Portland General Electric Co (POR) 2015 Q3 法說會逐字稿

Good morning, everyone, and welcome to Portland General Electric Company's third-quarter 2015 earnings results conference call. Today is Tuesday, October 27, 2015. This call is being recorded and, as such, all lines have been placed on mute to prevent any background noise. After the speakers' remarks there will be a question-and-answer period. (Operator Instructions)

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

Thank you, Vicki, and good morning, everyone. We're very pleased that you're able to join us today. Before we begin our discussion this morning I would like to remind you that we have prepared a presentation to supplement the discussion, which we'll be referencing as we go through the call. The slides are available on our website at portlandgeneral.com.

Referring to Slide 2, I'd like to make our customary statements regarding Portland General Electric's written and oral disclosures and commentary, that there will be statements in this call that are not based on historical 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. And, for a description of some of the factors that may occur that could cause such differences, the Company requests that you read our most recent Form 10-K and our Form 10-Q.

Portland General Electric's third-quarter earnings release was released via our earnings press release and Form 10-Q before the market opened today. And the release and the Form 10-Q are available at our website. The Company undertakes no obligation to update publicly any forward-looking statements, whether as a result of new information, future events, or otherwise, and this Safe Harbor statement should be incorporated as part of any transcript of this call.

As shown on Slide 3, 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 our lines up for your questions.

And now it's my pleasure to turn the call over to our CEO, Jim Piro.

Thank you, Bill. Good morning, everyone, and thank you for joining us. Welcome to Portland General Electric's third-quarter earnings call.

On today's call I'll provide an overview of our financial and operating performance, give an update on the economy in our operating area, discuss construction progress on our new Carty Generating Station, and provide updates on other initiatives affecting PGE. I'll then turn the call over to Jim Lobdell, who will provide more details on our financial performance and general rate case.

As presented on Slide 4, we reported net income of $36 million, or $0.40 per diluted share, in the third quarter of 2015 compared with net income of $39 million, or $0.47 per diluted share, in the third quarter of 2014. Although our financial results were lower quarter over quarter, I'm pleased with our solid operating performance and strong load growth, supported by continued positive economic trends in Oregon.

Construction on our Carty Generating Station is proceeding on budget and is expected to be completed in the second quarter of 2016. We have now settled all items for our 2016 general rate case with the OPUC staff and interveners, and we are affirming our full-year 2015 earnings guidance of $2.05 to $2.20 per diluted share.

Moving to Slide 5, our overall system performance was excellent for the third quarter, including achieving generating plant availability of 99%. Additionally, Uptime magazine named PGE the best reliability engineering for a maintenance program for generation. The award recognizes organizations that demonstrate excellence in managing equipment reliability using advanced strategies and high-tech sensing technologies.

I'm also pleased to report PGE continues to be ranked in the top quartile for customer satisfaction metrics for residential, business, and key customers according to Market Strategies International and TQS Research. We are continually striving to meet our customers' energy needs by delivering products and service that reflect their values.

Earlier this month we enhanced our nationally recognized renewable power program by offering a new, voluntary renewable power option for our customers called Green Future Solar. This program enables customers to support solar generation by participating in a program that is sourced through a shared local solar facility.

In September we released our 2014 Sustainability Update. It provides our 2014 highlights and key metrics, including five years of performance data. And it is designed to feature some of the ways we work to balance social, environmental, and economic impacts of our business decisions. This update is available for you at portlandgeneral.com.

Now let's move to Slide 6 for an update on the economy and our customers. Oregon continues to exhibit positive economic trends. In August Oregon's annual job growth reached a 10-year high, expanding by more than 60,000 jobs over the past 12 months. This is a 3.5% increase, is a milestone that hasn't been hit since 1997 during Oregon's high-tech boom.

September growth slowed slightly to 2.9% year over year; however, Oregon still added nearly 50,000 jobs. The unemployment rate of 5.4% in our service area for September compares favorably to Oregon at 6.2% and slightly above the US at 5.1%.

PGE's average customer count continues to increase at approximately 1% year over year. Portland State University Population Research Center reports 2014 population growth in PGE's service area at 1.4%.

Additionally, the Housing Construction Forecast from the Oregon Office of Economic Analysis calls for strong growth in the coming years, with housing starts in Oregon increasing from 15,000 in 2015 to almost 18,000 in 2016, and 23,000 annually over the extended horizon. Historically, approximately half of Oregon's building permits translates into new PGE customers.

