Avista Corp (AVA) 2005 Q3 法說會逐字稿

Good day, ladies and gentlemen. Welcome to the Third Quarter 2005 Avista Corporation Earnings Conference Call. [Operator Instructions]

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

Thanks, Bill, and good morning everyone. Welcome to Avista's Third Quarter 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; SVP, CFO, and Treasurer, Malyn Malquist, the President of Avista Utilities, Scott Morris; the President of Avista Energy, Dennis Vermillion; and Avista Corp. VP and Controller, Christy Bermeister-Smith.

As part of today's presentation, we'll be using some slides, which can be found on our website under the Investor section. There will also be a replay of today's call available on our website at 12:30 p.m. Eastern Time.

Before we begin, I'd 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. I would direct you to Avista's 2004 Form 10-K and Form 10-Q for the quarter ended June 30, 2005, which are available on our website for reference to the various factors, which could cause actual results to differ materially from those discussed in today's call.

Now, I'd like to turn this over to Avista's Chairman of the Board, President, and CEO, Gary Ely.

Thanks, Jason, and good morning everyone.

It's been a challenging year for Avista Energy. Due to the significant increase in natural gas prices, Avista Energy had a net loss for the quarter. As was the case during the first quarter, a significant portion of the net loss for Avista Energy was due to the GAAP accounting for natural gas inventory. Dennis Vermillion will have further explanation of this later in the call. As anticipated, our utility operations had a net loss for the third quarter of 2005. The third quarter is, historically, a weak quarter for our utility operations. This year's results were weaker than normal, due to higher electric resource cost and the absorption of excess cost under the Energy Recovery Mechanism dead band in Washington. This resulted in a dead band charge of $8.2 million for the third quarter, due to the reversal of the $700,000 benefit received during the first half of 2005. For the 9 months ended September 30, 2005, we continue to be pleased with the results from our utility operations, which improved considerably, as compared with 2004. We are also encouraged with the continued positive results of Avista Advantage.

In a recent legal development, I am pleased to report that on October 19th the United States District Court for Eastern District of Washington issued an order granting our motion to dismiss a shareholder lawsuit. You will recall that the complaint in this lawsuit was originally filed in September of 2002 and alleged violations of the Federal Securities Law through alleged misstatements and omissions of material facts with respect to our energy trading practices in the Western markets. The order to dismiss was issued without prejudice, allowing the plaintiffs 14 days to amend their complaint.

We anticipate a strong quarter, primarily based on expected performance of our utility operations. Looking ahead to 2006, we expect modest improvement for Avista Utilities and Avista Advantage, as well as a return to positive results for the Energy Marketing and Resource Management Segment.

Now, I'd like to turn this call over to Scott Morris for his report. Scott?

Thanks, Gary, and good morning.

Avista Utilities had a net loss of $0.04 per diluted share for the third quarter of 2005, compared to a net loss of $0.15 per diluted share for the third quarter of 2004. For the 9 months ended September 30, 2005, Avista Utilities contributed $0.72 per diluted share, an increase from $0.26 per diluted share for the first 9 months of 2004. You will recall that results for 2004 were adversely affected by write-offs related to the Idaho General Rate Case Order last year.

As most of you know, the third quarter is, historically, the weakest quarter for the utility. Results for the third quarter of 2005 were negatively affected by the absorption of $8.2 million of expense under the Energy Recovery Mechanism dead band in the State of Washington. Slide 4 presents the quarterly and year-to-date expense or benefit under the year 2005 and 2004. A full $9 million dead band was absorbed in 2004, and based on actual results and the forecast for the fourth quarter, we expect to absorb the full $9 million in 2005 as well. However, the timing, as well as the quarterly impact of the expense, has been different the past 2 years.

For the third quarter of 2005 we expensed $8.2 million, which includes the reversal of the $700,000 benefit received for the first half of the year. In 2004, the entire $9 million dead band was expensed during the first half of the year. As such, there was no dead band absorbed during the third quarter of 2004. Through September 30, 2005 we expensed a total of $7.5 million. We are forecasting to expense the remaining $1.5 million in the fourth quarter, which was expected and included in our earnings guidance for the utility. Excluding the affect of the earned dead band in the third quarter of 2005 and the IPUC related write-off in the third quarter of 2004, the improvement in utility results was primarily due to the affect of general rate increases. This is generally true for our annual results as well and I am pleased with the progress that we have made.

As we mentioned in our second quarter report, during late March through the second quarter of 2005 precipitation in hydroelectric conditions improved significantly from earlier in the year. We expect hydroelectric generation will be approximately 94% of normal in 2005 based upon the forecast of below normal precipitation and stream flows for the fourth quarter. This expectation may change based upon precipitation, temperatures and other variables. In our response to lower hydroelectric conditions and as a part of our resource optimization process, we have utilized our increased thermo-generating capacity during 2005. Our thermal generation has increased over 70%, as compared to 2004, primarily due to increased generation at the Natural Gas Fired County Springs II Generating Plant. This is due to both our full ownership of the plant, as well as increased total output.

