Portland General Electric Company (POR) Q1 2016 Earnings Report, Transcript and Summary

Good morning everyone and welcome to Portland General Electric Company's First Quarter 2016 Earnings Results Conference Call. Today is Friday, April 29. This call is being recorded and as such all lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer period. [Operator Instructions]. For opening remarks I would like to turn the conference call over to Portland General Electric's Director of Investor Relations Mr. Bill Valach. Please go ahead sir.

Thank you Candice, good morning everyone. We’re 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 presentation to supplement our discussions and we’ll be referencing throughout the call to slides. The 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 fact and as such consult to forward-looking statements under current law. These statements are subject to factors that may cause the actual results to differ materially from the forward-looking statements made today. For a description of some of the factors that may occur that could cause such differences the company requests that you read our most recent Form 10-K and Form 10-Q. Portland General Electric's first quarter earnings were released via our earnings press release and the Form 10-Q before the market opened today and the release is available on our Web site 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 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, Chief Financial Officer and Treasurer. Following our prepared remarks we will open the line up for your questions. And now it's my pleasure to turn the call over to our CEO, Jim Piro.

Thanks Bill. Good morning and thank you for joining us. Welcome to Portland General Electric's first quarter 2016 earnings call. On today's call I will provide an update on our financial and operating performance, the economy in our operating area and construction progress on our new Carty Generating Station and our capital expenditure forecast, our plan to request an accelerated renewable RFP, Oregon’s new landmark energy bill referred to as Oregon clean electric plants and our 2016 integrated resource plan. I’ll then turn the call over to Jim Lobdell who will provide more details on our financial performance and revised earnings guidance and review our dividend increase. As reported on slide 4, we reported net income of $0.68 per diluted share in the first quarter of 2016 compared with net income of $50 million or $0.62 per diluted share in the first quarter of 2015. Net income was higher due to cooler winter temperatures in the first quarter of 2016 versus the record warm temperatures in the first quarter of 2015. As well as the extra day in February for leap year. Contributing to a 2.7% increase in retail energy delivery, while our temperatures were favorable on an quarter-over-quarter basis, the first quarter of 2016 was also an seasonably warm, with seasonally degree [ph] days 15% below the 15 year average. As a result of an seasonally warm weather and unfavorable wind production in 2016 as well as the incremental cost of complete Catry that are not included in customer prices in our 2016 general rate case, PGE is revising 2016 earnings guidance down by $0.15 to $2.05 to $2.20 per diluted share. Jim and I will provide more details on Catry and a revised guidance later in the call. I'm also pleased to report that on Wednesday the PGE board approved our 10th and consecutive annual dividend increase as we went public a decade ago. The 6.7% increase in the dividend reflects our commitment to providing a competitive return for investors and is driven by the company's ability to execute our long-term strategic plan of operational excellence, business growth and corporate responsibility. Now for an operational update on slide 5, we delivered solid operating performance in the first quarter of 2016, including PGE generating plant availability of 93% and achieving high customer satisfaction. According to the latest survey results by market strategies TQS research, PGE continues to rank in the top quartile in overall customer satisfaction across all customer categories, residential, general business and key customers. Let’s move to slide 6 for an update on the economy. Our local economy remains strong with Oregon unemployment rate dropping to a record low of 4.5% in March, which is a 0.5% below the national unemployment rate of 5%. This is the first time in more than 20 years that Oregon is below the national unemployment rate and the lowest point in Oregon’s history, since comparable records began in 1976. Unemployment in PGEs operating area was also low at 3.9% in March. Oregon leads the nation with a best performing state economy last year according to Bloomberg’s economic evaluation of states released in February of 2016. Bloomberg’s analysis takes into account; employment, oil prices, personal income, tax revenues, breakage delinquencies and the publicly traded equities of its companies. According to the Portland business herald, Portland is broadening its position as an epicenter of the global four square business. Specifically, Nike is adding approximately 3.2 million square feet of office space mixed-use and parking structures to existing 2 million square foot Nike campus. Adidas announced plans to grow its Portland workforce by 10% adding 120 workers to its headquarters by year-end. And at the same time, Under Armour has identified Portland as the strategic hub also announcing plans to grow its footwear and innovation operations in Portland with the new facility south of downtown that will be more than 100,000 square feet and more than double its staff of 40 to 100. Oregon’s growing economy contribute to an increase in PGEs customer count of approximately 1.3% over the past year. It’s largest growth rate since 2008. The strong growth drove retail lows which were up 2.8% quarter-over-quarter when adjusting for whether and extremely one large paper company and up 1.7% quarter-over-quarter when you also removed the extra leap year day. This net growth encompasses lower industrial deliveries that reflect the softening in solar and metal manufacturing and a decrease in the rate of growth in the high-tech sector. Based upon first quarter weather adjusted load result and current economic indicators, PGE's projected year-over-year load growth of 1% this year is 1% for this year adjusting for whether the leap year day and including the one large paper customer. This growth reflects an of approximately 1.5% reduction due to energy efficiency. On slide 7 I’d like to provide an update on progress on the Carty generating station, our 440 megawatt natural gas baseload resource under construction near Boardman, Oregon. We estimate total capital expenditures for the Carty including AFDC to be unchanged from our prior estimated range of $635 million to $670 million. This range does not include any amount that may be received from Liberty Mutual Insurance Company and Zurich North America Insurance Company, the sureties that provided a performance bond of $145.6 million under the construction agreement. On March 9, the sureties denied liability under the performance bond, we disagree with the sureties determination and on March 23 we filed a breach of contact action against the sureties. On April 15 the sureties filed the motion to stay that proceeding, alleging that our claim should be addressed in the arbitration proceeding initiated by Abengoa in January. We also disagree with this assertion and will oppose the sureties motion to stay the proceeding. Construction and commissioning are continuing and we are making solid progress on the systems required for the first fire scheduled to occur at the beginning of June and we continue to target an in-service date by July 31. However due to uncertainties related to performed by the former contractor Abeinsa and that the work necessary to correct defects and complete construction, the cost and compensation date for Carty could vary from our current projections. Increased cost and a delay of the targeted service date could impact the amount PGE can recover for Carty in customer prices. Our 2016 general rate case authorized upto $514 million including AFDC assuming an in-service date by July 31, 2016. If our cost to compete Carty with any amount that may be received from the sureties exceed the allowed amounts PGE intends to seek recovery of the excess amounts in customer prices. However there's no guarantee that would be granted by the OPUC. Let’s turn to slide 8, as part of PGE’S renewable acquisition strategy we are now planning to request an accelerated RFP process reported to procure renewable resources to maximize the economic value of available tax credit on behalf of our customers. The recent federal legislation after December includes extensions of both the production tax credits for wind facilities and the investment tax credit for solar facilities with each including service debt provisions. Our current plan is to request OPUC approval to issue renewable RFP in the second quarter of 2016 with an accelerated process and timelines to allow participants in the RFP to maximize available tax credits on behalf of PGE customers. Subject to this approval we will issue an all source renewable RFP for up to approximately a 175 average megawatts of Oregon, RPS [ph] qualified renewable resources. Similar to PGEs prior RFP process, an independent evaluation would be selected to actively participate to ensure a repair and regional process and to assure that the short lived selection is the least caused least risk for PGE customers. Go on to slide 9, we have provided a summary of the company’s, capital expenditure forecast in 2016 to 2020. These amounts potentially to be augmented with incremental investments related to system reliability and operational efficiencies to provide guide to our customers as well as potential resources from the RFP for renewables. The graph does not any capital of projects and the outcome of our renewable RFP or any resources required under the 2016 integrated resource planning process. Additionally we are continuing to pursue on our first year basis and initial investment improving natural gas reserves of upto approximately $100 million, which would represent about 10% of our projected annual average national gas burn. We have filed our annual update tariff with the placeholder for a possible natural gas supply from this investment, pending approval of the OPUC and the identification of an opportunity that meets our requirements. We will continue to provide the updates on our capital expenditure forecast in future earnings calls. Now moving on to slide 10. During the 2016 session, Oregon’s legislature passed a landmark energy bill that will help preserve our environment while protecting PGE customers in our state's economy by ensuring reliability and affordability criteria are maintained. The new law requires PGE to increase the amount of energy delivered to customers from fall of price renewable resources to 50% by 2040. The law also requires PGE to eliminate coal-fired generation from our customer’s energy mix no later than the end of 2035.We are pleased to have been part of a collaborative process that puts Oregon electric sector on a path to achieve significant carbon reductions as we planned for Oregon’s energy futures. This is a sensible approach that reflects our customers values, while retaining key affordability and reliability protections for our customers. Turning to slide 11. Our 2016 integrated resource planning process will take into account this new legislation. It will evaluate the need for additional energy efficiency, demand-side actions and replacement of our Boardman coal plant that will at least use, the use of coal by the end of 2020. We will also look at renewables to meet Oregon’s renewable portfolio standard of 20% by 2020 and the capacity needed to meet both our energies winter and summer peak needs, while integrating new renewable resources. Now I’d like to turn the call over to Jim Lobdell, who will provide more details on our first quarter financial performance, liquidity, our revised earnings guidance and the dividend increase. Following these remarks we will open the lines for your questions. Jim?

