Portland General Electric Co (POR) 2013 Q4 法說會逐字稿

Good morning, everyone, and welcome to the Portland General Electric Company's fourth-quarter and full-year 2013 earnings results conference call. Today is Friday, February 14, 2014. 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, Angela, and good morning, everyone. We are very pleased that you're able to join us today.

Before we begin our discussion this morning, I would like to remind you that we have prepared a slide presentation to supplement the discussion which we'll be referencing throughout the call. The slides are also available on our website at PortlandGeneral.com.

Referring to slide 2, I'd also 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 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. Portland General Electric's fourth-quarter and full-year earnings were released via our earnings press release, and the release is available at our website at PortlandGeneral.com.

The Company also filed its 2013 annual Form 10-K before the market opened today, and it's also available on our website.

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.

As shown on slide 3, leading our discussion today are Jim Piro, President and CEO; and Jim Lobdell, Senior Vice President of Finance, CFO, and Treasurer. Jim Piro will begin today's discussion by providing an update on our growth initiatives, regulatory strategy, operational performance, and our service area economy. Then Jim Lobdell will provide more detail around the fourth quarter and the full-year earnings results and discuss our outlook for 2014.

Following these prepared remarks, we will open the line up for your questions. And now, it's my pleasure to turn the call over to Jim Piro.

Thanks, Bill. Good morning and thank you for joining us. Welcome to Portland General Electric's fourth-quarter and full-year 2013 earnings call. As presented on slide 4, we recorded net income of $105 million, or $1.35 per diluted share, in 2013 compared with net income of $141 million, or $1.87 per diluted share, in 2012.

The decrease in net income was primarily driven by three factors. The Cascade Crossing Transmission Project write-off of $0.42, a refund to industrial customers in the second quarter of $0.07, and an incremental replacement cost for our three generating plant outages of $0.13.

We made important progress in 2013 as we concluded two RFP processes that resulted in the selection of three new generating plants. And we reached a fair outcome and final order on the 2014 general rate case.

In 2014, we are focused on constructing our three new generating projects, bringing two of these projects into customer prices to the 2015 general rate case filed yesterday, and managing our operations in a safe and cost-efficient manner in order to provide excellent service to our customers.

Now let me update you on the progress we're making on these three projects. Slide 5 provides more detail on Port Westward Unit 2, a 220 megawatt, natural gas capacity plant being built next to our existing Port Westward plant in Clatskanie, Oregon. The project is on budget, on time, and scheduled to be operational in the first quarter of next year.

As you may have heard, before PGE received the engines on site, one of the 12 reciprocating engines was damaged while being transported to the construction site. The engine manufacturer will provide a replacement engine this spring. In the meantime, construction will continue with engine and generator installation and substation construction.

Slide 6 includes an update on Tucannon River, a 267-megawatt wind farm located on 20,000 acres in southeastern Washington. The project is on budget and on track to be fully online in the first half of 2015.

25 of the 116 turbine foundations have been completed and designed for roads. The operational building and the substation are near completion. In addition, about 30% of the blades have now arrived in the Boardman area and are ready for shipment to the construction site. Upcoming milestones include receiving the main transformer on-site, completing the remaining foundation, and erecting turbines.

Lastly, slide 7 summarizes the Carty Generation Station, of 440-megawatt baseload natural gas plant that is being constructed next to our existing Boardman plant. This project is on budget and on schedule to be operational in mid-2016. We broke ground in early January and are currently working on ground clearing and grading while the gas and speed turbines are being manufactured.

Next steps include completing design and engineering work, pouring foundations, and receiving the major equipment on site.

Slide 8 provides a summary of the Company's five-year capital expenditure forecast. Altogether, the new generating projects resulted in average rate base increase of $1.4 billion for an approximate rate base of $4.5 billion in 2017. We are focused on completing these projects on time and on budget in order to meet our customer's needs with reliable, efficiently generated power for many years to come.

