Portland General Electric Company (NYSE:POR) Q3 2023 Earnings Call Transcript

Portland General Electric Company (NYSE:POR) Q3 2023 Earnings Call Transcript October 27, 2023

Portland General Electric Company beats earnings expectations. Reported EPS is $0.4649, expectations were $0.45.

Operator: Good morning, everyone. And welcome to Portland General Electric Company’s Third Quarter 2023 Earnings Results Conference Call. Today is Friday, October 27, 2023. 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. [Operator Instructions] For opening remarks, I will turn the conference over to Portland General Electric’s Manager of Investor Relations, Nick White. Please go ahead, sir.

Nick White: Thank you, Latif. Good morning, everyone. I’m happy you can join us today. Before we begin this morning, I’d like to remind you that we have prepared a presentation to supplement our discussion, which we will be referencing throughout the call. The slides are available on our website at investors.portlandgeneral.com. Referring to slide 2. 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 Forms 10-K and 10-Q, which are available on our website.

A close-up of an electrical power line with a bright blue sky in the background, highlighting the company’s selection of electricity and natural gas services.

Leading our discussion today are Maria Pope, President and CEO; and Joe Trpik, Senior Vice President of Finance and CFO. Following their prepared remarks, we will open the line for your questions. Now it is my pleasure to turn the call over to Maria.

Maria Pope: Thank you, Nick, and good morning. Thank you all for joining us today. Beginning with slide 4, I’ll start by discussing our results for the quarter and speak to the key drivers, as well as our outlook for the balance of the year. For the third quarter, we reported GAAP net income of $47 million or $0.46 per diluted share. This compares with third quarter 2022 results of $58 million or $0.65 per diluted share. Clearly, it was a tough quarter. The key drivers include; first, continued load growth from industrial customers offset by reductions in residential and commercial usage, partially driven by cooler weather overall. And second, volatile power costs from a major heat event in mid-August, which resulted in transmission congestion issues and a significant spike in energy costs.

I will touch on each in turn. Turning to slide 5. We continue to see solid growth from industrial customers, particularly data centers. However, this growth is chunky, and we saw modest growth in the third quarter. Overall, through the first nine months of the year, industrial load has grown over 6.5% compared to 2022. We foresee continued growth in the fourth quarter and potentially even higher industrial growth in the coming years. With strong legislative tailwinds at both the state and federal level, there is significant government support through grants and other incentives focused on the semiconductor sector. 15% of US semiconductor manufacturing occurs in our state, largely within PGE service territory. The sector will benefit not only from the federal chipset, but from the $240 million of the Oregon legislature has allocated to 15 semiconductor companies.

As a result of these investments, state officials are projecting over $40 billion in new Oregon projects and over 6,000 new jobs. Recent expansion announcements have been made by Intel, Microchip and Analog Devices. In the third quarter, we also saw modest reductions in residential and commercial energy use compared to last year, driven by cooler weather, in the late summer as well as energy efficiency, rooftop solar and overall distributed energy adoption. Given lower-than-planned third quarter loads, we have revised our full year 2023 growth guidance to 2% weather adjusted, consistent with our long-term expectations. The second driver of third quarter results was higher power costs stemming from the record-breaking heat event. PGE set a new peak load that surpassed our previous summer peak by 6%.

During this time, we also in this day had Mid-Columbia peak pricing of nearly $1,000 per megawatt hour, given significant transmission issues and constraints. Our generation plants performed well, very well, and we’re well integrated with our contracted energy supply. We also saw meaningful customer demand response reductions. Even still, our overall purchase power and fuel expense increased significantly. I want to thank and recognize our PGE colleagues who helped to ensure that customers continue to receive safe, reliable and underrented power throughout the heat wave. Given the impact of power costs on our third quarter results, we are narrowing our guidance range for the year. We now expect 2023 results to be in the range of $2.60 to $2.65 per share as compared to the previous range of $2.60 to $2.75 per share.

We anticipate fourth quarter results to improve as a result of normalized power cost conditions. Just as a reminder, fourth quarter 2022 regional gas prices peaked to over $55 per MMBtu and average mid-sea power prices rose to $2.65 — excuse me, $265 per megawatt hour. Additionally, while year-to-date power cost performance has been challenging relative to the annual update tariff or AUT, we anticipate a more favorable resource mix and market conditions through the fourth quarter. And finally, we expect continued effective O&M cost management and to hit our 2023 targets. Joe will walk through our trajectory for fourth quarter in more detail. Overall, our capital programs are on track, with Clearwater Wind expected to come online later this year and continued progress on our previously announced battery storage projects.

These are in addition to our base capital work that support customer growth, as well as grid improvements, focused on greater safety, as well as reliability and extreme weather resilience. Two other significant highlights from the third quarter include including our 2024 rate case negotiations and the announcement of several federal grants, which will enable the acceleration of new technologies and transmission construction. I’ll start with our GRC, which we are very pleased to conclude with parties and a way to commission order expected in the coming weeks. Overall, we settled recovery of ongoing capital investments operating and maintenance costs and notably wildfire, litigation management expenses and importantly, risk reduction in our power cost recovery framework, an important first step in addressing our PCAM mechanism which Joe will touch on in his remarks.