Thank you, Jim. Turning to Slide 12, as Jim mentioned the first quarter of 2016, we reported net income of $61 million or $0.68 per diluted share compared to net income of $50 million or $0.62 per diluted share for the first quarter of 2015. The difference in quarter-over-quarter earnings can be attributed to multiple factors. First, an improvement in weather. Warmer than normal weather in the first quarter of 2016 resulted in a negative impact on earnings per share of $0.14, this compares to a negative impact from whether in the first quarter of 2015 of $0.20 per share for a quarter-over-quarter improvement of $0.06. Second, there was an increase in allowance for funds used during construction in comparison to the first quarter of last year, which contributed an additional $0.04 for earnings per share. This was partially offset by $0.05 related to an increase in the share count in June 2015 through the final draw on the equity for sale agreements. Moving to slide 13, total revenues for the first quarter of 2016 increased $14 million to $487 million. The change in revenue was primarily due to three factors; first, a $12 million increase in retail revenues from higher energy deliveries through largely to more favorable weather quarter-over-quarter. Second, an $8 million increase related to a slight rise in the average system delivery price due to an increase in the percentage of deliveries going to residential customers, while deliveries to industrial customers at somewhat lower prices declined. And third a $7 million decrease in wholesale revenues. Retail energy deliveries were up 2.7% quarter-over-quarter and an extra day for leap year with an 8.9% increase in residential deliveries, a 4% increase and commercial deliveries offset by a 10.4% decrease industrial deliveries, primarily due to the shutdown of a large paper customer. PGE’s 2016 general rate case outlook with the loss of this 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 $5 million quarter-over-quarter. However, cost for $1 million above the baseline of the annual update tariff due to unfavorable wind generation. This is in comparison to the first quarter of 2015 on net variable power costs for $2 million below the baseline. Moving on to slide 14, generation, transmission, distribution and administrative and other expenses totaled $127 million for the first quarter of 2016, an increase of $5 million from the first quarter of 2015. Generation, transmission and distributions increased $4 million due to a $2 million increase in the labor costs, a $1 million increase in service restoration costs and $1 million increase in information technology expenses. Administrative expenses increased 1 $million due to a $2 million increase in compensation and benefits offset by $1 million decrease in our reserve for customer receivables. Depreciation and amortization increased $7 million quarter-over-quarter and was driven primarily by a $4 million increase related to capital additions and a $4 million increase resulting from lower amortization of a regulatory liability for the Trojan spent fuel settlement. Total interest expense decreased $3 million quarter-over-quarter with $2 million related to an 11% decrease in the average balance of debt outstanding and $1 million allowance for borrowed funds used during construction. Other income increased $1 million from quarter-to-quarter due to a $3 million increase in AFUDC offset by a $2 million decrease in our earnings on the nonqualified benefit plan trust assets. Moving onto slide 15, we continue to maintain a solid balance sheet, including adequate liquidity and investments grade credit ratings. As of March 31, 2016 we had a total of $533 million of cash, available short-term credit and letter of credit capacity. $1.1 billion of first mortgage bond issuance capacity and a common equity ratio of 51%. The company has $500 million in revolving credit facility, which has an expiration date of November 2019, an additional letter of credit facilities totaling $160 million to meet the company's liquidity needs. Moving on slide 16 in earnings guidance. PGE is lowering its 2016 guidance of $2.20 to $2.35 per diluted share to $2.05 to $2.20 per diluted share. The reduction in guidance is based on the following factors. First, initial guidance provided in February included the impact of warm weather and lower than estimated wind production in January which totaled approximately $0.08 per share. Unfavorable wind and weather conditions in February, March and early April reduced estimated earnings an additional $0.12. $0.10 for warmer than normal weather and $0.02 for lower than estimated wind production. Second, we are estimating a $0.02 reduction in EPS in 2016 related to the additional cost to complete the Carty plant in excess of the $514 million approved by the OPUC in our 2016 general rate case. As these excess cost will not go into customer prices when Carty goes into service. Provides guidance as well as based on the assumptions displayed on slide 16. Regarding the company's quarterly dividend on April 27, the Board of Directors completed its annual dividend policy review and approved an increase of 6.7% for new annualized dividend of $1.28 per share or $0.32 for the quarter in comparison to our prior annualized dividend of a $1.20 per share or $0.30 per quarter. This increase represents a payout ratio of 60% based on 2016 revised earnings guidance. Assuming PGE's ability to achieve current estimates for earnings and cash flow and depending on other factors influencing dividend decisions PGE's management continues to anticipate sustainable annual dividend increases 5% to 7%. Over the long-term PGE targets of dividend payout ratio of approximately 50% to 70%. Back to you Jim.

