Avista Corp (AVA) 2005 Q4 法說會逐字稿

Good day, ladies and gentlemen, thank you for standing by and welcome to the Avista Corporation's fourth-quarter 2005 earnings conference call. My name is Carlo and I will be your coordinator for today's presentation. At this time, all of our participants are in a listen-only mode. We will be facilitating a question-and-answer session towards the end of today's presentation. (OPERATOR INSTRUCTIONS) I would now like to turn the presentation over to your host for today's conference, Jason Lang, Manager of Investor Relations. Please proceed, sir.

Good morning, everyone. Welcome to Avista's fourth-quarter and year-end 2005 earnings conference call and webcast. Avista's earnings were released pre-market this morning, and the release is available on our website at AvistaCorp.com.

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

As part of today's presentation we will be using some slides which can be found on our website under the investors section. We do notice that we're having some problems with the slides this morning; so if you could just click on them, you should be able to download them that way. There will also be a replay of today's call 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 and involve risks and uncertainties which are subject to change. For 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 2004 Form 10-K and Form 10-Q for the quarter ended September 30, 2005, which are available on our website.

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

Thanks, Jason, and good morning, everyone. We are pleased with the results from our utility operations for 2005, which improved considerably as compared to 2004. In late December, the Washington Commission approved the settlement agreement reached in our Washington general rate case, with certain conditions. We believe the settlement agreement strikes an appropriate balance between providing reasonable rates for our customers and reasonable returns to our shareholders.

However we're disappointed that the Commission did not decide to adopt the portion of the settlement that would have reduced the energy recovery mechanism, deadband, from 9 million to 3 million. Scott Morris will discuss this later in the call.

We are encouraged by the continued positive results for Avista Advantage, which showed significant improvement from 2004 and exceeded our expectations.

It was a difficult year at Avista Energy, which had a net loss for the year, primarily due to losses in natural gas trading. As you will recall, Avista Energy incurred a significant loss during the first nine months of 2005, related to the required accounting for the management of natural gas inventory. The majority of this loss was recovered during the fourth quarter. Dennis Vermillion will have further explanation of this later on the call.

Since our last conference call we have made some changes to our officer team. In November the Board of Directors elected Karen Feltes as Senior Vice President and Marian Durkin as Chief Compliance Officer. Karen is responsible for human resources and is also our Corporate Secretary. Marian serves as Senior Vice President and chief legal officer for the Company.

In January, we announced the appointment of Christy Burmeister-Smith as Vice President and Treasurer, and Ann Wilson as Vice President and Controller. Christie was previously Vice President and Controller for Avista Corp.; and Ann was previously Vice President and Controller for Avista Energy. We're fortunate to have this team of talent at Avista.

In a brief look ahead at 2006, we expect improvement in our consolidated earnings primarily as a result of a return to positive earnings for the energy marketing and resource management segment. Malyn Malquist will provide more specific earnings guidance later in the call.

Now I would like to turn this call over to Scott Morris for his report. Scott?

Thanks, Gary, and good morning. Avista Utilities contributed $0.34 per diluted share for the fourth quarter of 2005, compared to $0.41 per diluted share for the fourth quarter of 2004.

For the year of 2005, Avista Utilities contributed $1.07 per diluted share, a significant increase from the $0.67 per diluted share the utility contributed in 2004. You will recall that results for 2004 were adversely affected by write-offs related to the Idaho general rate case order last year, which totaled approximately $0.19 per diluted share.

The decrease in our fourth-quarter 2005 results was primarily due to an increase in certain operating costs. The improvement in our annual results, however, was primarily due to the general rate increases implemented in the second half of 2004, and partially due to the gain on the sale of our South Lake Tahoe natural gas properties.

As we expected in our forecast for 2005, we absorbed the entire $9 million deadband under the Energy Recovery Mechanism in Washington. Slide 4 shows where we were in each month of 2005 with respect to the deadband. As you can see, we had only absorbed $4.8 million of the deadband through November 30. A cold December, combined with seasonably low hydroelectric generation and high fuel and purchased power costs, caused us to absorb the remaining $4.2 million in December.

For the full year of '05, total electric resource costs exceeded the amount included in base rates by $18 million, of which $9.9 million was absorbed by Avista and $8.1 million was deferred for future recovery from customers.

