Idacorp Inc (IDA) 2003 Q3 法說會逐字稿

Good day, and welcome to the IDACORP third quarter 2003 conference call. Today's call is being web cast live. A complete replay will be available, from the end of the day for a period of 12 months on the company's Web site at www.idacorpinc.com.

Now, at this time, I'd like to turn the conference over to the director of investor relations, Lawrence Spencer. Mr. Spencer, please go ahead.

Good afternoon, and welcome to our earnings release conference call. We issued our release before the markets opened today, and shortly after that filed our third quarter 10Q with the SEC. For ease of downloading these documents have also been posted to our Web site. Now, with me today are Jan Packwood, IDACORP President and Chief Executive Officer, LaMont Keen, IDACORP Power President, Chief Operating Officer, Darrel Anderson, IDACORP Vice President, Chief Financial Officer and treasurer, and other officers who will be available to help you answer your questions during Q and A.

We will keep our presentation brief today, to allow more time for your specific questions about the company. And as always, feel free to contact me directly, if you have any follow-up questions after the call. 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. And with that I'd like to turn the presentation over to Mr. Jan Packwood.

Thanks, Larry. And good afternoon everybody. While accounting treatment of the intra period tax benefits continues to produce variability in our earnings, operating results while still sub par were reasonable all things considered. Our third quarter earnings of $1.22 per share, when combined with the negative results from our first half of the year result in the year-to-date earnings of $1.12 per share. As we explained in our release this morning, there are two major contributors to our rebound for the quarter.

The recognition of the intra period tax benefit, increased earnings by 33 cents per share, and the sale of IDACORP energies, both from whole sale electricity trading contracts to sample (ph) energy in mid August resulted in 26 cents per share. Darrel Anderson will discuss those and other transactions, in little more detail later. While those events enabled us to register a strong quarter, the results somewhat obscure the ongoing challenges that our main subsidiary Idaho Power. The fourth year of drought is resulting in increased power supply costs, that are only partially offset by the increased demand for energy by our customers during the third quarter.

LaMont Keen will review Idaho Power results, and the major impacts on operations during his time on the call. LaMont will also provide an update on the Idaho Power’s 86 million [inaudible] general rate case filing in Idaho, 20 million of which was requested in the form of an immediate interim increase. The Idaho commission is set to hear oral argument on November 13th on the need for, and the standard to be applied in reviewing our request for interim relief.

We took an equally significant step on September 18th with our board's difficult decision to reduce the dividend on our common stock by 35%. That was the first such action and our company (inaudible), but it reflects the strength of our commitment and strength in the balance sheet, and preserve our investment grade credit rating and improve cash flow to meet the challenges faced in our company. Chief among which is the unprecedented level of capital expenditures for critical infrastructure that must be reinvested in our business over the next three years. LaMont will now talk to you about results of Idaho Power for the quarter.

Thank you, Jan, and good afternoon everyone. Idaho Power contributed 40 cents per share to the third quarter results, and $1.06 per share year-to-date. Not great results from a historical perspective, but they are not too disappointing when you consider the operating conditions we were experiencing. I hate to sound like the broken record, but with the primarily hydroelectric generating system, our ability to produce low cost energy to supply our customers' needs has been materially impacted by below normal water conditions. So how dry has it been? The April to July runoff into Brownlee Reservoir this year, was less than 3.6 million acre feet. And unfortunately this is not just a one-year phenomenon. Over the past four years the April to July inflow has averaged about 60% of the 1960 through 2003 average. Even more telling in southern Idaho the April through July inflows at Swan Falls dam, declined to 46% of average this year. In July the flow at Swan Falls dam, it was the lowest level recorded at this critical measurement point for Snake River flows by the U.S geological service or Idaho Power.

In response to these flows, the Idaho Department of Water Resources was even prepared to take the extreme measure of actually curtailing up stream surface water diversions. Additionally reservoir storage in the upper Snake River systems above Milner dam is the second lowest on record. Not only was this summer dry, it was also very hot. In fact, Boise set a new record for the number of both consecutive, and total days with the maximum temperature above 100 degrees fahrenheit. As a result cooling degree days in the third quarter were up 33% over last year and 56% above normal. These temperatures as you might guess drove air conditioning loads. Sales to residential customers were up over 15% and commercial sales up over 10% versus last year. This apparent benefit to our business, however, was complicated at the operating level as we experienced greater forced outage at the company's jointly owned thermal facilities this year compared to last year's same quarter.

