Good morning, everyone, and welcome to Portland General Electric Company's third quarter 2023 earnings results conference call. Today is Friday, October 27th, 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. If you would like to ask a question during this time, press star, then the numbers one one on your telephone keypad. If you would like to withdraw your question, please press star one one again. If you do intend to ask a question, please avoid the use of speakerphones. For opening remarks, I will turn the conference over to Portland General Electric's Manager of Investor Relations, Nick White. Please go ahead, sir. Thank you, Latif. Good morning, everyone. I'm happy you can join us today. Before we begin this morning, I would like to remind you that we have prepared a presentation to supplement our discussion, which we will be referencing throughout the call. The slides are available on our website at investors.portlandgeneral.com. Referring to slide two, 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 can 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. 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. Thank you, Nick, and good morning. Thank you all for joining us today. Beginning with slide four, 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 five, we continued 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 U.S. semiconductor manufacturing occurs in our state, largely within PGE service territory. The sector will benefit not only from the federal CHIPS Act but from the $240 million that 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 witnessed day-ahead Mid-Columbia peak pricing of nearly $1,000 per MWh, given significant transmission issues and constraints. Our generation plants performed well, very well, and were well integrated with our contracted energy supply. We also saw meaningful customer demand response reductions. Even still, our overall purchased power and fuel expense increased significantly. I want to thank and recognize our PGE colleagues who helped ensure that customers continued to receive safe, reliable, and uninterrupted power throughout the heatwave. 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-$2.65 per share, as compared to the previous range of $2.60-$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-C power prices rose to $265 per MWh. 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: concluding 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 await a commission order expected in the coming weeks. Overall, we settled recovery of ongoing capital investments, operating and maintenance costs, and notably, wildfire vegetation 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 clause. 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 to support upgrading the Bethel- Round Butte 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 MW Pelton Round Butte Hydro projects along the Deschutes River for decades. Second, PGE, Utilidata, and NVIDIA has a consortium that was awarded $50 million grant for a smart chip grid project to improve visibility, reliability, and overall grid management. Lastly, the Pacific Northwest Hydrogen Association's hub is one of seven 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 offtake 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 in our long-term earnings growth rate of 5%-7% in 2024 and beyond. With that, I'll turn it over to Joe, who will walk you through our financial results. Thank you. 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 six, our third quarter results reflect dynamic load and customer composition, challenging weather and power market conditions, continued emphasis on grid 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 DERs 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 an acute impact on the quarter. I'll now cover our financial performance quarter over quarter. We experienced a $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 a prior medical plan buyout gain, did not reoccur, partially offset by $0.03 increase from higher AFUDC from clean energy and base capital project under construction, and $0.02 increase from higher returns on non-qualified benefit trusts and other miscellaneous items. Turning to page seven 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 experiencing. 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 1, 2024. On to slide eight, 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. Bid 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 nine for a summary of our liquidity and capital financing. Our equity, our liquidity and financing. Our strong balance sheet, investment-grade credit ratings, and stable credit outlook remain unchanged from our previous disclosures. Total available liquidity as of September 30, 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 30, 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 in power 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%-3% to 2%, which is in line with our long-term expectation. 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%-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. Now, operator, we are ready for questions. Thank you. As a reminder, to ask a question, you will need to press star one one on your telephone. To remove yourself from the queue, you may press star one one again. Please stand by while we compile the Q&A roster. Our first question comes from the line of Shar Pourreza of Guggenheim Partners. Morning, Shar. Good morning, Maria. Morning, Joe. Morning. Joe, you discussed getting, I guess, a little bit more in the weeds on the CapEx profile on longer term spending run rate, right? Regardless of the RFPs. I know obviously we're going to get an update in 4Q. You've been in the seat, you know, for a few months now, and we're still kind of looking at that declining CapEx profile on, 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. So, yeah, thanks, Shar. So you know, the way I look at it is so when we say more robust, I think we would like to provide more, you know, 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, you know, the potential for the opportunities, be it the RFPs that we've spoken to and the grants. It, you know, would not be, you know, 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, you know, what is, as you see there, a relatively flat plan. A nd, you know, in part, that will also weigh into that as it relates to that base, I should say, is, you know, the most-- how the most recent, IRP that has come out impacts our, our base capital as it relates to supporting renewables as well. Got it. And then just on the financing side, Joe, just obviously, I guess, how should we think about the forward equity financing 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? Yeah, well, I think we continue to evaluate based on, you know, the expectations or, 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 currently, as much as we have, you know, 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, you know, the ATM as it relates to supporting our business from a base, a transmission in others, and then evaluate it on an episodic basis based on the size of any of these significant wins that could come from an RFP. Okay, got it. And then lastly, just for me, is maybe just dive a little bit deeper into the power cost aspect of the settlement. I know, I guess, how do you see the mechanism you got for, let's just say, extreme events as actually insulating the EPS volatility? For example, like, how would it have impacted this quarter if you had it in place that past August? Thanks. Right. So, you know, the mechanism itself is not finalized as of yet, but based on our understanding, the definition of an event, there would be three items that would come into play as evaluating if there was an event, which would be the day-ahead Mid-Columbia index price, PGE'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 definitions would be. Shar, if we applied those, we do believe the heat event that occurred in August would have triggered that definition. We'd also believe that if we were to look to the prior years, there was a significant collection of events that, you know, not just this heat event. 