Chris Liddle - Manager of Corporate Finance & Investor Relations Jim Piro - Chief Executive Officer Maria Pope - President and incoming Chief Executive Officer James Lobdell - Senior Vice President of Finance, Chief Financial Officer and Treasurer

Julien Dumoulin-Smith - Bank of America Merrill Lynch Christopher Turnure - JPMorgan Paul Ridzon - KeyBanc Capital Markets, Inc. Michael Lapides - Goldman, Sachs & Co.

Travis Miller - Morningstar Paul Ridzon - KeyBanc Capital Markets Inc

Thank you, Ayeia. Good morning, everyone.

I’m pleased that you are able to join us today. Before we begin our discussion this morning, I would like to remind you that we have prepared a presentation to supplement our discussion, which we will be referencing throughout the call.

The slides are available on our website at investors.portlandgeneral.com. Referring to Slide 2, I would like to make our customary statements regarding Portland General Electric’s written and oral disclosures.

There will be statements in this call that are not based on historical fact, and as such constitute forward-looking statements under current law. These statements are subject to factors that may cause actual results to differ materially from forward-looking statements made today.

For a description of some of the factors that may occur that could cause such differences, the company requests that you read our most recent Form 10-K and Form 10-Q. Portland General Electric’s third quarter earnings were released via our earnings press release and Form 10-Q before the market opened today, both of which are 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, CEO; Maria Pope, President and incoming CEO; and Jim Lobdell, Senior Vice President of Finance, CFO and Treasurer. Following their prepared remarks, we will open the lines for your questions.

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

Thanks Chris. Good morning, everyone, and thank you for joining us.

Welcome to Portland General Electric’s third quarter earnings call, and my final call as PGE’s CEO. It’s been an honor to serve all our stakeholders in this capacity, and it’s my great privilege to hand the reins over to Maria, who will take over for me as CEO and join our Board of Directors on January 1.

Maria brings to this role a broad range of experiences and competitive field, including banking, forest products, apparel manufacturing and high tech, that has prepared her to take on the challenges and opportunities inherent in today’s fast-changing energy marketplace. I’m pleased to have a leader with Maria’s capabilities who will continue to champion the interest of our customers, community and shareholders and ensure that we will continue to deliver safe, reliable and affordable energy to our customers.

You will hear from Maria later in the call. Now let’s turn to Slide 4 to review our financial performance.

We reported net income of $40 million, or $0.44 per diluted share in the third quarter of 2017, compared with net income of $34 million, or $0.38 per diluted share in the third quarter of 2016. Our strong earnings were the result of an increase in energy deliveries across all customer groups related to increased customer count and usage, as well as favorable weather conditions.

These results were partially offset by higher power cost, an increase in depreciation and amortization, a decoupling adjustment and higher taxes. We remain pleased with the strength of our local economy and the growth of our customer base, and we are reaffirming our full-year 2017 earnings guidance of $2.20 to $2.35 per diluted share.

Now on to Slide 5 for an operational update. Our employees and systems performed exceptionally well during the August heat wave, demonstrating reliability and resilience during the stress of sustained high temperatures of more than 100 degrees over several days, setting an all-time summer peak of 3,976 megawatts on August 3.

Overall, our generating plant availability for the quarter was excellent at 96%. Additionally, we continue to be ranked in the top quartile for customer satisfaction for residential business and key customers according to Market Strategies International and TQS Research.

On to Slide 6 for an update on the economy and our customers. This week Portland took the top spot on Forbes annual ranking of the Best Places For Business And Careers based on its strong economic outlook and surge of talent.

While employment growth has slowed compared to the last two years, as the economy reaches full employment, unemployment in our service area remained low at 3.9% and lower than the U.S. rate of 4.2% for September.

Recently released data shows growth of 8.7% in Portland’s median household income for 2016. This was the fourth largest annual percentage change in the nation.

The continued strength of Oregon’s economy contributes in our total customer count of approximately 1.3% compared to the third quarter of 2016, and building permit trends suggest continued growth with an increase in year-to-date building permits of 6.4% in our service area, compared to 5.7% nationally. As we forecasted at the beginning of the year, we continue to expect weather-adjusted energy deliveries in 2017 to decrease between 0% to 1% year-over-year, primarily driven by ongoing energy efficiency efforts, which are lowering the residential and commercial load growth rates.

