Portland General Electric Co (POR) 2016 Q1 法說會逐字稿

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. (Operator Instructions)

For opening remarks, I would like to turn the conference over to Portland General Electric's Director of Investor Relations, Mr. Bill Valach. Please go ahead, sir.

Thank you, Candace. Good morning, everyone. We are pleased that you are able to join us today. Before we begin our discussion this morning, I would like to remind you that we have prepared a presentation supplemental to our discussion today. And will be referencing throughout the call the slides. Slides are also available on our website at Portlandgeneral.com.

Referring to slide 2, I would like to make our customary statements regarding Portland General Electric's written and oral disclosures and commentary that there will be statements in this call that are not based on historical fact and, as such, constitute forward-looking statements under current law. These statements are subject to factors that may cause actual results to differ materially from the forward-looking statements made today. For a description of some of the factors that may occur that could cause such differences, the Company requests that you read our most recent Form 10-K and Form 10-Q.

Portland General Electric's first-quarter earnings were released via our earnings press release and the Form 10-Q before the market opened today, and the 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 this Safe Harbor statement should be incorporated as part of any transcript of this call.

Leading our discussion today are Jim Piro, President and CEO; and Jim Lobdell, Senior Vice President, 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. 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, construction progress on our new party generating station and our capital expenditure forecast, our plans to request an accelerated renewable RFP, Oregon's new landmark energy bill referred to as the Oregon Clean Electric Plan, and our 2016 integrated resource plan.

I will 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 presented on slide 4, we reported net income of $61 million, or $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 temperatures were favorable on a quarter-over-quarter basis, the first quarter of 2016 was also unseasonably warm, with heating degree days 15% below the 15-year average. As a result of unseasonably warm weather and unfavorable wind production in 2016, as well as the incremental cost to complete Carty that are not included in customer prices in our 2016 day 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 Carty in our revised guidance later in the call.

I am also pleased to report that on Wednesday, the PGE Board approved our tenth consecutive annual dividend increase since 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 have 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 strategy and 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's unemployment rates dropping to a record low of 4.5% in March, which is 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 PGE's operating area was also low at 3.9% in March.

Oregon leads the nation with the 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, gold prices, personal income, tax revenues, mortgage delinquencies and the publicly traded equities of this Company.

According to the Portland Business Journal, Portland is broadening its position as an epicenter of the global sportswear business. Specifically, Nike is adding approximately 3.2 million square feet of office space, mixed-use and parking structures to its 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 a strategic hub, also announcing plans to grow its footwear and innovation operations in Portland with a 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 contributes to an increase in PGE's customer account of approximately 1.3% over the past year, its largest growth rate since 2008. This strong growth drove retail lows, which were up 2.8% quarter over quarter when adjusting for weather and excluding one large paper company, and up 1.7% quarter over quarter when you also remove 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 results and current economic indicators, PGE's projected year-over-year load growth of 1% this year is 1% for this year, adjusting for weather, the leap year date, and including the one large paper customer. This growth reflects an approximately 1.5% reduction due to energy efficiency.

On slide 7, I would like to provide an update on progress from the Carty generating station, our 440-megawatt natural gas base load resource under construction near Portland, Oregon. We estimate total capital expenditures for Carty, including ASEC, 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 America Insurance Company, the two 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 disagreed with the sureties' determination. And on March 23, we filed a breach of contract action against the sureties.

On April 15, the sureties filed a motion to stay that proceeding, alleging that our claims 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 proceedings.

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 work performed by the former contractor, Abeinsa, and the work necessary to correct defects and complete construction, the cost and completion dates for Carty could vary from our current projections. Increased cost and the delay of the targeted service date could impact the amount PGE can recover for Carty in customer prices. Our 2016 general rate case authorized up to $514 million, including ASEC, assuming an in-service date by July 31, 2016.

If our cost to complete Carty, less any amounts that may be received from the sureties, exceed the allowed amount, PGE intends to seek recovery of the excess amounts in customer prices. However, there is no guarantee that it 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 in order to procure renewable resources to maximize the economic value of available tax credits on behalf of our customers. The recent federal legislation passed in December includes expansions of both the production tax credits for wind facilities and the investment tax credit for solar facilities, with each including some debt provisions.

