Avista Corp (AVA) 2003 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Q4 2003 Avista Corporation Earnings Conference Call. My name is Caitlin 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 this conference. If at anytime during the call you require assistance, please press "*", "0" and a coordinator will be happy to assist you.

I would like to now turn the presentation over to your host for today's call, Mr. Dave Brukardt, Vice President and Treasurer of Avista. Please proceed, Sir.

Thank you, and good morning. Welcome to Avista's fourth quarter and year-end 2003 earnings conference call and web cast. Avista's earnings were released pre-market this morning. With me today in our offices in Spokane, Washington, are Avista Corp's Chairman, President, and CEO, Gary Ely; Senior Vice President and CFO, Malyn Malquist; the President of Avista Utilities, Scott Morris; 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 latest Forms 10-K and 10-Q filed with the SEC, and 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 the call.

I would also like to let you know that we will be using some PowerPoint slides to help illustrate our remarks today, as we did last quarter. These slides will be available to download from the web cast site on Avista's site at www.Avistacorp.com. Our release, the income statement, our balance sheet, and the operating highlights are also available there for some of you, who I understand may be having difficulties downloading them from the web.

Now, I would like to turn this conference call over to Avista's Chairman of the Board, Gary Ely.

Thanks, Dave and good morning everyone. 2003 was a solid year for Avista. As we've been saying each time we talked with you, we continue to fold the plans we've laid out and we are accomplishing our goals. I am pleased to tell you that for the fourth quarter of 2003, we are reporting net income available for common stock at $15.1m and earnings of 31 cents per diluted share.

As you can see on slide number 2, this is nearly a 35% increase in bottomline earnings for our Company over the same period last year. For the year-end 2003, we are reporting $43.4m of net income available for common stock and earnings of 89 cents per diluted share, again, an increase over 2002.

We continue to meet our milestones in regaining the financial help of our Company. Let me share some of these that occurred in 2003. They are listed on slide number 3. In the regulatory arena, we made progress towards resolving some issues that impact our revenues. In September, we received approval of a 10% or $6.3m general rate increase in the State of Oregon. The rate change became effective in October of last year. We reached agreement with Potlatch Corporation, -- our largest retail customer, on a new 10-year electric power purchase and sale agreement. In addition, we received regulatory treatment that will allow us to fully recover the costs associated with that agreement. As you are all aware, the price volatility in the natural gas markets around the country is impacting everyone. In the fall of 2003, Avista received purchased gas cost adjustment; price increases in four states where we serve natural gas. These adjustments brought the rates of our customers, -- the rates that our customers are paying for natural gas into better alignment with the cost of supply.

On the national fame we are encouraged with the recent orders from FERC, denying rehearing request that would have prolonged some of the other pending cases. You'll remember that the overhang from the FERC 206 investigation, which stemmed from the issues related to past energy crisis was taken one step closer to resolution in 2003, when the Chief Administrative Law Judge certified the agreement and resolution. We are still awaiting a decision from FERC. Approval of that agreement would resolve all issues in that case and we are hopeful that with the recent developments a decision on Avista case will soon come.

At the state level we had some regulatory issues pending in the State of Washington, including final review of purchased gas cost that were approved and subject to further review and refund and a decision regarding continuation of a natural gas benchmark mechanism. We received order yesterday in the Washington Commission that we should expect a decision on the benchmark case by mid February. During the second half of 2003 we recognized the impact of the proposed $2.5m settlement in the Energy Recovery Mechanism or ERM filing. The settlement is awaiting approval by the WTC. In Idaho, a decision regarding prudence of $11.9m of natural gas purchased for thermal generation will be reviewed in the general rate case that we intend to file in early February.

With regard to goal, we're seeing steady customer growth throughout our service territory. In fact, we've added over 5,300 electric customers and over 8,100 gas customers in 2003 meeting our projections for the year. There are also early signs that the economy is starting to revive in our area. But we usually drag the national economy by 12-18 months. Although, it is too early to make predictions about the spring runoff this year for hydro generation, precipitation levels at this point in the areas that contribute to our hydro facilities are a just below normal. Assuming normal precip and temperatures for the balance of the year, forecast for stream flows call but slightly higher than normal flow in the Spokane river drainage and 91 and 95% in the Clark Fork and Columbia rivers respectively. Initial indications for the 2004 hydro generation are reported to approximately 97% of normal. We reported to you last quarter that Avista is undertaking a series of transmission upgrade projects that will reinforce our electric transmission grid at Eastern Washington and Northern Idaho as well as helping the existing and future demands for electricity in our service territory. This undertaking, which should be completed by 2006, will cost roughly a $100m, which is already included in our forecast with capital expenditures. The projects are on track and are progressing well.