However, during the next few years, we expect to transition back to long-term positive annual energy delivery growth of approximately 1%, which is net of 1.5% reduction in deliveries due to energy efficiency. This outlook is based on the extension of growth in the high-tech sector, including several recent announcements of new data centers and the continuation of strong in migration.

Turning to Slide 7, I’m pleased to share that this quarter, we reached agreement on all issues of our 2018 General Rate Case with the Oregon Public Utility Commission staff and the participating stakeholder groups. We expect a final order from the Commission later this year.

The primary driver of this case was support for investments we’re making to keep the – our systems safe and reliable. Specifically, this includes our efforts to strengthen the power grid with earthquake protection measures and improved cyber security.

Replace an upgrade aging transmission and distribution equipment and substations and entering into the Energy Imbalance Market, which we joined successfully on October 1. Jim will go into more details around the terms of our settlement shortly.

Now I’d like to turn the call over to Maria, who will share an update on our recent entry into the Energy Imbalance Market and the status of our 2016 integrated resource plan.

Thank you, Jim. On behalf of all of us at PGE, we’re enormously grateful for your leadership and your dedication to all PGE stakeholders.

Your unwavering commitment to operational excellence challenged us to embrace new technologies and constantly benchmark our operations against the very best, driving us [indiscernible] operating performance. Moving on to Slide 8.

With our entrance into the Western Energy Imbalance Market, we’re now buying and selling energy on a five-minute interval, which helps us to better integrate renewable energy and lowers the cost for customers. Turning to Slide 9.

In August, we received acknowledgement of the majority of our 2016 integrated resource plan in order to meet our capacity need 350 to 450 megawatts, we remain engaged in bilateral discussions with owners of existing regional resources. Additionally, we requested a waiver from the OPUC competitive bidding guidelines.

If granted, we will work towards definitive agreements. We expect that this process will result in an outcome beneficial for all stakeholders.

And as such, we plan to withdraw our air permit applications for thermal resource development at the Carty 2 and 3 sites. In August, the OPUC passed on our proposed action on renewable resource and requested that we continue to work with parties on a revised plan.

We presented our revised plan to the Commission earlier this month, which reduces our request for renewable resources to 100 average megawatts from 175 average megawatts. The Commission has asked us to file a formal IRP addendum, which we will file in mid-November and hope to receive a response from the Commission in the first quarter of 2018.

This is an important step as we continue to work towards Oregon’s 50% 2014 Renewable Portfolio Standard. Additionally, we will be moving forward with an RFP process for renewable resources in parallel.

So as to ensure adequate time for bidders to capture 100% production tax credits, which means completion of a construction by the end of 2020. We have identified a potential benchmark resource and are engaged in negotiations.

Pursuant to the OPUC acknowledgment of our IRP and in accordance with House Bill 2193, we will file an Energy Storage Proposal by mid-November. We propose about 39 megawatts of energy storage to be developed over the next several years, which will include a number of projects in a variety of locations, including existing generation, distribution and customer sites.

The capital cost of the projects is estimated to be between $50 million and $100 million, which is not included in the capital expenditure forecast. And now I’m pleased to turn the call over to Jim Lobdell.

Thank you, Maria. Let’s move to Slide 10 for an update on our 2017 General Rate Case.

PGE, OPUC staff and parties reached a stipulated settlement that resolved all remaining aspects of the case. The two key – the key items are a return on equity of 9.5%, a capital structure of 50% debt and 50% equity, a rate base of $4.5 billion and an increase in the cost recovery for major storms from $2 million to $2.6 million.

The settlement reflects an estimated increase in customer prices of approximately 1.2% effective January 1. The change in prices will be updated for power costs in November and finalized in December following a Commission order.

Moving on to Slide 11, we provided an update on the Carty Generating Station that went into service in July 2016. As previously noted, we’re pursuing legal action against Liberty Mutual and Zurich North America, the two sureties who provided the performance bond in connection with the Carty construction agreement.

On July 10, the Ninth Circuit Court of Appeals held at the International Chamber of Commerce tribunal will decide whether the lawsuit is arbitrable in the International Court of Arbitration, an evidentiary hearing on this issue is scheduled for April 9, 2018. For more details, please refer to our 10-Q.

On to Slide 12, which shows our earnings drivers for the quarter. First, gross margin increased earnings by $0.13 due to the following: an $0.08 increase due to favorable deliveries in all customer sectors, reflecting an increase in customer count; and average use in the residential sector; an increase in commercial irrigation and pumping loads and continued expansion in the high-tech sector; a $0.06 increase due to favorable weather and a $0.01 increase for other miscellaneous items, partially offset by a $0.02 increase in the estimated refund from the decoupling mechanism.

