Avista Corp (AVA) 2007 Q2 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the second quarter 2007 Avista Corporation earnings conference call. (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 call, Mr. Jason Lang, Manager of Investor Relations.

Thanks. Good morning, everyone. Welcome to Avista's second quarter 2007 earnings conference call. Our earnings were released pre-market this morning, and the release is available on our Web site at AvistaCorp.com. Joining me this morning are Avista Corp. Chairman of the Board and CEO Gary Ely, President and COO Scott Morris, Executive Vice President and CFO Malyn Malquist, and Vice President, Controller and Principal Accounting Officer Christy Burmeister-Smith.

Before we begin, I would like to remind you that some of the statements that will be made today are forward-looking statements that involve risks and uncertainties, which are subject to change. For reference to the various factors which could cause actual results to differ materially from those discussed in today's call, I would direct you to our 2006 Form 10-K and Form 10-Q for the quarter ended March 31, 2007, which are available on our Web site.

To begin this presentation, I would like to briefly recap the financial results presented in today's press release. Our consolidated earnings for the second quarter of 2007 were $0.26 per diluted share, a slight decrease from $0.27 per diluted share for the second quarter of 2006. On a year-to-date basis through June 30, our consolidated earnings were $0.53 per diluted share, a decrease from $0.91 per diluted share for the six months ended June 30, 2006.

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

Thanks, Jason. Good morning, everyone. 2007 is a year of re-positioning our company with a focus on the future of our utility operations. The most significant event to date has been the completion of the sale of substantially all of Avista Energy's contracts and ongoing operations to Coral Energy Holding, a subsidiary of Shell, and certain of Coral's other energy subsidiaries. This transaction lowers our corporate risk profile and should increase the stability of our earnings. Over time, we plan to strategically deploy the majority of the proceeds from this transaction into our utility operations.

We pursued this transaction with the goal of reducing our risk profile, while making sure the customers of Avista Energy would continue to receive the kind of value and service they had come to expect over the past decade. In addition, it was important to ensure that our employees would be treated fairly, and to realize a fair value for the business.

I believe that we have accomplished all of these objectives with Coral Energy. It is a large international company with experience across all energy segments. Coral is already active in the Pacific Northwest, and desires to expand its business here. Coral has committed to maintain a significant presence in Spokane, Vancouver, British Columbia and in Montana, and they have hired almost all of our Avista Energy employees.

Over the long-term, our investment in Avista Energy has performed very well, with an annualized internal rate of return of over 16% during the past 10 years. However, the energy markets have changed significantly over the past few years. In many respects, the markets have become more national in scope, and large financial players have entered them. In today's world, credit is harder to come by, and the importance of a large balance sheet is important in order to properly conduct business. All of these issues caused us to reexamine our strategic alternatives, and we concluded that we should sell Avista Energy.

I now believe that we are well structured for the future success of our core utility business. Our consolidated earnings will not be what we had anticipated or expected or planned for, due to both the performance of Avista Energy and certain variables that have worked against us at the utility. This included weather conditions that were warmer than normal during the heating season, and the timing of our hydro generation with below-normal generation in the second quarter. However, I believe we are well positioned for 2008 and beyond, and with expected solid growth and more stability in our consolidated results.

Now I will turn the call over to Scott Morris for a report on utility earnings.

Thanks, Gary. Good morning, everyone. Avista Utilities contributed $0.32 per diluted share to earnings for the second quarter of 2007, compared to $0.34 per diluted share for the second quarter of last year. Although net income increased over the second quarter of last year, the contribution to earnings per share decreased due to the dilutive effect of common stock that we issued in December of last year. On a year-to-date basis, our utility operations contributed $0.70 per diluted share, a decrease from $0.87 per diluted share through June 30, 2006.

These results were below our original expectations, and our utility earnings will most likely fall short of our original target for 2007. This is primarily due to the Washington Commission's denial of our request for rate relief last December, higher-than-expected costs under the Washington Energy Recovery Mechanism, or ERM, and lower-than-expected loads.

The decline in our results for the first half of 2007 as compared to the prior year was primarily due to a decrease in electric gross margin and an increase in other operating expenses.

Electric resource costs were higher than the amount included in base rate for the first half of 2007. This was largely driven by higher fuel costs and greater use of our thermal generating resources, in particular Coyote Springs 2, to meet demand in January and February. Also, hydro generation was below normal for the second quarter, and we experienced some unexpected outages at our generating plant. As a result, we did not receive the level of benefit that we were anticipating under the ERM during the second quarter of 2007.

