Good morning, everyone, and welcome to Portland General Electric Company's Fourth Quarter and Full Year 2015 Earnings Results Conference Call. Today is Friday, February 12, 2016. 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, Candice, and good morning to everyone. I'm pleased that you're able to join us today. And before we begin our discussion this morning, I'd like to remind you that we have prepared a presentation to supplement our discussion today, which we'll be referencing throughout the call. The slides are available on our website at portlandgeneral.com. Referring to slide two, 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 law. These statements are subject to factors that may cause actual results to differ materially from the forward-looking statements made today. And for a description 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 release were released via our earnings press release and the 2015 annual Form 10-K before the market open today, and the release is available at 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 a part of any transcript of 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 updates on our operational performance, on Carty construction, our service area economy, and our integrated resource plan. Then, Jim Lobdell will provide more detail around the fourth quarter and full year results, our financing and liquidity, and discuss our outlook for 2016. 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 2015 earnings call. In 2015, we achieved several key objectives towards meeting our customers' energy needs, and I'm pleased to share our results with you this morning. On today's call, I'll provide an overview of our financial results in 2015 and initiate 2016 earnings guidance, give you an update on our operating performance, provide an update on construction at Carty, summarize the economic conditions in our operating area, and outline the status of our 2016 integrated resource plan. Following my remarks, Jim Lobdell will provide details on the fourth quarter, and annual financial results, and end with our key assumptions supporting our outlook for 2016. So let's begin. As presented on slide four, we recorded net income of $172 million or $2.04 per diluted share in 2015, compared with net income of a $175 million or $2.18 per diluted share in 2014. This decrease in earnings per share was largely due to a record warm winter that resulted in lower residential energy sales compounded by lower than budgeted hydro, wind and the associated lower production tax credits and higher replacement power costs. Management took prudent actions and through temporary operation and maintenance reductions offset approximately $0.09 per share of the financial impacts from weather and power costs. Now looking ahead for 2016, we are initiating full-year earnings guidance of $2.20 to $2.35 per diluted share, which reflects warmer than normal weather and lower wind production in January. Jim will provide more details later in the call. Now for an operational update on slide five, employees across the company did an excellent job in 2015 of improving efficiency, reducing costs and executing our business strategy to deliver value to our customers,…

Thank you, Jim. Turning to slide 10. For the fourth quarter of 2015, we recorded a net income of $51 million or $0.57 per diluted share, compared to net income of $43 million or $0.55 per diluted share for the fourth quarter of 2014. This increase was primarily driven by the addition of Port Westward Unit 2 and the Tucannon River Wind Farm in customer prices, AFDC related to the construction of the Carty Generating plant, and a reduction to O&M in the fourth quarter of this year, offset by an increase in share count 2015, related to the final draw in June under the Equity Forward Sale Agreement. Also, targeted earnings for the fourth quarter 2015 were reduced by warm weather, which had a negative impact of $0.05 in comparison to normal. As shown on slide 11, for the full year 2015, we recorded net income of a $172 million or $2.04 per diluted share, compared with the $175 million or $2.18 per diluted share for 2014. This decrease was largely due to the warmest year on record in Oregon, resulting in lower residential energy sales, compounded by lower than planned hydro and wind conditions, resulting in higher replacement power costs, and lower than anticipated production tax credits, and an increase in share count due to the timing of the final draw under the Equity Forward Sale Agreement. These decreases were partially offset by earnings from two additional generating clients, placed in service, Carty AFDC and a strong effort to temporarily reduce O&M spending for the year. Moving onto slide 12. For the full year, total revenues decreased $2 million. This decrease in revenues was primarily due to a reduction in residential energy deliveries, in addition to lower wholesale and other revenues. These decreases were partially offset by a…

Thanks. As we begin 2016, we are moving forward on initiatives that drive value for our customers and shareholders. Slide 17 displays our key objectives for 2016. First, maintain our high level of operational excellence with a focus on employee and public safety, meeting our operational and performance goals and meeting our financial performance targets. Second, bring Carty Generating Station into service, on or before July 31, 2016. And third work collaboratively, with all of our stakeholders, to prepare our 2016 integrated resource plan and its associated action plan, to meet our customer's future energy needs, using resources that provide the best long-term balance of cost and risk. And now operator, we are ready for questions.

