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 call 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 are 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 will 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 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. 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 when the market open 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 lineup 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 customer in the second quarter of $0.07, and 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 the fair outcome in final order on 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 are 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 Tucannon, 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 in the spring. In the mean time, construction will continue with engine and generator installation and substation construction. Slide 6…

Thank you, Jim. Turning to slide 12, in fourth quarter of 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 of 2012. This increase was primarily driven by three items, a $21 million increase in retail revenues as the result of an increase in energy deliveries due to a colder weather in 2013, a $5 million increase in AFDC due to higher [indiscernible] 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 cash balances recorded in 2012. These benefits were partially offset by $16 million -- in 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 plant outages during the quarter. As shown on slide 13, for the full year of 2013, we recorded net income of a 105 million or $1.35 per diluted share compared to a $141 million or a $1.87 per diluted share for 2012. This decrease was primarily driven by four items, a $9 million decrease in revenues from a customer billing refund in the second quarter of 2013, 17 million of incremental replacement power costs involving Coyote Spring and Colstrip Unit 4 outages, a $17 million increase in operations and maintenance expense, including increases in generation and distribution 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 [indiscernible] balances for the three new generating projects, a $7 million benefit from earnings from our non-qualified…

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 system safely, efficiently and effectively. Now operator we’re ready for questions.

Thank you. [Operator Instructions] And we’ll take our first question from Neil Mehta with Goldman Sachs.

Good morning.

Good morning Neil.

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

And so you’re talking about our Carty one project.

Yes, the Carty project.

So right now our forecast is to have that plant come online mid-2016. And we have -- no 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 will be depended on the timing of the construction of that project but that currently generally what we’re thinking about, but as I said we haven’t made a final decision.

And then Jim on hydro looking pretty dry up there and checked out this forecast, it looks like it’s going to raining for the next 10 days in a row.

Love it.

Embedded in your guidance is normal hydro and it seems like that’s the expectation based on forecast?

Yes. As we’ve always said on these calls, these early calls is it’s too hard to call right now. And 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 and so right now the forecast is about 96% and it’s still too early to call it and we’ll wait till 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’ve got a lot of snow up in the mountains but we still have a few more months to go.

And I think Neil a lot of its sitting up in Canada, so as they release it down the river we'll benefit from it.

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

So for the year-over-year it was flat on a weather adjusted basis. Second question.

How favorable was weather versus normal in 2013?

Quarter-over-quarter it amounted to quite a bit. It’s almost $0.09.

And for the full year?

Year-over-year about $0.05

And we’ll now go to Brian Russo with 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 and a lot of it will depend on how we draw the equity forward. So, I think we’re still looking at options whether we draw it early or late and so that will depend on the final share count.

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

At year end.

Yes. At year end.

Yes. But the actual distribution will depend.

Right.

88, 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.

Yes, Brian, we’re still working with the other utilizes 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 we’re still working with them on trying 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?

The way the process goes is all 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 and do as much a 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’re trying to get at?

Yes, exactly.

You go on the website and go to the revenue requirements estimate; you’ll see the rate base and all the components of that which is pretty detailed.

We will now go to Sarah Akers with 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’s 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 where it’s 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 that could delay the pull on that equity forward. So, it really -- if you’re asking just about the first mortgage bonds so that will have to be in the later 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?

You know, we are committed having a competitive dividend for our shareholders as these projects come on line and we generate earnings, I think the Board, obviously I can’t speak for the entire Board, but the Board was committed to continue to raise the dividend as we go forward. We typically address the dividend in our May Board meeting and I would suspect if we continue on a trajectory we will move the dividend up. I think we’ve got a payout ratio kind of ranged that 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.

We will now go to Brian Chin with Merill Lynch

Hi. 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.

You know if you model the stuff the best way to model is to do your base, you know net income and then you have to look at the wind generation, historically that factor in the production tax credit. The PTCs are real driver to the lower tax rate. So we are at the marginal rate of around 40% and then you have to subtract the after tax, the tax credits that we get from the wind farming. You can look at historic averages on wind and the tax credit in 2014 is $23 per megawatt hour.

