Avista Corp (AVA) 2004 Q3 法說會逐字稿

Good day ladies and gentleman. Welcome to your third quarter Avista Corporation conference call, you are in conference call.

[Operator Instructions].

I would like now like to turn the presentation over to our host for today, Mr. Jason Lang, Investor Relations Manager. Please proceed, sir.

Good morning everyone and welcome to Avista's third quarter 2004 earning conference call and web cast. Avista's earnings were released pre-market this morning and the release is available on our web site.

With me today in our offices in Spokane, Washington, are Avista Corp Chairman of the board, President, and CEO Gary Ely; Senior Vice President, CFO, and Treasurer, Malyn Malquist; the President of Avista Utilities, Scott Morris; Dennis Vermillion, President of Avista Energy, and Vice President and Controller, Christy Burmeister-Smith.

As we begin this morning's conference call, I will caution you that during today's conversation we will be making forward-looking statements that involve risks and uncertainties, which are subject to change.

I would direct you to Avista's 2003 Form 10-K and the company's quarterly report on Form 10-Q for the quarter ended June 30, 2004, which are filed with the SEC and are also available on our web site for reference to the various factors, which could cause actual results differ materially from those contemplated, to the extent these facts are not discussed on this call. We are using some slides as part of today's presentation. These are available on Avista web site in the investor section.

To follow along with the webcast, simply click the forward arrow to advance the slide. The slides also may be downloaded and printed at your convenience. Now I will turn this presentation over to Avista's Chairman of the Board, Gary Ely.

Thanks Jason and good morning everyone. I'll start this morning's report by telling you that we had mixed results this quarter, which were primarily dominated by the disallowances of past costs, ordered by the Idaho Public Utilities Commission in our general rate case.

Although we were disappointed in some portions of the commission's order, the order also provides important revenue increases that will improve financial results going forward. We intend to seek reconsideration on certain portions of that order, and Scott Morris will have more for you on that in a few minutes.

We're also disappointed in the performance in the energy marketing and resource management business segment this quarter including the impairment charge taken on a general rating asset owned by Avista Power. You'll hear more about that from Malyn Malquist.

On a positive note, excluding the Idaho disallowances, Avista Utilities had a good third quarter primarily as a result of the hot weather in late July and most of August. We're moving forward with the projects we told you about last quarter.

The sale of our California Natural Gas distribution properties is on track and our purchase of the Mirant's 50% share of Coyote Springs 2 generating facility is moving forward as well. Avista Advantage marked a milestone by posting its first positive earnings quarter.

The company is continuing to meet its internal goals and to work towards positive earnings on a consistent basis.

I want to take this opportunity to tell you that our search for a new CEO at Avista Advantage is still in progress. In the meantime, I want to keep the momentum going, so I've asked Scott Morris to oversee the Advantage business line in addition to carrying out his responsibilities as President of Avista Utilities. And with that, I'll turn this call over to Scott for his report. Scott?

Thanks Gary and good morning everyone. As Gary noted earlier, we were disappointed in certain portions of the recent IPUC order in our Idaho general rate case. The final order requires Avista to record write-offs totaling $14.7 million. The disallowances are related to prior deferred costs associated with natural gas contracts entered into to provide fuel for thermal generating facilities, as well as certain capitalized utility plant costs from the rate base.

These natural gas contracts originated during the energy crisis of 2000 and 2001, and we believe they were reasonable given the circumstances at the time. We plan to seek reconsideration on some of the issues in the order. In testimony filed in July, we revised our total electric and natural gas revenue increase request from $40 million to $35.2 million. The final IPUC order provided for a combined electric and natural gas increase of $28 million.

Slide number two provides a breakdown of our revised request, the authorized rates of return, and other information. The order includes an increase in base electric rates of 16.9%, which is designed to increase annual revenues by $24.7 million.

The rate impact on customers is largely offset by a reduction in the power cost adjustment surcharge, so our customers will see a net increase of only 1.9%. The IPUC authorized a 6.4% increase in natural gas rates, which is designed to increase annual natural gas revenues by $3.3 million.

In spite of the disallowances, the order provides important increases in both electric and natural gas revenues. These revenues will contribute towards our goal of improving cash flow and regaining our investment grade credit rating. In Washington, a settlement agreement recently was reached among three of the five parties in our natural gas general rate case, which was filed in mid-August.