In summary, we continue to focus on successful execution of initiatives that drive value for customers and shareholders. Slide 17 displays our key objectives for 2016. First maintain our high level of operational excellence with a focus on employee and public safety, meeting our operational and performance goals and achieving our financial performance targets. Second, bring Carty generating station from disturbance on or before July 31, 2015. Third, obtain approval from the OPUC for accelerating our renewable RFP and complete. And finally work collaboratively with all of our stakeholders to prepare our 2016 integrated resource plan and its associated action plan to meet our customer's future energy needs using resources that provides the best long-term balance of cost and risk. And now operator, we’re ready for questions.

[Operator Instructions] and our first question comes from Paul Ridzon of KeyBanc. Your line is now open.

Good morning. Can you hear me?

Good morning Paul.

Good morning. Can you just discuss what the implications would be if Carty went past July 31st. Is it just you would delay recovery or delay putting in the rates or are there implications?

We have a couple of different situations it really will depend on how far beyond the July 31 date it occurred. We will know more, as we get into the first fire. It looks like we will go beyond July 31st for the very short timeframe, based on our projections. Our current plan is that works with all our customer groups and the OPUC to see if we can get an amendment of the prior order to allow us to extend the in-service date not changing the dollars or the amount, but to the extend these in-service dates. If we’re unsuccessful with that approach, which we believe is a reasonable approach; we would then have to file some type of general rate case to recover the cost of that additional – putting Carty into service. We would also considering filing a deferred accounting application that will allow us to defer the cost between the period of went Carty goes into service and the time that we recover the cost of that end customer prices. That would subject to a learning path and obviously be subject to review by the commission on the appropriateness of recovering the cost that it [indiscernible]. So that’s kind of where we are right now. We will know more as of June as we continue to work very hard and diligently on getting the plant up. But that’s kind of where we are right now.

Where was the 175 megawatts in the accelerated RFP put you as far as the 2020 and 2025 RPS?

It would put it above the 20% but below the 20%, 25% targets. So kind of we think as a sweet spot, it still gives us some additional room. A lot of what we decide here will depend on the economics of the bids we see. We think this is a unique opportunity given the PTC extension as a fact that it does sunset and to accelerate this RFP, could capture value for our customers but will have to prove that out in the RFP.

