Welcome to IDACORP's Second Quarter 2021 Earnings Conference Call. Today's call is being recorded and our webcast is live. A complete replay will be available later today and for the next 12 months on the IDACORP website. I will now turn the call over to Justin Forsberg, Director of Investor Relations and Treasury.
Thank you, Paul, and good afternoon, everybody. This morning, we issued and posted to IDACORP's website our Q2 2021 earnings release and Form 10 Q. The slides that accompany today's call are also available on our website. We'll refer to those slides by number throughout the call today. As noted on Slide 2, our discussion includes forward looking statements, including earnings guidance and spending forecasts, which reflect our current views on what the future holds, but are subject to several risks and uncertainties, including those related to any potential further impact of COVID-nineteen.
This cautionary note is also included in more detail for your review in our filings with the Securities and Exchange Commission. 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. As shown on Slide 3, on today's call, we have Lisa Groh, IDACORP's President and Chief Executive Officer and Steve Keen, IDACORP's Senior Vice President and Chief Financial Officer. We also have other company representatives available for a Q and A session after Lisa and Steve provide updates. Slide 4 shows our quarterly financial results.
IDEXORP's 20 21 second quarter earnings per diluted share were 1 point $3.8 an increase of $0.19 per share from last year's Q2. Earnings per diluted share over the 1st 6 months of 2021 were $2.27 which were $0.33 above the same period last year. Both the 2nd quarter and year to date earnings are the highest in the history of the company. Today, we also increased our full year 2021 IDACORP earnings guidance estimate to be in the range of $4.70 to $4.90 per diluted share with our expectation that Idaho Power will not need to utilize in 2021 any of the additional tax credits that are available support earnings under its Idaho regulatory settlement stipulation. These are our estimates as of today and they assume normal weather I will now turn the call over to Lisa.
Thank you, Justin, and thanks to everyone for joining us on today's call. I'd like to begin my remarks by highlighting the continued robust customer growth we are experiencing across Idaho Power Service Area. You'll see on Slide 5 that the growth remains strong in the 2nd quarter, increasing 2.9% since June 2020. The influx of businesses and residential customers continues to benefit our company, while we believe the reliable, affordable, clean energy we provide remains one of the drivers for attracting new customers to Idaho. It has been remarkable to see this trend not only sustain but accelerate over the past several years.
We are also seeing a return to normal operations for many of our commercial and industrial customers as our service area rebounds from the impacts of the COVID-nineteen pandemic. As of the end of June, unemployment in our service area was 3.5% compared with 6% in June 2020 and the current mark of 5.9% nationally. Total employment in our service area has increased 6% over the past 12 months. Moody's forecasted GDP calls for very strong economic growth of 7.6% in 2021 and 6.9% in 2022. As we speak, like many employers in our area, Idaho Power is in the midst of the return to workplace process for many of our office employees.
I'm happy to see more people at our offices and thrilled that safely bringing our employees back reflects a significant step forward to our new normal that is taking place across our service area. Idaho Power service area continues to experience significant interest from commercial and industrial projects in food processing, manufacturing and distribution. Multiple developers, both local and national, are moving forward with the construction of commercial sized back shelf facilities to better accommodate the speed to market of prospective projects. Idaho Power has also been actively working with Gervois Mining, which announced in early July it will proceed with final construction of its Idaho Cobalt operations mine in Central Idaho. And just this past week, Lamb Weston announced a $415,000,000 investment in the planned of a new French fry processing line at its existing facility in American Falls with expected capacity to produce more £350,000,000 of frozen French fries and other potato products annually by mid-twenty 23.
This expansion is expected to add approximately 130 jobs. In addition to serving than ever, we've experienced very hot dry weather during the Q2, with our service area experiencing several very high temperature days in late June July. Slide 6 shows a recent outlook of precipitation and weather from the National Oceanic and Atmospheric Administration. Current weather projections for August through October shows 50% to 60% chance of above normal temperatures and a 33% to 50% chance of below normal precipitation in Idaho Power Service Area. If the warm and dry weather continues, we expect to see continued strong sales during the Q3, particularly for residential and irrigation customers.
