Good day everyone and welcome to the Portland General Electric fourth quarter 2008 earning results conference call. Today is Wednesday, February 25, 2009. 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 over to Portland General Electric's Director of Investor Relations, Mr. Bill Valach. Sir, please go ahead.

Thank you, Abigael, and good afternoon, everyone. I’m Bill Valach, Director of Investor Relations at Portland General Electric, and we are pleased that you were 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 fact, 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, company requests that you read our most recent Form 10-K and Form 10-Qs. The Form 10-K for the year ending December 31, 2008 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, future events, or otherwise. And this Safe Harbor statement should be incorporated as part of any transcript of this call. Portland General Electric’s fourth quarter 2008 earnings were released before the market opened today, and the release is available at portlandgeneral.com. With this release, PGE announced earnings of $20 million or $0.32 per diluted share for the fourth quarter ending December 31, 2008 compared to $24 million or $0.40 per diluted share for the fourth quarter ending December 31, 2007. Earnings for the year ending December 31, 2008 were $87 million or $1.39 per diluted share compared to $145 million or $2.33 per diluted share for the same period in 2007. 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 then will discuss in more detail our year-end and fourth quarter results. Then, we’ll open the call up for questions. Now, it’s my pleasure to turn the call over to Jim.

Thank you, Bill. Good afternoon, everyone, and thank you for joining us. Welcome to Portland General Electric’s 2008 year-end and fourth quarter earnings call. Today, I’m honored to lead my first earnings call as PGE’s President and CEO. Our leadership transition has been seamless, thanks to the great support of our retiring CEO, Peggy Fowler, and the experience of our new CFO, Maria Pope. Maria served on PGE’s Board of Directors since 2006, so she has a strong understanding of the opportunities and challenges we are facing. Welcome, Maria. For most industries, 2008 was a turbulent year. I know that liquidity and access to capital is on everyone’s mind. So on today’s call, we’ll address those issues and others and we’ll let you know how the economy is impacting PGE. First, I’d like to review PGE’s 2008 earnings and address the key drivers. Second, I’ll reaffirm and discuss guidance for 2009. Third, I’ll discuss Oregon’s economy and the outlook for our operating area. And finally, I’ll update you on PGE’s strategic direction and the progress we are making. Later, Maria will provide additional details on fourth quarter and year-end results, the outcome of our general rate case and other regulatory proceedings including an update on Trojan, as well as out liquidity and strategy for raising capital. So let’s get started. PGE’s net income for 2008 was $87 million or $1.39 per diluted share, which is $0.01 below the low end of our guidance. We revised 2008 guidance in the third quarter to $1.40 to $1.50 per share to reflect the Trojan Refund Order. For the full year 2008, results were driven primarily by increased energy deliveries and excellent power supply operations. However, these positive results were offset by the impacts related to the Trojan Refund Order and a decline in…

Thank you, Jim, and good afternoon everyone. First, I’d like to say how pleased I am to be the Chief Financial Officer of Portland General Electric. As a member of the Board of Directors for the past three years, I have worked closely with the PGE team and look forward to my new role. As Jim mentioned, net income was $1.39 per share for the 12 months ended December 31, 2008, compared to $2.33 per share for 2007. 2008 results were primarily driven by four key items; first, a $20 million after-tax loss or $0.32 per diluted share due to the Trojan Order; second, a $12 million after-tax loss or $0.19 per diluted share from the decline in the fair market value of our non-qualified plan assets during 2008; third, a $6 million after-tax gain or $0.10 per diluted share from oil sales at the Beaver Plant; and finally, a $6 million after-tax loss or $0.10 per diluted share from customer refunds under Senate Bill 408. 2007 results were impacted by the following gains; a $16 million after-tax gain or $0.26 per diluted share from the 2007 deferral of a portion of Boardman’s replacement power cost; an $11 million after-tax gain or $0.18 per diluted share from customer collections under SB 408; a $4 million after-tax gain or $0.06 per diluted share from the settlement with certain California parties involving wholesale energy transactions, which took place between 2000 and 2001; and finally, a $3 million after-tax gain or $0.05 per diluted share from the increase in the fair value of non-qualified plan assets during 2007. I will now discuss the fourth quarter results. PGE’s net income for the fourth quarter 2008 was $20 million or $0.32 per share. This compares to a net income of $24 million or $0.40 per…

Thanks, Maria. In 2008, all areas of our operations performed exceptionally well. We are number one in the western region in overall business customer satisfaction and power quality and reliability according to J.D. Power & Associates. 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 and our customers. Operator, we’d now like to open the call up for questions.

