Idacorp Inc (IDA) 2008 Q1 法說會逐字稿

Good day and welcome, everyone, to the IDACORP First Quarter 2008 Earnings Release Conference. As a reminder, 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'd like to turn the conference over to the Director of Investor Relations, Mr. Lawrence Spencer. Please go ahead, sir.

Thank you, Sarah, and good afternoon, everyone. Welcome to our May 8th First Quarter Earnings Release Conference Call.

We issued our earnings release before the markets opened today and that document is now posted to our corporate website. We also filed a Form 10-Q with the SEC today and that document has also been posted to our IDACORP website.

On our 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 here today 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 I'll briefly discuss the financial results from today's earnings press release.

IDACORP's first quarter 2008 net income was $21.7 million, $2.9 million less than last year's first quarter. Idaho Power's first quarter 2008 net income was $21.3 million, $2 million less than the first quarter 2007.

IDACORP earnings decreased by $0.08 per diluted share to $0.48 per diluted share quarter-over-quarter.

With that, I'll turn the presentation over to LaMont.

Thank you, Larry, and good afternoon, everyone. Thanks for taking time to call and participate in this discussion about out first quarter results. We thank you for your interest in IDACORP and Idaho Power.

Let me start by reviewing some of our regulatory activities. As a result of the settlement in February of our most recent general rate case, we implemented new rates in Idaho that increase the amount of annual revenue we collect by an average of 5.2%, or $32 million. The increase went into effect on March 1, so we are seeing only one month's collections on this quarterly earnings report.

Also, as part of the settlement, the Idaho Public Utilities Commission agreed to make a good faith effort to resolve the issues we have with the load growth adjustment rate, which is part of the power cost adjustment. The load growth adjustment rates subtracts the marginal energy cost of serving new Idaho customers from costs we are allowed to include in the PCA. The effect is that it reduces cost recovery. The Commission agreed to conduct workshops on this issue.

Our regulatory strategy is to make frequent and timely filings in an effort to recover our investments as quickly as possible. So far this year, we have filed a number of actions. I'd like to speak to them briefly.

On March 7, we applied in Idaho for authority to raise rates 1.4% to recover $60 million in construction costs for our new 170-megawatt Danskin natural gas-fired power plant near Mountain Home. The increase would produce an estimated $9 million in additional revenue per year. The new plant was built by Siemens and is available and ready for use to meet peak summer loads. We have requested that new Idaho retail rates become effective June 1.

We also filed a request to increase the monthly energy efficiency rider to 2.5%, an increase of approximately $7 million. This funds the programs that help us reduce the amount of power we have to buy or generate. Last year, our energy efficiency programs saved 91.2 million kilowatt hours, enough to serve more than 7,200 homes for one year.

We have also filed our first rate adjustment under the fixed cost adjustment pilot program, or decoupling program, and this was a $2.4 million rate reduction. The fixed cost adjustment encourages investment in energy efficiency programs and activities. It authorizes us to separate recovery of fixed costs from the actual sale of electricity.

On April 15, we filed this year's power cost adjustment. Our initial application called for an adjustment to increase rates by approximately $87 million. Last year's hot temperatures brought record-setting demand to our service area. That demand, combined with low stream flows, drove our power supply costs up considerably. At about the same time we filed the PCA, the Idaho Public Utilities Commission issued an order to enables us to mitigate some of these costs with $16 million in gains from the sale of excess sulfur dioxide emission allowances. So the $87 million adjustment has been reduced to about $71 million.

As part of our annual Idaho PCA filing, we requested that, on a prospective basis, 100% of the costs and benefits be flowed through to customers. As we have proposed it, the change would take place on April 1, 2008 and would impact this year's forecast component and its ultimate true-up next spring. The true-up component for last year would remain shared on a 90% customer and 10% company basis.

On March 28, 2008, we filed with the Idaho Public Utilities Commission notice of intent to file a general rate case on or after June 1, 2008. This notice provides a 60-day window for the company to make its filing. However, it does not bind the company into taking such action.

