Exhibit 99
Event Name: Fourth Quarter 2008 IDACORP, Inc. Earnings Conference Call
Event Date: February 20, 2009
Presentation
Operator: Good day, and welcome, everyone, to the IDACORP fourth quarter 2008 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 will turn the call over to Director of Investor Relations, Mr. Lawrence Spencer. Please go ahead, sir.
Lawrence Spencer: Thank you, Jeanetta, and good afternoon everyone. Welcome to our February 19th fourth quarter and year-end 2008 earnings release conference call. We issued our earnings release before the markets opened today, and that document is now posted to our IDACORP website at www.idacorpinc.com. We plan to file the Form 10-K with the SEC on February 26th, and that document will also be posted to our IDACORP website. On the call today, we have LaMont Keen, IDACORP and Idaho Power President and CEO and Darrel Anderson, IDACORP and Idaho Power Senior Vice President of Administrative Services and CFO. We also have other officers available to help answer your questions during the Q-and-A period.
Before turning the presentation over to LaMont, I’ll cover a few details with you. First, our presentation today may contain forward-looking statements, and it is important to note that the Corporation’s future results could differ materially from those discussed. A full discussion of the factors that could cause future results to differ materially can be found in our filings with the Securities and Exchange Commission. Now I’ll briefly discuss the financial results from today’s earnings press release. IDACORP’s 2008 net income was $98.4 million, $16.1 million more than last year. IDACORP earnings increased by $0.31 per diluted share year-over-year, to $2.17 per diluted share. IDACORP’s fourth quarter net income was $7.4 million or $0.16 per diluted share compared with $10.3 million or $0.23 per diluted share in 2007. I’ll now turn the presentation over to LaMont.
LaMont Keen: Thanks, Larry, and greetings to our call participants. We thank you for your interest in IDACORP. It goes without saying that the world is a dramatically different place than it was even a few months ago when we had our third quarter conference call. Despite the challenges of 2008, our Company managed through the issues and delivered improved annual results. We have rigorously pursued lowering operating costs and recovering investment dollars while still maintaining our low-cost position and high customer satisfaction marks.
The results of our hydroelectric operations, while not not ideal, were still an improvement. Our service area experienced near normal temperatures and better water conditions in 2008 than in 2007. This meant better hydroelectric generation year-over-year, improving Idaho Power’s operating results. However, while the hydroelectric generation for 2008 was up over 2007’s poor water year, it was still below normal. As we look forward, we see the 2009 water year taking shape. Snowpack is about 70 percent [sic] of normal, and reservoir levels are approximately 10 percent above normal for this time of year.
On the regulatory front, we have recently received several important orders. On January 9, 2009, the Idaho Public Utilities Commission approved a modification of our power cost adjustment mechanism. This positive order will help reduce the impact deviations in water conditions will have on our financial results going forward. We were disappointed with the Idaho PUC’s decision on January 30, 2009, regarding our 2008 generate rate case filing. Today, our Company filed with the IPUC a petition for reconsideration and/or clarification of this general rate case order. The filing addresses four key issues related to either test year revenue or expense levels that aggregate approximately $8 million on an Idaho jurisdictional basis annually. The largest components of the filing deal with reconciling the calculations used to determine the revenue requirement with the intent of the language used in the commission order. An 8-K further describing our filing will be released in the next day or two.
Also in January 2009, we received an unexpected decision relating to our open access transmission tariff. The order basically deprives us from recovering a portion of our wholesale transmission cost of service. We believe the decision is inconsistent with FERC precedent, and have filed a request for rehearing with the FERC. An otherwise healthy fourth quarter was negatively impacted by this FERC decision that results in a refund to our transmission service customers, and by an impairment charge for a decline in the market value of equity securities. The decline in market value of securities relates to investments set aside to help meet future obligations relating to a non-qualified benefit plan. The investment set-aside, although not required, was a proactive decision made to help offset future funding needs. These are very long-term investments, and it is unfortunate that recent market changes to their value impact current earnings.
