Portland General Electric Co (POR) 2011 Q4 法說會逐字稿

Good morning, everyone, and welcome to Portland General Electric Company's fourth-quarter and full-year 2011 earnings results conference call. Today is Friday, February 24, 2012. 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 over to Portland General Electric's Director of Investor Relations, Mr. Bill Valach. Please go ahead, sir.

Thank you, Ann, and good morning, everyone. I'm pleased that you're able to join us today.

Before we begin our discussion this morning, I'd like to make our customary statements regarding Portland General Electric's written and oral disclosures and commentary. There will be statements in this call that are not based on historical 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. And the Form 10-K for 2011 is available on our website at portlandgeneral.com. The Company undertakes no obligation to update publicly any forward-looking statements, whether as a result of new information, future events, or otherwise. And this Safe Harbor statement should be incorporated as part of any transcript of this call.

Portland General Electric's fourth-quarter and year-end earnings were released before the market opened today, and the release is available at our website, 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 presentation by providing a general overview of the year's results and our strategic capital projects. Then Maria will provide more detail around the quarterly and annual results and key regulatory proceedings. Following those prepared remarks, we will open the lines up for your questions.

And with that, it's a pleasure to turn the call over to Jim.

Thank you, Bill. Good morning, and thank you for joining us.

Welcome to Portland General Electric's2011 fourth-quarter and year-end earnings call. I'm very proud of our accomplishments in 2011. We effectively managed our power supply operations, taking advantage of positive regional hydro conditions; successfully upgraded our Boardman and Coyote Springs thermal plants; received final regulatory approval of our Boardman 2020 plan; saw the repeal of Senate Bill 408; and with the constructive outcome of our 2011 general rate case, we delivered a competitive return to our shareholders. Operating performance was also strong during 2011, with our transmission and distribution system performing well, good generation plant availability, and high levels of customer satisfaction. This reflects our ongoing focus on operational excellence, and strong customer service.

On today's call I'll summarize our financial performance, initiate 2012 earnings guidance, and update you on Oregon's economy. Then I'll discuss the progress we're make on our strategic initiatives. Following my remarks, Maria will discuss fourth-quarter and annual results, several regulatory items, financing and liquidity, and end with our outlook for 2012. So let's begin.

PGE's net income for fourth-quarter 2011 was $29 million, or $0.38 per diluted share, compared with $25 million, or $0.34 per diluted share for the fourth-quarter 2010. Net income for 2011 was $147 million, or $1.95 per diluted share, compared with $125 million, or $1.66 per diluted share for 2010. For 2012, PGE is initiating full-year earnings guidance of $1.85 to $2 per diluted share. 2012 guidance assumes hydro, wind, and plant operations consistent with the estimates in the annual power cost update tariff, as well as a relatively flat operating cost. Also included in guidance is low growth between 1% and 1.5% over weather-adjusted 2011 loads, excluding the loads of two large paper manufacturers.

Now let's move on to the economic outlook in our operating area. We continue to experience customer growth, and we're pleased to see a decline in Oregon's unemployment rate, which fell nearly 2% from 2010 to 8.9% at the end of 2011. Job growth in Oregon was faster than the national average in 2011, 1.6% for total non-farm jobs, compared with 1.4% nationally; and 2.3% for the private sector, compared with 1.9% nationally, as Oregon continues to be an attractive location for technology, manufacturing, and other industries.

With continued in-migration and increased employment activity, total retail energy deliveries on a weather-adjusted basis increased approximately 1.4% in 2011 compared with 2010. Excluding the loads of two large paper companies, weather-adjusted retail energy deliveries for 2011 were approximately 0.005% above 2010 levels. Both of these percentages includes the effects of energy efficiency measures, which reduced load growth by approximately 0.005% between 2010 and 2011. IHS Global Insights expects an improvement in the US economy in 2012; and in Oregon, we expect to follow that trend. We are monitoring all industrial sectors in our operating area to understand the economic factors impacting their businesses.