The staff of the Washington Utilities and Transportation Commission, The Northwest Industrial Gas Users, and Avista agreed to a 3.9% increase in natural gas base rates, which would increase annual revenues by $5.4 million. Our original request was for an increase of 6.2% or $8.6 million.

The stipulated settlement is scheduled for hearing tomorrow and if approved, would go into effect on November 1st. Avista Utilities also received a recent approval of purchased gas cost adjustment or PGA rate increases of 14.2% in Idaho, effective September 9th, and 12.6% in Oregon, effective October 1st.

The company also has pending PGA increases of 11.7% in Washington and 10.5% in California. These PGA rate adjustments are generally filed annually to more closely align the rates paid by customers with the cost of natural gas purchased by the company and these PGA rate changes do not affect net income for the utility.

Avista Utilities had a net loss of $0.15 per diluted share in the third quarter of 2004 compared to a contribution of $0.02 per diluted share in the same quarter last year. The loss is due to the IPUC related write-offs which totaled $0.20 per diluted share on an after tax basis. Excluding these write-offs, Utility results improved compared to the prior year.

And as Gary mentioned at the beginning of this report Avista has entered into an agreement with Mirant to purchase its 50% share of the Coyote Springs 2 generating facility for $62.5 million. The costs of acquiring these 140 megawatts of capacity is $439 per kilowatt, which compares quite favorably to the $750 per kilowatt cost assumed for the new gas generation in our integrated resource plan. Because Mirant is in bankruptcy, the agreement will be subject to competitive auction, in which Mirant could accept a higher bid. Once the auction process is complete and assuming there is no higher bidder, the transaction will require a number of approvals, including the United States Bankruptcy Court and the Federal Energy Regulatory Commission, and the agreement must also meet other federal and state requirements.

I'm pleased to report the generating facility has been fully operational since September 7th following the repair of the main transformer and a backup transformer has been purchased and is currently en route to the Coyote Springs site. Full ownership of this generating facility represents an excellent opportunity for our company and our customers as we continue to focus our business strategy on the northwest. Coyote Springs 2 will be a valuable and cost effective resource to help meet the growing energy needs of our customers and of course, we plan to seek rate base treatment of the new purchase at the appropriate time.

As we reported in the news release this morning, the proposal for the sale of our South Lake Tahoe natural gas distribution properties to Southwest Gas has been filed with the California Public Utility Commission. The transaction is expected to be completed early in 2005. As we look toward the end of the year the hydroelectric and steam flow conditions continue to be below normal, but they have shown some improvement since our last quarter report, due to the rainfall the region received in September. Our current projections call for 2004 hydroelectric generation to be 508 average megawatts or nearly 92% of normal. This is up from the previous forecast of 88% of normal.

Finally, at Avista Advantage, I'm very pleased to report that the third quarter of 2004 was the first positive earnings quarter for this company. Avista Advantage contributed a penny to earnings. In the past 30 days, Advantage has signed over 23,000 new accounts, which are ready to go live over the next four to six weeks and included in that number are completed contracts with three of the top 20 national retailers representing the automotive, video rental, and electronic sectors. Year-to-date, Advantage has increased revenues by 14% over the same time last year. The positive trends in Avista Advantage's results are due to a continued focus on operational cost efficiencies and new services for current and renewing clients. So, with that I'll turn it over to Malyn.

Thanks Scott and good morning to everyone. As Gary told you at the beginning of this call, we had a quarter with mixed results, negatively impacted by the IPUC write-offs and disappointing performance in the energy marketing and resource management segments. Our consolidated net loss for the third quarter of 2004 was $9.8 million, as compared to net income of $4.3 million in the third quarter of 2003.

We had a loss of $0.20 per diluted share this quarter, compared to earnings of $0.09 per diluted share during the same quarter in 2003. The third quarter is historically a low earnings period for our company. Utility gas sales are always low and the open question is whether the electric revenues will produce sufficient earnings to offset the losses generated by the gas business.

Our service area had a warmer than normal late July and early August this year, and as a result of the strong air-conditioning load, Avista Utilities exceeded internal targets, absent the IPUC disallowances of $0.20 per diluted share. Thus the loss of $0.15 per diluted share would have been a contribution of a positive $0.05 per diluted share from the utility without the disallowances.

