Chris Liddle - Manager of IR and Corporate Finance Jim Piro - President and CEO Jim Lobdell - SVP, Finance, CFO and Treasurer.

Paul Ridzon - KeyBanc Capital Markets Julien Dumoulin-Smith - UBS Michael Lapides - Goldman Sachs Brian Russo - Ladenburg Thalmann Michael Weinstein - Credit Suisse Travis Miller - MorningStar Andy Levi - Avon Capital Advisors.

Good morning everyone and welcome to Portland General Electric Company’s Third Quarter 2016 Earnings Results Conference Call. Today is Friday, October 28, 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 will turn the conference call over to Portland General Electric’s Manager of Investor Relations and Corporate Finance, Chris Bill Valach. Please go ahead sir..

Thank you, Chelsea. Good morning everyone. I’m pleased that you’re able to join us today. Before we begin our discussion this morning, I’d like to remind you that we have prepared a presentation to supplement our discussion and which we will be referencing throughout the call. The slides are available on our website at investors.portlandgeneral.com.

Referring to slide two, I'd also like to make our customary statements regarding Portland General Electric’s written and oral disclosures. There will be statements in this call that are not based on historical facts and as such constitute forward-looking statements under current law.

These statements are subject to factors that may cause actual results to differ materially from the forward-looking statements made today. For a description of some of the factors that may occur that could cause such differences, the company requests that you read our most recent Form 10-K and Form 10-Q.

Portland General Electric’s third quarter earnings were released via earnings press release and the Form 10-Q before the market opened today, both of which are available investors.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. This Safe Harbor statement should be incorporated as part of any transcript of this call.

Leading our discussion today are Jim Piro, President and CEO; and Jim Lobdell, Senior Vice President of Finance, CFO and Treasurer. Following their prepared remarks, we will open the lines up for your questions. Now, it’s my pleasure to turn the call over to our, Jim Piro..

Thanks Chris. Good morning everyone and thank you for joining us. Welcome to Portland General Electric's third quarter earnings call.

On today's call, I'll provide an update on our financial and operating performance, the economy in our operating area, the Carty Generating Station, our 2016 integrated resource plan, and finally, our capital expenditure forecast through 2020.

I'll then turn the call over to Jim Lobdell, who will provide more details on our financial performance and guidance. As presented on slide four, we reported net income of $34 million or $0.38 per diluted share in the third quarter of 2016 compared with net income of $36 million or $0.40 per diluted share in the third quarter of 2015.

Lower quarter-over-quarter financial results were primarily driven by a mild cooling season compared to 2015 and a slight decline in commercial and industrial deliveries. Despite this, we are reaffirming our full year 2016 earnings guidance of $2.05 to $2.20 per diluted share. Jim will cover this in more detail later in the call.

Moving to slide five, our overall system performance was strong in the third quarter, including 94% generating plant availability. I'm also pleased to report PGE continues to be ranked in the top quartile for customer satisfaction for residential, business, and key customers according to Market Strategies International and TQS Research.

According to an October report for Market Strategies International, residential customers ranked PGE number one for exceptional dedication to the environment out of the 130 utility brands surveyed. According to their research, residential customer say the most important cause their utility should support is promoting a clean environment.

In September, we released our newest sustainability report, which features five years of performance data and highlights some of the ways we work about social, environmental, and economic impacts of our business decisions. This update is available for you at portlandgeneral.com/sustainability.

Let's move to slide six for an update on economy and our customers. As I mentioned, we continue to see positive economic trends in our operating area. August marked 50 consecutive months of job growth in Oregon. The longest growth streak since comparable data began being collected in 1990.

In addition, Oregon is experiencing solid wage gains including and an increase in the median household income of 6% from 2014 to 2015, the third largest percentage increase in the nation. Also in 2015, the Portland Metro areas gross domestic product grew 4.6%, the 10th fastest growth rate among the nation's 100 largest area metros.

The unemployment rate of 4.9% in our service area for September compared favorably to Oregon at 5.5% and the U.S. at 5%. According to the Oregon Office of Economic Analysis, Oregon unemployment rates increased slightly in recent months as a large number of people entering the labor workforce outpaced the number of jobs added.

Strong employment growth continues to fuel in migration with PGE customer count growth at approximately 1.3% year-over-year, supporting our long-term growth.

Moving to slide seven, we have provided an update on our Carty Generating Station, the 440 megawatt natural gas baseload resource located near Boardman, Oregon, which just completed its first three months of operation.

I'm pleased to report that Carty contributed strong operations for the quarter including a 92% availability during August and September, an impressive number for a brand-new unit. The return of and on the approved capital cost of $514 million as well as the plant's operating costs were included in customer prices as of August 1st.

As of September 30th, we had $650 million including AFDC in plants in service for the project. Our current estimates for the final capital expenditures for Carty including AFDC is approximately $640 million to $660 million.