Second a $0.03 decrease due to higher depreciation and amortization expense due to capital additions, followed by a $0.02 decrease related to an increase in our effective tax rate, primarily due to lower federal and state tax credits. And finally, the $0.02 decrease due to miscellaneous items.

On to Slide 13, we have provided a summary of the company’s current capital expenditure forecasts from 2017 to 2021. We have changed the presentation of our capital forecast to include five years of expected investments to provide safer and more reliable service to our customers.

This outlook reflects the results of our strategic asset management efforts, which take into account, age, condition and other factors. Some examples of these efforts include substation reliability upgrades, PCB transformer testing and replacement, underground cable replacement; third, a hydro repowering; system, seismic and cyber security hardening and the West Side hydro structural and reliability upgrades.

Additionally, we are investing in a new customer information system and technology tools called customer touchpoints, which is scheduled to go live in the second quarter of 2018, as well as the foundational work necessary to offer customers more flexibility in pricing and program options. This investment is one of the factors into considerations, as we evaluate the need for a 2019 General Rate Case, which we will update on our plans at our next earnings call.

Finally, we have not included any capital expenditures on this slide related to potential projects pursuant to our 2016 integrated resource plan. On to Slide 14, we continue to maintain a solid balance sheet, including strong liquidity and investment grade credit ratings.

On July 20, S&P revised PGE’s outlook to positive from stable based on incremental improvements in the utility’s business risk profile. For 2017, we’re issuing $225 million of first mortgage bonds at an interest rate of 3.98%, $75 million funded in August, maturing in 2048, the remaining 150 will be funded in November and maturing in 2047, and will be used to repay the remainder of our bank loan due next month.

In addition, we do not expect to issue additional first mortgage bonds this year. As shown on Slide 15, we are reaffirming our full-year 2017 earnings guidance of $2.20 to $2.35 per diluted share.

Currently, we expect to be towards the middle of the guidance based on the following assumptions: a decline in retail deliveries between 0% and 1% weather adjusted; normal hydro conditions for the remainder of the year based on current hydro forecasts; wind generation for the remainder of the year based on five years of historic levels, or forecast studies from historical data is not available; normal thermal plant operations for the remainder of the year; depreciation and amortization expense between $340 million and $350 million; and operating and maintenance expense between $555 million and $575 million. Back to you Maria.

Thank you, Jim. Over the past year, the officer team has been working with our Board and our corporate strategy to respond to market forces.

Throughout the process, [indiscernible] and we will be engaging with our regulatory on strategy as we move forward. We know that the world is changing driven by rapidly evolving technology and new customer expectation.

In addition to providing safe, reliable and affordable energy, our customers also want cleaner and more secure energy. We’re working to incorporate more renewable; reduce carbon emissions, including within the transportation system; and then identifying new cost-effective technologies to help manage those.

For example, the City of Portland and Multnomah County have established a goal to meet 100% of their community-wide electricity needs with renewables by 2035, and 100% of their community-wide energy needs with renewable energy by 2050, and we expect more to follow. To meet our customer’s changing needs, we’re exploring additional smart grid investments, including the reliability investments that Jim outlined earlier.

As you can see on Slide 16, at a very high level, these include investments, implement and management solutions that meet consumers resiliency and sustainability needs, including new communication systems, distributed automation and data analytics. Investments to seamlessly integrate our customers energy resources, such as distributing generation and further investments in battery storage technology to provide grid stability, flexibility and the capability to integrate additional renewable energy.

These smart grid initiatives create an opportunity to engage our customers, optimize our assets and maintain a high reliable power service for our customers that they come to depend upon. At the same time, we remain committed to meeting our operational and financial goals and maintaining our high level of customer satisfaction with continued emphasis on employee and public safety.

As our plans continue to develop, I look forward to sharing more details with you. And now, we’re ready and available for questions.

Hey, good morning. Congratulations, Jim, and a very formal – warm welcome here to Maria.

Thank you. Welcome, Julien.

Thank you.

Good morning, Julien.

So perhaps just first on the capital budget, good job there. Curious how do you think about a run rate on spending?

Obviously you all look every year around this time at your capital budget, so you’ve kind of seen a pretty mature uptick here. How do you think about this relative to sort of the ongoing rate?