Now, for a regulatory update on slide 9. Yesterday we filed a new general rate case with a 2015 test year. The filing is now available on our website. The filing requests and overall revenue increase of $81 million based on a 10% ROE, a capital structure of 50% debt and 50% equity, and a rate base of $3.9 billion. This request includes a small increase in the base business cost which would be more than offset by several customer credits that we propose to begin amortizing in 2015.

The primary focus of this regulatory filing is the cost recovery of the Port Westward Unit 2 and Tucannon River Wind Farm. We are requesting customer prices changes at the time these resources go online. Port Westward Unit 2 represents an increase of $51 million, or 3% in the first quarter of 2015, and Tucannon River Wind Farm represents an increase of $47 million, or 3% in the first half of 2015.

We expect the commission to issue a final order in mid-December. If approved, the overall price increase for all components, including the customer credits, would be 4.6%.

Now for an operational update on slide 10. As we previously discussed, three generating resources experienced outage in the second half of 2013. Colstrip Unit 4 came back online at the end of January as expected. And I'm pleased that all three plants are available and operating well.

For the full year, overall PG generation of availability was 89%. We continue to have top quartile reliability metrics, and our customer satisfaction ratings for residential, general business, and key customers all ranked top decile in the latest surveys.

In 2014, we continue to focus on safety and efficient operations through leveraging new technology and refining business processes. We're making progress with our transmission and distribution transformation projects, which include replacing our work and asset management system and preparing for the replacement of our mapping and outage management systems.

I want to take a moment to recognize the great work and dedication that our exceptional employees have shown which has enabled us to maintain the excellent service and reliability our customers have come to expect from us.

Now for an update on the economy and our customers on slide 11. Oregon's economy continues to show positive signs with housing and commercial real estate indicators trending upwards. Oregon ranked number one for in-migration in 2013, according to the United Van Lines's annual study, supporting a year-over-year increase in customers of 1%.

Oregon's unemployment rate was 7% in December, which is the lowest unemployment rate in more than five years. This compares with 8.3% a year ago. The unemployment rate in our core service area was 6.1% in December, down from 7.4% a year ago. Employment growth in Oregon was 2.3% in 2013 with most of the growth occurring in the areas of construction, health services, leisure and hospitality, and professional and business services.

For the fourth quarter and full year 2013, weather-adjusted energy deliveries were comparable to the same period of 2012. Deliveries to residential customers were comparable to prior year as expected. Commercial deliveries dipped slightly despite the positive economic indicators over the past year. Deliveries related to the high-tech expansion showed positive signs but were largely offset by declining deliveries to solar manufacturing customers and a partial curtailment at a paper manufacturing plant.

In 2014, we expect weather-normalized load growth of approximately 1%. This is net of approximately 1.5% of energy efficiency.

Despite -- deliveries to residential commercial customers are expected to be comparable to 2013 with the majority of growth coming from increased energy deliveries to the industrial sector. In particular, energy demand from the high-tech sector is expected to increase as Intel, its suppliers, and data centers continue to grow and expand their business.

The Oregon state economic forecast released yesterday shows the economic outlook for 2014 is positive with a slight acceleration in the Oregon employment growth this year.

Now I'd like to turn the call over to Jim Lobdell who will discuss our financial results for the fourth quarter and full year and initiating our outlook for 2014. Jim?

Thank you, Jim. Turning to slide 12, for the fourth quarter 2013 we recorded net income of $47 million, or $0.59 per diluted share, compared to net income of $28 million, or $0.38 per diluted share, for the fourth quarter 2012. This increase was primarily driven by three items: a $21 million increase in retail revenues as a result of an increase in energy deliveries due to colder weather in 2013; a $5 million increase in AFDC due to higher CWIP balances in three new generating projects; and a $10 million decrease in income taxes due to changes in production tax credits and an adjustment to the deferred tax balances recorded in 2012.

These benefits were partially offset by a $16 million increase in net variable power costs driven by increased energy delivery and increased replacement power costs for Coyote Springs and Colstrip Unit 4 planned outages during the quarter.

