Idacorp Inc (IDA) 2004 Q1 法說會逐字稿

Thank you for standing by and welcome to today's IDACORP's First Quarter 2004 Earnings Conference Call. Today's conference is being recorded. Now at this time for opening remarks, I'd like to turn the conference over to the Director of Investor Relations, Larry Spencer. Mr. Spencer, please go ahead.

Good afternoon everyone and welcome to our first quarter earnings release conference call. We issues our earnings release before the markets open today and filed our Form 10-Q with the SEC shortly afterward. Each of these documents have been posted to our corporate Web site. With me today are Jan Packwood, IDACORP President and Chief Executive Officer; LaMont Keen, Idaho Power President and Chief Operating Officer; and

Darrel Anderson, IDACORP Vice President, Chief Financial Officer, and Treasurer. Other officers are also available to help answer your questions during the Q&A period. 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. Now, I'd like to turn the presentation over to Mr. Jan Packwood.

Thanks, Larry. Hi everybody. Obviously the $0.51 per share we reported this morning has a marked improvement over the $0.08 loss that we posted a year ago. The story there is improved performance by Idaho Power due largely to colder weather in January and February, and the absence of any significant writedowns in restructuring charges during the quarter. We have two significant issues that we are working diligently to resolve. The first obviously is the all too familiar challenge of greatly diminished streamflows, the second is the need for timely and adequate rate release. Weather out West has definitely taken a turn for the worst, which has implications for the balance of the year. After promising cold and snowy conditions in January and February, March was unusually dry and warm. Snow accumulation peaked on March 8th, about a month earlier than normal and has declined rapidly ever since. Consequently, we have lowered our expectations from a year with moderately low streamflows to a fifth consecutive year of drought.

On the regulatory front, we have two rate applications pending and moving forward in parallel. Our October 16, 2003 General Rate Case filing has fully argued and submitted. A decision from the Idaho Public Utilities Commission is expected by the end of this month. While this quarter's results are an improvement from a year ago, the utilities' actual return on equity of 7.4% during the past 12 months strongly supports our case for fair and timely general rate relief. We also filed our 2004-2005 Power Cost Adjustment with the Commission on April 15. We expect to implement pricing changes from both those rate cases on June 1st. That's pretty much the big picture here in a nutshell. Just as a reminder, our annual meeting will take place in Boise two weeks from today, that's May 20, starting at 10.00 am Mountain Time. We will webcast the meeting and you can access it through our corporate Web site, which is www.idacorpinc.com. I'll let LaMont give you the detail on Idaho Power's performance and outlook.

Thank you Jan. As indicated in the earnings release, Idaho Power contributed $0.51 to the first quarter results. Unfortunately that performance is not likely to be repeated because of the poor streamflow outlook for the balance of the year however. As you all know weather and hydroelectric generating conditions are two of the most significant factors in determining our earnings and cash flow. The current weather pattern clearly indicates the drought is extending into another year and the continuation will have a negative impact on streamflows, earnings, and cash flow. A portion of the impact is expected to be absorbed by continued cost-control measures, including controlling discretionary spending and managing our labor cost.

Average temperatures in our region were 16% cooler during the first quarter than during the same period a year ago. This contributed to a 10% increase in retail electricity sales volume and a 14% increase in residential usage. Most of the increased usage occurred in January and February. Until March, we had high hopes the dry weather patterns we have experienced over the past four years were changing, but warm, dry, and wet weather in March and April dashed our hopes for a better water year. Currently, the National Weather Services Northwest River Forecast Center is anticipating an April through July run-off for the Snake river above groundly reservoir of only $2.8m acre-feet. Last year the fourth year drought, we had 3.6m acre-feet. In an average year, we get approximately 6.3m acre-feet in net April through July period. Changing tracks a little since we filed our current general rate case last October, there have been several developments.

In February the Idaho Public Utility Commission Staff filed testimony proposing a $15m or 3% increase in rates. Under a in our testimony we lowered our increase request to $70m or 14.5%. Our revised amount includes updated depreciation rates recognition of lower year-end employment levels then we are anticipated when the case was filed and changes in the company's pension plan recovery method. The IPUC conducted hearings for March 29th through April 5th. As Jan mentioned, we also filed our annual power cost adjustments on April 15th for $71m above proposed base rates, but that's a $10m reduction from the current PCA. We expect the PUC to approve our PCA proposal at the same time that rules on the general rate case about the end of May and for new rates become effective on June 1st. We have several hydroelectric license applications pending before the Federal Energy Regulatory Commission. These projects include Swan Falls, Lower Salmon, Upper Salmon, Bliss and CJ strike. We don't know exactly when FERC will issue the licenses, but we hope to receive them soon.