(Operator instructions) Your first question comes from Rick Shobin with GLG Partners. Your line is open. Rick Shobin – GLG Partners: Hi, good afternoon.

Hi, Rick. Rick Shobin – GLG Partners: I was just curious as to, I know you guys are trying to do your best, as we all are with regards to managing the pension and trying to make sure that there isn’t a shortfall. I was just wondering, with regard to funding the pension, whenever you make funding or deposit money into it, is that recovered through rates as it go to rate base, how does it function?

The way we – this is Jim Piro, Rick, thanks for the question. The way we recover our pension expense is, we include in our general rate case our estimated what's called the FAS 87 expense. So that’s the smoothing number that we calculate under the accounting standards. That’s the number we include in general rate cases. So over time, we will have the opportunity to recover the cost of our pension. So it doesn’t quite necessarily match the cash flows, but over time it does catch up to it. Rick Shobin – GLG Partners: So the actual cash infusion into the pension gets amortized over the course of however long the life of the pension is?

That’s correct, Rick. Rick Shobin – GLG Partners: It winds up getting made up through the other rates.

That’s correct. There might be a little timing difference on funding versus the actual cash flow from our customers but that’s over the life of the plan and that can change based on the actual earnings of the assets. Rick Shobin – GLG Partners: Okay. Thank you very much.

You’re welcome.

Your next question comes from James Bellessa with D.A. Davidson & Co. Your line is open. James Bellessa – D.A. Davidson & Co.: Jim, I think I heard you say that your assumptions about your 2009 EPS guidance, one of the assumptions was flat weather-adjusted load in 2009 versus 2008. Was that correctly heard?

That is correct, Jim. James Bellessa – D.A. Davidson & Co.: Now, I see in your narrative, your unemployment rate in Oregon went to 9% versus a 6.3% average for the year. It went to 9% at the end of the year and you’ve called for the sensitivity of declines in your load versus increases in the unemployment rate. So, why would you be assuming that the load is flat ’09 versus ’08?

Good question, Jim. What we’re projecting, and this is based on the December state forecast which we use to do our load forecasting, is essentially we’re projecting a decline in residential usage and an increase in industrial usage, primarily driven by the new solar companies that are coming into our service territory and adding new facilities. That’s the simple answer to the question. So, we do understand that residential customers, both growth and their usage is going to be down, but that will be offset by increasing load in our large customer sector. James Bellessa – D.A. Davidson & Co.: On the renewable adjustment clause mechanism, you’re going to be filing here in, I think I heard April, for rates that would be used for recoverable starting January 1, 2010. Is that correct?

That is correct, though we are allowed under the renewable adjustment clause and we’ll do this, is to defer the net cost of the renewable assets during the year that they come into service. So, we will track both the costs and the benefits of Biglow Canyon Phase 2 during 2009. We’ll defer that amount during the year and then we’ll amortize that over a period of time depending on the size of that net revenue requirement. James Bellessa – D.A. Davidson & Co.: So, on Biglow Canyon Phase 2, you don’t start collecting on January 1, 2010 forward?

We start collecting the costs from customers starting January 1, but from accounting perspective, we will accrue for the revenues that we would have collected, had the (inaudible) service when it does. So, we get to defer the net cost of the project during 2009 with the rates to customers becoming effective on January 1, 2010. James Bellessa – D.A. Davidson & Co.: Okay. Now, I’m surprised to see negative working capital, and then I read the explanation on why you have it, but how long does it take to reverse that and rid yourself of a negative working capital position?

This is related to our collateral deposits? James Bellessa – D.A. Davidson & Co.: Yes.

Maria, you want to go and answer that one?

Sure. We have collateral deposits, as I said, of about $360 million. About half of that reverse is by the end of this year, assuming no change in prices from February 20. James Bellessa – D.A. Davidson & Co.: Is there something in the future you can avoid having negative working capital, like striking your contracts differently or –?

