Idacorp Inc (IDA) 2003 Q1 法說會逐字稿

Good day and welcome to the IDACORP first quarter 2003 conference call. Today's call is being recorded and is being webcast live. A complete replay will also be available from today for a period of 12 months on the company's website at www.idacorpinc.com. If you should need technical assistance at any time during the presentation you may have technical assistance by pressing star zero. And at this time I would like to turn the conference over to the Director of Investor Relations Lawrence Spencer.

Mr. Spencer please go ahead. Good afternoon and thank you for participating today in our quarterly conference call.

Today, Jan Packwood IDACORP President and Chief Executive Officer, will recap IDACORP's strategic highlights for the quarter. Lamont Keen, Idaho Power President and Chief Operating Officer will review Idaho Power first quarter operations.

Darrel Anderson, IDACORP Vice President, Chief Financial Officer, and Treasurer will discuss our liquidity, financing activities and earnings guidance as well as the common stock dividend. Then we will open it up for questions. Other officers are also here with us today and will be available to help to answer questions.

Now, 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. Also, the information in this conference call related to projections or other forward-looking statements may be relied upon subject to the previous Safe Harbor statement as of the date of this call and may continue to be used while this call remains in the active portion of the company's website.

Now I would like to turn the presentation over to Mr. Jan Packwood.

Thanks, Larry.

Welcome everybody out in analyst land. I hope you notice we took your suggestion and moved our date away from late Friday afternoon into mid-week and a little earlier in the day. I hope this time works better for most of you, particularly those of you in the eastern time zone.

Our first quarter results are disappointing to us. We're certainly not pleased to be reporting a loss.

That said, the poor financial results do mask good progress in doing the things we set out to do, mainly lower the risk and maintain liquidity. We are putting the issues from the 2000 - 2001 western energy crisis behind us and focusing on the core competencies of what has always been and will continue to be a first class utility business.

As we announced last week on May 1st and reiterated again this morning in our announcement, first quarter earnings were affected by a number of factors. The writedown associated with settling a legal dispute with the Overton Power District Number Five over wholesale energy contract, the effect of past quarters above normal temperatures on revenues at Idaho Power, and the continuation of below normal precipitation that is affecting Idaho Power's generating capacity and putting pressure on production costs.

I'm encouraged by the progress we are making in reducing our risk. Our cash from operating activities remains positive.

We have renewed our lines of credit and we are refinancing existing debt to capitalize on lower cost opportunities. In addition to the settlement agreement, I would like to mention a few other notable achievements during the first quarter that further demonstrate we are moving toward better times in 2004.

First, you may recall in January, we settled another agreement with the Truckee-Donner Public Utility District over a contractual dispute. Second, our wind down of IDACORP Energy continues to progress smoothly and on schedule.

Since the end of last year, we have decreased our credit exposure by another 23%. Liquidity requirements are 15% less, capital at risk has dropped by about 10%, and our value at risk stands around $240,000 down from almost $700,000 at the end of last year.

Staff reductions are still significant. IDACORP Energy had 31 employees at the end of the first quarter, a drop of 26% from the 42 employed at year's end. It is anticipated that by the end of May we'll probably be down right around 24 employees.

Third, we success fully closed on two 364 day credit facilities while reducing the size of the overall facility. Darrell will provide a little more detail on those accomplishments in a few minutes.

Finally, our primarily focus continues to be the performance of the utility. In mid-April we filed our annual power cost adjustment with the Idaho Public Utilities Commission. If accepted as filed, that will reduce our Idaho retail customer rates by an average of 18.2% and certainly for our customers signals beginning of a return to more normal energy costs.

In addition, we still expect to make a general rate case filing later this year. Our goal is to make current the recovery of our costs that are not addressed by the PCA mechanism.

In the meantime, we are containing our O&M and capital costs to the full extent possible while still complying with what we consider to be all prudent utility practices that are commensurate with our obligation to serve.

I'll turn the call over to Lamont to discuss in a little more detail Idaho Power's operations for the quarter.

Thank you, Jan and good afternoon everyone.

Since we are a predominantly hydroelectric utility that depends on snowfall for part of our fuel supply, this past winter was a disappointment to us. We watched the national weather news with envy as we saw much of the East Coast and other parts of the country buried from time to time under huge snowfall.

In a normal winter we see that sort of weather here in Idaho as well. But this was not a normal winter.

