Operator: 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 12 months on the company's website at www.idacorpinc.com. [Operator Instructions] At this time, I would like to turn the call over to the Director of Investor Relations, Mr. Lawrence Spencer. Please go ahead, sir.
Lawrence F. Spencer, Director of Investor Relations
Thank you Jaime and good afternoon everyone. Welcome to our February 15 fourth quarter earnings release conference call. We issued our earnings release before the markets opened today and that document is now posted to our corporate website. The Form 10-K 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 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.
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 $0.42 per diluted share quarter-over-quarter. For 2006, earnings were $2.51 per diluted share compared to a $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 will turn the presentation over to LaMont.
J. LaMont Keen, President and Chief Executive Officer
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 IDACOMM reflect our narrowed focus on our core utility business and its 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 million 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 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 the increased energy sales, improved hydrogenation, 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 from 2005 to $2.51 per diluted share.
The company's employees did a great job last year managing a robust and growing 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 Hells 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 workforce 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 inflow 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 9, the Idaho Public Utilities Commission issued an order modifying one component of the annual power cost adjustment mechanism, or PCA. This component, called the load 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 of our service territory, that expansion sets the foundation for future earnings per share and share price growth.
I will now turn the discussion over to Darrel and will look forward to your questions later in the call. Oh, I'm sorry, Lori Smith, want to do that for Darrel?
Lori D. Smith, Vice President of Finance and Chief Risk Officer
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 plans. 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 driver 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, the recognition of benefits 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 the combination of the impact of a 19% decrease in PCA rates, which reduced revenues by approximately 80 million for the year, partially offset by the effects of a general base rate increase, growth in 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 impact of the balance of our net power supply expenses including fuel, purchased power, and sales 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 impact 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 run-off 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. The load growth adjustment 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 approximately 2 million and a credit for FERC fees of approximately 3 million.
Other changes in operation and maintenance expenses are driven by a number of factors that include increases of thermal operating expenses of 4 million, distribution expenses related to growth in customers of 7 million and compensation expenses related to the increased number of employees and incentive programs 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 a net benefit being recorded in the fourth quarter, the majority of which was reported 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 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 flow from 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 increased due to increases in capital expenditures at Idaho Power Company, cash placed on deposit with the IRS and the timing of the 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 plans and through the exercise of stock options. Issuance of these shares increased equity by approximately 41.5 million. The proceeds were contributed to Idaho Power Company to fund the ongoing capital expenditure program.
I will now update you on the key operating and financial metrics for 2007. These are also shown in the earnings release, 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 mid point 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.
Our 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 a 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 systems, 40% related to power supply resources and the balance on general plant in support of the business.
The total of the three-year period excludes any estimates for any specific base load 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 a combination of internally generated resources, equity or equity like securities and debt.
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 contributions 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 rates at IDACORP are expected to be between 20 to 25% and the tax rates at Idaho Power Company are expected to range from 35 to 39%.
J. LaMont Keen, President and Chief Executive Officer
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 had been in an automobile accident. But the good news is that Darrel is back and his son is going to be fine. He is back to join us for the balance of the call, but that is what transpired there as I handed off. So with that, that concludes our prepared remarks and we would like to respond to your questions.
Operator: Thank you. [Operator Instructions]. We will take our first question from Paul Ridzon from Keybanc.
<Q - Paul Ridzon>: Could you remind us what the - if Idaho has a statutory timeline for issuing a rate case order?
<A - Darrel Anderson>: Paul, this is Darrel. We'll have Ric speak to what our statutory requirements are in Idaho regarding rate cases.
<A - Ric Gale>: Yes, this is Ric Gale. Typically you can expect a rate order about 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. But normally the processing time is seven months from filing.
<Q - Paul Ridzon>: Would you expect to have new rates in place for 1-1-08?
<A - Ric Gale>: 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.
<Q - Paul Ridzon>: Okay. Are there any emission allowances left and what's - is there any shareholder benefit for those?