Well, Jim, it all depends on what the price that we pay for the energy is. We’ve had times when we had significant deposits with the company when prices had moved up from what we actually purchased energy for. We try to do our best from a strategic purchasing strategy to buy that power and gas over time, and you’re never going to get perfect in terms of it [ph], the purchase as well to the market price. You may have times where you have to post collateral. There may be other times where you receive collateral. James Bellessa – D.A. Davidson & Co.: I see you have union negotiations going on. What’s the status, if you can tell us about that?

We’re in cooperative discussions with the union. We’ve had some fairly healthy discussions on the major issues. We hope to have something to disclose in the next couple of weeks or so, but that’s all I’d like to tell you about it right now. I think those – the conversation’s going well. The contract effectively ends on February 28, but there’s been no request for a termination of the contract. So, the contract will continue in force and I would tell you the negotiations have been constructive, and I think will produce a reasonable result for the company. James Bellessa – D.A. Davidson & Co.: In the most recent quarter, you had DD&A of $54 million, so the annual run rate is $220 million, but you’re calling forth in your 10-K Form $209 million DD&A in year 2009. Why does it go down, the run rate?

Maria, will you take that?

Sure. Our amortization is fluctuating as assets come off. In addition, we have several assets that will be coming on. James Bellessa – D.A. Davidson & Co.: Thank you very much.

Thanks Jim.

Your next Maurice May with Power Insights. Your line is open. Maurice May – Power Insights: Yes. Good afternoon, folks.

Hi, Maurice. How are you doing? Maurice May – Power Insights: Okay. Congratulations again, Jim. On the timing of the equity offering, can you help us out a little bit here more than just, depending upon market conditions which I assume you don’t want to sell it tomorrow at $16.38, but can you give us any timing throughout the year when you really need the equity?

We’ve been pretty broad in this question and I know people would like more specific guidance but we've said between now and the end of 2009 as we evaluate market conditions, I think that’s really about as far as we can go on that. Maurice, until we make some final decisions and we continue to evaluate the markets, looking around cash flow needs, but I think we're just comfortable at this point saying between now and the end of 2009. Maurice May – Power Insights: Okay. And your book value, I estimate, is about $21.64. Is there any intangible part of that book value or is there any part of that book value that you’re not earning on?

No, it’s all in the regulated core business. Maurice May – Power Insights: Okay. Another question on guidance, you said guidance was based on normal hydro but the current conditions are below normal. And I was just wondering if you can extrapolate on below normal current conditions to the end of the snow pack season, what might that impact be on guidance?

This is still early in the hydro season and we’ve seen in historic past that we can be below normal at this point in the season and still catch up within the next month or so with major snowballs coming. So it’s hard for us to estimate what's going to happen with the snow pack at this point. So when we developed the guidance, we just assumed normal hydro. You’ve seen the numbers probably on the Web site in terms of what the current forecast is. On the Columbia, it’s about, at Grand Coulee, it’s about 86%; on the Clackamas River, it’s about 84%; and on the Deschutes River, it is about 89%. So it’s a little bit more than around 10% to 15% below normal. But again, it’s still fairly early in the season. That’s based on the February 20th forecast. And so, it’s too hard to predict where it’s going to come out at the end of the day. So, that's kind of where we are at. In terms of the impact on our system, we are roughly 580 average megawatts of hydro between our mid-Columbia contracts and our existing resources. So, you can make your estimate of how that might be impacted by hydro in terms of where it might come out, and then just multiply that times the market price and come up with what you think the impact could be. But, again, it’s just too early in the hydro season to forecast where it’s going to be. And so, we were comfortable at this point, just continue to estimate it based on normal hydro. Maurice May – Power Insights: Okay. The forecasted prices this year are down, so the cost of replacement power costs would not be as detrimental to the PCAM as earlier years. Is that correct?

That’s correct, because gas prices are down which is reducing the market price of energy in the overall market. Maurice May – Power Insights: What assume us [ph] these days?

Let’s see, do you have that Maria? Let me see if I have. I think it's around the $4 rate, I think last thing I saw.

It’s about $4.50. Maurice May – Power Insights: Okay. Good. And then on, you refer to aligning operating costs with the recent rate case order. Can you give us some color on that? Will you disallow some costs that you decided not to spend?

