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Portland General Electric Company (NYSE:POR)

Q2 2009 Earnings Call

August 3, 2009 11:00 am ET

Executives

James Piro – President & CEO

Maria Pope – SVP & CFO

Bill Valach – IR

Analysts

Marc De Croisset - Macquarie Research

Michael Lapides - Goldman Sachs

James Bellessa - DA Davidson & Co.

Neil Kalton – Wells Fargo

Brian Russo - Ladenburg Thalmann

Maurice May - Soleil-Power Insights

Operator

Good morning everyone and welcome to the Portland General Electric Company’s second quarter 2009 earnings results conference call. Today is Monday, August 3, 2009. This call is being recorded. (Operator Instructions) For opening remarks, I would like to turn the conference call over the Portland General Electric's Director of Investor Relations, Mr. Bill Valach.

Bill Valach

Good morning everyone, I’m Bill Valach, Director of Investor Relations of Portland General and we are 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 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 difference, the company requests that you read our most recent Form 10-K and Form 10-Q's.

The Form 10-Q for the second quarter of 2009 was available this morning at www.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. This Safe Harbor statement should be incorporated as part of any transcript of this call.

Portland General Electric's second quarter 2009 earnings were released before the market opened today and the release is available at www.portlandgeneral.com.

With me today are James Piro, CEO and President and Maria Pope, Senior Vice President of Finance, CFO and Treasurer. James will begin this call with an overview. Maria will then discuss in more detail our second quarter results, and then we will open the call to questions.

Now it’s a pleasure to turn the call over to James.

James Piro

Thank you Bill, good morning everyone and thank you for joining us. Welcome to Portland General Electric’s 2009 second quarter earnings call. This morning we issued our earnings release. On today’s call we’ll provide more clarity around the key drivers of both earnings and the revised guidance we announced on July 22.

I’ll update you on Oregon’s economy, and the outlook for our operating area. Finally I’ll discuss the progress we’re making on our strategic initiatives. Later Maria will provide details on second quarter results, financing and liquidity, and current regulatory proceedings.

So let’s begin, PGE’s net income for second quarter 2009 was $24 million or $0.31 per diluted share. Operating revenues decreased in the second quarter 2009 compared to the second quarter 2008 as a slow economy and mild weather reduced retail energy deliveries.

With retail load demand down, power originally intended to meet forecasted load was instead sold into a low priced wholesale market. The combined impacts from lower revenues resulted in lower income taxes, which under Senate Bill 408 requires a customer refund.

Higher customer prices and increases in the fair market value of our non-qualified benefit plan trust assets helped to partially offset these impacts. Now I’ll move on to guidance. On July 22 we revised our full year 2009 earnings guidance to $1.35 to $1.45 per diluted share from prior guidance of $1.80 to $1.90 per diluted share.

Let me describe the key drivers that led us to reduce our full year’s earnings guidance. Oregon’s economy continues to be impacted by the national recession. Our industrial customers’ electric use has declined more than we projected just three months ago. This decrease in load resulted in a decline in retail margin.

At the same time lower prices in the wholesale energy market made it difficult to offset reduced revenues from the sale of excess power. In addition we are experiencing lower than forecasted hydro and an extended maintenance outages at Colstrip Unit 4 and the Boardman plant.

Finally there are the associated impacts of Senate Bill 408, Oregon’s utility tax law. As we look ahead to 2010 we anticipate a gradual economic recovery in Oregon. We continue to see ongoing investment opportunities in rate based assets. This gives us strong prospects for growth and we’ll continue actively manage our operating expenses just as we are currently doing now.

In 2009 we have taken the necessary actions to ensure that our costs align with the OPUC’s decision on our most recent general rate case. In managing our costs we are responding appropriately to the impacts of the economic downturn on our customers and our business.

We continue to position ourselves for upcoming growth opportunities including significant investments in generation, transmission, distribution, and new technology. We believe that through cost effective operations and continuously improving our business practices, we will deliver value to our shareholders and customers.

Now I’ll provide you an update on Oregon’s economy and specifically our operating area. The state’s economic downturn has continued but its rate of decline has slowed. Oregon’s unemployment rate has flattened at 12.2% in June, the same as May. This compares to the national unemployment of 9.5% for June.

The unemployment rate in our operating area continues to be about 0.5% to 1% less than the state’s overall rate or about 11.5%. Oregon’s unemployment is effected by in-migration with an estimated 50,000 people added to the labor force year to date.

On a percentage basis Oregon’s labor force in June 2009 grew 2.6% over the same period in 2008. Our customer base continues to grow. We served more than 817,000 customers at the end of the second quarter of 2009, an increase of approximately 0.5% year over year.

Despite this customer growth weather adjusted retail energy deliveries decreased 3% in the second quarter of 2009 compared to second quarter of 2008. This includes a 9% decrease in deliveries to industrial customers, a 3.6% decrease in deliveries to commercial customers, and a 1.3% increase in deliveries to residential customers.

