Portland General Electric Co (POR) 2016 Q2 法說會逐字稿

Thank you, Vince; and good morning, everyone, and I'm pleased that you are all 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, which we will be referencing throughout the call. And these slides are available on our website at portlandgeneral.com. Referring to slide 2, I'd like to make our customary statements regarding Portland General Electric's written and oral disclosures and commentary. 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 our Form 10-Q. Portland General Electric's second quarter earnings were released via our earnings press release and the Form 10-Q before the market open today. And that release and the Form 10-Q are 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 always 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. And now, as always, it's my pleasure to turn the call over to Jim Piro.

Thank you, Bill. Before we move on to the business of our second quarter 2016 earnings call, I'd like to take a moment to share with you that Bill Valach is retiring this month after 25 years at PGE. As many of you are aware, Bill was at the helm of our Investor Relations program when we returned to the New York Stock Exchange as a publicly traded security in 2006. Our Corporate Finance Manager, Chris Liddle, who is joining us on the call today, will lead our Investor Relations efforts moving forward. Chris brings a broad range of experience, knowledge and leadership to this role from his 11 years at PGE. Thank you, Bill, for your distinguished service and welcome, Chris. Bill, we're going to miss you and we'll miss your comments to start the calls.

Now, on to our second quarter earnings results. On today's call, I'll provide an update on our Carty Generating Station, which went into service on July 29, and our strategy for recovering cost in excess of the $514 million approved by the OPUC in our 2016 general rate case. Our financial and operating performance, the economy in our operating area; our 2016 integrated resource plan; our request for an accelerated renewable RFP, 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.

Turning to slide 4, let me begin with an update on Carty, our 440 megawatt baseload, natural gas-fired generating plant in Eastern Oregon. I'm pleased to say that on July 29, we successfully placed Carty into service for our customers. Carty was first selected as a project in 2013 as part of an exhaustive planning and competitive resource selection process that started with our 2009 integrated resource plan, acknowledged by the OPUC in 2010. The competitive bidding process was won by an engineering procurement and construction contractor comprised the several affiliates of Abengoa SA. Following our termination of the construction agreement in December of 2015, we assumed control of the project. Thanks to the hard work and dedicated efforts put forth by PGE's project team and operating staff, and the help of our key contractors, our new, highly efficient plant is now a source of safe, reliable and cost effective power for our customers.

New prices went into effect on August 1, 2016, which include the return on and of Carty's capital cost of $514 million, and all operating costs as allowed by the OPUC in the 2016 general rate case. This resulted in an overall increase in customer prices of approximately 2.5%, which is net of the amortization of proceeds we previously received from the US Department of Energy. This increase follows an overall price decrease of 2.5% that took effect on January 1, 2016, leaving overall customer prices approximately flat in comparison to 2015 prices.

Our current estimates for final capital expenditures for Carty including AFDC is approximately $640 million to $660 million. As of June 30, we had $587 million, including $59 million of AFDC, included in the construction work in progress for this project. On July 29, we filed a regulatory deferral request with the OPUC for future recovery of the revenue requirements associated with Carty's capital costs above the $514 million level starting from its in-service date until this additional amounts are approved for recovery if necessary under a future regulatory filing. This will depend on whether the additional amounts above the $514 million are offset wholly or in part by funds received from Liberty Mutual Insurance Company and Zurich America Insurance Company, the two sureties that provided a performance bond of $145.6 million under the construction agreement or from the original Carty contractor or the contractor's parent company. The performance bond was part of our requirements to incorporate financial protections into our original fixed price, turnkey, engineering, procurement and construction contract for Carty. We made a request for performance by the sureties under the performance bond after termination of the construction agreement back in December and following denial of our request by the sureties under the performance bond, we are pursuing litigation against the sureties to enforce satisfaction and return to the bond.

Until our litigation against the sureties is resolved, we have asked the Commission to delay review of the deferral filing. During this period of regulatory lag, the Company will incur higher depreciation expense and interest costs than what is reflected in the current authorized revenue requirement amount.

Now, to our quarterly performance. As presented on slide 5, we reported net income of $37 million or $0.42 per diluted share in the second quarter of 2016 compared with net income of $35 million or $0.44 per diluted share in the second quarter of 2015. While loans were reduced due to milder weather in the second quarter of 2016 compared to the second quarter of 2015, PGE delivered solid financial and operating performance during the quarter. We are reaffirming our full-year 2016 earnings guidance of $2.05 and $2.20 per diluted share.

Now, for an operational update on slide 6. In addition to placing Carty into service, we continue to see strong performance at our generating plants, power supply portfolio and customer satisfaction during the second quarter of 2016. According to the latest survey results reported by Market Strategies and TQS Research, PGE continues to rank in the top quartile in overall customer satisfaction across all categories, residential, general business and key customers. Additionally, a 2016 study by Market Strategies named PGE a most trusted brand. The study measures and tracks brand trust, customer engagement, satisfaction and relationship strength among residential customers across 129 gas, electric and combination utilities.