You’ve discussed a certain cadence of substation investments, et cetera, or actually could we see a further acceleration in light of some of these other elements you’ve discussed, smart grid, et cetera? And again, I’m excluding for the purpose of this conversation, the very discrete generation items we all know about?

Okay. Good question, Julien.

So as I mentioned in my talking points, we’ve been looking at our distribution system very, very closely. We’ve got like 186 substations, and 69 of those have been identified as high risk.

We’ve got a lot of aging cable that’s out there, that’s from the 1960s to the 1980s. And then we’ve got some segments of our system that really present some high risk to our customers.

So we’re continuing to focus on that. The uplift in the CapEx table really reflects what we have in front of us as far as what we think we know for cadence for the next few years.

We do see that it will carry beyond that, but I’m not at this particular point in time ready to put that in the CapEx table. In addition, as Maria had pointed out, there is other work that we planned to do to the system beyond trying to maintain it and preserve it that she is alluding to and we’re working through those particular plans at this point in time.

And as Maria pointed out, we will provide you more detail about that in future calls.

All right. So just to be clear on that, we should not necessarily expect to wait until the next year’s third quarter call for kind of an update on those other items you just alluded to?

Well, I can’t tell you that at this particular point in time. Like I said, we are still working through our plans.

Got it. Okay.

All right, fair enough. Then coming back to those discrete generation items, can you talk a little bit about how you think about the use of unbundled RECs as part of this new average 100 megawatts?

And then secondarily, with respect to the waiver, how are the negotiate – if I’m framing this appropriately, how are the negotiations going with respect to potentially soliciting and acquiring other asset outside of the competitive process? Presumably if you got this waiver, you would have some generation in hand already to file as an alternatives, right?

Good morning, Julien. Let me take the second part of your question first.

With regards to the waiver, we expect to receive that in the beginning of December, and we are currently in discussions with parties on existing resources in the region. And we’ll have more to discuss probably in the first and second quarter calls with regards to how those materialize.

But we would expect to be able to move forward with those. We have a very healthy list of interested parties.

With regards to your first question, with regards to RECs. The REC situation we have in Oregon is highly complex.

We have unbundled RECs. We have – and then we have different RECs with different lengths of time to be used, some of which we call golden RECs.

And we look at all of these as we look at our REC balance. And as we move forward with a RFP for 100 average megawatts renewable projects and the process with the OPUC, we will be managing our REC balance, so that we do not build given the earlier than the excess RECs we currently have.

So we will not be building our bank with this new renewable project that we are proposing.

Got it, okay. So but just to be clear there’s still the potential here to move forward with 100 average megawatt generation solution, it doesn’t – from your perspective, you don’t necessarily need to be depending on RECs here, just to be clear?

No, we have a healthy REC balance that we currently have and existing. And when we – part of our proposal to the OPUC was that, we would not build in the next couple of years that REC balance with this new project.

Yes, and just to add…

All right.

We’ll be divesting those RECs that would be generated from that project into the market.

Yes, just to be clear, this is a physical asset. This is not buying 100 megawatts of RECs.

Yes.

This is buying physical asset. We go short energy with the closure of Boardman at the end of 2020.

And so this is the fill in that short position.

Right, right. But your proposal would be to pursue the physical generation for the full 100 megawatts?

Yes.

Right. Yes, exactly, sorry.

Yes it’s through pursuing of the physical generation that we’re able to take advantage of the production tax credit and lower cost quite substantially.

Absolutely. Thank you all very much.

Good morning, Chris.

Good morning, Chris.

Good morning, guys, and congratulations again, Jim.

Thanks.

I wanted to just get a sense as to the regulatory strategy over the next several years. I understand you will update us on the fourth quarter call.

But I guess, a good way to frame the question would be, what prevents you from having to file next year and the year after? Is it better than expected load growth outlooks, or high-cost discipline, what would get you to that point of not having to file?

Chris, those are all the things that we’re evaluating at this particular point in time. So I’m not done with that evaluation.

I haven’t had conversations with all the stakeholders about the opportunity of filing an 2018 – or 2019 case here.

Okay. And can you just kind of refresh our memory or my memory on the potential for regulatory lag in the near-term?

It still is around 70 basis points.

Okay. And then just on the financing strategy the capital plan is taking a pretty big step up today, obviously, which is great to see.

How much maybe debt capacity do you have on your balance sheet right now to be able to absorb that extra CapEx?