We are pursuing legal action against Liberty Mutual and Zurich North America, the two sureties who provided $145.6 million performance bond in connection with the Carty construction agreement. At the end of July 2016, the U.S. District Court of Oregon ruled against the sureties motion to stay the proceeding filed by PGE in U.S.

District Court of Oregon and ruled in favor of PGE's motion to enjoin the sureties from participation in an International Chamber of Commerce arbitration proceeding initiated by Abengoa relating to the parental guarantee provided by Abengoa in connection with the Carty construction agreement.

The sureties have appealed the District Court's ruling to the Ninth Circuit Court. Absent reversal by the Ninth Circuit, PGE’s claim against the sureties will be tried in two phases. The first phase will be -- will determine whether PGE’s termination of the contractor was appropriate is currently set for trial in June of 2017.

The second phase will determine the damages and will proceed only if PGE is successful in the first phase. In addition, on October 21, 2016, following the U.S. Bankruptcy Court’s grant of our motion for relief from the stay imposed by Abeinsa's Chapter 11 bankruptcy proceeding, PGE filed a complaint in the the U.S.

District Court of Oregon against Abeinsa for failure to satisfy its obligation under the Carty construction agreement. For more details, you can refer to our 10-Q. Slide eight provides an overview of the focus areas and timeline for 2016 integrated resource plan that we expect to file with the OPUC in the middle of next month.

In anticipation of our filing, the OPUC has open docket LC66 and has a pre-hearing conference scheduled for November 2nd to discuss the schedule for the IRP review process.

This IRP will continue to reflect PGE shift over time to a less carbon-intensive power supply portfolio, which is consistent with Oregon's New Clean Electric and Coal Transition Plan, which calls for 50% renewable resources by 2040. Today, PGE is meeting the 15% renewable portfolio standard requirement.

And the 2016 IRP addresses the need for additional resources to meet the 2020 requirement of 20% and positions us for the 2025 requirement of 27%. We have been seeking input on the draft IRP from stakeholders including the OPUC staff and the draft IRP is available on our website at portlandgeneral.com/2016resourceplanning.

The final plan filed with the OPUC may include modifications to this draft. The proposed action plan and the draft IRP which covers the period 2017 to 2020 leaves with 135 average megawatts of cost effective energy efficiency and 75 megawatts of demand response actions.

The proposed action plan also includes adding approximately 175 average megawatts in new qualifying renewable resources and up to 850 megawatts of capacity comprised of 375 to 550 megawatts of long-term annual dispatchable resources and up to 400 megawatts of annual or seasonal equivalent capacity resources.

We will be asking the commission to acknowledge the 2016 IRP in mid-2017. Once the IRP and the associated plan -- associated action plan is acknowledged, we expect to issue one or more RFPs to acquire needed resources. On slide nine, we have provided a summary of the company's capital expenditure forecast from 2015 to 2020.

Total Board approved capital expenditures for these years have increased $279 million over our second quarter disclosure. The increased capital is part of a long-term program which will be focused on improving the efficiency, reliability and resilience of PGE's infrastructure to meet customer needs and expectations.

Examples of these investments include equipment replacements and upgrades to our older, higher risk substations to improve reliability, strengthen seismic resilience and add security enhancements. In the generation area, we’re rebuilding 100-year-old 46 megawatts Hydro facility at our Faraday side on the ClackamasRiver.

Additional reliability and resilience investments maybe discussed in future calls. The capital expenditures on this chart do not include any potential capital projects from any RFPs resulting from the outcome of our 2016 integrated resource planning process.

Additionally, we had not included in the chart, our previously discussed opportunity for investment in a natural gas reserves. That is currently pending in OPUC decision by November 4th. We will continue to provide updates on our capital expenditure forecast in future earnings calls.

Now I would like to turn the call over to Jim Lobdell, who will discuss our financial results for the third quarter and provide more detail around our energy deliveries and earnings guidance. Following his prepared remarks, we'll open the lines for your questions.

Jim?.

Thank you, Jim. As Jim mentioned for the third quarter 2016 we recorded net income of 34 million or $0.38 per diluted share compared with net income of 36 million or $0.40 per diluted share for the third quarter of 2015. Slide 10 shows a walk-through of the income statement changes quarter-over-quarter.

A few things to note on the slide are first retail revenues decreased to 11 million for the quarter.

This was the result of a decrease in retail sales volume due to unfavorable weather and a decrease in weather adjusted load which was partially offset by an increase in the decoupling mechanism and the August 1 price increase for placing Carty into service.

Secondly net variable power costs which are power cost net of wholesale revenues more than offset the negative impact of retail load within gross margin driven by higher wholesale revenues related to a rebalancing of the power supply portfolio.

For the purposes of the power cost adjustment mechanism net variable power costs were 3 million above the baseline for the annual update tariff for the third quarter 2016 in comparison to 6 million above the baseline for the third quarter of 2015.