Energy deliveries weather adjusted are down 1.1% for the third quarter and up 2.8% year to date 2015 versus 2014.

We have continued to see strong growth in the industrial sector, driven primarily by high-tech manufacturing. This is related to the growth of semiconductor and solar manufacturing, as well as the opening of two new datacenters in PGE's service area in 2015. Additionally, gains were seen in transportation equipment, driven by an increase in the number of ships in dry dock on the Willamette River this year.

There continues to be a lot of attention on the unseasonably warm temperatures in Oregon. While weather was warmer than normal this quarter, it was comparable to the third quarter of 2014. However, PGE did reach the second highest summer peak on July 30th of this year when temperatures reached 103 degrees.

Based upon the results of year-to-date energy deliveries and current economic indicators, PGE now expects 2015 weather-adjusted load growth to be approximately 2% over 2014 levels. This is net of approximately 1.5% in energy efficiency and also excludes one large paper customer who recently announced they are now suspending operations indefinitely.

Moving to Slide 7, we have provided an update on the Carty Generating Station, our 440 megawatt natural gas baseload resource under construction near Boardman, Oregon. Construction is on budget and the plant is expected to be placed into service during the second quarter of 2016 at an estimated cost of $450 million, excluding AFDC.

We've completed assembly of the heat recovery steam generator and successfully completed hydrostatic testing, an important milestone to test piping integrity. Overall construction on the project is 70% complete and we are starting the commissioning process.

On Slide 8 we have provided a summary of the Company's capital expenditure forecast from 2015 to 2019, and we are currently evaluating additional opportunities to invest in projects that provide value to our customers.

As outlined on Slide 9, the need for new resources to meet our customers' future energy needs will be evaluated through the 2016 Integrated Resource Planning process and detailed in a resulting action plan. This planning process involves stakeholder engagement, research, and analysis. It will evaluate many issues, including the need for additional energy efficiency, opportunities for demand-side actions, and replacing the output of our Boardman plant, which will cease the use of coal at the end of 2020.

In addition, the process will address how we plan to meet Oregon's renewable portfolio standard of 20% by 2020, which could be met through a combination of physical resources and the use of renewable energy credits. The plan will also evaluate the need for additional capacity to meet our customers' winter and summer peaks.

We will file the IRP with the Oregon Public Utility Commission in 2016, with the resulting action plan targeted to be acknowledged by the Commission in Q1 of 2017.

Last week the final EPA Clean Power Plan was published in the Federal Register. The final rule changed significantly from the draft rule, and resolves most major issues raised by PGE. Our company intends to be actively engaged with our stakeholders and the State's inter-agency team as we work together to determine Oregon's best path forward in implementing the plan.

Now I'd like to turn the call over to Jim Lobdell, who will discuss our financial results for the third quarter and provide you with an update on the 2016 general rate case. Following those prepared remarks we will open the lines for your questions. Jim?

Thank you, Jim.

Turning to Slide 10, as Jim mentioned, for the third quarter of 2015, we recorded net income of $36 million, or $0.40 per diluted share, compared with net income of $39 million, or $0.47 per diluted share, for the third quarter of 2014.

The difference in quarter-over-quarter earnings can be attributed to increased earnings for the third quarter of 2015 of about $0.04 from adding Port Westward 2 and the Tucannon River Wind Farm and higher AFDC from the construction of the Carty Generating Station. However, this increase was more than offset by a $0.06 decrease to earnings from several miscellaneous and other expenses.

The remaining $0.05 of the difference in earnings per share quarter over quarter was the result of an increase in the average share count from 80.2 million shares in the third quarter of 2014 to 88.8 million shares in the third quarter of 2015.

Moving to Slide 11, total revenues for the third quarter of 2015 decreased $8 million to $476 million. This decrease was primarily due to three items -- first, a $5 million increase in retail revenues due to the January 1st increase which included placing Port Westward 2 and the Tucannon River Wind Farm into service, higher energy sales partially offset by a decrease of supplemental tariffs and, second, a $10 million decrease in wholesale revenues and, finally, a $3 million decrease from other miscellaneous revenues.