When do you think you would, is it too early to think when that might be in service?

The timing to get – just to give you a sense of this, but to get to 100% production tax credits to win, solar has a longer extension, a 30% ITC for extends product period, so we got fair amount of room. But for the 100% PTC for win we’d have to have start construction at the end of this year and completion by the end of 2018, I think that’s right, end of ’18, so that’s the timeframe. And the 80% we’d happen to start construction in 2017 with the completion in 2019, so that would add two year of construction period, which is I think is achievable. Obviously trying to get into queue for this the wind turbo could be a challenge just because I think many people are looking at taking advantage of the accelerated PTCs or the ramp out of the PTCs.

The $100 million of net gas reserves, is that kind of a balance you’d wanted to maintain just by adding more as the resource are depleted?

No, I think that’s a starting place. We think a more appropriate levels for our long-term hedges is maybe as high as 30%, but we will continue to work with commission. This would put us roughly at 10% depending on where prices are and our comfort level with OPUC and they’re comfortable with where we wanted to be. We would like to increased that, but I think we want to latest transactions under our belt. Ensure that it delivers value and then take it from there, but I think we want to step into this. Demonstrate to our customer groups and our regulator that is a sensible approach to hedging natural gas prices.

And the higher amortization for Trojan is offsetting revenues, so there’s no earnings impact. Is that correct?

Right. It doesn’t have because of that DO, new DCs or whatever – settlement DC, right.

And then lastly, a lot of new around Intel and what do you think the potential fall-out could be for sales?

Well, we don't see any impact on our demand from Intel because the clean rooms are up, they’re operating. They have over 19,000 employees out in Hillsboro, this is their key headquarters and where they do much of their research. My sense is this is just a repositioning of their workforce. I think they are still big players; they are a very formidable company. I think they’re repositioning, their strategies. We’ve seen the topic before, whether in layouts, but immediately, they gear up in another area to meet the demand in a market. So we’re not seeing impact on demand even though low unemployment rate in Oregon, I think that’s kind of new for that could either retire or maybe be displayed, could easily find jobs in report matter region as the high check sectors, extremely high gear right now. So my sense is they’re looking at early retirements and severance plans but I think those folks to get displaced will easily get – not easily but should be able to jobs in the Portland market.

Hey guys. Sorry just one more, if you would deploy capital to one of the accelerated RFP and nat gas reserves. How do we think about the dividend growth? So do you need to kind of ratchet back to preserved capital for that, or is there still headroom to continue at 5% to 7%?

Well, I think we have to see the results of the RFP and in various capital expenditures I still feel like we have growth here. We want to reward our shareholders for that growth. I still think we have ability to continue to grow our dividend. Obviously that will change our equity needs and will all get factored into our decisions as we look at next year. But we always believe it, we’re at the low end of the payout ratio, but we still feel like we need to continue to reward our shareholders and the dividend that’s important part of the value proposition for our shareholders. So we want to continue to maintain that you know and given the potentially for investments, the company will have to balance out, but our general deal is we want to continue to reward our shareholders.

So these two initiatives look like really interesting compelling ways to kind of backfill that capital hiatus we were looking at?

Yeah.

Thank you very much.

Thanks, Paul.

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

Hey, good morning.

Good morning Julian.

Joe, perhaps let’s start by following up on some of the last questions. Just in terms of timeline, I know Paul was trying to get at that a little bit with the capital needs, but can you review a little bit just the overlapping timeline here for rate base and the accelerated IRP, when will we know about each one of them respectively in terms of a go, no go.

So the first step in the RFP process is to commission acknowledgement to move forward with the RFP and so we’re going to file that with them as quickly as we can put it together and get that in front of them. We may in fact start the RFP, while their deliberating that, so we can work it in parallel. As I mentioned earlier, we have to get some expenditures in this year to qualify for the 100% PTC that would be our first objective to try to accomplish. But if we are unable to do that, it would bite into 2017, which would still be of value to our customers to accelerate it. So our first goal is to try to get the acquisitions of the RFP renewables this year, but they have to go relatively perfect in terms of your OPUC [ph] is going to have to move relatively quickly on approval. You need to get the independent evaluator onboard, we need to get the RFP out into the market, but we think it is achievable. It’s a tight timeline but we think it is achievable. We’ll just have to see as it plays out, I think we will file this RFP request with the E2C [ph] very shortly and get the process started. So the decision on the RFP would come later this year. The next big step after we file the RFP, we get bids in. We would then go see the valuation process; we would come up with a shortlist and get the independent valuator to agree to that shortlist. We would file that file that shortlist with the commission for acknowledgment, we have got to an important step and it’s the current step under the competitive bidding roles. And then hopefully negotiates a conclusion and get a contract in place by the end of year, that’s how optimistic and that’s what we’re going to shoot for. If it were to slide into next year, it wouldn’t be the end of the world, we would lose value for our customers in terms of the production tax credit going from a 100% to 80%, but those are all being evaluated, we go to year and how quickly the PUC as well as the market can respond. I would also note that PacificCorp also has an RFP out there for renewable resources. But we do believe it’s important to move quickly so that we can potentially acquires those resources in the marketplace. In terms of expenditures, that’s really going to depend on, what we end up in the contract in terms of the agreement. We’re going to look build on transfers, purchase of development rights or PPA. It will an all source bid for renewable, so bidders will have all three options. At this point PGE will not have a self build options for wind in this RFP, beside it would have with so quickly, we have not fired our own self build option as we have another RFPs. But we feel that the market is very deep and there are a lot of projects out there which should help have a competitive process. Last question, total capital, kind of if we were success, we came all the way from zero as all PPAs, all went broadly approximately $1 billion in capital if we were to win and build all 175 average megawatts until it was all wind. So as a range there you would have to wait and see how the RFP turns out.