Our current plan is to request OPUC approval to issue a renewable RFP in the second quarter of 2016, with an accelerated processing timeline 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 175 average megawatts of Oregon RPS-qualified renewable resources.

Similar to PGE's prior RFP process, an independent evaluator would be selected to actively participate to ensure a fair and reasonable process and to ensure that the short-list selection is the least cost, least risk for PGE customers. Now on to slide 9.

We have provided a summary of the Company's capital expenditure forecasts for 2016 to 2020. These amounts potentially could be augmented with incremental investments related to system reliability and operational efficiencies that provide value to our customers, as well as potential resources from the RFP for renewables. The graph does not include any capital projects from the outcome of our renewable RFP or any resources required under the 2016 integrated resource planning process.

Additionally, we are continuing to pursue on a first-year basis an initial investment in proven natural gas reserves of up to approximately $100 million, which would represent about 10% of our projected annual average natural gas burned. We have filed their annual update tariff with a price holder 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 you updates on our capital expenditure forecasts 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 and 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 qualified renewable resources to 50% by 2040. The law also requires PGE to eliminate coal-fired generation from our customers' energy mix no later than the end of 2035. We are pleased to have been part of a collaborative process that puts Oregon's electric sector on a path to achieve significant carbon reductions as we plan 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 size actions and replacement of our Boardman coal plant that will cease the use of coal by the end of 2020. It 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 would 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 to your questions. Jim?

Thank you, Jim. Turning to slide 12, as Jim mentioned, for the first quarter of 2016, we recorded 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 weather 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 to earnings per share. This was partially offset by $0.05 related to an increase in share count in June 2015 due to the final draw on the equity forward sale agreement.

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 due to largely -- due largely to more favorable weather quarter over quarter.

Second, an $8 million increase related to a slight rise in 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 due to more favorable weather quarter over quarter and an extra day for leap year. With an 8.9% increase in residential delivery, a 4% increase in commercial deliveries offset by a 10.4% decrease in industrial deliveries primarily due to the shutdown of a large paper customer. PGE's 2016 general rate case outlook took the loss of this customer's load into consideration and incorporated its effects in the prices and load forecast, resulting in minimal earnings impact for 2016.

Now on to power supply. Net variable power cost decreased $5 million quarter over quarter. However, costs were $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 when net variable power costs were $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 distribution increased $4 million due to a $2 million increase in labor costs, a $1 million increase in service restoration costs and a $1 million increase of information technology expenses.

Administrative expenses increased $1 million due to a $2 million increase in compensation and benefits offset by a $1 million decrease in the 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 our 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 a $1 million due to a higher 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 earnings on the nonqualified benefit plan trust assets.

Moving on to slide 15, we continue to maintain a solid balance sheet, including adequate liquidity and investment-grade credit ratings. As of March 31, 2016, we had a total of $553 million in 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 facilities, which has an expiration date of November 2019, and additional letter-of-credit facilities totaling $160 million to meet the Company's liquidity needs.

Moving on to slide 16 and 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 in 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 and our 2016 general rate case, as these excess costs will not go into customer prices when Carty goes into service. Revised guidance is also based on the assumptions displayed on slide 15.

Regarding the Company's quarterly dividend, on April 27, the Board of Directors completed its annual dividends policy review and approved an increase of 6.7% for a new annualized dividend of $1.28 per share, or $0.32 for the quarter, in comparison to our prior annualized dividend of $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 of 5% to 7%. Over the long term, PGE targets a dividend payout ratio of approximately 50% to 70%.

Back to you, Jim.

In summary, we continue to focus on successful execution of initiatives the 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 out operational performance goals and achieving our financial performance targets.

Second, bring Carty generating station into service on or before July 31, 2016.

Third, obtain approval from the OPUC for accelerating our renewable RFP and complete a renewable RFP process.

And, finally, work collaboratively with all of our stakeholders to prepare our 2016 integrated resource plan and its associated action plan to meet our customers' future energy needs using resources that provide the best long-term balance of costs and risks.

And now, operator, we are ready for questions.