Year to date weather adjusted retail energy deliveries decreased 2.1% during the six months ending June 30, 2009 compared to the same period in 2008. This includes a 4.5% decrease in deliveries to industrial customers, a 2.9% decrease in deliveries to commercial customers, and a .01% decrease in deliveries to residential customers.

Since our residential and small commercial customers are decoupled, and our large industrial customers are not, decoupling had a minimal impact in the second quarter. We currently project weather adjusted deliveries for 2009 to decline by approximately 2.5% relative to 2008 as economic weakness persists.

For 2010 we currently project weather adjusted energy deliveries to be relatively flat to 2009. Now I’ll update you on our strategic direction which reinforces our commitment to our core business as a vertically integrated utility.

The three main focus areas we use to continuously measure our performance are operational excellence, corporate responsibility, and business growth. I’ll report out on each of these areas both what we’ve accomplished and where we’re headed.

In the area of operational excellence I’ll begin with customer satisfaction. We recently received feedback from our second quarter independent surveys and the response we received from customers was outstanding. Overall satisfaction for residential customers remains in the top quartile and our relationship with our small to medium sized business customers is stronger than ever despite the continuing economic difficulties faced by many of these customers.

Overall satisfaction for general business customers is at a new high over the last four years and we remain in the top decile. In addition the JD Powers 2009 electric utility residential customer satisfaction study issued in July echoed our strong performance. PGE’s overall customer satisfaction score places us third in the west and the top quartile nationally.

And last week we learned that according to the Esource 2009 review of North American electric and gas companies IBRs, PGE ranked number two nationally and number one in the western region for usability and functionality of our interactive voice response system.

Services like PGE’s IVR are key to strong customer satisfaction and so are power quality and reliability. For the past week we’ve been experiencing extreme heat waves here in Oregon setting the second highest record for temperature ever at 106 degrees and a new summer peak load of 3,950 megawatts on July 29, which was close to our all time system peak of 4,073 megawatts in December, 1998.

Despite the record breaking heat and power consumption, our system ran extremely well. Now let me give you an update on PGE’s generating facilities. We had successful scheduled maintenance outages at our Port Westward and Coyote Springs plants. Both of these plants are running exceptionally well.

At our Biglow Canyon Wind Farm construction of Phase II is on budget and ahead of schedule with 15 turbines placed in service as of June 30 and the remaining 50 turbines expected to be completed by September, 2009.

The availability of our plants through June 30, 2009 including thermal, wind, and hydro, was approximately 84%, with thermal at 78%, wind at 97%, and PGE owned hydro at 99%. Now I’ll provide you more details on the Colstrip Unit 4 plant in Southeastern Montana.

The Colstrip operator PPL Montana, informed us in April that the scheduled 2009 maintenance outage of Unit 4 was going to be extended eight to 10 weeks. They discovered that two turbines rotors were damaged. Both were sent to the manufacturer for repair.

Originally the operator expected Unit 4 to return to service in July, 2009 however due to welding problems that occurred during the initial repair work the operator now estimates that Unit 4 will return to service in mid November, 2009.

PGE has a 20% ownership interest in Colstrip Units 3 and 4 with each of the units providing approximately 6% or 148 megawatts of PG’s total generating capability. PGE’s share of repair cost is currently estimated at approximately $2 million, replacement power costs are estimated to be approximately $11 million through mid November, with $1 million in net replacement power costs incurred in the second quarter of 2009.

Now I’ll provide you details on the extended maintenance outage at the Boardman plant, in early April the plant was taken off line for maintenance and generator overhaul including the installation of a new rotor and [statter] with an expected restart date in June. The rotor did not pass acceptance testing and the new rotor did not perform satisfactorily.

So the existing rotor is being reinstalled. The plant is now scheduled to return to service by mid August. Repair costs are expected to be minimal, net replacement power costs are expected to be approximately $5 million.

Now on to hydro, generation from PGE’s hydroelectric plants provided approximately 11% of our retail load requirements during the first half of both 2009 and 2008. The July 8 hydro run off forecast indicates below normal conditions for 2009 including 92% on the Deschutes River, 122% on the Clackamas River, and 80% on the Columbia River at Grand Coolie.

In the area of corporate responsibility we’ve been very active on the public policy front. During the first half of 2009 carbon related legislation was at the forefront nationally as well as in many states. We continue to believe a federal legislative policy is the right direction to take.

We’re working 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.

At the state level we built strong coalitions with customers and other stakeholders to develop legislations that creates achievable carbon reduction strategies. This coalition came very close to achieving a compromise with Oregon’s governors, governor, the citizen’s utility board and the environmentalists on a utility planning approach to carbon regulation.

Ultimately the carbon bill failed to pass. PGE did work with legislators and stakeholders on a number of bills that were approved to help address climate issues including legislation to establish more energy efficiency financing, and encourage the development of solar generation.

Now I’ll move on to our growth opportunities, I’ll start with an update of some of our major capital projects, first our smart meters project. Our deployment efforts are both on schedule and on budget. At the end of July approximately 143,000 new meters have been installed within our service area.