I want to take a minute to share some information with you about our County Springs Two Generation facility. Two weeks ago on January 15, operating indicators noted a potential internal arcing problem in the plant step-up transformer. That is the main transformer connecting the plant to the grid. Numerous tests were conducted during the week of January 19 through to 23 concluding with an internal inspection of the transformer on January 24. The test found that internal arcing had in fact occurred. However, the internal inspection found no visible cost. The manufacturer has determined that the only way to find the cost is to return the transformer to the repair facility. Their initial estimates are that the transformer could be repaired and returned to the Coyote Spring site by June 30. All cost related to the repair of the equipment are covered by the manufacturers ORG (ph.). The economic dispatch the plant was offline at the time and was not scheduled to operate as far as Avista's resource mix until the third quarter of 2004, and thus should have little impact on supply or cost based on the forward pricing curves. Having said that we remain on track for meeting our goals to achieve longer term financial help. Over the past two years we repurchased about $256m in debt resulting in an interest expense reduction of almost $12m in 2003 over 2002 by keeping operations within budget and continuing positive operating cash flow while sustaining reliability for our customers and maintaining our focus on safety for our employees. As a result we were able to increase common stock dividend by 4.2% last August. We told you that we intended to find partners for Avista Labs to reduce the drag on the business corporate earnings and cash flows. We were successful in bringing together a group of equity partners who brought in the fusion of cash to Avista Lab. This reduced the drain on our capital expenditures while we retained a 17.5% ownership in the fuel well business. As an investor, we are pleased that the business is currently taking commercial product to market.

We met our earnings guidance which I will remind you we revised upward modestly at mid year. This was achieved in spite of warmer than expected weather, and the write-down of an asset, both in the fourth quarter; Malyn, will discuss this a little bit more later. Lastly, our subsidiary company, Avista Energy, and Avista Advantage, both performed according to plan in 2003 with positive earnings for Energy, and a first time monthly net profit for Advantage. Again Malyn, will have more to say about both these entities in a few minutes. So with that, I will turn it over to Malyn, to give you more details about the financial state of our company.

Well, thanks Gary, and good morning to everyone. Now before I talk about the numbers, I do want to take a minute to thank Gary for his guidance and leadership in setting our course for financial rebuilding and making sure that we met our objectives along the way. It's a pleasure to work with such a well-respected leader in a company with such dedicated and talented employees. As Gary told you at the outset of this report, we are pleased with the Company's performance for both the fourth quarter and the year 2003.

As you can see in slide 4, we finished the fourth quarter with just over $309m in consolidated revenues compared to nearly $288m for the same period in 2002. And for fiscal year 2003, we earned 1.1b in consolidated revenues, up from 2002. Even with the successes Gary, mentioned earlier, we were nonetheless disappointed that the fourth quarter wasn't even better. It was negatively impacted by the warmer than expected temperatures in October and December and an asset impairment at Avista Power. Unfortunately we can't do anything about the weather, which resulted in reduced gas loads and therefore lower gas revenues. But we are hoping for more normal temperatures and precipitation for the first quarter of this year. Historically the first and the fourth quarters are when the majority of our earnings are generated. Despite the warmer than expected weather, the Avista Utilities business segment earned 33 cents per diluted share, an increase of 10 cents over the same period in 2002. Avista Energy continued its stable performance in Q4, with net earnings of 5 cents per diluted share. The Company continues to uphold its disciplined, regional resource management strategy, and its focus on asset-backed optimization of generation assets owned by others in the West, along with its commercial energy activities. This is proving to be a sound strategy, and we will continue to move forward with it.

