Portland General Electric Co (POR) 2016 Q4 法說會逐字稿

Good morning, everyone, and welcome to Portland General Electric's fourth-quarter and full-year 2016 earnings results conference call. Today is Friday, February 17, 2017. 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'll turn the conference call over to Portland General Electric's Manager of Investor Relations and Corporate Finance, Chris Liddle. Please go ahead, sir.

Thank you, Michelle, good morning, everyone. I'm pleased that you are able to join us today. Before begin our discussion this morning, I would like to remind you that we have prepared a presentation to supplement our discussion, which we will be referencing throughout the call. Those slides are available on our website at, investers.portlandgeneral.com.

Referring to slide 2, I'd like to make our customary statements regarding Portland General Electric's written and oral disclosures. There will be statements in this call that are not based on historical 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 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. Portland's General Electric's fourth-quarter and full-year 2016 earnings were released via our earnings press release and the Form 10-K before the market opened today, both of which are also available at investors.portlandgeneral.com.

The Company undertakes no obligation to update publicly any forward-looking statements, whether as a result of new information, future events or otherwise. This Safe Harbor Statement should be incorporated as part of any transcript of this call. Leading our discussion today are Jim Piro, President and CEO, and Jim Lobdell, Senior Vice President of Finance, CFO and Treasurer. Following their prepared remarks we will open the lines for your questions.

Now, it is my pleasure to turn the call over to Jim Piro.

Thanks, Chris. Good morning, and thank you for joining us. Welcome, to Portland General Electric's fourth-quarter and year-end earnings results. In 2016, we achieve several key objectives toward meeting our customers' energy needs, and I am pleased to share our results with you today.

On the call, I will provide an overview of our financial results in 2016, initiate 2017 earnings guidance, and provide an update on our operating performance, the economy in our operating area, our capital expenditure forecast, Carty Generating Station, progress in our 2016 integrated resource plan and the status of our soon to be filed 2018 general rate case. Following my remarks, Jim Lobdell will provide details on our fourth-quarter and annual financial results and end with key assumptions supporting our outlook for 2017.

Let's begin. As presented on slide 4, we recorded net income of $193 million, or $2.16 per diluted share in 2016, compared with net income of $172 million, or $2.04 per diluted share in 2015. We did not achieve our initial guidance or allowed return on equity due to mild weather that reduced our energy deliveries, higher distribution spending and wind production, which was below our forecast.

Our increase in earnings per share compared to 2015 was largely due to strong power supply operations, driven by excellent generating plant performance as well as more favorable hydro and wind conditions year over year. Higher production tax credits and incremental earnings related to the investment in Carty during 2016. Looking ahead, we are initiating 2017 full-year earnings guidance of $2.20 to $2.35 per diluted share. Jim will provide more details on our guidance later in the call.

Now for an operational update on slide 5. I'm proud to share that employees across the Company did an excellent job in 2016 providing value to our customers, shareholders, employees in the communities we serve. We delivered strong operating performance despite the impact of lower retail loads associated with another mild weather year that resulted in 16% fewer heating degree days than the 15-year average as well as wind generation below our forecast.

I am pleased to report that our generating plant availability was excellent with an average of more than 93% across all of the resources PGE operates. Our Carty Generating Station has achieved an exceptional availability for a newly commission plant since coming online.

In addition, the latest survey results from MSI Research and TQS Research reflect that our customer satisfaction across all segments remains very high. Residential, business and key customers all placed us in the top quartile for satisfaction and top decile for trust. Also during 2016, PGE was named a most trusted brand, a customer champion and an environmental champion, according to customer surveys conducted by MSI Research.

Let's turn to slide 6. Oregon economic expansion, though slowing continued throughout 2016 and is expected to continue at a moderate pace. Unemployment in our service area in December was 4%, outperforming Oregon's unemployment rate of 4.6% and the US unemployment rate of 4.7%.

Strong in-migration continues to drive Oregon's population growth, particularly in Portland. More households moved to Oregon in 2016 than ever before, surpassing the record level of the tech boom of the 1990s according to the Oregon Office of Economic Analysis. As a result, our customer count grew by 1.2% year over year.

Solid economic conditions and strong fourth-quarter load growth in the high-tech industrial sector contributed to weather-adjusted load growth of approximately 1% for 2016 over 2015. This is net of approximately 1.5% for energy efficiency and excludes one large paper customer who ceased operations in late 2015.

Looking forward, based on expected decreases in deliveries to metals, manufacturing customers and ongoing energy efficiency, which is lowering the residential and commercial growth rates, we expect weather-adjusted energy deliveries in 2017 to decrease between 0% and 1%. Despite uneven growth rates due to the contraction in some of our traditional manufacturing segments, we continue to forecast long-term positive annual growth of approximately 1% based on the strength of our local economy. In particular, we're forecasting growth in the high-tech sector and strong in-migration will continue.

Moving to slide 7, we have provided a summary of our Company's current capital expenditure forecast from 2017 to 2021. These expenditures are related to investments we are making to build a more resilient grid to serve our growing customer base.

