Portland General Electric Co (POR) 2009 Q1 法說會逐字稿

Good day, everyone, and welcome to the Portland General Electric first-quarter 2009 earnings results conference call. Today is Monday, May 4, 2009, 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. (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, Dennis, and good morning, everyone. We are pleased that you are able to join us today. Before we begin our discussion this morning, I would like to make our customary statements regarding Portland General Electric's written and oral disclosure 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 and 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-Qs. The Form 10-Q for the first-quarter 2009 was available this morning at Portland General.com.

The Company undertakes no obligation to update publicly any forward-looking statements whether as a result of new information, current events, or otherwise, and this Safe Harbor statement should be incorporated as part of any transcript of this call.

Portland General Electric's first-quarter 2009 earnings were released before the market open today and the release is available at portlandgeneral.com. With this release, PGE announced earnings of $31 million or $0.47 per diluted share for the first quarter ending March 31, 2009, compared to $28 million or $0.44 per diluted share for the first quarter ending March 31, 2008.

With me today are Jim Piro, CEO and President, and Maria Pope, Senior Vice President of Finance, CFO, and Treasurer. Jim will begin the call with an overview. Maria will then discuss in more detail our first-quarter results, and then we will open the call up for questions.

So now I would like to turn it over to Jim.

Thank you, Bill. Good morning, everyone, and thank you for joining us. Welcome to Portland General Electric's 2009 first-quarter earnings call. On today's call we will review earnings, address the key drivers to our performance and reaffirmed guidance for 2009. Then I will update you on Oregon's economy and the outlook for our operating area.

Finally, I will discuss the progress we are making on our strategic initiatives. Later Maria will provide details on first-quarter results, current regulatory proceedings, our liquidity, as well as recent equity and debt transactions.

So let's get started. PGE's net income for first quarter 2009 was $31 million or $0.47 per diluted share. Revenues increased in first quarter 2009 compared to first quarter 2008 as the General Rate Case order went into effect at the beginning of the year. However, a reduction in energy sales, higher power costs, and increases and other operating expenses offset this increase. Maria will go into more details later on the call.

It has been a busy year. We have been working diligently to secure financing for our capital expenditure program to fund projects to deliver value to our customers and shareholders. In March, we issued 12.5 million shares of common stock for net proceeds of $170 million and during the first four months of the year, we raised $430 million through the issuance of First Mortgage Bonds. These transactions will provide sufficient liquidity to meet our debt maturities as well as fund our 2009 capital expenditure program.

Now I will move onto 2009 guidance. PGE is reaffirming full-year 2009 earnings guidance within the previously disclosed range of $1.80 to $1.90 per diluted share. Guidance assumes normal plant operations and reflects steps taken to align our operating costs with the Oregon Public Utility Commission's General Rate Case order issued in January. We are also reaffirming our long-term annual earnings growth expectations of 6% to 8%.

Now I will provide you an update on Oregon's economy and specifically our operating area. The slowdown in the state's economy has continued. Oregon's unemployment rate rose to 12.1% in March, compared to the national unemployment rate of 8.5% for March. The unemployment rate in our operating area rose to 11.2% in March, which is approximately 1% below the state's overall rates.

A large part of Oregon's unemployment increase is due to continued in migration with 60,000 people added to the labor force during the last year. On a percentage basis, Oregon's labor force in March 2009 grew 3% from March 2008, which tied with Nevada as the nation's fastest-growing labor force while the US labor force remained flat.

We do continue to see growth in our customer base. We served approximately 814,000 customers at the end of the first quarter of 2009, an increase of approximately 0.5% from the end of 2008. However, weather-adjusted retail energy deliveries were down 1.3% in the first quarter of 2009 relative to 2008. We currently project weather-adjusted energy deliveries for 2009 to decline by approximately 1% relative to 2008. This decline is due to a reduction in energy use by our customers specifically in the industrial sector.

Despite the economic conditions in Oregon, our business is performing well and we remain focused on delivering value to our customers and shareholders. We have had the opportunity to talk to many of you recently in face-to-face meetings or during one-on-one calls about PGE and our strategic direction. This strategy reinforces our commitment to our core business as a vertically integrated utility.

The three main focused areas that we use to continuously measure of performance are operational excellence, corporate responsibility, and business growth. I will report out on each of these areas both what we have accomplished and where we are headed.

In the area of operational excellence, we continue to receive positive feedback that tells us we are meeting our customers' needs. Today I am pleased to announce that the National Renewable Energy Laboratory just released its annual rankings and for the fourth year in a row PGE sold more renewable power to residential customers than any other utility in the United States. Overall, we rank number two for total number of customers participating in renewable programs and total renewable kilowatt hours sold to residential and commercial customers combined.

