Portland General Electric Co (POR) 2009 Q4 法說會逐字稿

Good morning, everyone, and welcome to the Portland General Electric Company's fourth-quarter 2009 earnings results conference call. Today is Thursday, February 25, 2010. This call is being recorded, and as such, all lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session. (Operator Instructions).

For opening remarks, I would like to turn the conference call over to Portland General Electric's Director of Investor Relations, Mr. Bill Valach. Please go ahead, sir.

Thank you, and good morning, everyone. We are very pleased that you're able to join us today.

Before we begin our discussion this morning, I would like to make our customary statements regarding Portland General Electric's written and oral disclosures to commentary that there will be statements in this call that are not based on historical facts and, as such, constitute forward-looking statements under current law. These statements are subject to factors that may cause actual results to differ materially from the forward-looking statements made today.

For a description of some of the factors that may occur that could cause such differences, the Company requests that you read our most recent Form 10-K and Form 10-Qs. Form 10-K for 2009 was available this morning at portlandgeneral.com.

The Company undertakes no obligation to update publicly any forward-looking statements, whether as a result of new information, 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 and annual 2009 earnings were released before the market opened today, and the release is available at portlandgeneral.com. And with me today are Jim Piro, President and CEO, and Maria Pope, Senior Vice President of Finance, CFO and Treasurer. And it is a pleasure now for me to turn the call over to Jim.

Thank you, Bill. Good morning, everyone, and thank you for joining us. Welcome to Portland General Electric's 2009 year-end and fourth-quarter earnings call. 2009 was a challenging year for our business and our customers. As the national recession impacted Oregon, we maintained our focus on operational excellence.

We've put a special emphasis on reducing costs in the short term and focusing on continuous improvements and sustainable cost efficiencies for the long-term. We work closely with our customers to support their needs through energy efficiency and flexible payment options. We made progress executing our strategic initiatives, and we continued our efforts to work with key stakeholders to help them understand our business and our challenges. This includes (inaudible) cost recovery, sharing risks appropriately and earning a fair return for our shareholders.

On today's call, I will address the key drivers of 2009 earnings. I will also provide more clarity around the key drivers for our revised 2010 earnings guidance. I will give an outlook for Oregon's economy and our operating area. Finally, I will update you on PGE's strategic direction and capital investment opportunities included in our integrated resource plan.

Then Maria will provide details on the fourth-quarter and year-and results, financing and liquidity and current regulatory proceedings, focusing on the general rate case we filed on February 16. So let's begin.

PGE's net income for 2009 was $95 million, or $1.31 per diluted share, compared to $87 million, or $1.39 per diluted share, for 2008. 2009 earnings were a result of the following key drivers -- the impact of the economic recession on retail loads; an increase in power costs due to poor hydro conditions and a prolonged outage at Colstrip Unit 4; an increase in the fair value of nonqualified benefit plan assets; the OPUC order on the Selective Water Withdrawal project; and a write-off of a portion of the regulatory asset associated with the Boardman forced outage from late 2005 to early 2006. I was disappointed in the Boardman deferral replacement power cost decision, which caused our earnings to fall below our 2009 revised earnings guidance.

We are revising our full-year 2010 earnings guidance to $1.30 to $1.45 per diluted share from prior guidance of $1.50 to $1.65 per diluted share. The two key drivers for the revision of guidance are the following. First, unfavorable hydro conditions. The April through September runoff the forecast for PGE-owned hydro and hydro energy received from the mid-Columbia is forecasted to be significantly below normal. This will result in increased power costs.

Second, warmer weather in January and February, resulting in a decline in retail margin. This past January was the third warmest on record, and February continues to be unusually warm. The combined impact from the above two factors results in lower income taxes, which in turn would require customer refunds under SB 408, an Oregon Utility tax law. Reduced hydro energy, a decline in retail margins and the related impacts from SB 408 represent approximately 50%, 25% and 25%, respectively, of the total reduction in earnings guidance.

