Portland General Electric Co (POR) 2009 Q2 法說會逐字稿

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, 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 over to Portland General Electric's Director of Investor Relations, Mr. Valach. Please go ahead, sir.

Good morning, everyone; I'm Bill Valach, Director of Investor Relations at Portland General, and we are very pleased that you are able to join us today.

Before we begin our discussion this morning I would like to make our customary statements regarding Portland General Electric's written and oral disclosures and commentary, that there will be statements in this call that are not based on historical fact and, as such, constitute forward-looking statements under current law. These statements are subject to factors that may cause actual results to differ materially from the forward-looking statements made today. For a description of some of the factors that may occur that could cause such differences, the Company request that you read our most recent Form 10-K and Form 10-Qs.

The Form 10-Q for the second quarter 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. 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 PortlandGeneral.com. With me today are Jim Piro, CEO and President; and Maria Pope, Senior Vice President of Finance, CFO and Treasurer. Jim 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. So now it's a pleasure to turn the call over to Jim.

Thank you, Bill. Good morning, everyone, and thank you for joining us. Welcome to Portland General Electric's 2009 second-quarter earnings call.

This morning we issued our earnings release. On today's call we will 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 the 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 nonqualified 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 lead 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 extended maintenance outages at Colstrip Unit 4 and the Boardman plant. Finally, there are the associate 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 to 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 in our most recent general rate case. In managing our cost, 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 rate 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 affected 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 0.1% 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 are 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 placed us third in the West and the top quartile nationally. And last week we learned that, according to the E Source 2009 review of North American electric and gas companies' IVRs, 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 have been experiencing an extreme heat wave here in Oregon, setting the second-highest record for temperature ever at 106° and a new summer peak load of 3950 megawatts on July 29, which was close to our all-time system peak of 4073 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 windfarm, 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 will 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 four was going to be extended eight to 10 weeks. They discovered that two turbine rotors were damaged. Both were sent to the manufacturer for repair. Originally, the operator expected unit four 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 four will return to service in mid-November 2009.

PGE has a 20% ownership interest in Colstrip's unit 3 and 4, with each of the units providing approximately 6% or 148 megawatts of PGE's total generating capability. PGE's share of repair costs 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 rotor and stator 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 runoff 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 Coulee.

In the area of corporate responsibility we have 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 are working with others in our industry including EEI to help Congress and federal policymakers understand the importance of this issue and implications to our industry and our customers.

At the state level we have built strong coalitions with customers and other stakeholders to develop legislation that creates achievable carbon reduction strategies. This coalition came very close to achieving a compromise with Oregon's governor, the citizens' 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 the selective water withdrawal project remains at $105 million to $110 million with PGE's portion of the total cost estimated at $80 million, including AFDC. 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 cost 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 windfarm. 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 loads 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 clause 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 negotiation. 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 OPC in this month, and the final IRP plan by late 2009. The resource requirements we are addressing in the IRP include the following -- the expansion of energy efficiency programs, additional renewable resources to meet Oregon's renewable energy standards including integration of an increasing amount of wind power; new facilities to meet baseload 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. PGE's net -- needs additional energy and capacity to meet its retail load, which creates potential for new generating resources. So we are considering the following -- a natural gas facility at Boardman to help meet additional baseload 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.

The following be OPC technology 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 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 in 2010. The estimated cost is between $520 million and $560 million. This is 100% of the total cost excluding AFDC.

We are taking the 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 system 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 Council to move the project forward. We expect to bring the state and federal permitting process -- excuse me -- 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 costs, 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 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.

As Jim 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 usage 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 decrease in lower income 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 for 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 by 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 nonqualified 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 sales 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 dead band 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 dead band. 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 results 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 line 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 another 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, $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 our 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 through 2010 with part of the proceeds to redeem $186 million in maturities and the balance to support the completion of Biglow III 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 BAA-2 at Moody's and BBB-plus at Standard & Poor's.

I would now like to provide an update on our pension funding status. At June -- at year end 2008, our funded status was 74% assets to projected benefit plan obligations. Based on 2009 funding requirements under the Pension 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 million to $9 million.

Now I will discuss the stimulus plan. 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 windfarm. The cash 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 million to $90 million. We will continue to review our options for Biglow Canyon Phase III. We're 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 regulatory filings. On April 1 we submitted our first filing under the renewable adjustment clause 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 a revenue requirement of approximately $41 million or 2.4% increase in prices. The new rates will become effective on January 1, 2010.