These rankings reflect our customers' commitment to green power and our commitment to delivering renewable resource options. Our most recent independent survey showed that overall satisfaction for residential customers remains in the top quartile and in the top decile for small and medium-sized business customers. In the first quarter, we continued to have excellent generation plant availability with PGE-owned Hydro at 99%, wind at 96%, and thermal at 99%.

I do want to update you on the coal strip plant in southeastern Montana. They have extended the scheduled 2009 maintenance outage of unit 4 which began on March 28. Two turbine rotors were found to be damaged. Both have been sent to the manufacturer for repair. It is currently estimated that the outage will be extended by eight to 10 weeks, with unit 4 now expected to return to service in late July 2009.

PGE has a 20% ownership interest in coal strips units 3 and 4 with each of the units providing 148 megawatts or approximately 6% of PGE's total generating capability. Our share of the repair cost has not yet been determined. In addition, we estimate the incremental power costs to replace the output of unit 4 through late July to be between $2 million to $3 million.

Now on to hydro. Since our last call, hydro conditions have improved. The April 23 hydro run-off forecast indicates slightly lower than normal conditions for 2009, including 95% of the Deschutes River, 107% on the Clackamas River, and 90% on the Columbia River at Grand Coulee. First-quarter results for power quality and reliability including customer outages, outage durations, and momentary interruptions are on track to meet our 2009 goals.

We have also been working very hard in the area of corporate responsibility, especially with so many initiatives on the public policy front. Carbon-related legislation is getting a lot of attention both at the national and state level. At the federal level, we support the Edison Electric Institute's global climate change points of agreement. We are partnering with others in our industry to help Congress and federal policymakers understand the importance of this issue and the implications to our industry and our customers.

At the state level, we are working with customers and other stakeholders to develop legislation that creates achievable carbon reduction strategies including increased funding for energy efficiency, adoption of an emissions performance standard for new power plants, expanded transmission capacity and flexibility to bring renewable power to our customers, and scoping and planning to help meet federal standards once adopted.

Now I will move on to our growth opportunities. Let me give you an update on some of our major capital projects. First, our smart meters project. We are pleased to announce the full deployment of the approximate 850,000 smart meters has begun. Approximately 25,000 new meters have been installed within our service area, including 15,000 as part of the project system acceptance testing phase. PGE estimates the capital cost of the smart meter projects to range from $130 million to $135 million and we expect the project will be completed by the end of 2010.

Next, our selective water withdrawal project at the Pelton Round Butte hydro facility on the Deschutes River. We have encountered a delay with the construction of this project. On Saturday, April 11, construction crews were in the process of positioning components at of the conduit when it separated. An analysis is taking place to determine the root cause as well as the estimated cost and timelines for completion.

On April 14, we filed a motion with the OPUC to request that the schedule for the inclusion of project costs and prices be suspended due to the recent delay in the construction. Currently the delay is anticipated to be a minimum of four months from the original completion date. This project is an essential part of our licensing agreement and important for the restoration of fish runs in the upper Deschutes River basin.

Next, Biglow Canyon Wind Farm. We are very pleased with the progress we are making at phases 2 and 3 of Biglow Canyon. Construction is on schedule with completion of phase 2 expected by late summer 2009 and phase 3 in 2010. The two phases will have a combined installed capacity of approximately 324 megawatts and with the completion of both phases, we will now serve approximately 11% of our load with renewable energy as defined by the Oregon renewable energy standard. This moves us closer to the RES benchmark of 15% of our load served by renewable resources by the year 2015.

The estimated total cost of phase 2 is $326 million, including $10 million of AFDC and phase 3 is $433 million including $27 million of AFDC. Our investment in Biglow Canyon will be fully included in prices through the renewable adjustment clause mechanism. Our first filing for this mechanism was on April 1. Maria will provide more details on how this mechanism works.

For additional renewable resources, we issued a request for a proposal last spring seeking up to 218 average megawatts. We have identified a short list of bidders and we expect negotiations to be completed in 2009. These new renewable resources will become available by the end of 2014 and will also help fulfill our commitment to meet the requirements of the renewable energy standard.

We are preparing our 2009 integrated resource plan, which we expect to submit to the OPUC later this year. The resource requirements were addressed and in the IRP include the following, the expansion of energy efficiency programs; additional renewable resources to meet Oregon's renewable energy standards, including the integration of an increasing amount of wind power; new facilities to meet base load and capacity requirements; the economics of emission controls on the Boardman plant; and a new transmission project called Southern Crossing.

Let me go into more detail on some of these projects. PGE needs additional energy and capacity to meet its retail load which creates potential for new generating resources and we are considering the following. A 300 to 500 megawatt natural gas-fired combined cycle facility located at Boardman to help meet our customers' energy requirements and a 100 to 200 megawatt natural gas-fired simple cycle facility at Port Westward to meet our customers' peak load requirements and balance our variable wind resources. These potential resources will be included as self-build options in a formal RFP bidding process following the OPUC acknowledgment of the IRP.

