Idacorp Inc (IDA) 2009 Q4 法說會逐字稿

Good day, and welcome everyone to IDACORP fourth quarter, 2009 conference call. Today's call is being recorded and is being webcast live. A complete replay will be also 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.

Thank you, Louisa, and good afternoon everyone. Welcome to our February 23, fourth quarter 2009 earnings release conference call. We issued our earnings release before the markets opened today and that document along with our SEC Form 10-K is now posted to our IDACORP website at www.idacorpinc.com. We will be using a few slides to supplement today's call and these are located on our IDACORP website. We will refer to specific slide numbers as we work our way through today's presentation.

Now moving to slide one. On the call today, we have LaMont Keen, IDACORP and Idaho Power President and CEO and Darrel Anderson, IDACORP and Idaho Power Executive Vice President of Administrative Services and CFO. We also have other officers available to help answer your questions during the Q&A period. Before turning the presentation over to LaMont I will cover a few details with you. First, our complete Safe Harbor statement is on slide number two. 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.

Referring to slide three, I will briefly discuss the financial results from today's earnings press release. Fourth quarter 2009 net income attributable to IDACORP was $23.5 million, $16.1 million more than last year's fourth quarter. For the year 2009 net income attributable to IDACORP was $124.4 million. $25.9 million more than 2008. Idaho Power's fourth quarter, 2009 net income was $25.9 million compared to $7.7 million in 2008 while Idaho Power's annual 2009 net income was $122.6 million or $28.4 million greater than 2008. IDACORP earnings increased by $0.33 per diluted share quarter over quarter, to $0.49 per diluted share and by $0.47 per diluted share on a year to date basis to $2.64 per diluted share. I will now turn the presentation over to LaMont.

Thanks, Larry, and welcome to our call participants. We thank you for your interest in IDACORP. 2009 was a challenging year. We sought to enhance the health and financial strength of the business while respecting the impact the ongoing economic uncertainty had on our customers. I am pleased our resourceful management of the Company resulted in increased earnings thanks to the creativity and hard work on the part of our employees and diligent oversight by our Board of Directors. We were also recognized for other successes in numerous national venues and despite the challenges that we faced, 2009 was a year of accomplishment. We are therefore well positioned as we enter 2010 from a financial and regulatory perspective.

We could use a little help from Mother Nature, however, as snow pack levels are currently only 60% of normal. Our 2009, fourth quarter financial performance improved over last year as 2008 fourth quarter earnings were negatively impacted by two matters that did not recur in 2009. These items, the open access transmission tariff refund ordered by the FERC and an investment impairment negatively impacted fourth quarter, 2008, pretax earnings by $15 million. As shown on slide four, and as I indicated earlier, our hard work is being recognized on many fronts.

The New York Times January 24, article on our energy efficiency programs has been picked up by numerous media outlets and acknowledges us as a leader not only in energy efficiency but also in designing the mechanisms which fund the programs. In 2009, we pursued and were approved for energy efficiency rider increase from 2.5% to 4.75% in Idaho. Our decoupling mechanism called the Fixed Cost Adjustment or FCA was also recognized for its ability to ensure we are not penalized for encouraging our customers to use less.

Additionally, the newly established Maplecroft climate innovation index shown on slide five recognized Idaho Power as one of the top 100 companies best equipped to handle environmental policy changes. Idaho Power ranked 68th in this index. We were also one of the companies selected from among many applicants to receive a smart grid stimulus grant from the Department of Energy. The final acknowledgement I would like to mention is our ranking in the top quartile in customer satisfaction in a nationally recognized customer satisfaction survey. All of these recognitions are a testament to the diligence of our 2,000 employees. In 2009, our purposeful regulatory strategy continued to produce key results. I already mentioned our energy efficiency rider increase.

