Idacorp Inc (IDA) 2007 Q4 法說會逐字稿

Good day, everyone, and welcome to the IDACORP fourth quarter 2007 conference call. Today's call is being recorded and is being web cast live. A complete replay will be available from the end of today for a period of 12 months on the company website at www.IDACORPinc.com. If you need assistance at any time during today's presentation, please press star zero on your touch-tone telephone. At this time, I would like to turn the conference over to Director of Investor Relations, Mr. Lawrence Spencer please go ahead, sir.

Thank you, Melanie, and good afternoon, everyone. Welcome to our fourth quarter earnings release conference call. We issued the release before the markets opened today. And that document is now posted to our corporate website. We plan to file the 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 Darrel Anderson, IDACORP and Idaho Power Senior Vice President of Administrative Services and CFO. We also have other officers here today to help answer your 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 know that the corporation's future results could differ materially from those discussed. A full discussion of the factors that could cause due to results to differ materially can be found in our filings with the securities and exchange commission. Also, the information that we're required to provide in connection with certain non-GAAP financial information presented during this call may be found in our earning's 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 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 year end and fourth quarter results, 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 stream flow figures since they have an obvious effect on our financial performance. For most of this decade, these numbers have been quite low. But 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 Brownly 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 an improved, but still below normal water forecast. And the forecast reflects the fact that reservoir carryover levels on the Snake River System are below normal as a result of last year's drought and must be replenished. There still is a month and a 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. If approved by the Idaho public utility's commission, we'll receive a 5.2% average rate increase, producing additional revenues of approximately $32 million annually. An important aspect of the proposed settlement is the party's 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 time frame 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 agree 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 go into effect on March 1. We are expanding our generating capacity this year, and will bring in 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 stand alone basis about the time the project comes online. Additionally, we have initiatives underway that should lead to implementation of a PCA mechanism in Oregon this year. And we continue to evaluate revenue requirements and will file new generate 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. This address is not only meeting the needs of new customers, but also includes the investments required to promote energy efficiency and assure the 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 will closely follow developments at the national, regional and state level with regard to climate change legislation and regulation and will modify our plans as needed. Energy efficiency and demand site management programs and investments are increasingly important as customers place new demands on our system in adding traditional resources becomes ever more challenging. We have a multitude of new and ongoing programs designed to help customers use our product wisely and to shape consumption patterns to reduce peak loads, even assuming aggressive achievements in energy efficiency and renewable resources, however, we have the need to bring in 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 greenhouse gas laws and regulations. We concluded the development of a natural gas combined cycle combustion turban was a better and more certain option for us in this time frame. We have several locations under consideration and plan to identify the plant site this year.

Growth in numbers of new customers on our system 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 rates we experienced over much of the last 10 years, but it is in-line with the anticipated long range expectations identified in our integrated resource plan. We continually monitored growth and numbers of customers and adjust our capital plan accordingly. If we experience a significant slowdown in customer growth, we will seek to spread anticipated capital investments out over a longer period of time. Now, with that, I will turn it over to Darrel 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 advance metrics and preview our 2008 financing plan. We'll then take your questions. As LaMont noted, below normal water conditions were one of the primary drivers to our reduced earnings in 2007. Reduced stream flows combined with increased operating and maintenance expenses, offset the benefits of increased energy sales, resulting in lower earnings with compared to 2006. In addition, during 2006, we benefited from the sale of Ida Tech, had greater emission -- excess emission allowance in sales and in 2007 and the settlement of prior period internal revenue service exams benefited 2006. At Idaho power, 2007 general business revenues increased by almost $32 million or 5% when compared to 2006. $3 million of the increase is the result of a combination of changes in retail rates 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 declined earnings of Idaho power is the impact of the power cost adjustment sharing mechanism and the low growth adjustment rates, both of which cause our electric utility margin percentage to decline from 87% to 82% when compared to 2006. Total system load in 2007 was 1 million megawatts over the base load established in the 2005 generate 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 the component of the PCA deferral. The decline in this component from 2006 to 2007 reduced electric utility margins by $13 million, funds that would otherwise have been available to absorb increases and other expenses. One of the outcomes of the proposed Idaho generate case settlement is that normalized base load levels will be reset to the amount included in the 2007 generate 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 to thermal operations and maintenance, regulatory activities and third party transmission fees drove 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 at IDACORP was 14% compared to 13% in 2006. At Idaho Power, the effective rate was 32% for both 2007 and 2006. These rates were near the lower end of the ranges that we provided in our third quarter update.