We recognized $2.4 million of expense under the ERM during the first half of 2007, as compared to a $7.2 million benefit recognized during the first half of 2006. This change from the prior year reduced our earnings by $0.12 per diluted share. And as you will recall, in the first half of 2006, we benefited from higher-than-normal precipitation and warmer-than-normal temperatures. And as a result of warmer temperatures and lower retail loads in this period last year, we were able to sell excess generation in the wholesale market at relatively high prices, which reduced our electric resource costs as compared to the amount included in base rate.

Based on our current forecast for fuel, purchased power costs and hydro generation, we're expecting to absorb costs under the ERM for the full year of 2007. Our original earnings guidance assumed the absorption of about $6 million under the ERM for the full year of 2007. And although we are expecting annual hydro generation to be near normal for 2007, due to the timing of the spring runoff, outages at generating plants, and higher-than-anticipated purchased power and fuel costs, we are now expecting to absorb approximately $8 million of costs under the ERM for the full year of 2007.

It's important to note that the amounts recognized under the ERM can vary significantly from quarter-to-quarter. And as you might expect, we will probably absorb additional costs under the ERM in the third quarter, as we usually experience low hydro conditions during that period.

In addition to the effect of the ERM, our electric and natural gas loads were below our expectations for both the quarter and year-to-date. This appears to be due to warmer-than-normal weather during the heating season, lower-than-expected customer growth, and customer response to price increases, particularly with respect to natural gas price increases.

On a positive note, July was among the hottest on record in our service territory, and I'm pleased that our system performed very well in meeting consistently high electric demand. So we are starting off the third quarter with retail electric sales above expected levels.

As you will recall, our gross margin for the first half of 2006 was increased by income received during the first quarter for the sale of claims against Enron Corporation and certain of its affiliates representing the recovery of lost margin. This increased our earnings for the first half of 2006 by $0.04 per diluted share.

Also contributing to the year-end -- to the year-to-date decline in utility earnings was an increase in other operating expenses, which reduced earnings per diluted share by $0.06. The decrease in electric gross margin and the increase in other operating expenses during the second quarter and year-to-date 2007 for the utility were somewhat offset by a reduction in interest expense. This was partially due to the positive effects of the financing transactions completed in the fourth quarter of 2006. The decrease in interest expense positively impacted diluted earnings per share by $0.02 for the second quarter and $0.05 for the six months ended June 30, 2007.

In April we filed a General Rate Case in Washington. We requested to increase electric rates for our Washington customers by an average of 15.9%, which is intended to increase annual revenues by $51.1 million. Approximately 42% of the increase in electric revenues provides for an increased level of production and transmission expenses. A portion of these costs would otherwise be recovered through deferrals under the ERM, and as such would not increase net income.

We also requested to increase natural gas rates by an average of 2.3%, which is intended to increase annual revenues by $4.5 million. Our request is based on a proposed rate of return of 9.39% with a common equity ratio of 47.8% and an 11.3% return on equity. In this filing we have requested the establishment of a limited scope proceeding called power cost-only rate case. This process would allow us to file for updates to our base power and supply -- our base power supply and transmission-related revenues and expenses between general rate cases to provide more timely recovery of our costs.

The current schedule from the WTC anticipates an order in the General Rate Case on or before March 1 of 2008. And as we look to the timing and the planning for future filings, we will take into consideration the assessment of our needs for rate relief, our short-term and long-term needs, as well as specific factors that can affect the timing of such filings. Such factors would include in-service dates of our major capital investments and the timing of any changes in major revenue and expense items. Going forward, we are planning to file a natural gas General Rate Case in Oregon by the end of 2007.

As Gary mentioned, we plan to strategically deploy the majority of the proceeds from the Avista Energy transaction into our utility operation. Proceeds from the sale of Avista Energy's net assets to Coral Energy and the liquidation of Avista Energy's remaining net current assets are expected to total approximately $170 million, to be received in the third quarter of 2007. We have already received most of these funds. And in the short-term, we will use the funds to keep borrowings under our committed line of credit at a minimum, and place the excess funds into short-term investments. These funds will allow us to increase our utility equity ratio. And over the next few years, we plan to invest these funds into our utility infrastructure, and we expect our rate base to grow by about 6 to 7% per year in 2008, 2009 and 2010.