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, you know, 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 order comes out and we have that clarity, we'll consider, you know, discussing what that, you know, average impact would have been over the last number of years here, you know, potentially as we get to year-end. But there is, so there is Is there something there? Yes. Are these events something that occur at least, you know, annually or so? Yes. Okay, perfect. Thank you, guys. We'll, we'll see you in a couple of weeks. Appreciate it. Thank you. Thank you. Thank you. Our next question comes from the line of Richard Sunderland of JP Morgan. Morning. Good morning. Can you hear me? Yep. Yes. Great. Thank you for the time today. A lot of helpful color on the quarter and looking to forecast here as well. You know, maybe starting on the O&M, I just wanted to make sure I was parsing this correctly. It sounds like you were standing up some savings specifically to help this year. Is that the case? And you know, how does that flow through versus, I guess, effectively, your plan 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? So, Joe, you want to take this one? 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 to April and beyond, will yield some benefits to us financially as reducing us below our run rate that we're currently at for the full year. You know, we did see a sort of a reduction in our overspend to expectation in the third quarter, but, you know, we were still over, but we expect in the fourth quarter, we will yield some O&M savings. Those O&M savings are intended to be like a structural going forward management of our costs. I mean, so we would expect to have that, 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 for to continue. 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 are ongoing wildfire prevention work, all of the mitigation we do, the interaction we do with the U.S. 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 deriving efficiencies, using technology better. You can see we've had plant availability most recently at the 96th percentile, and our forced outage 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 in 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. 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've come to expect as we've seen increasing amounts of extreme events throughout our area. Understood. That's, that was very helpful, caller. 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, and what, you know, your work with the industry is focused on in terms of, you know, wildfires overall as 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, you know, where you and EEI are, are focused on this front currently. 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're able to share that access with other parties, whether it be forest agencies in 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 both at the state level and the federal level, clearly we need to do more, and it's a high priority across the industry, and as well as with regulators. So I think you'll see increased actions coming that really support the ongoing reliability and important service that utilities provide. Got it. Thank you. Maybe one last one from me. The state and federal work you cited around the semiconductors 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 know recently refreshed it? So I think the use of the word harmonized is a really interesting term. We are seeing, you know, 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, 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 legislature's appropriation of $240 million of matching funds. You can find on the state website the, 15 companies that will receive, funds raising ranging from just a couple 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 Portland General Electric service territory. So for the next decade, it is a tremendous opportunity for the company, for the region, and it's also combined with a pretty extensive workforce support and investment in our universities, really focusing in on an important reshoring of our technical strengths as a country. And just as a reminder, 15% of semiconductor manufacturing is in this region. So it's a real strength for our state and for the company. Great. Thank you very much for the time today. Thank you. Thank you. Our next question comes from the line of Julien Dumoulin-Smith of Bank of America. Hey, good morning, team. Hey. Hey, thank you, guys. Appreciate it. Let me, 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, you know, 2% here in the current year to kind of getting up to, some of the higher levels that you talked about earlier, you know, just a moment ago, with some of the benefits from the CHIPS Act, and at the same time, still having, you know, 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, some really strong commentary around customer growth, sustaining itself in addition to sale, whether adjusted sales growth, sustaining itself here i n the medium term. I don't want to put words in your mouth. And Julian... Go for it. Yeah, no, no. I t's interesting. We look at it as building blocks, and, and I think there's rarely been a period of time of, 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, we continue to see really strong, like, 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 a Lam Research or a Mentor Graphics or others. And there's quite a bit of opportunity that will 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. Yeah, maybe just to clarify that, you're not pulling back on any of your earlier comments in light of the 2023? No. You know, I think- Yeah. No, we aligned our 2023 number really with our long-term guidance of 2%. You know, I think it's we feel very confident in the 2% number, and I think my comments underlie optimism for even higher growth than that. 