<A - James Miller>: This is Jim Miller. Currently we are holding around 46,000 excess SO2 emission allowances. We really have no intended plan to dispose of them. 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 so.
<Q - Paul Ridzon>: 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 2006 and what potential impact on 2007 it might have?
<A - Darrel Anderson>: We will have Ric kind of talk about and you are making reference to our OATT filing and that we have talked about on previous calls. We'll have Ric kind of give you an update just to where we stand on the OATT 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.
<A - Ric Gale>: This process at 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, towards the end of August of 2007. In fact it was just pointed out to me, more precisely August 21st of 2007.
<Q - Paul Ridzon>: What's the status of those revenues? Are you booking them or deferring them or how is that working?
<A - Lori Smith>: This is Lori Smith. We are booking those revenues currently. They are subject to refund. So, we do have those. We'll be recognizing a full - presumably a full year of those in 2007.
<Q - Paul Ridzon>: When did you start booking in 2006?
<A - Lori Smith>: June. June.
<A - Darrel Anderson>: 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.
<Q - Paul Ridzon>: Darrel, last time we talked at EEI 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?
<A - Darrel Anderson>: 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 just one of the tools we are looking at. We haven't settled in on any type of an equity-like security at this point of time, but what we want to do is evaluate all the options and to kind of determine the right balance for both rating agency purposes and our current owners.
<Q - Paul Ridzon>: Okay. Thank you very much.
<A - Darrel Anderson>: You bet Paul.
Operator: [Operator Instructions]. Next, we'll move to David Thickens with Deephaven Capital.
<Q - David Thickens>: Good afternoon.
<A - Darrel Anderson>: Hi David.
<Q - David Thickens>: I'm hoping your son is okay Darrel. I'm not looking forward to letting my kid drive.
<A - Darrel Anderson>: I was shaken up on that one but I think I'm back and ready to roll.
<Q - David Thickens>: All right. A couple of questions. Just more housekeeping than anything else. First, maybe we'll start with the emissions allowances. Can you explain maybe why these are not run through the fuel clause, it seems to me, or the PCA and why is that not considered just a component of fuel?
<A - Darrel Anderson>: David, this is Darrel. We are running 90% of those through the PCA.
<Q - David Thickens>: Okay. So, that was just.
<A - Darrel Anderson>: It's a 10% piece that is the piece that we were able to work with the commission on keeping for the owners.
<Q - David Thickens>: Okay. And can you also discuss a little bit more of the increase in O&M that you're expecting for 2007? What that comes from, is that just reflective of the customer growth, in general cost inflation? Is there anything you can do to mitigate that? It was going more than we are expecting.
<A - Darrel Anderson>: 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 old, older, and they are 30 plus years old, and we continue to rely on them fairly heavily - relied on them very heavily during the drought years, and so we're seeing increased O&M related to those facilities in the double-digit range as far as those and so we are seeing about a 13% increase overall for our thermal O&M fleet in the O&M side of things, which amounts to a little north of $5 million plus there, plus we have a kind of a general level of inflation related to our salary and costs, which in our case is - averages $3 million to $4 million a year, based on our current outstanding payroll, and then we also have - and we are managed - 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 service call center folks, you have linemen that support those facilities, and so all of that requires additional costs and expenses in supporting that. And 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 are in O&M. We are doing everything we can to manage those costs as tightly as we can, and being very cognizant of what the impact that has on future rates.
<Q - David Thickens>: Okay. And next question I have is, can you talk a little bit more about the - why there is significant change in the tax rate year over year? I understand your tax rate gets adjusted downward by the affordable housing tax credits that you have, but that just seemed kind of a market change.
<A - Darrel Anderson>: Well, first of all, if you take a look at what we are projecting for 2007, it's very comparable really 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.
<Q - David Thickens>: Okay. I didn't realize that that flowed through.
<A - Darrel Anderson>: Right. That's what had the largest impact on reducing that rate from what we had originally expected.