At the same time, dry conditions and overall lower reservoir storage levels have decreased our forecasted hydro generation for the remainder of the year, which Steve will address later on. But it continues to appear irrigators in most parts of our service area should have enough water to get them through the current growing season. The combination of customer growth and hot dry conditions has created high demand for energy across our region as noted on Slide 7. Idaho Power hit a new all time peak load of 3 1,751 Megawatts on June 30. And we have exceeded the previous 2017 peak demand of 3,422 Megawatts, more than 60 separate hours on 12 different days so far this summer.
I'd like to thank the wonderful employees our company who are helping us continue to meet this record demand. The recent heat wave has once again demonstrated the skill and dedication of our employees and the resilience of both our employees and our system. I'd also like to acknowledge our customers for helping us lighten the load during hours of peak usage in the late afternoons and evenings when we also ran demand response programs to help reduce loads. While we've been able to maintain reliable power for our customers during these extreme conditions, we also acknowledge the need for continued planning and preparation to meet the growing demand. The jackpot solar 120 Megawatt project in Southern Idaho is scheduled to come online by the end of next year.
And our company also recently issued a request for proposal to add another 80 megawatts of a capacity resource to meet peak energy needs by summer 2020 3. Separately, early modeling in the 2021 IRP suggests that subject to the timing of coal unit exits, additional and prices also emphasizes the importance of the Boardman to Hemingway transmission line or B2H, which we plan to bring online as soon as 2026. C2H will allow Idaho Power to import up to 500 megawatts, which will help meet customers' peak summer demand and increase reliability for our system as well as the region. Record heat waves don't last forever, but we believe periods of higher demand in the summer months are here to stay. Of note on D2H, this month all co participants entered into an agreement and acknowledged that Bonneville Power Administration does not intend to participate interest in the project to either Idaho Power or a 3rd party.
Options regarding BPA's interest. I have a couple of notable Idaho regulatory updates to share. The first is a recent filing Idaho Power made to Jim Bridger Coal Fire Plant, which is noted on Slide 8. Our Idaho rates currently reflect a recovery timeline through 2,034, but preliminary analysis indicate the potential exit of all 4 units at the plant sooner than the current timeline. If our filing with the Idaho Commission is approved as filed, rates would increase $30,800,000 in December of this year.
This would result in a near term rate increase for our customers, but our study shows the potential for customer savings in the long term. Exiting the Jim Bridger plant early also aligns with our goal to provide 100% clean energy by 2,045. Secondly, as seen on Slide 9, the Idaho Commission recently approved Idaho Power's request to defer incremental costs associated with our enhanced wildfire mitigation plan. This positive regulatory outcome will allow us to defer associated incremental costs to be included in a future rate proceeding. Our company is working hard to strengthen our grid and keep our customers safe during wildfire events.
On our last earnings call, I stated Idaho Power did not plan to file a general rate case in Idaho or Oregon in the next 12 months. That remains true today. Steady customer growth, constructive regulatory outcomes, effective cost management and economic conditions all play significant roles as we look at the need and timing of a future general rate case. I'll close my prepared remarks by reiterating my thanks to our employees for their hard work meeting the increased demand for reliable energy as our service area grows, particularly during the heat wave. I also commend them for their resilience over the past 17 months as we navigate the challenges of the pandemic together.
With that, I will turn the call over to Steve for an overview of our financial performance.
Thank you, Lisa. Let's now move to Slide 10, where you'll see our Q2 2021 financial results as compared to the same period in 2020. Overall, we have experienced a very solid first half of the year with strong customer growth, positive impacts from transmission services and higher revenues resulting from the heat wave that affected much of the Western U. S. Because of these IDACORP's 2nd quarter net income was substantially higher than last year.
On the table of quarter over quarter changes, you'll see our continuing higher by $22,900,000 Cooling degree days were nearly double last year's Q2 and the hot and dry conditions led to significantly higher usage across all customer classes. Irrigation and residential per customer usage increased 25% 10%, respectively. A return to more normal economic conditions combined with hot weather also drove a respective 12% 8% increase in usage per customer in the commercial and industrial classes. Continuing down the table, the higher usage for residential and small general service customers was partially offset by $5,100,000 lower revenues from the PC or the FCA mechanism. The FCA mechanism has tempered the effect of the higher usage for these customer classes and could do so again in the Q3 if customer usage continues strong.
