Avista Corp (AVA) 2006 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the third-quarter 2006 Avista Corporation earnings conference call. At this time, all participants are in listen-only mode. We will conduct a question-and-answer session towards the end of this conference. (OPERATOR INSTRUCTIONS). As a reminder, this conference is being recorded for replay purposes.

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

Thank you. Good morning, everyone. Welcome to Avista's third-quarter 2006 earnings conference call and webcast. Avista's earnings were released premarket this morning, and the release is available on our website at avistacorp.com.

Joining me this morning are Avista Corp. Chairman of the Board and CEO, Gary Ely; President and COO, Scott Morris; Executive Vice President and CFO, Malyn Malquist; Vice President and Controller, Ann Wilson; and the President of Avista Energy, Dennis Vermillion.

As a note to those of you on the webcast, we will be advancing the slides automatically during the course of the presentation. Following the call, the slides can be downloaded from our website at avistacorp.com. There will also be a replay of today's webcast available on our website later today.

Before we begin, I would like to remind you that some of the statements that will be made today are forward-looking statements that involve risks and uncertainties which are subject to change. For a reference to the various factors which could cause actual results to differ materially from those discussed in today's call, I would direct you to Avista's 2005 Form 10-K and Form 10-Q for the quarter ended June 30, 2006, which are available on our website.

Before I turn this presentation over to Gary, I would like to briefly recap the financial results presented in today's earnings press release. Avista Corp's third-quarter earnings report shows net income of $10.1 million or $0.20 per diluted share, an improvement compared to the net loss of $9 million or $0.19 per diluted share for the third quarter of 2005. Year-to-date net income was $55.1 million or $1.11 per diluted share, an increase from $19.8 million or $0.40 per diluted share for the same period last year.

Now, I would like to turn the discussion over to Avista's Chairman of the Board and Chief Executive Officer, Gary Ely.

Thanks, Jason, and good morning to everyone on this bright, crisp morning with temperatures in the teens. We are pleased with our year-to-date results for 2006. Our major business segments -- Avista Utilities, Energy Marketing and Resource Management and Advantage IQ -- are all performing well.

Our utility operation continues to benefit from lower electric resource costs for the year and the positive effect we have received under the Washington Energy Recovery Mechanism, or ERM. We are cautiously optimistic that we may end up the year on the positive side of the ERM for the first time since its implementation in 2002.

In August, we filed for a rate increase in Washington to recover increased transmission and production costs. Scott Morris will discuss this filing further and provide an update on our utility operations in a couple of minutes.

While Avista Energy's reported results continue to have more variability than we would like, in part due to the required accounting for certain contracts and assets under management, we are pleased with the results for the third quarter. This business is on track to meet its earnings target for the year. Dennis Vermillion will have further information on the results of Avista Energy in a few minutes.

That being said, as we reported in our second-quarter 10-Q, the variability in the results of the operation of Energy Marketing and Resource Management segment has caused management to continue to evaluate whether Avista Corp. should continue in this business over the long term as currently conducted, and what, if any, strategic alternatives may be available. Also of note in the Energy Marketing and Resource Management business segment, in October, Avista Power completed the sale of its 49% interest in Rathdrum Power for approximately book value.

Another contributor to our consolidated earnings growth was Advantage IQ. This business continues to increase revenues and build its customer base. Malyn Malquist will provide more details on the performance of this subsidiary later in the call.

As mentioned earlier in the year, we are planning to change the Company's organization to a holding company structure through a statutory share exchange. As proposed, the holding company would ultimately become the parent of Avista Utilities and Avista Capital, following the contemplated dividend of the capital stock of Avista Capital to the holding company. Since the Company's 9.75% senior year notes due in June of 2008 contain a restriction that would prohibit the Avista Capital dividend, but not the forming of the holding company structure, the dividend would not be distributed until the senior notes are retired.

To date, we have received approval for the organizational change from our shareholders, the Federal Energy Regulatory Commission and from the Idaho Public Utilities Commission. The statutory share exchange is also subject to regulatory approvals in Washington, Oregon and Montana, and the satisfaction of other conditions. We anticipate the statutory share exchange and the holding company structure implementation, if approved on terms acceptable to the Company, will not be completed earlier than mid 2007.

