Portland General Electric Co (POR) 2007 Q2 法說會逐字稿

Good day, everyone, and welcome to the Portland General Electric Company's second quarter 2007 earnings results conference call. Today is Monday, July 30, 2007, and this call is being recorded. All lines have been placed on mute to prevent any background noise. After the speakers remarks, there will be a question-and-answer period. If you would like to ask a question during this time, (OPERATOR INSTRUCTIONS). For opening remarks, I would like to turn the conference call over to Portland General Electric's Director of Investor Relations, Mr. Bill Valach, please go ahead, sir.

Thank you, Molly and good afternoon everyone I am Bill Valach, Director of Investor Relations at Portland General Electric, and we're pleased you're able to participate with us today.

Before we begin our discussion this afternoon, I'd like to make our customary statements regarding Portland General Electric's written and oral disclosures and commentary. There will be statements in this call that are not based on historical facts and as such constitute forward-looking statements under current law. These statements are subject to factors that may cause actual results to differ materially from the forward-looking statements made today. For a description of some of the factors that may occur that could cause such differences, the Company requests that you read our most recent Form 10-K and Form 10-Q.. The Form 10-Q for the second quarter ending June 30, 2007 will be available at Portland General.com by the end of this week. The Company undertakes no obligation to update publicly any forward-looking statements, whether as a result of new information, future events, or otherwise. The Safe Harbor statement should be incorporated as part of any transcript of this call. Portland General Electric's second quarter 2007 earnings were released before the market opened today and the release is available at our website at Portland General.com.

With this release, PGE announced earnings of $46 million or $0.73 per diluted share for the second quarter ending June 30, 2007 compared to $27 million or $0.43 per diluted share for the second quarter ending June 30, 2006. Earnings for the six months ending June 30, 2007 were $101 million or $1.61 per diluted share compared to $21 million or $0.34 per diluted share for the same period in 2006. With me today are Peggy Fowler, CEO and President, and Jim Piro, Executive Vice President of Finance, CFO and Treasurer. Peggy will begin the call with an overview, Jim will then discuss in more detail our second quarter results. Then we will open up the call for questions. To open our call this afternoon, I'd like to turn the discussion over to Peggy.

Thank you, Bill. Good afternoon, everyone, and thank you for joining us. We welcome you to Portland General Electric's second quarter 2007 earnings conference call. I'm pleased to share the news of our strong financial and operating results for the second quarter. We've set some aggressive goals for the Company and we're successfully executing our strategy. I'd like to command the hard work of our dedicated employees and congratulate them on their outstanding performance and commitment to operational excellence. This quarter we accomplished a number of milestones. On June 18th, the disputed claims reserve sold or distributed its remaining holdings of PGE common stock in a public offering. So now, just one year after stock issuance, substantially all of PGE's common stock is publicly traded.

Our new 400 megawatt Port Westward Generating plant became commercially available. And we're on schedule with construction at the Biglow Canyon Wind Farm. Also in June, we filed our integrated resource plan with the Oregon Public Utility Commission. And today, I'm happy to report that PGE is revising its full-year 2007 earnings guidance to $2.25 to $2.35 per diluted share from $1.90 to $2 per diluted share. The key drivers that support the revised guidance are improved margins on retail energy sales, favorable Mid-Columbia Hydrogeneration more than offsetting reduced generation on PGE's hydro system. Improved thermo plant operations, and the FERC approved settlement between PGE and California parties relating to wholesale energy transactions in the western markets from 2000 to 2001. Guidance continues to include approximately $0.30 due to $20.4 million pretax deferral recorded in 2007 related to the Boardman outage as well as the associated interest in FB408 impacts. Jim Piro will provide more detail on this quarter's financial results later in the call. I'll now provide an update on our strong operating performance. One big success we achieved this quarter was bringing Port Westward our new 400 megawatt natural gas fired plant into service. Total costs at the new plant through June 30, 2007 was approximately $280 million, including AFDC.

In January 2007, the OPUC issued an order approving a 2.8% price increase related to the recovery of Port Westward, which went into effect on June 15th. The citizen's utility board has requested a re-examination of the cost recovery of Port Westward. The OPUC is currently considering if a re-examination is necessary.

