Portland General Electric Co (POR) 2013 Q2 法說會逐字稿

Good day, everyone, and welcome to Portland General Electric Company's second-quarter 2013 earnings results conference call. Today is Friday, August 2, 2013. 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 Electric Director of Investor Relations, Mr. Bill Valach. Please go ahead, sir.

Thanks, Beth, and that's Portland General Electric, and we are pleased that you are able to join us this morning.

Before we begin our discussion this morning I like to remind you that we have prepared a PowerPoint presentation to supplement our discussion today and we will be referencing slides as we go through the call. For those of you joining the call over the phone, these slides are available at our website at investors.portlandgeneral.com.

Referring to slide 2, I'd like to make our customary statements regarding Portland General Electric's written and oral disclosure 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 incur that could cause such differences, the Company requests that you read are more recent form 10-K and form 10-Qs. Portland General Electric's second-quarter earnings were released before the market opened today, and the release is available on our website at 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 on 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 presentation by providing a review of our performance in the second quarter and an update on our strategic initiatives. Then Jim Lobdell will provide more detail around the quarterly results and our expectations for the full year 2013.

Following these prepared remarks we will open the lines up for your questions, and it is 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 second-quarter 2013 earnings call.

As slide 4 shows, on today's call, I will provide an update on our strategic initiatives, summarize the progress we have made on the 2014 general rate case, give you an update on our operations. And discuss the economy and customer satisfaction in our service territory. Then Jim Lobdell will give a financial update, discussing the quarter's results, and our outlook for the remainder of 2013.

As you can see, on slide 5, we recorded a net loss of $22 million, or $0.29 per diluted share. This compares with net income of $26 million, or $0.34 per diluted share for the second quarter of 2012. The decrease in earnings was primarily driven by the Cascade Crossing transmission project expense, and the customer billing refund.

In addition, operation and maintenance expense increased quarter-over-quarter as we expected, and is in line with our full-year forecast of $440 million to $460 million for 2013. Excluding these factors, earnings this quarter would have been comparable to earnings in the second quarter of 2012.

So let's start with an update on our three generation projects. First, the capacity resource on slide 6. We broke ground in May on Port Westward 2, our new 220 megawatt natural gas plant. This plant is expected to cost approximately $300 million, excluding AFDC, and is scheduled to be operational in the first quarter 2015. We expect to file a general rate case in early 2014 with a 2015 test year to recover the cost, which, by itself, may result in a customer price increase of between 3% and 4%.

We also entered into two power purchase agreements with Iberdrola for seasonal peaking resources to meet needs identified in our IRP action plan. The first agreement provides 100 megawatts of summer capacity, and the second provides 100 megawatts of winter capacity.

Now to our base load resource on slide 7. We are moving forward with the Carty generation station, a 440 megawatt natural gas plant next to our Boardman coal plant. We expect the project to come online in mid-2016 and cost approximately $450 million excluding AFDC.

To bring this resource into customer prices, we anticipate filing a general rate case in 2015 or 2016 to recover the cost which, by itself, may result in the customer price increase of between 6% and 7%.

Lastly, turn to slide 8 for an update on our renewable resource. I'm very pleased to announce that yesterday we closed the asset purchase agreement with Puget Sound Energy for the rights to develop phase 2 of the Lower Snake River Wind Farm in Southeast Washington. With this agreement finalized, we are renaming the project Tucannon River Wind Farm, after the Tucannon River which runs north of the project. RES will construct the 267 megawatt wind farm, installing 116 Siemens turbines on about 20,000 acres.

Overall, we expect Tucannon River to cost approximately $500 million, excluding AFDC, and come online in the first half of 2015. We may use either a general rate case, or the renewable energy adjustment clause mechanism to recover the cost which, by itself, may result in the customer price increase of between 4% and 5%. We are working hard to deliver operational efficiencies throughout the Company and investigating other strategies to offset these customer price changes.

Slide 9 provides a summary of the Company's five-year capital expenditure forecast, including expected spend patterns for the three new generation projects. Based on these, we estimate 2017 average rate base to be about $4.5 billion. These new projects are the least-cost, lowest-risk resources and will be used to meet our customers long-term energy needs with reliable cost effective efficiently generated power. We look forward to completing these projects on times and on budget.