We anticipate that smart meters will be installed in half of our service area by the end of 2009 with the remainder to be installed in 2010. We estimate the capital cost of the project to range from $130 million to $135 million and expect that the project will provide improved services, operational efficiencies and a reduction in future operating expenses.

Next an update on our selective water withdrawal project at the Pelton Round Butte Hydro Facility, in early April we encountered a delay in construction. The project is now expected to be completed in the first quarter of 2010. The total cost for this selective water withdrawal project remains at $105 million to $110 million with PG’s portion of the total cost estimated at $80 million including AFBC.

Our initial OPUC filing in this matter requested an annual revenue increase of $12.9 million. On April 14 we filed a motion to request that the schedule for the inclusion of project costs in prices be suspended due to the construction delay. A procedural schedule has yet to be reestablished.

The project is an essential part of the Pelton Round Butte FERC license agreement, and important for the restoration of fish runs on the Deschutes River. Next, Biglow Canyon Wind Farm, in June we announced the first turbines of Biglow Canyon Phase II began supplying power in the Pacific Northwest Electric grid.

Construction of Phase III is on schedule with the completion expected in mid to late 2010. This major capital investment is moving forward on time and on budget. The two phases will have a combined installed capacity of approximately 324 megawatts and with the completion of all three phases we will serve approximately 11% of our load with new renewables.

This moves us closer to Oregon’s renewable energy standard which sets a benchmark of 15% of our load served by renewable resources by the year 2015 and 25% by 2025. The estimated total cost of Phase II is $327 million including $11 million of AFDC. Phase III is $434 million including $28 million of AFDC.

Our investment in Biglow Canyon Phase II will be fully included in customers’ prices on January 1, 2010 through the renewable adjustment cost mechanism which was filed on April 1, 2009. Now I’ll provide you an update on our renewable RFP process. We have determined that we will no longer fulfill plans to add 218 average megawatts of renewable energy resources through a 2008 RFP.

Instead we will work to meet the renewable energy standard requirements in connection with our 2009 IRP process. The decision was made as a result of several challenges encountered during the RFP bid review and negotiations. These challenges included adverse changes in financial market conditions that impacted bidders’ cost and their ability to execute, transmission and interconnection deficiencies, and changes to bid structures.

We are still on track to fulfill our commitment to meet the requirements of the RES as we continue the preparation of our 2009 integrated resource plan. We expect to submit a draft IRP to the OPUC in this month and the final IRP plan by late 2009.

The resource requirements we’re addressing in the IRP include the following: the expansion of energy efficiency programs; additional renewable resources to meet Oregon’s renewable energy standards including the integration of an increasing amount of wind power; new facilities to meet base load and capacity requirements; the economics of emission controls on the Boardman plant; and a new transmission project which has been renamed Cascade Crossing.

Now let me give you a few more details, PG’s net needs additional energy and capacity to meet its retail load which creates potential for new generating resources so we’re considering the following: a natural gas facility at Boardman to help meet additional base load requirements estimated at 300 to 500 megawatts; another natural gas facility at Port Westward for additional peak load requirements estimated at 100 to 200 megawatts; as well as an additional 300 to 400 megawatts of wind or other renewable resources to meet the requirements of Oregon’s RES by 2015.

Following the OPC acknowledgement of our IRP these potential self build options would be included in a formal bidding process to be conducted in 2010. Part of our IRP is the evaluation of the economics associated with putting new emission controls on the Boardman plant. In June 2009 the Oregon Environmental Quality Commission adopted a rule that would require the installation of additional controls in three phases with completion dates between 2011 and 2017.

The rule is outlined in our Form 10-Q. The EQC rule has been submitted to the environmental protection agency for approval. We expect the EPA to issue a decision early 2010. The estimated cost is between $520 million and $560 million. This is 100% of the total cost excluding AFDC.

We are taking EQC rules into account and are evaluating options through the IRP process in order to make the right decision for the company and our customers. At a public workshop that occurred on Friday, July 31 we shared our draft IRP portfolio analysis. Based upon the expected costs relating to carbon, replacement generation, coal and natural gas and emission controls required to meet the EQC’s rule, we believe that the long-term continued operation of Boardman will best meet the economic interest of our customers.

We expect to submit the draft IRP reflecting this analysis for public comment this month. And finally on transmission we are continuing to study a 200 mile, 500 KB transmission project now referred to as the Cascade Crossing transmission project. This project is being designed to meet growing demand, provide enhanced customer reliability and help bring new renewable generation to our operating area while reducing our dependence on third party transmission providers.

We are currently exploring possible routes and working with other utilities and the Western Electric coordinating counsel to move the project forward. We expect to begin the state and federal permitting process which could take three to four years. The estimated cost of the project is currently between $600 million for a single circuit 500 KB line to $800 million for a double circuit 500 KB line.

This is 100% of total cost excluding AFDC. These investment opportunities give me confidence that our earnings growth plan is solid. We expect long-term average annual earnings growth of 6% to 8% starting from 2010 earnings results as 2009 reflects the near-term impacts of the economic recession on load and energy markets. With that I’ll turn the call over to Maria Pope our Chief Financial Officer to discuss our financial results in more detail.