Perhaps our greatest accomplishment from a regulatory perspective was the general rate case settlement agreement with Idaho regulators and customer groups as shown on slide six. The agreement specifies the distribution of the expected 2010 PCA decrease to provide up to $25 million of general rate relief to the Company and to fund the need for approximately $75 million of increased based power supply costs while granting a significant rate reduction to customers. The agreement also provides a general rate moratorium until January 1, 2012. We are still authorized to file applications for items like the PCA, the FCA, pension expense and the advanced metering infrastructure project. A key provision of the settlement gives us the ability to amortize additional accumulated deferred investment tax credits to achieve a 9.5% return on year-end equity in Idaho. The regulatory, finance, and legal teams worked hard last year to make the settlement work for the Company and our customers. We are making improvements to our system to ensure we are able to meet our customer's energy needs when the local economy recovers. Our integrated resource plan or IRP filed with the Idaho and Oregon Public Utilities Commissions in December projects the number of customers in the Company's service area will increase from approximately 490,000 now to over 680,000 by 2030. The IRP reflects our commitment to gradual reduction in carbon intensity goals and reaffirms our commitment to capital projects such as our 300-megawatt Langley Gulch natural gas fired combined cycle generation resources and critical transmission projects.

In Oregon we requested that new retail rates be implemented on March 1, 2010. It has been approximately six years since our last general rate case increase in Oregon. Idaho Power's rate case filed with the Oregon PUC sought approximately $7.3 million in annual cost recovery. The final settlement agreement which is subject to Oregon Public Utility Commission approval provides $5 million in annual recovery enabling the Company to better cover increases associated with expenses and capital expenditures.

To wrap up my comments 2009 was a challenging year. IDACORP, however, was able to succeed by continuing its path of prudent and resourceful management. We will continue stepping forward in 2010 looking for ways to approve operational efficiencies while preparing for an eventual economic recovery. Rest assured we are working to achieve continued success for our Company, our owners and our customers in 2010 and beyond.

I will now hand it off to Darrel Anderson, who will update you on our financial results.

Thanks, LaMont, and good afternoon, everyone. Today I will discuss the key fourth quarter and 2009 earnings drivers, our current liquidity positions at IDACORP and Idaho Power, the year-to-date financing activities and finish with a discussion of the 2010 key operating and financial metrics. After that, we look forward to taking your questions. Slide seven reconciles our 2008 earnings to 2009 earnings. All items on the slide are pretax except for the change in income taxes and other. The improved financial results were a combination of several factors. The positive changes to our power cost regulatory mechanisms in Idaho and Oregon, retail base rate changes in the first and second quarter of 2009 and the impact of reductions in the effective tax rate all contributed to the strong fourth quarter and overall 2009 results.

The annual results were partially offset by a reduction in retail energy sales and the commercial, industrial and irrigation classes. With greater precipitation in 2009 we saw a 14% reduction in irrigation sales year-over-year. Energy sales to the residential sector were effectively the same as 2008. Overall, Idaho Power's energy sales in 2009 decreased 4% as compared to the prior year in part reflecting economic factors and energy conservation. The declines in sales volume were partially mitigated by the load growth adjustment rate and the fixed cost adjustment decoupling mechanism. Hydroelectric generation accounted for 53% of the total system generation in 2009 compared with 48% in 2008. We produced 8.1 million megawatt hours of energy from our hydro-electric plants in 2009 approximately 17% more than the 6.9 million megawatt hours generated in 2008 and 94% of the 8.6 million megawatt hours of annual generation under median water conditions. General business revenues increased almost $100 million for the year as compared to 2008. The increase is mostly attributable to the changes associated with PCA rate increases in June 2008 and 2009 combined with increased retail base rates. Other operation and maintenance expenses excluding the fixed cost adjustment mechanism increased $2.8 million for the year, due to payroll related items and an increase in uncollectible accounts, partially offset by a reduction in outside services and office supplies due to cost containment measures.