Also on April 1 we filed an initial forecast with updated power costs for 2010 under the annual update tariff. This forecast of 2010 power costs includes the power cost facings from the Biglow Canyon Phase II estimated at approximately $17 million. Our initial filing indicates an approximate 3% decrease in prices. Throughout the year, we will make several update filings. Power cost will also be put into 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 are -- anticipate that the $33 million plus interest will be funded to 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 system; 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 Jim. Thank you.

Thanks, Maria. We remain on track with major projects, Biglow Canyon windfarm 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 planned 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.

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

(Operator instructions). Marc De Croisset, Macquarie Capital.

If I heard you correctly, you are 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?

Let me -- thanks for the question, Marc. Right now we have some major industrial customers who are commodity-oriented businesses, and we are not seeing, at 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 kind of recession is going to work through the system. But they're large customers who consume a fair amount of energy, and they're in the commodity space, primarily in the paper and in the metals business.

So that's our view right now. It's 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, do you have anything else to add to that?

No. 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 five or so customers.

On the good news side, Marc, we still are seeing a commitment by the solar companies that have come in, primarily SolarWorld and Sanyo, who are building new facilities in our service territory, and they are still committed to their strategy and moving forward. So that has still been a bright spot. Genentech, who is 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, again where we are today, we are being relatively conservative in terms of the look at what's going to happen next year.

Fair enough, and just two quick ones here. Are you willing to disclose an ending 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 million, $320 million from cash flow from operations in '09. But, are you willing to give us a little bit more color there as well?

Let me just speak to the rate base issue and then Maria can give you a little bit more information on cash flow. 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; it's 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 are consistent with our capital forecast we provided in 2009.

Maria, do you want to give a little more color?

Sure. More specifically, we are 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 are very close. We are roughly looking at about $330 million.

Okay, great. And I may overstay my welcome here, but let me ask this. Do you see an earnings trajectory that moves you towards an adequate return on your rate-based investments? I understand there has been a lot of earnings volatility over the past couple 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?

Great question; a couple things we are doing. We are 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 it's worked against us so far through the first two quarters this year, it's still a mechanism to reduce some of that volatility due to conservation and 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 those dead bands 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 bands where, if you look other places in the country, they tend to have the full pass-throughs, and that's something we'll continue to work on.

Those are the three areas of volatility that we see. The industrial customers 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 aligned.

Michael Lapides, Goldman Sachs.

Jim, Maria, a question for you. Trying to think through what's happened in the first half of '09 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.

Maybe we should talk about relative to 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 coal strip outage, which is -- and she'll give you the numbers on this. But the coal strip outage was clearly a one-time item. Boardman, with the new generator installation and the new stator, 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. It's been a consistent good workhorse for us, and it's a low-cost system. That's a one-time item.

Hydros -- 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 are right now in that 2010 budgeting process to see what choices and options we have as we set ourselves up for the 2011 rate case.

Maria, do you want to give the specific numbers?

Sure. So, as we said in our previous conversation, it was about $0.15 on the generation area. It was -- hydro was roughly on a net income basis about $1 million. Colstrip totaled about eight, and Boardman about two.

In terms of the effect of SB 408 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 are 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 SB 408.

I want 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 purchased power and fuel or elsewhere? Do you mind walking through -- you mentioned Colstrip, Boardman and then the SB 408. Walking through the specific line item, do you expect to be negatively impacted in '09?

Sure. So 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 SB 408 effects are on about $14 million. (multiple speakers) and that's on the revenue side.

That's on the revenue side?

Yes.

Got it, I appreciate it, thank you all.

James Bellessa, DA Davidson & Co.

First of all, you had a decoupling mechanism that is on a trial basis starting in February. And I heard it had a minimum impact on the second quarter. Then I heard you say, Jim, 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?

Sure. Let me give you the high points, and Maria can give you the exact numbers and how it works. 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 actual use per customer increased, which was kind of, frankly, a surprise to us. And the only thing we can attribute that to is, because of the recession, more customers are staying home, they are not going to restaurants, they are using more electricity in terms of cooking, they are buying more plasma TVs than we expected, which is kind of a surprise, and we are seeing the installation of a greater penetration of air conditioners.