As I mentioned, part of our IRP is the evaluation of the economics associated with installing new emission controls on the Boardman plant, in December 2008 the Department of Environmental Quality issued proposed plan that would require the installation of additional controls in three phases with the completion dates between 2011 and 2017. The plan is outlined in the Form 10-Q.

We have submitted comments of the DEQ's proposal requesting a phased approach which would allow for certain decision points along the timeline in order to provide flexibility and to help us make the most responsible decision on future controls. The estimated cost in nominal dollars is between $575 million and $640 million. This is 100% of the total cost excluding AFDC.

The public input period is closed and the Oregon Environment Quality Commission is expected to adopt the rule in June of 2009. The rule is then submitted to the Environmental Protection Agency for approval. We expect the EPA to issue their decision in early 2010.

And finally on transmission, we are studying a 200-mile 500 kV transmission project referred to as Southern Crossing. The project is being designed to meet growing demand, provide improved system reliability and help bring new renewable generation to our operating area while reducing our payments to third parties for transmission. The estimated cost of the project in nominal dollars is currently between $600 million to $750 million. This is 100% of the total cost excluding AFDC.

With that, I would like to turn the call over to Maria Pope, our Chief Financial Officer, to discuss our financial results in more detail.

Thank you. Good morning. As Jim mentioned, net income was $31 million or $0.47 per diluted share for the first three months ended March 31, 2009. This compares to net income of $28 million or $0.44 per diluted share for the first quarter of 2008. Revenues were higher in the first quarter of this year as a result of price increases that went into effect on January 1. These higher revenues were offset by a reduction in energy sales, higher power costs, and increases in operating expenses. Power costs were impacted [by] $3.4 million after-tax or $0.05 per diluted share as hydro production was lower than normal in Q1.

2009 results -- first-quarter results were also impacted by a $2.6 million after-tax loss or $0.03 per diluted share from a decline in the fair market value of our nonqualified pension -- benefits plan assets and additional costs related to the December 2008 storm.

2008 first-quarter results were impacted by $3.7 million after-tax loss or $0.06 per diluted share, also from a decline in the fair market value of the nonqualified benefit plan asset and refunds to customers under SB 408.

In 2009, PGE has been active in the capital markets with total issuances of $600 million consisting of the following three transactions. First in January, we closed a 130 million issuance of First Mortgage Bonds with interest rates ranging from 6.5% to 6.8%. Second, in March, we issued 12.5 million shares of common stock for net proceeds of $170 million. And finally in April, we issued $300 million in First Mortgage Bonds at an interest rate of 6.1% in part to refinance $142 million of pollution control bonds redeemed on May 1. This completes our financing requirements for this year's capital expenditure program.

PGE anticipates issuing $375 million of debt in 2010 with part of the proceeds used to redeem $186 million in maturities and the balance to complete Biglow 3 and other capital projects totaling $522 million, which are outlined in our 10-Q.

We continue to focus on our investment grade bond ratings. Our senior unsecured ratings are BAA-2 by Moody's and BBB+ by Standard & Poor's. PGE has $495 million in borrowing capacity under two credit facilities. The first facility is a $370 million unsecured multi-year revolver. The second facility is an also unsecured $125 million 364-day revolver. These credit facilities provide working capital as well as liquidity for our power supply operation and price risk management activity. We have entered into forward contracts for power and natural gas to meet our retail load and as a result of falling power and gas price, we have posted collateral to meet margin requirements under these contracts.

As of March 31, we have posted $409 million in collateral with wholesale counterparties consisting of $205 million in cash and $204 million in letters of credit. As of April 30, collateral posted was $380 million, declining as positions rolled off through the month. If market prices remain unchanged from April 30 levels, we anticipate that 45% of the current collateral deposits will roll off in 2009 and another 45% would roll off in 2010. The posting of collateral for margin requirements affects cash flow but it is important to note that costs associated with gas and power contracts are either currently in or are anticipated to be in customer prices.

As of March 31, we had no commercial paper outstanding, no direct draws on the revolver, and $223 million in outstanding letters of credit. As of March 31, total availability under our revolving lines of credit was $272 million, which compares to $166 million at the end of 2008. On April 30, we had $279 million available on our revolver and excess cash of $294 million.

On May 1, $146 million of excess cash was used to redeem the pollution control bonds and pay related accrued interest. Our debt to capital ratio was 48.3% on March 31 and 50.9% after the April 16 issuance of $300 million of First Mortgage Bonds, offset by the redemption of the Pollution Control Bonds on May 1.