Our investments include upgrading and replacing aging generation, transmission and distribution infrastructure, strengthening the power grid to better prepare for earthquakes, cyber attacks and other potential threats, and implementing new customer information systems and technology tools to ensure employees can continue to provide the prompt, effective service our customers expect. Any capital expenditures related to our 2016 IRP and RFP are dependent on the outcome of the RFP process.

Moving to slide 8, I'd like to provide an update on the Carty Generating Station, our 440-megawatts natural gas baseload resource near Boardman, Oregon, that went into service July 29, 2016. Starting August 1, we included the return on and of the $514 million of capital cost as well as the plant's operating costs in customer prices. As of December 31, we had $634 million, including AFDC, in plants in service for this project. Our current estimates for the final capital expenditures for Carty, including AFDC, is approximately $640 million.

As previously reported, we are pursuing legal actions against Liberty Mutual and Zurich North America, the two sureties who provided the performance bond in connection with the Carty construction agreement. At the end of July 2016, the US District Court of Oregon ruled against the sureties' motion to stay the proceedings filed by PGE in US District Court of Oregon, and ruled in favor of PGE's motion to enjoin the sureties from participating in an International Chamber of Commerce arbitration proceeding, initiated by Abengoa, related to the parents guarantee provided by Abengoa in connection with the Carty construction agreement.

The sureties appealed the District Court's ruling to the Ninth Circuit Court, and on December 13, the Ninth Circuit issued an order staying the District Court proceeding pending the decision on the appeal. The oral argument regarding the appeal is scheduled for the week of May 8 at the Ninth Circuit. We anticipate a decision will follow several months later. For more details you can refer to our 10-K.

Slide 9, provides an overview of the timeline and action plan for our 2016 integrated resource plan that we filed with the OPUC back in November. This IRP reflects our plans for a more renewable, reliable and affordable energy future for our customers. This is consistent with Oregon's new Clean Electric Plan that calls for 50% renewable resources by 2040.

Today, PGE is meeting the 15% renewable portfolio standard requirement, and the 2016 IRP addresses the need for additional renewable resources to meet the 2020 requirement of 20%, and positions us for the 2025 requirement of 27%. As part of the OPUC public review process, we have been continuing our dialogue on the IRP with the OPUC staff and other stakeholders. We will work within the process to address stakeholder questions and identify the best strategy for achieving a renewable, reliable, affordable energy future for our customers.

We continue to target mid-2017 for acknowledgment of the plan. In addition to pursuing energy efficiency and customer demand side resources, upon acknowledgment of the plant, we will request approval from the OPUC to issue one or more RFPs to acquire capacity and renewable resources. We will be seeking the best combination of resources, consistent with the acknowledged IRP action plan to meet our customers' future energy and capacity needs.

We have no predetermined outcome in the RFP process and will, along with the independent evaluator, analyze a variety of resource proposals to determine the portfolios with the best overall balance of cost and risk. Resource options could include hydro wind, solar, geothermal, biomass, efficient combine cycle, national gas fire facilities, and generic capacity such as, seasonal contracts, power purchase agreements, energy storage and combustion turbines. The RFP process will include oversight of an independent evaluator and review by the OPUC. The IRP is available on our website.

Now, turning to slide 10, PGE plans to finally general rate case by the end of February with the OPUC. Based on a 2018 test year, the filing will include investments related to keeping PGE system safe, reliable and secure. Our efforts include replacing assets at the end of their useful life, strengthening our system to better prepare for storms, earthquakes and cyber attacks and other potential threats, as well as investments in operational changes that will integrate more renewable resources and enhance system reliability.

We realize the impact price increases can have on our customers and we are not making this request lightly. These are important investments to ensure we can keep delivering safe, reliable and secure power to our customers. Regulatory review of the 2018 GRC will occur through 2017, with a final order expected to be issued by the OPUC by the end of December 2017.

Now like to turn the call over to Jim Lobdell, who will go into more depth on our financial and operating results and provide the assumptions for our 2017 earnings guidance.

Thank you, Jim. As Jim mentioned for 2016, we recorded net income of $193 million, or $2.16 per diluted share, compared with net income of $172 million, or $2.04 per diluted share for 2015.

Moving on to slide 11, it shows a walk-through of the income statement changes year over year. A few things to note on the slide are, first, retail revenues increased $8 million for the year. This was largely the result of the August 1 price increase from placing Carty into service and an increase of $10 million in the decoupling mechanism, offset by a decrease in retail loads.

Second, net variable power costs, which are power costs net of wholesale revenues, contributed $59 million to PGE's gross margin, driven by low-cost thermal operations, improved hydro and wind conditions and an increase in wholesale revenues. Net variable power cost as reported for regulatory purposes were $10 million below the baseline of the power cost adjustment mechanism in 2016, and $3 million below the baseline in 2015.

Third, operating and maintenance expenses were $26 million higher in 2016 than in 2015. $12 million of the increase is related to additional O&M spending from placing Carty into service and Carty legal expenses. The remaining increase was attributable to PGE's efforts to reduce O&M spending in 2015 after an exceptionally warm winter that impacted earnings in the first quarter 2015.