Overall, I am pleased with the Company's results so far in 2006. We are on track to meet our consolidated earnings targets. We are anticipating a good fourth quarter, and we expect that trend to continue into 2007.

Now, I will turn the call over to Scott Morris for his report.

Thanks, Gary, and good morning, everyone. Avista Utilities contributed $0.01 per diluted share for the third quarter of 2006, compared to a loss of $0.04 per diluted share for the third quarter of last year. The third quarter is typically a challenging quarter for our utility operations, and we have often reported a loss in past years. This has been primarily due to low natural gas loads and relatively high electric resource costs, because of seasonably low hydro generation.

Year to date through September, Avista Utilities contributed $0.88 per diluted share, an increase from $0.72 for the same period of 2005. The increase in our year-to-date results was partly because our electric resource costs were lower than the amount included in base retail rates, particularly due to strong hydro generation during the first half of 2006. As a result, we recognized a $3.4 million benefit under the ERM during the first nine months of 2006, as compared to a $7.5 million expense recognized in the first nine months of 2005.

The power supply cost variance is ultimately calculated on a calendar year basis and can change significantly during the interim periods of the year. As such, the power supply cost variance and the resulting calculations under the ERM will most likely be different at the end of 2006, compared to the end of the third quarter. However, as Gary previously mentioned, we're cautiously optimistic about recognizing a benefit for the full year of 2006 under the ERM.

Based on actual generation for the first nine months of the year, and assuming normal precipitation for the fourth quarter, we're expecting hydro generation to be 101% of normal in 2006. However, conditions can change during November and December, and our actual generation may be different from expectations, based on precipitation, temperatures and other variables.

We're continuing to invest in generating resources and our transmission and distribution systems to meet expected load growth needs and to continue to provide reliable service to our customers. Through the end of September, we spent approximately $115 million of our $160 million utility capital budget. Significant investments include the continued enhancement of our transmission system, ongoing installation of advanced metering technology and upgrades to our hydro generating facility.

Due in part to this investment in infrastructure, we filed a request with the Washington Utilities and Transportation Commission in August to increase electric rates for our Washington customers by an average of 8.8%. This request is designed to increase annual revenues by $28.9 million, of which approximately $10 million would increase gross margin. As such, approximately two-thirds of the revenue increase would not increase gross margin or net income, because it would be designated to recover an increase in resource costs. The proposed increase, referred to as a production transmission or PT update, includes an update to those ERM-related production and transmission costs that are included in base retail rates.

It should be noted that we are not requesting an increase in rates related to cost changes associated with administrative and general expenses, operation and maintenance expenses or the cost of equity and capital structure. In this filing, however, we are proposing to flow through to customers the lower cost of debt the Company is experiencing since the last general rate case.

Last week, the industrial customers of Northwest Utilities and the Public Counsel section of the Washington Attorney General's office filed motions to dismiss our PT update, claiming, among other things, that the filing represents improper single-issue ratemaking, and that the costs at issue should be addressed in a general rate case filing. We believe that the filing before the Commission is appropriate, and we are proceeding with the case with the expectation that the schedule established by the WTC will provide new rates effective in April 2007.

In April 2006, we filed a proposal with the WTC to implement a natural gas decoupling mechanism. Decoupling separates the direct link between natural gas sales volume and the recovery of the cost of providing distribution service or margin, which does not include the cost of the natural gas itself. Because our current rate structure provides for a recovery of the majority of our fixed costs on a per-therm basis, energy efficiency and conservation objectives are directly at odds with the recovery of fixed costs.

Decoupling breaks the link between the volume of sales and the recovery of fixed costs, and would facilitate an increased focus on energy efficiency and conservation. Our proposed decoupling mechanism would allow the Company to recover lost margin resulting from lower customer usage due to conservation and price elasticity. However, it would not provide for any rate adjustments due to abnormal weather.