<Q - David Thickens>: Okay, okay. So, it's not a double --
<A - Darrel Anderson>: But if you take that - if you took that into account and you get back to - we're right within the range of where we thought we would be for the year.
<Q - David Thickens>: Okay, that's all I've got for now. Thank you.
<A - Darrel Anderson>: Thanks David.
Operator: Next we'll go to Adar Zango from Zimmer Lucas Partners.
<Q - Adar Zango>: Hi, good afternoon guys.
<A - Darrel Anderson>: Adar.
<Q - Adar Zango>: 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?
<A - Darrel Anderson>: 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 into the utility and in the increased appreciation, if that kicks off, that is something that continues to - that will help us on the tax efficiency perspective going forward. So, 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.
<Q - Adar Zango>: Okay great. And 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 2008 and 2009?
<A - Darrel Anderson>: Well, we would hope that if we look year-over-year that we would expect to try to manage those down and a lot of this is - 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 are doing everything else in these other areas to keep those expenses down because they did have almost a 13% increase over the 2006 levels is what's forecasted for 2007 in that area of O&M. So that means we have to really kind of ramp down the other areas in order to bring that in. So I - we would hope that that 7% is not something that we would expect to continue to see on a go forward basis.
<Q - Adar Zango>: Okay. Thank you.
<A - Darrel Anderson>: You bet.
Operator: Next we will move to Reza Hatefi, from Polygon Investments
<Q>: Good afternoon.
<A - Darrel Anderson>: Good afternoon.
<Q>: Just a follow-up on IFS. You were mentioning that you are going to shift some of the money towards the utility that you are spending, and 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 2007. Does that mean that in 2007 you really - will basically have very little CapEx at IFS?
<A - Darrel Anderson>: We are not anticipating much investment in IFS in 2007.
<Q>: And is that sort of a business where maybe in 2008 or 2009 you will decide to reinvest or start to invest again similar to how you have been investing is sort of permanently I guess shifting your resources towards the utility?
<A - Darrel Anderson>: That is something we are going to continue to take a look at and there is lot of factors that impact that, but 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.
<Q>: Okay.
<A - J. LaMont Keen>: Because this is, if I could, this is LaMont and I am a former CFO, so I can give you a little bit of the history of - IFS really came about just 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 is generating new investments, it is generating new levels of depreciation at accelerated rates and so we just don't have the same need as an entity to shield our income tax payments to the federal government that we had at that time. Now as income improves, we could get back in a situation where circumstances that were in a place before again occur, and that would incent us to put more into the IFS than we presently have planned.
<Q>: Okay, great. That helps. And 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?
<A - Darrel Anderson>: We have not actually gone into individual entity guidance, we've kind of looked at them as package and - but historically that is a big - it's a bigger portion. But, we're not looking to give individual guidance for IFS or Ida-West or the holding company.
<Q>: Thank you very much.
<A - Darrel Anderson>: You bet. Thanks.
Operator: Next, we'll go to James Bellessa from D. A. Davidson & Co.
<Q - James Bellessa>: Good afternoon.
<A - Darrel Anderson>: Hi, Jim.
<Q - James Bellessa>: Did the Brownlee Reservoir inflows for last April through July change a little? I have them down at 9 million, I think that I got it off your third quarter call. And now I heard today it was like 8.9 million?
<A - Darrel Anderson>: It is - Jim, it was 8.9 for that period of time and whether it was at some rounded to 9, I am not sure, but 8.9 is the number.
<Q - James Bellessa>: Okay. Now would you please go over again the narrative and your thoughts about how much favorable hydro have added to your results in 2006 and then I'll come through with a question, well, how will unfavorable hydro impact 2007 possibly?
<A - Darrel Anderson>: Yeah, Jim let me - I am going to take a high level view and Lori then will address it. But, one of the things, I think it is important to note that we are 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 we came out of there was the development of a risk management program that was used to really mitigate the downside risk of what might - we didn't want a repeat of what happened during 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 period then 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, but at the end of the day, it's a way to minimize the impact to the customer overall.