As shown on slide 13, for the full year of 2013, we recorded net income of $105 million, or $1.35 per diluted share, compared to $141 million, or $1.87 per diluted share, for 2012. This decrease was primarily driven by four items: a $9 million decrease in revenues from the customer billing refund in the second quarter of 2013; $17 million of incremental replacement power costs at Boardman, Coyote Springs, and Colstrip Unit 4 outages; a $17 million increase in operations and maintenance expense, including increases in generation and distribution and maintenance and pension expense; and a $52 million expense from the write-off of the Cascade Crossing Transmission Project.

These full-year impacts were partially offset by a $10 million increase in AFDC due to higher CWIP balances for the three new generating projects, a $7 million benefit from earnings from our nonqualified benefit plan trust assets and lower interest expense, and a $9 million decrease in income taxes due to an increase in production tax credits, and an adjustment to the deferred tax balances recorded in 2012.

For the full year, excluding the negative impact of Cascade Crossing and the customer billing refund, non-GAAP adjusted operating earnings would have been $1.84 per share.

Moving on to slide 14, total revenues for the fourth quarter of 2013 increased $36 million to $499 million, driven by higher energy deliveries.

Weather in the fourth quarter of 2013 was much colder than the previous year with heating degree days increasing 26% quarter over quarter. For the full year, total revenues increased $5 million as increases in retail energy deliveries and wholesale sales were offset by a decrease in customer prices.

Purchase power and fuel expense increased $31 million year over year, driven by an increase in the average variable power costs per megawatt hour based on three main factors: less hydro or less favorable hydro conditions the region, which contributed to an increase in price per megawatt hour of purchase power; an 11% decrease in energy received from our own and contracted-for hydro, which we replaced with thermal generation and purchase power; and $17 million of incremental power costs for the three unplanned thermal plant outages that we replaced with purchase power as well.

In total, net variable power costs were $11 million above the annual power cost update tariff baseline for the full year.

Moving to slide 15, production, distribution, and administrative costs totaled $444 million in 2013, $17 million higher than in 2012 and at the lower end of our forecast range of $440 million to $460 million. This increase was largely due to planned overhaul and repair costs at Colstrip and Coyote Springs generating plants and a warranty extension for the Bigelow Canyon Wind Farm. In addition, pension expense increased approximately $6 million year over year.

Interest expense decreased $7 million year over year -- $4 million from the timing of maturities and issuances of long-term debt and $3 million from higher AFDC from borrowed funds.

Other income net increased $10 million year over year, primarily driven by $7 million increase in AFDC from equity funds and a $2 million increase in earnings from our nonqualified benefit plan trust assets.

Lastly, income taxes decreased $43 million year over year. In addition to lower taxable income in 2013, this decrease was driven by an increase in production tax credits due to increased wind generation and an adjustment to the deferred tax balances recorded in the fourth quarter of 2012.

Turning to slide 16, we continue to maintain a solid balance sheet including strong liquidity and investment grade credit ratings. As of December 31, 2013, we had $793 million of cash and available credit and a common equity ratio of 48.7%. On January 30, 2014, Moody's upgraded PGE's long-term issuer ratings from BAA1 to A3 based on their view of PGE's outlook and a favorable view of the US and Oregon's regulatory environment.

Total capital expenditures for 2013 were $720 million, including $385 million for the three new generation resources. To fund these projects and our base business capital expenditures, we successfully issued debt and equity in 2013. Between June and December, we issued $380 million of long-term first mortgage bonds at interest rates between 4.47% and 4.84%. We entered into an equity forward agreement in connection with the public offering of 11.1 million shares, and we issued 1.7 million shares from the underwriters' exercise of an overallotment option.

As of December 31, we have issued 700,000 shares under the forward sale agreement, resulting in a total shares outstanding of 78.1 million.