In March, we filed a request with the Washington Utilities and Transportation Commission designed to increase our annual electric and natural gas revenues. In August 2005, Avista, the WUTC staff, the Northwest Industrial Gas Users, and the Energy Project entered into a settlement that, if approved by the WUTC, would resolve all issues in our general rate case. The public counsel section of the Washington Attorney General's Office and the Industrial Customers of the Northwest Utilities did not join in the settlement agreement. The revised rate requests are designed to increase annual electric and natural gas revenues by $22.1 million and $1 million, respectively. It is important to note that the majority of the electric revenue increase is to reset at a higher level the amount of power supply cost recovered in base rates. As such, this portion of the revenue increase will not affect gross margin or net income. The settlement agreement also provides for a modification to the ERM, with the dead band being reduced from $9 million to $3 million.

Hearings were held this month and the parties have requested that the settlement agreement become effective January 1, 2006. We cannot predict whether or not the WUTC will approve or impose additional conditions to the settlement agreement based upon input from other parties. If the settlement agreement is not approved by the WUTC, or conditions are imposed that the settling parties do not agree to, the WUTC will order additional rate case proceedings.

It isn't news to anyone on this call that wholesale natural gas prices have increased significantly. We continue to be concerned about the impact of rising natural gas prices on our customers and our business. In response to these increases, we filed a purchased gas cost adjustment request during the third quarter in each of our jurisdictions to increase natural gas rates. Oregon natural gas rates were increased 22.5% effective October 1, and we have received approval for a 23.5% increase in Washington to become effective November 1. We've also requested a 23.8% increase in Idaho to become effective on November 1.

It is important to note that these natural gas rate increases are designed to pass through changes in purchased natural gas costs to our customers with no change in our net income. While these rate increases are large, they are generally less than those being experienced in other regions of the United States and do not fully reflect the current market price of natural gas. We're fortunate that we've already locked in a significant portion of our natural gas needs for the upcoming winter and we have regulatory mechanisms in place that provide for the deferral and the recovery of the majority of our supply costs. However, if current prices hold or increase, our deferral balances will continue to increase, which will negatively affect our cash flow and our liquidity. As an example, a $1.00 decatherm increase in natural gas prices will have a negative affect of approximately $25 million on cash flows related to our retail natural gas business for 2006.

We are concerned about the impact that increasing rates will have on our customers. In fact, as part of our rate settlement agreement, we proposed increasing funding levels for 2 of our existing programs aimed at assisting limited income customers. We would increase the limited income demand side management, or energy conservation funding, by $200,000 to $1.1 million annually. And we would also provide an additional $600,000 annually for 2 years to the low-income rate assistance program in Washington, raising our annual funding level to $3.6 million.

We operate 6 hydroelectric plants on the Spokane River and 5 of these are under one Federal Energy Regulatory Commission license, which is referred to as the Spokane River Project. The license for the Spokane River Project expires on August 1, 2007. In July, we filed an application with the FER to re-license this project. We have requested that the FER consider a license for Post Falls that is separate from the license for the other 4 hydroelectric plants. Post Falls presents more complex issues that may take longer to resolve than those dealing with the other facilities of the Spokane River Project.

In the license application, we proposed a number of measures intended to address the impact of the Spokane River Project and enhance resources associated with the river. Currently, certain proposed environmental measures in our license application have estimated costs of $3.2 million per year. For certain items, costs cannot be reasonably estimated at this time. The total annual operating and capitalized costs associated with the re-licensing of the Spokane River Project will become better known as the process continues over the next 21 months. You will recall that we re-licensed our Clark Fork facilities in 2001, which account for approximately 80% of our hydroelectric capacity.

So, with that I'll turn the call over to Dennis Vermillion to report on Avista Energy.

Thanks, Scott, and good morning.

The Energy Marketing and Resource Management Business Segment, which primarily consists of Avista Energy, had a net loss of $0.17 per diluted share for the third quarter 2005. This business segment had a net loss of $0.34 per diluted share for year-to-date 2005. The net loss for the third quarter and the year-to-date 2005 was primarily due to increases in natural gas prices and the negative affect on our positions. A significant portion of the loss was due to the accounting for our management of natural gas inventory that I will discuss in a few moments. However, part of the loss was due to changes in natural gas prices relative to the position that we have taken in the natural gas market. While our portfolio is well within our limits and in accordance with our risk management practices, losses can and do occur when the market moves contrary to our positions, which has occurred during 2005. These losses can be magnified when there are large, unforeseen fluctuations or disruptions in the market, such as those caused by the hurricanes in the Southeastern United States during the third quarter.

