Idacorp Inc (IDA) 2002 Q4 法說會逐字稿

Good day, everyone. And welcome to the IDACORP Incorporated fourth quarter 2002 earnings conference call. Today’s call is being recorded.

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

Thank you for the introduction, Lisa. And good afternoon.

Here with me this afternoon are IDACORP President and Chief Executive Officer, Jan Packwood, President and Chief Operating Officer of Idaho Power LaMont Keen, IDACORP Vice President, Chief Financial Officer, and Treasurer Darrel Anderson, and other Officers who will be available for q-and-a.

In a moment, I’ll turn this presentation over to Jan Packwood to recap IDACORP’s strategic highlights for the quarter. LaMont will follow with a review of Idaho Power. And finally, Darrel will discuss our financing activities and earnings guidance.

If you need assistance at any time during this presentation please dial star, zero. During q-and-a I would ask that you please identify yourself first before submitting your question, and limit yourself to one or two questions so that everyone has an opportunity to participate.

We are webcasting this conference call live. A complete replay will also be available at the end of today at our company’s website for a period of 15 days at www.idacorpinc.com.

The presentation we will hear during this conference call may also contain forward-looking statements, and it’s 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 & Exchange Commission.

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

And with that said, I would now like to turn the presentation over to Mr. Jan Packwood.

Jan Packwood. Thank you, Larry. And thanks, everyone for giving us a little bit of time this afternoon.

2002 was a challenging year, and we anticipate 2003 will be, also. Given the myriad of factors impacting our industry, however, I feel good about how IDACORP is currently positioned. The performance of Idaho Power, our regulated utility, has improved significantly over the previous year. We have reduced our risks substantially. We have no merchant generation exposure, and our exit of the trading business is progressing satisfactorily, as I will discuss in a minute.

Our liquidity is good and improving. We have reduced our reliance on short-term borrowings, and are working with our banks to renew our short-term credit facilities. Cash flow was strong, and we are on-track to recover the extraordinary power supply costs from 2000 through 2002. And throughout these challenging times we have retained investment grade credit ratings.

In our earnings release issued this morning IDACORP reported 2002 annual earnings of $1.63 per share, a decline of $1.72 per share from the year previous. We also reported a fourth quarter loss of eight cents per share, as compared to earnings of 55 cents per share in the fourth quarter of 2001.

During the fourth quarter we recorded a $3m in net losses, compared to earnings of $20m during the same period a year ago. Our annual net income for 2002 was 62m, 63m less than our 2001 results of 125m.

Our results for both the quarter and the year reflect significant improvement in the performance of our regulated utility, Idaho Power, as it achieved earnings of 31 cents per share and $2.24 per share for the quarter and the year, respectively. This marks a 24 cents per share improvement over last year’s fourth quarter, and $1.64 per share increase for year-end.

This was achieved despite the operational impacts of continued sub-par stream [flow] conditions on our hydro system, reduced general business sales, and aided, of course, by the affect of our tax method change.

LaMont will provide more specific information about Idaho Power’s performance during his portion of the call in just a few minutes.

Our decision to write-down 8.1m of equipment related costs associated with Ida-West Energy’s proposed Garnet Power Project resulted in a 13 cents per share loss during the fourth quarter. That partial write-down reflects the dramatic drop in prices for, and increased availability of generating equipment due to the collapse of the merchant power plant development business. This project was placed on hold last summer, when the upheaval in the merchant generation sector and tightening capital markets made financing terms and conditions unacceptable. As a fully permitted site, however, we believe that Garnet remains a valuable asset.

As anticipated, additional downward pressure was placed on our consolidated earnings by the wind-down at IDACORP Energy. That resulted in a 20 cents per share reduction in fourth quarter earnings, compared to a 49 cent per share contribution during the same period last year. IDACORP Energy’s results for year-end 2000 were a 39 cents per share loss, compared to a $2.87 gain in 2001. And I’ll talk about the IDACORP Energy wind-down in a little more detail in a moment.

Finally, I want to reiterate and remind everyone of two significant earnings related events that we discussed previously on our third quarter call. On the positive side we recorded a $35m tax related benefit, while the write-off of $12m in irrigation loss revenue disallowed by the Idaho Public Utilities Commission had a negative affect. Those calculate to 90 cents per share contribution from the tax benefit, and an offsetting reduction in earnings of 20 cents per share due to the disallowance. Obviously, the net positive affect of those events was important to our ability to report the level of annual earnings announced today.

Now, I’ll update you on our wind-down at IDACORP Energy. It is progressing well. As we continue our orderly exit from this business we are focused on reducing our credit exposure, our liquidity requirements, our capital at risk, and our average value at risk, or VAR. Since we announced the wind-down of this business last June our credit exposure has decreased by approximately 46 percent, liquidity requirements are nearly 60 percent less, capital at risk is 20 percent lower, and our average VAR stands at $696,000, down significantly from the 1.4m level in June of ’02. Darrel will discuss in a few minutes how that reduction in liquidity required has been taken into consideration as we renew the IDACORP credit facilities.

The most painful component of this wind-down is the impact on our employees. We have 42 employees today, compared to 125 at our peak last year. We expect to reach a staffing level of approximately 20 by July. That number is adequate as we continue to schedule-out our book, the lion’s share of which will have settled by the end of 2004.

I’ll conclude my comments with a quick review of our priorities for 2003. Our first priority will remain Idaho Power. While our regulated subsidiaries’ results were much improved in 2002 we face the challenge of a fourth year of below-normal stream flows, as well as increasing capital requirements associated with serving load and customer growth, re-licensing our hydro-electric plant, and possibly acquiring new generating resources.

As we complete our withdrawal from the energy trading business we are limiting new investments in non-regulated business activities to our field sales subsidiary, IDATech. All others are projected to pursue their growth objectives on a self-funded basis during 2003.

In the near-term our regulated business remains our most important concern, and our growth opportunities in the coming year are limited. We expect our 2003 earnings to be in the $1.50 to $1.70 per share range. If more normal weather and operating conditions return in 2004, and if we are successful with our anticipated general rate case, which we plan to file this fall, we expect significant improvement in 2004 earnings. Darrel will be able to provide more information with respect to that outlook later in this call.

I’ll now turn it over to Idaho Power’s President and Chief Operating Officer, LaMont Keen.

Thank you, Jan. And good afternoon, everyone.

While in a much better position than it was last year at this time, Idaho Power still has not fully recovered from the high wholesale power prices of two years ago and the ongoing drought. So I am going to begin today by giving you an update on snow pack conditions and the hydro outlook.

And we have been experiencing drought-like conditions for more than three years now, and at the moment the pattern does not appear to be abating. While we have been receiving some precipitation we have not received the quantities needed to produce normal snow pack or stream flows.

