Portland General Electric Co (POR) 2008 Q4 法說會逐字稿

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

Thanks, Abigail and good afternoon, everyone. I'm Bill Valach, Director of Investor Relations at Portland General Electric, and we're pleased that you're able to participate with us today. Before we begin our discussion this afternoon, I'd like to make our customary statements regarding Portland General Electric's written and oral disclosures and commentary.

There will be statements in this call that are not based on historical 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, the 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 www.portlandgeneral.com. The Company undertakes no obligations 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 a 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 diluted share for the fourth quarter ending December 31, 2007. Earnings for the year ended 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 and Maria then will discuss in more detail our year end and fourth quarter results. Then we will open the call up for questions. It's my pleasure to turn 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 has 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 in today's call, we'll address those issues and others. 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 our liquidity and strategy for raising capital.

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 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 the fair market value of nonqualified benefit plan assets, and finally, the resulting impact of Senate Bill 408.

The key factor driving earnings $0.01below guidance was the decline in the fair market value of nonqualified plan assets. During the fourth quarter, these assets declined by $8.3 million for an approximate EPS impact of $0.08. Maria will go into more detail on 2008 results later on the call.

Now I'll move on to 2009 guidance. Today, PGE is reaffirming full year 2009 earnings guidance of $1.80 to $1.90 per diluted share. Key assumptions for 2009 guidance are normal hydro and plant operations, and our latest load forecast which reflects no weather adjusted load growth over 2008.

We have reduced our previously forecasted operating expenses to ensure that we're running our business in a cost effective manner and have taken the necessary actions to manage our costs to align them with the OPUC's decision in our last general rate case, and to respond to the impact of the economic downturn on our customers. We were pleased that the OPUC authorized a new decoupling mechanism for a two-year period as part of our general rate case decision. PGE's long-term annual earnings growth expectations beginning in 2009, continues to be 6% to 8% which is supported by our ongoing opportunities to invest in generation, transmission and distribution assets.

Now I'll provide an update on Oregon's economy and specifically our operating area. We saw a slowdown in the state's economy through 2008, led by a decline in the housing market. Oregon's unemployment rate rose to an average 6.3% for 2008, compared to the national average unemployment rate of 5.8%.

However, we continue to see customer growth. We served approximately 810,000 customers at year end, an increase of approximately 1% from the close of 2007. We saw an increase in total retail energy deliveries of approximately 1.9% from 2007. As a result of the recession and an increase in the unemployment rate, we currently project weather adjusted energy deliveries for 2009 to be comparable to 2008.

We know that the state and federal stimulus packages will impact Oregon's economy, so we're examining the various grant and federal matching fund programs in the legislation to identify potential opportunities that make sense for PGE, our customers and our shareholders. These opportunities include tax and appropriations benefits related to renewable energy and other items, including the extension of the renewable energy production tax credits through 2012, the option to elect investment tax credits or ITC in lieu of the production tax credits for wind farms placed in service through 2012, the option to take an energy grant in lieu of either PGC or IGC for qualifying facilities placed in service by 2012 as long as the construction on the facilities commenced in 2010, funding grants for important infrastructure projects such as smart grid and charging stations for electric plug-in vehicles and funding grants for demand response and carbon sequestration demonstration projects.

While we've felt the challenge of this economy, certainly all areas of our business are performing -- currently all areas of our business with performing exceptionally well and we continue to focus on our strategic investments. Along with the PGE officer team, I've been involved in setting the strategic direction of the Company for several years. We've recently updated PGE's strategic direction to reinforce our commitment to our core business as a vertically integrated utility.

Let me describe the key three areas of our strategy moving forward. First and foremost, operational excellence; cost effectively running our operations and continuously improving our business practices which will deliver value to our shareholders and customers. Second, corporate responsibility; actively working at the federal, state, regional and local level to analyze and advocate for public policy that benefits our customers, the Company and our shareholders. This includes our participation in economic development and making strategic investments in the Oregon community. Finally, the third area, business growth; executing on opportunities to grow the business through investments that benefit and provide value for both our shareholders and customers. These are the key strategic areas that we are focusing on and continuously measuring our performance. And I will report out each quarter to you on what we've accomplished and what lies ahead.

