Lawrence Spencer – Director, Investor Relations
LaMont Keen – President, Chief Executive Officer
Darrel Anderson – Senior V.P. Administrative Services, Chief Financial Officer
Lori Smith – V.P. Corporate Planning, Chief Risk Officer
Ric Gale – V.P. Regulatory Affairs
Paul Ridzon - KeyBanc Capital Markets – KeyBanc Capital Markets
James Bellessa - D.A. Davidson – D.A. Davidson
IDACORP Incorporated (IDA) Q4 2008 Earnings Call February 19, 2009 4:30 PM ET
Welcome to the IDACORP fourth quarter 2009 conference call. (Operator Instructions) At this time I will turn the call over to Director of Investor Relations, Mr. Lawrence Spencer.
Good afternoon everyone. Welcome to our February 19, fourth quarter and year end 2008 earnings release conference call. We issued our earning 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 26, and that document will also be posted to our IDACORP website.
On the call today, we have Lamont Keen, IDACORP and Idaho Power's 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&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 to 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.
Greeting 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 hydro electric operations while 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 hydro electric generation year over year, improving Idaho Power's operating results.
However, while the hydro electric 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. Snow pack is about 70% of normal and reservoir levels are approximately 10% 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 of 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 general rate case filing. Today, our company filed with the IPUC a petition for a 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 on January 2009 we received an unexpected decision relating to our open access transmission tariff. The order basically deprives us of recovering a portion of our wholesale transmission cost of service. We believe the decision is inconsistent with precedent and have filed a request for re-hearing.
Another otherwise healthy fourth quarter was negatively impacted by this Firth 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 are 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 has 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 the hydro operations which provide more than 50% 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 was 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 shareowners, customers and employees to remain financially healthy and 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.
Good afternoon everyone. I will review some of the 2008 earnings drivers, currently liquidity and financing activities and then provide an update on the 2009 key operating and financial metrics. We will then take your questions.
Larry has already provided a brief review of our fourth quarter and annual 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 Firth on January 15 of this year that directed us to reduce our transmission service rates to our 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 of 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 for 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% of our 2008 earnings came from our regulated utility business unit, Idaho Power compared to 93% last year. In 2008 general business revenues increased $116 million, 27% from the increase in retail base rates and 71% from the increase in PCA rates.
A 1.6% growth in customers also contributed to the increase in general business revenues, partially offset by a reduced usage of weather related factors. Improved hydro electric operating conditions decreased net power supply costs which are fuel and purchased power, less off system sales, by $9.7 million with hydro electric generation increasing nearly 12% or 727,000 megawatt hours over 2007.
From 2007 to 2008, other operation and maintenance expenses increased $7.5 million or 2.6% in part due to increases in payroll related expenses of $10.6 million, purchase services of $2.4 million, water lease costs of $2.2 million, injury and damages costs of $2.1 million and increased of uncollectible accounts of $1.8 million.
These increased were partially offset by a decrease of $5.8 million from the fixed cost adjustment mechanism, lower outage costs at the thermal plants 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 the rate refund related to the Firth open active transmission tariff decision that I just recently discussed, offset by increases in wheeling and energy efficiency revenues.
Overall Idaho'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 were $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 examination including interest charges.
Investing activity in 2008 also include the $5.7 million proceeds from the sale of the southern portion of the southwest Innertide project rights-of-way, $8.3 million of additional investment 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 of 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 ten year first mortgage bonds at a rate of 6.025% 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 were issued under the continuous equity program. Overall, IDACORP net cash needs for 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 earning 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 in2008. 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 24X7 basis and retaining 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 pay salaries for our senior managers and officers.
In addition, we have had work force 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 does not include the expenditures for the sighting and fomenting of major transmission expansions for the Boardman to Hemmingway, Gateway West, Hemmingway Station and the Hemmingway Hubbard transmission facilities.
These amounts exclude costs for base load energy resources. 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. The decision from the IPC 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% equity and 53.6% debt at December 31, 2008 with the debt component including both short and long term debt.
