Idacorp Inc (IDA) 2006 Q4 法說會逐字稿

Good day, and welcome, everyone, to the IDACORP fourth quarter 2006 conference call. Today's call is being recorded and is being webcast live. A complete replay will also be available from the end of the day for a period of twelve months on the company's website at www.IDACORP Inc..com. [OPERATOR INSTRUCTIONS] At this time, I'd like to turn the call over to the Director of Investor Relations, Mr. Lawrence Spencer. Please go ahead, sir.

Thank you, Jamie and good afternoon everyone. Welcome to our February 15th fourth quarter earnings release conference call. We issued earnings release before the markets opened today and that document is now posted to our corporate website. The form 10K will be filed on March 1st and will also be posted to our IDACORP website. Included on the call today are LaMont Keen, IDACORP and Idacorp Power President and CEO and Darrel Anderson, IDACORP and Idacorp 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.

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. Before turning the presentation over to LaMont I'll briefly recap the financial results presented in today's earnings press release. IDACORP's fourth quarter earnings report shows net income of $18 million, up significantly from $8 million in fourth quarter 2005 and year-to-date earnings of $107 million, compared with $64 million in 2005. Earnings increased by $0.24 per diluted share to $.42 per diluted share, quarter-over-quarter. For 2006, earnings were $2.51 per diluted share, compared to $1.50 per diluted share in 2005.

Our chief subsidiary, Idaho Power, had earnings of $0.39 per diluted share for the quarter, the same as fourth quarter 2005. Now I'll turn the presentation over to LaMont.

Thank you, Larry, and greetings to all of you joining us on the call today. 2006 turned out to be a good year as a result of improved operating results at Idaho Power Company and the sale of IDACORP technologies. That transaction and the announced agreement to sell IDACOM reflect our narrowed focus on our core utility business and it's capital needs. In 2006, customer growth at Idaho Power Company continued at a strong, but somewhat slower pace from 2005. We connected 14,633 new customers, a 3.2% increase. And at the end of 2006, we had over 470,000 retail customers.

Weather variations also boosted general business sales in 2006 versus last year. Hot summer weather prompted record electric usage, primarily during July, when we set a series of new record peak loads. On the supply side, improved stream flows enabled us to generate 9.2 million megawatt hours with our hydro fleet, compared to only 6.2 in 2005. Hydroelectric generation contributed 57% of our total system generation, compared to 46% in 2005. In June, we received a general rate increase in Idaho, which increased customers' base rates by approximately with 3.2% or $18 million. We also sold excess sulfur dioxide emission allowances last year and were allowed to retain a small portion of that gain for the benefit of stockholders.

This combination of increased energy sales, improved hydro generation, rate relief, and emission sale benefits improved operating margins at Idaho Power and operating income increased by nearly $25 million over 2005. The sale of IDACORP technologies was completed during the third quarter and added $0.27 per diluted share. IDACORP's consolidated earnings per share for 2006 increased by over $1.00 from 2005 to $2.51 per diluted share.

The company's employees did a great job last year, managing a robust and capital investment program, meeting the needs of existing and thousands of new customers under sometimes very trying conditions, moving forward on obtaining a new license for our Hell's Canyon hydro complex and dealing with a myriad of other operational and regulatory requirements. One of our historic strengths has been the quality, skill, and dedication of our work force and we fully expect this to remain so in the future.

Looking forward, hydro conditions are not as favorable as they were last year at this time. January precipitation was only 30% of average. The Northwest River Forecast Center is projecting that stream flows into Brownlee Reservoir during the critical April through July time period will be 3.6 million acre feet. Last year flows were 8.9 million acre feet during this time period. The 30-year average measured in flow into Brownlee for the April through July period is 6.3 million acre feet. Darrel Anderson will speak more about this in a moment.

On the regulatory front we received an important order that will have ramifications in the future. On January 9th, the Idaho Public Utility Commission issued an order modifying one component of the annual power cost adjustment mechanism or PCA. This component, called the "low growth rate adjustment" subtracts the cost of serving new Idaho customers from costs we are allowed to include in the PCA. The impact of this decision will be determined by future load growth. Assuming an average 40 megawatt increase in annual loads, the new rate would result in an additional 4.4 million being subtracted from the PCA.