Let's move on to slide 7 now for an update on the economy. As the broad US economic expansion continues, Oregon in particular is experiencing a significant and sustained pace of growth. In June, the US Bureau of Economic Analysis released state GDP estimates for 2015. Oregon GDP growth rate of 4.1% tied California for the top rate. Oregon's 2015 economic output was driven by growth in the sectors of high-tech, professional and business services, and health and social services. Oregon also continues to outpace the US with respect to labor market indicators. Currently, Oregon's unemployment rate is 4.8% versus 4.9% nationally and the PGE's service area unemployment rate is lower at 4.2%. According to state economist, Oregon's uptick in unemployment from the March 2016 rate of 4.5% is partially attributable to a large increase in Oregon's labor force, now at an all-time high.

According to the Population Research Center of Portland State University, the Portland metro area population is growing at its fastest pace in eight years. In 2015, more than 20,000 people moved here, outpacing all but 10 major metro areas. While the cost of housing in Portland is rising, it is still lower than several other major Western metro areas and the Oregon Employment Department reported that construction is currently the fastest-growing employment sector in the region. The population growth of our service area contributed to an increased residential customer count for PGE, which is up approximately 1.4% over the past year. We are maintaining our 2016 year-over-year load forecast of 1% growth, which is adjusted for weather and excludes one large paper customer that ceased operation in late 2015. This growth reflects an approximate 1.5% reduction due to energy efficiency.

Slide 8 provides an overview of the timeline and focus area for our 2016 Integrated Resource Plan that we expect to file in the fourth quarter of 2016. The plan has four key focus areas that we will look at, the amount of cost-effective energy efficiency and demand-side opportunities, our renewable energy strategy to meet Oregon's renewable portfolio standard of 20% by 2020 and including considerations of the impacts of the Oregon Clean Electricity Plan, the new order requires PGE to increase the amount of energy delivered to customers for qualified renewable resources to 50% by 2040. The replacement of energy and capacity from our Boardman power plant that will cease the use of coal by the end of 2020. And finally, additional capacity needed to meet both our customers' winter and summer peaking needs, along with our needs to integrate new renewable resources.

Turning to slide 9, I would like to provide an update on our discussions with the OPUC for an accelerated renewable RFP process as part of our renewable acquisition strategy. At a public hearing on July 29, the commission decided to take no action on our request to have them approve an RFP for new renewable resources with a schedule that would allow us to capture the benefit for our customers a federal production tax credit at the 100% level before they begin to phase out in 2017. The Commission adopted the staff recommendation, which concluded that our RFP was not in alignment with our current acknowledged 2013 Integrated Resource Plan. We are disappointed with the Commission's decision in light of the questions expressed by the OPUC, staff and other parties. We are suspending our renewable RFP until such time as we are able to complete further analysis and determine the appropriate timing for seeking approval of a revised RFP.

On slide 10, we have provided a summary of the Company's capital expenditure forecast from 2016 to 2020. These amounts could potentially be augmented with the incremental investments to improve system reliability and operating efficiencies that provide value to our customers. The graph does not include any capital projects from the outcome of our 2016 integrated resource planning process. Additionally, we have identified an opportunity for an investment of approximately $70 million in a natural gas project. We have filed our annual update tariff with a gas supply from this investment pending approval of the OPUC. 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 provide more details on our second quarter financial performance and guidance. Following these prepared remarks, we will open the lines for your questions. Jim?

Thank you, Jim. Turning to slide 11, as Jim mentioned, for the second quarter of 2016, we recorded net income of $37 million or $0.42 per diluted share, compared with net income of $35 million or $0.44 per diluted share for the second quarter of 2015. The difference in quarter-over-quarter earnings per diluted share can be attributed to lower earnings from reduced load as a result of mild weather, an increase in our common share count due to the final draw on the equity forwards sale agreement in June of 2015, partially offset by increased earnings from favorable power supply operations, as a result of increased wind production and better hydro conditions and higher allowance for equity funds used during construction.

Moving on to slide 12, total revenues for the second quarter of 2016 decreased $22 million to $428 million. The change in revenues was mostly the result of $21 million decrease in retail revenues from lower energy deliveries resulting from mild weather as well as the price decrease effective January 1, 2016, related to the 2016 general rate case.

Contributing to the mild weather were 21% fewer heating degree days in the second quarter of 2016 in comparison to the second quarter of 2015 as well as 26% fewer cooling degree days. Retail energy deliveries were down 5.2% quarter-over-quarter due to mild weather and the loss of one large industrial paper customer who previously purchased power through the Company's variable priced option plan. Specifically, residential deliveries decreased 4.4%, commercial deliveries decreased 2.8% and industrial deliveries decreased 10.4%, reflecting the shutdown of the large paper customer. PGE's 2016 General Rate Case took the loss of this large paper customers load into consideration and incorporated its effect in the prices and load forecast resulting in minimal earnings impact for 2016.