The energy marketing and resource management segment recorded a loss of $0.03 per diluted share to corporate earnings in the third quarter. Unfortunately, we found it necessary to take a 7-cent per diluted share impairment during the third quarter, associated with the remaining LM6000 Generator owned by Avista Power.

As we have attempted to market this unit and the corresponding pollution control equipment, it has become more apparent that the book value of the generator is more than we can sell it for, so we have reflected the market value through this impairment. We are actively trying to sell the unit to allow us to put the cash to work in our other businesses.

Avista Energy continues to contribute positively to earnings, but the $0.04 earned in the third quarter was short of its internal target. This was primarily due to sharp increases in natural gas prices during the latter part of the third quarter that were unfavorable for some short-term positions. While 2004 results for Avista Energy have been disappointing, we continue to have confidence in the business.

We're seeing the number of market participants starting to grow once more, after watching the number drop off significantly following the energy crisis. Avista Energy is also in discussions with a number of potential customers in the northwest to manage their assets. It is important to view this business with a long-term perspective. Since its inception in 1997, Avista Energy's average annual return on equity has exceeded 18%.

We believe the business model is still sound and that the company's value will return over the next couple of years as the market improves. Our capital budget for 2004 is $110 million and we have spent approximately $78 million year to date. Looking to 2005, we're recommending a capital budget of $135 million to our board of directors.

As you can see, in slide number four, our historical capital spending level excluding major generating projects is about $90 million not adjusted for inflation. We will keep this base level of spending the same, but we need to complete our major transmission project. In addition, we're starting to spend some significant dollars on environmental issues related to the re-licensing of our hydroelectric facilities, thus a budget of $135 million. This excludes the purchase of the second half of Coyote Springs 2, which we hope to accomplish in 2005.

How will we finance this level of capital expenditures? Assuming normal hydro generation, we should generate enough cash internally to fund the $135 million of capital expenditures, plus pay off the $35 million of debt maturing in 2005. You will also recall that we have been planning to repurchase approximately $50 million per year of high cost debt.

Thus far, year to date, we've repurchased about $37 million. To finance the purchase of the second half of Coyote Springs 2, we will slow the level of debt repurchases over the next 12 to 18 months.

In addition, we will apply the proceeds, $15 million, from the sale of the South Lake Tahoe natural gas distribution properties to the purchase of Coyote. So again, with normal hydro conditions, we would not likely require any external financings.

However, if 2005 brings similar hydro conditions as the past two years, which have hurt us by about $30 million per year in lower cash flow, we might then turn to the debt markets for some level of financing. I will also tell you that we always reserve the right to tap the financial markets if by so doing, we can reduce interest costs or otherwise improve our financial condition. And I will say interest rates are looking very attractive.

With regard to 2004 earnings guidance, as you’ll recall the consolidated guidance was between $1 and $1.20 per diluted share. This was based on expectations that Avista utilities would contribute in the range of $0.75 to $0.90 per diluted share, excluding the impact of regulatory disallowances. The guidance called for the energy marketing and resource management segment to contribute $0.25 to $0.35 per diluted share, Avista Advantage to be earnings-neutral and the other segment to lose less than the $0.10 per share loss record in 2003. Based on our results to date, we are revising our consolidated earnings guidance for 2004 to between $0.70 and $0.85 per diluted share, with the inclusion of the Idaho disallowances of $0.20 per diluted share. So excluding the impact of the regulatory disallowances, the guidance would be in the range of $0.90 to $1.05 per diluted share.

On a business segment basis, Avista Utilities is expected to contribute earnings at the upper end of the previous expectations. Excluding regulatory disallowances, the guidance for Avista Utilities is raised to between $0.85 and $0.95 per diluted share and including such disallowances, $0.65 to $0.75 per diluted share. This year we expect close to 50% of our utilities earnings in the fourth quarter, assuming normal weather. The below target performance in the energy marketing and resource management segment for the third quarter is causing us to lower our expectations for earnings contributions to between 10 and $0.15 per diluted share for this year, including the impact of the asset impairment at Avista Power.

