Good morning 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's Director of Investor Relations, Mr. Bill Valach. Please go ahead, sir.

Thanks, Beth and that's Portland General Electric and we're pleased that you're able to join us this morning. Before we begin our discussion this morning I would like to remind you that we have prepared a PowerPoint presentation to supplement our discussion today and we'll 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 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 facts and as such constitute forward-looking statements under current laws. These statements are subject to factors that may cause actual results to differ materially from the forward-looking statements made today. And for 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 second quarter earnings were released before the market opened today and the release 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 these Safe Harbor statements should be incorporated as part of any transcript on this call. As shown on slide three, 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's my pleasure to turn the call over to Jim Piro.

Good morning and thank you for joining us. Welcome to Portland General Electric's second quarter 2013 earnings call. As slide four shows on today's call, I'll provide an update on our strategic initiatives, summarize the progress we've 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 five, 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 six, 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 of 2015. We expect to file our general rate case in early 2014 with a 2015 test year to recover the costs, which by itself may result in a customer price increase 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 plans.…

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, and $9 million customer 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 have 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 an industrial customer who is incorrectly build for several periods. Energy deliveries, adjusted for weather were up 2% quarter-over-quarter. We've seen 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 lease 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 is 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 cost in the second quarter were higher than forecast in 2013 annual power cost update tariff that were offset by an increase total sales. As a…

Thank you. Although, we had several factors that impacted our operating and financial performance this year, we're looking forward to entering a significant phase of growth with a 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 to meet our customers' long-term energy needs. Now operator, we're ready for the questions.

(Operator Instructions) Our first question today will come from Neil Mehta with Goldman Sachs.

Congratulations on the rate case results. Quick question there. Is the pension item still outstanding as that was an item that was still to be determined in the settlement or has that been resolved in the (inaudible)?

Neil, it's still outstanding, it's the only item that's outstanding still, because there's multiple utilities involved in at this pension discussion. There is a separate docket associated with it. So, we are going to be moving through that here shortly.

Yeah, we also filed rebuttal testimony in the case on that issue. We expect staff testimony next week I think it is. So, that will help us understand staff positions who may either just resolve this within the General Rate Case or as Jim talked about, we have this generic docket just to stay on top quickly that proceeds through the year.

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

So, no, we are moving forward with our projects. We feel like we've run a very good process and we had the independent valuator to review the process. So, PC has got a potential 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're moving forward with the project. As you know, our benchmark did not win that bid. It was a third-party bid on our site and we feel like it's a good project for our customers that provide long-term value.

And last question. Just, could you walk us through the right inventory 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 integrated?

So let's take one at a time. I talked a little bit about it in my script, but just to remind you. The Picker will come on probably either in the ‘14 or early 2015, we just have to see how construction goes. Our plan right now is to file 2014 Generate Rate, file our rate case to the 2015 test year in early 2014 with that included in the overall revenue requirements and in rate base, with prices to be effective when that resource goes in to service. So that's the first one. Exact timing of that will depend on when prices change, and we're still working on our strategies around that. The baseload resource, Carty generating station, we again expected to go into service in mid-2016. We will either file a 2016 General Rate Case or a 2017 General Rate Case or even potentially a split year, test year to recover the cost of that resource, again through a General Rate Case as the way we will do that. And the third one is the renewable resource. We think that will come online in the first half of 2015. We haven't really decided how we're going to recover the costs. We either use the combination of the renewable adjustment clause and/or General Rate Case to recover the cost of that resource, like we use the renewable adjustment clause for the period time when the project comes into service and then track and either through renewable adjustment clause or a General Rate Case in this subsequent year. So I think we've got a good strategy. The price increases are fairly minimal and we are looking at strategies to offset that cost and trying to capture operational efficiencies again to offset the cost of these projects.

Moving on to our next question, we will go to Mike Bates with D.A. Davidson. Mike Bates - D.A. Davidson & Co.: As I look at slide nine, just examining your CapEx forecast, I am wondering how from are you on the timing from year-to-year with these projects, is there, have you built in room for any potential slippage in construction timelines or what not?