The third item to note is that the increase in spending within operations and maintenance is largely attributable to placing Carty into service and legal expenses related to the Carty litigation.

And finally the increase in depreciation and amortization expense is due to placing Carty into service and was partially offset by a refund to customers related to the Trojan spent fuel settlement. On the slide 11 which shows earnings drivers for the quarter. First Carty overall resulted in a $0.01 decrease to earnings as a result of the following.

A $0.02 increase resulting from Carty AFDC equity in July and the earnings related to a return on the 514 million of capital costs included in customer prices on August 1, net of Carty AFDC equity in the third quarter of 2015.

The $0.02 was more than offset by a decrease of $0.01 for the depreciation and caring cost of Carty's capital cost greater than the 514 million in customer prices and about $0.02 decrease related to Carty legal expenses. These legal fees are about 3 million in the third quarter of 2016 and estimated to be 3 million in the fourth quarter of 2016.

We do not anticipate that legal costs will remain at these elevated quarterly levels in 2017.

On to changes in load, loaded a negative impact on earnings of about $0.05 mild temperatures in the third quarter 2016 in comparison to the hot weather experienced in the third quarter of 2015 resulted in a reduction in retail deliveries partially offset by higher wholesale volumes related to rebalancing of the power supply portfolio.

In addition to this weather adjusted loads were down for the quarter due to energy efficiency with building codes and standards likely reducing energy deliveries beyond the impact of energy efficiency programs.

Next PGE's non-qualified benefit trust increased 3 million in the third quarter of 2016 when compared to the third quarter of 2015 resulting $0.02 increase in earnings per share. Finally other miscellaneous items are driving the last two cents of earnings quarter-over-quarter.

On the slide 12 we continue to maintain a solid balance sheet with adequate -- including adequate liquidity and investment grade credit ratings.

As of September 30, 2016 we had a total of 675 million in cash available short-term credit and letter of credit capacity, 1.2 billion in first mortgage bond issuance capacity and a common equity ratio of 49%. In May 2016 we entered into an unsecured loan agreement with the certain financial institutions to borrow up to 200 million.

PGE borrowed 50 million under the agreements in May 75 million and June and we plan to borrow 25 million by the end of this month. No other borrowings are planned for the remainder of 2016. Moving onto earnings guidance on slide 13.

PGE is reaffirming its revised 2016 earnings guidance of $2.05 to $2.20 per diluted share based on the following assumptions. First our assumption for energy deliveries has been reduced from 1% estimated growth for 2016, weather adjusted and excluding one large paper company to flat or zero for 2016.

Year-to-date results and third quarter results in particular drive this reduction. For the past two years we have reported system growth, load growth driven by strong industrial growth in high tech sector which is slowed from the increases seen in recent years.

In 2016 these increases were offset by decreases in deliveries to metals and solar manufacturing customers resulting from operational changes and layoffs announced earlier in the year. Despite weakness in deliveries growth for 2016 economic fundamentals in our service territory remain strong.

We are still seeing continued population growth low, unemployment rate and a robust industrial sector all of which support future growth.

The remaining guidance assumption for 2016 include average Hydro conditions for the remainder of the year, wind generation for the remainder of the year based on five years of historic levels or forecast studies when historical levels or data is not available, normal thermal plant operations, operating and maintenance costs between 515 and 535 and depreciation and amortization expense between 315 million and 325 million.

Back to you, Jim..

Thanks.

In summary, we continue to focus on successful execution of our initiative that drive value for customers and our shareholders including deliver operational excellence by meeting our 2016 operating and financial performance target, two file our 2016 integrated resource plan and its associated action plan and three continue to pursue legal actions against the sureties and Abengoa.

Now, operator we are ready for questions..

[Operator Instructions] And our first question comes from the line of Paul Ridzon with KeyBanc Capital Markets. Your line is now open..

Good morning.

How are you?.

Good morning, Paul..

You indicated that the loads coming down and you gave some flavor there -- are you still seeing what -- what's happening with energy efficiencies? Is that getting worse, is it bottoming now? What you are seeing on that front?.

On the energy efficiency front, we do about 30 average megawatts a year run that’s through the energy trust. I would tell you as you look at over time absent any new technology if those numbers are coming down because we pretty much saturated the market with things like LED lighting and more efficient appliances and things like that.

So while we continue to have a focus on energy efficiency and we talked about the 135 average megawatts that we see going forward in our integrated resource plan, if you look longer-term that starts to come down absent any new technology.

In terms of the other softness Jim you want to talk about what you are seeing on that side?.

Yes, when you go beyond that Paul, we look at the industrial sector and what we're seeing in industrial sector is we had quite a ramp-up on the high tech sector in the past. And we're seeing continued growth in that sector but not at the -- at the rates that we've seen in the past.