Next, you'll see a decrease in operating income of $6,800,000 that relates to the change in the per megawatt hour revenue, net of power supply costs and power cost adjustment quarter to quarter. The primary driver of this decrease relates to the amount of net power supply expenses were not deferred through Idaho Power's power cost adjustment mechanisms. Recall that Idaho customers generally bear 90 5% of the power supply cost fluctuations and those costs were higher as the heat waves impacted wholesale energy prices at a time of increased energy usage by our customers. The heatwave also affected transmission revenues, which increased operating income by $3,900,000 Wheeling volumes increased as utilities work to serve high demand by moving energy across our system throughout the region during the quarter. In addition, Wheeling customers paid 10% more for Idaho Power's open access transmission tariff rate that increased last October to reflect higher transmission costs.
Next on the table, other operating and maintenance expenses increased by 5,300,000 was primarily due to last year's temporary deferral of certain maintenance projects at Idaho Power's jointly owned thermal generation plant as well as higher accruals of performance based incentives. We continue to see decreases in employee travel and training costs related to COVID-nineteen, while our allowance for bad debts remains above historic levels and is taking longer to collect. Our net COVID-nineteen recovery deferral impacts, however, continue to remain nominal. Finally, our higher pre tax earnings led to an increase in income tax expense of $4,200,000 this quarter. The changes collectively resulted in a net increase to Idaho Power's net income of $9,600,000 or 0 $0.19 share.
IACORP and Idaho Power continue to maintain strong balance sheets, including investment grade credit ratings and sound liquidity, which enable us to fund ongoing capital expenditures and distribute dividends to share owners. IDIPORT's operating cash flows along with our liquidity positions as of the end of June 2021 are included on Slide 11. Cash flows from operations were about $39,000,000 higher in the 1st 6 months of last year. The increase was mostly related to working capital fluctuations and the timing of net collections of regulatory assets and liabilities. The liquidity available under IDACORP's and Idaho Power's credit facilities is shown on the middle of Slide 11.
At this time, we still do not anticipate raising any equity capital in 2021. Our combined liquidity along with expected regulatory support from our annual adjustment mechanisms is a substantial backstop to our expected capital and operating needs. Slide 12 shows our raised full year earnings guidance and our current key financial and operating metrics estimates. We now expect IDACORP's 2021 earnings to be in the range of $4.70 to $4.90 per diluted share. This guidance assumes normal weather and operating conditions for the second half of the year and assumes economic impact from the pandemic will continue to normalize.
Our guidance still assumes Idaho Power will use no additional tax credits in 2021. While we do not currently expect to record sharing of excess revenues with Idaho customers this year, the FRN of our range approaches that level and the final jurisdictional allocation can adjust on that through year end. Recall that above a 10% return on equity in the Idaho jurisdiction, Idaho customers would receive 80% of any excess earnings. Our expected full year O and M expense guidance remains in the range of $345,000,000 to $355,000,000 It's fair to say this goal to keep O and M relatively flat for the 9th straight year is being challenged by the amount of customer and load growth we are experiencing. We also reaffirm our CapEx forecast for this year in the range of dollars to $330,000,000 Our expectation of hydropower generation has decreased somewhat given the weather conditions Lisa presented and is now expected to be in the tightened range of 5000000 to 6000000 megawatt hours.
With that, Lisa and I and others on the call will be happy to answer your
questions. We are now ready to begin the question and answer Your first question comes from Chris Ellinghaus with Seabury Williams.
Hey, everybody. Hope you're well. Hey, Chris.
Hi, Chris.
I got a million questions for you. It's a lot of exciting stuff here. First of all, should is it time to get worried at all about next year's reservoir levels considering sort of the outlook for precipitation and the expectation that there might be another La Nina developing for the fall. So can you just sort of give us your thoughts on that where reservoir levels are today?
Yes, certainly, I can start. Chris, this is Lisa. One of the things I was taught very early in my career is that no amount of worry actually puts any water in the reservoir. So it's not so much that we worry about it, but we certainly plan for the worst case scenarios. And so we are being careful about how we're using the water.
I would remind you, we have a we do have some weather modification that we utilize to pull as much as we can out of each storm that does come through. And I would also remind you that La Nina actually can produce really good snowpack for us as well. Austin, it's more the case that it does than doesn't, but I'm reminded that last year was also a long Nina. So, I don't know that there's a great trend line really on that. It's just that it continues to be variable.