While weather impacted earnings in the similar fashion in 2016, we were not able to repeat many of the same measures because they were one time in nature. Finally, an increase in depreciation and amortization expense is due to placing other capital additions and Carty into service and was partially offset by a refund to customers related to the Trojan spent fuel settlement.

On to slide 12, which shows earnings drivers for the year, first, Carty overall resulted in a $0.04 increase to earnings as a result of the following. A $0.10 increase from the Carty AFUDC equity and earnings related to the return of the $514 million of capital included in customer prices beginning August 1, net of the 2015 Carty AFDC equity. In addition, a $0.02 decrease for the depreciation and carrying cost of the Carty capital spending, greater than the $514 million in customer prices and a $0.04 decrease for Carty legal expenses.

The next earnings driver is a $0.06 increase related to rate base added at the beginning of 2016 in comparison to 2015. While PGE customers saw a 2.5% price decrease on January 1, 2016, that reduction was comprised of a large decrease related to lower net variable power costs, which are margin neutral, and more than offset increases related to O&M spending and higher rate based driven by the North Fork Surface Collector, the 2020 IT system replacement project, distribution construction and the Portland service center upgrade.

The third driver is $0.13 related to PGE's power supply portfolio, which had stronger performance in 2016 in comparison to 2015, primarily due to more favorable wind and hydro conditions. Fourth, the greater O&M spending decreased earnings per share by $0.07.

Next, an increase in tax credits, primarily production tax credits, resulted in a $0.05 increased to earnings per share. Lastly, earnings per share decreased $0.11 due to a higher average share count in 2016 as PGE completed the forward equity draw in June of 2015.

On to slide 13, we continue to maintain a solid balance sheet including strong liquidity and investment grade credit ratings. As of December 31, 2016, we had $610 million in cash, available short-term credit, and letter of credit capacity, $1.2 billion of first mortgage bond issuance capacity, and a common equity ratio of 49.4%.

The Company has a $500 million revolving credit facility to meet the Company's liquidity needs, which has a maturity date of November 2019, and additional letter of credit capacity facilities totaling $160 million. In 2017, PGE plans to issue $450 million of first mortgage bonds, a portion of which will replace $150 million of bank loans maturing in November 2017.

As shown on slide 14, we are initiating full-year 2017 earnings guidance of $2.20 to $2.35 per diluted share. Guidance is based on the following assumptions: a decline in retail deliveries between 0% and 1% weather adjusted, average hydro conditions for the year, wind generation for the year based on five years of historic levels or forecasted studies when historical data is not available, normal hydro plant operations, operating and maintenance costs between $540 million and $560 million, and depreciation and amortization expense between $340 million and $350 million. Back to you, Jim.

Thank you. As we begin 2017 we're moving forward on initiatives that drive value for our customers and our shareholders.

Slide 15, displays our key objectives for 2017. First, maintain our high level of operational excellence with a focus on employee and public safety and meeting our operational and financial goals.

Second, working collaboratively with all of our stakeholders to obtain acknowledgment of our 2016 integrated resource plan and its associated action plan that will deliver a more renewable, reliable and affordable energy future for our customers. Finally, achieve a fair and reasonable outcome on our 2018 general rate case.

Now, Operator, we're ready for questions.

(Operator Instructions)

Julian Smith, UBS.

Quick question, just want to reconcile the sales growth numbers you are talking about, how do you think about the earned ROE in 2017 and then also separately, how you transition from the 2017 sales growth to the longer dated 1%? What is driving 2017 and how to get back to that plus 1% or when do you that?

Do you mean from trying to figure out our EPS for 2017?

What is the earned ROW embedded in 2017 and also what is the cadence of the recovery back that long-term plus 1%?

Look at it this way, Julien. Take our rate base, approximately $4.4 billion, use our authorized ROE associated with that and then add some [C width] to it may be around approximately $250 million. Removed out the Carty drag, remove out uncollectible costs that we have always mentioned in the past and that should get you pretty close back to the middle of our guidance range.

In terms of the sales growth question, that will get normalized when we file our general rate case, so our general rate case that we will file at the end of February, will reflect our current sales forecast. So that should align our revenues and our cost structure together.

So what is driving the 2017 hit, if you can elaborate a little bit more maybe?

Why are sales -- got it. Sorry, we were having a little trouble hearing you, Julien. So if the question is, what is driving the reduction in sales for 2017, what we are seeing there is a continued softness in the manufacturing section of commercial and industrial. We are seeing high-tech not expanding at the fast-pace that we have seen in the past. We've been signaling this for a while. We were a little surprised in 2016, we have brought our guidance down based on the fact that we had thought that we were going to see a trend downward associated with some of the high-tech and that is what is happened in the first three quarters of the year and then in the last quarter of the year, their operation picked up. We're not expecting to continue to see that again in the 2017 time period. A little bit of softness in some of those sectors.

Can you elaborate a little bit, staff mentioned in their testimony on the IRP, the bank's [rex]. Can you elaborate a little bit on your situation with the bank's rex and what exactly would exhaustive those in the merits of pursuing the RFC now?