The projected range for annual hydro electric generation is between 6.5 million and 8.5 million megawatts hours. The projected range is based on 2008 to 2009 Snake River Basin snow pack at 70% of average on February 17 with reservoir levels approximately 10% above normal.
The decrease in the non regulated and holding company results from prior years is a result of expected decline 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% to 35% and for IDACORP, 24% to 28%. 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.
(Operator Instructions) Your first question comes from [Refa Hitaffi]
Do you have the number, the impact to earnings in 2008 because of the below average hydro versus normal?
We don't have that number available today as it relates to normal. We do know that we had improved results over 2008 versus 2007
But you would say though that in '08 there was a negative affect because of below average hydro, right?
Could you talk about the hydro impact going forward? 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?
I'll start and if we need to go into more detail we'll get some other folks, but a couple of things, one of the things that we do believe, a very successful regulatory activity was the changes in our PC 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 cash flow perspective and 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 we believe are very good benefits in trying to manage the risks around the hydro system.
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 going forward.
We do expect that. That is one of the outputs of going from 90/10 to 95/5. And, also changing the forecast methodology.
A question on Algar, do you expect to see an improvement in '09 versus 2008 in reference to Algar because I guess the Algar rates are a little bit lower now and also my understanding is that the normalized load associated with Algar calculations is now higher. Is that correct?
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 new normalized load that will measure against, and so we'll be even more current than we were in the full year of 2008.
Do you have any rough estimate as to what the improvement could be or what was the impact in '09 of Algar?
Like Darrel just said, we don't provide the individual details on the PCA impact and Algar is one of those impact in the PCA mechanism.
You mentioned filing, readdressing the results of the rate case that just concluded. Are you also looking to file another case in spring/summer that could go effective in 2010? A full rate case that is?
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 ion Oregon. We'll let some things play out in Idaho and then assess what's optimal in the State of Idaho. We are actively preparing a test year.
Your next question comes from Brian Russo.
Just to be clear, are you preparing to file an upcoming Idaho rate case or do you want to see how things play out maybe on the opening of the recently finalized case?
Just to reiterate, we will prepare a test year regardless. We will file in Oregon regardless because that's a requirement. 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. We won't lose any time but we'll be able to evaluate everything and make the right choice for rate recovery.
Is there any time line on the request for reconsideration?
There are multiple steps, so let me refer to my notes and I'll try to get these accurately. 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.
The next step is from our filing there is a period of time when the commission needs to decide whether it will grant the reconsideration and make a determination; not on the merits but whether they're going to consider it or not. And that's 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 a record. And then after that's finished, they have another 28 days to issue the order.
So if you file today you've got 28 days for 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 might possibly have a decision on that reconsideration?
That would be the maximum amount of time, and I would agree with your assessment of your time line.
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?
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 year. We filed in June. We had rate to place first of February.
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 benefits for new meters, and I'm wondering if that would all play into your decision to file a general rate case.
That is one regulatory action among many. That could be handled through a one off case. It could be incorporated in a general case, but we set the stage, if you read that docket to handle it as a one off rate recovery item.
Back on the impact of below hydro versus normal in 2008, it looks like you generated 6.9 million megawatt hours?
About 8.5 million.
So that difference, do we simply multiply it by some average mid C power price and say, the third quarter of '08 to get kind of a rough guestimate as to, and compare that to what's embedded into the PCA to get a better sense of what that under recovery or fuel impact would be?
There's a lot of factors that go into estimating that item and first of all, the 6.9 and 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 there's a lot of assumptions built into the variance. Market price is also a consideration as you indicated. I could say yes to everything that you said, but I think there's a lot of assumptions on the timing when the generation comes off.
I know you're trying to understand what the impact between normal and what we did this year, but that would be one way to get a ball park range of it. But again, your market price would be a big component of that.
What's remaining on the deferred energy balance and how and when do you think you might collect that?
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 that we haven't disclosed but that's something that obviously will be in the 10-K next week.
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?