As shown on slide 17, we are initiating full year 2014 earnings guidance of $2.00 to $2.15 per diluted share. This guidance is based on the following assumption. Retail deliveries and revenues in line with level set in the 2014 general rate case, average hydro conditions, wind generation based on historical levels, normal thermal plant operations, Colstrip Unit 4 replacement costs in January of $1.5 million, O&M expenses between $480 million and $500 million, and D&A expense between $300 million and $310 million. In addition, we expect capital expenditures slightly above $1 billion for 2014.

To finance these expenditures we will continue to use a combination of draws on our equity forward and new debt issuances. Further, we are exploring financing options that could allow us to delay some or all of the equity draws to the second half of the year, which would decrease our share dilution.

Back to you, Jim.

Thanks. For 2014 we are moving forward on our initiatives that deliver value to our customers, community, and shareholders. These include construction of our three new generation resources, on time and on budget; achieving a fair and reasonable result on our 2015 general rate case; and continuing to operate our systems safely, efficiently, and effectively.

Now, operator, we are ready for questions.

(Operator Instructions) Neil Mehta, Goldman Sachs.

Can you talk about the regulatory strategy to get the CCGT into rates?

So you're talking about our Carty 1 project?

Yes, the Carty project.

So right now our forecast is to have that plant come online mid-2016. Although we haven't made a final decision, what we're thinking about is filing a split year test year with rates being effective when the project goes into service. We haven't made a final decision on that. We're looking at other options. A lot of them would be dependent on the timing of the construction of that project, but that's kind of generally what we're thinking about. But as I said we haven't made final decision.

And then, Jim, on Hydro, looking pretty dry up there. And I checked out this forecast. It looks like it's going to be raining for the next 10 days in a row.

Love it, love it (laughter).

Embedded in your guidance is normal hydro, and it seems like that's the expectation based on the forecast.

Yes, as we've always said on these calls, these early calls is it's too hard to call right now. We saw it pretty dry in January, but recently we've had a lot of snow. And the river looks very, very full right now. So, right now, the forecast is about 96%, and it's still too early to call it. We'll wait until the next call to really have a better picture on hydro.

So that's kind of where we are, and we'll just see how it plays out. But right now we got a lot of snow up in the mountains, but we still a few more months to go.

The nice thing Neil is a lot of it is sitting up in Canada. So as they release it down the river, we'll benefit from it.

Perfect. And then in terms of weather normal demand, what was it in 2013? And do you have a number in terms of how favorable weather was versus normal in 2013?

For the year over year, it was flat on a weather-adjusted basis. Second question --

What was the second part of the question, Neil?

How favorable was weather versus normal in 2013?

Quarter over quarter, it amounted to quite a bit. It was almost $0.09.

And for the full year?

Year over year, about $0.05.

Okay, perfect. Thank you.

Brian Russo, Ladenburg Thalmann.

What's the average share count that you're using in the 2014 guidance?

I don't think we're giving that at this point. We've told you what shares we have today. A lot of it will depend on how we draw the equity forward. So I think we are still looking at options and whether we draw it early or late, and so that will depend on final share count. So, Jim?

We are assuming that we will pull it all down by the end of the year, so that would get us to about 84.5 million shares.

At year-end.

At year-end. Yes.

But the actual distribution will depend.

Right. (multiple speakers) sorry, 88 million at the end of the year.

How many?

88 million at the end of the year.

88 million shares.

So from a modeling perspective should we just assume the average of what's left to be drawn and add that to your year-end 2013 share count to come up with an average share count for us to use in our estimates? Is that fair?

That would be fair.

Okay great and then any update on the PCAM investigation that -- the combined filing with Portland General and Pacific Power to tighten the dead bands.

Jim, why don't you give him an update on that?

Yes, Brian, we're still working with the other utilities trying to scope out exactly what that filing or what that request will look like. The broader it is, the more difficult it is to be able to move anything forward. So, right now, all I can say is we're still working with them on trying to narrow that scope.

Are you working with staff or the commission because we haven't seen any filing since like I think it's been September of 2013?

