Avista Corp (AVA) 2005 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the quarter 1, 2005 Avista Corporation earnings conference call. My name is John, and I will be your coordinator for today. At this time all participants are in a listen-only mode. We will be facilitating a question-and-answer session towards the end of today's conference. (OPERATOR INSTRUCTIONS) As a reminder this conference is being recorded for replay purposes. I would now like to turn the presentation over to your host for today's conference call Mr. Jason Lang, Investor Relations manager. Please proceed, sir.

Good morning everyone and welcome to Avista's first-quarter 2005 earnings conference call and webcast. Avista's earnings were released premarket this morning and the release is available on our website at AvistaCorp.com. With me today in our offices in Spokane, Washington are Avista Corp's Chairman of the Board, President and CEO, Gary Ely; Senior Vice President, CFO and Treasurer, Malyn Malquist; the President of Avista Utilities Scott Morris, Dennis Vermillion, President of Avista Energy; and Vice President and Controller Christy Burmeister-Smith.

As we begin this morning's conference call I will caution you that during today's conversation we will be making forward-looking statements that involve risks and uncertainties which are subject to change. I would direct you to Avista's 2004 form 10-K with which was filed with the SEC and is also available on our website for reference to the various factors which could cause actual results to differ materially from those contemplated to the extent these factors are not discussed on this call.

We are using some slides as part of today's presentation. These are available on the Avista website in the investor section. To follow along with the webcast simply click the forward arrow to advance the slides. The slides also maybe downloaded and printed at your convenience. Now I will turn this presentation over to Avista's Chairman of the Board, Gary Ely.

Thanks, Jason, and good morning everyone. Reviewing our results for the first quarter of 2005, we know that our utility operations showed improvement from the first quarter of 2004. However, we are disappointed with the performance of Energy Marketing and Resource Management segment as Avista Energy reported a net loss for the first quarter of 2005. This breaks a string of 19 consecutive quarters of positive earnings from Avista Energy. Malyn Malquist will have more specific information about this for you later in the report.

The improved results for the utility were accomplished in spite of winter weather this year that was warmer and drier than normal and warmer and drier than last year. In fact, February 2005 was the driest February on record in the last 124 years for the Inland Northwest. Although we are encouraged by the increased precipitation and snowpack during the second half of March and April, we continue to be concerned about the impact the dry winter will have on our hydroelectric generation for the remainder of the year.

We do not expect to have any problems meeting our customer's energy needs but below normal hydroelectric generation has been replaced with more costly thermal resources and economic purchases of power on the wholesale market. Three years ago we set our goals for returning to financial health, an important part of this process has been to more closely align our actual returns with those allowed by each regulatory jurisdiction, and we continue to make progress in reaching that goal.

During the second half of 2004 electric and natural gas general rate increases were implemented in Idaho and a general natural gas rate increase was implemented in Washington. More recently in March of 2005 we filed a request for electric and natural gas general rate increases in the state of Washington. Scott Morris will provide more detail on this request and other regulatory matters in a few moments.

In January of 2005 we completed the purchase of the remaining 50% interest in the Coyote Springs 2 natural gas generating facility from Mirant. This strengthens our position in owning and/or controlling sufficient resources to meet our native load under a broad range of operating conditions. Earlier this month we received approval from the Idaho Public Utilities Commission to include the remaining portion of Coyote Springs 2 in base electric rates.

On a bright note, Avista Advantage had a positive quarterly results for the third consecutive quarter. As you know, we hired Stu Stiles as President and CEO of Avista Advantage during the first quarter of 2005. We look forward to having him lead this business to an even greater level of performance. In the other business segment we had a net loss which was anticipated. However, we believe the majority of the larger issues are behind us in this segment.

Overall the results for the first quarter of 2005 were disappointing to me. That being said I am optimistic about the remainder of the year ahead. I believe our utility operations can have a strong year as compared to 2004 in spite of warm and dry winter. I am very encouraged by the progress at Avista Advantage and I am hopeful but Avista Energy's performance will improve during the second half of the year. Now I would like to turn this call over to Scott Morris for his report.

Thanks, Gary. Good morning. As noted in the news release earlier this morning Avista Utilities contributed $0.39 per diluted share in the first quarter of 2005, an increase of 77% compared to $0.22 per diluted share for the first quarter of 2004. As Gary mentioned the Utilities earnings were positively affected by general rate increases implemented in Idaho, and Washington during the second half of 2004. These increased revenues are an important contribution toward our goal of earning allowed rates of return in all the states we serve. However, this was partially offset by decreased use per customer due to weather that was warmer than normal and warmer than last year. This had a negative impact on our operating revenues and earnings.