The impact may be partially offset through more frequent general rate case filings or by slower customer growth. We have said in the past that our regulatory strategy is to file more frequent rate cases because of the need for reinvestment and economic growth occurring in our service territory. This ruling tends to reinforce that strategy, and we therefore expect to file a general rate case this year. The good news is that while there are growing pains associated with the economic expansion in our service territory, that expansion sets the foundation for future earnings per share and share price growth.

I'll now turn the discussion over to Darrel and we'll look forward to your questions later in the call. I'm sorry -- Lori Smith, you're doing that for Darrel?

Yes, thanks, LaMont. Good afternoon, everyone.

Today, I will review with you some of the key drivers to 2006 results, discuss the 2007 key operating and financial metrics and then give you a preview of our 2007 financing plan. At the conclusion of the discussion, we will then look forward to responding to your questions.

As LaMont noted, 2006 results were impacted by a number of different factors with the primary drivers being improved operating results at Idaho Power Company, driven by a base rate increase that began in June 2006 and continued energy use growth, partially offset by increases in operating and maintenance expenses. In addition, [inaudible] -- from the sale of excess SO2 emission allowances, the sale of IDACORP Technologies and the settlement of all non-uniform capitalization-related items in our 2001 to 2003 Internal Revenue Service examination increased overall results. At Idaho Power Company, 2006 general business revenues decreased by almost $31 million compared to 2005. The decrease is a combination of the impact of a 19% decrease in PTA rates, which reduced revenues by approximately $80 million for the year, partially offset by the effects of the general base rate increase, [inaudible] customers and increases in demand due to weather-related factors.

On the resource side of business, our hydro facilities generated an additional 3 million megawatt hours compared to 2005. These improved hydro conditions, combined with the impacts of the balance of our net power supply expenses, including fuel, purchase power and sale for resale contributed an estimated $5 million to our improved gross margin or $0.07 per share. While one might expect a larger increase due to the improved hydro conditions, there are three primary factors that affect the net benefit. These factors include forward purchases made in accordance with our risk management policy, based on then-current forecast data, the reduced economic value of the hydro-generation due to the timing of the runoff and greater-than-expected purchases in the third quarter of 2006 due to warmer-than-normal temperatures resulting in increased demand. The net benefit was further reduced by $4 million, or $0.06 per share, primarily due to the impact of our existing load growth adjustment mechanism. So load growth included in the PCA mechanism eliminates power supply costs related to new loads between general rate case filings.

Our other operation and maintenance expenses increased approximately $15 million over 2005 or approximately 6%. The 2006 amount includes a credit for the gain on the sale of excess SO2 emission allowances of approximately $7 million. Also included in these expenses are the write-off of the Grid West expenses of $2 million and a credit for [furk] fees of approximately $3 million. Other changes in operation and maintenance expenses are driven by a number of factors that include increases in thermal operating expenses of $4 million, distribution expenses related to growth and customers of $7 million and compensation expenses related to the increased number of employees [inaudible] of $9 million.

Included in the 2006 net income is the impact of the settlement of all non-263A issues from our 2001 through 2003 IRS exam. The settlement resulted in net benefit being recorded in the fourth quarter, the majority of which was recorded at Idaho Power Company, increasing its 2006 earnings by approximately $8 million or $0.19 per share. If you exclude this settlement from the calculation of our effective tax rates, the effective rate would be 20% at IDACORP and the 38% at Idaho Power Company. The adjusted rates are within the previous guidance we provided for this metric. Our actual effective tax rates were 13% and 32% for IDACORP and Idaho Power Company, respectively.

Now turning to liquidity. Cash flows form operations increased slightly over 2005 levels. Total cash from operations was approximately $170 million compared to $161 million in 2005. Keys to the increase were improved net income of $44 million, partially offset by changes in working capital items and adjustments related to the gain on the sale of assets: cash used for investing activities, increase due to increases in capital expenditures at Idaho Power Company, cash placed on deposit with the IRS and the timing of cash flow related to the sale of excess emission allowances.

Short-term borrowings increased almost $69 million over 2005 levels. Proceeds have been used to fund increases in our ongoing capital expenditure program, as well as the $45 million refundable deposit related to the uniform capitalization issue with the IRS.

