Good morning everyone, welcome to Portland General Electric Company's first quarter 2019 earnings result conference call. Today is Friday, April 26th, 2019. This call is being recorded, and as such, all lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question and answer period. If you would like to ask a question during this time, simply press star, then the number 1 on your telephone keypad. If you would like to withdraw your question, press the pound key on your telephone keypad. If you do intend to ask a question, please avoid the use of speakerphones. 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're able to join us today. Before we begin our discussion this morning, I'd like to remind you that we have prepared a presentation to supplement our discussion, which we'll be referencing throughout the call. The slides are available on our website at investors.portlandgeneral.com. Referring to slide two, 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. Good morning, everyone. Welcome to Portland General Electric's first quarter 2019 earnings call. I'm pleased to share our financial results and accomplishments. We are also reaffirming our full year 2019 earnings guidance of $2.35-$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%-70% of earnings. Turning to slide four. For the first quarter of 2019, we 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 highest power prices we have seen in the Western power markets since the California energy crisis in the early 2000s.
Market conditions reflected 22% lower than average hydro and 43% lower than average wind, as well as ongoing reductions 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 costs. Turning to slide five. The economy in our service area remains strong. U.S. News & World Report recently ranked Portland as one of the top 10 places to live in the country. Average wages of Oregonians have risen 3%-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, PGE's average customer count increased by 1.2% in the first quarter, and our service area remains busy with new construction and expansion projects.
Turning to slide six. We're 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 deploy electric vehicle chargers. In addition, we recently partnered with our local transit authority, TriMet, to launch 100% wind-powered all-electric bus routes. Finally, we announced our participation in the West Coast Clean Transportation Corridor, working on commercial electrification on the main interstate highway in the West. 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 of $2.35-$2.50 per diluted share. Additionally, we are maintaining earnings per share growth guidance of 4%-6% on average through 2021, using our 2018 earnings of $2.37 per diluted share as the base year for that guidance. Turning to slide seven, which shows earnings drivers. First, gross margin increased a 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.
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. Our power plants achieved outstanding availability, allowing us to effectively dispatch the lowest cost resources in a challenged market. An increase of $0.03 is attributable to the absence of incremental costs 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.
Finally, a decrease of $0.01 for miscellaneous items. On to slide eight, we have provided a summary of the company's current capital expenditure forecast from 2019 to 2023. Consistent with our rolling planning process, we're 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 nine. We continue to maintain a solid balance sheet, including strong liquidity and investment-grade credit ratings. As of March 31st, 2019, we have 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. Now, operator, we're ready for questions.
Ladies and gentlemen, at this time, if you have a question, please press the star then the number one key on your telephone keypad. If your question has been answered or you wish to remove yourself from the queue, please press the pound key. To prevent any background noise, we ask that you please place your line on mute once your question has been stated. Our first question is from Chris Turner from JPMorgan. Your line is now open.
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 impact 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? Just separately on the 1Q results, what would be kind of a clean number x any kind of weather versus normal or commodities versus normal?
Sure. 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 had 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 will continue to see of this summer.
All of these things are important, not just in and of themselves, as they combine with lower wind and with lower hydro. The forecast for the balance of the year in The Dalles are much better for hydro. They are below normal in British Columbia, and on our system, we are seeing slightly above average. In general, we are expecting warmer temperatures this summer, and with those warmer temperatures frequently come lower levels of wind generation. As such, we are preparing for what will probably be a continuation of challenging energy markets. It is not possible really to break things up into sort of what does one area cost in one particular area. Jim might have some additional comments.
Yeah, Chris, one thing I do is if you are trying to kind of normalize it, I think about it from the perspective of the AUT. In the first quarter, we are over $12 million in the AUT. When you look at weather compared to normal, there really was no impact associated with the additional loads that were created there. As Maria pointed out, there were a lot of moving pieces that were occurring in the marketplace, and they are all interrelated, so it is very difficult to be able to pull out exactly what the impact of the gas was.
Okay. That is helpful kind of surrounding color, though. For the first quarter specifically, you guys benefited by $12 million pre-tax versus your kind of baseline plan that you submitted to the commission last year.
Well, we were $12 million above the baseline for this quarter.
Meaning higher costs.
Right.
We're $12 million above, we had higher revenues that offset some of those higher costs.
Okay. There's still a couple moving pieces around that, net, you obviously did well for the quarter.
Yes.
Yes. That cold weather drove our loads to be higher, it also drove natural gas usage to be significantly higher. During very cold periods of time, we generally see lower levels of wind generation in particular.
Yeah.