It is important to note that Avista Energy continues to produce positive results on the electric side of its business. We continue to explore opportunities to expand our successful business of optimizing generation assets owned by other energies. Earlier this year, we entered into an agreement with Barrick Goldstrike Mines, located in Nevada, where we are providing for Barrick's electricity needs while optimizing their natural gas-fired generation, electric transmission, and gas transportation assets. Also during 2005, we have expanded our natural gas and user business to commercial and industrial customers in Montana.

Now I would like to discuss the impact of accounting for certain contracts. Our results are subject to variances created by differences in the ways that certain transactions must be accounted for. The accounting treatment does not impact the underlying cash flows or economics of these transactions. The difference is generally reversed in future periods as market values change or the contracts are settled or realized. These differences primarily relate to our management of natural gas inventories, as well as our control of natural gas-fired generation through a power purchase agreement. These differences had a $7.7 million negative affect on results for the third quarter of 2005 and accounted for approximately 70% of the net loss for Avista Energy during the 9 months ended September 30, 2005.

Let me take a couple of minutes to further explain the natural gas inventory difference and how changes in prices have had such a significant negative affect on our results for 2005. Generally, injections of natural gas into storage inventory takes place in the summer months and natural gas is withdrawn from storage in the winter months. We economically hedge the value of natural gas storage with financial and physical sales, effectively locking in a margin on the storage. However, accounting rules require that the natural gas inventory be carried at the lower of cost or market, while the forward sales contracts, which are derivatives, are marked to market using forward price curves. Changes in forward price curves result in gains or losses on the derivatives sales contracts, but generally do not affect the recorded values for natural gas inventory.

Therefore, if we enter into a forward contract to sell natural gas as a hedge against the value of natural gas in storage, and market prices subsequently increase, a loss with respect to the contract is recorded in net income. As you can see in Slide 6, this is exactly what happened during 2005, as natural gas prices increased dramatically. The loss was further increased by our economic decision last winter not to withdraw our natural gas from storage until the upcoming winter.

We expect that the majority of the losses on our accounting for the management of natural gas inventory should reverse when we withdraw the gas from storage, which is currently forecasted to occur during the first quarter of 2006. However, the unrealized loss will increase during the fourth quarter of 2005, if natural gas prices rise from the levels at September 30, conversely the unrealized loss will decrease if prices fall. If prices stay at the same level at September 30, we would expect a gain of $0.25 per diluted share in the first quarter of 2006, in addition to other income we are forecasting for that period.

As many of you know, it has been a challenge each year to cover the demand charges for our Lancaster Power Purchase Agreement. However, I am pleased to report that we have already covered approximately 85% of the demand charges for 2006 and have made significant progress for 2007. This is well ahead of where we have been in prior years. So, for 2006, our outlook is encouraging. Every portion of our business is performing well, with the exception of natural gas trading, and we are taking steps to turn that around.

Now, I'll turn it over to Malyn Malquist.

Well, thanks, Dennis, and good morning everyone.

As you can see in Slide 8, Avista Corp. reported a net loss of $9 million, or $0.19 per diluted share, for the third quarter of 2005, compared to a net loss of $9.8 million, or $0.20 per diluted share, for the third quarter of 2004. On a year-to-date basis for 2005, net income was $19.8 million, or $0.40 per diluted share, compared to $12.6 million, or $0.26 per diluted share, for the first 9 months of 2004. On a quarterly and year-to-date basis, we showed improvement for Avista Utilities and Avista Advantage, 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 will make some comments on financing activities, cash flow, liquidity, Avista Advantage, and our earnings forecast.

We continue to focus on improving earnings and operating cash flows, controlling costs, and reducing debt, while working to restore an investment grade credit rating. Positive cash flows from operations, proceeds from the sale of our South Lake Tahoe natural gas distribution properties, and a reduction in our total cash position during the 9 months ended September 30, 2005 provided the majority of the funding for Avista's cash requirements, including utility capital expenditures of approximately $150 million and dividends to shareholders. The most significant capital expenditure was the acquisition of the remaining interest in Coyote Springs II, for approximately $60 million. For 2006, we are establishing a budget of approximately $160 million for utility capital expenditures.

In September 2005, Avista Corp. terminated the lease agreement with, and acquired, the natural gas-fired combustion turbine generating facility in Rathdrum, Idaho from WP Funding LP, an entity that has been consolidated with the Company since 2003. As such, as of September 30th, we are no longer including WP Funding LP and the associated long-term debt in our consolidated financial statements. From a consolidated perspective, we replaced the $56 million of WP Funding LP debt and third party investment with borrowings on our committed line of credit. However, we expect to issue up to $100 million of long-term debt during the fourth quarter of 2005, to pay down the credit facility and for other corporate purposes.