In the area of operational excellence, we have been very focused on meeting our customers' needs. I'm very proud to report to you that J.D. Powers and Associates just announced that we are number one in the western region in overall business customer satisfaction and number one in the nation in power quality and reliability. This is a real honor for my coworkers and it recognizes their ongoing commitment to delivering excellent customer service and system reliability every day.

I'm also proud of the outstanding performance by PGE employees during the December 2008 storm. Our service area was hit with a series of storms that brought freezing rain and the heaviest snowfall that Oregon has seen in other 40 years. Over the ten-day event, we handled more than 400,000 customer outages. Thanks to the hard work of my coworkers and our well-maintained system, power was restored effectively. It was a costly storm, but net of our transmission and distribution line insurance, the after tax cost in 2008 was approximately $1.4 million.

Throughout 2008, we had excellent generation plant availability with thermals at 89%, wind at 92% and PGE owned hydro at 99%. Current forecasts indicate lower than normal hydro conditions for 2009. We continue to investment in infrastructure, making sure our system is safe and reliable. In 2008, we invested over $210 million in system upgrades on transmission, distribution and existing generation. Results for power quality and reliability, including customer outages, outage duration and momentary interruptions exceeded our 2008 goals.

Now let me give you an update on the public policy front. Recognizing that the legislative decisions made in 2009 will directly impact our state's economy and business, we're taking an active roll in both the state and federal level. At the state level, we're working with regulators and legislators to develop responsible energy and environmental policies, just as we did in 2007 when we collaborated with the Governor and the legislature to adopt a renewable energy standard. That standard requires that 25% of Oregon's electricity comes from renewable sources by 2025.

On the national front, we're committed to working on policies that responsibly reduce carbon. We continue to believe a federal policy is the right direction to take. We're participating with others in our industry, including EEI, to help Congress and federal policy makers understand the importance of this issue, and implications to our industry and our customers.

Looking ahead, we see ongoing growth opportunities for investment in rate based assets. Our Port Westward plant and phase I of the Biglow Canyon Wind Farm are great examples of this. Both projects came in on budget and the costs were fully included in customer prices.

Moving forward, we're investing in new generation plants and systems. Biglow Canyon Wind Farm phases II and III, and our smart meter projects are examples of this. And we're pursuing strategic opportunities tied to our core business, such as additional energy and capacity resources including renewable resources and a potential transmission project.

Let me give you an update on some of our major capital projects. First our smart meters project. Approximately 16,000 new meters are being installed as part of the project system acceptance testing phase. We begin -- we plan to begin full deployment in late spring. We expect the project -- a total of 850,000 meters will be completed by the end of 2010. PGE estimates the capital cost of the smart meters project to range from $130 million to $135 million including AFDC.

Now an update on our Biglow Canyon Wind Farm. Phases II and III are currently under construction with completion expected by the end of 2009 and 2010 respectively. The two phases will have a combined installed capacity of approximately 325 megawatts.

The total cost of the two phases is expected to be $759 million including AFDC. Our investment in Bigelow Canyon will be fully included in prices through the renewable adjustment clause mechanism. Our first filing under this mechanism is planned for April of this year.

Last spring, we issued a request for a proposal seeking up to an additional 218 average megawatts of renewable resources. After receiving 38 responses to the RFP, we have identified a short list of bidders and we expect negotiations to be completed in 2009. Those additional renewable resources become available between 2009 and 2014, and will help fulfill our commitment to meet the 2015 requirements of the renewable energy standard.

We are currently preparing our 2009 integrated resource plan. The key areas we're addressing in the IRP are climate change policy, how policy will affect future choices for incremental supply as well as how policy effects our existing portfolio, the economics of the mission controls on the Boardman plant, how we plan to meet Oregon's renewable energy standard including integration of an increasing amount of wind power, and finally, the need for additional energy and capacity resources. We plan to submit our draft plan to the OPUC in late 2009.

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

We've submitted comments on the DEQ proposal, requesting the 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 $635 million. This is 100% of the total cost, excluding AFDC.

The Oregon Environmental Quality Commission is expected to adopt a rule in April of 2009 after the public process has been completed. The rule is then submitted to the Environmental Protection Agency for approval. We expect the EPA to issue a decision in early 2010. With that, I'll turn the call over to Maria Pope, our Chief Financial Officer, to discuss our financial results in more detail.