Expectations for 2004 earnings contributions from Avista Advantage, and the other segments are unchanged. Our consolidated earnings guidance for 2005 is in the range of $1.20 to $1.35 per diluted share. This would exclude regulatory disallowances, if any. We expect Avista Utilities to contribute between $0.95 and a $1.10 per diluted share. The earnings outlook for the energy marketing and resource management segment is in the range of 20 to $0.30 per diluted share, for Avista Advantage, about $0.5 per diluted share, and we anticipated the other business segment will lose about $0.5 per diluted share.

In conclusion, while we're disappointed in our bottom line results for the year, we are pleased with the improvement in the earnings levels at the utility, excluding the disallowances, and we believe that we have set the stage for some solid growth in 2005. We are actively working to improve revenue levels, and control costs to move our earned returns more in line with our cost of capital.

While Avista Energy has not met its targets, it is nevertheless making a positive contribution to earnings. This business has had some excellent years for our company and we continue to believe in its long term potential. We're very pleased with the progress at Avista Advantage and we believe that it has the potential to become a significant contributor to our bottom line.

And we are working, we are continuing to work through and put behind us some legacy issues from past diversification efforts and the turbulent energy markets of 2000 and 2001. The list is shorter and the impact is shrinking. We're clearly seeing the benefit with less earnings drains and almost no cash flow requirements. This is a dramatic improvement over prior years.

We believe that our strategies will position us to see significant improvement in financial results over the next few years. Now, I'll turn the presentation back to Jason.

Thanks Malyn. We'll now open this call up to questions from analysts and investors.

I would like to remind any members of the media who may have questions to please contact Jesse Wuerst at 509-495-8578. We are now ready for our first question.

[Operator Instructions]. Your first question comes from Doug Fischer of A.G. Edwards.

Thank you and good morning.

Good morning Doug.

Question about Coyote Springs. Obviously, there's going to be some lag, it appears, between when you close on the purchase and when you actually get it reflected in rate base. Can you provide any commentary as to the net income drag that ownership of that plant might incur until it is included in rate base? Any commentary on that?

Doug, this is Malyn. Of course we -- there are some benefits to having Coyote once we have the purchase completed. So while we aren't covering entirely depreciation and O&M expenses and a return on rate base associated with that, it doesn't fully fall to the bottom line necessarily.

We will file appropriately to try to recover this as soon as we possibly can, recognizing that we're still at the very end of our Idaho case and there's probably several months before we're going to have, before we know that we're getting the plant, for sure. And we have the plant closed and have the ability to operate it. We haven't calculated the full impact of that but I will tell you that we've reflected it in the earnings guidance for 2005.

So the guidance assumes that you purchased Coyote Springs 2 and it occurred what? Year-end 2004?

It assumes that it occurs in the first quarter of 2005. And it does assume that we will have regulatory lag. But because we're still working out those plans and when they the discussions with our regulators around that, I would prefer to not go into more detail other than to say we think we've assumed a reasonable time frame and amount that we would be able to earn a return on. But you're absolutely right. There is some lag associated with the ownership.

Two things. Maybe you can talk a little about the benefits, though they may not be fully realized on a financial standpoint in the early part of it. And then secondly, what kind of ROE on the -- what should we use for the equity for the utility for 2005 sort of an average you know to sort of to get at the range of ROE's at the utility that are implied by your guidance for 2005?

Well I'll start talking about - this is Scott. I'll talk about the benefits of Coyote while Malyn gets you the ROE numbers. Coyote is really is will be excellent for the utility in a number of ways. As you know in our integrated resource plan, we have the needs for about 150 more megawatts of combined cycle generation. This gives us an outstanding opportunity to purchase it at what I will call unique prices.

As we compared the price of the purchase of Coyote to other assets that were purchased in the marketplace, it is quite attractive. Also, if you look at our resource plan, while on average, we tend to be long for the year, there are certain quarters where perhaps we're a little short. And with bad water. So when you look at that, with Coyote, it's a very nice fit with our resource mix. And how kind of our resources shape.

So it is a very good fit for the utility company. And we're quite happy with the opportunity. Remember, Doug, we had originally in our 2000 integrated resource plan had assumed all of the output of Coyote. And when we had to sell it in 2001 because of our situation, we still needed the generation at some point in time. So this is a very good opportunity for us.

And when - which resource plan, and has this resource plan been approved by either Washington or Idaho and when, what year did it show this need for 150?