The Energy Marketing and Resource Management segment as a whole lost a penny in the fourth quarter, due to an after-tax impairment charge of $3.2m, related to an LM6000 generator owned by Avista Power. Four of these units were originally purchased during the energy crisis of 2000-2001 to be used in a non-regulated project. We sold three of the units in 2001, and we intended to install the remaining unit but more recent power supply conditions for the region indicate that it will not be needed in the near-term.

Frankly, we cannot afford to have capital tied up in assets that aren't earning a return for us. We've written the value of the LM6000 down to approximate market value and we are working to sell it, so that we can reinvest the sale proceeds. Avista Advantage continues to be cash flow positive and is on track to be earnings positive by mid-2004. Advantage grew revenues by 17% in 2003 over 2002, and their cost of processing a bill declined by 33% in that same timeframe.

Finally as you have read in our new release, we are reaffirming the 2004 consolidated corporate earnings guidance of between $1 and $1.20 per diluted share. With that I'll turn this call back to Gary.

Thanks Malyn. In the year and a half that Malyn has been with Avista, he has taken the new commerce view of our company, spending a great deal of times, scrutinizing processes, assets, and resources, asking the tough questions and making sure that we are doing everything we can to keep moving forward on our journey to financial help. I just want to say thanks to him for doing this tough job and for bringing his talents and skills and dedication to Avista. Having said that, I want to reiterate that Avista still has much work to do, to get to where we feel we should be to bring the greatest value to our shareholders and our customers. We will continue working to manage costs, with careful examination of our operations and capital expenditure processes. We will continue to work with regulators to achieve a recovery of our cost, to more closely align earned returns with those allowed by regulators in the states in which we serve. We will do this, while continuing to provide reliable cost affective and safe service to our customers.

When we started our recovery 3 years ago, we knew we were headed down a long and challenging path, but as we get nearer to regaining health in many, if not all aspects of our business, we continue to be vigilant with our planning. We will continue to focus on what we do best and execute our plans in efficient and affective ways.

Now I'll hand this call back to Dave.

Thanks Gary, we will now open the call to analysts and investor questions. I would like to remind any members of the media who may have questions to please contact Jessie Wuerst at 509-495-8578. Hello we are now ready for our first question.

Thank you sir. Ladies and gentlemen, if you wish to ask a question please press "*", "1" on your touchtone telephone; if your question has been answered, or you wish to withdraw your registration, then press "*", "2". Once again "*" "1" for any questions. One moment please.

Sir, our first question is from David Thickens (ph.) with Deephaven.

Hi everybody. Good morning.

Good morning David

Good morning David

Couple of questions for you. Can you give us a little more detail on Coyote Springs' plant, I know you said in your release and in your remarks that the manufacturer has said that the transformer could be back by the end of June, and that your system dispatch didn't anticipate using the plant before the summer. But can you talk about what kind of contingency you are planning, you are doing, you know, given that could this is not a very definitive statement and in the history we have had the problem with this transformer in the past?

Good question David. Let just say I am less than happy with the situation, but the manufacturers have indicated they will completely stand behind that, they will make every effort to take and how the transformer repaired and back by June 30. The contingency that we are making of course is insuring that we have adequate supplies right now. The good news is from an economy dispatch standpoint forward pricing curves would suggest that we should be able to take and replace any power on market that might be necessary during that third quarter. However, we are done messing with this transformer, and we do in fact plan on [inaudible] transformer that will be a standby transformer, that should be here later this year, that will actually be probably end of the fourth quarter before deliver of it.

Now, the cost of the manufacturer incurs, those are simply the direct cost for fixing the plant. You know, if you have additional capacity cost in such those are not covered by the manufacturers, is that correct?

That is correct; however, we are looking at business. You know, it is the third time that this has happened and we are looking to see what are the options.

Okay.

The other thing I might say to David is any cost that we have if you remember with our ERM we have the 90/10 sharing with our customers.

Okay. And you mentioned that the gas purchase cost have been rolled into the rate case in Idaho, can you give us an update on what's going on? I know there was also some question about what was going to happen in the State of Washington with those costs?

Now in Idaho we are planning of filing a general case in what was in our tracker. They are, I should say, our surcharge or PCA in Idaho. They identified that 11.9m as gas cost as they wanted to look at in the general case and which they will be doing when we file which will be sometime in early February.