It has also been warmer than usual. Temperatures during January were nine degrees above average, and snow pack on the Snake River Basin right now above Brownlee is only 81 percent of normal. The U.S. Weather Services’ River Forecast Center at this time is predicting April through July inflow into Brownlee Reservoir will be 3.6m [acre feet] [ph], and by comparison the normal 30 year average for inflow during that time is 6.3m acre feet. Now, we still have a couple of months left of our snow season here in the West, however, and these numbers certainly have the potential to change over the next couple of months.

Moving onto power supply costs, or production costs adjustment clause update, our purchase power costs in 2002 were far below those of 2001 mainly because of lower wholesale electricity prices. While we purchased only 16 percent less on the open market in 2002 versus ’01 the average price we paid was almost 75 percent lower than a year ago. After two successive years of record-high power supply costs or PCA rates we expect to see a significant reduction in Idaho retail rates across-the-board this coming May.

Our total deferred power costs balance at December 31st was 140m, down from 176m at September 30th. Of that amount 74m of that December balance is expected to be collected in the current PCA year while the remainder is expected to be collected in our next PCA year. The reduction, of course, will depend on actual power supply costs incurred through the end of the PCA accounting year in March and this winter’s snow pack on the Snake River drainage.

With the current water forecast the company has taken steps to mitigate the impacts of reduced forecast inflows into Brownlee, and believes it has adequate resources to meet the forecasted load for the upcoming year. It should also be noted that while the PCA provides some significant protection from volatile power markets that it does not mitigate 100 percent of that exposure. During 2002 the IDACORP shareholder absorbed approximately 25m or 40 cents per share in excess power supply costs, compared to approximately 76m or $1.22 per share in 2001.

I’d like to move-on now, and talk a little bit about the general rate case filing we anticipate later in the year. And while the PCA has been a valuable tool for Idaho Power to have during the energy crisis and it’s commensurate high power supply costs it has not provided revenue recovery related to Idaho Power’s other costs of serving its customers.

Increased operating expenses and substantial demands for infrastructure improvements are required to provide Idaho Power’s electric customers with the reliable energy they expect. And as a result, we do anticipate a general rate case filing with the Idaho Public Utilities Commission this fall. This will be our first rate case filing since 1994. We anticipate the request for an increase to be substantially less than the expected PCA rate related decrease our Idaho Power customers will see this spring.

Since 1994 our customer numbers have swelled by nearly 80,000, or about 25 percent. We have been experiencing a period of steady and often robust economic expansion in our service area. Additionally, we see more needs on the horizon. We expect increased capital costs for the protection, mitigation, and enhancement requirements of new licenses for some of our hydro-electric projects. Additionally, our integrated resource plan recognizes the need for new sources of power supply, and the need to continue the expansion of our transmission and distribution network is unrelenting. This does drive the need for the general rate case I mentioned earlier, but also provides the opportunity for us to grow our regulated operations. Through all of this, we’re confident our customers’ rates will remain among the lowest in the nation.

I want to cover just a couple other items before I conclude. First, our lost revenue appeal. As you recall, last October we filed an appeal with the Idaho Supreme Court of an Idaho Public Utilities Commission decision that denied us recovery of $12m of related to 2001 irrigation load reduction program costs. And these costs were related to providing service to the customers who took part in that program. The company filed its brief on January 31st, and will continue to pursue this appeal vigorously.

Kind of concluding here with an update on our integrated resource plan. We continue to work to meet our future energy needs. As you may recall at our last conference call we told you that we had filed a report with the Idaho Public Utilities Commission outlining options now available to meet future needs, and to replace the energy and capacity previously anticipated to come from the Garnet Energy Project. These options include wholesale power purchases, seasonal energy exchanges with other utilities, obtaining firm transmission rights, or constructing, or purchasing capacity from new generating resources cited in the company’s service area. We are currently awaiting the Idaho Commission’s response to our fall filings which is anticipated in the very near future.

That concludes my formal remarks, and I’ll now turn the call over to Darrel and let him address our financing activities and earnings guidance.

Thanks, LaMont. And good afternoon to everybody.

I am going to cover a number of topics today including cash flow, liquidity, and earnings guidance for 2003. As Jan indicated earlier, we are focusing our business strategies currently on strengthening the corporate balance sheet. And along those lines I’ll start this afternoon with talking about cash flow and liquidity.

Free cash flow increased by almost $340m over 2001, driven by collections of our outstanding PCA amounts discussed earlier by LaMont, reduced power supply costs and receipt of tax refunds related to our tax method change. The increased cash flows were used to pay-down short-term debt and redeem our [option] rate preferred stock.

At December 31st IDACORP had approximately $166m in commercial paper outstanding against its $490m available bank credit facility. Idaho Power had approximately $11m in commercial paper outstanding against its $200m available credit facilities at the end of the year. As of yesterday these amounts decreased further to $129m at IDACORP, and $9m at Idaho Power Company. We have continued to make progress in reducing the company’s reliance on short-term borrowings, and will continue to make this an emphasis during 2003.

In endeavoring to do this we are looking to refinance debt of up to $60m at IDACORP Financial that will free-up cash to repay IDACORP’s short-term borrowings. We expect to close this transaction during the first quarter of this year.

As it relates to our credit facility renewals IDACORP has a $350m 364-day credit facility that expires in late March of this year, along with a $140m three-year facility that expires in March of 2005. Idaho Power has a $200m 364-day facility that also expires in March of 2003. We are in the process of renewing these facilities at this time. Idaho Power’s 364-day facility is expected to remain at $200m, while the IDACORP 364 facility will likely drop to between $150m and $175m as the liquidity requirements at IDACORP Energy have continued to be substantially reduced.

During the fourth quarter Idaho Power Company issued $200m of first mortgage bonds in two series, $100m was issued for 10 years at 4.75 percent, and $100m was issued for 30 years at 6.0 percent. These proceeds were used to pay-down short-term debt as a result of our ongoing construction program.

In May 2003 we have $80m of 6.4 percent first mortgage bonds that mature, and we also have the ability to redeem another $80m of first mortgage bonds that we will evaluate at that time. In December of 2003 we may also refinance approximately $50m of 8.3 percent solution control bonds. At this point in time we don’t anticipate issuing equity securities during the balance of 2003 other than through the normal course of our various companies’ stock plans.

I’d like to now move-on to 2003 earnings guidance. As we have previously discussed, our 2003 earning guidance contributions will be heavily dependent upon the results of Idaho Power Company. The utility company is dependent on hydro conditions within a service territory that can vary dramatically from year-to-year and from average conditions.