(Operator Instructions) Paul Ridzon, KeyBanc.

Can you just discuss what the implications would be if Carty went past July 31? Is it just you would delay recovery or delay putting it into rates, or are there other implications?

We have a couple of different choices. It really will depend on how far beyond the July 31 date it occurred. We will know more as we get to first fire. If it looks like we will go beyond July 31 but a very short time frame based on our projections.

Our current plan is to work 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 extend these in-service dates. If we are 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 -- of putting Carty into service.

We would also consider filing a deferred accounting application that will allow us to defer the costs between the period of when Carty goes into service and the time that we recover costs of that in customer prices. That would actually be subject to an earnings test and obviously be subject to a review by the commission on the appropriateness of recovery to costs under that deferral.

So that's where we are right now. We will know more as of June as we continue to work very hard and diligently on getting the plan up. But that's where we are right now.

Where would the 175-megawatt and the accelerated RFP put you as far as the 2020 and 2025 RPS?

It would put us above the 2020 percent, but below the 2025 percent target. So it's kind of -- we think of it as a sweet spot. 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 PGC extension and the fact that it does sunset, and to accelerate this RFP to capture value for our customers. But we will have to prove that out in the RFP.

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

The timing of -- to get -- just to give you a sense of this. To get the 100% production cash for winds, solar has a longer extension. The 30% ITC for solar extends by the period. So we've got a fair amount of room. But for the 100% TTC for wind, we would have to have started construction at the end of this year and completion by the end of 2018. I think that's right -- the end of 2018. So that's the time frame.

And then to get to 80%, we would have to start construction in 2017, with the completion in 2019. So that's about a two-year construction period, which, I think, is achievable. Obviously trying to get in the queue for the wind turbines could be a challenge because I think many people are looking at taking advantage of the accelerated PTCs or the ramp-out of the PTCs. (multiple speakers) Go ahead.

The $100 million of net gas reserves, is that a balance you would want to maintain just by adding more as the reserves are depleted?

No, I think that's a starting place. We think a more appropriate level for the -- a long-term hedge may be as high as 30%. But we will continue to work with the commission. This would put us roughly at 10% depending on where prices are and our corporate level with the PUC, and they are comfortable with where we want to be. We would like to increase that.

So I think we want to get one of these 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 regulators that this is a sensible approach to hedging natural gas prices.

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

Right. Those are the DOD fees or whatever --

The settlement.

Settlement fees, right.

And then, lastly, a lot of news around Intel. What do you think the potential fallout could be for sales?

Well, so far, we don't see any impact on our demand from Intel because the clean rooms are up; they are operating. They have over 19,000 employees out in Hillsboro. This is their key headquarters, and really do much of their research. My sense is this is just a repositioning of their workforce. I think they are still very poised. They are a very formidable company. I think they are repositioning their strategy. We have seen this happen before where there's been layoffs. But, immediately, they gear up in another area to meet the demand of the market.

So we are not seeing the impact on demand. Given the low unemployment rate in Oregon, I think the kind of people that either retire or maybe be displaced could easily find jobs in the Portland metro region, as the high-tech sector is extremely hot here right now. So my sense is they are looking at early retirements and service plans. But I think those folks who get displaced will easily get -- not easily, but should be able to find jobs in the Portland market.

And I guess -- sorry; just one more. If you had deployed capital for the accelerated RFP and net gas reserves, how do we think about the dividend growth? Did you need to ratchet back to preserve capital for that, or is there still headroom to continue at 5% to 7%?

Well, obviously, we have to see the results of the RFP. There is capital expenditures. I still feel like we have growth here. We want to reward our shareholders for that growth. I still think we have the ability to continue to grow our dividend. Obviously, that will change our equity needs, and that will all get factored into our decisions as we look at next year.

But we always believe that we are at the low end of the payout ratio. We still feel like we need to continue to reward our shareholders, and the dividend is an important part of the value proposition for our shareholders. So we want to continue to maintain that. And given the potential for investing in the Company, we will have to balance that out. But our general view is we want to continue to reward our shareholders. So --

Well, these two initiatives look like really interesting, compelling ways to backfill that capital hiatus we were looking at. Thank you very much.