In terms of customer growth, we see a continued slowing trend. The year finished with 5,514 new customer connections, significantly fewer than previous years. And although consumption was relatively flat in 2008 compared to 2007, we experienced a new winter peak on January 24, 2008, of 2,464 megawatts and a new summer peak on June 30, 2008, of 3,214 megawatts. To meet these growing customer demands, we’re in the process of preparing a new integrated resource plan that will be filed with the Idaho and Oregon utility commissions later this year. The IRP is effectively the game plan for meeting anticipated customer needs for the next 20 years. A key part of our energy plan for the future is responsible energy usage, and it is manifested in the many energy efficiency programs we offer. We currently have 15 energy efficiency or demand management programs, with six more slated to launch this year. Every kilowatt we save is one we do not have to generate, reducing the number of additional new resources required and the necessity to purchase power on the open market.
As we look forward in 2009, climate change legislation could have a significant impact on the utility industry. IDACORP is dedicated to a healthy planet, and our core business, Idaho Power, is relatively well-positioned with our hydro operations, which provide more than 50 percent of our generation capacity under normal water conditions and a balanced resource portfolio. We understand, however, there will be challenges associated with the various climate change bills currently on the table.
In closing, our solid 2008 financial performance, given the events of the year, is a mark of sound fiscal regulatory and operational strategy. We also remain focused on effectively managing our costs, assessing operations for additional efficiencies and obtaining needed regulatory relief. We remain committed to share owners, customers and employees to remain financially healthy and to successfully navigate whatever challenges 2009 has in store for us and the nation. I will now turn it over to Darrel Anderson, who will update you on our financial results.
Darrel Anderson: Thank you, LaMont, and good afternoon everyone. I will review some of the 2008 earnings drivers, current liquidity and financing activities, and then provide an update on the 2009 key operating and financial metrics. We will then take your questions.
Larry already provided a brief review of our fourth quarter and annual financial results, so I will not repeat them. However, I do want to comment on some of the activity that occurred in the fourth quarter. Financial results for the fourth quarter were impacted by a few significant items. The first was the decision by the FERC on January 15 of this year, that directed us to reduce our transmission service rates to our FERC jurisdictional customers retroactive to June 2006. This resulted in an additional reserve of $7.9 million, including $700,000 in interest which we recorded in the fourth quarter. As LaMont mentioned, the second was an impairment charge of $6.8 million on equity securities which were determined to have other than a temporary decline in value. The investments are a broadly diversified group of exchange-traded index funds that are maintained by a trustee that were negatively impacted by a poor fourth quarter stock market performance. Thirdly, operating results for the quarter were enhanced by the recognition of $2.8 million of tax benefits related to the settlement of our 2001 to 2005 tax years.
Now I’d like to turn your attention to the full-year results. Nearly 96 percent of our 2008 earnings came from our regulated utility business unit, Idaho Power, compared to 93 percent last year. In 2008, general business revenues increased $116 million, 27 percent from the increase in retail base rates, and 71 percent from the increase in PCA rates. A 1.6 percent growth in customers also contributed to the increase in general business revenues, partially offset by reduced usage from weather-related factors. Improved hydroelectric operating conditions decreased net power supply costs, which are fuel and purchased power less off-system sales, by $9.7 million, with hydroelectric generation increasing nearly 12 percent or 727,000-megawatt hours over 2007. From 2007 to 2008, other operation and maintenance expenses increased $7.5 million or 2.6 percent, in part due to increases in payroll-related expenses of $10.6 million, purchased services of $2.4 million, water lease costs of $2.2 million, injury and damages costs of $2.1 million, and increases in uncollectible accounts of $1.8 million. These increases were partially offset by a decrease of $5.8 million from the fixed cost adjustment mechanism, lower outage costs at the thermal plant of $3.6 million and a reduction in third-party transmission costs of $3.1 million.
Other revenue was down $1.8 million year-over-year. The decrease is due to an addition to the provision for rate refund related to the FERC open access transmission tariff decision that I just recently discussed, offset by increases in [wheeling] and energy efficiency revenues. Overall, Idaho Power’s operating income decreased from $154.8 million to $189.4 million, an increase of $34.6 million year-over-year. Interest charges at IDACORP were up $9.7 million over 2007, largely due to higher long-term debt balances.
