Welcome everyone to the IDACORP first quarter 2008 earnings release conference. (Operator Instructions) At this time I would like to turn the conference over to the Director of Investor Relations, Lawrence Spencer.

Welcome to our May 8 first quarter earnings release conference call. We issued our release before the markets opened today and that document is now posted to our website. We also filed the Form 10Q with the SEC today and that document has also been posted to our IDACORP website. On our call today we have LaMont Keen, IDACORP and Idaho Power President & CEO, and Darrel Anderson, IDACORP & Idaho Power Senior Vice President of Administrative Services & CFO. We also have other officers here today to help answer questions during the Q&A period. Before turning the presentation over to LaMont, I'll cover a few details with you. First, our presentation today may contain forward-looking statements and it is important to note that the corporation's future results could differ materially from those discussed. A full discussion of the factors that could cause future results to differ materially can be found in our filings with the Securities and Exchange Commission. Now I'll briefly discuss the financial results from today's earnings press release. IDACORP's first quarter 2008 net income was $21.7 million, $2.9 million less than last year's first quarter. Idaho Power's first quarter 2008 net income was $21.3 million, $2 million less than the first quarter 2007. IDACORP earnings decreased by $0.08 per diluted share to $0.48 per diluted share quarter-over-quarter. With that I'll now turn the presentation over to LaMont.

Thanks for taking time to call in and participate in this discussion about our first quarter results. We thank you for your interest in IDACORP and Idaho Power. Let me start by reviewing some of our regulatory activities. As a result of a settlement in February of our most recent general rate case, we implemented new rates in Idaho that increased the amount of annual revenue we collect by an average of 5.2% or $32 million. The increase went into effect on March 1 so we are seeing only one-month collections on this quarterly earnings report. Also as part of the settlement, the Idaho Public Utilities Commission agreed to make a good faith effort to resolve the issues we have with the load growth adjustment rate which is part of the power cost adjustment. The load growth adjustment rate subtracts the marginal energy costs of serving new Idaho customers from costs we are allowed to include in the PCA. The effect is that it reduces cost recovery. The Commission agreed to conduct workshops on this issue. Our regulatory strategy is to make frequent and timely filings in an effort to recover our investments as quickly as possible. So far this year we have filed a number of actions. I'd like to speak to them briefly. On March 7 we applied in Idaho for authority to raise rates 1.4% to recover $60 million in construction costs for our new 170-megawatt Danskin natural gas-fired power plant near Mountain Home. The increase would produce an estimated $9 million in additional revenue per year. The new plant was built by Siemens and is available and ready for use to meet peak summer loads. We have requested that new Idaho retail rates become effective June 1. We also filed a request to increase the monthly…

Today I will review some of the key points related to our first quarter 2008 results, discuss updates to the 2008 key operating and financing metrics, and review our 2008 financing plans. We will then take your questions. I'll begin with our recent results. Larry creatively summarized our quarterly results so I'll jump right into Idaho Power. At Idaho Power first quarter 2008 general business revenues increased by $30 million or 32% when compared to 2007. Changes in Idaho base and PCA rates from last year accounted for $20 million of the increase. Growth in customers and higher electricity usage due to weather related factors accounted for $2 million and $8 million of the increase respectively. While these positive influences increased general business revenues, quarterly operating income at Idaho Power declined. Hydroelectric production levels were approximately 10% lower than during the first quarter of 2007 due to reduced precipitation and stream flows. This increased our reliance on more expensive thermal generation and drove up current power cost adjustment deferrals by almost $16 million. The load growth adjustment rate reduced earnings by approximately $3.2 million compared to first quarter 2007. The impact was greatest in January and February because the base loads and the rates were reset on March 1 as part of the general rate case going into effect. Total system load in the first quarter 2008 was 289,000 megawatt hours over the base load established under the load growth adjustment. The load growth adjustment rate was increased in April 2007 from $16.84 per megawatt hour to $29.41 per megawatt hour, effective March 1, 2008 it was increased again to $62.79 although it applied to only half the load change. The net effect is an increase in this component in the PCA deferral. Resetting of the base loads to 2007…

(Operator Instructions) Your first question comes from Lasan Johong - RBC Capital Markets.