And so that - and so what's happened is, this is the - this last year was really the first year that we've had, what we would say is a good hydro year, really, since the implementation of that policy. And so, what you see is some of the impact of that downside mitigation that 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 full extent of the hydro system because of some of the things you did on the risk management side of things. So, in the risk management policy as you go out, you look at a certain scenario, 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, let's say like it did 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. And that's what we were attempting to communicate as it relates to the overall risk management policy and what it does.
And then furthermore, the PCA provides, and obviously as you know the 90/10 split. And so, 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 that we'd hedged the system and then we had loads that came in higher than we expected in July and we had to go out and buy when it was higher. So, a lot of those factors moved around, it 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, but that at a high level, is what we were looking to try to communicate with you on.
<Q - James Bellessa>: And did I hear a $0.07 per share contribution?
<A - Darrel Anderson>: Right, you did. You did. You heard a $0.07 per share contribution from basically the net impact of our net power supply costs. At the end of the day, when you factored in the surplus sales, purchased power, fuel costs, and put all that together, you ended up with about a $0.07 benefit.
<Q - James Bellessa>: So you hedged - or did your risk mitigation as you went into 2006, is that correct?
<A - Darrel Anderson>: Yes, the policy provides that we look out 18 months.
<Q - James Bellessa>: And so you were looking at less than favorable hydro but it turned out to have very favorable conditions. Here we're in 2007 and we are faced with less than favorable. What were your assumptions in the last three months about how the outlook was shaping up and in which way have you leaned in your risk management?
<A - Darrel Anderson>: We have continued to follow our policy. We've continued to apply the policy no different than we would have had a year ago with that and 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 ended hedging it based on the low case scenario. And so we've been hedging all along throughout this period of time.
<Q - James Bellessa>: So if a 40% better than normal stream flow in the Brownlee gives you $0.07 on the upside, could 40% lower than normal conditions give you a 7% drag?
<A - Lori Smith>: All else being equal.
<A - Darrel Anderson>: I think, Jim, all else being equal but there is a lot of factors that go into that, market prices, market fluctuations, weather, because all that - all the number we gave you includes all the factors around, weather variations and market price variations that can happen when you end up moving some of the positions that you took. So it's really - it's hard to say, all - you know, it's a very dynamic kind of thing that goes on. So I can't tell you that you have it with - that it is symmetrical.
<Q - James Bellessa>: Do you think that you did benefit from that hot weather streak or overall you turned out just about neutral?
<A - Lori Smith>: Jim, this is Lori. I would say in the third quarter, our hot streak, we did have better sales, so we did have quite a bit higher than expected net power supply costs during that time. So, I mean, it's kind of - it can be a double-edged sword as far as serving that incremental load, especially if it's unexpected. So I think that, not specifically answers your question, but --
<Q - James Bellessa>: 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?
<A - Darrel Anderson>: They were, but we are - if you look - for the fourth quarter, we had about 1.2, 1.3% increase in overall energy sales during that period of time, despite the slightly warmer weather. So it's hard to pinpoint that, Jim.
<Q - James Bellessa>: Thank you very much.
<A - Darrel Anderson>: Thanks, Jim.
Operator: Next we'll go to Darin Conti with Wachovia.
<Q - Darin Conti>: Good afternoon.
<A - Darrel Anderson>: Hi, Darin.
<Q - Darin Conti>: Hi, couple of questions. First, on your hydro generation projection for 2007, looking at the, I guess, the amount that you were able to generate in 2005, of 6.1 million megawatt hours, and it looks like the water inflows are pretty comparable, the actual 2005 to what's being projected for this year. I'm kind of wondering what's giving you the confidence that you can generate the 6.5 to 8.5 million range? Just looking at 2005 you only did 6.1 million megawatt hours. So why is the forecast so much higher I guess?
<A - Darrel Anderson>: We'll have Jim Miller who heads our power supply side speak to that.
<A - James Miller>: This is Jim. The biggest issue is probably carryover in the upstream reservoir system, the biggest single factor. But then - I'm trying to think, well 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 are 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 carry over from upstream and precip through the rest of the year. So I think it should be better than 2005.