Now, onto power supply. Net variable power costs decreased $18 million quarter-over-quarter and the costs were $7 million below the baseline of the annual update tariff due to the overall optimization of our power supply portfolio. This is in comparison to the second quarter of 2015 when net variable power costs were approximately at the baseline.

Moving on to slide 13, generation, transmission, distribution and administrative and other expenses totaled $125 million for the second quarter of 2016, a decrease of $1 million from the second quarter of 2015. Depreciation and amortization expense increased $7 million quarter-over-quarter and was driven by a $4 million increase related to capital additions and a $4 million increase resulting from the temporary disallowance of amortization of credits for the refund to customers of the regulatory liability for the Trojans spent fuel settlement. Other income increased $3 million from quarter-to-quarter, due to an increase in the allowance for equity funds used during construction, primarily due to the Carty's project costs.

On the slide 14, we continue to maintain a solid balance sheet including adequate liquidity and investment grade credit ratings. As of June 30, 2016, we had a total of $661 million in cash, available short-term credit and letter of credit capacity, $1.1 billion in first mortgage bond issuance capacity and a common equity ratio of 49%. The Company has $500 million in revolving credit facilities, which has an expiration date of November 2019 and additional letter of credit facilities totaling $160 million to meet the Company's liquidity needs.

In May of 2016, we entered into a $200 million unsecured loan agreement with certain financial institutions. PGE borrowed $50 million under the agreement in May and an additional $75 million in June. We have until the end of October to borrow the remaining $75 million.

Moving on to earnings guidance on slide 15, PGE is reaffirming its revised 2016 earnings guidance of $2.05 to $2.20 per diluted share based on the following assumptions. Retail delivery growth of approximately 1%, weather-adjusted and excluding one large paper company; slightly below 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 data is not available; normal thermal plant operations; operating and maintenance costs between $515 million and $535 million; depreciation and amortization expense between $315 million and $325 million; and new customer prices effective August 1, 2016, which include only the return on and of the Carty capital costs of $514 million and all the operating costs as allowed by the OPUC in our 2016 general rate case. Back to you, Jim.

Thanks. In summary, we continue to focus on successful execution of initiatives that drive value for our customers and shareholders.

Slide 16 displays our key objectives for 2016. First, maintain our high level of operational excellence with a focus on employee and public safety, meeting our operating performance goals, and meeting our financial targets.

Second, work collaboratively with all stakeholders to prepare our 2016 integrated resource plan and its associated action plans as well as determine next steps for a possible accelerated renewable RFP. And third, with Carty now in service, continue to focus on our legal actions against the sureties and their obligations under the performance bond.

And now, operator, we're ready for questions.

Thank you. (Operator Instructions) Julien Dumoulin-Smith, UBS.

Good morning, Julien.

Good morning, Julien.

Hi, good morning.

(inaudible).

Excellent. Well, first off, Bill, congrats, but second, I suppose just following up on what you guys said on the RFP here, can you elaborate a little bit on how you're thinking about timeline, how much is that integrated with the IRP filing itself, is that sort of first the IRP, then the RFP? And then, secondly, given some of the considerations from PacifiCorp and [staff], how are you thinking about a rec procurement relative to just an outright ownership or development under a long-term PPA?

So this is a complicated conversation, but let me kind of take you through our thinking right now. We just got the decision last week from the Commission. We're trying to look at our options. We still see value of trying to pursue an RFP ahead of an approved IRP, but given the Commission guidance, that's going to be a little challenging. So I think the way we're going to approach it right now is continue to work through our IRP, file it at the end of this year. It will have an associated action plan, but continuing to look at how we could potentially move forward that RFP in an accelerated basis. But there is a little bit of internal discussion on how we're going to get there. We still like to capture the value of the production tax credits, but we also need to understand that the Commission wants to have an approved IRP to move forward with the RFP. So, when you look at the Commission decision last week, there are really two things that were raised; one is, we did not have an approved IRP, which we're going to work through towards the end of this year. The other thing is there still is a number of questions on the RFP that have to be sorted out. So our staff is looking at both those issues and trying to figure a path forward. Obviously, with Pacific's decision on pursuing wrecks that also factors into, we have been purchasing renewable energy credits all along as part of our acquisition strategy. And so we've been doing that, but we're in a little different position than Pacificorp. We are going to be short resources when Boardman goes out of service in the end of 2020. So we're in a little different situation than they are, where there tend to be more balanced. And so we are in a little different situation and we want to kind of factor that into our decisions as we decide whether to pursue wrecks or pursue renewable resources with steel on the ground. So those are the things we're all looking at. I think we will have more information in the next call, but we're just trying to figure out how we can capture the value of the production tax credits, but also understand what the Commission's concerns were and kind of working through that. It's going to take us some time to work through this all and we don't want to give up on the idea, but we also understand and appreciate what the Commission's concerns are. So the team is working hard on looking at various paths. But right now, we don't have a clear path forward, the likelihood is that we would ultimately have to get an improved IRP with an action plan with then we'll form the basis of the RFP, but we don't want to give up necessarily, I'm moving a little quicker, if we can find an avenue with all the parties to move forward.