On the liquidity front in 2006, we issued approximately 1.2 million shares of common stock under various plans, including the continuous equity program, dividend reinvestment plan, employee benefit plan and through the exercise of stock options. The issuance of these shares increased equity by approximately $41.5 million. The proceeds were contributed to Idaho Power Company to fund ongoing capital expenditure programs.

I will now update you on the key operating and financial metrics for 2007. These are also shown in the earnings press release we issued earlier in the day and included in the form 8-K that we filed with the Securities and Exchange Commission. Our current estimates for operation and maintenance expenses are expected to be in the range of $270 to $280 million. This midpoint of the estimate represents an increase of 7% over amounts reported in 2006. Increases are being driven by continued double-digit increases in expenses at our thermal operations and anticipated increases in labor expenses. We will seek to recover these increases in a 2007 general rate case filing that we plan to file later this year.

A range of capital expenditures is expected to be $290 to $320 million in 2007 and approximately $830 million for the three-year period 2007 through 2009. The estimate for 2007 includes a major portion of the capital spending for a gas-fired [peaking] plant to be located in Mountain Home, Idaho. It is expected that this plant will go on line in the first half of 2008. We recently received the requisite Certificate of Public Convenience and Necessity from the IPUC in order to proceed with this project. Approximately 50% of the total three-year estimate is expected to be spent on our transmission and distribution system, 40% related to power supply resources, and the balance on general plant and support of the business. The total of the three-year period excludes any estimate for any specific baseload resource as we are currently evaluating a number of options. The capital included in the current $830 million is expected to support our current projections of growth, and upgrading and replacement of our existing infrastructure.

Based on our current liquidity estimates, we expect to finance the capital program with the combination of internally-generated resources, equity or equity-like securities, and debts. We continue to have access to our continuous equity program, where we have approximately 1.9 million shares of common stock available. Our target is to maintain our current capital structure at Idaho Power Company, which was 50% equity and 50% debt at December 31, 2006.

The expected hydroelectric generation that we anticipate to produce for the year is between 6.5 to 8.5 million megawatt hours. The estimated total hydroelectric generation for the year is based on the assumption of normal operating conditions and slightly below normal precipitation for Spring 2007 with a return to normal precipitation for the balance of the year. We are estimating the combined contribution from IDACORP Financial and Ida-West Energy [net] of our holding company expenses to be between $0.10 and $0.15 per share. Our effective tax rate at IDACORP are expected to be between 20% to 25% and the tax rate at Idaho Power Company are expected to range from 35% to 39%.

Okay. Thank you. That was Lori Smith, our Vice President of Finance and Chief Risk Officer, and she did the proverbial stand in at the last minute. Just as Darrel Anderson was about to speak, he was called out of the room to find out that his teenage son has been in an automobile accident. But the good news is that Darrel's back, and his son is going to be fine. He's back to join us for the balance of the call, but that's what transpired there as I handed off. So with that, that concludes are prepared remarks, and we would like to respond to your questions.

Ladies and gentlemen, we will now begin the question and answer succession. [OPERATOR INSTRUCTIONS]

We'll take our first question from Paul Ridzon from KeyBanc. Would you remind us if Idaho has a statutory time line for issuing a rate case order?

Paul, this is Darrel. We'll have Ric speak to you what our statutory requirements are in Idaho regarding rate cases.

This is Ric Gale. Typically, you can expect a rate order seven months after the filing. The commission can take extra time, and has on occasion. And usually if that's the situation it behooves the company to allow them the extra time. Normally, the processing time is seven months from filing.

Would you expect to have new rates in place for 1/1/08?

The exact timing of our filing hasn't been determined yet. We are actively looking to address regulatory lag this year, so the exact nature of the test year and the timing of our filing hasn't come to a final determination.

Okay. Are there any emission allowances left? And is there any shareholder benefit for those?

This is Jim Miller. Currently, we're holding around 46,000 excess SO2 emission allowances. We really have no intended plan to dispose of those. Kind of waiting to see what happens with air quality legislation and other requirements at this point. And those are good, they roll over year-to-year.

And then earlier in the year you talked about a potential margin improvement from a rate case filing on transmission and just kind of wondering what the status of that is and what impact it had on '06 and what potential impact on '07 it might have.

Well, we'll have Ric kind of talk about -- you're making reference to our [oak] filing that we have talked about on previous calls. We'll have Ric kind of give you an update on where we stand the oak filing. We don't have that information directly available today, Paul, as to what the impact is as it relates to 2006. But Ric can give you an update as to where we stand with that.