We also maintained a 50-50 capital structure and a 9.5% ROE. Additionally, we received approval to amortize $27 million in wildfire deferrals and collect forecasted wildfire mitigation costs under the automatic adjustment case. Lastly, federal grants. We are pleased and excited with the three Department of Energy announcements that build upon the work we’re doing to advance the clean energy transition and in collaboration with our regional partners. First, DOE announced a $250 million grant support upgrading the Bethel-Round view transmission line from 230 to 500 kV in partnership with the Confederated Tribes of the Warm Springs. The tribes have been our partner and co-owner of the 500-megawatt Pelton Round Butte Hydro projects along the Deschutes River, for decades.

Second, PGE, Utilidata and NVIDIA have consortium that was awarded $50 million grant for a smart chip grid project to improve visibility reliability and overall grid management. And lastly, the Pacific Northwest Hydrogen Association’s Hub is one of 7 projects nationwide to move forward to the next step and negotiations with DOE. PGE is contributing our former Boardman coal plant site and water rights for the green hydrogen production facility. We also look forward to an off-take agreement and working on green hydrogen power generation. These award selections represent just the start. Near-term capital will be determined in 2024 as negotiations proceed. We are still pursuing additional projects and opportunities and have submitted over $65 million in incremental grants to support another $125 million in additional projects as well as have other projects in the pipeline.

These projects represent growing momentum in the region that will create meaningful benefits for customers and communities for years to come. In summary, despite challenging operating conditions in the third quarter, we made important progress towards strengthening key cost recovery mechanisms as part of the constructive GRC settlement. Our entire team is laser-focused on execution for the remainder of the year. Our long-term growth plan is increasingly well established, underpinned by investments to meet growing customer needs, ensuring grid resilience and leading the clean energy transition. Our recent regulatory progress and ongoing capital investment reinforces our confidence at our long-term earnings growth rate of 5% to 7% in 2024 and beyond.

With that, I’ll turn it over to Joe, who will walk you through our financial results. Thank you.

Joe Trpik: Thank you, Maria, and good morning, everyone. I’ll cover our Q3 results before providing updates on our rate case, capital investments and liquidity and financing. Moving to slide 6. Our third quarter results reflect dynamic load in customer composition, challenging weather and power market conditions, continued emphasis on good resiliency and execution of our capital plan. The economy in our service territory continues to display strength. As Maria noted, regional economists anticipate significant investment in our area, particularly focused on semiconductor manufacturing. Many large high-tech companies in our footprint have signaled upcoming growth projects that could result in sizable economic benefits to our region.

Unemployment in our region was 3.4% as of September below the national average of 3.8%. Industrial load growth continued, albeit at a more moderate rate than witnessed in the first and second quarters, which we see as a short-term deviation on a long-term industrial growth trend. Total Q3 2023 loads increased by 0.2% weather-adjusted compared to Q3 2022. On a non-weather adjusted basis, total load decreased 0.9% year-over-year as weather was less severe across the full quarter despite a hotter August. Q3 2022 average temperatures were the hottest on record for the third quarter in our region. We continue to see significant heat this summer, but we saw a milder weather in September, which had 35% fewer cooling degree days than compared to 2022.

Residential load decreased 2.5% or 0.5% weather-adjusted compared to Q3 2022. Fewer cooling degree days and increased energy efficiency and distributed energy resource adoption contributed to this decrease. Residential customer growth increased 0.7%. Commercial load decreased 2.1% or 1.2% weather adjusted as we also witnessed increased penetration of energy efficiency and DDRs among commercial customers. Industrial load growth continued in Q3 2023, increasing 2.5% or 2.7% weather adjusted. As Maria mentioned, we view this moderation compared to previous quarters as temporary and anticipate a continuation of the growth cycle that we have been observing in recent years. Third quarter power market conditions remain challenging in 2023 with resource scarcity during the peak period surrounding the August heat event having acute impact on the quarter.

I’ll now cover our financial performance quarter-over-quarter. We experienced an $0.18 decrease in total revenues driven by a 0.9% decrease in total deliveries, combined with unfavorable changes in the average price of deliveries due to lower residential and commercial loads. Q3 2022 power cost conditions were also challenging and $0.27 of the quarter-over-quarter earnings change is attributable to power cost headwinds in 2022 that we normalize for this comparison. Current year power costs were also elevated, driving a $0.07 EPS decrease in the quarter, reflecting costs that were higher than anticipated in our annual update tariff. There was a $0.02 decrease in EPS from higher operating expenses, net of deferral-related items, primarily driven by higher generation and grid maintenance costs.