Maria Pope

Good morning, as James mentioned net income was $24 million or $0.31 per diluted share for the three months ended June 30, 2009. This compares to net income of $39 million or $0.63 per diluted share for the second quarter of 2008.

Let me walk you through the major items that impacted net income for the second quarter this year compared to last year’s second quarter. Revenues decreased by $36 million due to a $19 million decrease from a decline in retail energy deliveries as a slow economy impacted energy usage of industrial and commercial customers and milder weather impacted the energy of residential customers.

A $23 million decrease in wholesale revenues driven by a 51% decrease in the average price which was slightly offset by a 1% increase in wholesale energy sales. A $10 million in lower incomes taxes owed led to increased customer refunds under Senate Bill 408. A $10 million decrease due to fuel oil sales in the second quarter of 2008 compared to the second quarter of 2009.

These decreases were partially offset by a $32 million increase from new customer prices that went into effect at the beginning of the year. Purchased fuel and power expense decreased by $1 million in the second quarter compared to the second quarter of 2008. This reflects the impact of higher average variable power costs being offset primarily by a reduction in total system load and refunds to customers booked in the second quarter of 2008 under the power cost adjustment mechanism or PCAM.

Other expenses decreased by $4 million driven primarily by declines in production and distribution as well as administration and other expenses. Other income increased by $7 million due to an increase in the fair market value of non-qualified benefit plan trust assets and higher AFDC.

Finally income taxes decreased by $14 million largely as a result of lower pre-tax earnings for the year and increases in tax credits, the majority of which consist of production tax credits. Now I would like to quantify the impact of the three drivers that led to our reduction in earnings guidance for the year from $1.80 to $1.90 per diluted share to revised guidance of $1.35 to $1.45 per diluted share.

First the effect of the economy which is resulting in decline in retail margins due to the reduction in load primarily in the industrial sector combined with subsequent sale of excess power into low priced wholesale markets. This is expected to impact the year by approximately $0.15 per diluted share.

Second, the cost of replacement power and repairs due to the extension of the scheduled maintenance outages at the Colstrip Unit 4 and Boardman coal plants. In addition hydroelectric results were lower than forecasted. These combined plant operating issues are expected to have a full year impact of approximately $0.15 per diluted share.

Third, as a result of lower earnings and the effects of Senate Bill 408 which reduces the otherwise normal tax effects of lower annual earnings and increases customer refunds for taxes which are included in rates but which are not expected to be paid, we forecast a full year impact of also approximately $0.15 per diluted share.

Now a brief update on the power cost adjustment mechanism or PCAM, for 2009 the [inaudible] ranges are from approximately $15 million below to $30 million above the baseline for net variable power costs. Although we expect that actual power costs for 2009 to be below the baseline the difference between actual and baseline power costs is expected to be within the established [inaudible].

As a result no customer refund or collection is anticipated. The OPUC authorized a decoupling mechanism in the final order of PGE’s most recent general rate case. The decoupling mechanism went into effect on February 1, 2009 for an initial period of two years. This allows for the recovery of fixed costs and lost earnings that are the result of customers energy efficiency and conservation efforts.

The decoupling mechanism tracks the differences between weather adjusted revenues that are collected on a per kilowatt hour basis with those that would be collected on a fixed per customer charge basis. This difference is accumulated in a balancing account and then refunded or collected over a future period.

As a result of increased energy usage in the residential sector on a weather adjusted basis and the return on equity reduction component from 10.1 to 10% ROE, we have booked a regulatory liability of approximately $2 million in the second quarter of 2009 as a reduction in revenues.

During the quarter we secured an additional $30 million in capacity under our revolving credit lines to bring total borrowing capacity under these facilities to $525 million. These credit facilities provide working capital as well as liquidity for our power supply operations and price risk management activities.

We have entered into forward contracts for power and natural gas to meet our retail load and as a result of decreased power and gas prices we have posted collateral to meet margin requirements under these contracts.

As of July 31 we had posted $331 million in collateral with wholesale counterparties consisting of $121 million in cash and $210 million in letters of credit. If market prices remain unchanged from June 30 levels, we anticipate that 30% of current collateral deposits will roll off in 2009 and other 50% would roll off in 2010 with the balance representing 2011 and beyond.

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

As of June 30 we had no commercial paper outstanding, no direct draws on our revolving lines of credit, and $201 million in outstanding letters of credit. As of June 30 total availability under our revolving lines was $324 million which compares to $272 million at the end of the first quarter of 2009.

As of July 31 we have $296 million available on a revolver and excess cash of $6 million. Our debt to capital ratio was 51% on June 30. PGE anticipates issuing a total of $375 million of debt for 2010 with part of the proceeds to redeem $186 million in maturities and the balance to support the completion of Biglow 3 and other capital projects as outlined in our 10-Q.

We continue to focus on our investment grade bond ratings. Our senior unsecured ratings are B AA two at Moody’s, and BBB plus at Standard & Poor’s. I would now like to provide an update on our pension funding status.