These are our best estimates of the construction schedule that we guide in place. It's fairly predictable at this point. We have turbine orders in. We've got projects plans in place. The contractors are moving. We feel pretty good about this spend. So obviously if there is something that's out of our 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 pretty good about these numbers. Mike Bates - D.A. Davidson & Co.: 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 spend going to be fairly stable from quarter-to-quarter or is it weighted toward either half of the year?

We haven't got the monthly cash flows. My guess is it's going to be fairly equal through the year. Obviously it will be a little lower in the winter season when we can't get in and do construction. So, we haven't done the monthly forecast also. We really haven't given any guidance on the actual monthly flows. Mike Bates - D.A. Davidson & Co.: All right. And then with regards to taken 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 Michael, it's 175 to 225. And that includes both debt and… Mike Bates - D.A. Davidson & Co.: 175 to 225.

Yeah, both debt and equity. Mike Bates - D.A. Davidson & Co.: All right. And remind me, does that include any long-term debt that has not yet been disclosed or priced?

Yes, it does.

And we will now go to Paul Risdon with KeyBanc.

Can you just give some more detail on the lumpiness of O&M throughout the year and kind of what is driving that?

I mean we do have seasonal flows. Most of the challenges with O&M each year is when the plants go under construction, our maintenance during the outages. And so Jim can give you a little better sense of that on the difference between last year and this year on the O&M side, but there is certain amount of seasonality to our O&M based on the maintenance at our plants.

Yeah, there are outage that we typically take that are based on cycles associated with generating plants. You will do it one year and you want do it the next year. So, that's driving a bit of the difference. We've had fewer heating degree days out there over the last couple of quarter. 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 very high, high growth year, we were 126% of normal event. So we had a lot of displacement associated with the power plant. This year for a hydro year, we're running the plants more, which means you're going two more cycles, which means that you're getting a bit more O&M expenses associated with it. But the key thing to keep in mind is when you look at it from an annual basis, we're expected to come back in line by year end.

Thanks. And when do you expect normal wind conditions for the year, is that kind of a revised wind resource analysis or is that the original?

It's revised. And I would note that in the General Rate Case, we did update the forecast to our best forecast wind would look like, the commission adopted that forecast 2014 and we continue to looking at 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 we're going to the four year rolling average -- five year rolling average on the forecast of wind, which will help through step up over time.

And then it sounds like you are going to be pretty busy on the regulatory front over the next few years. Is there going to be a discussion about kind of transfer of risk of the sharing mechanisms for power supply cost? Or is that something-

The utilities are looking at the PCAM mechanism right now, and out on the PacifiCorp was effectively handed the same PCAM mechanism that we have got. And so we're comparing notes with PacifiCorp and others and plan on having a discussion with the Commission on the ability to make improvements in that mechanism. So we're still very early in the process at this particular 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 and the extension there, was that a controversial issue or do you think maybe we may just see decoupling into the future as far as we can see.

You know I don't want to say a long term future at least the next three years it's in place. I think everyone finds the mechanism to be a right balance of risk and reward. It takes away the disincentive to encourage energy efficiency. You know we've been a real supporter of energy efficiency and we used the Energy Trust of Oregon to implement those programs. So I think it's a good mechanism and it allows for both the ups and downs on customer use and so overall we think we made some small minor modifications to the mechanism but they're very minor related to the new customer use per customer. So overall I think it's a good mechanism. There was very little controversy around that mechanism. Again it applies to our residential and small commercial customers.

And we'll now hear from Andrew Weisel with Macquarie Capital.

A couple of questions to follow-up on some what's been discussed. You mentioned you're going to consider using a combination maybe of general rate case and the rider of the recover 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 it's straight forward and simple. Why would you consider even partially using a general rate case?

Well, the way we would do this as the year of the project goes in to service, we've used the renewable adjustment clause. In the subsequent year, you would then -- you could use the renewable adjustment clause to put the rate, the prices in [took] place on January 1. But if we also have a general rate case, are 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. So it really depends on the timing of other things that we're doing. If there's nothing else going on, we would use the RAC but if we have a general rate case going in to service on 2016, we would just incorporate that investment in to that rate base and move forward it. There is no reason to have that extra clause out there. So we have a couple of options and it really depends on how we look at our regulatory strategy as we get close to that timeframe.