No, the way the process goes is all of the utilities, including conversations on the side with staff, is trying to figure out exactly what it's looking like. We don't just walk in and file something and try and get a reaction at that point. We try to do as much front-end work as possible.

Okay, and I assume the midpoint of your guidance range assumes a PCAM of zero.

Yes.

Okay, and then lastly the $3.9 billion of average 2015 rate base that was filed in the rate case last night, can you give us any CWIP assumptions?

Well, you can go on to the website and see the full rate base if that's what you're looking for. Is that what you are trying to get at?

Yes, exactly.

Yes, so if you go on the website and go to the revenue requirement estimate, you'll see the rate base and all the components of that, which is pretty detailed.

Okay great, I'll check that out. Thank you.

Sarah Akers, Wells Fargo.

In terms of financing, do you still expect the debt issuances in the second half of the year, or is the timing dependent on the timing of the equity now?

Well, it is going to be a combination -- the both. Before -- what we have is an issue associated with our ability to issue first mortgage bonds because that resulted from the Cascade Crossing right off. And so that effectively said until that wears through our financials, which will occur in the June timeframe, we really don't have as much bonding capacity as we would like. So we were planning originally on issuing or pulling down on the equity forward in the first half of the year but now we're looking at the potential that we might be able to do some other debt instruments that could delay the pull on that equity forward. So it really if you're asking just about the first mortgage bonds, that will have to be in the latter part of the year.

Okay, and does guidance incorporates the possibility of delaying the equity to the back half?

No, it doesn't.

Okay, perfect. And then one question on dividend strategy. With CapEx trailing off in 2015 and more so in 2016 and 2017, what are your thoughts in terms of the use of cash and the dividend payout ratio?

We are committed to having a competitive dividend for our shareholders. As these projects come online and we generate earnings, I think the Board, obviously I can't speak for the entire Board, but the Board was committed to continuing to raise the dividend as we go forward. We typically address the dividend in May Board meeting, and I would suspect if we continue on the trajectory, we will move the dividend up. I think we've got a payout ratio in a range we provided between 50% and 70%. We're at the low end of that now, so I would say that we will continue to move that dividend up as we grow our earnings.

Great, thanks everyone.

Brian Chin, Merrill Lynch.

Just a quick modeling question. What is the tax rate being assumed in the 2014 guidance? That's it.

Well, it's going to be approximately 30% plus or minus. I'd have to go and specifically (multiple speakers)

If you model this stuff, the best way to model it is do your base net income and then you have to look at the wind generation historically to factor in the production tax credit. The PTCs are real driver to a lower tax rate. So we're at the marginal rate of around 40%, and then you have to subtract out the tax credit that we get from the wind farm. And you can look at historic averages on wind and the tax credit in 2014 is 20 -- what cents?

It's $0.23.

$0.23 a megawatt hours or kilowatt hour? Megawatt. (multiple speakers)

$23.

$23 a megawatt hour.

Okay, but if we look at the marginal tax rate and then back down from the PTCs, effectively at around a 30% tax rate gets us within the ballpark of what you're using?

That gets you in the ballpark. So if you are doing it that way and you come up about that number, you've got a good model. That way as revenues or costs change you don't just stick with the 30% because it isn't the right -- because it will change based on taxable income (multiple speakers).

Understood, thank you.

(Operator Instructions) Mark Burnett, MorningStar.

A quick question, not necessarily something directly related. But regulators have gotten a little bit, I guess, a little bit louder about Colstrip plants and the true economics of both plants notwithstanding. A couple years down the line, is there an option out there to replace power from those should there be maybe action taken to replace them for the owner, and would that be through the same process that we just went through in 2013?