I'd like to provide you with a little more detail on our capital budget program, as it is an important part of the value that we are creating for both our shareholders and our customers.

For 2007 our original capital budget was $170 million, plus $8 million for the advanced meter reading project in Idaho. We may be increasing the budget by around $10 million in the second half of this year. These projects are necessary to provide reliable and safe service to existing customers, and to serve new customers in our service territory. With a beginning rate base of about $1.6 billion, and 2007 depreciation expense of $85 million, our rate base is growing by about 5% in 2007. Of course, we expect that this will eventually translate into earnings growth of a similar magnitude, depending on the receipt of timely rate recovery.

Our preliminary 2008 expectations call for our capital budget to exceed $200 million. We will be performing upgrades on some of our hydro projects. We will continue to reinforce and expand our natural gas and electric distribution system. And we're also looking for an appropriate wind generation site or generation projects that meet the renewable energy standards passed this year in Washington state. We hope to resolve the relicensing of the Spokane River hydro projects and our long-standing dispute over the use of Lake Coeur d'Alene, both of which may require capital expenditures.

We're also expecting our capital budgets to exceed $200 million in 2009 and 2010.

We will continue to request rate adjustments as necessary in future periods in order to recover our capital and operating costs, limit regulatory lag and provide a reasonable return to our shareholders. And at this point, I would like to give you an update on the relicensing of our Spokane River hydro facilities.

We've been engaged in a multiyear collaborative process with stakeholders to develop reasonable terms and conditions for the new licenses. We have submitted applications to the FERC to issue two licenses, one for the Post Falls facility and one for the other four hydro plants on the Spokane River. The current license expires today. And as the FERC has not issued final license orders, we will begin operating the plant under an annual license. This will in effect extend the terms and conditions of the expiring license.

In May, the Department of Interior issued final mandatory conditions for Post Falls. In July, the FERC issued a final Environmental Impact Statement. This is the last administrative step for the FERC before the issuance of license orders. However, the FERC cannot proceed until several other matters are resolved, including Clean Water Act and Endangered Species Act issues. We are currently in the process of reviewing the final Environmental Impact Statement. And while we believe the ultimate cost of relicensing will be less than our earlier projections, we are unable to base specific new cost estimates on our analysis of the final terms and conditions issued by the Department of Interior and the final Environmental Impact Statement at this point.

There is still some work to be done by multiple stakeholder parties, and we cannot predict the timing or outcome of the final stages of the relicensing process. But we will continue to work with our stakeholders to finalize reasonable terms and conditions for the licenses, and we will seek recovery of all operating and capitalized costs associated with the relicensing and operation of the Spokane River plant.

Now I will turn this presentation over to Malyn Malquist for an update on the segments of our -- on the other segments of our business, financing activities and our earnings guidance for next year.

Thanks, Scott. Good morning, everyone. The Energy Marketing and Resource Management segment, which is substantially comprised of Avista Energy, had a net loss of $0.07 per diluted share for the second quarter of 2007, compared to a net loss of $0.09 per diluted share for the second quarter of last year.

On a year-to-date basis for 2007, this segment had a net loss of $0.22 per diluted share, compared to a contribution of $0.01 per diluted share for the first half of 2006. The net loss for year-to-date 2007 includes the after-tax net loss of $3.4 million, or $0.06 per diluted share, on the sale of substantially all of Avista Energy's contracts and ongoing operations to Coral Energy.

These lower-than-expected results from Avista Energy were primarily due to the underperformance on the power side of the business, losses on the power purchase agreement for the Lancaster plant, and the difference between the estimated market value and the required accounting for certain contracts and physical assets under management.

Turning to Advantage IQ, the company's earnings for the second quarter and year-to-date 2007 were lower than the respective periods of 2006. This was primarily due to increased operating costs, which included expenses for consulting services related to long-term strategic planning for the business, which we incurred during the second quarter. We brought in some external help to examine current and future markets, and the best way to grow the business to maximize our shareholder value. This work cost us about $0.01 per diluted share in the quarter, but we believe that this will pay for itself many times over in the next few years.

I would like to comment further on the strategic work at Advantage IQ. Our consultant performed a detailed review of the markets we serve, as well as potential markets. The results were very enlightening. For example, we have a handful of customers that have encouraged us to move into international markets. The consultant examined this market and concluded that the market was very fragmented, the start-up costs large, and the risk quite high, and recommended against moving into that market.