Julien Dumoulin-Smith, UBS.

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 overlap in 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?

The first step in the RFP process is to get commission acknowledgment to move forward with the RFP. And so we are 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 they are deliberating that, so we can work it in parallel.

As I mentioned earlier, we have to get expenditures -- 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 slide into the 2017, which would still be of value to our customers to accelerate it.

So our first goal is to try to get the acquisition of the RFP renewables this year. But it's going to have to go relatively perfect in terms of -- PTC is going to have to move relatively quickly on the approval. You need to get the independent evaluator on board, and we need to get the RFP out into the market.

But we think it is achievable. It is a tight timeline, but we think it is achievable. We will just have to see as it plays out. Like I said, we will file this RFP request with the PUC very shortly and get the process started.

So the decision on the RFP would come later this year. But the next big step after we file the RFP, we get bids in, we would then go through an evaluation process. We would come up with a short list and get the independent evaluator to agree to that short list. We would file that short list with the commission for acknowledgment. And we think that's an important step, and it's a current step under the competitive bidding rules. And then hopefully negotiate to conclusion and get a contract in place by the end of the year. That is our 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 100% to 80%. But those are all things we'll evaluate as we go through the year and how quickly the PUC as well as the market can respond.

I would also note that specific quarter also has an RFP out there for renewable resources, so we do believe it's important to move quickly so that we can potentially acquire those resources in the marketplace.

In terms of the (multiples speakers) -- in terms of expenditures, that's really going to depend on what we end up in the contracts in terms of the agreements. We are going to look for build our own transfers, purchase of development rights or PPA. There will be an all-source bid for renewables. So, bidders will have all three options.

At this point, PGE will not have a self-build option for wind in this RFP. Because we've had to move so quickly, we have not acquired our own self-build option as we have in other RFPs. But we feel that the market is very deep, and there are a lot of projects out there, which could help have a competitive process. (multiple speakers)

Maybe the last question, maybe last thing. On total capital, if we were successful -- it came all the way from zero if at all PPA all the way up to probably an approximately $1 billion of capital if we were to win and build all 175 average megawatts and if it was all wind. So as a range there, we will just have to wait and see how the RFP turns out.

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

Yes. It's about 500 -- if you look at a 33% capacity factor for wind, and that would be kind of a gorge wind -- kind of a Oregon-Washington wind capacity factor. If you take 175 megawatts (inaudible) over 525 megawatts of nameplate, about $2,000 a kilowatt, that's about $1 billion in capital. It's roughly 2 Cannon River wind farm projects, the way we are thinking about it, which are about $0.5 billion each.

Got it. And on the -- yes. And then on the rate base side, the timing there, just a follow-up.

From a rate base perspective, we do have the renewable adjustment clause. So, to the extent we find renewables, we would use the RAC filing to incorporate those projects into customer 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 --. We don't believe the rate impacts would be large. Typically, renewable projects have raised customer prices in the 2% to 3% range because they usually come in small increments. So we don't necessarily want to raise customer prices. We are 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 an order in the November/December timeframe. We file the AUT and go out in the website and get that information on what the filing is and our general requirements. We put a placeholder in the AUT filing for that $100 million investment. And so -- and we laid general requirements. Our key factor here is it has to be the long-term price of natural gas -- meet or beat that target.

So, two things have to happen. One, we have to get the PUC and our stakeholders to agree on this as an appropriate long-term hedge and the requirements under which we would do that. And then, secondly, we still have to get to a transaction that would meet those specifications. So the (multiple speakers) would likely to occur towards the end of this year if we are successful on both fronts.

Got it. And presumably you found something that would work today at least under today's gas price environment?

We are in active negotiations. We haven't got to -- we are working on a term sheet right now. We have not got to final contracts, but we feel cautiously optimistic that we can get there.

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

I would think that if we internally conclude that we are not going to need the July 31 date, we would probably issue an 8-K. I can't tell -- I suspect it's an important-enough event that people are interested.

Obviously, first fire is very important, and that will give us an early indication of whether we think we can achieve. And even if we will get to July -- June 1 in terms of first fire, it's still a fair amount of work to be done to get to the July 31 date. But first fire is pretty important.