So we certainly know how to operate during those conditions. It does mean that we rely more on the market and we will it's the value of a diverse portfolio that we can access other sources of energy when we are in drought conditions. And Adam, is there anything that you would add from that I'm missing from an operations perspective?
No, I think you covered it. It's a little bit too early to tell, but we are focused on it and we in fact have some meetings over the next month or so to make sure we keep an eye on it.
Okay. Lisa, it's Chris, let me add one thing. It's been a while since we've talked about these issues. But if you go back a few years, we've had multiple times that we've had several years in a row that we had drought like conditions. And one good thing is the Brownlee reservoir sort of hits a bottom, that bottom might move slightly, but the level we're at right now, I think, is nearing the point.
It kind of doesn't go below that even in bad years. Now that doesn't mean that's an optimum thing because we'd much rather have a lot more water, but it doesn't go down to 0 or at least hasn't in what we've seen. It kind of stops at a certain level in the spring fed and other things.
Okay. Lisa, can you talk about what you were saying on the commercial industrial recovery? Where you feel like you are compared to normal? And what did this quarter look like versus last year from what you can interpret the COVID situation?
Well, as I mentioned in the remarks, we really are seeing a return to normal levels. And then some of the new businesses is starting to show up as well. So there have been some maintenance cycles that have happened during the last year that felt a little bit out of cycle from their normal timing, but I think they might have been taking advantage of what was going on in the world to do some maintenance in a time that was slightly different than normal. So I would say it's getting really close to normal levels. And as we mentioned, lots of planned increases as well.
So we're very excited about that return because also that means people are getting back to work and we're very optimistic.
Okay. I just want to
make sure I'm clear on this. You said a couple of times that the revised guidance is assuming normal for the second half of the year. So you haven't included any consideration for what appears to be a pretty hot and dry July so far?
Chris, the way I would put it is we don't put those in our baseline or in what we would say is our midpoint. We don't really tell you where that is in our range, but we do factor those in as we're looking higher. But you always have heard me talk about Q3 and July looks really good, but the whole quarter itself is a massive part of what we get for the year. So it's the thought is in there, it's not I'd just say it's a range and we put in the comment there towards the end that we're also starting to approach where you start sharing a little bit. We don't stop necessarily at sharing, but you do slow down.
And so I think this is a reasonable range. We come up with this script. It's midway through July, most of it's getting charted out. But as you point out, it's been pretty hot and it's continued on. Okay.
When does the sort of the unofficial end of the irrigation season really hit for you?
It generally is late August, September depending on the crops that are planted. So I would say it's generally into September, early September.
Yes, that's one area, Chris, where I think we don't know sometimes if we just got irrigation earlier or how much of it is going to be an absolute up. So that is one of the question marks that kind of you wait till you get to end of August and you kind of know what really happened, how much of that was all up and how much was just sooner.
Right. Lisa, you mentioned this cobalt mine. Can you give us some details and what kind
of load does that look like?
I'm going to have Adam Richens answer that. He's been more directly involved with that. Adam, you want to take that one?
You bet. Hey, Chris. One of the things I think you know that gets a little bit touchy with our customers in talking about the load tend to be a bit confidential for them. So can't get into that. Right now, they're focused on a mid-twenty 22 in service date.
And
I'll just tell
you, I've been up there. I've looked at the mine, and it's moving in terms of construction. So that's what they've said publicly. And in terms of the load, you can't get into that, but we're pretty excited about what it can bring to our service territory.
Will you be able to later talk about load or maybe what the scale of the mine is?
Yes. It all depends on whether they're willing to go out with that information or not publicly. A lot of these folks consider it competitive information. If others are looking at
what their load is and
they can determine what how much they're mining and some of those types of things. So it really depends on the customer. I would love to share more, but they have to let us know kind of when it's okay for us to do so. Okay.
And Lisey, you sort of were talking about depending on the coal retirements and obviously had some new peak loads and whatnot. Can you give us your general thoughts on new resources? Obviously, IRP details are somewhat fluid, but can you sort of talk about what your vision is and would you imagine participating in any kind of material new resources?
It's a great question. So as you mentioned, the IRP is really the process we go through to identify our future resources. But we do have an RFP out there on the street for 80 megawatts that we didn't have previously in the plan. It really came up from the analysis we did on looking on whether or not we could take the 2nd unit of Valmy out earlier. And when we refreshed all the variables, it demonstrated that we were going to need something sooner and something that was a capacity resource, not just energy.