There is also some upside to the warm winter which resulted in lower electric resource costs for the utility and the hydroelectric generation was higher during this period than in the prior year due to the early snowmelt. And combined with added generation and lower than expected total retail load, this allowed us to sell surplus energy in the wholesale market and reduce electric resource costs. As a result we only expensed 200,000 of the $9 million dead band under the Energy Recovery Mechanism in Washington during the first quarter of 2005 compared to 6.3 million for the first quarter of 2004. However, we still expect to expense the entire $9 million dead band during 2005. This is due in part to the higher cost of purchasing power or fuel for thermal generation to offset decreased available resources from below normal hydroelectric generation during the remainder of the year.

As Gary mentioned at the beginning of this report, the lack of precipitation this winter is a concern to us. However, we are encouraged by increased precipitation and snowpack during the second half of March and April. Slide 4 shows as a percent of average the snow water content for various locations in the western States as of April 22, 2005 our generation is derived from the mountains of northwestern Montana, northern Idaho and northeastern Washington, which is in the range of 50 to 75% of average. And although it's not what we would like it to be, this is an improvement over figures from early March, which indicated a range of 25 to 50%. We are also in a better generating position than other parts of the Pacific Northwest. This is due to in part to high water storage levels and reservoirs upstream from hydroelectric generation facilities.

Assuming normal precipitation for the remainder of the year, we are forecasting annual hydroelectric generation of approximately 457 average megawatts or 83% of normal. This expectation may change based upon precipitation, temperatures and other variables. We have power cost adjustment mechanisms in Idaho and Washington to mitigate much of their earnings impact of below normal hydroelectric generation. As I mentioned we still expect to expense the entire $9 million dead band in Washington under the Energy Recovery Mechanism during 2005. We budgeted for this and it has been included in our earnings guidance. Once the dead band is reached in Washington the impact of below normal Hydro generation would flow through our deferral mechanism with shareholders absorbing 10% of the impact. In Idaho the impact would flow through our power cost adjustment mechanism with shareholders absorbing 10% of the impact. The expected reduction in hydroelectric generation assuming normal precipitation for the remainder of the year, is estimated to have a negative effect on operating cash flows of about $25 million from the amount originally forecasted, with approximately 2.5 million impacting pretax earnings.

We believe that we have adequate liquidity through cash flows generated from operations and funds available under our committed line of credit to meet increased cash requirements for purchase power or fuel as a result of reduced hydroelectric generation. In March Avista filed a request with the Washington Utilities and Transportation Commission to increase base electric rates by 12.5% and base natural gas rates by an 1.8%. This request is designed to increase our annual electric and natural gas revenues by 35.8 million and 2.9 million, respectively. Avista's request is based upon a proposed rate of return of 9.67% and an 11.5% return on equity with an authorized equity level of 44%.

WUTC generally has up to 11 months to review the general rate case filing. The table on slide 5 shows the most recent general rate increases in each of the states in which we serve. These increases have been very important steps in restoring the financial health of a company by allowing us the opportunity to more closely align our actual returns with our authorized rates of return. The acquisition of the remaining 50% share of the Coyote Springs 2 generating facility has positioned the company very well to owner control, sufficient resources to meet our customer's needs.

We completed that $62.5 million transaction in January, and with the acquisition we added approximately 140 megawatts of generating capability to our power resource mix. Earlier this month we received approval from Idaho regulators to include the newly acquired portion of the Coyote Springs 2 plant in based electric rates. Under the Idaho order Avista received a 1.9% increase in base rates, which is designed to increase annual revenues by $3.2 million. To mitigate the impact of this rate request on our customers, we requested and the Idaho Commission approved a 1.9% reduction in the Company's current power cost adjustment surcharge. This extends the recovery period of deferred power costs and results in a zero net change to customer's current rates.

And finally, to bring you up-to-date on two ongoing activities, I can tell you that the sale of our South Lake Tahoe natural gas distribution properties, Southwest Gas was approved by the California Public Utilities Commission in March. The transaction is expected to close later this week. And also our six-year investment program in transmission infrastructure is continuing. This investment is expected to be completed by the end of 2007 and will help us meet our goal of increasing reliability for our customers throughout our service territory. And with that I will turn it over to Malyn Malquist.

Thanks, Scott, and good morning everyone. As you saw in our news release this morning and as you can see in slide 7, Avista Corp reported consolidated net income of $10.2 million or $0.21 per diluted share for the first quarter of 2005 compared to $12.2 million or $0.25 per diluted share for the first quarter of 2004. We showed improvement for this utility's and Avista Advantage offset by a decline for the Energy Marketing and Resource Management segment.