In October, we entered into a contested settlement agreement, which included the WTC staff, with respect to the decoupling mechanism. The mechanism would begin early in 2007, if regulatory approval is received. The mechanism is a three-year pilot, and the rate adjustment in any one year would be limited to no more than 2%.

During the third quarter of 2006, we filed purchase gas cost adjustment requests in Washington, Idaho and Oregon to adjust natural gas rates to reflect changes in natural gas costs. These requests were subsequently amended to reflect falling natural gas prices.

We received approval for a 1.3% increase in Washington and a 3.4% decrease in Idaho, to become effective November 1. We received approval for a 6.9% increase in Oregon, effective November 1, subject to refund pending further review of our natural gas purchasing and hedging strategies. These natural gas rate increases and decreases are designed to pass through changes in purchased natural gas costs to customers, with no change in Avista's gross margin or net income.

Avista's current license for our Spokane River hydro facility expires on August 1, 2007. These facilities represent approximately 16% of our current hydro generating capability. We have requested the FERC to issue separate licenses for the Post Falls facility and for the other four hydro plants on the Spokane River, because the Post Falls plant presents more complex issues that may take longer to resolve than those associated with the rest of the Spokane River.

It's interesting to note that the Post Falls facility, located in Idaho, represents less than 2% of our hydro generation capability and approximately 1% of our total generation capability. We have been engaged in a multiyear collaborative process with stakeholders to develop reasonable terms and conditions for the new licenses. In July, various parties -- including the Coeur d'Alene Tribe in the state of Idaho, Washington State agencies and others -- filed numerous comments, recommendations, terms and conditions and prescriptions regarding our license application with the FERC. In addition, the United States Department of Interior filed proposed mandatory conditions for the Post Falls facility.

Our initial estimate of the potential cost of these conditions proposed for Post Falls totals between $400 million and $500 million over a 50-year period. This assumes all conditions, both mandatory and recommended, as well as our proposed conditions, would be included in the final license issued by FERC, which we believe to be unlikely. For the rest of the Spokane River project, our initial estimate of the cost of meeting the recommended conditions, if they are included in the final license, totals between $175 million and $225 million over a 50-year period.

These cost estimates are based on the preliminary conditions and recommendations, and will be updated based on the outcome of the FERC proceedings. We believe the Department of Interior's proposed conditions for Post Falls are unreasonable, and the costs would be unnecessarily burdensome for our customers. As a result, we have requested a trial-type hearing process with respect to Interior's proposed addition. This process is a relatively new procedure created by the Energy Policy Act of 2005. The hearing process will focus on whether Interior's proposed conditions are supported by the facts.

We have also filed proposed alternative mandatory conditions with the Department of Interior, which we believe provide a more cost-effective alternative to addressing the concerns raised by this federal agency. On a positive note, we reached agreements this summer with the Bureau of Land Management and the US Forest Service on proposed license conditions for the Post Falls facility.

Now, I will turn this call over to Dennis Vermillion the a report on Avista Energy.

Thanks, Scott. Good morning. The Energy Marketing and Resource Management business segment, which primarily consists of Avista Energy, had net income of $0.17 per diluted share for the third quarter of 2006, compared to a net loss of $0.17 per diluted share for the third quarter of last year. For year to date 2006, the segment contributed $0.18 per diluted share, compared to a net loss of $0.34 per diluted share for year to date 2005. The increase in net income was primarily due to improved results from natural gas trading activities, which had losses in 2005, and the continued execution of profitable transactions in power trading and other asset management and optimization activities.

We manage our business on an economic basis, reflecting contracts and assets under management at estimated market value, consistent with industry practices, which is different from the required accounting for certain contracts and physical assets under management. These differences primarily relate to our management of natural gas inventory and the control of natural gas-fired generation through a power purchase agreement, as well as other agreements including natural gas pipeline transportation agreements.

These differences had an estimated $1.6 million after-tax positive effect on results for the third quarter of 2006, compared to an estimated $7.7 million after-tax negative effect on results for the third quarter of 2005. For the nine months ended September 30, 2006, these differences reduced net income by an estimated $3.7 million, as compared to an estimated $11.6 million for the nine months ended September 30, 2005.