Turning our discussion to liquidity, cash flow from operations decreased $89 million year over year. Total 2,000 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, an increase power supply cost referrals of $103 million, partially offset by adjustments related to the gain on the sale of assets. Increases in our investments and property plant equipment at Idaho Power increased cash needs for investing which was in line with our expectations. 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 emission allowances. Short term borrowings increased $57 million over 2006 levels. Proceeds have been used to fund increases in the preferred power supply centers and ongoing capital expenditure program. During 2007, we issued $240 million of first mortgage bonds. The proceeds were used to fund capital expenditures it and to retire $80 million of first mortgage bonds that had a coupon rate of 7.38%. On the equity front, we issued approximately $1.1 million shares of common stock in 2007, under various plans, including the continuous equity program, dividend reinvestment plan, employee incentive plan and the exercise of stock options. The issuance of these shares increased equity by approximately $37 million. These proceeds were contributed to Idaho Power to fund capital expenditures.

I will now update you on the key financial metrics for 2008. These are shown in the earnings release we issued earlier in the day, and filed with the Form 8-K we filed with the securities and exchange commission today. Our current estimate for operation and maintenance expenses are expected to be in the range of $285 to $295 million. The mid point of the estimate represents a 1% increase over the amounts 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 to $300 million in 2008. And approximately $900 million for the 2008 to 2010 period. The 2008 estimate includes the final expenditures early in the year for the Danskin gas-fired peaking plant in Mountain Home, Idaho. The 3-year total excludes any estimate for a base load 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 -- approximately $900 million dollars is expected to support our current projections of growth, and upgrade projects, as well as replacing parts of our existing infrastructure. We anticipate financing the capital program with a combination of internal generating resources, equity or equity-like securities and debt. We continue to have access to our continuing equity program with approximately $1.1 million shares of common stock available. Our goal is to maintain roughly the current capital structured Idaho Power Company, which was 49% equity and 51% debt at December 31. Earlier, LaMont addressed the prospects for approved hydroelectric generation, which during in the normal is 8.5 million megawatt hours. For 2008, our anticipated hydroelectric generation is between 7 and 9 million megawatt hours. This is based on the assumption of normal operating conditions and normal precipitation for the balance of the year.

Now, a comment about our non-regulated companies. We are estimating the combined contributions from IDACORP financial, to be between $0.05 and $0.10 per share. A decline from 2007 results in $0.13 per share, primarily relates to the higher amortization expense and lower tax benefits at IDACORP financial. Due to reduction in the amount of new investments, combined with continuing aging of existing investments. 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 would like to respond to your questions.

Thank you. Ladies and gentlemen, we will now begin the question-and-answer session. (OPERATOR INSTRUCTIONS) We will take our first question from Lasan Johong from RBC Capital Markets.

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

This is Darrel. I'm going to have Rick -- [Rick Gale] is kind of our point person with respect to settlement conversations with respect to generate case. But I'll ask Rick to comment on that.

Thank you.

Thanks. Good afternoon. The local adjustment rate was framed out in the case. We had a proposal of $29 and change per megawatt hour and the staff had one of $62.79. It was a contentious issue in that in a growing utility like ours, it is impactful to our PCA each year. So where it's set is important to material front. This is an issue we felt would be tough 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 issues on a long term basis and putting it in a stipulation than in keying up for a commissioner decision. And that resolution and the stipulation was to cut their recommendation in half or apply their recommendation to half the low, which in essence cuts their recommendation in half, therefore coming in very close to what our recommendation is.

So, if I'm not mistaken, for every megawatt hour of new demand, you would strip out basically round numbers, $30 of megawatt hour from that demand? Increased demand?

In round dollars, yes.

