Q2 2025 Idacorp Inc Earnings Call
John Wonderlich: Everyone heard Lisa's warning buzz off.
Everyone hurting leases.
As warranted welcome to Ida Corp, second quarter 2025 earnings call. Today's call is being recorded in our webcast is live a replay will be made available later today for the next 12 months on the Ida Corp website, if you need assistance at any time during the presentation. Please press star zero on your phone.
Speaker 5: Welcome to IDACORP's second quarter 2025 earnings call. Today's call is being recorded, and our webcast is live. A replay will be made available later today for the next 12 months on the IDACORP website. If you need assistance at any time during the presentation, please press star zero on your phone. I will now turn the call over to Amy Shaw, Vice President of Finance, Compliance, and Risk. Please go ahead.
I will now turn the call over to Amy Shaw, Vice President of Finance compliance and risks. Please go ahead.
Amy Shaw: 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 two, our discussion today includes forward-looking statements, including earnings guidance, spending forecasts, 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 three, we also have Lisa Grow, President and CEO, Brian Buckham, SCP, CFO and Treasurer, and John Wonderlich, Investor Relations Manager, presenting today.
Thank you good afternoon, everyone. We appreciate you joining our call. The slides we will reference during today's call are available on <unk> website as noted on slide two our discussion today includes forward looking statements including earnings guidance.
<unk> forecast financing plans regulatory plans and actions in 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 a 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 three we also have Lisa grow President and CEO, Brian bucket on the S. C P CFO and treasurer, and John Wunderlich Investor Relations manager at presenting today, but slide four.
Amy Shaw: Slide four 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.
A summary of our second quarter results I had a corpse 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 were raising the lower end of our full year I didn't work diluted earnings per share guidance by <unk> 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 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.
Amy Shaw: This increase was driven by strong operational results in the second quarter, and it includes our expectation that Idaho Power will use between $60 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.
For the rest of the year now I will turn the call over to Lisa.
Lisa Grow: 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 five. 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.
Amy and thanks to all of you for joining us today.
I'll start with.
Look at the continued customer growth across our service area, which we have summarized on slide five.
Powers customer base has grown two 5% since last year's second quarter, including two 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.
Talked about some of those on our first quarter call.
The most notable new one I'll highlight is micron 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 step. We have included a recent photo of the construction progress of the first fab on slide six you can see the scale of that project.
Lisa Grow: We've included a recent photo of the construction progress of the first fab on slide six, so you can see the scale of that project. We've 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 six new large electric vehicle fast-charging stations throughout Idaho Power's 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.
We've 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 will serve the expanded project.
Valor phase III data centers also announced an expansion at a second location in Boise and Tesla has energized six new large electric vehicle fast charging stations throughout Idaho power service area.
While growth is already robust, we continue to field and thoughtfully process request for 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 3800 megawatts.
Lisa Grow: 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 are 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 timeframes 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 seven, I'll provide some updates on what we're building to meet this historic demand.
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 IOP.
And they give us visibility on incremental load growth well into the 2030.
Also the infrastructure and resources needed to serve those prospective customers is not yet in our Capex plan.
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 timeframe needed for build out and ramp up as well as appropriate cost allocation just as we've done in recent.
Large load special contract.
Turning to slide seven I'll provide some updates on what we're building to meet this historic demand.
Lisa Grow: 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 Jackelope Wind Project in Wyoming to assess the impacts of these federal actions. In addition to permitting, there are other conditions that still need to be satisfied to move forward with the project.
In June we broke ground on the Boardman to Hemingway transmission lines, a key resource we've been working hard for nearly 19 years to make a reality.
We also recently brought our 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 construct ability of renewable projects.
So we've been working with our counter party 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 can move forward with the project.
Lisa Grow: 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 eight, 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 111(d), continue into the future. If those rules change, the portfolio could also change. Like I said, things are very dynamic.
This project would provide both energy and capacity that we need to serve load growth. So if ultimately the project does it 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 IOP on slide eight you can see our key takeaway from this 20 year plan is that our IOP recommend more gas fired resources, which are needed to provide additional system flexibility and dispatch full capacity.
These gas assets would complement our existing diverse resource portfolio.
Remember that the IOP is a fixed point in time and it assumes that current laws like the clean Air Act section 111 D continue into the future. If those rules change the portfolio could also change like I said things are very dynamic.
Lisa Grow: 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 nine, you can see the significant load growth, the 2025 IRP forecasted between 2025 and the early 2030s. As I mentioned, our five-year growth rate has increased notably in each of the last three IRPs, and Micron's 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 ten, we filed our 2029 RFP final shortlist in July for Oregon PUC acknowledgment.