We are obviously monitoring this on a daily, weekly basis. We are in constant communications with the team that is working out there. I would tell you the team is all working very hard and very diligently and still keeping safety top of mind as we work out there to get the project. But there's still a lot of work to be done, and we have to get it done in a systemic and systematic way so that we get the project up in service.

Got it. And then a regulatory strategy if you don't get it in time, do you have that set up right?

We talked about that in the last call, which is essentially if it doesn't get completed by July 31, we will first look to working with customer groups and a PUC staff to get an amendment to the prior order to extend the in-service date. Given the circumstances that were off by maybe a week or two, we feel like we have a good case to make just to get the order amended to change the July 31 date, not change the cost structure or the impact on customer pricing.

That would be our first thing we would try to do, given what we know and when the in-service date is. If that does not occur, then we would file some type of general rate case to recover the costs in a future time period. And then file a deferred accounting order to start tracking the costs associated with the in-service date at the time it does go into service. That deferred accounting order would be subject to regulatory review and prudency and an earnings test.

Got it. Thank you so much.

Brian Chin, Bank of America.

Just following up on Julien's question, if the plant is -- if you have to go through a regulatory review process with Carty, can that be done if there's only two commissioners? As I understand it, Commissioner Ackerman isn't going to be there by the time you get to the end of July. So can the process continue to unfold with two commissioners, or are we anticipating a third commissioner is going to be appointed or (inaudible)?

You can deal with two commissioners. That can be an approval. So the two commissioners could take action. My understanding is the governor is working hard is working hard on a process to look for a replacement for Susan. There is a legislative session in May where that commissioner, 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's pointing towards. But until we see the announcement and get it in front of the state senate, 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 timetables here, when we look at first buyers for other gas turbines, we tend to find that there is normally several months between first fire and when the plant is considered completed. Are there some specific circumstances around this project that give you confidence that a first fire as of early June results in the plant being completed by the end of July? It just seems like that's a relatively tight schedule versus other plants that we've seen -- the timetable first fire (inaudible).

It is relatively tight. As I said, everything is going to have to go perfect. Things like steam blows -- just a number of things that have to happen -- lube oil checks. All the things that have to happen need to happen perfectly in terms of what we have to do. We have tried to work on some things in parallel versus series so that we can accelerate the project. We are working very closely with Mitsubishi and the contractors. Obviously, first fire is very important, but then the steam blows and the other work that has to be done to ensure that the unit is safer and ready for commercial operations is -- are critical.

So this is an accelerated time schedule. I will tell you we have the eight teams from Mitsubishi and Black & Veatch, both very experienced start-up folks that have done many, many of these units. And while they are cautiously optimistic, they do understand that things are going to have to go well. And we have found things done by the prior contractor. We think we've cleaned out most of those things. But sometimes it's what you don't know that you don't know. So we continue to work on that.

So, understand it. We know we are scheduled to have done. We would love to have more time, but we're focused on trying to get the project in by July 31.

Last question. If -- let's say that the plant comes online. It's just a few weeks late, and so you guys asked for an amendment to the original order like you articulated. There's only two commissioners, and one commissioner says okay and the other commissioner doesn't. What happens then?

I don't think it's -- that's a great question. I don't think there's a decision. I think it's a non -- I've never thought of that one. By that time we would hope to have a (technical difficulty). Typically, the commissioners work closely together, and I think they would kind of bet that themselves. But I hadn't thought about that. But I assume a tie is a tie and there's no decision.

But I actually don't know the answer to that. I will have Bill Valach follow up. My sense is that when you have one for, one against, you have -- you don't have a decision.

I think it's an unlikely outcome, but one that we will have to check into.

Appreciate it. Thanks a lot, and good luck, guys.

Brian Russo, Ladenburg Thalmann.

Just to clarify, 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 are putting out there and the D&A associated with it.

Okay. So that's -- that $0.02 is for five months. Right?

Right.

Okay. So we would need to annualize that when looking beyond 2016 prior to any regulatory mechanism to defer that.

Yes.

That assumes that the surety lawsuit continues to be out there if we don't settle it for some reason. So -- or they try to pay.