We also saw a $0.06 impact from depreciation and amortization expense due to higher plant balances year-over-year. A $0.03 decrease from the impact of higher interest expense due to higher long-term debt balances and short-term debt balances carried for a part of the third quarter, a $0.07 decrease due to the dilutive impact of draws on the equity forward sale, which last occurred in mid-July. Finally, we had a $0.03 decrease from other items, which included $0.08 of a decrease in other income due to the prior year medical plan buyout gain did not reoccur, partially offset by $0.03 increase from higher AFUDC from clean energy and base capital projects under construction and $0.02 increase from higher returns on nonqualified benefit trust and other miscellaneous items.

Turning to Page 7 for a summary of our 2024 general rate case to-date, which remains subject to OPUC approval. As Maria highlighted earlier, we are pleased to reach a constructive settlement on the remaining items, including recovery of recent capital investments and operating costs to maintain the system reliability and resiliency. Given the frequency and magnitude of extreme weather and resource constraints in our region, including the August heat event, the reliability contingency event provision represents a constructive solution to our power cost recovery framework. This update better reflects the impact of climate change and dynamic regional markets that we have been historically experienced. Additionally, steps in the docket will continue in the coming weeks, including annual power cost updates in November.

A commission decision is expected by December but could come sooner for rates effective January 1st, 2024. On to Slide 8, which shows our current capital forecast through 2027. We are continuing to evaluate emerging transmission projects that Maria and I mentioned in the Q2 call and plan to provide a robust capital forecast update on the Q4 call in February. I will also note that the PGE portion of projects receiving grant funds is not yet reflected in these figures as scoping and negotiations are ongoing. We will reflect these projects in our forecast once final plans have crystallized. The 2023 RFP has worked through preliminary administrative steps and is expected to officially launch to the market in the coming weeks. Submissions are expected in early 2024, with submission of a project shortlist anticipated in the first half of next year.

Project selection will take place shortly after in mid-2024. Turning to Slide 9 for a summary of our liquidity and capital finance — sorry, our liquidity and financing. Our strong balance sheet, investment-grade credit ratings, and stable credit outlook remains unchanged from our previous disclosures. Total available liquidity as of September 30th, 2023, is $925 million. In mid-August, we amended our existing revolving credit facility to extend the maturity, while also upsizing from $650 million to $750 million to provide additional flexibility. We also executed a $500 million first mortgage bond purchase agreement in late August, including $300 million of that that was issued as of September 30th, with the remaining $200 million to be issued under a delayed draw feature in the fourth quarter.

As I said previously, we issued the remaining $92 million under the equity forward facility in July, and we continue to have equity market availability under our ATM program. PGE has entered into forward sales agreements for $58 million of the total $300 million of the ATM as of the third quarter. We remain confident in our balance sheet and our ability to access the capital markets. and continued strong interest from both debt and equity investors in recent offerings. Careful dilution management remains an important focus as we continue to track towards our authorized 50-50 capital structure over time and maintain flexibility in financing options. Our results in the third quarter continue to reflect our investment year thesis as we execute to establish a sturdy growth foundation for PGE.

They also reflect ongoing challenges that we are all working to diligently manage through year-end. Some of the headwinds we have faced through Q3 are expected to dissipate in the last three months of the year, including empower cost. Turning to Slide 10 for our outlook for the fourth quarter. As Maria touched on earlier, indicators point to a more reasonable power market condition, especially compared to Q4 2022, which saw cold weather, pipeline disruptions and regional gas storage anomalies drive Pacific Northwest gas and power prices to extreme levels. Due to these factors, fourth quarter power costs were meaningfully higher than considered in the AUT baseline, which is represented in the chart. We expect impacts of load growth, depreciation, interest expense and dilution observed year-to-date to continue.

Operating cost execution remains a critical component of our plan and all corners of our business are leaning in to drive savings and results. Given these efforts, we expect our fourth quarter O&M to come in below our current full year run rate. Finally, we expect an improved resource mix compared to our AUT expectations that will allow us to make up ground in our annual power cost position. This includes better availability of generating resources improved plant outage expectations and portfolio optimization that allows strategic dispatch of our generation fleet. Due to load results in the third quarter being below expectations, we are revising our 2023 full year weather-adjusted load growth guidance from 2.5% to 3% to 2%, which is in line with our long-term expectations.

We continue to have strong visibility to incoming projects concentrated among digital and high-tech customers, which are continuing their growth path. As such, we remain confident in the load profile in our area and are reiterating our long-term load growth guidance of 2% through 2027. As Maria noted earlier, we are narrowing our full year earnings guidance to $2.60 to $2.65 per diluted share to reflect power cost challenges experienced in the third quarter. We have sharpened our load expectations for Q4 and anticipate power costs and O&M execution will drive necessary results to achieve this range. 2023 continues to represent a key pivot point for our direction towards sustained growth and value for customers and shareholders. Constructive regulatory clarity, a robust capital investment pipeline and solid service territory fundamentals give us renewed confidence in reaching our earnings growth guidance of 5% to 7% in 2024 and beyond.