Got it. And then just on – actually you said $1 billion for 175 megawatts?

Yeah, it’s about 500 – if we look at a 33% capacity factor for win then that would be kind of a board’s wind, kind of Oregon, Washington wind capacity factor, you take 175 megawatts after over 525 megawatts of nameplate. About $2000 a kilowatt, that’s about $1 billion of capital. It’s roughly Tucannon River Wind Farm projects. The way we’re thinking about it, which were about $0.5 billion each.

And then on the rate-based side, the timing there, just the follow-up?

Well, from a rate-based perspective we do have the renewable adjustment cost, so to the extent we find renewable, we would use direct filing to incorporate those projects in the customers prices when they go into service. So we typically file in April, the prices would go in the following year as we go forward. So that’s the same process we’ve used historically and we would use that in terms of that. We don’t believe the rate impacts would be large typically; our renewable projects have rates, customers prices in the 2% to 3% range because they usually come in at small increments. So we don’t just want to rate customer prices, we’re going to need to add these renewables and this is the most cost effective way to do that, taking advantage of the PTCs of where they are today.

Got it and on the timing on the gas reserves rate base please?

That decision will come through the annual update tariff. We hope to have some indication from the commission in the October timeframe but would expect in order in the November and December timeframe. We file the AUC you can go out in the website and get that information on what the filing is in our general requirements. We put a placeholder in the AUT filing for that, $100 million investments. And we’ve made general requirements, our key factor here is that it has to be long-term price of natural gas, meet or beat that target. So two things happening, one we have to get the PUC and our stakeholders to agree on this as an appropriate long-term hedge and the requirement under which we would do that. And then secondly, we still have to get to a transaction that would meet those specifications. So that’s we would like a to occur towards the end of this period if we’re successful in both rooms.

Got it. And presumably you’ve found something that wouldn’t work today at least under today’s gas price environment?

We are in active negotiations. We haven’t got to, we’re working terms sheet right now, we have not got the final contracts, but we feel cautiously optimistic that we can get there.

Got it. And then last timing piece, I just wanted to follow-up on when will you know if you’re going to meet that July 31st deadline. I mean, obviously that’s around the corner here, but I’d be curious and how would you intend to update us, is that kind of a press release out one day or just kind of curious here.

I would think that as we internally conclude that we’re not going to leave the July 31st date, we would probably issue an 8-K. suspecting to the importance that it has, and if people are interested. I would think first fire is very important and that will give us an early indication of whether we think we can achieve. But even if we get July 30, June 1st in terms of first fire, it’s still a fair amount of work to be done to get to the July 30, the first fire is very important. And we’re obviously monitoring this on a daily, weekly basis. We’re in constant communications with the team that’s working out there. I would tell you the team is all working very hard very diligently and still keeping safety top of mind as we work out there and to get the project. But there's still a lot of work to be done and we have to get it done in systemic and systematic way so that we get the project out in service.

Got it. And then a regulatory strategy, if you don’t get them done, do you have that set up right?

We talked about that for the last call, which essentially if it doesn’t get completed by July 31st we will first look to working with customer groups, .in PUC, staff, to get amendment to the prior order to extend in-service date, given the circumstance that we’re outside maybe a week or two weeks. We feel like we have a big case to make to just to get the order amended to change the July 31st data, not change the cost structure or the impact of customer prices. Now we are first try, firstly we would try to given, what we know when the in-service data is. If that does not occur we would file some type of general rate case to recover the costs in a future time period and then file it for the counting order to start tracking the cost associated with in-service date at the time it does go in service, that’s for the counting order would be subject to regulatory review and prudency and an earnings test.

Got it. Thank you so much.

Thank you.

Thank you. And our next question comes from Brian Chin of Bank of America.

Hi, good morning. Just following up on Julien’s question. If the plan is – you have to go to regulatory review process for the Carty and that’s being if there’s only two commissioners, as I understand that commissioner Ackerman, is going to be there, but the time till end of July. So in the process continue to unfold with two commissioners, or are we anticipating third commissioner is going to be appointed. I’d like to a little spread work there?

You can do with two commissioners if that can be an approval, so the two commissioners could take action. My understanding the governor is working hard on the process, still look for a replacement for Susan. There is legislative session in May where that commissions if nominated by the governor could be approved by the state senate. So we think that that could all happen, I think that’s what she is pointing toward. But until we see the announcement and get it in front of this, but until we see the announcement and get it in front of the eight centers, I can’t tell you for sure but the commission can act with two commissioners.

Understood. And then just going back to the first fire and the timetable tier. When we look at first fire’s for other gas turbine, we tend to find that there’s only several months between first fire and when the plan is considered completed. Are there some specific circumstances around this project, that give you confidence that our first fire as of early June results and the plant B completed by end of July. it just seems like that’s a relatively tight schedule versus other plants that we’ve seen the time-table first fire display.