We want to ensure that our investors understand the challenges we face due to these weather-related drivers. Although still early in the year, we believe clarity around these key drivers is critical.

Now I will provide you an update on our 2011 general rate case filing. On February 16, we filed a general rate case based upon a 2011 test year, requesting an overall price increase of 7.4% and a return on equity of 10.5%. In the case, we are also addressing several key policy objectives that balance customer and shareholders' interest. Through this rate case, we will align customer prices with our ongoing costs to provide the financial stability that will allow us to make cost-effective investments in Oregon's energy future to benefit our customers and provide a reasonable rate of return for our shareholders. Maria will provide more details on the case later on the call.

Now I will give you an update on Oregon's economy and our operating area. Oregon's seasonally-adjusted unemployment rate was 11% for December 2009, which compares to the national unemployment rate of 10%. The unemployment rate in our operating area continues to average approximately a half of 1% lower than the state's 2009 overall rate. A fundamental reason behind Oregon's high unemployment rate remains the inflow of people moving here. In 2009, Oregon ranked second among the top states attracting in-migration.

At the close of 2009, we served approximately 816,000 customers, an increase of approximately 1% year-over-year. Even with this growth, weather-adjusted retail energy deliveries decreased 2.4% in 2009 compared to 2008. This decline was primarily due to economic impacts on three large commodity-based customers. The decline in energy deliveries to our commercial customers was offset by the increase in deliveries to residential customers. For 2010, we project annualized weather-adjusted energy deliveries will be about flat compared to 2009 levels.

Fortunately, we serve a diverse customer base and several industries appear ready for growth as the economy recovers. Manufacturing, health and education services and the retail sector added jobs in December. Daimler North America, owner of Freightliner Trucks, received a federal grant to build fuel-efficient trucks.

The emergence of solar cell manufacturing in our operating area continues to be a bright spot, and emphasizes Oregon's reputation as a center for power reliability, sustainability and clean technologies. SolarWorld and SANYO North America are both in production, and Solaicx plans to expand its North Portland manufacturing plant.

We are also seeing improvements in the high-tech sector, led by Intel. In fact, energy deliveries to the high-tech sector across the board increased by 4.5% in 2009.

Now I'll update you on our strategic initiatives and issues. First, in the area of operational excellence, we are in the top quartile for overall customer satisfaction with both general business and residential customers for the third and the fourth quarter of 2009.

For our generating facilities, the combined average availability of our thermo, wind and hydro plants, excluding Colstrip, was approximately 89% in 2009. Thermal was at 84%, wind at 97% and PGE-owned hydro at 99%.

In 2009, as part of our work on continuous improvement in cost efficiencies, we commissioned a study that benchmarked our costs and reliability with a large sample of utilities in the US. The study performed by Pacific Economics Group showed that we were a significantly superior performer in system reliability, and slightly below, but not significantly different, from the average cost of the entire sample of utilities.

This provides me some comfort that our customers are getting value for the prices they pay, but we can do better. Our leadership team is working hard to improve our performance by leveraging technology and improving our processes. We already have a number of initiatives underway that will lower our costs as well as increase the value of the services we provide to our customers.

On the public policy front, this February, the Oregon (technical difficulty) legislature confirmed Susan Ackerman, an experienced lawyer with a strong understanding of regulation in Oregon, to serve out the remaining two years of former Chairman, Lee Beyer's, term at the Public Utility Commission. And they reaffirmed Commissioner John Savage to serve for another four-year term. In addition, the Governor also selected Commissioner Ray Baum to serve as the Chairman of the Commission.

Now I will move on to our growth opportunities. I will begin with updates on some of our major capital projects. Our smart meter installation efforts are currently ahead of schedule. At this time, approximately 550,000 new smart meters have been installed within our service area, or about 67% of the total meters. We expect this project to be completed this year and within the capital budget we set.

Late August, we completed construction of Biglow Canyon Phase II on time and under budget. Through the renewable adjustment clause mechanism, we deferred the net revenue requirements during 2009 as the project went into service, and the project was fully included in prices on January 1, 2010.