As far as the order as we mentioned that we requested about $56 million and the commission came in at about $26 million. We looked at those various areas and we’ve taken what we feel as necessary action, get our O&M aligned with the approved O&M costs in the rate case. And we think we have a plan in place to do that, and we have reduced them of our discretionary spending. Some of our reduction in spending is related to the slowdown in the economy, so we’ve taken advantage of that and we’re trying to deploy our crews to capital projects to keep them employed, keep them busy, but to reduce our outside contractor costs as a way to absorb some of those cost differences. Maurice May – Power Insights: Okay. And then one final quick question, on decoupling, that covers both weather and conservation, does it not?

No. It does not cover weather. It only covers the effects of energy efficiency and conservation. It primarily is focused at our residential and commercial customers. For our large industrial customers, there’s a loss revenue calculation related to their specific projects that they might implement related to energy efficiency. So the decoupling mechanism, once we look at the final numbers, we have to weather normalize their usage and then we do the calculation of the effects of the energy conservation. Maurice May – Power Insights: Okay. Good. Thank you very much, folks.

You’re welcome. Thanks, Murray.

Your next question comes from Chris Ellinghaus with Shields & Company. Your line is open. Chris Ellinghaus – Shields & Company: Hi everybody, how are you?

Good. Hi Chris, how are you doing? Chris Ellinghaus – Shields & Company: Good. One thing you didn’t mention, Jim, that I was curious about, I know at some point you’re going to need a new regulating asset, but you didn’t talk about that in sort of your forward look. Can you comment about that?

What do you mean by regulating assets? Chris Ellinghaus – Shields & Company: I was under the impression that at some point, you were expecting you need some kind of gas asset for regulating and balancing of new (inaudible)?

Yes. You are talking about additional capacity, we call them capacity resources, something to balance the load with our additional wind resources. We definitely see a need at add capacity resources to help maintain the stability and reliability of our system. So as part of the integrated resource plan, we will file from self build options for both energy and capacity, and then we would include those self build options in an RFP that would likely be conducted in late 2010 or 2011, with construction probably in late 2011 or 2012. So, those dates will kind of move around as we go through the integrated resource plan. But we clearly see a need to add additional energy and capacity resources to protect the system and ensure reliability, especially given the amount of wind resources we’re adding. So that’s the way we are going to address it, we’ll file that integrated resource plan in third quarter of 2009 and then work through the various details with the regulatory and our intervener groups. Chris Ellinghaus – Shields & Company: And you expect that to be a self build plan as opposed to just a general RFP?

Well, what we would do, and this is exactly what we did with Port Westward, we would include a self build option kind of in a sealed bid. We’ll go to the market and ask for, request for, proposals for those same types of products, both energy and capacity. We’ll then compare the bids that are provided by the market against our self build options. If our self build options are the lowest cost, best value for customers, we’d move forward with those projects. If there’s a better option in the market place, then we would go forward with those options. So we have an obligation to ensure we deliver the lowest cost, best value for customers. Chris Ellinghaus – Shields & Company: Okay. And sometime this year, you’re supposed to have a significant Boardman outage, did you get approval through the rate case deferral of those costs?

Yes, we estimated about a 60-day maintenance outage for Boardman to address putting in our new starter and exciter at the plant, as well as put a new generator rotor in. So we believe we’ve got adequate time in our cost forecast to allow for that work to be done, so that was included in our annual update tariff filing as a 61 day maintenance outage, I think it was. Chris Ellinghaus – Shields & Company: And can you remind us when you expect that outage to begin?

We don’t typically disclose on those outages. They’re typically in the spring months, but we don’t like to give specific dates out there, because we have to go out and replace that energy in the marketplace and don’t like to let people know exactly when things are going to go off and on. Chris Ellinghaus – Shields & Company: Okay. And one last thing, can you give us any update on your dividend payout expectations and any sort of general thoughts?

