Good morning everyone and welcome to Portland General Electric Company’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.

After the speakers’ remarks, there will be a question-and-answer period. [Operator Instructions] For opening remarks, I will 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’re able to join us today. Before we begin our discussion this morning, I’d like to remind you that we have prepared a presentation to supplement our discussion which we will be referencing throughout the call. Those slides are available on our website at investors.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 facts and as such constitute forward-looking statements under current law.

These statements are subject to factors that may cause actual results to differ materially from the forward-looking statements made today. For a description of some of the factors that may occur that could cause such differences, the company requests that you read our most recent Form 10-K.

Portland General Electric’s fourth quarter and full-year 2016 earnings were released via earnings press release and the Form 10-Q 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 up for your questions. Now, it’s 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 achieved several key objectives towards meeting our customer’s energy needs. And I'm 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 on 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 of our fourth quarter and annual financial results and end with key assumptions supporting our outlook for 2017.

So 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 and communities we serve.

We delivered strong operating performance despite the impact of lower retail loads 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'm 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 commissioned 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. Now let's turn to Slide 6. Oregon’s 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 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 seized operations in late 2015.

Looking forward based on expected decreases in delivery 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 zero and 1%.

Despite uneven growth rates due to 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 were 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're 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 megawatt natural gas base load resource near Boardman, Oregon that went into service on 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 plant in-service for this project. Our current estimate for the final capital expenditures for Carty including AFDC is approximately $640 million.

As previously reported we are pursuing legal actions against Liberty Mutual in Zurich, North America, the two sureties who provided our 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 TGE in US District Court of Oregon and ruled in favor of PGE’s motion to enjoying the sureties from participating in an International Chamber of Commerce arbitration proceeding initiated by Abengoa related to the parent 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.

And 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 2015 integrated resource plan that we've 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 dialog 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 acknowledgement of the plan, 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 customer's future energy and capacity needs.

We have no pre-determined 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 combined cycle, natural gas fired facilities and generic capacities 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 file a 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, earthquake and cyber-attacks, and other potential threats as well as investment 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 I'd 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 onto Slide 11. It shows a walkthrough of the income statement changes year-over-year.

A few things to note on this 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 de-coupling 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 costs 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 of 2015.

While weather impacted earnings in a similar fashion in 2016, we were not able to repeat many of the same measures because they were one-time in nature.

And 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. Onto 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 on the 514 million of capital included in customer prices beginning on August 1, net of the 2015 Carty AFDC equity.

In addition, a $0.02 decrease for the depreciation in carrying costs of the Carty capital spending greater than the 514 million in customer prices and $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 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 offsets increases related to O&M spending and a higher rate base 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 increase 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.

Onto Slide 13, we continue to maintain a solid balance sheet including strong liquidity and investment grade credit rating. 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 tolling 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 zero 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 hydroplane operations, operating and maintenance cost between 540 and 560 million, and depreciation and amortization expense between 340 and 350 million.

Back to you Jim..

Thank you. As we begin 2017 we are moving forward on initiatives to 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 employ and public safety, and meeting our operational and financial goals.

Second, working collaboratively with all of our stakeholders to obtain acknowledgement 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. And finally achieve a fair and reasonable outcome on are 2018 general rate case.

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

[Operator Instructions] Our first question comes from Julien Dumoulin-Smith of UBS. Your line is open..

So quick question, just want to reconcile the sales growth numbers you guys have been talking about. How do you think about the earned ROE in ‘17 and then also separately how you transition from the ‘17 sales growth to the longer dated 1%? What's driving ‘17 and how do you get back to that plus one or when do you do that..

You mean from trying to figure out our EPS for 2017..

What’s the earned ROE embedded in ‘17 and then also what the cadence of the recovery back to that long-term plus 1%..

Well, look at it this way, Julien, take our rate base approximately $4.4 billion, use our authorized ROE associated with that then add some CWIP to it, may be around approximately $250 million, remove out the Carty drag, remove out uncollectible costs that we've 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 would get kind of normalized when we file our general rate case. So our general case that we’ll file at the end of February will reflect our current sales forecast. So that should align our revenues and our cost structure together..

What's driving the ‘17 - if you can elaborate a little bit more maybe? What's driving….