No, but isn't Washington also taking a second look at some of the costs related to the purchases for Coyote Springs as well?

No, they are not. That was handled in the settlements that I had mentioned that for the 2.3 under the ERM, which settled out.

Okay, so I've got for now. Thank you.

Yes, thanks David.

Sir, our next question is from Sierra Cansada (ph.) with Merrill Lynch.

Hi, it's Sam Brothwell and David did very good job asking my question, thanks.

Okay Sam.

Okay, Sam. You made it worth.

Our next question is from Doug Fischer with A.G. Edwards

Thank you, and congratulations on making some very good progress for your turnaround. Could you update me on this -- this Washington natural gas benchmark case, just give me the background on what the issues are there, and what kind of financial impact we are talking about?

Sure, Doug, by the way. Thank you for being on. As far as the Washington benchmark case, if you remember, we have the benchmark mechanism in place for a number of years where we have had Avista Energy managing the gas purchase and supply requirements for the utility.

They are just for electric and gas, or electric?

No, this is for gas only.

Gas only.

Yes, gas only. Not just for our residential gas customers, Washington residential but for our commercial gas customers --residential and commercial retail gas customers. And they have been doing that for a period of time. In the States of Idaho and Oregon, the commissions have been very happy with that, and in fact that has a three-year approval the last time under that benchmarking process, which took us out through 2005. In Washington there has been concern not about the savings that energy can bring to our retail gas customers buy more about it's just a subsidiary and lot of this is raised of course by all the comps that we are in the industry, and there is just a philosophical difference, I believe, in the State of Washington around whether a subsidiary should be working with the utilities customers. That being said, they have allowed us to do it; over the past, it does bring savings to our customers. We have presented our arguments, and they are more, I think, philosophical in nature and the Commission will be making a decision on that by mid-February and will either -- it will either expire and we will transition out of that as far as doing it for the utility customers or we'll continue it. As far any impacts, the impacts on the utility side will be some additional cost because we'll have to set up our own dispatching office and our own purchasing group in order to do that. So that would be the only cost that we probably be involved with that.

Are you -- you are making some margin at Avista Energy as a result of this mechanism if you perform better in the benchmark? Correct?

Yeah, we do.

And you are at risk of losing that margin if the Washington Commission ends this mechanism. Is that what you are seeing?

Yes. We would be at risk of losing that, but it actually is a very small percentage of their total. It's less than $1m.

And that's a [pickax] number?

Yes.

Of the gross margin number.

That's right.

Great and --?

Anyway, I have just got to say they are going to cost the utility almost that much to set it up inside. But it will be put back in rates at that point.

Either of cost okay. So they would flow through the gas cost adjustment or would you have to absorb those until some kind of rate adjustment?

We probably would have to absorb those until some kind of general rate case or general rate adjustments.

No, that are just O&M type cost or O&M and Capital, what --?

Just basically O&M cost.

And as you look at your range for '04, you know, as you're looking into the year, do you have any sense, whether you are likely to be towards the upper end of that range given your good performance in '03?

Come on, Doug.

Yeah, I take it that you don't want to comment on that. Okay that's a good enough, thanks guy, congratulations.

Thank you Doug. I appreciate it.

Our next question is from James Bellessa with D.A. Davidson and Company.

Good morning, I hope it is cold in Spokane and it is in Great Falls this morning.

No it's not Jim; it's -- the wind is blowing here and I think it blew it all over to you. We are up and above the 35 to 40 degree temperature rate.

20 below here.

Is it really, send it back.

The benchmark decision that you discussed coming up in mid-February, wasn't there an exploration of that in Washington at the end of January?

Yes there was.

And so what happens for the 15-day period.

They extended it actually. They asked for an extension and we just [mailed] it to them yesterday.

You had indicated in the press release the proposed settlement of Washington for the Energy Recovery Mechanism and Gary you said 2.3 the -- should we expect 2.5m?

Okay I -- 2.5. Well I guess we are not looking and talking off my head.

It was the second half of 2003 event, was it really a fourth quarter event or was it in the third quarter?

It's both, -- Jim this is Malyn. We were in the middle of negotiations late in the third quarter and I had an offer that we put on the table in discussions and so we had about two-thirds of it, that we booked in the third quarter related to that offer that we made and booked the rest when we finalized the agreements in the fourth quarter.