Great. And then, can you discuss the Carty's deferral filing you made, I suppose last week it is, and how that would work in terms of both EPS impact in 2016 and 2017, as well as the timeline as it relates to the surety?

So let me talk of the [hike] part and then Jim could talk more specifically on the numbers. This is really just to preserve our position in terms of being able to differ, the cost above the $514 million. We clearly have to go prosecute our case against the sureties which we think we have a strong case to recover all the cost above the $514 million level and we will go through that case, but that's going to take some time, which is deferral actually just helped us preserve that higher cost and the ability to recover it, but as we said in the call, we're not going to pursue that until we exhaust all our opportunity to recover the cost of maturities and the contractor , as well as apparent of the contractor. So we're going to pursue all that before we actually try to recover any cost under the [deferral], we feel, I would say confident that we're going to be successful in those, in that pursuit of those dollars.

Jim, you want to talk about the numbers,

Julien, the only thing I'd add to Jim's comments is we estimate the earnings drag from not getting recovery immediately of those costs, it's going to be about $0.05 per year, annualized for full year.

So we're continuing to work it. It's going to take a number of years to get through the court cases that the surety continue to bind us to this, but I think we have a strong case and I believe we're going to be very successful in recovering our cost

Last with the detail on the numbers for guidance, what's the impact of hydro, obviously shifted a little bit quarter-over-quarter?

Julien. I don't have the exact number associated and what we're seeing in the hydro situation is, because of the temperatures we're seeing at faster run off of hydro this year than we saw last year and all get back to you on exactly what that EPS impact is.

Great. Thank you, guys.

Well, just an update, it's $0.02. The nice thing about having staff in the room.

Thank you. Our next question is from Brian Russo of Ladenburg Thalmann. Your line is open.

Good morning, Brian.

Good morning. Just to be clear, have you filed the deferral request and you're awaiting OPUC decision on that, or it's still to be filed.

No it's been filed with the OPUC.

It's been filed with the OPUC and then we've asked them to take no action on that filing until we're done maturities, as Jim pointed out earlier.

And that deferral will not run through the P&L at this point. I mean we are going to soak it, and then reserved against it.

Okay. So the $0.05 of full-year impact, that's not going to hit GAAP earnings.

That will hit GAAP earnings.

Okay. And remind me when you revised your guidance down last quarter, due to weather, I think there was a component of that for the unrecovered cost of Carty, is that accurate?

Yes. That is accurate, we reflected that in our updated guidance.

Okay.

With that by $0.02.

Right. But basically half the year.

Yeah.

Yeah. Okay. And why not just go forward with wind investments, you know, without Commission approval, they seem to be supportive and encouraged, but was more of a legal or regulatory decision that they couldn't take action or approve it. Just wondering what your thought process and strategies there.

Well, I think the way we thought about -- there was concern raised by parties on the design of the RFP. In terms of how we did the scoring and evaluation and without getting conclusion on the RFP itself, moving forward and let's say, we did do an RFP and it was not approved by the commission, and as you know, as you go through these processes, there's always winners and losers. Losers would have come back and say, what a process? wasn't fair, wasn't approved by the PUC, the company made a wrong decision and then, we ultimately have to fight their prudency battle, when their plant goes into service, which is after we've invested all the money. And that just seem to be too big a risk without having an approved RFP from the Commission. On the way we evaluate the resources, not only the process to get the bids in, but how we evaluate those resources to determine the shortlist and ultimately the winning bidder. So with that kind of backup, we would take huge risk for our investors with no certainty on recovery at the back end. It just didn't seem to be a place we wanted to be and felt like the commission needed to at least approve the process and the RFP to move forward, albeit they would still get another look at the shortlist, but they weren't comfortable with that. The other question they had in their mind to kind of represent their views is there was this question about what is the right strategy on wrecks versus tightening of the RFP. And while we did our own analysis to suggest that moving forward sooner was more advantageous to our customers that really hadn't been embedded in an IRP process, an integrated resource planning process. And so without that kind of rich analysis and review by all the stakeholders and the fact that there were people saying, we shouldn't go forward, they were left in a position with not having a full record to make that decision. And so I think they backed up to where we need to have a process that really backs all these issues before we like to forward. So given all that, it just didn't make sense for us to go forward. I would tell you that I believe it's a buyer's market right now given there's not a lot of demand for new renewable resources in the west, and if you happen to listen to the call of the hearing, there is a developer there who kind of express that of that point of view, but I think the Commission felt that they needed to have a fully vetted process. If we could have all the parties to agree, that would have been one thing, but because there were parties who disagreed, the Commission felt compelled to kind of really fall the process and so we agree with that and we'll have to go forward and under that premise. If we can find a path forward where we get broader support, we'll try to bring it back up. But I think we will have to finish at least some of the preliminary analysis in the IRP to kind of vet some of these issues that there were left kind of unanswered.