Results for this segment were consistent with the Company's expectations for the first nine months of 2006. A significant portion of the estimated $3.7 million negative difference between the economic management and the required accounting for certain contracts and physical assets under management for the first nine months of 2006 is expected to reverse in the first half of 2007, when the contracts are settled or realized.

This assumes stable commodity prices and no additional transactions by Avista Energy. Until the contracts are settled or realized, this difference could also increase or decrease due to changes in forward market prices. Based on our results for the first nine months of the year, we are on target to meet our earnings forecast for 2006.

At this point, I will turn this call over to Malyn Malquist.

Thanks, Dennis, and good morning, everyone. I will provide an overview of financing activities, cash flows, the performance of Advantage IQ and the Other business segment, as well as our earnings forecast. Our total debt outstanding decreased approximately $41 million in the first nine months of 2006, primarily due to operating cash flows in excess of utility capital expenditures, dividends and other funding requirements. Our debt to capitalization ratio has decreased from 60.2% of the end of 2005 to 58% at September 30, 2006.

For the fourth quarter, we expect net cash flows from operating activities and our committed line of credit to provide adequate resources to fund capital expenditures, maturing long-term debt, dividends and other contractual commitments. However, we currently expect to issue long-term debt in the fourth quarter to partially fund debt that matures in December 2006 and January 2007. We expect that this new debt issuance will be at a lower rate than the maturing debt.

Even though we have reduced debt levels, our interest expense increased $2.8 million for the first nine months ended September 30, 2006, as compared to the same period a year ago. This was primarily due to two factors.

First, an increase in interest rates has affected our variable-rate long-term debt to affiliated trusts.

Second, during 2005, we carried higher levels of short-term borrowings under our committed line of credit at relatively low variable rates of around 4%. During the fourth quarter of 2005, we essentially refinanced these borrowings on a long-term basis at a fixed rate of 6.25%. Although this was a prudent long-term financing decision, it has resulted in a increase in interest expense for 2006, as compared to 2005.

With respect to other cash flows, deferred power and natural gas costs were reduced by $35 million during the first nine months of the year, primarily through recovery from customers. As of September 30, 2006, our combined electric and gas deferral balances totaled approximately $112 million.

On a consolidated basis, Avista's effective tax rate has decreased, as compared to the prior year, on both a quarterly and year-to-date basis. During the third quarter of 2006, the Company recognized adjustments related to the Internal Revenue Service audits and adjustments for the 2005 filed federal tax return. In total, these adjustments had a favorable impact on recorded tax expense of $1.3 million, with a positive effect at Avista Utilities of $1.7 million, partially offset by a negative effect in the Other business segment of $400,000.

In the Washington general rate case settlement and in an agreement with Idaho regulators related to the holding company formation, Avista has agreed to increase the utility equity component to 35% by the end of 2007 and 38% by the end of 2008. Failure by the Company to meet those targets could result in a reduction in base rates of 2% for each target. The utility equity component was approximately 33% as of September 30, an increase from 31% at year end 2005. Beyond expected earnings, we continue to evaluate and implement measures to increase our utility equity ratio.

In August, the Board of Directors increased the quarterly dividend by $0.005 to $0.145 per common share. This was the fifth dividend increase in three years.

Advantage IQ continues its trend of earnings growth. The Company contributed $0.04 per diluted share to earnings in the third quarter of 2006, and $0.10 per diluted share on a year-to-date basis. Advantage's revenues increased by 25% for the first nine months of 2006, as compared to the first nine months of 2005.

On a year-to-date basis, Advantage processed bills totaling $8.1 billion, an increase of $1.4 billion or 20% as compared to the same period in 2005. The number of billed sites increased by approximately 36,000 or 22% during the 12-month period ended September 30 of 2006. Advantage's interest earnings on funds held for customers also increased, partly because of an increase in interest rates.

Advantage is considering certain strategic technology investments aimed at reducing the cost per bill and at keeping Advantage as an industry leader. These investments should create long-term savings, but may increase operating and capitalized costs in the short term through upfront expenditures. This could limit earnings growth through 2007, while enhancing Advantage IQ's long-term profitability. As such, we are expecting Advantage's earnings to be at the high end of 2006 guidance, but perhaps flat in 2007, even though we are projecting revenue growth to be in 15% range.