Moving to slide 10, we filed a general rate case in February with a 2014 test year, and have now reached settlement with the OPUC staff and interveners on all items except tension expense. PGE and the parties have stipulated to a 9.75% ROE, a capital structure of 50% debt and 50% equity, and an average rate base of $3.1 billion. In addition, our decoupling mechanism has been extended with a few minor modifications, for an additional three years through 2016.

Over the next several months, we will continue to update power cost, debt cost, and our retail-load forecast for the 2014 test year. Our most recent updates for these items, as filed on July 17, led to an additional $19 million of revenue requirements for an estimated total increase of approximately $79 million. We expect a final order from the commission to be issued in mid-December resulting in an average overall price increase of approximately 5% effective January 1, 2014.

Now onto operational updates on slide 11. As we disclosed on July 15, the Boardman and Colstrip coal plants have experienced recent outages. Boardman, of which we own 69%, tripped off line on July 1 due to a temperature shock in the cold reheat pipe. We have repaired the line and rebuilt the pipe support structure, enabling the plant to come back online earlier this week. We estimate our replacement power costs will total $3 million to $4 million.

Colstrip Unit 4, which we own 20%, but do not operate, also tripped off line on July 1. A generator failure caused damage to the stator and the rotor and we expect the unit we off-line for the remainder of the year. We estimate our replacement power costs will be $7 million to $8 million through the rest of 2013.

Engineering estimates indicate outage repair costs could total approximately $10 million for Boardman and between $30 million and $40 million for Colstrip Unit 4. Both plants have insurance coverage and providers have been notified of potential claims. At a minimum, we will incur our ownership share of the $2.5 million insurance deductible at each plant. We expect that the majority of the repair cost not covered by insurance will be capitalized.

Now, let's move on to slide 12 for an update on the economy and our customers. Oregon's economy continues to show positive signs. The residential housing market has been improving since last year and we continue to see growth in Oregon building permits.

In addition, we've seen strong employment growth in construction, business services, and leisure and hospitality sectors so far this year. Oregon's unemployment rate has dropped to 7.9% in June, compared with 8.2% at the end of the first quarter -- at the end of the last quarter, and 8.8% a year ago. The unemployment rate in our core operating area is 6.8% in June, down from 7.2% at the end of the last quarter.

The state continues to demonstrate strong in migration, and PG continues to add new customers each quarter. In addition, weather-adjusted energy deliveries grew this quarter, which Jim will discuss later.

Our overall customer satisfaction continues to be very strong. PGE ranked in the top decile for both residential and general business customer satisfaction in Market Strategies International's most recent surveys. We also ranked second nationally for large key customer satisfaction in TQS's Research Incorporated annual survey.

Now I like to turn the call over to Jim Lobdell, who will discuss our financial results in the second quarter and review our expectations for the rest of 2013.

Thank you, Jim.

Turning to slide 13, the second quarter of 2013 recorded a net loss of $22 million, or $0.29 per share, compared to net income of $26 million, or $0.34 per share, for the second quarter a year ago. This decrease was driven by a $52 million expense related to the suspension of the Cascade Crossing transmission project, a $9 million customer billing refund, and a $12 million increased operating and maintenance expense related to our generation and distribution system. Excluding the impact of these factors, earnings this quarter would've been comparable to the earnings of the second quarter of 2012.

Moving to slide 14, total revenues for the quarter were $403 million, down $10 million from the same period last year, primarily due to a $9 million refund to industrial customer who was incorrectly billed for several periods. Energy deliveries, adjusted for weather, were up 2% quarter-over-quarter. We've seen a notable increases in residential and commercial deliveries, and industrial deliveries continue to grow as well.

While the second-quarter growth was better than the first quarter of this year, our year-to-date energy deliveries, adjusted for the leap day, are approximately flat compared to the first six months of last year. As a result, we are expecting relatively flat energy deliveries for the full-year, compared with 2012 weather-adjusted levels.

Purchase power and fuel expense were flat quarter-over-quarter. Hydro generation from PGE's owned and mid-Columbia hydro resources decreased 12% this quarter, compared to above-average conditions a year ago. Thermal generation increased quarter-over-quarter, accounting for 23% of PGE's retail load requirement and generation at our Biglow Canyon wind farm was comparable quarter-over-quarter.

