Idacorp Inc (IDA) 2006 Q2 法說會逐字稿

Good day, and welcome, everyone, to the IDACORP Second Quarter 2006 Conference Call. Today's call is being recorded and is being webcast live. A complete replay will also be available from the end of the day for a period of 12 months on the Company's website at www.idacorpinc.com. (Operator Instructions.)

At this time, I would like to turn the call over to the Director of Investor Relations, Mr. Lawrence Spencer. Please go ahead, sir.

Thank you, Tom, and good afternoon, everyone. Welcome to our August 8 Second Quarter Earnings Release Conference Call. We issued an earnings release before the markets opened today and that document is now posted to our corporate website. We also filed our Form 10-Q with the SEC, and that document has been posted to our IDACORP website.

Included on the call today are LaMont Keen, IDACORP and Idaho Power President and CEO, and Darrel Anderson, IDACORP and Idaho Power's Senior Vice President of Administrative Services and CFO. We also have other officers here today to help answer your questions during the Q&A period.

Our presentation today may contain forward-looking statements and it is important to note that the Corporation's future results could differ materially from those discussed. A full discussion of the factors that could cause future results to differ materially can be found in our filings with the Securities and Exchange Commission.

Before turning the presentation over to LaMont, I'll briefly recap the financial results presented in today's earnings press release. IDACORP's second quarter earnings report shows net income of $19.9 million, up significantly from $9.5 million in second quarter 2005, and year-to-date earnings of $45.3 million compared with $32.5 million in 2005. Earnings increased by $0.25 per diluted share to $0.47 per diluted share quarter-over-quarter.

For the first six months of 2006, earnings were $1.06 per diluted share compared to $0.77 per share for the same period in 2005. Our chief subsidiary, Idaho Power, had earnings of $0.51 per share for the quarter compared to $0.30 per share in second quarter 2005.

Now, I would like to turn the presentation over to LaMont.

Thank you, Larry, and good afternoon, everyone. Before getting into more specifics about the results Larry has just reviewed, I first want to reiterate our strategic direction at IDACORP. We are focusing on our core business, Idaho Power Company, and are streamlining the overall business accordingly by monetizing endeavors that have been consuming capital, earnings, and effort without a commensurate financial return.

Our actions, both in the past and prospectively, will demonstrate our commitment to this direction. The strategy is enabled by the customer growth in Idaho Power's electric service area that is providing ample opportunity for reinvestment in the utility business we have been in for 90 years. Our leadership team and employees are focused on the dual goals of providing reliable electric service to our customers at a fair price and consistently registering strong financial performance for our owners. We believe that both can be met and we apply ourselves every day to their collective achievement.

Turning now to some specifics, and beginning with Idaho Power Company, the customer growth I just mentioned is continuing in 2006. In the first six months, we added 7,251 new customers. And that's just slightly fewer than last year's record peak. That is a 1.6% increase in customers thus far in 2006. While this growth brings the opportunity for reinvestment in our core business, it also places increasing demands on our electric system. Those demands have been amply demonstrated this summer. [The] effects of higher customer numbers in hot weather resulted not only in new record peak being set three times, also in the previous peak, they exceeded 11 times.

The previous hourly peak load record of 2,963 megawatts was set in 2002. New peaks were set this year of 3,050 megawatts on June 27, 3,065 on July 21, 3,084 megawatts on July 24. In addition, wildfires are prevalent in the West this summer in and around our service territory. These fires have already threatened some major transmission lines critical to the operation of the network. But even under these stress conditions, our system has operated well overall this year in meeting our customers' energy needs.

Our irrigation sales, measured in megawatt hours, were up dramatically - 64% in the second quarter of 2006 versus 2005 - partially due to warmer weather, but primarily as a result of more typical precipitation this year. Last May, we experienced nearly four times the average precipitation, significantly reduced that month's demand for irrigation.

On the supply side of the equation, improved water conditions in the Snake River Basin this year enabled Idaho Power to make better use of its hydroelectric generating system. Last year, April through July inflows into Brownlee Reservoir were only 3.6 million acre feet, or 57% of the 30-year average of 6.3 million acre feet. This year, the Northwest River Forecast Center reported nearly 9 million acre feet of water flowed into Brownlee Reservoir in the same period.