The combination of increased loads and reduced generating capability at both the hydro and thermal facilities obviously combined to produce the need for increased power purchases this summer and they were up by over 50%. Additionally, we are not the only ones dealing with reduced hydro availability this year. In regional Idaho sale prices are up and our price per megawatt hour purchased during the third quarter increased the by nearly 47% over last year. Which leads me back to where I begin. 40 cents a share in the quarter like we just experienced doesn't seem too disappointing. Our employees did an outstanding job this summer in all facets of our integrated operation. We met our customers' needs and operated profitably despite trying conditions. I've heard economists' saying every recession so far has been followed by a recovery, they can't say when that's going to happen. Unfortunately that is where we find ourselves with water conditions. Every drought we've experienced thus far has been followed by normal or above normal stream flows. We can't say when either but we will keep managing the system as well as we can for the benefit of our customers and owners and remain prepared for the return of better times going forward.

Change in tracks a little bit, as Jan mentioned the other major event for Idaho power is our general rate case application filed on October 16th with the Idaho Public Utilities Commission. In that, we requested $86 million in additional revenue 17.7% increase in average rates. An additional component of the filing was a request for interim rate relief for approximately $20 million or 4.2% which offers the potential for some immediate relief as the general rate case proceeds through the regulatory process. We filed our last general rate increase request in 1994 based upon a 1993 test year. We have managed our capital and operating costs well since that time. But the time has now come for us to seek additional revenues to support the investments we have made in our electrical system and the increased expenses we are incurring on our customers we have. With the significant reduction in the power supply cost component of our rates in Idaho this past May, rates have returned to more normal levels which makes the prospect of a general rate increase more tolerable for our customers and the local economy. The IPUC has established a preliminary process for consideration of the company's request. On November 13th the IPUC will convene two proceedings in regard to the company's filing. The first which Jan mention the will allow for oral argument on the need for and standard to be applied in reviewing the company's request for interim rate relief. And the second will set the procedural timetable for the general rate increase review process. And with that, I'll turn it over to Darrel for financial update.

Thanks, LaMont. I'll begin by summarizing the contribution by subsidiary for the third quarter. As LaMont mentioned, Idaho Power third quarter was 40 cents a share, compared to 1.02 a year ago. Included in the earnings from a year ago was the effect of a tax method change that increased earnings by 96 cents as was offset by amounts not approved for recovery related to lost revenues of approximately $12 million or 19 cents a share. Both periods reflect the continued impact of below normal water conditions. IDACORP Energy reported earnings of 19 cents a share compared to 2 cents a share during 2002's third quarter. These results include the after tax earnings on the sale of the book in the third quarter of approximately 26 cents per share or $10 million. IDACORP Financial increased its contribution to 7 cents a share a 1 cent per share improvement over 2002 results. IDA Tech's performance improved 11 cents a share as it registered a 4 cents per share contribution during this year's third quarter compared to a 7 cent per share loss in 2002. IDA Tech's earnings were positively impacted by a contract settlement that resulted in an after tax gain of $2.4 million or 6 cents a share.

IDA-West energy recorded a 1 cent per share profit during the recent quarter, the same as last year. The combined operations of IDACOMM and Velocitus recorded a break-even quarter comparable to the break-even quarter in 2002. The balance of the EPS are attributable to the holding company of which the majority represents the effects of the intra period tax benefits that has been deferred in the first two quarters and are now being recognized. I want to recap our comments from the earnings release related to our effective tax rate. GAAP require the companies to apply the estimated annual effective tax rate in computing the provisions for income tax for interim reporting periods. For 2003, IDACORP has projected annual pre-tax book income but also has projected an annual income tax benefit or negative effective rate. The income tax benefit results primarily from the realization of low income housing credits. Because IDACORP had pre-tax losses in the first two quarters of 2003, it did not apply the negative estimated annual effective rate to these pre-tax loss periods. IDACORP recognized tax benefits in the third quarter based on its forecasted annual pre-tax income.

The quarterly results include approximately 33 cents per share related to the impact of these benefits. For purposes of reported earnings per share by subsidiary; each subsidiary stand-alone effective tax rate for the quarter has been used. The adjustment necessary to reach an estimated annual effective rate of a negative 41% for the consolidated group of companies has been recorded at the holding company. The company expects that the effects of the intra period tax adjustment recorded at the holding company will be reflected in the individual subsidiary results by year-end. I'd like to now talk a little about cash flow. Net cash provided by operating activities by IDACORP for the first 9 months of 2003 was 257.2 million, and increased ever the 242.8 million generated in last year's first nine months. The increase is attributable to cash received from IE related to the sale of its forward book of wholesale electricity trading contracts offset by decreased operating cash flows from Idaho Power. The decrease at Idaho Power was driven by the timing of tax payments and reduced retail rates from the PCA.