That's really going to be a factor of what we determine our equity needs to be and it's going to be predicated ultimately on 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 of where we are today, and also recognizing being opportunistic in the market if the market were to open up, then we would take a look at it them. I can't tell you what that schedule looks like today.
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?
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. So if you look at that in the context of we issued $59.00 in total equity in total during 2008 we would expect that number going into 2009 to be less than that, and given the fact that our capital spend projections are less as we sit here today, combining all those things, we're really looking to minimize financing it.
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 siteing and permitting on the transmission side of things. That's the main area of emphasis.
Can you break down the three year CapEx program by year and maybe talk about what's kind of maintenance or ongoing and then the other permitting or siteing costs are for the development project?
I hate to say it but we have that very well laid out in our 10-K that will filed next week and that will give you a great view of what that looks like. I'll kind of leave it at that. We don't want to have to then go out and issue multiple additional information. It will be in the 10-K very laid out by project on the major transmission projects.
Are any of these projects contingent on legislation that's being proposed regarding more timely recovery of costs and kind of pre-endorsement of these large scale projects by the commission?
As we sit with the capital markets at the state they are today and if we proceed with 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 strengthened 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 a rate base which the Idaho Commission already has the ability to do if they have the desire to do. So we would expect before we would launch one of those major projects, we would try to get some assurance like one of those two forms before we proceeded.
And just remind me when the legislature ends?
That's the $64.00 question right now because of the stimulus or the 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. Whether or not they make that remains to be seen.
Your next question comes from Paul Ridzon - KeyBanc Capital Markets.
Paul Ridzon - KeyBanc Capital Markets
I'm just looking for more clarity. Equity financing beyond the continuous offering, is that hinged upon what happens at transmission in '09 and what's the '10 outlook?
I think the equity financing going into 2009 will continue to be focused on trying to keep the cap structure balanced where we are today. We have cut back our capital spend in2009. As we said, depending on what happens with our base 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 siteing and permitting and the challenges that we have there, will dictate some of when you start seeing acceleration in some of the spend on the major transmission projects. Again, I point you in the direction of our 10-K that gets filed next week which will lay out at least what 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 siteing.
Your next question comes from James Bellessa - D.A. Davidson.
James Bellessa - D.A. Davidson
During the formal presentation I was hearing about the smoke pack and you were citing I thought 70% and I think you were using your own statistics. Was it 70% I was hearing because it was in the footnote here it says 77%.
I think you are correct. I think the number that we put out in the earnings release is 77%, and I believe that is the correct number.
That was as of February 17 that number.
James Bellessa - D.A. Davidson
Has it dropped to 70% today?
No, I think we had a bad number in there based on the February 17 information.
James Bellessa - D.A. Davidson
So it is 77%.
James Bellessa - D.A. Davidson
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 an extended period of time before you get approval, but you're getting approval for a number of items. You say you exclude the comps for the base load energy resource itself. So why would you get approval for a base load resource but exclude it?
First of all, we are evaluating proposals at this point in time. It may or may not be the building of a resource. It could be another form of what 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 its something else.
So that's why we're saying it excludes it at this point because it may or may not be a hard asset. It could be a tolling agreement or something along those lines.
James Bellessa - D.A. Davidson
Do you have a per share figure for the work impact on you, the decision to have a refund? Is there a per share figure that you used internally?
For the adjustment we made or for total? 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 - D.A. Davidson
It says in the press release footnote revenues, but you're saying it's an after tax impact, the $4.8 million.
What we're saying is we have to reduce our revenues, we have to provide a provision for rate refunds back to our customer, so it is on an after tax basis, it is $4.8 million.
James Bellessa - D.A. Davidson
And how about the impacts of these impairment of the equities, securities, the settlement of prior years, the tax returns that you used? Can you share a figure on any of those?
In our earnings release, the numbers in our reconciliation in the earnings release we used in this particular case, we had impairment securities on an after tax basis is about $4.2 million. So there again, you do the math on the shares.
There are no further questions. Mr. Keen, I will turn the call back over to you.
I would 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.
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