In the Other business segment the net loss increased, due in part to the tax adjustments that I previously mentioned. The negative effect of tax adjustments were partially offset by the improved performance of Advanced Manufacturing and Development, which does business as METALfx. That Company had positive earnings in each of the first nine months of 2006. This is a significant improvement from last year's results. I will remind you that our Other business segment absorbs some corporate overhead costs, and will likely always experience a small loss.

Now, looking at our 2006 guidance, we are confirming our outlook for Avista Corp. consolidated earnings in a range of $1.30 to $1.45 per diluted share. We expect Avista Utilities to contribute in the range of $1.00 to $1.15 per diluted share. If hydro and weather conditions in the fourth quarter of 2006 are normal, we would expect our utility earnings and our consolidated earnings to be at the high end of our guidance range.

The outlook for the Energy Marketing and Resource Management segment is a range of $0.20 to $0.30 per diluted share, excluding any positive or negative effects related to the required accounting for certain contracts and physical assets under management. We expect Advantage IQ to contribute at least $0.12 per diluted share, and our Other business segment to lose $0.05 per diluted share for 2006.

For 2007, Avista is initiating its guidance for consolidated earnings to be in the range of $1.40 to $1.55 per diluted share. The Company expects Avista Utilities to contribute in the range of $1.10 to $1.20 per diluted share for 2007. The outlook for the utility assumes, among other variables, near-normal precipitation, temperatures and hydroelectric generation, as well as the implementation of the PT update in Washington, as designed in April 2007.

The 2007 outlook for the Energy Marketing and Resource Management segment is a contribution range of $0.20 to $0.30 per diluted share, excluding any positive or negative effects related to the required accounting for certain contracts and physical assets under management. We expect Advantage IQ to contribute in the range of $0.13 to $0.14 per diluted share and the Other business segment to lose less than $0.05 per diluted share.

Now, I will turn the presentation back to Jason.

Thank you, Malyn. At this time, we would like to open the call up for questions.

(OPERATOR INSTRUCTIONS). Paul Ridzon, KeyBanc Capital Markets.

Your strategic review process with regards to Avista Energy -- how should we expect that timeline to unfold?

I think we talked about this on a number of calls. We have a hurdle rate for Avista Energy, a risk-adjusted hurdle rate of around 15%. You know they have not been reaching that, although they are doing better now.

We have got probably one of the most experienced and mature teams. They do a wonderful job. They manage over 3,000 megawatts of assets, and that number continues to grow. We now have storage not only at Jackson Prairie that they manage, but they also have storage in Montana. They manage assets and are doing a very good job of doing that.

The question that we have to answer is, in the long term, does this business -- are we a large enough company to manage the type of business that they will be doing? As we look at that, we have to look at all the alternatives. Can the business be done or structured differently? Are there those that could better hold this business and provide the opportunity for the employees and for the customers that they serve to be more financially strong in the market? Those are the kind of questions we continue to ask and continue to look at, so there really isn't a long-term timeline on it that we're going to come to a decision by any particular point. We continue just to look at that and see if it's a fit.

How much deadband did you the eat in the quarter?

We're checking, Paul. Just a second.

$3.8 million.

$3.8 million, Ann says.

Is there a way to get a split at trading results between asset optimization and point-of-view trading?

I'll let Dennis answer that.

That is a little difficult to do, because we manage our assets with our trading portfolio kind of as a combined portfolio. I think we’ve answered this question before.

Really, what we try to do is look at how we have done historically. When we budget year over year, those asset management-related activities generally make up about 60% of our margins, with the remaining being trading.

If you look at our performance over Q3, we had strong performance in our power group, which I would say was more heavily weighted towards trading. However, our natural gas group also had a nice turnaround on the trading side from last year. But also, we're able to optimize assets and lock in end-use customers. So the higher percentage for the quarter came from, I would say, more the recurring margin type activities.