Forecasting earnings contributions is, therefore, based upon assumptions regarding water conditions. As LaMont has mentioned earlier, Idaho Power Company has just concluded its third consecutive below-normal water year, and as we entered the last two months of the 2002, 2003 snow accumulation season we now project a fourth consecutive year of below-normal hydro conditions.

Given the projected hydro conditions, known expected increases in our insurance costs, re-licensing costs, and employee benefited related expenses IDACORP expects that earnings for 2003 to be in the range of $1.50 to $1.70 per share. These estimates assume that Idaho Power Company will contribute approximately $1.40 to $1.60 per share, and that the non-regulated operations will contribute between a break-even and a 10 cent positive contribution.

The non-regulated operations are expected to be benefited from reduced losses at IDACORP Energy during the wind-down, continued strong results from IDACORP Financial, the turn to profitability of IDACOMM offset by our continued investment in IDATech as noted by Jan earlier. These estimates assume the normal wind-down of IDACORP Energy, and make no assumptions as to the ultimate outcomes of outstanding issues associated with an FERC maters, settlement of California issues, resolution of our Overton litigation, or other issues that are or will be included in our filings under the 34 Securities Act.

In response to the continued below-normal hydro conditions and increases in our other operating and maintenance expenses that we consider non-discretionary IDACORP has instituted a hiring freeze, and will only fill positions that come about from retirement or attrition that are deemed mission critical. In addition, it has frozen salaries for officers and senior management personnel throughout the organization.

Included in our earnings guidance for 2003 are increases in pension, healthcare, insurance re-licensing, and transmission costs, and other related areas of over $15m. These costs are principally being incurred at Idaho Power, and are not currently reflected in our existing rate structure.

One area of interest that we wanted to touch-on was pension expense. Our pension expense is expected to increase from approximately zero in 2002 to approximately $7m in 2003. Of this amount approximately 70 to 75 percent will impact our operating and maintenance expenses.

At the end of 2002 our projected benefit obligation exceeded our pension assets by about $12m. Based on current estimates we do not expect to be required to make any cash contributions during the plan in 2003.

Free cash flow for 2003 is expected to be positive based on our capital spending program of just over $162m, primarily directed to utility spending. Cash flow continues to be supported by ongoing collections of our past PCA deferrals and positive cash flow during the wind-down of the energy trading business. Of the $162m capital budget at IDACORP $150m will be for capital expenditures at Idaho Power Company. Of that $150m approximately 60 percent of that amount is dedicated to our delivery system, and 30 percent is in support of our power supply and re-licensing efforts.

As we have previously discussed, our goal is to work through 2003 to strengthen the company’s balance sheet for the paying down of short-term debt, and tight controls over our expenses. We believe that beginning in 2004 a combination of general rate relief, a potential return to more normal water conditions combined with continued customer growth will contribute to the success of the company’s back-to-basics emphasis.

On another note, the Emerging Issues Task Force reached a consensus to rescind EITF 9810, and replaced it with EITF 0203, the impact of which has precluded mark-to-market accounting for all energy trading contracts not within the scope of FAS 133. The review of our energy trading contract indicate the impact of this change will not have a material affect on our financial statements as substantially all of our energy trading contracts meet the definition of derivatives under FAS 133.

Last, I’d like to close with a short discussion about the dividends. As many of you know, we declared a common dividend on January 16th of this year of 46.5 cents a share. We continue to recognize the importance of the dividend to our shareholders, and particularly our large base of retail investors.

As we have previously discussed, the dividend level is a function of what the company earns and what it can afford to pay to its owners. The sustainability of the dividend long-term is dependent on the financial health of Idaho Power Company. The company will continue to monitor the stability to pay while maintaining a healthy balance sheet. The ultimate decision regarding the dividend rests with the company’s Board of Directors who review the decision quarterly. The next Board of Directors meeting that the dividend will be discussed is the March 20th, 2003 meeting for the May dividend declaration.

We would now like to open it up for questions.

(Caller Instructions.)

We’ll go first to Andrew Levy, [Bear Wagner] [ph].

Hi, guys. Just a couple of questions. And actually, one request while we get started. If you could maybe change the time of the call from Friday afternoon, that would go a long way, I think, for a lot of people.

We will definitely take that under consideration for sure. We have actually already talked about that, so we understand.

Okay. I appreciate that. Just a couple of questions. Just one clarification, on the Idaho Power, you said their earnings range for ’03 was $1.40 to $1.50, or?

$1.40 to $1.60.

$1.60, okay. And then for the other part it was zero to 10 cents, right?

That’s correct.

And then, anything for the parent, the corporate?

That is, that combines all of our non-reg businesses including our holding company operations.

So the range actually I guess is more like a $1.40 to $1.70, I guess? Right, it’s depending on what ultimately happens?

Well, no, I think one of the things you need to take a look at is when we put our estimates together we have highs and lows that we take a look at, and run various sensitivities around those numbers.

Oh.

And so, you can’t really take all the lows and the highs of each of them, because each of them have a range that, where we think we will hit. And the $1.50, the $1.70 is our combined judgment as to where we think we will end-up by looking at all those factors.

Okay. And on the hydro conditions, the $1.40 to $1.60 for Idaho Power incorporates your current conditions?

That’s correct.

Okay, so we don’t have to worry about anything there. On the dividends, I understand kind of what you’re saying. Is there a pay-out or a current like dividend policy beyond just, you know, what you said as far as pay-out ratio, or anything else that you can share beyond the statement you’ve made already? Because, obviously, that is a big question with pay-out ratio where it is.

That’s correct. And I think as we have mentioned in prior calls we have, obviously, recognized the importance of the dividend. We also recognize the fact that in past years we have had difficult times where we have sustained the dividend even during difficult times. But we will continue to monitor that, and discuss that with the Board. And, obviously, it’s the Board’s ultimate call.

Is there any kind of things that we can watch out for? Milestones, or whatever it may be, on keeping the dividend at its current level versus not keeping the dividend at its current level, or a time payment as far as timing? You know, just in your view, again, I understand the Board or you, obviously, have to make a recommendation to the Board. And I am just trying to figure-out, you know, is this going to be safe for a long period of time? Or what’s the tolerance of the patience?

As you know, we can’t give any guarantees. And it’s, obviously, the Board’s decision. And all we can, what we want to do is keep you updated on when the decision the Board makes – but it is – obviously, the Board has a long-term focus of the company, but we will continue to monitor it. And I can’t tell you any more than what we’ve really told you today with respect to the dividend, other than we will continue to monitor it and give you feedback as it comes.

