Lawrence Spencer - Director of IR LaMont Keen - President and CEO Darrell Anderson - SVP of Administrative Services and CFO

Lasan Johong - RBC Capital Markets Paul Ridzon - Keybanc Travis Miller - Morning Star James Bellessa - D. A.

Davidson & Company

Thank you, Melanie, and good afternoon, everyone. Welcome to our fourth quarter earnings release conference call.

We issued the earnings release before the markets opened today and that document is now posted to our corporate website. We plan to file our Form 10-K with the SEC on February 28 and we'll also post that document to our IDACORP website.

On the call today, we have LaMont Keen, IDACORP and Idaho Power, President and CEO, and Darrell Anderson, IDACORP and Idaho Power, Senior Vice-President of Administrative Services and 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. Also the information that we are required to provide in connection with certain non-GAAP financial information presented during this call maybe found in our earnings press release located on our IDACORP website.

Now, I'll briefly discuss the financial results from today's earnings press release. IDACORP's fourth quarter 2007 net income was $10.3 million, $7.8 million less than last year's fourth quarter.

For 2007, net income was $82.3 million compared to $107.4 million in 2006. Earnings decreased by $0.19 per diluted share to $0.23 per diluted share quarter-over-quarter.

And for the year, diluted earnings per share fell by $0.65 from 2006. I'd like to point out that $0.17 of this reduction is attributable to discontinued operations.

With that, I'll now turn the presentation over to LaMont.

Thank you, Larry and good afternoon everyone and thank you for joining us on this conference call and for your interest in IDACORP. Since you have our earnings release and Larry has given a synopsis of our year end and fourth quarter result, I won't comment directly on them, but there are several important items I want to address.

First of all, I'll comment on our most recent snow pack and steam flow figures since they have an obvious effect on our financial performance. For most of this decade, these numbers have been quite low.

While, thus far this winter the news is better. Snake River Basin snow pack levels are 108% of average and at this point the Northwest River Forecast Center is projecting 5.3 million acre-feet of water will flow into Brownlee Reservoir during the April through July period.

Last year actual numbers were 2.8 million acre-feet and the 30 year average is 6.3 million acre-feet. Now you may wonder, why an above average snow pack at this point yields are improved, but still below normal water forecast.

And the forecast reflects the fact that reservoirs carryover levels on the Snake River system are below normal as a result of last year's drought and must be replenished. There is still a month and half left in the snow accumulation period, so these numbers may well change, but the weather pattern to date has been improved over last year.

Changing topics, we have a proposed settlement to our 2007 rate case that was approved by the Idaho Public Utilities Commission. We'll receive a 5.2% average rate increase producing additional revenues of approximately $32 million annually.

And an important aspect of the proposed settlement is the parties' agreement to discuss the use of forecast data in addition to historic information in future rate cases. The company believes that it is important to be able to use forecasted data because doing so shortens the timeframe between making expenditures and recovery of costs from customers, while the proposal also maintains a low growth rate adjustment at approximately the level it is today.

The parties agreed to work on an adjustment or replacement to the LGAR. The Idaho Commission still must approve this agreement and we hope to see the new rates going into effect on March 1.

We are expanding our generating capacity this year and we'll bring a new 170 megawatt natural gas peaking unit online at our Danskin Power Plant prior to peak summer loads. We intend to file for cost recovery on this project on a standalone basis about the timing the project comes online.

Additionally, we have initiatives underway that should lead to implementation of the PCA mechanism in Oregon this year. And we continue to evaluate revenue requirements and we'll file new general rate cases as it becomes prudent for us to do so.

Our focus for the foreseeable future, is on what we call invest build and grow, which addresses not only meeting the needs of new customers, but also includes the investments required to promote energy efficiency and a sure reliability of our electrical system for all customers. In order to meet the energy and reliability needs of our customers, we anticipate continued significant capital investments in our electrical system this year and into the foreseeable future.

As always, we'll closely follow development at the national, regional and state levels with regard to climate change legislation and regulation and we'll modify our plans, as needed. Energy efficiency and demand side management programs and investments are increasingly important, as customers place new demands on our system and adding traditional resources becomes even the more challenge.

We have the multitude of new and ongoing programs designed to help customers, use our product wisely and save consumption patterns to reduce peak loads. Even assuming aggressive achievement in energy efficiency, in renewal resources, however, we have the need to bring a new 270 megawatt base load resource on to our system by 2012.