This process of the [FERC] is a long process. Right now, the company is preparing rebuttal testimony which is due at the first of April 2007. I think that we are still expecting an initial decision of approximately August of 2007 -- in fact, toward the end of August of 2007. In fact, it was just pointed out to me, more precisely August 21st, 2007.

What's the status of those revenues? Are you booking them or deferring them? How is that working?

This is Lori Smith. We are booking those revenues currently. They are subject to refund. So we do have those. We'll be recognizing, presumably, a full year of those in 2007.

When did you start booking in '06?

June.

Paul, this is Darrel. We are recording the revenues that were approved subject to refund and as part of that we are setting up a part of that as a reserve. And we started booking those in June of 2006, so we'll see in 2007 some benefit from that as compared to 2006.

Darrel, last time we talked [inaudible] you said you were thinking hard about which equity or equity-like instrument you'd want to use. Just wondering what progress you've made in that decision process.

We are continuing to evaluate the products that are out on the market and we will continue to evaluate those securities throughout 2007 based on our needs and so it is one of the tools we are looking at. We haven't settled in on any type of an equity-like security at this point in time. But what we want to do is evaluate all the options to kind of determine the right balance for both rating agency purposes and our current owners.

Thank you very much.

[OPERATOR INSTRUCTIONS] We'll move to David Thickens with Deephaven Capital.

Good afternoon. Glad to hear your son's okay, Darrel. Not looking forward to letting my kid drive.

Shaken up on that one. I think I'm back ready to roll here.

A couple of questions. Just more housekeeping than anything else. First, maybe we'll start with the emissions allowances. Can you explain why these are not run through the fuel clause or the PCA? And why is that not considered just a component of fuel?

David, this is Darrel. We are running 90% of those through the PCA. It's the 10% piece that is the piece that we were able to work with the commission on keeping for the owners.

Okay. And can you also discuss a little bit more the increase in O&M that you're expecting for '07. What that comes from. Is that just reflective of the customer growth or general cost inflation? Is there anything you can do to mitigate that? It's kind of more that we were expecting.

It is and a couple of things that's important to understand. And a big part of the increase is coming out of the continued O&M at our thermal facilities and those, as you remember, are older. They are 30+ years old and we continue to rely on them fairly heavily. Relied on them very heavily during the drought years. So, we're seeing increased O&M related to those facilities in the double digit ranges for those.

So, we're seeing about a 13% increase overall for our thermal in the O&M fleet in the O&M side of things. Which amounts to a little north of $5+ million there. But, we have the general level of inflation related to our salary and costs, which, in our case, averages $3 to $4 million a year, based on our current outstanding payroll. And then we also have -- and we are looking to try to manage this very tightly, but it's the adding of the new resources required to continue to support our new customers.

LaMont mentioned, we added almost 15,000 customers and if you think about what does that mean in the form of -- you have call center folks, you have linemen that support those facilities, and so all that requires additional costs and expenses. We are estimating about $4 million or so in new salary costs related to positions to stay up with the growth that we are continuing to anticipate. Now, if that growth is to slow down, then we will manage that cost accordingly.

But right now, based on our estimate for 2007 and what we see on the horizon related to continued growth, those are expected increases -- the main areas of our expected increases in our O&M. We are doing everything we can to manage those costs as tightly as we can and being very cognizant of the impact on future rates.

Okay. And next question I have is -- can you talk a little bit more about why the significant change in the tax rate year-over-year? I understand that your tax rate gets adjusted downward by the affordable housing tax credits that you have, but that just seemed kind of a market change.

First of all, if you take a look at what we are projecting for 2007, it's very comparable to the levels that we had originally expected to see in 2006. And the main driver to the change in 2006 really is the settlement of the 2001 to 2003 tax settlement.

OK, I didn't realize that that flowed through.

That's what had the largest impact on reducing that rate from what we had originally expected. If you took that into account and you get back to -- we are right within the range where we thought we would be for the year.

Okay. That's all I've got for now. Thank you.

Next we'll go to [Dar Zango] from Zimmer Lucas Partners .

Hi, afternoon guys. I was wondering if you could talk a little bit more about IFS and your plans for that business over the next few years. Are you going to continue to make regular investments in affordable housing projects? Is it a growing business? Are there any growth opportunities there at all?