Jerry and Scott have outlined many of the things that affected quarterly earnings for the utility operations, including the effects of rate increases and the warm and dry weather. However, I would like to make a few comments on the operating cost of the utility financing activities, cash flows and liquidity before I discuss subsidiary results. Avista Utilities operations and maintenance expenses decreased $100,000 and administrative and general expenses decreased $300,000 for the first quarter of 2005 as compared to the first quarter of 2004. While these are not substantial changes, they do reflect our long-term focus on improving the profitability of the utility operations.

We remain focused on managing our operating expenses, and we will continue to implement initiatives that are expected to improve efficiencies and enhance overall productivity. Examples include the implementation of a new financial accounting and supply chain software system during the first quarter of 2005 and the continued installation of advanced meter reading technology. Avista continues to focus on reducing interest costs and improving its balance sheet. Positive cash flows from operations during the first quarter of 2005 provided the majority of the funding for Avista's cash requirements, including utility capital expenditures of approximately $83 million, debt redemptions and dividends to shareholders. The most significant capital expenditure was the acquisition of the remaining interest in Coyote Springs 2.

During the first quarter of 2005 Avista redeemed a total of $26 million of medium-term notes scheduled to mature in future years. The amount outstanding on our five-year $350 million committed line of credit increased from $68 million to $74 million during the quarter to partially fund these redemptions. Also in March 2005 Avista Energy paid $10 million in dividends to Avista Capital, which flowed to Avista Corp. During the remainder of 2005 we expect cash flows from operations and our committed line of credit to provide adequate resources to pay dividends, fund capital expenditures, maturing long-term debt and other contractual commitments. This excludes the $54.6 million of WP Funding LP debt maturing in October 2005. We're currently evaluating our options with respect to that debt.

Additionally we expect the closing of the sale of our South Lake Tahoe natural gas distribution properties to provide approximately $15 million of cash. The quarterly dividend for the first quarter of 2005 was 13.5 cents per common share, an increase of 1/2 cent per common share over the previous quarterly dividend and the third such increase authorized by Avista's Board of Directors in the last 18 months.

The Energy Marketing and Resource Management business segment had a net loss of $0.17 per diluted share for the first quarter of 2005. The net loss for the first quarter of 2005 was primarily related to losses in Avista Energy's natural gas portfolio. It is important to remember that the nature of Avista Energy's business will result in net losses from time to time, and this is Avista Energy's first quarterly net loss since the first quarter of 2000.

Increases in natural gas prices and the deviation from expected price trends in western natural gas supply basins had an overall negative impact on results for the first quarter of 2005. As markets moved counter to certain contracts, Avista Energy acted to adjust its position consistent with established risk management policies. This reduced market exposure but had the effect of locking in losses during the first quarter of 2005. I would like to point out that Avista Energy continued to produce positive results on the power side of its business. This includes marketing and managing the output and availability of generation assets owned by other entities.

It is important to note that losses and gains from the operations of Avista Energy are due to a variety of factors, most relate to normal business uncertainties. But some relate to variances created by differences in the ways for which certain transactions must be accounted for. It is these differences that I will devote some attention to this morning.

The operations of Avista Energy are managed on an economic basis, reflecting all contracts and assets under management at estimated market value, which is different from the required accounting for certain contracts and physical assets under management. During the first quarter of 2005 these differences accounted for approximately two-thirds of the net loss for Avista Energy. The most significant of which related to Avista Energy's management of natural gas inventories and a purchase power contract. Avista Energy generally enters into forward sales agreements to capture profits and economically hedge the value of natural gas inventory and storage. These agreements are recorded at market value in accordance with statements of financial accounting standards number 133, accounting for derivative instruments and hedging activities. However, the natural gas inventory is required to be valued at the lower of cost or market value.

If Avista Energy enters into a forward contract to sell natural gas as a hedge of natural gas and storage, and market prices subsequently increase a loss is recorded in net income. While the market value of the natural gas inventory has also increased, the natural gas inventory remains valued at the lower of cost or market value. Now as you can see in slide 8 natural gas market prices increased significantly during the first quarter of 2005. Avista Energy has entered into contracts to effectively sell natural gas for delivery during next winter. Avista Energy has an equivalent amount of natural gas in storage; approximately 2.4 billion cubic feet. The natural gas was sold at a price above its weighted average cost. And I think my voice has about run out. So the natural gas was sold at a price above its weighted average cost.

Of course the profit from the transaction isn't recognized until the natural gas is delivered or the contract is otherwise settled. Natural gas prices increased during the first quarter of 2005 as shown in slide 8. The contract to sell natural gas has to be mark to market at a loss while the natural gas and storage continues to be carried at cost. This had a negative effect on net income of $3.9 million, or $0.08 per diluted share for the first quarter of 2005.