And we provide this information to give you a relative sense of our hydroelectric generating conditions. Please understand, however, that there is not a one-for-one correlation between Brownlee inflows and our overall hydro generation production. There are many factors that impact the amount of hydro generation produced by our system, such as beginning and ending reservoir levels, the timing of the spring runoff, and the dispersion of the snow pack across the Snake River Basin.

On the Idaho regulatory front, our rates changed on June 1. The IPUC approved the implementation of a 3.2% general rate increase that was more than offset by a 19.3% overall reduction due to our 2006/2007 power cost adjustment. The PCA adjustment was a direct result of the improved water conditions. These changes provide both long-term cost recovery to Idaho Power and a welcomed price reduction to our customers following a prolonged period of drought that drove up our power costs.

Also on June 1, new wholesale transmission rates were put into effect, subject to refund, by the Federal Energy Regulatory Commission, or FERC, under our Open Access Transmission Tariff. Settlement discussions with intervening parties are scheduled to occur this summer. The proposed rates would produce an annual revenue increase of approximately $13 million.

The FERC also just released its draft Environmental Impact Statement, or EIS, as the next step in our Hells Canyon project relicensing process. While we still are reviewing the document and caution that it is a draft EIS, only containing first FERC staff conclusions, it appears that their conclusions with regard to the effects of the project and the measures necessary to address those effects, are in many cases consistent with our license application filed in 2003.

In the second quarter, we also booked a $4.7 million after-tax benefit at Idaho Power from the sales of excess sulfur dioxide emission allowances. As discussed in the 10-Q, the proceeds from these sales relative to the Idaho jurisdiction were split 90% to our customers and 10% to our shareowners. Accordingly, this sale lifted second quarter earnings and also will benefit our customers next year when their portion is reflected in our annual power cost adjustment.

Turning to other subsidiaries, on July 20 we completed the sale of IdaTech, our fuel cell subsidiary, to IdaTech UK Limited, a wholly-owned subsidiary of Investec Group Investments, Limited. This sale is consistent with our strategic focus and IDACORP expects to record a gain of $0.24 to $0.26 per share from this transaction in the third quarter. This sale enables us to focus on the higher priority capital requirements at Idaho Power, while allowing IdaTech to realize its potential under the leadership of Investec.

Also, consistent with our strategic focus, we have classified our communications subsidiary, IDACOMM as assets held for sale for financial statements. Darrel will discuss this more fully in his report. And so, I will now turn the presentation over to him.

Thanks, LaMont, and good afternoon, everyone. I will spend a few minutes reviewing some of the key drivers to second quarter results, and will also discuss cash flow liquidity in the 2006 key operating and financial metrics. We then look forward to responding to your questions.

The earnings per share for each business unit have been included in our earnings press release issued earlier today. As expected, Idaho Power Company drove overall results. General business revenues increased by $9 million from second quarter 2005, in part to general business customer growth of approximately 5 million and increased customer usage of approximately $13 million, offset by net rate changes, which lowered revenues by $9 million.

Hydroelectric generation was 56% greater than the second quarter of 2005, which helped reduce net power supply costs and resulted in approximately 7/10ths per share benefit to the annual power cost adjustment, or PCA. For the first six months of 2006, we have reported approximately $0.14 per share benefit through the PCA as compared to last year.

As LaMont mentioned, energy sales for our irrigation customers rebounded increasing 64% quarter-over-quarter. Last year's second quarter was cooler and wetter than this year, especially the month of May, and that kept irrigation sales far below historic norms.

Turning now to the results of IdaTech and IDACOMM, these entities have been recorded as discontinued operations on our financial statements in accordance with Statement of Financial Accounting Standards Number 144. Combined, they recorded a $0.06 per share loss in the second quarter this year versus an $0.08 per share loss in the second quarter last year. The combined losses were $0.10 and $0.14 per share for the six months of 2006 and 2005, respectively.

I would now like to move over to cash flow. For the six months of 2006, cash from operations at IDACORP increased nearly $81 million compared to 2005. The increase is primarily attributable to a $13 million increase in net income over the respective period and changes in working capital accounts of approximately $56 million. Included in the change in working capital is $13 million of cash received from the California party settlement and $10 million from the expiration of a margin agreement related to the original sale of the IDACORP Energy Trading Book.