Now turning the discussion to liquidity, cash flow from operations increased from $80.6 million in 2007 to $136.5 million in 2008. The increase is primarily attributable to increased net income and the increase in the collection of previously deferred power supply costs. Idaho Power collected approximately $66 million more through the PCA in 2008 than in 2007. The increase in net income and the collection of previously deferred power supply costs were partially offset by an increase in income tax payments of $17 million in 2008 compared to 2007. Cash used for investing activities decreased by $64.3 million in 2008 as Idaho Power’s expenditures for utility plants was $43.7 million less than 2007. The decline in spending reflects the continued slowdown in new customer connections and the deferral of certain capital expenditures.
In May 2008, we withdrew $20 million from the $44.9 million of refundable income tax deposit that was made with the Internal Revenue Service in 2006. Approximately $21 million of the deposit has been applied to settle our 2001 to 2004 IRS examinations, including interest charges. Investing activities in 2008 also include the $5.7 million proceeds from the sale of the southern portion of the Southwest Intertie Project rights-of- way, $8.3 million of additional investments at IDACORP Financial and $3 million in investments in Bridger Coal Company.
Commercial paper outstanding at December 31, 2008 was $13.4 million for IDACORP and $109 million for Idaho Power. In addition, IDACORP had $25 million of floating rate advances outstanding under its credit facility. The advance was repaid on January 9, 2009 with proceeds from the issuance of commercial paper. Current revolving credit facilities at IDACORP and Idaho Power are $100 million and $300 million, respectively, with $61.6 million available at IDACORP and $166.8 million available at Idaho Power at December 31, 2008. These facilities expire in April 2012. In July, Idaho Power issued $120 million of 10-year first mortgage bonds at a rate of 6.025 percent, with proceeds used to pay down short-term debt balances. Also during 2008, IDACORP issued $50.9 million of common stock of which $42 million, or 1.5 million shares, were issued under the continuous equity program. Overall, IDACORP’s net cash needs from financing activities decreased $117.4 million.
I will now update you on the key operating and financial metrics for 2009. These are also shown in the earnings release issued earlier today. The estimated 2009 Idaho Power operation and maintenance expense range is between $280 million and $290 million, down from $294 million spent in 2008. In light of what is expected to be a prolonged economic downturn, our Management Team is working diligently on reducing operating expenses of the business, while serving approximately 487,000 customers on a 24-by-seven basis, and maintaining reliability and safety standards. We started this process in early 2008, and continue to look at areas where we can reduce, eliminate or defer expenses by challenging every operating aspect of our business.
Cost management efforts start at the top, and for this reason we did not increase 2009 base salaries for our senior managers and officers. In addition, we have had workforce reduction in the form of the elimination of contract crews that we employ as well as not filling positions vacated by attrition. At the end of December we were down approximately 100 full-time-equivalents for contract crews and an additional 73 internal positions from our 2008 staffing estimates. The management team also eliminated planned capital expenditures related to anticipated growth as well as deferred non-critical projects. As a result, our current range of capital expenditures at Idaho Power of $220 million to $230 million represents reductions from amounts included in previous estimates as we continue to review our spending requirements. For the three-year period 2009 to 2011, Idaho Power expects to spend approximately $780 million to $800 million on capital projects. This amount includes expenditures for the siting and permitting of major transmission expansions for the Boardman to Hemingway, Gateway West, Hemingway Station and the Hemingway Hubbard transmission facilities. These amounts exclude costs for a base load energy resource.
Subject to board approval, Idaho Power will seek approval from the Idaho Public Utility Commission relating to a base load resource recommendation during the first quarter of 2009. A decision from the IPUC would be expected later this year. Based on our current liquidity estimates, we expect to finance the capital program with a combination of internally-generated resources, new equity and debt. Excluding the base load energy resource decision, we expect financing needs to be less than 2008 levels. If we need to issue equity in 2009, we have access to our continuous equity program, with approximately 2.6 million shares of common stock available. Our target is to maintain our current capital structure at Idaho Power, which was 46.4 percent equity and 53.6 percent debt at December 31, 2008, with the debt component including both short- and long-term debt.