Why are sales, oh, got it. Sorry, we’re having a little trouble hearing you Julien. So if the question is what's driving the reduction in sales for 2017.

What we're seeing there is a continuous softness in the manufacturing section of the commercial and industrial, we're seeing high-tech now expanding at the fast pace that we have seen in the past and we've been kind of signaling this for a while. We were a little surprised in 2016.

We had brought our guidance down based on the fact that we had thought we were going to see a trend downward associated with some of the high-tech and that's what 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. So just a bit of softness in some of those sectors..

And can you elaborate a little bit, [indiscernible] mentioned in their testimony on the IRP, the bank REC, can you elaborate a little bit on your situation with the bank RECs and just what exactly would it exhaust those into merits of pursuing the RFP now?.

So the real question on production tax credits, we've accumulated those in excess of what we needed to retire and if those gets utilized each year to meet our requirement under the rule. The RECs, accumulated over time and so we build up a bank of those RECs and those then get amortized over time.

And right now we have an excess amount of RECs and if we utilize those RECs to meet our obligation we wouldn't necessarily need to add a renewable resource for a number of years.

However the value of production tax credits in our analysis show that it would make more sense to acquire renewable resource sooner to potentially take advantage of the production tax credits that eventually go away.

So that's 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 credits or wait to later on and use up the bank RECs. So that's the conversation we're having with all the stakeholders and they want to really understand the economics of that.

At the end of the day we are sure energy starting in 2021 and so as you know the RECs don't necessarily provide us real energy. And so we are trying to look at that aspect of it also.

So that’s all on the conversation, we’re working with stakeholders and we want to provide that analysis so then can determine which is the least cost path for our customers..

The only other thing I'd add to that, Julien is there is a limitation on how many RECs you can to unbundle RECs that is in order to meet the state standard and that's limited to 20%. So we always have to keep that in mind as we're looking at that bank..

Just the last quick one here on bonus appreciation.

There's no reason that tax reform would change your current election, correct?.

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

Our next question comes from Chris Turnure of JPMorgan. Your line is open..

I was wondering if you could kind of give us a bit of a historical timeline and forward looking timeline on customer rates. You've had a couple rate cases in the past to get the last cycle of the IRP generation build out through I going to think kind of three years in a row there.

And some of it was replacing PPAs but there was still rate kind of inflation for the customers. Could you maybe just speak to that historically and then it's 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 be the next IRP cycle..

[indiscernible] we've 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 to decrease early in the year and that was offset by the increase when Carty went into service.

So we've 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 benefited from low natural gas prices which have helped keep and manage our prices down and that's been a real benefit as we've gone through the cycle.

As we look forward, we didn’t have a rate case for 2017 so this will be the second year of the cycle. And we are seeing inflation in our cost with very minimal load growth and those two things kind of you know kind of work against each other if you will.

And 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’s cost effective for us.

And so, when you don't 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'd like to be on a two year cycle that tends to be where we want to be.

And so that’s kind of where we are, we're still working on the numbers for the 2018 price change and we'll 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 topline ask that you know about right now..

There are no additional. We had one credit associated with the Trojan decommissioning trust that will expire at the end of this year. So there's no additional ones that we’d be putting on top..

No significant ones let’s just put it that way..

And then just a little bit more detail on 2017 guidance in your numbers, I'm thinking about 2018 for now. You're 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 kind of not be repeating a little bit that Carty drag or other factors there..

No, there shouldn’t..

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

Remind me of just the components of the Carty drag?.

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

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

Correct..

That’s correct..

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

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

To the extend we get an action plan that requires and I suggest that we have renewables in the RFP, we will go to the market for bid and people will bid in and to the extent they have safe harbors, they’ll 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.

And so that really will be determined through the RFP process.

So we still think we have a window here that if we get approval in this year, start the RFP that there are projects that could qualify for 100% PTC which would significantly reduce the cost of the project versus those projects that don't 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 your liabilities spending, kind of what you're thinking about that process and what do see going forward?.

I'll 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 them, I'll call the asset management to really look at the risk and lifecycle of all 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 of loads which was reduced in the capacity factor on those units. So we really felt like we needed to address that.