For starters, first quarter temperatures were much warmer than usual. Overall for the quarter, heating degree days were down 19% when compared with the previous year.

Despite adding more than ten thousand general business customers over the past year and having higher rates in effect from the 2002 PCA, our first quarter general business revenues were down $11.1 million or 5.9%. Further, since October, precipitation and snowpack in the Snake River Basin has been approximately 85% of average.

Precipitation or the lack thereof and the resulting stream flows obviously affect our ability to generate electricity at the hydroplants. Precipitation levels were higher in March and April than they were in the early winter, but we do not expect that to translate into average stream flows in the Snake River this year.

Three years of drought have depleted the Snake River Aquifer and upstream reservoirs. Much of the water from this spring's runoff will therefore be captured in those upstream reservoirs. The Northwest River Forecast Center is now projecting that April through July inflows into Brownlee Reservoir will be 3.6 million acre feet. A little better than last year's 3.3 million but still far below the average inflow of 6.3 million.

On April 15th, we filed our annual power cost adjustment with the Idaho Public Utilities Commission. As filed, this year's PCA would reduce overall Idaho retail customer electricity rates by 18.2%.

The decrease primarily results from lower power supply expenses over the past 12 months and we expect a new PCA rates to be in effect on May 16th. The PCA has been a valuable tool for us during the energy crisis in recovering most of the resulting increased power supply costs, but we have not had rate recovery for infrastructure improvements for nearly ten years.

During that time we have in incurred increased capital costs related to acquiring new licenses for some of our hydroelectric projects, bringing new generation sources on-line such as our Danskin gas plant that we brought on a couple years ago, and expanding our transmission and distribution grids.

And our operating costs have also increased over that ten year timeframe, and as a result we still anticipate filing a general rate case in Idaho later this year.

And with that I'll turn it over to Darrell Anderson who will discuss financial issues.

Thanks, Lamont. And good afternoon to everyone.

Earlier today we filed our quarterly report on Form 10-Q that includes a more detailed discussion of some of our quarterly results. This afternoon I'm going to focus on some of the key issues that impacted these results.

Before we get too far into the quarterly results, however, I want to reiterate our comments in the earnings release related to our effective tax rate. The financial results for the quarter reflect the company's estimated annual effective tax rate of zero.

This rate is the result of forecasted annual pretax income being at a level such that annual tax credits and regulatory flow through tax deductions are expected to fully offset income tax expense for 2003. For purposes of reporting earnings per share by subsidiary, each subsidiary stand alone effective tax rate for the quarter has been utilized.

The adjustment necessary to reach an estimated annual effective tax rate of zero for the combined group of companies as required by Generally Accepted Accounting Principles has been recorded at the holding company.

With that short summary, let's quickly run through some of the numbers. Our first quarter loss of 8 cents per share is a marked decline from our earnings of 66 cents per share during the first quarter of 2002. We recorded a net loss of $3.1 million in the first quarter this year compared with net income of $24.7 million during the first quarter a year ago.

Our results include the effects of a $21.5 million noncash charge related to the settlement of the Overton dispute. Includes $10.6 million of benefits related to settlements of other disputed amounts at IDACORP Energy that we had previously forecasted as part of the winding down of the business.

Heating during days that were 19% less than last year's first quarter in the region served by our utility contributed to a reduction of revenues that Lamont has already previously discussed.

In summarizing the first quarter contributions by subsidiary, they can be summarized as follows. Idaho Power's first quarter contribution was 36 cents per share compared to 57 cents per share a year ago.

IDACORP Energy recorded a loss of 28 cents per share compared to a profit of 11 cents per share during 2002 first quarter. IDACORP Financial increased its contribution to 6 cents per share, a 1 cent per share improvement.

IDATech performance improved by 3 cents per share as it registered a 1 cent per share loss during this year's first quarter, compared to a 4 cent per share loss in 2002. IDAWest Energy registered a breakeven performance during the recent quarter, a 2 cent per share improvement from a year earlier.

And a combined operations of IDACOMM and Velocitus broke even during the first quarter in both 2003 and 2002. The holding company recorded a loss of 21 cents per share compared with a loss of 1 cent per share during 2002's first quarter driven principally by the impact of the interim tax allocation noted earlier.

Now I'd like to move on to some other topics starting with our cash flow. Net cash provided by operating activities for the quarter was $95.5 million, down from $110 million in last year's first quarter.