I will now go on to discuss the stimulus plan. The American Recovery and Reinvestment Act of 2009 provides for a number of enhanced tax benefits, many of which are favorable to renewable energy projects such as PGE's Biglow Canyon Wind Farm. The tax benefits include the extension of production tax credits from 2009 the 2012 and in lieu of the PTC, a company may elect investment tax credits or Treasury Department grants that meet certain criteria.

Based on our preliminary assessment, we believe we may qualify for treasury grants in the amount of $60 million to $90 million in the latter part of 2009 and $80 million to $110 million in 2010 for Biglow 2 and 3. We are also considering opportunities under the Act that would provide funding for smart grid projects, vehicle electrification, and research relating to potential carbon capture projects. Our assessment of the options under the Act are still preliminary and being reviewed.

Now turning to regulatory proceedings, the OPUC authorized a decoupling mechanism in the final order of PGE's most recent General Rate Case that a coupling mechanism went into effect on February 1 for an initial period of two years. This allows for recovery of fixed costs in earnings that are the result of customers' energy efficiency and conservation efforts. The decoupling mechanism tracks the differences between weather-adjusted revenues that are collected on a per kilowatt hour basis with those that would be collected on a fixed per customer charge basis. This difference is accumulated in a balancing account and then refunded or collected over a future period.

As of February 1, the net impact of the mechanism in the first quarter was approximately $500,000, which is included within revenues. On March 24, the Citizens Utility Board filed a motion to OPUC for reconsideration of decoupling. The OPUC's had 60 days to respond to this motion. In the first quarter, PGE made the following regulatory filings.

On April 1, we filed our initial 2010 forecast with updated power costs under the annual update tariff. Our initial filing indicates a slight decrease in prices. Throughout the year, we will make several update filings. Power costs will be put into customer prices effective January 1, 2010.

Also on April 1, we submitted our first filing under the renewable adjustment clause mechanism. This mechanism allows for costs of renewable resources that are expected to be placed into service in the current year to be recovered in customer prices without filing a General Rate Case.

Our initial filing on April 1 included Biglow Canyon Phase 2 and PGE's share of two solar projects. The filing requests revenue requirements of approximately $41 million with new rates to become effective on January 1. The $41 million increase consists of $6 million to be deferred in 2009 and $35 million increase in 2010 revenue requirements. These amounts are partially offset by power cost savings estimated at approximately $15 million for 2010. Also included in the annual update tariff on April 1.

Finally, an update to the Trojan order. On March 19, the OPUC issued an order that reset and restarted the Trojan refund as outlined in the September 30, 2008 order. Based on the OPUC orders, we anticipate that the $33.1 million plus interest will be refunded to customers by the end of 2009.

In closing, the focus of our financial objectives continues to support our core utility business, namely a solid balance sheet and adequate liquidity to maintain our investment grade ratings; efficient access to capital markets to support investment in new and existing generating assets, and our transmission and distribution system; reasonable and fair regulatory outcomes while earning a competitive rate of return on our invested capital.

Now I would like to turn it back over to Jim. Thank you.

Thanks, Maria. In the first quarter, all areas of our operations performed well. Customer satisfaction continues to be high. We are on track with major projects, Biglow Canyon Wind Farm and our smart meters project, and we continue to focus on our business strategy to strengthen our position as a leading regional energy provider through an emphasis on operational excellence, corporate responsibility, and investment opportunities that support our core utility business, enhance service to our customers, and deliver value to our shareholders.

Operator, we would now like to open the call for questions.

(Operator Instructions) Brian Russo, Ladenburg Thalmann.

Good morning. You talked about your 2010 capital market needs in terms of debt and I'm just wondering it looks like your debt to cap is creeping up above 50%. I think that is even with the equity offer completed in March, and I'm wondering do you have any capital equity needs in 2010 to finance the CapEx?

Thank you, Brian. I will have Maria answer that.

Sure. Brian, we are expected to be just a tad bit above our target 50%-50%, but as we see collateral positions rolling off as well as with the $375 million of debt that we will be issuing combined with the redemption of $186 million of bonds in 2010, we do not see any material change from where we are versus our target.

Okay, great. Then just on the guidance, it looks like hydro was below normal in the first quarter and growth is slowing. And I'm just wondering how -- if we could talk more about the positive and negative drivers that you've assumed in your '09 guidance versus '08?

I'll have Maria answer that. Go ahead.

Sure. As we noted in the first quarter, we were off on hydro. Hydro conditions though since our last conference call and our expectation have increased almost 10 percentage points on average, so we are expecting more hydro profitability in that area. And then also with the exception of the coal strip outage that Jim mentioned, our operating facilities are doing quite well and we would expect the plant to continue to have a positive impact on our outlook. We are maintaining our guidance of $1.80 to $1.90.

