Portland General Electric Company (POR) Q2 2016 Earnings Report, Transcript and Summary

Good morning everyone and welcome to Portland General Electric Company’s Second Quarter 2016 Earnings Results Conference Call. Today is Wednesday, August 3. This call is being recorded and as such all lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there will be a question-and-answer period. [Operator Instructions] For opening remarks I would like to turn the conference call over to Portland General Electric’s Director of Investor Relations Mr. Bill Valach. Please go ahead sir.

Thank you Vince and 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 discussions and 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 also 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 opened today and that release and the Form 10-Q are available on our website at portlandgeneral.com. The company undertakes no obligation to update publicly any forward-looking statements whether as a result of new information, future events or otherwise and the 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 our, Jim Piro.

Thank you, Bill. Before we move onto the business of our second quarter 2016 earnings call, I’d like to take moment to share with you that Bill Valach is retiring this month after 25 years at PGE. As many of you are aware, Will is at the helm of our Investor Relations program, when we return to the New York Stock Exchange as a publically traded security in 2006. Our Corporate Finance Manger, Chris Little who’s 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 you distinguished service and welcome Chris. Bill we’re going to miss you, and we’ll miss your comments at the start of the call. 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 for 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 fire 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, acknowledge by the OPUC in 2010. The competitive bidding process was won by an engineering procurement and construction contractor comprised of several affiliates of Abengoa S.A. Following our termination of the construction agreement in December 2015, we assume 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 U.S. Department of Energy. This increase follows an overall price decrease of 2.5% that took effect on January 1, 2016, leaving the 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 cost above the $514 million level, starting from an in-service date until this additional amounts are approved for recovery if necessary, under a future regulatory filings. This will depend on whether the additional amount 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 in 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 these sureties to enforce satisfaction in terms of 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 a 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 the relationships strength among residential customers, across 129 gas, electric and combination utilities. Let us move onto Slide 7 now for an update on the economy. As the broad U.S. economic expansion that continues Oregon, in particular, is experiencing a significant and sustained pace of growth. In June, the U.S. Bureau of Economic Analysis released state GDP estimates for 2015. Oregon GDP growth rate of 4.1% tied California for the top rank. Oregon’s 2015 economic outlook 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 U.S. with respect to labor market indicators. Currently, Oregon’s unemployment rate is 4.8% versus 4.9% nationally. And the PGE 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 the 10 major metro areas. While the cost of housing in Portland is rising, it’ 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 account 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 focused 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 portfolios 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 customer’s winter and summer peaking needs, along with our needs to integrate new renewable resources. Turning to Slide 9, I’d 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 approved in RFP for new renewable resources with the 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 the 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 investment of approximately $70 million in a natural gas project. We have filed our annual update tariff with the gas supplied 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’d like to turn the call over to Jim Lobdell, who will provide more details on our second quarter financial performance and guidance. Following his 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 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 account due to the final draw on the equity forward 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 onto 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 a loss of one large industrial paper customer who previously purchased power through the company’s very hopeful 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 effects in the prices in load forecast resulting in minimal earnings impact for 2016. Now on to 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 onto 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 Trojan spent fuel settlement. Other income increased $3 million from quarter-to-quarter due to an increase in allowance for equity funds used during construction primarily due to the Carty’s project costs. On to 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 facility, 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 onto 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 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 operating costs as allowed by the OPUC in our 2016 general rate case. Back to you, Jim.

In summary, we continue to focus on successful execution of initiatives that drive value for 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, we are 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] Our first question is from Julien Dumoulin-Smith of UBS. Your line is open.

Good morning Julien.

Hi, Julien.

Hi, good morning.

How are you?

Excellent. So 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 are 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 wreck procurement relative to just outright ownership or development under a long-term PPA?