The other application we have pending before FERC is the Hells Canyon complex, which provides approximately two-thirds of Idaho Powers hydroelectric generation capacity. We filed this application last July. In December, FERC notified us that it had accepted our application. On Tuesday, we received 14 additional information requests from the FERC. The receipts of these requests provide us with a clear view of the issues that lie ahead of us. We move toward a new license for the Hells Canyon complex. They spent a wide range of issues including general operation, geology, water quality, aquatic resources, terrestrial resources, and developmental resources, land use, and transmission line. The dead line for completing these additional studies ranges from 30 days to 9 months. We are closely examining this request and will begin implementation immediately. It will probably be a few years, however, before FERC takes final action on our application. And with that I will turn it over to Darrel Anderson for a financial update.

Thanks LaMont and good afternoon to everyone. As quarters go, this quarter was relatively straight forward for IDACORP from the financial point of view. Idaho power on $0.51 of share and the other subsidiaries combined with the holding company broke even. Our earnings per share contribution for each of the business units can be found in our press release filed earlier this morning, which is also posted on our corporate web site. The holding company recorded a $0.02 per share loss for the quarter compared to $0.21 per share loss in the first quarter of 2003. The change of the holding company is due to the inter-period tax allocation requirements of ABB 28 that we discussed through our 2003. In the current year, we are projecting at the company's effected tax rate will be approximately 19%, which is up from a 0% effective rate projected for 2003 in the first quarter. In the first quarter of 2003 it was expected that the available tax benefits from tax credit and regulatory flow through tax reductions would offset the tax expense on pretax book income resulting in a 0% effective tax rate. For 2004 the increase in the effective tax rate is resulted in an increase in expected pre-tax earnings. Turning to cash flow, IDACORP operating cash flow for the first quarter was $58m compared to $96m in last year's first quarter. Of this $38m decrease, $28m is directly related to reduce collections from electricity customers in 2004 primarily as a result of the decrease in PCA, and $15m is attributable to the lying down of IDACORP energy in 2003. Idaho powers operating cash flow of $78m for the first quarter increased $7m from last year's first quarter. The principle year-to-year variations were the collections from electricity customers discussed previously and the timing of income tax payment between quarters. Utility Capital Spending increase $12m over the first quarter of 2003 to $37m. This is in line with expectations given the company's forecast of capital spending of $207m for 2004.

On the financing front in March, IDACORP and Idaho Power secured three-year credit facilities of $150m and $200m respectively. The combined facilities of $350m have been reduced from the $515m under the prior credit facilities, reflecting the lower level of liquidity required at the holding company due to the company's decision to exit the energy trading business. In March, Idaho Power refinanced its $50m 8% Series First Mortgage Bond with $50m of 5.5% 30 Year First Mortgage Bonds. The increase in cash at the quarter end reflects the issuance of commercial paper by Idaho Power to bridge this refinancing. This commercial paper was repaid in April. We currently stand at no commercial paper outstanding at Idaho Power as we sit here today.

From an earnings per share guidance perspective, we want to update you there. At the end of the year conference call, we said that we would update you on earnings guidance as key issues became clear. The company's 2004 guidance remains in the range of $1.60 to $2.20 per share. The range continues to purposely broad, as we are still awaiting the final decision from the IPUC on the Idaho Power Company's general rate case. While forecasted expenses have increased because of the need to purchase more energy from the wholesale market, we have been able to partially offset the impact through stringent cost control. Our guidance encompasses not only the impact of worsening hydro conditions, but the anticipated positive benefit from the recovery of lost revenues. An asset sale by IDACORP Financial and the favorable settlement of litigation by IDACORP Energy. As these and other matters are resolved during the year, we will adjust our estimate accordingly.

With the recent Supreme Court ruling on the $12m loss revenue case in favor of Idaho Power Company, we have now included an estimate of the successful resolution of this matter in our earnings estimates. We are still awaiting the outcome of the IPUC's partition for reconsideration, which is currently pending. If the decision becomes final, the matter will be remanded to the IPUC to determine the amount of lost revenues to be recovered by Idaho Power in connection with this program. The inclusion of lost revenue settlement partially offset the impact of the deteriorating water condition. In addition, IDACORP Financial sale of its interest in the test property in late April and IDACORP Energy's expected settlement of outstanding legal issues, are also earnings positive and are reflected in the 2004 earnings per share range. The combination of these two events is expected to add $0.07 per share to second quarter earnings. That concludes our former comments and we'd now like to respond to your questions.

Today's question and answer session will be conducted electronically. If you would like to ask a question, you may do so by pressing the star key followed by the digit one on your touch-tone telephone. Once again, star, one for a question. If you've been utilizing your mute button, you want to make sure that does engage so your signal will be recorded. Our first question will come from David Dickens with Deephaven Capital Management.