Thank you. [Operator Instructions] And our first question comes from Michael Weinstein of UBS. Your line is now open.

Hi, good morning.

Good morning, Michael.

Good morning.

Hey on the results for 2015, where you say that you have a temporary reduction O&M of about $0.09 I believe you said at the beginning of the call.

Yes.

Okay. So, why is that temporary and I'm guessing that since, it's temporary does that $0.09 is now responsible for higher O&M in 2016 guidance. So, going forward in 2017, we would subtract that $0.09 out again to normalize?

No, Mike, I wouldn't do that. What we did in 2015 was to the extent that we could push off any particular activities and not impact safety and reliability or customer satisfaction, we took account for that, but I wouldn't add that back into the following year, or just pick a point in time. We still need to assess or what needs to happen there.

Yeah. In 2016, our O&M is in line with what was allowed in the general rate case and that's for work that needs to be done on our system, to meet our reliability and customer service obligation. What we looked at in 2015, we're delaying some types of work and it's not something we can do permanently.

Right. And also on the Carty project, is there any chance that you guys can finish the project before July right now or is it something you're willing to talk about in terms of is the project ahead of schedule or is it exactly on schedule and any slippage might be a problem?

Well, we have a schedule and it has us completing the project in July and we have some room, but everything is going to have to go perfect. We have to go through the startup, we have to get all the construction work completed. As I mentioned earlier, we’ve mobilized enough people on the site to do the work. Now, we have to see the productivity and we have to see everything go as we have planned. And so, we're going to watch it pretty carefully. We'll know a lot more at our next earnings call. But I would say everything is fully going at this point, and we're moving and things are happening out at the site.

At what point do you think you'll finish negotiating with the surety providers to figure out exactly how much they are going to assume?

That's going to be a process. We do have a meeting scheduled in March, but that will be just the first step in the process with them.

Okay. All right. Thank you very much.

Thank you. And our next question comes from Paul Ridzon of KeyBanc. Your line is now open.

Good morning. How are you?

Good morning.

Good morning, Paul.

Can you parse out the $0.08 headwind we're facing? How much of that is wind and versus weather?

Most of that is all weather, and about $0.02 of it represents wind. And then there's the PTCs in there as well, which is about a $0.015.

Okay. Just back to Mike's question, so how much of the $0.09, how much was deferring versus actually just not doing, and then how much of that $0.09 is creeping into 2016?

The O&M forecast that we have provided the range is to do the work we need to do in 2016. Things that we didn't get done in 2015 or delayed are basically incorporated in our budget for 2016. So, we have a budget now. We have a work we have to get completed and I think we are aligned with our budget for this year.

And that's embedded in our guidance.

Okay. And then just on history of Carty, $514 million was approved and now you're looking $620 million or more. What kind of – what's the delta there?

[With cost] [ph] $140 million, we took the high-end versus the $514 million. So basically what we've got there is we have to remove liens that have been [perfected] [ph] associated with the site. We've got a lot of rework that needs to be done, cost to complete the construction, which is construction and start-up, site stabilization, there are delayed costs that can include productivity, AFUDC and contingency and other costs.

You are successful in securing the full surety Carty will come in under budget?

Well, I think it'll come in pretty much at budget. I think the 514 included the contractor meeting the obligations under the agreement. So, our sense would be is if the sureties do what we think they're responsible for doing, we would come in at our budget amount.

Okay. Thank you very much.

Thanks, Paul.

Thank you. And our next question comes from Chris Turnure of JPMorgan. Your line is now open.

Good morning, Chris.

Good morning, guys.

Good morning, Chris.

Could you give some more color on Carty? Just another question on that front. How do you plan on financing the incremental cash that you're going to need to fund that this year? And have you had any conversations with the commission yet, and kind of walking them through what's gone wrong throughout the process and to the degree that you kind of do about it even before late December?

Well, the first part of the question is, how are we going to go about funding the incremental capital associated with the project. I think as we have mentioned previously, we’ve got plenty of capacity under our short-term [earnings] [ph] access to bank loans that we can provide in order to cover any incremental costs that we have to fund that we're not getting from the sureties associated with the project. On the regulatory side...

Yeah. I can cover that. We've been keeping the PUC informed throughout the process. We recently have been asked to provide an update on Carty through a public meeting. However, it hasn't been scheduled yet. Probably, that meeting would happen sometime in March or April.

