Portland General Electric Co (POR) 2010 Q2 法說會逐字稿

Good morning, everyone, and welcome to Portland General Electric Company's second-quarter 2010 earnings results conference call. Today is Thursday, August 5, 2010. This call is being recorded and as such, all lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer period. (Operator Instructions). For opening remarks, I would like to turn the conference call over to Portland General Electric's Director of Investor Relations, Mr. Bill Valach. Please go ahead, sir.

Thank you, Sara, and good morning, everyone. I'm pleased that you are 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, that there will be statements in this call that are not based on historical facts and as such, constitute forward-looking statements under current law. These statements are subject to factors that may cause actual results to differ materially from the forward-looking statements made today.

For a description of some of the factors that may occur that could cause such differences, the Company requests that you read our most recent Form 10-K and Form 10-Qs. The Form 10-Q for the second quarter 2010 was available this morning at portlandgeneral.com. The Company undertakes no obligation to update publicly any forward-looking statements, whether as a result of new information, future events or otherwise. And this Safe Harbor statement should be incorporated as part of any transcript of this call. Portland General Electric's second-quarter earnings were released before the market opened today and the release is available at portlandgeneral.com.

Leading our discussion today are Jim Piro, President and CEO; and Maria Pope, Senior Vice President of Finance, CFO and Treasurer. Jim will begin today's call by providing an overview of the quarter's results and our strategic capital projects; then, Maria will provide more detail around the quarter's results and key regulatory proceedings. Following those prepared remarks, we will open the lines up for your questions.

And now, it's my 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 second-quarter 2010 earnings call. PGE's net income for second quarter 2010 was $24 million or $0.32 per diluted share compared to $24 million or $0.31 per diluted share for the second quarter of 2009. We are increasing our full-year 2010 earnings guidance by $0.10 to $1.40 to $1.55 per share, up from the prior guidance of $1.30 to $1.45 per share. Increased guidance reflects the positive impacts of improved hydro conditions, strong thermal operations and Senate Bill 408. The guidance also reflects the margin impact from a downward revision to the 2010 load forecast. Maria will talk more about guidance later in the call.

Now, an update on our 2011 general rate case filing. I am very pleased with the productive and open dialogue we've experienced during this regulatory process. We are making good progress and have reached agreement on all revenue requirement items, resulting in an overall increase of approximately $52 million in annul revenue. This will cover inflationary cost increases, the effects of reduced loads, new rate-based investments, and provide the Company with the opportunity to earn a fair return on equity. Excluding future updates to net variable power cost and updates to the 2011 load forecast, this represents an approximate 3% overall increase in customer prices subject to OPUC approval.

We've also reached agreement with the parties in the case on several policy issues. We made progress on the power cost adjustment mechanism, resulting in a fixed deadband range of $15 million below to $30 million above baseline net variable power cost, which will not expand as rate base grows. We also agreed on the cost of capital with a capital structure of 50% debt and 50% equity, a return on equity of 10% and an overall cost of capital of approximately 8%.

We extended our decoupling mechanism for another three years and as the operating life of the Boardman plant continues to be evaluated, we agreed on a mechanism that will allow recovery of PGE's remaining investment in the plant, if a decision is made on an early closure. All of these agreements remain subject to OPUC approval, which we expect to occur in December of this year. Maria will go into more details on the case later.

Now, I'll move onto quarterly results with -- and an economic outlook in our operating area. During the second quarter, we saw strong plant operations, specifically at our thermal plants. Scheduled maintenance outages were successfully completed and we are exceeding our performance objectives. In the Pacific Northwest, June's record-setting levels of rain resulted in an improvement to hydro conditions for the second quarter of 2010 compared to the first quarter of 2010. However, when we look at the entire year, energy from hydro resources is expected to continue to be below normal for 2010.

While we experienced customer growth of 0.5% quarter over quarter, overall retail energy deliveries were flat. Cooler temperatures increased residential energy deliveries; however, the continued effects of the weak economy resulted in a decrease in energy deliveries to industrial and commercial customers. Oregon's unemployment rate has eased to 10.5% in June from its peak of 11.6% in mid-2009. Year-to-date, Oregon has added jobs at a rate of 0.5%, similar to the overall US economy.

In light of continued economic pressures in the region, we have reevaluated our load forecast. For 2010, we project that weather-adjusted retail energy deliveries will decrease approximately 1% to 1.5% relative to 2009, a revision from last quarter's load forecast, which was approximately flat. The key factors behind this change are slightly lower than expected deliveries to industrial and commercial customers.