So this is a complicated conversation, but let me kind of take you to our, thank you right now. We just got the decision last week from the Commission. We’re trying to look at our options. We still see value you are 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, filing at the end of this year. You will have an associated action plan. But continue to look at how we could potentially move forward that RFP in an accelerated basis. But there is a little bit of internal discussion and how we’re going to get there. We still like to capture the value of the production tax credit, but we also need to understand that the Commission wants to have an improved IRP to move forward with that RFP. So, when you we look at a Commission decision last week, there are really two things that were raised, one is, we do not have an approved IRP, which we’re going to work through towards the end of this year. The other thing is there’s still a number of questions on the RFP that have to be sorted out. So our staff is looking at both of those issues and trying to figure out 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 a little different position in Pacific Corp, 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 that, we are in a little different situation than 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 things we’re all looking at I think we’ll 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 approved IRP with an action plan we then would form the basis of the RFP. But we don’t want to give up necessarily on 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 the deferral filing you made I think it was last week it is. And how that would work in terms of both EPS impacts in 2016 and 2017 as well as the timeline as it relates to the sureties?

So let me talk about the hike part of it and then Jim can talk more specifically on the numbers. This is related to preserve our position in terms of being able to defer 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’ll go through that case. But that’s going to take some time. The deferral actually just helps 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 opportunities to recover the cost from the sureties and the contractors as well as the parent of the contractor. So we’re going to pursue all that before we actually try to recover any cost under the deferral. And 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.

Yes, Julian the only thing I’d add to Jim’s comments is, we estimate earnings drag from not getting recovery immediately of those costs is going to be about $0.05 per year.

That annualized?

Annualized.

Annualized for the full year.

It’s going to take a number of years to get through the court cases if the sureties continue to find us through this, but I think we have a strong case and I believe we’re going to be very successful in recovering our cost.

Last little detail on the numbers for guidance. What’s the impact of hydro obviously you shifted a little bit quarter-over-quarter?

Julian, 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 a faster run off of hydro this year than we saw last year. And I’ll get back to you on exactly what that EPS impact is.

Great. Thank you, guys.

Well. Just an update its $0.02. Well now you think about having staff in the room.

Some positives in the quarter.

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

Good morning, Brian.

Good morning, Brian.

Good morning. Just to be clear, have you filed the deferral request and you’re waiting OPUC a 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 we’ve asked them to take no action on that filing until we’re done with the sureties as Jim had pointed out earlier.

And we will – that deferral will not run through the P&L at this point, we are going to soke it, and then reserve against it.

Exactly.

Okay the $0.05 of full year impact that’s not going to hit cap earnings.

It will hit, that will hit cap earnings.

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

Yes, that is accurate. We reflected that in our updated guidance. Its was about $0.02.

Right pretty much basically half a year.

Yes.

Okay. Why not just go forward with winds investments without commission approval, they seem to be supportive and encouraged but with more of a legal or regulatory decision that they couldn’t take action or approve it. Just wondering what your thought processes and strategies there?

When I think the way we thought about there was a concern raised by parties on the design in the RFP in terms of how we did the scoring and evaluation. And without getting conclusion on the RFP it self moving forward and let’s say we did do an RFP and it was not approved by the commission. And as you know if you go through these processes there is always winners and losers, the losers would have come back and say, well the process wasn’t fair, it wasn’t approved by the PUC, the company made a wrong decision. And then we ultimately have to fight that prudency battle when that plant goes into service, which is after we’ve invested all the money. And that just seemed 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. So it just didn’t seem to be a place we wanted to be and felt like the commission needed at least improve the process and the RFP to move forward, albeit they would still be and then look at the shortlist. But they were uncomfortable with that. The other question they had in their mind to kind of represent their views. There – was this question about, what is the right strategy on wrecks versus timing 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 a IRP process, integrated resource planning processes. So without that kind of rich analysis and review by all the stakeholders and in fact that there were people saying we shouldn’t go forward, they were in a position with not having a full records to make that decision. So I think they backed up to why we need to have a process that really vets all these issues, before we let you go 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 buyers market right now, given there is 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 would kind of express that point of view. But I think the Commission felt that they needed to have a fully vetted process. If we could have got 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 follow the process. And so we agree with that and we will have to go forward under that premise. If we can find a path forward, where we get broader support, we will 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 were left kind of unanswered.

Got it and just on Slide 8, the standard IRP process timeline expect to reach RFP decisions in 2018, would you say that’s early 2018, mid or late?