Based on recent snowpack surveys, we are expecting hydroelectric generation to be slightly above normal in 2006. We started off the snow season with good snow accumulations in November. This was followed by an unusually cold and dry period through about the third week in December. We then entered into a period of above-normal precipitation and temperatures.

Some of you may have read about record precipitation in the Pacific Northwest, and this is true; but it has not translated into snowpack conditions that are that much above normal for our region, partially due to warmer than normal temperatures.

Take a look at slide 5. This shows precipitation throughout the Pacific Northwest from October 2005 through January 2006. As you can see, precipitation has been well above normal in our region.

So how does this translate into snowpack? Slide 6 shows the snow water content as a percent of average for various locations in the Western United States as of February 7, 2006. Our generation is derived from the mountains of Northwestern Montana, Northern Idaho and Northeastern Washington, which are generally in the range of 90% to 110% of average.

Although this is good and an improvement over recent years, it is just about average. There is not as much snowpack in our basins as in other parts of the Pacific Northwest. However, it's important to remember that conditions can change substantially throughout the snow season and the year.

Our forecasts will change throughout the year based on precipitation, temperatures, and other variables. For example, last year at this time, you will recall that we were forecasting 2005 hydroelectric generation to be well below normal. However, due to a wet and cool spring and above-normal precip for the last nine months of the year, hydroelectric generation ended up being 95% of normal for the year.

As I mentioned earlier, temperatures in our service territory were warmer than normal in January 2006. This had a negative effect on our retail electric and natural gas loads for the month.

In December, the Washington Utilities and Transportation Commission approved our combined electric and natural gas general rate case settlement agreement, with certain conditions, which were subsequently accepted by Avista and other settling parties. The WUTC ordered provided base rate increases of 7.5% for electric, and 6/10 of 1% for natural gas effective January 1, 2006.

It's important to note that the majority of the increase in electric revenues is related to increased power supply costs. As such, a significant part of the increased electric revenues will not increase our gross margin or net income, because it will be matched by an increase in cost.

As part of their order, the WUTC rejected the proposal in the settlement agreement to reduce the ERM deadband from $9 and to $3 million. However, as directed in the WUTC order, we made a filing with the Commission on January 31, proposing that the ERM be continued for an indefinite period of time and that the $9 million deadband be eliminated. The elimination of the deadband would reduce the volatility of our earnings that has been caused by variations in hydroelectric generation, as well as prices for fuel and purchased power.

The Commission indicated in its order that it would provide for an expedited process to allow for a determination of any changes to the deadband or any other aspects of the ERM in early 2006. The Commission also stated that any changes to the ERM ordered in 2006 would be effective for the full year.

I would like to draw your attention to slide 7, which shows our authorized overall rate of return, return on equity, and equity levels in each of our jurisdictions. Since October 2003, we have received general rate increases in each of our jurisdictions. We regularly review the need for electric and natural gas rate changes in each state in which we provide service; and we will continue to file for rate adjustments as needed to provide for recovery of our costs to more closely align earned returns with those allowed by regulatory agencies in each jurisdiction.

In response to increases in wholesale natural gas prices in 2005, we received purchased gas cost adjustment increases of 23.5%, 23.8%, and 22.5% in Washington, Idaho, and Oregon, respectively. These natural gas increases are designed to pass through increases in purchased natural gas cost to customers, with no change in our gross margin or net income. While those rate increases are large, they are generally less than those being experienced in other regions of the United States.

We continue to be concerned about the impact that increasing rates have on our customers. In fact, as part of our rate case in Washington, we increased funding levels for two of our existing programs aimed at assisting limited-income customers; and we provided additional funding assistance to Project Share, our region's energy assistance program.

In 2005 we had net growth of approximately 7,000 electric customers and 11,000 natural gas customers, excluding the sale of our South Lake Tahoe operation. We continue to be committed to investing in our generation, transmission, and distribution systems in order to meet our load growth needs and to continue to provide reliable service to our customers.

Our utility capital expenditures in 2005 totaled approximately $210 million, which included the acquisition of the remaining 50% interest in Coyote Springs 2 and the continuation of the project to enhance and expand our transmission system, which is expected to be completed in 2007.