Initially we planned for a coal plant, but we adjusted our preferred resource plan last year due to emission concerns, escalating construction costs, potential permitting issues and uncertainty over future green house gas laws and regulations. We concluded the development of a natural gas combined-cycle combustion turbine was a better and more certain option for us in this timeframe.

We have several locations under consideration and plan to identify the plant size this year. Growth in numbers of new customers on our systems slowed somewhat in 2007 to about 2% as we added just under 10,000 new customers.

This is down from the 3% to 4% new customer growth, which we experienced over much of the last 10 years, but is in line with the anticipated long-range expectations identified in our integrated resource plan. We continue to monitor the growth of numbers of customers and adjust our capital plans accordingly.

If we experience a significant slowdown in customer growth, we will treat the spread anticipated capital investments allowed over a longer period of time. Now with that I'll now turn it over to Darrell Anderson, who will give you more detail on our financial results.

Thanks LaMont and good afternoon everyone. Today I will review some of the key items related to 2007 results, discuss the 2008 key operating and financial metrics and preview our 2008 financial plan.

We will then take your questions. As LaMont noted, below-normal water conditions were one of the primary drivers to our reduced earning in 2007.

Reduced stream flows combined with increased operating and maintenance expenses offset the benefits of increased energy sales resulting in lower end when compared to 2006. In addition during 2006, we benefited from the sale of IdaTech at greater emission, excess emission allowance to sales than in 2007 and the settlement of prior period internal revenue service exempt benefit 2006.

At the Idaho Power 2007 general business revenue increased by almost $32 million or 5%, when compared to 2006. $3 million of the increase is the result of the combinational changes in retail rate between 2006 and 2007.

Growth in our number of general business customers accounted for $12 million of the increase and $17 million is attributable to greater customer usage due to weather related factors. While general business revenues grew, a key component of the decline in earnings at Idaho Power is the impact of the power cost adjustment sharing mechanism and the load growth adjustment rate both of which caused our electric utility margin percentage to decline from 87% to 82% when compared to 2006.

Total system load in 2007 was 1 million megawatt over the base load established in the 2005 general rate case and was an increase of 274,000 megawatt hours over 2006 total system load. The load growth combined with an increase in the load growth adjustment rate in April 2007 from $16.84 per megawatt hour to $29.41 per megawatt hour caused a decline in a component of the PCA deferral.

The decline in this component from 2006 to 2007, reduced electric utility margin by $13 million, funds that otherwise have been available to job increases and other expenses. One of the outcomes at the proposed Idaho general rate case settlement is the normalized base load level, where we reset to the amount included in 2007 general rate case filing.

These amounts will be used in the determination of the 2008 load growth adjustment, reducing some of the regulatory lag associated with this mechanism. Other operation and maintenance expenses in 2007 increased 8% or approximately $22 million year-over-year.

Higher expenses related thermal operation and maintenance, regulatory activities and third party transmission fees towards this trend. Operation and maintenance expenses reported for 2007 were $3.7 million or just over 1% higher than our third quarter guidance.

The increase over the guidance relates to higher than expected expenses for salaries and wages, information technology and legal expenses. The 2007 effective tax rate that Idaho Power was 14% compared to 13% in 2006.

Idaho Power the effective rate was 32% for both 2007 and 2006. These rates were near the lower end of the range that we provided in our third quarter update.

Turning our discussion to liquidity cash flow from operations decreased $89 million year-over-year. Total 2000 in cash from operations were $81 million compared to $170 million in 2006.

The decrease was a result of reduced net income of $25 million and increased power supply costs of $103 million partially offset by adjustments related to the gain on the sale of asset. Increases in our investments and property, plant and equipment at Idaho Power increased cash used for investing which was in line with our expectation.

The increase was partially offset by changes due to cash placed on deposit with the IRS in 2006 along with the timing of cash flows related to the sale of excess SO2 emission allowances.

On the equity front, we issued approximately $1.1 million shares of common stock in 2007 under various plans including the continued equity program, dividend reinvestment plans, employee benefit plans and the exercise of stock option. The issuance of these shares increased equity by approximately $37 million.

These proceeds were contributed to Idaho Power to fund capital expenditures. I'll now update you on the key operating and financial metrics for 2008.

These are shown in the earnings release, we issued earlier in the day and included with the Form 8-K that we filed with the Securities and Exchange Commission today. Our current estimates for operation and maintenance expenses expected to be in the range of $285 million to $295 million.