At year end 2008 our funded status was 74% assets to projected benefit plan obligations. Based on 2009 funding requirements under the pensions protection act, we do not anticipate having any required contribution in 2009. We do anticipate having required contributions of up to about $12 million in 2010.

Our pension expense for 2009 is estimated to be about $350,000. In 2010 the expense is estimated to be approximately $8 to $9 million. Now I will discuss the stimulus plans, the American recovery and reinvestment act of 2009 provides for a number of enhanced tax benefits, many of which are favorable to renewable energy projects such as PGE’s Biglow Canyon Wind Farm.

The tax benefit includes the extension of production tax credits from 2009 to 2012 and in lieu of [PTCs’] a company may elect investment tax credits or treasury department grants to meet certain criteria.

We have completed our assessment and determined that continuing to claim PTCs of approximately $110 million for Biglow Canyon Phase II is preferable versus treasury grants of $60 to $90 million. We will continue to review our options for Biglow Canyon Phase III.

We are also considering opportunities under the act that would provide funding for smart grid and electric vehicle projects. We expect to complete our filings of grant applications with the US Department of Energy in August.

Now I’ll give you an update on regulatory proceedings, in the second quarter PGE made the following regulator filings. On April 1 we submitted our first filing under the renewable adjustment cost mechanism. This mechanism allows for costs 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 initial filing on April 1 included Biglow Canyon Phase II and PGE’s share of two solar projects. The filing requests revenue requirements of approximately $41 million or 2.4% increase in prices. New rates will become effective on January 1, 2010.

Also on April 1 we filed initial forecasts with updated power costs for 2010 under the annual update tariff. In its forecast of 2010 power cost includes the power cost savings from the Biglow Canyon Phase II estimated at $17 million, our initial filing indicates an approximate 3% decrease in prices.

Throughout the year we will make several update filings. Power costs will also be put in the customer prices effective January 1. As a result of these filings customer prices in 2010 are estimated to be relatively flat.

Finally an update on the Trojan order, on March 19 the OPUC issued an order that reset and restarted the Trojan refund as outlined in the September 30, 2008 order. Based on the OPUC orders we anticipate that the $33 million plus interest will be [funded] customers by the end of 2009.

As of July 31 just over half of eligible customers had applied for the refund. In closing the focus of our financial objectives continues to support our core utility business, namely a solid balance sheet and adequate liquidity to maintain our investment grade credit ratings, a target capital structure of 50% debt and 50% equity, efficient access to capital markets to support investment in new and existing generating assets and our transmission and distribution systems, fair and reasonable regulatory outcomes, while earning a competitive rate of return on our invested capital.

Now I would like to turn it back over to James.

James Piro

Thanks Maria, we remain on track with major projects, Biglow Canyon Wind Farm, and our smart meter project. Customer satisfaction continues to be high. We expect to submit a draft IRP to the OPUC in this month and the final IRP plan by late 2009.

And we continue to focus on running our business in a cost effective manner and continuously improving our operations. Looking ahead we remain focused on our business strategy with an emphasis on operational excellence, corporate responsibility, and investment opportunities that support our core utility business, enhance service to our customers, and deliver value to our shareholders.

We’d now like to open the call for questions.

Question-and-Answer Session

Operator

(Operator Instructions) Your first question comes from the line of Marc De Croisset - Macquarie Research

Marc De Croisset - Macquarie Research

If I heard you correctly, you’re guiding for flat earnings deliveries in 2010, does that mean that you’re not expecting a rebound in industrial sales next year and if so, who are your industrial customers and can you give us a little bit of color around that.

James Piro

Right now we have some major industrial customers who are commodity oriented businesses and we’re not seeing a this point a recovery in that sector probably until late 2010. Now we could be surprised but we’re being fairly conservative just given the uncertainty of how this recession is going to work through the system.

But they’re large customers who consumer a fair amount of energy and they’re in the commodity space primarily in the paper and in the metals business. That’s kind of our view right now. Its been a tough sector to forecast just because they’re so close to the margin in their operations and so dependent on the markets in the US and worldwide for that matter.

Maria Pope

If you look at where we were on 2009 if it wasn’t for those customers we would have had much less of a change so there’s a large focus on about the five or so customers.

James Piro

Kind of on the good news side we still are seeing a commitment by the solar companies that have come in primarily Solar World and Sanyo who are building new facilities in our service territory and they’re still committed to their strategy and moving forward so that has still been a bright spot, Genentech, whose another major customer is doing quite well also.

So there have been some bright sectors in the market and we are hopeful that things are going to start stabilizing and indications are that they are but at this point for 2010 and given where we are today we’re being relatively conservative in terms of the look at what’s going to happen next year.

Marc De Croisset - Macquarie Research

Are you willing to disclose amending rate base number for 2009 at this stage and also do you have a sense for 2009 cash flow from operations. I’m guessing around $300, $320 million for cash flow from operations in 2009 but are you willing to give us a little bit more color there as well.

James Piro

Let me just speak to the rate base issue and then Maria can give you a little bit more information on the cash flow, we provided, we did a 2009 general rate case and things are pretty much in line with that 2009 general rate case albeit the SWW, the selective water withdrawal project, is not going to close the plant this year, its going to stay in construction work in progress.