So that's not a very good answer, I think, but it is difficult to try to segregate those. I would just point out how we have performed in the past, and I would say that this year is similar to how we have done in the past, with 60% coming from assets.

The headwind that you're seeing at Advantage in 2007 leading to flattish results -- can you quantify that in cents per share?

In a normal year, we would expect to see Advantage growing in the $0.02 to $0.03 range. We're really looking at, most likely, fairly flat. You see the guidance increased a little bit year over year, but I would expect that there are going to be really right up at that high end of guidance this year, and then just a very modest growth next year from that.

Eric Beaumont, Copia Capital.

On Rathdrum, can you quantify what the proceeds were? Have those proceeds already been used as far as paying down debt with regard to the utility or anything else?

$18 million proceeds.

Secondly, just on your guidance for next year, if I think about the PT update, and obviously it's a request for the $10 million in gross margin you're talking about, I can make assumptions and how much you get and go there. I think about interest savings that you may have, and I understand that there's some additional regulatory lag. I guess I would come up with a number that would indicate maybe you have a little bit more regulatory lag than I had expected in my numbers, given your guidance. Can you just kind of frame things around there, if I am looking at the -- you are going from $1.10 to $1.20 versus the $1.00 to $1.15 in the utility. You have a potential $10 million margin pickup, if you get all of it, which obviously you're assuming some fraction there, some interest savings and others. Can you just walk me through what you're assuming in a kind of additional regulatory lag and organic growth for the utility?

Sure can. We see a couple of things happening that cause us to maybe not see as much growth as you might expect with that PT update.

First, we forecast based on normal hydro conditions and normal weather, and you see us expecting to get a benefit from the ERM this year. Going into next year, that's an open question where we're going to end up in the ERM balance. So I think you need to make an adjustment there.

Secondly, we are spending quite a bit more on rate base than we're recovering in depreciation, so the regulatory lag next year -- we're probably going to spend a little bit more capital budget than the $160 million this year. It could very well be up in the $170 million to $175 million range. So we will get some regulatory lag that causes our earnings to be a little bit depressed then just basically getting the PT update and flowing it all to the bottom line. So, long-term year over year, rate base should be growing around 5%, and one would expect that we could take that to the bottom line on utility earnings.

Obviously, you haven't actually done it yet. But do you have an expectation built in for interest savings that's in the guidance already? Or with regard to the two issues that you're going to be -- that are maturing and you are going to be replacing? Or are you waiting to see what prevailing rates are at that point?

Actually, we expect that we will -- basically, what we're doing with the PT update is we're reflecting financings that have been done and passing that back to our customers. So that really isn't a part of the equation, I think, on the earnings growth.

James Bellessa, D.A. Davidson Company.

First of all, I'm going to ask about this year's guidance, 2006's guidance, of about $1.30 to $1.45. You have also indicated that you still have marked-to-market losses year to date of $3.7 million or $0.07 per diluted share, and that you don't expect them to influence the fourth quarter. They do not, evidently -- are realized in the first half of next year. Is that correct?

On the $3.7 million, if nothing changes during the fourth quarter, that's right; the majority of that would reverse in Q1 or Q2 of next year. But keep in mind, it's a function of forward market prices as well, and our storage capability at Jackson Prairie and in Montana drive that, as it has in the past quarters, along with there's other components as well. But that's a big driver this quarter.

So to the extent gas prices move, forward prices, we could see that move into the fourth quarter. It's just a function of what the market does.

Or it could be even more negative; it could go either direction.

It could go either direction. That's just the snapshot of where it was at the end of Q3.

Gas prices at the end of September were very low. If they were to go back to just reasonable levels in the fourth quarter would that inherently cause you to have a marked-to-market decline in the fourth quarter?

Yes. That would intuitively drive a GAAP loss that wouldn't necessarily be an economic loss.

Now, in the $1.30 to $1.45 guidance, have you stripped out any of these marked-to-market activities?

No, we look at that on an economic basis and we don't look at, necessarily, the GAAP impacts as a result of changes in market prices.

Now, you're indicating that if the weather is normal and the precipitation is normal in the fourth quarter that your utility will be at the upper end of the guidance range?

That's correct.