Right now, our current emphasis is not to continue to grow that business, given the continued investment that we are making in the utility and it really is driven by what we perceive on the horizon is our ability to utilize some of those tax benefits. And right now we believe with the investment end of the utility and the increased depreciation, that kicks off -- that is something that will help us on a tax efficiency perspective going forward. Our goal right now is to continue to manage the current investments that we have at IDACORP Financial. And so for right now, we don't see significant increases in investments at IDACORP Financial.

OK great. Just in terms of the 7% increase in O&M year-over-year, will that be an ongoing rate at least in the near term? And if not what should we see going forward, looking into '08 and '09?

We would hope that if we look year-over-year we would expect to try to manage those down and a lot of this, like we said before, a big piece of this is coming out of the thermal fleet and depending on the progress that they can make there that will drive a piece of that increase. We're doing everything else in these other areas to keep those expenses down. They did have almost a 13% increase over the 2006 levels, is what's forecasted for '07 in that area of O&M. That means we have to kind of ramp down the other areas in order to bring that in. So, we would hope that that 7% is not something that we would expect to continue to see on a go-forward basis.

Okay. Thank you.

You bet.

Next we'll move to Reza Hatefi from Polygon Investments.

Good afternoon.

Good afternoon.

Just to follow up on IFS. You were mentioning that you're going to shift some of the money towards the utility that you are spending. If my memory serves me correct, I think in last year's 10-K you were guiding to $47 million of CapEx at IFS in 2006 and '07. Does that mean that in '07 you really will basically have very little CapEx at IFS?

We are not anticipating much investment in IFS in 2007.

Is that sort of a business where maybe in 2008 or 2009 you'll decide to start to investment again, similar to how you have been investing? Or permanently shifting your resources towards the utility?

That's something we're going to continue to take a look at and there's just a lot of factors that impact that. One of the other items out there is just finding good affordable housing investments today that provide a return that we believe is competitive to continue to make those investments is another side of that.

Okay.

This is LaMont. I'm former CFO, so I can give you a little bit of the history. IFS really came about as trying to manage our tax payments to the federal government as a shield to the amount we were paying at a point in time that we were approaching full depreciation of some significant investments that we had made in the 70s. And so we needed a vehicle because depreciation was falling off, investment tax credits were falling off. And so we shielded the tax income with IDACORP Financial Services. .

As we go into the big capital campaign at Idaho Power Company, it's generating new investments. It's generating new levels of depreciation at accelerated rates and so we just don't have the same need as an entity to shield income tax payments to the federal government that we had at that time. Now, if income improved, we could get back in a situation where circumstances that weren't in place before again occur and that would [incent] us to put more into IFS than we presently have planned.

OK. Great. That helped. As part of your $0.14 -- I'm sorry as part of your $0.10 to $0.15 guidance for 2007 for the unregulated businesses, what portion of that is IFS?

We've not actually gone into individual entity guidance. We've kind of looked at them as a package. Historically, it's a bigger portion. We're not looking to give individual guidance for IFS or Ida-West or the holding company.

Thank you very much.

You bet. Thanks.

Next we'll go to James Bellessa from D.A. Davidson & Co.

Good afternoon.

Hi, Jim.

Did the Brownlee Reservoir [inaudible] for last April through July change a little? I had them down at $9 million. I think I got them off of your third quarter call. I heard today it was like $8.9 million.

Jim, it was $8.9 million for that period of time and whether it was at some point rounded to $9 million, I'm not sure.

Okay. Would you please go over again the narrative and your thoughts about how much favorable hydro added to your results in '06 and then I'll come through with a question -- how will unfavorable hydro impact '07 possibly?

I'm going to take a high level view -- then we'll address it. One of the things I think it's important to note is that we're looking to communicate in the prepared remarks was the fact that the hydro system -- if we went back to 2001 and we went to the energy crisis. One of the things that came out of there was the development of a risk management program that was used to really mitigate the downside risk -- we didn't want a repeat of what happened in the energy crisis.

So we instituted a risk management policy that set us up to begin hedging the system with a longer-term view. And so what that does is you make an assumption and based on certain factors that you know as you go into the precipitation periods and you go out and decide, based on certain assumptions, what is the requirement? Where are you long? Where are you short? And you go out and begin hedging the system.