In June, we locked in the interest rate on $50 million of this forecasted debt through an interest rate swap agreement. Due primarily to the funding of the WP Funding LP transaction, as well as other debt redemptions and maturities, the amount outstanding on our 5-year, $350 million committed line-of-credit increased from $68 million dollars at December 31, 2004, to $157 million at September 30, 2005. During the 9 months ended September 30, 2005, Avista Energy paid $15 million in dividends to Avista Capital, which has flowed up to Avista Corp.

As Scott mentioned earlier, we have entered into a settlement agreement in our Washington general rate case. The settlement agreement provides for an overall rate of return of 9.11%, including a return on common equity of 10.4% based on a consolidated equity level of 40%. Under the settlement agreement, we have agreed to increase the utility equity component to 35% by the end of 2007 and 38% by the end of 2008. If these targets are not met, it could result in a reduction in our base retail rates. As a point of reference, our utility equity component was approximately 31% as of September 30th.

Beyond our expected future earnings, we are currently evaluating additional ways to increase our equity ratio. Such measures could include delivering original issue shares under our equity compensation plans and dividend reinvestment plan, as well as possibly making small common stock issuances from time to time through underwriters or agents.

We're pleased to report that Avista Advantage contributed $0.03 per diluted share to earnings in the third quarter of 2005. On a year-to-date basis, Avista Advantage has contributed $0.06 per diluted share, which exceeds our original guidance for the entire year of 2005. As indicated in Slide 9, Advantage continues to show significant improvement since the first quarter of 2002. We continue to be pleased with the performance of this Company. Revenues have increased by 38%, as compared to year-to-date 2004, while the cost of processing a bill declined by 7% in the same time frame. The positive earnings impact is the result of customer growth and a focus on controlling operating costs. In the past year, the number of billed sites has increased by over 31%, or 37,000 new sites billed each month.

Before I discuss specific earnings guidance, I'd like to discuss projected earnings for our utility operations in a broader sense. Based on our authorized rate base and allowed rates of return, we believe that our utility operations could earn approximately $1.25 per diluted share. However, even if the settlement agreement in our Washington rate case is implemented, as designed, on January 1, 2006, we are not expecting to have earnings at this level for 2006.

There are 4 primary reasons for this. First, we still anticipate filling the proposed $3 million dead band under the Energy Recovery Mechanism. In fact, based on current prices, we expect to incur additional power supply costs beyond the amount of the dead band. Second, in spite of our efforts, not all of our costs are recovered through retail rates. Third, there is a regulatory lag between when capital dollars are expended and when the associated utility plant is included in our recoverable rate base. And fourth, we expect to see the impact of some price elasticity on our sales, particularly, in our gas business, as a result of significant commodity price increases.

As you can see in Slide 10, we are revising our 2005 guidance for consolidated earnings to a range of $0.65 to $0.75 per diluted share from a range of $0.95 to $1.05 per diluted share, due to the under performance of the Energy Marketing and Resource Management Segment. We still expect Avista Utilities to contribute between $0.95 and $1.05 per diluted share in 2005. The outlook for the utility assumes a forecast of normal weather and temperatures and below normal hydro generation for the fourth quarter of 2005.

The 2005 outlook for the Energy Marketing and Resource Management Segment has been revised to a range of a loss of $0.30 to $0.35 per diluted share from a range of a loss of $0.05 to a contribution of $0.05 per diluted share. This assumes stable natural gas prices and no further negative or positive affect of accounting for the management of natural gas inventory.

For 2005, we expect Avista Advantage to contribute approximately $0.08 per diluted share and for the other segments to lose $0.05 per diluted share.

Now for 2006, we are initiating guidance for our consolidated earnings to be in the 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 for 2006. The outlook for the utility assumes normal weather, temperatures, and hydroelectric generation, as well as the implementation of the Washington general rate increase on January 1, 2006, as designed in the settlement agreement.

The 2006 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 the changes in prices on the accounting for the management for natural gas inventory. If natural gas prices remain at September 30th levels through the end of the year, we estimate that an additional $0.25 of earnings per diluted share will be recognized at Avista Energy when natural gas is withdrawn from storage, which is forecasted to occur during the first quarter of 2006. This is also not included in our consolidated guidance, which is why we presented it separately on the chart.

Just to be clear, this is the turnaround of this year's Avista Energy losses due to the fact that our fuel inventory is valued at cost, not market. You see on the graph the question mark for 2005. It is possible that, if gas prices increase during Q4, additional losses would be booked in Q4 and would be reversed in Q1 of 2006. Conversely, if gas prices decline, we will see some of the $0.25 shift into Q4 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 $0.05 per diluted share for 2006.

Now, I'll turn the presentation back to Jason.

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

[Operator Instructions] [Paul Ritten], Key McDonald.

I had a question on the $7.7 million market-to-market incurred in the third quarter. Is that a pre-tax number or an after-tax number?