There was a corresponding positive effect on net income for the first quarter of 2004 of $800,000. The accounting does not impact the underlying cash flows of these transactions and depending on market conditions this $3.9 million should reverse in future periods as market values change or the transactions are settled or realized, with the majority of the reversal projected for next winter. It is important to note that the difference could increase or decrease in the interim prior to the settlement of the transactions depending on the volatility of natural gas prices. A similar issue exists for Avista Energy's contract with the Lancaster natural gas fired generating project. Through our purchase power agreement Avista Energy controls Lancaster which is 49% owned by Avista Power. The power purchase agreement gives Avista Energy the right to purchase natural gas for generation and convert it to electricity for a fixed fee.

Avista Energy has economically hedged the value of this power purchase agreement by entering into contracts to buy and sell natural gas and electricity during certain time periods in the future. Although the power purchase agreement is not a derivative as defined by SFAS 133 and not mark to market, the contracts to buy and sell natural gas and electricity are derivatives that are recorded at market value. In an effort to reduce the earnings volatility associated with these combinations of accounting treatment Avista Energy has implemented a hedge accounting program in accordance with SFAS 133. However, not all of the contracts qualify for hedge accounting.

Similar to natural gas inventory, the power purchase contract is managed as if it is recorded at estimated market value. So during the first quarter of 2005 overall increases in natural gas and electricity prices for the future delivery periods in which the contract has been hedged, had a negative effect on net income of approximately $1.5 million. During the first quarter of 2004 this activity changes and prices had a negative effect on net income of approximately $800,000.

So in summary we realize that this accounting is complicated and makes the analyst job difficult. However, the bottom line is that approximately two-thirds of the net loss from the Energy Marketing and Resource Management segment should reverse in future periods. We do acknowledge that this segment had a net loss independent of these issues.

At Avista Advantage the Company completed its third consecutive quarter of positive earnings, contributing $0.02 per diluted share to earnings in the first quarter of 2005. As indicated in slide 9, Avista Advantage has shown significant improvements over the first quarter of 2002. We are pleased with the performance of this company, its revenues increased by 37% over the first quarter of 2004 while the cost of processing a bill declined by 7% in the same timeframe. The positive earnings impact is the result of customer growth and a focus on controlling operating costs. As we told you in the year end conference call, we signed three major new customers in the fourth quarter, the growth from these new customers contributed strongly to the first quarter 2005 results.

We continue to be disappointed in our results in the other business segment. We reported a loss of $0.03 per diluted share for the first quarter of 2005. Although we believe the majority of significant issues in this segment are behind us, we will continue to limit our future investment in this business segment and look for opportunities to monetize our existing investments. As you can see in slide 10, we are revising our consolidated earnings guidance for 2005 from a range of $1.20 to $1.35 per diluted share to a range of $0.95 to $1.05 per diluted share primarily as a result of the first quarter performance of the Energy Marketing and Resource Management segment.

The upper end of the range for Avista Utilities has been reduced by $0.05 per diluted share due to below-normal hydroelectric generation forecasted for the year and decreased retail revenues during the first quarter of 2005 as a result of warmer than normal weather. As such we expect Avista Utilities to contribute between $0.95 and $1.05 per diluted share. The outlook for the utility assumes normal weather, temperatures and precipitation as well as no regulatory disallowances for the remainder of 2005.

The 2005 outlook for the Energy Marketing and Resource Management segment has been reduced from a contribution in the range of $0.20 to $0.30 per diluted share to a range of a loss of $0.05 to a contribution of $0.05 per diluted share. This will require the Energy Marketing and Resource Management segment to earn between $0.12 and $0.22 per diluted share the remainder of the year. We expect the majority of these earnings will be generated in the second half of the year as the second quarter is historically the weakest quarter for Avista Energy. We still expect Avista Advantage to contribute $0.05 per diluted share, and the other segment to lose $0.05 per diluted share.

Now I will turn the presentation back to Jason.

We will now open this call up to questions and analysts and investors. I would like to remind any members of the media who may have questions to please contact Jesse Worth at 509-495-8578. We are now ready for our first question.

(OPERATOR INSTRUCTIONS) Paul Ridzon of KeyBanc McDonald.

The two thirds that's going to reverse I guess there's really no way to -- you have to have a crystal ball to see what the gas market is going to do to kind of forecast when that's going to happen. But when is the actual settlement of the majority of those contracts?

The majority of those contracts are currently scheduled for settlement next January and February of 2006.

So we could potentially look at Avista is saying this year's pain is next year's gain?

That's one way of looking at it.

And the balance one-third, what is behind that? Was that kind of a point of view position that went against you?

That is correct.

Okay. Thank you very much.

Doug Fischer of A. G. Edwards.