And so that would be the only real difference to if you will approved rate base, but generally we’re kind of consistent with our capital forecasts we provided in 2009.

Maria Pope

More specifically we’re looking at about $2.4 billion by the end of this year in terms of rate base and then in terms of cash flow from operations you’re very close, we’re roughly looking at about $330 million.

Marc De Croisset - Macquarie Research

Do you see an earnings trajectory that moves you towards an adequate return on your rate base investments. I understand there’s been a lot of earnings volatility over the past couple of years, is there anything that you can do operationally or on the regulatory front to diminish volatility and achieve a more systematic return on your rate base investments.

James Piro

Couple of things we are doing, we’re likely to file, I think we’re moving along the path to file a 2011 general rate case primarily driven by the reduction in load. That will give us another chance to benchmark our costs with our revenues. Secondly we did get decoupling included for the next couple of years to address any potential volatility on our residential, small commercial customers.

So that albeit its worked against us so far through the first two quarters this year its still a mechanism to reduce some of that volatility due to conservation energy efficiency. The third big area is power costs and by far it’s the area that’s most volatile in our business because of hydro conditions and power plant operations.

In the next general rate case we’re going to have to look real closely at trying to reduce the size of [dead bans] to reduce some of the volatility and that’s something that’s an ongoing conversation with our customers and our commission. The west has a history of having these dead bans where if you look other places in the country they tend to have full pass throughs.

And its something that we’ll continue to work on and those are the three areas of volatility that we see. The industrial customer is a much tougher nut to crack just because they are so subject to market conditions and hard to find a mechanism that effectively addresses that.

Historically we’ve seen pretty predictable industrial loads but any time you get these major economic downturns and dislocations you get challenges in that sector. So we are trying to look at mechanisms to do that. Clearly the 2011 rate case is key to getting our revenues and our costs to aligned.

Operator

Your next question comes from the line of Michael Lapides - Goldman Sachs

Michael Lapides - Goldman Sachs

Trying to think through what’s happened in the first half of 2009 that would not be recurring into 2010, just trying to think about what are the items we should back out of 2010 numbers that aren’t necessarily normal or recurring.

James Piro

Maybe we should talk about relative to the guidance because the first two quarters is probably not indicative of what we’ve seen for the year and I think the major ones, and Maria can get the exact numbers, but the major issues would be the Colstrip outage was clearly a one-time item. Boardman with the new generator installation and the new statter, clearly that’s a one-time item.

We expect to get that plant up and running and last year we had a great operating year with Boardman, its been a consistent good workhorse for us and it’s a low cost system. That’s a one-time item. Hydro is obviously a little bit of impact this year. Those are the major one-time items.

The load is the issue that we’re going to have to work through into next year and what that does to revenues versus increases in costs that we would see due to inflation and we’re right now in the 2010 budgeting process to see what choices and options we have as we set ourselves up for the 2011 rate case.

Maria Pope

As we said in our previous conversation it was about $0.15 on the generation area, that was hydro was roughly on a net income basis about a million, Colstrip totaled about $8 and Boardman about $2. In terms of the effect of SB408 on that, that was also about $0.15 and about half of that would have been associated with the generation issues that took place.

The part that we’re analyzing more closely as we look to 2010 is the impact on the economy and the load loss which for the 2009 is also about $0.15 before the effects of SB408.

Michael Lapides - Goldman Sachs

I going to make sure I understand specifically so, I’m going to go through some of the specific lines you mentioned, the Colstrip impact, are we talking about an impact on the production and distribution line item on your income statement or is this up at the purchase power and fuel or elsewhere. Do you mind walking through, you mentioned Colstrip, Boardman and then the SB408, walking through the specific line item you expect to be negatively impacted in 2009.

Maria Pope

Colstrip was $2 million on the O&M side, and $11 million on the power cost side. Boardman was largely all on the power cost side at about $5 million, and these are pre-tax numbers I’ve just given you. And then hydro again on a pre-tax basis is now about $2 million on the power cost side. And then SB408 effects are on about $14 million.

Michael Lapides - Goldman Sachs

And that’s on the revenue side.

Maria Pope

Yes.

Operator

Your next question comes from the line of James Bellessa - DA Davidson & Co.

James Bellessa - DA Davidson & Co.

You had decoupling mechanism that is on trail basis starting in February and I heard it had a minimum impact on second quarter and then I heard you say that it has not worked in your favor in the first half, can you go through and explain the benefits or why it hasn’t worked and so forth.

James Piro

Let me give you the high points and Maria can give you the exact numbers and how it worked, so the whole theory of decoupling was to get it to a dollars per customer basis and when we put the mechanism in place and given the recession we were seeing and the continuing promotion of energy efficiency, we actually thought use per customer would decline this year due to both more energy efficiency being installed as well as just people conserving energy because of the recession and trying to watch their energy costs pretty closely.