In addition to that we've seen some softness associated with solar and metals manufacturing. Solar facing global competitive forces and metals is just a commodity play at this bigger point in time. So that's masking a little bit of the growth we're seeing on the industrial sector as well.

The other thing I'll note is that new connects continue to be strong in the service territory. We got about 1.3% increase in new connects year-over-year..

And may be on that point we had a meeting yesterday with the homebuilders association. We're starting to see a rotation from single-family to multi-family.

So that's an interesting transition with the younger generation more infill in the city of Portland so while connects are up overall use per customer is going down because the multi-family tends to have a little less consumption than single-family.

But it's gone from historically 60% single-family, 40% multi-family and right now it’s about 50-50 and you see a rotation more towards 60% multi -- multi-family, 40% single-family. But it's an interesting rotation we're seeing in our market with lot of cranes out there, a lot of multi-family construction being completed..

The incremental CapEx that you announced today, there is no big projects and I know sounds like its blocking and tackling and swapping out old substations, anything…?.

The idea is with blocking and tackling, we have a number of substations they are 50 to 60 years old and with the increased density in many of the areas of our city we need to upgrade those substations to handle the load, plus a lot of that equipment has reached the end of its useful life and is subject to failure.

And given the importance of our key risk substations we've identified probably 40 substations that are high risk. That over the next couple of years we're going to be addressing with various upgrade to transformers, new capacitors, new control buildings when you look at substations six years ago, the technology significantly change.

Those are just the basic blocking and tackling things that we need to do and focus on. We're also working hard on looking at the underground system. About half of our distribution system is underground and [inaudible] 1970 vintage a direct buried cable.

We've identified one of the riskier segment, the cable that is most likely prone to failure and is failing and we're addressing that also. So a couple of big, big projects it's just the basic work we need to do to provide reliable service to our customers..

In the -- the IRP is acknowledged when could capital start flowing towards that and would that capital potentially displace some of the higher cap you've announced today? And then as a follow-on kind of you're financing plans for the next two, three years..

I'll take the first and Jim you can take the second part. In terms of the RFP process, right now the way we see its playing out is hopefully by next -- middle of next year we get a decision from the commission on our action plan as part of the integrated resource planning process.

We also need to get approval for the RFPs that would be part of that, they were trying to run in parallel with the IRP process, so that we can start the process. The concern we have is Boardman will shut down on call at the end of 2020 and we become pretty significantly capacity deficit.

And so both the addition of new renewables and the need for additional capacity would like to us get going on these RFPs. So, we get started on the RFPs, we hope to have decision in early 2018, so that we would then move forward with those projects.

We'll again look at, as we have before, both look at ownership and contract options and determine what the lease cost lowest risk choices are for our customers..

You hope to have a decision in the RFP process by early 2018?.

That's kind of what we're thinking about right now. That's probably our plan at this point. Obviously, how the IRP process goes and the questions we see there and the timing of that process is going to determine whether we get there not..

And how does that timing play into the PTC?.

On the production tax [inaudible], they go down over time and you have to start construction and various contractors or owners or developers may or may not have started and made the Safe Harbor under the tax rule that will all be something that comes out in the RFP.

It declines over time and so depending on where those developers are that may or may not affect how they bid into the project and whether they have 100% or 80% or 60% PTCs will depend on their own project development..

And do you have comments on financing?.

Yes, Paul, so as we look forward from a financing perspective, as we mentioned in our comments earlier, we're only going to pull another $25 million on that $200 million bank loan that we have in 2016. And we don't have anything else planned beyond that.

In 2017 probably between maturing debt and some other activities will issue may be $400 million worth of additional long-term debt in 2017. We got no plans for equity at all. At this point, it really just depends on when we get to the next significant resource investment as we move forward and find out what's going on with the IRP and the RFPs..

Thank you very much. That's very helpful..

Thanks Paul..

Thanks Paul..

Thank you. And our next question comes from the line of Julien Dumoulin-Smith with UBS. Your line is now open..

Hi, good morning..

Hey Julien..

So, perhaps to go back to some of those questions we were just reviewing there. On the distribution CapEx, are we through this cycle on the assessment, you mentioned going -- looking at 40 substations at this point.

Something we've seen first review of your communications network now we're seeing some of the substations, should we expect anything else in terms of possible distribution CapEx revisions between now and when that IRP sort of comes into fruition in terms of an RFP and subsequent CapEx deployment?.

We're taking this one year at a time. This represents the projects that were approved by the Board and that represents about 20 substations that need to be rebuilt. We'll look at the next 20 next year, capital cycle; see how we're progressing on these projects.

I'm sure that we're on schedule and on-budget on those and then we'll take on the next tranche. The underground is a continuing set of challenges. I think we only have about 100,000 feet or about five to 20 miles that we're really focusing on right now in the next couple of years, but we have a lot of underground that we have to address.