Let us see, by the end of – 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 used the RFP from the last RFP’s, 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 it so really depends how long it takes to get to an approved RFP. And it can go quickly or it could take a long time. We expect to get the acknowledgement in probably late 2017, about a year after we filed mid to late 2017 and then in the time to go forward. So…

First half of 2017…

Yes, that 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 high 2018 we will have it approved.

Alright, so does that – would that give you enough time to build and own or reach some sort of solution to the Boardman replacement capacity that’s needed in 2020.

Yes, I think that gives us plenty – not plenty of time it’s tight [ph] if you look at two, three years I mean Boardman closed 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 earlier, but did you quantify that natural gas opportunity?

We said about $70 million.

Got it. Okay, thank you.

Thanks, Brian.

Thank you. Our next question is from Chris Turnure of JPMorgan. Your line is open sir.

Good morning, Chris.

Good morning, Chris.

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

You’re 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 sureties. 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 a correct way to think about that?

Yes, that’s right Chris.

And remind us if there’s 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, I don’t know five to 10 years on ultimately getting commission approval. Not for deferral, but for the actual recovery of such expenses?

Starting to figure out we have anything like that. I don’t recall kind of…

I mean we have capital – 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 at the sureties and we’re not successful with the contractor or the parent, we’ll have to see where that all plays out to make our position. I think, we’ll have to exhaust all our remedies to recover the cost and then and 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 plant 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 what I guess try to flow through the gas reserve investment through your fuel clause, is that correct?

Yes. So on the – Jim will talk 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 for any kind of general rate change. So we are probably going to look more likely at 2018 general rate case and we’ll evaluate that, we wouldn’t have to file that till February of 2017. So we have some time to evaluate and 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 is all the costs associated with those gas – with the gas project, the natural gas reserves would be flowing through the AUT filing. Jim you want to talk a little bit about the capital expenditure forecast?

Fair, so on the CapEx table, there is 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 so that 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 figure of point in time until such time as we have gotten approval by the commission through the AUT update.

Okay and then once you – do you get that approval that would immediately put that $70 million into rates?

It was, we get that approval and the investment has made then yes.

Okay, great. Thanks.

Thanks, Chris.

Thank you. Our next question is from Paul Ridzon of KeyBanc. Your line is open.

Good morning Paul.

Good morning.

Let me tell congrats to Bill and thank you for your help.

You welcome, Paul.

Under the timeline you’d laid out, which would imply you’d get 60% of the PTC. Is that the right way of thinking of it?

Yes, we executed – again depends on the contractors, where they are in their development path and whether they’ve got any safe harbors. The safe harbor doesn’t get executed to 2018 and be at the 60% level for PTCs. But that’s the all-purpose of the RFP, there may be some developers out there who have Safe Harbors that might be a little ahead of that they procured turbine contracts and they might have a better position to capture maybe a higher percentage of the PTCs. But right now, we don’t execute till 2018 it’d be at the 60% level.

Got it, okay. And then just want to make sure that, could you give some mix language around the deferral. So the path line is you will defer these costs, but reserve against some – for about a nickel a year, if you're successful against the sureties or – Abengoa and its really a non-issue you'll just reverse those and then if you are unsuccessful in either of those paths, you go to the Commission and you'll start deferring in reverse what you have deferred?

Well, we will then take it to the Commission whatever was remaining and make our case of why we think we ought to be allowed recovery of those costs, then the Commission will 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 be have to have a Commission order.

Do you going to treat that $0.05 is kind of a non-recurring item, are you just going to book that?

Well, we are going to book at…

Well, with the reserve…

But you are not going to carve it out when you kind of report it in your decision.

No, no, we have to go through a lot of operations it will just be – result of slightly lower ROE.

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

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

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

Thanks Paul.

Thank you. Our next question is from [indiscernible] of Bank of America Merrill Lynch. Your line is open.

Good morning, Kevin.

Hi, Kevin.

Hi, good morning it is actually Brian Chin.

Hi, Brian.