Fair enough. And two last questions, and then I’ll let somebody else go. You also made a comment that at this time there was no need to issue equity in 2003. And I always read in the statement – I just want to understand what that really means at this time? Does that mean that there’s not going to be any equity in 2003, or there is a scenario where there possibly could be some equity issued? If there was a scenario, I don’t know if you can share that type of scenario, or some type of guidelines on what it would mean issuing equity versus not issuing equity?

Based on our, where we stand today, and as we referred to in our last conference call, we continue to take a look at strengthening our balance sheet. And as we forecast today, we don’t believe we have a need to issue equity at this time. But I can’t tell you all the varieties of options that might come about that might require us to issue equity, but right now, we don’t forecast issuing additional equity for the balance of 2003.

And so unless something changes, kind of earnings wise, or rating agency wise, we probably would not see any type of equity?

That’s correct.

Okay. And then, one last question. You mentioned about new generation sources. And I am just wondering, you know, basically are you looking to diversify out of the hydro? If so, when and what type of or size generation are you kind of looking at? Is it kind of peakers you’re looking to add? Is it something else? And then, if the answer is ‘yes’ to that, I have one more question.

This is LaMont. The integrated resource plan that we filed primarily shows needs for energy for peaking purposes during our summer peak, and during the month of December in the winter. We, as I say, there are a number of options on the way. We can fill those needs. Some of those involve construction of plants, some of it involve the purchase of energy from others.

The IRP does call for us to put-out a RFP for a peaking facility, assuming that the Idaho Commission acknowledges our plan. That’s really what we’re waiting for. They don’t approve it, but if they essentially accept it or acknowledge that it’s there then that’s the plan that we will use to operate for a couple of years. In that event we would put-out a request for proposal for a gas, most likely a gas peaking facility in our service territory. And the company might consider doing that itself. We’ll probably have a self-build option that we’d use as a bogey to compare the bids that came-in. But that’s really the nature of the resources that we’re looking for at this time.

Would you consider buying an existing unit from somebody? I don’t even know if there is one, out where you need it, but?

Essentially, on the RFP it will be open, and those that are interested will be able to bid, and you know.

But you wouldn’t buy another generation station or peaking units, or anything like that, outright? And try to put it into rate base, that type of thing?

Well, I guess I can’t think of one that would be a likely candidate. As I say, I am sure that we will run the costs of the self-build option, similar to the plant we already have at [Danskin] [ph], and make sure that the bids that come-in are at least as cost effective as we could do it, hopefully, lower. There’d be no reason to buy from others versus do-it-yourself. And so, there’s some chance or potential for Idaho Power to build a peaking facility, or as you say, buy one. I guess I just can’t right now think of any facility located near us that would be a candidate.

And that would be what? An ’04 type event, as far as if you were to build your own peaking unit?

The need that we’re trying to fill at this point in time is, begins in the summer of 2004.

Okay, great. Thank you very much, guys, have a great weekend.

Thank you. Thanks for hanging with us.

David Pickens, [Steve Haven Capital Management] [ph].

Hey, everybody. Gee, that was kind of an exhaustive list that Andy had there, but! A couple of questions. Can you tell us, you said the hit in 2002 to your earnings above and beyond the PCA was about 40 cents from the poor hydro conditions. Can you tell us if we look say at the mid-point – I realize that your estimates for 2003 for the utility are dependent in large parts, or the range is in large part driven by hydro conditions. But, you know, if we look at the mid-point there, what is the impact that results in that mid-point?

This is LaMont. I guess I am not entirely sure I follow your question. Maybe you help me understand?

You said the shareholders absorbed about 40 cents of power costs that were not covered by the PCA?

Right.

What is the equivalent number for 2003 that’s built into your guidance, and if you want to give a point number at maybe the mid-point?

Okay. I don’t know that I can give you that. Darrel can think about whether that’s a number he’d release. I can tell you that the actual run-off into Brownlee Reservoir last year in that same timeframe was 3.2m an acre feed.

So real similar to the forecast?

So, it’s looking like ’03 is shaping up to be pretty similar to what 2002 was at this point.

Are you basing your forecast – is your forecast similar to the Northwest River Center’s forecast?

We do our own internal estimates, and they are similar. But they’re not necessarily always the same. We don’t publish what our internal estimates are.

Fair enough. Can you give us a little bit more of a schedule for the GRC? You said you’d file in the fall. But kind of give us an idea of various different milestones, or I’m not familiar with what the – if there’s some kind of statutory clock with the Idaho Commission?

Sure. The reason that we’re looking at filing in that timeframe is we would like to use 2003 as the test year. As Darrel mentioned in his remarks, we have some operating expenses that were basically, have been thrust upon us in the insurance arena, pensions, and other areas, that are impacting 2003 that were not there, or not there in the same magnitude in 2002.

And so, we’re going, the intent is at least to wait until we get some actuals under our belt for 2003. Maybe six months of actuals, or something, and then file a test year that’s partially actual and partially estimated. But file it late enough in the year that the actual numbers would be known before the Idaho Commission had to make a decision.

They basically have – and Rick Dale is here with me – seven months, I think, from the time that we file until they have to render a decision. And so, if we file this fall we should have the right to expect an order sometime in the spring of 2004.

Okay. And my final question is could you give us just a break-down on the non-regulated side of the guidance? What that – the various different components that ago into that break-even to 10 cents? You know, I know the financials are typically up, corporate drag typically down, but kind of a little more detail on what the moving parts are there?

Yeah, let me give you some of the components of that. And they are – and I guess – I’m probably not going to give you the exact numbers because we’ve not historically provided guidance on the non-regulated side of the businesses. But what I will kind of give you some oversight as to what we are expecting.

As we had indicated, and I’ll start with IDACOMM, as we disclosed IDACOMM lost a cent a share basically in 2002. And we are anticipating those guys to be profitable in the neighborhood of somewhere less than 10 cents a share.

IDACORP Financial we expect there to be some improvement over its results in 2002.

We see IDATech in the same range, or less than where it ended up in 2002. Mainly, that’s going to be driven by the success of our efforts there in partnering up there as we find a strategic partner there.

In IDACORP Energy, as we had indicated, we anticipate a significant decrease in what – in its loss that it recorded, but we do still anticipate a small drag coming out of IDACORP Energy and it’ll probably be less than the 10 cent area.

So that’s – and then, on the Ida-West side of things we would expect Ida-West at this point in time to be kind of break-even to a few cents a share.

Okay. And for IDATech, when you said ‘same range or less,’ is that same range or less -- since we’re dealing with a negative I just want to make sure I am getting my signs right.

Yeah, Ida-West we expect to be positive contribution.

For IDATech?

Oh, IDATech, excuse me, yes.

Similar, or slightly less of a loss?

Similar to slightly less.

Got you. Thank you very much.

Rick Sheldon, [Ducane Capital] [ph].