As we enter the final months of 2023, our ongoing focus of providing clean, reliable and affordable energy remains unchanged. We look forward to furthering this core mission, which will enable prolonged value for our customers, communities and shareholders. And now, operator, we are ready for questions.

See also 12 Best Advertising Stocks To Invest In and 20 Most Valuable Business Lessons to Make You More Successful.

Q&A Session

Operator: Thank you. [Operator Instructions] Our first question comes from the line of Shahriar Pourreza of Guggenheim Partners.

A – Maria Pope: Good morning, Shah.

Joe Trpik: Good morning, Shah

Shahriar Pourreza: Good morning, Maria. Good morning, Joe.

Joe Trpik: Good morning

Shahriar Pourreza: Joe, you discussed getting, I guess, a little bit more in the weeds on the CapEx profile on longer term run rate, right, regardless of the RFPs. I know, obviously, we’re going to get an update in 4Q, but you’ve been in the seat for a few months now, and we’re still kind of looking at that declining CapEx profile on the slides. Can you just maybe elaborate on what you mean by robust. I mean is it fair to assume that $800 million run rate will step up materially? Just directionally, how we should think about it as we head into the fourth quarter. Thanks.

Joe Trpik: Hey, thanks, Shar. So the way I look at it is, when we say more robust, I think we would like to provide more transparency as we work through 2024 and the further years of our base business, the transmission that Maria had mentioned before as well as what I’ll call the potential for the opportunities, be it the RFPs that we’ve spoken to and the grants. I would not be unreasonable to say there’s some upward pressure there. But Shar, that’s what we’re waiting for is as we get through the rate case outcome here and get a little more clarity on the transmission plan and the grants that we hopefully, can give a little more of a transparent longer view of the possibilities as opposed to what is — as you see there, a relatively flat plan. In part that will also weigh into that as it relates to that base, I should say, is the most — how the most recent IRP that has come out impacts our base capital as it relates to supporting renewables as well.

Shahriar Pourreza: Got it. And then just on the financing side, Joe, just obviously, I guess how should we think about the forward equity findings and for any sort of wins under the next RFP round, I think it’s awarded next year, right? So you have an ATM now. Is that kind of the avenue you’re going to look at this point?

Joe Trpik: Well, I think we continue to evaluate based on the expectations and the outcomes that will come from the RFP our approaches. But I mean, I think an approach that starts with a base of having an ATM to support us, right? We can — we currently as much as we have about $250 million left to issue, right? The cash flows of the ATM are still — we haven’t yielded any from so far. But we’ll continue to evaluate the ATM as it relates to supporting our business from a – from a base transmission and others and then evaluate it on an episodic basis based on the size of the — any of these significant wins that could come from an RFP.

Shahriar Pourreza: Okay. Got it. And then lastly, just for me is maybe just tied a little bit deeper into the power cost aspect of the settlement. I guess how do you see the mechanism you got for, let’s just say, extreme events is actually insulating the EPS volatility. For example, like how would have impacted this quarter if you had it in place that past August. Thanks.

Joe Trpik: All right. And then so the mechanism itself is not finalized as of – as of yet. But based on our understanding, so that the definition of an event, there would be three items that would – that would come in to play as evaluating the — if there was an event, which would be the day ahead Mid-Columbia index price, BG’s eligibility to request resource adequacy assistance and then a neighboring balancing authority that’s publicly declared an event. So those are sort of what we believe the definition would be. So if we applied those, we do believe the heat event that occurred in August, would have triggered that definition. We would also believe that if we were to look to the prior years, there was a significant collection of events that not just the seat about if we were looking to 2022 and 2021, there are several events that would meet that.

So we do believe that a portion of our costs that are incurred in this current year would have been defined to pull into that. We’re not – because the commission hasn’t issued an order, and we haven’t finalized, we’re not at the point of declaring what that value or average would be. But once the orders come out, we have that clarity. We’ll consider, discussing what that average impact would have been over the last number of years here, potentially as we get to year-end. But is there something there? Yes. Are these events something that occur at least annually or so? Yes.

Shahriar Pourreza: Okay. Perfect. Thank you, guys. We’ll see you in a couple of weeks. Appreciate it.

Joe Trpik: Well. Thank you.

Maria Pope: Thank you.

Operator: Thank you. Our next question comes from the line of Richard Sunderland of JPMorgan.

Maria Pope: Good morning.

Joe Trpik: Good morning.

Richard Sunderland: Can you hear me?

Maria Pope: Yeah.

Joe Trpik: Yes.

Richard Sunderland: Great. Thanks for the time today. A lot of helpful color on the quarter and looking at the 4Q here as well, maybe starting on the O&M, I just wanted to make sure it’s parsing this correctly. It sounds like you were standing up some savings specifically to help this year. Is that the case? And how does that flow through versus, I guess, effectively, you’re planning at the start of the year? And then just to be more precise on kind of 2023 versus beyond. Are any of these savings kind of structural into 2024 and more long-term?