In addition to Port Westward coming online our generation portfolio performed at a high level this quarter. The availability at our plants, including both thermal and hydro was approximately 90% in the second quarter with thermal at 86% and hydro close to 100% PGE is focussed on operating our plants to the highest standards to support the growth we continue to see in our service territory.

During the past 12 months, we've added over 11,000 new customers, bringing our total to over 800,000. We continue to engage in Oregon's economic development efforts, Solar World, a German company recently announced their plans to open a production facility in our service area, would be one of the largest solar manufacturing plants in North America. And we're pleased that other large industrial customers are looking here too. With this growth, we continue to deliver high customer value. Our recent JD Power survey of residential customers ranked PGE as one of the top three utilities for customer satisfaction in the west. Nationally, we are a top quartile company and one of the most improved. We know our customers have a strong interest and renewable power, including the progress we're making at the Biglow Canyon Wind Farm. Crews in the field have finished road construction and are now installing foundation. A few weeks ago, the first of more than 700 truck loads of wind turbine equipment began arriving. On March 2, we filed a tariff application, seeking an increase in annual revenue requirements for full recovery of costs related to Phase I of Biglow.

On June 20, PGE, the OPUC staff and other parties agreed to a revenue requirement of $9.4 million based on an allowed ROE of 10.1% and an equity capital structure of 50%. A hearing is scheduled for August 1. If approved, new prices are expected to become effective beginning January 1, 2008. Phases II and III of the project are currently in the planning stages . In the second quarter, PGE made a $17 million payment to a vendor towards turbines for Phases II and III. If PGE does not use good faith efforts to negotiate and execute a definitive agreement, the payment would be non-refundable. The estimated cost of Phases II and III is 600 to $700 million, including AFDC. Phase II is expected to be completed by the end of 2009 and Phase III by the end of 2010.

Biglow Canyon Phase I and Port Westward were key elements of our last integrated resource plan and on June 29, PGE filed a new IRP with the OPUC. The IRP describes our energy supply strategy for 2008 through 2015. It's available on our website, but here are some highlights.

First we plan to complete Phases II and III of Biglow Canyon Wind project for our total installed generating capacity of between 400 and 450 megawatts. Second, we plan to procure an additional 218 average megawatts of renewable power to meet Oregon's new renewable energy standards, which I'll discuss in a few moments. Third, we plan to increase energy efficiency by an additional 45 megawatts by 2012. We'll achieve this goal through partnering with the Energy Trust of Oregon on energy efficiency programs. Fourth, we plan to enter into purchase power agreements with the duration of 5 to 10 years. This will reduce our reliance on energy markets to help stabilize customer prices and meet electricity demands. These extended agreements would also allow more time for new supply and demand side technologies to mature and become cost effective. And finally we plan to acquire 100 megawatts of peaking capacity to meet an increase in forecasted winter and summer peak needs and to help with integration of variable wind resources. During the planning process, we worked with stake holders to identify and design the best combination of lease costs and lease risked energy resources. We considered the environmental impact, the dispatch capabilities of various resources, transmission access, fuel supply availability, and price volatility. The review process is expected to take approximately nine months.

With renewable power being such a critical part of our IRP, it's important to mention that on June 6, the Governor signed an Oregon Renewable Energy Act, Senate Bill 838 into law. The act requires that electricity providers serve at least 5% of their load with renewable energy by 2011 and then meet interim goals which ramp up to 25% by 2025. Counting 47 average megawatts from Biglow Canyon Phase I and 50 average megawatts from Pelton Park, Roundbutte low impact hydro, we would meet nearly 6% of our annual energy needs in 2008 through renewable resources. Assuming Phase II and III of Biglow Canyon are completed, that percentage would approach 10%. PGE worked closely with Oregon state lawmakers and key stake holders to make sure that the renewable energy standard would be meaningful and at the same time allow us to effectively manage our power supply. We are pleased with the outcome.

Another important issue on the public policy front is the suspension of benefits from the Bonneville Power Administration Residential Exchange program. PGE is working hard on behalf of our customers to get these benefits restored. We're working with the BPA, our Congressional delegations, OPUC, other utilities, customer groups, and low income advocates to preserve the value of BPA system for customers of northwest investor-owned utilities. Now our Chief Financial Officer, Jim Piro will discuss our financial results in more detail.