So that the real question on production tax credits we have the accumulated those in access of what we needed to retire. And those get utilize each year to meet our requirement under the rule. Excuse me, the rex, accumulated overtime so we built up a bank of those rex and those then get amortized over time. Right now we have in excess amount of rex and if we utilize those rex to meet our obligation we would not necessarily need to add a renewable resource for a number of years, however the value of production tax credit in our analysis, shows that would make more sense to require renewable resource sooner to potentially take advantage of the production tax credits that eventually go away. That is the analysis that people are trying to look at is, is it more cost effective to add renewables now and take advantage of the higher production tax credit or wait until later on in use of the bank rex. That is the conversation we're having with all of the stakeholders and they want to really understand the economics at that. At the end of the day we are short energy starting in 2021 so as you know, the rex does not necessarily provide us real energy. We're trying to look at that aspect of it also. That is all in the conversation and we are working with stakeholders and we want to provide that analysis so they can determine which is the least cost path for our customers.

The only other thing I would add to that Julien, there is a limitation on how many rex you can use, unbundled rex that is, in order to meet the state standard and that is limited to 20%, so we always have to keep that in mind as we are looking at that bank.

And last quick one on bonus depreciation. There's no reason that tax reform would change your current election, correct?

It is something that we constantly look at every single year. As you know, we [haven't] elected bonus depreciation in the past. We have had state tax credit that would be avoided and then by taking bonus depreciation it is just going to continue to push out the PTC balance that we have.

Thank you very much, guys.

Chris Turnure, JPMorgan.

I was wondering if you could give us a bit of a historical timeline and forward-looking timeline on customer rates? You had a couple of rate cases in the past to get the last cycle of the IRP generation build out through, I think, three years in a row there. And some of it was replacing PPA's, but there was still rate inflation for the customers. Could you maybe speak to that historically and it is early but maybe how you're thinking about the customer bill impact from the filing that you're going to make this month and then maybe looking even more forward to the next IRP cycle?

Let me go a little historical, we have gone through three rate periods to include various resources into our cost structure, with very minimal price impact. In fact, last year I think net-net the overall price change for our customer was about 0%. We had a decrease earlier in the year that was offset by the increase when Carty went into service. We have done a really good job managing our price changes while including new resources into our rate base to serve our customers.

So that's kind of the historical perspective we have benefited from low natural gas prices which have helped keep and manage our prices down and that has been a real benefits as we have gone through the cycle. As we look forward, we have gone, we didn't have a rate case for 2017 so this will be the second year of the cycle. We are seeing inflation in our cost with very minimal load growth and those two things work against each other if you will. That load growth reduction is primarily due to the slowdown in the economy a little bit but also the fact that we continue to promote energy efficiency as a very efficient way of serving our customers in terms of reducing their consumption because that is cost effective for us.

We do not have a lot of sales growth and you have general cost increases due to inflation, those things cause you to have to go in periodically. We would like to be on a two-year cycle, that tends to be where we want to be the that is where we are. We're still working on the numbers for the 2018 price change and we will have more information on that later in the month.

For that case specifically, are there any kind of customer credits or anything that might offset your top line ask, that you know about right now?

No additional. We had one credit associated with the charging decommissioning trust that will expire at the end of this year so there's no additional ones that we will be putting on top. No significant one, lets put it that way.

Then just a little bit more detail on 2017 guidance in your numbers and thinking about 2018 for now. You are obviously going to have new rates in effect and then maybe even a little bit of a tailwind from load growth there. But are there any other items in 2017 that you think might not be repeating a little bit of that Carty drag or other factors there?

No, there shouldn't be.

The Carty drag will probably continue. Will probably take us two to four years to get through that litigation as we noted. So that will continue to be a drag as we go until we get to the litigation but other than that, we should be pretty well aligned at that point with our cost structure.

Okay, remind me of the components of the Carty drag.

Carty drag really represents several components. It is the DNA associated with the above $514 million, it's the carrying costs associated with it and then we have got legal expenses in there as well. For 2016 that was about $0.06, looking forward for 2017 that is about $0.05 and then you put a couple of cents on top of that for legal.

Okay, and that would not be trued up in the rate case you would have to wait until the litigation is done.

Correct.

That is correct.

Okay great, thank you very much.

Paul Ridzon, KeyBanc.

Have you made any provisions to safe harbor any turbines to qualify for the 100% PTC or are you looking for your vendors to have done that?

To the extent we get an action plan that requires and suggest we add renewables in the RFP, we will go to the market for bids and people will bid in and to the extent they have safe harbor's they will bid it in with those projects. We would hope that if we go early, those bids would contain the value of that 100% production tax credit so that really will be determined through the RFP process. We still think we have a window here that if we get approval this year, start the RFP, that there are projects that could qualify for 100% PTC which would significantly reduce the cost of a project versus those projects that do not have any safe harbor or can't access the PTC in time.

On the third-quarter call, you ramped up the CapEx forecast with a lot of reliability spending. What is your thinking about that process and what you see going forward?

