Idacorp Inc (IDA) 2004 Q4 法說會逐字稿

Good day and welcome, everyone, to the Idacorp fourth quarter 2004 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 date for a period of 12 months on the Company's website at www.Idacorpinc.com.

If you need assistance at any time during the presentation (OPERATOR INSTRUCTIONS). At this time, I would like to turn the call over to the Director of Investor Relations, Mr. Lawrence Spencer. Please go ahead, Sir.

Good afternoon, everyone, and welcome to our fourth quarter earnings release conference call. We issued our earnings release before the markets opened today and expect to file our 2004 Form 10-K with the SEC on March 9th. The earnings release is now posted to our Idacorp website.

Included on our call today are Jan Packwood, Idacorp President and Chief Executive Officer, and Darrel Anderson, Idacorp Senior Vice President, Administrative Services and Chief Financial Officer. Other officers are also available to help answer your questions during the Q&A period.

Our presentation today may contain forward-looking statements; and it is important to note that our corporation's future results could differ materially from those discussed. A full discussion of factors that could cause future results to differ materially can be found in our filings with the Securities and Exchange Commission.

First on our call today is Jan Packwood.

Good afternoon. Thank you for joining us today. The results we announced earlier this morning reflect considerable improvement in both our quarterly and annual results. Average yearly earnings in 2004 increased 68 cents per share to $1.90 as the result of improved performance at Idaho Power. Idaho Power's earnings were $1.71 per share, up 27 cents from 2003. The utility contributed 37 cents per share to fourth quarter earnings, 1 cent less than last year's fourth quarter.

We also benefited from a strong year at Idacorp Financial and the extra boost provided by the sale of the L. Cortez property at midyear. That subsidiary's contribution of 35 cents per share is at an all-time high.

Ida-West Energy earned 8 cents per share, a considerable turnaround from the 13 cent loss it incurred in 2003 when we wrote off the development costs associated with the Garnet Power Project.

Finally, the favorable settlement of some outstanding legal issues that Idacorp Energy resulted in 6 cents of our annual earnings from this now inactive energy marketing subsidiary. The collective effects of continued investment at Ida Tech and IdaCom and standard holding Company activities fell within our expectations.

We accomplished a lot in 2004. We completed the first general rate case in almost a decade here in Idaho, strengthened our balance sheet through the issuance of 4 million shares of common stock. We received licenses for our mid Snake Hydro facilities and managed through the fifth consecutive year of drought. In addition our nonregulated businesses continue to achieve their strategic operational and financial milestones.

Looking forward to 2005, we are clearly focused on our regulated business. Growth is presenting us with some interesting opportunities. In 2004, we added 13,809 customers to our system. That is an annual growth rate of 3.2 percent and the greatest one year increase in our Company's history. We project similar growth in 2005 and beyond.

Over the next three years, we expect to invest 672 million in Idaho Power Company, of which 202 million is expected to be spent in 2005.

Over the next 10 years, we will build 150 miles of transmission lines and 20 new substations, just to meet the demand in the Boise area. We also need to obtain additional sources of power. This summer the Betamount (ph) power plant will provide an additional 160 MW to meet our summer peak; and we have issued a request for a proposal in January for 200 MW of wind power.

Our investment plan, of course, is subject to regulatory approval and adequate and timely rate relief will be essential. We plan to file in March for the authority to include the Bennett Mountain power plant in rate base. I also expect that 2005 will serve as a test year for a general rate case in 2006.

Drought continues to be a challenge for us. We just completed one of the driest Januarys on record and to date February has continued that trend. The February 4th snowpack level in the Snake River basin was 65 percent of average. Due to the fact that reservoirs are depleted, soil conditions are dry and the expected timing of spring runoff, the Northwest River Forecast Center is projecting a 2.6 million acre foot inflow into Brownlee Reservoir during the April through July period.

Historically, the average inflow into the Brownlee is 6.3 million acre feet during that period. Last year, the inflows were 3.2 million acre feet.

While the utility will be the main focus of our efforts, we expect our nonregulated businesses to provide a net positive contribution this year. We expect all but IdaTech to have positive earnings in 2005.

I will let Darrel Anderson, our Chief Financial Officer, give you some of the more specifics on our financial performance in 2004 and what to expect in 2005. Darrel.

Good afternoon everyone. I will touch briefly on a couple of items that impacted the fourth quarter and then spend some time on the outlook for 2005. First, I will start with the fourth quarter and the irrigation load reduction program.