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 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 nonqualified 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 replacement power costs. 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 nonqualified 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 share for the fourth quarter 2007. Fourth quarter 2008 results were positively impacted by the exceptional thermal plant operation and lower gas prices. These positive factors, partially offset by a decline in hydro conditions and a 1.7% quarter over quarter decrease in retail energy loads.

Fourth quarter 2008 results, relative to the fourth quarter 2007, were also impacted by the following. A $5 million after tax loss or $0.08 per diluted share from the decline in the fair market value of the nonqualified plan assets. A $2 million after tax loss or $0.03 per diluted share from customer refunds under SB 408. And a $1 million after tax loss or $0.02 per diluted share from the storm restoration costs, net of transmission and distribution insurance.

Fourth quarter 2007 results were impacted by the following. A $4 million after tax gain or $0.06 per diluted share from customer collections under SB 408. And a $1 million after tax loss or $0.02 per diluted share from the decline in the fair market value of the nonqualified plan assets.

Now, a brief update on the power cost adjustment mechanism or PCAM. In 2008, our overall power operations performed well, resulting in net variable power costs for the year that were approximately $31 million below the base line under the PCAM. This would typically result in a refund to customers of approximately $15 million.

However, the PCAM has an earnings test whereby if PGE's regulated ROE is below 11.1%, no refund is given. For 2008, PGE's ROE was below the 11.1% threshold. Therefore, no PCAM refund is required.

I'd now like to talk about our general rate case. In January, the Oregon Public Utilities Commission issued its final order which included the following, $121 million increase in revenue, existing of $95 million for net variable and $26 million for other costs, the continuation of both power cost mechanisms, the annual update tariff and the PCAM, a capital structure of 50% debt and 50% equity. We were pleased that the OPUC authorized a new decoupling mechanism.

As a result of the associated reduction in risk to PGE, the commission required a 10 basis point reduction in ROE to 10% from the original 10.1%. Our filing to implement decoupling was effective February 1st, 2009. Effective January 1st, the average price increase to customers was approximately 7.3%. Net of the 2007 PCAM results, the impact on customers was 5.6% increase.

Other regulatory items worth mentioning include the recovery of our investment in the selective water withdrawal system at the Pelton Round Butte generating facility which was removed from the rate request and is under a separate proceeding at the OPUC. We continue to anticipate that the project will go into customer prices upon completion in the second quarter of 2009. PGE's share of the capital costs including AFEC is approximately $80 million, and our initial filing indicated that an annual revenue increase of $12.9 million.

In April, we will be filing our initial 2010 forecast with updated power costs under the annual update tariff. Throughout the year, we will make several update filings. Power costs will be put into customer prices effective January 1, 2010. We are pleased with Oregon's regulatory support of new renewable resources through the renewable adjustment clause mechanism. As part of Oregon's renewable energy standards, PGE recovers the cost of renewable resources without filing a general rate case. We will submit our first filing in April with prices to become effective January 2010.

Finally, an update on the Trojan refund order. On September 30, the OPUC ordered PGE to refund $33.1 million to customers. The refund related to amounts PGE collected under the POPC approved prices on the unrecovered balance of our investment in the Trojan plant. In September 2008, we accrued the refund as a regulatory liability which was reflected as a reduction in our third quarter revenues.

Currently, certain parties have filed a petition for review and a motion for stay of the refund with the Oregon Court of Appeals. The stay was denied this week. We will now request that the OPUC move forward with the refund process. Separately, the class action lawsuit continues to be in abatement. Also this week, the circuit court judge found that the abatement was necessary and appropriate, and that the matter should remain with the OPUC and the Court of Appeals.

And now I'd like to provide you an update on our financial position and liquidity. In late 2008, PGE put in place an unsecured $125 million 360 four-day revolving credit facility. This facility is in addition to the $370 million revolver already in place, giving PGE $495 million in borrowing capacity under the two facilities. As part of PGE's power supply operations and price risk management, we have entered into forward contracts for power and natural gas.

As a result of the following power and gas power prices, we have posted collateral to meet margin requirements under these contracts. As of February 20th, we have posted $363 million in collateral with wholesale counter parties.. It is important to note that the cost associated with the gas and power contracts are either currently in or are expected to be in customer pricing. The posting of collateral for margin requirements creating a cash flow timing difference, but has minimal impact on earnings.