Depreciation expense increased $8.5 million mainly due to the accelerated depreciation of the existing meter infrastructure related to our change to automated meters. Income taxes for 2009 reflect the settlement of the 2006 to 2008 Internal Revenue Service examinations. These and other regulatory flow through tax adjustments at Idaho Power contributed to the reduction in the effective tax rate at IDACORP to 15.2% compared to 16.3% in 2008 and 22.5% at Idaho Power Company as compared to 28.5% in 2008. Two additional items that positively impacted the comparison of 2009 to 2008 results relate to 2008 activities that did not recur in 2009. The two items include an open active transmission tariff refund of approximately $5 million ordered by the FERC that reduced transmission revenues and an impairment of investments of $6.8 million. No additional amortization of deferred investment tax credits was utilized during 2009 as the Idaho jurisdictional earnings exceeded 9.5% of the Idaho Retail Common Equity.

Cash flow from operations improved to $284 million from $137 million in 2008. The increase is primarily the result of a deferral of net power supply costs decreasing $65 million and the collection of previously deferred net power supply costs increasing $49 million. The net cash paid and refunded for income taxes improved cash flows by $42 million primarily due to audit settlements. Cash flow from operations was also positively impacted by an increase in net income of $26 million. These improvements were partially offset by the refund of $13 million to transmission customers after receiving a final order from the Federal Energy Regulatory Commission on Idaho Power's open access transmission tariffs. Cash used for investing activities was $242 million, an increase of approximately $40 million over 2008. The increase is attributable to the return in 2008 of a $45 million refundable tax deposit originally made with the Internal Revenue Service in 2006.

The impact was to reduce total investing activities in 2008. Through it subsidiary IDACORP Financial, IDACORP also made a $6 million investment in affordable housing. The outflows were partially offset by $9 million received from the sale of bond investments at IDACORP Financial, $2 million in proceeds from the sale of emission allowances and $2 million in proceeds from the sale of Southwest Intertie Project both by Idaho Power. Financing activities during 2009 included the issuance of $230 million of Idaho Power first mortgage bonds,net repayment of $94 million in short term debt and proceeds of $24 million in new equity issued under the dividend reinvestment plan, employee benefit plan and the continuous equity program. On December 1, 2009, Idaho Power repaid $80 million of its 7.2% first mortgage bond. During the third quarter 2009, Idaho Power remarketed $166 million in pollution control revenue refunding bonds, and used the proceeds to repay its $170 million term loan credit agreement. Commercial paper outstanding at December 31, 2009, was $54 million at IDACORP and none at Idaho Power. Current revolving credit facilities at IDACORP and Idaho Power are $100 million and $300 million respectively with $46 million available at IDACORP and $276 million available at Idaho Power at December 31, 2009. Both of these facilities expire in April, 2012. I will now update you on the key operating and financial metrics for 2010 on slide eight. I will also discuss the initiation of our 2010 earnings guidance. These are also shown in the earnings release issued earlier today. The increase in capital expenditures to a range of $355 million to $365 million from 2009 levels reflects the expected ground breaking of the construction of the Langley Gulch power plant with anticipated spending on the project in the range of $138 million to $140 million in 2010.

The range also includes expenditures for the Hemingway-Bowmont transmission line, Hemingway Substation, and the expenditures for the siting and permitting of transmission expansions for Boardman to Hemingway and the Gateway West transmission projects. For the Boardman to Hemingway transmission line we expect that the project will cost approximately $600 million and Idaho Power expects its share of the project to be between 30 and 50% to meet needs identified in the 2009 integrated resource plan and forecast growth of network customers. This project is expected to be completed in 2015 subject to siting, permitting and regulatory approval. Idaho Power Company is exploring potential joint development and ownership opportunities with PacifiCorp regarding this project. In addition the Bonneville Power Administration is investigating if participation in Boardman to Hemingway may be feasible.

The Idaho Power Company portion of the Gateway West Transmission Project is expected to be between $300 million and $500 million. Initial phases of the project could be completed by 2014. We continue to finance the capital program with a combination of internally generated funds, equity and debt. While internal cash generation after dividends is expected to provide less than the full amount of total capital requirements for 2010, IDACORP and Idaho Power expect minimal need for external financing during 2010 except for the issuances under the dividend reinvestment, employee related plans and the continuous equity program. We have access to approximately 2.1 million shares of common stock remaining under the continuous equity program.