Good afternoon.

Good afternoon, Rick.

I was wondering if you could just go over your balance sheet capitalization goals, and what you’re targeting versus where you are now? And whether your cash flow can get there, or it gets you there alone? And then, what happens if you buy assets, and what kind of – whether you’ll have to do some equity, or you can do it with debt financing to get you there?

Sure. Right now, I think as you probably, everyone has able to calculate our cap structure based on our earnings release information today. But we are, obviously, targeting to retain and, or improve our existing credit ratings. And so, obviously, we really would like to get the utility down to kind of a 50, 50 type of cap structure. And we are going to have continued focus there on attempting to manage to do that. That would be our ultimate goal.

And at the holding company we would like to see a reduced amount of short-term borrowings at the holding company level, but as I’d indicated earlier what our balance is around 129m today, we’d like to get that balance down with some of the refinancing that we see at IDACORP Financial that we hope, actually, if we are successful to get that on a non-recourse basis to get that excluded from our capital structure from rating agency purposes.

And so, I would say that from a target, at the IDACORP level where we stand today we’re about kind of the 55, 45 right now. We would hope to reduce that, getting it a little bit closer to the 50, 50. But it probably won’t be quite at 50, 50.

All right. And I hope that you can just go over one more time, because you went over it a little quick over this, the bank facilities at the utility and holding company which are coming due?

Sure.

And also, if – basically, how you are expecting to be replaced? Whether some of them will be taken out with long-term debt? And whether there is some sort of impact from your – the marketing and trading wind-down on the size of the bank facilities that you need to get replaced? And how those will play in there?

Sure. Let me go back to the – our facility. We are right in the middle of beginning the renewal process of our 364-day facilities. And I’ll review those maybe a little bit slower with you. IDACORP currently has a $350m 364-day facility that expires in March. We would expect that number – we’re looking at that number being reduced by something, 50 percent, right around the 50 percent level.

Okay.

So down to the 150, the 175 area. And we also have at IDACORP $140m three-year facility.

Okay.

So we believe that the combination of those two facilities provide us adequate liquidity for IDACORP.

And when does that come due?

The three – the 140 three-year comes due in 2005.

Okay.

And we believe that the combination of those two facilities provide us adequate liquidity at the IDACORP level. At Idaho Power we have $200m credit facility which at this point in time we have, I believe the number is about $9m – no, excuse me – yeah, $9m outstanding on that facility today. That also is a 364 facility that comes due in March, of which we are looking to renew at the $200m level also.

Okay. And my last question is with regards to the rate case that you’re going to be filing, could you give us an idea, or just some general idea of what size rate increase that you may be filing for? I mean, given that you’ve been earning – given what hydro conditions have been doing to the ROE at the utility?

And also, can you just talk about the industrial usage? I know that you guys have lost a customer, one of your biggest customers in the State, and how those – how that may impact earnings at the utility going forward, ’02 over – ’03 over ’02, as well?

This is LaMont. Maybe I’ll address the first part of that. I don’t know, if maybe Darrel takes the last piece on the industrial loads.

But we’ve not released a number, nor have we at this point been able to calculate exactly what the number is going to be that we file. Obviously, as events transpire during the year it will shape what that number is. I think currently we expect the rate decrease for our customers this spring. I think in the last or third quarter call I put that in the range of about $150m to $200m. We see that as lower now, maybe a range of $130m to $175m. And that’s down due to the continued drought conditions that have increased costs on an actual basis, and also, lowered the expected water run-off for the 2003, 2004 year.

Our filing in the fall, basically, if you say that’s $150m, give or take, I think we’re going to be somewhere between a third to a half of that number. But, again, that’ll depend on what we’re able to put-together this fall.

All right. And as far as the industrial usage?

Well, the industrial usage is a customer that left our system, was [Astaris] [ph]. And it was a large industrial customer. It had very good rates that it purchased from us, in the 2 to 2.5 cent range.

And so, the wholesale prices, you know, currently running in the 3 to 4 cent range. You don’t incur a significant a loss, selling that energy on the market, or in our case, what it’s done is enabled us to not have to acquire as many additional resources as we otherwise might have. It helped us.

And then the other thing, and our [recent] resource plan it talked about this, we have moved to a more, or at least asked the Commission to move to a more stringent planning criteria. We used to plan on what was called median water conditions, which essentially meant half the time we would not have the native generation to cover our loans. We have tried to move to a 70th percentile test where 70 percent of the times we would have water to cover our own loads. And we’ve also used that same 70th percentile test with regard to consumption. And asked them to approve that.

And what that has done is to create the need for additional resources on our system, to be able to meet loads, and the loss of the Astaris load simply helped us. It was like the addition of a resource of that magnitude.

Okay. Thank you very much.

Nick Andrew, [Rudasell Travlet and Company] [ph].

Can you all hear me?

You bet!

I had a question just about the flexibility in the $152m in capex? You’ve got $150m for Idaho Power.

Right.

And that other 12m, is there any flexibility there, or within the Idaho Power capex number?

I’ll address part of that, and then, LaMont can kind of kick-in on the utility side of the business. But as the $12m, the majority of that $12m is really dedicated to IDATech and our funding, continued funding of the IDATech operation. And as Jan indicated, you know, we will – we continue – we’ll continue to fund that through 2003 as it continues to hit, some of it, we think of it as major milestones. But as we’ve also talked we have also looked to obtaining a strategic partner that will help us carry part of that investment.

And we also, and then, on the utility side we broke that out between where the major pieces of that are. The majority of that, 60 percent of that, is dedicated to our delivery system, 30 percent is dedicated to our power supply and re-licensing effort. And I think I’ll let LaMont kind of address the, you know, the flexibility there as it relates to those expenditures.

And I am not entirely sure I heard the question. Was it do we have flexibility with regard to reducing that, is that what you asked?

Yes. Flexibility either way?

Well, I guess, you know, the straight answer is obviously you have flexibility. You have things where you have the choice whether or not you do it. I think prudently we think we need to make those investments for our system. As I mentioned, we’ve been adding about 10,000 customers a year here for the last few years.

And we simply have needed infrastructure that we need to install on the delivery side. On the distribution and transmission network, to prudently meet our customers’ needs. And on the power supply side we have an aging thermo fleet that takes some care and feeding. We have the hydro re-licenses. We expect to get a handful of those this year that have additional costs that go-along with those. And we’re continuing to vigorously pursue the re-licensing of the Warehouse Canyon Complex, and we’re spending money on that.

So prudently, I think, that’s a number we need to spend. If we hit absolutely dire straits could we spend less? The answer is ‘yes.’ Hopefully, we don’t meet those circumstances. I think in what Darrel laid-out for you today it accommodates us to be able to spend that amount of money.