Good afternoon gentlemen.

Hi David.

Just a bit clear on my guidance. The current guidance, the $1.60 to $2.20 now includes roughly $0.27 of one-time items the sale of property of IDACORP financial and the litigation settlement?

David that's correct. This is Darrel.

Okay. Okay. The other question I had was the upper -- you had said in the past that the upper end of the guidance was based on receiving your full rate request which is the time was $84m, but you have subsequently revised that downward just $70m. Has there been some positive -- you've talked about the water, is there been some positive offset that would allow you to get back up to the upper end of that guidance. I've kind of was under the understanding that that guidance was -- the upper end of the guidance would have come down because the upper end of your rate requested also come down?

You're right David, and I think what you have to assume is you just mentioned you add a $0.27 to the range by taking -- assuming the lost revenue is in there and also the two items at IDACORP Financial and IDACORP Energy. In addition to, so you have a number of moving parts in there. One of those moving parts is the water situation, one of those issues is the rate case, and another item that LaMont referred to is that we are heavily focused on managing the expense side of the business. As the water has continued to deteriorate, so its really, David, a combination of all of those factors that still allow us to remain in the range between $60 and $2.20.

Okay, and the $0.07 related to the transactions of Idacorp Financial, are those transactions that are -- you have already have been put together and just have not closed or is there -- I guess what I am trying to ask is there potential for further upside from sales or property at Idacorp Financial beyond the $0.07 you have identified?

And just to clarify, the $0.07 is the combination of the expected settlement of some litigation Idacorp Energy, and so the Idacorp Financial pieces about $0.05 a share and that closed at the end of April, so that is pretty much a done deal. And the other two cents are the estimate of what the settlement of the potential litigation is at Idacorp Energy.

Okay, is there -- should we be looking for incremental shares beyond that at Idacorp Financial this year?

This will happen to be an opportunity that we had with our partner in that particular project that Idacorp Financial is able to take advantage of at that time. And so it is not something that we are actively looking to pedal those properties.

Okay, and does that reduce your ability to generate future income or credits after that portfolio?

This does not really have a significant impact on changing the outlook of Idacorp Financials forecasted earnings over the next couple of years.

Alright, thank you so much.

Once again star one for a question. We will next go Andrea Feinstein with Highbridge.

Hi, just a couple of questions guys. First on the expense management that you mentioned. Can you give us a better sense of the magnitude of what you have been able to accomplish or what you think you will be able to accomplish over the year and can you kind of frame for us how we should think about the timing of having to potentially reverse diet expense management in future years. Whereas this permanent reductions that you don't think will have to make up in future years?

Andrea, I am not going to give you a number, but I will give you a sense of what numbers these areas are. We are holding -- we have about 50 some odd positions that we are currently holding open as it stands right now. We think that we are trying to manage the workforce side of this, and in conjunction with the changing water condition. We cannot do that for ever, that is not really the plan that we want to stay with because we do need to meet our customer needs and so it is something that we are managing as we are go into the fifth year drought and still awaiting the outcome of the general rate case.

Understood, and is there anything more from a O&M perspective that you have been able to put off as well.

We are looking at all areas, we are heavily focused on taking a look at our insurance premiums, any of those costs that we think are discretionary in the area of training and travel. Those type of areas that we are trying to keep strong controls on so that as things turn around, we will be able to -- can't run those forever.

Understood

And the other thing Andrea, we did do -- I think we talked about this on our last call, but we did implement a wage freeze at the end of 2003.

Okay.

We did away with our general -- we call salary structure adjustment or general wage adjustment, which has historically ran about 3% and so we froze those wages at the end of 2003. That's about a on average a $3m or so number if you can look at it in round numbers.

And just to follow-up on David's question about guidance. I have a better picture now of the top end of the range. I didn't recollect that you guys had mentioned in prior calls that that built-in essentially the full request for the rate increase. Did you similarly mention in the past what was built into the lower end of that range in other words was the staff rack kind of the model for the $1.60 portion of that range, or how should we think about that?

We have not provided any discussion in that area, we don't really plan to.

Okay, last question with regard to the interperiod tax issue that you went through. Can you remind me if there are changes, and how should I think about the next three quarters relative to this year and that particular issue?

Well, that was really a 2003 issue. We have to continue to obviously look at the effect of tax rate for the balance of the year as we indicated earlier. Our current forecast indicates that Idacorp effective tax rate of about 19%, and that could move up or down little bit as we move throughout the year, but that is our current estimate what the effective tax rate would be for the year. And that's the rate we have to book to as we look at the quarterly results.

And so when I look at the impact that that I had on first quarter '04 versus first quarter '03, should I expect to see similar follow-through in the next three quarters of the year in a comparison between the second, third, and fourth quarters of last year and this year?