So all of that has kind of added to the fact that actual customer demand on a residential basis, on a use per customer, increased.

In the commercial sector, we actually did see some reduction in revenues which offset the residential impact, and this was as 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 the big picture as we saw at. And as we put this in place, we looked back to the last recession in 2001 and 2002, were we did see a significant reduction in use per customers by our residential customers. So again, due to energy efficiency and conservation, due to the point where we had high energy prices. So again, we had 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 take away the dis-incentive for customers to do energy efficiency. So first half of the year has worked against us, but we haven't seen the whole year play it out. And we'll watch this through the 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 we still believe it's the right policy decision for our Company and our customers.

Maria, do you want to get the actual numbers?

Sure. 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 $500,000 positive in the first quarter. Jim mentions that they have a two-component part. The 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 million to the good, for the $700,000. As Jim mentioned, residential was up 1.3% on a weather-adjusted basis in terms of their load. The ROE component included $0.8 million or $800,000, getting us to the $1.5 million year-to-date.

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

Jim, 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 resources on load requirements. It may, in fact, be posted on our website. I don't know that, but I would suspect it is. 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 it's 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. So it's a great document and a lot of good information there.

Your rates are based on a 50% capital ratio, but you aren't 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?

We expect to issue debt. We're 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.

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

Yes; I used it to figure up $110 million in terms of PTCs over the next 10 years.

Oh, over 10 years?

Yes.

Production tax credit is based on a generated basis, on certain mils per kilowatt hour of generation. So it goes over 10 years, and it's based on the output of the windfarm. And that would be included in customers' prices that we filed in the RAC filing.

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

So we looked at our alternative cost of capital, how each would flow through the 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 windfarm, which is about 25 years.

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

Was the $110 million for just Biglow II, Phase II?

It's just for those 65 turbines.

Thank you very much.

Jim, 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.

Neil Kalton, Wells Fargo.

Most of my questions have been answered, but I just wanted to get a couple of things straight. I think on 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 a little bit in 2009? Is that included in there?

No, that does not include that.

So would that be an incremental -- how much extra would that be?

So that's roughly -- and this year, it should be an additional $106 million by 2009 and then $172 million by the end of 2010 -- million. And that assumes that prices are roughly where they were at the end of June.

And then one follow-up on pension. It looks like, by my calculations, that it'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?

Yes, you are exactly right. And we are currently in discussions with the OPUC. Traditionally we have received expense or FAS 87 expense and recovery -- or, in rates. 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.

Brian Russo, Ladenburg Thalmann.

Most of my questions have been asked and answered, but 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 $3 million drop in administrative and other. And I'm just wondering if it's being masked by some of these one-time costs that you discussed earlier.

What we tried to do is, once the PUC made a decision, most of those disallowances 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 it's probably across the board and 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 things that we had to incur some additional costs for the maintenance of Colstrip, and we also had an environmental reserve, a small environmental reserve, we had to take. So that's where it is.

Maria, have you got anything more to add?

Sure. 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.

Maurice May, 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 -- how many of these projects are in your five-year CapEx projection at present?

So 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 largely just our base CapEx including hydro, and then we have some of the Boardman emissions, not all that Jim mentioned there. We will wait until the projects are more final and we've finished our IRP process before formally including them into our CapEx plans for the next five years.

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

Sure. There's a big concentration that would take place in 2012, '13 and then '14, which we don't even list in our public disclosures.

Okay, and what might your equity needs be during these years?

So, as we look to target our capital structure at 50% debt and 50% equity, and we are adding significantly new generation, we would then look to the equity markets at that point in time. At this point in time, I think it's 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 Jim outlined.

As a practical purpose, the way we do these is we don't usually put anything in our 10-Q or K in terms of the capitals until they are approved by the Board in terms of the direction we want to go. Boardman is a little different in that because we have a requirement to retrofit that project. But generally, that's the process we use. And it's part of 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 are required as part of that process to make sure we get the lowest cost option per customer.

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

Now, 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?

Well, let's not assume that the market continues the way it's been. Maybe -- you know, we've gone through a pretty heavy economic recession, and I do believe that, at least in another 12 months, we will 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 into 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.

(Operator instructions) Michael Lapides, Goldman Sachs.

My question has been asked and answered; thank you.

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.

Ladies and gentlemen, this concludes today's conference call. You may now disconnect.