Looking forward to the balance of the year, net cash provided by operating activities at IDACORP is forecast to be approximately $247 million, an increase from June 30th estimate of 218 million. The increase over our previous estimate is largely attributable to positive cash flow associated with the sale of the book at IDACORP Energy. At Idaho Power Company we are forecasting that net operating cash will be approximately $185 million compared to our June 30 estimate of 176 million. The increase in forecast of operating cash flow is attributable to the timing of payments of certain working capital amounts including income taxes. Both estimates however are smaller than originally forecasted. Capital expenditures at Idaho Power are expected to come in $10 million under the budgeted levels of $150 million for this year. The decrease is due to the timing of payments related to re licensing expenditures that are expected to be spent in subsequent years.

The combined 2004 to 2006 construction expenditures are expected to be allocated as follows. Of the 675 million that we have previously discussed, we expect approximately 20% of those dollars to be spent on thermal generation, approximately 10% will be spent on hydro generation, approximately 10% will be spent on re licensing and mitigation, approximately 20% on transmission, approximately 30% on distribution, and the balance on general plants. With respect to thermal generation, the companies coal fire plants are approaching a fourth decade of service and plant utilization has increased due to low growth and reduced hydro generation because of the low normal hydro conditions. All resulting in increased upgrade and replacement requirements and plant additions such as the Bennett mountain power plant, which is currently estimated to cost $61 million.

The company's aging hydro facilities require continuing upgrade and replacement needs in addition to costs related to re licensing the majority of the hydroelectric facility including the Hells Canyon complex, which comprises 40% of the company's total generating capacity. Regarding transmission and distribution facilities continuing low growth requires that the company upgrade the system to maintain reliability. Variations in these estimates are dependent on the ongoing analysis of the timing of spending for re licensing, load growth and other resource acquisition needs. The ultimate outcome of the ability of the company to generate adequate operating cash flow to fund these increased capital requirements and the ability to access the capital markets in 2004 to 2006 will be dependent on whether our hydroelectric generating conditions and results of general rate case filings. These factors will drive the level of capital that the company can ultimately re invest back into the utility and the level of returns to our shareholders. A couple of comments on liquidity.

At the end of September, IDACORP had approximately $11 million in commercial paper outstanding, against the $315 million available at the bank facility. Idaho Power had $14 million in commercial paper outstanding against its $200 million facility. Since the beginning of the year we have reduced our total debt by over a $100 million. Just to update you on one of the financing activities of late, on October 22nd, Humble County, Nevada, issued forth to benefit of Idaho Power company $49.8 million of pollution control revenue bonds due December 01,2024. The bonds were issued in an option rate mode under which the interest rate is reset every 35 days. The initial option rate was set at .95% and has just recently been reset to .9%. Looking to earnings guidance for the balance of the year, our 2003 earnings continue to be dependent on the results of Idaho Power Company.

We still believe that Idaho Power will end the year within our most recent guidance of $1.20 to $1.40. The year-end results will continue to be impacted by weather, water conditions, regulatory lag and the company's ability to manage operation and maintenance expenses through the balance of the year. After considering the earnings from the sale of the book at IDACORP Energy, we are revising the consolidated earnings estimates for 2003 to be between 1.15 and 1.30 up from our previous range of 90 cents to 1.15. Guidance for 2004 is somewhat more problematic. Consolidated earnings will be dependent upon the results of the utility business. The utility results will be dependent on the various factors we have previously discussed including weather, water, and the outcome of our regulatory proceedings. Given the uncertainty and potential variations in those factors, the earnings guidance for 2004 is purposefully broad. Assuming regulatory treatment consistent with the current application and the return of normal precipitation and weather, consolidated earnings will be in the range of 1.60 to 2.20. As our water year progresses and the regulatory proceedings unfold, this guidance will be updated. With those comments, that concludes our formal comments. We would now like to respond to questions that you may have.

Thank you. Ladies and gentlemen, we will now again the question-and-answer session. Please limit yourself to two questions so that everybody has an opportunity to participate. If you'd like to ask a question at this time, you may do so by pressing the "*" key, followed by the digit "1". Once again, that is "*1". And we'll pause just a moment to assemble the question roster.