I will talk a little bit about the T&D reliability projects we have moved forward. We took a step back and said the system, we use a model called asset management, to really look at the risk and lifecycle of all of our resources and we determined that some of our resources needed to be upgraded because they were at the end of their useful life as well as we had increase in lows which was reducing the capacity factor on to those units. Really felt we needed to address that.

We have over 170 substations. We determined that about 69 were high risk so we're going to take those on over the next couple of years, and address the aging infrastructure that is there to deal with earthquake and other resilient matters so they are up to current standards. And so it's something that we need to do to improve the reliability as well as the capacity of the system. That is the first big attack.

Added to that, as we mentioned before on the call, we have a number of transformers that have high PCB levels and we need to address that and we are finding a number of those transformers as we have gone through this year, that have high PCB levels that we are going to maybe transition out or replace. So that is another big project; the third big project is our underground system. Much of our underground went in during the 60s and 70s and again now we are almost 40 years, almost 50 years old and in many cases with that underground. So we have identified those key circuits that our underground and need to be replaced. We have typically had a plan that we wait for three or four failures before we do a replacement, but some of those key underground segments have really reached the end of their useful life committee to address those also. So those are the major areas.

It will be a three to five year program to really catch up on those assets so we get them to where they need to be along with our pole-fitness program would we go in and replace poles that again have reached the end of their useful life. It is a program that has been a long time coming. We really need to address that before we really start having failures which impact system reliability.

So the next opportunity will probably be in the third-quarter call when you maybe, after capital budgeting re-up the CapEx forecast?

Yes, Paul. Our typical process is, we will make a recommendation to the board of directors for additional projects. That happens in the third quarter and our October meeting and then we will provided in our disclosure thereafter.

What we committed to our board was really kept showing them that the performance we can get done this year, the kind of success we're having ensure that we can deliver what we said we could deliver and then will bring the next launch forward.

Okay, thank you very much.

Brian Russo, Ladenburg Thalmann.

Hi, good morning. Just back to the embedded ROE in the 2017 guidance, is it accurate to say the midpoint assumes approximately a high 8% earned ROE?

Seems reasonable.

The step down in 2019 CapEx are you waiting to see how the RFP plays out, prior to potentially increasing that with your previously mentioned R&D investment strategy?

Yes, as we just explained to Paul, we wait on the T&D investments until we have done a presentation to the board, regarding any CapEx that might come out of the RFP process that is a wait-and-see as to what the best choices for our customers.

Okay, so the T&D in the RFP are totally independent of each other as it relates to any upside to your 2019 CapEx?

That is exactly right.

Okay got it. In this upcoming rate case, is there a strategy to address how the wind production, were falling below the historical average how that impacts your ROA? I think, prior periods you attempted to address it in a separate docket.

We've had an agreement with the regulators and stakeholders that we use a five-year rolling average. So as you look at the numbers, and the wind capacity factors have been going down to reflect what we have seen in terms of actual production. Now, whether that is a permanent trend or just a natural volatility of wind we do not know but the wind forecast continues to come down. The other thing we are allowed to do, even outside of a rate case, is true up the production tax credits to match that wind production. We did that in this [AUT] filing for 2017. The capacity factors are coming down.

To the extent that this is just an aberration we started seeing increases that would again, pick that up in the five-year average. We do not know yet what the long-term sustainable capacity factor is but the five-year averages a way to true that up, if you will, over time. I think there has been general agreement that is a good methodology. We would like for that to continue going forward.

Understood. Could you quickly characterize hydro conditions in your region?

Hydro conditions in the Pacific Northwest have been getting better and better. We just came out of a major snowstorm that was down in the Portland metropolitan area. That is not were a lot of our hydro comes from but it is clearly an indication that the winter has been a lot better than what we have seen in prior years. If you look in the 10-K we estimate that we are about normal for most of the basins that we deal with. But if I were to look out today to projections I would say we're probably in some of them up to 125%. I think Brian, one of the interesting things is, California's hydro condition is significantly better than what we have seen in prior years, to the point where even though Southern California does not have a lot of hydro, I think they are at 200% now. So it's going to be an interesting year.

I think the real question, Brian, is how that snow pack comes off. It be getting really warm spring that it all comes off all at once, which doesn't necessarily help us as much as it we have a slow warming winter where we can get some of that hydro off in June and July which helps to reduce some of our cost even more.

Michael Lapides, Goldman Sachs.

Real quick is wanted to make sure I understand, if you were to assume a lower demand growth rate, let's say it's 0.5 % instead of 1 % in your long run forecast; how much would that impact your capacity and energy needs? I'm thinking about the IRP and some of the pushback you have gotten in the IRP and especially around demand growth forecast.

It would have some effect but the big driver on capacity is the closure of the Boardman facility which is almost 600 megawatts. So that and along with some of the previous hydro contracts that we know longer have, have been a real driver to that. What we're trying to do is really separate the need versus how we're going to fill that need. But the major driver of the need is really the closure of Boardman which is but a pretty significant hole in our capacity. How we're going to the letter still the question that is with the purpose of the RFP is to determine what is the least cost, lowest risk way to replace that capacity.