Increases in cash proceeds from our PCA collections were offset by changes in working capital accounts and decreases related to the $41 million we received last year in the form of income tax refunds. Cash used for investing purposes decreased from 2002 levels by almost $39 million due to reductions in our investment in affordable housing projects.

As Jan noted earlier, in March of this year IDACORP and Idaho Power successfully completed the closing of $175 million and $200 million 364 day credit facilities. IDACORP also has a 3 year, $140 million facility that expires in March of 2005.

The company believes that the amount of liquidity available is sufficient to manage the winding down of IDACORP Energy and to support the ongoing operations of Idaho Power Company as well as the other nonregulated subsidiaries. At March 31st, IDACORP had approximately $103 million in commercial paper outstanding against its $315 million facility that was available to it.

Idaho Power had no commercial paper outstanding against its $200 million available and in fact had $26 million invested in short-term investments.

As we look forward for this year and as it relates to financing plans, on May 1st, we redeemed, we actually had $80 million of 6.4% first mortgage bonds that matured and we redeemed $80 million of 7.5% series first mortgage bonds. We issued short-term debt to pay these bonds and expect to issue additional bonds in the near future under favorable terms from the original issue.

As indicated in our last conference call, we are also considering refinancing approximately $50 million of 8.3% pollution control bonds that become available in December.

We would like to kind of discuss a little bit now on earnings guidance. As we've previously discussed, our 2003 earnings contributions will be heavily dependant on the results of Idaho Power Company.

Because of the warmer than normal weather and the charges associated with the settlement agreements at IDACORP Energy, we have lowered our 2003 IDACORP earnings guidance to between 90 cents and $1.15. The revision to our earnings guidance is attributable to following changes in our annual operating plan.

As previously mentioned, the settlement of the Overton contract, we've discussed reduced general business revenues from our utility customers as a result of warmer than normal winter weather and expected slow down in the economy this year. And also changes in net power supply components consisting of surplus sales, purchase power and fuel net of the PCA impact due to the changing weather conditions that Lamont's previously mentioned.

A breakout by our major business units of the expected results is as follows. Idaho Power Company is expected to contribute between $1.20 to $1.40. IDACORP Energy including the writedown of the Overton litigation is expected to loose between 44 cents and 34 cents a share.

And the combined results of the rest of our businesses are expected to earn between 10 cents and 20 cents a share. If you add those up, obviously the highs and the lows of each of ranges, you come to a range of 86 to $1.26, which in management's mind and estimates fits between the 90 cents and the $1.15.

We obviously don't anticipate either all the highs or all the lows, but it is management's best estimates on where those ranges will fall.

Cash flows from operating activities which are before capital expenditures and dividends, are forecasted to be in excess of $225 million at IDACORP, and in excess of $190 million at Idaho Power Company.

I want to now move to discussion and have a brief discussion about our dividend. As we have just discussed, the company's cash flow remains adequate but the dividend now significantly exceeds our forecasted earnings for the year causing concern for some investors.

With the wind down of IDACORP Energy, the long term sustainability of the dividend is now primarily dependant upon the profitability of Idaho Power Company, IDACORP's major subsidiary. Idaho Power's earnings depend on many factors, but the most significant are weather and water conditions, and the ability to obtain rate relief to cover operating costs.

If Idaho Power is successful in obtaining the general rate relief to be requested this fall, and there is a return to more normal operating conditions this winter, 2004 earnings should rebound significantly. However, management and the Board of Directors will obviously continue to evaluate these and other factors in determining the appropriate and sustainable level of payout to IDACORP owners going forward.

With that, we would now like to open it up for questions.

Thank you. Ladies and gentlemen, we will begin the question and answer session. At this time, to ask a question you may do so by pressing the star key followed by the digit one on your touchtone telephone. And again we ask that you limit yourself to two questions so that everyone does have an opportunity to participate. Again, star one if you do have a question. And we'll take our first question from Greg Schultz with SAB Capital.

Hello. It's Greg Schulz.

Hi, Greg.

Hi, a couple questions . You guys talk about earnings might rebound if weather gets better and you get the rate case. Can you give me a feel for what that might be under normal circumstances what do you think the utility can earn?

Well, this is Darrel. Historically as we have addressed this particular question in the past, we always kind of go back to what should the utility be able to earn.