And so we're looking forward to getting the results back there. And then we are looking at all kinds of resources. And again, that analysis that sort of the sort of the technologies against one another on their performance and cost. So I am very optimistic. I think there's a lot of exciting opportunities out there and I'll let the IRP run its course and we'll have more information available at that point.
That should be out by the end of this year.
Okay. Thank you so much for
the color. I appreciate it. Have a lucky August.
Thank you. You too.
Your next question is from Ryan Greenwald with Bank of America.
Good afternoon, everyone. Appreciate the time. Hi, Ryan. Maybe first, can you guys just talk a bit about any shift in dynamics amid the latest scarcity concerns when it comes to the planned early acceleration of Jim Bridger? In terms of any initial conversations with stakeholders and any change in mindset there?
Yes, I'm not sure. I mean, we've been certainly again talking with the IRP and other stakeholders about what that might look like. And certainly, we talk with our partner over at Pacificor. Recall, they're the majority owner operator of that plant. So I don't think there's been anything that I could say is a change of how we've been thinking about it in the past.
So maybe I'm not fully understanding the question you're asking.
Yes, Ryan, part of the if you look at the 2 plants that we already have moved through that process, the fact that the end of life costs and some of those things kind of have just set out there from you start the plant and you think that's kind of just far out, you don't think about it. As you get near, you have to start encompassing the whole the final answer for any of these plants. So that Bridger decision, as Lisa mentioned, the last IRP is the best information we've got in terms of timing. Everybody's working hard on the next one. But there's pieces of that in order of spreading those costs over periods of time, collecting them from the customers that are getting enjoyment of the use of the plant, all of those things, none of that has really changed or moved and that is a lot of the impetus behind the filing.
Got it. So it sounds like at this point, you guys plan to kind of proceed with the earlier acceleration and not too concerned about a slowdown?
Not too much. I guess I'd point it too that it's the beauty of this, the way that both the Valmy decisions were put out and Boardman, they both allowed flexibility. So they're kind of a living plan once you put them out. You start with a plan, there's plan A and then it adjusts and adapts and people you report. It's got a process that allows the oversight to continue all through the process and continual updates.
So I think the starting with the process is still a good thing. And you never really are going to get a point when you know perfectly the answer for the future. So that's we focus more on a mechanism that could live through those type of things.
I think it's worth noting too, to remind you in the it's fascinating on the Balmy agreement that the final depreciation date was actually past the date of when we would finish or cease operations there. So if we did have to change the operation date, it doesn't change the depreciation schedule. So it's we do have some movement capability there.
Understood. And then maybe lastly, with respect to the BPA intention to sell their stake, any more color you guys can provide there around timeline and how this could play out in coming months in terms of your potential ownership?
Well, we're still working with our partners on that. So there isn't a lot more that we can say, but they're active conversations and we continue to work through it.
Your next question is from Brian Marasso with Sidoti.
Hi, there. Hi, good afternoon.
Hi, Brian. Hey, so just
curious, is there this might sound silly, but is there a scenario where it can be too hot and too dry, where the demand is exceeding your generation capacity. And with low hydro conditions, you need to go out and buy high priced power, which is what led to the margin negative margin variance on the PCA?
Too much might be not the best terminology, but certainly when usage gets really high and you cover power, then it's a balancing process. I mean, I think we refer to it typically as balancing and you're weighing, do you run your water now, do you save it till later in the year, do you is the market giving us an opportunity to buy today at a better price so we can keep one of our resources for later? That's what the operators do constantly is try to sort that out. But it certainly can drive high costs. And if you remember back, we've had some years in our past when we've had really high power costs.
There was 1 year when they were so high, we offered to spread them over a couple of years and they ended up going ahead and collecting it in a single year. But it does drive the costs up. You are somewhat subject to the market for parts of it. And we do the best we can there and we try to manage that. I think the hydro is really nice and that we have a little more choice with it at times than others.
So we'd like to have more of it. But we started this year with a pretty normal amount and as far as carryover. We probably were slightly below normal when we hit summer just because we've used some in the spring, but it was close. So you can hit it even if you have a pretty good year, there could be days that you go to market.