What I would suggest is that as you look at '04 results using in stands today a 19% effective rate, and as we did last year, that rate was adjusted as we moved to the quarters depending on what our estimated effective rate would look like. As you recall, last year we did have a tax settlement that impacted the effective rate that half and mid-year that we weren't anticipating. So, those types of things have an effect on the ultimate effective rate.

Okay, thanks guys.

Good-bye Andrea.

And our next question will come from John Hanson with Imperium Capital.

Good afternoon.

Hi John.

I know the rate cases is still in process right now, but you are getting fairly close aren't you in terms of getting that result in the next few weeks?

We expect an order by the end of the month.

And you have, I notice that you, there are couple of items that were filed out on the PUC side. What I'm indicated that you had kind of, that it was okay to extend that out by a few days, or by ten day or something in terms of the order?

15 to the 25, is correct.

And there was another item that looked like it was a joint proposal with regard to energy efficiency. Can you talk a little bit about that?

This is LaMont, John, and I'm sorry you're catching me cold on that.

Okay. It was an item that was filed with regard to the Northwest Energy Coalition and looks like you are coming up with something there in, looks like you are kind of coming to some kind of joint proposal. So, it was an indication to me that maybe you were talking with some parties involved in some of the intervenors.

John, Ric Gale is here with us today. He is our Vice President of Regulatory Affairs. He can give you a brief over view of that filing.

Great, thanks.

This is Ric. There was a discussion with some other parties related to, some of the low-income issues and approach towards our low-income weatherization program, and following up on some rate ideas having to do with decoupling, and that was the nature of that joint proposal.

So, it does sound like you are at least talking about some of the parties involved as you are coming down to scratch on this thing.

Well Lloyd, what I think will happen is, once we get the order, we'll go forward on those issues, and see if we can work out low income weatherization, and probably if the commission agrees, may open a dockers on decoupling as a rate making item.

Okay. Jumping back a little bit again to the situation with, the hydro situation. Just to refresh my memory again, when you have those kind of conditions, you end up incurring extra power cost, those extra power cost are something that you defer and recover most of it at later time, right, rather than experiencing them of.

LaMont is going to update you. I will give those short update I have with me. It maybe what you asked about how the PCA works?

Yes. Just a little bit in terms of how much customers end up having to bear versus how much the company ends up having to bear?

This is LaMont again. It varies by jurisdiction, but in the state of Idaho, which is our primary jurisdiction, those costs are shared 90% by the customer and 10% by the company.

So, you are fairly protected if you end up having to pay to buy powers that are being able to generated with the hydro .

That's right. We have a mechanism that passes most of that through, although at times when those guys are material, there is also a significant retention by the company. And then in Oregon, sometimes we get to the forecast, sometimes we don't, and we do not have a mechanism with the Federal Energy Regulatory Commission.

Okay. And just lastly. I noticed the way you've presented your earnings for the quarter, you talk about the last 12 months you earned 7.4% versus and allowed the 11%. That sounds like a pretty big gap. Have you ever quantified that in terms of how much in terms of earnings that is potentially, hopefully will be closed by, and that will closed quite a bit by this rate case, right?

John, I think one of things -- one simplistic way to look at this, at the Idaho power level you have a total amount of common equity of about $800m plus, and if you take that time using a 11% number, which is their current we are trying an equity number that a kind of give you at least some estimate of what the gap is. And if you did that math that gets you to a number north of $2, $2.20 and $2.30, kind of depends --- but that's kind where the math works to.

Okay, good. Thanks.

Next question will come from James Bellessa with DA Davidson.

Earlier the expression decoupling, the read making item was stated, I don't know what that means, decoupling, what would that mean?

Well Ric. Jim, Ric Gale will give you an update on decoupling.

One of the issues brought up by one of the parties in the General Rate Case was the idea using a term decoupling, as a way of approaching the utilities, maybe reluctant to engage in energy efficiency programs because to the extent that we sell less kilowatt-hours, our revenues are impacted. So decoupling, in its easiest sense of the word, breaks the fixed cost recovery from the variable price. In other words, if you are collecting fixed costs from variable prices, you're really going to be reluctant to cut doing thing that will cut your sales. So, decoupling is a generic term that tries to address that issue.

You didn't pay yourself any bonuses, that's a good thing in bad years. I didn't see though on the balance sheet $1.1m of underlying compensation, what that might be?

Jim, that is the -- that reflects the amount of restricted stock and performance shares that is yet to be earned based on restricted shares then and performance share is granted under the management incentive programs.

And that wasn't in place before because there was no item like this before?

Now, that has been in there before. This is the stay, it was determined in better presentation, and so we concluded this quarter. That those programs have been there for a number of years, they were just determined, that was a better presentation on the balance sheet.