Got it. And then, just on slide 8, the standard RFP process timeline, expect to reach RFP decisions in 2018. Would you say that's early 2018, mid or late?

Let's see, [it is] probably mid to late 2018, I would guess. I think it depends on how long it takes to get the RFP approved. I think when we started this last accelerated RFP, we use the RFP from the last RFPs, which we thought would simplify the process because it had been approved. But a number of parties raised issues around that RFP and the design of it. And so it really depends how long it takes to get to an approved RFP. And if you go quickly, or can take long term, we expect to get the acknowledgment in probably late 2017, about a year after we file mid or late 2017 and then, time to go forward. So, (multiple speakers) again depends on first half of 2017 for the approval of the 2016 IRP, if things go well. I mean it depends on how many questions we get and issues that get raised. So, I would guess, probably mid to late 2018, we will have it approved.

Right. So would that give you enough time to build and own or reach some sort of a solution to the Boardman replacement capacity that's needed in 2020?

Yes, I think that gives us plenty of -- not plenty of time, it's tight. If you look at it two, three years, I mean Boardman closes at the end of 2020. So you've got 2020, 2019, and half of 2018. So it's doable.

And I'm sorry, I think, I missed this early, but did you quantify the natural gas opportunity?

We said about $70 million.

Got it. Okay, thank you.

Thanks, Brian.

Christopher Turner, JPMorgan.

Good morning, Chris.

Morning, Chris.

Morning guys, and congratulations, Bill. Thank you for the help and the patience over the past couple of years.

You welcome Chris, thank you.

Just, first, to clarify on the deferral filing, I think, I understand it, but it sounds like you made this filing, but you're basically not asking for any action on that for a while until you get everything situated with the SerDes. So from our vantage point right now, you are going to book this $0.05 cost ongoing in your GAAP earnings. And then, there's a potential to reverse that later. Is that kind of the correct way to think about that?

That's right, Chris.

And remind us if there is any kind of precedent here in the state for cost overages or anything that you or others might have experienced in the state over the past five to ten years, on ultimately getting commission approval. Not for deferral, but for the actual recovery of such expenses.

Trying to figure out (inaudible) individual capital projects that are small, but something this large with a lot of visibility. I think we're going to have to make a case of why -- if we're not successful with the sureties, then we are not successful with the contractor or the parent. We will have to see when that all plays out to make our position, I think, we will have to exhaust all our remedies to recover the cost and then make a case to the Commission, of why we should be able to cover that cost from customers.

Okay, great. And then, on the revised CapEx plan that seems to have gone up in 2017 and 2018 as a function of this new technology investment, in that plan right now is not the $70 million from the potential gas reserve investment. Could you just remind us of the exact kind of regulatory strategy going forward in terms of filing any new general rate cases? I know that you kind of flirted with the idea early this year and would I guess try to flow through the gas reserve investment through your fuel clause, is that correct?

Yes. So on the -- Jim talked about the capital switch and what's going on there, but in terms of rate cases, we were looking at 2017 general rate case as a backstop that Carty hadn't gone into service by the end of July. With Carty in service, we will skip July 2017 or any kind of general rate change. So we are probably going to look more likely at a 2018 general rate case and we will evaluate that. We wouldn't have to file that till February 2017. So we have some time to evaluate that, look at our cost structure and see what's going on with loads and so forth. In terms of the gas reserves, that will be a decision that comes out of the AUT filing and that will get a decision hopefully in October of this year of whether the Commission is supportive of that investment. And so that will play itself out later this year, but the way we've structured it is all the cost associated with the gas project and the natural gas reserves would be flowing through the AUT filing. Jim, you want to talk about capital expenditure forecast?

Yes. Chris, on the CapEx table, there's a couple of things that are going on in there. One is we've got a voice data project that was approved by the Board and fair bumped it up about $63 million. In addition to that, we've got a few additional dollars associated with the implementation of our customer information system. And as Jim was mentioning regarding the natural gas project, that is not included in that CapEx table at this bigger point in time until such time as we have got an approval by the Commission through the AUT update.

Okay. And then, once you do get that approval, that would immediately put that $70 million into [rates]?

Once we get that approval and the investment is made, then yes.

Paul Ridzon, KeyBanc.

Great, good morning. Let me tell congrats to Bill and thank you for your help. Under the timeline you'd laid out, which would imply you'll get 60% of the PTC. Is that the right way of thinking of it?

Yes. If we execute it, again depends on the contractors of where they are on their development path and whether they've got any safe harbors. If the safe harbor doesn't get executed to 2018, it would be at the 60% level for PTCs. But that's the whole purpose of the RFP, there may be some developers out there who have safe harbors that might be a little ahead of that. They've procured turbine contracts and they might have a better position to capture maybe a higher percentage of the PTC, but right now we don't execute until 2018, it would be at the 60% level.