Paul, this is Malyn. That's an after-tax number.

So, you took guidance down essentially $0.30 after incurring an additional $0.15 of losses?

We incurred an additional, roughly $0.15 from the natural gas piece. We also had expected energy to contribute positive earnings, excluding the issue of the natural gas inventory, and essentially they came close to breakeven but they had a slight loss and we expected them to do quite a bit better in the quarter.

As of the second quarter call, you were looking for about $0.15 out of energy in the back half of the year. Is that the right way of looking at it?

That is, and we expected roughly half of that to come in the third quarter.

And you remain committed to the trading business?

Paul, this is Gary. You know, as we mentioned, we always look at all of our portfolio companies and what have you, but from our standpoint the Company is well positioned for next year. As it was mentioned by Dennis, they've already covered 85% of their demand charges on the Lancaster unit. We have that value coming back off of the storage. The electric side of the business had positive earnings every month and actually fairly substantial earnings, as well as they have continued to grow the asset bases of that Company as far as managing assets for others, as Dennis had covered. Whether that business fits long-term, you know the next 5 or 10 years will depend, as I said on the last conference call, and I think I said it before that, on whether the market has fundamentally changed or not. We have exited the gas side of the trading business until we get a handle on that and then we'll determine whether that's part of that business going forward or not.

What has electric done in the third quarter and year-to-date?

This is Dennis. The electric component of the business has performed very well this year. On a gross margin basis for the quarter and for year-to-date, they're right in the range of where we would expect them to be when we put together our budgets and our targets for the year. So, their performance has been consistent with what we've seen in the past on an economic basis.

Dennis, just maybe a little more on that. The electric in and of itself would have come pretty close to hitting our target for the quarter, so that was offset by some gas positions that went against us in the quarter. And, as Gary said, we've basically gotten out of that part of the business.

And strategically on Advantage, obviously it's gaining a lot of traction. Just continue to nurture that business and kind of realize the benefit from that. Is that kind of the near to intermediate term focus?

Yes, Paul, that's probably the best way to put that.

Eric Beaumont, Copia Capital.

A couple of quick clarifications here. Paul asked a few of the ones I had, but just one is a suggestion. Everyone else, as there's been confusion, has gone to reporting kind of adjusted earnings, so the mark-to-market's stripped out so you can see what's really the real earnings base is, knowing that the mark-to-market eventually reverses. It would be helpful if you guys would include a line item like that, so we can strip out what is the actual trading piece and what's mark to market.

But the second piece, Malyn, you were talking about the utility, and obviously you have the settlements being worked out. You show kind of the midpoints going up about $0.07 from '05 to '06 guidance. You know, that kind of in and of itself is taken up by just the movement of dead band from 9 to 3, and I understand that there will additional [toss and curve] [ph] based on the 10% churn once you get beyond there. But does that basically say that the settlement in and of itself is basically accounting for 1 year of kind of regulatory lag and plus some other cost pressures? Is that a way to think of it for this year?

Eric, I think that's a fair assessment on your part. We know we're going to eat the full $3 million of the dead band, assuming that the settlement is adopted, of course. And I would -- we're estimating that we're probably going to eat maybe twice that much, given current gas prices and purchase power prices. But there is a benefit from going from roughly $9 million this year down to somewhere in the $5 to $6 million dollar range, I think is where we're going to end up. But, the majority of the increase that we're receiving is really going to fuel and purchase power and there's not much that's going to the bottom line and that really is offsetting costs that we're incurring as we build additional rate base.

Okay. I guess along those lines, you know, maybe there's a chance for relief down the road, maybe not. But, when is the -- you put in the IRP, when are we going to hear more about it as far as when assets might be [current] [ph] construction or some of the other pieces that you had in the IRP?

Paul, this is Scott. We've released -- or Eric, I apologize. Eric, this is Scott. We've released the integrated resource plan. We've been discussing that, and if you'd like to give me a call, I'd be more than happy to kind of go over that with you. But, in general, we do have plans to start adding generation. We are pretty much -- our resources are met through 2010. We plan on having to add additional generation after 2010. In that, we have a good portfolio mix of some renewables, as well some coal added by 2016, with a little bit more added to 2026. So, if you'd like to get it in more detail, I'd be happy to talk to you about that.

Sure, and I guess one more piece on the energy side. You know, again, we're talking $0.20 to $0.30 is what you are guiding for next year, exclusive of any mark-to-market reversals or issues that you'll have with mark-to-market next year. Kind of going from Paul's question, how much of that $0.20 to $0.30, expectation-wise, is from electric?

We have budgeted roughly about 50% of the margin to come from electric and 50% from gas. So, our internal targets are actually somewhat higher than that. We tried to be a little bit conservative. That guidance probably assumes a 50/50 from each group, as we have done in the past.

