Portland General Electric Company Q4 2009 Earnings Call Transcript

Mar. 1.10 | About: Portland General (POR)

Portland General Electric Company (NYSE:POR)

Q4 2009 Earnings Call Transcript

February 25, 2010 11:00 am ET

Executives

Bill Valach – Director, IR

Jim Piro – President and CEO

Maria Pope – SVP, Finance, CFO and Treasurer

Analysts

Brian Russo – Ladenburg Thalmann

Jaideep Malik – Goldman Sachs

Nancy Doyle – MetLife

Igor Grinman – Zimmer Lucas Partners

Gavin Tam – Macquarie

John Ali [ph] – Decade Capital

James Bellessa – D.A. Davidson

Operator

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 now like to turn the conference call over to Portland General Electric’s Director of Investor Relations, Mr. Bill Valach. Please go ahead, sir.

Bill Valach

Thank you, Cachetta and good morning, everyone. We’re very pleased that you’re able to join us today. Before we begin our discussion this morning, I’d like to make our customary statements regarding Portland General Electric’s written and oral 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’s a pleasure now for me to turn the call over to Jim.

Jim Piro

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 end 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; and increase in power costs due to poor hydro conditions and a prolonged outage at Colstrip Unit 4; and 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 just disappointed in the Boardman deferral replacement power costs 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 per diluted share to $1.45 per diluted share from prior guidance of $1.50 per diluted share 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 run-off 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 16th 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 customers 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 0.5% lower than the state 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’re 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’re in the top quartile for overall customer satisfaction with both general business and residential customers for the third quarter 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 U.S. The study performed by Pacific Economics Group showed that we were a significantly superior performer in system reliability, 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 process. 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 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 1st 2010.

Construction of Phase III is on schedule and on budget, with completion 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 1st 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. And 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 base load requirements estimated at 300 megawatts 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, base load and peaking resources. In these RFPs, we plan to include our own self-build options to compete with the market bid.

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 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 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 Rule.

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 base load resource in order to provide a better balance of costs 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 exist 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 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.

Maria Pope

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 2009 general rate case. And 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 $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 1st the date 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 pre-tax 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 reduction 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, 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 were down 6% and 9%, respectively.

Current forecasts indicate that regional hydro conditions in 2010 will again be below normal level. As Jim discussed, the year has started out quite mild and with very low snow-pack level.

February 18th forecast of the April 2010 to September 2010 run-off 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 16th 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 base load for power costs.

The recovery of costs or benefits related to power supply collateral requirements and automatic adjustment tariff related to recovery of our remaining investment in the Boardman’s 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 12th 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 1st.

Now, updates on our existing power cost adjustment mechanism. In 2009, the PCAM deadband ranged from $15 million below to $29 million above the base line for net variable power costs. Although actual power costs for 2009 were above the base line 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 1st 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 1st.

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 31st. $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 31st, 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 65% of the posted collateral 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 requirement 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 31st 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 31st 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 under earnings of authorized returns.

S&P revised its outlook from negative to stable, based on their expectations the credit metrics 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 acquired 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 the capital structure 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, solid balance sheet and adequate liquidity to maintain our investment grade credit ratings; long-term capital structure, 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, fair and reasonable regulatory outcome, while earning a competitive rate of return on our invested capital.

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

Jim Piro

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.

Question-and-Answer Session

Operator

(Operator instructions) And your first question comes from the line of Brian Russo with Ladenburg Thalmann.

Brian Russo – Ladenburg Thalmann

Hi, good morning.

Jim Piro

Good morning, Brian. How are you?

Brian Russo – Ladenburg Thalmann

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

Jim Piro

Maria will take that.

Maria Pope

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’s resolved.

Brian Russo – Ladenburg Thalmann

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?

Maria Pope

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’re expecting to be capital expenditures in 2012 associated with the IRP.

Brian Russo – Ladenburg Thalmann

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

Maria Pope

Sure. We, 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 '12 and beyond.

Brian Russo – Ladenburg Thalmann

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?

Jim Piro

That’s a great question, Brian. I think we 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’s 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’re 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.

Brian Russo – Ladenburg Thalmann

Okay, thank you very much.

Jim Piro

Thanks, Brian.

Operator

And your next question comes from the line of Jaideep Malik with Goldman Sachs.

Jaideep Malik – Goldman Sachs

Hey, good morning.

Jim Piro

Good morning.

Jaideep Malik – Goldman Sachs

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 like changed since the last case when you filed this testimony?

Jim Piro

There’s just a couple things 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’s been kind of a latest practice in Oregon. In the case, we filed in 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 kind of image advertising, which is kind of below the line expense that’s typically not allowed in customers prices. Other than that, all our costs should be recoverable in customer prices. And I think our case demonstrates those costs are prudent and reasonable.