The projected range for annual hydroelectric generation is between 6.5 million and 8.5 million megawatt hours. The projected range is based on a 2008 to 2009 Snake River Basin snowpack at 70 percent [sic] of average on February 17, with reservoir levels approximately 10 percent above normal.
The decrease in the non-regulated and holding Company results from prior years is a result of expected declines in contributions from IDACORP Financial Services because of lower tax benefits from aging investments.
And finally, the effective tax rate range for Idaho Power is 31 percent to 35 percent, and for IDACORP 24 percent to 28 percent. Additional information will be available next week when we file our Form 10-K. This concludes our financial update, and we’d now like to respond to your questions.
Q&A
Operator: Thank you. Ladies and gentlemen, we will now begin the Question-and-Answer session. (Operator Instructions). Your first question comes from the line of Reza Hatefi.
Reza Hatefi: Thank you very much. Do you have the number, the impact to earnings in 2008 because of the below-average hydro versus normal?
Darrel Anderson: Reza, this is Darrel. We don’t have that number available today as it relates to normal. We do know that obviously the improved results from -- over 2008 versus 2007.
Reza Hatefi: But you would say, though, that in ‘08 there was a negative effect because of below-average hydro, right?
Darrel Anderson: That’s correct.
Reza Hatefi: Okay. And could you talk about the hydro impact going forward? I mean it seems like with the rate case settlement, that with the ability to forecast hydro conditions and changing the sharing to 95/5, your exposure to hydro should be pretty minimal going forward. Am I understanding it correctly?
Darrel Anderson: Yes. I’ll start and if we go into some more detail, I may flip it to some other folks. But a couple things. I think it’s a great question first of all, because one of the things that we do believe a very successful regulatory activity was the changes in our PCA methodology where we first of all, changed the sharing from 90/10 to 95/5 for Idaho. That’s number one. Number two, the changes around the forecast methodology, we think is a really big plus from a standpoint of cash flow perspective. And where now we rely on our internal forecast versus relying on a different methodology that was more based on a regression formula. So those two pieces are I think -- we believe are very good benefits in trying to manage the risks around the hydro system.
Reza Hatefi: It sounds like the earnings impact from -- or the earnings volatility from below-average hydro or even above-average hydro should be sort of minimal, I guess, going forward.
Darrel Anderson: We do expect that. That is one of the outputs of it going from 90/10 to 95/5. And also changing, I think, the forecast methodology.
Reza Hatefi: And then a question on LGAR. Do you expect to see an improvement in ‘09 versus 2008 in reference to LGAR? Because I guess the LGAR rate’s a little bit lower now. And also, my understanding is that the normalized load associated with the LGAR calculation is now higher? Is that correct?
Darrel Anderson: Yes, Reza, Lori Smith is going to respond to that.
Lori Smith: Hi Reza. Yes, we would expect that to be a reduced impact in 2009 just for the reasons that you just stated. The 2008 rate case will give us a new normalized load that we’ll measure against. And so we’ll be even more current than we were for the full year in 2008.
Reza Hatefi: Do you have any rough estimate as to what the improvement -- improvement could be? Or what was the impact in ‘08 from LGAR?
Lori Smith: Like Darrel just said, we don’t provide the individual details on the PCA impacts, and LGAR is one of those impacts in the PCA mechanism.
Reza Hatefi: And just lastly, you mentioned, I guess, filing a -- re-addressing the results of the rate case that just concluded. Are you also looking to file another case spring/summer for -- that could go effective in early 2010? A full rate case, that is?
Darrel Anderson: Ric Gale is going to respond to that.
Ric Gale: Hi Reza. We have an obligation in our Oregon jurisdiction to file a case this year. So the team is putting together a test year. We will file in Oregon. We’ll let some things play out in Idaho and then assess what’s optimal in the state of Idaho. But we are actively preparing a test year.