Two-thirds in the third quarter.

Yes, roughly.

Okay. And then you talked about prudence review in Idaho and the figure is $11.9m, I had it $5.9m before, did they up that?

When the commission issued its order, accepting the extension of the PCA of the full amount, they said we just want to review all the gas contracts that were in that deferral mechanism in the general case.

But they have not made a statement around whether they believe that it -- whatever the staff actually recommended looking at the 5.9, but the commission when they issued they orders they said we will just go all of it in there and review it.

You indicated that you are going to bring in a backup transformer, is that going to be a cost to you or this is going to provided by the manufacturer?

No, actually what we will doing on that Jim, is we will actually be going out and purchasing a new transformer by a different manufacturer by the way to be a backup for that transformer; it will be set onsite, so it will always be available to use. We don't usually do that on a lot of our substations and generation plants, but this is a more uncommon transformer as we talked in year-end -- over the last year and half and so we just decided that it's prudent to have a backup there.

And who is going to bare that cost?

That will be split between ourselves and it will eventually be recovered in rates.

Our portion of that Jim is going to be a little lesser than million dollars

A year.

No, that's a total capital.

Cost.

Cost.

Okay.

Capitalized

And so these reformers or transformers are only a million or 2m, or 3m type of expenses?

Yes they are around $1.5m for that particular transformer.

You can't operate without it so you have to have one?

You got to have one.

Okay in the last call you had said that the expected fourth quarter hydro production would be about 500 average megawatts or about 90% of normal what was -- what happened. What was the reality of the situation?

Jim actually that is what it turned out to be; it was we finished the year at about 90% of normal and that for us represents about $15m of cash flow expenses that and it flows through the balance in account mechanism, so 90% gets differed and about 10% of that goes to our shareholders that's again

So had it not been -- had it been normal you wouldn't have had the $15m?

We would have had about $15m less in fuel and purchased power expenses and since we were outside of the debt band, we are in the 90:10 sharing range associated with that.

You went over the steam flow or maybe it was the hydro generation and you expected from the different drainages, would you do that again repeat that again?

Sure on the Spokane River, Jim we should be at or just likely above normal. But remember the Spokane River drainage only has about 15% of our hydro generation. The Clark Fork where most of our generation is should be about 90 to 92% normal and then in the Columbia River drainage will be around 95% of normal. So overall if you take that into account that's stream flow, when you convert that to actual generation we should be somewhere around 97% of normal generation.

But I want to stress Jim, that it's really very early still in the snow cycle here. Last year at this point, we were at about 70% of normal and we winded up getting a very strong springtime snows. And so, I -- we are not putting a lot of hopes on that yet; we still have -- we still need quite a bit of preset here.

Well, again those numbers are predicated on the fact, that we would normal precip and normal temps from here through the spring so --.

Thanks Gary.

They are always conditioned that way.

But, yeah, last year we were -- in fact, I think, we were little below 70% at one time. I think, we were 67%, and then we had some very large snows late in February and early March, and brought us up to where we were.

And would you like to comment on this last season of federal court, in Mazola (ph.). This was about some complaint that you haven't been paying for the trust lands and, you know, compensating the school trust funds?

As, you know, Jim, it's our practice not to comment on losses but just--I will just say this, that we believe our license covers everything that we have in there. We go through FERC, that's all encountered, we just relicense that plant, as you know, before even five years, two years ago and we don't believe there is an issue there. But we just think it's just another way for some people to try and do what they were doing two years ago either get hold of the dams and try to get hold of money in other ways.

Thank you very much.

Thanks, Jim.

Jim, I want to go back to just one other -- one point, on the $15m to make sure we are clear on that. That's the annual impact, that's not the fourth quarter impact.

Okay. Thank you.

Okay. Thanks.

Our next question is from John Hensen (ph.) with Imperium (ph.)

Yes. Good morning.

Good morning, John.

Before, I begin with my [manufacturing] question, I want to follow up on the gas benchmarks, kind of, issue, make sure I understand so the unregulated business is buying gas for the regulated business, right?

That is correct.

Okay. How much of the volume of your -- of the unregulated gas business -- marketing business is attributable, is it a significant amount?