The other thing I'd add to that it there is a lot of closures of other facilities in the region and to the extent that we are out in that regional portfolio trying to meet our customer's needs and do that reliably, it's a bit challenging.

One or two follow-ups. What was the impact of weather on a dollar millions or dollars cents per-share basis in 2016?

From cents per share compared to normal it was about $0.22 for the year.

Meaning it was $0.22 negative for the year?

Correct.

That is margin right?

Yes.

If I think about your original guidance, which was $220 million to $235 million, and you did, you obviously brought your guidance down based on what happened in the first-quarter of last year; and so you did beneath that level but now you are rolling out 2017 guidance which is the exact same as the original 2016 guidance. I'm struggling a little bit to understand the puts and takes there.

There's a lot of moving pieces in trying to come up with the 2017 guidance but as I've pointed out before, it is actually right in the midpoint. When you look at what our rate base and the other components of our earnings calculation would be, in 2016 we tried to avoid as much cost as possible especially you go back to 2017 some of the things we had to push forward. So, we think it is a reasonable guidance range for 2017.

But, if I assume normal weather rather than the $0.22 negative that you saw in 2016, what is the major offset? Your O&M is up some but not up dramatically, and the DNA partially offset but it seems that nothing fully offset the $0.22, unless it is the actual weather normal demand assumption.

We have been putting, bringing power cost back down year after year and then you are adding Carty in there as well.

Meaning continued drag from Carty?

Yes.

But will the drag be similar to what it was in 2016 or would be a little less because 2016 was the high end of that drag?

It is actually going to be a little bit more. As we pointed out earlier, 2016 was about a $0.06 drag associated with Carty and in 2017 were expecting about a $0.07.

Got it. Does that show O&M or is that A&G cost?

It shows up across several line items including A&G. The legal part shows up in A&G.

Depreciation would be higher and obviously our carrying cost will be higher because of the excess cost. The other thing, when Jim talked about the $0.22 some of that was due to the fact that we were assuming Carty was going to go into service a lot sooner. And so that was in our forecast for revenue but it didn't show up later, so revenues were down but then AFCC was up so there was some offset to that negative $0.22.

In the PCAM what was the positive benefit from PCAM and is that embedded in the $0.22 or is that a separate number?

That is a separate number. We were about $10 million above the baseline for 2016.

Does that mean it was a earnings headwind by $10 million pretax or earnings tailwind? I'm just trying to get my arms around that.

I'm sorry, it was $10 million below on the PCAM mechanism. What was the rest of the question, Michael?

That meant that it helped earnings by a pretax $10 million?

Yes.

So, earnings in 2016 what have been $6 million or $7 million less after-tax, had you not have the PCAM benefits so I assume you back to that out of your 2017 guidance?

Yes.

I may have a few others but I will follow up with Chris off-line. Much appreciated, guys.

Greg Boyle, Barclays.

Is it possible to say how much incremental rate base will be in your upcoming rate filing?

Greg, what we're going to do, we're putting the final touches on the rate filing and once we have got that done then we will put out either in A-K or press release to have all of the details associated with that.

Okay. Was there anything to report from the IRP hearing yesterday? Any key takeaways there?

I think there's still a lot of questions by the parties. Everyone has a different point of view on what the action plan should look like. I think there is a lot of questions about how we're going to fill that capacity. I think that is the biggest issue as well as should we add renewables now or later is the other issue, as we talked about the rex bank. Is it more cost effective to add new renewables now and take advantage of 100% production tax credit or is it better to delay and use the rex bank and have those renewables much later. I think that is one issue.

The other issue is, the 800 plus megawatts of capacity that we need; and the real question there is, what is the least cost, lowest risk way to fill that capacity. And parties have different points of view on what is the right way. And what we tried to let people differentiate what is the need, first of all, and then what is the least cost way to fulfill that need. People feel there are other capacity options in the market and there may in fact be those options, but we need to get to an RFP to determine what those options look like and see if they are real. So those are the two questions.

I don't think there's any debate around continuing support for energy efficiency, continued support for demand response. I think it just really gets down to what the action plan is. I think as we go to the RFP process, we will let it play out and we will see what is the least cost, lowest risk. We really don't have a point of view; that is the whole purpose of the RFP is to determine what is the best decision for our customers. With the independent evaluator and the commission, we'll all have the opportunity to look at that. So we don't know exactly what the outcome is going to be but we need to get to that process so we can determine that.

Chris Ellinghaus, Williams Capital.

Good Morning. When you were talking about the manufacturing and industrial weakness, are you still talking about solar and aluminum? Is there chip weakness? Can you give us a little more color there?

No, it is more in the solar manufacturing side, transportation, things of that nature. We're still seeing growth in the high tech sector.

Okay. Can I infer from the $0.22 that you were talking about that the fourth quarter was something like $0.06, $0.07 negative?

I think we have reported in the first part of the year that compared to normal, the impact of weather was about $0.19. I think it was $0.03 in the last quarter.

Okay. Can you talk about January or year to date? I gather that your guidance is merely taking a reversion to that five-year mean for wind. Can you talk about what it has looked like so far?