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.
What our IOP shows.
On slide nine you can see the significant load growth for 2025, ERP forecasted between 2025 and the early 2030.
I mentioned, our five year growth rate has increased notably in each of the last three IOP and Micron second fab wasn't included in this one so we're quite possibly underestimating load growth in our 2025 IOP.
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 that 2028, RFP final shortlist last quarter and it has a mix of renewable projects for.
Lisa Grow: 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 impacts 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 shortlist 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.
For resources in both Rfps and 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 project as we focus on identifying the least cost least risk resources from those rfps.
The most notable is the 167 megawatt Idaho power owned gas plants shown as the top project on the short list for the 2029, RFP, which would provide us with greater certainty on our high capacity factor relative to the other listed projects.
Turning to regulatory matters on slide 11.
Oh power filed a general rate case in Idaho at the end of May.
Lisa Grow: 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 ADIPCs 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.
The regulatory process for that cases 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 request an overall rate increase of about $199 million for Idaho customers.
We're requesting a 51% equity ratio of 10, 4% Roe.
An additional 80 ITC to be added to a regulatory mechanism along with the depreciation and interest expense tracker.
Brian will talk more about the case in his comments and I will hand, it over to him now.
Brian Buckham: Hey, 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 of this year compared with the second quarter last year. The major drivers for the quarter were higher retail revenues from the January 1st 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.
Thanks, Lisa Hi, everybody I'm going to start on slide 12 today and that's it.
Table shows added Corp's net income increased $6 3 million for the second quarter of this year compared with the second quarter last year.
Major drivers for the quarter were higher retail revenues from the January 1st rate change customer growth higher customer usage due to warm and dry weather and then reporting 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 project.
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 a net increase in retail revenues per megawatt hour increased operating income by $8 $8 million on a relative basis.
Brian Buckham: That benefit was mostly from the increase in Idaho-based 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 with 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, though our irrigation customers used 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 programs and some related insurance expenses included in the mix of higher costs as well.
Benefit was mostly from the increase in Idaho base rates from the limited issue rate cases 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 of 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 cost as well.
Brian Buckham: 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 non-operating 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 non-operating expense side that you might have noticed in the 10-Q if you've gotten to it yet.
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.
Net changes in operating revenues and expenses decreased operating income by $5 $6 million. We expected. This 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 non operating expense increased $7 million in the second quarter interest on a higher long term debt balances needed to finance our growth and also an increase in interest in Idaho Power's required to pay on transmission customer deposits. Both contributed to the increase there is one new factor. This year on the nonoperating expense side that you might have noticed in the 10-Q.
If you have gotten to it yet.
Brian Buckham: 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 passed 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 non-operating expenses were partially offset by an increase in AFUDC because the average construction work in progress balance was higher. CWIP 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 of this year.
In May our first battery projects 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.
Financial results perspective, this item and the 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.
Yeah.
The increases in nonoperating expenses were partially offset by an increase in AFDC because the average construction work in progress balance was higher clip was a fairly staggering one for $1 billion at quarter end.
Also we saw higher interest income due to higher cash balances in the second quarter of this year.
Brian Buckham: 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 radically 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.
The decrease in income tax expense was mostly the result of an increase an additional 80, ITC amortization and some variances in flow through tax adjustments.
Based on our current expectations, our full year financial results, Idaho power reported $17 2 million of additional <unk> amortization Blake Amy Amy noted earlier compared with $7 5 million in the second quarter last year.
Remember, we record the itc's rapidly 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 <unk> stock through a discreet follow on offerings.
Brian Buckham: Combining the future net proceeds from that offering with the $145 million of forward sale agreements we executed through our ATM program in the fourth quarter last year and in the first quarter 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 RFP, 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, but those are all available, and they aren't shown as equity in our capital ratio right now.
Combining the future net proceeds from that offering with $145 million a forward sale agreements, we executed through our ATM program in the fourth quarter last year and in the first quarter. 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 depending rfps. So there is 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 short shares or any of the shares from our follow on offering to date. So those are all available and they aren't shown in the equity in our capital ratio right now.
Brian Buckham: 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 committed to maintaining a 50 50 debt to equity ratio at Idaho power and our equity forward transactions helped 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.
Just say that we appreciate our owners continued support and confidence and we are of course two minutes of the thoughtful drawdown in 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 or $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 I 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're making we've made in our system reliability and to address economic growth.
Brian Buckham: We're looking to add nearly $1 billion of rate base through the case, just reflecting the investments we've made in our system for reliability and to address economic growth. Now, 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 and rate-based 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.