Energy deliveries for the third quarter of 2015 were 0.6% higher than the third quarter of 2014, with a 0.2% increase in residential deliveries, a 0.9% decrease in commercial deliveries; and a 4.0% increase in industrial deliveries.

For the full year of 2015 we expect weather-adjusted load growth of approximately 2% net of energy efficiency and excluding one large paper company. This is a 0.5% increase from our previously disclosed load growth estimate.

Now onto power supply. Net variable power costs decreased $11 million quarter over quarter. However, NVPC was $6 million over the baseline of the annual update tariff due to unfavorable hydro and wind generation. This is in contrast to the third quarter of 2014 when net variable power costs were $5 million above the baseline.

Moving on to Slide 12, generation, transmission, distribution, administrative and other expenses totaled $123 million for the third quarter of 2015, an increase of $9 million from the third quarter of 2014.

Generation, transmission and distribution increased $4 million due to a $2 million increase due to higher operating and maintenance expenses from the addition of the Port Westward 2 and Tucannon River Wind Farm generating facilities, and a $1 million increase due to a partial write-off of the biomass inventory at Boardman and a $1 million increase in repairs and maintenance at our Port Westward 1 and Beaver plants.

Administrative expenses increased $5 million due to our combination of higher expenses, including legal and environmental services, information technology, pension, and other miscellaneous items.

Depreciation and amortization was comparable quarter over quarter and was impacted primarily by $7 million in higher expense in 2015 resulting from capital additions, offset largely by a $6 million reduction related to the amortization of deferred regulatory liabilities primarily related to the Trojan spent-fuel settlement.

Total interest expense increased $5 million quarter over quarter, with $3 million from lower allowance for borrowed funds used during construction and $2 million from an increase in the average balance of outstanding debt.

Other income decreased $8 million quarter over quarter, primarily driven by a $5 million reduction on AFDC equity, due to two plants being placed into service in the fourth quarter of 2014.

There was also a $1 million decrease in investment returns on the nonqualified benefit trust assets.

Moving on to Slide 13, as Jim mentioned, PGE, OPUC staff, and other parties reached an overall stipulated settlement that resolved all remaining matters in the 2016 general rate case. The key items in the settlement were a return on equity of 9.6%, a cost of capital of 7.52%, a capital structure of 50% debt and 50% equity, and a rate base of $4.4 billion.

The estimated net increase in revenues is $13 million, which includes the addition of the Carty Generating Station and results in an increase to customer prices of approximately 0.7%. The increase will be effective in two stages.

On January 1st of 2016, customer prices will decrease 2.4%, representing the change in base business costs and certain customer credits. Prices will then increase by 3.1% when Carty comes into service in the second quarter of 2016. The increase in revenues will be finalized in November after the final update to power costs and cost of debt have been submitted.

All stipulations remain subject to OPUC approval and the final order is expected before the end of 2015.

On to Slide 14. We continue to maintain a solid balance sheet, including adequate liquidity and investment grade credit ratings. As of September 30, 2015, we had a total of $631 million in cash, available short-term credit, and letter-of-credit capacity; $959 million in first mortgage bond issuance capacity; and a common equity ratio of 50.3%.

The Company has a $500 million revolving credit facility to meet the Company's liquidity needs, which has a maturity date of November 2019. The Company has additional letter of credit facilities totaling $135 million.

Regarding the Company's quarterly dividend, on October 22nd, the Board of Directors approved a quarterly dividend of $0.30 per share. Assuming PGE's ability to achieve current estimates for earnings and cash flow and depending on other factors influencing dividend decisions, PGE Management anticipates sustainable annual dividend increases of 5% to 7%. Over the long term, PGE targets a dividend payout ratio of 50% to 70%. The next annual review of the dividend will be conducted in April of 2016.

Moving to Slide 15 and earnings guidance, PGE is affirming its 2015 revised guidance of $2.05 to $2.20 per diluted share based on the following additional assumptions: Annual weather-adjusted load growth of approximately 2% over 2014, excluding one large paper company; below-average hydro conditions for the year; normal thermal plant and wind operations for the remainder of the year; depreciation and amortization expense between $300 million and $310 million; and capital expenditures of approximately $580 million.

Back to you, Jim.