It's really too early to call that. You probably saw the Puget IRP up in Washington, and the decision from the commission up there to look at the Colstrip plants. Puget is 50% owner of 1 and 2 and then there are smaller share owner of 3 and 4. We're a 20% owner of Colstrip 3 and 20% owner of Colstrip 4. So we're kind of a minor player on those projects. They are still very cost-effective resources for the Company. You need to understand that 1 and 2 is much older than Units 3 and 4, and so, they're going to be probably the focus of the initial conversation. Unit 3 and 4 are still pretty cost-effective and still relatively young in their life. Obviously, there's a lot of focus on coal especially with what's going on in EPA with the 111(d) process and greenhouse gases related to existing resources. So, you know, we're going to have to see how those rules unfold and what the economics tell us for those projects.

In Oregon, we use an integrated resource planning process to make decisions around resources, and right now, at least, we're not facing any significant capital expenditures for those projects. So again, they continue to be very cost-effective. But as we go through time, we have to look at those issues on an annual basis and make decisions based on the economics of those projects and kind of the public policies issues that unfold.

So more to play out on that. I think we'll see probably more focus on 1 and 2. From my perspective, I think that will be where the initial focus is. But we'll have to watch where the EPA regulations go.

Thanks for clearing that up. I was thinking your interest was in 1 and 2. That was just confusion on my part.

One quick thing, a follow-up on your questions about the equity draw. It's entirely related to the funding limitations you have from the write-off. There's no change in your CapEx outlay within 2014.

No, there's no change. Just a matter of timing.

Okay, thanks.

(Operator Instructions) Maury May, Wellington Shields.

On your PCAM, the results in 2013 you said that it was $11 million above the baseline. That means that shareholders essentially absorbed $11 million of expense there, right?

Yes.

Okay, and you have an initiative that you are pursuing with other utilities in Oregon as well as with the staff of the OPUC. And the purpose of this is for what? Are you looking for tighter bands, or are you looking for symmetrical dead bands for fairness? Or what exactly is your objective here?

We're looking for all of the above, Maury. Again, as I was mentioning earlier, we're in conversations with the other utilities. As I've also told many of the analysts that I've met with over time, this is -- PacifiCorp was just recently handed our PCAM mechanism. And as such, to go in and ask for significant changes in that mechanism right now is a very touchy subject, but one that we believe there are some very specific changes that I think we can all agree upon. So, we're trying to scope out exactly what that looks like and get agreement that everybody believes that we should move forward into a docket and see if we can find some resolution.

Okay. Is there any chance here of Oregon going to more of a national model on fuel adjustment clauses where you have essentially don't have asymmetrical dead bands, where you have pretty much of fuel pass-through subject to audit of course? But would Oregon ever go to a normal fuel adjustment clause?

Maury, this is Jim. Oregon has had a long history of a sharing mechanism. Even way, way back in the 1980s it was an 80/20 power cost adjustment mechanism. So whether we -- chance of -- you never say never, but chance of getting into a full pass-through I think are pretty small. But I do think we can get to a different kind of mechanism hopefully over time that has us sharing some of the risk from dollar one forward, obviously, based on prudency and all the other things we are still subject to. But it's going to take time. I think -- we keep working on these issues similar to what we did with 408. We just keep working on these issues and try to lay out the risks and discuss with the staff and the commission our concerns, and eventually get some movement.

I don't think we get to 100%. I think that just given the history of Oregon and Washington, even Idaho, there's some type of sharing. And I believe the regulators like to see us having some skin in the game and to ensure that we're motivated as we always are to keep our costs down.

Okay. All right. Moving on to plant operations for 2014, what is the outlook for scheduled outages in your fossil fuel plants?

Nothing special. Boardman is scheduled for 30-day outage, its normal outage. All the outages are included in our AUT filing, and we're pretty much on track to meet those filings. So nothing really special going on from our perspective. We will bring the dry sorbent injection project online for Boardman, but that is pretty much on schedule and on budget.

Okay, good enough. And then I know you can't predict unscheduled outages. But 2013 was a really bad year, wasn't it? I mean you had outages unscheduled outages that three of your plants. Just reassure us a little bit that that's very unusual and won't happen in 2014. Can you do that? (laughter)

You know, can't do it necessarily, but I will tell you we are committed to keeping these projects running on time. If you look at the history of these projects, Coyote Springs has had a long history of running. That crack that we had in the road there was an unusual situation. In fact, it had never been seen before by General Electric on those 7-FA's. So we got that corrected, and that unit has been running well since we brought it back online.