Um-hmm.

And when we take a look under the assumption of a return on equity number of say in the range of 11%.

Yep.

If we use that number, and if we use the current equity number you can take and come to a number of what the utility should be able to earn in a more normal period of time. And we have always said that number is obviously somewhere north of $2.00, so I think those you know, it's subject to obviously water conditions, and obviously subject to, as we indicated earlier getting successful rate relief going forward. Those are all factors that need to be looked at in determining what the true earnings potentials of the utility can be.

Sure. And then on top of that the unreg stuff would add another 10 to 20 cents typically on an annual basis?

We believe that depending on obviously the results we continue to invest in IDATech operation. We've indicated that it continues to, we continue to invest in that on a growth basis and therefore we don't anticipate contributions from that entity, but combining that with our other businesses, we do anticipate on a net result, positive results coming out of those businesses.

Okay. And what are you guys asking for in the general rate case? Have you made a filing yet?

We'll let Lamont address that question. He's closest to that.

Hi, Greg, this is Lamont Keen. No, we really don't anticipate making the filing until this fall. And in an earlier call I guess, last quarter, I was asked a similar question and in that call we kind of bracketed the range as between 50 and $75 million, and we still think that is a pretty good ballpark for where the request would fall, most likely using the 2003 test year which is why it would be later in the year versus earlier in the year.

And this is primarily to make up for all the CAPEX you've put in over the years?

Exactly. Our base rates today are based on a 1993 test year.

Right.

That we filed in '94 and received the rates in 1995 and we have added roughly ten thousand customers a year over that time frame, so it's significant capital investments. And we've managed expenses well, we were growing at a compound rate of growth 3% or so in that 10 year period. But even so, we have a need for some additional rate relief to cover those expenses as well.

Got you. And final question would be, the, you guys kind of guided to cash from operations of $190 million at IPC?

Correct. That -- that's correct. We said we'll exceed $190 million.

Exceed that. Do you have some idea what you might get from the PCA recovery in the cash flow number to get to that? Because to me, it seems like the number would be much bigger than that and I don't know if you're just being very conservative. I know you have $126 million of regulatory asset out there. Any idea of how much of that 126 you think you can recover this year?

Well, at the end of March, we have the total deferral that we have at the end of March is $90 million. Which is comprised of a number of different components.

Um-hmm.

And we can give you a majority we are asking right now we have a request in for the PCA collection for the '03 '04 year is, I believe $80 million is the request, and so, but the current balance left on the $90 million, 14 of that relates to our Oregon deferral.

Right.

And then the balance of those dollars are expected to be collected in this upcoming rate period which covers obviously goes in a piece of '04.

So it was 126 the end of the year and then you collected 50 and now you're down to 76.

Right. Actually the end of the year balance was $140 million of which 14 related to Oregon and that's how you get to the---.

Got you. Okay. Thank you very much.

We'll take our next question from David Thickens with Deep Haven Capital Management.

Hello everybody.

Hi, David.

Hi, David.

Just following up on the PCA recovery your PCA is going down to about $80 million. Am I correct? Or the $80 million this year includes, I had a schedule of it, about -- it was $16 million I think you said from prior deferrals, and then of the balance it was a true up off of last year and then a slightly smaller amount than the true up for your expected additional power costs for this year. Am I correct?

That's right.

So if we jump forward a year and look at kind of the cash flows out of the PCA for the following year, assuming that we come in fairly close to your forecast and there is no need for true up next year, based on this year's forecast, and you assume that we're going toward a more normal year, PCA would, the cash flow coming in from the PCA would decline to a fairly small number next year would it not? When it gets reset in the following May? I'm just trying to make sure I have all the different moving pieces of that correct.

I think under the assumptions, David, that you had there, that's correct.

Okay. Okay. I guess my question is with the PCA obviously declining but the expectation that cash flow from operations from having lower power costs would increase, and the fact that right now you still are eating 10% of the excess power costs, I guess I'm surprised that you state in the Q that you expect free cash flow defined as operating cash flow less CAPEX and dividends to still be, I think you said you expect to generate about 78% of cash flow less CAPEX and dividends internally. So, I mean, you're running free cash flow negative this year versus an expectation at the last guidance of about flat, and then you say roughly similar levels for the '04 and '05 time periods. I guess I'm kind of scratching my head a little bit about what, why you, why that's flat. Why it wouldn't be increasing more if we're assuming a return to more normal weather and water?