And that's going to be a multi-your project. The PCB replacement transformer is another big project; we’re just now in the testing phase. That replacement will happen over a number of years. So, this is going to be a multiyear effort that's going to have to address the infrastructure and transmission and distribution side.

But we're just taking it one year at time. We're not forecasting those next year's capital until we see the progress we're making on this and the challenges that we had with the rest of the system..

And just to be clear the additional 20 substations for next year and for the underground, is that all reflected already in the CapEx update you have provided and updated today?.

No, we have continuing capital for the projects for the first 20 that we're attacking, but for the next that we have not scoped out yet and determine the timing and the exact amount working in the capital forecast. We'll address that in the next capital cycle..

Got it. Excellent.

And then to go back to another capital investment item, obviously we don't necessarily know what's going on with the gas reserves effort; can you provide at least some sense of scenarios around what could develop in the next week? And what the possible path forward would be?.

Well, there's really just two paths. If the commission approves the transaction, we would then move forward with a counterparty to invest in gas reserves and take action to acquire those reserves. That agreement with the counterparty has multiple stages on it.

We would execute against the first stage of that and then look at subsequent years as part of our longer term hedging strategy. The commission doesn't approve the transaction, does not view that the long-term hedge is appropriate for our customers, then we would unwind the transaction and no longer pursue it. So, it's really just -- A or B..

Got it. No, I was wondering if there was a C at all..

No, C. there is no C here..

That great. All right. Excellent. Perhaps lastly can you go back -- I suppose in terms of other avenues of potential spent coming out of the draft RFP, there was pretty extensive discussion of energy efficiency demand response and even some storage discussions.

Any opportunities for rate base eligible projects under any three of those that we should be initially aware of?.

I think we're going to go through the process at this point and get to acknowledge the action plan, which would then lead the to the RFPs. I do think in the area of capacity, we're going to look on all kinds of options. We're going to be looking at batteries, as well as contract, as well as asset to provide that capacity resource.

The exciting thing is we're seeing much more flexibility in the frame technologies, the combined cycle units that can meet a lot of our capacity needs while also providing really low cost, low carbon energy. And we need that as we add more renewables to the system.

So, we're looking at all kinds of things in the capacity space all the way from the combined cycle units with lots of flexibility to batteries that would help us at the top of the stack around regulation and reserves.

So, we're trying to look at the whole gambit, but that will not play out until we issue the RFPs and product ahead of that at this point..

All right. Most excellent. Thank you so much..

Thanks..

Thanks Julien..

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

Couple of questions..

Good morning Michael..

Good morning.

In the IRP you're using a demand growth projection, I just kind of skimmed it real quickly of about 1.2%, but you just -- for this year, you took your weather and normalized demand growth down to flat or zero, how do you reconcile those items and is that something that's already been stipulated to with all the intervenors and with the commission or is that a debate or a debate item that will come up in the IRP review next year?.

In the IRS it is a key issue in the IRP and we did actually bring a consultant in to help us with the load forecast to make sure that we reflected the best technology and thoughts around load growth. So, while be an issue we've already had workshops with the parties on it. We brought the third-party consultant in to help us with the forecast.

So, while it is a driver, obviously, to what our needs for resources are. My sense is that those issues have embedded pretty well in terms of the conversation. And the third-party helping us with forecast is giving us some credibility around the number.

So, I'm not expecting a lot of pushback on that number given a way the talked with the parties about it and the consultant we brought in. And it seems reasonable given the history we've seen over time..

The only thing I'd add is that our long-term projection and keep in mind, it goes up and down from year-to-year, but on average, just about 1%..

Also with the increased CapEx, how does this impact the -- what you're thinking just in the timing of your next rate case cycle?.

So, it obviously is a factor, but it's one of many factors including OEM increases, load increases. We run power cost through the AUT filings, so that's not a concern for us. So, it really just looking at OEM growth, the return on capital, and we know what's going on with rate base and then where's demand going.

And so we're right in the process now, looking at 2018 general rate case, we've made no decisions. We just finished our budget for 2017 and now we're looking at 2018.

We'll make a decision over the next couple of months whether we think we need to file for a rate increase; we'll look at what we think ROEs are, so it’s a whole number of factors that go into that evaluation. If we decide to go forward, we file in February and you would know that when we file it. So, it's kind of where we are right now.

We haven’t made a permanent decision one way or the other, we're just looking at all the numbers and we'll have to see how it plays out over the next couple of months..

And so if you were to file this coming February, you've got forward look, so it would capture both the 2017 CapEx as well -- including the incremental $200 million, as well as the 2018 CapEx because rates would be set effectively January 2018..

In essence that's true. We've been using year-end rate base as a projection for the rate cases. So, it's been a pretty good proxy for what the average rate base has been for the year.