Colstrip Unit 4, as you know, we don't operate that project, but that generator was kind of the original generator. And things do wear out over time. We feel like we've got that project back where it needs to be and running well.

And then Boardman was just a one-off issue, and again, that plant has had a long -- since it came back online in August, it's had a continuous run cycle. So, we met our commitment to getting the projects back online.

And the other thing we really pride ourselves on is reliability-centered maintenance, to really be ahead of our curve on maintenance, and making sure that we're on top of our all of our procedures. So hopefully, it was just a one-off thing, and I think we're set up well for this year.

Okay, good. Thank you, Jim.

Andrew Weisel, Macquarie Capital.

Two quick questions on the rate case. First one, can you elaborate a little bit more about this amortization of customer credits and kind of what they are and what the earnings impact would be?

Sure, we have three credits that we've got to amortize the customers, and they are all kind of over 1 to 3 years. So we've got -- first of all we've got Trojan decommissioning fund excess balance that we want to refund back to customers. We kind of sued the US DOE over decommissioning. They were supposed to take our fuel a number of years ago, and they didn't perform. And we took the DOE to court. We ultimately settled and got a $44 million award for prior nonperformance and an additional $6 million coming for current year nonperformance. So, we're going to amortize that over three years, and it's about $17 million per year.

The second one is some state tax credits related to the Trojan spent fuel pool tax credits related to that project. That's about $5.5 million that we're amortizing over one year. And then we also have a BPA refund that would go back to residential small farm customers, and that's about $12 million over two years. So in total, about $29 million impact for 2015, and we propose to amortize that against a small increase in base rates and also to help minimize the impact of the new projects coming online.

And the earnings impact, is that all earnings neutral for you?

Yes, it's all earnings neutral. Those are all dollars we have on the balance sheet that would get amortized.

Okay, great. And the other question was just if you could talk a little bit more about the decision on the wind farm, embedding that in the rate case as opposed to using the renewable adjustment clause? I know you have gone back and forth. (multiple speakers) the final decision?

So just a couple of things there. We decided, first of all, the RAC will go into place during the time the project comes online because it will come on in various -- as each string or each line of turbines comes online, we would put that into service so we could generating production tax credits. And that would go through the RAC, the renewable adjustment clause mechanism, as each string comes online until the project fully goes operational.

Our plan is that that putting the project in customer prices immediately when the project is completed reduces the size of the deferral, and therefore, minimizes that catch-up, if you will, in the future years. So it doesn't mean we couldn't go use the RAC for the entire period of 2014, but our recommendation to the commission would be to change rates immediately rather than run the deferral for the entire year.

So that's our thinking right now if the commission and staff rather say, no we want you to wait until 2016, and then we could run the RAC for all of 2015. But then we build up a deferral which would then have to be amortized.

And the strings start coming online when?

Probably later in 2014.

Okay, great. Thank you very much.

Paul Ridzon, KeyBanc.

I had a quick question around a clarification on the equity. At the midpoint of guidance, was that an assumption of issuing the equity ratably through the year?

No, it was assuming that we're going to issue it in the first half of the year.

All of it?

Yes.

Okay. Thank you very much.

Andrew Levi, Avon Capital.

Just kind of a longer look type of question. So as you get out to 2016 and 2017 and these plants all come online and you get through the rate process, it seems that you guys have a lot of free cash flow after dividends. And could you possibly talk what your thoughts are on that? Is that something that you would ramp up the dividend, have opportunity for stock buyback? Or are there other longer-term projects after these that you may want to spend the money on and not have to issue as much equity as you did for these projects?