David, part of that is the projected increases in our capital spending program in 2004 and 2005 and support of our transmission distribution system as well as some estimates in those CAPEX numbers for a resource that we would need to -- that we have projected to build.

Okay.

So the primarily driver there is increases in our CAPEX program in '04 and '05.

Okay. Then taking that and just kind of jumping back to the dividend policy. I do realize this is a board decision but obviously the board is going to rely heavy on the input of senior management when making their decision. So I'd like to get a little bit better understanding of your thought process.

You said obviously, we've got you know, utility performance as it relates to weather and water conditions and then rate relief as kind of the the two biggest variables here going forward. But if you're not going to file the rate case until this fall, and then presumably sometime next year get some kind of answer on the dividend, is that saying that you know, things are status quo in -- you know, out close to a year or, you know, given the negative forecast and the fact that we are by my calculations, you know, about a dollar per share in the hole on a free cash flow basis this year. That's a convoluted way of saying, can you wait that long before you make a decision about the dividend?

David, what we intended to convey and my previous comments are the fact that the dividend is predicated on a number of different assumptions and I think given where we stand today we need to see how those play out. And it will ultimately be a board decision obviously with a lot of input from management. But we have to see as we look forward, how the outcome of those issues are in order to determine our recommendation to the board.

And it is going to be heavily dependent upon those two factors as to our sustainability going forward. And we wanted to get that, we tried to make that as clear as we could in those comments and that is what we attempted to do. So I think that given what we see for this year and as we look forward we are going to be looking to next year's -- this next water period to see what kind of water we have and how successful we are in rate recovery.

Okay. So that it implying that you feel confident that you'll not have to reduce the dividend, you know, this, you won't have to take -- that implies to me that you're confident you will not have to take action on the dividend this water period, this calendar year, if you're not going to know anything about rate recovery until next, until sometime in calander '04?

And my response there David is going to be, we will look at that on an ongoing basis and make our recommendations to the board as those things develop.

Okay. Thank you.

Our next question will come from Zack Schriver with Duchenne Capital.

Hi, guys it's Zack Schriver from Duchenne Capital Management.

Hi, Zack

Just wanted to follow up on David's question and just make sure that I got it clear. In reading the statement on the dividend in the 10-Q, I think the dividend is a function really now with the winding down of IDACORP Energy of the ongoing earnings power of the utility which is a function of hydroconditions and how you get treated for our rate relief at the commission. Given that and given that we won't know how the hydro is until the next hydroseason, and won't know about the rate case until late '03 at the soonest. probably early, mid '04 maybe even at the soonest, to follow on David's question and that those outcomes won't be known until then, does that mean that there is no change in that policy expected until those factors are known? Or does that not mean that?

I think you know, I'm not sure how to rephrase your question different than as I responded to David.

You kind of gave a different answer to two of David's questions which is why I'm trying to clarify.

Well, I think the reality of it is, it continues to be a board decision.

Yes, sir.

We will continue to review the results. Our focus as we look forward, will be on our continued ability to bring in cash in order to support the operations of the entity and also take a look at what we can provide back to our owners.

I'm sorry what was the last part?

As to what we can provide back to our owners.

Great, great. How do your rates compare with other utilities in the state, with other utilities in the region? When was the last time the relevant commission which you are going to be going before after you went through a full blown rate case, what was your last allowed ROE? All these questions that we used to ask folks 7, 8 years ago.

Lamont will take part of that and then depending on what doesn't get answered we'll fill in.

I think I can remember most of those. It was several questions in one there.

Sorry about that.

It has been a while since we were before the Idaho commission as I mentioned for a general rate increase. We had a general rate increase in 1995 and we also had a plant or two that came on-line after that where we had sort of a one time adjustment for those plants. But it's been a fairly long hiatus since we were there.

Our rates on a basis not counting the PCA increases in there are among the lowest in the nation versus any one around us or anywhere else in the country. They're slightly inflated now as a result of the power supply cost, but that's temporary and goes away when water conditions come back. So on that basis, our rates are very low as I indicated our general rates have not changed in going on 8 years now. So it has been a long time since we were in there. We have done a good job managing costs and we're as cautiously optimistic as we can be that if we go in and make a good case to our commission, we have a good shot at at getting some rate relief. Because again the number I gave was 50 to $75 million. Another way to look at that is it's roughly 10 to 15%, for as long as we have been out that seems like a fairly reasonable amount.