As we talked about on the call here, in the long term, we’d like to get to 60% payout ratio. That’s kind of consistent with our industry peers and where the market is. But we do have good investment opportunities, so we are going to move very cautiously up that curve. We are around, if you look on a normalized basis, we are around the 54% level and we’d like to move that up over time. But as long as we have good investment opportunities, we’d like to re-deploy that equity in the business. The Board makes decisions on the dividend every quarter as we present to them our plans and what they think the market requirements are, but that’s our plan right now. Over the long term, we’d like to get to 60%, but how we specifically get there will depend on our arranged pattern and our investment opportunities. Chris Ellinghaus – Shields & Company: Thanks, Jim. Welcome aboard, Maria.

Thank you.

Thanks, Chris.

Your next question comes from Michael Lapides with Goldman Sachs. Your line is open. Michael Lapides – Goldman Sachs: Hey guys. Congrats on a really good quarter and welcome Maria. Question for you, I want to make sure, and you reaffirmed the dividend (inaudible), we think that some other companies that have traded below book value reassess how do they juggle the need for equity versus the dividend payout. Just curious for your thoughts in terms of the balance between those two items given your, I don’t know, roughly $4, $4.5 below book value.

Good question, Michael. We believe that our investors expect a dividend from our company. We think that’s appropriate to reward them for not only the growth in the business, but also for the dividends that they expect out of our company. We have a fairly conservative payout ratio right now, so we’re not where other people might have been, which is at the high end of that payout ratio. So, we’re comfortable with where we are today. Obviously, we’re not comfortable for our stock prices, but we show builders [ph] there’s a commitment to our dividend and that’s important to our investors. Michael Lapides – Goldman Sachs: Follow-up question, totally unrelated to financing, can you talk a little bit about the RFP for the 218-megawatt equivalent for renewable and the Southern Crossing Project? Should we view those as separate, distinct, rate-based growth opportunities or are they tied to each other, and if they are on similar timelines for approvals and reward, or if they are completely different?

They are not really connected at this point for different reasons. Let’s talk about the 218-average megawatts of RFP for renewables. The bids we got in were primarily wind and we’ve identified the shortlist. As I mentioned, we’re in negotiations. I will tell you the biggest challenge we’re having with these projects is transmission access. They’re located in areas that may not have or do not have transmission, or they are working on transmission. And so we really need to understand the transmission issues associated with those projects and whether the transmission will be built to facilitate the integration of those resources into our system. The Southern Crossing Project would not provide the transmission for those specific projects that we’re looking at, so that’s where we’re in negotiations right now. There’s still a blend of both purchases and ownership options there and we really can’t disclose the name of the bidders or the projects themselves because we don’t want to affect the negotiation process. We hope to have something to announce by the end of 2009. But frankly, the biggest issue is the transmission and getting that transmission built to our system or integrated into the overall grid, and that’s what they’re spending a lot of time on. I think the building of the resources or the construction of the wind assets is fairly straightforward. It’s the transmission that’s what we’re struggling with. So, that’s where we are. We hope to have something to announce later this year. As soon as we get to a final list, clearly, we’re going to announce that to the market, but we’re still in that gray area of negotiations. Michael Lapides – Goldman Sachs: Got it. Okay, thank you.

On the Southern Crossing Project, where we are on that, that project, as you know, would integrate our resources at Boardman, Coyote Springs in the same vicinity, and potentially, a new energy resource in that area. It also could potentially facilitate some additional wind development that could be integrated into that line, but that’s not, again, part of the RFP. We’re in discussions with potential co-owners of that project. It will be a 500 kV line, about 225 miles. Cost is somewhere between $0.5 billion and $1 billion. We’re going to use existing right-of-way, which is the real benefit of that project. We’re pretty excited about that project. We’re still running the numbers and the economics and we would hope to go to our Board later this year and get approval of that project, at which point, we would start full-scale development in terms of citing and licensing of that project. But clearly, there’s a need for more transmission, especially with the challenges of all the additional renewables in the region and we’re in conversations with some key co-owners who could really help us enable that project. Michael Lapides – Goldman Sachs: Got it. Okay. Thank you, guys. Much appreciated on the answers regarding the development project.

Thanks, Michael. Appreciate it.

Your next question comes from Steve Gambuzza with Longbow Capital. Your line is open. Steve Gambuzza – Longbow Capital: Good afternoon.

Hi, Steve. How are you doing? Steve Gambuzza – Longbow Capital: Good, thanks.