And that's how our risk management policy was developed, was around mitigating that downside. It also mitigates a little bit of the upside, that you would allow. At the end of the day, it's a way to minimize the impact of the customer overall. And so what's happened is this last year was really the first year that we've had what we'd say is a good hydro year really since the implementation of that policy. What you see is some of the impact of that downside mitigation we saw in the first five or six years of when the policy was in effect. And now what you're seeing is some of that -- we didn't necessarily maximize the fullest extent of the hydro system because some of the things that you did on the risk management side of things.

In the risk management policy says you go out, you look at a certain scenario and then you go out and hedge the system. And that's what we did. By doing that, you get long and if you get long and the water comes, like it did in 2006, then you end up longer, you end up reselling it. But at the end of the day, you have minimized your downside risk. You haven't necessarily taken full advantage of the upside either, but you kind of caught it in the middle. That's what we attempted to communicate as it relates to the overall risk management policy and what it does.

Furthermore, the PCA provides, as you know, the 90/10 split. In this particular case we did receive some benefit from the hydro system. Not as much as one might have thought. But which part of that then was mitigated by some of these other factors; the fact we'd hedged the system and then we had loads that came in higher than we expected in July. We had to go out and buy with the fire. So, a lot of those factors moved around that actually put a bit of a cap on how much we could have otherwise got out of the hydro system. That's a long, probably drawn-out answer to your question. At a high level, is what we were looking to try to communicate with you on.

And did I hear a $0.07 per share contribution?

Right, you did. You heard a $0.07 per share contribution from, basically, net impact of our net power supply costs at the end of the day when you factor it in, the surplus sales purchase power, fuel costs and put all that together, you ended up with about a $0.07 benefit.

You hedged or did your risk mitigation as you went into '06? Is that correct?

The policy provides that we look out 18 months.

And so you were looking at less than favorable hydro, but it turned out to have very favorable conditions. Here we're into '07 and we're faced with less than favorable. What were your assumptions in the last three months about how the outlook was shaping up and which way have you leaned in your risk management?

We have continued to follow our policy and continued to apply the policy no different than we would have had a year ago with that. Based on the assumptions that we went in there with, and we go in with an expected case and a low case, and the way the policy is written, we end up hedging it based on a low case scenario. We've been hedging all along throughout this period of time.

If a 40% better-than-normal stream flow into Brown Lake gives you $0.07 on the upside, could the 40% lower-than-normal give you a $0.07 drag?

I think, Jim, all else being equal. But there's a lot of factors that go into that: market prices, market fluctuations, weather. Because all that -- the number we gave you includes all the factors around weather variations and market price variations that happen when you end up moving some of the positions that you took. So it's hard to say. It's a very dynamic kind of thing that goes on. I can't tell you that it is symmetrical.

Did you think you did benefit from the hot weather streak or overall turned out just about neutral?

JIm, this is Lori. I would say in the third quarter, our hot streak we did have better sales, but we did have quite a bit higher than expected net power supply costs during that time. So I mean it's -- can be a double-edged sword as far as serving that incremental load, especially if it's unexpected. I think that -- not specifically to answer your question, but --

On a per share basis, how adversely impacted were you by the temperatures in the fourth quarter? They were warmer than normal by about 8% over the previous year.

They were but if you look -- for the fourth quarter we had about a 1.2%, 1.3% increase in overall energy sales during that period of time, despite the slightly warmer weather. It's hard to pinpoint that, Jim.

Thank you very much.

Thanks, Jim.

Next we'll go to Darin Conti with Wachovia.

Good afternoon. A couple of questions. First, on your hydro generation projection for '07, looking at the amount that you were able to generate in '05, 6.1 million megawatt hours, and it looks like the water inflows are pretty comparable, the actual in '05 to what is being projected for this year. I'm wondering what's giving you the confidence that you can generate the 6.5 to 8.5 million range -- just looking at '05, you only did 6.1 million megawatt hours. So why is the forecast so much higher I guess?

You have Jim Miller, who heads up our power supply side speak to that.

This is Jim. The biggest issue is probably carryover in the upstream reservoir system. The biggest single factor. But then -- well, I'm trying to think, as far as the forecast we've got lower than average precip forecast for the next month or two and then heading back towards normal. So it's tough to estimate.