Okay. And have you disclosed how much, let's say a one month delay in the project past July 31 would mean for EPS?

No. We haven't.

Okay. And then, my second question is just on the legislation now kind of making its way through the legislature over there. Can you give me some color on what do you think the chances of passage are, and then what that would mean for the next, let’s say five to seven years of capital deployment and renewable growth opportunities for you guys, because certainly in the long-term it would be a big benefit, but I am focused a little bit more on the near-term.

Yeah. So let me give you an update on it, it's called the Oregon Clean Electricity plan, it's called H.B. 4036 is the actual bill number. It just passed out of the House Energy and Environmental Committee on a 6-4 vote. It will now go to the floor for a vote at the House level. Assuming if it passes there than it would move to the Senate Committee, and then work its way through the Senate. The bill essentially does two major things; number one, it eliminates coal in Oregon by 2030 and for us up to five years later for Colstrip up to 2035. And then it increases our renewable portfolio standard targets, mostly in the out year. So it's a 50% standard by 2040. The interim targets are 27% in 2025 versus the current RPS standard of 25%. 35% by 2030, 45% by 2035 and 50% by 2040. So you can see from those new numbers, the bulk of the changes would be in the outer years, as we go to a 50% RPS standard. This will all be factored into our integrated resource plan as we work through the process in this case, because we wouldn't want to go long generation as we think about a higher RPS standard. So, it's all been factored into our planning at this point, but it is all dependent on that law passing the legislature and signed by the Governor. So, that's kind of where it is. We have got support, a number of people are supporting the measure, and there is some opposition to the measure. So, we'll just have to see how it plays out.

Great. That's helpful. Thanks.

Thank you. And our next question comes from Brian Russo of Ladenburg Thalmann. Your line is now open.

Hi, good morning.

Good morning.

Could you just remind us the amount of capacity you need to meet the 20% RPS in 2020, any backup capacity necessary and then, the number of megawatts you need to replace on Boardman?

So, in 2020, the RPS standard goes another 5%. It's probably a very similar to Tucannon River Wind Farm, it's probably around 100 average megawatts. So, it'd be very similar to adding another Tucannon River Wind Farm. If you're thinking about the size of that, that was about 267 megawatt of nameplate capacity. So, a lot of it will depend on capacity factor. So, that's kind of what we're looking at it. The timing of that still kind of up in the air. With the extension of the PTCs, we'll have to evaluate when is the right timing for that unit, because we do have renewable energy credits that we can apply. And so, we're looking at what's the right timing of that, especially given the extension of the production tax credit. That will all be a topic of our integrated resource planning discussion. As it relates to Boardman, our piece of the capacity is about 520 megawatts, hydropower owns 10% of the project. And so, that is again being evaluated on what to – how we replace Boardman in the IRP. Obviously, I think, prior to H.B. 4036, I think our thinking was likely a natural gas prior plant would be that the type of thing we would do, and we would do and we will have to do an RFP like we did before, but as you know, we've said before, Carty has been designed as the two-unit site. So, it would be a very good site to look at the second unit there. But with a 50% RPS standard, we have to kind of consider the entire mix in the long-term trajectory and what's the right kinds of resources we're going to need. So, it's not clear to me at this point, what we will do to replace Boardman, whether it will be more capacity in renewables or base load gas generation. So, that really is the topic of the IRP and we're just now in the process of developing portfolios that we can look at to see what provides the best balance of cost and risk going forward.

And would you need backup power for the – an additional wind farm?

Yeah. As we look at the renewables, as you know, they are not firm energy, at least we haven't found at this point that really correlate directly with our loads. So, it would be a wind farm, backed up by some type of capacity resource, either a simple cycle turbines or reciprocating engines like Port Westward Unit 2. Again, we have capacity needs. That's something that's been identified in the integrated resource plant as we look at what our loss of load probability study show us. And so, that is going to have to be addressed also. But our sense is, we're going to need additional capacity as we go to a higher RPS standard.

Okay. So, just back of the envelope $1,100 a KW for CCGT and maybe $1,500 a KW for wind, I know you talked in probably a $1 billion of potential spend, is that reasonable?