And Adam, do you want to add any color because we have a relatively new group of leaders in operations and they were really creative looking out and seeing some of this coming and moving quickly to adapt.
Yes. Thanks for the question. It's a good one. We experienced in June a 1 in 45 year event in our service territory. In the 6th North West, it was a 1 in 1000 year event.
And as Steve mentioned, although the conditions of Carrier over were decent, we had one of the driest springs in memory, and we were absolutely able to work through it. The system held up well. We have operational folks. This is what they train for. This is what they're ready for.
We did have to buy more energy on the market, but we also have processes that in before these times come to make sure we're being proactive. Sometimes we hedge some of those purchases as well. We also actively bought so far, our system has been performing well, and we've been pleased with the results.
Right. Got it. So the $6,800,000 of negative net income driver related to power supply costs, That implies you're already in the 95.5 sharing, correct?
The 95.5 is on all power supply costs. So everything that good or bad. So if we are experiencing lower than normal costs, 95% of the savings goes back to customers and we get to keep by. When the costs are higher and this is Idaho primarily that I'm talking about, the 95% goes to bears the cost that is the customer and then we take the other 5%. If you that used to be a ninety-ten split and then it was adjusted and we're at 95.5% now.
And that's all based on whatever was in the last rate case. So it factors off of that. You really start with whatever was in your last base your last general rate case and then the 95.5 works either direction off of that number.
Okay, got it. And then the IRP filing, I think you got an extension to December, but I think the target month was in September of 2021 to file. Is that still the goal or is it going to be pushed back, you think, towards the end of the year?
Our goal has been around November And right now, we're on track to meet that.
Okay. And then also the 80 megawatt RFP, is that a purchase power agreement type scenario or is that something you would consider self building?
Well, we're looking to do a little of both. I mean, obviously, we would love to build and own, but we're also wanting to make sure that people respond to the RFP. So we're looking at we're open to a number of possibilities.
Okay. And then lastly, can you remind us what BPA's percentage stake is in the B2H?
I believe it was 24%.
Okay. So 24% of, I guess, that one point $1,000,000,000 kind of cost you guys disclosed?
Yes.
Yes. Okay, great. Thank you very much.
Thank you.
Thank you, Brian.
Your next question is from Ashar Khan with Vireshaun. Your line is open.
Hi, there.
Hi. How are
you doing? So I just wanted to I guess, there are a couple of things happening, if I may mention right to what people are talking about. But the higher load and the higher warm weather is generally positive for earnings. Is that fair to assume?
I would say that, yes.
Okay. Because we've had a good July. So as you're mentioning, we still have to wait for August and I guess September somewhat, but August is the key month, if I'm right, right? So that and that is not yet included in your forecast. But you did mention that if you go over, I guess, the top end of your range, 4.90s, right, you will be in the sharing mechanism, if I heard it correct?
Yes, it's not. We're not saying the $4.90 is the number. We're just letting people know that it's not a long ways past that, that the where the allocator sits currently. It doesn't move around, so it can actually shift up and down a few pennies itself, but it's beyond that upper range today.
So it's beyond okay. So it's not at $4.90 it is something above that, that is when the sharing will happen?
Correct. We just wanted people to remember that there is a place where it slows down. And earnings don't necessarily stop at sharing. It's just they begin to accumulate.
Yes, yes, yes. No, I just wanted to I was just doing a rough back ended math is that at what level do you reach 10%, right? That's when sharing start, right? And my earnings number calculation were coming that earnings have to go over $5 to reach that level. So when you said $4.90 I got a little bit confused.
So I wanted to check my math with you whether I was missing something.
Well, as far as you're trying to get a number that hasn't happened yet. So it is a tough number to hit. It's going to be a year end calculation. It's going to depend on how many sales happened in Oregon, how many sales happened in Idaho, how which class happened, which place it has. So it's a very complex allocator that at this point in time we kind of have a thumb in the air idea of where it's going to be, but it's going to move most likely from what we think it is today.
It's affected by its year end equity.
Understood. I totally understood it, but it's not at 4.90 right now. That's my main point. I guess I just wanted to clarify that, right?
You're correct. It's above that.
It's above that. Okay. That's what I just wanted the clarification on. Okay. And then if I just any update on the relicensing
issue and it's still
a 2023 event in 2023 event in your eyes?