For 2006 we have a utility capital budget of approximately $160 million. Significant investments for the year include the continued enhancement of our transmission system, ongoing installation of advanced meter reading technology, and upgrades to our generation facilities.

We are systematically upgrading our hydroelectric plants to increase their availability and capture additional output. Currently, plans call for upgrading one unit each year for the next five years.

In October, we submitted the 2005 Electric Integrated Resource Plan to the public utility commissions in Washington and Idaho. We are forecasting quarterly energy deficits to begin in 2007, with annual energy deficits anticipated to begin in 2010.

Last month, we issued a request a Request for Proposal to add approximately 35 average megawatts of long-term renewable energy supply, to begin in the fourth quarter of 2007, to help fill this projected energy deficit.

We have also recently entered into an agreement with Idaho Power to jointly investigate possible future coal-based generation resources.

In summary, we are embarking on some significant capital investments, particularly for a company of our size. We're planning in advance to bring additional resources online to upgrade our generation, transmission, and distribution systems and to continue to provide reliable service to our customers.

With that, I will turn the call over to Dennis Vermillion for 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 fourth-quarter 2005. This business segment had a net loss of $0.18 per diluted share for the year 2005.

Net income for the fourth quarter of 2005 was primarily due to the recovery of unrealized losses recorded during the first nine months of the year, which were related to how we have to account for our management of natural gas inventory.

The differences in the economic management of our business and the required accounting for certain contracts and physical assets under management were discussed at great length in our conference calls last year. These differences, which primarily relate to our management of natural gas inventory and our control of natural gas-fired generation through a power purchase agreement, had a positive effect of $12 million on earnings for the fourth quarter of 2005, primarily as a result of decreases in natural gas prices.

In our call last quarter, we noted that if natural gas prices stayed at the same level as September 30, we would expect $0.25 of earnings per share to be recognized in the first quarter of 2006. As natural gas prices decreased in the fourth quarter of 2005, we recognized a large portion of the $0.25. So, essentially the net loss of $0.18 per diluted share for 2005 was almost the same as our economic results for the year.

Last week, we made the decision to sell our natural gas inventory forward for delivery in the first quarter of 2007. This transaction will allow us to capture approximately $2.70 per MMBtu of value; and it represents a time spread which is among the widest we have seen in the marketplace.

This forward sale will have to be marked-to-market in 2006, and it will undoubtedly result in earnings volatility even though we have the natural gas in storage to deliver on the sales. However, this decision is part of the prudent economic management of our assets.

This business segment's net loss for the fiscal year 2005 was primarily due to natural gas prices moving counter to our trading positions. As markets moved against us, we acted to adjust our position consistent with established risk management practices. This liquidation process reduced our market risk, but had the effect of locking in losses that were recorded during 2005.

Even though we scaled back our natural gas trading portfolio considerably in the second half of 2005, some losses did continue to occur during the fourth quarter, as we continue to unwind our positions that we established in earlier periods.

Although annual results for our electric side of the business declined as compared to 2004, it continued to produce positive results for 2005. We continue to explore opportunities to expand our business of optimizing generation assets owned by other entities. For example, we have recently been selected to manage the generation assets of Columbia Power Corporation, located in British Columbia, beginning in 2007. CPC will be a good addition to the portfolio of assets that we manage.

We're ready to put the losses of 2005 behind us, and we are expecting a profitable year in 2006 for a number of reasons. For example, we have already substantially covered the demand charges of our Lancaster power purchase agreement for 2006, which is well ahead of where we have been in past years. We also continue to expand our profitable asset optimization business and our natural gas end-user business.

We have refocused our natural gas trading business and we expect it to return to profitability during 2006. We have more closely aligned our natural gas and electric trading activities in an effort to improve coordination and communication between the groups.

As an energy marketing and trading company, the very nature of our business results in some earnings volatility and some difficulty in forecasting results. I believe it is important to look at this business over the longer term. Although 2005 was disappointing, it was our first net loss since 1999, and we have demonstrated a strong track record over the last several years.

Now with that, I will turn it over to Malyn Malquist.

Thanks, Dennis, and good morning, everyone. As you can see in slide 10, Avista Corp. reported net income of $25.4 million or $0.52 per diluted share, for the fourth quarter of 2005, compared to $22.6 million or $0.46 per diluted share for the fourth quarter of 2004.