And on your question could we spend more? The answer to that is obviously yes, too. There’s a lot of things we wold like to do that aren’t in that capital budget, but we think the things we need to do are included.

Okay. The second question was just why did you all downsize the size of the 364-day credit facility at IDACORP, from 350m to 175m to 150m?

When we put that facility together last year that was predicated on the continued growth of our marketing and trading subsidiary. With the wind-down of the marketing and trading facility that level of liquidity is not required. And as we continue to wind-down that business and that liquidity requirement rolls-off as we forecast out we don’t need that same level of liquidity today. That’s the main reason for the reduction.

Okay, that’s great. And then, just one last question. Internally what are your cash flows, your operating cash flow estimates for ’03?

As I had – as I indicated in my earlier remarks we are projecting that we will have positive free cash flow going into 2003. We haven’t provided the specific cash flow numbers for that estimate.

Okay, thank you all very much.

You bet.

Jason [Skruck] [ph], SAC Capital.

Oh, good afternoon, gentlemen. Thanks for taking my call. I guess from my standpoint it looks like the earnings power of the core utility business is kind of being obscured by the cost of capital invested in the non-regulated businesses. And I guess in light of your decision in the fourth quarter to term-out some of your short-term debt, or keeping your effective debt levels the same, could you talk about the internal decision process? That the salient points of maybe the internal discussion you had of terming out that debt versus issuing equity?

Yeah, I think I’ll attempt to answer your question. I think as we look through the rationale to refinance that short-term borrowing we kind of took a look at where we stood, and where we think we’ll be going forward into 2003 and beyond. We felt like it was more appropriate at that time to issue the debt given where we projected ourselves to be through 2003, and even into 2004. We felt like we were on the road to building a better balance sheet after we made the decision to wind-down the trading business, which changed what we believe is our risk profile in regards to the rating agencies. And so we believed that that was the appropriate thing at the tie.

Thank you.

You bet.

[Paul Rizza] [ph], McDonald Investments.

Good afternoon.

Hi, Paul.

Of the $90m tax benefit, is all of that related to this year? Or is there some prior year period? And what can we look for, kind of on an ongoing basis there, if it’s not all this period?

Right. About 82 cents of that number is the key motive adjustment of that, and about 10 cents of that is the current year affect of which we would estimate that that should continue on until we have our next rate case.

Next year?

Right. To the extent that we have our, we end-up going in for rates at that point in time then that would be all trued-up at that time.

Then, on the hydro, you’ve indicated that if you had a normal hydro year you’ve got what I call ‘catch-up affect,’ where you’ve kind of got, I guess, backfill some streams and things like that. So you would not have normal river flow. Does that get worse and worse each year that you have sub-normal hydro? That catch-up affect?

Well, it’s kind of two things there. The reservoir storage, you know, could gradually get worse. But I think where we’re sitting today is it’s – I think we’re sitting, as I recall the Federal System is in the 35, 36 percent range versus normally being in the 60 percent range, as far as being full at this time.

Our own reservoirs are in pretty good shape. Especially our Brownlee Reservoir, but we will have to pull it down for flood control purposes this spring. Otherwise we’re within three or four feet of full on our own reservoirs as we sit here today, at least the large one at Brownlee.

So the affect you’re talking about, I think, is kind of an aqua for recharge, and I think there’s probably people in the company that would be effective at responding to that. I am not sure I am one of them.

But I do know that there is an affect there, and you get periods of good water years, it helps with the in-stream flows. And as you get periods of dry years it does just the opposite. So if where you’re angling is how many good years do we have to, you know, replace this, I guess I can’t answer that for sure. Other than that we have seen some reduction, and included in the run-off forecast would be some reduction of the normal aqua for recharge process.

Okay. And then, I guess, just one last question. The last call you indicated you had pretty much put on ice any plans for diversification. Is that still the thinking?

That’s true, Paul. As we indicated earlier, as Jan commented, our emphasis right now is on the utility. We have continued investment into IDATech, but without looking beyond that other than our existing subsidiaries today.

Okay. Thank you very much.

Yes.

[Jim Blasa] [ph], DA Davidson and Company.

Good afternoon. Thanks for your detail refinement on your earnings guidance, and the detail that was afforded there.

You bet.

You indicated that capex, 162m, 154 the utility. And then, you indicated 60 percent for delivery, and 30 percent for power supply and re-licensing. That means there’s 10 percent left. What would that be or?

10 percent is for the other corporate purposes, for administration, support, IT, those types of things. So that’s about a $15m number to support the rest of the operation.

Your purchased power expense was over $30m in the recent quarter. And that works-out to over six cents a kilowatt hour for purchased power. Is it that high in the marketplace? Has it been that high, or is there some unusual reason why you have to pay-up for it?

I think, I’ll take an attempt here, and then maybe Darrel and [Laurie] [ph] can come-up with it. If you have a number that includes our co-generation in the small power production purpose plan, they are in that range. In fact, some of them would pay more than six cents for. I think the average is probably six or seven cents. And those are the longer dated [PERFA] [ph] contracts that we have in Idaho and in Oregon. I do not think that we paid anywhere near that range for our, you know, our normal wholesale purchases to meet system needs due to the lower water.

And Jim, it also includes still that we still have some carryover affect of our voluntary load reduction program with Astaris. It’s still in that number.

So that should be wearing off?

Yes, by March.

You indicated that you have a pension expense increase of about $7m, but none was going to be out of cash. Why wouldn’t you want to fund it?

Well, actually, we don’t have a requirement to fund – the expense item and the cash funding are two different calculations. The expense funding requirement comes as a result of FAS 87, and based on the various assumptions are included under FAS 87, that determines what our pension expense is. The funding level is a different calculation.

And so we are not required from an actuarial purpose, there are no cash contributions required. We are, as I indicated, our plan assets are just barely below our projected benefit obligation. And we truly believe it is just a function of the marketplace. Our plan did relatively well overall through 2002, and so, we’re 12m below, but we don’t expect – I mean can’t predict the future, but at this point in time we’re not expecting to make a cash forecast. And I think we will, you know, if the market turns-around that will be, that’s not a very big hurdle to get over.

In past calls you’ve had an attempt to answer that your utility had earning power of $2.20, or thereabouts. Are you still holding to that?

Yes, I think we are. I mean that’s in a normal year, and as soon as we get rate relief, Jim, that covers our additional investments. But that’s pretty easy to get to that number. It’s roughly $20 per share book value, and 11 percent return, gives you $2.20. So assuming we can get an 11 percent return allowed, and actually earn it it produces that number.

Thank you very much.

Thanks, Jim.