On prior calls, we have discussed our expectations of energy deliveries to paper product manufacturers in 2010 would be lower than 2009, and we continue to be affected by the impact the weakened economy is having on these commodity-based customers. In addition, ramp-up from several of our technology customers has been positive but slower than expected. I'm encouraged to see that the growth of our solar cell manufacturing continues and recently, Solexant announced they will build a new manufacturing plant in our operating area.

Now, an update on our strategic initiatives. Our overall customer satisfaction ratings were very strong in the second quarter. We ranked in the top decile for both residential and general business customers. We also ranked in the top 10% for residential customers in the J.D. Power and Associates 2010 Study. Power quality and reliability directly contributes to customer satisfaction. Entering the second quarter our system operated well. Our distribution metrics remained strong and our generating facilities ran extremely well.

I'm proud that our Selective Water Withdrawal System is operating as expected. Already more than 100,000 migrating fish have successfully passed through the facility. In June, the Selective Water Withdrawal project was honored with the 2010 Edison Award, EEI's most prestigious award, which recognizes leadership and innovation within the industry. These accomplishments are outstanding examples of the great work that my co-workers do every day to deliver value to our customers and our shareholders.

Now, an update on our key projects. At the end of July, our Smart Meter project had approximately 800,000 new meters installed throughout our operating area. A total of approximately 850,000 new meters are expected to be installed by the end of 2010. The budget for the project was increased by $10 million to reflect additional communication enhancements and software development related to business process automation.

We recently announced the good news that the first turbines at Phase III of Biglow Canyon Wind Farm are generating electricity. 24 turbines are currently online with all 76 turbines expected to be completed by the end of the third quarter of 2010. Phase III has an estimated total cost of $390 million, including $20 million of AFDC with installed nameplate capacity of 175 megawatts.

All three phases of Biglow Canyon, when completed, we expect to meet approximately 11% of our load with renewable energy in 2011. This is ahead of Oregon's renewable energy standard first benchmark of 5% by 2011. The next benchmark is 15% by 2015, with a final target set at 25% by 2025. Our strategy for meeting the 2015 renewable energy benchmark is one part of our 2009 integrated resource plan.

The evaluation of the economics associated with putting new emission controls on the Boardman plant is another part of that plan. In April, we submitted a petition to the Department of Environmental Quality, requesting a revision to the existing regional haze rules for Boardman. This [Bar-2] petition called for the installation of certain limited emission controls and then ceasing coal-fired operations by the end of 2020.

In June, the Oregon Environmental Quality Commission voted to deny our Bar-2 petition and directed the DEQ to propose alternatives through a new rule making. The DEQ proposed three new options for Boardman that it believes would meet federal regional haze requirements. The three new options require a different combination of emission controls and would require us to cease coal-fired operations in either 2015, 2018 or 2020. These new options are in addition to the current BART rule that allows PGE to install all controls and operate the plant through 2040 or at the end of life. Details of each of these options are clearly outlined in our Form 10-Q. We believe that these new DEQ options would impose greater cost, price volatility and reliability risks on our customers, and in some cases are not technically feasible.

We continue to advocate for a 2020 time frame with a reasonable level of emission controls as the best path to meet applicable environmental standards at a reasonable cost to our customers while maintaining reliable electric service. We already have a path to resolve all current emission requirements with the existing regional haze rule for Boardman and continued operation for at least the next 30 years. However, it would be unfortunate to lose the opportunity to achieve an even better outcome for our customers and the environment.

We are urging the DEQ to work with us to develop a reasonable 2020 framework, with an appropriate emissions control strategy. We will continue to advocate for a balanced solution for customers and the environment that allows sufficient time to put replacement generation resources in place. It is expected the DEQ will submit a new proposed rule in mid-August with a final rule by the Oregon Environmental Quality Commission anticipated at the end of 2010.

Our integrated resource plan was filed with the OPUC in November of 2009. The proposed 2015 IRP action plan includes meeting approximately 15% of our load growth over the next decade through energy efficiency measures as well as with the addition of the following generation and transmission projects. An additional 122 average megawatts of new renewable resources to meet Oregon's renewable energy standard requirement of 15% by 2015; a natural gas facility to meet additional baseload requirements estimated at 300 to 500 megawatts; a natural gas facility for additional peak load requirements estimated up to 200 megawatts; and a new transmission project called Cascade Crossing.