In December, I/O Power was authorized to collect a total of $13.5 million in additional revenues from its Idaho retail customers, beginning June 1st, 2005. In connection with the decision we recorded a gain of $13.3 million or approximately 21 cents a share in the fourth quarter, which was made up of 11.6 million in irrigation program cost recoveries, along with 1.7 million in interest.

Roughly $200,000 in additional program interest charges will be recorded during the first five months of 2005. Also in the fourth quarter, we recorded accruals for employee and management incentives that reduced earnings approximately 14 cents a share. The timing of these amounts were a result of incentive targets not being fully achieved until the fourth quarter.

Turning to the capital structure. IdaCorp's total debt to total cap at December 2004 was 52 percent, compared with 55 percent at the end of 2003. The percentage fell partially because of our 4 million share common equity issuance completed in December. Our long-term goal is to continue to maintain a solid investment-grade rating.

The consolidated short-term debt at year end was $36 million, down from $57 million in December 2003. Idaho Power had no short-term debt at the end of 2004 or 2003.

Now I will briefly discuss our 2005 financing plans.

In late January, Idaho Power increased the size of its debt shelf registration from 55 million to 300 million. At this time, the only planned long-term debt refinancing in 2005 is the 60 million, 5.83 percent Series first mortgage bonds which mature in September.

We are also exploring the option of extending our bank lines of credit to take advantage of the current favorable market conditions.

Now I will discuss our 2005 earnings guidance. Looking forward to 2005, our strategy is clear. We are focused on managing the growth in our service territory and the related opportunities this growth brings. This requires timely rate filings and collection of new revenues in support of our investments in our utility system.

2005 will include the request for recovery of the Bennett Mountain power plant and the full year benefit of the general rate case approved in 2004, as well as expected benefits from the conclusion of the Oregon general rate case.

It also will include the expectation of continued customer growth in the service territory of between 2 to 3 percent. While we will not be providing specific earnings per share guidance for Idaho Power for 2005, we will be providing certain forecasts in operating information for the utility. The earnings estimate for the utility begins with the current allowed rate of return of 10.25 percent in the Idaho jurisdiction. Potential earnings or the product of the net equity of book value and the allowed rate of return on equity should then be adjusted to reflect water conditions, deviations in the weather, and the outcome of federal and state regulatory proceedings, regulatory lag, the impact of capital expenditures, litigation, and other factors.

For 2005, other operation and maintenance expenses are expected to be $248 million, a decrease of approximately 8 million from 2004.

Drought water conditions are expected to continue. Generation from Idaho Power's hydroelectric facilities is expected to be 5.9 million MW hours compared to 6.0 million MW hours in 2004. And normal generation of 9.2 million MW hours.

On the tax front, we estimate that the consolidated effective tax rate will range between 10 to 15 percent at Idacorp and between 35 to 40 percent at Idaho Power Company.

We believe that providing you with some of the detailed forecasted operating information today may give a better understanding of the earnings potential of Idaho Power Company. We are reaffirming our 2005 earnings per share guidance for the nonregulated businesses that include the holding company expenses to be in the range of 5 cents to 10 cents per share positive.

That now concludes our formal comments and we'd now like to respond to your questions.

(OPERATOR INSTRUCTIONS) David Dickens from Deephaven (ph).

Couple of questions. Can you run through the items in the tables where you said that following table summarizes the effect of certain items on earnings per share? Maybe we can have a little discussion on the adjustment items for the year-to-date '04 and which of those we should consider ongoing and which are more onetime in nature?

Sure, David, I will kind of walk through those. It is probably fair to say that when you look at the entire list of items that are on that list, while we won't say those are one-time one-off items, we are not estimating today those types of items occurring in 2005. So most of those items are the result of either a specific transaction, a specific regulatory settlement that -- as we stand today -- we could not predict going into 2005. What I would say is the only potential reoccurring items that really is in there today, based on what we know today, is an estimate we have included in our 2005 operating and maintenance expenses for incentives. We have estimated approximately $6 million in that $248 million for estimated incentives for what we call operating targets under the utility incentive program.

That's a pretax or after-tax?

That is a pretax number. That's part of that $248 million that we talked about earlier.

That was the biggest question I had there. And the tax liability, the reversal of the tax liability reserve. That reserve was taken in 2002?

Yes.

The 43 cents? Okay. Fair enough. The other question I had is just having to do with current rate base equity and what you are adding. I have I believe from the rate case -- I mean, Idaho you have got just a hair under $700 million of rate base equity and that was, I believe, 93 percent of the Company total. Regulatory perspective. The 93 percent I just got from testimony that didn't seem to be contested about the jurisdictional separation. Which would imply another 50 million or so in Oregon.