Got it. Okay. And then, just want to make sure that because there was some mixed language around the deferral. So the pathline is you will defer these costs, but reserve against them for about $0.05 a year, if you're successful against the SerDes or the Abengoa, then it's really a non- issue, you'll just reverse worst those. And then, if you are unsuccessful on either of those paths, you go to the Commission and you'll start deferring and [virtually] you have deferred?

Well, we would then take it to the Commission whatever is remaining and make our case of why we think we ought to be allowed recovery of those costs than the Commission would rule on that request and if they approve some or all of that remaining balance, we would then reverse that to the income statement, but it would have to have a commission order.

Are you going to treat that $0.05 as kind of a non-recurring item or are you just going to book that?

Well, we're going to book it (multiple speakers) and reserve.

But you're not going to carve it out and (inaudible)?

(inaudible) result in slightly lower ROE.

And do you anticipate any extraordinary cost measures to try to offset that or it kind of is what it is until the Commission rules?

It is what it is until the commission rules. I think until we get full satisfaction through the court case.

Got it. Okay, thank you very much for your help.

Thanks, Paul.

[Kevin Spate], Bank of America Merrill Lynch.

Hi, good morning, it's actually Brian Chin, so I apologize if you mentioned this in your remarks already, I jumped on the call late, but could you give a little bit more sense of timing on the legal actions, I guess the sureties and their obligations? It would be helpful if we had some degree or sense of precedent or timing just help anchor expectations?

Okay. So in terms of getting all the way through the court case, it could be at least two to three years, maybe even longer, I mean four years, but where we are in the court case is we have a US District Court case against the sureties for recovery under the performance bond. They had requested that be stayed. We thought it should not be stayed and then there's also an arbitration going on, but in terms of the US court case, we did get a ruling last week from the US District Court that ruled in favor of us, that the court case should go forward on our claims against the sureties, and that the sureties should be precluded from participating in the arbitration case that's before the ICC. So that was a very good decision for the Company, that allows us to move forward with the case. We're going to move aggressively to move that case forward. The next part of that process is to set a schedule and our lawyers are working to put that schedule together, including all the steps. So that's the one thing that's going forward, and that's under the surety bonds that really specify that the US District Court is the place for our remedies there. There is also an arbitration going forward, and that is related to our guarantee that's provided by Abengoa, and under that guarantee, there is a provision for arbitration under that guarantee. So that arbitration has been set, we now have a panel of three arbitrators. Our first discussion with the arbitrators is to suggest that that arbitration doesn't need to move forward until we actually make a claim against Abengoa under the guarantee. So that's really the first step in that process before we get to damage it because our view is we need to solve all the issues with the sureties first to determine whether we have to go towards Abengoa for any additional satisfaction of our claims. So that's the process. The court case again could take two to three, maybe even four years, depending on how fast we can move through it. We believe, we have a very strong case and we will move that forward as expeditiously as we can, but that's kind of the time frame.

That's very helpful. I guess, does that mean that the Abengoa arbitration is in a little bit of a holding pattern now until the surety (multiple speakers)?

No, it's moving forward, the panel has been set, but I think, our first argument to the arbitrators would be as this case is not ripe yet, because we have not made a claim under the guarantee against Abengoa. And until we make that claim against Abengoa, there's nothing to decide, because there is no damages to claim against it. So we have to really go through the sureties first, and satisfy our demand and performance bond, and then we will turn to Abengoa if there is anything remaining of damages to be claimed. And so that's the way we see it going on, and so the panel has been set, there will be some process to brief the ICC or the arbitrators on the issues, and they will get a ruling on that specific issue before we actually get into the narrative of the damages. So that's kind of the way we see it playing out and we think that's the right way to play it out as we go forward.

Got it. Thank you very much. It's very helpful.

Thanks, Brian.

Andrew Weisel, Macquarie Capital.

Good morning, Andrew.

Good morning, guys. Just to follow up on that last -- the timing of the court cases, you mentioned a potential general rate case for a 2018 test year, which would be filed in roughly six months. My question is, if you have a GRC before the court cases are done which seems maybe somewhat likely, would you be able to crew up your expenses then, or would you still wait for the court and the GRC would only deal with recovery of a [non-other] CapEx and cost inflations?

I guess my general view is, we will have -- we're not going to answer recovery of the dollars until we have totally exhausted our legal remedies. The Commission will likely not want to rule on this issue until we have exhausted all those remedies because then it would basically be recovering twice. And so I think we're going to have to play the court cases all the way to the end to determine whether there is any remaining cost to recover from our customers and that will be the topic of a future rate case, probably not the 2018 rate case, given the time of the legal discussions.