How much more in costs do you think you will incur to make up for the lack of hydro this year?

We have an ongoing hedging program that we constantly monitor the status of our resources and demands and so we have an ongoing program that allows us to do that. As conditions change we hedge going forward. We generally do not talk about what we’re looking at on a forward look as it relates to what those forecasted prices and unexpected costs will be. But we do hedge on an ongoing basis the resource requirements.

Which liquid hub do you look at mostly?

We generally look mid-C is where we transact most the business but we also look to do transactions at our border.

Where was the first location?

Mid-C, mid-Colombia.

In terms of the load growth adjustment mechanism you said you’re still conducting a study? I thought the $62 change; I thought that was going to be the last step. Am I incorrect about that?

What we did in our rate case settlement, one of the steps in the rate case settlement was what we would agree to look at the load growth adjustment in a separate workshop setting and that has yet to be scheduled but we expect to see that sometime later this year.

Any idea what the outcome might look like?

I don’t think we know. I think we know what the issues are and I think we have to get everybody in the room and talk about the impacts of what growth is having.

Could you go over what happened at the Bridger Coal Company?

No, I’m going to have Jim Miller who heads up our power supply group, he’s here today with us, and he’s intimately familiar with what happened, what goes on over at Bridger so I’ll have him chat with you about that.

Late December we got into an area along the long-wall that had substantial moisture in it. It got into a situation that we call a soft floor with the long-wall shear got mired in mud. By the time we got in there, shored it up and dug through that wet spot it was almost two months. So it was late February, early March by the time we dug through the water area and got back into full production. This resulted in less coal being mined out of Bridger for two months and the quality of the coal was down a little bit so financial performance for Bridger Coal Company and IERCO was down.

You said that you’re going to be filing for a rate increase after June 1 and that you got a 60-day window horizon. Is that correct?

That’s correct. We filed a notice which then allows us by June 1 is the earliest we could file it and then we have basically 60 days from that point.

This is going to be based on ‘07 test year or how is this going to work?

I’m going to, Rick Gale who heads up regulatory side of things, have him talk to you about that filing process and talk about the forecasted test year.

You might recall one of the other settlement provisions in the last general rate case was to go through a workshop on forecasted test year. We’ve conducted that workshop and we’re preparing the next case on a 2008 basis along the lines of agreements on methods or approaches to that test year for developing that workshop.

In terms of your financing needs, can you break out how much debt and equity you’re going to be looking at this year or give us a rough estimate?

We won’t speak specifically to it other than to say that we will be looking at both combinations of debt and equity as we look to the balance of the year to find not only the current capital but also some of the short balances that have been built up to date. So we will be looking at some of those financings with those continued goals to look at staying in our around that 50/50 level.

So if we model things out on a 50/50 basis we should be safe?

Yes, in and around that range. That’s pretty close. It moves around a little bit between periods but that’s our target.

Maybe in longer term any concept or idea of how you will mitigate the load growth relative to your static hydro-profile? In other words very little opportunity to increase your hydro generation capabilities but low growth with 2% a year quickly catches up to you over time. How do you try to mitigate the load growth relative to the supply? Are you looking to build more plants? Where and what types or are you going to rely more on purchase power?

We have a fairly extensive planning process, part of that is our integrated resource planning process that most recently filed in 2006 and as LaMont we’re looking to update that integrated resource plan later this summer that will provide updated information based on what we know and so what our focus is, is to keep a balance between loads and resources the best that we can in anticipation of what growth is going to be taking place but also planning for the future which is one of the reasons obviously we have the 250 megawatt plan out there that Jim has got out that the RFP that could go up as high as 600 megawatts. It’s on ongoing process that we look at in keeping loads and resources balanced.