As a notable amount, but if otherwise the relatively standard general rate case for us in most respects, we're asking for our typical historic test year treatment with known and measurable adjustments in annualized adjustments on larger capital projects for a period at a rate based treatment like we received in our 2023 general rate case, but because of the notable regulatory.
We lag that inevitably results from that historic test year approach. We also requested an arcade and 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.
Brian Buckham: 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.
I'll, just say that generally the mechanism would measure the difference between the actual depreciation and interest expense and a sales adjusted baseline level of depreciation and interest expense on a calendar year basis, starting in 2026.
What about the forecast and drew up component like our PCA and rates would adjust at the same time, it's a 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 and the acceptable level ultimately benefiting our customers as well.
We also asked in our filing for authority to incorporate additional 80 itc's in the tax credit regulatory mechanism. We ask that all existing 80 itc's on the books that are not already authorized for inclusion in the tax credit mechanism plus all the Itc's. We earned through 2028 included.
Brian Buckham: And 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.
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.
And we also asked for usage cap of $75 million of Adi Tcs in any single year.
Was it made the 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 metrics.
John Wonderlich: 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 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 to $475 million. We still anticipate spending between $1 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.
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 <unk> 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 one 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.
John Wonderlich: Finally, we still expect good hydropower generation in 2025, though we have updated our range to 7 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.
Finally, we still expect good hydro power generation in 2025.
Though we have updated our range to $7 8 million megawatt hours for the year. The dry June whether it was the largest driver of the reduction to the high end with that we're happy to address any questions you might have.
Speaker 5: We are now ready to begin the question and answer session for attendees who have joined the Q&A line. If you would like to ask a question, please do so by pressing star one on your telephone. Please ensure your mute function is turned off before asking your question. We will now take as many questions as times permit on a first-come basis. Once again, that is star one on your telephone keypad to ask a question now. Your first question is from the line of Chris Ellinghouse with Seaberg Williams Shank.
We are now ready to begin the question and answer session for attendees, who have joined the Q&A line. If you would like to ask a question. Please do so by pressing star one on your telephone.
Please ensure your mute function is turned off before asking your question.
We will now take as many questions as time permits on a first come basis.
Once again that is star one on your telephone keypad to ask a question now.
Your first question is from the line of Chris <unk> with Siebert Williams Shank.
Chris Ellinghaus: Hey, everybody. How are you today?
Hey, everybody how are you.
Lisa Grow: Great.
Hey, good Hi, Chris.
Chris Ellinghaus: Good.
Brian Buckham: Hi, Chris.
Chris Ellinghaus: How are you doing, Brian?
How are you doing Brian.
Brian Buckham: Good. Thank you.
Chris Ellinghaus: I think the number you quoted us was 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?
I think you are.
I think the number you quoted as 3800 megawatts in the pipeline.
Hey 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 IRB numbers.
Lisa Grow: 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 exact number I don't have on the top of my head.
So I don't have the number of exact.
Uh huh.
Projects that that amounts to and its actually more than our peak load.
But kind of around that that number. So it's mostly data centers that are that are in that.
In that pipeline, although there are there are smaller.
Projects in there as well so the exact number I don't have on the top on my head thinking you would I don't have the exact number Chris. This is al I think one of the data centers is included but it's beyond the five year window, and mostly and so you won't see that load included in the IRB forecast.
Brian Buckham: I don't have the exact number, Chris. This is out of, I think one of the data centers is included, but it's beyond the five-year window mostly. And so you won't see that load included in the IRP forecast of the 8.3% that you guys have.
Eight 3% that you guys have.
Chris Ellinghaus: 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, you know, looking at slide five, 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?
And Chris This is Brian I'll say, when we do our load forecasting for the IRB, 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 address this where you might be conservative in the IRB or you're kind of thinking at this point looking at slide five which shows sort of the progression of your retail sales forecasts growth.
Are you thinking that it's conceivable that you could have another step up in the 2027 IRB, that's kind of comparable to what we've been seeing in the progression.
Lisa Grow: Yeah, I think that's a fair assumption, Chris. And I'll say I've said it on several of these calls, you know, the IRP process, we sort of publish a study every two years, but these are studies we essentially do with every large load 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, you know, the economic activity continues. So a long-winded way of saying that, yes, it could very well be higher in a similar amount.
That's a fair assumption Kristen and I will say I put it on several of these calls.
The IRB process, we sort of published a study every two years, but these are studies, we essentially do with every large load customer that comes in which is quite frequent.