It is relatively tight, as I said; everything is going to have to go perfect. Things steam blows [ph] just a number of things that have to happen, move oil checks. All the things that has to happen need to happen perfectly. In terms of what we have to do. We try to work some things in parallel versus series so that we could accelerate the project. We’re working very closely with Mitsubishi and the contractors. Obviously first fire is very important but steam blows and the other words that has to be done to ensure that the end of this April, I’m ready for commercial operations are critical. So this is an accelerated time schedule. I would say we have A team Mitsubishi and Black & Veatch. Both very experienced startups to folks that have done many, many of these units. And while they’re cautiously optimistic, they do understand that things are going to have to go well. And we have found things by our prior contractor. We think we’ve cleaned out most of those flames, but some time what you don’t know that you don’t know. So we continue to work on that. So understand that, we know we’re scheduled to have done. We would like to have more time but, we’re focused on trying to get the project done by July 31.

Last question if let’s say that, let’s say the plant comes online just a few weeks late and so you guys asked for an amendment to the original order like you are pixilated to those commissioners and one, the commissioner says is okay and the other commissioner doesn't. what happens then?

I don’t think there’s I think its [indiscernible] brought that one, by that time we would hope they have a very typically the commissioners look both together and I think they would kind of themselves but haven’t thought about that. But I feel a tie is a tie and this is the decision. But I can actually got the needles for that, I have build and my sense is we have win, win against you don’t have a decision.

I think it’s unlikely outcome, but lot to check into.

Appreciate it. Thanks a lot and good luck guys.

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

Hi, good morning.

Hey, Brian.

Just, start by the $0.02 negative EPS impact from Carty, what exactly is that. Is that O&M depreciation, interest expense?

Brian, it’s basically the carrying cost of the incremental debt or capital we’re putting out there and the D&A associated with.

Okay, so that’s, the $0.02 is to five months, right?

Right.

Okay. So we would need to annualize that when looking beyond ‘16 prior to any regulatory mechanism to defer that.

Yeah, that assumes that the surety lawsuit continues will be out there, we don’t settle for some reason. So or they might pay.

And is there any timeline on the sureties lawsuit and the Abengoa litigation?

No. it could be two to three years, we believe we have a very strong case but we’ve looked at other cases similar to this case they can take two or three years to get the final decision.

Okay. So your regulatory strategic is kind of outside of outcomes of the sureties and litigation?

That’s correct. And then the wind production variability it seems to be kind of a recurring theme in your guidance provisions over the last couple of years. Just curious, I recall an open docket and which you were trying to address that and remove the wind cost from pecan.

So and here’s where we are on the wind, we do have the five-year rolling average, so eventually we hope to catch up actual to the broadcast and support case continues to come down with the five years of average. So we had hoped at some point that should level off. We did have a docket trend get this trued up within the year that did not get any traction, but the five-year average will ultimately I would assume catch up with the forecast and actually. So that’s one thing. Sa part of the new legislation we now tracking in the PTCs to be aligned with the forecast where historically we just had the PTCs and a general rate case and then if they were reduced or fell off. We had to go back and file with the regulators now these PTCs are powered by AUT filing and they are aligned with our forecast. So as our forecast gets closer to actuals there should be less of a variation between that and it is for some reason the actuals come in above the forecast and that will hopefully could be an outer tier earnings. So we’re hopefully getting closer, but we’re still not there yet.

Okay and then lastly just the guidance for guidance raised in related to year-to-date weather. We’ve seen a lot of other utilities experience mild first quarter weather yet. They did not revise guidance, just to kind of manage their O&M or wait for the peak demand season. I’m just curious what’s your guidance strategies. Do you just revise it as weather becomes actual?

Pretty much. We try to look at the offset but because we’re winter peaking utility, the ability for us to offset the winner loss compared to the summer gain is pretty small.

About five times. You’re going to five times as many cooling degree days for every heating degree day that you move.

Yeah, so even if we get hotter in Portland in our service area, it doesn’t add a lot of loan because it still cools off. In the evening we make it one or two weeks, but again we don’t have hug air conditioning penetration, we have some but it’s not like Texas or some of warmer states where restated where their peak is in the summer and most of their consumption is in the air conditioning area. So that’s kind of where we are, so we feel like though we take a little pick up some, it’s still too early to tell wither that one summer will show up and if it has not a big contributor. We are trying to manage our O&M as closely as we can know. As you know we did some temporary deferrals last year. We can’t continue to do that and still maintain system integrity and reliability. So we are continuing to looking at the O&M line where we can but there’s a lot of work to be done, we it’s not a construction going on in the Portland metro region. A lot of new [indiscernible] there is a lot of cranes out and as a result our folks are busy, busy and the ability to just say we’re not going to do things in a market that’s pretty hot right is more to challenging.

Understood. Thank you.

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

Good morning guys. The only question I had left was on the RFP. My understanding previously was that you had a little bit of flexibility around the 2020 step to purchase credits to meet that standard. So is the right way to think about how you’re going to pitch this to the commission that the savings from not buying those wrecks in 2020. Will offset the fact that your over procuring power in the early 2020 timeframe because of the new accelerated tax credits.