Jaideep Malik – Goldman Sachs

Any way to quantify those amounts?

Jim Piro

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.

Maria Pope

It is pointed out in the rate case filing. It generally is about 3.25 to a 1% of ROE.

Jaideep Malik – Goldman Sachs

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

Jim Piro

Thank you.

Operator

And your next question comes from the line of Nancy Doyle with MetLife.

Nancy Doyle – MetLife

Yes, hi. Could you explain to me again how the deadband works and why the higher purchase power fuel expenses you experienced weren’t recovered from rate payers?

Jim Piro

Talking about 2009 specifically?

Nancy Doyle – MetLife

Yes.

Jim Piro

Maria, why don’t you go through that?

Maria Pope

Sure. The deadband has two parts to it. The first is we start with base line 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’s the first test.

The second test, which came into play last year is, 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.

Jim Piro

Last year, we’re actually over $22 million in 2009?

Maria Pope

Yes, so, we didn’t have a refund. I said at the wrong way. We were over instead of under. Sorry.

Jim Piro

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.

Nancy Doyle – MetLife

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

Jim Piro

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’s a $10 million on the up and down side without any change over time and then a 90-10 sharing above those numbers or below those numbers.

Nancy Doyle – MetLife

And what was your earned ROE last year?

Maria Pope

It was right about 6.4%.

Nancy Doyle – MetLife

And in addressing the dividend, you increased it in May. Your plans for a dividend increased this year?

Jim Piro

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’s typically the time we address it. I can’t tell you how we’ll decide on that issue at this point.

Nancy Doyle – MetLife

Thank you.

Jim Piro

Thank you, Nancy.

Operator

And your next question comes from the line of Igor Grinman of Zimmer Lucas Partners.

Igor Grinman – Zimmer Lucas Partners

Hey, guys, actually, my questions have been answered. Thanks.

Jim Piro

Thank you.

Operator

And your next question comes from the line of Gavin Tam with Macquarie.

Gavin Tam – Macquarie

Hi, 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 your rate case, I understand that you’re 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? 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 how that might soften declining sales for your large C&I customers.

Jim Piro

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’s where we use a lost revenue calculation. 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 they compute the lost revenues for those measures. So it’s 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 the whole purpose of decoupling is to address the disincentive of us putting in energy efficiency with our customers. And those customers are minimally 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’s really hard for us to argue that that large class ought to go into the decoupling mechanism. It’s 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’re doing for 2011.

Gavin Tam – Macquarie

Okay, thanks.

Jim Piro

Thanks, Gavin.

Operator

And your next question comes from the line of John Ali [ph] with Decade Capital.

John Ali – Decade Capital

Good morning, guys. 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, has there been?

Maria Pope

Sure. In December, we filed a deferral order related to the expense of $3.7 million that we’re 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; '12 would be $18 million and then '13 would be about $16 million, declining to about $6 million and de minimis after that.

John Ali – Decade Capital

So for 2010, is that baked into guidance?

Maria Pope

Yes, that is.

John Ali – Decade Capital

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

Maria Pope

It’s within our range.

John Ali – Decade Capital

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, there is a small uptick from AFUDC, but then maybe some headwinds from inflation kind of offset growth, but then you have significantly more shares in '12 than you do '11. So we should really look to '13 to meet kind of your full potential?

Jim Piro

I would say 2011 look like 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’s really what we are pointing towards.

And we’re really focused on getting through the rate case and getting prices in place that will recover our costs. The problems we’ve had over last few years have been economically driven and a couple of problems with the plant, not necessarily, regulatory problems per se. And so we are hoping that if 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.

John Ali – Decade Capital

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

Maria Pope

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

John Ali – Decade Capital

Okay, great. That’s all my questions, thank you.

Jim Piro

Thanks, John.

Operator

And your next question comes from the line of James Bellessa with D.A. Davidson & Company.

James Bellessa – D.A. Davidson

Hi. Good morning.

Jim Piro

Hi, Jim, how are you doing?

James Bellessa – D.A. Davidson

All right. 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?

Maria Pope

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

James Bellessa – D.A. Davidson

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

Maria Pope

Sure. 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 summer time or later towards the end of Q3.

Jim Piro

We have a large retirement coming due in –

Maria Pope

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 has (inaudible) life.

James Bellessa – D.A. Davidson

Thank you very much.

Jim Piro

Thanks, Jim.

Operator

(Operator instructions)

Bill Valach

I think we’re ready to close it off.

Jim Piro

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.

Operator

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

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