Our integrated resource planning that we file with our commissions are never officially approved. They are accepted or recognized, if you will.

OK. This is the 2000 plan that you're talking about?

Well the 2003 plan reflected 150 megawatts of, needed of combined cycle gas fire generation, so -- and again in that integrated resource plan, it assumed a price of $750 a kilowatt. And at the current $62.5 million purchase, it's about $463 a kilowatt. So significantly under the integrated resource plan number, that was recognized by the Washington commission and the Idaho commission.

Thank you, Scott.

This is Malyn. The answer to the rate base number, our rate base at the end of September was $1,456 million. And of course, we're continuing to spend, we'll spend next year, about $135 million plus Coyote being another, roughly $60 million, back out the South Lake Tahoe of 15, and back out depreciation of about $70 million. And you can do the math to get at kind of what our year-end 2005 rate base would be. And of course, you would need to average, basically take the average rate base to do that calculation.

And what's the equity ratios recognized in the two states?

It's about 42% at this point.

Doug, I misspoke. The Coyote deal is a little better than I said. It’s $439 a kilowatt. So I think I said $463, I apologize. It is $439.

Thank you very much.

Thanks Doug.

Your next question comes from James Bellessa of D.A. Davidson & Co.

Good morning. I heard on the conference call that you expect 50% of your utility EPS to fall in the fourth quarter. Now is that pre the $0.20 disallowance or post the $0.20 disallowance, so that you're talking about?

Jim, this is Malyn. It is pre the disallowance.

And so your guidance for the year is $0.85 to $0.95 for the Avista utilities, is that correct?

That's correct. And if you back out the disallowance from the first nine months earnings, we're at about $0.46.

That means you have to hit, to get to the mid point of that guidance range, you have to have $0.44, fourth quarter for the utility, which would be up 33% from last year's fourth quarter. What would cause it to be up like that?

Well, I think the major issue is we've had some fairly significant rate increases. We have the impact of the Idaho rate increase that took effect in September and we've got the full impact of the Oregon rate case that took effect late in 2003. We would assume normal weather, and last year, our fourth quarter was a little warmer than normal, and I think we're expecting a little bit more normal, not a lot, but a little better hydro conditions in the fourth quarter of this year than we had in the fourth quarter of last year.

OK. Good. Now on the charge that you had for the LM6000 generator and corresponding pollution control equipment, what was the dollar amount of that pretax charge, and what was the after tax number?

The dollar amount, pretax, was roughly $5 million. After tax, it was $3.3 million.

OK. And then on the $14.7 million disallowance at the utility, what was the after tax amount of that?

I'm going to ask Christy Burmeister-Smith, our Controller, to answer that question.

Hi. The write off after tax was $9.6 million, or $0.20.

OK. And you're saying that you're interested in trying to rate base the second half of Coyote Springs 2, if you were to acquire it. And that sounds like a good idea. But in your plan, your business plan, your long-range resource plan, you say that you don't need a gas-fired generation until 2008. So if you acquire this in 2005, how could you go in and say we should rate base it now?

Jim, remember that you're looking at annual averages and as you look at the various seasonal differences, especially third quarter hydro-flows, you know we get a lot of our hydro off in the second quarter. And way more than what we need for our system. And if you average that across the year, it looks like your surplus.

Third quarter is usually short for us, and a lot of times, we need to go out and buy during third quarter. This actually fills the hole out there, that we would have actually starting probably next year. So it fits in, as Scott was saying, very well, in filling in our load resource profile. So we think that it is prudent, especially if we are able to get it at the price that we currently have offered to buy it for.

If my memory is correct, at the last call, I believe you indicated that there was a possibility that you would soon be announcing an executive at Avista Advantage. Evidently, your negotiation or whoever you were talking to at that time didn't work out. Is there any reason, is there a business reason why that arrangement didn't work out?

No. There wasn't a business reason. The individual was very interested in coming to it -- let me just leave it as, it was a family situation. And although the individual was very interested in coming, and we had met all the needs there, the individual had some children that were in high school and it just came down to it was too difficult of a move for them to make from where they were coming from to Spokane.

And the 23,000 new customers -- that's not the right term -- new accounts. That comprises how many customers? New customers? Did you sign up some new customers as a result, get these new accounts?