So what we’ve looked at is the net present value benefit of taking advantage of the PTCs still they’re versus having versus say no PCD if wait until the 2023 or 2024. So PTCs produced significant value for customers and it’s a capture of those PCTs that compel us to move forward with the RFP versus lagging. Had the PTCs not being extended and there was just zero we would probably kept with our prior strategy which is go through the IRB [ph] get a master plan delay, the physical compliance still 2022 or 2023, obviously it’s been a conversation with the regulators and our action plan. But generally we would have used the rest bridge deck. So the bridge that created. Now with the PTCs sunsetting, we want to capture that value. Because it is significant so that’s the really basis of it. We’ve talked to their commissioners individually about that and they would achieve the whole filing in the process. But they understand there is value to every customers whether we can get to our process quick enough to capture them and it will have to be what we working closely got our regulators and our consumers. The other thing its part of the legislation, renewable energy credit that we would bank those in a longer period they’re called golden wrecks. As long as we get the projects up I think by 2019. I’m not sure of the year but I think it’s 2019 or 2020. I will get the exact date. Those wrecks can be used through the compliance period all the way throughout the timeframe for compliance so we can paint those and use those. There is no sunset date. We can get you the actual date on that, but it does provide value to I believe, can you other email we’re generating wrecks in excess of what we need we can bank those wrecks and use them in any future period.

Okay and the analysis presumably would take into account the time value of that being procured in advance as well?

Yeah we’ve done that analysis we show that value.

Okay. Great. Thanks.

Welcome.

Thank you and our next question comes from the line of Andrew Weisel of Macquarie. Your line is now open.

Good morning Andrew.

Hey, Andrew. Q – Andrew Weisel: Obviously, a lot of questions about a small number of topics, and I’ve got a couple of more to add there. Which Carty, middle and mis-Carty, you break the cost estimate would have gone up right, by $15 million related to the prior forecasts.

Yes kind of 365 and 370 to the – by 14, so $120 million would.

Andrew would provide that related to the update, three months ago.

It’s the same as a 8-k that we’ve produced before in terms of estimate on March 23, so the estimate we provided in 8-K March 23 we gave the estimate of $635 million to $670 million and then have still, still our estimate.

Okay, I’m comparing to the last five years. In terms of financing, not surprising you’ve increased the potential debt needs. If things don't go your way in terms of recoveries of cash from ETC as [indiscernible] is there any risk issue some equity or do you think this is B4, to fund our debt.

Right now we think B4 is funded by debt Andrew.

Okay. Great. Then just a couple of quick ones on the renewable and the accelerations. Was this an upsizing of your plan relative to what you previously anticipate filing, it’s not part of the IRT or this simply a timing issue that you’re going forward?

This is just a timing to pull them forward, both the 2020 requirement and the 2025 requirement, a little bit of the 2025 requirements and take advantage of the PTCs that would start to sunset. So had we just gone to the normal process we would have still needed renewables but probably in a period. If the PGC has not been extended.

Okay. Any consideration to going above that 175 number given that the 2025 target is higher and you now have a better visibility to long term needs.

Definitely we have to see that, obviously when we see the RFPs that may change our views, this is kind of the target, we think this is the sweet spot or where can manage the wreck the get these project online. But we will see we can we can manage the direct impact on the customer's ability to identify online but we will see what the RFP produces and it we may decide that there isn’t any value there too quickly. It will depend on the track of those projects and the ability to get them completed and take advantage of the production cash credit. So this is our target at this point and we’ll see how it plays out in the RFT.

Thank you.

Thank you. And our next question comes from Feliks Kerman of Visium Asset Management. Your line is now open.

Hi, thank you for taking my question and appreciate all the additional colors today you provided on your program. If you can just Jim, comment on one times on your physical gas hedging program. I believe a similar program was introduced to the commission a couple of years back by PacifiCorp, that program from what I understand never came to fruition. What gives you the confidence that now is the right time to introduce this and what are your confidence levels on getting this program if you provide than.

So a couple of point to clear there. I don’t believe PacifiCorp has made such a request. Northwest Natural has done such a transaction. It did a number of years ago. There were certain I think some of the customers groups were please with how that all played out because of the timing and get it done. But the commission I might stay relative beyond that. They made some modifications to the program but they still have in place. So it has been done in Oregon. And we’ve learned from the experience. We’ve tried to adjust our filing to reflect some of the concerns of the consumer groups around sharing of risk and rewards and try to tailor in a way that provides that long-term hedge for consumers. Obviously prices for natural gas at all-time low it’s hard to understanding it could that much lower when NorthWest Natural did their transaction of while they were trying to hit the price. Prices did decline from that a point they did the hedge. And as know hedges are never perfect, they update hedge at the time you’re making a transaction. So we’re having good conversations with our custom group’s I think they trying to get their arms around it and ensure that the right balance of risk and rewards between customers and shareholders is included and a we’ll know more to move our data request right now, where we’ve having meetings and discussions with those groups. So like I said I’m cautious they optimistic at these prices this which provides a good hedge for our construction a structural changes in the natural gas industry.

Okay. Thank you for clarification. Thank you.

Thank you. [Operator Instructions] And our next question comes from Andrew Levi of Avon Capital.

Good morning, Jim and Jim. How are you guys doing?

Good and you.

I’m doing well. Good day today so far. You got three to go, so we’ll see you four hours. Okay, so, just I want to make sure I heard something right. If you add like $1 billion for renewable. Can you just go over that again, is that …?

Yes, I gave you a range. I said the capital opportunity for the company could be anywhere from zero to $1 billion you would a favor all PPAs would have to look at the impact of that on the balance sheet. We’d have to adjust our balance sheet to reflect that kind of PPA. So it would have to delever the balance sheet if you will because of those kind of PPA obligations. But in terms of just CapEx spending. There would be all PPAs if they were to be all either build on transferred or selling of renewable or development rights. The projects where we doing the construction towards the Tucannon River Wind Farm, 175 average megawatt equates to about 525 megawatts of winds nameplate capacity [indiscernible] and win is typically about $2000 a kilowatt, so that equates to about a little over $1 billion of total capital. That’s from all the projects were to be origin operated by Portland General.