For the year 2005, net income was $45.2 million or $0.92 per diluted share, compared to $35.6 million or $0.72 per diluted share for 2004. On an annual basis we showed improvement for Avista Utilities, Avista Advantage, and the other business segment, offset by a decline for the Energy Marketing and Resource Management segment.

Scott and Dennis have already outlined the most significant items that affected earnings for Avista Utilities and Avista Energy. I would like to take a couple of minutes to discuss the operating costs of the utility; an overview of financing activities, cash flows, and the performance of Avista Advantage; as well as our earnings forecast.

As was mentioned earlier, the primary reason for the decrease in Avista Utilities' net income for the fourth quarter of 2005 as compared to the fourth quarter of 2004 was an increase in operating costs. Part of this was due to an increase in depreciation expense, related to significant utility plant additions. Part of the increase was also due to administrative and general expenses.

We continue to focus on restoring an investment-grade credit rating for the Corporation. While this process is taking longer than we had hoped, we believe that we're on the right track. Our total debt outstanding increased approximately $40 million in 2005, primarily to fund utility capital expenditures that were in excess of our operating cash flows.

As Scott mentioned earlier, our most significant capital expenditures were the acquisition of the remaining interest in Coyote Springs 2 and transmission system enhancements.

Also, during the fourth quarter we made the decision to terminate the lease agreement and repurchase our corporate headquarters and central operating facility in Spokane. These actions are being taken to serve the needs of our customers and do so in the most cost-effective manner.

Although our debt levels have increased slightly, we have been able to control our debt service costs through multiple actions over the past years, including the repurchase of higher-cost debt and the issuance of new debt at relatively low interest rates.

During the fourth quarter of 2005, we issued $150 million of 6.25% First Mortgage Bonds that mature in 2035. The proceeds from the issuance were primarily used to repay short-term borrowings under our $350 million committed line of credit. This issuance was larger than we had originally planned, but we believe it was prudent to take advantage of the capital available at relatively low interest rates.

Also, in November, the Board of Directors increased the quarterly dividend by $0.005 to $0.14 per common share. This was the fourth dividend increase in three years.

As Scott method earlier, in December the WUTC issued an order approving the settlement agreement reached in our Washington general rate case, with certain conditions. We 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 these targets could result in a reduction in base rates of 2% for each target. As a point of reference, our utility equity component was approximately 31% as of December 31.

Beyond our expected earnings, we are currently evaluating additional ways to increase our equity ratio. Such measures could include delivering original issue shares under our equity compensation and dividend reinvestment plans, as well as possibly making small common stock issuances from time to time through underwriters or agents. Our regulators have approved the issuance of up to 2 million shares of common stock from time to time over the next two years.

At Avista Advantage, 2005 was a year significant improvement. Advantage contributed $0.02 per diluted share to earnings in the fourth quarter and $0.08 per diluted share for the year. This exceeded our original guidance of $0.05 for the year.

As indicated in slide 11, Advantage has shown good growth in its net income since 2001. We continue to be pleased with the performance of this company. Avista Advantage's revenues increased by 35% for 2005 as compared to 2004. While the average cost of processing a bill decreased by 6% for the same period, the number of billed sites increased by over 33,000 or 24% in 2005.

This business continues to have strong client retention as demonstrated by a 95% retention rate over the past three years.

Avista Advantage acquired TelAssess Inc. early in 2005. Although this was not a significant financial transaction, this acquisition provides Advantage a foundation on which to expand beyond existing utility bill information services, to provide similar services relating to telecom expense management.

As you can see in slide 12, we are confirming our 2006 guidance for consolidated earnings in a range of $1.30 to $1.45 per diluted share; and we expect Avista Utilities to contribute in the range of $1.00 to $1.15 per diluted share. If the ERM deadband remains at $9 million for 2006, the Company expects Avista Utilities' earnings to be at the lower end of this range. The outlook for the utility assumes, among other variables, normal weather, temperatures, and hydroelectric generation for the year.

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 of changes in prices on the required accounting for the management of natural gas inventory.

In our previous conference call, we disclosed that an additional $0.25 of earnings per diluted share could be recognized at Avista Energy during the first quarter of 2006. However, primarily due to changing natural gas prices, the large majority of this $0.25 was recognized during the fourth quarter of 2005.