On April 28, the Oregon Public Utility Commission approved our file stipulation that established a power cost adjustment mechanism, or PCAM, for our Oregon jurisdiction. This concludes a multi-year effort to better recover power supply costs from our Oregon retail customers. Still pending is the first rate implementation of the PCAM, which could result in a $4.8 million annual rate change, and that's 15.7% on average, beginning on June 1, 2008.

We have also issued a request for proposals to acquire 250 to 600 megawatts of firm energy by June 1, 2012. Responses are due early in the fourth quarter and must identify a resource within our control area. The new resource is needed in order to meet growing loads within our service territory.

All of these activities impact customers. We have launched a public outreach program in an effort to educate and inform our customers and public officials about the challenges we face together. The intent is to help them understand why these investments are necessary and why we must seek timely recovery of the costs.

Customer growth declined in the first quarter. We connected 872 new customers, down from 2,038 in the first quarter of 2007. We attribute some of this to winter weather influences on construction activity, but a slowing economy and volatility in the capital markets no doubt also are having an influence. Our 2006 Integrated Resource Plan calls for sustained growth of 2% annually over the next 20 years. We plan to file a refreshed 2006 IRP with the Idaho and Oregon Commissions in the second quarter.

Turning to water conditions -- our current water conditions. We experienced reduced hydroelectric generation in the first quarter due to carryover impacts of last year's drought, cold temperatures that kept the snow on the mountains and below normal precipitation in the valleys. While there is still a significant snow pack in the mountains, it is uncertain how much runoff will reach the river system because of continued dry conditions. The Northwest River Forecasting Center is projecting April through July streamflows into Brownlee Reservoir this year of 4.9 million acre feet. That's down from their earlier estimates and the long-term average of 6.3 million acre feet.

Reflecting on the first quarter's reduced flows and our expectation of lower summer and fall streamflows, we have reduced our hydrogeneration operating metric for the year. We now believe that our annual hydroelectric generation will likely fall in the range of 6.0 to 8.0 million megawatt hours this year. Actual flows will be impacted by how and when the winter snow pack comes off the mountains, as well as by precipitation levels and temperatures during the balance of the year.

And with that, I'll yield to our Chief Financial Officer, Darrel Anderson.

Thanks, LaMont, and good afternoon.

Today I will review some of the key points related to our first quarter 2008 results, discuss updates to the 2008 key operating and financial metrics and review our 2008 financing plan. We will then take your questions.

I'll begin with our recent results. Larry previously summarized our quarterly results, so I'll jump right into Idaho Power. At Idaho Power, first quarter 2008 general business revenues increased by $30 million, or 22% when compared to 2007. Changes in Idaho base and PCA rates from last year accounted for $20 million of the increase. Growth in customers and higher electricity usage due to weather-related factors accounted for $2 million and $8 million of the increase, respectively.

While these positive influences increased general business revenues, quarterly operating income at Idaho Power declined. Hydroelectric production levels were approximately 10% lower than during the first quarter of 2007 due to reduced precipitation and stream flows. This increased our reliance on more expensive thermal generation and drove up current power cost adjustment deferrals by almost $16 million.

The load growth adjustment rate reduced earnings by approximately $3.2 million compared to first quarter 2007. The impact was greatest in January and February because the base loads and the rates were reset on March 1 as part of the general rate case going into effect.

Total system load in the first quarter 2008 was 289,000 megawatt hours over the base loads established under the load growth adjustment.

The load growth adjustment rate was increased in April 2007 from $16.84 per megawatt hour to $29.41 per megawatt hour. Effective March 1, 2008, it was increased again to $62.79, although it applied to only half the load change.

The net effect is an increase in this component of the PCA deferral. Resetting of the base loads to 2007 levels from 2005 levels should moderate the impact of load growth. A workshop on the mechanism expected later this year will give us the opportunity to further address the load growth-related issues.