We have had added significant number of customers and a significant amount of plant in that time frame and it is just time for us to go in and try to move our base rates up somewhat as well. So that's kind of the status of the rate case. Now was there a part of your question that I missed there or not?

I think I guess what was -- what was your last allowed ROE?

It was 11%.

In '94.

11% on common equity.

Okay. And what was the PCA reduction that you just proposed to be effective on May 16th?

It was a reduction of $114 million from $195 million down to $81 million.

And has there been any sort of political response to that reduction? Has there been any response from the commission?

Well, political I'm not sure. Certainly in the public there is a sense relief that the rates are going in the right direction from their perspective. The staff of the commission actually file their comments tomorrow.

On the PCA?

On the PCA.

Is there any deadline for prosecuting a rate case? Certain states have like an 11 month deadline once they are filed.

In Idaho with some rare exception, I think they can add a couple of months. The normal process is seven months.

Beautiful.

But it can take as long as nine.

Thank you so much.

You bet. Thanks Zack.

Next question will come from James Bellessa with D.A. Davidson and Company.

Good afternoon.

Hi, Jim.

When you filed for your general rate increase do you believe that you'll ask for an interim increase?

Yes, we do. We believe we will. I can't be as specific with regard to amount. It won't be for a 100% of what we ask for but we will ask for an interim for some portion of the filing yet to be determined.

What is your experience in asking for interim rates or the other utilities that are in the state?

I don't think there is a lot of experience. In our case, I think we obtained interim rate relief once when we had a power plant that was just coming online. Beyond that we have historically not requested that. I have Rick Gale sitting here. Do you add anything to that or not.

No, not during my tenure have we requested interim.

There isn't a lot of track record there, Jim, I guess is what we're saying.

Last week you put out a press release and indicated that operating cash flow for 2003 was expected to be in excess of $200 million. What is your definition of operating cash flow?

Jim, our definition of operating cash flow is the GAAP definition as provided in our statement of cash flows that we report on a quarterly basis so it would be that definition. It is before investing before financing activities.

Thank you very much.

You bet.

We do have a follow-up from Dave Thickens with Deep Haven Capital Management.

Can you help me a little bit on what the existing regulatory equity level is at the utility? I saw on the 10-Q, I believe it was the GAAP equity level was I believe $771 million. Are you fairly close to that from a regulatory perspective?

We -- David we are going to try to confirm that for you. We believe it is in that range. I don't have that specific number in front of us right now.

Are you asking, this is Lamont, David. What is it was in 1993 or I'm not sure I even understand the question.

I'm trying to just look at, you know, when you talked about, you know, 11% on the current equity, I guess what is the number that the regulators are looking at right now in terms of a an equity level for the company? For the utility?

Well, this is Lamont, Darrell correct me if you take a different tact on this, but I think our filing will pretty much encompass the equity we have today. Our capital structure is balanced just about proportionate to the way we file the rate case, so when we file, it would roughly mirror the cap structure that we have today.

Can you give us what it was as of the last rate case as a comparison?

I think it was 45% common equity. I can't recall exactly how the debt preferred split. But I think preferred was 7 or 8% and the balance was debt.

That's close to it.

And what was the equity number? Common equity number I think, was 45%. Rick and I----.

You're looking for dollars, David?

Yes.

I don't. That is going to to be significantly different because the company was smaller then.

Okay.

David, we don't have that number here in front of us today.

Okay. I'll follow up with Larry.

We'll next go to Rick Shobin with Duchenne Capital Management.

Good afternoon.

Hi, Rick.

I guess my question really just is about the rate case and how the PCA mechanism would function in that rate case, and is there a way that you can file in the rate case so that you can have the PCA mechanism set on a more critical water level say like 80% of normal so that there is less variability in your earnings on a year-to-year basis, so that like maybe the base PCA recovery is a little bit higher?

I'll let Rick answer that maybe directly. I would like to take an indirect approach first. This is Lamont. Kind of the way we're addressing that is through the integrated resource planning process.

We have historically planned on a median water basis meaning that in half the years we had enough water to run through our plants to cover our loads, and half we didn't. And the PCA sort of took care of the swings.