Recently, we signed a memorandum of understanding with PacifiCorp to officially open discussions on establishing an agreement to jointly develop, construct and own the proposed Cascade Crossing transmission project in Oregon. There is a regional need for more transmission and we have received a lot of interest in this project. This MOU is a positive step in the process.

Upon receipt of a commission acknowledgement of our IRP, we plan to conduct three separate RFP bidding processes, the first for new renewable resources, the second for baseload generation, and the third for peaking generation. In each of the RFPs, we plan to include our own self-build option to compete with the market bids. We expect the RFPs to be completed by the end of 2011 or early 2012.

In April, we filed an addendum to the IRP, which recommended ceasing coal-fired operations at the Boardman plant by 2020. In July, the OPUC revised the timeline for reviewing the IRP, to be more in line with the Oregon Environmental Quality Commission schedule. We expect a final OPUC decision on the IRP by year-end 2010.

Now, I would like to turn this call over to Maria Pope, our Chief Financial Officer, to discuss our financial results in greater detail.

Good morning. Today, I will cover the increase in our 2010 earnings guidance, the quarter's financial results as well as update on our general rate case, and conclude with a discussion on financing and liquidity. As Jim discussed, we are increasing our 2010 earnings guidance by $0.10 to $1.40 to $1.55 per diluted share. The guidance change reflects four key drivers.

First, hydro conditions have improved as a result of the wettest June on record in the Pacific Northwest. We specifically have seen material improvements on the Clackamas and Deschutes rivers.

Second, PGE's plants are operating well. This is primarily due to favorable market prices of both power and gas as well as plant availability, which have provided additional opportunities to economically dispatch our thermal operations. Offsetting these positive factors, we continued to experience the negative effects of the recession. We have reduced our 2010 weather-adjusted load forecast from approximately flat to down 1% to 1.5%.

And finally, the last factor is the positive impacts from Senate Bill 408. Hydro conditions, thermal plant operation and SB 408 each represent approximately $0.05 in earnings per share with the decline in retail margin representing a negative $0.05 for the combined guidance increase of $0.10 per share for the year.

Now, onto second-quarter results. Second-quarter 2010 net income was $24 million or $0.32 per diluted share. This compares to $24 million or $0.31 per diluted share for the second quarter of 2009. Similar to full-year expectations, operating results for the quarter were positively impacted by cooler-than-normal temperature, strong power supply operations and impacts of SB 408, all of which were partially offset by the continued effects of a weak economy.

Retail revenues increased 7% in the second quarter of 2010 compared to the second quarter of 2009. A majority of this increase is related to the return of a former direct access industrial customer to PGE for its energy supply. Additionally, in the second quarter, we continued to see customer growth of approximately 4,000 retail customers.

Total retail energy deliveries were flat quarter-over-quarter. Residential energy sales increased 2.4% due to colder-than-normal weather in the second quarter of 2010 compared to warmer-than-normal weather in the second quarter of 2009. On a weather-adjusted basis, total retail energy deliveries decreased 3.5% quarter over quarter due to the sustained effects of a weak economy. This is a similar trend to what we saw in the first quarter where total retail energy deliveries decreased 3.3%.

In the second quarter, we continued to see energy deliveries to industrial and commercial customers decrease a combined 1.1%. While still down, this is better than first-quarter trends of negative 5% quarter over quarter. In the second quarter, overall customer prices decreased approximately 4%, reflecting a decrease in net variable power costs, partially offset by increases from Biglow Canyon Phase II and the Selective Water Withdrawal Project, which are now in customer prices.

Average variable power costs decreased 7% in the second quarter of 2010 compared to the second quarter of 2009, primarily due to an increase in low-cost generation resources. Fuel expense increased in 2010 due to the increased thermal plant availability coupled with the utilization of PGE-owned generating resources to meet loads. Year-to-date through June 30, total Company thermal plant availability was at 89%. For PGE-operated plants, availability was at 92% versus 84% in the first half of 2009.

Now, more on Hydro. Regional hydro conditions improved significantly over first-quarter expectations due to record-level precipitation in June. Energy received from hydro resources during the second quarter of 2010 was slightly above normal levels versus the 21% below normal we experienced in the first quarter of the year. Due to timing, hydro conditions still negatively impacted our financial performance by approximately $1.2 million pretax in the second quarter of 2010 compared to a positive impact of approximately $1.4 million pretax in the second quarter of 2009. Overall for 2010, we continue to forecast hydro conditions to be below normal.