No, it's less than 10%.

So, it's not a material factor in there. What happens just procedurally if that kind of order comes up so you have to unwind things? Are there any positions there or issues there that we should be aware of or not?

No, there is not. Basically, what has occurred in the past is that the -- we have people on staff at the utility that basically lay out their plans for the year and then we actually have Avista Energy execute that plan for them. And then actually run the dispatch or the daily nominations and things to make sure the gas gets there. That saves the customers about $1m a year and like I said earlier it's a philosophical issue about whether parents and subsidiaries are to be working together it is retaliated interest question. With that if they would decide down to unwind it, what it means is that we'll have to duplicate those daily nominating people and the gas purchasing people in the utility. We used to do that, I thought as a saving a few years ago and got permission to move it out, I think that everything is going on, there is just some feeling that it's not appropriate anymore. So, from that standpoint, if we are asked to not do that any longer than we will set up a similar structure in-house and they will then have the responsibility to go out and buy that gas. As you know, we bought all the gas and things for this winter, that's all taken care of.

Right.

And they will allow us a transition period, they will also allow a transition period then to take and move across on that. So, you know, between that and I think there is a disagreement on how much of the benefits that are out there between what Energy is keeping and what should be returned to the customer, but I believe right now we're returning, I don't remember the number on top of my head, but at least the cost savings as well as some additional benefits. It will put the utility in a position than of going out and getting the gas on their own for our customers. And we just think our personnel and the management, we think it's better the way it is, but we'll certainly follow whatever order comes out of the commission.

Sure. Then what we are saying is, is that you got to or may have to eat a little bit of cost, so that all gets caught up on the utility side and on the unregulated side, you're going to lose a little bit of margin for period of time. I guess the question as you're going through that is sometimes these operations are somewhat fixed cost, does that mean you have to -- if we just set it up inside of the utility that you'll have some duplicated efforts overall in the marketing side to continue the business you've got there now? Looking into what -- have to have that same kind of parallel entities, right.

Well, yeah, we will have the same parallel seasons.

Okay.

Equipment, the fact of the matter is that it's a very small percentage of Avista Energy and at the utility that will be recovered in rate -- you know, like I said, it's probably about a $1m but that's for an annual basis and so we would set it up and we would get it -- for back in rates, so it's very small percentage of our overall costs. It just -- we think it's done better the other way and that being said we will do whatever we need to.

Good, we will watch for it to see how it turns out. The main -- Gary I wanted to get into though, was just to make sure I understand the marketing going forward and that's an important part of you meeting the -- your projections for 2004, correct?

Yes, it is.

Are you talking about how much of the 2004 is attributable to that business?

Yes, you are talking about the energy marketing, right?

Yes.

Yeah. As we said it's between 25 and 35 [inaudible].

Okay. Alright good -- I wanted to make sure you are still putting that kind of number. What's the key to success in that business here in 2004? I know we have got you know, high gas prices, we've got hopefully knock on with good hydro. What do you see the keys to success in that?

I think John, the key to success in that business is really continuing to do what they have done -- probably the biggest key is liquidity. You know, that we have gone through some very difficult years in last couple of years and liquidity has been the biggest issue because there are just not nearly as many players in the marketplace. That being said, they continue to manage assets for others and continue to share in the value of that. We have -- you know, as you remember we manage over 3000 megawatts of generation for others. They got a committed bank line that they use to take and backs up that from their own liquidity. They are in great shape, but they have a lot of cash on the balance sheet which is one the reasons they are earning or their returns on this as higher as I would like to see. But the fact of the matter is that they are doing a very job and very disciplined job and they continue to work and emphasize the markets with others. They have got over 200 megawatts of transmission under long-term contracts. They have natural gas storage that they take and own and manage for others. So there is a number of issues, in fact they manage almost over 25% -- over 20% of the natural gas storage in the Northwest so I kind look at them as my unregulated utility because that's really what they're doing; they're managing pipes and wires and generation facilities. They are just doing it on the unregulated side for others, and then we have our regulated utility that does it under regulation

Wouldn't, -- if the hydro situation is good, would that reduce the prices that you might get in the market for that some, and offset part of the volume or is it that, you obviously must be better from?