Power costs in the second quarter were higher than forecast in the 2013 annual power cost update [tariff], yet were offset by our increased wholesale sales. As a result, net-variable power costs were $13 million below the ADT baseline for the second quarter, compared to $5 million below the baseline for the second quarter of 2012.

For the full year, including the effects of replacement power costs for the coal plant outages, we expect the net-variable power cost to be within the [pecan deadband].

Moving to slide 15, reduction, distribution, and administrative costs total $190 million this quarter, $12 million higher than the second quarter 2012. As expected, pension expense increased by $2 million, and maintenance expense for a generation and distribution systems increased by about $10 million.

O&M expense can vary from quarter to quarter due to seasonal factors, but it is important to note that we are on track for our full-year O&M forecast of $440 million to $460 million. Interest expense decreased $2 million quarter-over-quarter, due to the maturity of two tranche first mortgage bonds that were redeemed with cash, $100 million in October 2012 and $50 million in April 2013. Income taxes decreased $20 million quarter-over-quarter, due to lower pretax income, resulting primarily from the suspension of the Cascade Crossing project.

Now on to slide 16. We continue to maintain a solid balance sheet, including investment-grade credit ratings and strong liquidity. As of June 30, 2013, we had $787 million in cash and available credit, and an equity percentage of 50.4% percent.

In June, we successfully executed equity and debt financings. We completed a public offering of 12.7 million shares of common stock for an offering price of $29.50 per share using a forward sale transaction. 1.7 million shares were issued in June, and our remaining shares are expected to be issued over the next two years.

We also closed the debt offering in the private-placement market for $225 million of first-mortgage bonds at 4.47%, separated into two tranches. $150 million was issued in June, and $75 million will be issued by the end of August.

For the remainder of the year, we expect to issue equity using the forward structure that we currently have outstanding and additional debt for a combined total of $175 million to $225 million. I'm also pleased to report that on June 28, Moody's upgraded our long-term credit ratings, moving our issuer rating from BAA2 to BAA1 and our first-mortgage bonds from A3 to A2. This improvement reflects a constructive regulatory environment and a stable financial profile with adequate liquidity.

Now let's discuss our outlook for the remainder of 2013. As shown on slide 17, as you recall, we revised our guidance on June 3. We are now reducing our 2013 guidance by an additional $0.10 to a $1.25 to $1.40, due to the $10 million to $12 million of replacement power costs for the outages in the Boardman and Colstrip plants.

As slide 18 displays, our revised full-year guidance includes the following assumptions. Energy deliveries, comparable to weather-adjusted 2012 levels, O&M expense between $440 million and $460 million, D&A expense between $240 million and $250 million, and capital expenditures between $710 million and $730 million.

Now back to you, Jim.

Thank you. Although we had several factors that impacted our operating and financial performance this year, we are looking forward to entering a significant phase of growth with the construction of three new generating plants.

We are moving forward with our IRP action plan to bring these resources online on time and on budget meet our customers' long-term energy needs. Now, operator, we are ready for questions.

Thank you.

(Operator Instructions)

Neil Mehta, Goldman Sachs.

Congratulations on the rate case results. Quick question there. Is the pension item still outstanding? That was an item that still to be determined in the settlement, or has that been resolved in this latest iteration?

No, Neil it is still outstanding It is the only item that is outstanding still, because there's multiple utilities involved in this pension discussion. There's a separate docket associated with it. We are going to be moving to that here shortly.

We also filed rebuttal testimony in the case on that issue. We expect staff testimony next week, I think it's. That will help us understand staff's position. We may either just resolve this within the general rate case, or as Jim talked about, we have this generic docket. Just depends how quickly that proceeds through the year.

Got it. And just to confirm, you have no expectation to change your CapEx schedule in light of some of the challenges by Troutdale on the RSP? Any can you just remind us where we stand with that docket and that challenge?

No, we're moving forward with our projects. We feel like we've run a very good process and we had the independent evaluator review the process.

So, TC's has got a petition for a declaratory ruling before the commission. They were supposed to have raised that on August 6, but it's been rescheduled to September 19, special meeting. So, the OPUC will address that issue in mid-September, and we will see where they go with it.

But again, we are moving forward with the project. As you know, our benchmark did not win that bid. It was a third-party bid on our site. We feel like it is a good project for our customers that will provide long-term value.

