Good morning, everyone, and welcome to Portland General Electric Company’s First Quarter 2019 Earnings Results Conference Call. Today is Friday, April 26, 2019. 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 Director of Investor Relations and Treasury, Chris Liddle. Please go ahead, sir.

Thank you, Gigi. Good morning, everyone. I’m pleased you are 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’ll be referencing throughout the call. The slides are available on our website at investors.portlandgeneral.com. Referring to Slide 2, I would like to remind everyone that some of our remarks this morning will constitute forward-looking statements. We caution you that such statements involve inherent risks and uncertainties and actual results may differ materially from our expectations. For a description of some of the factors that could cause actual results to differ materially, please refer to our earnings press release and our most recent periodic reports on Form 10-K and Form 10-Q, which are also available on our website. Leading our discussion today are Maria Pope, President and CEO; and Jim Lobdell, Senior Vice President of Finance, CFO and Treasurer. Following their prepared remarks, we will open the lines for your questions. Now it’s my pleasure to turn the call over to Maria Pope.

Thank you, Chris, and good morning, everyone. Welcome to Portland General Electric’s first quarter 2019 earnings call. I am pleased to share our financial results and accomplishments. We are also reaffirming our full year 2019 earnings guidance of $2.35 to $2.50 per diluted share. Earlier this week, our Board approved a 6.3% increase in our annual dividend or $0.09 per share. Additionally, to provide better guidance, we’re narrowing our dividend payout range to 60% to 70% of earnings. Turning to Slide 4. For the first quarter of 2019, we have reported net income of $73 million or $0.82 per share, an increase of $0.10 per share compared to the first quarter of 2018. As many of you know, we experienced unprecedented volatility and the higher power – highest power prices we have seen in the Western power markets since the California energy crisis in the early 2000. Market conditions reflected 22% lower-than-average hydro and 43% lower-than-average wind as well as ongoing reduction in gas pipeline capacity resulting from the Enbridge explosion in British Columbia last fall. During this time, we achieved 98% plant availability, which allowed us to effectively navigate market challenges and strategically dispatch our generation to maintain reliability and consistent power cost. Turning to Slide 5. The economy in our service area remains strong. U.S. news and world report recently ranked Portland as one of the top 10 places to live in the country. Average wages of Oregonians have risen 3% to 4% per year for the last several years, and unemployment rates in the urban centers of our service area are near historic lows. Reflecting these factors, PG’s average customer count increased by 1.2% in the first quarter, and our service area remains busy with new construction and expansion projects. Now turning to Slide 6. We are advancing transportation electrification. Earlier this month, we opened our latest Electric Avenue location and officially launched our charging network. By the end of this year, we will have seven locations within our service area. We have also filed proposals that will help a greater number of customers to deploy electric vehicle charges. In addition, we recently partnered with our local transit authority, TriMet, to launch 100% wind-powered, all-electric bus route. And finally, we announced our participation in the West Coast Clean Transportation Corridor, working a commercial electrification on the main interstate highway in the West. Also in the first quarter, the Public Utility Commission approved our green tariff proposal, which we’ll bring to market later this spring. We’re also moving forward with our 2019 Integrated Resource Plan and anticipate filing this summer. With that, I’ll turn the call over to Jim.