Maria Pope: So, Joe, do you want to take this one?

Joe Trpik: Sure. Good morning, Richard. So as it relates to O&M. So yes, we do believe some work that we’ve been doing throughout the year, when I say throughout the year, more think to April and beyond. Will yield some benefits to us financially as reducing us below our run rate that we’re currently after the full year? Yeah. We did see a sort of a reduction in our — what I’ll call our, overspend to expectation in the third quarter, but we were still over, but we expect in the fourth quarter, we will yield some O&M savings. Those O&M savings are meant to be like a structural going forward, management of our cost. I mean, so we would expect to have the same structure in place. These are not one-time items to achieve benefits for the year, but more structural items as we relate to changing the way we manage our costs and run our business going forward. So we would expect that will continue.

Maria Pope: Richard, one of the things as you look at our external statements, I think it’s important that we acknowledge that there’s a couple of things going on. The first is you can see the amortization of deferrals from the, ice storm, wildfire events, prior PCAM years and other things are increasing that O&M line. But so our ongoing wildfire prevention work, all of the mitigation we do, the interaction we do with the US Forest Service and Local Entities, really around vegetation management and others. And through this rate case, there were some really important mechanisms that were put in place. That combined with what Joe was speaking of in terms of the ongoing alignment, reduction in our costs, quite frankly, just driving efficiencies, using technology better.

You can see we’ve had plant availability most recently at the 96 percentile, what rate and our first data rate was just 1.7%. That was a huge contributor particularly to the third quarter. We can see in our distribution system, work order output is a 12% improvement year-over-year. We’re seeing for customers’ better crew alignment and scheduling restoration priorities. And our duration of impacting events was an improvement of 13% and overall 1.3 million customer minute outages — excuse me, customer outage minutes were saved just from 2022. So there’s a real impact not only to our cost structure and to better operations, but to serving our customers more reliably with power that they come to expect as we’ve seen increasing amounts of extreme events throughout our area.

Richard Sunderland: Understood. That was very helpful color. Maybe zooming out to a high level, and Maria, you brought this up in terms of the wildfire work. But could you speak a little bit to sort of what you’re focused on and what your work with the industry is focused on in terms of wildfires overall. It’s an industry issue. It’s been obviously hugely topical this summer and for prior years. Just curious if there’s anything you can share in terms of where you and EI are focused on this front currently?

Maria Pope : Sure. It’s a good question. And let me turn first to ourselves internally. We have absolutely improved our practices, better use of technology and some truly cutting-edge technologies where we are able to share that access with other parties, whether it be forest agencies and the national the state and the local entities where we’re working in conjunction on vegetation management. The Ag bill that’s working its way through Congress, I think, is a really good example where we’ve — includes timber and debris removal on an expedited basis. We’ve also had permit reform in particular with the U.S. Forest Service, reducing permits from several years down to months and really accelerated our collaboration and our improved practices.

As we look forward at the state level and the federal level, clearly, we need to do more. It’s a high priority across the industry, and as well as with regulators. And so I think you’ll see increased actions coming that really support the ongoing reliability and important service that utilities provide.

Richard Sunderland: Got it. Thank you. And maybe one last one for me. The state and federal work excited around the semiconductor industry. And then your latest IRP update is that all harmonized? Or is there even some elements of this that have emerged that are additive to that outlook as you recently refreshed it?

Maria Pope : So I think the use of the word harmonized is a really interesting term. We are seeing the pace of change. And clearly, the programs that we’ve seen come out of the federal government Department of Energy that supports transmission, better use of a smart grid and our partnerships between tribes, all the way to NVIDIA are really making a difference. But you take a look at the CHIPS Act and then what the State of Oregon has done through the semiconductor task force and the legislatures appropriation of $240 million of matching funds. You can find on the state website the 15 companies that we’ll receive funds ranging from just a couple of million dollars to $115 million. Those projects, some of which are included in our forecast, but the majority are not.

And if you look at that list, about 85% of those projects are actually in the Portland General Electric service territory. So for the next decade, it is a tremendous opportunity for the company for the region and is also combined with a pretty extensive workforce support and investments in our universities really focusing in on an important reshoring of our technical strength as a country. And just as a reminder, 15% semiconductor manufacturing is in this region. So it’s a real strength for our state and for the company.

Richard Sunderland: Great. Thank you very much for the time today.

Maria Pope: Thank you.

Joe Trpik: Thank you.

Operator: Thank you. Our next question comes from the line of Julien Dumoulin-Smith of Bank of America.

Julien Dumoulin-Smith: Hey, good morning, team.

Maria Pope: Hey, Julien.