Okay. There's no real assumption then for additional margin erosion in gas, given where prices are? That's pretty consistent with what you had originally anticipated for '05 prior to the gas spike. Is that accurate?

Malyn Malquist. Well, we need to remember that in our gas group, we also have a storage component that we manage. There are other end-use components of the business where we have end-use business in Canada, end-use customers in the U.S., and pipeline optimization, so we'll continue to do those things and those have been consistent performers for us. I think we would expect to get good margin from those next year, as we have this year and in past years. The issue will be our gas trading which has, as we've said, not performed the way it has, historically, this year. But, as Gary said we are actively working to develop plans to assess the situation. Is it market conditions? Are we lacking knowledge, expertise? We're also going to take a look at limit structures and that type of thing in our risk policy. So, we believe -- I believe that we will be able to turn that component of the business around and resume the performance from that to, be consistent of where we've been over the last 5 years, absent this year.

Okay. Well, thank you for all the time and good luck going forward guys.

Doug Fisher, A.G. Edwards.

Maybe you can give us a little bit of help with the sensitivity of utility earnings to natural gas prices for generation and for purchase power. Malyn, I think, said that if current power prices and natural gas prices held steady, I guess, are you assuming forwards for '06 there, Malyn?

Yes, Doug.

And if those were to take -- can you tell us roughly what those numbers are and then give us any kind of sensitivity of earnings to those changing?

Doug, we've tried to build into the guidance and one of the reasons that the guidance is perhaps a little lower than we were hoping that it would be, the fact that we've seen some -- actually some fairly significant increases in the fuel and purchase power marketplace. Now, it's bit of double-edge sword for us in terms of if we have a very good hydro year, hydro really still is the key for us, if we have a very good hydro year, it creates opportunity for us to sell into the marketplace and could be a very positive thing for us. If we have a poor hydro year, then we're going to be replacing that with our gas-fire generation and that could be fairly costly for us.

Now, the way that we've looked at this in the past is if you see roughly a 10% reduction in hydro that has cost us about $30 million in additional fuel and purchase power expenses. Since we are forecasting that we're going to fill the whole dead band, then what you would expect to see is roughly 10% of that hitting the bottom line. So, I guess what I'm suggesting is we've attempted to put current prices, forward prices, into that earnings guidance that we've given you and the variability is really going to depend on the hydro. Doug Fisher: And the $30 million is a pre-tax number?

Yes, it is.

And what -- any comment on your approximate tax rate for '06?

Remember, the $30 million goes - it's outside of the dead band at that point, so 90% of that is deferred.

Right, right.

And 10% would basically flow to the bottom line. And our effective tax rate is pretty close to statutory, 36% essentially.

Okay. And do you -- I'm a little confused by the natural gas trading loss in the third quarter apart from the inventory issue. I guess I thought you'd closed out most of your positions and you weren't in the market, so maybe you can talk to me a little bit about why there was a drag from that?

This is Dennis. I'm not sure where you got that we had closed out the positions. In Q1, we did have an event in the market where we suffered some losses in our gas-trading book. However, we took steps to liquidate those positions and flatten that out. We did, however, re-engage in the market based on some fundamentals we saw and within established risk management practices and basically we were wrong. And as we saw the market run up, we had positions in the West that were spread positions and also spread against Henry Hub that took some losses during the event. So, we acted to address those losses and basically locked in some of those and we're still in the process of liquidating that portfolio. Now, it's important to note that, on a gross margin basis in Q3, we did very well in power, and on a gross margin basis we ended up still positive on an economic gross margin basis. So, although we suffered some losses in our trading on natural gas, we still ended the quarter on a positive note there.

On gas, or gas and electric combined?

Gas and electric combined. For the entire business combined on a gross margin basis, we were positive. Unfortunately, we did not make enough on a gross margin basis to cover all of our expenses. We were very, very close. We ended the quarter with a very small or slight economic loss. Which, of course, is all overshadowed by the impacts of the storage.

I guess my misunderstanding was I didn't know that you had reentered the market since the first quarter issue, so that I think is the genesis of my misunderstanding.

James Bellessa, D.A. Davidson and Company.

You've indicated in your press release that you anticipate losses of approximately $12 million, and [inaudible] taxes will be reversed out in the first quarter of next year. Is that the $0.25 swing?

Yes, Jim it is. And that's based on the September 30th valuation of the book, if you will, which includes a gas price forecast. So then, if those gas prices stay in effect at December 30th, if they happen to be equal, then the $0.25 would turn around, as we all expect. It's going to be a little more or a little less or -- I don't know where gas prices are going, I admit. But, if it stays the same, then it's the $0.25 that would flow back in if the gas is withdrawn out of inventory.

Then you've given guidance that this year you expect Avista Energy to have a $0.30 to $0.35 loss. Now, that includes the markdown of this $0.25 a share, is that right?