So, yes, I think the interesting thing and this is something we're looking at 2018 is our customer information system which is about $137 million of capital goes into service in the first quarter of 2018 and similar to what we did with Carty, we're looking at whether we would track that in separately or would be part of a general rate case, but it's something we're also factored into our discussion around the need for price increase in 2018..

Got it. Okay. Thank you, guys. Much appreciated..

Thanks Mike..

Thanks Michael..

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

Yes, hi good morning..

Good morning..

Good morning Brian..

The upcoming IRP, will there be any self-build scenarios..

At that point, we have not made any commitment to a self-build option. We are looking as we always have. Clearly Carty 2 is available as a potential development opportunity that would be that Carty -- Carty was development of the two unit system, it's got substation, it's got gas infrastructure and it's got land availability. It is clearly an option.

I suspect we would look at -- we haven’t made a decision on this, but I suspect we do like we did before with Carty 1 is we would create -- make the site available for a bid, but it would be under our ownership.

But again those decisions haven’t been made yet, but that to us is a very favorable site and has a lot of the attributes we would be looking for, it has transmission, it has number of things that make it a very attractive site.

Whether we do a self-build on that or just let the site go open for someone -- for an EPC contractor to bid, we haven’t made that decision yet. But we're looking at that. On the renewables side, we're doing the same thing.

We're looking around determining whether we would want to put in a self-build option or not, but again we haven’t made a firm decision on that yet..

Okay, got it.

So, it seems like a self-build transfer scenario is an option?.

Yes, a build on transfer type of arrangement..

Yes, got it. Okay.

And then with the lower CNI load growth and the overall expected load growth in 2016, what tools are you using to offset the margin impact of that that enables you to reaffirm your guidance?.

Well, from a cost perspective, obviously, we're always continuing to maintain our cost. From energy usage compared to what we had in the general rate case with the decoupling mechanism is helping out. And you saw that in the slides as well. So, it's focusing on our operations and trying to be as effective as we can, going forward..

The other thing is as you noticed in the third quarter when don't have retail sales that uncover some generation that we can sell in the wholesale market and that helps offset some of the cost also.

That's why you saw the big pop-up in the third quarter around wholesale is that retail wasn’t there, so we had resources that were uncommitted, if you will.

Because of lower loads, they were able to lease monetize that in the market around wholesale sales create some margin, not clearly as great margin as selling retail, but helps offset some of the cost..

Okay.

And I know you don't provide 2017 guidance, but without a rate case or 2017 test year rate case, will you guys be able to earn near your ROE or we're going to see ROE degradation and a step-up with kind of new rates in 2018?.

We haven’t provided guidance. We'll do that in the first quarter as we typically had.

We obviously had some headwinds with Carty and has been very clear that we said that those are some headwinds that we’re facing that hadn’t been factored into our forecast, that’s the continuing drag from the additional depreciation on the cost in excess of the 514 and as well as return on depreciation of that amount.

So that’s the little bit of the headwinds we are facing and so that’s going to be a part of our challenges we put our forecast together for next year.

But we always try to get close to our allowed ROE 0.34 on a regulated basis and as Jim talked about before we have a 60 -- 50 basis point kind of uncovered cost that we had even this year around cost that are not allowed in rate making. So we have a little bit of headwind next year, we are trying to look at that.

We have couple of other items that are pending also before the commission so. We will give you guidance in February, but that’s as much I can tell you now..

Okay, great.

And then just can you remind us, what the weather impact versus normal is in 2016?.

Yes, Brian. This is another one of those quarters where you really can't look just at the particular quarter you needed really combine it with the prior quarters, so that you take Q2 and Q3 together compared to normal on a cycle basis you get to keep in mind all the unbilled and how we deal with that, it was really a negative $0.05..

Okay, great. Thank you..

Yes. Thanks Brian..

Thank you. And our next question comes from the line of Michael Weinstein with Credit Suisse. Your line is now open..

Hi, guys..

Hi Mike..

One of my question to answer, but I was wondering if you could talk about the relief you got from the Bankruptcy Court against Abeinsa's that your complaint in U.S. District Court, is that basically now in front of the Bankruptcy Court? Are you going to be -- would you take precedence over bankruptcy payments if you….

We are now pulling U.S. District Court both against the sureties and Abeinsa's. We got relief from the Bankruptcy Court to sue Abeinsa's under the construction agreement. So we now are fully in U.S. District Court pending any action by the Ninth Circuit Court on the U.S. District Court decision.

So where we want to be which is consistent with what the construction agreement called for as well as surety agreement called for and the other good news is obviously they stayed or enjoin the sureties from being a part of the arbitration proceeding.

The arbitration proceeding is just around the parental guarantee and that’s why we waited and the courts have agreed with us on that point. So we are now moving forward with the trial doing discovery and preparing for the trial in June on phase one of the case around whether the termination was proper..

That’s for the sureties, right.

What's the next step in the Abeinsa's case?.