Construction of Phase III is on schedule and on budget, with completions expected in the third quarter of 2010. The estimated total cost of Phase III is $428 million, including $23 million of AFDC. Similar to Phase II, we will begin to defer the net revenue requirements through the RAC mechanism as the turbines are placed into service during 2010. This project is anticipated to be fully included in customers' prices on January 1, 2011.

Biglow Canyon is a critical part of our resource strategy, and our 2009 integrated resource plan outlines that strategy moving forward.

In November, we filed our 2009 Integrated Resource Plan with the OPUC. The proposed action plan for 2015 includes the following -- the continuation of energy efficiency programs to reduce consumption by approximately 214 average megawatts; an additional 122 average megawatts of renewable resources to meet Oregon's renewable energy standard requirement of 15% by 2015; a natural gas facility to meet additional baseload requirements estimated at 300 to 500 megawatts; a natural gas facility for additional peak load requirements estimated at up to 200 megawatts; a new transmission project called Cascade Crossing; and the installation of emission controls on the Boardman Plant.

We expect an OPUC decision that would acknowledge our IRP action plan in the second half of 2010. Upon receipt of a Commission decision on our IRP action plan, we plan to conduct separate RFP bidding processes for new renewables, baseload and peaking resources. In these RFPs, we plan to include our own self-build options to compete with the market bids.

We have also begun the permitting process for our proposed 200-mile 500 kV transmission project called Cascade Crossing. The project is designed to meet PGE's growing demand, provide enhanced system reliability and bring new renewable generation to our operating area. We plan to file a notice of intent with the State Energy Facility Siting Council this spring. This will kick off a series of public meetings hosted by state and federal agencies. We are also starting discussions with the Confederated Tribes of the Warm Springs on permitting and right-of-way matters.

The estimated cost of the project is currently between $610 million and $825 million, excluding AFDC. Assuming we get regulatory and corporate approvals, we expect the in-service date to be the end of the year 2015.

The IRP as filed calls for the installation of new emission controls on the Boardman Plant to comply with the requirements of Oregon's regional haze rules. The completion of emission controls -- with the completion of the emission controls, we would operate the plant through 2040. During the public process of our IRP and in subsequent discussions with the Commission staff and key stakeholders, we found continued interest in an alternative operating plant for Boardman, similar to our decision point plan submitted to the Oregon Department of Environmental Quality at the end of 2008.

So in January 2010, we proposed to either discontinue the use of pulverized coal as a fuel source or cease operations of Boardman in 2020 and replace it with a new baseload resource in order to provide a better balance of cost and risks for customers. The alternative plan would require a change in the state rules adopted by the Oregon Environmental Quality Commission for Boardman and possibly federal legislation, in addition to acknowledgment of the plan by the OPUC as part of an amended IRP, which we intend to file in March of 2010.

Stakeholder support is essential, and we are now engaged in active discussions with interested parties and regulators to determine if a realistic path exists to make an implementation of an alternative plan possible. We currently plan to submit a new regional haze rule called the Best Available Retrofit Technology Plan to the Oregon Department of Environmental Quality in March of 2010, with a decision by the end of the year.

If regulatory approval on a 2020 alternative plan for Boardman can't be achieved, we will continue to pursue OPUC acknowledgment of the proposed installation of all required controls and continued operations through 2040 and beyond.

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

Good morning. Fourth-quarter 2009 net income was $8 million, or $0.11 per diluted share. This compares to $20 million, or $0.32 per diluted share, for the fourth quarter of 2008.

The major items that impacted results include revenues, which increased by $36 million, primarily due to a $30 million increase from higher prices granted in the 2009 general rate case; an $11 million increase related to revenue requirements for Biglow Canyon Phase II; a $4 million increase driven by retail sales, which were up 1%. This was the result of a 3.4% increase in residential deliveries, given colder weather in November and December, offset by a 3.9% decrease in commercial and industrial energy deliveries.