Is the decoupling mechanism that began on February 1 -- are you able to mitigate any pressure on your ROE from the 1% decline in growth versus the flat growth you previously had expected?

Yes, the decoupling mechanism is working virtually as we expected and that is in our forecast and we mentioned that in the first two months of it being in effect since February 1, we have seen about $0.5 million net benefit and that is taking into consideration what we received through the decoupling offset by the 10 basis points reduction in our ROE.

Okay, and you mentioned that you expect hydro conditions to improve in the second quarter. Can we assume that the $0.05 hit you took in the first quarter could possibly reverse in the second and third quarter? And you could see a net benefit for hydro?

Yes, we do -- we are expecting that.

A lot of it will depend, Brian, on how the snow comes off the mountains. You know, if it comes off ratably so we can utilize all that hydro, it should work for us. But it all depends on weather conditions and how fast it melts, and we've seen melts kind of all at once and we can see it kind into the third quarter. So a lot of this will depend on temperature and the snow melt as it comes off, as well as what the Canadians do with their upstream reservoirs.

Okay, great, then just lastly, your initiative to realign your cost structure relative to the General Rate Case outcome, can you just site maybe some examples or projects that are ongoing? And did we see any impact of that in the first quarter?

We did see impact. A couple things going on. First of all, we tried to realign our operations in the distribution area to reflect a couple things. One is the fact that we are seeing less customer activity there and we have deployed some of our crews to capital projects that need to be worked on. Typically we use contractors and so we've been able to deploy those crews to construction projects. That is one area.

We have kind of gone through all areas of operations to see where we can reduce costs to make sure we are still delivering value but reducing mostly outside services. We've taken kind of a very slow position on replacing open positions in the company and just look where we can realign operations. So it's a number of areas. You can't point to any one thing, but we've looked at a number of things to lower our cost.

Okay, great. Thank you.

Steven Gambuzza, Longbow Capital.

Good morning. Can you repeat the comments you made about the Boardman controls? I just wanted to understand where that process is in terms of whether or not you are actually going to go ahead and deploy that capital.

Here's the process, okay? The Department of Environmental Quality has put out their proposal. We then submitted comments suggesting more of a phased approach to decision point analysis which would give us decision points along the way. All that is before the Oregon Department of Environmental Quality and then the Environmental Quality Commission will make a decision on that. What we think right now is that the Department of Environmental Quality will put out a draft proposal in mid-May and then the Environmental Quality Commission will make a decision in June.

We will then take whatever that decision is and model the economics of that proposal and present that to the Oregon Public Utility Commission as part of our integrated resource plan. And the process there is to look at the overall economics of the project and what we would like to get from the commission is some acknowledgment of the proposed action.

The challenge we have right now is we are not sure what the Environmental Quality Commission is going to decide. Are they going to adopt our phased decision point analysis? Or are they going to just say you need to do it all and you need to make that decision now? We have looked at the economics of these various options and proposals and have presented that to the stakeholder group and our integrated resource plan, but until we see the final Environmental Quality Commission decision, we really don't have a firm proposal yet to model.

Okay, so the comments you made about future resource needs given your short energy and capacity position of 300 to 500 megawatts, CGT at Boardman and a 100 to 200 megawatt simple cycle at Port Westwood. Does that assume that Boardman stays in the mix as a resource?

Yes, that would assume Boardman stays at the mix. If Boardman were to be phased out or shut down, we would have to replace it with an additional energy resource, another type of Port Westward type unit, combined cycled gas turbine.

And what would the time period be on the simple cycle and the CGT and simple cycle that you mentioned?

I think we are talking the 2013 to 2015 timeframe, someplace in that. We have to go through the process. The IRP has to get decided. The action plan will get decided. Then we do a request for proposals where we would put in our self build options. That would likely go through end of 2010 maybe into 2011 until we finally look at the economics of the proposals. If our self build options are the most economic, then we would start construction of those in probably mid to late 2011 and then complete those in 2012, 2013, just depending on the time frame.

What we are doing right now is we are going through the siting process for each of those projects. You know, you have to go through the air permitting process. So we are going through all the permitting processes as well as identifying natural gas transportation options? That's the work that's going on internally as we work through the integrated resource planning process.

So you would imagine filing the application for the self build at some point in 2010 or '11?

No. We will probably file them this year.

This year. Now it seems one of the questions about whether to do a self build or whether you do a PPA is what the cost of the self build is and a key component of what the cost is going to be is what your required return is. And just given the change in your cost of capital, is it fair to say that you are going to require a higher rate of return than 10% to go ahead and raise a bunch of capital and increase investments at this point?

When we do those economic analyses, we do kind of an economic projection of what we think the ROE requirements are based on where we think treasuries are and the risk profile of the company. We watch that very carefully to see that the ROE reflects what we think is a fair return for our shareholders. So we will try to reflect that.