We're going to Rick Gale (ph) -- Rick is here with us today and let him respond to that question for you.

Dave, I don't have the exhibits in front of me but the 93 percent sounds about right.

And, lastly, you mentioned needing to -- or potentially filing another rate case in 2006. Is there any -- there is no quick treatment or AFUDC in Idaho, is there?

There's no quick treatment in Idaho.

And is Bennett Mountain kind of a unique investment in that you can file to have that put into the rate basis as a single item as a result of the last settlement? Is that the only rate base addition that you can treat that way?

This is Rick Gale again. Once before in the 1990s following the completion of a rate case, we had a production plant come in the following year and we included it as a one item, if you will, rate case. That is exactly the plan with Bennett Mountain. It is a peaking plant that will go in and be treated as a one-item case. Think of this as doing the same thing was when their production plants and I think we expect favorable treatment of that approach.

I was just backing into a question. All the other spending you are talking about at the utility needs to be dealt with in a general rate case? In terms of being able to earn on?

Most of it has to be dealt with in terms of the general rate case. There are small items that get caught up in our other mechanisms but by and large the bulk of it has to be caught up in the general rate case.

Paul Reisen (ph) from Key McDonald.

Would you quantify your estimate of the year-to-date impact on Hydro? I think it was about 17 cents at the end of the third quarter.

Paul, in our inner earnings release we did discuss the amount of net power supply costs that were not absorbed and (MULTIPLE SPEAKERS) that's about $13.4 million or around 21 cents a share.

That compares to about 37 cents a share last year or 23.4 million.

Is there a statutory timeline that the Bennett Mountain filing will have to follow?

It is our expectation that Bennett Mountain could be placed on modified procedure. And we are hoping to have rates in effect for Bennett Mountain by June 1 of this year.

You said 6 million is embedded in the 248 O&M. That's a pretax number?

That is a pretax number.

Should I be using the 30 or 35 percent or the 10 to 15 percent tax rate?

In that number I would be using the 35 to 40 number. That is expected at the utility.

James Bellessa from D. A. Davidson and Company.

Follow-up question to David Dickens' issues there. On the employee incentive and expense you said that the 2005 estimates for $6 million, if I look at your table this last year, it cost you for the full year 004 20 cents a share times a number of shares. I get $7.7 million. Why is the employee incentive expense forecast down in '05 from '04?

Right, Jim, and the other thing is that number you have is -- that is an after-tax number when you do that particular math and gross that up for taxes and that $6 million number is actually significantly less than the amount in -- that we are going to be paying out for 2004. So the estimate that we have in there for the 6 million is really what we have estimated at a -- what we estimate at target level.

So it is a little more than half, actually less than half of what that current 2004 incentive payout is going to be.

And why is it less? It is just targeted, you can exceed that amount, can you?

We can exceed it but then other things would have to happen and earnings would have to -- would grow accordingly. So the earnings would increase in order to cover that amount of incentive; but this is the estimated operating incentive that we are estimating to pay. It could come in less than that if we don't hit the operating target. These are operating targets, not earnings for related targets.

This O&M expense item that you're talking about of $248 million is decreased by 8 million from '04, while in the year you had an impairment of assets of -- at least I call it impairment of assets -- of $9.7 million. So you aren't going to have that replicated, right?

That's correct.

So really your O&M is slightly up?

If you take it after those adjustments that is correct. It is up and it is up for -- we did grant a general wage adjustment in 2000 -- at the beginning of 2005 of 3 1/2 percent. That is part of what is driving the increase in the O&M as well as expected increases in transmission expenses, related to increased purchases required because of the changing water condition.

You've indicated that you aren't going to give specific EPS guidance right now. Does this mean you will never do that or is it just unique situations?

Jim, our belief right now is that by providing you the operating information that this gives you the ability to better estimate what we can do vs. us trying to guesstimate the weather and other things but we can give you these things, and we will update you on these targets as we move throughout the year. We will give you our updated O&M estimates, we will give you our updated capital spending estimates, as well as water and other considerations in order to provide you the information with which to better estimate what we may do.

The tax rate for Idacorp. That would be the tax rate for the whole entity which would calculate EPS, right?

On a consolidated level that is the way to estimate the effective tax rate and remember rumor on our tax rate one of the reasons you were saying it's in that rate is primarily because of the impact of the Idacorp financial tax credit and the impact it has on reducing our effective rate.

Paul Patterson, Glenrock Associates.

If you could just review again, what the targets are that are driving the incentive comet?