Other operation and maintenance expenses in 2008 increased 1%, or approximately $1.1 million year over year. This was due to higher overhead line expenses and payroll-related expenses offset by decreased operating expenses at our fleet of thermal plants.

Idaho Power Company earnings were negatively impacted by $1.6 million due to underperformance at Bridger Coal Company related to difficulties with underground longwall mining operations in January and February 2008. Beginning in March, the mine has resumed normal operations.

Interest charges increased $2.3 million over 2007, due primarily to a $3.5 million increase in interest on long-term debt related to increases in debt balances and the impact of higher variable interest rates on our pollution control bonds. This increase was offset by a half a million dollar reduction in non-utility interest and a $400,000 change in the allowance for funds used during construction.

Turning our discussion to liquidity, cash flow from operations was relatively flat quarter over quarter. Cash from operations was $21 million in each period. Operating cash in each period was reduced by increases in net power supply expenses that had been deferred for further recovery.

Increases in our investments and property, plant and equipment at Idaho Power increased cash used for investing. This was in line with our expectations.

IDACORP's short-term borrowings during the first quarter increased $57 million over 2007 levels. Proceeds have funded increases in our deferred power supply expenses and our ongoing capital expenditure program at Idaho Power.

I will now update you on the key operating and financial metrics for 2008. These are also shown in today's earnings release that we released earlier in the day.

We have not changed our outlook for operation and maintenance expenses, non-regulated earnings contributions or estimated effective tax rates. We have lowered our estimated range of capital expenditures, now projecting an investment range of $270 to $290 million. The lower range is due mostly to the expected impacts of a decline in the number of new customer connections and the deferral of certain other capital expenditures, none of which impacts reliability or safety.

We anticipate financing the capital program with a combination of internally-generated resources, equity or equity-like securities and debt. We have access to our continuous equity program with approximately 1.1 million shares of common stock available under this program.

Our long-term goal is to maintain a capital structure that is roughly 50% equity and 50% debt.

Earlier, LaMont addressed the changes in our expected hydroelectric generation, which, during a normal year, is 8.5 million megawatt hours. For 2008, our anticipated hydroelectric generation is between 6 and 8 million megawatt hours.

That concludes our prepared remarks and we would now like to respond to your questions.

Thank you. (OPERATOR INSTRUCTIONS). We'll take our first question today from Lasan Johong at RBC Capital Markets.

Sorry. Good afternoon.

Good afternoon.

Wanted to ask a couple very basic questions. How much more in cost do you think you will incur to make up for the lack of hydro this year?

Lasan, this is Darrel. We have an ongoing hedging program that we constantly monitor the status of our resources and demands, and so we have an ongoing program that allows us to do that. And so as conditions change, we hedge going forward. We will -- generally do not talk about kind of what we're looking at on a forward look as it relates to what those forecasted prices and expected costs will be, but we have -- we do hedge on an ongoing basis the resource requirements.

Which liquid (inaudible) do you guys look at mostly?

We generally look -- Mid-C is where we transact most of the business, but we also look to do transactions at our border.

Where was the first location?

Mid-C. Mid-Columbia.

Okay. Oh, I see. In terms of the load growth adjustment mechanism, you said the state was still conducting a study? I thought the $62 and change -- I thought that was going to be the last step. Am I incorrect about that?

What we did in our rate case settlement -- one of the steps in the rate case settlement was that we would agree to look at the load growth adjustment in a separate workshop setting, and that has yet to be scheduled, but we expect to see that some time later this year.

Any idea of what the outcome might look like?

I don't think we know. I think we know what the issues are and I think we have to get everybody in the room and talk about the impacts of what growth is having.

Okay. And could you kind of go over what happened at the Bridger Coal Company?

No, I'm going to have Jim Miller, who heads up our power supply group --. He's here today with us and he's intimately familiar with what happens -- what goes on over at Bridger, so I'll have him chat with you about that.

Thank you.