And is there any timeline on the surety's lawsuit and the Abengoa litigation?

No, it could be two to three years. We believe we have a very strong case. But we have looked at other cases similar to this case, and it can take two to three years to get to the final decision.

Okay. So your regulatory strategy 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 revisions over the last couple of years. And I'm just curious -- I recall an open docket in which you were trying to address that and remove the wind costs from the PCAM.

Here's where we are on the wind. We do have the five-year rolling average. So eventually we hope to catch up actuals to the forecast, as the forecast continues to come down with five years of average. So we had hoped at some point that should level off. We did have a docket trying to 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 in actuals. So that's one thing.

As part of the new legislation, we are now tracking in the PTCs to be aligned with the forecast, where historically we just had the PTCs in a general rate case. And then if they were reduced or fell off, we had to go back and file with the regulators. So now the PTCs are part of our 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 if for some reason the actuals comment above the forecast, that will hopefully -- could be an additive to earnings. So we are hopefully getting closer, but we're still not there yet.

Okay. And then lastly, just the guidance revision related to year-to-date weather. We've seen a lot of other utilities experience mild first-quarter weather. They did not revise guidance to manage their O&M or wait for the peak demand season.

I'm just curious what's kind of -- what is your guidance strategy? Do you just revise it as weather becomes actual?

Pretty much. We try to look at the offsets. But because we are a winter-peaking utility, the ability for us to offset the winter loss compared to the summer gain is pretty slow. What's the numbers, Jim?

It's about 5 times as many cooling-degree days for every heating-degree day that you lose.

So even if we get hotter here in our service area, it doesn't add a lot of load. Because it still cools off in the evening, we may get one or two weeks. But, again, we don't have huge air-conditioning penetration. We have some, but it's not like Texas or some of the warmer states 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 -- so we think we will pick up some. Still too early to tell whether that warm summer will show up. Even if it does, it's not a big-time contributor.

We are trying to manage our O&M as closely as we can. 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 continually looking at the O&M lines where we can. But there is a lot of work that needs to be done. We've got a ton of construction going on in the Portland metro region. A lot of new connects. There's a lot of cranes up. And, as a result, our folks are busy, busy, and the ability just to say we are not going to do things in a market that's pretty hot right now is a little more challenging.

Understood. Thank you.

Chris Turnure, JPMorgan.

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 are going to pitch this to the commission that the savings from not buying those RECs in 2020 will offset the fact that you are over-procuring power in the early 2020 timeframe because of the new accelerated tax credits?

What we have looked at is the net present value benefit of taking advantage of the PTCs sooner versus having virtually no PTC if we wait until 2023 or 2024. Those PTCs produced significant value for customers, and it is the capture of those PTCs that compel us to move forward with the RFP now versus waiting.

Had the PTCs not been extended and it was just zero, we would've probably kept with our prior strategy which is go through the IRP process, get a master plan, delay the physical supply until 2022 or 2023. That would've obviously been a conversation with the regulators in our action plan. But generally we would have used the RECs to bridge that period. 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 the commissioners individually about that and they want to see the whole filing in the process, but they understand there is value there for customers. Whether we can get to a process quick enough to capture them, it will have to be what -- we work closely together with both our regulars and our consumer groups.

The other thing is part of the new legislation, renewable energy credits that we -- we can bank those in a longer period. They are called golden RECs. As long as we get the projects up I think it's by 2019 -- 2022? I'm not sure of the year, but I think it's 2019 or 2020. We can get the exact date. Those RECs can be used throughout the compliance period all the way throughout the entire time frame for compliance. So we can bank those and use those. There's no sunset date. I can get to the actual date on that.

But it does provide valuable -- value to us so we can use those RECs. Even though we are generating RECs in excess of what we need, we can bank those RECs and use them in any future period.

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

Yes, that does. And we've done that analysis and we've shown that value.

Okay, great. Thanks.

Andrew Weisel, Macquarie.

Obviously a lot of questions about a small number of topics. So I've got a couple more to add here. With Carty, maybe I misheard you, but the cost estimate has gone up by about $15 million relative to the prior forecasts?