But when you're looking at that total generation number for the entire year, it doesn't just include the spring runoff period. So, it isn't just the snow pack condition. It can also include flows through the rest of the fall and those are based on reservoir carryover from upstream and precip through the rest of the year. I think it should be better than 2005.

But you understand the comparison I'm trying to get at? It seems a little optimistic I guess, the projection. Unless over the next month the conditions change a little bit. But my other question was --

Hey, Darin, LaMont has a comment to add.

Just to make sure I'm following. The 2006 actuals were 9.2 and we're saying 6.5 to 8.5. We give the range because we don't know that the weather doesn't improve materially between now and spring and it has in some years past. Not forecasting that, but it has and if it does then the top end of this range calculates reduced flows to date and factors in that they would be better in the future. The low end of the range is more of a continuation of what we've seen. That's why that range is pretty broad -- the 6.5 and 8.5. And if the weather changes over the next few months, it could improve materially versus what it appears today. So that's why it's a broad range.

Okay. Fair enough. Thank you. Another question looking at the earnings drivers in '07, it seems like your guys are facing some pretty significant headwinds with the one-timers of the IRS tax benefit and the emission allowance sales and now we're looking at the expected down side from the load growth adjustment rate. And I'm kind of wondering, what on the positive side, aside from customer growth, what are some of the drivers or factors that might be able to offset the one timers that kind of benefited you in '06?

Darin, just a couple of things to remember and we talked about one of these already. We have the transmission tariff that we are waiting on that is out there what we will see in effect for the full year. Obviously, we'll have the base rate case that went into effect on June 1st in effect for the entire year. Those are probably two of the items that I would look at as things that go into 2007 on the plus side of the ledger.

Could your just remind me on the transmission - could you quantify that? What kind of impacts are we looking at potentially?

Yes, we're -- Lori you want to talk about it?

Darin, what we originally filed for was about an annual increase of $11 million and then subsequently to that, there was an adjustment made to that that brought that annual look based on 2005 transmission activity, related. It brought it down a couple million dollars to about $9 million. And then like we said earlier, we do have a reserve against that on a go-forward basis because of the proceeding that's in progress today.

Right. Okay. Thank you.

Thanks, Darin.

[OPERATOR INSTRUCTIONS] We'll go to Paul Ridzon from KeyBanc.

IFS -- how should we think about, absent new investment, how will these tax credits decay over time?

I'll ask Steve. Steve Keen's here who is still working closely with the IDACORP Financial side of things.

Paul, I think we do see some decay because we have -- and I do want to clarify -- we have continued to make small investments. What we haven't been doing is really ramping up that. Given that, there will continue to be some decay. There's a playoff of the credits and also the amortization. So it's not a direct correlation that the credits are the only item that effect the income line. I would say we'd see that IFS still providing benefits into the future. So it isn't -- I mean that's why we've given the guidance that we've given for 2007. But it is safe to say without continued investment and some rampup, we won't see levels of the past.

Okay. And just a separate question. Year-over-year depreciation and amortization dropped. Just wondering what drove that.

Paul, that was an anomaly in 2005 where we had some depreciation taking place on some short-lived assets, that was included in '05 that fell off in '06. so that wasn't there any longer. I think going forward, we would expect to see increases in that line as we continue to add plants.

'06 and '07 should be more normal where '05 was the odd ball.

That's right. '05 was an anomaly.

Thank you again.

Next, we'll go to Neil Kalton with A.G. Edwards.

Good afternoon. Just a question on the CapEx guidance. I noticed in the press release that it explicitly excluded new base load over the next three years. How should we think about that? What's the likelihood that we might see some movement on the base load plant within the next few years?

This is LaMont. I'll handle it from a policy level and if you want specifics, Jim Miller, our Senior Vice President of that area is here. Where we are is our integrated resource plan shows the need for a new base load unit or coal plant by about 2013. As we sit here today, with the state of flux with regard to the rules that are going to apply to any carbon-generating form of generation and certainly coal today as well as the uncertainties surrounding plant locations and transmission lines to bring it home, it's simply not possible today to put in anything other than a concept place holder.

Rest assured, we're looking at all of our options to meet that need in the future. We see that need continuing to be there and as something firms up enough that we can say OK, that is an option we believe is viable and regulation, or new laws or legislation, settles down to where we can understand the situation with enough certainty to make an informed decision, we will introduce that into our capital budgets. Right now, it's just not possible to put in anything but a concept.