This is Jim Miller. Late December, we got into an area along the longwall that had substantial moisture in it. You got into a situation that we call a soft floor, where the longwall sheared, got mired in mud. By the time we got in there, shored it up and dug through that wet spot, it was almost two months. So it was late February, early March by the time we dug through the water area and got back into full production. This resulted in less coal being mined out of Bridger for two months, and the quality of the coal was down a little bit. So financial performance for Bridger Coal Company and IERCO was down.

I gotcha. That makes sense. You said that you're going to be filing for a rate increase by June -- or after June 1 and then you've got a 60-day window horizon. Is that correct?

That's correct. We filed a notice which then allows us up to -- by June 1 would be the earliest we could file it, and then we have basically 60 days from that point.

And this is going to be based on an '07 test year or how is this going to work?

I'm going to have Ric Gale, who heads up regulatory side of things -- have him talk to you about that filing process and talk about the forecasted test year.

Sure. You might recall one of the other settlement provisions in the last general rate case was to go through a workshop on a forecasted test year. We conducted that workshop and we're preparing the next case on a 2008 basis, along the lines of agreements on methods or approaches to that test year that were developed in that workshop.

Right. Right. Yes, I remember that now. In terms of your financing needs, can you kind of break out how much debt and equity you're going to be looking at this year, or give us a rough estimate?

We will -- we won't speak specifically to it, other than to say that we will be looking at both combinations of debt and equity as we look to the balance of the year to fund not only the current capital, but some of the short-term balances that have been built up to date. So we will be looking at some of those financings, with the continued goal to look at staying in and around that 50/50 level.

Okay. So if we kind of model things out on a 50/50 basis, we should be safe.

Yes. In and around that range. That would -- that's pretty close.

Okay.

It moves around a little bit between periods, but that's our target.

Okay. And medium to longer-term, any concept or idea of what -- or how you're going to mitigate the load growth relative to kind of your static hydro profile? In other words, very little opportunity to increase your hydrogeneration capabilities, but load growth of 2% a year kind of quickly catches up to you over time. How do you try to mitigate the load growth (inaudible) you -- are you looking to build more plants? Where and kind of what types and -- or are you going to rely more on purchase power?

We have a fairly extensive planning process. Part of that is our integrated resource planning process that most recently filed --

Right.

2006, and as LaMont mentioned, we are looking to update that integrated resource plan later this summer that will provide updated information based on what we know, and so what our focus is, is to keep a balance between loads and resources the best that we can in anticipation of what growth is going to be taking place, but also planning for the future, which is one of the reasons, obviously, we have the 250-megawatt plan out there that Jim has got out that the RFP that could go up as high as 600 megawatts. And so it's an ongoing process that we look at in keeping loads and resources balanced.

I'm assuming hydro -- new hydro is out of the question. Correct?

The only part of our resource plan that talks about new hydro is expansion at existing facilities, and it's pretty minor. There's not a lot of opportunities and I doubt we'd be able to build new large hydro anywhere along the Snake River, at least. But following up on what Darrel had said, if you look at our resource plan, there's a pretty broad mix of new resources that includes natural gas and wind, geothermal, substantial amounts of energy efficiency, combined heat and power, additional (inaudible) resources. There's a pretty broad mix, plus some purchases from the outside. So there's a pretty broad mix of new resources that we add over the next 20-year planning horizon.

Okay. And this 250-megawatt RFP -- are you guys going to keep it open-ended -- a mix of coal, gas, [renewables], or are you specifically talking fuel?

It is unspecified in the RFP, but we did say it needs to be located close to our load center here in the Treasure Valley.

So you avoid transmission.

Right. Our self-build -- we'll be proposing a self-build natural gas-fired combined cycle combustion turbine that'll be located somewhere in the Treasure Valley as a reference plant, if you will.

That's in addition to the Danskin plant?

Yes.

How big would that be?

Again, it'll be competing in that 250-megawatt RFP. It'll be --

Oh, oh, I see. So that's a reference plant --

Correct.