The projected range for annual hydroelectric generation is based on 2009/2010 Snake River basin snow pack at 60% of average on February 21, 2010, with reservoir storage levels in selected federal reservoirs upstream of Brownlee at approximately 118% of average as of February 21, 2010. The effective income tax rate ranges include the utilization of up to $25 million of additional deferred investment tax credit amortization at Idaho Power. The rates do not reflect discrete events such as examination settlements or method changes.

In light of the 2009 settlement agreement with the Idaho Public Utilities Commission and the impact of the settlement on earnings over the next two years, we are initiating earnings guidance for 2010 in the range of $2.65 to $2.80 per diluted share. The guidance incorporates the benefits assumed under the settlement agreement approved by the Idaho Public Utilities Commission in January of 2010. Key elements of the settlement that relate to the guidance provided are the use of deferred investment tax credits to arrive at a 9.5% return on equity in the Idaho jurisdiction and an equal sharing of any Idaho earnings exceeding the authorized level of 10.5%. The guidance also incorporates the impact of the estimated key financial and operating metrics as presented in today's earnings press release and the Form 10-K. This concludes my financial update. Now we would like to respond to your questions.

(Operator Instructions) The first question comes from the line of [Brian Russo with Ladenburg Thalman. ]

Thank you, good afternoon.

Hi, Brian.

Given that the ROE is calculated off the year-end shareholder equity balance, could you give us a better sense of the timing or the trends of the 2.1 million shares under the DRIP and sales agency agreement.

Brian, this is Darrel As it relates to the timing of that, we don't have any specific plans as it stands right now as I mentioned earlier. Our needs are modest as we go into 2010 and we would like to be more opportunistic in issuing the shares. One reason we have the program is to allow some of that flexibility. So, right now, we don't have any specific plans or timing as it relates to when we would initiate the continuous equity program.

All right. And in terms of your guidance, how could we look at the ROE assumptions. Is the low end 9.5% ROE and high end somewhere closer to 10.5%. Maybe you could give more directions on what gets you to the mid-point.

Brian, here again, this is Darrel. One of the things around the guidance, I would share with you on that, we are looking at that first of all in light the stipulation and in light of the 9.5% that is included in the stipulation. As that is somewhat being a floor barring a lot of different things that would happen and so really, that's kind of range that is based in and around, using the 9.5% utilizing up to $25 million of ITC and so, that number, the amount of ITC most likely will be the item that is the lever on the number. If we have earnings that are greater than we are expecting, those will be modified by use of the ITC and if they are a little bit less than what we think, then those would also be modified by how much is ITC is going to be used. Best thing I can tell you is, if you look at the range and look at where we are ended up for 2009. That range is in and around the 9.5% and we will update that throughout the year based on how things develop.

Okay. Could you just talk a little bit more about the the pending PCA, adjustment and the 70, close to $75 million base rate increase you filed for early this year. How does it play out into, hydro conditions and your actual fuel costs that get set later in the year? Could that PCA assumption in base rates change?

As you know Brian, I will start and may flip it over to Ric Gale since Ric is the one that going to be working through that. We have filed for an estimate on revised, on what the number should look like. That is working its way through the process under modified procedure and so, we expect as we get ready to file for the actual PCA in April is when things will know more and exactly what the numbers will look like. I will turn it over to Ric. He can add some comments there.

Brian, this is Ric, if I could take you back to slide six, if that's possible. We could put this in a little context. The going from left to right is the progression of expected PCA benefits. And the application, how those benefits will be distributed. So not quite your question.

And first, we will go through benefits to the customers and the Company that's the first thing that happens any benefit and as we move out, you see the $75 million in the change that we hope to make to the net base power supply costs. As conditions, if conditions would deteriorate, we would move then right to left so the first thing that would disappear in the example would be that last $15 million of customer only benefits.

Then the $10 million of 5 for the Company, 5 for customer. And then we would get into the $75 million. And parallel. The $75 million was a place holder number that we used for settlement purposes and now we have an active filing and a docket on modified procedure which will come to resolution of what the $75 million actually is ahead of the PCA file.