Yes, that is correct.

Then if it includes it there, the next year's guidance doesn't include the markup? So, do you not have an apples and orange comparison?

Yeah, a little bit, Jim; you're right. That's one of the reasons we tried to separate that out to make sure that it was absolutely clear that we were treating that as a separate item. And the reason for that is because we still expect that that could vary fairly significantly in the fourth quarter of this year. That there may be some plus coming in or there may be some additional minus going out that then gets trued up in the first quarter of next year. But, absolutely believe that that will turn around. It will when the gas is drawn out of storage.

And, is there any activity that could cause you to have such a challenging year next year? Are your portfolio activities such that you could have the same type of volatilities next year?

This is Dennis. We've had the storage asset under our management for several years and we will next year as well. So, we will continue to manage that asset to create economic value. That said, if we put gas in the ground and hedge those positions against next winter and we see gas prices as volatile as we've seen this year, you will again see volatile gas results that aren't real. They will true up over time, as they will this year or in Q1. Unfortunately, that will continue and it's a function of what, --really what the forward gas prices do which are hard to predict.

And the pattern this year was a little different from past years because we saw a real economic advantage in the first quarter of 2005 to not draw the gas out of storage and to roll it forward. We were able to capture some additional economic gain by doing that. Normally, we would withdraw that from storage. And I'm very confident that that is going to be withdrawn in the first quarter of 2006. However, we will be re-injecting in the late second quarter and the third quarter again to take advantage of that storage. And so in the third and fourth quarter, I think next year you could see some volatility again if prices jump around.

Dennis Vermillion. That's right. We'll put gas in the ground typically in the summer and capture that summer/winter spread. Let's say it's $2.00. Gas is in the ground, and if the winter prices rally by $5.00 or $6.00 or whatever they've done this year, then you're going to see -- you will continue to see the same issue.

I think, Jim, another way to look at it is there's almost 2.5 ECF there, so every $1.00 change in price moves it $2.5 million either up or down, depending on what the average cost of the gas in the storage is.

You've explained this before about the $7.7 million dollar after-tax difference in the most recent quarter, compared to the actual loss of $8.3 million that you realized for Avista Energy, and you've explained the difference of that $600,000. Now, was that some contracts went against you and you closed them out and you took losses on them? And will you continue that activity in the future?

That's the part, Jim, that I said we are in the process of liquidating the final pieces of those positions, and that we have, in fact, taken losses on some of those contracts. And part of that was because of the run-up, we were shorted some hubs. We're re-looking at not only whether that makes sense in that business or not, but also then should there be changes in hub limits and bar limits and things regarding that particular part of the business. So, from a risk management committee standpoint, we just said we will not enter into anymore of those until we've had a chance to look at it and re-look at that part of the business. And it will be a conscious effort on our part, or conscious decision on our part, to take and enter back into those types of positions.

In the most recent quarter, in the natural gas distribution business, the volumes were up 20%. What explains that swing in the summer months? Total therms delivered were up 20%.

We don't sell much gas in the third quarter. And so, I noticed that also and I think we just saw some of our commercial customers using a little bit more gas in the third quarter. But, it tends to -- because the number is so small, I think the percentage change looks - it's big.

We're also balancing the system, which energy used to do for us, and that's been moved back into the utility now as a result of the benchmark mechanism coming back. I think that may have had something to do with the gas volumes in the summer.

In addition, I think, Jim, we've actually had quite a bit of growth over the last 2 years, especially in the commercial area. There's been a lot of retail, as well as office space and other things, that requires ongoing usage, even during the summer.

In the third quarter of a year ago, you had both a disallowance, a regulatory disallowance, and some impairment charges. On a per share basis, can you break those out? I think it was total $0.20.

That's about right. I think it was $0.20 or $0.22.

We can get back to you afterwards.

It's $0.19.

Paul Ritte, Key McDonald.

How should we think about your hedging activity for fuel? I would imagine it's somewhat difficult, until you have a pretty firm grasp of what the hydro picture looks like for the forward year. Is that kind of --

Paul, what do is we go ahead with our risk management, we look ahead 18 months. And if we have open power positions, we look at it and we decide what's the best economic way to cover those positions. Is it to look at -- right now, 18 months in advance, we're assuming some normal hydro. You can't -- you don't know what the winter is going to be. So, we'll go ahead and we'll procure those positions and we'll either buy gas to run Coyote or we'll make market purchases. And where we see the opportunity, it's economic to run Coyote Springs, we've already made some gas purchases to cover those positions. So, that's how we kind of start layering in our gas for thermal. We've already covered -- we've hedged about 40% of our gas in 2006 year-to-date and expect to start layering in even more gas.

40%, is that under the assumption of normal hydro?