Assuming reasonable rate relief at the decision here at the end of the month, what is your tax rate likely to be in 2005?

All right, Jim. I don't have a number for you on that one. I will --

Is it between 20% and 25%?

I think it would be most likely north of 20%, somewhere I'm going to guess 20% to 30%, but what you have to look at is the effective rate at the utility which continues to be between the 35% and 40% level. So, as that becomes the primary driver, your effective rate over time will move up.

The $0.02 per share benefit from a settlement of IE, can you elaborate what the settlement is about?

We prefer no to do that right now. It's imminent that that is going to be expected to close, but right now we really can't talk about that litigation but we are very comfortable with the number. And it's not any of the California issues or those types of issues.

Would you guesstimate or give us an idea of what portion or what percentage or what amount per share non-utility EPS is of the guidance range?

I was waiting for somebody to answer that question, Jim, as I question actually. Right now, our estimate for the non-regulated range, that includes the holding company and everybody else, we estimate right now in the $0.05 to $0.15 per share range.

For this year?

For this year.

And that includes the $0.07 that you are going to get in the --

That's correct.

Second quarter?

That's correct.

So, is that range narrow down? Backing up that $0.07, is it lowered for some reasons?

No.

The difference between the 25th of the month of May and the 28th, how do you reconcile those two days and how do you bring those two orders together?

You mean the --

There was a -- you on our previous question, you evidently allowed the IBUC to extend the date till the 25th of May. But at the same time, you are talking about the decision by the 28th of May.

We need a decision by the 28th of May at minimum in order to implement rates on June 1, so that's the last date we could get an order and still implement rates. Now, what we've done in between is talk with the commission and extend by 10 days, and offer to extend by 10 days, the time period for them to make their decision. They would have timed out on May 15th for the General Rate Case because we filed on October 16th, but we're just allowing them time to finish their decisions so we can get rates implemented on June 1. So it's still possible that you'd give them another three-day extension if that's what it takes. Basically, they need enough time to make the decision. We're still optimistic that we'll get the rate change in effect and implemented on June 1.

Thank you very much.

Thanks James.

Next question will be from Peter Talent Capital.

Good afternoon. Hi guys, I am still a little confused over the nature of the earnings guidance, $1.60 to $2.20, that now includes this $0.27 of gains that suggest the underlying businesses are going to earn like $1.33 to $1.93, and I was wondering how much of that decline, the $0.27 decline is being accounted for by poor hydro and how much of it is due to a change in the rate filing from $86m to $70m.

Peter, I think the water conditions declined, significant decline of water condition from the last time we spoke to today has been significant and one of the things to look at is we've talked about the change in our projected hydro production, and our original estimate included a number around 8m megawatt-hours production coming out of hydro. Our revised forecast now is around 6m megawatt-hours coming out of hydro. So, you can do your own estimates of what the impact of that is but that's basically 2m megawatt-hours that we'll either have to produce more with our thermal facilities or go to the market to acquire, and you can use whatever estimate of market prices you want to use but you can make your own estimates as to what that is, but that has a significant effect on the change as it relates to or the offset is $0.27.

Okay. So going from 86m to 70m on rate case, that's pretty much offset by declines in expenses as you said, you are going to change depreciation rates or the way you booked pension. Is that kind of absorb the $16m decline from the rate request?

Yes. One of the things you have to realize within the rate request itself, we have a multitude of items that are included in that rate case that has a number of different issues that go with them and so, its very difficult to model all of those assumptions, but we have, our earnings guidance does include what are our best guesses for the worsening water conditions offset by the items that we spoke to you about with respect to lost revenues and the IFS, then Idaho energy transaction.

Why then if water is so bad did you file for no change to the PCA rate? I mean, why wouldn't you, there be expectations that purchase power cost would at least be as high if not higher than last year and therefore have the PCA component go up?

Well, the water actually had even declined from what we found in the PCA. So that is a deferral issue that will be a cash flow issue, thus we will end up deferring more than we would originally be forecasted. So, that's something we would expect to see happen, because there is a cutoff as to when the PCA gets filed. Secondly, I don't remember the rest of the parts of your question there.

You answered most of it, I guess.

Okay.

You are going to defer, you are going to have to defer some of these amounts.

We will defer those but you will also remember we have a true-up of a true-up recorded in the PCAT, so we'll eventually collect those amount, if it matters, it will be a cash flow item. I think Ric got a comment here for you.

Essentially, the reason that PCA didn't go up, it was high to begin with because we're continuing the drought situation. So we had a high PCA. We're coming off our high PCA and then moving forward into another high PCA year. So, both years were dry.