If we had a good hydro here, what it does is that it allows them to take and move power to other places like California, as an example, we have got a 200 megawatt path in the Northern California. So it means that they can buy cheaper power to move into a more expensive market. So those are the kinds of things that they do, and especially when they're managing it for others those assets are there and we'll produce power. We've got actually about 450 megawatts in Canada right now, and our actually moving that power in the Canadian markets, as well as I think under this energy if you remember and John you may not, but we do have a retail, on I say retail, is really to industrial customers, natural gas company, and British Columbia that serves about 50% of all the industrial gas is sold in British Columbia. And that has done very well for us in the last couple of years.

Good. You mentioned moving power to California, there has been an item going on around the financial markets that there is a transmission line that's going to have the -- have some restrictions down to California, and then they actually be out later in the summer, and if that was possibly and if that's is always to show prices lower in the Pacific Northwest, have you quantified that kind of effect on marketplace for transmission?

Oh, yeah. We -- the folks do all kinds of scenario planning around, what may or may not happen, and what the best way to serve our customers are.

Okay. Just one last follow-up and that is the question on the Coyote Spring plant, now that's part of your Idaho case, is that right?

Yes, it is.

Okay. Or will be, I mean, sorry, will be part of that?

Yes.

Any question around that with regard to, -- you've said in the past, that you are going to file that fairly assuming soon

Right.

Well that case, with the plant being out, is that a kind of use and useful issue for -- over in that jurisdiction, or do you know how that would turn out to be?

No, I -- well, of course, we don't know, at this point and we haven't filed yet.

Sure.

But what I would suggest to you, is that we should have it back in service well before, the case is decided.

Good.

In Idaho, it's at least probably going to be 8 months or longer and the plant should be back in service, well before and so it will be used & useful.

Very good. Thank you.

Sir, our next question is from Peter Sue (ph.) with Gemco (ph.).

Good morning.

Good morning, Peter

Congratulations on great quarter, and a great year.

Thank you.

Thank you.

I just had a few clarification questions on your transmission, as now I know; in your press release you mentioned you want to spend $100m on transmission by the end of 2006. Could you talk a little bit about how you are going to finance the investment and how the earnings will roll in overtime?

Yeah. Actually, I will let Malyn cover that, but basically we are financing everything internally on that. And that is in our CAPEX budgets and our budgets going forward, including our forecast. But I will let Malyn cover it in more detail.

Peter, it's a fairly significant bite for us, and actually it will be a fairly large piece of the capital budget going forward. Having said that, we are still holding the line on our CAPEX spending expected this year to be little less than $110m. And frankly that will roll into the rate cases that we'll be filing overtime and asking for recovery of those dollars as any other [planeticians] would.

I see. When you seek recovery for the investment, will it be really earning into the cash flow roll in as you put in your investment or would it all come in at the end of 2006 if it is at the end of 2006 and much over the time period?

Oh, I think the question you are asking is that are we going to wait till 2006 before we roll it into rate. The fact is that in our Idaho case, we will have picked up a small piece but what we've already installed in 2003 will be a part of that case.

It's been done in phases, Peter and so there is some natural progression here to add it overtime, you know. So it's not going to be a big one at the end that we'll be asking for. And we are not planning to do any specific project financing around it. If you look at our cash flows, we continue to show a positive cash flow in excess of CAPEX and so we really don't need to do financing. Again, we might take some opportunity, we've got a fairly big chunk of debt that matures in 2007 and 2008 and we may do some things in the shorter term to try to take care of that lump again and smooth it out. So, you may see us do some financing this year and/or next year. But we have no need to do it based on our Capital expenditures.

Okay, great. And then for the capital structure for the investment, shall I be thinking about 50% equity, 50% debt?

Well, we'd like to get there but it's going to take us -- that's going to take sometime to build the equity ratio up. We're making progress on that as you know and our goal in the long term is to have the debt ratio below 50%.

Okay great. What's an approximate range of ROEs I should think -- be thinking about for transmission investments. I know it's FERC regulated entity and I think that transmission ROEs pick range anywhere from between -- I know it's certainly higher than utility, but the range that I am thinking about is something like a 12, 13% ROEs.

Actually Peter all of our transmission is under our state regulation, so all our --.