Last question, just could you walk us through the regulatory strategy in terms of getting each of these assets into rates? When you expect to file? When you expect to ultimately get each of the assets into your rate base?

Let's take them one at a time.

I talked a little bit about it in my script, but just to remind you, the peaker will come on probably either end of '14, early 2015, we just have to see how construction goes. Our plan right now is to file a 2014 general rate -- file a rate case for 2015 test year in early 2014. With that included in the overall revenue requirements and then rate based, with prices be effective when that resource goes into service. That is the first one. Exact timing of that will depend on when prices change, and we are still working on our strategies around that.

The base load resource, Carty Generating Station, we again expect go into service the 2016. We will either file a 2016 general rate case or 2017 general rate case, or even potential a split year, test year to recover the cost of that resource. Again, through a general rate case is the way we would do that.

The third one is the renewable resource. We think that'll come on line in the first half a 2015. We haven't really decided how we will recover the cost. We either use the combination of the renewable adjustment clause and/or general rate case to recover the cost of that resource. Likely we would use the renewable adjustment clause for the period of time when the project comes into service, and then track that into either the renewable adjustment clause or a general rate case in the subsequent year.

I think we've got good strategies. The price increases are fairly minimal and we are looking at strategies to offset that cost. And, trying to capture operational efficiencies to offset the cost of these projects.

Terrific. Thank you so much.

Mike Bates, D.A. Davidson.

As I look at slide 9, examining your CapEx forecast, I'm wondering how firm are you on the timing from year to year with these projects? Have you built in room for potential slippage and construction timelines and whatnot?

These are our best estimates of the construction schedule we have got in place. We are fairly predictable at this point. We've got turbine orders in, we've got project plans in place. The contractors are moving. We feel good about these spends. Obviously if there is something that is out for control that happens related to weather or some type of force majeure, things could change. But right now, these are our best estimates of the capital spend, and given the nature of these projects, we feel good about the numbers.

Sure. And as we think about 2014, obviously by far the peak year in this CapEx budget. Can you give us any picture as to -- is the spent going to be fairly stable from quarter to quarter, or is it weighted toward either other half of the year?

You know, we haven't gotten to monthly cash flow. My guess is, it is going be fairly equal through the year. Obviously, it will be a little lower in the winter season when we can't in and do construction. So, we haven't done a monthly forecast of this so we haven't really given any guidance on the actual monthly flows.

All right. With regards to taking delivery of your equity capital, did I hear correctly that you would anticipate in 2013, that total being from $75 million to $125 million of the overall total?

Jim, do you want to address that?

$175 million, Michael. It's $175 million to $225 million. That includes both the debt and the equity.

$175 million to $225 million?

Yes, both debt and equity.

Remind me, does that include any long-term debt that has not yet been disclosed or priced?

Yes, it does.

Thank you very much.

Paul Ridzon, KeyBanc.

Hello.

Hello, how are you.

Could you give a little more detail on the lumpiness of the O&M throughout the year, and what's driving that?

Yes, Jim, do you want talk about -- we do have seasonal flows. Most of the challenges with O&M each year is when the plants go under construction -- or maintenance during their outages. So, Jim can give you a little bit of better sense for that to the difference between last year this year on the O&M side, but there is a certain amount of seasonality to our O&M, based on the maintenance at our power plants.

There are outages that we typically take that are based on cycles associated with generating plants. You'll do it one year, and you won't do the next year. That's driving a bit of the difference. We've had fewer heating degree days out there, over the last couple of quarters. So that's creating some differences there as well.

In addition, we've had, if you look at last year versus this year, last year was a very high hydro year. We were 126% of normal then. So we had a lot of displacement associated with the power plants. This year, slower hydro year, we are running the plants more, which means that you are going through more cycles. Which means that are getting a bit more O&M expenses associated with it. As a key, the thing to keep in mind is, when you look at it from an annual basis, we are expected to come back in line by year-end.

Thanks. When you expect normal wind conditions for the year, is that a revised wind resource analysis or is that the original?

It is the revised.

I would note that, in the general rate case, we did update the forecast to our best forecast of what wind would look like. The commission adopted that forecast 2014, and we'll continue looking at it as we go through each subsequent test year. But it was a recognition that the wind hasn't generated in the past and I believe are going to -- is it a four-year rolling average?

Five year.