Okay. And in terms of forecast test year, is it likely to happen, is it not likely to happen, are they agreeable, not agreeable? I'm not quite sure where that stands at this point?

In my view. We're very explicit in these discussions with the staff and other parties in the settlement. And the tension there is that staff very much would like to start with an auditable base, an auditable test year, and in my view, are not necessarily opposed to moving those numbers forward. But that is where they would prefer 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 -- kind of a slightly different bend to the question, a slightly different emphasis. But a lot of the states in the western part of the United States are allowing renewable energy [credits] to be bought and sold. There's a lot of discussion around low impact hydrogeneration renewable energy credit. Would any of the hydro facilities that Idaho owns qualify for these credits? And if so, how much and -- how would you then monetize these things?

We're going to have Jim. Jim Miller who's our guy knows power supply by rule, talk a little bit about our hydro research that relates to the renewable energy credits.

Our existing resources wouldn't qualify, of course, but we are looking at upgrades and turbine improvement. things like that at some of our plant that would. We're also looking at a possible expansion at one of our projects along [mid Snake] that again would, I guess, would achieve the goal of the legislation that would give us those credits. What we're using that money for is to reduce the cost of the resource, so not necessarily getting the green tags that we would go out and sell. Well, we should back up a second because right now we don't have a requirement to maintain green tags. There are no RPS standards in the state of Idaho. And what we propose is if we had green tags for hydro projects like we do with these wind projects that just came online. We can go out and sell those until we had a need internally for them. And at that point we -- the proposal has been that we would probably share that with the customer and run it back to the PCA.

I see, so right now, no real commercial market opportunities, for [real] as you credit, within Idaho?

That's not the feeling right now, no.

Okay. And then there was some discussion of potentially maybe buying renewable energy credits from third party of renewable generated. Is that still a viable option for you guys or something that's not going to happen and who pays for it, and so on?

Well, there's a proposal out right now that we're talking about with the commission and interveners on using proceeds from the sale of the SO2 allowances to go out and buy green tags.

Yes.

And it's still being discussed. It 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's an RPS standard applied or applied to us.

I see, I see. Can you give us any more data on how much commission allows earnings in '08, you expect to kind of, I guess, earn?

Well, it would be very minimal. We're down to a point where we don't have many surplus or allowances left. We do generate some every year. At this point, we haven't decided whether or not we'll go out and sell the excess allowances we issued for 2008. We're allocated more than what we need. So, we generate surplus every year, but they're minimal amounts.

They're small impact going-forward?

Yes.

And last question on the transmission projects, such as Gateway -- is there any -- are you seeing any significant cost escalations? If so, how much? Is it going to throw off getting approval for rate base? How do you manage all that problems and is there any significant timing issues?

This is Darrel. I'll start this question which explains it. As it stands right now, as you know, very early in the process in looking at both the Gateway west, as well as the Idaho to the northwest line. And we're very preliminary into the planning and citing process as it stands right now. Obviously, you know that there has been increased prices associated with the cost of construction over -- especially over the last year or so, and so that's something that we continue to Monday at the, but we need to work through the sighting and planning process first, which is a fairly lengthy process in and of itself in order to ensure that we have the appropriate right-of-ways and sites identifies.

So the commission is not -- you have not made aware to the commission of any kind of cost situations at this point? In other words, there's not going to be any surprise a year or two down the line, when you go to file for rates personally or approvals, that they're going to see, you said this, and now it's that?

You know, we -- initially we put out some very broad estimates initially as it relates to the Gateway west project, which was pretty -- our share between $800 million and $1.2 billion. Now, we haven't gone in and updated those numbers as it stands right 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 numbers at the time. And we're continuing to work through that. Now, as we work -- as we spend more time on that in 2008, we would expect to be able to become a little more clear around what we believe the price of -- and the cost of the project is going to look like, but right now it's very preliminary.

Okay. If you don't mind, I just ask one last question, what's the maintenance Cap Ex going-forward?