We expect Avista Advantage to contribute in a range of $0.10 to $0.12 per diluted share and the other business segment to lose about $0.05 per diluted share for 2006. Now I will turn the presentation back to Jason.

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

(OPERATOR INSTRUCTIONS) Paul Ridzon with KeyBanc.

You talked about capturing a $2.70 spread on the gas. Can you tell us the volumes associated with that and what that equivalent spread was in the prior-year period?

Good morning, Paul. We will let Dennis handle that.

Good morning. We talked about $2.70 per MMBtu. Our current volume that we have at JP Storage is roughly 2.7 Bcf. So if you can do that math.

That spread of $2.70 is large, compared to what we have seen in years past. I think last year we saw probably a half, roughly half that in capturing the economic value of that asset. There has been years where it's been less than that. So it was really a very smart economic move on our part, we believe, to capture that spread, because it was such a large one.

When will you realize this? Is this an '07 income statement impact or '06?

We rolled the storage to first quarter of '07.

So actually delivery will be '07, and then that is when you will realize it?

That's correct. As the current market sits today, if we don't change that, it would be first quarter of '07.

Then, every quarter we have kind of a residual hangover from exiting gas trades. Are we done with that?

Yes, the residual gas trades that caused the losses during the hurricane event are essentially done with. They're closed out. We do, however, continue to actively manage our assets and service our end-use customers. So we are trading around gas transportation, trading around the storage, as I mentioned, and buying gas for end-use customers. So there's still some trading activity associated with that.

Paul, this is Malyn. Dennis, that trading is not speculative in nature, which is what caused the past losses.

That trading is not associated with our substantial term spec trading activities, which -- you're right, Malyn -- was associated with our losses earlier during last year.

Just switching gears, you are talking about maybe partnering with Idaho Power on a coal plant. Are there I guess regional environmental concerns that might force you to one technology? Or are we too early to be thinking about -- am I getting ahead of myself there?

Maybe Scott can answer that question for you, but certainly I would say we are fairly early in the investigation, and that is really what the agreement is. It's to get together and figure out where location, what type of equipment and stuff should be done. Scott, you have anything?

The only thing I can add, Paul, is that we continue to look at new technologies. Right now we have no interest in being a beta site for some of those new coal technologies. However we continue to investigate and look for opportunities, have consultants hired, and we will look at those opportunities.

But again, we don't see coal being a part of our future till well after 2010, probably in 2013 range. So we have time to continue the investigation.

Maybe they won't be beta sites anymore by then.

That is our hope.

All right, thank you very much.

Doug Fischer with A.G. Edwards.

Just, you have talked about a variety of things in the past about your gas trading, given the disappointing results in '05. Obviously this transaction that will be delivered in '07 is a positive. Would you talk to us about where you are at in your thinking about that? To what degree will you be involved in speculative trading?

And if not -- and I don't know if there is a bright line between speculative trading and the rest of it; I think it is a continuum. And then if not, can you earn a reasonable return on the equity invested in that business?

Then maybe you can talk a little bit, electric lost some money in the fourth quarter. Talk to us about that. Was there something unusual going on there?

Doug, I think I will let Dennis answer most of those questions. He's running that business. I would just say that, you know, your question that was kind of in the middle of the bunch -- around can we earn a reasonable return on it -- that is one of the things that we are evaluating and trying to do. I guess take a kind of a forward look on.

What I would say is they are positioned very well for 2006. And probably I think they're are in better position than they have in any of the years of the 2000 series, because of what they have done, both with our Lancaster plant and the heat rate, as well as the other positions that they are in, in various places. So I think 2006 will have them back on the right road.

But to answer your question about that, I don't believe that they will be where we would like them to be on a risk-adjusted rate of return in 2006. I think that is something that we have to look at for the long term, and just ask ourselves -- can they get there? And if not, is this a business that we want to stay in long term? But certainly for 2006 I think it is.

And I think Dennis can address your other questions.

I will start with the question on the electric. We actually had a very good year in our electric side of the business. We were profitable from a gross margin standpoint 11 out of the 12 months of the year. The last month, we had some positions -- or prices went against some of the positions we had in place and we unwound those.

So in the earnings release we talk about a loss in electric. If you look at the actual numbers, it was a slight loss. We ended up -- if you round it, it is basically zero earnings per share impact from our electric business in Q4.