Five-year rolling average on the forecast for wind, which will help true itself up over time.

And then, it sounds like you are going be pretty busy on the regulatory front over the next few years. Is there going to be discussion about transfer of risk of the sharing mechanisms? For power supply cost?

The utilities are looking at the PCAM mechanism right now. The PacifiCorp case, PacifiCorp was effectively handed the same PCAM mechanism that we have got and so we are comparing notes with PacifiCorp and others and plan on having a discussion with the commission on the ability to make improvements in the mechanism. So we're still very early in the process of this point in time. So it's hard to say what those conversations are going to look like.

And then just lastly, the discussion around decoupling an extension there. Was that a controversial issue, or do you think maybe we may see decoupling into the future as far as we can see?

I don't want to say long term future, at least in the next three years, it is in place. I think everyone finds the mechanism to be a right balance of risk and award. It takes way the disincentive to encourage energy efficiency. We've been a real supporter of energy efficiency and we use the Energy Trust of Oregon to implement those programs.

So, I think it is a good mechanism and it allows for both the ups and downs on customer use. Overall, we think we made some small minor modifications to the mechanism, but they are very minor related to the new customer use per customer. So, overall, I think is a good mechanism. There was very little controversy around that mechanism. Again, it applies to our residential and small commercial customers.

Thank you very much.

Thank you.

We will now hear from Andrew Weisel, with Macquarie capital.

Thanks, good morning. Couple questions follow-up on some of what has been discussed. You mentioned you're going to consider using the -- a combination maybe of general rate case and the rider for the renewable costs. Why wouldn't you just use the rider? I thought that was one of the more favorable mechanisms at your disposal because the straightforward and simple. Why would you consider even partially using a general rate case?

Well, the way we would do this is, the year of the project goes into service, we use the renewable adjustment clause. In the subsequent year, you would then, you could use the renewable adjustment clause to put the prices into place on January 1. But if we also have a general rate case contemplated for that exact same period, you would essentially include it in the general price change overall. It just would be simpler that way, rather than having a rider tariff.

It really depends on the timing of other things that we are doing. There's nothing else going on, we would use the [rack], but if we have a general rate case going into service in 2016, we would just incorporate that investment into that rate base and move forward with it. There's no reason to have that extra clause out there. We have a couple of options and it really depends on how we look at our regulatory strategy as we get closer to that timeframe.

Okay. That is helpful. And then the prepare costs related to the two coal plants. Said those would be capitalized. When might those be recovered? Would that be folded into next year's rate case, or could be slipped into the current one?

So what we would do is, in the 2014 test year -- or 2015 test year which we'd file in 2014, whatever that remaining investment would go into our capitalized rate base a be recovered on a going-forward basis. It's likely to be very small just because we think most of the cost will be covered under our insurance program. And it would be recovered over the life of the asset.

Very good. Next question is on load growth. It looks like you are now expecting this year to be flat relative to -- previously you said 0.5% to 1%. Can you talk about the 2Q actual weather-adjusted load growth, and maybe some more underlying trends you are seeing in terms of the economy? It looks like the account growth was there, so what else am I missing?

Yes, we really good strong second quarter and very pleased to see it rebound from what we saw in the first quarter. So, that is encouraging news.

I think we are being still a little bit pessimistic in terms of how things are going as the Oregon economy is -- it's starting to improve, but we've been relatively conservative in terms of how this is ultimately going to play itself out through the rest of the year. Jim, do you want to give us some specific details on it?

Yes, we saw growth in all sectors, effectively, in the second quarter. It was on a weather-adjusted basis. So that was good news, but we are still trying to figure out what happened in the first quarter of the year where we saw quite the opposite.

So, when we looked at it from an annual perspective, we said we need to be a little more conservative in what we think our load forecast looks like, because it would take a pretty good lift to get back to that 0.5% to 1%. So we took the latter approach and said effectively we think it's going be flat to 2012.

By the end of the third quarter, we will have a better look to see how that growth as manifesting itself whether it is basically sticking.

I though the first quarter was flat, ex weather and adjusting for the leap day. Sounds now like you're saying 1Q was actually negative? Do you have the numbers for 1Q and 2Q?

For the first Q, on a weather-adjusted basis, I've got to find it here real quickly --

You said it was flat on the last call.