We'll take our first question from Paul Ridzon with McDonald Investments.

Hi, Paul.

The 1.60 to 2.20 guidance, are there any kind of non recurring unusual type things in that that we should be thinking about?

Paul, in that range, that is really business as usual for all the entities. There are no anticipated one time adjustments included in those estimates as it stands today.

OK. Thank you.

Our next question will come from John Hanson (ph) with Imperium Capital.

Yes. Good afternoon.

Hi, John.

I just want to get a little bit into the guidance range you gave us for next year as a bit broad as you stated it was. I just want to try to calibrate some of the things we're looking at and make sure I understand maybe how achievable you know some of those numbers may be. Specifically, on the non-reg businesses, are you counting a lot of income from some of the non-reg businesses in order to get up to the numbers you have in there? In your forecast?

Let me provide a little more light on the non-reg businesses. Obviously those businesses as they stand today are not subject to the same variability that the utility has, but also I think to remind everyone that as we go forward, as we have previously said, the utility will continue to be the major part of our earnings quotient here. So when we look at the balance of our non-reg businesses, which includes the holding company and the rest of the non-reg businesses, it's probably a range to use for those entities. We see a net positive contribution coming out of those entities. And at this point in time, we would say that number is in the 8 to 10 cents per share range.

OK. So in terms of the achievability towards the upper end of the range, you're not counting on a big contribution from those businesses necessarily?

No. Our emphasis now is the utility will be the key driver to our overall operating results.

Great. On the utility, so I can understand how -- I know you don't know what you're going to get out of the rate case and all that. But just in terms of mechanics as you look at your view for next year, you really only have part of the year of a rate increase in there? Is that correct? Because your rates wouldn't be effective until somewhere partially through the year, right?

We have asked that the general rate increase would become effective on June 1st.

OK. So it's probably that part of a year's favorable effect is included in that number. Ongoing, it would be potentially a little bit better than that. OK. I guess then the last question I have is, you know, we talked about hydro again. Does this count on having a very, very good hydro year, or is this something kind of a normal business as usual?

What we have indicated in our range there is that in the expectation that we get normal precipitation, that does not equate to normal water flow through our facility because of the impact of our ongoing drought, as we have stated, we're just working through our fourth year of below normal water. And so there are recharge issues and reservoir carryover issues that even -- under the assumption you get normal precipitation does not expect that you get back to normal water flow through the facilities.

You factored that in then. Great. Thanks.

Thank you.

And we'll take our next question then from Zach Miscelles (ph) with Zimmer Lucas Partners.

Hi, guys. Just wanted to clarify the breakdown for the quarter in terms of the holding company contribution. Could you break that out?

. Well, I think as we kind of walk through the earnings contributions, let me -

I remember you worked through all the businesses but the holding company, you only mentioned there was a 33 cent gain. I was wondering if there was any other item included in the holding company?

No. The holding company the majority of the effect of the holding company for the quarter includes the effect -- at least on a quarterly basis, the effect of our intra period tax allocation. Now, what you have to be remind full of here is that APB 28 requires us to look at the effective rate based on year-to-date results, what we expect the rate is at the end of the year and apply that to our year-to-date results. So that can skew the quarterly results separate and apart from the year-to-date results. And that's the impact that you are seeing. If you look at the $12.5 million benefit tax provision that we have recorded, that equates to the 33 cents a share that we have disclosed. The balance of those dollars currently reside at the holding company that we would expect to see work its way through by the end of the year. On a year-to-date basis, the holding company is sitting at approximately a 7 cent earnings number. And so you would expect -- we don't expect at the holding company that that number -- that the earnings will remain at that level through the balance of the year. We would expect that the holding company will have a loss. So that will turn around similar to what you saw with the first six months of the year where we had certain amounts that we would expect to reverse between then and the end of the year, which they have for the most part at this time.

Great. And another question has to do with the non-reg assumption for next year. I just wonder could you break out what other businesses in this non-reg assumption and what are the business units included?

Our non-reg. businesses include all of our businesses outside the utilities, Ida-West, IDACORP Financial, IDA Tech, and IDACOMM and the holding company operations.

And year-to-date we saw quite a turn around at IDA Tech. I just wonder if you assumed that turn around continuing until '04 or what is the IDA Tech level assumed for 2004?