Well, right now in the number that we are providing, which is the approximately $900 million for the next three years, all of that is not maintenance capital as we look forward for the next three years. That's the number on average for the next three years that we believe is to an appropriate level. We're going to do everything we can to only spend what is absolutely necessary to spend especially in light of the 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 is 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, the transmission projects made in part of construction costs of the CCGT?

That does not include costs --

Not on that.

That's correct.

Okay, great. Thank you.

Okay.

Next, we'll go to Paul Ridzon from KeyBanc.

Good afternoon. Can you hear me?

Hi, Paul. You bet.

A couple questions. If it's accepted, what would the year over year impact be versus '07?

I think, Paul, I'll attempt to answer that. The main change as it stands right now would be to updating the year, the base load in which the numbers apply to moving from 2005 and to 2007. That change is around, I believe, the increase in hours year over year. And that is about 800,000 megawatt hours, I believe. Let us check on that, Paul. We're going to check something. Well, I will check on that, Paul and we get back to you. But the main benefit on the load growth is the change in years and to reduce the lag from 2005 to 2007. This is obviously -- to update those numbers, we'll minimize the impact that the load growth going forward to make it as current as possible. And if we can answer that before the call is out, we will, Paul.

I have a couple more questions.

Sure.

You talk in the past about [potential reason for] higher securities, and what are you seeing in the markets there. And was that longer dated when issued those [hybrid], could be time for the markets to turn around, are they still on the table?

Right now, as we said in the past regarding those hybrids, we believe we probably have kind of a one-shot opportunity there given the size of our capital structure today and given the make-up of that. And so, if we're looking at 10% of our cap structure, possibly with a hybrid. And so, we're going to continue to look at the market. And continue to evaluate our options as we go into 2008 and fund that capital.

Okay. What was the shareholder portion of the PCA that was absorbed in 2007?

Let me just turn you to the earnings release a little bit on this. I'll give you a way to at least estimate it, because we -- and one way to look at it is, if you take the -- our margin table and you take what we call the office and sales purchase power and fuel and take the change, kind of between those year over year and this is just really a ballpark number, Paul. But if you take that number, the difference is about $130 millions between the two years. And if you want to estimate around 10% or so of 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 to seek recovery of that capital or recovery on that capital or both?

Both?

How much capital is there.

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

$70 million?

The estimate was 60 with transmission on top of that.

So, your investment is 70 million?

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

Okay. Thank you very much.

Next, we'll go to [Travis Norris] from [Bear Stearns].

Hello. Can I -- a question on the follow up for Rick on the timing of this forecast test discussion and LGAR adjustment discussion. Is that something you'll wait until a future rate case? Is that something that could be implemented this year or would you file another rate case this year to incorporate those? How would that timing go?

The first thing that happens is, we'll get the order, because we have had some preliminary discussions debt. They definitely want to see that final order that addresses the stipulation. But at that time, we convened with staff and the other parties, I anticipate and we're preparing to lead that first discussion on how that forecast -- prepare the straw man on how that forecast will be repaired. 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 year. And then we would incorporate it in our next generate case.

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

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

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

There's pressure for rate recovery.

Okay, thanks.

Next, we'll go to James Bellessa from D.A. Davidson and Company.

Good morning or good afternoon.

Hi, Jim.

The Gateway West project, is that going to be [Zurich] or an IPUC jurisdiction?

Jim, this is Darrel, we have got one of our folks who spent a lot of time with this project, his name is Kip Sykes. And we're going to ask Kip to talk about that project with respect to that question.

This is Kip Sykes. In respect to the state jurisdictional attributes of that type of the project, the answer is both. It is required under our open access transmission tariff to provide transmission service to third parties that are both jurisdictional, as well as 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 online in April 2008. What is the name of that? You have, one called Danskin and another name, something or other.

This is going to be Danskin number one, the other one is the Bennett Mountain. They'll be sister units.

And how far along is Bennett mountain?

Bennett's done.

Okay. Is that in the rate base now?

Yes.

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

This is Rick, I'll pick up on that. You mentioned the Bennett Mountain, which was, I think, two years ago, we're going to -- our plan is to sustain template for rate recovery for Danskin as we did with Bennett Mountain about two years ago, which is basically a single item overlay off the recent rate order. Single item case. Single item issue that overlays the recent expected rate order.