At the end of June 2006, IDACORP's short-term debt balance was $45 million, down $15 million from the end of March. The net proceeds from the sale of IDACORP Technologies received in July have been used to further reduce this balance, so that at July 31, the short-term debt outstanding at IDACORP was approximately $20 million. Idaho Power had no short-term borrowings at the end of June or at the end of July.

I'll now update you on the key operating and financial metrics for 2006. These are also shown in the earnings press release that we issued earlier today. Our current estimates for operation and maintenance expenses are still expected to be in the range of $250 to $260 million. And capital expenditures are expected to come in within the range of $190 to $200 million. We have accelerated some of the capital expenditures associated with our new peaking resource that we would have otherwise incurred in 2007. The movement of these expenditures is not expected to increase the projected three-year capital spending estimate.

We have tightened the range of expected hydroelectric generation that we expect to produce for the year to between 8.8 and 9.3 million megawatt hours. Through the first six months of the year, we have generated approximately 5.9 million megawatt hours, which is a 76% increase over last year. This represents between 63 and 67% of our total estimated hydroelectric production for the year. The estimated total hydroelectric generation for the year is based on the assumption of normal precipitation and normal operating conditions through the balance of the year.

With the classification of IdaTech and IDACOMM as assets held for sale on the balance sheet and discontinued operations on the income statement, we have excluded the impacts of these operations on our non-regulated earnings per share contribution metric. After excluding the results from these entities from our estimate, we have revised the combined contribution from IDACORP financial and Ida-West Energy, net of holding company expenses, to be between $0.09 and $0.13 per share. As we have previously disclosed, we are expecting to report a gain on the IDACORP Technology sale of between $0.24 to $0.26 per share in the third quarter after all closing adjustments are made.

We are continuing to pursue alternatives at IDACOMM and, as previously disclosed, expect to be substantially complete with that process by the end of 2006.

Our effective tax rates at IDACORP and Idaho Power Company have not changed from our previous estimates.

That concludes our prepared remarks, and we would like to respond to your questions.

Thank you. (Operator Instructions.) We'll take our first question from James Bellessa with DA Davidson.

Good afternoon.

How are you, Jim?

Good afternoon.

The hydro generation during the first half, I think I heard 5.9 million megawatt hours.

Yes.

And then, your forecast is 8.8 to 9.3 million megawatt hours for the year. What was the second half generation last year?

Jim, we don't--I don't have that number right here, but we can get it before the call's over.

Is this a typical type of proportion first half to the second half?

This is LaMont. We'll get you the number, Jim, but certainly the flows once you get into summer are considerably lower than they are during the spring. So we'll get the data for you, but the fact that it is less and considerably less is not unusual.

And I heard that there was - during the formal comments - something that could add $13 million in transmission revenues. Is that in place or is that a prospective proposal, or what is the status there? I didn't understand.

Jim, that is a rate filing we had with FERC regarding a transmission filing that did go into effect on June 1. Total estimated annual revenues off of that is about $13 million. It is--a portion of that is subject to refund, which we have made a provision for that in what we have estimated--at least in--we recorded in June. And so, we do expect--we are recording those revenues currently.

And I see that your mining activity is displaying a loss. Could you go through that--and at least I think it's being displayed on your income statement under this joint venture--not joint venture. I have to turn to the income statement to tell you what line item. Just a second. Losses of unconsolidated equity method investments. Can you tell us about that - how long that might endure?

Jim, you are correct. There is a decline in the contribution coming out of Idaho Energy Resources Company, which is the Bridger Coal Company subsidiary of ours. And we are seeing some reduction in the production as it transitions. And we can turn that over--Jim Miller is on the phone with us also. And we can ask Jim to kind of respond to what he sees in that looking forward.

Yes. Jim? This is Jim Miller. What was your question again?

Yes. It appears that there is a loss being generated at the coal mining activity and I'm just asking how long might that last?

Well, I don't have the specifics on that in front of me. I'm not at the office. But a lot of what we're doing now is we're starting the underground mine, so I think our costs have been a little higher this year. As we start to close down the pit mines, we're [indiscernible] some costs in that. And like I said, we're just exploring and just starting to dig into the underground section, so we're getting better coal. But we're still in the process of expanding into that new area.

How long is the expansion expected to take place? And do you have a duplicate activity going on at the same time, therefore, twice the overhead?