Thank you, Maria. As Maria mentioned, we are reaffirming our full year 2019 guidance $2.35 to $2.50 per diluted share. Additionally, we are maintaining earnings per share growth guidance of 4% to 6% on average through 2021 using our 2018 earnings of $2.37 per diluted share as a base year for that guidance. Turning to Slide 7, which shows earnings drivers. First gross margin increased to total of $0.10 per diluted share. As part of our 2019 General Rate Case, we added $250 million of rate base, which increased earnings power by $0.03 per share in the first quarter. Additionally, weather represented a $0.03 per share increase when compared to unfavorable weather in the first quarter of 2018. The remaining $0.04 are the net of the following: colder temperatures across the region, which increased demand that resulted in higher revenues; higher power prices in the market as a result of increased regional demand due to colder temperatures, lower wind and hydro production; and limited gas supply due to gas pipeline maintenance and inspection. And our power plants achieved outstanding availability allowing us to effectively dispatch the lowest-cost resources in a challenged market; next, an increase of $0.03 is attributable to the absence of incremental cost associated with the Carty litigation included in the first quarter of 2018; a decrease of $0.02 from lower production tax credit generation as wind underperformed in the first quarter of 2019; and finally a decrease of $0.01 from miscellaneous items. On to Slide 8, we have provided a summary of the company’s current capital expenditure forecast from 2019 to 2023. Consistent with our rolling planning process, we are updating our capital forecast to include additional expenditures of $20 million in 2019 for a total of $600 million. These additional expenditures will be focused on upgrading our generation facilities. On to Slide 9, we continue to maintain a solid balance sheet including strong liquidity and investment-grade credit ratings. As of March 31, 2019, we had first mortgage bond issuance capacity of $1 billion, cash, available short-term credit and letter of credit capacity totaling $726 million and a common equity ratio of 50.7%. This month, we redeemed $300 million of first mortgage bonds with an interest rate of 6.1% and issued $200 million of first mortgage bonds at a rate of 4.3%, maturing in 2049. For the remainder of 2019, we expect to fund estimated capital requirements with cash from operations and the issuance of debt securities up to an additional $250 million. And now operator, we’re ready for questions.

[Operator Instructions] And our first question is from Chris Turnure from JPMorgan. Your line is now open.

Good morning Chris.

Good morning Maria and Jim.

Good morning.

You guys mentioned the Enbridge pipeline situation from the fall. Could you just kind of walk us through the impacts on the quarter itself for you, not necessarily directly your bottom line and the EPS impact, but what that means for the commodity markets in the area right now? And then just separately on the 1Q results, what would be kind of a clean number ex any kind of weather versus normal or commodities versus normal?

Sure. So I think it’s important as we look at the Enbridge pipeline explosion and then the subsequent repair and maintenance as well as inspection that they’ve been doing from the entire pipeline in British Columbia has meant that we’ve curtailed capacity. This has largely been an issue for electric generation when we’ve had very cold periods of time and the heating load has required extensive use of gas that would not take place during normal temperatures. As we look into the balance of the year, we’re not just concerned about the issues with the Enbridge pipeline and the additional inspections and maintenance that will be ongoing, but we’re also concerned around the withdrawal rates at Aliso Canyon and the protocol restrictions that we saw last summer and we’ll continue to see this summer. All of these things are important not just in and of themselves, but as they combine with lower wind and with lower hydro. The forecast for the balance of the year in the Dallas are much better for hydro, they’re below normal in British Colombia and in our system, we’re seeing slightly above average. But in general, we’re expecting warmer temperatures this summer. And with those warmer temperatures frequently come lower levels of wind generation. And as such, we’re preparing for what will probably be a continuation of challenging energy markets. It’s not possible to break things up into what is one area cost in one particular area. Jim might have some additional comments.

Yes. Chris, one thing I do is we’re trying to kind of normalize it. I think about it from the prospective of the AUT, and in the first quarter, we’re over $12 million in the AUT. But when you look at whether compared to normal, there really was no impact associated with the additional loads that were created there. And as Maria pointed out, there are lot of moving pieces that were occurring in the marketplace, and they’re all interrelated. So it’s very difficult to be able to pull out exactly what the impact of the gas was.

Okay. That’s helpful. Kind of surrounding color though. But for the first quarter specifically, you guys benefited by $12 million pretax versus your kind of baseline plan that you submitted to the commission last year.

We were $12 million above the baseline.

Meaning higher cost, we’re $12 million above and then we had higher revenues that offset some of those higher costs.

Okay. So there’s still a couple of moving pieces around that and net-net, you obviously did well for the quarter.