As of February 20th, we had $53 million back stocked for commercial paper issuances, $61 million direct draws under our credit facility and $153 million in letters of credit, resulting in total availability under our revolving lines of credit on February 20 of $228 million which compares to $166 million at year end. The Company's debt to capital ratio was 52.7% on December 31st. In January, we closed on $130 million issuance of first mortgage bonds at 6.5% to 6.8% interest. We continue to maintain investment grade bond ratings. Our senior unsecured ratings are B AA 2 at Moody's and BBB plus at Standard and Poors.

Given the turbulence in the financial markets over the last year, I would like to provide an update on pension funding status. At year end 2007, our pension was overfunded 109% assets projected benefit obligations. Given the market activity in 2008, our pension lost $145 million. At year end, our funded status was 74% assets to projected benefit obligations. Based on 2009 funding requirements under the Pension Protection Act, we do not anticipate having required contributions in 2009, but estimate contributions of $23 million in 2010.

PGE continues to investment in our infrastructure, and in the [absence] it provides benefits to customers and shareholders, such as wind generation and smart metering. In 2008, we invested $372 million in capital projects. For 2009, capital expenditures are expected to be approximately $722 million. The bulk of the increased expenditures will be for Bigelow Canyon, phases II and III, and our smart meters project. Our base capital expenditures remains just above last year at approximately $224 million.

In response to the economic climate, we have reduced capital spending from prior expectations by approximately $38 million in production, transmission, and distribution areas. To finance these programs and maintain our target 50/50 capital structure, we are planning to issue approximately $170 million in additional long term debt, remarket $142 million in pollution control bonds, and issue between $175 million and $200 million in equity in 2009. The timing of the debt and equity issuances is subject to market conditions.

In closing, the focus of our financial objectives continues to support our core utility business; namely, a solid balance sheet, adequate liquidity to maintain our investment grade ratings, efficient asset to capital to support investment in new and existing generating assets and our transmission and distribution system, fair and reasonable regulatory outcomes, while earning a competitive rate of return on our vested capital. I would now like to turn it back to Jim. Thank you.

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. Powers and Associates. And we continue to focus on our business strategies 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 would now like to open up the call for questions.

(Operator Instructions). Your first question comes from Rick Shelby with GLG Partners. Your line is open.

Good afternoon.

Hi, Rick.

I was just curious as to -- I know you guys are trying to do your best, as we all are, with regard to managing the pension and trying to make sure there isn't a shortfall. With regard to funding the pension, wherever you make funding or deposit money into it, does that recover through rates? Does it go through rate based? How does it function?

This is Jim. Thanks for the question. The way we recover our pension expenses we include in our generate rate case our estimated -- what's called a FAS 87 expense. That's the smoothing number that's been calculated under the accounting standards. That's the number we include in general rate cases. Over time, we will have the opportunity to recover the cost of our pension. It doesn't quite necessarily match the cash flows, but over time it does catch up to it.

The actual cash infusion into the pension gets amortized over the course of however long the life of the pension is?

That's correct.

They wind up getting made up through -- via the rates.

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. That can change based on the actual earnings of the assets.

Okay. Thank you as much.

Your next question comes from James Bellessa with D.A. Davidson and Company. Your line is open.

Jim, I think I heard you say that your assumptions ant your guidance 2009 EPS guidance. One of the assumptions was flat. One other adjusted in 2009 versus 2008. Was that correctly heard?

That is correct, Jim.

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 forth the sensitivity of declines in your load versus the declines -- increases in the unemployment rate. 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 that we use to do our load forecasting. Essentially, we're predicting 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 a simple answer to the question. 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.

On the renewable adjustment clause mechanism, you're going to be filing here in I think I heard April for rates that would be recoverable starting in January 1st of 2010. Is that correct?

That is correct. Although we do -- we are allowed into the renewable adjustment costs and we'll do this is to defer the net cost of the renewable assets during the year that they come into service. We will track both the cost and the benefits of Bigelow Canyon phase II during 2009. We'll defer that amount during the year. We'll amortize that over a period of time, depending on the size of that net revenue requirement.

On Bigelow Canyon phase II, you don't start collecting on January 1st, 2010 for it?

We start collecting the costs from customers starting January 1, but from an accounting perspective, we will accrue for the revenues that we would have collected had the plant gone into service when it does. We get to defer the net cost of the project during 2009 with the rates to customers becoming effective on January 1, 2010.