Well, a little bit like that. But we're supposed to be in full production of the underground by next year.

Jim, this is Darrel. Let me just clarify just so--I mean, because you're looking I think on the line item on IDACORP's consolidated financials. If you look at the Idaho Power-only financial, if you have the 10-Q. On there we discuss the earnings under unconsolidated equity method investment where you do see a decline. We have a contribution in last year of about 5.2 million. It has gone down to 3.8 million when you take a look at the six-month ended number in that.

And so, there has been some slight reduction in the earnings coming out of the Bridger facility, but it's not a lot. What you see on the consolidated IDACORP number, that also includes the losses coming out of--where we record the losses that come out of IDACORP Financial. And then, the credits show up down in the tax line as the net tax benefit. So what you see on the consolidated number is the combination of IDACORP financial losses, as well as the contributions coming in from Bridger Coal. So you see a combination of those. You need to go back to the Idaho Power-only financials to kind of take a look at what's coming out of Bridger.

Thank you very much.

You bet, Jim.

And we'll take our next question from Steven Gambuzza with Longbow Capital.

Good afternoon, gentlemen.

Good afternoon.

A question regarding the FERC transmission rate increase. Do you now have a portion of your rate base that is kind of a FERC jurisdictional rate base?

Ric Gale here is head of our regulatory area and he'll respond to that.

Yes. We separate for cost allocation purposes into an Idaho jurisdiction and an Oregon jurisdiction and a FERC jurisdiction.

Would you mind just saying what the current rate bases in each of those jurisdictions are?

I can't do that off the cuff. I can supply those numbers through our Director of [inaudible]--.

--Okay. I'll follow-up on that offline. I guess this is a--is it fair to say that historically you have--you have not unbundled transmission in Idaho and you've had one--you just had Idaho and Oregon. Now you've broken it out into a new bucket essentially.

No. This is LaMont. That's not the case. We've always been a FERC jurisdictional entity and have owned transmission facilities where our [weaning] rates were governed by FERC rules.

Okay.

But it's a relatively small piece of our total plant, but I don't think we have the materials with us today.

Okay. And then, regarding the PCA mechanism--I think in your prepared remarks you mentioned that there was a $0.14 improvement over last year's earnings from the PCA mechanism. What was the--was there a loss that ran through last year?

I'm going to have Lori Smith answer that question.

Hi, this is Lori. I don't have that--I do. Let's see. Sorry. What we had in 2005 was a $0.05 in the first quarter and a $0.01 loss in the second quarter. So a total of a $0.06 loss. So it was a loss.

So essentially, it's like $0.08 of net income associated with PCA this year and--.

--Right. The change from quarter-to-quarter is $0.07. That's correct.

Okay. And then, in terms of the emission sales, what was the actual cash proceeds from the emission sales that you made in the quarter? And over what time period will that cash--the portion that gets returned to shareholders--I'm sorry--to ratepayers. Over what time period will that be refunded?

First of all, let me take you back to the amount of emission sales that shows up in our cash flow statement. Kind of talk a little bit--well, actually, it doesn't show up as a line item in there. But it's an amount that's not a large number in the first part of this year. The main part of those emission allowances occurred last year. And we realized over $70 million of cash that came into the door last year through end of 2005. And that's the majority of that cash that is--has been deferred and will be applied back on a--back to our customers. What we are doing now because we have a final rate order, we recognized the 4.7 million in this quarter once we received a final order from the Commission.

Okay. So that basically--you were basically recognizing the income that the Commission said you're allowed to recognize on what you sold last year?

That's correct.

And I guess you have the ability to retain a percentage of gain on future emission sales. Should we expect to see additional monetizations going forward, or can you kind of put some parameters around what the opportunity is there?

We'll have Jim--can you--do you want to respond to that question? Jim Miller?

I'm sorry. [Inaudible.]

If not, Jim, we can take it. If you're having a tough time. Jim's on a cell phone down in [inaudible].

That's fine. I can call offline. If I could--just one final question regarding the assets that--kind of the asset sale that you're contemplating. In terms of IDACOMM, can you just kind of remind us what assets are actually involved in that business and what actually is for sale?