Yes.

Yes. Because that cold weather drove our loads to be higher, but it also drove natural gas usage to be significantly higher. And during very cold periods of time, we generally see lower levels of wind generation in particular. And the snowpack was still pretty strong, so we didn’t see a lot of run-off for hydro.

Yes. So you’ve got cold weather running up prices because it’s running up demand. You’ve got gas prices that are increasing because of the constraints on the gas – the mainline gas system. You’ve got lower hydro and wind, as Maria was pointing out. And then you’ve got our power plants where it had great availability during that time period. All of those combined allowed us to be able to manage our power prices very consistently.

Okay. And then my second question is on cap and trade. It looks like it’s kind of in the final stages here. And you guys don’t have a lot of coal exposure, obviously, but I’m wondering if you or others have done a, kind of, estimated customer build impact for your customers or electric utility customers, in general, in state.

Sure. Thank you. The cap and trade discussions have been ongoing for some time and continue in the state of Oregon as well as sort of region- wide. We’ve been participating actively with all of the stakeholders. And our main concern has been that our customers don’t pay twice. We have very specific renewable goals in the state of Oregon, which require us to add renewable energy at different points in time as we move forward towards 2050. And so as we do that, we’re able to stay within the realm and not incur any fees or penalties, which would require any impact to customer prices. So it’s very important as we decarbonize our electric supply, the customers don’t pay twice for that. And that’s currently included in the drafts of the legislation.

Thank you. Our next question is from Julien Dumoulin-Smith from Bank of America. Your line is now open.

Hey, good morning. Can you hear me?

Good morning Julien.

Yes. Good morning.

So perhaps just to pick up on a smaller – bunch of smaller items here. In terms of cost cuts, you all have talked about pursuing a more meaningful revisit of your structure over time here. How do you think about that relative to the lower loads as you think about it? Just – I’m just thinking about 2019, how you’re trending and an overall on sort of this multiyear basis given some of the comment you made last quarter and especially relative to lower trends as well.

Well, from a load perspective, we’re anticipating on a long-term basis to have over 1% increase in load. For 2019, we were saying weather-adjusted in our guidance, we’re going to go up 0.5%. So not really seeing a drop-off in load as Maria had mentioned in her comments, we’re seeing a tremendous amount of construction that’s occurring in our service territory and that is keeping us more than busy. So we are trying to address how we go about performing on all of that additional growth that’s occurring in the service territory, while at the same time, trying to be as efficient as possible on our long-term view for the company. And that’s meant a lot of changes inside the organization.

Got it. So maybe said differently, net-net cost program is still underway as anticipated and load roughly not too far.

That seems reasonable.

Okay. And Then turning to the IRP here, I know that filing this summer. Maybe just in terms of setting expectations, how do you think about potential awards coming out of that, even preliminarily, given sort of the back and forth on REC availability that you have, et cetera and PTC acceleration that we just saw?

So Julien, there is three main areas of our IRP that we’ll be focusing on. The first one is energy efficiency, demand response and dispatchable storage. The second is, we’re seeking approximately 150 average megawatts of additional renewables that we would hope we’d be able to come online by about 2023 to be able to pick up some of that last remaining portion of the PTC as they roll off into the future. And then thirdly, a stage process to acquire additional capacity resources that would meet our resource needs by being able to take advantage of capacity that is carbon-free first and really understand the depth of the market in that area. It’s too early to speculate what might happen out of an RFP for any of the additional builds that might take place from our IRP. Our hope is that we’ll have a preliminary draft of our IRP out sometime in May, maybe towards the latter part of May, and then with the filing of the final document sometime this summer. We have had a number of public hearings and a very robust public process so far.

Sorry, and Maria, if I can – can you elaborate a little bit more on this process for low-carbon resources? Just what that could broadly look at? Because it seems like obviously it’s a little bit of a – it’s sort of ill-defined right now. What could that – what permutations could that take?