The consultant reviewed margins for each customer segment and each customer, helping us to identify customer segments where we clearly need to improve our margins. The consultant's work, clearly beyond what we have the expertise to do internally for ourselves, will give us a road map to target markets where we can receive the best return on our investment. It will also help us to better determine appropriate pricing for our customer contracts.

The business has continued to grow its top-line this year, but the expenses associated with this study, as well as our efforts to upgrade our core information systems to increase our efficiency, have caused our expenses to grow, negatively impacting our bottom-line. We expect to return to positive earnings growth next year.

In the Other business segment, our results indicate an improvement over the prior year, as measured on a year-to-date basis. This was primarily due to net gains on certain long-term or legacy venture fund investments in 2007 as compared to net losses in 2006.

With respect to cash flows, during the first six months ended June 30, 2007, positive cash flows from operating activities were used to fund our cash requirements. These cash requirements included utility capital expenditures of $92 million, debt maturities of $12 million and dividends of $15.6 million. As cash flows from operating activities and other sources of cash inflows exceeded other funding requirements, our total cash and cash equivalents increased by $75 million during the first half of 2007. This was primarily due to the liquidation of restricted cash and deposits with counterparties at Avista Energy. Also, our deferral balances decreased over $20 million during the first half of 2007, primarily due to recovery from customers. For the remainder of 2007, we expect net cash flows from operating activities, proceeds from the Avista Energy transaction, and our committed line of credit to provide adequate resources to fund all of our capital expenditures, maturing long-term debt and preferred stock, and dividends, and other contractual commitments.

We have $358 million of long-term debt maturities and mandatory preferred stock redemptions in the remainder of 2007 and 2008. This includes over $270 million of 9.75% notes that mature in June of 2008. While proceeds from the Avista Energy transaction should reduce our needs, our forecasts indicate that we will need to issue new securities to fund a portion of these requirements during 2008.

In 2004, we entered into forward starting interest rate swap agreements, effectively locking in market fixed interest rates, which were relatively low compared to historical interest rates, for $125 million of our forecasted debt issuances in 2008.

In May, the Board of Directors declared a quarterly dividend of $0.15 per common share. This was an increase of $0.005 per common share over the previous quarterly dividend declared in February of 2007. This was the sixth common stock dividend increase authorized by the Board of Directors in the past four years, and it's an important indicator to our shareholders of the progress we continue to make in strengthening our financial health.

When the company is able to restore its investment-grade credit rating, management intends to recommend that the Board gradually increase the dividend payout ratio to be more in line with the average payout ratio for the utility industry, which currently is approximately 60 to 70% of utility earnings. The Board considers the level of dividends on a regular basis, taking into account numerous factors, including financial results, business strategies, and economic and competitive conditions.

Due to an error that we recently discovered, we have made some relatively minor adjustments to our year-end 2006 consolidated balance sheet. During preparation of our Form 10-Q for the quarter ended June 30 of 2007, we determined that we had not previously recognized the actuarial, liability or costs relating to a plan that provides benefits to the beneficiaries of former and current executive officers of the company in case of their death. We believe the impact of this error to net income or the balance sheet in any period in the 2006 Form 10-K is not material. As such, pursuant to the Securities and Exchange Commission Staff Accounting Bulletin #108, we plan to reflect the correction of this error through future filings with the Securities and Exchange Commission, including our quarterly report on Form 10-Q that we plan to file on or before August 9.

At this time we are revising our guidance for Avista Utilities downward to a range of $1.00 to $1.10 per diluted share for 2007, a decrease from our previous guidance of $1.10 to $1.20 per diluted share. This decrease is primarily due to our expectation of absorbing higher costs under the ERM and lower retail loads.

When we gave our initial guidance for 2007 nine months ago, we believed that we would receive a positive result from our Production Transmission Cost Update request in Washington. The WUTC's decision late last year to deny our request presented a significant challenge for us to replace the assumed rate relief, which amounted to about $0.17 per diluted share. As we discussed in our year-end earnings conference call, with the hard work of our employees, we were hopeful of meeting our original earnings target, although we indicated that we would likely be at the low-end of our guidance. We did not foresee the lower-than-expected loads that we have experienced this year, which have been largely weather-related, and we did not expect to absorb higher costs under the ERM.

These negative factors are partially offset by the deployment of proceeds from the Avista Energy transaction, primarily through the repayment of borrowings under our committed line of credit and the short-term investment of excess funds.

The outlook for Avista Utilities assumes, among other variables, normal precipitation, temperatures and hydroelectric generation during the second half of the year.