<Q - Darin Conti>: But you understand the comparison I'm trying to get at.
<A - James Miller>: Yep.
<Q - Darin Conti>: It just seems a little optimistic I guess the projection. Unless over the next month the conditions change a little bit. But my other question was --.
<A - Darrel Anderson>: LaMont has got a comment to add.
<A - J. LaMont Keen>: Just to make sure I'm following, the 2006 actuals were 9.2 and we're saying 6.5 to 8.5 and so 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. So, 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.
<Q - Darin Conti>: Okay. Fair enough. Thank you. Another question looking at the earnings drivers in 2007, it seems like you guys are facing some pretty significant head winds with one timers of the IRS tax benefit and the emission allowance sales and then we're looking at the expected down side from the load growth adjustment rate. I'm kind of wondering, what are on the positive side, 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 2006?
<A - Darrel Anderson>: Darin, just a couple of things to remember and we talked about one of these already a little bit. We have the transmission tariffs that we are waiting on that is out there that we will have 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. And so those are probably two of the items that I would look at as things that go into 2007 as on the plus side of the ledger.
<Q - Darin Conti>: Could your just remind me on the transmission. What did you quantify there? What kind of impacts are we looking at potentially?
<A - Darrel Anderson>: Yes, Darin we're kind of - Lori you want to talk about it?
<A - Lori Smith>: 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.
<Q - Darin Conti>: Right, okay. Okay, thank you.
<A - Darrel Anderson>: Thanks Darin.
Operator: [Operator Instructions]. And next we will go to Paul Ridzon from Keybanc.
<Q - Paul Ridzon>: At IFS - what - how should we think about absent new investment, how will these tax credits decay over time?
<A - Darrel Anderson>: I'll ask Steve - Steve Keen is here, who is still working closely with the IDACORP Financial side of things.
<A - Steve Keen>: Paul, I think we do see some decay because we have - and I do want to clarify, we have continued to make small investments, but what we haven't been doing is really ramping up that business. And so given that, there will continue to be some decay but there is a play-off of the credits and also the amortization, so it's not a direct correlation that the credits are the only item that affects the income line, but I would say we would see that IFS still providing benefits into the future. So it isn't - and 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 ramp up, we won't see levels of the past.
<Q - Paul Ridzon>: Okay. And just a separate question, year-over-year depreciation and amortization dropped, I'm just wondering what drove that?
<A - Darrel Anderson>: Yes. Paul, that was - that was kind of an anomaly in 2005 where we had some extra - some depreciation taking place of some short-lived assets. That was included in 2005 and fell off in 2006. It's no longer - and so that wasn't there any longer. You will see kind of going forward we would expect to see increases in that line as we continue to add plants.
<Q - Paul Ridzon>: So 2006 and 2007 should be more normal where 2005 was the oddball?
<A - Darrel Anderson>: Yes, right. 2005 was an anomaly.
<Q - Paul Ridzon>: Thank you again.
<A - Darrel Anderson>: You bet.
Operator: Next we will go to Neil Kalton with A.G. Edwards.
<Q - Neil Kalton>: Hi, good afternoon.
<A - Darrel Anderson>: Hi, Neil.
<Q - Neil Kalton>: Just a question on the CapEx guidance, I know it's there in the press release that it explicitly excluded new base loads in the next three years and how should we think about that? What is the likelihood that we might see some moving on the base load plant within the next few years?
<A - J. LaMont Keen>: This is LaMont. I'll handle it from the policy levels 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, this with regard to the rules that are going to apply to kind of any carbon generating form of generation that's certainly coal today, as well as the uncertainties surrounding plant locations and transmission lines to bring it home. It is simply not possible today to put in anything other than a concept placeholder. Rest assured we are 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 then we can say, okay, that is an option we believe that 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 budget. Right now, it's just not possible to put in anything but a concept.
<Q - Neil Kalton>: Okay, thanks.