At the end of the day, the Commission decides what the ROE is in each specific rate case. They really are not making a decision on that self build option relative to our ROE. It is for a planning purposes only at that point. We will have to make our case before the Public Utility Commission and the General Rate Case of what the appropriate ROE is for our company. I think you are seeing a trend in the industry across the nation that ROEs are going up to reflect the potential risk in the utilities sector as well as the overall required return given the current economic times.

So it would be nice as we go into our next General Rate Case, which likely would be 2011, the extent that commissions are granting higher ROEs, I think that will be reflective of the risk and the appropriate return for equity investors in the utility sector.

Thank you very much.

Sarah Akers, Wachovia.

Good morning. I think last time on the call regarding the Southern Crossing project you said that you were in talks with potential co-owners. I was wondering if there been any progress in securing the partners and then just an update on the outline of what the next steps are for that project.

Yes, we are in conversation with other potential co-owners. We really haven't got too specific on what's going on in those conversations, but there's a number of utilities in the Northwest who would have an interest in that line and so we are in discussions with them in terms of their potential partnership either through ownership or a contract for certain rights to the capacity. So that is kind of what we are doing.

Our current plan is to have that project in commercial operations around 2015, again to link it up with the energy resource at Boardman. So that is kind of where we are in the process. We are going through right now all the feasibility studies in terms of how the transmission system would work within the context of the Northwest. Once those are completed and we will take it to the next step, which is a more detailed analysis in terms of the economics.

So we are doing a number of projects. We are starting the survey work for environmental mitigation and where the transmission line is going to go. This line is mostly an existing right of way, so that should minimize some of the environmental impacts. So that's the process we are going through. We hope to make a decision in terms of continued commitment to this project toward the end of 2009 as we complete our studies, finish the conversations with potential co-owners and get a better handle on the economics and cost of the project.

Okay, and then on the decoupling mechanism, is there anything that the regulators tried to separate the impact of efficiency and conservation versus just the economic declines? Or is it all kind of captured in there?

It's really all captured and it's almost impossible at least for the customers less than 30 kW, it's impossible to determine whether it's resulting from energy efficiency or conservation. Frankly either one is a good thing for our customers because it reduces our environmental footprint. So I don't think they have tried to distinguish between the two.

For the customers between 30 kW and one megawatt, those customers what we will have to identify specific energy efficiency measures that they implement and will work with the Energy Trust of Oregon to identify those specific measures. So -- and then the customers larger than at one megawatt, they don't fall under the decoupling mechanism.

So that is kind of where that is and that is one of the concerns raised by CUB I think around the residential sector. But our view is that whether customers change their behavior and reduce less of our product or actually install measures that reduce the consumption of electricity like fluorescent lighting or other measures like weatherization, customers and the company should be indifferent to that impact. So that's kind of where we are.

Great. Thanks.

James Bellessa, D. A. Davidson & Co.

Good morning. I want to double check on your guidance. In the most recent quarter, you had a couple of items that are one-time or nonrecurring of nature. Are they built into the guidance?

Yes, Jim, they are.

At how about the coal strip outage and the select water withdrawal delay?

Yes, Jim, both are baked in.

On the selective water withdrawal, our assumption is that the project would continue under construction work in progress and then would go into service -- go into rates when it goes into disservice. We think that may -- is a minimum of four months and we do not yet have a final date on when that would go into service.

And are you warming up to the potential for these [treasure] grant options, or you are still kind of iffy on that?

Jim, with regards -- we are currently assessing them and we are looking for a little bit more information with regards to how the rules are applied and particularly around some of the normalization issues. But we are more enthusiastic about the grants than the PTCs, but there is still some unknowns we need to resolve.

And we are trying to work with EEI and the other utilities in the industry to try to clarify those rules so we can maximize the value of the grants for our customers.

And then on your income statement, this time you have a non-controlling interest loss adjustment. Is this just kind of a one-time occurrence or will this be occurring regularly or --?

Yes, this is related to the ProLogis solar project that we've located on a rooftop. It's a about a 1.1 megawatt facility, thin film technology and at the time we went through this, that transaction, the utilities were not able to utilize the investment tax credit. So I will have Maria explain the particulars of the transaction.

Sure, what we did was we increased our depreciation and amortization by about $7 million and then added back $7 million, the same number, to net losses attributed to noncontrolling interest. So remember that we are the minority partner at this point. We contributed about 7% of the project cost for just under $700,000. And the tax equity partner will receive the majority of the benefit of all of the tax credits as well as the accelerated depreciation.

When we take ownership in five years, we will be just reflected the value at that time one-time items on the statements ended March 31. Does that answer your question, Jim?

And in five years you are going to buy it from the partners?

Yes, we won't -- it automatically reverts. The ownership changes in terms of structure.