I think we have bonding capability of probably close to $1 billion. We do not see issuing any equity out there in the near-term.

I think, the only time we get close to considering equity might be around a new large generating resource.

Okay. So we can kind of rely on that for the planning horizon of CapEx as it’s laid out right now, excluding generation no equity needs for that?

Currently, yes.

Okay. That’s very clear.

Thank you.

Thank you, Chris.

Good morning, Paul.

Good morning. Just wanted to reiterate that the CapEx forecast you laid out today does not include anything fossil or wind currently pending before the commission?

You’re correct, Paul, it does not.

Okay. And then what was the wind capacity factor in the quarter, or how much of a headwind was the wind, as I understand, it was below normal?

[Multiple Speakers] I should know that off the top of my head, the capacity factor is not going to be there, just give me a second, and I’ve got here at some place. Do you have another question?

Yes, you’ve talked in the slide deck about Carty litigation being a two to four-year process. Is that from today or from the original start of a litigation?

No, I think that is from today. Given where we are, the ICC process have to commence, they will not start until April 9, and that just determine the arbitratable most of the issues.

And then we have to get pass that to the evidentiary part of that. But I think our case is still very, very strong, but it’s just going to take time to get through that entire process.

And how should we think about the trajectory of the litigation costs and the financing costs is – are we going to have that for the next few years?

Yes, the depreciation and the return on a piece of capital that’s not covered under that allowed incurring customer prices will continue to be a drag on earnings. I think we said, it’s around $0.09 to $0.10.

We see that continuing. No legal cost to go up and down based on the activity of the cases.

So we’re trying to manage as close as we can. We believe we have a strong argument to recover those litigation costs in addition to the capital costs so.

That’s $0.09 to $0.10, including litigation?

Yes.

And Would that be recoverable from – would that be damages you pursue from the demand – the contractor, or would you try to get that from [indiscernible]?

No, we believe that’s part of the surety bond that that allows us to recover those costs, and we will include that in our claims against the sureties, and then ultimately the guarantee with having go.

That’s all my questions. If you haven’t found that, you can – the capacity factor, you can just interject, I guess later in the call?

No, Paul, it was in the mid-20s for the quarter, and it was actually 16% below quarter-over-quarter. So it’s about 25% is what we’re expecting.

Yes, just a little more color on that, we had extremely hot weather in the quarter. And when we have that hot weather, at least the way the wind blows in the gorge, the wind doesn’t show up when we have those hottest days.

And so that’s kind of consistent with the high lows that we saw a lower wind capacity factor.

Yes.

Paul, I correct myself, it was about 30%. It was down 25% from what we’re expecting.

About 30%, down 25%?

30% was the capacity factor for the quarter.

For all three?

Yes, for all the units.

And how should we – that weather phenomenon you talked about, when it’s hot the wind doesn’t blow, how does – what does that do to earnings? Is it net neutral, because you pick up higher load, or there’s no hard and fast rule, I guess to think about?

There’s no hard and fast rules. I’ve But I will tell you, on those hottest days or those coldest days, we just don’t see wind in the gorge because of the temperature inversion.

Yes. Okay.

Thank you very much and congratulations, Jim.

Thank you. I appreciate it.

Hey guys, congrats on a great – hey, Jim, congrats on a great quarter and obviously on the transition between you and Maria. I have a couple just IRP questions and then one kind of housekeeping one.

On the IRP, so you think you’ll be able to start entering bilateral negotiations or discussions with people who own conventional generation. That include either just doing a PPA or a tolling agreement, or does that also include potentially someone selling an asset to Portland General and putting in rate base?

The short list that we have includes both.

Got it.

And it will be predominantly existing. It will be – it’s all existing resources in the Pacific Northwest, which would be both hydro and thermal.

Hydro and thermal? So it’s conceivable you could simply re-contract, because it’s part of what’s driving, this is obviously Boardman.

But part of this as you have hydro contracts that are rolling off, there is a scenario where you could potentially re-contract with existing hydro?

Yes, absolutely.

Great. I want to make sure I understand on the renewable side, you need 300 megawatts of what – or roughly 300 megawatts of roughly what would be a nameplate, or 100 megawatts of roughly megawatt equivalent generation.

Am I thinking about that right, or could that 300 be a significant?

Yes.

Okay. And your project, the one you kind of mentioned as kind of, I don’t want to use the word stalking-horse, but your company sponsor bid into the…

Self-build option.