Now, that could all change if we can settle this sooner or the sureties agree to pay all the damages under the performance bond, which again would leave us nothing to discuss in the next rate case.

Got it, okay. Unfortunate, but that sounds prudent. Next question on the 2016 financing, your slides still show that you may borrow another $100 million in the fourth quarter. With Carty now done, what are the swing factors that might make you elect to do that or not? And if you don't do it, would it just be a timing thing that we should expect that early next year, or could it be downsized or avoided?

It could be either downsized or eliminated, just depends on cash flows going into the balance of the year.

Alright, great. Then, lastly, the $70 million for the nat gas project, you said that's not included in the CapEx. What would be the timing of it in terms of when -- which years would that show up in if it is approved?

So again, we would expect a decision in October. If that decision is to our satisfaction in terms of the cost recovery of that investment, would happen fairly immediately in terms of investment going forward. Probably over six months, probably is what the spend would be is my guess.

Andy Levi, Avon Capital.

Hey, good morning. Congratulations, Mr. Valach. (multiple speakers). Yes, it's been a long time. Just a couple of questions. Actually, most of them actually were answered but just since the wind investment is kind of on the sidelines for now and I understand that you may have this $70 million opportunity on the gas side, and then obviously you raised your CapEx for 2017 as well by about $50 million or something like that. But even with that, you still have now, again, the high-quality problem of 2017 and 2018 and I guess 2019 as well of significant free cash flow after dividends, so just your thoughts on that. Obviously, you've said stuff in the past and the first desire was always CapEx, but now we're actually getting closer to where that money is going to be in the bank and as you know, interest rates are kind of low, so can't keep it in the bank. So I'm just curious what your thoughts are.

So, just the general view is there are investments not nearly to the extent of a wind farm, for example, but we do have, right now, we're building a new substation at Marquam. We need to do upgrades, the downtown core, there are other substations that need to be upgraded. So we are looking at the opportunity and will probably take it to our Board in our next board meeting to discuss areas that we need to improve the reliability of our system and move some of those projects forward. So that will probably be further discussed at our next earnings call. But we're in the process of looking at that and see important investments in the distribution system to improve the reliability of the service we provide our customers. And as you imagine like our utilities, the system start aging and you need to -- that aging system to ensure that we deliver the liability to our customers. So I think we'll have, feel pretty confident, until we share with you on the next call about that program.

Okay. So that will be on the third quarter call -- that we'll get some type of CapEx update. And I'll take through the rest of this decade, I guess, is that kind of the thinking?

Yes, probably five years. I don't know if it's okay.

Yes. Okay. Pass that, okay. And that you think will absorb most of this free cash flow, which is probably $150 million, $200 million a year in 2018 and 2019 after dividends. Is that kind of the way to think about it?

Good question, Andy. We will continue to look at it, look at what cash flows are, what investment opportunities are and we will make decisions based on what does projections look like. So stay tuned.

Okay, thank you. The [thorough] process recovered free cash flow or CapEx cover though. On the sales side, I don't remember if you have given this, I know you gave in your release, whether normalized sales number for the entire retail system, but just for residential and commercial for the quarter. Can you weather normalize those numbers or have not done that yet.

Hold on one second. So, quarter-over-quarter, weather adjusted for the entire system, so our residential, commercial and industrial, it's about down 5.1%. But you have to keep in mind, we've got that large paper company that had stepped out. So if you turn around and take that large paper company out, -- goes down to about 2.3 and that's just quarter-over-quarter. If you actually look at it on a year-to-date basis and then that number drops down to a positive 0.4% growth, net system weather adjusted.

But that includes industrial as well, Right.

Yeah, that includes industrial.

Can you isolate residential, commercial or not.

Not on our weather adjusted basis. I don't have those numbers in front of me.

Okay. And just last question on the IRP that you'll be filing in November. Is that correct.

Yes, fourth quarter.

Fourth quarter 2015.

And I understand, you go to the boards for some, obviously, which is unrelated IRP some system enhancements that are needed. But just is there any kind of high level kind of thoughts you can give us on this IRP beyond. You know, trying to maybe get some wind in which you talked about, but just any other things that you're thinking of longer term that you are willing to share with us.

So, I think, if you look at the IRP and what I've seen in the initial analysis is, clearly, we have to be thinking more about more renewable energy, given the 50% standard by 2040. And the ability to do that, all with RECs is probably impossible to do, because then you end up having to build ground power and then buy RECs to clean it up. So my guess is that we will continue to pursue new renewable resources to meet our obligation with some mixture of RECs and hard assets. I think that will be part of our strategy. We have to do that planfully over the period, so we can get to the 50%. Secondly, we have a fairly significant capacity shortfall. The extent we add more renewables and Boardman comes out of the mix, we are short capacity. I think the numbers are between 800 megawatts and 900 megawatts of short on the capacity side. So we're looking right now what's the right type of capacity to add to the system that at least cost lowest risk for our customers and as technology continues to evolve on the gas turbine side, we see that flexible combined cycle units can provide the kind of ramp rates that we would need while giving you the economics of a combined cycle operation. So those are starting to emerge as viable resources to meet our capacity needs because they provide us the flexibility to ramp up and ramp down but give us the heat rate benefit of combined cycle operation. So that is emerging where before we were looking at the reciprocating engines, this time we're looking at more of the gas turbine technology to be able to meet those capacity needs. Finally, we will continue to look at energy efficiency and demand response, that's still part of our strategy. We need to factor that in to minimize the load and we continue to look at where battery is positioned ourselves in terms of helping us meet peak load at that [needle peak] opportunity. So that's all it's being part of. I think that's going to bode well going into an RFP and allow us opportunities to continue to meet our customers' energy needs with reliable resources.