Now, I'll give you an update on our strategic initiatives, starting with operational excellence. We continue to deliver excellent operating performance Company-wide. Our overall customer satisfaction ratings remained strong in 2011. We ranked in the top decile for general business customers, third in the nation among large key customers, and in the top quartile for residential customers. In addition, our system operated extremely well. Our distribution reliability metrics remain strong and generation plant availability was high. We also made good progress in meeting Oregon's Renewable Energy Standard. In 2011, qualifying renewables supplied approximately 10% of our load requirements, double the 5% requirement for the year. Moving forward, we will continue making improvements focused on streamlining operations by leveraging technology and refining work processes. Our goal is to reduce the cost of service we provide to our customers, while maintaining high levels of customer satisfaction.

Now let me update you on our progress in executing our IRP action plan. Our 2009 IRP action plan was acknowledged in November 2010, and we filed an informational update in November 2011. This update outlined changes in the external environment and updated our load forecast, our natural gas forecast, and the cost of new resources. It also provided a progress report on the implementation of our action plans, including the Boardman emission controls upgrades, Cascade Crossing Transmission Project, and the RFPs for new generation projects. The updated plan supports the Company's need for additional energy, capacity, and renewable resources, as outlined in the 2009 IRP action plan.

Last month we filed a draft combined Energy and Capacity RFP with the OPUC. The combined RFP allows self-build benchmark proposals, and offers bidders the option to build on PGE's benchmark sites with two conditions -- first, the plant would be built to PGE specifications; and second, given permitting and land issues, the plant would be owned and operated by PGE. We expect the Capacity and Energy RFP process to be completed in late 2012 or early 2013. We are still in the process of completing a draft of the Renewable RFP, which we plan to file later this year.

Now let me provide you an update on Boardman. Last year, we successfully installed two emission control systems at our Boardman plant. The low-NOx burners reduced nitrogen oxide emissions by 50%, and the mercury controls meet Oregon's stringent standard for mercury emissions. In December, the EPA issued its MACT rule, and, based on our full0scale testing results, the plant should be in compliance with the rules once all the controls are installed. We are moving forward with the installation of the dry sorbent injection system to go into service in 2014 to control sulfur dioxide.

In regard to our Cascade Crossing Transmission Project, PGE and Bonneville Power Administration have established a framework for definitive agreements that would allow the project to move forward. We are on track to file a preliminary application for site certification with the Oregon Department of Energy within the quarter. System planning and environmental studies, along with preliminary design engineering, are all moving forward. We expect to receive permits in 2014, and the in-service date for this project is expected to be late 2016 or early 2017.

Now I'd like to turn the call over to Maria Pope, our Chief Financial Officer, to discuss our financial and operating results in greater detail.

Thank you, Jim.

Today I'll cover results for both the quarter and the year, provide an update on key regulatory items, discuss liquidity and financing, and conclude with our outlook for 2012.

As Jim noted, net income for 2011 was $147 million, or $1.95 per diluted share; compared with $125 million, or $1.66 per diluted share for 2010. Operating results for the full year were positively impacted, but increased sales due to cooler weather and strong power supply operations, driven by favorable hydro conditions. Higher loads contributed $0.07 per share, and strong power supply operations added approximately $0.13 per share, net of the power cost adjustment mechanism, or PCAM, refund. These gains were partially offset by several items outside of the PCAM, which totaled $12 million on a pre-tax basis, reducing earnings per share by $0.10. These items, which were approximately $3 million each, included an expense related to the order on our 2012 annual power cost update tariff, lower than expected investment returns on our non-qualified benefit plan trust assets, increased employee compensation and benefit expense, and several other items.

Now, I'd like to provide further detail on energy deliveries and retail revenues; first, for the fourth quarter, and then for the year. For the fourth-quarter 2011, total retail energy deliveries were unchanged from the fourth quarter of 2010, both on an actual and weather-adjusted basis. Excluding cooler temperatures, energy deliveries to our residential customers increased 0.7%. Commercial deliveries were unchanged; and industrial deliveries, excluding paper manufacturers, decreased 1%.