On the wind side, we continue to see an increase in generation. Wind production provided 6% of PGE's retail load requirement in the second quarter of 2010 compared to 3% in the second quarter of 2009, primarily as a result of Biglow Canyon Phase II becoming operational mid last year.

Now, I'll update you on a few regulatory items starting with our Power Cost Adjustment Mechanism or PCAM. For 2010, the PCAM has deadband ranges of approximately $17 million below to $35 million above the net variable power baseline. Year-to-date through June 30, the net variable power costs were approximately $9 million below the baseline. Net variable power costs for this year are expected to be below the baseline, but within the established threshold. Accordingly, no amount was recorded for a refund to customers as of June 30.

For decoupling, we recorded a collection from customers of $3 million in the second quarter of 2010. This resulted from lower weather-adjusted use for residential and small commercial customers than what was approved in the 2009 general rate case.

50 cap structure. The increase includes a reduction in net variable power costs of $48 million. These power costs and our 2011 load forecast will be updated later in the year before prices are set for 2011. Revenue increases will cover inflationary costs and other cost increases, not offset by savings from smart meters, and our continued focus to reduce expenses and gain long-term efficiencies.

We also agreed to remove several capital projects estimated at approximately $95 million, which are expected to be placed in service mid-year and add to the average 2011 rate base of $3.1 billion. Parties supported the use of deferred accounting from when these capital projects are placed in service. Additionally, we adjusted depreciation expense and other items not affecting earnings.

10 sharing outside the deadband.

While we did not receive approval on all of the adjustment mechanisms requested, parties have reached agreement on recovery for costs associated with their defined benefit pension plan, a provision for cost recovery for future storm damage, an automatic adjustment tariff related to recovery of our remaining investment in Boardman, and continuation of decoupling for residential and small commercial usage, and a lost revenue mechanism for large non-residential customers.

The 2011 rate case, as revised by these stipulations, is subject to OPUC approval. We are currently in the process of aligning our 2011 budget with a revised estimate and assumption. As Jim mentioned, we have been pleased with the constructive process of working together with OPUC staff and customer groups, and a final order is expected by mid-December with new prices becoming effective January 1, 2011.

Now, I would like to discuss Senate Bill 408, a complex tax law. As we discussed last quarter, when differences exist between taxes paid and taxes collected in customer prices, a surcharge or refund to customers is required. A key element in SB 408 is the protection of federal tax normalization rules. As a result, in 2010, due to a significant accelerated tax depreciation, the protection of normalization rules will come into effect, which impacts the calculation. For second quarter of 2010, PGE recorded an estimated collection from customers of $4 million, compared to an estimated refund of $9 million in the second quarter of 2009.

Now, onto financing and liquidity. We are active in the wholesale marketplace entering into forward contracts for natural gas and power to mitigate price risk for our customers. As of June 30, we posted approximately $270 million in collateral with wholesale counterparties, which consisted of $77 million in cash and $193 million in letters of credit.

If market prices remain unchanged and if contracts settle, we would anticipate that 29% or approximately $74 million in letters of credit and $4 million in cash will roll off by year-end and another 46% will roll off in 2011. We have $600 million in revolving lines of credit, of which $387 million was unused as of June 30. At quarter end, we had no commercial paper outstanding or direct draws on the revolvers. During the first half of 2010, we issued long-term debt of $249 million, which completes our debt issuances for the year.

In the general rate case, we forecasted the issuance of $300 million of equity in the latter part of 2011. This issuance is in anticipation of large capital projects in the IRP. I would like to emphasize that the ultimate amount and timing of future equity issuances is dependant on market conditions, as well as PGE's earnings, cash flow, capital expenditures and project timing. Capital expenditures will be affected by the outcome of our IRP process and the result of the RFP competitive bidding process.

We target a capital structure of 50% debt and 50% equity. Periodically, we are higher or lower. As of June 30, our equity ratio was 46.3%. Our 2009 capital expenditures have been reduced and we are estimated to be [approximately] $495 million of capital expenditures for the year of which the Company has already completed more than half. The $495 million of capital expenditures includes $245 million for upgrades to and replacement of generation, transmission and distribution infrastructure; $175 million to complete Biglow Canyon Phase III; $50 million for smart meter project; and $25 million for hydro re-licensing and Boardman emissions controls.

Additionally, to take advantage of tax carry-back opportunities, we plan to make an early pension payment of $30 million in the third quarter, offsetting 2011 and part of 2012 contribution.

