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. (Operator Instructions) For opening remarks, I would like to turn the conference call over the Portland General Electric's Director of Investor Relations, Mr. Bill Valach.

Good morning everyone. We're pleased that you're able to join us today. Before we begin our discussion this morning, I'd 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 difference, the company requests that you read our most recent Form 10-K and Form 10-Q's. The Form 10-Q for the first quarter of 2009 was available this morning at portlandgeneral.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 opened 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. Now I'd like to turn it over to Jim.

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'll review earnings, address the key drivers to our performance and reaffirm guidance for 2009. Then I'll update you on Oregon's economy and the outlook for our operating area. Finally, I'll discuss the progress we're 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 in other operating expenses offset this increase. Maria will go into more details later on the call. It's been a busy year. We've 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'll move on to 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 assume normal plan operations and reflects steps taken to align our operating costs with the Oregon Public Utilities Commission's General Rate Case order issued in January. We're also reaffirming our long…

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 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 non qualified pension benefit plan assets and additional costs related to the December 2008 storm. 2008 first quarter results were impacted by $3.7 million after tax loss of $0.06 per diluted share, also from a decline in the fair market value of the non qualified benefit plan assets and refunds to customers under FC-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 on $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…

In the first quarter all areas of our operations performed well. Customer satisfaction continues to be high. We're 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. We'd now like to open the call for questions.

(Operator Instructions) Your first question comes from Brian Russo – Landenburg Thalmann. Brian Russo – Landenburg Thalmann: You talked about your 2010 capital market needs in terms of debt and I'm wondering, it looks like your debt to cap is creeping up above 50%. I think that's even with the equity offering completed in March and I'm wondering, do you have any capital equities in 2010 to finance the CapEx.

We are expected to be just a tad bit above our target 50/50% but as we collateral positions rolling off as well as with the $375 million of debt that we'll 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. Brian Russo – Landenburg Thalmann: On the guidance, it looks like hydro is below normal in the first quarter and growth is slowing and I'm just wondering if you could talk about the positive and negative drivers that you've assumed in your '09 guidance versus '08.

As we noted in the first quarter, we were off on hydro. Hydro conditions though since our last conference call and our expectation has increased almost ten percentage points on average and so we are expecting more hydro profitability in that area. Also, with the exception of the Coal Strip outage that Jim mentioned, our operating facilitates are doing quite well and we would expect the plants to continue to have a positive impact on our outlook. We are maintaining our guidance of $1.80 to $1.90. Brian Russo – Landenburg Thalmann: 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?

The decoupling mechanism is working virtually as we expected and that is in our forecast. And we've mentioned it in the first two months of this being in effect since February 1, we have seen about $5. million net benefit. And that's taking into consideration what we received through the decoupling offset by the ten basis point reduction in our ROE. Brian Russo – Landenburg Thalmann: You mentioned that you expect hydro conditions to improve in the second quarter. Can we assume that 5% to 6% hit you took in the first quarter could possibly reverse in the second and third quarter? Could you see a net benefit to hydro?

Yes. We are expecting that.

A lot of it will depend on how the snow comes off the mountains. If it comes off at a rate that 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 could see it melt all at once or we could see it 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. Brian Russo – Landenburg Thalmann: Your initiative to realign your cost structure relative to the General Rate case outcome, can you cite some examples or projects that are ongoing and if you see any impact of that in the first quarter.

We did see impact. A couple of things are going on. First of all, we've tried to realign our operations in the distribution area to reflect a couple of things. One is the fact that we're seeing less customer activity there and we have to place some of our crews to capital projects that need to be worked on. Typically we use contractors, and we've been able to deploy those crews to construction projects. That's one area. We've gone through all areas of operations to see where we can reduce costs to make sure we're still delivering value, but reducing mostly outside services. We've taken a very slow position on replacing open positions in the company and just looked where we can realign our 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 costs.

Your next question comes from Steven Gambuzza – Longbow Capital. Steven Gambuzza – Longbow Capital: Can you repeat the comments you made about the Borgman controls? I just want to understand where that process is in terms of whether or not you're actually going to go ahead with that capital?