We didn't actually talk specifically about what is driving it, but the operating program is really set up and is changed from our 2004 plan; and it really has an operating focus to it for a portion of the plan and does have earnings targets for another portion of the plan. But what we have estimated in our current O&M targets is an estimate for the operating components which are -- there is a customer satisfaction component and then there is a total O&M and capital component.

So you are assuming that you guys didn't achieve any earnings component? Is that -- do I understand that correctly?

We have -- there is a separate component, which we are calling a profit-sharing component which if we exceed certain earnings targets, then there will be a piece of that would go back to the employees; and under the employee plan, the maximum payout under the combined plans is, it would be 10 percent of an individual employees base compensation.

So what is the threshold where that starts to happen in the earnings basis?

We have not disclosed that number because -- and we are not expecting to disclose that number.

You're not disclosing it?

That's correct.

Is there any reason why you are not disclosing it or --?

The main reason is it's because we aren't giving earnings guidance. It is fairly closely aligned with what our earnings estimates are internally and so that is one of the main reasons. Primary reasons.

(OPERATOR INSTRUCTIONS) Reza Hadasee (ph) from Zimmer Lucas Partners.

You mentioned in the press release CapEx guidance of 202 million for '05 and you had about 200 million for '04. Going back to your prior guidance in the 10-Q and last year's 10-K, does that mean that '06 CapEx will be something like 240 or sorry 1-- 240 area? I guess that was something like 640 for '04, '05 and '06.

Right and what we will -- there will be information right now in that Jan talked about. We are expecting our number right now for the three-year number for '05 to '07 is 672 million.

672?

Right. That's the part of that in the '06, the '07 period is an estimate for the needs for another peaking facility as part of our additional resources that Jan referred to.

Also for cash flow purposes, would you be able to provide any guidance for deferred taxes, part of cash flow in '05. I know that in '04, deferred taxes were negative 56 million -- in '03, it was negative 56 and '04 it was about a negative 34 million. How should we look at that item?

I do not have that information here in front of us today to be able to respond that and I think some of that, the timing of that, a lot of it depends on the items that flowing to deferred taxes; and I think in our particular case when you look at current operating cash flow, we will talk about that in the 10-K that comes out on March 9th. We will have some expanded discussion about future cash flows. So I would probably be inclined to hang tight until that 10-K gets filed.

For the general rate case that you mentioned filing, that you might be filing or will be filing -- should we assume the year ending '06 test year, meaning that the '06 CapEx of let's just say, it comes out to be 240 or so. That will be part of rate basis while 200 or so from this year?

This is Rick Gale again. Right now we are anticipating using 2005 as our test year and probably file in a similar plan as last time, actually making that filing in the fall of this year and then we will process the case and hope for a rate order that would be implemented June 1 of '06.

Do you foresee filing again in a year following this filing I guess it would be like fall of '06 to try to -- or get earnings on the high CapEx you have going forward?

What we see right now is a number of smaller rate cases and kind of a rapid succession compared to what we have done in the past. It is hard get too far out there with those dominoes because, ultimately, you have to see what the result of one case is before you really know what you're going to do with the next one.

David Dickens from Deephaven.

This question is kind of a review of the ERG mechanism and how it works inside the PCA. I understand that when you look at the difference between the projected power cost and your actual power cost it is adjusted for the growth component. My understanding is that this sets up a situation where your new customers pay a blended or average rate for the power they use but the PCA recovery is adjusted for their usage at a marginal or incremental rate that is significantly higher than the funded rate that they are paying. It effectively sets up a regulatory lag for power supply for your growth. Am I A., understanding that correctly? And B., can you give us an idea of how much under recovery that new customer growth sets up inside your PCA mechanism?

I will attempt to do that. We reset all the values, all the power cost values at the time of the general rate case including the load to be used for the Idaho jurisdiction and essentially what the PCA does from there, it measures the variation. And as you probably are already aware, the difference is our 90 percent whether it's benefit or cost picked up by the customer and 10 percent by the Company.

The load adjustment that you alluded to tries to take into consideration the fact that we are setting up these costs based upon a load for a test year and as soon as we move off that test year the load changes. It takes that adjusted value, which I think is close to about $17 per MW hour. And applies it, whether the load is up or down is an attempt to reconcile back to that test year base.

I thought 17 was the old number and the new number coming out of the rate case was higher than that.

I'm glad you asked that. It was a controversial issue in the case. And when we had those two-part settlements in September, what we agreed to do is continue on with that same value.