Okay so, but if we look at the marginal tax rate and then back down to from the PTCs effectively at around 30% tax rate, gets us within the ballpark of what [indiscernible].

That gets you in the ballpark, so if you’re doing it that way and you come up about that number, you got a good model, that way as revenues are cross changed, you want to just stick with the 30%, because it isn’t right, because they will change based on taxable income.

(Operator Instructions) We will now go to Mark Barnett with Morningstar.

Three questions, not necessarily something directly related but regulators have gotten a little bit -- I guess a little bit louder about the Colstrip plant. And the true economics of those plants kind of notwithstanding; couple of years down the line, is there an option out there to replace power from those, should there be maybe action taken to replace some, for the owner and with that these to 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 plant. Puget is 50% owner of 1 and 2, and then they are a smaller shareholder of 3 and 4. We are at 20% owner of Colstrip 3 and 20% owner of Colstrip 4. So we are a kind of a minor player in those projects. They are still very cost effective resources for the company. We need to understand that one and two is much older than units three and four, and so they are going to be probably the focus of the initial conversations. Units three and four 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 [1011D] process and greenhouse gases related to existing resources. So we got 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 you will 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 policy issues that unfolds. So and more to play out on that, I think we'll see probably more focus on 1 and 2. From my perspective I think that would be where the initial focus is but we will have to watch where the EPA regulations go.

Thanks for clearing that up. I was thinking your interest within one and two. That was just a confusion on my part. One quick thing, a follow-up on your questions about the equity drop, it's entirely related to the funding limitations you have from the write-off, there is no change in your CapEx outlay within 2014?

No, there is no change, just a matter of timing.

[Operator Instructions]. I will now go to Maurice May with Wellington Shields.

Anyhow on your PKM, the results in 2013, you said that it was 11 million above the baseline. That means that show orders essentially absorbed $11 million of expense there, right?

Yes.

Okay and you have initiative that you’re pursuing with other utilities in Oregon as well as with the staff at the OPC, and the purpose of this is for what? Are you looking for tighter bands, or are you looking for symmetrical dead band for fairness or what exactly is your objective here?

We are looking for all of the above Marty. Again as mentioned earlier, we are in conversations with the other utilities. As I also told, many of the analysts that I met with over time; this is specific or was just recently handed our PKM 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 are all kind of agree up on. So we’re trying to scope out exactly what that looks like and get agreement that everybody believes that we should move forward into the right docket and see if we can find some resolution.

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

Yes Marty, this is Jim, Oregon has had a long history of a sharing mechanism, even way-way back in the 80s it was an 80-20 power cost adjustment mechanism. So whether we -- the chance, we never say never, but the chance again to 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 a sharing some of the risk from $1 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’ll keep working on these issues similar to what we did with [indiscernible]. We just can’t 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. But I don’t think we'll get to a 100% I think that just given the history of Oregon, Washington even Idaho there is some type of sharing and I believe the regulators like to see us having some skin in the game and to assure that we’re motivated as we always are to keep our cost down.

Yes, okay, all right. Moving on to plan operations for 2014, what is the outlook for scheduled outages in your fossil fuel plants?

Nothing special Boardman schedule for a 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 my perspective. So we will bring the dry sorbent injection project online for Boardman but that’s 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 at three of your plants and just reassure us a little bit that that’s very unusual on what's happened in 2014, can you do that?

Can’t do it necessarily but I would 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 rotor was an unusual situation that hit back and never been seen before by General Electric on those seven FAs. So we’ve got that corrected and that unit's been just running well since we brought it back online. Colstrip unit four, as you know we don’t operate that project but that generator was kind of the original generator and things do wear out of a time as 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 had a long, since it came back online in August, it’s had a continuous run cycle. So we’ve met our commitment getting the projects back online. And the other thing we really pride ourselves on is reliability centered maintenance to really be ahead of the curve on maintenance and making sure that we’re on top of all our procedures. So hopefully it was just a one off thing and I think we’re set up well for this year.