I’m assuming new hydro is out of the question. Correct?

The only part of our resource plan that talks about new hydro is expansion at existing facilities and it’s pretty minor. There’s not a lot of opportunities and I doubt we’d be able to build new large hydro anywhere along the Snake River at least. But in following up on what Darrel had said, if you look at our resource plan there’s a pretty broad mix of new resources that includes natural gas, wind, geothermal, substantial amounts of energy efficiency, combined heating power, additional [perpa] resources. There’s a pretty broad mix plus some purchases from the outside. So there’s a pretty broad mix of new resources that we add over the next 20 year planning horizon.

This 250 megawatt RFP are you going to keep it open ended the mix of coal, gas, and renewables or are you specifically targeting fuel?

It is unspecified in the RFP but we did say it needs to be located close to our load center here in the Treasure Valley.

So you avoid transmission?

Our self-build, we’ll be proposing a self-build natural gas-fired combined cycle combustion turbine that’ll be located somewhere in the Treasure Valley as a reference plant, if you will.

That’s in addition to the Danskin plant?

Yes.

How big will that be?

Again, it’ll be competing in that 250 megawatt RFP.

I see so that’s a reference plant for somebody to come in and say okay I can do better than that?

Exactly.

Your next question comes from James Bellessa – D.A. Davidson & Co. James Bellessa – D.A. Davidson & Co.: On the window of opportunity to file a rate case has that opened, that 60-day window started or is that still a month away?

It basically starts June 1. James Bellessa – D.A. Davidson & Co.: So let’s say you file on July 1, would you be putting in a 2008 test year did I hear or would be one-half of 2007 and one-half of 2008?

We are planning to file a full 2008 rate case. That’s what we’re looking at this point. James Bellessa – D.A. Davidson & Co.: The moisture in the valleys you say is sub-par, what’s the outlook for the farmers, what’s the outlook for the weather and likely that they might have to increase their irrigation load?

We usually don’t like to comment on the weather forecast but right now we’re expecting a hot dry summer, that’s what we’re hearing from the weather forecasters. Typically it’s dry anyway so I don’t know that’ll increase irrigation loads a lot but it could be more. You’ll have to just wait and see. We don’t know how the run off is going to come, or that’ll come off all at once. If it comes off slowly it might get soaked into the ground if it gets wet all. Of course that’ll help but right now we’re expecting a hot dry summer.

Just to add to that one of the swing months is May and June and those are months that are tough to predict from a weather perspective and so I think that the best thing there is whatever weather forecast you believe in watch that one and that will help you determine what impacts we will have. That’s what we keep an eye on. But May and June are fairly critical. July and August are generally dry here anyway. It’s May and June that are the wild cards for us. James Bellessa – D.A. Davidson & Co.: [inaudible] has it rained since the first of May?

In some spots.

There are some thunderstorms a few that have rolled through. James Bellessa – D.A. Davidson & Co.: You indicated in your press release that you think that the rate case that went into affect on March 1 will help the rest of the year. Any of these other items that you mentioned on our regulatory front likely to help this year?

I would think that if we walk through the list that LaMont walked through obviously on the assumption that we can begin recovery of the Danskin plant on June 1st, there’s a benefit there. Obviously the PCA recovery is good for cash flow considerations. Obviously the increase in the energy efficiency rider is a good thing for the organization at least in the recovery of costs and in order to continue to invest into efficiency programs and looking at those items that we would expect all those at least from a cash hold perspective and also from a return perspective related to the Danskin facility. James Bellessa – D.A. Davidson & Co.: If it’s hot this summer and your hydro conditions are only roughly 90% of thermal, what does that mean to your results?

That really does depend on where we’re at from a resource perspective and if it’s beyond what we’re currently planning for, if it goes beyond what we’re planning for and is subject to what the market conditions are at the time. Today we do certain hedging opportunities based on what we think it’s going to look like with our operating plan and so we believe we take that into account in our hedging program. It’s really tough to predict what’s going to happen but we make our best estimate along our planning parameters.