Can you give us an idea from a dollar perspective of how much under recovery that growth component puts into the PCA? Because you are adjusting down the figure that you applied the 90 percent recovery to and it seems to make sense to me that you've got -- one number is kind of your blended customer rate, and the other is -- the marginal in it is higher. Is that material to earnings? Does it -- is that going to keep you from being able to, all other things being equal, get up to the allowed rate of return?

I think all I can do is describe that aspect maybe a little more clearly; and maybe Darrel and others can weigh in on whether it is material.

The issue in the rate case, as we are trying to figure out the offset was, what value do you offset by? And the Company's view was that we would offset by an embedded value. And the staff's view was that we would offset by a marginal value, which is considerably different. The 17, really, has no economic bearings anymore. At the time we initiated the PCA, it was a blend of two of our thermal plants which in those days was really kind of a proxy for our marginal resource. Now, not very close.

David just another point, not specifically to that question, but to recognize what did happen in this last rate case; and it is the kind of the amount of the item jurisdiction that is now covered by the PCA has actually increased so the variability around the PCA has shrunk somewhat in that we now absorb somewhere in the neighborhood of around 15 percent or so, which is less than what it was prior to this last rate case.

(OPERATOR INSTRUCTIONS) John Hanson from Imperium.

Just a couple of questions. You mentioned in your '05 guidance discussion the Oregon general rate case. What -- refresh me on that in terms of how much we have for that carrying over here in '05?

The filing in Oregon was for 4.4 million as I remember and around an average increase of 17 percent in change.

And the status of that case is?

We, on Monday, initiated the scheduled settlement conferences with staff and other parties and we are in the middle of that settlement discussions as we speak.

On the PCA, the balance of PCA at the end of the year here in '04 vs. '03. Is it fairly similar? Are those numbers fairly similar?

One second and we will get that number for you. Just a second. If you have another part of that question, we will get that for you.

That's all I have (MULTIPLE SPEAKERS).

Hang tight 1 second. Just have to dig out so we don't give you a bad number. Right now as it sits at the end of '04, the current balance is about -- is 59.5 million down from 71.9 million at the end of '03 and the components of that are, include, approximately $8.4 million of amounts to be collected under the last year's PCA. And then we have an approximately $22.8 million of deferrals; and then we also have the 13.3 million in lost revenues to be collected. And there is about 12 million in there for Oregon deferrals.

Paul Reisen from Key McDonald.

Did you say that the 248 O&M does not include earnings-related compensation targets?

That's correct because the way it is set up is in order to earn the earnings related incentive earnings will increase commensurate with that piece. And so it is kind of an iterative process. So if we exceed those targets we will have earned it and that is why -- so it's not included in there today. So we would have to exceed targets that we had set for ourselves.

I think the last time you spoke, you suggested something like a 17 or 18 percent consolidated tax rate. Now you're saying 10 to 15. I'm just wondering what's driving that down?

Right now it's really estimated credits and the total combined amount of earnings is where that, what drives those numbers.

Is the Hydro forecast a big part of that?

Hydro has a AA component of that as does the credits that we recognize.

James Bellessa from D. A. Davidson and Company.

It may be premature to think much about the tax rate for 2006; but if you had to guess, would it be higher than the 10 to 15 percent that you are suggesting for 2005?

I think part of that obviously is predicated on what happens with water. What happens with the rate cases that we have talked about and the impacts there. Which I'll have what we would hope is potential increases to earnings which, obviously, over time would drive that rate up. So we would hope that that rate is moving up in '06.

Talking about the loss revenue case, I think I heard there was 200,000 yet to be recorded in the first five months of 2005. Is that a charge? Or is that a benefit?

That's a benefit.

And where does that come in? What line item or --?

That will be in other income.

Reza Hadasee from Zimmer Lucas Partners.

Is there a specific target or policy regarding the Idaho Power dividends to the parents?

We, basically, the policy is that we would dividends dollars up from Idaho Power sufficient to that we would believe to cover the Idacorp dividends.

Are you still -- is it fair to assume for IDA financial earnings somewhere in the low 20 cent, low 20s, 20 cent range ongoing I guess?

We have given -- we've given you the range on the non-regulated businesses as we had indicated in our call today, also, that they had hit a record high earnings for them. We don't expect that to repeat at the levels of 2004. So, on an ongoing basis, I think that we expect something less than where they're at in 2004.

That does conclude the question-and-answer session for today as we have no further questions in the queue. Mr. Spencer, I would like to turn the conference back over to you.

I'd like to thank everyone for your interest in Idacorp and our fourth quarter earnings. And, again, we expect to file our Form 10-K with the SEC on March 9th, and we will post that document to the website. Goodbye.

Thanks everybody, appreciate it.

That does conclude today's conference.