And we will now go to Andrew Weisel with 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’re all kind of over one to three years. So we’ve got -- first of all we had [Trojan] de-commissioning fund excess balance that we want to refund back to customers. We consider U.S. DoD over de-commissioning. They were supposed to take our fuel number of years ago they didn’t perform and we took the DoD to court. We ultimately settled and got a $44 million award for prior non-performance and an additional $6 million coming for current year non-performance. 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 persuade 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.

Any earnings impact, is that all earnings neutral for you?

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

Okay, great. Then 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 renewal adjustment cost. I know you’ve gone back and forth, just the final decision.

So just a couple of things there, we decided, first of all the rack will go into place during the time the project comes online because they’ll come on in various, as each string or each line of turbines comes online we would put that into service so we could start generating production tax credits and that go through the rack, the renewable adjustment cost mechanism as each stream comes online until the project fully goes operational. Our plan was that, excuse me, our plan is that putting the project in customer prices immediately when the project’s 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 rack 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 commissions and staff rather say no, we want you to wait till 2016, then we can run the rack for all of 2015 but then we’ll build up a deferral which would then have to amortized.

And the strings start coming online when?

Probably later in 2014.

And we will now go to Paul Ridzon, with KeyBanc.

Had a quick question on a clarification around the equity. At the midpoint of guidance was that an assumption of issuing your equity ratably through the year.

Paul, we’re assuming that we’re going to issue it in the first half of the year.

All of it?

Yes.

And yes, we’ll go ahead and go to Andrew Levi with Avon Capital.

Hey, good morning guys. Just kind of a longer look type of question, so as you get out to like ’16 and ’17 and these plants all come online and you get through the rate process, do you think you guys have a lot of free cash flow after dividends and could you possibly talk what your thoughts are on that, is something that you’d ramp up the dividends, have opportunities for stock buyback or there’re other longer term projects after the, 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 decision on what’s the right set of resources to replace that base flow 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-filled 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 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 customers’ needs, but those will all be the subject of the integrated resource plan that will 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 and as always we want to optimize our capital structure around the 50% debt, 50% equity looking at increasing dividends to address that and you know potentially if necessary buy back stock, but it’s really too early to make a call on that. We got a lot of process ahead of us and we’ll get a better sense of that once we get to the next integrated resource plan.

And if you were successful on those two potential longer term projects when would the spend begin on those, you know…

Well, probably not till ’19, takes about 2.5-3 years to get a gas project up though we would propose probably Carty 2 as a very good base flow gas resource if that’s the least cost, lowest risk option. Probably a two year construction cycle, the wind farm again probably in the ’19 timeframe, we probably don’t need that project up till 2021 or the end of 2020 as the soonest, but probably in that timeframe, so it’s a little bit of period in 2018, and ’19 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 a $100 million project that we’re making progress on, I think what we would do is to continue to build the equity structure, address the dividends to get them competitive and look at the future for future capital expenditures.

So, I guess, your ’16 and ’17 Cap Ex forecast could go up, I guess they don’t include these upgrades to your customer service [indiscernible] ….

We have not those in our forecast right now. It is in, 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 that we’re also doing some 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 in agreement that we need to replace our billing system and have been helping us fund that project in the early stages. We’d likely make the decision on the billing system later this year.

So basically we get more rate based growth which hopefully turns into earnings growth or we return cash to shareholders through either dividends, share buyback or both…

And again we’re going to optimize our capital structure seeing as our target 50% debt, 50% equity and use all the tools available to do that.

And then the last question is, as you get to ’16 or ’17 you know you have this regulatory lag kind of on some fixed expenses and we’ve discussed this before on these conference calls, where, that number is fairly fixed is my understanding. So you any number you want to throw out, may not want you, but where, how much we can reduce lag or you can reduce lag by ’16 or ’17 relative to where it is today.

You’re talking about the difference between allowed ROE and actual ROE.

Yes, my understanding is that the cost that you’re no recovering are fairly fixed, so, as your rate base grows and you have recovery of that that number should shrink.

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

Of lag?

Of lag, yes.

And it appears 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.