So far leading up to the end of 2016 or end of 2017?

First quarter so far. Whether it's been better, so has wind responded?

No. The problem with wind is, as I mentioned earlier, we've had some very cold temperatures here in the Portland metropolitan area and across Oregon, Southwest Washington. As we have been experienced that, the one thing that wind reacts to is in a very cold day it does not blow. The production that we received out of the wind resources during that particular point in time was far below expectations.

As far as the IRP issues, subsequent to the filing there has been some, I suppose, disagreement thus far. You feel like your talks with stakeholders, you are making some progress at this point?

I think we're making progress. I think we are trying to help all of the folks and the stakeholders at the table to understand, let's differentiate the need versus how we meet the needs. I think we clearly demonstrate that we have a need. I think the real debate is how we meet the need and that is the purpose of the RFP. I think we need to get to that, because Boardman in its current plan will shut down at the end of 2020 and that is 600 megawatts.

So, I think the conversation seems to be integrated and we need to identify what the need is first and then talk about what is the right strategy to fulfill that need. That is what we're trying to work with all of the stakeholders on. We are totally open to any option that could meet that in the least cost, lowest risk way. That is really the purpose of the RFP so that is where we need to go. I think there has been some conversations around potential for hydro contracts. This may or may not be available. We need to test the market on that. There may be resources out there that might be available and again, that is the purpose of the RFP.

We need to get acknowledgment of the plan to identify what the need is and then move on to the procurement side of that, what are the options in the least cost, lowest risk way to do that. That is where we are. I think we're making progress on the renewables, as I pointed out before, there is that question of whether now versus later. Again, you can determine that through an RFP process but that is something that the analytics is pretty clear on but there are people have a different point of view on that.

What is the next hard date to look for in terms of the IRP process?

March 3, we file comments back to the parties on their comments and then there could be additional comments over the next couple of weeks and we have 14 days to respond. Our challenge is, we have a lot of comments to respond to and so we have to get all of the comments responded to. We are likely, based on the hearing at the commission, get some additional data request from the commissioners and we need to respond to those also. We're in that, going through the questions, getting the analytics, explaining the basis of our action plan. Those are the next two steps as they go through the process.

Paul Ridzon, KeyBanc.

You're back.

I am back. Thank you for the O&M forecast. How much of that is work that was pushed out of 2016 into 2017, so temporary?

It is hard to say, Paul. When we are sitting in 2015 and dealing with that really warm winter, we looked at the four corners of the company and it is nuts and bolts from around the company. We are trying to stick to a more average O&M cost going into 2017. I wouldn't say you are going to see a big bump in the rug but there are some projects that we delayed that we otherwise would have moved forward on.

In the midpoint of guidance assumes no, nothing at the PCAM?

Nothing at the PCAM we just assume AUT filing.

So 120% snow pack is bullish in that regard? Depending on how the water comes down.

The forecast right now is normal.

Right. But as Jim pointed out, Paul, it really depends on what the runoff looks like. If we are headed into a warm summer and I am off hiking in the mountains and I am not finding snow in the summertime, then it is going to be a higher power prices.

Travis Miller, Morningstar.

What is the chance real quick, what is the chance of having interim rates during some period this year?

0%. We filed AUT filings. I think we have got a good case for the year. The Carty cost are the one issue we're struggling with and that has to really get through the litigation. Until we complete that litigation, where we have the opportunity to recover that depreciation expense of some of our carrying cost, we had to complete that litigation before we can go to the regulators and ask for any, if there were any cost left over. We believe we should be able to recover all of the cost from assurity but if there is any cost left over we would have to evaluate that whether there is a basis for recovery.

On the dividends, you guys, given the guidance that you put out there, in the current rate and then even looking if you continue that $0.08 type run rate you are toward the lower end, mid to lower end of your payout ratio. Given what you see in the CapEx side, other investments, operating costs etc., what is your thought in terms of coming off of that $0.08 type annual increase rate?

Each second-quarter board meeting we do a thorough review of our dividend. We look at our CapEx policy and where we think we will stand. We look at the balance sheet, we look at our capital ratios. All of that gets factored in. We said we want to be between 50% and 70% of the payout ratio and we are within that. So we will move it as we feel it is the right move, the board clearly understands the importance of the dividend wants to make that dividend competitive and reward our shareholders. But we also want to manage the capital structure in the way it makes sense for the company. You probably hear more about the dividend when we report in the second quarter -- first quarter.

One higher level question, was wondering what you are seeing in terms of corporate renewable energy purchases. So PPA, something outside of the traditional rate making and power that you guys deliver but the PPA side of it in Corporate with the renewables?

Other companies going their own way to buy renewable energy?

The Amazons, the Google's.

Sure. So we have a direct access in Oregon. We have a cap of 300 average megawatts that can go to the market right now. So to the extent a customer wants to go do that directly and buy renewable energy source from a third-party they can do it up to the 300 megawatts. We also provide green credits or green tags if you will, through programs that we offer so that people can essentially neutralize any carbon impact by buying those tags through our program. That is another way customers can do that.