That suggests -- you have got $0.88 under your belt right now for the utility. $1.15, the upper end, would suggest that the fourth quarter is a $0.27 quarter, approximately. But last year's fourth quarter was $0.34. Can you tell us why utility results in the fourth quarter this year are likely to be down in comparison to last year's fourth quarter?

A lot of that has to do with the weather. You remember, we had a really, really cold December last year, well below normal.

We had good precipitation in the fourth quarter of last year.

In the fourth quarter, starting in September, going on. So things matched up to make the end of last year very good. So we look at, then, fourth quarter this year and saying, what is normal? Of course, as you look out across what some of the weather forecasters are suggesting, light El Nino's and other things, you take all that into account when you make your estimates going forward.

There was one other factor, too. We had very strong hydro conditions in the fourth quarter of last year -- lots of rain. So we ended up going from right at the top end, I think, of the ERM hit and recovering some of that in the fourth quarter, as I recall.

You don't remember how much the ERM benefit was?

I'll have to get that for you.

Remind me -- I'm sure I've asked this before. What is the equity position of Avista Energy? How much do you have invested?

Approximately $200 million.

Your guidance this year and, now, next year for the first time is one and the same, $0.20 to $0.30. Why no improvement year over year?

As you know, it's just the nature of the business, being a function of the market in many ways. It's very difficult to forecast what our earnings will be. We have a portfolio of assets, as Gary alluded to earlier. Basically, that makes us long optionality, which really depends on market volatility and prices, to see how much money we could make off those. On the trading side, its basically take what the market gives you.

So it's difficult to predict. If you look at our economic results for this year, we're already at the high end of that range through the third quarter. So what we're doing for next year is just sticking with the same thing. It's a conservative estimate. I would expect to, again, be on the high range or even exceed that in a good year for us.

If I take $0.20 to $0.30 and put it into a dollar amount, that's $10 million to $15 million, I think.

Sounds about right.

Then if I divide that, divide your equity position of $200 million, you're a return on that business of 5% to 6%. Is that --?

I think it's actually maybe a little bit better than that, but that is still not sufficient, to go back to Gary's earlier comments, where our targets really are in the midteens. We have not been able to achieve those over the last couple years.

I guess I misstated. It was 5% to 7.5%, by my calculation. The Company says that the holding company formation, if completed, would not be completed earlier than mid 2007. Has that been pushed out now?

Yes, it has a little bit. We actually, as we have the Washington and Oregon set times for their hearings and such, we don't expect to get orders until probably sometime in April or May, that general range.

May. Gary is correct; it's May of 2007 when we will get final rulings from our commissions in Oregon and Washington.

It looks to me like this Other had something in there -- tax, extra tax that they had to pay or something? Can you go through that?

Yes, we actually booked an additional $400,000 in income tax that related to audits that were done and completed from 2005 as well as the IRS, I think, completed audits of the years 2001, 2002 and 2003. There were certain deductions that were taken in the Other category back in 2001 and 2002 as we closed down a couple of the subsidiaries that we ended up reversing, versus in the utility, we actually had some additional deductions that we were able to take and claim.

So we saw a net benefit of $1.3 million to the bottom line, $1.7 million positive to the utility and $400,000 loss. Of course, that's taxes, so it's after-tax; that's the bottom-line impact to net income that hit the Other category.

In the Other category, you say that you had a loss from operations pre-tax of $46,000, and then your net loss is $1.1 million. You just explained that $400,000 of that differences is tax. What is the additional $600,000 attributed to? Somewhere between the line item for loss from operations down to the net loss line item.

We're going to have to get back to you on that. I don't know the answer off the top of my head.

(OPERATOR INSTRUCTIONS). [John Hanson].

The hydro relicensing costs we were talking about earlier -- what kind of costs are included in that? Those were fairly large numbers. You said they were over a long period of time.

In the hydro relicensing case there're a number of things that FERC considers, everything from water quality to cultural resources to recreation. There're a number of issues through that. You do scientific studies, and anything that impacts hydro or impacts the river from the hydro dams is included in that. Obviously, there's a lot of room for negotiation and consideration in the science, and that's really what happens if you do an environmental impact study. You work with other agencies and you come up with different mitigation strategies.