Thank you, Peggy, and good afternoon, everyone. As Bill mentioned, PGE's net income for the second quarter of 2007 was $46 million or $0.73 per diluted share, compared to $27 million or $0.43 per diluted share for the same period in 2006. Let me provide some detail on the two primary drivers for our strong financial performance. We experienced increased margins on energy sales due to power costs in the second quarter of 2007, reflecting the return of the Boardman Power plant to full operations as well as good performance at our other thermal plants. Also contributing to the increase in earnings was approximately $8 million after tax impact of Senate Bill 408 with the potential collection from customers resulting in $2 million of net income recorded in the second quarter of 2007 compared to a potential customer refund resulting in a $6 million reduction in net income recorded in the second quarter of 2006, including associated interests.

Now I'll give you an update on Oregon regulatory matters. First, advance metering infrastructure. Last Friday, we filed testimony requesting that our proposed tariff to implement the AMI project go into effect for the period of June 1, 2008 through December 31, 2010. The decision to delay the implementation was based on the meter technology vendor requiring additional time to complete its scalability testing and delivering host systems software. In addition, we also wanted to minimize the initial price impact of AMI by coinciding the project's implementation with potential customer credits expected from SB408. The proposed tariff would run for approximately 2.5 years coinciding with the system acceptance testing and the installation of 800,000 meters. Once the meters are installed at an estimated capital cost of $132 million, we estimate that AMI will save approximately $18 million annually in operating expenses, providing benefits to customers.

Now, I'll update you on our price adjustment mechanisms related to power costs. Our annual power cost update tariff, which contains a preliminary forecast of net variable power costs for 2008 was initially filed in April and recently updated in July. The updated forecast estimates a 2% overall increase in customer prices, effective January 1, 2008. We will provide another update to the OPUC in the fall and expect a decision in November. I would also like to update you on our power cost adjustment mechanism or PCAM, which accounts and reflects our recent power supply performance. As you may recall, the PCAM provides annual price adjustments that reflect a portion of the difference between each year's actual net variable power cost and the annual forecast in the annual power cost update tariff. At the end of the second quarter, due to lower than forecasted net variable power cost, the PCAM's year-to-date annual variance is greater than the dead band of $11.7 million. Because we've exceeded the dead band by $3.1 million, we've activated the 90/10 sharing mechanism. AS a result, PGE has booked $2.8 million regulatory liability for potential refund to our customers.

Now a brief update on the Boardman deferral. By the end of the quarter -- third quarter we expect to file a request with the OPUC to amortize the $26.4 million deferral of Boardman replacement power costs, plus accrued interest. We will propose that the deferral, including accrue interest be offset with certain credits due to customers with no anticipated price impact. The proceeding will include a prudence review of PG's actions with respect to the outage and acquisition of replacement power and a determination as to whether recovery of the deferred amount would cause PGE's earnings over the deferral period to exceed a reasonable range.

I'd like to provide you a brief update on Senate Bill 408 and Oregon Utility Income Tax Law. For 2007, because of higher taxes due to our positive financial performance, we estimate a potential collection from customers of approximately $10 million. Based on a percentage of estimated annual revenues collected in the first half of the year, PGE recorded a deferral in the amount of approximately $5 million at June 30, 2007. Any collection from or refund to customers for the 2007 tax year will be reported in our October 15, 2008 filing with the OPUC and may be placed into customer prices in mid 2009.

Now I'll provide you with an update on PG's capital expenditure program. For 2007, capital expenditures are expected to be approximately $529 million, including $282 million for the Biglow Canyon Wind Farm, $187 million for ongoing production, transmission, and distribution,$44 million for hydro relicensing projects, and $16 million for the completion of the Port Westward project. To finance continued capital expenditures on May 16, 2007, we issued $170 million of first mortgage bonds bearing an interest rate of 5.8% and maturing on June 1, 2039. We have also entered into a agreement in a private placement market to sell $130 million of first mortgage bonds maturing on October 1, 2037. The bonds will bear an interest rate at approximately 5.8% and may be issued at any time up to October 1, 2007. We continue to maintain stable operating cash flows and adequate liquidity through both our $400 million, 5-year revolver, and access to the commercial paper markets. At the end of the second quarter, PGE had approximately 387 million of available liquidity under the revolver. In June, we executed a one-year extension of the credit facility, extending the maturity from July 2011 to July 2012. Cash provided by operating activities totalled $201 million in the first half of 2007, compared to $46 million in the first half of 2006. The increase was driven primarily by two key factors. First, a decrease in power purchases as we incurred higher costs during the same period of 2006 to replace the output of the Boardman Coal plant during its outage. And second, positive cash inflow due to net margin deposit activity.