Sure. So first of all, as we’re looking at low-carbon resources, I’m going to address the capacity piece, which I think is where you’re going versus just a RFP for energy. On the capacity side, what we’ll do is, we’ll go out with a sort of a layered approach. As you remember from our last discussion in the 2016 IRP, we ended up with contracts with a number of regional parties and significantly Bonneville Power Administration to be able to provide capacity. And so being able to use hydro capacity contracts as a non-carbon-emitting way to be able to balance intermittency of renewables will be the first way that we’ll test the market. And based on that, then we’ll figure out what else we need to do as we use a layered approach to our capacity RFP processes.

Okay. All right. Fair enough. I’ll leave it there. So thank you very much.

Thanks, Julien.

Thank you. Our next question is from Insoo Kim from Goldman Sachs. Your line is now open.

Thank you. On the tightened dividend payout policy, is there a thought that over time gradually from just the moderate differences in the EPS growth and dividend growth that you’ve recently been growing at that 60% to 70% and especially maybe at the midpoint that will come gradually over time?

Yes.

Okay. But there’s no specific time period or a – whether it’d be in the lower or upper end of that in some period of time?

No. No, we’re not providing any guidance along those lines. We’re just – we looked at our modeling and we thought it was appropriate based on what we were seeing in order to narrow the range.

Got it. And then on the low growth, I know you’ve guided to the 0.5% weather-adjusted for this year and 1% will definitely be a pretty positive step longer term. Are you seeing – Maria, I know you talked about all the activity outside your window on construction and whatnot. Do you have any time frame in your head as to whether that’s going to be in the next couple of years? Or whether that will be a little bit more longer term?

I think it will be both. Right now, Oregon has the third highest number of cranes in the country behind Seattle and Los Angeles, obviously, much larger metropolitan areas than Portland. We’re also seeing substantial interest in a wide variety of industries, but significantly in terms of energy consumption, digital companies as well as other high-tech companies. And I think this is not just a reflection of robust economy, but also our economic position vis-a-vis California and markets in Washington. Our geographic area is much less expensive to operate in than Northern California and San Francisco versus the Seattle region.

Understood. Thank you very much.

Thank you.

Thanks, Insoo.

Thank you. Our next question is from Paul Fremont from Mizuho. Your line is now open.

Good morning. Thanks a lot. Just following up on Julian’s question with respect to the IRP. If you were to determine that additional resources were required, I assume there would be an associated RFP process. How far out into the future would you expect that RFP to take place?

Well, I don’t think we know, which is one of the reasons why we’re testing the market and applying a layered approach. Whatever we do, we’ll absolutely have a competitive bidding component through an RFP process and – or something similar. And we will also be discussing it publicly with all stakeholders. And should also appreciate that West-wide, there is a pretty significant discussion within the industry regulators and others around the growing interdependence of gas and electricity, overall capacity, availability, markets, and we would expect that all of these discussions will come into play as we look at also advances in technology. Jim may have some other comments he wants to add.

Yes. The other thing, I’d say Paul is that as we are looking at renewable resources, the value that PTC is still out there, we’re going to try and capture as much as possible for our customers.

Great. And then the other – I guess, the other question that I had really relates to sort of the change in the dividend policy. It seems like the payout level is going up at a time where you might end up in a period of higher spending levels. I just – maybe just want to get a better understanding of that.

Again, as we’re doing our long-term modeling for the company, the narrowing of that range really fits well with us. So we’re comfortable with it.

Great. Thank you very much.

Thanks, Paul.

Thank you.

Thank you. Our next question is from Gregg Orrill from UBS. Your line is now open.

Good morning, Gregg.

Good morning.

Hi, good morning. Not to read anything into this, but in the cash from operations guidance for 2019, are there any adjustments that you would guide to that to think about using it as a base for going forward?

No. I take it as written in the queue. I think it explains it quite well or expecting from operations, what we’re expecting from investing and financing activities.