Okay, that's helpful and the repair cost related to two coal plants. You said those will be capitalized. When might those be recovered? Would that be folded in to next year's rate case or could it be slipped in to the current one?

So what we do is in the 2014 test year or 2015 test year, what we file in 2014, whatever that remaining investment would go in to our capitalized rate base and 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 will be recovered on the life of the asset.

Very good, next question is on load growth, it looks like you're now expecting this year to be flat relative to a previously you said, 0.5% to 1%, can you maybe talk about the 2Q actual weather adjusted load growth and maybe similar, underlying trends you're seeing in terms of the economy, looks like the account growth was there. So what else am I missing?

Yeah, we had a really good strong second quarter and very pleased to see it kind of rebound from what we saw in the first quarter. So that's encouraging news, I think we're being still a little bit pessimistic in terms of how things are going as the Oregon economy is 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 can you give us some specific details on it?

Yeah, we saw growth in all sectors effectively in the second quarter, so it was on a weather adjusted basis, so that was good news. We're still trying to figure out what happened in the first quarter of the year, where we saw quite the opposite. So when we look at it from an annual perspective, we said we need be a little bit more conservative on what we think our load forecast looks like, because it would take a pretty good lift in order to get back to 0.5% or 1% so. We took the lateral approach and so effectively we think it's going to be flat to 2012.

By the end of the third quarter, we'll have better look to see how that growth is manifesting itself and whether there -- it's basically sticking.

I thought, the first quarter was flat ex-weather in adjusting for the leap date, current -- now look – you're saying 1Q was actually negative, could you have the numbers for 1Q and 2Q?

For the first Q, on a weather adjusted basis.

You said it was flat on the last call?

Yeah, when you take out the leap day and other adjustments, but when you look inside it, and we are trying to figure out what the trends are it becomes a bit more confusing as to why with the trends you are seeing from the economy, unemployment rates or new connection going where economic outlook looks for the State of Oregon. We would have expected more of an increased than we did in the first quarter.

Okay, fair enough, and then lastly to whatever degree you are able to comment with this trout request, what are some possible range of outcomes, you know, best case scenario, I would assume is that the commission just dismisses it, what sort of realistic negative possible outcome for you guys whether its financial or timing or whatever?

As you know, as I see it playing out we just have to see, I think you got the best case, right, the worst case is that, I guess the commission could move forward with an investigation on this issue. Ultimately, we will go through a prudence review and this resource goes in the service which is them if they would review whether we've delivered 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 is going to laid out for us. The only we did not ask for was acknowledgement of the shortlist but because of the need to move forward on this resources and preserve the economic value that was bid into the process, we felt we had borrowed everything and hopefully the commission will sustain at position, but it's hard to tell where it could go but maybe the worst cases they do open investigations and look at the issues. But again, I feel like we've done everything correctly according to process that was laid out and we've identified the leased cost lowest risk resource for our customers.

And we'll now go to Sarah Akers with Wells Fargo.

Just one question on the guidance. With the PKM 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 PKM benefit already embedded in the prior guidance or what am I missing there?

Sarah, really gets down to the fact that we're looking at two different metrics, you are looking at the income statement versus looking at the PKM mechanism and how the two are accounted for the PKM mechanism takes into account that the net of wholesale sales. And where an income statement it's split out. So there is some…

Yes, I think you got about right. Sarah, if we put our guidance together, there is some assumption of improvement in overall power cost, some of it's been there. There is a wide range for our guidance and some of that will depend on what happens in overall power markets associated with hydro and other thing. So, essentially that, I think you got it about right. Not the whole but there is some of it's in there.

So, is it an expectation of what's going to happen in the second half of the year, besides the outages that's going to bring that back kind of to normal which I would assume is in better than guidance or you saying that better the normal on the PKM wasn't embedded originally?

Not following your question?

I can follow-up offline.

Yeah why don't you follow-up offline because I think there's just all bunch of things that are moving on, you know, most of the power costs under in came in the second quarter, we still have the rest of the year to go 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 happen when we look at the year, the quarter-to-quarter distribution on power cost.