Okay. I'm surprised to see negative working capital. And then I read the explanation of why you had it. How long does it take to reverse that to rid yourself of a negative working capital position?

This is relating to our collateral deposits?

Yes.

We have collateral deposits of about $360 million. About half of that reverses by the end of this year, assuming no change in prices from February 20th.

Is there something in the future you can avoid having negative working capital by striking your contracts differently?

It all depends on what the prices we pay for the energy is. We've had times where we've had significant deposits with the Company when prices have 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. You're never going to get it perfect in terms of -- the purchase is relative to the market price. You may have times where you have to post collateral. There may be other times where you receive collateral.

I see you have union negotiations going on. What's the status that you can tell us about that?

We're in cooperative discussions with the union. We had some fairly healthy discussions on the major issues. We hope to have something to disclose in the next couple weeks or so, but that's all I'd like to tell you about it now. The conversation is going well.

The contract effectively ends on February 28th. But there's been no requests for a termination of the contract. The contract will continue in force. And negotiations have been constructive and I think will produce a reasonable result for the Company.

In the most recent quarter, you had DD&A of $54 million. The annual run rate is $220 million. But you're calling for -- in your 10-K form, $209 million DD& A in year 2009. Why does it go down? the run rate.

Maria, you want to answer that.

Our amortization is fluctuating as assets come off. In addition, we have several assets that will be coming on.

Thank you very much.

Thanks, Jim.

Your next question comes from Maurice May with Power Insights. Your line is open.

Good afternoon, folks.

Hi, how you doing?

Okay. And congratulations, Jim. On the timing of the equity offering, can you help us out a little bit here -- more than just depending on market conditions which I assume you don't want to sell it tomorrow at $16.38. Can you give us any timing throughout the year when you need the equity?

We're pretty broad in this question. I know people would like specific guidance, but we've said between now and the end of 2009 as we evaluate market conditions. That's about as far as we can go on that, Maury, until we make some final decisions. We continue to evaluate the markets, looking at our own cash flow needs. We're just comfortable at this point, saying between now and the end of 2009.

And our book value I estimated at 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 earnings on?

No. It's all in the regulated core business.

Okay, 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 the below normal current conditions to the end of the snow pack season. What might that be on guidance?

This is still early in the hydro season. We've seen in the 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 snowfalls coming. It's hard for us to estimate what's going to happen with the snow pack at this point. When we develop the guidance, we just assume normal hydro.

You've seen the numbers on the website in terms of what the current forecast is. On the Columbia at [Grand Cooley], it's about 86%. On the [Clockmas River], it's about 84%. On the [Des Chutes] Rivers, it's about 89%. A little bit more than -- around 10% to 15% below normal.

It's still fairly early in the season. That's based on the February 20th forecast. It's too hard to predict where it's going to come out at the end of the day. That's where we're at. In terms of the impact on our system, we're roughly 550 --

580.

580 average megawatts of hydro between our mid-Colombia contracts and our existing resources. 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 the impacts could be. It's too early in the hydro season to forecast what it's going to be. We were comfortable just continuing to estimate it, based on normal hydro.

The forecasted prices this year are down so that the cost of replacement power costs would not be as detrimental to the PCAM as earlier years. Is that correct?

That is correct because gas prices are down which is reducing the market price of energy in the overall market.

What is -- assume us these days?

Do you have that, Maria? It's in the $4 range.

About $4.50.

Okay, okay. Good. And then you referred to aligning operating costs with the recent rate case order. Can you give us some color on that? Were you disallowed some costs you decided not to spend?

Part of the order, as we mentioned, we requested about $56 million. The commission came in about $26 million. We looked at those various areas and we've taken the -- what we feel is necessary action to get our own in aligned with the improved costs O&M costs in the rate case.

We think we have a plan in place to do that. And we have reduced some 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. We're trying to deploy our crews to capital projects to keep them employed, to keep them busy. But to reduce our outside contractor costs as a way to absorb some of those cost differences.

Okay, okay. I'm sorry. Then one final quick question on the decoupling. That covers both weather and conservation. Does it not?

No. It does not cover weather. It only covers the affects on energy efficiency and conservation. It is primarily focused on 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. The decoupling there -- 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.