Fourth-quarter 2011 retail revenue increased 7%. This was primarily due to a $24 million increase in average retail prices and a $10 million increase related to several regulatory items, including the reversal of a collection in the fourth quarter of 2010 under SB-408, Oregon's now-repealed utility tax law. For the full year, retail energy deliveries increased 3% over 2010. On a weather-adjusted basis, load growth was 0.5%, excluding two large paper manufacturers. Energy deliveries to our residential customers increased 0.2%, commercial deliveries increased 0.4%, and industrial deliveries increased 0.7%. For the full year, retail revenues increased $58 million, or 3%, from 2010, due to higher total retail energy deliveries and an increase in average retail prices of 4%.

Now, I'll move onto power costs. For the fourth-quarter 2011, purchased power and fuel expense was flat over the fourth-quarter 2010. For the full year, purchased power and fuel expense decreased $69 million year-over-year, due to a 9% decrease in average variable power costs. Hydro conditions in the Northwest were above normal in 2011. Energy received from PGE-owned and contracted hydro resources was approximately 13% above normal for the year. Energy from these projects also increased 14% in 2011 compared to 2010, providing approximately 25% of the Company's retail load requirement for the year.

Energy from the Biglow Canyon wind farm increased 46% year-over-year, primarily due to the completion of Phase III in August 2010. Biglow Canyon provided 6% of our retail load in 2011, compared with 4% in 2010. However, wind generation was below projected levels, which was offset by favorable hydro conditions and low cost purchased power. With abundant hydro conditions in the Northwest, wholesale market prices were low, enabling PGE to economically displace a significant amount of our thermal generation with wholesale power purchases. As a result, thermal generation, which operated at 93% availability, supplied 29% of the retail load in 2011, compared with 44% in 2010.

For 2011, the PCAM dead-band range was $15 million below to $30 million above the baseline for net variable power costs. PGE refunds or collects 90% of power costs outside of this range, subject to a regulated ROE earnings threshold. Total net variable power costs were $34 million below the baseline of 2011, resulting in a potential customer refund of $17 million. However, the regulated earnings threshold of 11% reduced this refund to $10 million. In 2010, actual net variable power costs were $12 million below the baseline, and within the lower dead-band range, so no refund or collection was recorded.

Now, I'll cover decoupling and expenses for 2011. As PGE's weather-adjusted loads will vary costs due levels forecast in the 2011 general rate case, only a small refund was recorded for the year on the decoupling mechanism. Overall, operations in maintenance expense in 2011 increased by 16% over 2010, and was in line with levels forecasted in the 2011 general rate case. The primary areas of increase include production OEM expense for the Boardman and Coyote Springs upgrades; information technology expense, as we replaced aging systems; and distribution expense related to ensuring safety and reliability. PGE's effective tax rate for 2011 was approximately 28%, compared with 30% for 2010.

Now, onto financing and liquidity. We continue to be active in the wholesale marketplace entering into forward contracts for natural gas and power, to mitigate commodity price volatility for our customers. As of December 31, we posted approximately $184 million in collateral wholesale counterparties, which consisted of $80 million in cash, and $104 million in letters of credit. As contracts settle, and if market prices remain unchanged, we anticipate that two-thirds, or approximately $120 million of collateral will roll off by the end of 2012, with another $45 million rolling off in 2013. We now have $670 million in revolving lines of credit, an increase since the third quarter, as the new $300 million five-year revolver was completed in the fourth quarter. Total available credit at the end of the year was $516 million. In December, we redeemed $63 million of first mortgage bonds, which brought our equity ratio to 49%, very close to our target capital structure of 50% debt and 50% equity.

Now, I'll discuss our outlook for 2012. As Jim discussed, we are initiating earnings guidance of $1.85 to $2 per share. This guidance for 2012 is based on a load forecast of 1% to 1.5% over 2011 weather-adjusted results, excluding the load to large paper manufacturers. Our load forecast assumes growth of approximately 0.05% for residential customers, and 1% to 1.5% for commercial customers. Key assumptions include Oregon employment growth of about 1%, modest population growth, and some improvement in overall economic conditions. Industrial customer demand is forecast to grow approximately 3%, driven by high tech companies and their suppliers' growth and expansion plans. In particular, Intel's new large Fab, D1X, is expected to come online late this year and ramp production over the next several years. We also expect growth from new data centers and other industrial customers expanding their operations.