The 2007 outlook for the Energy Marketing and Resource Management segment has been revised to a loss of $0.22 per diluted share, which is our reported results for year-to-date. The loss from this segment reflects the operating loss for the first half of 2007 and the loss on the sale of the business. With the completion of the transaction, we are not expecting any significant activity in this segment for the second half of 2007. We are happy to bring this segment in our history to a close.

We are making a slight revision to our guidance for Advantage IQ to a contribution range of $0.11 to $0.13 per diluted share, a change from our previous guidance of $0.13 to $0.14 per diluted share. This change is primarily due to the expenses for consulting services during the second and third quarters.

We expect our Other business segment to lose $0.02 per diluted share for the year.

Based on the revisions to each segment, we are revising our guidance for 2007 consolidated earnings to be in a range of $0.85 to $1.00 per diluted share.

For 2008 we are initiating guidance for consolidated earnings to be in the range of $1.35 to $1.55 per diluted share. The Company expects Avista Utilities to contribute in the range of $1.20 to $1.40 per diluted share for 2008. The outlook for the utility assumes, among other variables, normal precipitation, temperatures and hydroelectric generation, as well as the implementation of the Washington General Rate Case in March of 2008. This wide range for Avista Utilities reflects the inherent uncertainty regarding the outcome of the rate case.

We expect Advantage IQ to contribute in a range of $0.13 to $0.15 per diluted share, and the Other business segment to be between breakeven and a loss of $0.03 per diluted share.

Now I will turn the presentation back to Jason.

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

(OPERATOR INSTRUCTIONS). Paul Ridzon, KeyBanc.

What was the mark-to-market impact in the second quarter?

We're checking on that. Paul, we will get back to you on that. With the sale, we realized a portion of the mark-to-market with the final sale. So that would have been included in the $0.06 loss that we took. But, it looks like we had about $1 million.

That's after-tax?

Yes.

A $1 million (inaudible)

$1 million loss.

Could you just review -- there was a comment about the Washington GRC would provide $51.1 million of revenues, and there's a 42% (inaudible) production in transmission, which would not have -- is it 42% of $51 million would have no net income impact?

The 42% is the portion of the $51 million -- that is attributed to fuel and purchased power. It will -- it could have an impact on net income because what ends up happening is the midpoint of the ERM gets reset. So this year where we expect to lose $8 million, you would expect next year to start out at breakeven going into the year. So there is some earnings impact associated with that 42%.

You filed for -- basically you're raising your threshold by $8 million of where you start the breakeven?

It's not quite that simple, because recall how the ERM works. There is a $4 million plus or minus that we eat 100%, and then the next 4 million is plus or minus -- we keep 50% of that. So when we're eating $8 million this year, our actual costs are expected to exceed what's in rates by about $18 million. So we're booking that first 6 million, and then -- which accounts for 8, if you're with me -- 4 million, 100%; 2 million for 50%; that gets you to 6. And then we have additional costs that we only eat about 10%; we only eat 10% of the additional. So we're expecting our costs to be higher. Now, what we also are reflecting is expected '08 costs, and the markets change for '08. And so, I guess the easiest way to look at that is, again, we're resetting, and you would hope next year to not have an $8 million drain on earnings starting the year.

So it's really like $21 million that you're moving against the 42% of $51, and that benefit or hurt to you is much less because of the sharing kicking in?

That's the way to look at it. Yes.

I know you gave an '08 CapEx number in excess of 200. I had to jump off for a second. Did you talk about '09?

Yes we did, and we said we expected it to also exceed $200 million in '09 and 2010.

Is that kind of the timeframe you're anticipating having fully deployed the receipt of the trading proceeds?

Yes.

Could you just give a little more clarity of what gradually bringing the dividend up to a 60 to 70% payout ratio entails, from a timing standpoint?

I think what we were wanting to indicate to you there is, unlike some other utilities, we wouldn't do it in one kind of -- one event change. We would probably see the Company, the Board, wanting to do it in a step fashion, where maybe it occurs over a two, three, four-year period. And I can't tell you for sure what they would do, but I think that management would prefer to see it done in that kind of a fashion.

Any update on Washington, and any reaction to your rate case filing, particularly with regards to the equity layer?

I would say at this point it's just a normal process where we continue to get a request from the staff on our case and other intervenors, and we're filing those information requests back to them. And it's on track, and really nothing to report there. It's just in the normal process. We wouldn't expect to really start discussing settlement until well into the third quarter or fourth quarter, and that's probably the timing for that kind of discussion.