We’d say that as we’re taking up our capital expenditures, having them being spent more proportionally throughout the year has been a consequence of the higher level of capital spending that we have to be able to effectively get the work done efficiently and as low-cost as possible.

Okay. And then on the next RFP or IRP, have you identified yet the level of resource that you’ll need or maybe better said the shortfall in supply?

We’re still in discussions of that. What we have had discussions with is about 150 average megawatts of energy. And then what is – what will be in the mid-2020s growing capacity shortfall.

Okay. Thank you.

Thanks, Gregg.

Thank you. Our next question is from Travis Miller from MorningStar. Your line is now open.

Good morning. Thank you.

Good morning, Travis.

Sticking on the IRP here for a moment. Those two buckets that you identified, would you plan to offer self-build or self-investment options in all three of those? Is there any bucket there that you would think about not doing it or doing more of a self-build option? Your thoughts on that.

We have not discussed any of those thoughts publicly at this point in time. We’re still in the planning stages to – and making sure that we have the least cost resources available for customers. We take a look at what’s competitively available and if we need to supplement that competitive marketplace with a bit of our own. And at this point in time, we’re still doing that work and looking at the market.

You won’t rule out any of those buckets in terms of possible self-build and none of that’s in your kind of 2022, 2023 CapEx or it would all be incremental? Is that, right?

It will all be incremental, correct.

Okay. And then real quick. Wondering if you could give an update on the Wheatridge facility where it is in siting or early construction or what.

So construction has not started. We’re doing a lot of engineering, a lot of permit work. Unfortunately, as one prepares a site, there’s a lot of work that takes place that – where there’s not of lot of capital spending until you really get into the construction and assembly mode for a wind farm. So we’re very much in the early stages.

Okay. Still on track for the original schedule?

Absolutely. Yes, it’s going well.

Great. That’s all I had. Thank you.

Thanks Travis.

Thank you.

Thank you. Our next question is from Vedula Murti from Avon Capital. Your line is now open.

Good morning.

Good morning, Vedula.

In terms of the netting of revenues versus the fuel and purchased power cost, you indicated that – I want to make sure I got this right that your fuel and purchased power incurred cost was about $12 million above the baseline. So – and if that is correct, that would imply in order to get to the $0.07 positive delta to that gross margins cost system or basically about positive $20 million to end up there. Is that basically accurate?

It is a reasonable direction, the numbers little bit up. But Chris or Peter can help you with those later.

Okay. And secondarily, in terms of the – some of the cost initiatives you discussed, when I take a look at the operating expenses, generation, transmission, distribution and administrative and others, year-over-year, at least for the quarter, that was about 7% above an aggregate combined 7% higher in 2019 versus 2018. I assume some of the extreme weather conditions may have affected that. So on a going-forward basis here kind of how should we be thinking about that?

From two perspectives. One is that, we aligned our cost structure to our most recent 2019 GRC. And with that being said, we are containing – as we’ve mentioned previously that we are focusing on the efficiency and throughput of the operations. And we’re hoping to improve the overall cost structure of the company going forward.

Is there a way – can you bound that off in any fashion as to kind of what would be original expectation?

No. Not at this point.

All right. Thank you.

Thank you.

Thank you. Our next question is from Phil Covello from ExodusPoint. Your line is now open.

Good morning, Phil.

Hey guys. It’s Andy Levi. That’s actually Andy.

No, I was hoping for Phil.

I know you were. So, I like you guys. So, I ask.

All right, go ahead.

Actually another good quarter. So you guys managed everything really well.

Thank you.

Just on the – just backing up the kind of the dead horse, but just on the power market situation, I just want to kind of understand it and I can understand your situation, but what was the – how could you characterize your hydro conditions were they were 90 – did you give a number, I don’t remember as far as first normal for the quarter?