The mid point of the estimate represents a 1% increase over the amount reported in 2007. Increases are being driven by thermal operations, third-party transmission and increases in labor related expenses.

Our estimated range of capital expenditures is $280 million to $300 million in 2008 and approximately $900 million for the 2008 through 2010 period. The 2008 estimate includes the final expenditures early in the year for the Danskin gas-fired treatment plant in Mountain Home Idaho.

The three year total excludes any estimate for the base loads combined cycle natural gas plant expected to go online in 2012 or expected capital incurred for expansion of our high voltage transmission system for the Gateway West project or the Idaho Northwest line. Each of these projects are currently being evaluated and more detailed estimates will become available in the future.

The capital included in the -- approximately $900 million was expected to support our current projections of growth and upgrade project, as well as the pricing cost of our existing infrastructure. We anticipate financing the capital program with the combination of internally generated resources equity or equity like securities and debt.

We continue to have asset to our continuous equity program with approximately 1.1 million shares of common stock available. Our goal is to maintain roughly the current capital of structure at Idaho Power Company, which was 49% equity and 51% debt at December 31.

Earlier LaMont addressed the prospects for improved hydroelectric generation, which during a normal year is 8.5 million megawatt hours. For 2008, our anticipated hydroelectric generation is between 7 million megawatt and 9 million megawatt hours.

This is based on the assumption of normal operating condition and normal precipitation for the balance of the year. Now I will comment about our non-regulated company.

We are estimating the combined contribution from IDACORP Financial and Ida-West Energy, net of holding company expenses to be between $0.05 and $0.10 per share. The decline from 2007 results of $0.13 per share primarily relate to the higher investment and amortization expense and lower tax benefit at IDACORP Financial due to reduction in the amount of new investments combined with the continued aging of existing investment.

Our 2008 estimated tax rate at IDACORP are between 20% and 24% and between 32% to 36% at Idaho Power Company. That concludes our prepared remarks and now we'd like to respond to your questions.

Thank you, good afternoon. What exactly are the LGAR mechanisms, and for what test year compromise IDACORP is looking for versus what's being discussed around these two issues?

This is Darrel. I'm going to have Ric Gale, he is kind of our point person with respect to the settlement conversations, with respect to the general rate case -- I'll ask Ric to comment on that….

Thank you.

To say a little bit. Thanks.

Good afternoon. The load growth adjustment rate will spring down in the case, we had a proposal of $29 in change per megawatt hour and the staff had one of $62.79.

It was a contentious issue and that, in a growing utility like ours, it is impactful to our PCA each year. That is an important material for us.

This was an issue that we felt would start to deliver to two new commissioners to decide, and we felt more comfortable in a settled provision, where we would work with staff to resolve the issue on a long-term basis and putting it in a stipulation than key ended up for a commissioner decision. And that revolution and the stipulation was to cut their recommendation and tap or apply the recommendation to have the load, which in you have to cut their recommendation now, therefore coming in very close to what our recommendation.

So, if I've taken for every megawatt hour of new demand, you would strip out basically round some numbers $30 in megawatt hour from that demand, increasing that?

In round dollars, yeah.

Okay. And in term of the forecast test year, is it likely to happen, is it not likely to happen or they agreeable or they not agreeable, I'm not quite sure, where does that stand at this point?

In my view, we were very expert in this type of discussion with the staff and other parties in the settlement and the tension there is that the staff very much would like to start with an auditable face, and auditable texture. And in my view are not necessarily opposed to moveing those numbers forward, but that is where they would prepare to start.

So, I think we very much have a framework to propose in our next rate case again a forecast year that I think will pass the muster with staff and other parts.

And that's why you're using the '07 data to set the '08 rate?

That would be the plan.

I see, okay. I understand now.

In terms of the -- I have a slightly different bend of the question. But a lot of the states in the western part of the United States are allowing renewable energy to be bought and sold.

There's a lot of discussion around low impact hydro getting renewable energy credit. Would any of the hydro facilities that Idaho owns qualify for these credit and installed and how much kind of like?

How would you then monetize these things?

We are going to have Jim Miller, who is our head of Power Supply, and I'll talk a little bit about our hydro resources and links to those news in the renewable energy credit.

Hi, Jim Miller. Our existing resources wouldn't qualify of course, but we're looking at upgrade and turbine improvement things like that at some other plants that would.