Operator: Next we will go to Adar Zango from Zimmer Lucas Partners.
<Q>: My question was answered.
<A - Darrel Anderson>: Thanks Adar.
<Q>: Thank you.
Operator: [Operator Instructions]. We will go to Peter Hark, Talon Capital.
<Q>: Thank you. Good afternoon, everybody.
<A - Darrel Anderson>: Hi Peter.
<Q>: 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 am seeing here is that, the deduction amount was as you mentioned increased from 5.9 to 10.3 million. But I am just trying to understand what that means in the context of expectations now that hydro conditions have deteriorated for you year-over-year.
<A - Ric Gale>: It's Ric Gale. The adjustment has to do only with load and it has to do with really trying to capture the difference between the load assumed when we establish base rates and then the load as it changes from year to year. And it's always been there. It's just what's happened now is that the value has been increased from the 16.84 where it was for the whole time of the PCA up to around 29. So the key thing and it is prospective, so it doesn't even come into play until June 1. But 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.
<Q>: Well. Okay, I got you. Maybe I don't. I will follow-up offline to get a better understanding. Secondly then just to make sure I understand the positive drivers in 2007, the - first you have the $9 million of transmission revenue that you are booking. But that you began booking in June 1 of 2006.
<A - Ric Gale>: Right.
<Q>: On pro rata, so you will see about a 5/12ths impact of $9 million in 2007. Is that the way to think about it?
<A - Darrel Anderson>: Yes. I think that's fair and less haircut for a reserve.
<Q>: Okay. And then, in Idaho I guess you have 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?
<A - Darrel Anderson>: Well, it's based on obviously rate per usage. And so, and also remember part of that is, we do have - we have seasonal rates in June, July, and August. And so, it's probably not quite pro rata. But something 7/12ths or above is probably a fair estimate of what was in 2006.
<Q>: So closer to two-thirds. So maybe 6 million will be a residual carryover into 2007, is that the right way to think about it?
<A - Darrel Anderson>: Ongoing.
<Q>: 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 2006, but then went on to say that the increase in usage was primarily a result of a record demand due to the hot weather. Of that 15 million, how much of it was due to weather?
<A - Darrel Anderson>: Do you have that?
<A - Lori Smith>: We have energy sales and a gross margin that we have broken out. We don't have it specifically quantified for weather alone.
<Q>: Okay. That's fine. Thank you. And then just to 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?
<A - Darrel Anderson>: I think that's a good way to do that. We are not going to give individual line item income statement guidance, but that's one way to look at. We have long-lived assets that we are investing in for the most part.
<Q: Okay 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?
<A - Ric Gale>: This is Ric Gale. With the capital growth mode that we are in, it's likely that and with the recent load growth adjustment, it's likely that we will 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 right now and then the split in the PCA is a form of incentive, but that's pretty much the extent of the incentive rate making anticipated. PBR works well, if you can stay out for a while and let that mechanism work. We are just going to be driven by the capital requirements for a while it looks like to me.
<Q>: Okay Ric and you say that you know it's a, multiple cases, so it's the DSM, the PCA and/or the traditional general rate case, capital cost recovery case that.
<A - Ric Gale>: I am going to take a second just to make sure we are tracking. The company looks like it is in a series of general rate cases just by what we see in the future. That being said, that doesn't if we are in a series 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 are trying to get through the commission right now.
<Q>: Okay. Thanks for clearing that up. I appreciate your time. Thanks again.
<A - Ric Gale>: Thanks a lot.
Operator: And we have no further questions left in our queue at this time. Mr. Spencer, I will turn the conference back over to you.
Lawrence F. Spencer, Director of Investor Relations
Okay, thank you. We would like to thank all of you for your continued interest in IDACORP and our fourth quarter earnings, so goodbye.
Darrel T. Anderson, Senior Vice President of Administrative Services and Chief Financial Officer
Thanks everybody, good day.
Operator: This does conclude today's conference call. We appreciate your participation. You may now disconnect.
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