So that is going to happen, that is the nature of the business. To have 11 out of 12 months where you are profitable is quite remarkable, really. So I have no concerns or issues around that.

Let's see, your other question, Doug? Gas trading. Obviously it was a disappointing year from our gas group. We had a handful of -- or three major strategies that didn't work out for us.

However, I think it is important to point out that the success of that group over the long haul has been very favorable. We have made probably roughly $130 million of gross margin from that line of business over the last six years. That includes the contribution or the loss from last year.

So I would encourage people to consider that and look at their results over the long term. Now, does that mean it's business as usual going forward? No, certainly it does not.

We have made some changes internally, as I mentioned earlier. We have combined the groups to better coordinate and communicate between the power side and the gas side. We in hindsight -- hindsight being 20/20 -- we've taken a look back in '05 and identified some of the things that we did wrong and some things that we can improve upon. And we are preparing to make those adjustments and move forward.

Obviously, it won't be business as usual. We will try to rein in some of the limit structures; or we will rein in some of the limit structures we have in place with regard to stop-loss, [scanner], total contracts by location, that kind of thing.

Some of the things that really bit us in '05 ended up having larger positions than we should have at very liquid points, out over the forward curve. So we will be taking steps to protect against that going forward.

Okay, thank you, Dennis. Scott, maybe you can talk a little bit finally about rate case strategy. You touched on this. But you know, you are experiencing ongoing regulatory lag even with relatively -- certainly very new rates in Washington, and not too long ago, rates reset in Idaho.

How quickly might we see you move to deal with that issue? And then, an update on the schedule for the ERM consideration?

Doug, first, Kelly Norwood does an outstanding job for us in our rate area, as you know. Kelly is in the process of doing a rate cast for all of our jurisdictions, and he should have that completed sometime this spring. When we get those rate casts done, we will go ahead and make an evaluation on what it looks like in each jurisdiction.

At this point, we don't anticipated anything for 2006. But we will continue to evaluate, and we will always go in if we need to.

Preconference hearings for ERM filing starts on February 22; so at that point we will have a more clear view on the time frame from the Commission on how fast we can get a ruling on our ERM.

Thanks; that's it.

James Bellessa with D.A. Davidson.

On the ERM deadband issue, you won't have a decision in the first quarter likely. Is that correct? If not, what do you do when you report your first quarter? Do you start eating into the full deadband and report it as that way? Then if the Commission allows you to eliminate the deadband, then you reverse that at sometime in later quarters?

Jim, we will not have a ruling from the Commission in the first quarter. I know that. But I'll let Malyn talk to you a little bit about the art of the deadband and how we expect it to work out.

The way we will handle that is we will have to book it as if we had the $9 million deadband in place. Because that is, in effect, what we have in rates currently. So until the Commission relieves us of that, that is the way it will work out.

As I think you know, at least early in the quarter our stream flow conditions are in pretty good shape, because of the precip that we have had. So the shape of the deadband, I think, could be a lot like it was last year, with first quarter probably recognizing some, but hopefully not too much, of the $9 million.

What does the temperature have to do with the deadband? You said that January was much warmer than normal.

The temperature really doesn't deal much with the deadband, other than sometimes when our customers are using less, we can sell some of our hydro to other customers; and that all flows through the deadband mechanism.

So on the one hand, warmer temperatures in January are lower gross margins for us. But on the other hand, to the extent we can sell that off, it means that we probably eat less of the deadband.

That's helpful. If you get a second quarter decision here, then do you restate first quarter? Or do you just do the reversal in the second quarter?

It will just show up as a reversal in the second quarter.

On the front cover of your press release you show revenues of $458.4 million; and down in the detail lower, you show the revenues by segment. But the revenue for the Avista Energy is not provided and you just show margins. What is the revenue contribution to the $458.4 million that comes from Avista Energy?

We're looking at that; hang on a second, Jim. I'm going to ask Ann Wilson, our Controller, to help us with this.

The revenue component for Avista Energy that is part of that 458 is 63.

You broke up there, 63 what?

63 197.

Thank you. Then on the contract that you put in place, you said it was at $2.70 for 1 million Btus, and for a year-long contract; and it was for all the 2.6 billion that you have in storage?