Yes, when you take out the leap day and other adjustments. But when you look inside it, and you try to figure out what the trends are, it becomes a bit more confusing as to why -- with the trends that you are seeing from the economy, unemployment rates, where new connects are going, where economic outlook looks for the state of Oregon, we would've expected more of an increase than we did in the first quarter.

Okay. Fair enough. And then lastly, to whatever degree you are able to comment, with this Troutdale request, what are some possible range of outcomes? Best case scenario, I would assume, is that the commission just dismisses it. What sort of a realistic negative possible outcome for you guys, whether it is financial or timing or whatever?

As I see it playing out, we will just have to see. I think you the best case right. Worst case is, I guess the commission could move forward with an investigation on this issue. Ultimately, we will go through a prudence review when these resources go into service, which at the time, they would review whether we've deliver these projects on time and on budget. It's hard to tell where it is going to go, but I think we feel like we have followed the process that has been laid out for us.

The only thing we did not ask for was acknowledgment of the short list. But, because of the need to move forward on these resources and preserve the economic value that was bid into the process, we felt we had followed everything and hopefully the commission will sustain that position. You know, it is hard to tell where it could go, but maybe the worst case is they do open an investigation to look at the issues. But again, I feel like we have done everything correctly according to the process that was laid out. And we've identified the least-cost, lowest-risk resource for our customers.

All right, thank you very much for the details.

Sarah Akers, Wells Fargo.

One question on the guidance. With the PCAM falling $14 million below the baseline year-to-date, why is that benefit not offsetting the higher $10 million to $12 million in outage-related costs? Was that positive PCAM benefit already embedded in the prior guidance, or what I missing there?

Sarah, it really gets down to the fact that we are looking at two different metrics. You're looking at the income statement versus looking at the PCAM mechanism, and how the two are accounted for. The PCAM mechanism takes into account that the net of wholesale sales and where on the income statement it's split out.

I think you've got it about right, Sarah. As we put our guidance together, there is some assumption of improvement in over-all power cost. Some of it's in there. There's a wide range for our guidance and some of that will depend on what happens in the overall power markets, associated with hydro and other things. Essentially, I think you've got it about right. Not the whole thing, but some of it is in there.

So is it an expectation of what is going to happen in the second half of the year, besides the outages that's going to bring that back to normal, which I would assume is embedded in guidance? Or are you saying that something better than normal on the PCAM was embedded originally?

I'm not following your question.

I can follow up off-line.

Yes, why don't you follow up off-line, because I think there's just a whole bunch of things moving on. Most of the power costs under-run came in the second quarter. We still have the rest of the year ago, and things can always change. The hydro comes off early. It depends on the shape of the hydro. There's a whole bunch of things that happened when you look at the year -- the quarter-to-quarter distribution on power cost.

Okay. Thank you.

(Operator Instructions)

Mark Barnett, MorningStar Equity Research.

Two quick questions. With the Colstrip replacement power, given that you expect it through the end of the year, have you already essentially fully contracted for that through the year-end 2013?

We have hedged the power costs as soon as we found out the plant was going off line. We went out and we hedged the majority of that risk. There's a little bit of shoulder hours that we didn't bother to cover because you've got wind that will peak up in the evenings and it didn't make sense for us to go ahead and hedge that part. But we did all of the peak load, pretty much.

Okay. I know that you announced this in June and it might be too early to really give more detail, but with the Cascade agreement, is there any chance you could talk about the term in exchange for certain PGE assets investments or transfer capabilities? What that might entail, or is it too early?

It's still too early to tell. We are in detailed conversations with Bonneville on a type of agreement that would allow us to meet our capacity -- long-term transmission capacity needs, and help them meet some of the needs they have on the overall system performance and reliability. Were really working with the parties very closely to try to work out what that arrangement would be.

If we can reach that agreement, then we would ultimately have to take that agreement forward to get regulatory acknowledgment, and at that time we would like to address with the commission our investment in Cascade Crossing, which has really been the precursor to the conversations we have had with Bonneville as the whole transmission situation has changed in the West. We are working hard with Bonneville right now on that issue and, we will just have to see if we can get to an agreement between BPA and PGE on meeting our needs and their needs.

Okay. Thanks.

David Paz, Wolfe Research.

A quick question. Does the $4.5 billion average repay assessment for 2017 include your assumption of the accumulated deferred tax balance?