So I apologize if you mentioned this in your remarks already, I jumped on the call late, but could you give a little 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 how 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, maybe four years but where we are in the court cases, as we have U.S District Court case against the sureties for recovery under the performance bond they had requested that the stay we thought it should not be stayed. And then the results of an arbitration going on but in terms of the U.S court case, we did get a ruling lastly from the U.S. District Court that ruled in favor of the us, that the court case should go forward on our clients against the sureties and 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 will allows us to move forward with a case we’re going to move aggressively to move that case forward the next part of that process is ahead of schedule and our lawyers are working to put that schedule together including all the steps. So that’s the one thing that going forward and that’s under the surety bonds that really specify that the U.S. 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 guarantee – that arbitration has been set we now have a panel of three arbitrators. Our first discussion with the arbitrator’s is to suggest 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 cases again it could take two to three maybe even four years depending on how fast we can move through it. We believe we have a very good strong case. And we’ll move that forward as expeditiously as we can, so that’s kind of the timeframe.

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 contribution is off.

No it’s moving forward the panel has been set, but I think our first argument to the arbitrators would be is this case is not right yet because we have not made a claim under the guarantee against Abengoa. And until we make that claim against Abengoa there is nothing to decide but there is no damages to claim against. So we have to really go through the sureties first and satisfy our demand and performance bond and then we’ll turn to Abengoa if there is anything remaining to be damages to be claimed. And so that’s the way we see it going on. 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 way we see it play now and we think that’s the right way to play it out as we go forward.

Got it. Thank you very much. That’s very helpful.

Thanks, Brian.

Thanks, Brian.

Thank you. Our next question is from Andrew Weisel of Macquarie Capital. Your line is open.

Good morning, Andrew.

Good morning, guys. Just a follow-up on that last – the timing of the court cases. You mention a potential general rate case for 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 true up your expenses and/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 to – we are not going to actually recover the dollars until we have totally exhausted our legal remedies. The Commission would likely not want to rule on this issue until we have exhausted all those remedies, because then we would basically be recovering twice. And so I think we are going to have to play the court cases all the way to the end just in terms of whether there is any remaining cost to recover from our customers and that would be the topic of our future related, probably not 2018 break year, given the time of the legal discussion.

Got you.

Now that could all changes if we can sell it sooner or the sureties agreed 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 the time is prudent. Next question on the 2016 financing, your slide still show that you may borrow another $100 million in the fourth quarter. With Carty now done, what are the twin factors that might make you elect to do that or not? And if you don’t do it, would it be just be a timing thing? We should expect that early next year or could it be downsized or avoided?

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

Alright. Great. And then lastly the $70 million for the nat gas project, you said that not included in the CapEx. What would be the timing of it in terms of when – which year would that show up in if it is approved?

So again, we would expect the decision in October. If that decision is towards satisfaction in terms of the cost recovery and investment, would happen fairly immediately in terms of investment going forward. Probably over six months, probably where the spend would be, it’s my guess.

That’s nice, okay. And also Chairman, thank you very much, Bill, congratulations. Jim and Jim I know you got a good bench there, but I am sure Bill will be missed.

Thanks, Andrew.

Thanks, Andrew.

Thank you. Our next question is from Andy Levi of Avon Capital. Your line is open.

Hi.

Good morning, Andy.

Hi, good morning. Congratulations Mr. Valach. Envious.

That over here, but he’s still flowing.

Yes, it’s been a long time. Just a couple of questions, actually most of it were actually 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 in 2017 and 2018 of – and I guess 2019 as well a 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 the lows so you 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 market, we need to do upgrades to the downtown core, there are other substations that need to be upgraded. So we are looking at the opportunity – I’ll 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 our further discuss at our next earnings call. But now 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 all utilities the system start aging and you need to access that aging system to ensure that we deliver the reliability to our customers. So I think we’ll have, feel pretty confident, we’ll have something to share with you on the next call about that program.

Okay. So that will be in the third quarter call/e.i., that we’ll get some type of CapEx update. And that will take us through the rest of this decade, I guess, is that kind of the thinking?

Well, probably five years, five to ten.

Yes, okay, I’ll past that. Okay, okay. That you think it will absorb most of this free cash flow, which is probably $150 million to $200 million a year in 2018 and 2019 after dividends, it’s that the 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’ll make decisions based on what our projections look like. So stay tune.