Okay.

So the state will set these ROE funds.

Are their rates different from what you would get at the distribution business?

No, they're not. It's all rolled in together; it's all part of our installed plan.

Okay. Good, thank you very much.

Thanks Peter.

Once again ladies and gentlemen, as a reminder "*" "1" for any questions. We have a question from Paul Debbas with Value Line.

I have a couple of questions.

Hi Paul.

Hi. What's the outlook for O&M expense this year?

Well, Paul we're continuing to see some upward pressure on O&M expense caused by higher insurance cost, primarily our pension cost have actually stabilized and I am real pleased about that although we're still not recovering a significant percentage of that in rate. So that's an issue that's driving some of our rate cases. But we expect pension to be flat and we expect.

The other piece that was, that hit us last year pretty hard was our property and D&O insurance and we expect them to flatten out. In fact our property insurance actually came in a little bit less than it did in 2002, when we renewed it for the next year 2003 -- when we renewed it for next year.

The other major driver in terms of our O&M expenses is Coyote Springs, we'll have a full year of maintenance expenses versus the half of year, a half this year. And so I think that you can look for -- and we are trying to hold the line on the rest of the cost, but I think you may see as much as 5% increase in the O&M expense line year-over-year for '04 versus '03 caused primarily by that increased maintenance expense on Coyote and some of the other plants that we've put in rate base and the insurance issues.

Okay. And do you have a specific dividend policy as far as in annual growth rate or a payout ratio?

Actually, no, we have reviewed it with the Board every quarter and that is Board's decision.

Okay. Thank you.

We have a question from Dough Fischer with A.G. Edwards.

Thank you. Could you comment on O&M was up in the fourth quarter that had early springs or exactly what is that? And then secondly, weather impact for the year, is there -- do you break that out versus the hydro and that, you know, what kind of gross margin would you have lost due to abnormal weather which is normally in '03?

Okay. Malyn will help me on this, but most of the fourth quarter increase in expenses for the Coyote Springs 2, the maintenance cost on it. Insurance, of course, was a big piece that and then the pension expenses a big piece of that. We did have some storms that did cost us some, but they were actually minor in nature and I think if you average the year we were probably under budget in our storm damage.

And the second part of the question Doug was weather? Would you repeat just that part of the question.

Okay. Was weather for the year milder than normal and if so any kind of ballpark as to what kind of gross margin and it will be that was versus?

Gary. It was warmer than normal and I can't remember exactly what it was but it seems to me like it was about 5% warmer than normal overall. It was colder than 2002, but it was still warmer than normal; we had some very cold pieces and then we had some very warm, it's like you know, few weeks or a week or so though we are very cold today is almost is 40 degrees here unfortunately, but Malyn why don't you talk a little bit about kind of the impact of those things.

I've tried to quantify that and that's -- it's a not an uneasy thing to quantify because it really goes up and down from months-to-months, but our gas gross margins look to me like it will cost us about a nickel as a result of the first and fourth quarter being warmer than normal.

Okay and then on the electric side you almost all be on the gas side versus the electric.

That's right our electric loads were very close to what our forecast was we had some good strong air-conditioning load in the summer for us -- we don't you know, it's never that hot here but it was warmer than normal and so the electric loads turned out to be very close to what we were forecasting for the year

Okay thanks. That's helpful.

It's your final question comes from Christie Quivic (ph.) with Northwestern Mutual.

Good morning

Good morning Christie.

Hi.

Yes.

Could you -- you stated earlier that operating cash flow would cover the $110m of expected capital expenditures in '04, is that also going to cover your dividends?

Yes.

And then any further debt reduction targets this year?

We have a target of $50m a year for the next three years.

Okay, Thank you.

That was our final question, sir.

Ladies and gentlemen, thank you for joining us today. If you have additional questions or follow-ups, please don't hesitate to call us. And I suggest you touch basically with Angela Teed at 509-495-2930. A replay of this conference call will be available today, beginning at 12:30 New York time. The contact information for the teleconference replay, as well as for the web cast and slides are available on the Avista Corp. website. And again thank you for joining us and have a great day.

Ladies and gentlemen, we thank you for your participation in today's conference. This concludes the presentation and you may now disconnect.