But even with '04, are you believe it is going to be worse than ' 03. So, in my mind, why wouldn't you be asking for more PCA revenue upfront?

The forecast is on a formula that's based upon past costs and market prices. So, the....

Okay. I got you. It's the we're looking new. Maybe that'll help explain my next question, looking at the quarterly comparisons, there was a $39m reduction in the PCA expense at the utility quarter over quarter. So, I did not have that reconciles with PCA collection is going to be down year over year compared to 2003, yet the expense recognition in the quarter was down $39m.

Right here again, and you have to look at that kind in total, when you look at those numbers and when you look at the PCA expense component. And when you are looking quarter-over-quarter, the amortization in 2003 was about $54m of the prior year's amount. If you guys remember, last year we had a pretty significant rate reduction. So this year, the amortization of that amount was $12m in the quarter. So that kind of gets to your $30m plus difference that you are talking about just of the PCA component. But you have to kind of look at all of those components together, fuel expense, purchase power, and resale when you are looking at the combined supply cost.

Okay. Well hopefully, one day, maybe, you can have a PCA seminar. We can all understand this little bit better. The last question I had was on the recognition of the lost irrigation revenue, and I guess it's a bigger portion of the $0.27. How are you able to recognize those earnings now, and how are you going to recognize and what period of time or why wouldn't it be amortized over the full term of the PCA?

Very good question.

And separately, if it's still being remanded back to the commission, and they have yet to decide what those amounts should be? How are you able to say we are going to recognize this today?

What we had said is, we have included those amounts in our earnings guidance and that's for the balance of the year. So our position today is that our case is strong, and we believe that we will have ability to collect those $12m. You have to remember what that $12m relates to. It relates to cost, our fixed cost, that we did not have the ability to recover as part of the irrigation buyback program back in 2002. And so why is it that we believe we can recognize that well, it is recovery of past costs. We already wrote those costs off, and they relate to a prior period. So the fact that if we get a court decision in our favor, we believe then that we will recognize those revenues at that time, and then evaluate the flexibility of that amount over a period of time. And then in fact that if they get collected in the PCA, we would recognize revenue at the time the decision is finalized.

Perfect. I guess more specifically looking forward -- for instance, if it's going to be decided as part of the rate case, will you recognize all those earnings in the second quarter, or will it be recognized over the next three quarters through December 31st of 2004, and then why not some of it spill into 2005, given that the PCA is of one year mechanism?

The PCA would be the mechanism, we think it would be the mechanism and which it would be collected is really the way we -- it really goes to the fact that it's a lost revenue item. It's not necessarily PCA specific related item.

Okay. I had a couple of little other issues if you don't mind. Do you have a minute?

We think so.

Okay, thanks. The wholesale revenues that you booked, are they below the line for the utility and for the calculation of ROE?

Help me better understand your wholesale revenue.

Yes, I guess you put the revenue off separately for the quarter, for instance $28m versus $18m, though actually wholesale revenue went up.

Okay.

And then, the earnings from that, are they separate from utility and the calculation of regulatory ROE?

This is LaMont, Peter. Actually our wholesale revenues at the utility are part of the ratemaking process, although it is done on a normalized basis during the hearings, they take the company's operations. Assuming a broad range of water conditions come up with a normalized amount of purchase power, fuel offset by some wholesale sales, and that is included in our base rate. The deviations from that go into the PCA.

Okay, thank you very much. And then the last one was just the balance sheet, you have on your books over $400m of regulatory assets. I didn't know what that was, and if those are earning assets of utility?

One of the biggest components of the regulatory assets are related to deferred income taxes. That's why it's the largest piece of those regulatory asset piece.

Do they earn a return in the eyes of the regulator? Do they earn -- for instance, if we're seeing 11% ROE, do they earn that on the equity piece of that $400m?

They go as a reduction to rate base, as part of deferred taxes.

Okay, great. Thanks for your time. I appreciate it.

Our next question will then come from Jeff Chrzanowski with George Wise .

Hi, good afternoon. I'm sorry to be the dead horse here, but I just need to clarify something about your guidance. Can you just confirm did the -- I guess when you recently put out that $1.60 to $2.20, did it include any of that $0.27 of gains?

No, it did not.

It did not.

Okay, that was question. Thank you.

And again, it is star one for an initial question and also for a follow-up. If you find your question has been answered, you can remove yourself from the queue by pressing star two. We do return for a follow up by Andrea Feinstein with HighBridge.

Hi, just one more quick question. Can you talk a little bit about your strategy? How has it unfolded regarding hedging out your power needs for this summer due to the fact that hydro has gotten increasingly paid?