In closing, we continue to focus on financial objectives that support our core utility business and growth initiatives, including adequate liquidity to maintain our investment grade credit rating and readily available access to capital markets, while earning a competitive rate of return on our invested capital. Jim?

Thank you, Maria. Our second-quarter results show we are making solid progress on several key projects. Customer satisfaction continues to be high, construction at Phase III of our Biglow Canyon Wind Farm is on time and under budget, and we continue to work constructively through the regulatory process on our 2011 general rate case and the 2009 integrated resource plan, including Boardman. Looking ahead, we will continue to position the Company for future growth opportunities that deliver value to our shareholders and our customers. Operator, we'd now like to open the call for questions.

(Operator Instructions). Your first question comes from the line of Brian Russo with Ladenburg Thalmann.

Hi, good morning.

Hi, Brian.

Hey, you mentioned earlier kind of the timing of the equity issuance and it's kind of towards the latter end of 2011 and it's contingent on the IRP approval. But I thought you mentioned earlier in your comments that the three individual RFP process you hope to complete by year-end 2011 or early 2012. Is the equity offering contingent on completion of that or are there other factors as well like trends you see in your equity ratio from now until then?

It's a combination of both, Brian, but really it's going to be driven by the RFPs and whether we are successful on those projects. And I think that's really the key point here, is that if we are successful in the RFP then we would need to issue equity, and the timing of that would be towards the end of 2011 or into 2012. It appears from the process that we've lost some slippage in terms of the IRP process and the RFP is going to take some time. So things tend to be slipping a little bit, but again it will be dependent on the RFPs primarily.

Right. So we should kind of look for the final RFP outcomes as kind of a signal, as to maybe the timing that you might issue equity?

Yes, and [obviously], we have three RFPs going forward and so each of those will play. If it's just the peakers we're successful in, then maybe we would need to issue equity. If we get the peakers and the baseload generation and also the renewables, then obviously we will need to issue equity. So a lot of it will be dependent on the outcome of that RFP process.

Okay. And then, you mentioned part of the increase in guidance was the result of improved performance of your thermal plants and I think you also mentioned lower cost, lower market prices and I am just curious with the above-average run-off in June, were you able to just not run some of your thermal plants and buy low-cost power to sell to your customers? Just curious how that dynamic works?

The way it works, Brian, is when we see that heavy hydro conditions, we were able to shut down our thermals and take advantage of lower market prices. We also saw a lot of wind during the second quarter and that again allowed us to back off our thermals. Our wind generation was significantly higher than the first quarter. And the combination of good hydro and favorable wind conditions really allowed us to back off our thermal plants and leave them as a backstop for our system. We were able to sell the gas or not burn the coal and keep that in inventory. So that was clearly a factor that helped the second quarter; it's that flexibility that we have in our system that allows us to take advantage of good market conditions.

Okay. And then just lastly, you mentioned some of these new technology-related customers that you're optimistic will start up soon. Is that captured in this 20-year -- 2011 test year rate case sales assumption or will that kind of be incremental to what you guys settled on yesterday, I guess?

The way the load forecast works is we try to continue to update it through the process. We'll do another update based on the September data from the state and so we will continue to watch the economic conditions in Oregon. We do have the opportunity as part of the regulatory process in this general rate case to update the load forecast as well as net variable power cost later in the year.

So we will continue to monitor those customers to see how their plans are advancing as well as the pace of their growth. In many cases, the customers are -- we have the solar companies, SolarWorld and Sanyo and then Genentech, they are ramping up but not ramping up as fast as we had expected, and we will try to get the best information when we update our load forecast to make sure that our prices are aligned with the expected loads for 2011 and so we'll get that opportunity in the September time frame.

Okay, great. Thank you very much.

Thanks, Brian.

Your next question comes from the line of Jennifer Sireklove with McAdams Wright.

Good morning.

Good morning, Jennifer.

There was an article in The Oregonian in July about a sudden surplus of wind power coming out of the gorge in May and so two parts of the question. One, I am assuming the BPA could foresee this shutdown in Biglow Canyon. So I just want to ask if that's true. And B, I am wondering when the -- where the power will come from? To what extent, you will be able to self generate or would you need to go out and buy power? And this also just goes back to the PCAM, it's great that the deadband is fixed, but it's still quite wide, and I am just wondering how you think about forecasting supply and power costs, as your reliance on wind power grows over time?

Great question, Jennifer. I think it is one of the big challenges in the region as we continue to add more wind resources in the region. I think we are close to about 3,000 megawatts total in the Northwest -- Pacific Northwest. And it obviously raises some challenges to Bonneville to try to operate a system with such a variable resource. And it's something we are all working on in the region, looking for ways of storing wind through either pump storage or compressed air or looking at adding peakers to manage the flexibility and the variability of wind.