Here's the process. The Department of Environment Quality has put out their proposal. We then submitted comments suggesting more of a phased approach to the decision point analysis to give decision points along the way. All of 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 Environment Quality will put out a draft proposal in mid May and then the Environmental Quality Commission will make a decision in June. We'll 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. The process there is to look at the overall economics of the project and what we'd like to get from the commission is some acknowledgement of the proposed actions. The challenge we have right now is we're not sure what the Environmental Quality Commission is going to decide. Are they going to adopt our decision point analysis or are they just going to 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 in our integrated resource plan, but until we see the final Environment Quality Commission decision, we really don't have a firm proposal yet to model. Steven Gambuzza – Longbow Capital: The comments you made about future resource needs given your short energy capacity position of 300 to 500 megawatts via Borgman and a 100 to 200 megawatt simple cycle up at Westward, does that assume that Borgman stays in the mix as a resource?

Yes that would assume Borgman stays in the mix. If Borgman 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 with a gas turbine. Steven Gambuzza – Longbow Capital: What would the time period be on the simple cycle and PTC simple cycle that you mentioned?

We're talking in the 2013 to 2015 time frame, 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 a proposal where we would put in our self build options. That would likely go through the 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 '12 and '13 dependant upon the time frame. So what we're doing right now is we're going through the citing process for each of those projects. You have to go through the air permitting process. So we're 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. Steven Gambuzza – Longbow Capital: Your would imagine filing the application for the self build at some point in 2010 or 2011?

We'll probably file them this year. Steven Gambuzza – Longbow Capital: 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 you're required return is, and just given the change in your cost of capital, is it fair to say that you're going to require a higher rate of return than 10% to go ahead and raise a bunch of capital and increase investment at this point?

We do those economic analysis. We do 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. We will try to reflect that. At the end of the day, the commission decides what the ROE in each specific rate case. They really aren't making a decision on that self build option relative to our ROE. It is for planning purposes only at that point. We will have to make our case before the Public Utility Commission in a General Rate Case on what the appropriate ROE is for our company. I think you're seeing a trend in the industry across the national that ROE's are going up to reflect the potential risk in the utility sector as well as the overall required return given the current economic times. So it will be nice as we go into our next General Rate Case which likely would be 2011 to the extent commissions are granting higher ROE's, I think that will be reflective of the risk and the appropriate return for equity investors in the utility sector.

Your next question comes from [Sarah Acres – Wachovia] [Sarah Acres – Wachovia]: 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's been any progress in securing the partners and then just an update on the outline of what the next steps are for that project.

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 is 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's kind of what we're doing. Our current plan is to have that project in commercial operations around 2015, again to link it up with the energy resource at Borgman. So that's kind of where we are in the process. We're 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'll take it to the next step which is a more detailed analysis in terms of the economics. So we're doing a number of projects. We're starting the survey work for Environmental mitigation, where the transmission lines are going to go. This line is mostly an existing right of way so that should minimize some of the environmental impacts. And so that's the process we're 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 our conversations with potential co-owners and get a better handle on the economics and cost of the project. [Sarah Acres – Wachovia]: On the decoupling mechanism, is there anything that the regulators tried to separate the impact of efficiency and conservation versus just the economic decline, or is it just all kind of captured in there?

It's really all captured in there. It's almost impossible, at least for the customers less than 30kw, it's impossible to determine whether it's resulting from energy efficiency or conservation. And frankly, either one is a good thing for our customers because it reduces our environmental footprint so I don't think they've tried to distinguish between the two. For the customers between 30 kw and 1 megawatt, those customers what we will have to identify specific energy efficiency measures that they implement and we'll work with the Energy Trust of Oregon to identify those specific measures. And then the customers larger than 1 megawatt, they don't fall into the decoupling mechanism. That's kind of where that is, and that's one of the concerns raised by COV. I think on the residential sector, but our view is that whether customers change their behavior and reduce our product or actually install measures that reduce the consumption of electricity like fluorescent lighting or other measures like weatherization, our customers and the company should be indifferent to that impact. So that's kind of where we are.

Your next question comes from James Bellessa – D. A. Davidson & Co. James Bellessa – D. A. Davidson & Co.: I want to double check on your guidance. In the most recent quarter you had a couple of items that were one time or non recurring of nature. Are they built into the guidance?

Yes, they are. James Bellessa – D. A. Davidson & Co.: And how about Coal Strip outage and the select water withdrawal delay?