So, as you look beyond these three projects, we will be going through a very detailed integrated resource planning process starting probably next year to start looking at a couple of things. Number one is the Boardman replacement. Our Boardman coal plant will close down in 2020, at the end of 2020. And we're going to have to make some decisions on what's the right set of resources to replace that baseload resource. So that's one decision. And we would likely go through the same process we did before, which is do an RFP. And we would likely put in our [self-build] option which would be Carty 2 if gas determines to be the least cost resource.

We also have the next tranche of renewable resources we need to add to get to 25%. The next test is at 20% in 2020, and we probably have a little bit of time on getting that resource online. But that's going to look like another Tucannon River Wind Farm or something like that in the renewable space.

So there's still a couple of projects out there that we need to look at to invest in the Company and meet our customer's needs. But those will all be the subject of the integrated resource plan that we'll start starting next year. So those are the two things. Obviously, if those projects turn into capital projects for the Company, then we would use and deploy our cash flow to finance those projects. If for some reason we're not the ultimate builder of those projects, then we, as always, we want to optimize our capital structure around the 50% debt, 50% equity; looking at increasing dividends to address that; and potentially, if necessary, buy back stock. But it's really too early to make a call on that. We've got a lot of process ahead of us, and we'll get a better sense of that once we get through the next integrated resource plan.

And if you were successful on those two potential longer-term projects, when would the spend begin on those? (multiple speakers)

Well, probably not until 2019. It takes about 2.5 years to 3 years to get a gas project up, so we would propose probably Carty 2 as a very good baseload gas resource if that's the least cost, lowest risk option. Probably a two-year construction cycle.

The wind farm again probably in the 2019 timeframe. We probably don't need that project up until 2021 or at the end of 2020 at the soonest. So probably in that timeframe. So there's a little bit of a period in 2018 and 2019 where we might be generating some cash flow, but we're also updating some of our technology systems. We're looking at replacing our customer information system. That's about over $100 million project that we are making progress on.

So you know I think what we would do is continue to build the equity structure, address dividends to get them competitive, and look at the future for future capital expenditures.

So I guess of your 2016 and 2017 CapEx forecast could go up, because I guess they don't include these upgrades to your customer service (inaudible) and things like that.

Yes, we have not put those in our forecast right now. It is -- the discussion of that is in our rate case. We've been working closely with the commissioners and the staff on our needs to replace our aging billing system. And as we mentioned, we are also doing some other technology upgrades, so that is a big investment. And we really need to get our regulators comfortable with that path. So far, they've been an agreement that we need to replace our billing system and have been helping us fund that project in the early stages.

So basically (multiple speakers) -- go ahead, I'm sorry.

We'd likely make the decision on the billing system later this year.

So, basically, either we get more rate base growth, which hopefully turns into earnings growth, or we return cash to shareholders through either dividends, share buyback, or both? Is that kind of the way (multiple speakers)

Again, we're going to optimize our capital structure, staying at our target -- 50% debt, 50% equity -- and use all the tools available to do that.

And then the last question is this you get to 2016 or 2017, you have this regulatory lag kind of on some fixed expenses, and we discussed this before on these conference calls, where that number is fairly fixed is my understanding. So any number you want to throw out, you may not want to, but where -- how much we can reduce lag or you can reduce lag by 2016 or 2017 relative to where it is today?

You're talking about the difference between allowed ROE and actual ROE?

Yes, my understanding is that the costs that you're not recovering are fairly fixed. So as your rate base grows you get recovery of that, that number should shrink.

Yes and as we've grown rate base that -- because that's very fixed amount, we think by the end of that period, we're going to be somewhere in the 50 to 65 basis points.

Of lag?

Of lag, yes.

All right. Got it. Thank you.

And it appears that there are no further questions at this time. Mr. Piro, I'd like to turn the conference back to you for any additional or closing remarks.

Thank you, we appreciate your interest in Portland General Electric and invite you to join us when we report our first-quarter 2014 results in late April. Thanks a lot, and have a great day.

Ladies and gentlemen, this concludes today's conference. We thank you for your participation.