The one thing that is obvious is when we don’t have hydro we have to replace it with something more expensive. As it goes down we have to increase purchases or generation at other facilities that have a fuel cost associated with. So we have to say the general effect of not having hydro is negative. Most of that is passed through the PCA; the customers’ part of it is kept by the company.

I was going to add that we start hedging the system 18 months in advance so we started buying energy for this summer 18 months ago. James Bellessa – D.A. Davidson & Co.: So that’s why it was cheap or was it?

Better than it is today.

Your next question comes from Neil Kalton - Wachovia Capital Markets, LLC.

Just a question on the new Oregon adjustment mechanism which I think is being implemented on June 1. Will that have an impact to your earnings relative to the last year or two and if so can you give us a sense of what impact that might have?

What we just had approved was the method and that was just within the last week. We have the Commission approval of the method and we have filed our first rate adjustment. Our first rate adjustment is about $4.8 million on an annual basis toward the Oregon retail customers. We have filed that case in conformance with that method so we haven’t gone through the process of having Oregon staff weigh in on that conformance. But assuming that we have filed it appropriately you could expect a June 1 rate increase of 15.7% and almost $5 million for the Oregon customers starting June 1. Now that is a catch up on our power supply costs in Oregon, there’s some other things we need to catch up on Oregon once we get this done.

Your next question comes from Stephen Gambussa – Longbow Capital. Stephen Gambussa – Longbow Capital: The Bridger Coal issue, that’s in rate base right? All those costs are part of your revenue requirement? Is that a fair statement?

Yes, they are. Stephen Gambussa – Longbow Capital: So obviously your actual diverse, what was embodied in rates this quarter, but going forward we should still think of that as regulated operation?

That’s correct.

Your next question comes from Edward Hein – Catapol. Edward Hein – Catapol: How does the four test year you talked about works in regards to capital structure? You mentioned that you potentially need a mix of debt and equity over the year to fund your capital expenditures. How does that work with regard to the test year? Is that a known and measurable that needs to be in place before the June 1 filing or is that something that you could accomplish later in the year and still put that in pro forma?

We will have an internal witness to speak to a forecast cap structure and support it. That’s my assumption as we talk today but there will be a witness at the [inaudible] structure in relation to 2008. Edward Hein – Catapol: This is the first time that you’ve been using this forward test year?

No, it’s not. We actually did it last time proposed a forecast test year last time. It became a major issue in the case and you might recall we had two new Commissioners last year so ultimately that became a factor in our decision to settle the case and then re-try the forecast in 2008.

Your last question comes from Adar Zongo – Demiere Lucas Partners. Adar Zongo – Demiere Lucas Partners: Can you talk a little bit about your capital commitments to ISS going forward and your outlook for that business? Do you expect to continue to see earnings decline over time or do you plan on pursuing additional investments in order to generate the tax credits?

One of the things that we do provide at least in the shorter term is that we look to give you some non-regulated guidance which does include Idacorp Financial as well as Idawest and holding company so we do attempt to capture what we believe in the current year the estimate for those earnings are going to be. As it relates to Idacorp Financial specifically going forward we continue to look at what our tax appetite is as an organization and with the investments now that we are making at Idaho Power Company it does, and what comes with that is additional depreciation and other things, it reduces really the amount of opportunities we have at Idacorp Financial at this time. We are monitoring that business and we will continue to look at it going forward but we don’t have any major new investments planned for Idacorp Financial.

We have no further questions left in our queue at this time.

Thanks everyone for participating in today’s call. Before closing I’d like to remind you that both our earnings release and our Form 10-Q are posted on our Idacorp website. I also want to remind everyone that the 2008 Annual Shareholders Meeting will be held next Thursday, May 15th starting at 10:00 am Mountain Time, noon Eastern Time and will be webcast live. For more details go to www.IdacorpInc.com. This now concludes our call. Thank you.