Potentially, again, as you know, we have to go through an RFP. We have to ensure that we have the least cost, lowest risk projects to bring forward. As we've said before, we would always want to include our own self build options and I think we've demonstrated from the construction of Port Westward Unit 2 and Tucannon, that we can deliver those projects on time and on budget. So, we will want to provide our own projects. We have some sites that are very competitive sites, at least on the gas side, and we'll continue to look for those wind farms, and wind projects that can meet our renewable standard.

And when would you expect to get acknowledgement from the OPUC, and when would be RFP process start, and then finish?

Probably in 2017, we expect the acknowledgement from the commission.

We'll file in the later part of this year. We would expect a position decision in early part of 2017. Then, we will go into an RFP process, where hopefully we'd know the decision by late 2018 and then, move forward from there.

Okay. Great. And then, what are the regulatory options for recovery of the Carty costs above what's in the general rate case?

Well, there's couple of things. First of all, it depends on what the number is. Obviously, if we're above that, but only slightly, we'll evaluate that, and we'll have to understand the reasons for that. But, the way we would do that is through general rate case, and next subsequent rate case. At this point, we're not planning on filing a 2017 general rate case, looking to 2018 as a potential. We will then file that case with what we think our prudent capital costs, and we will go through the process to support those costs. If the project is delayed beyond July 31, we will enter into discussions with the stakeholder groups to talk about options to recover the costs. A lot of it will be dependent on when that project will be going online, and we'll determine what's the best way to move that forward. We have options and – but a lot of it depends on when that project would come online.

Okay. And then, I assume that midpoint of your guidance assumes a zero balance on the PCAM?

Yes.

And when was the net variable cost set in terms of gas prices or prevailing commodity prices?

It was set in November, when we file our final update, which includes cost curves and all our contracts that we have in place. Usually, we're about 95% hedged against our forward position. So, we've locked in those financial or physical contracts on gas as well as any electric purchase contracts. So we're pretty balanced in November. So, than the variabilities we deal with are hydro, wind and plant availability. So those are things that we feel. The good news is that hydro is about normal this year. We've had a really good snowpack early on and we'll have to see how it goes for the rest of the year, because that normal forecast does assumes normal precipitation for the rest of the cycle. So, we'll watch that pretty carefully as we see a snowpack build hopefully.

And what appears to be lower gas prices now versus I guess what was implied in November, are you able to optimize your generation fleet to kind of capture that spread, so to speak?

Not necessarily. A lot of it will depend on what happens in markets in terms of opportunity, but our plans are committed to meet our retail load. And so, we've already locked in essentially the gas price for those plants to run and meet our retail load. There may be some opportunity, but probably the only real value is that, if for example, we have lower wind, a lower gas prices would lower our replacement cost instantly with hydro. But on the flipside, if we have a lot of hydro, low gas prices depressed the market price, so we don't get as much value. So it has kind of pluses and minuses as we think about it. But right now, we're hedged against where our loads and resources are.

Okay. Thank you.

Thank you. And our next question comes from Michael Lapides of Goldman Sachs. Your line is now open.

Hi, Michael.

Hi, Michael.

Hey, guys. Congrats on a good year and a good start to 2016. Just curious, thinking about the RFP process and thinking about the IRP as well, does the State of Oregon need capacity or energy or does simply your service territory does and so one of the alternatives in all of this process could be simply increasing the amount of power that could be sent into the Greater Portland area from other parts of the state. The reason that's, I'm kind of thinking through that is, there are – we've seen in other states over the years, Louisiana, Mississippi great example of this also in the desert Southwest, where merchant projects that were in a state like in Oregon or like Louisiana or Arizona, roundup getting bid into RFPs and sold at a price that was well below new build cost. Now, some of the ones in your state, they're not really in downtown Portland, so there it have to be a transmission alternative, but I think that largely will depend on, is it a state need or is it a part of the state need for new capacity in energy?

So, let me talk about that generally. In the last IRP, projects that were available or bid in, and they were not competitive with new generation, just because of higher heat rates and older units. So they were not successful. And to that extent, nothing has been built since then to my knowledge in the region in terms of new gas fire generation.

And then, on top of that, you got several plants that will be taken out of the regional mix, but essentially are the – plants will be going away, Boardman will be going away in 2020, and what has been added to the market place has been mostly in variable energy resources...

Under a contract.

Yeah.