Well, now that we've got Abeinsa's -- we got another bankruptcy we were unable to sue Abeinsa's in the U.S. District Court because of the bankruptcy….

Automatic..

The automatic Bankruptcy Court, so that stage is lifted so we now have filed against Abeinsa's in the U.S.

District Court, our sense is those two will be consolidated into one case and will be the same thing there which is preclude them from being a part of the arbitration and move forward with them as the joint case, I think that’s what is going play out, that’s have not been done yet.

As two cases has been joined we just did that filing the last week I think..

Right.

If you are combined, I mean you are looking at June 2017 for the trail to begin at the very least?.

And again that -- that’s on the single issue the phase one part of the case, single issue was the termination proper?.

Right, right.

And on the RFP, can you just remind me PTC’s assuming they are included in a similar products are built in time to collect PTCs, those PTCs are really for the benefit of customers right now for the benefit of shareholders?.

That’s absolutely correct. We factored that into our revenue requirements as less reduction in taxes..

Right.

And it in terms of self-build I mean you would compete in the RFP assignment?.

Yes, we have self-build option that actually competes against the others. We would put in our self-build option, we have put that ahead of time into the RFP process, at least that's the way it was done before, but next time we do that and we have to compete on less cost lowest risk basis..

Right.

And I think I recall at some earlier time that the company had discussed owning up for I guess favorable properties and properties that were located in the right locations for when and you already talked about the location at Carty for additional gas plant there?.

We have nothing on the win side right now. We try to do self-build option in the last RFP that was unsuccessful, so we ended up with Tucannon River wind farm project which turned out to be a lower-cost project..

Is there any potential to expand to Canon that sometimes that would competitive?.

There are number of sites that developers have and I am not aware whether that site -- I know that site has expandability but it's owned by someone else and I don’t know what their intent is with that project..

Got you. Thank you..

Thank you..

Thank you. And we do have a follow-up question from the line of Michael Lapides with Goldman Sachs. Your line is now open..

Hey, guys. Just really quick on the incremental capital spend, it’s about 300 million of incremental CapEx when I look at just the combination of 2017, 2018 what’s the corresponding increase on rate base? Meaning, I know, there are things like deferred tax liabilities and other items that may offset rate base a bit..

We will back to you on that Michael..

Got it. And you're still not expecting to….

Michael on that point I think what you can do is, you can look at the capital we do not use bonus depreciation -- we haven’t used bonus depreciation just because of all the production tax credit we generate.

So you can essentially take the tax rate, the normal makers rate against the straight line rate and that will tell you what the deferred taxes, that’s really only the offset, but little bit of accumulated depreciation I think we are pretty close there, we are just doing that calculation, the tax rate assuming Measure 97 doesn’t pass..

Understood. Thank you, guys. Much appreciated..

Thanks..

Thank you. And our next question comes from the line of Travis Miller with MorningStar. Your line is now open..

Good morning. Thank you..

Good morning, Travis..

I was wondering, if you can give us high level, what you're seeing in terms of the economics for renewables especially when in your area relative to other generation source in particularly gas? And then related to that how regulators might view the potential for allowing more wind, more renewables above and beyond the state requirements?.

Well, I don't know one of our senators here in Oregon; Senator Merkley is pushing for 100x50 which 100% renewables by 2050. I do worry about the stability of the grid, if all these renewables were wind and solar.

Wind in the Northwest fairly variable has a lot of variation intends not to be aligned with loads on the hottest days of the year and coldest days of the year the wind doesn’t seem to blow and even this year that same phenomenon continues to exist.

So while we continue to move forward with renewables we're going to have to add firm capacity to back up those renewables and we are spending a lot of time educating our environmental groups and others around the need for firm capacity to ensure that we can meet firm load and so while there is continued pressure on adding renewable.

My senses, we need to get to 50% first before we take the next step and see how we are doing as I tell many people, we are going to be energy-rich, but capacity poor. We need to add firm capacity to ensure we have a reliable system.

We have talked before that we're joining the energy imbalance market in California called the Western EIM that is a only energy market it’s not capacity market it does not provide firm capacity, you have to go to the energy imbalance market balance and resource sufficient and so we still need capacity to do that, that's really the discussion during the integrated resource plan to demonstrate why we need firm capacity Closure of Boardman, obviously, we lose was about 580 megawatts of capacity and we got to replace that going forward.

So I think, the needed is there if we're going ensure reliable service to our customers..

You can bring in….

There will always conversation about adding more renewables and we have to ensure that we have stability and we got a path in front of us to 50% and will continue working in that path..

Do you get the sense that regulators understand that distinction and thus would be supportive of going the capacity duration?.

I think regulators understand the need for firm capacity, need firm load and they understand that renewables are not firm resources.

The type of capacity to do that always subject to what the right mix of short and long-term contracts and simple cycle versus combined cycle there's all those kinds of conversations, but I think that will get worked out in the RFP.