We continue to maintain investment-grade bond ratings, our senior secured ratings are BAA-1 at Moody's and BBB+ at Standard & Poor's. PG's financial objectives are focussed on our core utility business. These objectives include providing capital to invest in assets to achieve our service and reliability objective, connect new customers, and add new generation. Maintain investment-grade credit ratings, and earn a fair return on our invested capital. Over the long-term, PG targets a capital structure of approximately 50% debt and 50% equity. And at the end of the second quarter, our equity as a percentage of total capital was 53.9%. Now I'd like to turn it back over to Peggy.

Thanks, Jim. It really was an outstanding quarter for PGE. We have strong performance both financially and operationally. Substantially all of PGE's common stock is now being publicly traded. After several years in the making, it was a great day for PGE employees when electricity from Port Westward, our first new plant in more than a decade began serving customers. Progress is underway at the Biglow Canyon Wind Farm with the arrival of wind turbine's for Phase I and we are making good progress on Phases II and III. And we filed our IRP, the strategic plan that focuses on securing diversified energy resources while keeping electricity affordable for our customers.

I'd also like to mention that we have a new appointment to our executive team. Attorney Jay Dudley has been selected to serve as PGE's Vice President and General Counsel and Corporate Compliance Office. Jay will be taking over for Doug Nickels who is retiring in August after 16 commendable years with the Company. Jay joined PGE in 1988 and has been a lead regulatory attorney on state and federal matters working with the OPUC, FERC and BPA. Before joining PGE, he specialized in energy issues for nearly 14 years with law firms in Seattle and Cincinnati. We welcome Jay and know that his experience will support PGE's goal of delivering value to our customers, employees, shareholders, and the communities we serve. Thank you for your time and interest in PGE. Operator, we'd now like to open up the call for questions.

(OPERATOR INSTRUCTIONS) Your first question comes from David Frank with Catapult Partners.

Hi. Can you hear me?

Yes, good afternoon.

Good afternoon. I had just a question. I wanted to clarify the guidance you provided. I guess this is a GAAP on a GAAP basis you provided the earnings guidance for 2007.

Yes.

And just some of the large items that I think you've highlighted that are impacting your guidance for this year would be recovery of the Boardman would be one of them?

Yes, that would be included.

Is that 26 -- was that the number you spoke of before? I think it was 26.7?

For this year, 20.4. Go ahead, Jim.

We booked 6 million in 2006 and the 20.4 million in 2007. That was included in our original guidance that we provided at the end of the first quarter when we updated the guidance of 1.90 to $2 a share.

Okay, and the favorable gains on of SB408, you highlighted about 8 million in the press release for this year? Is that in there, as well?

Yes.

Okay. And the California settlement? That's, I think you booked in the first quarter? I think that was was $0.06?

Yes, that's approximately right.

Are there any other items that you would consider one-time in nature that would be impacting this year's results?

Well, we mentioned improved hydro generation, margins on energy sales, thermal plant operations in the California receivables, and each kind of breakdown to an equivalent impact to the revision of our guidance.

Okay. So if -- I guess if you had to give a range, ex all these items, are we looking in something kind of the $1.80, $1.90 range?

For what?

For earnings. For ongoing earnings.

We haven't provided any guidance on ongoing earnings. We don't typically do that until November. We'll provide guidance for 2008.

Okay. Okay. Great. And then will the Biglow Phases II and III, will that be wrapped up as part of the IRP? Will you give approval for that specifically as part of the IRP?

Well, part of the renewable energy standard allows us to put new resources in like that automatically if they meet. We really haven't made the decision. Those actually will be included as part of the resources that we're using to meet that. But in terms of how we go about the rate impact, we'll make that decision as we get there, but more than likely it will just be tracked in, similar to what we've done with Biglow I.

Okay. Okay great. Thank you very much.

Thanks, David.

Your next question comes from Michael Lapides from Goldman Sachs.