No.
Just given that when you do the IRB process, you have to sort of locked down the number youre going to use in this study and Meanwhile, the economic activity continues so long winded way of saying that yes. It will it could very well be higher than in the.
Similar amount and Chris just maybe I'll add to that this is Adam just to give you one stat line on that front.
Brian Buckham: And Chris, just maybe I'll add to that. This is Adam. Just to give you one stat line on that front, our large load requests this year, inquiries have increased right around 30% compared to the year before. And the year before was a relatively strong year in terms of inquiries and interest. So we're seeing, you know, continued interest in our service territory moving forward.
Our large load request this year inquiries increased right around 30% compared to the year before and the year before it was a relatively strong year in terms of inquiries and interest. So we're seeing continued.
Interest in our service territory moving forward.
Chris Ellinghaus: Okay. That's great. So looking at slide eight, you know, 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 know, you've got an awful lot that's affected in the solar winds, you know, 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?
Okay, that's great.
So looking at slide eight I looked at this preferred portfolio for a long time when it came out.
Yes, you mentioned the tax bill and how that May complicate things it certainly looks today.
Mike.
You've got an awful lot.
Effective.
Solar winds.
Maybe not the best column, but.
Are you currently thinking today that youre going to need to upsize and pull forward more of the gas expectation given what the tax bill looks like.
Lisa Grow: That's certainly some of the scenarios that we're analyzing.
That's certainly some of the scenarios that we're analyzing.
Chris Ellinghaus: Okay. 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?
Okay.
And lastly, I guess I haven't seen it yet, but do you have any idea when youll get a procedural schedule on the rate case.
Lisa Grow: Tim, do you want to take that one?
Tim do you want to take that one sure Hi, Chris This is Tim Tatum.
Chris Ellinghaus: Sure. Hi, Chris. This is Tim Tatum. Yeah, we've been working on a procedural schedule with the parties and staff. I would expect it in the coming weeks, maybe even as early as next week, but we're close. We're not all the way there yet. Okay. Maybe one more thing. Brian, can you give us any kind of color on what the irrigation impacts look like in the second quarter?
Yes, we've been working on a procedural schedule with the parties and staff I would expect it in the coming weeks, maybe even as early as next week.
Our clothes, we're not we're not all the way there yet.
Okay.
Well, maybe one more thing Brian.
Can you give us any kind of color on what the irrigation impacts looks like in the second quarter.
Brian Buckham: I can give you a little bit on that, Chris. It was pretty significant. You know, last year we had a really strong irrigation season second quarter. That was fueled by high temperatures. You know, this quarter we had 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 it 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 adjusts for those types of sales.
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 had continued high temperatures relative to normal while we saw this quarter, though was very low precipitation across our service territory and it turns.
Our 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 as 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.
Chris Ellinghaus: Right. Okay. Thanks a lot. Appreciate it.
Okay. Thanks, a lot appreciate it.
Lisa Grow: Thanks, Chris.
Brian Buckham: Thanks, Chris.
Thanks, Chris.
Speaker 5: As a final opportunity, press star one to signify a question, and we'll pause for just a moment. Your next question is from the line of Julian DeMall Smith with Jefferies.
As a final opportunity press star one to signal for a question, we'll pause for just a moment.
Your next question is from the line of Julien Dumoulin Smith with Jefferies.
Lisa Grow: Hi, Julian.
Hi, Julien.
Chris Ellinghaus: Yeah. Hey, it's Brian Reeson along for Julian.
Hey, its Brian Russo on for Julien, Hi, Brian Hi, Brian.
Lisa Grow: Oh, hi, Brian. It's good to know. It's always sort of a guess.
Sort of a guest.
Chris Ellinghaus: Good afternoon. Hey, just on you mentioned the Micron phase two. 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, you know, the first phase is 500 megawatts. You know, what kind of timeline do you see unfolding here? You know, I suppose they're just going to want to start construction of phase two, maybe even before phase one ends, right, to keep the continuity of the EPCs, etc. Just any thoughts there? And I would imagine that would correlate to one of the upside scenarios in the 2025 IRP?
Good afternoon.
Hey, just on.
You mentioned, the micron phase II, it's great to hear it could be the same.
Sizes.
<unk> still under construction and I think according to the tariffs.
Lee.
The first phase is 500 megawatts.
What kind of timeline.
Do you see.
Unfolding here as opposed to just going to want to.
Store construction of phase two maybe even before phase one ends right to keep the continuity of the Epc's et cetera, just any thoughts there and I would imagine that would correlate to one of the upside scenarios in the 2025 by ERP.