Reza Hatefi: Thank you very much.
Ric Gale: Thank you.
Operator: Your next question comes from the line of Brian Russo.
Brian Russo: Good afternoon.
Darrel Anderson: Hi, Brian.
Brian Russo: Just to be clear on -- are you preparing to file an upcoming Idaho rate case, but you want to see how things play out maybe on the reopening of the recently finalized case?
Ric Gale: Brian, this is Ric again. Just to reiterate, we will prepare a test year regardless. We will file in Oregon regardless, because that’s a requirement. So we’ll have everything prepared. It gives us the option of seeing how this request for reconsideration plays out and some other possible regulatory actions. So we’ll be able -- we won’t lose any time, but we’ll be able to evaluate everything, make the right choice for rate recovery.
Brian Russo: Is there any timeline on the request for reconsideration?
Ric Gale: There are multiple steps. So let me refer to my notes, and I’ll try to get these accurately. And also, it’s on the record as far as rules of practices and procedure. It starts off with once you get the order, there’s 21 days to file a request for reconsideration, which we’ve done on the 20th day. The final day would have been tomorrow. That opens a seven-day window for others to cross-petition. Then the next step is, from our filing there is a period of time when the commission needs to decide whether or not it will grant the reconsideration, make a determination, not on the merits on whether they’re going to consider it or not. And that’s 21 -- or excuse me, 28 days. Then that opens a 13-week period to establish the record, and that record might be based upon hearings or it might be based upon briefs. But they have 13 weeks to submit the case, build the record. And then it finishes. After that’s finished, they have another 21 -- or 28 days to issue the order.
Brian Russo: Okay. So if you filed today and you’ve got 28 days for the IPC to decide, that brings you to the end of March. And then 13 weeks, or say three months, brings you to the end of June. And then 28 days after that is sometime, I guess, late July we possibly might have a decision on that reconsideration?
Ric Gale: That would be the maximum amount of time, and I would agree with your assessment of the timeline.
Brian Russo: And if you get the decision by then and choose to file for a full-blown general rate case, there’s enough time to get new rates effective in early 2010?
Ric Gale: Well, we’ll be able to track some of the progress as we go. Our typical rate filing would have a June rate filing. That’s what we did last time. We filed in June. We had rates in place first of February.
Brian Russo: Okay. And the IPUC recently directed Idaho Power to install automated meters, and it seems like they granted your request for acceleration on depreciation from existing meters. But it does not include accelerated depreciation or O&M benefits for new meters. And I’m wondering if that would all play into your decision to file a general rate case.
Ric Gale: That is one regulatory action among many. That could be handled through a one-off case, could be incorporated in a general case. But we’ve set the stage, if you read that docket, to handle it as a one-off rate recovery item.
Brian Russo: Okay. And then just back on the impact of below-hydro versus normal in 2008. It looks like you generated 6.9 million-megawatt hours?
Darrel Anderson: Right.
Brian Russo: What’s normal?
Darrel Anderson: About 8.5.
Brian Russo: Okay. So that difference, do we just simply multiply it by some average mid-C power price and say -- I don’t know -- the third quarter of ‘08 to get kind of a rough guesstimate as to -- and then compare that to what’s embedded in the PCA to get a better sense of what that under-recovery or fuel impact would be?
Darrel Anderson: Brian, there’s a lot of factors that go into estimating that item. And first of all, the 6.9 and the 8.5 are annual numbers so that generation happens throughout the year. And when we have higher generation, that generally happens earlier in the year. So to -- and so there’s a lot of assumptions built into there. A market price is also a consideration as you had indicated. So a lot -- I could say yes to everything that you’ve said, but I think there’s just a lot of assumptions on the timing when the generation comes off. So I’m not sure how to -- I know what you’re trying to do is understand the impact between normal and what we did this year. But that would be one way to get a ballpark range of it, but again, your market prices would be a big component of that.