It flips to 95/5, where we on 95% of it and then we have the option to buy their additional 5% out. But it essentially flips to us at the end of approximately the fifth year.

And other than the 5%, there's no money that is transferred to the other parties?

Other than the 5%, no.

Okay. Then on your operating statistics, I don't see any entry for regional power [ad] credits. Don't you get any of those credits any longer for you customers?

Yes, we still get those credits. I think it's (multiple speakers) it is basically in a line called other retail revenues.

And in the quarter ended March 31, we got $16 million.

$16 million, thank you very much.

Jaideep Malik, Goldman Sachs.

Good morning. Just wanted to ask what is your outlook for the industry demand going forward in the division?

Sure, our industrial demand is looking strong. When we last spoke at the end of February, we were expecting about a 3% increase and we are not seeing it quite as high, but we are seeing an increase year over year, and a lot of that is driven by much of what happening in the solar area. We have four strong solar companies that are doing quite well, in particular SANYO and SolarWorld are in our service territories.

And can you provide any timeline for the results of the renewable RFP?

What was the question again? Oh, the timeline on the renewable RFP? Here is where we are in the process. As you know, we went out for 218 average megawatts. We did get a short list together. We then started negotiations with that short listed set of parties on their specific projects. During this negotiation, capital markets have kind of gone south on a number of these developers, where they can no longer access the capital markets, and they now are talking to us about potentially us taking the ownership control of those sites.

And so as part of our due diligence, we have had to go in and look more specifically at the site and two issues have emerged. One is making sure that we have transmission capacity to get the power out to our system. And secondarily, just the availability of turbines related to those sites because many of these sites came with specific turbine vendors and we want to make sure that we have done the diligence on those turbine vendors to make sure we are comfortable with the characteristics of those turbines.

So the negotiations have taken a little bit longer. We are still in active negotiations and again, we hope to have something to announce in 2009. I'd like to get these built in the 2014 timeframe. I don't think we will need the full 218 average megawatts, but that is the full list that we're looking at right now.

Thanks. Thank you.

Jeff Coviello, Duquesne Capital.

Good morning, how are you? I had two questions. I guess the $41 million you referenced earlier in the call was for the RAC filing I guess? But that is for mostly Biglow Canyon too, right? I presume that -- is it in -- at the end of 2010 or 2011 you will file a similar filing for Biglow Canyon 3. Is that correct?

That's correct. And it did have a little bit of ProLogis. It's up a couple of the solar projects in it, but it's really, really tiny. (multiple speakers) So $31 million included $35 million for the revenue requirements for 2010 plus about $7 million for the -- $6 million for the deferred costs for 2009. And then we also had some power cost reductions in the annual update tariff of about $15 million.

Okay, so does that include the annual update on the power costs as well or is that a separate --?

That is a separate filing. It's called the AUT filing and that reflects the benefits of Biglow Canyon Phase 2 in terms of power cost. It's kind of in two places. One has got the fixed cost and the other one has got the variable cost.

Okay, got it. And the selective water withdrawal system, that's been delayed but I think you had filed for about a $13 million revenue increase, which I gather is not -- if it's included in '09, it's included a lot later in '09. So is that something to think about as a revenue increase going into 2010?

Well, it will depend on when that goes into service. It's about $1 million a month and so whenever that goes into service, then we would hope to have prices go into effect to cover the cost of that. And during the interim we will continue to book AFDC on the capital. Our share of the capital is about $80 million of the total of about $110 million.

This is a complex project and it's not surprising as you go into these things, sometimes things happen. It's kind of a state-of-the-art project and I think we will recover okay and I still think we fundamentally believe the project will work once it's completed.

And we have been into conversations with the fish agencies and they are understanding of the challenge to this project and still very supportive of the project.

Got it, okay. Thank you.

(Operator Instructions) Mark Dishop, The Boston Company.

I just have a few questions. First of all, what is your expected change in pension expense this year?

We are forecasting about $300,000, $350,000 through the income statements. We have delayed our expectation with regards to cash funding in 2010 probably up to about $12 million as [benefit], previous $23 million, $25 million we had considered as a result of changes in the Pension Protection Act.

The $10 million in 2010 or just '09?

It would be up to -- up to $12 million in 2010.

Up to $12 million in 2010 versus your prior expectation of $20 million?

No, that is a funding requirement. It's not necessarily income statement, so it's a matter of having to put additional funds into our pension plan.

And it used to be $20 million?

It was $23 million was our last expectation that you can find in our 10-K.

Okay, now it's only 12, and your pension expense changes only $350,000 this year?

Yes.

That is the FAS 87 expense, which is more of a smoothing calculation that reflects both gains and losses from prior periods.

It is smoothing, okay. And then is that change in your rates or do you have to eat that until you get the next rate case?