As we mentioned, IDA Tech's results were benefited by the fact of a contract settlement that they had during the quarter, which increased the earnings by approximately 6 cents over what they otherwise would have done. So that was a really a one time event that they ended up settling out. And so, therefore, that's not something that we forecast going forward and it will still be there.

Thank you.

You bet.

And we'll take our next question then from Philip Adams with Bank One Capital Markets.

Two questions. I apologize. I was dragged off the call for a minute. Is all of the marketing and trading gone? Is there any residual business there or overhead? And if so, is that just now under the holding company?

We will, as of November, the last employees will be terminated at IDACORP Energy. The balance of the activities have been moved to the holding company of which we will be dealing with the related administrative issues associated with that at the holding company.

OK. And I see you have a -- you've reduced debt year-to-date by $100 million, you've got an 8% first mortgage bond coming due in March. Do you expect to cash flow that or would you be refunding it?

Right now we're expecting to refund that, as it stands today.

OK. Thank you.

You bet, Phil.

Once again, "*1" if you do have a question. We'll take our next question from James Bellessa, with D. A. Davidson and Company.

Good afternoon.

Hello, Jim.

The tax magic that you're talking about works out, will you have a zero tax amount in the fourth quarter in your reported results?

For the quarterly results, Jim, or on a year-to-date basis?

Just on the fourth quarter. Have you felt -- have you benefited all you can from the intra period transfers of tax?

We expect that the fourth quarter results will be at a negative 42%, which is what our estimated annual effective rate is as it stands today, as our estimate today. It will be a negative 42%. 41.2 actually I think it is.

41.2 did you say?

Yes 41.2. That's the estimate today.

It says in the Q that IFS borrowed $25 million from a corporate lender in July. Why don't I see it in the summary of long-term debt?

Just a second, Jim. As you know, first of all, the debt that was issued at IDACORP Financial was a refinancing of debt that they had that was on an inter company basis at the time. As we have worked to pay down the IDACORP short-term facilities, short-term credit facilities, we had IDACORP Financial go out and refinance those borrowings. Those amounts are included in the IDACORP line in our 10Q we show detail of all of our long-term debt. But the detail really is the regulated debt. And so I don't believe you see all the components of that debt in our total long-term debt summary.

You have announced in the fourth quarter that you have a settlement payment to United Systems and also a settlement payment to [inaudible] have you also reserved for those or will they be drags on earnings for the fourth quarter?

We have reserved for United Systems. And the (inaudible) is a fourth quarter item. Jim, by the way, I want to go back to your question for the debt related to our affordable housing program. If you go to page 11 under note 4.

Yes, I'm there.

It's there when you see debt related to investments and low income housing. $53.5 million at the end of September.

And is that the increase of $25 million that you are talking about in your IFS borrowed $25 million in July? Is that what it is?

Right. If you look at the change from the 37 to the 53.4.

You talk about issuance of tax credit notes. Why and what are you doing with tax credit notes? Why do you use them?

Those are what they really are was a -- the best way I would characterize this is a special debt instrument that the financing organization that we used issued and to refund that debt. That is really the instrument that they put together to refinance those obligations. I think it's more -- because these are notes that are secured by the tax credits themselves. And so, that's the special nature of those facilities.

Thank you very much.

You bet, Jim.

Our next question will come from Zach Schriber (ph) with Duquesne Capital Management.

Hello. It's Zach Schriber (ph) with Duquesne Capital Management. I promise I will be better behaved on this call and I apologize for the second quarter call. I was wondering on the PCA mechanism, just sort of how it works and I understand that it's not fully compensatory now given the way that -- given the below average hydro, given some of the forced outages on the thermal side, as well as the higher power prices. It seems to be a perfect storm. Will it work differently under this sort of proposed rate increase where the PCA mechanism will be not fully compensatory and there won't be there sort of margin of error in it? Or on a going forward basis, do you expect the PCA mechanism to be fully compensatory and allow the volatility that we've seen in the financial results from this hydro situation to sort of be a thing of the past?

Zach, we've not actually proposed any changes in the structural mechanism itself of the PCA in the rate case process, some of the underlying assumptions of what your purchase power fuel expense and surplus sales are would get updated from '93 levels to 2003 levels in the process. But the mechanism itself, where there's a 90% sharing between the rate payer and the company on the Idaho portion would remain the same. That's something we could maybe try in another context if we were so inclined. We did not try to do that in the context of the general rate case. And actually the sharing mechanism is appreciated I think in the state of Idaho in that it marries in the interest of the shareholder with the customer and motivates us to do the best we can, whatever the water condition, because we have a little of our money in the game as well. So we didn't propose that in this case. And I'm not sure what the likelihood of getting that accomplished in Idaho would be, if we tried.