Brian Russo: Okay. And what’s remaining on the deferred energy balance, and how and when do you think you might collect that?
Darrel Anderson: Brian, what I’m going to do, if you could wait a week for the 10-K on that, that would be great because that’s something we haven’t disclosed. But it will be -- that will be something obviously that will be in the 10-K next week.
Brian Russo: Okay. And then the remaining shares in your continuous equity program. Can we assume that that ‘s -- dribbles into the market in ‘09, or multiple years going forward?
Darrel Anderson: Brian, that’s really going to be a factor of what we determine our equity needs to be and it’s going to be predicated on ultimately how much capital we ultimately spend this year. We’re going to do obviously everything we can to manage what that total equity issuance has to be in light of what we spend. So we’re going to be kind of focused on our cap structure, keeping that somewhat balanced from where we are today. And also recognizing kind of -- being opportunistic in the market. If the market were to open up, we would take a look at it then. But right now I can’t say what that schedule looks like today.
Brian Russo: Would you say with what’s remaining on the continuous equity program combined with external debt, that that’s kind of enough to support the capital expenditures outside of any major breaking ground on these large transmission projects? And then the base load project?
Darrel Anderson: Yeah, one of the comments I made in my prepared remarks was the fact that we would expect to see financing less than what we did in 2008. And so if you look at that in the context of, we issued $50 million in total equity in total during 2008, we would expect that number going into 2009 to be less than that. And we’re going to work -- given the fact our capital spend projections are less as we sit here today, combining all those things we’re really looking to minimize the amount of financing that we have to do, subject to a major capital project or expansion. And right now, 2009, we don’t see that right now for -- 2009 is really focused on siting and permitting on the transmission side of things. That’s the main area of emphasis.
Brian Russo: Can you break down the three-year CapEx program by year and maybe talk about what’s kind of maintenance or ongoing? And then what the other permitting or siting costs are for the development projects?
Darrel Anderson: Brian, again, and I hate to do this to you, but we have that very well laid out in our 10-K that will be filed next week. And so that will give you a great view of what that looks like. Anyway, I’m going to leave it at that there. We don’t want to have to then all of a sudden go out and issue multiple additional information. So it will be in the 10-K very well laid out by project on the major transmission projects.
Brian Russo: All right. And just one last question, if you don’t mind. Are any of these projects contingent on legislation that’s being proposed, regarding more timely recovery of costs and kind of a pre-endorsement of these large-scale projects by the commission?
LaMont Keen: This is LaMont. I’ll take a shot at that. As we sit with the capital markets at the state they are today, and if we proceed with larger projects, the size of those capital expenditures vis-a-vis the size of our company, we are going to look for some kind of a strengthen certificate from the Idaho commission in order to launch those projects. And I think you mentioned the two likely forms. One would be either some kind of prior approval, which is a piece of legislation that’s being considered by the Idaho legislature currently, or approval of construction work in progress and the rate base which the Idaho commission already has the ability to do if they have the desire to do so. So we would expect before we would launch one of those major projects, we would try to get some assurance and like one of those two forms before we proceeded.
Brian Russo: And just remind me when the legislature ends.
LaMont Keen: Well, that’s a $64 question right now because of what the stimulus or potential availability of stimulus funds, it’s taken some pressure off the budgeting process in the state of Idaho potentially. So I think they have a target date of March 19 that the governor arbitrarily set at some point. But whether or not they make that remains to be seen.
Brian Russo: Okay. Thank you very much.
Darrel Anderson: Thanks, Brian.
Operator: Your next question comes from the line of Paul Ridzon.
Paul Ridzon: I’m just looking for more clarity. I’m sorry, I’m on my cell phone and didn’t really get catch a lot of it. But equity financing beyond the continuous offering, is that contingent upon what happens in transmission in ‘09? And what’s the ‘10 outlook?