Thank you, and good morning. What, if anything, can you do to reduce these timing mismatches over time at Avista Energy? And then secondly, other has lost I believe $0.03 in the first quarter and you're looking for it to lose $0.05 for the year. Am I understanding that correctly? Explain to me how we are only going to lose $0.02 more over the next three quarters.

Let's take the last question first. The reason for that is we have our venture funds, and they all come due in the first quarter when we have to evaluate those and put them on our books. And so we were anticipating that, and that came out to about where we expected it to be. And so that won't happen again until January of 2006 as far as those venture funds. And hopefully if markets improve they could be up. However, markets today aren't looking that well, but we will see. The second question I will either have Malyn, or Dennis is actually with us this morning, maybe he would like to answer that second question.

Thank you, Gary, and good morning, Doug. As Malyn mentioned in his talk, there are two major components; we have the gas storage and then the tolling arrangement. I will talk about the storage first. We have looked at implementing hedge accounting for storage two different ways, the first being cash flow hedging. And the problem with that one is it requires us to be able to predict with a high level of probability when the withdrawal from storage will actually occur. And that is the problem. It is very difficult to predict when we will actually take the gas out of the ground.

So for example we have as Gary mentioned at this point sold that gas for next winter, market conditions could change, and we could end up being in the situation where that gas is pulled out of the ground at another time depending on economic conditions. So that effectively removes that option from the table because we manage that asset on an economic basis. The other way to look at it is fair value hedging. And I'm not an accounting expert, but my understanding of that is that we would have to basically mark the inventory to spot prices and the hedges to forward prices. So that would also create a gap to economic difference, and there could be volatility also under that hedging program because as you know, there is volatility between spot prices and forward prices. So for gas storage it really is a difficult situation, and we haven't found an effective way to take that volatility out.

Now on the tolling arrangement we actually have implemented a cash flow hedging program or hedge accounting for that. And it works very well for most of the year. The problem with that that we do have with tolling is for the second quarter of the year when you have spring runoff, and you're down for maintenance, the units oftentimes doesn't run. And just as I mentioned in for storage you have to be able to predict with certainty that you will physically produce energy out of that unit in order to implement the hedge accounting. So we are able to do that for three-quarters of the year for the most part, but for that second quarter it remains a problem because we can't say for certain that the unit will actually run. So that is primarily what is creating the volatility or the differences between GAAP and economic results is that Q2 tolling component.

Of course, we had a variance here in Q1, but that was driven by forward positions that are hedges against that tolling, that we were not able to implement hedge accounting on and primarily that is Q2 of '06. So in summary we believe that over time we're making the best economic decisions for the Company and it's just unfortunate that the accounting doesn't follow along.

Thank you. That was very helpful, Dennis.

Nicolas O'Grady of Sandal Asset Management.

A couple quick questions. First off in terms of I guess it is the 9 and 3/4 notes that prevent you guys for a dividend, in terms of growing it at the rate of earnings?

The 9 and 3/4 notes do have restrictions on how much we can grow the dividend. It basically amounts to one half a cent a quarter. Until we get our triple B bond rating back.

Right but it is a simple consent solicitation on the notes, right in the indenture? So technically you could maybe just exchange them if you had to? To maybe remove that provision?

There is that possibility that we could get the exemption removed, yes.

Okay, and my other question was just in terms of -- in terms of the Commission you guys are going in for filings right now. Can you talk a little bit about any changes that have gone on in terms of people there or if it is becoming more positive in terms of regulation?

Sure. This is Scott Morris, Nick. There have been a few changes to the Washington Utility Commission. We have two new commissioners, the new Governor of Washington, Goverbir Gregoire as you know replaced the Chair, Marilyn Showalter and the new Chair is a gentlemen named Mark Sidran. Mark was just confirmed by the State Senate in the State of Washington during this session. Mark ran in the primary for Attorney General but was defeated and has been an attorney in Seattle and been quite active. So Mark is now the Chair, and another gentlemen named Phil Jones who was the Republican nominee to the Commission was confirmed as well. Phil has a degree from Harvard and a fairly extensive business background; he also worked for Sen. Dan Evans about 10, 15 years ago when Evans was in the United States Senate. Two very good people, and we fully expect to continue the positive relationships that we have built with the Washington Commission staff and the commissioners.

Great. And just one point of clarification. So two-thirds of the loss is non-cash, right, and so I guess its sort of a mark to market position the, and you said a third of it was a point of view. Do you think you guys have now -- in terms of point of view have you changed your policy completely so that you're just not going to even take that risk anymore?

This is Dennis. No, we have not changed our policy. We actually believe our policies and procedures work exactly as they were planned. We had some point of view positions on -- based on some what we believed to be very sound fundamental views of the marketplace. And they went against us. So per our policies and procedures we acted. We have VAR limits, position limits, stop loss limits, they worked as they should. So yes, we have retrenched, and we are looking at the marketplace and looking backwards and trying to understand how we could have managed through the situation better. But if you look at our performance over time and we have produced solid results from that part of our business, and we would expect that to continue within our very disciplined risk management policies and procedures.