Okay. We continue to focus on successful execution of our initiatives that drive value for customers and shareholders, including delivering operational excellence by meeting our 2015 performance targets; continuing construction of the Carty Generating Station; achieving an on-budget second-quarter 2016 in-service date; and working collaboratively with all our stakeholders to prepare our 2016 Integrated Resource Plan and its associated Action Plan to meet our customers' future needs with resources that provide the best long-term balance of cost and risk.

And now, Operator, we are ready for questions.

All right. Michael Weinstein; UBS.

On the rate case settlement, how do you anticipate the settlement will enable you to earn the authorized ROE of 9.6%?

What we see is it's more of a true-up. Because of the fact that we've been in rate case after rate case, our O&M expenses and other corporate expenses are closer to what we're incurring because of the true-ups that we've had with the general rate case.

We will continue to have a drag on the 9.6% associated with disallowed costs. There's about anywhere from 65 to 70 basis points that we'll be experiencing once we approach about a $4.5 million rate base. But that's -- we're feeling pretty good about it, Michael.

Okay, great. Just looking at the trailing 12 months, we're coming in looks like towards the low end of the guidance range. I know you said you're expecting a higher overall weather [NOI] sales growth for the year now. What are the positive factors that we're going to look for in the fourth quarter to make sure that we're still in the range, especially considering the higher share count?

Well, as you pointed out, we are looking at strong growth. When you look at the second quarter versus the fourth quarter there's a little bit of activity going on there in regards to adjustments. So, as we pointed out earlier, strong growth on the revenue side.

We're also, we're continuing to push on the O&M expenses associated with the organization. And we think between the combination of load growth and cost management that we'll be able to land within our revised guidance.

All right. And one final question, about the IRP. I know you guys talk about renewable credits versus new generation as both being able to satisfy clean power plant requirements going forward. Is there any way that you could quantify what the status is of your available credits? How many credits do you have? How long do they last? How many years do they have in them, and what that might mean in terms of new generation opportunities going forward?

We haven't disclosed the actual numbers, but we continue to build our [rec] bank because our loads have been under what our forecast was and the resources have been operating. So right now we think that there's enough credit that could take us two to three years beyond 2020.

And the question really is -- how do we utilize those credits in an economic fashion? A lot of it will depend on the discussions in the Integrated Resource Plan on the timing of adding a physical resource to meet our obligation and how we might smooth that out using those credits. So there's a lot of discussion to have with the parties on what's the right way to use that balance. But if we were just to use the balance it would potentially defer the need for resource out a couple years.

But that also (multiple speakers) -- oh, go ahead.

That isn't a final decision. That's just the way the numbers work out. Really the conversation has to be included in the IRP and a lot of it may have to do with how the production tax credits kind of play out over time.

And does that also assume -- that assumes that Oregon remains at a 20% RPS, right?

That is also. There has been a ballot measure that's been filed with the Secretary of State that would potentially increase that renewable standard. But that's really just in the early stages of discussion.

Interesting. Okay, thank you very much.

Paul Ridzon; KeyBanc.

Can you talk about what's going on with the wholesale sales volumes? Is it price or is it volume? Both?

Yes, Paul. What happened with the $10 million decrease in the wholesale revenues is the fact that when you look at our generation portfolio, most of our generation was committed to meeting our loads. And when we saw higher loads in the third quarter because of all of the temperature and exactly how the temperature showed up, that meant that we were more of a buyer on the marketplace than we were a seller. In addition to that, there was some movement in the overall wholesale prices in it, so.

Looking at year-to-date volumes, industrial sales are up 7.6%. Is there anything chunky in there? Or is that kind of similar to same-store sales? What's driving that?

What's driving it is a continued expansion of high tech. We're seeing -- we've got a couple of datacenters that have come into the service territory, in addition to we're seeing more transportation manufacturing, basically ship repair, going on in our service territory. Those can be some (multiple speakers) --

But nothing like you had a big customer down for an outage last year and they came back this year? It's all real organic?

Yes.

Wow. Okay. And then, just back to Michael's question on the fourth quarter. So we've got growth and some O&M controls. Can you kind of point which half of the guidance you think you could end up in? (Multiple speakers) --

No, I can't.

Okay.

I really couldn't do that at this point, Paul, but appreciate the question.

Thank you very much for your help.

Brian Chin; Bank of America.

I notice that for the guidance reiteration on page 15 you're looking at normal thermal plant and wind operations for the remainder of the year. A couple of your peers have commented on the impact of El Nino on wind operations. Are you just not really seeing that? Or can you comment on that at all?