Okay, so that’s where I missed, the 175 being converted into 525. Okay. That would be between now and 2020 is that what you guys are saying?

We would do that, to capture the greatest benefit of CTCs, would have to be completed by 2019, the end of 2019 if we were to do it all by then. Clearly we like to get it done by the end of 2020 to get at least the 80% PTCs, but again it all depends on how quickly we can move through the process.

Well, that’s quite an opportunities and then so you make filing you said in June?

No, we’ll make the filing in the next week or so, when the commission …

Next week or so, okay.

So starting our key process, then we will get a design from the commission, we’re going to higher – work of the commission to hire an independent evaluation and get an RFPI which reads fairly quickly.

So when do you think we would actually get the results?

Probably not till the fourth quarter.

Okay. So then in this year. Okay. Got it. That’s great. Okay. And then just make, just to make sure, I understand what you’re seeing on Carty. So just out of the potentially for an amendment, so assuming that it could get delayed. Beyond July 31st timeframe are there discussions kind of going on right now between the stakeholders and you about that or do you kind of got to wait till you get closer to the end of the project.

Yeah, my sense is we are way towards the end of June as we see how things are coming together and where we are in first fire and how everything else is progressing we’ll have a better sense. We thought about talking early but we don’t want to jump the gun until we really had some facts because I think customer looks towards and understand and its regulators in our OPUC staff just wondering kind of what we think their best estimate is because it could change their views and revenue create a bunch of hypothetical closer to the date.

I understand and then on the amendment process itself how does that generally work? Like we can yield, like would you get a settlement once you knew, let’s say you just wanted to focus not on the incremental cost, just on what was authorized originally, you would come to the commission with a settlement or would that be a formal process, just how does that generally work?

Well, Andy, we’d have to work with the stakeholders in order to come to an agreement as to what we think the amendment to the prior stipulation would be. Once we have that agreement, we do a filing through the commission and seek approval for that amendment.

And generally so basically you don't really know how long the process would take to get the various parties to agree. And what would that be the staff and interveners and would there be other stakeholders you mentioned customers or something like that or is that part of the interveners?

That’s part of the interveners.

Okay. So if you like – I don’t know if you call the consumer council, but something like that.

Well, Citizens Utility Board is the typical folks that are in staff that are a part of those discussions and all the parties that were a party to the original stipulation.

Right. Okay. And I assume that you've been communicating with them about you know, kind of what's been going on, so they’re well-informed at this point.

I think everybody is aware of the situation but as Jim pointed out the more in-depth conversations need to happen once we know whether we’re going to meet first fire and whether we’re going to meet the July 31 date.

And then again if the amendment were not to happen you would prepare a rate case which would include the 2017 test year, right. Is that correct? That would kind of accelerate in the filing and then put office ‘17 rate case for the ’18 test year, so you kind of bring your rate case forward, I’d say you guys have many expenses but just to understand that. So if that was the case that would be filed, kind of at the beginning of the third quarter if that was determined that was the course actually you needed to take?

As soon as we know what we know, it looks like it’s going to be delayed significantly. We would move pretty quickly on pretty net general rate case together, probably in a month or so to get filed. And then worst case it will take 10 months for them to make a decision on that case.

And just in general on the staff side, because obviously maybe ’17 would be effective but ‘18 should be unaffected. It is not like building an IGTC kind of Southerner is doing with Kemper [ph] and obviously you’ve had some cost overruns. But this is not a very complicated process even with mistake but made by Abengoa. Is that fair to say from what you guys are seeing at this point.

Yeah, I mean, this is pretty standard work that has to be done. These plants have been done very quickly; we have like I mentioned we have very experienced team bringing this project in the service. So it’s just a matter of getting the things done, the prior contractor left us at a bunch of a pickle we found lots of things that had to be reworked, a lot of things that weren’t done correctly which is required the additional inspection and catch up so you know we are running back to catch up on many of those things and but I would tell you we got the best team we got over 700 workers on the site working hard. So there is a lot going on and we’re not impacting these. So it’s not complicated but its work that has to be done perfectly.

Right. No I understand, so it’s more of a time factor first IGTC, which [indiscernible].

Yeah perfect technology, perfect business.

Yeah I mean the [indiscernible] are nearly when it’s starting to turn the key it will actually work right.

Yeah.

Yeah, okay. That answers all my question. Sorry I asked many but that clears things up.

Okay. Thank you.

Thank you. And our next question comes from John Ali, Castleton Capital [ph]. Your line is now open.

Good morning John.

Just quick question, I think Andy had pretty much everything. When was the original first fire?

It must have been back in April because we had targeted a mid May kind of timeframe, its mid second quarter kind of timeframe. So that was kind of our original timeframe.

Got it. Okay. You guys really are working?

Yeah.

All right. Thanks very much.

Thanks John.

Thank you. And our next question comes from Paul Ridzon of KeyBanc.

Thanks. I’m good.

Thanks Paul.

Okay, that’s the last questions we’ve had. So we appreciate your interest in Portland General Electric and we invite you to join us when we brought our second quarter 2016 results in late July. Thanks again and have a great day.

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