Yes, both are baked in.

On the water withdrawal, our assumption is that the project would continue on the construction work in progress and then would go into service, go into rates when it goes into service. We think that's a minimum of four months and we do not yet have a final date on when that would go into service. James Bellessa – D. A. Davidson & Co.: Are you winding up for the potential of these Trojan grant options or are you still kind of iffy on that?

We're currently assessing them and we're looking for a little bit more information in regards to how the rules are applied and particularly around some of the normalization issues. We are more enthusiastic about the grant than the PTC's but there are still some unknowns that we need to resolve.

We're 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. James Bellessa – D. A. Davidson & Co.: 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 it be occurring regularly?

This is related to the Pro Lodges solar project that we've located on a roof top that 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.

What we did was we increased our depreciation and amortization by about $7 million and then added back the $7 million, the exact same number to net loss contributed to non controlling interest. You'll remember that we are the minority partner at this point. We contributed about 7% of the project cost. We're just under $700,000 and the tax equity partner will receive the majority of the benefit of all the credits as well as the accelerated depreciation. When we take ownership in five years, we will be reflected the value at that time as a one time item on the statements ended March 31. James Bellessa – D. A. Davidson & Co.: And in five years, you're going to buy it from your partners?

Yes. It will automatically revert. The ownership changes in terms of structure.

It switches from 95/5 to where we own 95% and then we have the option to buy their additional 5% out. But it flips to us in approximately the fifth year. James Bellessa – D. A. Davidson & Co.: Other than the 5%, there's no money transferred to the other parties?

Other than the 5%, no. James Bellessa – D. A. Davidson & Co.: On your operating, I don't see any entry for regional power credits. Don't you get any of those credits any longer for your customers?

We still get those credits. It's in the line call other retail revenues.

In the quarter ended March 1, we got $16 million.

Your next question comes from [J. D. Malik – Goldman Sachs] [J. D. Malik – Goldman Sachs]: I wanted to ask about the industrial demand going forward.

Our industrial demand is looking strong. When we last spoke at the end of February, we were expecting about 3% increase and we're not seeing it quite as high but we are seeing an increase year over year, and a lot of that is driven by what's happening in the solar area. We have four strong solar companies that are doing quite well in particular, Sanyo and Solar World are in our service territories. [J. D. Malik – Goldman Sachs]: . Can you provide any time lines for renewal RFP?

Here's 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 negotiations, capital markets have kind of gone south on a number of these developers where they can no longer access the capital markets, and they are now talking to us about potentially us taking the ownership control of those sites. So as part of our due diligence, we've had to go in and look more specifically at the sites 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've done the diligence on those turbine vendors to make sure we're comfortable with the characteristics of those turbines. So the negotiations have taken a little bit longer. We're still in active negotiations and again, we hope to have something to announce in 2009. We'd like to get these built in the 2014 time frame. I don't think we'll need the full 218 average megawatts, but that's the full list that we're looking at right now.

Your next question comes from [Jeff Coviello – Duquesne Capital] [Jeff Coviello – Duquesne Capital]: The $41 million you reference earlier in the call was for the RAC filing, but that's mostly for Biglow Canyon II, right? I presume that the end of 2010 and 2011 you'll file a similar filing for Biglow Canyon II, is that correct?

That's correct. We did have a little bit of Pro Lodge, a couple of the solar projects, but it's really, really tiny. The $41 million included $35 million for the revenue requirements for 2010 plus about $6 million for the deferred cost for 2009, and then we also had some power cost reductions in the annual update of about $15 million. [Jeff Coviello – Duquesne Capital]: Does that include the annual update on power costs as well or is that a separate file?

That's a separate filing. It's called the AUT filing and that reflects the benefits of Biglow Canyon Phase II in terms of power cost. It's kind of in two places. One's got the fixed cost and the other one has the variable costs. [Jeff Coviello – Duquesne Capital]: And the selective order withdrawal system, that's been delayed. I think you had filed for about a $13 million revenue increase which I gather, 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 '10?

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 to 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 something things happen. It's kind of a state of the art project and I think we'll recover okay and I still think we fundamentally believe the project will work once it's completed. And we have been in conversations with the fish agencies and they're understanding of the challenges of this project and still very supportive of the project.