Yes, 2.7 billion.

2.7 billion?

But that is the time spread, the spread from this March to next Q1. That is the difference in price. And that is the $2.70 times 2.7 Bcf would give you the economic value generated from that transaction.

Now a few years ago, you had told us that you had changed your accounting so that you were able to specify each contract separately, so that you didn't have to get into this mark-to-market stuff. Am I wrong on that? Why isn't this contract under that new accounting?

This is Dennis. I'm not sure I am completely sure what you're talking about. But we used to be able to mark-to-market our storage. So there would not have been a difference between the economic results and the GAAP results that we record.

However, I don't know, probably four years ago, that accounting guidance was rescinded, which now creates the mismatch and creates the GAAP earnings volatility as we go through the year, as prices change.

Now we have implemented hedge accounting on our Lancaster power purchase agreement, where you can designate some of those hedges and remove them essentially from the mark-to-market volatility. It essentially moves those hedges to accrual accounting, which is the way we must account for the Lancaster PPA.

We are not able to -- because of the accounting rules -- apply hedge accounting completely for Lancaster. But we get part of the way there in removing volatility.

On the gas side, however, we have looked at other alternatives, and it just (technical difficulty) based on the hedge accounting rules, we can't put it in place. So we're going to have to live with that volatility that we see.

Jim, kind of the simple answer is the contract to sell the gas forward is a derivative, and you have to account for it, mark it to market under the FASB rules. The inventory is considered inventory in gas storage, and it can't be accounted for until it's pulled out of storage.

So it is [not] accrual based accounting. So it's really just a timing difference. But that is what the issue is.

So if that gas was sold at market, if the market goes up on gas, you will see a loss that we will record. If the gas prices go down, you will see a gain that we will record on GAAP earnings between now and when that actually comes out of storage. But the economic loss won't change.

The gas is there to back it up.

And the gas is in storage.

On Avista Advantage, you reported $922,000 of profits. You had been making sequential improvements in net income, and this 922 --.

That's a good thing, Jim.

Jim, what happened in the fourth quarter, we had three or four kind of what I would call onetime events that occurred. We brought in some outside help to examine how we process the customer bill payments, to see if we could take some costs out of the business. So there were some onetime expenses associated with that.

We had two major tradeshows which we attend to try to capture new clients. That is when that occurs during the year.

Then because we did so well, we had some fairly significant incentive payments that were largely booked in the fourth quarter for all of our employees at Avista Advantage. That is the result, that we saw some deterioration in that quarter. But we would expect the trend to get right back on track again in the first quarter.

Back on a growth pattern, but the fourth quarter you will have trade shows in the future and you will have incentive programs if this is a successful business as we expect. You won't necessarily have the consultants from outside. Is that true?

Yes, that's true. The two major tradeshows are in the fourth quarter (multiple speakers).

Pattern between the third and fourth quarters might not be always up then?

That's correct.

Yes.

Thank you very much.

(OPERATOR INSTRUCTIONS) [Stephen Gambuzza] with Longbow Capital.

I was wondering if you could provide what percentage of your energy marketing revenue came from external asset optimization contracts, roughly?

This is Dennis. If you take a look at what our targets are year-over-year, the term trading component that we target from both the power and gas side historically makes up roughly 38% to 40% of the margin target.

So the remainder of that, we do have some shorter term trading in our balance of the month, real-time activities on the power side. But also included in that is their optimization of our assets such as our relationship with Chelan, Cominco, our transmission, that type of thing.

Then on the gas side, we have our Canadian business, end-use business, our end-use customers in the U.S., storage, those types of things.

Is Lancaster, would that be -- that is included in there also, right?

Lancaster, typically we have budgeted that or targeted that to account for about 5% of our total gross margin.

Okay. I guess what I'm trying to get a handle on is just kind of the economics of the external optimization contracts that you sign, in terms of the -- I know it's a relatively -- not very capital intensive. But what types of margins, kind of operating margins, do you achieve on those contracts?

Are you able to continue to achieve that, for example, in the new contract that you signed up in Canada?

The margin off those transactions is not large for each one by themselves. But when you add them up, if you look at the portfolio of assets that we do manage, it starts to make a pretty significant contribution to the overall earnings.