With the magnitude of the swings we have encountered the last couple of years, we applied for a different standard in our current integrated resource plan where there would be a 70th percentile test that would have Idaho Power have more its own resources to cover its load so it had had loads and resources at a 70th percentile conditions, sort of what you're referring to here. And we're moving down that path. So rather than revising the PCA, we are shoring up Idaho Powers' planning process and the resources it has of its own regard to meet our loads in the future.

So once we effect that, hopefully we wouldn't have quite the deviations that we have today because we would be more capable under less than median conditions to cover our own loads.

And the costs that you are incurring under that integrated resource plan would be already recovered through the fuel adjustment costs or the PCA mechanism?

Well, some yes and some no. I mean to the extent that they are PCA component expenses we would hope to recover them through the PCA. To the extent that they're capital investments and those things, they'll have to be recovered through the normal rate making process. But the commission has acknowledged our IRP. They don't formally accept it, they acknowledge it. So we're operating under that plan and as we get the components lined up we will take those to them for approval.

And the purpose of it is to provide a more stable cash flow and recovery of your purchase power and things of that sort?

Well, there is certainly a company perspective of doing that. It is also to provide more certainty for our customers that we have the resources to meet their needs and the secondary benefit is, it should provide some stabilization for the company as well.

Okay. Thank you.

Our next question a follow-up from Greg Schulz with SAB Capital .

Hi, thanks for the follow-up. I want to return to the cash flow projections. I just wanted to tie out a couple of things. You were talking 2.25 from IDACORP and 190 from IPC?

Right.

Is the difference the tax attributes or is that really how much the holding company throws off?

It is really a combination of IDACORP financial kicking out cash as well as IDACORP Energy kicking off cash.

Okay. And could you walk me through the components of the 190? Because I don't know if you're being very conservative or if I'm missing something because I get a much larger number.

I can give you a summary of those numbers in just if you hang on just one second.

Okay. The, obviously the keys to the Idaho Power pieces of those items really come from -- I don't have the detail here in front of me. Um-hmm.

I can give you the main components that would -- really if you take a look at our quarterly report it will really be it will play out there because obviously we had operating cash through the first quarter of basically $95 million or so.

Right.

And when you take a look at those components, they really just kind of play out through the balance of the year.

Let me give you what I have and maybe you can comment on that.

Sure.

If I take your fully taxed guidance of about the 30 at the mid point, it gets me to about $50 million. And then I add about 100 for depreciation so it is 150, and then I'm assuming around $100 million of PCA cash flow that you get back. That gets me to 250 and then if you're not paying taxes that gets me close to 300. And then I pull out, that gets me close to 300 versus your 190. It's such a big difference I feel like I'm missing something.

Why don't you run those through me one more time and make sure I got those.

A buck 30 mid point of your guidance is about $50 million of net income. I add $100 million back for D&A and add $100 million back for the PCA accrual coming down, the regulatory asset being paid.

Right.

And then I add $30 million because you're not paying taxes. Deferred taxes. Gets me closer to $300 million. Maybe I'm being aggressive on the PCA or maybe there is some working capital that I'm missing.

I think what I would have to look at the PCA components of what your assumptions are there and I don't have that here in front of me.

I was just assuming that you basically get most of the 90 that you have left or the 126 that you had at beginning of the year.

I think the component that the piece that you're missing, one of the things we will do this year at the Idaho Power level is we will have a tax component that we will have to pay.

Um-hmm.

Because the PCA dollars that are coming back are now taxable so we will have cash outflow going out for that.

Got you, okay. And then next question would be, let's assume you know you get, let's assume weather returns back to normal and let's assume you also get rate case recovery and maybe the utility can earn, I don't know 2.25 or 240, 250. Even with that earnings level if you have $200 million of CAPEX in the next couple of years which I think is what you got it to, how do you still fund the dividend even if you get all those things?

That is the continued question that we will continue to review and evaluate as.

Right.

As the company moves forward. I mean that will be a--- .

But it seems like you guys have kind of said, you know, weather's been tough which it has been, and we haven't had rate relief and if we get those things, we'll be in kind of good shape to support the dividend. And I'm kind of separating that saying, even if you get those things, can you still support the dividend or are are you willing to borrow money over the next couple of years to pay for CAPEX needs?

I think our decisions that some of the CAPEX numbers that are included in the utility include building power generating facilities and what have you and depending on what the outcome of our resource acquisition strategy is, we'll have some dependency on whether or not we actually build it or we end up contracting for it.