The snowpack was still pretty strong, so we didn't see a lot of runoff for hydro.
Yeah. 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 mainline gas system. You've got lower hydro and wind, as Maria was pointing out. Then you've got our power plants, where had great availability during that time period. All of those combined allowed us to be able to manage our power prices very consistently.
Okay. My second question is on cap and trade. It looks like it's kind of in the final stages here. 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 bill impact for your customers or electric utility customers in general in state.
Sure. Well, 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. 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. As we do that, we're able to stay within the realm and not incur any fees or penalties, which would require any impact on customer prices. So it's very important as we decarbonize our electric supply, that customers don't pay twice for that. That's currently included in the draft of the legislation.
Thank you.
Okay.
Our next question is from Julien Dumoulin-Smith from Bank of America. Your line is now open.
Hey, good morning. Can you hear me?
Yeah. Good morning, Julien.
Yes. Good morning.
Hey. Perhaps just to pick up on a 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? I'm just thinking about 2019, how you're trending, and then overall on sort of this multi-year basis, given some of the comments you made last quarter, and especially relative to load trends as well.
Well, from a load perspective, we're anticipating on a long-term basis to have over a 1% increase in load. For 2019, we were saying weather-adjusted in our guidance, we were going to go up 0.5%. 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 it is keeping us more than busy. We are trying to address how we go about performing on all that additional growth that's occurring in the service territory, while at the same time trying to be as efficient as possible on a long-term view for the company. That's meant a lot of changes inside the organization.
Got it. Maybe said differently, net cost program still underway as anticipated and load roughly not too far.
That seems reasonable.
Okay. 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?
Julien, there's 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 MW of additional renewables that we would hope would be able to come online by about 2023 to be able to pick up sort of that last remaining portion of the PTCs as they roll off into the future. Thirdly, a staged 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, with a 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. Maria, if I can you elaborate a little bit more on this process for low carbon resources? Just what that could broadly look at? It seems like obviously it's sort of ill-defined right now. What permutations could that take?
Sure. 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 sort of a layered approach. As you'll 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. Being able to use hydro capacity contracts as a non-carbon emitting way to be able to balance the intermittency of renewables will be the first way that we'll test the market. Based on that, we'll figure out what else we need to do as we do sort of a layered approach to our capacity RFP processes.
Okay. All right, fair enough. Well, I'll leave it there. Thank you very much.
Thanks, Julien.
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 the 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%-70%, and especially maybe at the midpoint, that'll come gradually over time?
Yes.
Okay. There's no specific time period or whether it'll be in the lower or upper end of that in some period of time?
No. We're not providing any guidance along those lines. We looked at our modeling, we thought it was appropriate based on what we were seeing in order to narrow the range.
Got it. On low growth, I know you've guided to the 0.5%, whether adjusted for this year and 1% would definitely be a pretty positive step longer term. Are you seeing, Maria, I know you talk about all the activity outside your window on construction and whatnot. Do you have any timeframe in your head as to whether that's going to be in the next couple of years or whether it'll 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. I think this is not just a reflection of a 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 or 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.
Morning, Paul.
Good morning. Thanks a lot. Just following up on Julien'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?
Boy, I don't think we know, which is one of the reasons why we're testing the market and following a layered approach. Whatever we do, we'll absolutely have a competitive bidding component through an RFP process or something similar. We will also be discussing it publicly with all stakeholders. You should also appreciate that west-wide, there's a pretty significant discussion within the industry, regulators, and others around the growing interdependence of gas and electricity, overall capacity, availability, markets. 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.
Yeah. The other thing I'd say, Paul, is as we're looking at renewable resources, the value of that PTC is still out there. We're going to try and capture as much of that as possible for our customers.
Great.
Great point.
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 that. 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.
Morning, Gregg.
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 Q. I think it explains it quite well. We're expecting from operations what we're expecting from investing and financing activities.
Okay.
I would say that as we've taken up our capital expenditures, having them being spent more proportionately 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. 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 will be in the mid 2020s, a growing capacity shortfall.
Okay. Thank you.
Thanks, Gregg.
Thank you. Our next question's from Travis Miller from Morningstar. Your line is now open.
Good morning. Thank you.
Morning, Travis.
Sticking on the IRP here for a moment. Those three 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? What are 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, 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 bid of our own. At this point in time, we're still doing that work and looking at the market.
Okay. You wouldn't rule out any of those buckets.
No
in terms of possible self-build. None of that's in your kind of 2022, 2023 CapEx, so it'd all be incremental. Is that right?
Correct.
It would all be incremental. Correct.