Your subsidiary guidance is down. Is this kind of the tone of business going-forward in '09-2010 or do you think you'll see subsidiaries picking up at a later date?

Jim, this is Darrel. We're not planning any new significant investments in those non-regulated businesses with the needs that we have at the utility. So, it's probably fair to say that that is probably the name of the business going-forward at least for the next couple years as we're 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 seeing any of that problem?

Jim, we do have about $170 million or so of bonds that are floating rates that are subject to those auctions. We have seen challenges in that marketplace. Obviously, we -- AMBACK was an insurer of those bonds. And so, we have seen an impact. But we filed the 8-K a while back related to it that. There are challenges out there with respect to those, but we have yet to -- we have not had a failed option as it stands today. As you know, those markets are very kind of up and down right now, so we're watching very closely.

And when is your next auction?

We actually just had an auction yesterday. We have two sets, one sets every seven days and one is a 35-day. We just set a 7-day yesterday.

Is it harder to re-auction the 35-day or are they about the same?

Well, we'll wait and find out when the 35-day comes due, but obviously the 7-day is more frequent. So -- as it stands right now, both of those markets are challenging. And part of it,we have to follow what happens with the insurers, I mean, that's a big part of what's going on today.

You've indicated that there was some share issuances, what is your year-end share count? Actual outstanding shares?

Hang on just a minute. We'll look that up right now, Larry -- I mean, Jim. Larry's going to look that up for us.

While you're doing that, I may as well ask about your guidance for hydro generation is 7 to 9 million megawatt hours. And I think I heard you say normal is 8-1/2?

That's correct.

So right now, you give yourself some chance that you might be normal to above normal. From right now, how would you get the normal to above normal? What would have to happen?

Well, this is Jim Miller again. Jim, if we had a period of [precipitation] like we had the last few weeks, that would definitely bump it up again. It's just going to take more [precipitation] during the spring period to create more snow that hopefully we'll get over the summer period. And then any kind of air change in weather patterns over the summer or fall. I always put more water in the river for us. We're always hopeful and we've seen a change in the weather pattern, so we're hopeful that maybe the -- we better not say the drought 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 $44,786,541, so roughly $44.8 million shares.

Thank you very much.

Thanks, Jim.

This is Rick right now. Just a quick follow-up to Paul Ridzon. Paul, you question related to the logos and just so we're clear on what we're going to answer. Obviously, the estimate for 2008, we can't talk about because there's a lot of variables there. But what we can tell you at least is what happens with respect to the change in the base load numbers, if you take a look at what the change is from 2005 to 2007 what that would be. The normalized numbers for 2005 are approximately 14.8 million megawatt hours, compared to the 2007 numbers of 15.6 million. So that should hopefully give you some basis as to the change. And then obviously then it becomes a matter of what actually happens in 2008.

We'll take our next question or a follow-up question from Lasan Johong from RBC Capital Markets.

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

We did not. What we provided you with was an estimate for the non-regular side of the business.

Would we -- should we expect one coming over the next couple months or quarter?

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 that we use to manage the key parts of our business, which is obviously O&M capital, our estimated hydro generation. We do give you some guidance related to the non-regulars considering earnings numbers. And then we give you the best estimates of what the effective tax rates are going to be. Those -- we believe are all the key metrics that we use and we feel that gives you a better opportunity based on a bunch of other assumptions that you can use and for whatever model you may be using to model us.

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

What that says is, our normalized load number for 2007 that we used in the rate case filing were about 15.6 million megawatt hours.

Versus '05 which is 14.8 million megawatt hour.

That's correct.

So over the two-year period, it's an average of 400,000 megawatt hours?

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

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

I think that -- there's some logic to that, but you also have to look at tax impacts and other things.

Well, there are pretax.

Right.

Okay. Great. Just so I can understand the mechanism. Thank you.

Okay.

And we have no further questions in our queue at this time. Mr. Spencer, I will turn the conference back over to you.

Thank you, Melanie. And thanks everyone for participating in today's call. Before closing, I would 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 28th. 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.