Understood completely. If I look at last year's earnings in that business, is there say a percentage or a portion that is fee-based that is contractual, just contracts with other munis and stuff like that where it is pretty consistent over time? As sort of a baseline?

We do have as you know a number of arrangements with other entities within the Pacific Northwest, and if you take that business and much of it is fee-based, there is also some sharing mechanisms in place. And you add the performance from that part of the business along with our end use marketing activities, and our own asset management activities, historically that part of our business has provided the majority or roughly two-thirds of the positive going forward.

In addition might just mention too that from a fee-based standpoint we have our Canadian entity that does a very large retail business in Canada that is all fee-based. And that business has continued to grow, and we normally expect somewhere between $3 and $4 million a year off of that business alone.

Perfect. Great. Thanks a lot, guys.

James Bellessa of D.A. Davidson.

Good morning, everyone. The contract that you say will expire next January and February, when did you put those on?

Those contracts were put in place during the first quarter.

Now were they put in place as a result of you seeing yourself on the wrong side of the contract because the loss in the quarter, or were they in place before you realize you've got, you're going to have a loss for the period?

They were put in place because of the way the forward curves work. If you look at how forward market was being traded you had a situation where the -- it was more economically advantageous to sell that gas next winter than to pull it out of the ground this winter as we had originally planned when we put the gas in storage. So it was really, Jim, an economically driven decision based on where the forward markets were trading.

In the past you told us an estimated approximate weather impact on EPS. You had milder than normal weather. What might have the first quarter's impact from the weather have been on your EPS for your utility?

Jim, the warmer weather cost us $0.03 to $0.04 cents in the first quarter.

What was the quarter's growth rate at Avista Advantage in number of bills handled?

I don't have that at my fingertips. We could get that for you, certainly. It was significant growth.

Do you think it was double-digit?

Yes it was double-digit, Jim.

You evidently have some accounting reclassifications between resource cost and O&M cost. When does that go into place?

We took a look at our classifications of items and gross margin and we have done a minor reclassification. A piece of it relates to a lease cost for our ratran (ph) plant. If you would like more details I can speak to you later.

That would be great. I am wondering if we will get the quarterly restatements for all of last year so that we can have comparisons in place as we do our forecast. Is that possible or will we have to wait quarter by quarter?

I'll have to look into it and see how difficult it is to do it now versus quarter by quarter.

Now if I'm understanding correctly, you are indicating that you didn't dig into the dead band very much. And that was a difference of $6.1 million. This year you expensed 0.2 million. Last year at the same time you had expensed 6.3. So $6.1 million difference, and if I do arithmetic tax effective I get $0.08 a share.

You did your arithmetic right.

Now you're telling me that that $0.08 came into the quarter. That is why you were able to produce such a strong utility result and those $0.08 amounts will be withdrawn from later quarters. Is that right, and which quarter -- will you get through that dead band at what time do you get through that dead band?

Jim, what occurred was because of the warmer than normal weather, the snow that we did have came on very early. So we were able to generate additional generation above what our needs were, because again the weather was warmer and our loads were less. Consequently, we sold market power into the wholesale market, and that is why we had good positive earnings. And in the normal course of things, we will have most of our power costs during the July and August time periods. So you can see most of that being refilled during that period of time.

Jim, I will just add a little color to that perhaps. Our gross margin was up $0.20 a share, and the dead band was down $0.08. So net-net, we were up $0.12, So that is still pretty strong growth. And we actually had budgeted our -- we were not surprised by this in the first quarter; let me put it to you that way. We were very close on the dead band for what we thought we would be budget-wise, and our budget really calls for most of the dead band to be consumed, as Gary said, in the third quarter. Some in the second quarter, but mostly in the third quarter.

In your rate application in Washington, are you proposing that this dead band go away? Are you going to continue having this in place?

Jim, we have made a proposal to change the dead band in the state of Washington to actually have it be removed. But as you know through any regulatory proceeding, it is just too early to predict what the reaction of the regulators will be to that. But we certainly will work hard to try to change it.

Thank you very much.

Alan Shay (ph) of Ironbridge.

I have a question on what is -- could you give us a comment on your outlook for gas price for the whole year; maybe even further out if you can?