Okay, good. Thank you very much, folks.

Your next question comes from [Chris Elinghouse with Shield and Company]. Your line is open.

Hi everybody. 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 your forward look. Can you comment about that?

What do you mean by regulating asset?

I was under the impression that at some point you were expecting to need some gas asset for regulating and balancing of new --

You're talking about additional capacity. We call them capacity resources -- something to balance the load with our additional wind resources. We definitely see a need to add capacity resources to help maintain the stability and reliability of our system. As part of the integrated resource plan, we'll file some self-billed options for energy and capacity. And then we would include those self-billed options in an RFP that would likely be conducted in late 2010 or 2011 with construction probably in late '11 or 2012.

Those dates will move around as we go through the integrated resource plan. 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. That's the way we're going to address it. We'll file that integrated resource plan in third quarter of 2009 and work through is various details with the regulatory and our intermediate groups.

You expect that to be a self-build plan as posed to a general RFP?

What we would do -- this is exactly what we did with Port Westward. We would include a self-build option -- a sealed bid. We'll go to the market and ask for a request for proposals for those same type 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 move forward with those projects. If there's a better option in the marketplace, then we go forward with those options. We have an obligation to deliver the lowest cost, best value for customers.

And some time this year, you're supposed to have a significant Boardman outage? Did you get approval through the rate case deferral of those costs?

We estimated about a 60 day maintenance outage for Boardman to address putting in a new [statter and excider] at the plant as well as a new generator rotor in We believe we have adequate time in our cost forecast to allow for that work to be done. That was included in our annual update tariff filing as a 61-day maintenance outage.

Can you remind us when you expect that outage to begin?

We don't typically disclose on those outages. They are typically in the spring months. We don't like to get specific dates out there. We have to replace that energy in the marketplace, and don't like to let people now exactly when things will go off and on.

Can you give us any update on your dividend payout expectations and any general thoughts?

As we talked about on the call here, over the long term, we'd like to get to 60% payout ratio. That's consistent with our industry peers and where the market is. We do have good investment opportunities. We're going to move very cautiously up that curve. If you look on a normalized basis, we're around the 54% level.

We'd like to move that up over time, but as long as we have good investment opportunities, we'd like to redeploy 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. That's our plan right now. Over the long term, we'd like too get to 60%. How we specifically get there, will depend on our earnings pattern and our investment opportunities.

Thanks, Jim. Welcome aboard, Maria.

Your next question comes from Michael Lapides with Goldman Sachs. Your line is open.

Congrats on a really good quarter and welcome, Maria. Question for you. I want to make sure -- reaffirm the dividend this week. We've seen some other companies that have traded below book value, reassess how did 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 roughly $4, $4.50 below book value.

Good question, Mike. We believe that our investors expect a dividend from our company. It's appropriate to reward them for not only the growth in the business, but also for the dividends 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.

We're comfortable with where we are today. We're not comfortable with where our stock price is. We still feel there's a commitment to our dividend and that's important to our investors.

Follow-up question, totally unrelated to financing. Can you talk a little bit about the RFP for the 218 megawatt equivalent for renewables and the Southern Crossing project? Should we view those as separate distinct rate based growth opportunities? Or are they tied to each other? If they are on similar timelines for approval than -- or if they are completely different?

They're not really connected at this point. They are for different reasons. Let's talk about the 218 average megawatts RFP for renewables. The bids we got in were primarily wind and we've identified the short list as I mentioned. We're in negotiations.

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. We need to understand the transmission issues associated with those projects and whether the transportation 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. That's where we're in negotiations right now.

There's still a blend of both purchases and ownership options there and we can't disclose the names 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. Frankly, the biggest issue is the transmission and getting that transmission built to our system or integrated into the overall grid. And that's where they're spending a lot of time on.

The building of the resources or the construction of the wind assets is fairly straight forward. It's the transmission that we're struggling with. 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 are going to announce that to the market. We're still in that gray area of negotiations.

Got it. Okay. Thank you.

On the southern crossing project, where we are on that. That project will integrate our resources at Boardman, Coyote Springs in the same vicinity and potentially, a new energy resource in that area. It could potentially facilitate some additional wind development that could be integrated into that line

That's not part of the RFP. We're in discussion with potential co-owners of that project. It will be a 500 KV line, about 225 miles. A cost is somewhere between $0.5 billion dollars and $1billion. We're going to use existing right-of-way which is a real benefit of that project. We're excited about that project. We're still running the numbers and the economics.