We typically just include that in the next General Rate Case. We are looking at 2010 to see how big the expense would be in 2010 and a lot of that will depend on how the assets earn during the rest of the year. And we may look at some potential deferral for that, but right now, the current methodology is we put it in the General Rate Case and we forecast it.

So in other words, you are eating for the moment. It's tiny, but --

Tiny this year but I think in the rate case, we assume zero.

Okay, and then the --? What is your rate base currently in your regulated rate base?

With Biglow Canyon Phase 2 completed? (multiple speakers) Maria is going to look up for a second. I think we provided a projection (multiple speakers)

The average for this year is 2.3 million.

The 2009 average is 2.3 billion?

Yes, and that does not include Biglow Canyon.

It excludes Biglow Canyon, so the Biglow Canyon is how much this year on average -- are you going to spend?

That is $240 million, I believe.

That's the total spending that's excluded?

Yes.

Okay and in your earnings do you somehow calculate some EPS on that Biglow Canyon?

Well, the way it works on Biglow Canyon because of the renewable energy adjustment clause, we book AFDC during the construction of the plant, so that is non cash earnings. That would go until plant goes into service and then under the renewal energy clause we defer the net cost, so that's including the power cost benefit less all the capital costs including depreciation and a full return on capital until the end of the year. That's the number that Maria reported, $6 million. That's the deferred benefits or deferred net cost of the project.

So we get a full return. It just -- it is still all non-cash during 2009 and then it turns into increases in customer prices starting in 2010.

Non-cash 2009 $6 million and you get it in rates 2010.

Actually in prices starting January 1, 2010.

And that's the $6 million difference.

That 6 million deferral is from the point the project goes into service until the end of the year.

Okay, so -- but that's not the return on the $240 million. That's just the deferred cost.

That includes everything, both the return on capital, the depreciation, less the power cost benefits.

Okay, that's great. Then the -- so in your EPS, you get a return on the equity part of your $2.3 billion rate base plus you are also getting an equity return calculated on your $240 million that is excluded from -- that is not in the rate base yet. Is that right?

The $240 million is the average rate base for the year, not just the full cost, because the full cost of Biglow Canyon is much greater than that.

Yes, (multiple speakers) it's about $320 million.

$320 million total spending by the end of the year?

Yes.

Right, so I am just trying to see. I mean you are getting a 10% ROE. You are getting that on in the equity part of your $2.3 billion plus you are getting -- you are calculating also an equity percent on your -- on the $240 million average for Biglow Canyon, you get a return on that for the year. That is just not cash, is that right?

Yes.

Okay, and then in terms of any -- so that would all be your allowed return and then you have some things that are kind of hits against your allowed 10%. So this pension is kind of tiny and then you have the demand being lower than normal that is also kind of a hit that you eat till the next rate case. Is that right -- or until -- within the band you would eat it?

Part of that is covered through decoupling. On the residential commercial side, it is covered through decoupling.

Does the decoupling have a band where you eat part of it first?

No, it's just a straight calculation. It's a weather-adjusted calculation so you don't -- the only thing you are potentially exposed to is the power cost component of it. It could be either above or below the average cost in rates.

You don't eat anything at all for this volume change?

For the residential commercial component of the load reduction.

Okay. And then -- I thought you said on volume you're expecting it to be down 1% for the year because of industrial demand. And then you said I thought that industrial demand is not as strong as expected but still up.

Right, it's up but it's not as high as what we forecasted as part of the General Rate Case. So when we did the General Rate Case, we projected certain industrial loads and those projections were done before the downturn in the economy. The downturn started in October. By that time we had already set our load forecast. So I think it's a relative measure, so we had projected a little stronger industrial growth and even though it is growing this year, it's not growing as much as we had anticipated.

Okay, so -- okay, great. So that would be a hit because that -- the industrial part is not covered by your decoupling.

That is correct.

And so the 1% decline versus what was in your rate case, what was the expectation, was it growth or zero?

For what?

What was the expectation for growth in your rate case?

For overall growth? Approximately, I think around still less than 2%, about 1.87%.

1.87%.

1.7%

1.7% was forecast in the rate case. Instead, it is negative one. Most of that change is industrial, which you have to eat for the moment for this year, which is all -- it's all within your guidance. I am just trying to get the calculation. Is that a fair way to say that? Okay, those are my questions. Thank you.

At this time, there are no further questions. Are there any closing remarks?

Thank you. We appreciate your interest in Portland General Electric and invite you to join us in a few months when we report on second-quarter 2009 results. If you have any additional questions, please contact Bill Valach, who will be available after this call. Thank you again for joining us today.

Ladies and gentlemen, this does conclude the Portland General Electric first-quarter 2009 earnings results conference call. You may now disconnect.