We have over 100 - right around 170 substations, we determined that about 69 were high risk and so we're going to take those on over the next couple of years and address the aging infrastructure that there to deal with earthquake and other resilience that matters so that they're 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 and so that's 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've gone through it this year that have high PCB levels that we're going to - maybe transitioned out or replaced. So that's another big project.

The third project is our underground system. Much of our underground went in during the 60s and 70s and again now, we’re almost 50 years old and in many cases, with that underground. And so we've identified those key circuits that are underground that need to be replaced.

We've 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 our useful life and we need to address those also. So those are the major areas.

It's going to 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 where we go in and replace poles again that have reached the end of our useful life. It's a program that has been a long time coming.

We really need to address that before we really start having failures, which impacts system reliability..

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

Yeah. Paul, our typical process is, we’ll make a recommendation to the board of directors for additional projects. That happens in the third quarter in our October meeting. And then we will provide it in our disclosure thereafter..

And we’ll recommend to our board is really showing them the performance we could get done this year, the kind of success we’re having to ensure that we could deliver what we said we could deliver and then we’ll bring the next tranche forward..

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

Hi. Good morning. Just back to the embedded ROE in the ‘17 guidance.

Is it accurate to say the midpoint assumes approximately a high 8% earned ROE?.

Seems reasonable..

Okay.

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

Yeah. As we just explained to Paul, we wait on the T&D investments until we’ve done a presentation to the board regarding any CapEx that might come out of the RFP process. That’s a wait and see as to what the best choice is for our customers..

Okay.

So the T&D and the RFP are totally independent of each other as it relates to any upside to your 2019 CapEx?.

That's exactly right..

Okay. Got it. And in this upcoming rate cases, is there a strategy to address kind of how the wind production were falling below the historical average, how that impacts your ROE.

I think prior periods, you attempted to address that in a separate docket?.

We’ve had an agreement with the regulators and the stakeholders that we use the five year rolling average. So as you look at the numbers, the wind capacity factors have been going down to reflect what we’ve seen in terms of actual production. Now, whether that’s a permanent trend or just the natural volatility of wind, we don't know.

But the wind forecast continue to come down. The other thing we're 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. So the capacity factors are coming down to the extent that this is just an aberration.

We started seeing increases that we’d again pick that up in the five year average. So we do not know yet what the long term sustainable capacity factor is, but the five year average is a way to true that up if you will over time. And I think there's been general agreement that’s a good methodology and we would like that to continue going forward..

Understood.

And then could you just 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 port metropolitan area. That's not where a lot of our hydro comes from, but it's 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 estimated that we were about normal for most of the basins that we deal with, but if I were to look out today at the projections, I'd say we're probably in some of them up to 120%.

I think Brian, one of the interesting things is California's hydro condition is significantly better than what we've seen in prior years to the point where even though Southern California doesn't have a lot of hydro, I think they're at 200% now. So it's going to be an interesting year..

I think the real question Brian is how that snowpack comes off. If we get a really, really warm spring, then it all comes up all at once, which doesn’t necessarily help us as much as if we have a slow warming winter where we can get some of that hydro off in June and July, which helps reduce some of our cost even more..

Our next question comes from Michael Lapides of Goldman Sachs. Your line is open..

Hey, guys. Real quick. I want to make sure I understand if I were - if you were to assume a lower demand growth rate, I mean let's say it's, I don't know, 0.5% instead of 1% in your long run forecast.

How much would that impact your capacity in energy needs? I'm thinking about the IRP and some of the pushback you've gotten in the IRP and especially around demand growth forecasts?.

I mean 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 no longer have, have been a real driver to that.

So 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 has put a pretty significant hole in our capacity.

Now, how we’re going to fill that is still the question and that's really what 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 is that there's a lot of closure of other facilities in the region and to the extent that we're out in that regional portfolio, trying to meet our customers’ needs and do that reliably, it's a bit challenging..

Got it. One or two follow-ups.

What was the impact of weather on a dollar millions or dollar 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..

And so if I think about your original guidance which was 220 to 235, and you did too, 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're rolling out 2017 guidance which is the exact same as the original 2016 guidance.

I'm just 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 pointed out before, it’s actually right in the midpoint.