I just don't think we know yet. It's still a very inexact science. Obviously wind has been down for the entire year. Third quarter we were actually pretty close to normal. So it's hard to tell what's going to happen in the fourth quarter. So rather than trying to pick a number we just said we're going to keep it at expected levels consistent with our budget. And then we'll just have to see where it plays out. These resources are fairly new and we're still learning a lot about how they operate in a very complex weather system.

Okay, got it. Secondly, noticed that there was a little bit of timing changes in some of the CapEx in terms of what year some of the CapEx spending would happen. It looks like some stuff that was in 2015 got pushed out into 2016. I apologize if you commented on this in your prepared remarks, because I missed part of the call. But is there any additional color you can provide on that? And if you already commented on that, then I'll just go back and look at the transcript.

No, you've got it right, Brian. There was just a bit of movement from 2015 to 2016. We did include in our CapEx table this time around the replacement of our customer information and meter data management system, but a lot of it is just timing.

Okay. And last one, because I want to be respectful of the queue. Last quarter you commented on bridge spending, the $58 million. And obviously it's probably a little too soon for you to give an update on that, but just how confident do you feel that there are additional opportunities on bridge spending that can be captured over the next call it like two or three years before the Boardman replacement question comes into play?

Yes, we're still looking in the distribution area. This is an opportunity for us to catch up on some of our reliability work that even though the system's in really good shape our underground needs to be addressed. We have environmental CapEx that we're going to need to do. So there's a number of things that we are looking at and trying to balance managing our prices as well as managing the reliability of our system.

So we haven't got a lot of visibility. There's a lot of work going on internally and looking at projects that we need to advance. And hopefully on our call next year we'll be able to give you more clarity on that as we kind of solidify those plans on what we need to do.

Great. Thanks a lot.

Michael Lapides; Goldman Sachs.

Congrats on a good quarter. Real quick, want to make sure I understood the commentary about thinking about the drag on earnings, on authorized earnings. Are you saying you still expect to have about 60 to 75 basis points of drag relative to the 9.6% authorized ROE for next year?

Yes, it's actually 65 to 70 basis points associated with authorized ROE. And, again, it's expenses like lobbying and advertising and incentives and a little bit of capital structure in there.

Got it.

But when you're up around a $4.5 billion rate base, that's what it pretty much pencils out to be.

All right. So that would imply you earn somewhere close to about a 9% ROE next year. When we think about 2017, is there much of a step up in the weighted average rate base in 2017 over 2016?

Rate base right now looks like it's going to be relatively constant until we get to the next decisions around the IRP resources. We'll be doing, as I mentioned earlier, some work on the distribution system, some reliability and environmental adds. But I think generally we'll be keeping it relatively flat until we get some clarity on the new resources and go through the RFP process.

Right. But the $4.4 billion, that's a weighted average, so only has half a year of Carty in it and therefore the second half -- that alone would potentially give a little bit of an uptick in 2017? Or am I mis-thinking about this?

I think the $4.4 billion includes the full year of Carty.

Yes. At the beginning of the year it's about $4 billion and by the time you get to midyear you're at $4.4 billion. So you're about $4.2 billion average for the year.

Got it. Okay. I appreciate it, guys. Thank you.

Andrew Weisel; Macquarie Capital.

You've touched on a lot of the big issues. I've got a couple of small relatively quirky questions I just want to get your quick thoughts on. First, there was a comment in the press release that the rate case is predicated on Carty entering service by the end of July. What happens if hypothetically you get a little bit of a delay on Carty and it runs past there?

Well, right now July 31st is the end date. We have to have it in service by that date. If not, it really will depend on what the reasons for the delay are. But in kind of the worst case we'd have to refile a rate case to include that into our prices. But, again, I think it'd have to be circumstantial. We don't see that as being very likely. We'd have to see what would be the cause of the delay, whether it's factors that we had control of or something that's totally outside our control, like some type of weather event or force majeure type of an event.

So right now all indications is the plant will be completed by that date. But if it were not, then we'd have to go to the regulators and talk with them about some type of interim rate relief or rate case filing.

Okay, great. Hopefully that won't come into play. Next question -- the tax rate was relatively low in the quarter. Just if you could comment on your expectations for the full year and maybe looking even beyond to next year for tax rates?