These increases were offset by a $15 million decrease in wholesale revenues, consisting of a 22% decline in market prices and an 18% decrease in volume.

Purchase power and fuel expense increased by $54 million in the fourth quarter of 2009 compared to the fourth quarter of 2008. This reflects the impacts of the following. Increased cost of purchase power, including incremental replacement power costs due to the Colstrip outage, partly offset by lower wholesale sales. Increased costs of power generated, largely due to higher fuel costs. And the $18 million write-off of a portion of the regulatory asset related to Boardman's forced outage from late 2005 to early 2006.

Production and distribution expense increased by $7 million. This was primarily the result of an agreement not to seek regulatory recovery of $6 million of costs associated with the Selective Water Withdrawal system construction delay. We are pursuing insurance coverage and cost recovery from firms involved with design, construction and installation of the system. The project is currently in customer prices effective February 1, the day the project was in service.

Administrative and other expenses decreased by $3 million, or 6%, reflecting lower cost and lower incentive compensation. Other income increased by $8 million, primarily due to an increase in the fair market value of nonqualified benefit plan trust assets, which gained $1 million in the fourth quarter of 2009 compared to an $8 million loss in Q4 of 2008.

Now I will discuss full-year results. As Jim mentioned, net income for 2009 was $95 million, or $1.31 per diluted share, compared to $87 million, or $1.39 per diluted share, for 2008. Operating results for 2009 reflect higher customer prices, offset by a decline in retail energy deliveries, lower average wholesale prices and volume, as well as higher power costs.

Other items that impacted operating results on a pretax basis include a $33 million increase resulting from the Trojan refund recorded in 2008; a $26 million increase from the improvement in nonqualified benefit plan trust assets in 2009 compared to 2008; and an $11 million decrease in administrative costs, as we focused on cost reductions and lowered incentive compensation.

These results were offset by the $18 million write-off associated with Boardman's forced outage and a $6 million decrease related to the Selective Water Withdrawal project, both previously discussed.

Last year, our Company and customers encountered significant challenges due to the economic recession. We responded in reduced costs. These reductions included no salary increases for senior management and professional staff; companywide reductions in targeted programs; significantly reduced levels of contract workers; and voluntary furloughs. Most of these actions, while not sustainable long-term, are being continued through 2010.

Now let me provide more detail on hydro generation. Regional hydro conditions were below normal in 2009. PGE-owned hydro production and energy received from mid-Columbia projects was down 6% and 9%, respectively. Current forecasts indicate that regional hydro conditions in 2010 will again be below normal levels. As Jim discussed, the year has started out quite mild and with very low snowpack levels. February 18th forecast of the April to September 2010 runoff schedule indicates that the Deschutes River will be at 76% of normal, the Clackamas River at 78%, and the Columbia River at Grand Coulee at 79%.

Now I will give you an update on several regulatory proceedings, starting with our general rate case filing. On February 16, we filed a general rate case with the OPUC based on a 2011 test year. We have proposed a $125 million increase in revenue requirements, representing a 7.4% overall increase in customer prices, which includes a 2% decrease related to projected power costs.

In addition, PGE is requesting a capital structure of 50% debt to equity, a return on equity of 10.5%, for a total cost of capital of approximately 8.3%. We are also asking that the OPUC approves several important policy objectives. A continuation of the annual update tariff and the modification of the power cost adjustment mechanism, or PCAM, to be more closely aligned with other utilities across the country. This includes an asymmetrical deadband of 10 million above and below the estimated baseload for power costs.

The recovery of costs or benefits related to power supply collateral requirements. An automatic adjustment tariff related to recovery of our remaining investment in the Boardman Power Plant. And balancing accounts to track the recovery of costs for future major storm damage and the costs of contributing to our defined benefit plans. And finally, a continuation of the decoupling mechanism for residential and small commercial customers and the lost revenue mechanism for medium to large commercial customers.