(Operator Instructions) And we will now go to Mark Barnett with Morningstar Equity Research.

Two quick questions, with the culture for placement 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 since we found out that the plant was going offline. We went out and we hedged the majority of that risk. It's a little bit of shoulder hours that we didn't bother to cover because you got a win that will peak up in the evening and it didn't make sense for us to go ahead and hedge that part. But we did all of that peak load pretty much.

I know you announced this in June and might be too early to really give more details but with the Cascade agreements, is there any chance for you to talk about the term and exchange for certain PGEF based investments or transport capabilities, what that might entail, or is it too early?

No, it's still too early to tell. We're in detailed conversation with Bonneville on a type of an 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. So we're really working with the parties very closely. They try to work out what the arrangement would be. If we can reach that agreement, then we would ultimately have to take that agreement forward to get regulatory acknowledgement and at that time we would like to address what the commission are investment in Cascade Crossing which has really been the precursor to the conversations we've had with Bonneville as the whole transmission situations change in the west. So we're working hard with Bonneville right now on that issue and we would just have to see if we can get to an agreement between BPA and PGE on meeting our needs and their needs.

And moving on, we will now go to David Paz with Wolfe Research.

Quick question. Does the $4.5 billion average rate investment for 2017 include your assumption of your cumulated deferred tax balance?

Yes, we forecasted right in there.

Okay, do you have any sense of, if we look at what was in your 2014 rate case, the balance you got in there, how much does it grow in 2017?

I want to you to give Jim a call maybe he can give us a little detail on that. We don't have it here. We would just forecast those deferred taxes as part of our overall structure and the tax rates that we expect.

Great, despite from the potential transmission agreement that you just discussed, are there other potential projects outside of your ‘13 or ‘17 capital plans, particularly as I guess we approach the 2020 I guess deadline?

We are right now in 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 probably be a couple years after now, so 2015ish or may be 2016. We do have to address both the Boardman replacement and our strategy to address that in 2021. We'll have another 5% of renewable energy that we are going to have to add to get to the 2020 target of 20%. And so IRP is relatively light, but the next IRP will be a fair amount of conversations on how we meet those obligations and we will work with the constituents and all our parties to figure out what the lease cost lowest risk solution is on those decisions.

Okay. And I guess just regarding our PSO, I know there was some discussion about vote initiative include large hydro power, you know where that stands right now?

The parties are doing ballot title testing and they are probably want to collect both signatures to get that initiative on the ballot. We do understand that the environmental teams or groups maybe looking at increasing the RPS standard also as a potential counter to that measure, so it's still little bit in the state of flux. And we believe what put in place is a good policy. It's unfortunate that that one party thinks that 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 not just to recognize what was already in place. So we will see how that goes and we think that the curve legislation is solid and we would like to see it continue.

And our next question will come from Andy Levi with Avon Capital.

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

We didn't say specifically, we said combination of debt and equity from 175 to 225, about a third that will probably be equity. We are still sticking to our plan I want go guess going to match our equity draws in the forward structure to our capital expenditure programs.

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

And then with rate base going up actually 50% is impressive from now just 2017 based on your rate base forecast. How should we think, I know you discussed this before, but your lag number is pretty stagnant as far as the expense itself, so should we assume that the ROE lag should lease because it have if not more is that kind of the simple way to look at it by 17?

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

So I guess if rate base goes up 50%, it's kind of a simple math I guess right?

Yes.

(Operator Instructions). We'll now go to Ashar Khan with Visium.

I guess just elaborating on Andy's question, is there some way write the forward how should we think of the draw each year, is there some rough percentages you could give us that how it would be drawn based on the CapEx forecast?

We've been pretty clear, we want to keep our capital structure about 50% debt, 50% equity, we'll use that as a guiding principle as we go forward. I think for purpose of modeling that's probably as good as assumption or maybe month to month differences as we look at what's the optimal way to drive capital. To the extent we're going to issue new debt, we want to factor that into that discussion. So for modeling, I think that's closed enough, for actual we'll be moving that around based on the needs for additional debt financing and the timing of that.

Could you give remind us how the forward was for how long of a period?

It's for a two year period

For two year period.

We want to draw by June 11 of 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.