What we saw in the first half of the year was just the opposite, that actually use per customer increased which was kind of frankly a surprise to us and the only thing we can attribute that to is because the recession, more customers are staying home, they’re not going to restaurants, they’re using more electricity in terms of cooking, they’re buying more plasma TVs then we expected which is kind of surprise and we’re seeing the installation of a greater penetration of air conditioners.

So all that kind of added to the fact that actual customer demand on a residential basis, on a use per customer increase. In the commercial sector we actually did see some reduction in revenues which kind of offset the residential impact and this was a result of commercial customers installing energy efficiency measures where we have to track those in.

So those were the two things and then offsetting all that obviously we had the ROE reduction. So that’s kind of the big picture as we saw it and as we put this in place we looked back to the last recession in 2001 and 2002 where we did see a significant reduction in use per customer by our residential customer.

So again due to energy efficiency and conservation due to the point where we had high energy prices. So we kind of assumed that that same thing would happen and as you can imagine past performance isn’t always indicative of future activity so we learn something new every day. That being said we still think it’s the right mechanism from a policy perspective because it does kind of take away the disincentive for customers to do energy efficiency.

So kind of first half of year it kind of worked against us but we haven’t see the whole year play it out and we’ll watch this through next year. It’s a two year trial plan and at the end of two years we’ll have to refile with the commission if we want to continue that mechanism. So we’ll learn a lot over the next couple of years and still believe it’s the right policy decision for our company and our customers.

Maria Pope

First of all the decoupling mechanism covers approximately 60% of our customer base. It has on a year to date basis about $1.5 million negative impact to the company, $2 million in the second quarter and $0.50 million positive in the first quarter. As James mentioned its made up of two components. First is the decoupling adjustment itself and on a year to date basis that was approximately $700,000 to the negative.

On the residential side it was actually unfavorable $1.1 million but the commercial or non-residential sector was 0.4 to the good for the $700,000. As James mentioned residential was up 1.3% on a weather adjusted basis in terms of load. So ROE component included $0.8 million or $800,000 getting us to the $1.5 year to date.

James Bellessa - DA Davidson & Co.

You indicated that there was a draft IRP that you shared with some parties, is that a privileged party or is everybody available to see that draft IRP.

James Piro

That’s a public document, it’s a fairly voluminous two set presentation, Bill Valach can get it to you if you’re interested, it is a public document. It gives you a lot of good detail on our plans for the future meeting resource load requirements. It may in fact be posted on our website. It is posted on our website. But if you can’t find it, get a hold of Bill and he can get it to you. But I’m sure its there from a public process standpoint.

Good document, it really has some interesting data about the heat wave, air conditioning penetration, our strategy around Boardman and new resources. It’s a great document and a lot of good information there.

James Bellessa - DA Davidson & Co.

Your rates are based on a 50% capital ratio but you’re not quite there and you talked about issuing debt between now and the end of 2010, so how are you going to be able to maintain your appropriate capital ratio.

Maria Pope

We expect to issue debt. We are also about $375 million or so between now and the end of 2010. We also expect to redeem about $186 million of debt in the first quarter of next year and combined with earnings as well as collateral roll off we expect our ratios to roughly be around our target 50/50, maybe a tad bit higher on the debt side.

James Bellessa - DA Davidson & Co.

And you indicated that you’re going to turn to maintaining the production tax credit in your income statement, did you say you were going to collect $210 million, I’m not certain of the figure you said.

Maria Pope

Yes I used the figure of $110 in terms of PTCs over the next 10 years.

James Bellessa - DA Davidson & Co.

Over 10 years.

Maria Pope

Yes.

James Piro

The production tax credit is based on a generation basis at certain mills per kilowatt hour of generation so it goes over 10 years and its based on the output of the wind farm and that would be included in customers’ prices that we filed in the [RAC] filing.

James Bellessa - DA Davidson & Co.

How did you find that $60 to $90 million this year, next year was not as advantageous as $110 over 10 years.

Maria Pope

We looked at our alternative cost of capital, how each would flow through to rates. The grants would have resulted in a reduction in our plant placed into service and our regulatory asset base and would have reduced that as well as would have gone to customers over the life of the wind farm [inaudible] 25 years.

So the PTC is roughly about $0.03 per kilowatt hour and we felt that it made good sense with Biglow 2. We will do the same analysis and make a decision on Biglow 3 probably around this time next year.

James Bellessa - DA Davidson & Co.

Would the $110 for just Biglow, Phase II.

Maria Pope

Yes, its just for those 65 turbines.

James Piro

The big problem there is that the grants have to be treated like investment tax credits which have to be shared between customers and shareholders which diminishes the value for customers. But we have to take the alternative that creates the greatest present value for customers and that’s why we went to the production tax credit.

Operator

Your next question comes from the line of Neil Kalton – Wells Fargo

Neil Kalton – Wells Fargo

I just wanted to get a couple of things straight, I think in an earlier question you mentioned that the operating cash flow for 2009 would be roughly about $330 million, does that include the benefit of the net margin deposits reversing I guess a little bit in 2009, is that included in there.

Maria Pope

No, that does not include that.

Neil Kalton – Wells Fargo

Okay, so would that be an incremental, how much extra would that be.