Yes. For this year I would think about an effective tax rate of 20% to 25%. PTCs are coming in a little bit better because of the wind ticked up in the third quarter. So that was a good positive for us.

Going forward beyond the current year I'd just look at the statutory rate at this particular point in time. There's too many moving pieces for us to give any guidance.

Okay, great. Then, two other quick news items I just wanted to see if you could comment on. One, a bunch of utilities are suing the Oregon Department of State over this quasi tax, the energy supplier assessment. Is that anything that could move the needle either for investors or for rate payers?

No. That's a really small, relatively small, tax. It obviously affects the PUDs quite a bit. I think it's going to be a tough battle for them to win that issue. But it's going to be small.

Okay, great. And then, lastly, there's an initiative from some environmental groups to eliminate all coal-fired resources. Obviously you have your plans for Boardman, but in terms of some of the stuff over the wires, is that something that might affect your long-term planning?

We have to obviously consider it. The ballot measure that's been filed with the Secretary of State says no coal by wire by 2030. We're obviously owners in Colstrip 3 and 4, which would be our only remaining coal resources. We own 20% of units 3 and 4. That would have an impact on our ability to use Colstrip to meet our customers' load. It doesn't talk anything about shutting the plants down. And so those plants, under this legislation, would still be available for some purpose, not clear what, in terms of probably wholesale sales or some other market activity.

The other part of that measure is an increase in the renewable portfolio standard to about 50% by 2040. It kind of ramps in over time. Again, that's just a measure. It hasn't got the signatures yet and the title hasn't been confirmed. So those are things that are moving forward. I will tell you we are in conversations with environmental groups and others about kind of where we need to be and the progress we're making on the current RPS standard.

Okay, great. If that RPS were to be increased, is your assumption that you would continue to own some portion of the renewables in rate base?

Our preference would be to own these resources. They're very strategically located. These are usually the best sites as they kind of get ticked off and picked off. And so, our desire, because this RPS standard's not going to go away, it's going to be a long-term obligation of the Company, we'd really like to own these sites because that preserves the value of those resources for our customers long term.

But, again, we would have to go through an RFP process. We would likely put in our own benchmark resources to compete in the market. But our desire would be to own resources to meet that obligation because of the long-term nature of that obligation.

Okay. Thank you so much.

Sarah Akers; Wells Fargo.

With the RFPs commencing in 2017, how long do those processes typically last? And when's the earliest you could be in construction on any of the related self-build projects there?

Well, the way I would think about it, assuming that we get the order from the Commission Q1 of 2017, it's going to take us probably three to six months to get the RFP prepared and ready for the marketplace.

And so we'd probably issue the RFP towards the end of 2017. Hopefully by the end of -- middle of 2018 we'd be able to reach a decision on the RFPs and start progress on the project. So, hopefully by the middle of 2018, possibly towards the end of 2018. Again, Boardman shuts down at the end of 2020, that's the real key important date.

As it relates to the renewables, as we mentioned earlier we have some flexibility on when we need to add the renewables. The timing of the renewables will depend on discussions with all the stakeholders, as well as what's going on in the market related to production tax credits and other projects that might be competing for those renewables.

Got it. Thank you.

So that's kind of timing as we look ahead.

Perfect. And then a follow-up to Brian's question on the bridge spend. Is rate basing of gas reserves still on the table? And, if so, would that be addressed in the IRP?

We are not addressing it in the IRP. We pulled it out of the IRP. We are conducting discussions with all the stakeholder groups about where we see the value of the long-term hedging. And that's really where the conversation starts, is we think where gas prices are and the fact that we have a pretty significant need for natural gas to fuel our power plants, that a long-term hedge would provide value for our customers of some percentage.

So we're in discussion with the stakeholders on kind of the structure of that hedge, how we would do it, what risks and rewards we take and the customers take around a gas reserve strategy. And so those conversations are going forward. And so we're doing it outside of the IRP process and we're still working with all the customer groups in terms of trying to understand how we would execute on that plan. So hopefully we'll continue to make progress, and the team is working hard on that strategy.

Great. And then last, can you just give the EPS impact of weather versus normal for the quarter?