Yes gone up from between $635 million and $670 million to the $514 million. So, $120 million to -- $120 million plus.

And what drove that relative to the update three months ago or less than three months ago?

It's the same as the 8-K that we have produced before in terms of the estimate on March 23. So the estimate -- we provided an 8-K on this. On March 23, we gave the estimate of $635 million to $670 million, and that has still -- that's still our estimate.

Okay. My mistake. I was comparing to the last slide deck.

In terms of financing, not surprisingly you've increased the potential debt needs. If things don't go your way in terms of recovery of cash from the EPT and from maturities, is there any risk that you might need to issue some equity, or do you think this would be fully funded by debt?

Right now, we think it should be fully funded by debt, Andrew.

Okay, great. Then just a couple quick ones on the renewables and the accelerations. Was this an upsizing of your plan relative to what you previously anticipated filing as part of the IRP, or is it simply a timing issue that you're pulling it forward?

This is just a timing to pulling them forward. Both the 2020 requirements and 2025 requirements -- a little bit of the 2025 requirements to take advantage of the PTCs that would start to sunset. So, had we just gone through the normal process, we would've still needed renewables but probably in the later period if the PGC had not been extended.

Okay. Any consideration to going above that $175 million number, given that the 2025 target is higher and you now have better visibility into long-term needs?

At this point, we don't see that. Obviously when we see the RFPs, that may change our views as to kind of the target we think this is the sweet spot for where we can manage the RECs, the impacts on our customers, the ability to get these projects online.

But we will see what the RFP produces. We may decide that there isn't any value there to move quickly. It will depend on the attractiveness of those projects and the ability to get them completed and take advantage of the production tax credit.

So, this is our target at this point, and we will see how it plays out in the RFP.

Sounds good. Thank you.

Felix Carmen, Visium Asset Management.

Appreciate all the additional color today you've provided on your program. If you can just, Jim, comment on one item on your physical gas hedging program. I believe a similar program was introduced to the commission a couple 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 through, if you can provide that?

A couple points of clarity. I don't believe PacifiCorp has made such a request. Northwest Natural has done such a transaction. They did it a number of years ago. There were certain -- I think some of the customer groups weren't pleased with how that all played out just because of the timing to get it done.

But the commission, I understand, is still standing relatively behind it. They made some modifications to the program, but they still have it in place. So it has been done in Oregon, and we have learned from that experience. We have tried to adjust our filings to reflect some of the concerns of the consumer groups around sharing the risks and rewards, and trying to tailor it in a way that provides that long-term hedge for consumers.

Obviously, prices for natural gas are at all-time lows. It's hard to understand if you go that much lower -- when Northwest Natural did their transaction as well, they weren't trying to hit the price. Prices did decline from that -- the point they did the hedge. And as you know, hedges are never perfect. They hedge at the time you're making the transaction.

So we are having good conversations with our customer groups. I think they are trying to get their arms around it, ensure that the right balance of risk and reward between customers and shareholders is included. And we will know more as we go. We fill out data requests right now and we are having meetings and discussions with those groups.

So like I said, I'm cautiously optimistic. At these prices, this would provide a good hedge for our customers against structural changes in the natural gas industry.

Okay. Thank you for the clarification. Thank you.

(Operator Instructions) Andrew Levi, Avon Capital.

I just want to make sure I heard something right. You two added like a $1 billion number for renewables. Could we 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. Zero would be if they were all PTAs. We would have to look at the impact of that on the balance sheet. We would have to adjust our balance sheet to reflect that kind of PPA. So there would be a have to -- we would have to delever the balance sheet, if you will, because of those kind of PPA obligations.

But in terms of just CapEx spending, zero would be all PPAs. If they were to be all either build, own, transfer, or selling of renewable or development rights to projects where we were doing the construction similar to Cannon River wind farm, 175 average megawatts equates to about 525 megawatts of wind nameplate capacity. Assume it's all wind. And wind is typically costing about $2,000 a kilowatt. So that equates to about a little over $1 billion in total capital. That's if all the projects were to be owned and operated by Portland General.

Okay, so that's what I missed -- the $175 million being converted into $525 million. Okay.