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 signing and licensing of that project. Clearly there's a need for more transmission, especially with the challenges of all the additional renewables in the region. We're in conversations with some key co-owners who could really help us enable this project.

Thank you, guys -- much appreciated on the answers regarding the development.

Your next question comes from [Steve Gambuzza] with Longbow Capital. Your line is open.

Good afternoon.

Hi, Steve.

What would you expect your FAS 87 pension expense to be in 2009?

Maria.

We're looking at about $300,000, $350,000. We had a benefit most recently.

Did you change your actuarial assumptions?

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%.

In terms of cost initiatives, can your just give some sense as to what you'd expect O&M expenses to be in '09 versus '08?

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 decision they reached there. We don't typically provide detailed estimates or comparisons, but you could look at the rate case and that's obviously what we're trying to meet in terms of trying to get to the place we needed to be on our utility operating expense.

You expect O&M to not be what you filed in the past year -- what was allowed -- what was essentially authorized.

As I mentioned, we took a very aggressive approach to our own data to get it in line with what the regulators felt was appropriate costs.

On the RFP short list, are there some potential sub build options in that short list?

There's self-build options and contracts, and we're evaluating both.

What's the earliest that you'd pursue self-build? That that would begin to be developed -- ?

It's going to depend on the contract and negotiation availability of turbines. There's a better variability for turbines right now. It's somewhere in the ten to 14 timeframe. It's going to be driven more around transmission than it is around the projects themselves, and getting the transmissions cited and licensed with those projects. And some of that may depend on what [Barnaville] Power moves for with certain construction of lines and the timing of that. The transmission citing and licensing is by far the bigger challenge in these projects than the construction of the wind turbines.

Given that fact, I was curious to get your view on all this money has been thrown at Barnaville and [Waffa] from the stimulus bill. Some of us scratching our heads wondering where it is going to go. Do you have any perspective?

You have to understand, Barnaville need borrowing authority to finance their projects. Those projects ultimately have to be included in the prices they charge for transmission services. They were granted $3.2 billion of additional borrowing authority.

They can use that to finance certain improvements to their projects, but the costs of those projects are charged through to the customer. It's not like free money. It's a loan to Barnaville which they incorporate into projects which will be included in the rates they charge to transmission customers. 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 shovel ready that they can move on. Others still take more work in terms of citing and licensing. Primarily it's to reduce constraints on the system to allow for the wind resources -- renewable resources to the system and then to facilitate additional load growth.

Okay. And then on the Southern Crossing, I missed your comments. If all went well, when could construction begin on that --

Probably the soonest would be 2013. I think we're framing this in 2013 to 2015 timeframe. A lot will depend on citing and licensing of the project and how that goes, and the timing of getting that work done.

You mentioned when discussing the liquidity situation of the roughly $360 million you had posted about half would reverse by the end of 2009, assuming no change in power prices. Is that correct?

Yes.

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 2002. We're front loaded to near term roll offs here.

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 or Q2 regardless. If prices fell another dollar --

You will get that much more back.

If prices fell, you'd post --

We'd post more, but then that much more would roll off when it does roll off.

You'd still get the $85 back by the first half of the year if you didn't 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.

Okay. All right. Thank you very much.

Thanks, Steve. Take care.

Your next question comes from Gary [Little] with Ironworks Capital. Your line is open.

Thank you. You've answered my question.

Thanks, Gary.

Your next question comes from Eric McCarthy with [Preceded]. Your line is open.

Good afternoon, guys.

Hi, Eric. How are you doing?

Good. The equity offering -- I'd assume that's in the guidance in the diluted share count. Can you tell us what the range of stock prices you have estimated in that guidance for the dilution?

No.

Okay.

That gives you a sense of when we issue it and then you can back into when the timing is and that's something we can't provide. Appreciate the question, but it's something we can't provide.

Of course, of course. And the PCBs, when those reset, what are your options? Is there a minimum or maximum rate those could reset to or do you have the option to refund those in full?

Maria will talk about that.

We have $142 million in May. And we have the option of either replacing those with other [cruise control] bonds or with first mortgage bonds. At this point in time, it probably would be first mortgage bonds.