Hey, guys. Congratulations on the quarter and the start to the year. Question on Biglow Canyon. The CapEx number for 2007 was 70 to $80 million higher than what was in your June 1, presentation. Is that because you're already incurring costs for Phase II? Or is that because costs for Phase I are higher than the 203 million outlined in that piece?

We're moving into working on Phases II and III. The numbers for Phase I remain the same as in the past.

So you're spending 70 or 80 million on Phase II and III, this year?

Yes, that's correct.

Okay.

An additional 62 million towards Phases II and III.

And the number, the 550 to 650 million moved from that to 600 to 700 mill. Can you talk about the 50 million, not a big number, but just checking.

AFDC, that wasn't included before.

Okay.

We quoted those numbers.

So does the -- the CapEx table on page 18 in that presentation doesn't include AFDC for any of those items we should move forward accordingly?

That's correct. It does not.

Okay. Great. Thank you.

Your next question comes from Brian Russo from Ladenburg Thalman

Good afternoon.

Good afternoon, Brian.

Could you just maybe elaborate on kind of the CapEx longer-term picture in terms of the Phase II and Phase III. What years might be more of a heavy capital spend. And then maybe your thoughts and timing on the financing for that.

Pretty much we're looking at 2009 for Phase II. And 2010 for Phase III. And the expenditures at this point in time look to be relatively split. We'll begin some spending, but we're just now in the planning pieces of that and trying to work through that. And as we've talked before, we'll have to look at what we need to do from a financing standpoint as we get closer to that. But more than likely, we may need to issue some equity for that.

Okay. Can you just elaborate on the earnings guidance comment here on favorable mid-Columbia hydrogeneration more than offsetting reduced generation on PGE's hydro system.

Basically the hydrogeneration for the area is down this year on our specific system and certainly areas like the Snake Rivers. Mid-Columbia during the time frame that we get most of our hydro, there was more water in the system. We were able to use that to our advantage during those spring months when there is extra runoff available.

Okay. Thank you very much.

Your next question comes from Jim Bellessa from D.A. Davidson.

Good morning. Or afternoon.

Hi, Jim.

Regarding the Phase II and III buildouts, you say that Phase II by '09 and Phase III by 2010, can they be before then?

Well, we're in the -- Jim, we're in the process of negotiating with the vendor there. And the availability of the turbines. I would say at this point in time it's likely that that's a good time frame that we're looking at.

And when you say for Phase II '09, is that the end of '09? Or will that be half way into the year and you're done with the project?

Yes, we really don't know on that yet. As soon as we finish things up and can let people know have a better sense, we'll provide you information on schedule there.

And for accounting purposes, you get (Inaudible) on that project.

Allowance for funds used during construction.

Put on the balance sheet [CWHIP] and put into the income statement as allowance for funds used during construction? Is that right?

Yes, that's correct.

And do you have any ability to give us anyhow this rolls out? How much per year or how much per quarter?

No, we don't. Not yet.

Thank you very much.

You're welcome.

Thanks, Jim.

Your next question comes from Justin McCann from Standard & Poor's.

Good afternoon. I'm from Standard & Poor's Equity, not ratings.

Thanks for clarifying that.

For BBB+.

One is, what is the effective tax rate for which you're presenting your guidance for this year?

We typically don't provide that detail of guidance. Taxes can move around a little bit as we go throughout the year. You can look at historically what our effective tax rates have been. But with all the tax credits being generated from the wind products and so forth, we really haven't provided any clear direction on that. Won't do that until the year-end results are completed.

I would just like to follow-up on the question just a couple questions ago. On the Mid-Columbia hydrogeneration. I'm almost trying to physically visualize it. How it more than offset the reduced generation in your own system. And if you can just kind of give a little color to that.

Let me give a little color. There's three different River systems we get hydrogeneration from. First, the Columbia River and you look at the Grand Coolie runoff as the key driver, which is up in Canada. So all the flow out of Canada through Revel Stoke and Arrow comes into the Grand Coolie. That's one river system, and that's where we have our mid-Columbia hydro projects on. You can look at the runoff forecast at Grand Coolie. The other systems we have is on the Deschutes River, which is on a different river system that feeds into the Columbia at a much different basin. And the Clackamas River system. The Clackamas is more rainfall driven. The Deschutes is more snowfall driven but has a lot of spring water, so each of the basins are different so you have to look at each basin. We have about half of our hydrogeneration on the mid-Columbia through long-term contracts and the other half is on the Deschutes and the Clackamas. So that's why you can get different results. And if you look at the runoff forecast, the Columbia's been ahead of kind of what the other basins have been doing. And the Snake has been really bad this year. So when you look at the overall Columbia system at the Dow's it's well below normal. Primarily driven by the Snake. But again we don't have any generation. Hydrogeneration on the snake.