No. hydro for us – well, the region was down. So you have to think about that from perspective of how it influences power prices. When you look at our hydro alone, we’re about 22% under where we expected in our AUT filing.

Okay.

And a lot of that comes from regional contracts we have with the mid sea. So that would be representative of the industry in general in the Pacific Northwest.

Okay. And I mean when you say the contracts, it’s the contracts you have but not because it was below normal was this weather and cold weather related, so both…

Yes. These are long-term contracts we have with some of the Columbia River dam operators. And that’s the bulk of the generation – those dams are the bulk of the generation in the Pacific Northwest.

And was it more than it was just so cold that the water was flowing? Or there wasn’t even any melt at all or? I’m just trying to figure out why the winter – which I know is a lower hydro time anyway, but why it was below normal?

A couple of things, Andy. One is, when you look at the snowpack that’s occurred in the region, you might say, and I include in the region going up in the Canada. That Canadian snowpack and the reservoirs that we saw up there are at lower levels than what we were experiencing down here in the Pacific Northwest. So when you look at the forecast that was in the Q4 hydro for the annual basis, you’ll find that Grand Coulee was down below 100%. But if you look at what we’ve got for the Oregon resources, so looking at the Clackamas River or Deschutes River, those levels were up higher than 100%. So that had a big impact because the Canadians are a big driver of the flows that go down to the Mid-Columbia system and a big impact on power prices. I mean specifically, Grand Coulee for 2019 is estimated to be about 87% of normal versus last year where we were closer to 100%. If you look at the Deschutes River, the Deschutes is sitting at – and as Deschutes is in Oregon, it’s one of our major power plants are sitting on that, the Pelton Round Butte, that one is supposed to be at 110%. So that has a significant impact on power prices. When you got cold weather occurring, you’ve got a decrease in hydro and rain at that particular point in time and you’ve got the gas issue that was going on, on the Enbridge system, and at the same time, you’ve got wind that is not delivering at the forecasted levels, then that really comes together and drives power prices.

I got it. And then – but just as far as it is back on the hydro, so it wasn’t your own hydro that was the issue. It was more around, as you said, north of you…

Correct.

Where the excess hydro normally would flow. Is that kind of the way to look at it?

Yes. And I’m not sure I would use the word excess, but that’s where the larger quantity of hydro for the entire region is. Our hydro, as Jim mentioned, actually performed relatively well versus the region as a whole all the way through British Columbia.

Okay. I got it. Thank you very much, and see you soon.

Thanks, Andy.

Thank you. Our next question is from Greg Reiss from Centenus. Your line is now open.

Greg.

Yes, can you hear me?

Yes.

Yes, we can.

Congrats on a good quarter. Just a real quick question on the IRP. The 150 megawatts that you mentioned, is that kind of what the nameplate capacity of the resource would be? Or would you have to kind of gross that up for like renewable capacity factors or it would be something bigger than that.

Yes, that’s an average megawatt not capacity but the generation. So you would need to gross it up. Yes.

Okay. So if like a wind farm was selected, you’d have to gross that up by like a 35% capacity factor.

Yes, I generally multiply by 3.

Okay. Got you. Perfect. Thank so much.

Thanks, Greg.

Thanks, Greg.

One other thing I want to mention is, when we look at wind, during the summertime, we will have more thermal, so we can’t have reasonable wind during the summer time period. And when you’re looking at the expectations, keep in mind, from a modeling perspective, from a recovery perspective, we’ll look at a five year average. So…

Yes. So these poor wind conditions actually roll into our average in the future.

Got you.

Thanks, Greg.

Thank you.

Thanks.

At this time, I’m showing no further questions. I would like to turn the call back over to Maria Pope for closing remarks.

Thank you. We very much appreciate your interest in Portland General Electric, and we invite you to join us in August when we report our second quarter 2019 results. Have a great day, and thank you again.

Ladies and gentlemen, thank you for your participation in today’s conference. This concludes the program. You may now disconnect.