IDACOMM is a telecommunications provider that basically operates in Boise, Reno, and Las Vegas. Its primary asset these days are key local fiber loops it holds in each of those areas. And as well, they still have--do some Internet service business. But the majority--the biggest value of that asset today is the fiber that it owns in each of those respective markets.

And the book value is approximately 25 million or something like that?

No. We haven't actually publicly--we haven't disclosed that in this quarter.

Okay. But basically, how much is held in assets for sale?

Well, that's a combined number for both IdaTech and IDACOMM. When you look at the number that's sitting in our financial statement, that encompasses both of those two companies. The net number for both of those companies on a combined basis is about 20-some odd million dollars combined.

Okay. And besides there'll be--is there anything else? Any other assets you'd categorize as non-core at this time that you might consider selling over the next 12 months besides what you've already announced and what you've--in IDACOMM?

This is LaMont. On that point, what we're doing at the moment is addressing the underperformers from a financial return perspective, not the performers in the other subsidiaries. It would be IDACORP Financial and Ida-West have been profitable. So we're not looking at any activity with those at the moment. But that said, we'll keep all of our options going forward should the need arise to redirect capital from those subsidiaries into the core business.

Great. Thank you very much for the time.

Let me just--let me go back and address your question on the excess emission allowances, since Jim's got a tough connection there. We do have a certain number of excess allowances that we continue to hold. And our current program right now is that we are evaluating all of our current and ongoing needs in determining whether or not that we would monetize any of those into the future.

But right now, we are not anticipating monetizing any of those current excess allowances as we stand today. As we continue to evaluate our future position, we'll look at it as it relates to our IRP that we'll file later this year and take a look at all of those allowances and emission requirements looking forward. So we don't anticipate right now monetizing any of those current excess allowances.

When will the IRP be filed?

We expect it to be late--late as fall in September.

Great. Thank you very much.

It's in September. This is Jim. I'm sorry. I'm kind of back in there.

Okay.

When we looked at the excess allowances, we've got a couple of things coming up in IRP. We're expecting to probably have new coal plants in that. And we've got 32,000 surplus allowances right now after the sale of the last group. And considering the regulatory climate with changes in emission allowances and regulations, we're not sure what's going to happen with SO2 allowances. And we may need some of those allowances for operation of a future coal plant. So at least for now, it seems like we ought to just hang onto them and see what happens.

We are continuing to watch the market, but we really don't have any plans for selling the excess allowances we have left on the system. At least not right now.

Thanks, Jim.

Yes.

And we have a question from Reza Hatefi with Polygon Investment Partners.

Good afternoon.

Good afternoon.

I was wondering, could you talk about how we should think about 2007 hydro generation? I recently noticed there was a 2007 forecast for 6 million acre feet of water flow issued by the Northwest River Forecast Center last month. How should we think about '07 hydro based upon that forecast?

This is Jim. I guess I can go there. That's leaning again towards normal. We do the same thing in our forecasts as well. We always trend back towards some normal level of precip. The Forecast Center's average number, if you will, is 6.3 million acre feet. So I'm sure they're looking with a full reservoir system to next year, assuming we have normal snow and precip through the winter, we will have more of a normal year next year.

And is normal, again, 8.5 terawatt hours of hydro? Is that right?

That's about right. Darrel, you got those numbers there? Is normal 8.5?

A million megawatt hours of generation.

[Multiple Speakers.]

Great. And that FERC $13 million revenue increase, is that going to be offset by certain cost increases or certain new contracting that's going to offset--that's part of the 13 million, or how should we think about that?

This is Ric Gale. I think you should think of that as increases to the top line, increases to revenue.

And then, how about will there be expense items that are offsetting it, or is it basically a pickup in margin?

I would call it a pickup in margin.

It's just bringing our rate base with regard to the transmission investment current. And so, the expenses that are there are ones we've essentially--investments we've made or expenses we've incurred and now we're getting increased revenue recovery to compensate us.

Great. Thank you very much.

Thank you.

(Operator Instructions.) And we have a question from Peter Hark with Talon Capital.

Yes. Good afternoon.

Good afternoon.

Hi, Peter.

Hi, everybody. Just first, I was hoping you could provide some color on the off system sales margins--net of purchase power expense and the increase in hydro production.

Well, your question then is just kind of put some color around the combination of those three areas?