Okay. Thank you.

Your next question comes from Steve Gambuzza from Longbow Capital.

Good afternoon.

Hi, Steve.

I was wondering if you could first just review any other changes to your long-term resource plan. I think you talked about a couple of them other than Phase II and III, the Biglow Canyon. I think you mentioned some peaking capacity and some other renewable resources. Can you just repeat or elaborate upon your earlier comments?

I don't really know if those are changes. Because as we talked before-- We had a pretty good sense of what you're putting into our resource plan at that time. We have energy efficiency which 45 megawatts, we have some plan efficiency upgrades of about 10 megawatts. Biglow Canyon II and III, and then the long-term purchase power contracts split between 5 years and 10 years. And then some renewables, about 200 megawatts of renewables.

200 -- the 200 megawatts of renewables, what are they?

That's outside of Biglow Canyon II and III. And those will be more than likely will go out for bid, and there'll be some biomass probably maybe some more wind, geothermal, solar whatever we can come up with. They're not specifically identified or have been made known public yet.

And is there -- what's the targeted kind of in service date for that increment of capacity whatever you decide it to be?

2012 is the end of the where we want to have this completed. But if it's possible, I suppose if some of it was completed or available, we might consider putting it online sooner.

Okay. And then, and then you also mentioned 100 megawatts of gas peaking capacity, when would that come into service?

Again, that would be we go out for an IRP on that. And probably that's closer to the end 2012, just depending on our needs. And again, when we get -- it could be actually in the time frame of when Biglow Canyon II and III come online if we need that to integrate the resources.

That was 100 megawatts.

Right. We're still trying to identify the need for that and how we're bringing it into the system.

The one question we have there is whether it's available in the market. And that's one thing we need to test to see if there is capacity available. And if not, we may have to look at other options to meet that capacity need. And so that's what we're trying to understand a little bit better.

And in your comments, I think you made some remark about you can automatically bring things into rate base that are I guess intended to fulfill the requirements the RPS standards, is that correct?

Yes, that's correct. Part of the renewable energy standard bill allowed for renewable resources to be tracked into rate base.

So there's kind of a presumption of prudence when you add these resources?

Correct.

How should we think about that in the context of kind of the competitive dynamics associated with who gets to build these resources? RFP or rate base addition? Is there a competitive process for each of these increments of capacity?

From our standpoint, and from a prudency stand point, we will want to show that whatever renewables we bring online are the least cost resource for our customer and make the most sense. We will go through some type of process, whether it's the competitive bid process per se or whether it's analysis of what the various options are out there on the market.

And when you look at the IRP that you've put forward, do you feel as though the transmission CapEx incorporated in your previous 5-year CapEx forecast, is adequate to accommodate all these new resources?

We probably have some additional transmission that is included in the integrated resource plan. But again, that's something we need to continue to review and see if there's things that make more sense for our customers.

Okay. And then, finally, as it relates to the, I guess from an earnings standpoint where you are to date in 2007 with respect to power costs. You mentioned that you've kind of -- you've exceeded the threshold in the dead band on the positive side and booked the regulatory liability. Can you just review kind of from an income statement perspective how much you have -- how much has flowed through the income statement from a early recovery standpoint.

Jim can talk to --

We booked $2.8 million in the second quarter for potential refund to customers.

So that's what was hung up on the balance sheet. But how much prior to triggering that regulatory liability, how much flew through the income statement on the positive side?

We were in the dead band before that. So nothing flow throughs. Only the second quarter that we got out of the dead band. So first quarter we booked nothing, second quarter we booked $2.8 million refund to customers on the income statement and then put it on the balance sheet. That make sense?

You're saying the only benefit you've experienced to the income statement is 2.8?

It's not a benefit, it's a reduction to -- or it's an increase basically. Not a reduction.

$2.8 million represents the amount that is going to be refunded to customers.

That's correct.

Before you book that, some benefit flow through the income statement.