Sure. Yeah. I would think it's about 35 new customers. And you know, some of them have multiple sites. So it is -- 35 customers for the whole year. Excuse me.

There were about five to six customers that comprised that 23,000.

Now before this new guidance, your guidance for energy marketing and resource management was $0.25 to $0.35 for 2004. Now, next year, you've taken that down by a nickel of share of that range. What causes the range to go down from next year? I can understand that this not the disallowance, but the impairment charge that you took, and maybe just the current market conditions, but why would next year's guidance go down?

I've got Dennis Vermillion here, who runs Avista Energy. I'm going to let him address part of that and if there's anything else, I'll pick it up later.

Thanks Gary. Good morning Jim. The guidance for 2004 was $0.25 to $0.35. And if you back out the Avista power impairments, we are about $0.14 per share for Avista Energy so far for this year.

We did state in the call that we had some positions that were unfavorable in Q-3. Part of that was driven by some of our short-term positions. Some of it is an issue associated with how we account for our gas storage. If you adjust the gas storage and look at our performance for the year, we're actually not that far off from meeting our targets for the $0.25 to $0.35. So we also did lose our agency agreement as you know and that's about $0.02 per share.

$0.02, did you say?

Roughly.

OK.

So that lowers it by $0.02. If you look at market conditions. Although they are improving, we see some new market players entering, there's better liquidity on the power side, especially with the introduction of NYMEX clearing and we see things starting to turn around but we ought to be conservative. So I think $0.20 to $0.30 is a pretty good range for us. And, given market conditions, it's really not that far off from where we were for 2004.

Thank you very much.

Your next question comes from John Hansen (ph) of Emperium (ph).

Good morning.

Good morning John.

First of all, congratulations on the Avista Advantage deemed to be positive. I know you have talked about that for a while so, congratulations on that.

Thank you.

Let me come back to utility. In the guidance that you've got for next year, what kind of water year are you planning for there?

Normal.

Normal water year? OK. Following up a little bit on the direction with the process for getting the Coyote Springs 2 into rate base and recovery mode, could you recap again that you have something in that for 2005 or no, in terms of the effects of that in some indirect way?

We would expect to request rate-making treatment in the first half of 2005. And then of course, each jurisdiction has their own time frame as far as when they get that done. We would hope we would get it done earlier than the maximum limit but we never know in those cases. It is really at their discretion.

Might that involve a general rate case in electric in Washington? Or is that something your are exploring lots of in different possibilities on?

We don't know. We’re at this point exploring the possibilities and I know Kelly Norwood who heads up our regulatory staff has been doing a lot of work in trying to prepare and see what would be the best way to approach this, including discussions with the staff. If we're successful in getting it, remember, we've signed the deal and now it has to go through bankruptcy court and the other things. We assume that we will have a fair opportunity of getting the plant, in which case we're exploring the other options. But it’s a little bit too early at this point to say exactly where we're at.

It looks like you have got a settlement in the works on the gas case. So that seems to indicate that at least your relationships with the regulatory process, they're in Washington, might – or are improving a bit, might work out for electric in Coyote Springs case as well.

I think we've worked very hard in all of our states to maintain good regulatory relationships with our commission. It's always a balancing act for them because they have to balance the interests of the customers, along with the interests of our company and the shareholders. Sometimes that's a difficult balance and we don't always agree, as you see in Idaho you know we will be asking for reconsideration on the pieces that were disallowed or at least anticipating doing that. But we still have good relationships there and I think we do in Washington. It really comes from I think Kelly and his staff's work of being candid and up-front with the commission and playing it straight up. And we'll continue to do that.

Thank you.

A follow-up question from James Bellessa.

I have two follow-up questions. First of all, would you please remind me about Washington and whether or not they allowed or disallowed the gas purchase for the Coyote Springs 2 plant that was later sold at a loss?

Well, that, Jim, was never really addressed in the sense that in Washington, it is a different issue because we have the dead band. Remember, it’s a $9 million dead band and you know it just falls into the $9 million. So you can argue one way or another whether it was or wasn't.

And I'm going to ask three questions. This is the second one. This 50% of results from the utility falling in the fourth quarter, is that going to be a normal pattern going forward, or unlikely to be that high of a waiting for the fourth quarter?