Yes, sir. More from a margin perspective. I mean, I see a pretty dramatic rise in off system sale revenue and certainly a commensurate pickup in purchased power expense. But it's just trying to get a feel for the margins you're seeing on those.

Right. And I--we'll start this. There's--this is a--that's a pretty open-ended question and I will attempt to dive right into it and give you some color. First of all, you have to go back, and this is really a process driven by our risk management program in how we provide resources for the system and for our customers. And so, it really kind of goes back to how we look at that going forward. And we make estimates of what we believe the estimated resource requirements are going to be. We do an estimate of what we believe the estimated resources--if they're going to be there.

And then, from that point forward, we - as part of our risk management program - we begin a hedging program on a longer-term view of this. And so, in our case 12 to 18 months. And so, as it relates to that, we will begin that program whether that means we are buying or we are selling, depending on what the numbers look like as we look forward. And so, coming back to your question, when you take a look at where we're at through the first six months of this year, you see, for instance on the off system side of things, you see that in 2005 we sold for an average price in this particular case of around $42. And this year we're in and around $42. So in that case, we sold--the off system sales came on about comparable year-over-year.

Now when you take a look on the purchase side of things, similarly, we had an increase in purchases. And there again, on--as a six-months number, we--it cost us about $48 last year for the first six months, and it cost us about $48 this year for the first six months of the year. So--and that's an average number, but that just kind of tells you we kind of take a longer term view as we try to manage the system.

And so to--I'm not sure--to put any more color on it than that, LaMont has--may have some comments.

The only thing I'd add to that is we are not a trader. Our transactions are either buying energy to meet our system needs or selling surpluses. So as Darrel articulated, most of the purchases you see us have in the second quarter of 2006 were made--the transactions were initiated prior to the start of the quarter. As we looked forward at the water year 2006 in the fall of 2005, we expected a below normal water year following five years of drought and having depleted reservoirs.

As we move into that period then, we have our own resources, plus the purchases that we've largely contracted for in advance. And to the extent they exceed our loads, we have sales into the marketplace. So that's what we're doing is using our system resources and the purchases that we've made. Now that--on any daily basis or hourly basis we could have sales or purchases to balance our loads vis-à-vis the market. But we are not out buying from others and reselling.

Got you. But to extend a little bit further, as you mentioned, July--a pretty hot period. How would you have positioned yourself going into this abnormally hot period?

Well, going into July in almost any summer, even a normal year, we have a need for purchases. So we would position our book in advance, again, pursuant to the risk management strategy that we have in effect, to have sufficient resources to cover our loans. Now when you get into a period where you have much higher than normal anticipated retail loans, [we] may not have assumed that retail loans would be that high, which would require us to go back to the market or increase generation at our facilities, like our gas plants.

So we do manage that real-time, but we also look ahead and go--try to go into every month with the resources we need to cover our loans.

Got you. Thank you. The second question is on the rate increase effective June 1 - the 18 million. How much of that would you realize this year in '06? And then, how much of it would roll into '07? Is it a pro rata distribution? In other words, will you see 7/12ths of it roughly here in '06 or would more of it be concentrated this year due to summer sales?

Let me just clarify your question first. This is Darrel. Let me clarify your question first of all. You said an $18 million increase?

Yes. The 18.1, effective June 1. Is that right?

Yes, okay. I was just making sure your--which piece you were talking about and make sure it wasn't the transmission piece. But we--there is some seasonality to how we collect that number because we do have seasonal rates in effect from January--from June through August where those rates are higher than the balance of the year.

I'm looking at Ric now to ask him if he has a sense as to the--how he would expect to kind of look at that over the 12-month period. Do you have any sense you want to--?

Well, my take on it would be a higher weight because you're picking up the summer months, the summer rates, which are proportionally higher than the non-summer rates. And then, you have the higher volumes in the summer as well. So--be better than the 7/12ths.

Okay. Okay, that makes sense. Thank you. And then, the next question was on D&A expense. Just remind us again why we're seeing a declining D&A line.

We're going to have--Lori Smith is going to talk to that question for you.

Okay.

Good afternoon. What we have is we have a previously settled depreciation arrangement with our Commission. And in that there were several classes of assets that were accelerated from a depreciation standpoint. That was completed at the end of 2005. And so, going forward we will have the impact of that reduction. Of course, it will begin increasing as we close more assets to plan. But that's the main reason you see that change.