Typically under contract. So, you think about Oregon, and maybe the region, I see has been more capacity deficit, our study show that. And there is just not capacity sitting on the sideline. On an energy basis, it's a really kind of tough issue as we see all these renewables show up in the system. Obviously, what's going on in California with the Duck Curve and all the solar energy down there, those are the things we're looking at, but the strong to California is only so large. And so, we have to think about the reliability of that supply as well as the costs. So, those are things that we are evaluating in the IRP, but I would clearly say, there is a need for additional capacity in the region, especially as we add in more variable resources.

Got it, guys. Thanks. One follow-up, unrelated to that. You made some minor changes to your base CapEx forecast in today's disclosure. Can you just kind of walk us through what drove those changes?

Yeah. Effectively, it was just a shifting of dollars associated with our customer information, and meter data management project, and that was essentially it.

Meaning, moving stuff into 2016 from it, can you just like – which years went up, which years went down and what was the – and was that the main driver of that, when I think about 2016, 2017, 2018 or so?

Well, the movement of dollars from 2017 to 2016.

Got it. Okay. So, you just moved up the project a little bit.

Yes.

Got it. Thanks, guys. Much appreciate it.

Thanks Mike.

Thank you. [Operator Instructions] And our next question comes from Paul Patterson of Glenrock. Your line is now open.

Good morning.

Hi Paul.

Just on H.B. 4036, looks quite ambitious, and I haven't checked. When it passed, I guess it was about yesterday. Were there amendments that addressed some of the issues that I guess are being brought up by the Oregon PUC? I guess, was there any big changes, or would those issues addressed or do you think that – I mean, it looks like it passed with a pretty good margin, I mean I'm just sort of wondering?

Yeah. It passed to explore, I don't recall if there is – I was talking to Dave yesterday, there weren't any major amendments, and there might have been a few tweaks, but nothing that was material to way legislation would setup. I think the important thing to note is that it does still have the cost cap, and that's currently in the legislation today. It also added another standard around reliability. So it has provided certain protections for our consumers that we think are adequate to address the concerns the commission has raised. Our evaluation looking at price impacts on consumers over the lifecycle is Bill, is somewhere in the 1.5% higher prices. So it's not materially higher. As I said, the bill has passed, the House Committee, it's going to the House floor for vote. It can then move to the Senate, where we could see potential other amendments, and we'll have to see how that plays out in the coming weeks.

It looks like it's on schedule for the House passage next week – early next week?

That's correct. And then, it goes to the Senate, Senate Business and Transportation Committee.

Okay. And is energy efficiency part of the RPS standard or is that separate? In other words, I mean, does energy, because I did notice this regional for state thing that was big pushing energy efficiency, is that part of getting to be the standard?

No, because that just reduces our load energy efficiency. It just measures that. We don't want to continue our commitment to energy efficiency. We use the Energy Trust of Oregon to determine what is the least cost, lowest risk energy efficiency and how to acquire that. We do a very detailed study in our IRP to determine what that is. And so, I don't think that changes dramatically in this legislation. It just continues to support the need for energy efficiency, but it does not count against the RPS standard in a sense that it's part of the – how we meet retail load. It would reduce retail load, but it doesn't necessarily count as – against the percentages.

Okay. Excellent. And then, just in terms of obviously this CapEx forecast, we should expect that once this – we get more information on H.B. 4036 and your IRP, that – those numbers will probably be considerably higher, I would expect, correct?

Yeah. I think the question we have to ask and we'll be looking at this in the IRP is, given the shutdown of Boardman in this high RPS standard, what's the right timing and quantity of renewables we need to add to the grid, kind of to get us to the 50%. Because you wouldn't want to necessarily agitate base load gas generation, and then, find out that you have too much generation as you go to a 50% RPS. So we're going to have to think very, very smartly about the right mix of resources and the trajectory to get to that 50% RPS, and the bill does allow us to may be pre-build ahead of the need if we can demonstrate that's the cost effective thing to do. So that's really the magic here in trying to figure this all out is, what's the right timing of doing this in a way that provides the least cost, lowest risk for our customers.

Okay. Great. The rest of my questions have been answered. Thanks so much.

Thank you.

Thank you.

Thank you. And our next question comes from Michael Weinstein of UBS. You line is now open.