Do we have any -- enough experience under our belt to comment on elasticity response to the BPA reset?

What we've historically seen is for a change in rates of about 10%. We would expect to see price elasticity of about 1%. That's generally the rule of thumb. And so, that was a fairly significant change for our customers. And we are, I think, seeing -- we saw that in the first six months of the year our retail loads for both electric and gas were below what we expected to see. So I think some of that is price elasticity, and I think probably more of it is weather, frankly. But it's a combination of the two.

And you've contemplated the BPA delta and some assumption for the rate case outcome in your forecast with regards to an elasticity response?

Yes, we did.

John Alli, Zimmer Lucas.

Just a few questions regarding the '08 guidance. There's a fairly wide range there, $1.35 to $1.55. I was wondering if you could go over the range of assumptions that would take you from $1.35 to the $1.55.

It really is largely a determination of how much you think we can get in rate relief. John, we tend to not want to lay that out very clearly, because we don't want any of the parties to the case really to say, well, you said you thought you would get this percent, and so if we don't give you 100%, that's what you expected to get. So I'm going to be a little bit elusive about that, frankly.

But what I will tell you is that at the low-end of the range, we are only earning about a 7.5% ROE. And at the high-end of the range, we're only earning about a 9% ROE. So part of that is a result of the timing. And we're assuming that we're going to get rate relief sometime in March. We may have an opportunity to settle and get it in January. And in January and February, those are big usage months for us, and it could have a significant impact on the end result and put us closer to the higher end of the range. I guess the other message there is, even at the high-end of the range, we are definitely experiencing some regulatory lag, and not likely to earn whatever the authorized ROE is for the year.

Given your increased CapEx, when do you think you'd have the opportunity to go in and get a little more recovery?

I think one of the things we're asking to do is get a [peak work] in place, a purchase that would allow us to have resets more quickly and a little more often. And I think that's important, given the need that we see just to put a lot of capital in the business. (multiple speakers)

John, I would also add that it really depends on the outcome of the Washington case, the timing of when we would turn around and have to file again in Washington. That's one driver. As well as we continue to look at Idaho. We did say we were going to file in Oregon, so --

What are you earning in Idaho and Oregon?

We're consistently earning our allowed returns in Idaho at this point, but we always are kind of looking at a forward forecast to see what we think might happen in '08 and '09. So we're evaluating Idaho and we are filing in Oregon. And in Oregon, we're right now at about a 5% return.

5% ROE or return on rate base?

Return on rate base.

What would the ROE be on that then?

We're allowed to earn in Oregon about (multiple speakers) 10.25% is the current.

And what are you actually earning?

At that level it's pretty low.

You filed for a 47 or 47.5 in Washington? Is that correct?

ROE -- excuse me (multiple speakers) we filed for 47.8.

And it seems like you have a little more room in your balance sheet. What would you do with the additional -- if I can get you up to a 50% equity ratio -- the additional 2% of balance sheet?

What we would like to do is we would like to be able to earn on whatever we have. And so if the Commission in Washington is resistant at a 48%, if they don't want to let us earn on a 48% return, we probably wouldn't want to have that much on the balance sheet. And we likely would look at ways to reduce that amount. There's a couple of obvious ways that we could do that. But we want to -- we really would prefer to have that equity ratio somewhere in that 48 to 50% range. So we're going to test that with the Commission in this case.

For your 2008 guidance, what are you assuming your ROEs are in Oregon and Idaho?

In Idaho, I think we are pretty close to authorized returns. In Oregon, we're clearly well below, because I'm looking at the rest of the folks here, in terms of what we've assumed for timing on rate relief there. April rate relief is what we have assumed. Obviously, we won't earn the full return. I guess we would probably be somewhere in the 8% range.

(OPERATOR INSTRUCTIONS). James Bellessa, D.A. Davidson & Co.

Several of my questions were answered, but I have a few. If I look at the guidance for '08, the bottom-end of each number turns out to be $1.30 and the upper end works out to $1.55. Yet your overall guidance is $1.35 to $1.55. Can you explain the bottom-end variance there?

I think that we just believe we've got to find a way to get to that $1.35 to $1.55 range. And so we're going to do everything we can to have those segments operate to get us at least to that level. We don't think that everything is going to go against us next year, as it seems to have done this year.

The new guidance for '07, $0.85 to $1.00, that's down from -- what level was the previous guidance?