Good. Steve Gambuzza – Longbow Capital: What would you expect your FAS 87 pension expense to be in 2009?

Maria?

We’re looking at about $300,000 to $350,000. Steve Gambuzza – Longbow Capital: Okay.

We had a benefit most recently. Steve Gambuzza – Longbow Capital: Did you happen to change any of your actuarial assumptions this year?

At this point in time, we have a growth rate of 9%. We slightly adjusted our discount rate by about 40 basis points from 6.5% to 6.9%. Steve Gambuzza – Longbow Capital: Okay. In terms of cost initiatives, can you just give some sense as what you’d expect O&M expenses to be in ’09 versus ’08?

Well, I think you could go to the rate case and get a good sense of what our ongoing operating expenses would be based on the decisions they reached there. We don’t typically provide detailed estimates or comparisons, but I guess you could go look at the rate case and that’s what, obviously, we are trying to meet in terms of trying to get to a place we needed to be on our utility operating expense. Steve Gambuzza – Longbow Capital: You’d expect O&M to not be what you filed last year to be what was allowed – what was essentially authorized.

Yes. As I mentioned in my call, we took a very aggressive approach on O&M to get it in line with what the regulators felt was appropriate costs. Steve Gambuzza – Longbow Capital: Great. And on the RFP shortlist, are there some potential self-build options in that shortlist that you’re looking at?

Yes. There’s both self-build options and contracts and we’re evaluating both. Steve Gambuzza – Longbow Capital: What’s the earliest that do you think you did pursue self-build that would actually begin to be developed? Is that kind of post Biglow Canyon or some of these projects move forward in the 2010/2011 timeframe?

It’s going to depend on the contract and negotiation availability of turbines. There is a better availability for turbines right now. It’s somewhere in the 10 to 14 timeframe. Again, it’s going to be driven more around transmission than it is around the projects themselves and getting the transmission sited and licensed with those projects. And some of that may depend on whether Bonneville power moves forward with certain construction of lines from the timing of that. Transmission siting and licensing is by far the bigger challenge in these projects than the construction of the wind turbines. Steve Gambuzza – Longbow Capital: Given that fact, I was curious of your view on what the – all this money’s been thrown at Bonneville and WAPA from the Stimulus Bill, and I guess, some of us have been scratching our heads wondering where it’s going to go. Do you guys have any perspective on this?

Well, again, what they – you have to understand, Bonneville needs borrowing authority to finance their projects. Those projects ultimately have to be included in the prices they charge for transmission service, so they were granted $3.2 billion of additional borrowing authority. What they can do is use that money to finance certain improvements in their projects, but the costs of those projects are charged through to the customers, so it’s not like free money. It is a loan to Bonneville, which they may incorporate into projects, which then will be included in the rates they charge to their transmission customers. So, that’s how it’s going to play out. They have a number of projects and they have a number of constraints they’re working on. I don’t know the specific projects. Some are shelved [ph] already that they can move on. Others still take more work in terms of siting and licensing. But primarily, it's reduced constraints on the system to allow for the wind resources, renewable resources to the system, and then just to facilitate additional load growth. Steve Gambuzza – Longbow Capital: Okay. And then, on the Southern Crossing – I’m sorry, I missed your comments, if all went well, when could construction begin on that to the extent you move forward in the next (inaudible)?

Probably, the soonest would be 2013 and I think we’re kind of framing this into 2013 to 2015 timeframe. Steve Gambuzza – Longbow Capital: Okay.

A lot of it again will depend on siting and licensing of the project and how that goes and the timing of getting that work done. Steve Gambuzza – Longbow Capital: You mentioned when discussing the liquidity situation of the roughly $360 million you had post in deposits that half would reverse by the end of 2009, assuming no change in power crisis, is that correct?

Yes. Steve Gambuzza – Longbow Capital: Could you give us some sense as to what – if gas were to go down another dollar, how that would change?

Sure. It would – assuming that energy followed suit, it would be approximately another $30 million. I would note that we have about $25 million rolling off in March, and then about $60 million rolling off in Q2, so we’re still frontloaded to near-term roll-offs here. Steve Gambuzza – Longbow Capital: Okay. So, those – the $25 million and the $60 million come back regardless of – you’ll get that money back. The postings may change between now and then based on the prices, but you’re going to get that money back at the end of Q1, at the end of Q2 regardless.