Lisa Grow: Yes. On the second part of your question, it would be upside. And to the first part, we're just working through those details with Micron, so we're not really able to speak to the amounts or timing. But it is underway, and as soon as we have information we can share, we will.
Yes on the second part of your question it would be upside and to the first part we're just working through those details with micron, so were not really able to speak to the amounts or timing.
But it is it.
It is underway and.
And as soon as we have information we can share we will.
Okay.
Chris Ellinghaus: 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's 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.
Okay great.
Just to clarify the 28 and 29.
Rfps that you show in the slide.
In theory, that's based off of your 23 ERP right. So.
The way to look at it is whatever it is in the 22025, our ERP to subtract what we see here on slide 10, and that's what will be incremental and any sort of follow up.
RFP.
Lisa Grow: I'm not sure if the math is that simple, just given how many moving parts are, but what would you say, Adam?
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 an RFP.
Brian Buckham: Yeah. Typically, the way it goes is we send out an RFP. We get the projects that come in. As we're evaluating those projects, we're also evaluating the load and the need. And so that can ebb and flow given what we need at that exact time that the RFP is out. So this is just a list of the projects that were shortlisted that responded to our RFP request. Then we would have to decide how many of those projects we actually pick to then meet the current need that exists at that time. Does that make sense, Brian?
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 a given what we needed that at that time that the RFP is out. So this is just a list of the projects that were Shortlisted that responded to our RFP requests than we would have to decide how many of those projects.
<unk>, we actually pick to that meet the current needs that exist at that time does that make sense Brian.
Chris Ellinghaus: Yeah, it does. So, you know, for example, the 160 megawatt self-build gas plant that you referenced in the '29 RFP shortlist, that kind of correlates to what you have on slide eight, 2029, 150 megawatts of 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?
Yeah. It does so for example, 160 megawatt self build gas plant that you referenced in the 'twenty nine RFP shortlist.
Kind of correlates to what you have on slide eight 2029, 150 megawatts of new gas, but I suppose you'll need an RFP for 2030 for 300 megawatts.
So is that the simplistic way of looking at it.
Brian Buckham: Yeah, I think that's one way to look at it. And maybe another way, Brian, is just in terms of the next five years, our need in megawatts of perfect capacity. So that's, you know, the resource that's maybe not 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, you know, 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.
Yes, I think Thats, one way to look at it and maybe another way Brian is just in terms of the next five years, our need in megawatts of perfect capacity. So thats.
The resources, maybe now renewable that can give you everything you need at that moment is about to little over 200 megawatts a year every single year based on the 2025 ERP now when we decide which projects we're going to pick up related to the 2028 2029 RFP. We will continue to look at that load forecast <unk>.
But in terms of the 2025 ERP is 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 thats kind of how it works as we move forward and work on these different projects.
Chris Ellinghaus: Okay. Great. And then just lastly, you mentioned some issues with the Jackelope Wind Farm. It's a build-on transfer, right? And I think it's for 2027 needs. Conceptually, if that's facing, you know, economic, you know, issues with the tax bill, etc., could you just shift to gas?
Okay, Great and then just lastly.
You mentioned some issues with the Jack a little a wind farm, it's a build own transfer it right I think it's for 2027.
Thanks.
Conceptually.
If that's facing economic.
Issues with the tax bill et cetera.
Could you just shift to gas.
Brian Buckham: This is Adam. Yeah, that is absolutely one option. I think on Jackelope, we're really looking at the permitting, potential permitting issues related to the executive orders that are out there. If we did not build Jackelope, certainly, one of the things we have and will continue to look at is gas bills in that timeline.
This is Adam yes that is absolutely one option I think Jeff look we're really looking at the permitting.
Permitting issues related to the executive orders that are out there we did not build jackalope certainly one of the things we have and will continue to look at it as gas bills in that timeline.
Chris Ellinghaus: Okay. Great. Thank you very much.
Okay, great. Thank you very much.
Lisa Grow: Thanks, Brian.
Brian Buckham: Thanks, Brian.
Thanks, Bryan Bryan.
Speaker 5: That concludes the question and answer session for today. Ms. Grow, I will turn the call back to you.
That concludes the question and answer session for today.
MS <unk>, you well I will turn the call back to you.
Lisa Grow: 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.
Well, thanks again to everyone for joining us today and we thank you for your continued interest in <unk> and I wish you all a good evening. Thank you.
Speaker 5: This concludes today's call. Thank you for joining. You may now disconnect your lines.
This concludes today's call. Thank you for joining you may now disconnect your lines.
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