Okay, thank you. Deferral processes recovered free cash flow or CapEx cover though. On the sales side, I don’t remember if you had 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. I’m just trying to grab a page. So quarter-over-quarter weather adjusted for the entire system, so our residential, commercial and industrial its about down 5.1%. But you have to keep in mind, we’ve got that large paper company that had stepped out.

Right.

So if you turn around and you take the large paper company out that 5.1% 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, then that number drops down to a positive 1.4% growth net system weather adjusted.

But that includes industrial as well, right?

Yes, that includes industrial.

Right. Can you isolate residential, commercial or not?

Not on a 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 of 2016.

And I understand you’re going 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 regret is probably impossible to do, because the new, you have to build ground power, and then by Rex to clean up. So my guess is that we will continue to pursue new renewable resources to meet our obligations with some mixture of Rex and hard asset that will be part of our strategy. We have to do that planned fully over the period, so we get to that 50%. Secondly, we have a fairly significant capacity shortfall, the extent we more renewables and Boardman comes out of the mix, we are short capacity, I think the numbers are between 800 and 900 megawatts or short on the capacity side. So we're looking right now, what's the right type of capacity to add to the system that least cost lowest risk for our customers in, 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 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 down a bit of combined cycle operation. So that is emerging where before we are 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 continue to look at energy efficiency and demand response, that's still part of our strategy and we need to factor that into – can minimize the load and we continue look at where batteries position ourselves in terms of helping us meet peak load at that needle peak opportunity. So that always been 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.

And just a reminder – I’m sorry go ahead.

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

And again, Boardman, is at 2020, 2021.

End of 2020.

End of 2020, so you really needs to be part of this IRP and…

Capital.

And I guess the latest spend, would probably start on something like that, assuming it gets approved and if you are chosen to do, it would be about in the 2019 timeframe or would it be early?

I think we are seeing hopefully mid-2018 we get a decision on the resources, so we can move forward on getting those resources constructed by that time should have contracts in place things ready to move so we should be able to break around 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 wanted to ask it's just succession plan for you Jim?

Bill.

Hey, Bill.

We got a great one for Bill. [Indiscernible]

I did know mandatory retirement age right, if I’m not mistaken right, your company unlike some others, right, so you could kind of go on…

I can go on…

But is there any thought of any type of successful plan or you kind of sticking around and we have to worry about that now?

We are not going to talk about that in a call anyway. I would you tell you the Board every year I sit down with the Board and do succession planning of the entire officer team. As well as myself, just in case, I have to win the lottery or something like that, but we always take that as a very – the Board take that as a very serious issue and we always are doing that. But I have nothing to announce or any indication of when I'm going to retiring the company.

And you look great by the way. Sensational, I hope to be…

Could you just translate that to my golf game?

Thank you very much.

Thanks Andy.

Thanks for your questions, Andy.

See you in November.

Thank you. Our next question is from Michael Sullivan of Wolfe Research. Your line is open.

Good morning, Mike.

Hi, Mike.

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 OPC for approval of just 5% investment to preserve the potential of getting 100% PTC and then trying to hash out the rest of kind of the RFP thereafter?

Because we don’t know what the project is and who the winning project is and whether they come with a wrong turbine contracts or not. For any developer to commit to a 5%, they're going to want to recover the cost of that and so they are going to look to us, again there is – just the complications of who is the winning bidder. So we saw 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 if that project was lease 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 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 the bids under, prices were comfortable and the regulators are comfortable, its hard to get to that decision. So we continue to needle on the idea, we’ll 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 bit of impasse right now with 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 regulators…

Well we say 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 the [indiscernible].

Andrew had asked too [ph].

Okay, thank you.

Thanks Michael.

Thank you. our next question is from John Ali of Castleton Investment Management. Your line is now open.

Good morning, guys. Hi, congratulations Bill. This might be a little bit in weeds and I’m just curious. How do you get to the nickel relative to that $100 million give or take overage?

About half of it is depreciation, the other half is interest cost and then there is miscellaneous expenses that are also included in there.

Got it. Okay.

But those are 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 participation in today’s conference. This concludes the program. You may disconnect.