That's a real good question. I'm not sure that we're in any better position to forecast future gas prices than anyone else. However, we think that there has been changes in the market to the point where gas is certainly, I guess, more associated with the high oil prices that what it has been in the past. And as you look forward if you can forecast the oil prices, you know there will be -- some ratio of that will be natural gas prices as we go through the year. Now, we have not seen the seasonal differences that we normally have. The first quarter we should've seen gas prices in the Northwest falling because we had warmer than normal temperatures. Storage projects were at or near some of their highest levels they've ever been at that time of the year. We've had more drilling going on and more new gas coming into the market, and yet prices were higher than they had almost ever been.

So as you look and try and associate or try and figure out what has caused that, there is a very strong association between natural gas prices and the oil prices. And because of infrastructure issues on the oil side and because BTUs are BTUs on a world market. If you look at China and India and other places that are starting to draw an LNG and other things, we would anticipate at least for the near next few years probably in the near term there will be a much closer association between oil and gas prices than their ever has been in the past.

So since your outlook on higher oil price and higher gas price, are you acting on that to hedge your storage as the month goes on? Or are you not taking any actions right now in terms of your, on your views?

I think there are two different pieces to that, Alan. First off on the distribution side Scott's people are working very hard to figure out longer-term ways to stabilize and take some of the volatility out to our customers. I truly believe that to a certain extent we are destroying demand as the prices stay high because people will start making other choices or finding other means to take and (multiple speakers).

yes, the calculation.

Yes, but on the energy side and Dennis, you can speak to this as far as what you are doing as you go forward on gas prices.

To answer question yes, we definitely are capturing the economic value that storage asset provides for us.

Sorry to interrupt you, but it seems to me like I am not an expert, by far on predicting gas prices, but I would think that you would be able to forecast weather pretty good and I think that the short, warmer weather would result in lower high (indiscernible) generation and that would relate to higher gas price in that region. So I was wondering why did you make it take a view that to hedge the gas in storage because you take that -- I would think that you might need the gas to supplement lack of Hydro generation.

Well the two businesses aren't and can't be connected. Avista Energy -- the storage that Avista Energy has is totally independent from Avista Utilities, and that is the way from a regulatory perspective that it has to be. And so Avista Utilities has acted to basically tie up all of the generation that it needs throughout the summer period because of the poor Hydro. Avista Energy saw an opportunity to actually capture profit by selling its 2.4 billion cubic feet of gas storage forward into next winter. And we will realize that profit but we won't realize it until the settlement occurs. And in the meantime we have this accounting difference that really is generating most of the loss. The remainder of the loss was a result of some point of view position in terms of how gas supply between the various points of our region would work, that was a fairly significant piece of it that simply didn't play out in the marketplace as it historically has.

Okay. One final question. Has there been any change in the team in Avista Energy team training team, or will there be a change? Does this miss call for action -- you know what I'm trying to get at?

No, Alan it doesn't call for action and there has not been any team -- we have one of the most experienced teams, and we in fact have I think have the most experienced on the West Coast. We have a great team and they've done a great job. As we try to explain, two-thirds of the loss came from just accounting. And no other issues there. If you look at the other piece, it is very small in relation to the 19 straight quarters of positive earnings. As well as the over $160 million that they have passed back to the Corporation from the earnings they've had over that period of time. So we're very happy with the team and very proud of what they've accomplished.

Good. Glad to hear that. Thank you. Good luck.

John Hanson of Imperium Capital.

Just a couple follow-up on a couple of the rate case activities; you've got the Washington general case just filed. When will that, when does an order have to get likely get sent in that order?

We always fully expect that it will take the full eleven months. You always work for settlement if there's an opportunity but at this point we made the filing in March. So we expect by the end of February of 2006 to get the order out of the Washington Utility Commission. That is what we forecast.

History with settlements in Washington, how has that been going of late?

We were able to settle our last general case in 2002. We were able to settle and we were able to settle our case in our gas case that we had in 2004, and we did it in a very short amount of time within two or three months, we were able to get a settlement of our general gas case. We filed it in late summer of 2004 and had a settlement in place by the beginning of December or November, excuse me, of 2004.

It's early to talk about settlement in the current case, but do you have any kind of reaction at all in terms of constituents?

Well we continue to work well with our regulators and will continue to dialogue not only with regulators, but with public counsel and other interveners so we will work hard with all the parties and if there is an opportunity we will certainly pursue it.

John, just to comment -- I mean it has been so quick they haven't even suspended the case yet. So we will start getting data requests and other things, and then as they go through that then it shapes around well what are the real issues and where do we go. But that is at least a month or two out because this is a full general case on both the gas and the electric. Gas will be fairly simple in comparison to the electric. But that being said, it will take some time before we are even in a position to discuss what the issues are.

Over on the Coyote Springs case over in Idaho just to make sure I am clear on that, the lowering of the PCA cost, that does not have a net income affect?

No, all we are doing is delaying -- originally had we let that continue to roll we would have actually collected all of our deferred power cost in a much shorter period of time. So we reduced the rate at which we were recovering that so it actually extended it out over a longer period of time.