Exactly. Steve Gambuzza – Longbow Capital: And so, when you say another – if prices fell another dollar –

You would just get that much more back. Steve Gambuzza – Longbow Capital: If prices fell, you’d post –

We’d post more, but then that much more would roll off when it does roll off. Steve Gambuzza – Longbow Capital: But, you’d still get the $85 million back by the first half of the year, but you have to post an additional $30 million in the back-half of the year, essentially.

Yes. I was answering your question as if the dollar was in effect today. Steve Gambuzza – Longbow Capital: Okay. All right, thank you very much.

Thanks, Steve. Take care.

Your next question comes from Gary Lenhoff with Ironworks Capital. Your line is open. Gary Lenhoff – Ironworks Capital: Thank you. You’ve answered my questions.

Thanks, Gary.

Your next question comes from Eric McCarthy [ph] with Presidios [ph]. Your line is open. Eric McCarthy – Presidios: Good afternoon, guys.

Hi, Eric. How are you doing? Eric McCarthy – Presidios: Good, how are you?

We’re good. Eric McCarthy – Presidios: The equity offering, I assume that’s in the guidance in the diluted share count. Can you tell us what at least the range of stock prices you have estimated in that guidance for the dilution?

No. Eric McCarthy – Presidios: Okay.

I just thought that I gave you a sense of when we issue it, then you can back into when the timing is, and so that’s something we can’t provide. I appreciate the question but it’s something we can’t provide. Eric McCarthy – Presidios: Right. Of course, of course. And the PCB’s, when those reset, what are your options? Is there a minimum or maximum rate that those could reset to or do you have the option to refund this in full?

Maria will talk about that.

We have a $142 in May and we have the option of either replacing those with other pollution control bonds or with first mortgage bonds. At this point in time, it probably would be first mortgage bonds.

Yes, it’s interesting right now the pricing on first mortgage bond is cheaper than pricing on pollution control bonds, so it seems like we’ll take the lowest cost option so we’ll continue to evaluate that over time. Eric McCarthy – Presidios: Okay, so the market is open to those first mortgage bonds and you will be able to replace the PCB?

Yes.

We don’t have any concern there. We just did a $130 million which closed in January.

And then, $142 million of pollution control bonds are already backed by first mortgage bonds, so it’s not like we have to issue additional first mortgage bonds that would hit our capacity. It’s already included in the reduction. Eric McCarthy – Presidios: Okay. All right, that’s about it. Thanks guys.

Thank you

Your next question comes from Paul Patterson with Glenrock Associates. Your line is open. Paul Patterson – Glenrock Associates: Good afternoon, guys.

Hi Paul, how are you doing? Paul Patterson – Glenrock Associates: All right. The hydro condition question and I apologize for being a little slow on it, I got a little distracted, if the hydro conditions don’t improve, what’s the expected impact?

Well, we haven’t made a forecast of what the impact would be. If you think about it, the numbers we mentioned is about 580 average megawatts is our current expected hydro generation and average hydro conditions. And the one we’ve talked about historically is you can have one or two standard deviations. Two standard deviations is kind of the worst we’ve seen on record which is about a 20% reduction in average amount of hydro. So, so you can decide based on the numbers we’ve got how much deviation you think might be there based on the current forecast, multiply that percentage times the 580 average megawatts times a current market price. So that’s kind of the way you have to get your arms around the number. And right now, as I mentioned, we’re about 86% normal on the mid-Columbia and 84% below normal, or 84% abnormal on the Clackamas and about 89% abnormal on the Deschutes. One thing I would mention on this call, just to be aware of, those numbers represent expected precipitation and a snow pack which ultimately translates into run off. When you look at the Columbia River run off, it doesn’t necessary always translate into generation because of the large reservoirs up above Grand Coulee that can either increase flows or decrease flows above or below normal precipitation. So it’s not as simple as just taking a percentage that side and assuming that’s what's going to happen with generation. But that’s the general premise, so is that helpful? Paul Patterson – Glenrock Associates: Okay. Yes. The second question is, do you guys have a shelf [ph] already out there for the equity issuance?

Go ahead, Maria.