When you look at what our rate base and the other components of our earnings calculation would be, I mean in ‘16, we try to avoid as much cost as possible, especially if you go back to 2017, some of those things we had to push forward. So we think it's a reasonable guidance range for 2017..

But if I assume normal weather rather than the $0.22 negative that you saw in 2016, what's the major offset? I mean your O&M is up some, but it's not up dramatically.

The D&A partially offset, but it seems that nothing fully offsets the $0.22 unless it's the actual weather normal demand assumption?.

Well, we've been bringing power costs back down year-after-year and then you’ve added Carty in there as well..

Meaning continued drag from Carty..

Yes..

But will the drag be similar to what it was in ‘16 or would it be a little less because ‘16 was the high end of that drag?.

It's actually going to be a little bit more. As we pointed out earlier, 2016 was about a $0.06 drag associated with Carty. In 2017, we're expecting about a $0.07..

Got it.

And does that show up in O&M or was that in like A&G costs?.

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

Depreciation would be higher. And obviously, our carrying costs are going to be higher because of the excess cost. Jim talked about the $0.22. Some of that was due to the fact that we were assuming Carty was going to go in to service a lot sooner and so that was kind of in our forecast for revenues. So they didn’t show up later.

So, revenues were down, but then AFDC was up. So there were some offsets to that negative $0.22..

Got it.

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

That’s a separate number. We were about 10 million above the baseline for 2016..

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

I'm sorry it was 10 million below on the PCAM mechanism and what was the rest of the question, Michael..

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

Yes..

So earnings in ‘16 would have been $6 million or $7 million loss after tax had you not had the PCAM benefits, so I assume you backed that out of your ‘17 guidance?.

Yes. Got it. Okay, guys. Thanks. I may have a few others, but I'll follow up with Chris offline. Much appreciate it guys..

Our next question comes from Gregg Orrill of Barclays. Your line is open..

Good morning.

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

Greg, what we're going to do is we're putting the final touches on the rate filing and once we've got that done, then we will put out either in 8-K or a press release to have all the details associated with it..

Okay.

Was there anything to report from the IRP hearing yesterday, or were there any key takeaways there?.

Well, I think there's still a lot of questions by the parties. Everyone has a different point of view on what the actual plan should look like. I think there is just a lot of questions about how we're going to build that capacity gap.

I think that’s the biggest issue as well as should we have renewables now or later is the other kind of issue as we talked about the REC bank, is it more cost effective to add new renewables now and take advantage of the 100% production tax credit or is it better to delay, use the REC bank and add those renewables much, much earlier and I think that's one issue.

The other issue is the 800 plus megawatts of capacity that we need.

And the real question there is what's the least cost lowest risk way to fill that capacity and parties have different points of view on what’s the right way and what we try to let people kind of differentiate, what is the need first of all and what is the least cost way to fulfill that need and as people feel there are other capacity options in the market and there maybe in fact be those options, but we need to get to an RFP to determine what those options look like to see if they're real.

So those are the two constant questions. I don't think there is 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. And I think as we go through the RFP process, what it's like to play out and we’ll see what the least cost lowest risk.

We really haven't got a point of view. That’s the whole purpose of the RFP is to determine what is the best decision for our customers and with the independent evaluator and the commission will 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..

Our next question comes from Chris Ellinghaus of Williams Capital. Your line is open..

When you were talking about the manufacturing and industrial weakness, are you still really talking about solar and aluminum? Is there a chip weakness.

Can you give us a little more color there?.

It's more in the solar and the 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 had reported in the first part of the year 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 year-to-date, I gather that your guidance is merely taking a reversion to that five year mean for wins.

Can you talk about what it's looked like so far?.

So far for, so far leading up to the end of 2016 or end of 2017?.

This quarter so far.

Weather's been better, so has wind responded?.

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. And as we've been experiencing, the one thing that wind reacts to is in a very cold day, it doesn't blow.

So the production that we received out of the wind resources during that particular point in time was far below expectations..

Okay. Great. And as far as the IRP issues, subsequent to the filing and there has been some I suppose disagreement thus far.

Do you feel like your talks with stakeholders, you're making some progress at this point?.

I think we're making progress. I think we're trying to help all of the folks and the stakeholders in the table to understand let's differentiate the need versus how we meet the need and I think we clearly demonstrate that we have a need.