Julien Dumoulin-Smith: Hey, thank you guys. Appreciate it. Perhaps let’s pick up on that last question there quickly. How do you think about tying the sort of the timeline between having a more normalized 2% here in the current year to getting up to some of the higher level that you talked about earlier, just a moment ago with some of the benefits from the CHIPS Act and at the same time still having that 2% long-term. I mean, sort of how do you see the profile of that sales growth and the confidence for I think previously when we connected some really strong commentary around customer growth, sustaining itself in addition to sales whether just sales growth, sustaining itself here in the medium term? I don’t want to put words in your mouth.

Maria Pope: Yeah. No, no, it’s interesting. We look at it as building blocks and I think there’s rarely been a period of time of so much change and opportunity. So first of all, we’re a state and a region that has benefited from immigration, and while that has paused, most recently, we continue to see really strong blocking and tackling economic growth across our service territory. What we also are seeing is increased data centers and the continued digital expansion. One of the things that’s important about that is that many of those facilities are built, but not yet built out. And so the infrastructure is there, and you’ll see the capacity built out over the coming months and quarters. And then finally, the longer term and really significant opportunities comes in the manufacturing side of things.

And this is everyone from silicon manufacturers all the way down to semiconductor manufacturers to those who are really helping with the tools and cutting-edge development like Lam research or metro graphics or others. And there’s quite a bit of opportunity that some of which we can see today and are already serving, and much of which will come out over the number of quarters, years, and actually even through the decade. It’s truly game changing for the state as well as for us as a utility to be able to serve such growth.

Julien Dumoulin-Smith: Yeah. Maybe just to clarify that. You’re not pulling back on any of your earlier confidence in light of the 2023?

Maria Pope: No. We aligned our 2023 number really with our long-term guidance of 2%. I think it’s a — we feel very confident in the 2% number and I think my comments underlie optimism for even higher growth than that.

Julien Dumoulin-Smith: Okay. All right. Fair enough. I’m just trying to tease the near term from the long-term here. And then if you can, I mean speaking about kind of reconciling 2023 against the longer-term, how about 2023 in the levers that you’ve pulled here to keep it at the lower end, despite the litany of more weather-related pressures here, as you alluded to earlier? Is there a read into 2024 that we should be aware of? I know you provided some commentary in the remarks, but is there any kind of direct read through whether it’s O&M or otherwise in terms of pull forward that’s a 2024 we should just be ready for?

Maria Pope: Yeah. No, I think as Joe outlined, we have really focused cost management efforts on how we manage the business, stay very constant to customer prices and drive efficiencies across our organization. But we remain confident in the long-term growth rate of 5% to 7%. And as we’ve always said, 2023 was an investment year.

Julien Dumoulin-Smith: Got it. But no hesitation on 2024 in turn from what I can tell?

Maria Pope: No, not at all.

Julien Dumoulin-Smith: Okay. Wonderful. Thank you so much. You guys take care.

Maria Pope: Thank you. You too.

Operator: Thank you. Our next question comes from the line of Nicholas Campanella of Barclays.

Maria Pope: Good morning.

Nicholas Campanella: Hey, thanks for taking my questions. Good morning. I guess, just on the revenue increase to $391 million. I know that there’s a lot of moving pieces with power costs and you called out the $183 for power costs. But is the net of those two numbers that’s what’s falling to the bottom line? Or is that too simplistic?

Joe Trpik: I think — I’m not sure, I would do that math on the net power cost. And specifically, we’re talking about 2024 here. But I think the performance of what will fall to the bottom line is obviously our load recovery, our return on the assets here as we build to 2024. I mean, the rate case overall and the net outcome that we have, we’re pretty satisfied that it was a really constructive dialogue And the case itself fits within our what I’ll call our calculus to Maria’s comments of our long-term growth plan.

Nicholas Campanella: Great, great. And then could you just expand a little on why load and demand mix was an issue for third quarter, but what’s just driving your confidence level for the fourth quarter? I’m sorry, if I missed that.

Joe Trpik: Yeah. So I think as it relates specifically to the third quarter, right, the mix shift was away from the residential commercial heading towards the larger, and it’s really due to two things that occur more in — the one that occurs more in the summer and one overall. One is energy efficiency, we have a little more penetration on energy efficiency at that commercial and that residential level. But also — and more of the summer item, there was rooftop solar penetration that was occurring at both at commercial and at residential level that was pushing down the overall load. The customer growth continues to be as we had anticipated, I believe we had 0.7% customer growth. But it’s just that that pressure from the energy efficiency and the DER penetration that are driving it.

Nicholas Campanella: Okay, great. And then just one more, Joe, just on the equity. I thought that you said that you would pull the full ATM down by the end of the year. If I’m wrong, please correct me. But just as an aside, how do you think about on this current CapEx plan with the equity announced to date, your ability to get to the 50%? Or is there more that needed to be thinking about? Thank you.

Joe Trpik: So all right, thank you. Specifically, as it relates to the ATM, we have not pulled down on the ATM as a fall. So what we have entered into is about we have — I believe we disclosed $58 million of the ATM we have entered into agreements on, none of which we have closed upon. So from a cash flow standpoint, the entire ATM is outstanding with $240-ish million is left to take into the market. As it relates to our — could you say your second part of your question again, just to make sure I don’t answer it as it relates to the capital?