What happened in June is we did have a tremendous amount of hydro and Bonneville does have operational control to back off wind if there is not sufficient load, if they have constraints on the hydro system. They have certain fish constraints that they need to meet on the hydro system and maintain certain flows. And they are motivated to run that water through the generators as opposed to spilling which causes dissolved gas problems. And so they can back off on wind; that tends to be kind of intermittent. And to the extent they back off wind, that's usually a sign that there is a lot of hydro in the region; that means prices are getting bid down pretty low in the marketplace. And so what we all do in those cases, if they were to curtail us, we would then be able to buy secondary power in the marketplace.

So, usually when that occurs, we are in a situation in the spring where you have lots of hydro and potentially lots of wind, and so market prices are pretty favorable at that point. Sometimes, prices can actually go negative because of the need for wind generators to try to generate to capture production tax credits. So, yes, it has some effect, but not a material effect on the Company. It happens irregularly; it usually happens in the nighttime when we have minimum load problems. As I mentioned earlier, we tend to try to shut down our thermals when you see that coming and try to keep enough wind and hydro on the systems so that we don't have to back down the wind.

As to your second question, we are pretty pleased with the progress we made on the PCAM. We would obviously like to have symmetrical deadbands. We would like to have a little tighter in, but this is a process we need to continue to work through. Many of our hydro contracts are starting to go away. So our exposure to hydro is diminishing but in the same sense, our exposure to wind is growing a little bit and we will continue to work with our customer groups and the regulatory staff and the commission just to talk about how we deal with that variability going forward.

We're comfortable with the progress we made, but this is just a step and a longer process. And as we get more exposure to wind, we are going to have to work with the regulators on kind of what is the average wind generation look like, as well as what is the average hydro look like. So we will continue to work on this project and it is a longer-term plan but we're pleased with the progress we've made to date.

Very good. That's helpful, thank you.

Thank you.

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

Hi, good morning, guys. A question on the electric output data for the Pacific Northwest seems to be pretty weak. Wondering your sales outlook, does it include July? And then, could you go over your customer exposures? What do you expect for commercial/industrial in the second half? And then what portion of that 4% commercial decline is covered by your decoupling mechanism? Thanks.

Okay. Let me take the high level and let Maria get into more of the detailed numbers. We have seen weakness in the economy. When you look at our industrial customers as a group, about half are up and half are down relative to their forecast. And in many cases, it's just a slower pace of growth than we had anticipated. Others have just kind of trimmed back as we are highly dependent on manufacturing and they have trimmed back a little bit of their production. Kind of on the bright side, Intel continues to operate and be strong as a customer of ours. Nike has done well; Genentech and the solar companies continue to grow, albeit at a slower pace. So those have all been positive signs. And as we mentioned, the commodity businesses have struggled a little bit, primarily in the paper and steel side.

On the commercial side, the weakness has been -- it's just a secondary impact of a slow economy where our -- the population isn't going out and buying as they previously had when we have seen a recovery, and so it has been slow.

We do have, as I mentioned earlier, the opportunity to update our load forecast to reflect those changes, that will hopefully put us in a good position to allow us to recover our cost in 2011, and we'll continue to watching that. There was a report out from Tim Duy from University of Oregon. It seems to indicate a softness in the Oregon economy, but our State Economist, Tom Potiowsky, still believes that we will see a slow growth in 2011, albeit we've taken a little bit of pause here. Maria, do you want to kind of go into the numbers and the decoupling issues?

Sure. Just for a perspective, if you look back on the first quarter of the year, we were down in all segments, residential, commercial and industrial. And industrial was down quite significantly at about 6%. Industrial in the second quarter was almost flat where it was second quarter last year. Residential continued to decline and then also commercial was slightly worse. So, it's that improvement in industrial that we were pleased with in the second quarter. On average quarter on quarter, each of the quarters was fairly similar in terms of where they were versus last year.

If you remember last year, it was for the June-July time period where our industrial and then later commercial customers began to take a much more significant downturn in their load. And residential actually held up all the way until really the first quarter of this year.

For the latter half of the year, we are forecasting residential to be roughly flat with last year and commercial to be roughly flat and then industrial to have a slight improvement for a combined, down on the full year of 1% to 1.5%. Not all of this will affect our bottom line. We do have the decoupling mechanism which covers all of our residential and our small commercial for about 60% of our customer base in total.