Now, the Boardman deferral. On February 12, we received an order from the OPUC that granted the recovery of 50% of the $26.4 million of deferred excess replacement power costs associated with the forced Boardman outage from November 2005 through February 2006. The OPUC order authorized the collection of $13.2 million of the deferred amount. We recorded a pretax write-off of approximately $18 million, including interest in the fourth quarter of 2009.

Moving on to Selective Water Withdrawal project at the Pelton Round Butte Hydro facility. The project was completed in January 2010. We entered into a stipulation agreement with regulators, settling all issues in the proceeding. Our allowed revenue requirement resulted in a 0.6% increase in customers' prices, which went into effect February 1.

Now, updates on our existing power cost adjustment mechanism. In 2009, the PCAM deadbands ranged from $15 million below to $29 million above the baseline for net variable power costs. Although actual power costs for 2009 were above the baseline by approximately $22 million, they were within the deadband, and as a result, no customer refund or collection has been recorded for 2009. In 2010, the deadbands are expected to range between $17 million and $34 million.

Now, the decoupling mechanism. Offsetting higher residential sales in 2009, the decoupling mechanism resulted in a $7 million decrease in retail revenues for 2009, as weather-adjusted use per customer for the year exceeded that approved in the prior rate case, the renewable adjustment cost, or RAC mechanism.

On April 1, 2009 we submitted our first RAC filing. This mechanism allows for the cost of renewable resources that are expected to be placed into service in the current year to be recovered in customer prices without filing a general rate case. Our filing included Biglow Canyon Phase II and PGE's share of two solar projects. The result was a 2.5% increase in customer prices, which went into effect on January 1.

Finally, the annual update tariff. Also in November 2009, we completed our update on net variable power costs. This resulted in a 4.1% decrease in retail prices, which also became effective January 1.

Now moving on to financing and liquidity. PGE has $600 million in revolving lines of credit as of December 31, $200 million of which support operating and working capital needs, and $400 million of which is for liquidity for our power supply operations and price-risk management activities. I am pleased that in December, we replaced the $125 million, 364-day credit facility with a $200 million facility and extended the term [three years]. As of December 31, we had posted $200 million in collateral with wholesale counterparties, consisting of $56 million in cash and $144 million in letters of credit.

Our forward contracts for power and natural gas may require the posting of collateral to meet margin requirements under these contracts. If market prices remain unchanged, we anticipate that (technical difficulty) of the posted (technical difficulty) would no longer be required by the end of 2010, as the related contracts are settled, with another 25% expected to roll off by the end of 2011.

The posting of collateral for margin requirements affects cash flow, but it is important to note that the costs associated with gas and power contracts are either currently in or are anticipated to be in customer prices.

As of December 31, we had no commercial paper outstanding, no direct draws on the revolvers, and a total of $163 million in letters of credit outstanding. Our debt-to-capital ratio was 53% on December 31, largely unchanged from year end 2008.

Credit ratings. In January, Standard & Poor's lowered its senior unsecured rating on PGE from BBB+ to BBB. The change reflects their view of the impact of current weak economic conditions and concerns regarding the Company's underearnings of authorized returns. S&P revised its outlook from negative to stable, based on their expectations the credit matrix will not diminish further. Our senior unsecured ratings remain unchanged at Moody's, with a Baa2 rating and a positive outlook.

Pension. Based on funding requirements under the Pension Protection Act, we did not have a required contribution in 2009 and do not anticipate any required contribution in 2010. We do expect to begin funding in 2011 with a $19 million contribution.

Our pension expense for 2009 was approximately $350,000, and is estimated to be $3.7 million for 2010. This past December, we filed a deferral application with the OPUC for 2010 pension expense.

2010 capital expenditures are estimated at $540 million, and include Biglow Canyon Phase III, the smart meter project, hydro licensing, and construction and ongoing capital expenditures related to transmission, distribution and generation infrastructure.