Okay. Then, real quick, wondering if you could give an update on the Wheatridge facility, where it is in siting or early construction, or what.
Sure. 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 where there's not a lot of capital spending until you really get into the construction and assembly mode of a wind farm. We're very much in the early stages.
Okay. Still on track for the original schedule?
Absolutely. Yep. It's going well.
Great. That's all I have. Thank you.
Thank you.
Thanks, Travis.
Thank you. Our next question is from Vidula Murti from Avon Capital. Your line is now open.
Good morning.
Good morning, Vidula.
Let's see. In terms of the netting of revenues versus the fuel and purchase power cost, you indicated that, I want to make sure I got this right, that your fuel and purchase power incurred costs were about $12 million above the baseline. If that's correct, that would imply in order to get to the $0.07 positive delta, that close margins across system were basically about a positive $20 million to end up there. Is that basically accurate?
It is a reasonable direction. The number's a little bit off. Chris or Peter can help you with those later.
Okay. Secondarily, in terms of some of the cost initiatives you discussed. When I take a look at the operating expenses, generation, transmission, distribution, and administrative and other, 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. 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. With that being said, we are continuing, as we've mentioned previously, that we are focusing on the efficiency and throughput of the operations. We're hoping to improve the overall cost structure of the company going forward.
Can you bound that off in any fashion as to what would be a reasonable 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.
Hey, guys. It's Andy Levi. That's actually Andy.
I was hoping for Phil.
I know you were. I like you guys, so I asked anyway.
Likewise.
Actually another good quarter, so you guys managed everything really well.
Thank you.
Yep.
Just on the fact, not to kind of beat a dead horse, but just on the power market situation, I just want to kind of understand it. I kind of understand your situation. How could you categorize your hydro conditions? Were they, what, 90? Did you give a number? I don't remember. As far as versus normal for the quarter.
Hydro for us, well, the region was down, so you have to think about that from a perspective of how it influences power prices. When you look at our hydro alone, we're about 22% under where we expected in our-
Okay
in our AUT filing.
Okay.
A lot of that comes from regional contracts we have with the Mid-C. That would be representative of the industry in general in the Pacific Northwest.
Okay. 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?
Yeah. These are long-term contracts we have with some of the Columbia River dam operators.
All right. Basically, I guess.
Those dams are the bulk of the generation in the Pacific Northwest.
Was it more that it was just so cold that the water wasn't flowing, or there wasn't even any melt at all? I'm just trying to figure out why in the winter, which I know is a lower hydro time anyway, but why it was below normal.
A couple of things, Andy. One is that when you look at the snowpack that's occurred in the region, you might say, I include in the region going up into Canada. The Canadian snowpack and the reservoirs that we saw up there are at lower levels than what we're experiencing down here in the Pacific Northwest. 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%. If you look at what we've got for the Oregon resources, looking at the Clackamas River, the Deschutes River, those levels were up higher than 100%. That had a big impact because the Canadians are a big driver of the flows that go down through the mid-Columbia system and a big impact on power prices.
Specifically, Grand Coulee for 2019 is estimated to be about 87% of normal versus last year, we were closer to 100%. If you look at the Deschutes River, the Deschutes is sitting at, and the Deschutes is in Oregon. It's one of our major power plants are sitting on the Pelton Round Butte. That one's supposed to be at 110%. 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, you've got the gas issue that was going on on the Enbridge system. At the same time, you've got wind that is not delivering at the forecasted levels, that really comes together and drives power prices.
I get it. Just as far as back on the hydro, it wasn't your owned 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. I'm not sure I would use the word excess, 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.
Thanks, Andy.
See you soon. Bye.
Thank you. Our next question is from Gregg Orrill from Sentinus. Your line is now open.
Gregg?
Yep. Can you hear me?
Yeah.
We can all hear.
Hey there. 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 a renewable capacity factor, so it'd be something bigger than that?
Yes, that's an average megawatt, not capacity, but generation. You would need to gross it up. Yes.
Okay. If a wind farm was selected, you'd have to gross that up by a 35% capacity factor.
Yeah. I generally multiply by three.
Okay. Got you. Perfect. Thanks very much.
Thank you.
Thanks, Gregg. One other thing I want to mention is when we look at wind, during the summertime, we'll have more thermal, so we can have reasonable wind during the summertime period. When you're looking at the expectations, keep in mind from a modeling perspective, from a recovery perspective, we look at a five-year average.
These poor wind conditions actually roll into our average in the future.
Yeah.
Got you.
All right. Thanks, Gregg.
Thank you.
Thanks.
Thank you. 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.