Okay thanks.

You bet.

Next we'll go to [Dar Zango] from Zimmer Lucas Partners.

My question was answered.

Thank you, Dar.

[OPERATOR INSTRUCTIONS] We'll go to Peter Hark with Talon Capital.

Thank you. Good afternoon everybody. Just trying to understand again the impacts of hydro relative to the new PCA adjuster that the Idaho commission ordered I guess about a month ago. I guess what I'm seeing here is that the deduction amount was, as you mentioned, increased from $5.9 to $10.3 million. I'm just trying to understand what that means in the context of expectations now that hydro conditions have deteriorated far you year-over-year.

It's Ric Gale. The adjustment has to do only with load. It has to do with really trying to capture the difference between the load assumed when we established base rates and then the load as it changes from year-to-year. It's always been there. What's happened now is that the value has been increased from the [1684], where it was for the whole time of the PC, up to around 29. So the key thing and it's prospective, it doesn't even come into play until June 1. The key thing that will happen then is if load does go up, then it will be adjusted by that rate and vice versa -- if load goes down, it's adjusted the other way. But, depending upon what load does, not anything related to hydro is how it impacts the company.

Okay. I got you. Maybe I don't. I'll follow up offline and get a better understanding. Secondly, then, to make sure I understand, the positive drivers in '07. First you have the $9 million of transmission revenue that you're booking that you began booking in June 1 of '06. In pro rata, so you'll see about a 5/12 impact of $9 million in '07. Is that the way to think about it?

I think that's fair and less some haircut for reserve.

In Idaho, I guess you had the $18 million rate increase go effective June 1, as well. I was just wondering, of that 18, how much of that was recognized in 2006?

Well, you know, it's based on obviously rate per usage and also remember part of that is we do have seasonal rates in June, July, and August. And so it's probably not quite pro rata. Something 7/12 or above probably a fair estimate of what was in 2006.

Closer to two-thirds. Maybe $6 million will be a residual carry over into 2007? Is that the right way to think about it?

Ongoing.

Yes. Okay. And then maybe you said this and I missed it, but when you talked about increased energy sales contributing $15 million after tax in '06, but then went on to say that the increase in usage was primarily a result of record demand due to the hot weather. Of that $15 million, how much of it was due to weather?

We have that.

We have energy sales and a gross margin that we have broken out. We don't have it specifically quantified for weather alone.

Okay. That's fine. Thank you. And then just a follow-up. Paul Ridzon had a question on D&A. What will the D&A line go up by? A couple of million? Is that about right? If you take the $60 million increase in CapEx and if that's over 25 or 30 years, is that the right way to think about the increase there?

That's a good way to do that. We're not going to give individual, line-item income statement guidance, but that's one way to look at it. We have long-lived assets that we're investing in for the most part.

OK. And when you do file a case, aside from the usual cost of service items, are there any other features that you might be seeking in terms of PBR-type of features to the case?

This is Ric Gale. With the capital growth mode that we're in, it's likely that and with the recent load growth adjustment, it's likely that we'll be filing multiple cases, so it doesn't really have a chance for a PBR to work yet at this time. We have a small incentive filing, related to DSM, before the commission now and then the split and the PCA is a form of incentive, but that's pretty much the extent of the [inaudible] rate making anticipated. PBR works well if you can stay out for a while and let that mechanism work. We're just going to be driven by the capital requirements for a while, it looks like to me.

OK, Ric. And you say that multiple cases -- so it's the DSM, the PCA and/or the traditional general rate case, capital cost recovery case.

I'm going to take a second just to make sure we're tracking. The company looks like it's in a series of general rate cases, just by what we see in the future. That being said, if we're in a serious of general rate cases, it doesn't give a performance-based rate-making mechanism a chance to really work. So it just doesn't fit our situation right now. The other two things I gave you were examples of where we do have one incentive in place. Our PCA does have an incentive element to it. And then we have a new DSM, just a pilot filing that we're trying to get through the commission right now.

OK, thanks for clearing that up. I appreciate your time. Thanks again.

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

Thank you. We would like to thank all of you for you're continued interest in IDACORP and our fourth quarter earnings, so goodbye.

Thanks everybody.

This does conclude today's conference call. We appreciate you participation. You may now disconnect.