Yes, on our thermal plant for generation. This is for generation. We're talking power supply, correct?

Yes.

Yes.

And then just back to trading, you said you've kind of taken a step backwards and you want to kind of reassess the situation. I mean, if you decide that the risks may be more than you're willing to bear at this point, given what we're seeing in the markets, what does that do to the $0.20 to $0.30 forecast on the gas side?

I think that, as Dennis said, Paul, there's a lot on the gas side that is not part of the trading - all of the gas storage, all of the management of transportation, a lot of the work, end-use customers. You know, our Canada business has just been a great business for us. The people that are up there have been doing a great job, as far as making consistent margin on moving gas to end-use customers.

The biggest issue that we face in the end-use markets, whether it be there or in Montana or other places, is really are those businesses able to continue to operate with high gas prices, because some of them are looking to switch to other fuels and/or in some cases close down parts of their operation or these shifts of their operation. So, that's the biggest risk in that, is not exposure from the standpoint of supply, the market exposure, but will there be demand destruction in the gas business, and that could occur on those businesses, as well as in the utilities across the nation, as people find these higher gas prices this winter.

What part of your customer base on the industrial side uses natural gas as a feedstock and what kind of exposure is there, there?

Well, the majority of our industrial customers are transportation customers and they purchase their gas outside of the utility so we don't have -- when you say feedstock are you assuming fertilizer?

[Voices overlap] plastics, I would imagine you don't have a lot of that in [voices overlap].

The majority of our industrials are more wood products related, manufacturing related, so we do have a small amount of that. but I would say it's primarily related to natural resource usage. as opposed to feedstock usage.

John Hanson, Imperium.

Most of my questions have been answered but just one left. In regards to the Avista Advantage, when I look at your chart on page 9, it looks like that business is,-- the net income is growing a couple hundred thousand dollars every quarter pretty consistently or even more than that. I guess the question I have is, is that taking any additional investments or what's the outlook for that to continue at that kind of increase into '06?

John, this is Malyn. We haven't had to put any capital into Avista Advantage the last couple of years. And, at this point, we're not forecasting any for 2006. We continue to look to make sure that we can continue on the path that we're on to grow the business. And last year we made a very small acquisition of a telecom company to help round out a piece of that business. And we may make some additional acquisitions along those lines to further enhance our ability, particularly in the telecom area. But, at this point, we're not forecasting any additional capital requirement.

The business continues to grow as the result of we're just providing outstanding service for our customers and so there's 2 pieces to the growth. One is every time Starbucks opens a new shop we grow because we handle all of their bills for them. So, there's kind of some internal growth that's built in. We do need to continue to add some new customers and we're making very good progress, as we have this year, in lining those up for additional growth for next year.

So, you're continuing to see growth in that and there's really not too terribly much extra you have to do to continue that growth path?

No, there really isn't.

All right, just making sure I understood, thank you.

Doug Fisher, A.G. Edwards.

External financing needs for '06, if the kind of guidance that you have laid out here fleshes out, in other words you get the $0.25, you earn somewhere between $1.30 and $1.45, you spend, what it is $160 million is it, CapEx?

$160.

At the utility? What will that require roughly in terms of debt and any new equity?

Doug, we're going to do in the next few weeks -- our plan is to do $100 million debt financing and that really should take us through the year. Now, we have in early --

Through all of '06?

Through all of '06. We have in early '07 some additional debt that's maturing. So it's possible that we may replace that in the fourth quarter of next year, but it would be a replacement of debt that's already outstanding, and frankly, hopefully, at a much lower interest rate than we're currently paying.

Now Malyn, of that $100 million, basically $56 million of that is just replacing this WP Funding debt. Is that the way to think about this?

Yep, that's correct and --

So, the new -- the incremental capital for CapEx in '06 would be something on the order of $44 million?

Actually, it's less than that I think, Doug, because we actually had some retirements of some debt that we are are going -- that that's covering also.

We did some early retirements in the first and second quarter. I believe the amount was $26 million, Doug, so we're essentially swapping out higher cost debt for lower cost debt is the way I would look at it.

There's only about $14 million in new debt.

Say that one more time, Gary.

There's only about $14 million of new debt.

Okay, all right, that's what I was trying to get at. Thank you.

James Bellessa, D.A. Davidson and Company.

Well, it didn't signal on this side and I forgot my question, I'm sorry.

That's okay Jim. If you think of it, call us.

Is it snowing in Montana, Jim?

It's sprinkling, so we're glad to have the moisture.

Just make sure by having it not.

Thank you very much, sir. Ladies and gentlemen, that concludes our Q&A period for today. I'd like to turn the call back over to our management team for any closing remarks they may have.

I would like to thank everyone 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.

Thank you very much, sir. Thank you, ladies and gentlemen, for your participation in today's conference call. This concludes your presentation and you may now disconnect. Have a good day.