It's interesting right now, the pricing on first mortgage bonds is cheaper than the pricing on our pollution control bonds. We'll take the lowest cost option so we'll continue to evaluate that over time.

The market is open to those first mortgage bonds and you will be able to replace the PCB?

We don't have any concern there. We just did $130 million in January.

The $142 million of pollution control bonds are already backed by first mortgage bonds. It's not like we have to issue additional first mortgage bonds. It's in our capacity. It's already included in the reduction.

All right. That's about it. Thank you, guys.

Thank you.

Your next question comes from Paul Patterson with Glenrock Associates. Your line is open.

Good afternoon, guys.

Hi, Paul. How you doing?

All right. The hydro condition question, 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?

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. Historically, you can have one or two standard deviations.

Two standard deviations is the worst we've seen on record which is about a 20% reduction in the average amount of hydro. You can decide based on the numbers we've got how much deviation might be there based on the current forecast. Multiply that percentage times the 580 average megawatts times a current market price. That's the way you have to get your arms around the number. And right now as I mentioned, we're about 68% normal on the mid-Columbia and 84% of normal on the [Clackamas] and about 89% on the Des Chutes.

One thing I would mention on this call to be aware of -- those numbers represent expected precipitation and snow pack which ultimately translates into runoff. When you look at the Columbia River, runoff doesn't necessarily always translate into generation because of the large reservoirs up above the Grand Coulee that can either increase flows or decrease flows above or below normal precipitation. It's not as simple as taking a percentage and that's how you are assuming that's going to happen with generation. That's the general premise.

Okay. The second question is do you guys have a shelf already out there the equity issuance?

Yes, we do.

Thanks a lot.

Thank you.

Your next question comes from James Bellessa with D.A. Davidson and Company. Your line is open.

Decoupling mechanism, how do the powers to be who are judging whether or not your achieving your goals on that mechanism decipher between a family who's bought a brand new appliance that's highly energy efficient and a family who's having tough times and maybe one of the household people are unemployed and cutting back. How do you decipher -- that it's energy efficiency or conservation versus the economic issues?

You can't with the mechanism as it's designed. But both are good results, because customers are using less of the product which is reducing the environmental footprint. Where the commission is is whether it's conservation or energy efficiency, it's the right thing and utilities should have -- should not have a disincentive for encouraging either conservation or energy efficiency.

Whether consumers do it on a behavioral basis or implement technology, 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's hard to sort out or tease out the effects of conservation or energy efficiency. But in the end, the result -- both are good for our customers. It reduces environmental footprint and encourages people to use our product as efficiently and effectively as they can. We don't have the disincentive from encouraging that kind of behavior.

The timing of the decoupling mechanism, is it really a God send in the fact that we're in a tough recessionary period?

I think the commission didn't look at it that way. They implemented it for Northwest Naturals. It's been moving across the country. In the stimulus bill, they tied some of the granting to the fact that utilities implement decoupling.

I think you have to take a longer perspective on this and timing is never right for any of these things. The commission 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. Because of the economic times, it is what that is and that can change within a year. It could be someplace else. That's our view on that one.

Thank you.

Thanks, Jim.

(Operator Instructions). Your next question comes from Maurice May with Power Insight. Your line is open.

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. It's always a question that sometimes is a little bit confusing. The way that line would likely be treated is similar to our other transmission line which is we do set up a FERC rate for use of our transmission line like the [intertie]. Third parties who want to use the intertie pay the FERC approved rate.

What we do in Oregon, because not all the transmission we use is used to integrate our generation to our load. Essentially, it gets reregulated by the Oregon PUC. It's included as our rate based asset. Any nominal revenues we receive from any third party sales of our transmission act as a credit against our revenue requirement.

And the ROE would be set by the Oregon commission?

That's correct. We don't have what you'd 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. If that changes over time, we'll reevaluate that. At this point, that's the way it's treated in Oregon.

BPA would not be a candidate to construct this? I always thought that BPA ran most of the transmission in the Pacific Northwest.

It's a combination of BPA and Pacific Corp. We have a large transmission line related to [coal strip] hat integrates the coal strip facilities. We have a 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 Barnaville, are the two dominant providers. 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.

Okay. Great. Thank you very much.

Thanks. Have a good day.

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.