And that's using a wind (multiple speakers).

That would be between now and 2020 -- is that would you guys are saying?

Well, we would use that -- to capture the greatest benefit of PTCs would have to be completed by 2019 -- the end of 2019 if we were to do it all by then. Clearly, we would 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.

Wow, that's quite an opportunity. So -- okay. So -- and then so you make this filing you said in June?

No, we will make the filing in the next week or so at the commission.

The next week or so. Okay.

The start of the RFP process. Then we will get a decision from the commission. We're going hire -- work with the commission to hire an independent evaluator and get an RFP out in the streets fairly quickly.

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

Probably not until the fourth quarter.

Okay, so the end of this year. Okay, got it. That's great. Okay.

And then just back -- just to make sure I understand what you are saying on Carty, so just on the potential for an amendment, so assuming that it could get delayed beyond the July 31 time frame, are there discussions going on right now between stakeholders and you about that? Or do you kind of got to wait until you get closer to the end of the project?

My sense is we will wait 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 will have a better sense.

We thought about starting earlier, but we didn't want to jump the gun until we really had some facts. Because I think that the customer groups want to understand, and the regulators and our OPUC staff just want to understand, what we think that our best estimate is because it could change their views. And rather than creating a bunch of hypotheticals, we need to get a little closer to the day.

I understand. And then on the amendment process itself, how does that generally work? Would you get a settlement? What's new? Let's say you just wanted to focus not on the incremental costs, just on what was authorized originally. You would, what, come to the commission with a settlement? Or would that be a formal process? How does that generally work?

Well, Andy, we would 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.

Okay. 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 -- 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 that would be like -- I don't know if you would call it the consumer council but something like that.

It would be a citizens' utility board. It would be ICNU, the industrial customers. It would be the renewable folks -- the typical folks that are in staff that are part of those discussions and the part -- all the parties that were a party to the original stipulations.

Right, right. Okay. And I assume that you've been communicating with them about what's been going on, so they are 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. But once we know whether we are going to meet first fire and whether we are going to meet the July 31 day.

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?

Correct.

Right. That would accelerate in a filing and then put off a 2017 rate case for the 2018 test year. So you would bring a rate case forward I think as that -- maybe expenses. But just to understand that -- so if that was the case, that would be filed at the beginning of the third quarter if that was determined that was the course of action you needed to take?

My sense is we will know -- as soon as we know what we know about the plan, if it looks like it's going to be delayed significantly, we would move pretty quickly on putting a general rate case together probably in a month or so to get it filed. And then at the worst case, it would take 10 months for them to make a decision on that case.

Okay. And just in general on this gas plant -- because obviously maybe 2017 would be affected but 2018's earnings should be unaffected. This is not like building an IGTC kind of like Southern is doing with Kemper. And obviously you have some costs overrun. But this is not a very complicated process even with the mistakes that were made by Abengoa. Is that fair to say what you guys are seeing at this point?

Yes, this is pretty standard work that has to be done. These plants have been done very quickly. We have -- like I mentioned, we have a very experienced team bringing this project into service. So it's just a matter of getting the things done. The prior contractor left us in much of a pickle. We found lots of things that had to be reworked, a lot of things that weren't done correctly, which has required additional inspections and catch-ups.

So we are running past the catch-up on many of those things. And -- but I would tell you we've got the best team. We've got over 700 workers on the site working hard. So there's a lot going on, and we are not impacting safety. So it's not complicated, but it is work that has to be done perfectly.

Right. No, I understand. So it's more of a time factor versus an IGTC, which is maybe more of a (multiple speakers) factor (multiple speakers). Ultimately when it's done and you turn the key, it will actually work. Right?

Yes. (laughter)

Okay, okay. That answers all my questions. Sorry I asked so many, but that clears things up.

[John Ollie, Castleton Capital].

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

Oh geez, it must have been back in April because we had targeted a mid -- kind of a mid-May kind of time frame. Mid-second-quarter kind of time frame. So, yes, that was our original timeframe -- probably in April.

Got it. You guys really are working in parallel, then. All right. Thanks very much.

Paul Ridzon, KeyBanc.

Thanks; I'm good.

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 report 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.