I think the real debate is how we meet that need and that is the purpose of the RFP and I think we need to get to that, because Boardman in its current plan, will shut down at the end of 2020. And that's 600 megawatts.

So I don't think, yeah, I think we really need, I think the conversation seems to be integrated and we really need to separate, let's identify what the need is first and then let’s then talk about what’s the right strategy to fulfill that need.

And that's what we're trying to work with all the stakeholders on and we're totally open to any options that could meet that and at least cost lowest risk way and that's really the purpose of the RFP and so that's where we need to go. And I think there's been some conversations around potential for hydro contracts. Those 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's the purpose of the RFP. So we need to get acknowledgement of the plan to identify what the need is and then move on to the procurement side of that as what are the options in these cost flows, what’s the risk way to do that.

So that’s kind of 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's something that the analytics is pretty clear on, but there are people who have a different point of view on that..

Okay.

What's the next target date to look for in terms of the IRP process?.

March third, we filed 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 that we got a lot of comments to respond to and so we got to get all the comments responded to.

We're likely based on the hearing down at the commission, get some additional data requests from the commissioners and we need to respond to those also. So we’re in that going through the questions, giving the analytics, explaining the basis of our action plan and so those are the next two steps as they go through the process..

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

Thank you for the O&M forecast.

How much of that is kind of work that was pushed out of ‘16 into ‘17, so kind of temporary?.

It's hard to say Paul. When we were sitting in 2015 and dealing with that really warm winter, we liked to the four corners of the company and it's nuts and bolts, just from around the company. So we're trying to stick to a more average O&M cost going into 2017.

So I wouldn't say you're going to see a big bump in the rod, but there are some projects that we delayed that we otherwise would have moved forward on..

And the midpoint of guidance assumes nothing at the PCAM?.

Nothing at the PCAM. We just assume the AUT filing..

So 120% snowpack 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. I mean if we're headed into a warm summer and I'm up hiking in the mountains and I'm not finding snow in the summer time, then it's going to be higher power prices..

Our next question comes from Travis Miller of MorningStar. Your line is open..

Good morning. Thank you. Real quick.

What's the chance of having interim rates during some period this year?.

Zero. I mean we filed AUT filing. I think we've got a good case for the year.

The Carty costs are the one issue we're struggling with and that have to really get through the litigation and until we complete that litigation, where we have the opportunity to recover that depreciation expense of some of our carrying costs, we have to complete that litigation before we can go to the regulators and ask for any, if there were any costs left over.

We believe we should be able to recover all the costs from the sureties. But if there's any costs left over, we would have to evaluate that, whether there's a basis for recovery..

Got it. Okay.

And then on the dividends, given the guidance that you’ve put out there, the current rate and then even looking if you continue that kind of $0.08 type run rate, you're toward the lower end, mid to lower end of your payout ratio, given what you see on the CapEx side, other investments, operating costs, et cetera, what's your thought in terms of coming off of that $0.08 type annual increase?.

Each second quarter board meeting, we do a thorough review of our dividend. We look at our CapEx policy and where we think we're going to spend. We look at the balance sheet. We look at our capital ratios. All that gets factored in. We said we want to be between 50% and 70% as a payout ratio and we're within that.

And so we’ll move it as we feel it’s the right move. The board clearly understand the importance of the dividend and wants to make that dividend competitive and reward our shareholders, but we also want to manage the capital structure in a way that makes sense for the company.

So you’ll probably hear more about the dividend when we report in the second quarter - first quarter..

And one higher level question, I was wondering what you're seeing in terms of corporate renewable energy purchases, so PPA, something outside of the traditional rate making and power that you guys deliver, kind of the PPA side of it corporates..

So I mean, other companies go in their own way to buy renewable energy..

Yeah. The Amazons, the Googles..

Sure. So we have a direct access in Oregon. There's a cap of about 300 megawatts, average megawatts that can go to the market right now. So to the extent that customer wants to go do that directly and buy a renewable energy source from a third-party, they can do that up to the 300 megawatts.

We also provide greening 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 programs. And so that’s another way customers can do that. We haven't seen a lot of third-parties offer renewable products in the marketplace at least in our state.