Yes self-build option, is that a project that can be scaled up or down, meaning, is that a site where it would still be economic, if let’s say, it was 200 megawatt nameplate, instead of 300 megawatt. I’m just trying to think about the flexibility?

Yes. No, I appreciate the question.

And at this point in time, all of those discussions are confidential.

Got it. And then one kind of – one or two housekeeping items.

So you talked about weather in the quarter versus last year, what was the weather impact versus normal?

It was about $0.06.

Okay. And you said the costs that are not recoverable in rates are roughly 70 basis points.

I’m just trying to put some back of the envelope math around that, that’s kind of roughly in the $15 million and $16 million range, or is – or am I off on that?

You’re off on that. It’s around $25 million range.

Pre-tax.

Pre-tax.

Pre-tax, yes.

My apologies, I was doing after tax, and that doesn’t include Carty litigation?

Correct.

Correct.

Got it. So the Carty litigation is incremental on that, okay.

Yes.

I appreciate it. Thank you guys and look forward to seeing you in a week and half.

All right. Thanks, Michael.

Thanks, Michael.

Good morning, Richie.

Hey, guys, it’s actually [indiscernible] here. Most of my questions were answered.

But I just want to get a little bit of a sense on your updated capital program. How much of your strategy is around grid mod and sort of smart grid, some of your data planning automation is embedded in that capital program versus what normal based spend would be?

And then just counter to that, what’s the right podium where you would come out with additional visibility on upside potential around sort of the grid mod investments you discussed today?

Sure. So thank you for the question.

We’re currently working with stakeholders and regulators on this. So we don’t have a specific time, as Jim mentioned, for coming out with announcements.

The – and we will be at the OPUC in early November talking about smart grid and what we’re doing there and our expectations for the future. So we’re working with parties diligently on this.

None of those investments are currently in the capital table that is presented in the presentation or in the 10-Q.

Okay, got it. And then just to follow-up on that, is there an opportunity to accelerate that spend into that current capital program just given the needs and where you’re obviously where you’re heading as far as renewable, or is this sort of thinking outside of the current program?

Yes, this would be in addition to the current program and we’re working through those issues with regulators and stakeholders currently.

Okay. Got it.

And then just lastly, on EIM, it’s interesting that you highlighted that on an Investor deck. Is there sort of any upside opportunities from a growth standpoint, from EIM and what I mean by that is moving the system away from just being an automated real-time administrative sort of program to something that could lead to additional infrastructure needs?

First of all, I think there are a number of opportunities as it allows us to integrate additional renewables into our system more cost-effectively. And overall, it will allow us to reduce cost for customers, which is important in terms of our overall strategy as we go forward.

Okay, great. Thanks.

That’s all the questions I had.

Thanks.

Thanks, Richie.

Thank you, and good morning. Hi.

Question on the capital budget. I wonder if you could characterize the projects sizes within that.

Are we talking about a program here that has a lot of small projects, or program that would have larger ticket, but fewer projects?

Well, I think, it depends on how you characterize the different bucket. And Jim talked to you a little bit about the size of our system.

And generally, you’re probably looking at a number of smaller projects, but that would amount to a significant investment over time if we really make the 186 substations we have in our grid system capable of handling by directional flows of electricity and handling increased amount of distributed resources on the system.

Okay. And then does the extra CapEx impact your dividend growth outlook for the next, call it, two to three years before you get over this larger self-capital spending?

No, I would not expect it to.

Okay, great. Thanks a lot.

Thank you.

Thanks, Travis.

Welcome back, Paul.

Thank you. Was that down 25% capacity factor versus normal or versus last year?

That was versus what we had in our budget, which is based on a five-year average, as well as expected forecast?

And did you – is that baked into the $0.06 of positive weather?

Yes, it’s all reflected – it’s reflected in power costs, but it’s reflected in our financials that we reported.

But did the $0.06 weather have any negative component was actually higher than $0.06, but there’s winter baked in there?

Jim?

Yes, $0.06 for weather did have the winter in there.

The wind?

Oh the wind?

These estimates the wind impact.

It had the cost. It had the reduction of wind, yes, replacement of our costs associated with it.

So temperature drove higher than $0.06, but it’s partly offset by the weaker wind?

Yes.

Thank you very much for the clarification.

Thanks, Paul.

Okay. Thank you very much for joining us today and for your interest in Portland General.

And we look forward to seeing you in Orlando at the EEI Annual Finance Conference. Thank you.