Your next question comes from [Mark Bishop – Boston Company] [Mark Bishop – Boston Company]: What is your expected change in pension expense this year?

We're forecasting about $300,000 to $350,000 to the income statement. We have delayed our expectation with regards to cash funding in 2010 probably up to that $12 million instead of the previous $23 million to $25 million we had considered as a result of changes in the Pension Protection Act. [Mark Bishop – Boston Company]: $10 million in 2010?

It would be up to $12 million in 2010. [Mark Bishop – Boston Company]: Up to $10 million in 2010 versus your prior expectation of $20 million?

No, that's our funding requirement. It's not necessarily income statement. So it's a matter of having to put additional funds into our pension plan. [Mark Bishop – Boston Company]: It used to be $20 million?

$20 million was our last expectation that you can find in our 10-K. [Mark Bishop – Boston Company]: Okay, now it's only $12 million, and you pension expense change is only $350,000 this year?

Yes.

That's the FAS-87 expense which is more of a smoothing calculation that reflects both gains and losses from prior periods. [Mark Bishop – Boston Company]: 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 earned 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 a General Rate Case and we forecast it. [Mark Bishop – Boston Company]: So in other words, you're eating it for the moment.

It's tiny, but I think in the rate case we assume zero. [Mark Bishop – Boston Company]: What is your rate base currently in your regulated rate base?

The average for this year is $2.3bmillion. [Mark Bishop – Boston Company]: 2009 average is $2.3 billion?

Yes. And that does not include Biglow Canyon. [Mark Bishop – Boston Company]: So the Biglow Canyon is how much this year on average?

That is $240 million I believe. [Mark Bishop – Boston Company]: That's the total spending that's excluded?

Yes. [Mark Bishop – Boston Company]: In your earnings, do you somehow calculate some EPS on that Biglow Canyon?

The way it works on Biglow Canyon, because of the renewable energy adjustment costs, we book AFDC during the construction of the plant, so that's non cash earnings. That would go until the plant goes into service and then under the renewable 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 and 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's still all non cash during 2009 and then it turns into increases in customer prices starting in 2010. [Mark Bishop – Boston Company]: Non cash 2009, $6 million and you get it in rates 2010.

Actually in price, it's starting January 1, 2010. [Mark Bishop – Boston Company]: And it's the $6 million difference.

That $6 million deferral is from the point the project goes into service until the end of the year,. [Mark Bishop – Boston Company]: But that's not the return on the $240 million.

That includes everything; both the return on capital, the depreciation less the power cost benefits. [Mark Bishop – Boston Company]: So in your EPS you get a return on the equity part of your $2.3 billion rate base, plus you're also getting an equity return calculated on your $240 million, that's 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. The full cost of Biglow Canyon is much greater than that.

Yes, $320 million. [Mark Bishop – Boston Company]: You're getting a 10% ROE, you're getting that on the equity part of your $2.3 billion plus you're getting, you're calculating also an equity percent on the $240 million average for Biglow Canyon, you get a return on that for the year. That's non cash, is that right?

Yes. [Mark Bishop – Boston Company]: So that would 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 is also kind of a hit that you eat until the next rate case, or until the band you would eat it.

Part of that is covered through decoupling. On the residential, commercial side it's covered through decoupling. [Mark Bishop – Boston Company]: 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 the only think you're potentially exposed to is the power cost component of it. It could be either above or below that average cost in rates. [Mark Bishop – Boston Company]: You don't eat anything at all for this volume change.

For the residential, commercial component of the load reduction. [Mark Bishop – Boston Company]: I thought you said on volume that you expecting 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 by still up.

It's up but it's not as high as 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 through it's growing this year, it's not growing as much as we had anticipated. [Mark Bishop – Boston Company]: So that would be a hit because the industrial part is not covered by your decoupling and so the 1% decline versus, what was in your rate case, the expectation was growth or zero?

Overall growth, approximately a little less than 2%, about 1.7%. [Mark Bishop – Boston Company]: 1.7% was forecast in the rate case. Instead it's negative 1%. Most of that change is industrial which you have to eat for the moment for this year which is all within your guidance. I'm just trying to get to the calculation. Is that a fair way to state that? Those were my questions.

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.