So we're going to keep the mechanism the same but we are going to change some of the inputs you're saying?

We'll update the underlying inputs or assumptions in the PCA. The level of power supply cost, the level of fuel expense, surplus sales levels that go into that. And all that would do, would mean that there would be some of those costs that have been in the PCA now, to the extent our costs are higher than they were 10 years ago, would become base costs. And then the PCA would pick up deviation above that.

So basically what you're saying is we're going to keep this mechanism the same, but we're going to sort of fatten up and rebase our purchase power expense and rebase our wholesale sales and rebase our fuel expense so that the mechanism should you know within a range of scenarios work the way it was actually anticipated to work? Is that what you're saying?

I think that's essentially it. The mechanism will work, we will update the assumptions. The other thing that happens is the IDACORP allocation going forward will be a greater percentage than it was in 1993 assuming that we're successful in the rate case. So there will be a greater percentage of our total costs that are allocated to Idaho than have historically been, that's because our jurisdictional sales are not as large as they once were.

And then, can you update us on this forced outage on the thermal side, where things stand? What kind of availability you have had on the thermal side, relative to your expectations. Can you quantify what that impact was in the quarter and also quantify the impact of the higher purchase power expense? And then sort of what kind of planning and assumptions you've got embedded in the 2004 guidance on the thermal side.

I don't have the specific numbers for you, Zach. I can tell you with regard to thermal operations, this summer, we had a myriad of different issues at the various plants. At the Jim Bridger facility there were four units there and a number of things at various times during the summer either reduced the output or took those units off-line. I think we had two fires in cooling towers, if you can -- if that makes any sense, that at times took units off-line. We had one of the above the units that was off-line for a couple of months due to a forced outage there due to some turbine damage and I don't think we believe it's symptomatic of anything going forward, it was just the circumstances this summer meant those units weren't available. And obviously what we do is go to the wholesale markets at those times and replace the energy to the extent we need to meet our customers' needs. But I don't have that number today of what we think the estimate of that was for the third quarter.

Is that something you think we could follow up on at some point in terms of just understanding the megawatt hours that were sort of lost as a result of some of these thermal issues, and given what prices were, try to quantify what that impact was?

Zach, this is Darrel. One way we can attempt to approach that and it doesn't include all of the effects of that, however, but we do, you know, in our 10Q, we do summarize the changes in our purchase power cost, the changes in the average cost per megawatt related to that volume. And you know, we don't necessarily have the exact volume associated with those outages, but what you are basically seeing there, though, is we doubled the level of the dollars that we had in purchased power with only about a -- I think the percentage is -- let me calculate it for you. We have a 50% increase in volume purchased, but you saw a 50% increase in what it cost us to acquire that energy, also. Those combined to have an impact on the total amount of purchase power that we had in the quarter, a lot of that was related to those outages.

Got it. OK. Good luck with all the regulatory stuff. We'll follow up off-line.

Thanks, Zach.

We'll take our next question from Andrea Feinstein with Millennium Partners.

Hello, Just a quick question for you on the DRC and I project I was off the call for a couple of minutes and don't know if this was already covered. Could you talk briefly about the process, where we are and where you know the various data points we should expect to see over the coming months are. I had seen an article come across Bloomberg wires about a week and a half ago noting that the commission had decided not to act on your request for interim rate relief. And have you seen anything in the 10Q today referring to that decision. I think that they had specifically noted that there were too many complexities in the case to decide on an interim basis and wanted just to get some comments on you on that and whether or not indeed that was a final decision.

I think unfortunately there was some confusion with the commission's orders and the way it was interpreted in the media. The Idaho commission has not denied our interim request. In fact, what they have done is set up a process to review it. The typical process in Idaho is we file the rate case, we ask for the rates to go effective within 30 days. They never do. We fully expect that they will suspend them for six months. And the normal rate case takes six months from beginning until end. The commission received our filing as we mentioned in our comments today, have set hearings for November 13th, specifically to look at the interim increase, what's the standard they are going to use to judge that and are moving the case forward. I can't tell you exactly what's going to happen at that point. But all they have done is suspend it from going into effect 30 days after our filing. And again, we think the commission is being responsive in dealing with the issue. If necessary, they have also set a couple of days in December, mid December for a hearing should they decide to have one, with regard to the interim increase. So at this point, it's by no means a lost cause and that will continue to evolve. We'll probably know something after the hearing on the 13th. And if that results in a formal hearing in the middle of December, then I would expect we'd get an order on the interim case not too long after that.