Hi, Andrea, this is LaMont Keen again, and we have a very systematic and programmatic way that we approach risk management of the company, the system operations. We have a committee of senior officers and staff that monitor our situational needs at least every two weeks. As that situation changes over time, we go out and cover any proceed shortages that the system has, and again it's a three-step process that we go through, but it's actively managed. We've been doing that actually to purchase this as early as , and as we see today, it has covered our shortages under expected water condition.

With regard to the timing of when you would have layered that and your current earnings guidance, given the uptick we've seen in western power prices, should we assume that that higher level of current power prices or whatever the level it is of current power prices that you were able to hedge at is already reflected in the range that you provided?

That's correct, and you could assume that we have averaged into the price. Obviously, as this water situation deteriorated, some of the purchases were more recent, but some of those, as I say, were made as early as last fall.

And to the extent that we have unusual weather, we should expect that that would be served by the spot market for you guys. Correct?

For the most part, yes.

Thanks so much.

And we'll next then go to Rick Shobin with Duchenne Capital.

Hello guys, good afternoon. Andrea kind of stole my question, so thank you.

Okay, thanks.

We do have a follow-up from David Dickens with Deep Haven.

Hi.

Hi David.

More on PCA 101, if I might. Can you explain how the growth mechanism works in terms of the PCA, and talk a little bit about your filing where you were asking to use, I guess, an embedded cost of supply versus the historical use of a marginal cost in Idaho?

This is Ric Gale. That issue has been removed from the general rate case and will be taken up separately, and we hope that will be done in a technical manner, as it is a technical issue. And how it operates or the theory behind it is, we have rates that are based upon a presumed load, and we sell more or less than that presumed load, then there is an element in that energy price that recovers more than just the energy. So, it's trying to reflect that over or under collection.

And if I understand this correctly, if it's basically how much -- how many -- it's adjusting the number of dollars that you actually spend in the power -- on power supply for -- you are trying to back out the amount of the increase that's attributable to growth before you then collect for the over or under versus the initial estimate?

Well, for instance, if we had increased load and were charging for kilowatt hour for that increased load, there would be an element of recovery for each kilowatt hour sold above the base presumed in setting our general rates. So, it could be viewed as, if you are collecting all your cost through the PCA, then a portion of them through the increase load, it's a double count for the company, so you need to back out part of the double count. And the issue is, do you back that out at the marginal rate or do you back that out at the embedded rate, that' what we'll be working on going forward.

Okay, so this won't impact the amount of recovery or the amount in the first year. It's really more of an issue of how much of customer growth you can bring to the bottom line versus having a regulatory lag issue?

Yes, it's an issue going forward. In the current year, it becomes more important issue, as you get further away from the base year.

And what is the timing of having that resolved?

Current year it becomes more important as you get further away from the base year.

And what is the timing of having that resolved?

I don't know that off the top of my head. I expect that -- I mean, basically we need to get it resolved between now and next year's PCA. So we have a year in which to resolve the issue.

Okay. And if I understand it correctly, historically the adjustment has been based on marginal or incremental costs and not embedded costs?

Well, no, historically it has been a hybrid of two of our thermal plants actually.

Okay.

Incremental cost of two of the thermal plants combined.

Okay. I didn't understand reading some of the staff testimony that way. Okay, thank you very much.

Thanks, David.

And a follow-up from James Bellessa, DA Davidson.

Your PCA mechanism is not just backward looking for the last year, but it also takes into consideration the forecast, is that correct?

That's correct, right.

Forecast for hydro this year. Now if they are considering these cases altogether looking at it for decision at the same time and the deterioration has occurred since you filed your PCA application, is it possible that they might say we are going to give you more for the PCA and that would soften maybe something less than your $70m that you are asking for your general rate increase?

Glen, this is Ric. Let me back you up just a second. We are wanting the rate from both cases to be implemented at the same time, so our customers only have one rate change. But they are separate cases, the PCA is pretty much a cost recovery case and should be fairly straightforward, and what we hope is that the logic and the decisions don't get intermingled, we like to have the fact patterns result in two different results and then those results are merged into new rates.

But humans may be more compromising than that, is that a possibility? You are talking about how you would like to have it done, but in a compromise situation, could they consider that they might give you more for the PCA and then reduce your general rate case?

The PCA, again is a very straightforward filing and all the years we filed for power cost adjustments we've never got more than we've requested, and most of the times we get exactly the request, sometimes there's a disallowance for one issue or another. But usually that is a very straightforward decision.

Now you are saying that the $71m that you have applied for in the PCA is over a proposed base rates, meaning over the $70m of increase that you have asked for?

They are set at the new base rates for power supply cost, which is a non-controversial issue in the rate case, that is not one of our issues that which people disagree with the company.

So, the proposed base rate of the company could be increased from where it has been, is that right? But that's not in contention; it's not a contested item?