(multiple speakers) I'm sorry. Go ahead.

Whether there are contracts or ownership, that would be the conversation of the RFP and as always, we have to determine least cost lowest risk for our customers.

And again, Boardman, is that 2020-2021?

End of 2020

End of 2020. So you really need to be part of this IRP and (multiple speakers) and I guess the latest to spend would probably start on something like that, assuming it gets approved and if you are chosen to do, it would be in the 2019 time frame or would it be early?

I think we're saying hopefully mid-2018, we get a decision on the resources. So we can move forward on getting those resources constructed by the time people should have contracts in place, things ready to move, so we should be able to break ground and get going in that timeframe, if we can get a winning project.

Okay. And then, don't be insulted by this question, I just want to ask it. Just succession plan for you, Jim.

Or Bill.

Or Bill. We've got a great one for Bill.

(multiple speakers) mandatory retirement age, right, if I'm not mistaken, right, at your Company unlike some others, right, so you could go on [one to one] but is there any thought of any type of successor plan or are you kind of sticking around and I don't have to worry about that now?

No, I can't talk about it on a call anyway. I would tell you that the Board, every year I sit down with the Board and do succession planning for the higher officer team, as well as myself, just in case I happen to win the lottery or something like that, but we always take that as a very -- important to take those as very serious issue and we always are doing that, but I have nothing to announce or any indication of when I'm going to retire from the Company. So --

And you look great by the way. [You are sensational]. I hope to be able to --

Just translate that to my game.

Michael Sullivan, Wolfe Research.

Good morning, guys. Bill, congratulations. Just two quick questions circling back on the renewables RFP, just curious given the Safe Harbor language, why not ask the OPUC for approval of just 5% investment to preserve the potential of getting 100% PPC and then trying to hash out the rest of kind of the RFP thereafter?

Well, because we don't know what the project is and who the winning project is and whether they come with their own surfing contract or not, for any developer to commit to a 5%, they're going to want to recover the cost of that and so they're going to look to us and again, there is just the complications of who is the winning bidder. So we thought through those kinds of things, we've looked at that, but we don't see how we get a path forward with that process that would allow us to determine that that project was least cost lowest risk under an RFP evaluation process. So, we continue to needle through that, I mean clearly the Safe Harbors are out there which is of extreme interest to me just because you could commit this year, you really don't have to have that project up for four years which allows us to delay the impact, but without a process under which we can kind of review all of the bids under prices we're comfortable and the regulators are comfortable with, it's hard to get to that decision. So, we continue to needle on the idea, we continue to have conversations internally and maybe reach out the stakeholders and see if there's some opportunity. But right now, we're kind of better impasse right now what the parties and the Commission really wants to kind of prosecute the process. So, kind of we are where we are and we will continue to look at options, but right now, we don't see a path forward unless the party has really come to the table and work with us on getting agreement on that.

Okay, thanks. And just one more, I know you guys gave the EPS impact from the Carty overages, but just kind of thinking about it from a regulatory lag perspective, you guys have historically given some sort of guidance relative to the allowed ROE, how are you kind of thinking about that given the overages and still waiting on the deferral?

We haven't given guidance on the ROE in the past.

No, it's a spread between the allowed and the regulator, we said it's (multiple speakers).

Well, we said the lag. The lag when we get to having Carty in rate base, then the regulatory lag ends up being about 65 basis points to 70 basis points.

And this would add to (multiple speakers).

Right. This will add to it, yes.

Thanks, Michael.

Thank you. Our next questions from (inaudible). Your line is open.

Good morning, guys. Hi, Congratulations Bill. This might me a little bit in the weeds, I'm just curious how do you get the nickel relative to that $100 million dollar give or take over.

About half of it is depreciation, the other half is interest cost. And then, there is a miscellaneous expenses I've also included in there. But they will be the big drivers.

Okay, thank you.

Thanks, John.

Thanks, John.

Okay. I think we have no further calls. So we appreciate your interest in Portland General Electric. And we invite you to join us, when we report our third quarter 2016 results in late October. Thanks a lot and have a great day.

Ladies and gentlemen, thank you for your participation in today's conference. This concludes the program. You may disconnect.