Our guidance assumes normal plant operations. In addition, to hydro and wind conditions consistent with levels forecast in our 2012 annual power cost update tariff. Given our focus on Company-wide cost reductions, operating and maintenance expense is expected to remain relatively flat, which includes an increase in pension expense. 2012 pension expense is expected to be $13 million, compared with $5 million for 2011, and included in customer prices. Our 2012 guidance also includes a deferral of approximately $17 million related to four capital projects, totaling approximately $100 million. These projects are not yet in rate base, as they were not completed at the time of our last rate case. ¶ The costs associated with these projects can be deferred when our regulated ROE is 10% or below. In 2012, we expect capital expenditures to be approximately $330 million. This forecast does not include projections for the construction of capacity, energy, or renewable projects, as the RFP processes are ongoing. As such, no new debt or equity issuances are currently projected for 2012.

In closing, we continue to focus on financial objectives that support our core utility business and growth initiatives, including improving our ROE and earnings performance, and maintaining adequate liquidity and strong balance sheet to support our investment-grade credit ratings.

Jim?

Thank you, Maria.

Our fourth-quarter and full-year 2011 performance reflects our continued focus on operational excellence, high customer satisfaction, and delivering a competitive return for our shareholders. As we move forward with the implementation of our IRP action plan, we will continue to position the Company for future investment opportunities that deliver value to our customers and our shareholders.

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

Thank you very much. (Operator Instructions) We'll take your first question from Neil Mehta with Goldman Sachs.

Can you talk us through the RFP time lines for gas and wind? When are the next major milestones, and when can we expect a final outcome?

Okay, let me take you through, generally, the schedule. We have not had a pre-hearing conference yet to tie down the schedule precisely, so we don't have exact dates. But we did file the draft RFP with the OPUC on January 25 of this year. We are now working on a schedule. Our plan generally is that the OPUC would render a decision in June of this year, at which point we would start the RFP. The hope would be we would identify the final short list by the end of this year and complete negotiations, depending in the outcome of the bids, early next year.

So that's the general schedule we have in place. It's been filed. We're getting comments back at this point. We've got to get a schedule tied down, so things are progressing nicely. I think we've responded to many of the questions the Commission raised in our capacity RFP, so hopefully this process will go relatively smoothly.

Got it. And then timing around the next rate case filing, is the plan still to go in '13 for '14 implementation with more of an O&M type of case and then tackle more of a capital rate base case later?

We're still looking at the data, and obviously it's depending on load growth. We do have a pretty significant capital project going in during 2014. That's our dry sorbent injection system that will go into service probably mid in 2014 with a fair amount of chemicals that will have to go in and be included. So we are looking at 2014 as a likely rate case, but we're looking at options that we could investigate to work around that to deal with some single issues. So right now, we're tending to focus on 2014. We would file in early February or late February of 2013 if we go forward with that. So we continue to look at the numbers. A lot of it will depend on load growth and whether we can address some of the single issues that we have that are causing some challenges.

All right, Jim, and my last question is on load growth. I guess demand forecast a bit lighter than the long-term 1.7% or 1.9% you've talk about historically for next year. Can you talk about part of what's driving the delta and whether you think the 2012 run rate is the right long-term run rate?

I'll have Maria address this in more detail, but as I look at it, the big challenge for us is we really haven't seen much in the residential sector. Starts are down, new connects are down. That's been where it's been soft, even though we are seeing continued in-migration. We're starting to see some construction in multi-family space as rental vacancy rates are at historic lows here. So we are starting to seeing a number of developers being interested in development a multi-family. The foreclosures are starting to work through the market, and that will eventually unseize the residential market. And so I think we're starting to come out of this slow down, and it's going to be driven by our commercial customers and their growth that we see out there. Maria, do you want to add anything more to that?

Sure, for the past quarter, we saw a slight downturn in smaller industrial customers, but for the year, we were just over 1% growth in the industrial area. And as Jim mentioned, the commercial and residential areas for 2011 lagged at 0.2% and 0.4% growth, respectively. Much of that was still due to the economy. For the net coming year, we're expecting slightly higher residential growth, but a particular pick-up in the commercial area, as we're seeing increased signs of employment in Oregon. Last year Oregon had some of the highest growth in employment across the country. In fact, I think we were second, and we expect to have probably about a 1% growth forecast for employment, which would directly impact the commercial area.