We're also looking at possible expansion of one of our projects named the Mid-Snake, but again we'd, I guess we'd have achieved the goal I guess with legislation that would give us those credits. But we’re using money for is to reduce the cost of the resource.

So, not necessarily getting the green tag that we would [got ourselves].

Well, to backup a second, because right now we don't have a requirement to maintain green tag. There are no RPS standards in the state of Idaho, and what we propose is that we had green tag for hydro project like we do with the wind project came on line.

We can go out and sell those until we had a need internally for them and at that point at least the proposal has been -- we will probably share that with the customer and run it back to the PCA.

I see. So, right now no real commercial market opportunities for renewal energy credit within Idaho?

That's not the feeling right now, no.

Okay. And then, there was some discussion of potential maybe buying renewal energy credit from third-party renewal generating.

Is that still a viable option for you guys or is just something that not going to happen and who pays wages?

No. There is a proposal out right now that we are talking about with commission and interveners on using proceeds from the sale of the SO2 allowance is to go out and buy green tags.

Yes.

And that's still being discussed, has not been decided yet It's in a comment period right now with the Idaho commission. But the proposal would be, of course, let's go out and buy the renewable credits from [Purple] Wind Project.

We don't get renewable credits for buy those ahead of need. But the idea, we probably get a better price today that -- when there is RPS standard apply to us.

I see. Can you give us any more data on how much emission allowance earnings in '08 you expect to kind of I guess earned?

Well, it would very minimal. We are down to a point, where we don't have many surplus SO2 allowances left.

We do generate some every year and at this point, we haven't decided whether or not we'll go out and sell the excess allowance that we were issued for 2008. We were allocated more than what we need.

So we generate surplus every year, but it's a minimal amount.

Slowing back, going forward.

Yes.

Okay. And last question on the transmission projects such as the Gateway.

Is there any, are you seeing any significant cost escalation, as to how much this must throw off getting approval for rate base? How do you manage all that problem, is there any significant timing issue?

This is Darrel. I'll start this question and let Ric explain to it.

As it expands right now, as you know, very early in the process in looking at both the Gateway West as well as the Idaho-Northwest Line and we're very preliminarily into the planning and exciting process that expands right now obviously you know that there has been increased prices associated with the cost of construction especially over the last year or so. And so that's something we continue to monitor.

But we need to get and work these exciting and planning process first which is a pari ranking process in it itself in order to ensure that we've the perfect right-aways and sight to identify.

So the commission is not, you've not been aware to the commission of any kind of cost situations at this point. Does that going to be surprise year 2009 when you go to offer rate potentially or approvals that and mostly you said this and no it's that?

We initially we put out some very broad estimates initially as it relates to the Gateway West project, which was pretty [offshore] between $800 million and $1.2 billion. Now, we haven't gone in and updated those numbers at this center now because it's still very preliminary as it relates to what we think the exact costs are going to be.

Those were very early number at the time and we are continuing to work through that. Now, as we spend more time on that in 2008, we'd expect to be able to become a little more clear around what we believe the price and the cost of the project is going to look like, but it's right now, it's very preliminary.

Okay, if you don't mind I'll just ask one last question. What was the maintenance CapEx going forward?

Well right now, in the number that we're providing which is approximately $900 million for the next three years, while all of that is not maintenance capital, as we look forward for the next three years that, that's the number on average. For the next three years, we believe it is an appropriate level.

We're going to do everything we can to only spend what is absolutely necessary to spend especially in light of there are three other projects that we discussed. So, we've announced $900 and our hope is to be in or below that number in the form of what we're going to call maintenance capital.

And that -- most likely the maintenance capital was less than that but we want to give you the $900 as it stands right now.

Okay. And, so that would include the development of the CCGT, the transmission potential, development transmission projects maybe and Powder construction costs associated?

That does not include costs associated…

Not all that.

And that's correct.

Okay, great. Thank you.

Okay.

Good afternoon. Can you hear me?

Hi Paul, you're there.

Couple of questions under the proposed load growth adjustments; what, if it's accepted, what would the year-over-year impact will be versus '07?

I think Paul, I've said the answer. I think the main change that it stands right now would be to updating the year, the base load, of which the numbers are slightly moving from 2005 and into 2007.

That change is around, I believe the increase in hours year-over-year and that is about 800,000 megawatt hours. Just a second, Paul, we're going to check something.