So I guess with, the adjustments to how you forecast hydro, conditions and kind of the 95-5 sharing, do you feel that if you do fall short of the 9.5% ROE before the ADITC credits based on changes in the base rate, is that $25 million of credit enough to get you back to the 9.5% ROE?

Brian, one of the things, this is Darrel again. Remember any time we move into the 75 that ends up being a 95-5 sharing so we end up with a bottom line impact of that is a 5% impact as you move into the 75 traunch. So, in response to your question, we believe, given the range--the earnings range we have today that any decline in that, we would be able to accommodate that within the deferred ITC as we sit here today.

Thank you very much.

Thanks Brian

Your next question comes from the line of Emily Christy with RBC Capital Markets.

Good afternoon.

Hi, Emily.

Could you give me a number for the impact in the fourth quarter of the PCA structure changes. I know each quarter we have been given an update. Do you have a number for the fourth quarter?

This is Darrel. I do not have a number available on that with me today.

Okay. And could you give us an update on the transmission projects, the siting. Kind of time line, regulatory issues, that kind of thing.

You bet, Emily. Vern Porter is here with us, who heads up that side of our business and he will give you an update to where we stand on our transmission projects.

Thanks, Darrel. First I'll talk about the Boardman to Hemingway project. Right now we are finishing up tour community advisory process that we had ongoing for the last year. We had been out meeting with the public and getting their input on alternative routes.

And the team out there with the public have done their job, they've created the alternate routes early March. Early March we will be out will with them to narrow those routes down to the preferred and alternative route that we will take into the NEPA and Oregon EFSC process. So any way, we believe that we will be able to initiate those two processes there in the first part of April and begin the scoping and those processes to determine the NEPA and EFSC proposed route.

We expect if that starts in April, we expect to have a draft environmental impact statement from the BLM by the fall or actually more closer to the end of the year, and with final permits and right of way secured by 2013 when we can start construction ,which would give us a two year window for 2015 summer in service date. So things are moving along there with Boardman to Hemingway.

With Gateway West, the BLM has entered the environmental study work for the proposed and alternative routes there and we expect a draft environmental impact statement ready by this summer. Following that, there will be a public comment period and the BLM will begin work on the final environmental impact statements and they are moving along with the environmental work there.

Emily, this is Darrel again. Just a reminder-- the comments I had earlier about where we are going with the Boardman to Hemingway line and the fact that we had previously discussed the fact that we were looking for a partner on the line because we're not going to build the line ourselves and so, what we are now in the process of working with PacifiCorp. as well as Bonneville Power Administration on taking additional ownership in that line along with ourselves with our ownership range between 30 and 50%.

Okay, great. Thanks very much.

Thanks, Emily.

Next question comes from the line of Paul Ridzon with KeyBanc.

Good afternoon, how are you? When you first started your settlement discussions I think you were looking at a PCA adjustment of $160 million. If you kind of looked at the world, and to do that assessment now given the hydro conditions, where do you think that might fall?

Paul, this is Darrel. We are right in the middle of analyzing that right now as we go through our normal processes. And obviously snow pack is at 60% of average as it stands today. So, it could have an impact but we don't have a specific number but as Ric talked about earlier as you go down the chain of that and move into the different buckets of dollars, that the majority of that, regardless of where we stand today, we still sustain most of that barring really some catastrophic things that would otherwise take place that we are not forecasting today.

It seems like water would have to get pretty weak before there was any threat to not being able to hit your 9.5% ROE, is that fair?

I think, I think as it relates to impacting what we are talking about with respect to the PCA changes. I would say, water would have to be--get pretty low for us not to hit that.

And to reiterate, it sounds as though beyond the 2.1 million share continuous offering, there is no need to access the equity markets in '10?

That's correct. And I qualify there from the standpoint of we don't know what is going to take place for the rest of the year, but based on what we know today, that is true.

Thank you very much.

Thanks, Paul.

Next question comes from the line of James Bellessa with Davidson and Company.

Good morning or afternoon I guess it is. Hard to tell.

Yes.

If you stand there today and peer out into the future, would you say there is over 50% chance you will not have to draw on this ADITC?