Hey guys. A quick follow-up question. On the legislation, as a co-owner of Colstrip 3 and Colstrip 4, just wondering what do you see, how do you anticipate the disposition of that plan once coal by wires eliminate 2035 for it, under the legislation, what do you see happening with it?

So, we've thought a lot about that. Obviously, our plan under this would be to recover all the capital costs and decommissioning costs through 2030 or 2035 depending on – the legislation allows us to keep the plan in customer prices through 2035. So, beyond that, the question is, what would we do with the plant. There is options we would consider obviously, if the plant continues to operate, it has value, we could either sell it in an auction, we could sell the power in the market. Those are two considerations as we look forward. And those are the things we'll have to evaluate as we get closer to that period. And so, we don't have any answer yet, but we have options.

On minority owner.

Yeah. We're a 20% owner in Colstrip 3 and Colstrip 4. So, it's not like we can decide to shut the project down. And so, we will look at that as we get closer to that timeframe, but those are the two options we would consider.

Okay. I'm just wondering if there's been any moves to try to push to sell to [indiscernible] just like they're doing with Colstrip 1 and Colstrip 2?

Well, yeah, I understand that. And...

Yeah.

In Washington, they have a prohibition from utilities buying coal output also. So, I know they're working on their own issues around units 1, 2, 3, and 4. And we'll have a lot to see when we get there. I think the landscape can change. Montana is a potential market. Obviously, there are other places that power could be sourced to. Yeah.

Right. Okay. Thank you.

Thank you. And our next question comes from [indiscernible]. Your line is now open.

Hi, good morning.

Good morning.

Good morning.

Just a question on slide 14 regarding the financing. You guys have year marked about a $160 million of additional bonds you may issue. Is that currently embedded in the future testier that you have this year, and then in guidance? What's the situation with the interest related to that? And what was the site, if you issue it or not?

Yeah. Now, it is included in the guidance already.

It's included in the rate case too.

Including the rate case too.

Because I think, do we update the numbers for those bonds or?

Updated for the bonds of ...

January.

January, yeah.

Okay.

Great thing. If you aligned up with the guidance that we have.

Okay. And then, just one follow-up question. Now, this is kind of an asset, I just want to make sure I understand it correctly. On the surety bonds, by when do you need to have some kind of resolution on those before you decide to take action at the commission? I mean, you can have the plant in service by your required service date, but when do you need to know about the recovery of the surety bonds before you go to the commission?

Well, right now, our prices are based about on the $540 million, and that's kind of the agreement we have, the next time we would address this in a subsequent general rate case. And so, we would obviously need to have that resolved by then, but if we're looking at a 2018 general rate case, we've got sufficient time to address that. Again, our hope is that we will get full compensation for the cost exceedance, but that's obviously something we have to work through with the sureties.

Okay. I appreciate it. Thank you and congratulations.

Okay.

Thank you. And our next question comes from Michael Lapides of Goldman Sachs. Your line is now open.

Hey guys. Just a quick question on rate case timing again, meaning going forward. It doesn't sound like you are going to do a lot of construction on stuff related to the RFO or RFP until the 2019 timeframe. Do you anticipate filing again between now and then?

Yeah. Right now, our thinking is, 2018 general rate case, but a lot of that will depend on load growth, inflation, cost controls, just a number of factors that we look at. We clearly have not filed for a 2017 rate case and don't anticipate doing that, absence something going on with Carty. So, we would likely look at 2018. We will make that decision till probably November of this year, when we finish our budget to be filed in February of 2017 for a 2018 general rate case, if we decided to do that. A lot of it will also depend on interest rates, what return on equities are doing. So, there are a whole bunch of factors will go into that decision. But right now, that's kind of what we're pointing towards, but we haven't made a final decision.

Got it. So, you would file in 2017 for 2018, but that really wouldn't incorporate many of the stuff coming out of the RFP process?

Not at this point now. And to the extent there are renewable resources, we do have the tracking mechanism under the current RPS standard, that those can get track in directly when they go into service. So, we'd only be either capacity resources or something other type of thermal resources that would have to get, whether we require a general rate case. So, we could actually track in the renewables with the current standards we have and the mechanism we have.

Got it, guys. Thank you. Much appreciate it.

Thank you.

Thank you.

Okay. I think that's the end of the calls. We appreciate your interest in Portland General Electric and invite you to join us when we report our first quarter 2016 results in late April. Thanks, again, and have a great day.