But not all the commercial is covered by it, just the very small commercial -- so a very small piece of the commercial reduction is covered through decoupling.

Okay, thank you.

Thank you.

Your next question comes from the line of James Bellessa with Davidson and Company.

Good morning.

Good morning, Jim.

On the Cascade Crossing transition line, can you give us some highlights of what that might look like, how many miles, what kind of [pullable] feature you might install, what might be the cost, what your partnership splitting might be or how much do you think you can handle yourself?

Okay. A good question, Jim. We have decided to go forward with at least at this point in the planning phase a double circuit line which could have a capacity of up to 2,500 to 2,700 megawatts. So that's a -- we have decided that that's a good move because of the need for regional transmission. PacifiCorp has indicated an interest for about 600 megawatts of that capacity and we are in the conversations with them on trying to reach a definitive agreement on a partnership, where they can own that share of the project.

We are also in conversations with other potential partners that we can't disclose at this point but hope to find some additional partners. Besides that, we have had a number of interconnection requests from generators who would like to interconnect in the system, which again is a positive sign for us. In terms of the project itself, it's a little over 200 miles, a double circuit line through an existing right-of-way -- major portions through an existing right-of-way and the cost is in there. I think around $825 million assuming all phases of the project are completed.

So those are preliminary. The construction time frame is in the 2013 to 2016 time frame, but as you can imagine, we have to get through all the permitting and licensing phase of that which we're working on right now. It is important to get a partner on this project and we are pleased that PacifiCorp has entered into the MOU for those conversations. As you know, they have a load in Southern Oregon that they need to serve and this would allow them to move power into that service territory.

So we are making good progress on the project. We have a long way to go to get to the finish line. We have not yet got full approval to move forward on the project. We are still in the licensing phase and until we get licenses secured and permits gained and final ratings for the projects, it's still in the planning stage.

And what kind of return do you get? What's the state's view of receiving incentive compensation for transmission?

A lot of it will depend on how the ultimate structure of the line is. If it's a FERC-regulated line, it would go under FERC jurisdiction. Typically, our transmission has been used to serve retail load only and so then it gets regulated as a retail rate-based investment in Oregon -- in our Oregon rate base. So depending on the final structure of the line and how it's ultimately developed, it will either be under FERC regulation which at this point gets a premium return on equity or it could be under Oregon jurisdiction if it's just fully used for Oregon customers. And that's something we continue to look at as we move forward to determine what is the appropriate place to regulate that line and a lot of it will depend on the structure that we end up with and that's still in the preliminary conversations. But I think for your purpose, at this point, you should just assume a regulated, a rate-based item in Oregon.

And the Eastern Terminus of this is near Boardman, is it?

It will start -- actually, it starts at Coyote Springs which is northeast of Boardman, a few miles, like at 40, 50 miles, I think -- maybe less than that -- 20 miles. It will pick up Coyote Springs, it might interconnect with the Idaho line that comes from Idaho, and then it will go through Maupin and then into the Salem area which is the southern part of our system. So that's the line and that's the route that we are looking at and that's the preferred route. The good thing about this, it will create some diversity of transmission. Right now, all of the transmission tends to go up the gorge. So it's going east to west and so this will clearly provide some diversity and some reliability value to our system which is we add more and more wind resources is critical for the region.

And you've been considering I think in your Boardman some gas-fired facilities; is it tying into those and --?

Yes, we have that project called Carty, which we are planning for as a potential self-build option in the RFP. A Carty would be a -- we're citing it as a two-unit gas-fired baseload generation unit. The first unit would be bid into the RFP as part of a self-build option. The second unit is at this point a backstop for Boardman, a contingency, if you will, if in case we have to close Boardman down earlier.

We are looking at two routes for Carty; we're looking at both Bonneville transmission as well as Cascade Crossing. So we still haven't made a final decision and until we get a final determination on Cascade, we want to keep our options open for transmission. So we could either interconnect Carty with Bonneville or we could connect Carty into Cascade Crossing.

Thank you very much.

Thanks, Jim.

Your next question comes from the line of Chris Ellinghaus with Wellington Shields.

How are you?

Good morning, Chris.

Jim, just as you are mentioning Carty, could you just go through -- Carty 1 is part of the IRP, is that correct?

It would be a self-build option to meet the baseload generation in the RFP as part of our IRP. So it will be bid in as a self-build option for baseload generation.