I am going to back up one more time. Within the rate case there are the power supply cost items, which are the same items which comprise the PCA, and so when we have a rate case, a general rate case, we reset those at base levels and that resetting to the base level use is not a contested item in the case, therefore we assume, nor is it even moving substantially from 10 years ago. So, by that we are assuming that the new -- the new base rates will be accepted, and the PCA rate change will be $71m above.

Thank you, very much.

Thank you.

And we have a follow-up from Jeff Chrzanowski with George Wise.

Hi, I'm sorry my question was already answered, thanks.

Thank you, and Rick Shobin of Duchenne Capital.

Hi, guys I just wanted to clarify or try to simplify something from my understanding. When we look at the way you set guidance, the $160 to $220 previously, I assume you guys had stated in previous calls that you were hedged for your summer expected needs given at certain hydro level, is that correct? Going forward that was based on your previous guidances historical, I mean, expected hydro levels and hedging levels is that correct?

No, the PCA has filed actually was based on a lesser water assumption than what our original forecast is based on because remember we filed out in April, and so we filed a based on the best information available at that time and obviously that had changed since we had provided guidance so that -- so those aren't two different sets of assumptions.

Well, I 'm just confused then if your filing to get proactive or future recovery under the PCA -- I don't understand really what has caused the decrease in the allowable earnings level or the core earnings level of the company because if your going to be able to recover these costs on a going-forward basis, if you get your PCA set, you're saying that the cost are actually going to be even higher than what was filed in the PCA is that correct?

Rick, it's not a 100% pass through remember on a --

Isn't that on a retroactive basis?

Yeah, got both components - both the forecast and the deferral.

Okay, and then what about your off-system sales or off-system sales get packed into that to?

That's correct.

And given the fact that you guys have had higher off-system sales this quarter, does that -- should that benefit you or does that actually hurt you because you should be actually be fined for less of a PCA increase?

Actual sales would be blended with the purchase power and fuel costs and that would produce an actual power supply cost number for some month that would be compared to what was excluded in the previous year's PCA forecast and if they were lower than the forecast, it would benefit customer , if they were higher than the forecast then they would be a 90% difference in Idaho. Again knowing that the company also absorbs some of those costs for Oregon, and the PUHCA restrictions. The other thing I would say with regarding of your questions is a related but they are not the same processes - the PCA, as Ric indicated, is a formulating process developed over a decade ago, but takes the April 1 forecast by the Northwest River forecasting service. There is regression analysis that compares that or tries to convert into power supply cost, and its added to whatever the true-up is for the previous year and that becomes the PCA request.

I understand.

That may or may not be close to our internal estimate of what the go-forward power supply cost are over that same time frame.

So, just to extend a little further, then the difference between the guidance that you guys provided before and the guidance now then is that there is incremental cost to supply this power given the hydro levels and so that 10% that you wind up eating is actually the reduction?

Yes, that's correct and out of the total, just to clarify, it's greater then 10% including Oregon and it's probably closer to 20%.

I understand that will effect on an economic basis becoming a larger number and then my last question is can you give us the estimated purchase power price that you use in your PCA filing?

We're trying to see if we even have that answer for you because it is a market based -- I mean it's a forecasted estimate.

Well, that's why I'm wondering because I want it -- I guess what we wanted to figure out is how I can gauge whether you are actually not being because if you buy power actually a less because hydro all of a sudden kicks in and then maybe we can get back to that 220 number versus if you buy power significantly more or it might be a little bit less, so I'm trying to get a benchmark as to where to - how to see where power is coming out?

Sure and the reason we fumbled a little bit for that answer because as Ric said the PCA is to look back using historical cost; so, it's actually comparing power supply cost we incurred over period of years under varying water conditions for those years.

Sure.

And then it correlates a future expectation of water to a cost number, and I'm not sure at that that points to any point estimate of what power supply costs are. We will certainly take a look at that and see if we can provide some guidance but I jut don't know that the mechanism works that way.

Rick one other thing we attempted to do this quarter was to give you guys a little more information on trying to get a hand around those power supply cost by providing some of the generation estimates and so one other things that we really can't give you is even the market is the market -- and so think if you go back and take a look at the market over a period of time and do some estimating there, I think, you have an ability to estimate what potential impact there is with the change in hydro conditions from what we've told you and everybody is going to have different assumptions there, but I think an opportunity for you to kind to go and take a look at what that impact is.

So, if I was to pull up something like the northeast Columbia pricing - mid Columbia pricing and looked at it over course of the last four months, I can say that that's probably around the levels that you guys looked used?

That's one place that we go to.

Okay. Thank you.

There are no further questions. We will conclude today's conference call therefore and we'd like to thank everyone for your participation and wish you a good day.

Thanks a lot.

Thanks everybody.