David Pickens, Steve Haven Capital Management.

Hi. Just a couple of questions relating to how the filing for the rate case works. I am assuming that because you’ve got the PCA your rate case would file assuming normal water, am I correct?

This is Rick Gale. That is a good assumption. We normalize water for a general rate case.

Okay. And can you just also give us an update about how the outcomes of the hydro re-licensing would relate to the general rate case? Do you need to have more progress in terms of finding out what kind of operational restrictions might be placed upon you as part of the re-licensing?

Yes, we would incorporate any operating restrictions into the case. Also, any of the capital costs that could be incorporated into the case would be included, as well.

Okay.

Rick Sheldon, Ducane Capital.

Just one follow-up. When you talk about winding down the marketing and trading business, can you give me the idea of how big, or how much cash you expect to gather from winding down the marketing and trading business? As well as whether it’ll be a positive cash flow or a negative cash flow in the wind-down?

We are projecting positive cash flows in 2003 to 2004, which are the majority periods of time that where we see the majority of that book rolling off.

Okay. So you project positive cash flows in ’03 and ’04. And I mean is there anything that I can watch to make sure that it’s going to be positive? I mean what kind of expectations or assumptions do you use in determining that it’s going to be positive?

Well, one of the things that – I guess one number we can give you on our pre-tax basis we would project that we project about $45m as pre-tax cash coming in off of the trading business over ’03 and ’04. I think the best way, we will update you on that number, I think as the book continues to wind-down in our quarterly calls, I think that’s probably the best way to monitor that.

And just is the way to wind it down just to wait for the contracts to expire, or is it to – are you actively kind of trying to seal-off the contracts by taking the exact opposite side? How is it done?

We are doing a number of things in order to work to wind-down that book. Part of that is flattening out the book at all levels that we can. In certain cases we have some positions that are maybe at illiquid points, or those types of things that we are working through. But we are trying to get it as slight as we can so that number one, that we can pretty much put it on kind of an auto pilot type mode to work its way out over the term of the book.

Okay.

With 20 people that we will have there by the end of July that’s our target is to get it as flat as we can make it.

Okay. And my last question is as far as that tax refund is concerned, that you booked at the Idaho Power this year, and you say that it’s going to carry over into ’03, so we’re going to see something of a similar level, is that correct?

We – no, we expect something probably in the area of about $1m or so a quarter, we would expect.

Okay, is that realized as cash, as well? Or is that a non-cash item?

We – that’s a cash item for us.

All right, thank you very much.

You bet.

Bob Patterson, Glenrock Associates.

Good afternoon. I just wanted to follow-up on Rick’s trading question. Could you give me some idea about what the trading book was at the end of the year?

Let me, I guess one item I can provide for you I think that would be helpful I think is to get a sense as to what our net marketing assets were.

That’s what I mean, right. Yes, the assets.

I think where we sit at the end of December of ’02 we have a net marketing asset of about $38m as compared to about $136m at the end of ’01.

Okay, I had 138 in what I had in the past, but okay, so that’s roughly the same. But it’s going into $38m, but yet you expect to receive $45m in cash in 2003 and 2004, is that right?

You know, I am going to have [Sharon Hoyte] [ph] who is our V.P. of Finance at IDACORP Energy respond to your question. Go ahead, Sharon.

Hi. One thing to keep in mind with that $38m at the end of the year is that is impacted by any cash that we have out on margin that as the position rolls-off we would be able to pull back in. It’s also …

So does that include that, or is that excluded from it?

It is included in the $38m as a …

Okay.

If we have posted margin that would be negative to that 38.

Okay, I see. Okay. And that’s why the cash – okay, so in other words, if we were to look at the unwinding of that book it – okay, so in other words the cash, the collateral would help you out there in terms of the cash number coming in larger than your net, risk management asset itself? Is that correct?

Yes, that’s correct. And we also have, you know, our valuation adjustments for credit, and liquidity, and model impacts are also included in that 38m. When we make our projection for cash flow, you know, we take a look at whether or not – actually, we take a look at that anticipating we’re not going to have big credit hits. So there is some risk, I guess, to that 45m that we’re talking about.

Okay. I hear you, but in terms of just the earnings what was the mark-to-market gain, I guess, in revenue recognition for 2002 as a total for the year? I think it was actually probably a loss, is that correct?

Yeah. Mark-to-market total for 2002 was …

Yeah, revenue recognition impact?

$66m loss.

$66m loss, and what happens going forward? Would we expect – I mean is this going to be listed as a discontinued operation, or I mean in terms of, I mean should we see really much happening in mark-to-market considering that you guys are taking steps to keep it from, you know, from the volatility of the, you know, the value of the contracts, and fluctuating much? I mean we shouldn’t see much of a change, but what is your expectation with respect to future mark-to-market revenue recognition?

Well, a couple of things to keep in mind. And one is a metric that you can watch is the value at risk number. That’s sort of an indication of how flat our book is, and the type of volatility we would see.

But in terms of mark-to-market recognition over the course of the wind-down of the book, any income that was recognized on these positions prior to today, as those positions settle what happens from a financial reporting perspective is you would see a negative mark-to-market, which is you know, basically reversing the effective unrealized income, and then the positive settled income. So as, if you had a dollar of unrealized income booked last year and that position settles at one dollar this year you’ll see unrealized income of negative one dollar and settled income of positive one dollar for …

Right, in terms of how the book will settle-out. I am just looking in terms of on the income statement are you expecting to have any substantial impact in revenue recognition from mark-to-market activity, considering you’re unwinding the book and you’re getting out of the business?

On …

Do you see any material change, or do you see what I am saying?

Yeah, I do. On the net income basis we don’t anticipate a lot of volatility in that unrealized income number.

Okay, thanks a lot, guys.

Thanks.

Andrea Feinsten, Angelo Gordon.

Just a couple of quick questions. The first question, can you remind me, you said at the beginning of the call that you had issued some new long-term debt somewhere in the fourish percent range, and then somewhere in the sixish percent range. Can you give me the details on that again?

Sure, Andrea. We issued $200m in November, and we issued the – let me just make sure I give you the right numbers here. We issued the 10 years went-out at 4.75, and the 30-year went out at 6.0.

And you – and that took-out some short-term, an equivalent amount of short-term debt that you were paying somewhere, say in the twoish percent range on?

Correct.

Okay, where – can you show me where in your guidance the increase in capital costs is being reflected, for that 200m? Because I don’t see a step-up in any of the stuff that you guys had walked us through.

Well, we provided to you the, obviously, our Idaho Power arrangement. And this was debt that was issued at Idaho Power.

This is at Idaho Power. Okay.

This was issued at Idaho Power, and so it’s included in the dollar, in our $1.40 to $1.60.