For the utility or for the consolidated?

Consolidated.

I'm looking for that. I don't have that at my fingertips. I'll have to call you with that.

The loss of $0.06 for exiting the assets of Avista Energy, what was that dollar amount? You said it could have been up to $5 million, but what was the total (inaudible)?

It was $3.4 million. That's after tax.

And you had previously hoped for $175 million in proceeds, and now you're saying $170. Can you tell us the variance there?

I think that was a result of the gas inventory levels, the price that Coral paid at the time of closure of the sale. I think that was the largest variance there. The price of natural gas had dropped quite a bit by June 30.

I think you touched on second-half potential earnings. Could you go over those points as well, second half of '07?

What we did was we gave revised guidance for the year, and so we didn't really talk about the specific -- didn't do the math on the second half of the year, first half versus the guidance. But we are expecting that our hydro conditions are going to be pretty close to normal. We are off to a good start in July. Scott mentioned that our electric use was actually quite a bit higher than budget because we had one of the hottest average temperature months in July that we've had. And so we would expect all of those things to contribute to a fairly normal second half of the year.

The streamflow numbers are below normal, yet you're saying your hydro conditions, or hydro generation, in the second half will be more normal. How does that happen?

Jim, as you know, when we run out of water for the third quarter we're in essence to natural flows. And then if we have normal precipitation into the fourth quarter, often it regenerates, and we're able to go ahead and it will increase in the fourth quarter. So, assuming normal precipitation, we expect to have additional hydro for the fourth quarter.

You indicated that so far this year you have incurred $2.4 million of expense under the ERM, and that the full-year absorption is expected now to be $8 million. So, incremental, a second-half number of $5.6 million more. Do you have any characterization on how that hits the second half, which quarters or --?

I think that the large majority of it will hit in the third quarter, because our hydro conditions are the lowest in that quarter, and the price of purchased power tends to be highest in that quarter.

Does that suggest perhaps a reported loss by the utility in the third quarter?

Not necessarily. I think, again, because our retail loads are looking pretty good --

Although, Jim, if you remember, usually our third quarter is a negative quarter over -- if you go back through history, so it's not unusual to have it. We're not necessarily anticipating that. But historically, it always has been a negative quarter.

John Hanson, Praesidis.

I have several items here. You mentioned you had unexpected outage that was part of the [effects] here. Was that unexpected outage in Q1 or Q2?

Q2.

What plant was that?

We lost a transformer at Coyote Springs, which it was off-line for a lot of the quarter, but we did get it back on at the end of the second quarter. And then we lost a unit at Noxon, which affected some of our generation from hydro.

Okay. Thanks on that point. The second thing I had was on the Washington case, you are filing for peak or some kind of tracking of cost? That's in your part of your plan now?

Yes. We filed, in essence, the same mechanism that Puget's had for a number of years to be able to file a power cost-only rate case in between general rate cases, so that we can reset our power and purchase -- our fuel and purchased power expenses.

So it's fuel and purchased power that's set in there, not capital the cost of those lines?

We will try to -- in the mechanism you can include new generation facilities as well as some transmission upgrades as part of that mechanism. And that's part of the ask. It depends -- again, you don't always have those when you make those filings. So if we had those, we would include them. And if we did not, we would just do purchased power and fuel expenses.

And Puget's been doing that to get some of their wind in (inaudible) been successful (inaudible)?

Yes.

Thanks. Good luck, guys.

James Heckler, Levin Capital Strategies.

I was wondering -- on your '08 guidance, that range assumes a March 1 effective date for rate. Is that correct?

That is correct.

I was wondering if you could talk about what that guidance range may be if, hypothetically, there was a settlement, and rates went into effect January 1.

I don't know that we can really answer that question, because we've, obviously, assumed that we're not going to get everything that we asked for. If we were to have a settlement, generally, the way those settlements work is you give something to get something. So if you want it earlier, you're probably going to get a lower level of revenue out of it than if you proceed through the case. At least that's -- from the CFO's perspective, that's why we'd settle. But you would only do it if it would benefit you. So if we thought handicapping it, we could get a better deal by -- or more money for the year by settling earlier, we would probably be inclined to do that.

But given that first quarter is kind of a significant quarter for you, if I'm thinking about what a more normalized range would be, would it be fair to say that that range would be higher?

We would take that into account in our analysis of whether we should settle or not.

Paul Ridzon, KeyBanc.