Yes, we do. Paul Patterson – Glenrock Associates: You do? Okay. Thanks a lot.

Thank you.

Your next question comes from James Bellessa with D.A. Davidson and Company. Your line is open. James Bellessa – D.A. Davidson & Co. : On the decoupling mechanism, how do the powers that looks to be who are judging whether or not you’re achieving your goals on that mechanism decipher between a family who's bought a brand new appliance that is highly energy efficient and a family who is having tough times and maybe one of the household people are unemployed or something like that, and they’re cutting back. How do you decipher, is that energy efficiency or conservation versus just the economic issues?

You can’t with the mechanism as it's designed, but I think both are good results because customers are using less of the product which is reducing the environmental footprint. And I think where the commission is, is whether it's conservation or energy efficiency, it’s the right thing and utility should not have a disincentive from encouraging either conservation or energy efficiency, and whether – because consumers do it on a behavioral basis or implement technology. Again, I think their views are utilities ought to be trying to advise their customers to use our product as wisely and efficiently as we can, and it targets sort out or tease out [ph] the effects of conservation or energy efficiency. But at the end result, both are good for our customers. It reduces our environmental footprint and encourages people to use our product as efficiently and effectively as we can. And obviously then we don’t have the disincentive from encouraging that behavior. James Bellesa – D.A. Davidson & Co.: The timing of the decoupling mechanism, is it really a Godsend in the fact that we’re in a tough recessionary period?

I think the commission didn’t look at it that way. This is something, as you know, they implemented it for Northwest Natural. It’s been something – it’s been moving across the country. In fact, in the stimulus bill, I believe they were – they tied some of the granting to in fact the utilities implement decoupling. So I think you have to take a longer perspective on this and timing is never right for any of these things, and I think the commission just felt this was the right thing to do from a public policy perspective. And with the rate case pending and the fact that we do need to encourage more energy efficiency and reduce the carbon footprint, it was the right decision to do. And because of the economic times, it is what that is and that can change within a year and we can be some place else. So that’s our view on that one. James Bellesa – D.A. Davidson & Co.: Thank you.

Thanks Jim.

(Operator instructions) Your next question comes from Maurice May with Power Insights. Your line is open. Maurice May – Power Insights: Yes. Just a follow up on the Southern Crossing transmission line, and maybe this is a dumb question, but who would regulate it, Oregon or FERC?

Good question, Maurice. It’s always a question that sometimes is a little bit confusing. The way that line would likely be treated similar to our other transmission lines, which is we do set up a FERC rate for use of our transmission line like the intertie, because third parties who want to use the intertie, pay the FERC approved rate. But what we do in Oregon, because most of the transmission, if not all the transmission we use is used to integrate our generation to our load, essentially gets re-regulated by the Oregon PUC. So it’s included in our rate-based asset, and then any nominal revenues we receive from any third party sales of our transmission act as a credit against our revenue requirement. Maurice May – Power Insights: And the ROE would be set by the Oregon Commission?

That’s correct. We really don’t have what you would call a true wholesale transmission business. We do provide services. But most of our transmission is used to integrate our generation to our retail load. Maurice May – Power Insights: Okay.

If that changes over time, we will reevaluate that. But at this point, that is the way it’s treated in Oregon. Maurice May – Power Insights: Okay. And BPA would not be a candidate to construct this. I always thought that BPA run most of the transmission in the Pacific Northwest.

That’s a combination of BPA and Pacific Corp. We have a large transmission line related to coal strip that integrates the coal strip facilities. We have piece of the intertie, and then we have a lot of transmission that rings our system. In terms of major transmission systems in the West, it’s Pacific Corp and Bonneville are the two dominant providers. But in this case, this makes a lot of sense for us to build because it integrates our resources to our load and gives us somewhat control of the cost structure around that asset. Maurice May – Power Insights: Okay, great. Thank you very much, Jim.

Thanks Maurice. Have a good day. Maurice May – Power Insights: You too.

Okay. I think that concludes our questions. We appreciate your interest in Portland General Electric and invite you to join us in a few months when we report on first quarter 2009 results. If you have any additional questions, please contact Bill Valach, who will be available after this call. Thanks again and have a great day.

This concludes your conference call for today. You may now disconnect.