In 2010, we expect to issue $250 million of long-term debt, of which $70 million was issued in January. Proceeds will be used for current-year debt maturities and capital expenditures.

I know that many of you have questions regarding PGE's plans for issuing equity and the amount of equity identified in the general rate case. The amount and timing of future equity issuances is dependent on several factors, including earnings and operating cash flows, planned capital expenditures, specifically driven by the outcome from our IRP process and the result of the competitive RFP bidding process.

While we periodically are higher or lower, over the long term, we target a capital structure of 50% debt and 50% equity. In the general rate case testimony, we have included the issuance of $300 million of equity in the latter part of 2011. This issuance is in anticipation of large capital projects in the IRP, specifically, additional wind resources to meet our renewable energy standard targets.

In closing, we continue our focus on financial objectives that support our core utility business, namely, a solid balance sheet and adequate liquidity to maintain our investment grade credit ratings; long-term capital structure, a target of 50% debt to equity; efficient access to capital markets to support investment in new and existing generating assets and our transmission and distribution system; and fair and reasonable regulatory outcomes, while earning a competitive rate of return on our invested capital.

With that, I would like to turn it back over to Jim.

Thanks, Maria. Looking ahead, we will continue our focus on operational excellence through actively managing our costs and monitoring our performance metrics. We will do this through our Companywide efforts on efficiency and cost-effectiveness, while not losing sight of the importance of delivering high customer value.

We will continue to work with our regulators and our customers to help them understand the challenges our business is facing and the importance of a fair and reasonable cost recovery, so that we can deliver the service, safety and system reliability our customers expect at the lowest possible cost.

Finally, we will continue to pursue solid, rate-based investments in generation, transmission and distribution assets that will deliver value to our customers and shareholders.

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

(Operator Instructions) Brian Russo, Ladenburg Thalmann.

You mentioned up to $300 million of potential equity needs in '11. Can you comment on your potential debt needs in 2011 as well?

Yes. Maria will take that.

Sure. At this point in time, we are not estimating issuing any debt in 2011. Both of those assumptions, the equity and the debt, are based on the level of capital expenditures that we will see, in addition to our base capital, from the IRP, as that is resolved.

So I guess your equity ratio is likely to fall meaningfully below the 50% mark by year-end '10 with the debt issuances in 2010, and then the up $300 million of equity issuances in '11 get you back up to the 50%. Is that correct?

We do expect to have a -- we are below our target right now by about three points. We expect to be lower by about another point at the end of 2010, and then to be slightly higher at the end of 2011, with some excess cash for what we are expecting to be capital expenditures in 2012 associated with the IRP.

Okay. Can you just repeat what -- your comments on the collateral returns you expect in 2010 and 2011?

Sure. We are expecting -- first of all, we have $200 million in collateral currently outstanding at December 31. And given no price changes, we expect 65% of that to be returned in 2010 and 25% of that in 2011, with the balance in 2012 and beyond.

Okay. And then just on your guidance, I am a little surprised that you would revise it lower based on current hydro conditions. Am I correct in assuming that February is generally a trough month, and there tends to be improvements as we move through March and April? So if indeed we do get improvements in hydro, would that create sensitivity in your adjusted guidance?

That's a great question, Brian. I think we've struggled a lot with the hydro. We are seeing a very strong El Nino effect in the Northwest, and it just seems stronger than we've seen in the past. You are correct that we have seen snowfall in March, and we can get fairly significant snowfall in March. But the weather forecasters are saying that the El Nino effect is pretty strong.

And so given that, we thought about waiting on the hydro, but it is out there. It was pretty clear that the forecasts were down and there has been a fair conversation around it. So there is some potential we could get a recovery in March, but just given the weather factors we are looking at, we just felt like it was important to kind of communicate that to the market. If we were to get significant snowfall in March, that might change our perspective, but the probabilities just don't seem to be weighing in that direction at this point.

Okay. Thank you very much.

Jaideep Malik, Goldman Sachs.