Our big swing for 2012, actually is in the industrial area, where we're forecasting about 3%. As we mentioned, there's quite a bit of growth going on with one of the largest fabs in the world being built in our service territory by Intel. And obviously a number of their suppliers are expanding as well. We're also seeing a couple data centers come into our area, and then Boeing and other industrial companies are reinvesting in their operations. So we feel pretty good about our outlook.

Operator. We'll take our next question from Brian Russo with Ladenburg Thalmann.

Just could you elaborate on the $0.10 per share expense item for the 2012 AUT?

Oh, I think what you're referring to is our deferral of capital in -- as part of the 2011 Rate Case. We had not completed about $100 million of capital projects, is that what you're referring to?

He's talking about the AUT.

$12 million pre-tax, $0.10 per share item related to additional expense from the OPUCs adjustment on 2012 annual power cost update.

That's composed of a number of items. Maria will give you the details, but one of those items was there was a $2.6 million adjustment in our AUT filing for 2012. That came about as a very interesting conversation in our filing around the mid-term strategy and how we buy power long-term. And the Commission went through a very exhaustive investigation of our mid-term strategy. And our mid-term strategy is how we purchase power, both energy, electric energy, as well as natural gas on a long-term basis to reduce the volatility of our customer's prices. We went through a very long discovery process. At the end of the day, the Commission agreed that our mid-term strategy was prudent. They did find some documentation lacking in some transactions in 2007. And they ultimately decided to give us a small adjustment to reflect the need to do better documentation, and that was about a $2.6 million adjustment. And that's for 2012, but based on the accounting requirements, we booked that in 2011. There's other numbers included in that, and Maria can give you the detail.

Sure. So the -- a number that you're referring to is $12 million of pre-tax items, or about $0.10 a share. And these were outside of our power cost adjustment mechanism and so they directly fell to the bottom line versus affecting the power cost calculations. And they include the amount that Jim mentioned for $2.6 million, as well as under performance in our non-qualified benefit plan trust assets, which is a result of market performance with those investments. We also had some higher benefit costs and incentives, and then a couple other miscellaneous one-time items that are non-recurring.

Okay. So this $0.10 is non-recurring?

Yes.

Yes.

And almost considered one-time, and you guys would have earned $2.05 without it?

Yes, there would have been some adjustments. The PCAM also factors in there, but you can essentially say it's one time.

Yes. Except for the piece on the incentives, because as we do better, we budget at expected levels, and because we don't get full recovery of our incentive in customer prices, that would have still been there on a recurring basis. To the extent we do better than our forecast, then there is some additional upside on incentives.

Okay, and then just why do you exclude the two large paper manufacturers from your industrial load growth, and what would growth be if you included that?

Maria, why don't you take that one.

Sure. The two customers that we're talking about have very large loads. One actually doesn't exist anymore, and the other one is also financially troubled and is in Chapter 11. Their uses is very volatile, and also we get very little margin from these businesses, as it doesn't -- they buy either direct from the market or are not included in our margin. So we would have seen probably about 1.4% load growth instead of the 0.5% that we saw without them.

So the real key point here is they really just take at the market. We charge them a small margin. They buy opportunistically when prices are low. We just act essentially as a marketing agent for them. And so they're very volatile in their usage, depending on what happens in the power -- the paper market.

Right. I understand. So the 1% to 1.5% load growth you're forecasting for '12, if you included the large -- the two large paper manufacturers, growth would be even higher than that, although the margin impact is minimal?

Yes, it actually, because one of them no longer is operating, it probably would be lower.

Okay.

And I think it's very hard to project with their financial situation.

For the second one.

Yes, for the second.

Okay. Great. You mentioned earlier the $100 million of cost deferrals due to the 10% or below ROE. I guess that implies that you're going to earn below 10% in '12. I'm just curious, in the midpoint of your guidance, does that assume a 9% regulated equity ROE?

No. First of all, let me just clarify. The $100 million is capital that we've spent that we can pull the revenue requirements in if we're at 10% or below. So the guidance that we have, you're correct. It's about a 9% ROE at the mid point. However, what we're showing is that we normally have a lag between our regulated and our accounting ROE, and we've said that's somewhere in the neighborhood of 1% or so.