Okay. Okay, perfect . And then, on the O&M side where you say you're still on target for 250 to 260. And you've done about 132 through the first six months. Again, seeing probably then a similar amount of O&M in the second half of '06, how does that compare to the second half of '05? Is that a slight increase or so in O&M second half versus second half?

I don't have the second half/second half comparison for you. I will tell you though that the second half of last year's O&M was impacted by additional payroll incentive accruals that occurred in the second half of the year as we were attaining targets. We can get that information for you. We don't have that right now available to you.

Okay.

But we can estimate what those are. But we still do believe we're in the 250 to 260 range as it stands right now. We will obviously have an update for you as we go into the third quarter call.

Got you. Thank you. And then, the last question is on capital requirements where I've seen in the Q that you're saying that due to current performance that you're actually internally covering more of your CapEx here in '06.

Right.

Gone to 58% from 43. But given the sale of IdaTech and what might happen with IDACOMM, is it possible that you would then cover all of your caps closer to--all of your CapEx for '06?

No. It's fair to say that the proceeds--as we indicated earlier, the proceeds we received from the IdaTech sales we used to reduce short-term borrowings at the holding company. And it would be expected likewise that we would use those same proceeds--any proceeds from an IDACOMM transaction would be similarly applied there.

However, I will say that the increase is the result of a number of things. One of those is that as we had previously anticipated or as we were including in the original number that we provided was some sense that the emission allowance cash would go back earlier than it's going back. And so, that changes the amount of how much cash goes out the door this year. It will eventually go out as we look at it next year, but for 2006 it didn't have an impact on--it did have a tendency to increase that percentage.

I got you. Because I guess the point I'm getting to somewhat is the fact that interest expense on long-term debt is fairly flat. And suggesting that you're not doing any incremental borrowing as of yet to finance capital spending. And I didn't know when we'd start seeing maybe--I guess an increase, a slight increase in interest expense there.

Right. A couple of factors there. Obviously, one of the things we are very focused on is credit quality. And so, we're doing everything we can to not have to go out and incur additional debt as we try to continue to strengthen that overall. Now it is fair to say that as we continue down the capital program, and subject to things like water conditions and other things, we will be looking to have to continue to keep that capital structure balanced as we move forward.

We do have a small amount of equity that goes out annually through our dividend reinvestment program as well--as part of that program. And so, we do have a little bit of equity that's coming in and we'll continue to keep that cap structure balance and we will--to the extent we have to, we will issue debt to manage the capital program. But right now, we're looking to keep a balance and we're not foreseeing a huge increase in financing needs at least through the balance of '06.

Right. And actually, looking out beyond, I was trying to find if there's a way for you to avoid any incremental equity issuances, aside from the [trip side], through the rationalizations of assets that you're currently performing.

Right. And I think that we will--our focus is going to be on keeping the cap structure balanced. And while we don't necessarily want to have to issue new equity, we will kind of continue to evaluate that as we move forward. But right now, we have no plans outside of the current dividend reinvestment program, even though the tools are available for us if we were so inclined.

That's perfect. Thanks for your time and answers. Thank you.

Okay. I want to get back--just a follow-up response to Jim Bellessa's original question regarding the question on the generation question for the balance--as comparing to where we were a year ago. And the second half of 2005, we generated approximately 2.9 million megawatt hours in the second half of the year. If you take what we have generated through the first six months of this year and you look at our estimate of 8.8 to 9.3, that would give you a number for us for the balance of the year between 3.0 and 3.5. So that at least gives you some sensitivity to what we would've produced in the second half of last year versus what we expect to produce in the second half of this year.

So, Jim, hopefully that helps you answer your question.

And we have a question from James Heckler with BKF Asset Management.

Good afternoon.

Good afternoon.

Just a clarification on a transmission--the new revenues from the transmission assets. You had mentioned that there was--some was subject to refund - in your initial comments. But in response to someone's question you had said we should basically consider that a margin improvement. And I was wondering if you could just clarify that for me once and for all.

We do have interveners in that proceeding as it stands, and we're working through that. And so, we are recognizing the--a component of that revenue currently. And then, we are also providing some level of provision for refund in accordance with the proceeding. And so, we will work through the proceeding, which we hope to have wrapped up by the end of this year or before. And that's where that stands. I mean--Ric has got a comment on the proceeding, if you need some more information.