Okay, so just actually on that point then, if I look at what this year’s earnings were on an operating basis, and if I define that as, you know, reversing out the tax benefit and the 20 cent variation loss, you come to about $1.52 on an operating basis at the utility in 2002.

You’re saying that you’re expecting basically very similar hydro. You’ve got these higher pension – I am sorry, these higher interest costs, some higher hydro relationship costs, and some higher pension and opec costs. What is – can you help me understand why then I am not seeing a decrease from the $1.52 operating earnings you made this year in your guidance for next year? What’s offsetting those higher costs?

Andrea, there’s a number of factors that are impacting our ’03 operations at the utility business. One of those is, obviously, as LaMont indicated, we are anticipating a significant rate decrease coming in May. We believe that the impact of our increased rates had an elasticity affect on consumption. So that’s one factor that is probably a big driver to looking at that forecast.

That provides, so as we look to reduce rates we would expect to see potentially more of a return to more normal usage patterns. So that’s probably a key component of that results, plus, you know, there’s just a lot of moving parts, that when we put our estimates together which, you know, we have not covered all of those, so I am not sure how to completely address your question, other than giving you our forecast which I don’t think we’re – we can probably do that.

Just on the elasticity question, can you give me a sense in percent, you know, kind of terms, roughly speaking, how much demand, how much use per customer has dropped-off in your opinion as a result of this elasticity issue?

We’re going to – I am going to give you an estimate of what that is. And as you can imagine, it’s definitely not an exact science. It’s really an estimate based on our load and resource forecaster folks. But we would estimate that on a – for 2002 somewhere in the two to three percent range is maybe a conservative number of what that elasticity affect is on that. And that’s …

And I just want to make sure I’ve got it right. Two, three percent if I am looking at the expected average use per customer versus what you actually experienced in 2002?

Correct. And then, what that doesn’t factor in, however, is other factors regarding weather, and other factors that are out there. But that is our estimate of an elasticity affect on consumption.

And for 2002 overall, can you tell me how much weather affected earnings positive or negative? You know, if you – you know, just from the perspective of kilowatt hour sales, as opposed to, you know, isolating out the drought, you know, the drought as an act of weather.

Andrea, I don’t have that number.

Can you tell me if it was material? You know, relatively speaking? Or was weather generally from a [descending degree and quality degree] day, the basis is relatively in line with normal?

It – you know, I can’t comment, because I don’t have the information here in front of me, Andrea.

Okay. Let me just see what else I had for you. Can you – actually, I can just follow-up – do you guys happen to have what percent of normal hydro was for the last couple of years, just to give me a sense of kind of if I look back and want to do some additional comparisons?

Yeah, the – let’s make sure I have the information here in front of me. Andrea, can you hang onto the call. Let us see if we can’t get that information. I don’t have that.

That’s fine. It’s not a problem.

Okay. It’s kind of in that format, so.

Okay, that’s not a problem. That’s basically all I’ve got. Thank you very much, guys.

Thanks, Andrea.

Andrea. This is LaMont Keen. I can give you a little bit of information. The – on your earlier question, the cumulative heating degree days for 2002 were very close to normal. And it was above normal in cooling degree days. I don’t know if I have them here – I can see if I can give you a percentage here.

Great.

By about 20 percent. I just calculated 24, actually, and so it was warmer than normal in the summer, and just about a normal winter.

And from the perspective of your guidance you’re assuming normal weather?

We are using our best estimates today of what our longer term forecast on weather are based on our meteorologists and in-house folks.

And have you already adjusted for what you’ve seen in January, which has obviously not been normal?

We have taken in all the information that we have available today.

Great, thank you.

You bet.

Rick Sheldon, Ducane Capital.

Sorry, guys, one more question.

Hey, Rick.

My last question, or one of, or hopefully, my last question is how much cash did you bring-in from the winding down of the marketing and trading book in ’02? And was there any collateral posting, or anything of that sort, at all in ’02?

Hang-on, Rick. The actual cash flow, the trading business in ’02 is actually negative by about $30m.

Because when I look at the actuals from ’02 from your press release it looks like you started with $138m net asset, and you’ve got like a $38m net asset at the end of the year. And so it kind of implies that you had realized $34m in cash in ’02. What am I missing, what was the change? Was it the …

You’re talking about the change in our marketing [assets?

Marketing change, yeah.

Sharon is going to address that.

Let’s see. Quite a bit of the change is just positions rolling off, and then they don’t always roll-off at the same value that they had at the end of the year in ’01, obviously. And so, you know, that’s quite a bit of the change, $100m. We also had some change in the value of the positions that we still have on our books. Positions that we had on the books at the end of ’01 that we still have on the books at the end of ’02. There’s been actually some loss in value of those positions over the course of the year with the changes in market prices and volatility.

So what would have to happen for there to be negative marks in the book again and a negative, sort of negative cash flow coming out of via winding down of the book again?

I guess the things that cause a negative mark on the book, or the mark on the book to lose value would be change in market prices for those positions that you don’t have closed-out. And I think we’ve talked already about the fact that we’ve made significant progress in closing out all of our open positions. And so we don’t anticipate a lot of change in value due to that.

Other than that, things that could change from our projection on cash flows for our remaining positions would be defaults by counterparties, you know, people not paying what they owe us. And then, obviously, any changes as a result of changes in the California situation, FERC situation, Overton situation, and things like that.

So that $45m, how much of that is basically guaranteed to come-in, versus is just an estimate and could fluctuate? I mean is it $40m, or is it $15m?

Well, I guess I would have to prudently say none of it’s guaranteed until you actually get it!

Of course, I understand what you mean, but at the same time, how much of it is locked-in, hedged, basically, until the contracts expire?

You know, I don’t have actually a firm number on that. All I can tell you is that we have made significant progress in closing our position. And so I would have to say we feel pretty good about our cash flow estimates.

Thank you.

I wanted to follow-up to, Andrea, your question with respect to percent of normal on the inflows into Brownlee. And I’ll start with 1999. 1999 we were about 137 percent of normal. 2000 we were 75 percent of normal. 2001 we were about 41 percent of normal. And 2002 about 56 percent of normal. That kind of gives you an indication, obviously, as we had indicated we are entering into our fourth year of below-normal inflows. That obviously supports that, so hopefully, that is responsive.

At this time, we have no further questions. I’ll turn things back over to our presenters for any additional or closing remarks.

Well, Lisa, thank you very much. And I would like to thank everyone for their interest in IDACORP, and our fourth quarter annual earnings release. And we’ll give you further updates as our situation progresses. And so, with that, than you again for your time and attention.

Thank you.

I’d also like to thank everyone for your participation. This concludes our conference.