Okay. And what's the tax rate to use for 2012?

We've historically had a tax rate between about the 26% to 30% range. This past year's tax rate was about 28%. So I would use some of the historical averages.

Yes. I think the challenge you have there, Brian, just to be aware, a lot of that lower tax rate is due to production tax credits. So on the margin it's closer to 30-- what, 38% or something like that, 35%.

Probably 35%.

35%.

And depending on how the wind blows and the production tax credit, our tax number can jump around.

Right.

We'll go next to James Bellessa with DA Davidson & Company.

All right. Say, on the tax issue that was just addressed, in the most recent quarter, the tax rate was higher than I had expected. You had been running down in the 24% to 29%, and then all of a sudden, it jumps up to almost 36%. What caused that fourth quarter jump?

A lot of that was the production tax credits. And if you look at the prior year's tax trends, Jim, they were actually very similar as well. A lot of the items that we do, we target the end of the year, but then we do very thorough true ups as we get to the end of each year.

Okay. And then you're talking about in your guidance, you're assuming normal hydro conditions, but you had one the best hydro conditions ever this last year, 2011. So how much did it add to EPS?

Well, again as you know, the hydro as well as our plant operations all go through the PCAM. And the PCAM has the earnings test that goes into that. And Maria can give you more detail, but we did have a very good hydro year last year, which resulted in a refund for customers. So the mechanism worked as we expected, and so we did get some benefit because we got up to the 11% ROE and a refund for customers. Maria, you want to go into the particulars?

Sure, this gets into our overall outlook for '12, but as we look at the impact of hydro and then unusually low power prices in the Pacific Northwest due to all the hydro, netting out the refund to customers that Jim mentioned, it was a benefit of about $0.13. We're seeing the additional impact we had from cooler-than-normal weather, is offset by our expectations of higher loads. And then as I mentioned, we have these deferrals, Jim, which is at about positive $0.15 for the coming year. We are projecting flat O&M and compensating for higher pension costs and other healthcare-related items with cost savings in each of our operating areas. So that's essentially how you get there.

Jim, just to give you a perspective, right now, we're slightly below normal for hydro forecast this year in the Northwest. But again, it's still relatively early, and we can still see some significant moisture and snow even into March. So it's still too early to call how the year's going to play out, but right now, we're just slightly below normal across the Northwest.

So we talked earlier, that the $1.95 could have been adjusted up by that $0.10 per share one-time items, but then we need to subtract out $0.13 for favorable hydro versus normal hydro conditions, would that be fair?

Yes.

Then, you just mentioned deferrals for $0.15 for 2012. I didn't catch what that was about, would you go through that please?

Sure. As part of our last rate case, we had capital projects totaling approximately $100 million, and these four projects were not completed at the time of the case. So we get them into customer prices, or the revenue associated with that capital into customer prices, when we're at a 10% ROE or below. And we're expecting to be able to include the majority of that or about $0.15 per share due to that capital spending.

So that's an add in 2012?

Yes, it is.

Okay. Then deliveries -- they were touched upon earlier, and you said that one of the paper companies was defunct, and the other one was not operating efficiently or very often. Was there any adds to deliveries, industrial deliveries, during 2011 from those two plants?

Yes, there was from 2011. If you take them out, as we noted, our forecast would have been in total an increase of about 0.5%. And if you include them, it was about 1.4%. But as Jim mentioned, they have virtually no impact on margin, because they're essentially buying power at market, and we're acting as a delivery agent for them and getting just compensated for that.

Now when you talk about 0.5% excluded, 1.4% included, those are, I believe, if I'm catching that correctly, normalized for weather, is that right, the figures that you --

Yes, that's correct. Yes.

But when you give out data, you don't normalize the data that you give out in actual deliveries. Is there any rules of thumbs here?

Well, if we had -- our total deliveries would have been up 3%, Jim, if you had included weather, and so, when we are forecasting for '12, we try and do it on a weather-adjusted basis. So, you would adjust down for the cooler temperatures in 2011, but we are forecasting increases in '12.

Okay.

And those two items offset one another.