Well, I'll check on that Paul and get back to you. But the main benefit on the load growth is the change in the years and to reduce the lags on 2005 to 2007, which is obviously to update those numbers will minimize the impact of the load growth going forward to make it as current as possible.

And if we can answer that before the calls, yeah, we will, Paul.

Another couple of more questions….

Sure.

You talked in the past about potentially using hybrid securities and nobody is seeing in the markets there and was that longer dated, when issued those [hybrid], could be fulltime for the markets to turn around at least turn the table?

Right now as we've said in the past regarding those hybrids we believe we probably have kind of one shot opportunity there given the size of our capital structures today and given the kind of the makeup of that. And so, if we -- we're looking somewhere around 10% of our capital structure possible with the hybrids.

And so, we're going to continue to look at the markets and continue to evaluate our options, as we go into 2008 to fund that capital.

Okay. And also shareholder portion of the PCA that was observed in 2007?

Let me just turn to the earnings release a little bit on this. I'll give you the way they are at least estimated because we and one way to look at it is if you take our margin table and if you take what we call the assets from sale purchased power and when you take the change kind of between those year-over-year, and this was just really a ballpark number, but if you take that number the difference is about $130 million between the two years.

And if you want to estimate around 10% so that number that will get you in the ballpark of approximately, what the impact of that might be.

Thank you. The plant that's going in at Danskin are you going take recovery of that capital or recovery on that capital or both and how much capital will be there?

It's going to be just under $70 million.

70 million.

Ric, that was right.

Yeah, that not was 60 with transmission on top of that.

So, your investment is 70 million.

Then the final numbers actually aren't in at this point, Paul, but we think it will be something under that number.

Okay, thank you very much.

Good morning. I had a question on the follow-up for Ric.

On the timing of this forecast past year discussion and LGAR adjustment discussion, is that something that you wait until future rate cases, that could be implemented this year, would you file another rate case this year to incorporate those. How would that timing go?

Well, the first thing that happens is we get the order. As we have had some preliminary discussions with them, they definitely want to see that final order that addresses the stipulation.

But that time we convened with staff and the other parties, I anticipate and we are preparing to lead that first discussion on how that forecast prepare to strong and how that forecast would be prepared recognizing the concerns that were expressed in the rate case. So we would be working through in a workshop manner to find what agreement we could have on a methodology for forecast here.

And then we have to incorporate it in our next general rate case.

And if that workshop process goes well, do you anticipate filing this year?

Well, we always plan to be ready to file, I don't we haven't made any decisions about filing.

Okay. It would be a good benefit, though, to file as soon as possible though.

It's pressure for rate recovery.

Okay. Thanks.

Good morning or afternoon.

Hi, Jim.

The Gateway West Project, is that going to be an IPUC jurisdiction?

Jim, this is Darrell. We've got one of our folks, who spent a lot of time with this project his name is [Kip Sykes].

And so we are going actually ask to talk about that project with respect to that question.

This is Kip Sykes. In respect to the 3rd state jurisdictional attributes for that type of a project and to answer both, it is required under our open access transmission tariff to provide transmission service to third parties that are jurisdictional as well as the major forward looking component of the capacity has serve our need of load..

You have this 170 megawatt natural gas plant you're going to bring on line on April 2008. What is the name of that?

You have one called Danskin and another name something or other.

Yeah, it's going to be Danskin number one, the other one is Bennett Mountain. There will be testing unit.

And how far long is Bennett Mountain?

Bennett is done.

Okay. And is that in the rate case now?

Yes.

And so Danskin, one that you're going to be asking for rate recovery, now you're going to do that outside of a general rate case or you're going to put it inside at general rate case filing?

This is Ric. I'll pick up on that.

That you mentioned Bennett mountain, which was, I think two years we're going to -- our plan is to use the same template to rate recovery for Danskin, as we did in Bennett mountain two years ago, which is basically a single item overlay off the recent rate order. The single item case -- single item issue that overlays that with the respected rate order.

Your subsidiary guidance is down, is it’s a kind of the tone of business growing-forward in '09, 2010 or do you think that you'll see subsidiaries picking at a later day?

Jim, this is Darrel. We are not planning any new significant investment in those non-regulated businesses with the need that we have at the utility.

So, it's probably fair to say that, that has probably been the name of the business going forward leads for the next couple of years as we are looking at those entities today.