Maria Pope

That’s roughly, in this year it should be an additional $106 by 2009 and then $172 by the end of 2010, billion, and that assumes that prices are roughly where they were at the end of June.

Neil Kalton – Wells Fargo

And then on pension it looks like by my calculations there’s going to be about a $0.07 headwind as we go into 2010, are there things that you can do to offset that incremental expense.

Maria Pope

You’re exactly right and we’re currently in discussions with the OPUC. Traditionally we have received expense or [FAS] 87 expense and recovery in rates. As our recent history has led us to have no expense, we have no near-term recovery mechanism but we expect to be able to resolve that with the OPUC.

Operator

Your next question comes from the line of Brian Russo - Ladenburg Thalmann

Brian Russo - Ladenburg Thalmann

I was just curious on your cost cutting initiatives following the disallowance of some costs on your last rate case, where will that show up in the income statement, is it going to fall primarily in administrative and other or is it elsewhere and it just seems that the expense items seem to be relatively flat excluding a drop in administrative and other and I’m just wondering if its being masked by some of these one-time costs that you discussed earlier.

James Piro

What we tried to so was once the PUC made a decision, most of those disallowance were in the operating cost, production, transmission, distribution, administrative, other, customer service, so we went through and exercised with our officer team to try to get our costs back in line with what the rate case decision was.

So its probably across the board in all the production and O&M lines and then there have been some costs that have gone the other way this year that have gone against us. We had a couple of things that we had incurred some additional costs for the maintenance of Colstrip. We also had small environmental reserve we had to take so that’s kind of where it is.

Maria Pope

One of the things I think when you look at the quarter to quarter statements, remember that while we were disappointed with our outcome for our 2009 rate case, we did see an increase in costs that were passed on to customers, just not as high as we had requested in the initial filing.

Operator

Your next question comes from the line of Maurice May - Soleil-Power Insights

Maurice May - Soleil-Power Insights

I have a question on the capital expenditures you listed quite a few projects, the Boardman expansion and the Port [Washington] expansion and then the transmission line etc., and also additional wind power to meet the 2015 requirements, so my question really here is is how many of these projects are in your five year CapEx projection at present.

Maria Pope

If you look in the 10-Q none of the ones that you just mentioned are in our 10-K, 10-Q disclosures. We have [inaudible] just our base CapEx including hydro and then we have some of the Boardman initiatives, not all that James mentioned there. We will wait until the projects are more final and we finished our IRP process before formally including them into our CapEx plans for the next five years.

Maurice May - Soleil-Power Insights

But do you see some of them ending up in the outer years of the five year forecast.

Maria Pope

Sure, there’s a big concentration that would take place in 2012, 2013 and then 2014, which we don’t even list in our public disclosures.

Maurice May - Soleil-Power Insights

And what might your equity needs be during these years.

Maria Pope

As we look to target our capital structure at 50% debt and 50% equity and we’re adding significantly new generation, we would then look to the equity market at that point in time. At this point in time I think its too premature to speculate but we don’t have any equity plans in 2010 and nothing until we take a look at some of the additional generation assets that James outlined.

James Piro

And for practical purposes the way we do these is we don’t usually put anything in our 10-Q or K in terms of the capital until they’re approved by the Board in terms of the direction we want to go. Boardman is a little different in that because we have a requirements to retrofit that project. But generally that’s the process we use and that’s, and as far as those, the energy and capacity resources we have to do an RFP to the marketplace where we would include our own self build options in that RFP and we’re required as part of that process to make sure we get the lowest cost option for customers.

So until we go through that RFP process and we determine that our projects are the lowest cost option its hard to say that they’ll actually get built at this point albeit that I think our projects are very favorable and well positioned, we still have to go through that process.

Maurice May - Soleil-Power Insights

Okay perhaps the toughest part of this question is you just had to sell stock at a substantial discount to book value, going forward, assuming that market prices don’t change a lot over the next couple of years, do you have enough flexibility with these proposals to put them off so that you don’t have to finance the equity portion below book value.

James Piro

Let’s not assume that the market continues the way its been. Maybe we’ve gone through a pretty heavy economic recession and I do believe that at least in another 12 months we’ll start seeing a very strong recovery and the markets will get going again.

That being said, clearly that’s an issue that we will be talking with our Board and our internal management team around is what is our strategy to maintain the most flexibility but still moving forward on our growth strategy, but clearly a part of our strategy assumes that we’ll be able to sell our stock above book value.

These are great utility investment opportunities, we’ve got good mechanisms to track these projects and to customers’ prices and they do provide value to our customers so we hope that the conditions of the past don’t replicate themselves in the future. Maria and her team are working hard on how we can have more flexible financing strategies to be more responsive to changes in market conditions.

And we’ll keep working on that one.

Well thank you everyone, I think that concludes the question portion of our earnings call. We appreciate your interest in Portland General Electric and invite you to join us in a few months when we report on the third quarter 2009 results. If you have any additional questions, please contact Bill Valach who will be available after this call.

Thank you again for joining us today.

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Source: Portland General Electric Company Q2 2009 Earnings Call Transcript
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