Darrel Anderson: I think, Paul, this is Darrel again. I think the equity financing going into 2009 will be -- continue to be focused on trying to keep the cap structure balanced where we are today. We have cut back our capital spend in 2009. As we said, depending on what happens with our base load resource requirement, which we don’t expect to see any major decisions on that out of the PUC until later this year, that it really says that the bulk of that capital will be looking to be spent more in ‘10 and ‘11. But there again, subject to siting and permitting and the challenges that we have there, will dictate somewhat when we start seeing the acceleration in some of the spend on the major transmission projects. So again when -- I’ll point you in the direction of our 10-K to get filed next week which will lay out what at least we believe is the capital requirements for ‘10 and ‘11 on those transmission projects. But right now the main emphasis is on the permitting and siting.
Paul Ridzon: I guess I’ll stay tuned for the 10-K. Thank you.
Darrel Anderson: Okay. Thanks, Paul.
Operator: Your next question comes from the line of James Bellessa.
James Bellessa: Good afternoon.
Darrel Anderson: Hi, Jim.
James Bellessa: During the formal presentation I was hearing about the snowpack, and you were citing I thought 70 percent. And I think you were using your own statistics. Was it 70 percent that I was hearing, because in the footnote here it says 77 percent?
Darrel Anderson: Yes, I think, Jim, I think you are correct. I think the number that we put out in the earnings release was 77 percent, and I believe that is the correct number.
Lawrence Spencer: Yes, Jim, this is Larry. That was as of February 17, that number.
James Bellessa: And has it dropped to 70 percent today?
Darrel Anderson: No. No, I think we had a bad number in there, Jim, based on the February 17 information.
James Bellessa: So it is 77 percent?
Darrel Anderson: Correct. That’s right.
James Bellessa: And then on that same page, you have a footnote about base load resource activity, where you’re going to go to the commission and ask for approval. And you’ve indicated there’s an extended period of time before you get approval. But you’re getting approval for a number of items, but you’re saying you exclude the cost for the base load energy resource itself. So why would you get approval for a base load resource, but exclude it?
Darrel Anderson: Jim, this is Darrel. Just -- first of all, we are evaluating proposals at this point in time, may or may not be the building of a resource. It could be another form of what the -- a project, the resource, could look like. So when we file with the commission after the board makes its decision, then that will then take the form of whether it’s a hard resource or it’s something else. So that’s why I guess we’re saying it excludes it at this point because it may or may not be a hard asset. It could be tolling agreement or something on those lines.
James Bellessa: Do you have a per-share figure for the FERC impact on you, the decision to have a refund? Is there a per-share figure that you were -- used internally?
Darrel Anderson: For the adjustment we made, Jim, or for in total? Because there’s a couple of different numbers. What we put in the release, obviously we talk about $4.8 million after tax. So if you want to do the number of shares, you’re going to get around $0.08 or $0.09.
James Bellessa: And that was -- it says in the press release footnote, revenues. But you’re saying it’s an after-tax impact, the $4.8 million?
Darrel Anderson: Well, what we’re saying, Jim, is we have to reduce our revenues. We have to provide a provision for rate refund back to our customer. So it is -- on an after-tax basis it’s the $4.8 million.
James Bellessa: And how about the impacts of these -- impairment of the equity securities, the settlement of prior years’ tax returns that you used a per share figure on any of those?
Darrel Anderson: No, Jim,what I would -- in our earnings release, the numbers in our reconciliation in the earnings release we use in this particular case, we have the impairment of securities on an after-tax basis of about $4.2 million. So here again, you do the math on the shares. I mean you can do it as well as I can.
James Bellessa: So that is an after-tax figure Thank you for pointing that out.
Darrel Anderson: Yes. It’s about $0.09.
James Bellessa: Okay. Thank you very much for your help.
Darrel Anderson: Okay. Thanks, Jim.
Operator: That concludes the question-and-answer session for today. We have no further questions in queue. Mr. Keen, I will turn the call back over to you.
LaMont Keen: All right. We’d like to thank you all for your interest in IDACORP, and as Darrel mentioned, we will have the release of the 10-K in a week that will provide you further detailed information that we weren’t able to provide today. So thanks again and have a nice evening.
Operator: That concludes today’s conference. Thank you for your participation.