Yep.

Those will drive some of those issues also. So there is a number of factors still in the air even as we look forward into '04 and beyond that we will have to continue to evaluate.

Can you give me an idea of how much of the two hundred that you budgeted is budgeted for new resources?

About $40 million, I believe, is the number in 2004. And then there is some additional dollars that go into 2005 and I don't know that number off the top of my head.

Okay. And then one final question. The contract with FMC that ran off this quarterer?

Yes.

That is assumed in your guidance?

Yes.

Okay.

This is Lamont, could I weight in a little bit too on the issue of the CAPEX?

Um-hmm.

Because it kind of relates to an earlier question too and it seems like the assumption that a couple of you are coming from is that in a normal year if we are spending $200 million on CAPEX that we would want to generate all that internally? And I am not sure that in long run that is a model that works for a utility.

Again, when we file these rate cases, we have to go in and file a balanced capital structure that includes a significant component of debt and preferred stock. So in a normal year, if you're spending, not a normal, but a big year for us, we're spending $200 million depreciation and other things generate $100 million of the $100 million that is on top of the depreciation. The assumption would be in a regulatory model, that half of that approximately is debt and half of it would be the equity funds that we try to generate in our business and supply. So I don't think if folks are making that assumption that if we can't hit the whole $200 million we can't cover the dividend that probably fits with the normal utility model.

Yeah, but your capital structure right now is kind of 50-50.

Right. And we need to maintain that going forward. If we let the equity component grow, it doesn't mean the regulator's going to give us a higher component of equity to earn on the next rate case a couple of years from now. They're still going to want the 50-50. Because that's best cost to the customer to maintain our credit quality and have lower rates for them.

Yeah, absolutely. But if you can't fund it internally you have to raise, you're saying you would raise equity to fund it. Is that what you're saying?.

What you would hope to do in an ideal world, is generate internally your equity component and finance the debt component and keep your capital structure balanced.

But you're not able to do that over the next couple of years even under robust earnings assumptions.

Well, it doesn't require us to generate the whole $200 million to do it is what I'm saying.

Okay.

Maybe 150 of it and 50 of it is debt would get you to a balanced capital structure going forward.

Okay.

Our next question will come from Stephen Goldfield with Emporium Capital.

Hi guys, this is Eric Anderson with Imperium Capital. Just wanted to ask you a question relating to the housing tax credits and if there will be any impact on the usefulness this year or any years going forward? Based on our current forecast, we currently project based on our current tax appetite and our current level of credit that we are currently generating that we can continue to utilize those credits. And so right now we don't believe we have any stranded credits as it sits there today. Okay. So you can use those at any end, at the lower end of the guidance range as well? That's correct. Okay. Great. Thank you.

As a reminder star one if you do have a question. We return to Zack Schriver with Duchenne Capital Management.

Hi, guys sorry for all the questions here. I was just wondering if you could sort of update as to where you are in this integrated resource planning process? And if you could just sort of give us some milestones from a timing perspective as to when you're going to be making different decisions about whether to contract or whether to build or buy generating assets would be great.

I'll let Rick Gale take that one.

The bids under the RFP have been received and the team that is working those bids are reviewing them and will be working their way to ultimately a short list and then taking it from there.

And would you expect to get regulatory approval of the outcome of that process before you entered into binding contracts?

The, I would expect something similar to the last go-around where we would, if it is a contract that ultimately is the case, that we would take that contract to the commission for approval.

And when do you expect to sort of pick a winning bid or a winning set of bids?

I don't know off the top of my head have that date. The short list I think will be a matter of weeks. But I don't have when that next event is.

Can you talk about the involvement, if any, that the commission has had in the crafting of this resource plan? Is this something that you went out and sort of developed on your own? Or is this something which you worked with the commission on in terms of creating a more balanced sort of power supply portfolio?

The resource plan is a very public process and one in which we work with and discuss with the staff and actually make filings with the commission. So it is a process the commission has a lot of input and actually acknowledges. They are active in the process.

Thank you so much.

There are no further questions at this time. I would like to turn the conference back to Lawrence Spencer.

Okay. Well, thank you. I would like to thank you all for your interest in IDACORP and our first quarter earnings. We will give you further updates as our situation progresses. So thank you again for your time and attention.