You mentioned you have this new contract in Canada. Are you seeing -- are you currently pursuing additional external asset optimization opportunities? Or should we expect to see some more similar announcements in the quarters to come?

Yes, the CPC arrangement, actually we will not begin to optimize that until 2007. So we will not see any margin generated from that in '06. However, you're correct, that is one of the key business strategies that we have, is to go out and seek out those type of opportunities throughout the Northwest. Hopefully we will have some other good news for you later on.

Thanks. In terms of the -- on the regulatory front, I believe Malyn mentioned that the Washington regulator had approved the Company to issue 2 million shares, over I think the next two years. I wasn't aware that they have jurisdiction over security issuance. Is that in fact correct? They have to approve your financing plans?

They do. All of our -- and I think this is fairly typical for most utilities -- regulatory commissions approve financing, so we had to ask them for the authority to sell stock. And we do that for our debt also.

Okay. Then is there an ability -- as you talk about kind of the amount of capital you have invested in the utility versus what you have invested at Avista capital. Is there any ability to repatriate capital from Avista capital into the utility while still maintaining the earnings power of Avista capital?

Yes, there is, and we're looking at some alternatives around that. As Gary mentioned, that based on our forecast of earnings for Avista Energy this year, they're still earning a subpar ROE for where we would like them to be. One of the ways that you can fix that, besides increasing your earnings, would be to take some of the equity out of the business. We are looking at some alternatives to try to do that.

Okay. Finally on the coal plant opportunity that you're pursuing with Idaho Power, is there any -- when would actually -- when would capital actually start getting spent on that, if you were to pursue it?

Small amounts of capital will get spent in the next couple of years with engineering kind of plans and those kind of things. But the large majority would not happen till 2010.

Okay. Is there a third partner or is it just the two of you currently?

Right now there's two; but we're always looking for other investor-owned utilities, perhaps, that want to build as well. We are aware of other regional utilities that are interested, so we will continue to work with them.

Great, thank you very much for your time.

Paul Ridzon.

Is it too early to try to get a sense of what kind of elasticity response we may see from gas users?

It is probably a little early, especially since January was a very warm month, so it is going to take a little bit. Back in the energy crisis in 2000, we saw a fair drop early on, and then over the next two years it basically climbed back to where it was before. So we expect to see some downturn.

But at this point, they got their first heavy bill in December, and then January was really warm, so the bills were much smaller. We will have to kind of see whether we can even have any data points to project that for this winter. But it's a little early yet to tell.

How much equity is at energy right now?

$200 million.

What buckets is that in? How much is cash collateral?

We maintain a fairly significant amount of cash on the books at energy. Ann, can you be a little more specific?

Yes, we have approximately $45 million of cash at the end of the year. The rest of the equity is comprised of our mark-to-market portfolio primarily.

It sounds as though you're going to kind of keep plugging through '06. If there were another stumble and it was decided that maybe we need to rethink strategy, would it be a wholesale exit from that business? Or would it be selective components of that business? Would you continue kind of the asset management and optimization business? Or would you just kind of -- what is the thinking there?

I think it's a little early to talk about that. I think we certainly are looking at various alternatives. I think I have mentioned that before on one of the calls, that there are several different options.

Of course if somebody was interested in purchasing it and purchasing the whole business, we would have to look at that. Certainly there are components of it that's very profitable and we look at those things.

But as they are set up this year moving forward, I think they are going to have a fairly strong year. At least they're starting out that way. I'm looking forward to them getting back on track.

If they are not able to earn their returns long-term, then yes, we do have to make some other decisions. We will be evaluating that as we move through this year.

Okay, thank you again.

James Bellessa.

Your IRP calls for a coal plant win; or does it? Does your IRP even have a coal plant outlined in it?

Yes, it does, Jim. We have got a little over 400 megawatts of renewables in the Integrated Resource Plan and 250 megawatts of coal in the Integrated Resource Plan. The way we have it staged at this point is renewables first, coal second. So that is the way we're looking at it. Therefore that is why we're looking at a 2013 approximate date for the coal plant.

Thank you.

That concludes our question-and-answer portion for today's presentation. Ladies and gentlemen, I would like to thank you for your participation in today's conference. This concludes your presentation and you may now disconnect.

I want to thank you all for joining us today. We certainly appreciate your interest in our 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.