Good morning. I had a question about the rate case. What are the O&M costs that are typically not recovered in these rate cases, the amounts and all? And has this changed since the last case when you filed this testimony?

There are just a couple things that are typically -- that we made adjustments in actually the rate case filing. On the incentive side, the last rate case, the Commission decided to allow us to recover half of all non-officers' incentives and none of the officers' incentives. That has been kind of a latest practice in Oregon.

In the case, we filed it consistent with what the PUC decided in the last rate case. So a portion of the incentives are not recovered in our customers' prices. Now, we structure our incentive plans to address that. So we've kind of taken that off the table.

The other issues are around our deferred comp plans and some of the plans that we run where we defer executive and high compensated employees' salary and then that goes into a separate plan. That typically is not recovered in customers' prices.

And then advertising for -- kind of image advertising, which is kind of below the line expense, that is typically not allowed in customers' prices. But other than that, all our costs should be recoverable in customer prices. And I think our case demonstrates those costs are prudent and reasonable.

Any way to quantify those amounts?

I think you could look back at the last rate case. I don't have the numbers here. Maria, I don't know if you have them.

It is pointed out in the rate case filing. It generally is about 3/4 to 1% of ROE.

Okay. That is the only question I had. Thanks.

Nancy Doyle, MetLife.

Could you explain to me again how the deadband works and why the higher purchase power fuel expenses you experienced weren't recovered from ratepayers?

You talking about 2009 specifically?

Yes.

Maria, why don't you go through that?

Sure. The deadband has two parts to it. The first is sort of a baseline -- we start with baseline that variable power costs, and then we are 150 basis points above or 75 basis points below. And so for this year, the $22 million higher cost would fit into that 150 basis points above for higher costs. That is the first test.

The second test, which came into play last year, is that we only have a customer refund if we are over 100 basis points or under 100 basis points of our target ROE of 10%. So last year, we were under 10% in our results and we did not have a refund, based on the second part of that test.

Actually, we were actually over $22 million, weren't we, in 2009?

Yes, so we didn't have a refund. I said it the wrong way -- we were over instead of under. Sorry.

Last year, we were at $22 million, so we still didn't get through the deadband, and so as a result, we didn't have the ability to surcharge our customers.

Okay. And then in your rate case that you're finally now, you said you were going to be addressing that asymmetric deadband?

Yes, this has been a continuing issue, Nancy. A few years ago, we did not have a PCAM mechanism at all. We put a proposal forward, negotiated with the parties. The Commission ultimately decided on this structure that we currently have, which is not symmetrical. We really feel that we have some ability to absorb some cost, but the deadband gets larger and larger as we grow our rate base, and puts us exposed to significant risk, which affects our metrics and our bond ratings, potentially, as well as our stock price, because of that volatility.

So in the rate case, we've requested a smaller deadband and a symmetrical deadband, and we will argue real hard and try to convince the Commission and the parties that this makes sense for both our customers and our investors. So it is a $10 million on the up and down side, without any change over time.

Okay.

And then a 90/10 sharing above those numbers or below those numbers.

And what was your earned ROE last year?

It was right about 6.4%.

Okay. And in addressing the dividend, you increased it again -- or you increased it in May. Have you -- your plans for a dividend increased this year?

Typically, we look at the dividend in May with our Board, and will look at operating cash flows, we'll look at needs for capital, and we will make that decision in May. And that is typically the time we address it. I can't tell you how we will decide on that issue at this point.

Thank you.

[Igor Grinman], Zimmer Lucas Partners.

Actually, my questions have been answered. Thanks.

Gavin Tam, Macquarie.

Good morning, guys. Question on decoupling. I guess my understanding is that the large C&I customers aren't covered under your current decoupling.

And then in your rate case, I understand that you are just asking for an extension of your pilot. But how come you guys didn't try to have decoupling, I guess, revised to include the large C&I customers?

And then maybe if you could talk a little bit about -- I don't know if it relates to that lost revenue adjustment that you spoke about earlier. If you could talk a bit about that and how that might soften declining sales for your large C&I customers.