On the other side, environmental may have less understanding about as they don't operate grids and understand that and we are spending a fair amount of the time with them explaining, how they two have to work together.

Okay, great. Appreciate it..

Thank you. And we have a follow up question from the line of Paul Ridzon with KeyBanc Capital Markets. Your line is now open..

Thank you..

Hi, Paul..

I just wanted to clarify this 290 or whatever is incremental capital is result of looking at 20 substations you'd starting the process to look at an incremental 20 as well as underground systems that are getting old to be adjusted in the next capital cycle, is that correct? And then, secondly, when is that next capital cycle, will that be a Q3 2017 call discussion?.

The answer to that is yes. The current forecast has 20 substations that we've identified, they need various amount of upgrades, rebuilds, refurbishment, equipment’s that reached the end of its useful life.

The next 20, we will look at in next capital cycle depending on the progress and results we had this on this program and so that’s when we will revisit that item. The PCB work and the underground is been an ongoing program, we are ramping that up, and to really address the stated system.

At the current pace, we are going, it’s about 250 conductor mild of underground that we've identified as being reaching the end of its useful life.

We’re only taking a 20 of it over the next couple years, so this is going to be a multiyear program that we would have to go after and pay for that will be dependent on resources and again progress and cost effectiveness, deployment of new cable, so lots going on in T&D area, things that we really need to address.

As someone said earlier, it’s just a blocking and tackling we needed to do to ensure our customers get the reliability they expect..

But you think that incremental trend will be kind of looked at in the -- over the next 12 months? 20 substations, sorry?.

I can't tell you. We haven’t really taken a detailed look at that. I would suspect it's in about the same mix, may be a little bit lower.

We're taking big high risk substations first and they are going to be an order of magnitude probably higher just because they are bigger and have more capacity on them, but we still haven’t put those estimates together to a point where we're comfortable with any kind of numbers around that.

And again we need to complete what we have on our plate first to make sure that we have the capacities to take on the mix.

And really the question we’re trying to evaluate because the 20 that we're taking on this year or starting next year is our multi-year and so we have to kind of see how that fits with the other work that we need to do and whether we'll do it in 2018 or 2019 is part of the work that we need to do as we make progress on the first 20..

Understood. Thanks again for your help..

Thanks Paul..

[Operator Instructions] And our next question comes from the line of Andy Levi with Avon Capital Advisors. Your line is now open..

Hi, can you hear me?.

Good morning Andy..

Yes, got you..

Okay, because we had a little trouble.

How are you guys doing?.

Good, how are you doing?.

We're doing really well actually. So, got two months to go. Okay, so obviously, very good news on the incremental CapEx. I just want to make sure that I'm just modeling this correctly.

So, just on the $400 million of debt you said for 2017, is part of that $400 million refi? So, I guess how much is actually new debt -- incremental debt?.

Probably about $250 million of it is refi Andy..

Okay..

No, sorry, $250 million is new debt..

New debt, okay.

And that you'll do kind of long-term or -- what are thinking?.

Yes, we'll do long-term..

Okay, got it. And then I assume on the incremental, it's about $180 million I guess from the third quarter -- from the second quarter call of incremental CapEx for 2017? And then also the incremental $100 million plus in 2018 until you go in for rates, which you said would be the beginning of 2018 if I heard correctly.

We should assume you earned AFUDC on that, is that correct?.

Those projects will close in various stages throughout next year and 2018. So, we will start the work in 2017. We're just now ordering equipment. Some of those sensations may get completed in 2017; some will be completed in 2018.

So, you'll AFUDC on some of that during 2018 and -- or 2017 and some during 2018 and they will probably all be closed by 2018..

Okay.

And then your filing for rates at the beginning of 2018; is that correct with the test year?.

If we -- we haven’t made the decision to file. As I mentioned early, we're looking at it. If we file, we will file in February of 2017. It's typically a $10 million project. Rates would be effective January 1 of 2018..

All right. Okay.

And there will be a 2018 test year or-- is that correct?.

2018 test year..

All right. Okay. So, it would incorporate all this CapEx..

Yes..

Great. Okay, sounds good.

And then just on the no equity part that takes you out how many years based on your current CapEx program in terms of IRP?.

We've got another major resource that we need to add in the portfolio..

Got it. Thanks so much..

There are projections. If we do not add any large resources, we can self-fund our CapEx..

That's terrific. Okay. Great guys. I'll see you in a week..

Thanks. We'll see you in a week..

See you Andy..

Okay. I think that ends our call. We appreciate your interest in Portland General Electric and appreciate your questions. We look forward to seeing you -- many of you at the EEI Annual Financial Conference in Arizona next two -- in two weeks. So, have a great day and we'll see you in two weeks. Thanks..

Ladies and gentlemen, thank you for participating in today's conference. This does conclude the program and you may all disconnect. Everyone have a great day..