Just a quick follow up. I had pulled up the press release from the Idaho PC itself. And if you could help me understand it or go into your comments a little bit more. They are saying in their own press release that they suspended your -- Idaho Power's request for a 4.16 percent interim rate increase on all customer causes. You say they only suspended it from the November 15th date but not indefinitely. Is that accurate?

Exactly. They almost never go into effect 30 days after the filing. And so it's just the normal process. It's wording that confused people, but there's nothing unusual in what they did from our perspective.

OK. And so suspended for an effective date for either interim or permanent rates for up to six months. That would mean that even there's nothing in that context that clarifies the exact schedule that we should expect them to deal with, either the interim or the full rate relief; is that correct?

We'll know more after the hearings on the 13th. And they will set the time-line for the general most likely on when hearings will be, when we'll have to respond to requests for interrogatories and that kind of thing. So we'll have a better feel for how the general rate case lays out. And again, they are having oral argument on what the standard should be for the interim increase and should one be put into effect. So the attorneys will argue that on the 13th. We should get some indication of where the commission is headed in that regard following that hearing. But I view it as a positive sign that they set aside two days for additional proceedings on the interim in mid December. It tells us they are take our request seriously.

I appreciate it. Thanks.

We have a follow-up from John Hanson with Imperium Capital.

Yes. Just a quick follow-up here. Somebody asked a question with regard to the FERC settlement that would be a fourth quarter item. Is that something that you guys have quantified?

$83,000.

I'm sorry it cut off for a second. How much?

$83,000.

Thanks.

Follow-up also from James Bellessa.

Your tax rate for next year, do you think it's going to go back to normal? Or are we going to have continued tax issues?

I think, Jim, that you know, one of the reasons we ended up with a negative tax rate this year is because of the level of earnings that we had. And because we have a fair amount of contribution coming out of IDACORP Financial, because of their credit show up in our tax line, so that's what drives our rate negative. So depending on the level of income that we would expect to have next year above and beyond the IDACORP Financial credits, it will be dependent upon what our effective rate will be. I think right now, actually, we're just trying to see if we can come up with -- right now we are projecting an effective rate north of somewhere in the 20 to 25% range.

Thank you very much.

You bet.

And a follow-up also from Zach Schriber.

Hello. Just as far as an earlier question goes, what exactly kind of assumptions are you making in your 2004 guidance in terms of the timing of the general rate case? I thought you said the order would be coming out in June? Would it be effective in June or retroactive to January and if it is only effective in June we've got a part year impact. Are there other any new regulatory developments that would be relevant for '05. I recall some plans about either buying or building generation and rate basing generation in terms of this whole resource need package and how does that play out from a regulatory perspective and earnings perspective?

Right now, we have filed our general rate case to go effective on June 1st. And so that's the current general rate case. The general resource you referred to is the Bennett mountain power plant that we have contracted with a third party to build under a build and transfer that we would expect that to be completed in 2005. And we'll have to assess the situation in 2005 and determine you know our ability to recover that asset. And the rest of our construction at that time.

What’s the capital laid out for that asset? Do you get any construction work in progress on that asset? Do you defer the interest expense?

We do not get construction work in progress as part of our rate base today. We do get allowance for funds as part of the carrying costs of our construction work in progress.

So then we would just think that the interest expense would be effectively capitalized but you wouldn't get a return on the assets until it was put into rate base?

Correct.

How big is that investment?

The all in current estimate is around $61 million.

And that would be financed mostly next year?

We would expect to finance that -- we would make progress payments to the contractor with a fair amount of retainage expected to be at the conclusion of the contract. So we wouldn't pay all the dollars over that period of time.

So it's back end loaded.

Right.

That would be in mid 2005 or early 2005?

It's expected to be able to provide energy to us in June of 2005.

Perfect. How many megawatts is that again?

It is 162.

Thank you.

And we'll take a question from Paul Ridzon from McDonald investments

Next year we should see energy totally gone there won't even be a line-item for that? Is that correct or will there be some residual?

We will have a line item. IDACORP energy is an entity that will continue on for a period of time. As you recall, we do have a receivable out there that we are collecting on. We'll continue to monitor various pieces of litigation or what have you as it goes on. So it as an entity will still be there and so you know I would not expect it to have earnings of a nature or losses of a nature that would be reportable on a line-item basically as it stands today.