So the mechanism has two components. The first one is for the residential and small commercial, which is just used for customer base on a weather-adjusted basis. The next group of customers is the medium to large commercial customers, and that is where we use a lost revenue calculation.

And what we do is we work with the Energy Trust of Oregon, who delivers these energy efficiency programs to that class of customers, and we identify the measures that they install and then compute the lost revenues for those measures. So it is really tied to energy efficiency actions.

The large customers are a completely different animal because they are so economically driven, as opposed to related to energy efficiency or conservation. And so it is just -- the whole purpose of decoupling is to address the disincentive of us putting in energy efficiency with our customers. And those customers are impacted by energy efficiency, but more impacted by the economy.

But again, the decoupling proposal is really to address the disincentive of promoting energy efficiency. So it is really hard for us to argue that that large class ought to go into the decoupling mechanism. It is pretty much what we've agreed to, and I think that the challenge for us is when we have significant change in large customers, the way we have to address that is by filing a general rate case, which we are doing for 2011.

Okay. Thanks.

[John Ali], Decade Capital.

Just a quick question. If you could go over the pension accounting treatment that you requested. Is there going to be any movement on that, or has there been?

Sure. In December, we filed a deferral order related to the expense of $3.7 million that we are anticipating in 2010. And then in the rate case, we filed a request to recover not only the income statement or FAS 87 expense, but also the cost of funding additional dollars as required by the Pension Protection Act. And that, for 2011, would be $19 million; 2012 would be $18 million; and then 2013 would be about $16 million, declining to about $6 million and de minimis after that.

So for 2010, is that baked into guidance?

Yes, that is.

So if that doesn't happen, is there further downside?

It is within our range.

Okay. And just looking at kind of the out years, is it kind of fair to say that 2012 is more of a transition year? Because, you know, there is the small uptick from AFUDC, but then maybe some headwinds from inflation kind of offset growth, but then you have significantly more shares in 2012 than you do 2011. So we should really look to 2013 to be kind of your full potential?

I would say 2011 looks like it should be a full potential year; if we're successful in our rate case and get adequate and reasonable cost recovery, we ought to be able to earn near our allowed ROE, other than the disallowances we talked about earlier. And that is really what we are pointing towards. And we are really focused on getting through the rate case and getting prices in place that will recover our costs.

The problems we've had over the last few years have been economically driven and a couple of problems with the plant, not necessarily regulatory problems, per se. So we are hoping that we get this case settled, get the policy issues aside, and we should be in a reasonably good place going into 2011. We hope to have prices effective January 1.

Okay. And just one other question. When you guys talk about the collateral, can you give us a breakout in terms of what is returning of LCs versus cash?

It is about proportionate. The vast majority of collateral we have outstanding is LCs. We have about 50 some odd million dollars of cash.

Okay, great. That is all my questions. Thank you.

James Bellessa, D.A. Davidson & Company.

Say, on the Senate Bill 408 deferral, how much was the amount in 2009, and what are you kind of thinking it will be in 2010?

Sure. It was about $13 million in 2009, and we are forecasting roughly about the same amount in 2010.

Then in your issuance of debt this year, you indicate it should be in the order of magnitude of $250 million, $70 million of which has already been issued. What is the timing on the remainder?

We are looking at issuing approximately $120 million of our pollution control bonds that we repurchased last year and decided not to reissue. And that will take place and probably close in March. And then we will look at our cash flows for the balance. It could either be in the summertime or later towards the end of Q3.

We have a large retirement come due in --

Yes, we have about $140 million coming due in March, with the balance to $186 million in April and May. Those are unsecured, long-term debts that (inaudible).

Thank you very much.

(Operator Instructions)

I think we're ready to close it off.

Okay. We appreciate your interest in Portland General Electric and invite you to join us when we report on first-quarter 2010 results. If you have any additional questions, please contact Bill Valach, who will be available after this call. Thank you again for joining us today.

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