You indicated that your depreciation line at the utility is about $85 million a year?

Yes.

Where is that going to go over the next couple of years? Just modestly increase by a couple million a year?

Generally speaking, most of the investments that we're making are in a traditional utility plant, which has about a 30-year depreciation line. So if you assume $200 million of -- on an annual basis what we're going to spend, roughly $200 million, then you've got $6 million of additional depreciation each year coming in.

And with regards to you're exploring wind, have you talked to vendors yet? Where are you in that process? Where are you in finding land? And if you were to purchase land before -- basically secure some land, given that there's competition for those resources, what --

We've done an extensive look-see. If you'll remember, we did a 2005 RFP looking for wind opportunities. And unfortunately it didn't meet our price point, so we did not make a choice to enter into any wind deals at that point. But we continue to look. We've got opportunities both in our service territory to minimize transmission expense, and also some opportunities just on our outskirts of our service territory, again, to really minimize some of those transmission exposures in the wheel.

We continue to look -- if you remember, to do -- the Washington initiative says that you have to build the wind in the state of Washington or the Columbia Basin area. So we've been primarily looking in the Washington/Oregon area. If you look at what we need for the law, Initiative 937, we only need 3 megawatts of wind by 2012, or 3 megawatts of renewable resources. So it's not that we're in dire need to find it immediately. So we're trying to really make a prudent investment, something that's of high quality that really meet our needs. So we've got a pretty good, I think, a good strategy and a good philosophy, and we're out trying to do the right deal for our customers as well as our shareholders.

If you were to buy land ahead of developing it, what kind of rate-making treatment do you think you would get on that investment?

That's the $64,000 question. I think that we continue to try to work with our commissions around having them understand that it's important for us to tie up some of those sites early so that we don't miss out on the opportunity. And we'll continue to work with our commissioners to allow us to, at a minimum, defer the accounting and hopefully earn a return on that early. But that's something that's really to be determined. And unfortunately, in Initiative 937, that's not clear. The rules around how we can do that are not clear. So we're going to have to go in and, in essence, be one of the first folks that has to try that out. So the commission is currently going through the rule-making for Initiative 937, and it's just not clear on how we can recover those costs. But we have strategies in place, and Kelly Norwood and his team are consistently talking to both the staff and the commissioners around those issues.

Do you currently have any calls on turbines?

No.

John Alli, Zimmer Lucas.

Just wanted to clarify a few things regarding your rate base. In Oregon, you guys are assuming an 8% ROE earned? Is that correct?

For next (multiple speakers) year.

What equity ratio is that calculation made on?

They've actually given us a 48% equity ratio

They've given you a 48 already? What about in Idaho?

Idaho, we have a 43% (multiple speakers)

And Idaho usually allows real equity ratios, right?

Yes.

So if you jack that up to your actual, which would be, what, 48-49, what would you be earning then?

If we're at a 48% equity ratio. That is part of the issue for next year as we consider Idaho (multiple speakers) intentionally drive some kind of a rate case there.

Great. And just the years that you guys use on those, for Idaho?

For the test year?

Yes.

Historical test year.

(multiple speakers) average rate base or year-end?

Average.

And Idaho includes known immeasurables?

Yes.

What about Oregon?

Historical. (multiple speakers) Idaho Power did file a forward-looking rate case in their last case, and we would contemplate trying that in the State of Idaho. We're watching that procedure quite closely. And if staff is agreeable to Idaho Power's filing, we would probably do something similar.

Great. Just out of curiosity, why do you think no one is giving you full credit for the full year of rate increases that you expect to get in Washington, and being it's coming in in almost the middle of the year, and you're kind of missing out on the whole first quarter of volumes? And on top of that, the debt paydown midyear, which alone is like a 10% earnings growth. Just wondering --

One of the reasons we gave earnings guidance -- this is early for us to give guidance for next year -- is we are having a bit of a sideways year, I think, is what I would call it. But we really believe we've positioned ourselves to do well the next few years, and we're trying to help people focus on 2008 and beyond. Because we believe that we should be able to translate a pretty significant capital budget into good earnings growth for the bottom-line of the business. And hopefully that gets reflected in the stock price. I don't think it is right now.

I agree, and I appreciate your time.

I would now like to turn the conference back over to Mr. Jason Lang for closing remarks.

I want to thank you all for joining us today. We certainly appreciate your interest in our company. Have a great day.

This concludes your presentation. You may now disconnect. Have a great day.