And then finally, in the most recent quarter power costs, natural gas prices were low, but yet your power costs per megawatt hour went up. You call it NVPC, or something like that, and I don't have the ability to calculate that exactly. All I do is take your power costs divided by the megawatt hours of production. And I'm coming up with an increase for the quarter that went against my senses that the natural gas prices were going to be down. Can you explain that?

Your math is correct. We were up just slightly in the fourth quarter. The reason of that was is that the strong hydro started in the fourth quarter of 2010. So it rained a lot, and we had the benefit of strong hydro going into the winter season of 2011.

We'll take our next question from Sarah Akers with Wells Fargo.

Just a follow-up on some of the cost containment efforts that are benefiting 2012. Can you give us an update on some of the specific initiatives, and really whether most of the benefits are flowing in 2012, or should we expect that 2013 will have a benefit there as well? And then also, can you just remind us if there are any cost trackers or accounting mechanisms you have in place that you can -- that will help out on the operating expense side?

So I'll take the first, and then Maria can talk about the second in terms of trackers. In terms of the initiatives we've got going on in the Company, we started in the financial area. And what we've been doing is, we start with benchmarking and best practices to identify where the opportunities are. And then we put in place very specific improvement plans that will reduce the cost of operations, but still deliver high customer satisfaction to our customers. And so we started in the financial area. We've just completed a new financial system which has significantly improved the efficiency of the work that we do in the finance area. And that has produced some cost savings in that area.

We're now moving into the T&D area, the transmission and distribution area. We're looking at new technology. We're implementing what's called a [maximal] work management system, mobile and scheduling systems, and really trying to change the way we do work in the T& D area to get better results at lower costs. And that's going to happen probably this year and next. We've also gone through the streamlining of our IT organization, again, based on benchmarking and best practices. And in the human resources area, again we're moving from a lot of manual processes to using technologies that automate many of those processes. That will, that system won't be completed until later this year, which would produce savings in 2013.

So a number of projects underway, and more to come as we go through the next few years at really sprucing up our technology system to take advantage of those systems and reduce our manual works activity and produce lower costs to do the things we do. So I see a continuing trend in this area. We obviously will still see increases in costs for inflation, and other benefits, but we're trying to mitigate that through better performance and lower costs through technology. Maria, do you want to talk a little bit about the tracking?

Sure. We had requested some trackers for pension in particular in our last rate case, but we don't have any.

Okay. Thank you. And then just lastly, has a Chairperson been named to the OPUC?

No, not at this point. I would mention that Susan Ackerman did get re-appointed just recently for another four years, four-year term. And Steve Bloom has been appointed also, so we now have a full commission, but the Chairman at this point has not been appointed.

We'll go next to Andrew Weisel with Macquarie Capital.

Just one more question on the RFP. I know there's been some comments back and forth and a handful of IPPs seem to think that it's still a little bit of a home court advantage. I know you have a week or two to file your comments back, but from your preliminary understanding, are these complaints something that may have merit and can further slow down the process? Or is it more just a matter of paperwork and filing more data requests?

My feeling is, I think we've responded to many of the questions that they've raised in the prior capacity RFP, to the extent that we can provide lower cost projects that provide lower costs to our customers. That's really what we want to accomplish in this. And we're not trying to produce high cost projects. We're trying to get low cost, and we're trying to create a process that allows people to bid, and compete against our projects to the extent they think they can build something cheaper on our sites. We've now moved in that direction. I think the remaining issue is really around keeping the RFP as competitive as we can, so that anyone bidding on our site does not get information on the cost of our site, so they can't use that against us in the bidding process. So my sense is it's just paperwork at this point. We need to move forward with these RFPs to address the shortfall in capacity and energy. And I think we've designed a process that allows for that, and our projects are going to be competitive. We're going to try to keep the cost as low as possible, because that benefits our customers.

Got it. Very good. Okay. Then last question, you had some comments in the press release about an increase in provision for uncollectible accounts. Can you give a bit more detail on that as far as the magnitude and the outlook? Is that something that's going to be a concern going forward as well?

Maria, you want to take that one?

Sure. We have about 0.5% historically and about in our customer prices. We did have one customer go bankrupt, and there was a large exposure there. We consider that to be one of our one time items and go back to our norm.