You know Jim what's happened, it used to be we would get the majority of our earnings in the first and fourth quarters. And now because of the way the ERM dead band has been working and the fact that we have been eating the whole $9 million, that has tended to occur largely in the first quarter. And so we now have a little bit more, I guess, less balance between the four quarters and we end up having the fourth quarter be our major earnings quarter for the utility.

And I think, you know, that could change. We hope at some point to not be eating the $9 million every year and actually have a good opportunity to make some money potentially, if we can manage our resources well. And that would show up in the first quarter of those years, in terms of no longer having to eat that $9 million. It would round things out a little more and give us more of the historical pattern.

The 2002 Washington settlement took the dead band out for how many years?

It's 2006.

And so it includes 2006. We'll still see $9 million dead band in the first half or so of 2006, is that right?

No. That's not necessarily true, Jim. The dead band will be in effect and it will depend on where our rates are set in relation to the market and how our loads are and everything else. We could actually, you know, if we had a very good water year and didn't have excess costs, we could actually have a plus $9 million. That was the whole idea of setting it up.

You have to have your rates set, though, and one of the things that have been hurting us a little bit is the gas cost for our thermal generation because nobody expected when we set rates for them to be in the $6 and $7 range like they are today. So that impacts that to a certain extent.

OK, thank you. And then the $14.7 million disallowance of this most recent quarter at the utility, what line item did that show up in?

Christy?

Jim, it’s in a couple of different line items. There were some resource costs related to the gas deals; that’s 12.3 million. So you'll see that in the resource line. And then the rate base disallowances show in the O and M line and they are approximately 2.5 million.

That's helpful. Thank you very much.

You have an additional follow-up question from Doug Fischer.

Thank you. Just contemplating the possibility of general rate case in Washington State. What do you think would be the key issues beyond R.O.E.? This would be the first attempt to, in a rate case, fully rate base Coyote Springs, the entire plant? Is that correct?

Well, Doug, the half that we currently own is in rate base in the state of Washington, so there’s not an issue there whatsoever. And as far as the balance of the plant, we have a ways to go before we could even consider what we might do there. Like I say, it still has to go through the auction process. It has to go through the bankruptcy court. It has to be approved by FERC and stuff. And then as we would go to the states to have it approved there, that's probably when you would address those issues.

This is Malyn. The other issue that I think would take place in an electric general rate case would be resetting the dead band, if you will, this $9 million is based – it was put in place based on basically $4.50 gas and we aren't seeing any of that anymore. So we would try to reset the rates, such that we have an equal chance of having upside. This is basically the same chance of having upside as we have of having a downside from that and I think that's not where we're at based on the rates that are in effect today.

And just to get back to the earlier question, do you think that we would have the staff of the commission, or the commission itself looking at the issues, the disallowances that we saw in Idaho? Or do you think that that, it's pretty clear that's already been absorbed through the dead band?

I think our position would be that they've taken their pound of flesh. We've really been hit pretty hard by the $9 million per year. And so I think our contention would be that that has all been accounted for, now the staff may take a different position on that and you know they always have the chance to do that.

And even if you filed a general rate case, the 9 million dead band would stay in effect, you might recess the fuel and purchased power rate, shall we say, but the 9 million dead band would stay in effect through the end of 2006? Is that the settlement agreement?

Yeah, the settlement agreements end at a stage in effect through 2006. Everything is on the table when you go in for a generate case, you know we may (multiple speakers).

That could be an issue of discussion?

Absolutely. And also, it might be an issue, that if it’s reset right, that we want to keep it a lot longer than after '06. We think it affords both the company some protection as well as our customers in an up because we actually give back when we have this above that. So as you go into a general rate case, as you know, everything is on the table when you go into them, but as a current under the last order that we have on that, that dead band is in effect through 2006.

OK Thank you.

Thank you, Doug.

There are no further questions at this time. I would now like to turn the presentation back over to Mr. Jason Lang.

I want to thank you all for joining us today. Analysts, investors, you may direct any other questions you have to me at 509-495-2930. Again, I will ask the media to please direct their questions to Jesse Wuerst, Avista Communications Manager, at 509-495-8578. A replay of this conference call will be available today beginning at 12:30 p.m. eastern time.

The contact information for the teleconference replay, as well as for the web cast, and slides, is available on the Avista Corp web site at avistacorp.com.

Again, thank you for joining us and have a good day.