Yes. For the quarter it really was $0.07. But we looked at this quite a bit and you really need to take the third quarter and the second quarter of 2015 and put the two of them together. If you recall, the second quarter was down $0.07. Now the third quarter is up $0.07. So you really net zero for 2015. And then when you compare it to 2014, we were down $0.05 in Q2 and up $0.03 for Q3, so you're really down a total of $0.02. So you kind of look at the comparison of year over year from normal and say we're better by $0.02. Hopefully that helps.

Perfect. Understood. Thank you.

Lauren Duke; Deutsche Bank.

So, following up on the weather impact discussion you were just having with Sarah, can you give us the weather impact versus normal for Q4 last year? Because I believe it was quite warm.

For Q4 -- it's about down $0.04.

Okay. And then, can you talk a little bit about your rate case plan going forward? Now that you have the new plants kind of addressed under the rate cases that are passed and the one that's still underway, can you talk about how we should think about your rate case plan, if you're going to try to stay out until you have major new rate base sources or if we should think about you continuing to file fairly regularly?

So, the way we think about it is a couple ways. First of all, you have to understand that we do track and power cost each year through our Annual Update Tariff. So changes in power cost would be adjusted each year through the Annual Update Tariff. And so that will continue forward. So to the extent natural gas prices go up or down or energy prices for electricity go up or down, those would be passed on customers through the AUT filing.

So the other thing we have to address is our O&M increases and any changes in rate base. And so that is really going to be dependent on load growth. To the extent we continue to have strong load growth that will provide us some margin to cover those increases and inflationary costs. And to the extent we have flat load growth or declining load growth, then that will be kind of a pressure on our prices.

So typically as we've looked at the Company about every other year would be a time that we would go in for a general rate case. But a lot of it depends on those factors, our ability to control O&M, where load growth is, and kind of what the inflationary pressures are on our costs.

So we would hope to stay out for 2017. We'll just be putting our budgets together for 2017. We haven't made a final decision on that yet, but we're looking at everyone's budgets for 2017 and looking at our load growth for 2017 to kind of get a sense of whether we can take a period off for 2017. We'll probably make that decision late this year or early next year. We really wouldn't have to file a rate case until February of 2016 for a 2017 price change.

So that's kind of what we're thinking about right now. But if you looked historically, when we don't have new resources coming online, every other year or every couple of years is kind of what our pattern would be. But, again, it's depending on those factors that I just discussed.

Thank you very much. One final question -- with load growth coming in significantly stronger than you had originally forecasted this year, is that something that seems sustainable at least for the next year or two? Or are you kind of still in wait-and-see mode to see if this can carry through to next year?

Well, a lot of it's been driven by some of our large customers, specifically Intel and the growth they've seen added in Hillsboro with B1x in their facility. So I don't think that is ultimately sustainable. I think there are some really good factors going on in Oregon around economic growth. This is really a hub for high tech and software developers. So we've seen a lot of in-migration and good, strong growth. Whether that will continue on long term, there's many factors that affect that.

You have to understand that that growth right now will be picked up in our 2016 rate case as we adjust our forecast. So our loads and our costs will be aligned going into 2016.

Okay, great. Thank you very much.

Mark Barnett; Morningstar Equity.

Thanks for all the detail today on the call. I just want to ask a question that perhaps you won't be able to give too much color on. But we're talking about availability of resources in the region and you'd addressed maybe the coal issues in the future, bringing it into the state. But Colstrip itself in its own state is also under pressure. I'm just wondering how you see that developing with the kind of few bills that we've seen introduced in the Washington legislature this year.

Well, besides the legislation that's been discussed up in Washington, Montana's got a significant challenge to the Clean Power Plan. If you look at that plan, Montana has some pretty significant hurdles that they have to achieve. And that's going to also have an impact on the coal projects in Montana.

So there are -- obviously Montana's challenged that legislation in the courts, along with a number of other states. So we're going to have to see how that all plays out. Puget and the conversations they've been having up in Washington -- Puget's a 50% owner of units 1 and 2. And so that's been kind of the early talk around what's the fate of units 1 and 2, since those are the older, more inefficient units up there.

So there's lots of conversations going on around Colstrip and it's hard to tell how that's all going to play out. We're going to have to watch Puget's lead up in Washington as they think about their strategy and working with their legislature.

Okay. But ultimately it makes sense to kind of view the Clean Power Plan as the larger risk to availability of that over the longer term I would imagine.