The costs that you were talking about were the costs of the mitigation strategy?

Yes. The costs that we're talking about were the mandatory conditions imposed on the Post Falls dam from the Department of Interior, that number. If you take their number of their mandatory conditions, as well as the number that we made around recommendations, the number was $500 million. Again, we think that's a highly unlikely number, and that's why we're going to the ALJ through the Department of Interior and using the process that was set up in the EPAC in 2005.

But that $500 million is some CapEx that needs to be done (multiple speakers)?

I would suggest there're a variety of things that's in there. Again, it would be doing things around cultural resources around Coeur d'Alene Lake, around erosion mitigation, around recreation, around water quality, around fisheries. There're a number of things that are in there. Again, I would tell you that's a worst-case, high-end number. We felt like again, it's an opportunity for us to go before the judge and get the facts fixed as far as what those costs might be.

If you remember, when we licensed the Clark Fork River, the number there looked pretty big, but it spread out over 45 years. So even a couple of million dollars a year adds up to large numbers on that timeframe. But it's everything from building fisheries on the Clark Fork, doing the fisheries, buying wildlife habitat to doing all those kinds of things. The thing I would mention is it's part of the cost of operating the dam. In the past, all those costs have been included as part of the production costs, and therefore included in rates that our customers would pay.

Do you keep the same MW/MW hour kind of thing, or also there are some adjustments to that, possibly?

At this point, what we're trying to do is make sure that we don't lose any generation out of the facility. That's obviously a big part of what we try to accomplish through the relicensing process.

Paul Ridzon, KeyBanc Capital Markets.

As gas prices have softened up a little bit, how aggressive has your procurement been for hedging purposes for next summer's load? Have you contemplated that in your guidance?

On the utility side, as you know, the prices have come off quite nicely for the wintertime this year, but as we look at the forwards for next winter, they have not come off. So while they have mitigated a little bit, they have not really come off to the same level that we're seeing this year. So at this point in time, we're contemplating the same hedging philosophy and schedules that we have always taken, which is to average in over a period of time. We will continue to look at that. If there's opportunities and the forwards continue to fall in 2007 in 2008, of course, we will take advantage of that.

The other thing I might just add to that, just as a reminder, that none of those gas costs either take away or add to our margin or net income. They're strictly pass-throughs to our customers.

I was thinking more along the lines of generation fuel.

Oh, on the generation fuel.

On the generation fuel as well, again, we're taking advantage of what we can for this year. But again, forwards have not really come off enough, and we will continue to look at our loads and our resources and hedge appropriately when we see an opportunity for Coyote.

We have factored the very latest curves into our guidance.

Any update on what weather and hydro you have seen quarter to date in 4Q?

Well, third quarter was below normal for hydro, but we're expecting and hoping for normal hydro in the fourth quarter. It's going to rain this week, so we will continue to hope for normal hydro in the fourth quarter.

How was October?

October was just a little drier than normal. We have had a dry August, September and October. But we're heading into a rainy pattern this next week. As Gary said at the outset, it's really cold. I think it was 15 degrees this morning.

If you look outside, there's snow on Mount Spokane and that's always a good sign.

We're optimistic.

Did you say 15 degrees?

15.

Oh, my gosh.

James Bellessa, D.A. Davidson Company.

Your Energy Marketing and Resource Management segment has $0.18 year-to-date earnings. If we strip out the marked-to-market activity, you can add $0.07 back, if I'm understanding correctly. You're at $0.25 right now.

That's correct.

So you are really saying you don't know which way the rest of the quarter is going, when you give guidance of $0.20 to $0.30.

We're being very conservative on (inaudible).

I would now like to turn the presentation over to Mr. Jason Lang for any closing remarks.

I want to thank you all for joining us today. We certainly appreciate your interest in the Company. As always, if you have any follow-up questions, please feel free to contact me at 509-495-2930. Again, thank you for joining us and have a great day.

Thank you for your participation in today's conference. This concludes your presentation. You may now disconnect and have a great day.