You call out the fact that you had some municipal related option activity and I saw a headline reading that this week there was a failed MUNI auction. Are you saying any of that problem or?

Jim. We do have about 170 million or so bonds that are floating rates that are subject to those auction.

We have seen challenges in that marketplace. Obviously, we -- AMBACK was an insurer of those bonds, and so, we've seen an impact as we did file the 8-K a little back related to that.

So, there are challenges out there with respect to those but we've not had a failed auction as advance today. But as you know that those markets are very kind of up and down right now and so we're watching that very closely.

And when is your next auction?

We actually, we did that an auction yesterday. We've choose that's one and that's every seven days and one is the 35 day.

And so we just reset a seven day yesterday.

It is harder to re-auction, the 35-day or is it about the same?

Well, we’ll wait and find out when the 35 day comes to you. But I mean obviously the seven day is obviously more frequent.

So, as it stands right now both of those markets are challenging. And part of it is we've to follow what happens with the insurers I mean that's the big part of what's going on today.

You've indicated that there was some share inventories. What is your year end share count, actual outstanding shares?

Hang on just. We'll look at that right now, Larry.

I mean, Jim. Larry will look that up for you.

And why you are doing that I might have well asked about your guidance for hydro generation is 7 to 9 million megawatt hours and I think I heard you say normal was 8.5?

That's correct.

So, right now you give me some chance that you might be normal to above normal. What -- from right now how you did to normal to above normal?

What would have to happen?

Well, this is Jim Miller again. Jim, if we had a period of precept like we had in the last few weeks so, we'd definitely bump it up again.

It's just going to take more precept during the spring period create more snow that hopefully will get over in the summer period. And then, any kind of a change in weather patterns over the summer or the fall can always put more water in the river for us.

So, we're always hopeful and we've seen a change in the weather pattern. So, we're hopeful maybe the -- better not to say the draught is over but hopefully it's going to be better.

Jim. This is Larry, Larry Spencer.

The share count at the end of the year was 44 -- I mean its 786.531, so roughly 44.8 million shares.

Thank you very much.

Thanks Jim.

This is Greg right now. Just a quick follow-up to Paul Ridzon -- Paul your question related to the load growth and just to be clear on what we're going to answer.

You know obviously, that the estimate for 2008, we can't talk about because there is lot of variable there. But what we can tell you at least is what happens with respect to the change in the days flow number if we take a look at what the change is from 2005 to 2007 and what that would be.

The normalized numbers for 2005 are approximately 14.8 million megawatt hours compared to the 2007 numbers of about $15.6 million. And so that should hopefully give you some basis for the change.

And then obviously then it becomes a matter of what actually happens in 2008.

Very quickly on 2008, did you give specific EPS guidance?

We did not. What we provided Ric, was an estimate for the non-reg side of the business.

Should we expect when coming over the next couple of months or quarters?

No, we elected a couple years ago really not to go down that path and what we believe we think is more beneficial is giving you some of what we believe our key operating metrics. The way we used to manage the key parts of our business, which is obviously O&M capital or estimated hydrogenation.

We do give you some guidance related to the non-ranked subsidiary earnings numbers and then we give you our best estimates of what we think is effective tax rate are going to be in. Those are we believe are all the key metrics that we use and so that gives you a better opportunity based on a bunch of others assumptions that you can use in whatever model you might be using the model us.

I see and then just on the Energy just in response to your statistics now on average that implies about a 400,000 megawatt hour change due to new demand, correct figure?

Well, our normalized load numbers for 2007 that we use in the rate case filing were about 15.6 million megawatt hours.

Versus '05 versus 40.8 million megawatt hour?

That's correct.

Over the three year period an average of 400,000 megawatt hour?

Per year, yeah you can look at that way, that's correct.

In theory that's a $12 million adjustment to your earnings power due to load growth, this is $13 per megawatt hour. LGAR is approved.

I think that there is some logic to that, but you also to look at tax impact and other thing.

Well, I understand. Where is the pre-tax?

Right.

Okay great. Just I can understand mechanism.

Thank you.

Thank you, Melanie. And thanks everyone for participating in today's call.

Before closing, I'd like to remind you that our earnings release is posted on our IDACORP website and that we expect to file our 10-K with the SEC on February 28, that document will also be posted to our website. That now concludes our call.

Thank you.

Thanks, everybody.

This does conclude today's conference call. We appreciate your participation.

You may disconnect at this time.