Nicholas Campanella: I just wanted to be sure, are you leaving it open to whether or not you would pull that down by the end of the year? Or could that be further feathered into 2024 and beyond?

Joe Trpik: I would say that the ATM that we have in the — our equity needs are complete for this year, and the ATM would be open for next year. We don’t have any at least current needs. And we obviously would always be opportunistic with our equity, but we do not have any current needs for the ATM.

Nicholas Campanella: Thank you.

Operator: Thank you. Our next question comes from the line of Gregg Orrill of UBS.

Gregg Orrill: Thank you. So two parts. First, just how do you — regarding the $0.27 to $0.32 driver on the current year at variable power costs, what — how do you think about putting that range in place? What kind of gets you there? And then secondly, how are you thinking about the level of ownership in renewables in your RFP and just maybe not a number, but sort of appetite for ownership, I guess?

Maria Pope: Okay. So let me take your first question and then your second and if I don’t do an adequate job, Joe can fill in. So with regards to power costs, the $0.27 to $0.32, roughly about half of that, I would call sort of structural. And you can see that in the AUT numbers, we can see it in what we sort of have already in place for the quarter. The other part is really the work that we do every day. And the work that we can see and that would not be unusual for those kind of activities to yield those kind of results for what is a pretty challenging fourth quarter and a lot of work that we have to do, we feel confident that we’ll get there. With regards to the RFP, we feel be issued shortly. We will put in a short list of opportunities that the company would hope to be able to participate in.

Those have a little bit of a different timing just to make sure that there is full transparency, but we’re looking for the final RFP to be out by the end of this year. The first half, probably the short list will be submitted by that time. And we would hope that by the end of 2024, we would have finished some negotiations, obviously overseen by an independent evaluator to make sure that we are driving the lowest-cost, least-risk projects for our customers. And we’ve been pretty fortunate so far with regards to the company’s ownership projects, and that has really been being able to drive competitive costs, be able to manage risks and quite frankly, have very good partners as we move forward. So we would hope to have the same circumstances as we enter into 2024 and beyond.

Clearly, there’s a lot of opportunities.

Gregg Orrill: Appreciate it.

Maria Pope: Thank you.

Operator: [Operator Instructions] Our next question comes from the line of Andrew Levi of HITE Hedge Asset Management.

Andrew Levi: Hi, guys. Can you hear me?

Maria Pope: Good morning, Andy.

Andrew Levi: Hey, how are you?

Maria Pope: We can.

Andrew Levi: Okay. That’s good, always a good thing. Just a few questions, if you don’t mind. Just on the August that — hurt things a little bit for the quarter. If you had this settlement on the PCAM in place, just for that event, not for the quarter, but just for that event, how would that have kind of played out? And how would we think about the numbers? Again, it’s more of a guesstimate by you guys, but I’m just curious?

Joe Trpik: So Andy — good morning. So we are — back to what I said earlier, so we do believe the obvious event would be would meet the definition, although that definition is still to be finalized by the commission order. Each event here is unique. But to your comment, and we’re not signing numbers here yet, but they’re would there be some — I hate to be so big, but would there be some impact to our results this year, if it was treated positively, yes. And this event was not — even though each event is unique, not uncommon, over the last — from 2020 to 2022, there were about 15 events that we believe would meet the definition of an RCE over about 40 days. So and — for right now, I would say that we believe there would have been some positive impact to the results for the quarter, if this meets the definition, but we’d like to wait and see and make sure we’re aligned on that definition and calculation with the commissions ordered before we sort of declared what the result would or could have been.

Maria Pope: Andy, this is a solid first step as we work to have power cost mechanism that is comparable to other utilities across the country.

Andrew Levi: Okay. And I guess that’s something for the next rate filing as well to try to improve once again? And then my second question, is around transmission CapEx. And obviously, we have to wait for the fourth quarter. You talked about a robust update on the CapEx in general. But can you just talk about your transmission strategy and how that may ultimately play into the RFPs and how much capital you kind of want to deploy from one to the other with transmission CapEx being a little bit more predictable because obviously, there are no RFPs involve?

Maria Pope: Sure. Well, thank you and clearly, we’re similar to other utilities across the countries — we look at increased electricity use, growing service territory and renewable development transmission is an important component. When we look at our transmission strategy in particular the core of our projects that we’re looking at are actually within our service territory or adjacent to our service territory. Many of them are reconductoring. Most of them use existing rights of way. And so they’re relatively lower risk, easier to execute projects. And as we build those out and better understand the significant growth in customer usage, we will have more announcements as we move forward. And we’re very encouraged as well by the discussions at the federal level with regards to facilitating faster transmission citing and making all of the permitting easier to do.