The benefit was lower power costs and the offset is refund to customers. We've already experienced the lower power costs and the offset is the refund to customers.

Can you quantify the lower power cost?

It's $2.8 million-- 3.1 million was the overall amount that was beyond the dead band and 90% was booked as a refund to customers. The 11.7 million dead band. So we worked through the dead band.

That's really what I was asking. You worked through the entire --

Yes.

Through the amount of the dead band.

We're booking this on a full basis. The way we've got the accounting set up, we would not book a deferral until we worked through the entire dead band.

Really the income statement benefit would be the dead band, the entire 11.7. You experienced that on a positive side.

Plus 10% of the 3.1.

Thank you very much.

Your next question comes from Michael Lapides from Goldman Sachs.

Hey, guys. My question's been asked and answered. Thank you.

Thanks, Michael.

(OPERATOR INSTRUCTIONS) Your next question comes from Jim Bellessa from D.A. Davidson.

Good afternoon, again. Would you go through this process of getting a contract for turbines and how tight the market is or how extensive the work is for you? And what's the availability? Those kind of things. Can you give us a little color on what's involved?

Sure I can. I'll talk about it a little bit. Jim can add to it if he wants. But as we look at anything like this, PGE doesn't go after new technology. So the people we've been talking to are those that are proven in the industry and have had turbines that are operating and show to be good. So you can sort of figure out who those vendors are. We went through a process, similar to a request for proposal process, essentially to see what was available, what sizes from what vendors and what time frame. And looked at how that fit with our needs for energy and the site that we have. And made a decision on who we think the best vendor and then we've been in negotiations with them trying to -- we have actually worked through the pieces of the contract. We're trying to get all that written down now. As I've mentioned, we've put $17 million out there believing that we're moving in the right direction here. Is that sort of enough color?

Who did the initial work for Phase I?

(Inaudible) Best turbines, they're involved and then we have local contractor who is doing the work who's done other types of these projects.

And the size of the units for Phase 1, will they likely change for Phases 2 and 3?

(Inaudible).

Standardize the equipment throughout your whole fleet or whole system?

That would kind of give away the vendor, so we probably can't tell you that. The things we take into consideration in terms of trying to maximize the efficiency of the system. But we haven't decided one way or the other yet. Can't tell you.

Is there -- could there be a benefit from a standardized equipment throughout the wind farm? Or it doesn't matter?

It doesn't matter. Some people might make a case it's not a benefit. Because if there's problems, maybe you're better off to have some diversity. So as we've looked at it, it can go -- you can justify both directions.

Thank you.

Your next question comes from Nikki Edgecombe from JPMorgan.

Hi, good afternoon.

Hi, Judy.

Wondering if you guys can, Jim, you went a little fast for me. If you can walk me through your 2007 for SB408 weight exposure again and any discussion about what your next-- what the next piece of the strategy is legislatively on this issue?

Okay. On SB408, when we looked at the results, forecast for the year, it looks like we'll be paying more taxes than what we would collect in rates based on a fixed methodology. And our estimate at this point is that we'd paid $10 million more in taxes. So under the rules, we have the right to collect that from customers. This is the double whammy thing we talked about before. As you recall last year, we had a $40 million benefit of which 17 was related to our ownership with Enron. Last year we had poor financial results and we exacerbated the problem last year by booking the SB408 refund to customers. And we talked about the double whammy. And this year now we're having a good year because the good hydro and good plant operations. We're going to pay more taxes this year because we're doing well. And as a result of that, we're going to pay more taxes and under the methodology, we would get the right to collect those taxes from customers. We worked real hard in the legislative session to try to get that corrected. We just couldn't get any traction. We tried real hard. We will probably make another run at the next legislative session to try to get this piece of the legislation fixed. The double whammy, as we just talked, gives you perverse results and doesn't make a lot of sense. Hopefully next time we'll get a lot of customer support to get this part of the legislation corrected.

And that isn't until 2009.

Okay.

And maybe it's easier when it's going in the wrong direction for customers. But it's hard to tell.

Great. Thank you.

Welcome.

There are no further questions at this time.

We appreciate your interest in Portland General Electric Company and invite you to join us when we report our third quarter results. If you have any additional questions, please contact Bill Valach, who will be available after this call. And thank you again for participating and for your questions.

This concludes today's conference call. You may now disconnect.