There obviously is conversations. We actually try to put forth a green tariff for our customers. We’ve put that on hold, because we couldn't get to a reasonable welcome with our constituents. So it's something we look at.

Obviously, you have to ensure that there's a full backup of that energy, it’s not just renewable because renewable attributes are 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 or the sun doesn't shine all the time. So, you have to think about the full aspects of that product to serve a customer..

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

It's a miracle. I didn’t know if I could get a question. [Technical Difficulty] Okay. Got my list. Actually, a lot of them got answered. But let's go over real quick. You’re running out of time. Okay.

What's the tax rate that you guys are assuming for this year? Can you share that with us?.

We’re assuming about 20% to 25%..

Okay. And then going forward, absent anything from the IRP.

Should we assume that going forward that 20% to 25?.

Yeah. That would be right. I don't think it would really change materially until we see the first tranche of canyon fall off from a PTC perspective, which would be in the 2018 time period..

Okay. And then as far as, again obviously the board has to look at the CapEx potential for ‘18, ‘19 and ‘20.

But does ‘18 already reflect some of these, I guess, it does, but the full extent of the aging infrastructure upgrades?.

No. It doesn’t. It includes some of the tail of the projects we started in ‘17, but as we look to the continuation of the PCB programs and other programs we will factor that in when we talk to you all after the third quarter decision with the board..

And that will fill in summer ‘19, but it won’t obviously do ‘20 except the way your board cycle and CapEx cycle works, is that correct?.

Yeah. That’s correct..

Okay. And as far as the rate case itself which has a 2018 test year, if I’m not mistaken, right, will that ,include because it's - you'll have some of the incremental 18 CapEx, but it won't 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 is, we're trying to finish all the details associated with that case. And as I mentioned earlier at the call, we would be putting out a press release or an 8-K associated with it. So you'll get details there. So please just be patient..

Okay.

But let me just ask in another way, in the past, when you’ve filed these rate cases, does it generally incorporate what the board may do on the - do you understand what I'm saying because if, let’s say you add, I don't know, just $50 million of CapEx to ‘18, based on what you guys are seeing, does that generally get incorporated in your rate case when you make your rate case filing?.

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

Okay. And then as far as the kind of again, we're going to bear with you as you said to make your filing.

But what are some of the, like Carty has already in rates, right, and so that would come in your big spend in ‘15 and ‘16 plus the wind, which is in rates, but what other?.

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

And then the 610 million, I’m just staying 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're spending in ‘17, was that incorporated in the last rate case or that’s incremental and that will be in this rate case?.

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

Okay. I won’t push you on that.

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

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

Okay. So the fact that [Technical Difficulty].

It’s based on a use per customer..

Right. Okay.

So customer growth is I guess more important than 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.

And what is your customer growth that you're forecasting for this year?.

I have not provided that..

Okay. That's fair.

Is it positive?.

It was about 1.3%, 1.2% last year..

Okay. That’s fine. I just want to see if there’s anything else. We went over the legal stuff. Infrastructure CapEx [indiscernible]. I think that's it. I think I’m good. I’m done..

Our next question comes from [indiscernible]. Your line is open..

My questions have been answered. Thank you..

Our next question comes from Kevin Fallon of Citadel. Your line is open..

Hey, guys.

I apologize if I’ve missed it, but what are you guys assuming for the strict Carty legal costs in ‘17?.

In ‘17, there's about $0.02 associated with it..

Okay.

And is this the last year that or should that go over the two to four year cycle to resolve this?.

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

Fair enough.

And then 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's the outstanding balance of those credits at year end ‘16?.

We'll follow up with you. I don't have that off the top of my head..

Andy, your line is open..

Okay. Thank you.

Just on how much debt are you guys going to issue this year if any?.

About $450 million is what we're estimating, about 150 is out, it will go towards repaying a bank loan that we've got out there and the balance will help fund the capital program that we've got going..

So it's 450 million of new debt?.

Yes. But that new debt, but as I pointed [Technical Difficulty].

Right. The bank loan.

And how much is the bank loan? What's the interest rate on them?.

It’s 150..

But what’s the interest rate on that?.

It’s LIBOR plus 63..

Okay.

And I guess the tenure of this debt will be what, like kind of average ten year 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..