There’s no question that we need to build transmission and whether it is the Pelton Round Butte in partnership with the Confederated Tribes of the Warm Springs or reconductoring and within service territory work. It’s a really important opportunity as we move forward. And we will have a decade of projects in front of us that will enhance our overall reliability.

Andrew Levi: Okay. And I just wanted to get back to PCAM because honestly, I’m pretty honest, right? A couple of people hitting me up here on my ID. So I just want to make sure there’s no confusion. So the $0.07 hit or $0.07 negative variable quarter-over-quarter from net variable power costs. You’re not saying that, that PCAM mechanism that has been modified would only have helped by $0.07? Or should we not — is that not like apples-to-apples, that negative $0.07 and how that PCAM. Without getting into the details of it because I think some people are kind of looking at it where just straight apples-to-apples and I’m guessing if not that simple.

Joe Trpik: Andy, so as you know, each year, the PCAM, we set our baseline and that $0.07 year-over-year is just really our relative performance in the quarter to the baseline. So it is potentially any impact of the heat up inside of that performance, but that is in no way meant to identify that. It is just the overall the design by quarter of how the AUT identified net variable power cost to our performance. So yeah, there is no direct linkage…

Andrew Levi: Right. And then as you get into the fourth quarter, that’s part of the reason why there’s such a large benefit because there was such a large hit last year, and now you’re getting a recovery of that this year.

Joe Trpik: Right. As a reminder, so as it relates to year-to-date, as we disclosed in the 10-Q, we are $28 million above the baseline, part of what drives the fourth quarter through that resource availability mix is an expectation that we will move from being above the baseline to some amount below the baseline by the end of the year.

Andrew Levi: Okay. And then, I guess, part of it is also fuel as well, right? From the fourth quarter, right? Lower..

Joe Trpik: That is – to the — key to the fourth quarter here is the expectations of resource mix, what we’ll consider normal win, normal weather, normal — what we’ll call normal market pricing, and that all will allow us to optimize our portfolio and help us to move in the — within the PCAM band between the above to below.

Andrew Levi: And its seem like you guys are in great shape heading into 2024. I mean, beyond this rate case settlement that hopefully gets approved, you’ve had modifications. You’ve got top line growth, robust CapEx opportunities and commission that’s been very supportive and you guys working well with them. I mean, I don’t see anything on the negative side. I don’t know if you guys can do it any differently, but…

Joe Trpik: We — Andy, we continue to write the rate case outcome, we would agree it was very, very constructive. The growth opportunities that we have previously spoken to are continue to be supported. And when I say growth on the investment side, either through the IRP update or through some of the most recent grant that there’s clearly the opportunities and our sort of a longer-term growth plan, the facts that came out during the quarter continue to validate at that point.

Andrew Levi: Okay. People are getting tired of hearing me ask questions. So I want to move, but have a great weekend, guys.

Joe Trpik: Thank you, Andy.

Maria Pope: Thanks, Andy

Operator: Thank you. Our next question comes from the line of Travis Miller of Morningstar, Inc. Please go ahead, Travis.

Travis Miller: Thank you.

A – Maria Pope: Good morning, Travis

Travis Miller: Good morning. A quick follow-on to some of the discussion early. The decoupling mechanism that was in the settlement, how would that have affected some of the variability in the earnings or just financials in general — this year and the third quarter.

A – Maria Pope: It’s a good question. And in the third quarter where we did see lower residential and small commercial energy usage, it would have had an impact. We had had a decoupling mechanism previously, and this decoupling mechanism is a good first step in improving how that looked. I’d also say that weather have — had a significant impact on the third quarter, and that would not have been included.

Travis Miller: Okay. Okay. Very good. And then again, related, are there capital investments that you can make over the next couple of years that might reduce either the variability in some of those extreme events or in general, power cost variability on the capital side? Any thoughts?

A – Maria Pope: Yes. Absolutely. And as we look at on the power cost side, I mentioned we had a solid first step with regards to the PCAM. We’ve also invested significantly in our processes, our people, our systems, we have more work to do, but it is making a difference, and we’re able to update our annual update tariff with those annually when we don’t have a rate case. We also have additional capacity contracts and our three battery storage projects, which are progressing quite well, will have a significant impact on our ability to be able to balance between days, not necessarily provide longer-term reliability. But certainly, the warrant price stability around power costs. All of them are important. And I would add that the region continues to move forward with day ahead market discussions as well as resource adequacy discussions through the Western powerful. So all of those things taken together will improve the situation.

Travis Miller: Okay. Great. That’s great. Thanks.

A – Maria Pope: Thank you.

Operator: Thank you. I would now like to turn the call back over to Maria Pope for closing remarks. Madam?

Maria Pope: Thank you very much. We appreciate your interest in Portland General Electric. We look forward to connecting with everyone soon, in particular, those who will be at the EEI conference in a couple of weeks. Thank you for joining us this morning. Have a good weekend. Good day.

Operator: This concludes today’s conference call. Thank you for participating. You may now disconnect.