For somebody to come in and say, "Okay. I can do better than that."

Exactly.

I see. Gotcha. Gee, that'll do it for me. Thank you.

Thank you. Thanks a lot.

Next we'll hear from James Bellessa, D.A. Davidson & Co.

Good afternoon.

Hi, Jim.

On the window of opportunity to file rate case, has that opened -- that 60-day window started or is that still a month away?

It basically starts June 1.

Starts June 1.

Right.

Okay. So let's say you file on July 1, would you be putting in a 2008 test year -- did I hear? Or would it be one-half of 2007 and one-half of 2008?

Jim, this is Ric. We are planning to file a 2008 -- full 2008 -- rate case. That's what we're looking at, at this point.

And the moisture in the valleys, you say, is sub-par. What's the outlook for the farmers? What's the outlook for the weather? And what's the likelihood that they might have to increase their irrigation take -- or irrigation load?

Usually don't like -- this is Jim -- usually don't like to comment on the weather forecast, but right now, we're expecting a hot, dry summer. That's what we're hearing from the weather forecasters. Typically, it's dry anyway, so I don't that it'll increase irrigation loads a lot, but it could be more. But you'll have to just wait and see. We don't know how the runoff is going to come, whether it'll come off all at once. If it comes off slowly, it might get soaked into the ground. If it gets wet at all, of course, that'll help. But right now, we're expecting a hot, dry summer.

And Jim, this is Darrel. Just to add to that, one of the swing months for us is May and June, and those are months that are tough to predict from a weather perspective. And so I think that the best thing there is to kind of -- whatever weather forecast you believe in, watch that one and that will help you determine kind of what impacts we will have. And that's what we keep an eye on. But those are -- May and June are fairly critical. July and August are generally dry here anyway. It's May and June that are kind of some wild cards for us.

We're in the 8th of May. Has it rained since the first of May?

In some spots. We've had some thunderstorms, a few that have rolled through, but --.

And you've indicated in your press release that you're thinking that the rate case that went into effect on March 1 will help the rest of the year. Are any of these other items that you've (inaudible) mentioned on our regulatory front likely to help this year?

Jim, I think we would think that, if we walk through what -- the list that LaMont walked through, obviously under the assumption that we can begin recovery of the Danskin plant on June 1. Obviously, that -- there's a benefit there. Obviously, the PCA recovery is good for cash flow consideration. Obviously, the increase in the energy efficiency rider is a good thing for the organization, at least in the recovery of costs, and in order to continue to invest into efficiency programs. And so looking at those, I don't -- we would expect all those, at least from a cash flow perspective and also from a return perspective related to the Danskin facility.

If it's hot in the summer and your hydro conditions are only roughly 90% of thermal, what's that mean to your results?

Jim, that kind of debt really does depend on what -- where we're at from a resource perspective and whether -- if it's beyond what we're currently planning for -- if it goes beyond what we're planning for and it's subject to what the market conditions are at the time. And so today, we do certain hedging opportunities based on what we think it's going to look like with our operating plan, and so we believe we take that into account in our hedging program, and so it's really tough to predict what's going to happen. But we make our best estimate along our planning parameters.

Jim, this is Lamont. The one thing that is obvious is when we don't have hydro, we have to replace it with something more expensive. So as it goes down, we have to increase purchases or generation at other facilities that have a fuel cost associated with. So you have to say the general effect of not having hydro is negative. Most of that is passed through the PCA to customers. Part of it is kept by the company.

Thanks very much.

Jim, I was going to add that we start hedging the system 18 months in advance, so we started buying energy for this summer (inaudible) 18 months ago.

So that's when it was cheap. Or was it?

Better than it is today.

Okay. Very good. Thanks.

Thanks, Jim.

Next we'll hear from Neil Kalton from Wachovia.

Good afternoon.

Hi, Neil.