Yes. We forecasted that in there.

You happen to have a sense of -- if we look at what was in your 2014 rate case, the balance you had in there? How much does it grow by -- in 2017?

Why don't you give Bill a call and maybe he can get you some details on that. We don't have it here.

Okay.

We would just forecast those deferred taxes as part of our overall structure in the text rate that we expect.

Great. Aside from the potential transmission agreement with BPA that you just discussed, are there other potential projects outside of your '13 to '17 capital plan, particularly as we approach the 2020 RPS deadline?

We are right now in a current integrated resource planning discussion that we will file later this year. There is really not a lot of resources on the table, or decisions that are critical in this IRP. The next IRP we will file, which will probably be a couple years after, so 2015-ish, or maybe 2016, we do have to address both the Boardman replacement and our strategy to address that in 2021.

We will have another 5% of renewable energy that we're going to have to add to get to the 2020 target of 20%. So this IRP is relatively light, but the next IRP will be a fair amount of conversation on how we meet those obligations. And, we will work with the constituents and all our parties to figure out what the least-cost, lowest- risk solution is on those decisions.

Regarding RPS, there was discussion about a voter initiative, to include large scale hydro power. Do you know where that stands right now?

The parties are doing ballot title testing. And, they probably want to collect votes -- or signatures to get that initiative on the ballot, but we do understand that the environmental teams -- or groups are looking at increasing the RPS standard also as a potential counter to that measure.

So, it still a little bit of the state of flux. We believe what's been put in place is a good policy. It's unfortunate that, that one party thinks that they want to change a little bit. When it was designed, it was designed with the assumption that we were going to exclude hydro. So, if we had been including hydro, I think the discussion would have been about a higher RPS standard, because the whole thrust of the legislation was to increase the amount of renewables and not just to recognize what was already in place.

We will see how that goes and we think that the current legislation is solid and we would like to see it continue.

Great. Thank you.

Andy Levi, Avon Capital.

One question was asked, second one I didn't listen to that closely. So maybe we can just go over it real quickly. On the equity side, how much equity did you say you would draw down this year?

We didn't say specifically. We just said, a combination of debt and equity from $175 million to $225 million. About one-third of it will probably be equity. We're still sticking to our plan of, we're just going to match our equity draws in the forward structure to our capital expenditure program.

We have a lot of flexibility in the forward structure on how we draw that equity. So we do have some ability to move that around as we need the capital.

Yes, I'm just being a little anal, I'm just trying to get my model all set here. Okay. So about one-third equity. That answers that. And then, with rate base going up, actually 50% -- impressive -- from now to 2017, based on your rate base forecast. How should we think -- I know you've discussed this before, your lag number is pretty stagnant as far as the expense itself, so, should we assume that the ROE lag should at least be cut by 50%, if not more? Is that a simple way to look at? By '17?

Yes, most of the cost that we don't get recovery for are fairly fixed, other than a little bit of inflation on those. As we grow rate base, and grow our earnings, those numbers become a smaller percentage. I don't know exactly 50%, but they will go down and reduce the difference between our regulatory ROE and our actual ROE, which will help.

I guess if rate base grows up to 50% it's simple math, I guess, right?

Yes.

Okay, thank you very much.

(Operator Instructions)

Ashar Khan, Visium.

Just elaborating on Andy's question, is there some way -- [right] the forward -- how should we think of the draw each year? Is there some rough percentages you could give us on how it would be drawn, based on the CapEx forecast?

We made it pretty clear. We want to make our capital structure about 50% debt, 50% equity. We'll use that as guiding principle as we go forward.

I think for the purpose of modeling, that's probably good as an assumption. There may be month-to-month differences as we look at what's the optimal way to draw capital, the extent we're going to issue new debt, we'll want to factor that into that discussion. For modeling, I think that's close enough. For actual, we will be moving that around based on the needs for additional debt financing and the timing of that.

Okay. Could you remind us -- the forward was for how long of a period?

For a two year period.

For a two year period.

We have to draw it by June of what, June 11, 2015.

Okay. Thank you so much.

Okay, I don't think we have any other calls. We really thank you and appreciate your interest in Portland General Electric, and invite you to join us when we report third-quarter 2013 results in November. Thanks a lot, and have a great summer.

That does conclude today's program. Thank you all for joining today.