Well, it's an ongoing process. At this point, we believe that that still is possible, but there's the gauntlet of things we've got to go through to get there, but that's
our
best guess today.
Okay. Okay. And then I'm just trying to just for reference purposes, as you're seeing this higher growth in the service territory and one thing which has happened, if you look at your annual report and all that is that our ROEs have gone a little bit down, right? Sometimes we are 9.6%, 9.4%. I guess the last year based on your annual report and that I guess you do based on the total stock as book value of the whole company, so it's a mixture, is 9.3% was at the low end.
So from your perspective, what is the ideal rate? Is it 9.3%, 9.4%, 9.5 percent? Where should one kind of like set one's horizon in terms of planning for the future with this higher growth? And I just wanted to get your thoughts on it.
Well, you say an ideal, I mean, they do move. There's years that we have better support, say, out of our subsidiaries. Our Oregon property has no mechanism around it the way Idaho does. So it has variability. And so the reality is there's some years we don't get as high as others, but the goal is to
Maximize, yes.
Yes. So we're aiming to maximize. And I think we've talked many times about weighing the whether you're filing, whether you're not filing, how much this growth continues to bring and COVID did throw some question marks into that. I think we just weren't sure where we're sitting today and with the year that's happening now, it appears that growth is still alive and well and we're kind of just hanging on to keeping up and making sure we serve everything that comes. So some of the years you're looking at there were impacted by a thing I don't think any of us saw coming.
I certainly didn't have the pandemic in my 5 year window back in 4 years. So I don't know what to say about that, Ashar. It does move around with outcomes, but I think we're sitting in a good place and the story we've had is still on track. I think the growth continues to be our interim answer. And as Lisa talked about some of our growing needs and we've put out reports in our owner updates on CapEx growth, there's a different story that's building that's kind of our future.
So that's we're still on that track.
Okay. And if I can ask the last question, right. So if you look at it on a consolidated basis, right, the book value is increasing by $2 And if you apply, say, roughly, I want to go to the lower end 9, right, ROE on that, that gives you like 18,000,000 and if you divide it by 50,000,000 shares, that gives you like annually, you should grow by about at least kind of somewhere in the $0.30 range, but we don't achieve that. So I'm just trying to understand what is the right way to look at the increase in book value because that's a consolidated book value, right? It's not the IDACORP is where the mechanism is.
So what is a good number for IDACORP's increase in book value? Is it $1.50 or what is the right number to want to think about?
So the mechanism is an Idaho mechanism that looks at the Idaho allocation of the equity for Idaho Power. So it's the mechanism isn't sitting at IDACORP.
Understood. That's why I
was asking what is a good number to look at from an IDACORP's perspective for increase in equity every year?
Yes, we haven't put that out, sure. I mean that's why we put the chart that we've been sharing for quite a number of years on the we give you the chart of year over year changes. And with that, you can kind of look through and see the years that we've hit sharing and that that's put a limiter and you can kind of do your own calculations of where those support mechanisms might be, which kind of gives you a bottom and then you can figure out where the sharing might be above that and people have used that to ban their estimates.
Okay. I thought I would try it once more to see if I can make my model more accurate, But appreciate it. Thanks. Great results. And just a reminder, when is your some I've now lost track, previously you used to come up with your dividend policy in August.
Is that still the case or now it's been delayed into the fall?
For the last few years, we've made our dividend changes when we've done it in September. And we've I think we announced that that was the plan we were going to go with. Normally given some sort of an indication what to expect might come in the next year, but then we didn't actually do it and announce it until we're through the September.
Okay. So we should wait until September?
Yes, it's actually with our release. I think that we've got it out for the Q3.
Thank you.
Your next question is from Vedula Murti with Hudson Bay Capital.
Nice to hear from you. Nice talk. With the Fort McMurray line, how much of the is your 21% already reflected in the existing CapEx 5 year plan that you have, which you published before?
Some of it is in there. I can't remember how much actually gets in, in terms of construction. A lot of it is just the pre construction and the planning and the financing piece.
I'm not sure I heard
The construction period is 2,003 to 2,006. And that's where the bulk of the funds will be
So 23.4
is welcome.
Yes.
And that would be the earliest from our standpoint.
And what is the status in terms of whether this thing is an actual real go or just in terms of looking through any other sprinkler for approvals, environmental, other things? And is there still some probability that this will not
This is Adam. I'd be happy
to answer that.