Just a follow-up on the aquifer recharging. You have normal hydro next year and normal hydro into 2005. What kind of pickup would you expect to get from that? Just the benefit of having gone through the recharge in 2004 and then I assume you get essentially back to normal?

Going into and out of a drought is a little bit of a multiple year process. I guess what you are saying if normal precip this winter doesn't get us normal stream flows in 2004, if we have two winters of normal will it get us back to normal in 2005. And I think the answer is it will get us closer. I don't know that two years of just normal gets us back to fully normal conditions again because it does affect in stream flows and other things. Certainly it would move us substantially in that direction and I don't know that we would be materially below normal, but I can't tell you that two years of normal gets us back to where we should be.

Given that you have handicapped 2004 guidance for the recharge, what kind of pickup in earnings could you predict if you did have two years of normal, assuming we do get essentially back to normal conditions or pretty close there anyway?

Paul, that's a pretty tough question, to tell you the truth. I'm not sure.

I know there are a lot of variables.

That we'll have a good answer for you on that today. I'm not sure we can answer that question.

Well part of that too relates to the up stream reservoir storage is very low on the upper Snake now as we mentioned in what we said. If we're sitting here next year and those reservoirs are back to normal levels we had a normal winter, and we're looking at another normal winter, I'm not sure that 2005 isn't fairly close to normal. If for what ever reason they don't get the reservoirs refilled as they normally would by this time in the year, we'll have somewhat of a carryover. But again, I don't think as we look forward, if we assume two normal winters that we're looking at much below normal in 2005.

OK. Thank you.

Thanks, Paul.

Our next question comes from Mashar Khan(ph) with (inaudible) Site Investments.

I apologize. I'm entering late in the call so I might ask a question which probably has been answered. Did you provide also forecast for 2004, how the utility and non-utility businesses?

What we did was we gave a number for the non-reg businesses and a range of around 8 to 10 cents.

8 to 10 cents.

On including all the non-reg business, that’s where we stand today (ph)..

OK. And then just going back on the kind of the utility business, the forecast just repeating the question earlier, right now you are assuming that the interim of 20 million gets affected at the beginning of next year and then the full rate case decision whatever it is impacts you on June 1st; is that correct, in terms of your guidance?

We have made assumptions regarding the timing of the general rate case as it relates to June 1st and also as it relates to the interim rate increase beginning in the first of the year. So we have made assumptions for those in our estimates.

On those estimates. OK. And I think going back to -- I tried to go to the rate case document. If I can just understand, if you have it on the back of the envelope or not, we can discuss it later, as to how much of the rate increase is just the addition in rate base times the rate of return.

I'm not sure we have all of that information here today, to tell you the truth. I'm kind of looking if we have that information. I don't think we have it, Mashar, at this point. We talked about what we expect to see coming in off the interim, the components of the interim piece that we've asked for, but not that we haven't discussed or the general.

OK. If I can ask a question then on a separate basis. How much are you expecting O&M expenses, non-fuel O&M expenses to go up 2004 versus 2003?

Right now, those numbers are in the 3 to 5% range.

3 to 5% ranges. OK. I appreciate it. Thank you very much.

And we return to James Bellessa.

Your guidance for Idaho Power company in the fourth quarter, you haven't specifically said, but you've given guidance for the year of 1.20 to 1.40. And you already have under your belt 1.06. So that's just an implied range for the fourth quarter of 14 cents to 34 cents for the utility.

That's right.

I looked at the mid point of that, 24 cents. And it would suggest that the utility results would be down this year's fourth quarter versus last year's period. Is that a reasonable assumption if we hit the mid point? If you hit the mid point of 24 cents that utility results would be down?

Given, Jim, what you have said related to the mid point, that's correct. And there are still a number of variables that are impacting us in this fourth quarter even against last year's fourth quarter. Some of those are O&M increases. We have, you know, potential -- our estimates where revenues may go and some of those areas. So it is -- based on what you have said, that is true.

Thank you.

You bet.

That concludes the question-and-answer session today. We have no further questions in the queue. Mr. Spencer, I'd like to turn the conference back to you.

OK. Thank you. I would like to thank you all for your interest in IDACORP and our third quarter earnings. And we will give you further updates as our situation progresses. Thank you.

This does conclude today's conference. Again, we'd like to thank you for your participation.