Jim, this is Darrel. I would say-- when we went into the settlement process, we knew that in foregoing a rate, a price change, that we might need some help short of a price change. So I would say as we sit here today, we would expect that we would draw on some of the ITC and I would tell you if I was sitting here a year ago I might, if I was sitting here a year ago and under the same mechanism, I might be sitting here saying we might also be drawing on it. Wherein at the end of this year, we ended up not drawing on it. As I sit here today, I can't tell you whether it is 50/50 or 70/30 , 60 /40 but I would tell you we probably would draw on that. And as we said in the discussion, we say up to $25 million because that is what is available to us with the carry over as well as the amount in the current year; and that is the limit of the amount that is available to us. So that's why we provided that. We are working on a number of different fronts. Obviously minimize that to the extent we can. And continue to be focused on the operation side of our business. And taking a hard look at everything we are doing. So, as to minimize how much ITC we would otherwise have to amortize but it is there, it's there for a safety net of sorts and if you go back to the mid-90s when we had similar provision in place before. Knock on wood, we were in a position there where we had the same mechanism and did not have to draw on it at all. So, it is there for us to use to help manage the business during these difficult times and it was specifically set up for us as we look to bridge ourselves to 2012. That was the whole idea behind the settlement discussions in order to grant some relief to our customers at the same time we continue to focus on what it is we

You surprised me in the fourth quarter that you didn't draw on the ADITC and I asked myself why not and I see that there may have been tax benefits and a very low or maybe even a negative tax rate where you have a tax benefit. Is that a bulk of the explanation, or are there other issues that arose and that you performed so well in Idaho that you didn't have to draw on ADITC?

I think, Jim, it is combination of a number of factors. One of those, you had to settle out tax items in the fourth quarter. At the same time it was, we did see some of the impacts of the regulatory activities that had been put into place prior to the fourth quarter, some of those things had an impact and continued to manage expenses. So it is a combination of a lot of things out there that has allowed us not to have to amortize any of the ITC.

Now before you had this opportunity with the settlement, to use ADITC, you were projecting that 2009 effective tax rate for the consolidated company would be in the 19 to 24% area. All of a sudden now we are seeing that you are forecasting 2010 at only six to 10% tax rate.

Right.

Can you explain that? Why it dropped so much and is it because you do think you are going to have to draw on some of the ADITC?

It's a reflection that we will have-- we would expect to have some level of tax benefits and will reduce our effective rates, and I think what I would encourage you to do as all of you are going to dig into our 10-K, is if you take a look and read on our income tax section on or around page 38 where we are assessing and analyzing a couple of different projects on the tax side as an opportunity for us to generate, take advantage of the changes in tax methods. That could have an impact on us. We are looking at those things. Those are some things that we are continuing to look at that could have an impact so we would point you there to take a read on that. And keep you updated on those as the year plays out. Those could have an impact of reducing the effect tax rate while not using ITCs.

I thought maybe you had a guidance. Maybe I made it up. I thought perhaps you were thinking $320 million of CapEx for 2010. Now, I see the guidance is 35 to $45 million higher. Has there been a change and if there has been a change, what is incrementally put into CapEx for 2010?

Jim, I think, and I don't have, you are saying previous 2010 numbers?

Well, I don't know where I remember getting that, but I don't know that I just fabricated it.

I think last year's 10-K, we gave you a combined '10 and '11 number. And I think, maybe you 50% you can get there but in actuality our '10 number is down from what we otherwise would have been projecting as we continue to reassess our capital spending so overall it is actually down from what we otherwise would have been expecting in 2010 and when we, even for this year, we give you a '10 number plus an '11 and '12 combined we don't break the '11 and '12 years out separately. So that could be one of them, but we continue to reassess the capital spending every year and spending only what it is we have to do.

In your maintenance expense O&M expense line item guidance, does that include energy efficiency programs or is that a stand alone investment or stand alone expense line item?

Sorry, Jim, can you repeat that question?

In your O&M guidance of 295 or $305 million for 2010, does that include energy efficiency programs or are those stand alone expense items?