Go ahead, Adam.
Yes. The federal permitting, we've received those permits, and that's the NEPA process. We are in federal litigation on those permits, but we've received actual permits. The state permitting should be completed, we believe, the second half of twenty twenty two. And B2H continues to be our least cost, least risk resource as we look at through the 2019 IRP.
And so we're moving ahead. We think we're making good progress. And our partners in PAC is also moving ahead and excited about the project. So yes, we think it's moving forward at a good pace.
So I guess at this point, when do you think you're looking to be able to tell us that this is that we have working in hand and this is real project and this is cost and this is time line and this is what we're doing?
Well, right now, our schedule shows, as I mentioned, a 2023 kind of construction window to 2020 6, that's the earliest it would occur. We would obviously need to get our permits before that. Some of that depends on what occurs with litigation in the federal permitting. But again, right now, our partners are moving forward with it, and we feel good about the progress.
And is there anything formalized about the process of EPA that was relinquishing there and if you were to acquire it, was there anything ever in terms of a formula under which you would you've already known that you might pay BCA for their share? Or is this just a flat out negotiation?
This is Adam again. It's in the middle of negotiations. We're exploring different asset service and ownership arrangements, frankly, with BPA. One scenario though would include Idaho Power acquiring BPA's ownership share and then we would on the back end provide BPA long term transmission service in lieu of ownership. Scenario, we would have instead of the 21% interest we have now, it would increase up to 45%.
But again, these discussions are preliminary and confidential in nature. At the end of the day, our intent is to maximize the value of the project for all parties. And so we're in the middle of those discussions and we'll advise when we can.
Okay. Different topic the Jim Bridger increasing the depreciation expense. To the extent that the commission was to do the different number, you simply choose that number. And if they chose not to, you can simply not go forward with it. So it's simply a matter of whatever the commission is willing ends up agreeing upon, you'll be able to do that, but if they choose something different that's due to you wouldn't see the request if they gave something different?
Well, it's like if I'm following Vedula, what we're saying is we've got our best information filed. That's what's going in right now with the case that was put before the commission, knowing that a lot of the pieces and parts of that could move or change. And so it's going to allow for those dynamics to move and adjust. I think that's anticipated that there would be updates to that. It isn't it's very difficult to set all of that and be perfect at this point.
So encompassed in that is sort of a dynamic response element to the way the rate mechanism works.
What's the timeline that's been stated for the submission to and process it on this? December?
Yes. I'm looking at it. Yes.
That was a request.
That was a request, yes. Certainly, the commission can take other actions, but that's what it would be under a normal course.
And I guess, the other thing I think you are very curious about, obviously, you mentioned the RFP for the WAF and also highlighting very strong growth in territories. When should we be expecting a update on the capital program? Because it seem like you have minimal base CapEx just to for maintenance of service there, so it would have to be going up given new customers, etcetera. So when should we be expecting a revision on capital program?
I think we give frequent updates with some of the
Yes, it's been going up each of the last couple of years. And I don't have a number to give you for next year, but you're right as growth maybe outputs what you were expecting, it often means you're going to have to spend a little more money in the following year. But that's usually a year end process for us where we update those numbers. And so you'll see your next update from us on just an annual basis would be with our year end earnings release. But we do occasionally put out we'll take it out to all share owners through we've updated our booklets at times and so you might keep an eye on that.
If you haven't, there's some out there, I don't know when the last time the CapEx forecast changed, but the CapEx forecast that we currently have out is, if you haven't looked for a while, may surprise you what it shows that our expectations of growth have gone up quite a bit.
No, I'm taking a look at your investor book and it wasn't clear to me whether there are things that are prospective that are possible. I think you're showing things that are possible to occur versus things that are formally in your official plan?
Yes. It's probably a mix because parts of it are building off of what our normal CapEx program has been, but they change and they do go up at times. And then there's other pieces that are maybe planned or hopeful that timing could shift year to year or amounts change. So it's a blend.
That concludes the question and answer session for today. Ms. Groh, I will turn the conference back to you.
Thank you again to all of you for your continued interest in IDACOR. And we certainly look forward to the possibility of meeting with you in person later this year. And I continue to wish you all good health and have a great evening. Thank you very much.
That concludes today's conference. Thank you for your participation.