Just a question on the new Oregon adjustment mechanism, which I think is being implemented on June 1. Can you give us -- will that have an impact to your earnings relative to the last year or two, and if so, can you give us sort of a sense of what kind of impact that might have?

Neil, this is Ric. The -- what we just had approved was the method, and that was just within the last week. So we have the Commission approval of the method and we have filed our first rate adjustment. And our first rate adjustment is about $4.8 million on an annual basis toward the Oregon retail customers. We have filed that case in conformance with that method, but we haven't gone through the process of having an Oregon staff weigh in on that conformance or not. But assuming that we have filed it appropriately, you could expect a June 1 rate increase of 15.7% and almost $5 million for the Oregon customers starting June 1. Now that is a catch-up on our power supply costs in Oregon. There's some other things we need to catch up on Oregon once we get this done.

Okay. Thank you.

Thanks, Neil.

Next we'll hear from Steven Gambuzza, Longbow Capital.

Good afternoon. Just a quick question on the Bridger Coal issue. That's in rate base, right? All those costs are kind of part of your revenue requirement? Is that a fair statement?

Yes they are.

Okay. So obviously, your actual (inaudible) what was embodied in rates this quarter, but going forward, we should still think about it as a regulated operation.

That's correct.

Okay. Thanks very much.

(OPERATOR INSTRUCTIONS). Next we'll hear from Edward Heyn, Catapult.

Good afternoon.

Good afternoon.

Just had a quick question on how your -- the forward test year you talked about works in regards to capital structure. You mentioned that you needed a -- you potentially need a mix of debt and equity over the year to fund your capital expenditures. How does that work with regard to the test year? Is that a known and measurable that needs to be in place before the June 1 filing, or is that something that you could accomplish later in the year and still put that in pro forma?

This is Ric again. We will have an internal witness speak to a forecasted cap structure and support it, but that's my assumption as we talk today. But there will be a witness (inaudible) to support that caps structure in relation to 2008.

Okay. And this is the first -- this is just to clarify. This is the first time that you've been using this forward test year?

No, it's not. We actually did it last time. We proposed a forecast test year last time. It became a major issue in the case and you might recall we had two new commissioners last year, so ultimately, that became a factor in our decision to settle the case and then retry the forecast in 2008.

Okay. Great. Thanks for the clarification.

Thank you.

Next we'll hear from Adar Zingo, Zimmer Lucas Partners.

Hi, guys.

Hi, Adar.

Can you talk a little bit about your capital commitments to IFS going forward and your outlook for that business? Should we expect to continue to see earnings decline over time or do you plan on pursuing additional investments in order to generate the tax credits?

Right. Adar, this is Darrel. One of the things we do provide, at least in the shorter term, is that we look to give you some nonregulated guidance which does include IDACORP Financial as well as Ida-West and holdings companies. So we do attempt to kind of capture what we believe in the current year the estimate for those -- what those earnings are going to be. As it relates to IDACORP Financial specifically going forward, we continue to look at what our (inaudible) is as an organization and, with the investments now that we are making at Idaho Power Company, it does -- and what comes with that is additional depreciation and other things -- it reduces really the -- an amount of opportunities that we have at IDACORP financial at this time. So we are monitoring that business and we will continue to look at it going forward, but we don't have any major new investments planned for IDACORP Financial.

Alright. Thank you.

(OPERATOR INSTRUCTIONS). And we have no further questions left in our queue at this time. Mr. Spencer, I will turn the conference back over to you for any additional or closing comments.

Thank you, Sarah, and thanks, everyone, for participating in today's call.

Before closing, I'd like to remind you that both our earnings release and our Form 10-Q are posted on our IDACORP website. I also want to remind everyone that the 2008 Annual Shareowners' Meeting will be held next Thursday, May 15, starting at 10:00 a.m. Mountain time, noon Eastern time, and will be webcast live. For more details, go to www.idacorpinc.com. This now concludes our call. Thank you.

Once again, this does conclude today's conference. We appreciate your participation. You may now disconnect at this time.