No, the demand side costs are separate and apart from the O&M guidance we provide. And the reason that is, Jim, we treat those as the expenses that we incur and they are offset by the revenues and so, to the extent those vary, we defer. And those are offset. One's in the revenue line and one's down the expense line. So, it's not included in the normal ongoing O&M.

Typically energy efficiency programs look like they hit their highest level of expense in the third quarter and then drop off. But the drop off in the fourth quarter this year was considerably greater percentage wise than the previous year. Is there an explanations for that, or was the third quarter exceptionally high?

Jim, one of the things we have going on with our programs as our programs have evolved is one of the big increases in our program is in our peak rewards program with our irrigation customers and that has seasonality to it. So what you see a lot of expenses occurring in the third quarter and those would obviously fall off as you go into the fourth. And they are tied closely to the irrigation customers.

Thank you very much.

But those are a big piece of some of the increases in 2009 that we expanded those programs (inaudible).

Thanks for your responses.

Thanks, Jim.

Next question comes from the line of Reza Hatefi with Decade Capital

Thank you. I noticed in your 10-K that your deferred net power supply balance is $84 million so does the $84 million, is that just cash that is going to flow into the cash flow in first half of 2010 or so? Is that the way to think about that?

I will have Lori Smith and go ahead and speak to that while I get my voice back.

You are talking about which balance?

The deferred net power supply balance, which was $84 million at the end of '09. Is that going to be cash flow that is going to come in, in the first half of 2010?

Yes, between January and May, we will have cash flow from the 2009 deferral. And cash flow from the forecast that was a combination last year. So a good portion of that will come in from a cash flow perspective.

Okay. And on the continuous equity, I guess you said 2.1 million shares left. Just to clarify, are you expecting to use all of the 2.1 million shares in 2010 or just part of it?

We don't have any specific level of activity that we are sharing today. Because again, we don't have a big need. And we believe that right now the employee plan and the dividend and reinvestment programs will provide us a fair amount-- an adequate amount and if we want to be opportunistic with the continuous equity program we will continue to assess that.

Then, also I just wanted to follow up on an earlier question. Not only are you getting the $75 million base fuel rate increase but you are able to forecast your power cost and thus your exposure to the 5% band is limited or is very small because of that as well. Correct?

That's correct

Thank you, appreciate it.

Thanks a lot.

Your next question is a follow up from Paul Ridzon with Keybanc. Please proceed.

Looking at IFS's trajectory, where do you see it going in 2010? Is that going to be de minimis going forward?

Paul, we gave you the range of the nonregs are and you saw what we did this year on a combined basis for all of the nonreg activities. We are not anticipating a lot of new investments in IDACORP Financial going forward. It is really in a maintenance mode and we don't expect them to have a significant impact as we go to '10 and '11.

How much do you typically issue out in DRIP and employee plans?

It is I think, it is somewhere between eight to $10 million.

Then, your 2010 guidance, does that make any assumptions that you do a tax change methodology from capitalizing to expending?

Our tax rate, our earnings assumption is making an assumption that we utilize up to $25 million of ITCs and so therefore, anything we might, there is a possibly that if you do one tax item for another, you may trade one for the other. In that particular case. That's one, one thing that could happen.

That would be all be at ITC. Is that correct?

We would expect, assuming that it was up and around the 9.5% it would generally off set any ITCs that would otherwise be recognized.

If you do a look back,earlier then. And looking back-- pretty far back, this could be a sizeable tax event. Is that fair? Given what we have seen in other companies?

Paul, I am going to say that is a fact and circumstances sort of thing and we are in the middle of evaluating those projects and we'll keep you guys apprised as the year goes along. Best I can tell you on that.

Thanks again.

(Operator Instructions) We will pause for just a moment. That concludes the question-and-answer session for today. We have now further questions in the queue. Mr. Keen, I will turn it back to you.

All right. Thank you all for participating on our call this afternoon. And thanks for the interest in IDACORP. Have a good day.

Thanks, everybody.

That concludes today's conference. Thank you for your participation.