Yes. If you could, is it--on an order of magnitude - percent of the 13 million - how much is being sub--reserved, basically?

We haven't disclosed that specifically. We don't believe it's a significant amount as it relates to disclosure. So you can kind of take that. We haven't disclosed that though as a specific item, especially given the fact that it's still an open proceeding.

Sure. Thank you. And just one other question on your financial metrics for 2006 and your current estimates versus your previous estimates. In your non-regulated subsidiary earnings, you moved your range from a negative $0.05 to $0.00 to $0.09 to $0.13. And I was wondering if that movement and the range was--can completely be explained by the sale of IdaTech or if there's something else there that we should be thinking about?

Well, let me clarify. We added a footnote in the release and in my remarks I made, I wasn't very clear in my opening remarks. But what we have done with that range basically, we have excluded both IdaTech and IDACOMM from that earnings guidance range. So we've excluded both of those businesses because since we've now classified them as discontinued operations, that number is - as we've stated there - is non-regulated subsidiary earnings per share from continuing operations. So excluded from that number is anything related to IdaTech or IDACOMM. It includes our estimates for IDACORP Financial, Ida-West Energy offset by our holding company expenses.

Okay. Thank you very much.

You bet.

And we have a follow-up question from James Gambuzza--I'm sorry, Steven Gambuzza with Longbow Capital.

Hi. I was wondering if you could just tell me what the total rate base, including Idaho, Oregon, and the transmission is, as opposed to breaking it out individually - at the end of 2005?

Okay.

Approximately.

Sure.

Steven, this is Ric Gale. And I asked one of the analysts to gather that information since it was asked the first time. And we're using a test year '05 for the analysis. It shows total combined rate base of about $1.8 billion. And in percentage terms, Idaho would be about 92% of that. Oregon, 5%. And then, there's two parts to FERC. It's the FERC wholesale customers - they're a little less than 1%. And then, the transmission piece is about 2%.

Great. And that's a year-end 2005 or an average 2005?

I can't clarify at the moment. I just had an analyst come in and give me the best shot he could while we're still on the phone.

Thank you very much.

And we did have a follow-up question from James Bellessa with DA Davidson.

Hi, Jim.

Hi. During the call, I think I heard that you used the metric for the 30-year inflow into Brownlee. And I think I heard at the meeting it was 6.3 million acre feet over a 30-year period.

That's the River Forecast Center's number.

Oh. Because I was wondering why you were using that statistic when the last call you were saying that the median was 8.5 million megawatt hours over the period of 1928 to 2004.

Jim, this is Darrel. I think--and I'll make sure we clarify it. 8.5 million megawatt hours versus the 6.3 million acre feet inflows into Brownlee. So one is the hydro--estimated hydro generation. One of those is the inflows into Brownlee.

Oh, I see. I'm sorry. I misunderstood then. I mixed up the million acre feet with a million--.

--Megawatt hours.

Okay.

Okay?

And the 6.3 is just April through July.

Right.

Thank you.

You bet.

And we have another follow-up question from Reza Hatefi with Polygon Investment Partners.

I just had another couple of questions on the FERC rate case. So what--can you give us an estimate of what ROE you think you're currently earning? Because I guess from your 10-Q you applied for an 11.25 ROE.

For the FERC jurisdiction?

Correct.

I need to follow-up with you through Larry on that.

Yes. I'll follow-up, Reza.

Okay, great. I'm just kind of confused because taking your 1.8 billion rate base and 3% of that is about 54 million. So it just seems like 13 million revenue increase on 54 million of total rate base, it just seems like an awful lot. Is there something else I'm missing here?

Well, the--or the FERC filing was a movement to formula rates, which changed the basic way that we approached FERC rates for the first time in over 10 years. A breakdown of those components, I think we're just going to have to do offline separately because I'm not prepared to do it at this moment.

Thank you very much.

And we have no further questions left in our queue at this time. Mr. Spencer, I'll turn the conference back over to you.

Okay. I'd like to thank everyone for your interest in IDACORP and our Second Quarter Earnings Release Conference Call. Goodbye.

Thanks, everybody.

This does conclude today's conference call. We appreciate your participation. You may disconnect at this time.