Yes. I think that's -- I mean, clearly, those are rules that have to be promulgated. And as I understand the Clean Power Plan, if the state doesn't take action the federals can move in and put their own federal implementation plan in place. They're very stringent up in Montana. I'm not sure how Montana's going to achieve those goals. They clearly would require some shutdown of the coal plants to meet the mass base goals that have been set for Montana.

So more to watch on that. Obviously we'll have to see how the rules play out in the courts. And I think we're early in the game in this process, so more to come.

All right. Thanks.

Justin [Morrow]; [Boyd Abbott].

I can't let it go by without asking a dividend question. So, I believe you guys talk dividend policy once a year in the spring meeting. Is that correct?

That's correct.

And so, obviously with CapEx coming down, you guys have talked about the next wave of CapEx opportunities, so you want to hold back on that. But if you do the simple math on your current run rate on modest earnings growth next year it gets you to the lower band of the 50% to 70%. So I'm just curious. You talked about 5% to 7% divi growth, but if earnings kind of grow at that rate anyway, how does that percentage move up over time?

Well, as you mentioned, every spring we do a complete dividend review. We look at our CapEx forecast. We look at the capital structure. We look at the need for equity as we think about another construction cycle and potentially not having to go to the equity markets to finance that. So those are all the factors that go into that. And we want to make sure we have a balanced cap structure, but we also want to allow ourselves some flexibility going into a construction program.

So it's hard to handicap it right now. A lot of it depends on earnings, too. So there's many things that we go into that. We are committed to the dividend. We're committed to a good payout ratio that's within the range that we provided. And so we will continue looking at that. So those are all the factors that go in there. And you'll hear more about it next April, 2016, when we release the final number.

But you ask the right questions, same questions we're asking. And we'll take those all into account as we make the decision next year.

Well, again, I think most people understand and appreciate the wanting to hold that back for the IRP, given it's not that far away. But the fact that -- I mean, unless you guys think, and I don't think you do, that earnings should grow at some rate below that, that percentage won't move, all things equal. Right? It will always be at the lower band, at the lower end of the band.

Okay. I think you're right. And we'll have to continue looking at it.

Thank you.

(Operator Instructions) Michael Lapides; Goldman Sachs.

Little bit of just an accounting question. Interest rates are up and treasury yields and corporate bond yields are obviously down. Can you walk us through what the impact on pension would be for the future, meaning next year, maybe even a little beyond?

Well, the greatest impact for the pension for us is the discount rate. And if we see a forward movement upward in short-term interest rates -- not short-term, but in interest rates -- then we'll see the funding associated with it go up, so the funding status that is associated with the pension plan go up. Beyond that, we don't see much other changes, because it's a closed plan.

Got it. So in other words there's no real O&M impact on next year, given the fact the 10-year is hovering around 2% and corporate bond yields are back to kind of historical lows?

Yes, the only movement, again, would be the returns in the plan and the discount rate.

And maybe just an update for you on the PUC process. Why don't you give them that (multiple speakers) --

Yes, good point. So we had a pension docket down at the Oregon Public Utility Commission associated with trying to get not only recovery of the expense associated with the pension service costs for the plan, but also a return on the investments that we have made, basically the contributions we have made into the pension plan. The outcome of that docket was a decision in August that basically said what we will recover is only the FAS 87 expense associated with the Plan.

So right now our FAS 87 expense and what we're recovering in rates is pretty much on top of each other at this point.

Got it. Okay. Last thing, I want to make sure I understand. You talk about in the Q and in some of your prior details some rate credits and kind of regulatory amortizations, two tranches of $28 million of credits that roll off. How much of that goes to reduce D&A next year? And how much is for other items?

Well, most of it is just revenue reduction. And it's things like the settlement associated with the spent fuel at the Trojan nuclear plant. It's the residential credit from the Bonneville that we have out there. And there's a whole series of others. I can have Bill Valach give you a follow-up, because there's a lot of details back behind that, a lot of small pieces.

Happy to do follow-up. Thanks, guys. Much appreciated.

Okay, I think that's all the questions we have in the queue. So let's close this up. We appreciate your interest in Portland General Electric and we look forward to seeing many of you at the upcoming EEI Annual Finance Conference in Florida. Thanks a lot and have a great day.

Ladies and gentlemen, thank you for participating in today's conference. This does conclude the program. You may all disconnect. Everyone have a great day.