We'll go next to Mark Barnett with Morningstar.

Just one more quick question here. On the flat costs in 2012 versus this year, I know you had a union contract that you were in the middle of negotiating. I'm just wondering if that's already finished, and if that's incorporated in your costs projections?

We have two union contracts. One's for some of our, a couple of our generating plants, that got completed and is in place. And we did agree to an extension on the main contract, a three-year extension. And that got approved and is in place, so we're -- both of those have been negotiated and they're included in our guidance.

Okay. Thanks for that. And I guess, last real quick question. If you do manage to pull in the RFPs for self-build, are you still considering some equity over the next maybe two years? And would you still be thinking more along the lines of a forward sale versus just a lump?

So just generally, I think once we get more visibility on the results of the RFP, that will inform us on how we move forward with equity. The exact structure we're going to look at once we have more clarity on the projects, but clearly a forward is one of those types of vehicles that we would consider using, as well as other types of vehicles. So Maria is looking at that right now, and we've really got through these RFP processes and get a little further on Cascade Crossing. With that information, we'll have a lot more visibility on our capital needs, and then we'll try to manage that capital at the lowest cost lease risk for both our shareholder and our customers.

(Operator Instructions) We'll take a follow-up question from Brian Russo with Ladenburg Thalmann.

Just in terms of any bonus depreciation that's taken, that has been taken but not included in the previous rate case, just curious if you have taken bonus depreciation and how that might impact the rate base when you file your next case, say, with a '14 test year?

Maria, you want it take that?

Sure. So we have taken bonus depreciation in prior years, but we're currently not anticipating taking any more bonus depreciation, and will not take any for 2011. The reason for that is that we have quite a few tax attributes from our wind farms, in particular, our production tax credits. And if we were to take more bonus depreciation, we would lose some of the benefit of those production tax credits. And so we are not going to take this accelerated -- most recent accelerated bonus depreciation, so we don't have any mismatch with the last Rate Case we filed.

Oh, okay, good. The roughly $3.2 billion of rate base currently is a good clean number to build off of?

Yes, it is.

Okay. And then just curious, with the recent slump in natural gas and power prices, is there an opportunity for you guys to optimize your generation fleet and possibly have costs that enable you to earn margin in the PCAM? And if so, is that included in your guidance range?

So in terms of natural gas, we forecast them by forward natural gas to fuel our power plants to meet our retail load. To the extent prices move, we are always out there trying to optimize our generation plants. Some of that is forecasted in the AUT filing when we run the models to show when those plants are in the money, so it's already somewhat taken advantage of in the model. But there's always changes in the market as we go through the year, especially related to hydro conditions, wind conditions and other things. I will tell you we're always out there optimizing our plants, but that's really opportunistic and it really depends on market conditions. And we really don't really include that kind of opportunity in our forecast, so that's how we look at it.

And we'll take a follow-up from James Bellessa from DA Davidson & Company.

Following up on that prior question, there was no bonus depreciation in 2011?

No, we did not take any for -- we haven't filed our tax return for 2011, but we do not expect to take any bonus depreciation.

And --

We've taken it for prior years, Jim.

Okay. And then on Cascade Crossing, the narrative talks about an arrangement with BPA that you're discussing. Was PacifiCorp also discussing ownership in this transmission project?

Yes. We still have a memorandum of understanding with PacifiCorp. They do have interest in a share of the line. That discussion was put on hold during last year because PacifiCorp was working on their Gateway West project. And they also needed to find a path from their Gateway West project to Boardman, and they've now entered into discussions with Idaho Power around some type of relationship on the Hemingway to Boardman line. So to the extent those two projects get completed, they now are at Boardman. They'd like to move power to Medford, which is the southern part of Oregon, and to do that, they would like to use a portion of Cascade Crossing. So we have now restarted the conversations with PacifiCorp to see their interest in participating in that line and entering into a relationship as a potential equity owner.

Thanks, Jim. It looks like we have no further questions. Thank you all for participating on the call today. We appreciate your interest in Portland General Electric, and invite you to join us when we report on first-quarter 2012 results. Thank you again.

And this does conclude today's conference. We thank you for your participation.