Okay. I just want to clarify Carty 2 is the Boardman replacement option?

It's a backstop for Boardman and we have yet to determine how if Boardman has an early closure, whether we would have to go through an RFP or we would just move quickly to use Carty 2 as its replacement resource.

Okay. And would that be a similar scale to Carty 1?

Yes, we are citing the -- cited the 900 megawatt dual fired -- a dual unit site. So, yes.

Okay, all right. And as part of -- the whole Boardman issue is very confusing from -- to see on the outside; I can only imagine what it is like for you.

Yes.

Can you give us some more clarity on how you view the situation?

Well, right now, in the -- we are waiting for DEQ to issue a proposed final rule. They have given us some proposed rules that we don't find either financially viable for our customers or technically feasible and so we are hoping to work with the DEQ to come up with a 2020 plan that is cost effective for our customers, yet still meets the environmental needs that the DEQ feels like are appropriate for the project.

And we'll have to wait to see whether the DEQ-proposed rule kind of finds that midpoint. If we cannot find a reasonable midpoint, the 2020 plan that could meet both the economic and environmental needs of our customers, we will be faced with an early shutdown in 2015, which we think puts significant risks on our customers, or moving forward with an acknowledgement for the 2040 plan, which is put all of the emission controls in place. And that's where we've been from day one is we think the 2040 plan is the best plan from our customers, if we only have those two options, 2015 or 2040.

So we are hoping to find this interim closure plan on coal in the 2020 time frame that allows us enough time to replace Boardman but still meets the environmental requirements and that is cost effective. So, that's kind of where we are. We'll see the DEQ proposed rules in mid-August. They may not get published by the Secretary of State till early September, but that's an important milestone in the project, which will set the kind of the stage of where we go next with the Boardman facility.

Is it starting to feel like Carty 2 is becoming more and more necessary and maybe on a faster timetable than you had originally planned?

It's hard to do it much faster than what we've got on our drawing boards. I mean, I think right now, Carty 1 is planned for in the 2014 to 2016 time frame. We need to get that unit built because we're still significantly short to the market, assuming that's successful in the RFP and then we would follow on with Carty 2. So we're looking at Carty 2 in the 2018 to 2020 time frame to get that project completed just given that we haven't got turbines lined up.

There is a lot of uncertainty of when those projects will exactly come online because we really haven't got into equipment suppliers and found out what the lead time is for our equipment. So, we clearly want to cite that as a two-unit site, so we have a backup. If we lose Boardman, we will be significantly short to the market probably in the sense of something like 40% short and that's the place we're not comfortable as a Company. And so we really do need to have a backstop to protect ourselves and be sure that we can provide electricity to our customers.

Sure. Maria, do I recall correctly in the first quarter that SB 408 was neutral to earnings?

Yes.

Okay. And have you got any kind of color on -- you've said that you expect hydro for the year to still be below normal, but how do you see particularly after July where the backend of the year looks?

Sure. We are looking for [obviously] positive impact in Q3, and Q4 is really quite unknown. Right now, we're just calling it about normal.

Okay. But part of your guidance is a pretty significant swing, how your expectations for the third quarter have changed?

Sure. It would also be the second quarter expectations came in quite different from the first quarter.

Okay. All right, thanks a lot.

Thanks, Chris.

Thank you.

Your next question comes from the line of [Igor Grinman] with Zimmer Lucas Partners.

Hi, guys.

[Hi, Igor].

Hey, a bit of a follow-up on the equity needs. I know that it's a bit early and that you are waiting on the RFP results on the RFPs, but given the recently signed MOU with PacifiCorp on the Cascade Crossing line and I guess you guys are seeing some more interest from other parties, could that potentially alleviate your future equity need in '11, '12 time frame.

Yes, Cascade Crossing wouldn't be built from 2013 to 2016 time frame. So we are a long way from actually having to raise capital to fund that project, clearly having partners -- which we have always anticipated we would try to get partners in that project. Clearly having a partner would reduce the capital requirements of the project. And that's something we have assumed kind of day one that we would try to find a partner for that project because we didn't think we could take the whole project ourselves. So we really do want to get a partner. But in terms of the 2011-2012 equity needs, Cascade Crossing really doesn't factor into that decision.

Okay. Thanks, guys.

(Operator Instructions).

Okay, I think that ends the call. So, we appreciate your interest in Portland General Electric and invite you to join us when we report on third-quarter results in the third quarter 2010. If you have any additional questions, please contact Bill Valach who will be available after this call. Again, thanks for joining the call.

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