Left no net income effect (multiple speakers)?

No impact, we still get the money, it is just we get it over a longer period of time.

And then on the other side the general, putting the plant in rate base that part of it does end up --

That absolutely does, yes, raises earnings.

Great. Thank you very much, and good luck in the Washington case.

Maura Shaughnessy of Massachusetts Financial Services.

With regards to the dead band in Washington the 9 million, I think if I recall that was set on a 450 gas. So is there also the assumption that if that were not to go away that you could also change the assumption since we haven't seen 450 gas for a while?

As part of the rate case process we plan to true up the gas prices, and I think the filing has roughly $6 as the gas price that we put into the filing which actually still might be a little bit on the low side. As we talked about we also have requested to do away with the dead band, which would eliminate most of the issue of mismatch there and it would strictly be a 90 (indiscernible) sharing at that point.

Perhaps this quarter is the one to highlight the point of view trading just because it is not because it was obviously a tough quarter for that. But I guess at the end of the day given the size of your Company and given that companies 6, 7, 10 times as large have walked away from the point of view trading business, can you talk about why you're in that business given the size of the Company, given that its having an impact on your bond ratings? And how should I think about the risk inherent in point of view trading for sub one billion market cap company?

I think it is a very good question Maura, one that we continue to look at from a strategic standpoint each year. We discuss with our board of directors as we have our strategic planning. It has been a very good Company for us. In fact we probably would not have existed as a company today had it not been for Energy's earnings back in 2000, 2001, 2002 when the Company really -- the utility was going through some very difficult times. And they up streamed a lot of cash and capital to us. As I mentioned earlier we've had 19 straight quarters of positive earnings. This is the first one and if you look at just the piece that actually was a point of view issue its a very small piece in comparison to the overall thing. They run a very tight ship and have very good risk management controls.

That being said, we have been very pleased with that business unit and what they've been able to accomplish. Now as we look forward we have to look at has markets changed? Are there things different there that would require us to take and operate differently from what we have in the past, or can they continue to provide the kind of earnings and the kind of cash that they have provided over the last four years, five years almost? If they can there is reason to stay in the business. Somebody has to be an intermediary in these markets. And since most of them as you have mentioned have left, there is a niche market there providing it. And if you remember a lot of our business is around managing other people's assets. We have over 3500 megawatts of generation that we manage for others. We have our Canadian Gas Co., which basically for a fee basis moves retail gas to industrial end-users. And so there is a number of pieces in this business that produce good return on income and only a very, only part of that is the point of view trading. So at this point although we continue to assess the markets and assess the viability of each of our portfolio companies, we have been satisfied with the work that Energy has done and anticipate at least in the near-term continuing that.

How is it impacting the bond ratings do you think?

I think from the impact of bond rating I would probably let Malyn address that but the fact of the matter is that our various rating agencies do not like trading businesses, period. Because they can't forecast; it is like our analysts, its hard to take and put their earnings into a model and look at them from a stable nature. Because their very business is dealing with volatility. And that just creates some angst on their part.

I would add, Maura, that I think the impact is there is an impact. There is no question about that. They put us into a different risk category as a result of having this business. And what they've told us is essentially you need to hit the numbers to get your triple B rating back, and you need to hit them in the rearview mirror. You need to hit them on a historical basis rather than maybe looking ahead a year and saying okay, we see you getting there. And so I think it will slow a bit our return to getting the investment grade rating back. Having said that we are not doing -- we are doing very little financing, and so there really is very little impact on the price of new debt that is being issued. But it is something that is of concern to them.

Would it be a big deal if you were to just be trading around the assets rather than doing the point of view trading do you think to the rating agencies, or it is all thrown in the same bucket?

I think its hard for them to differentiate that. I think that would be -- it could be helpful but I don't know that it would be real significant.

Maura, we try to explicitly explain that to the rating agencies, but when you come right down to it, it is a trading business, and irrespective of that it puts us in a different classification.

Okay. Thank you.

Ladies and gentlemen, this concludes today's question-and-answer session. I will now turn the call back over to Mr. Jason Lang for closing remarks.

I want to thank you all for joining us today. Analysts and investors may direct questions to me directly at 509-495-2930. I will ask the media again to please direct their questions to Jesse Worth, Avista Communications Manager at 509-495-8578. A replay of this conference call will be available today beginning at 12:30 PM Eastern time. The contact information for the teleconference replay, as well as for the webcast and the slides is available on the Avista Corp.'s website at AvistaCorp.com. Again, thank you for joining us, and have a good day.

Ladies and gentlemen, we thank you for your participation in today's conference; this concludes the presentation, and you may now disconnect. Have a great day.