We have not seen in a lot of third parties offer renewable products in the marketplace, at least in our state. There obviously is conversations. We actually tried to put forth a green tariff for our customers, we have put that on hold because we couldn't get to a reasonable outcome with our constituents. It is something that we look at.

Obviously, you have to ensure that there is a full backup of that energy, not just renewable because renewable attributes aren't necessarily firm. And so the extent a party buys a renewable resource they also have to address the capacity to firm up that resource because as we mentioned before; the wind doesn't blow all the time and the sun doesn't shine all the time. So to think about the full aspects of that product to serve a customer.

Andy Levi, Avon Capital.

It's a miracle. I do not think I was going to get a question. A lot of them could answer but let's go over that really quick because we're running out of time. What is the tax rate that you guys are assuming for this year can you share that with us?

We are assuming about a 20% to 25%.

Going forward, absent anything from the IRP, should we assume that going forward, the 20%, to 25%?

Yes. That would be right. I don't think that would really change materially until we see the first tranche of Biglow Canyon fall off from PTC perspective which would be in the 2018 time period.

As far as, I get obviously, the board has to look at the CapEx potential for 2018, 2019 and 2020, but does 2018 already reflect some of these, I guess it does but the full extent of the aging infrastructure upgrades?

No, no, it does not. It includes some of details, the projects we started in 2017 but as we look to the continuation of the PCB program and other programs we will factor that in when we talk to you all after the third-quarter's decision with the board.

That will fill in some of 2019 but it won't obviously do 2020 because board cycle and CapEx cycle works, is that correct?

Yes.

As far as the rate case itself which has a 2018 test year if I'm not mistaken, will that include, it is you will have some of incremental 2018 CapEx but it will not have been approved by the board, so how do you handle that as far as the rate case itself and the level of CapEx/rate base?

The answer is, Andy, as we're trying to finish all of the details associated with that case and as I mentioned earlier on the call, we will be putting out a press release or in 8-K associated with that. You will get the details, so please, just be patient.

Let me ask you again in another way, in the past when you have filed in these rate cases, it generally incorporate what the board may do? Do you understand what I'm saying? Let's say you add, I don't know what, we'll say $50 million of CapEx to 2018 based on what you guys are seeing, is that generally getting incorporated in your rate case when you make your rate case filing, just from past history?

Typically, what we have done in past cases is that it starts with the rate base, the year-end rate base from the prior year.

Then, as far as the again, we're going to bear with you as you said, until you make your filing, but what are some of the -- Carty is already in rates, so that was just your big spend in 2015 and 2016 plus the wind, which is in rates?

The component is associated with the original stipulation is in rates. The component that we talked about earlier that's above the $514 million, is not.

So the $610 million -- I am just saying in general as far as trying to think what the incremental -- let's say we want to frame what type of rate increase we're looking at and incremental rate base that you may file, again, we need to be patient. But like the $610 million that you are spending in 2017, was that incorporated in the last rate case or is that incremental and that will be in this rate case?

Andy, as I've pointed out, just be a little bit patient.

As far as the sales growth, and you have a partial to decoupling and that -- just explain to us again what that relates to?

It relates to our residential and part of our commercial group.

So the fact that sales are down --

It's based on a use per customer.

Right, okay. So customer growth is, I guess, is more important then sales growth. Is that correct on the residential level?

We get to use customer growth to cover increasing cost margins but if use per customer changes either positive or negative that gets decoupled away.

Okay. What is your customer growth that your forecasting for this year?

I have not provided that.

Is a positive?

It was about 1.3%, 1.2% last year.

Just want to see if there was anything else. Went over the legal stuff, aging infrastructure, CapEx, [C lift] is 250. I think that is it. I think I am good.

Ashar Khan, Visium

The questions have been answered, thank you.

Kevin Fallon, Citadel.

I apologize if I missed it, but what are you guys assuming for the strict Carty legal cost in 2017?

In 2017 there's about $0.02 associated with it.

Is this the last year of that or should that go over the two to four year cycle to resolve this?

The thing you have to keep in mind with $0.02 it can be above it, it can be below it, it can be one year, it can be two to four years. We don't know. It just depends on how the case plays out.

In terms of the state tax credits that you guys are using in lieu of taking bonus depreciation, how much did you book in 2016 and what is the outstanding balance of those credits in year-end 2016?

We will follow-up with you. I do not have them right here.

One more question. Last on, Andy, your next in line.

How much debt are you guys going to issue this year if any?

About $450 million is what we are estimating. About $150 million of that will go towards repaying a bank loan that we have got out there and the balance will help fund some capital program that we have going.

So it's $450 million of new debt?

Yes. But the new debt, as I pointed out --

The bank loan. How much is the bank loan with interest rate?

It is $150,000.

What is the interest rate?

LIBOR plus 63.

The tenure of this debt will be average tenure debt or something like that?

To be determined.

Thank you all. Great questions. We appreciate your interest in Portland General Electric and invite you to join us when we report our first-quarter 2017 results in late April. Thanks a lot 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. Everyone have a great day.