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, you know, kind of reconciling 2023 against the longer term, how about 2023 and the levers that you've pulled here to keep it at the lower end, you know, 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 to 2024 we should just be ready for? Yeah. No, I think as Joe outlined, we have really focused cost management efforts on how we manage the business, stay very cognizant to customer prices, and drive efficiencies across our organization. But we remain confident in the long-term growth rate of 5%-7%. And as we have always said, 2023 was an investment year. Got it, but no hesitation on 2024 in turn, from what I can tell? No, none at all. Okay, wonderful. Thank you so much. All right, you guys take care. Thank you. You too. Thank you. Our next question comes from the line of Nicholas Campanella of Barclays. Hey, thanks for taking my question. Morning. Good morning. morning. Good morning, Morning. I guess, just on the revenue increase to $391 million, you know, I know that there's a lot of moving pieces with power costs, and you called out the $183 million 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? You know, I think, I'm not sure I would do that math on the net of the power costs, and specifically, we're talking about 2024 here. Yep. But I think the, you know, 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, you know, 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. 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. 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. The one that occurs more in the summer period and one overall. One is energy efficiency. We had a little more penetration on energy efficiency at that commercial and that residential level. But also, and more the summer item, there was rooftop solar penetration that was occurring at both that commercial and that residential level, that was pushing down the overall load. I mean, the customer growth, you know, continues to be as we had anticipated. I believe we had 0.7% customer growth, but it's just that pressure from the energy efficiency and the DER penetration that are driving it. Okay, great. 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 kind of 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 needs to, that we need to be thinking about? Thank you. So, all right, thank you. Specifically, as it relates to the ATM, we have not pulled down on the ATM as a whole. So what we have entered into is about, you know, 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, right, the entire ATM is outstanding, with $240 million-ish 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? I just wanted to be sure. Are you leaving it open to whether or not you would, you would pull that down by the end of the year, or could that be further feathered into 2024 and beyond? I would say that the ATM that we have and, you know, 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, you know, we obviously would always be opportunistic with our equity, but we do not have any current needs for the ATM. Thank you. Thank you. Our next question comes from the line of Greg Orrill of UBS. Morning, Greg. Good morning. Hey, good morning. So, two parts. First, just, how do you, you know, regarding the, the $0.27-$0.32 driver on the current year, the variable power costs, what, y ou know, how do you think about putting that range in place? W hat kind of gets you there? And, then secondly, how are you thinking about the level of ownership in, you know, renewables in your RFP and, just maybe not a, maybe not a number, but, you know, sort of appetite for ownership, I guess? 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-$0.32, you know, roughly about half of that, I would call sort of structural. And you can see that, you know, 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 it's that would not be unusual for those kind of activities to yield those kind of results for what is a pretty challenging for a quarter and a lot of work that we have to do. We feel confident that we'll get there. With regards to the RFP, the RFP will 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 shortlist 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. Appreciate it. Thank you. Again, to ask a question, please press star one one on your telephone. Once again, that's star one one on your telephone to ask a question. Our next question comes from the line of Andrew Levi of HITE Hedge Asset Management. Hi, Andrew. Good morning, Andy. Can you hear me? Hey, how are you? We can. Yep. Okay, that's good. All is a good thing. Just a few questions, if you don't mind. Just on the August event 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, you know, it's more of a guesstimate by you guys, but I'm just curious. You know, Andy, we're... Good morning. We are, you know, back to what I said earlier, we do believe the August 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, you know, we're not assigning numbers here yet, but would there be some impact-- I hate to be so vague, but would there be some impact to our results this year? If it was treated positively, yes. These, this event was not an, e ven 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 Andy, 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 commission's order before we sort of declare what the result would or could have been. Andy, this is a solid first step, as we work to have a power cost mechanism that is comparable to other utilities across the country. Okay, and I guess that, you know, that, that's something for the next rate filing as well, to try to improve once again. Then my second question is around transmission CapEx. And obviously, you know, we have to wait for the fourth quarter. You know, 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, and with transmission CapEx being a little bit more predictable, because obviously there are no RFPs involved? Sure. Well, thank you. A nd clearly, you know, we're similar to other utilities across the country as 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, as we build those out and better understand the significant growth in customer usage, we will have more announcements as, as we move forward. And we're very encouraged as well by the discussions at the federal level with regards to facilitating faster transmission siting 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 Line 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. Okay. And, I just wanted to get back to, PCAM, 'cause honestly, I'm pretty honest, right? A couple people hit me up here on my ID. So I just wanted 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, that negative $0.07 and how that PCAM w ithout getting into the details of it. Like, because I think some people are kind of looking at it where, you know, just straight apples to apples, and I'm guessing it's not that simple. No, and Andy, so as you know, each year, the PCAM, we set our baseline. And, you know, that $0.07 year over year is just really our relative performance, you know, in the quarter relative to the baseline. So it is, you know, potentially any impact of the heat event 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, you know, there's no direct linkage there. 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 recovery of that this year. 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. Okay, and then I guess, I guess part of it is also fuel as well, right? For the fourth quarter, right? Lower- Right. That is, you know, to the... The key to the fourth quarter here is the expectations of resource mix, you know, what we'll consider normal wind, 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, you know, move within the PCAM band, between the above to below. I mean, it seems like you guys are in great shape heading into 2024. I mean, beyond, you know, you have this rate case settlement that hopefully gets approved. You've had modifications, you got top-line growth, robust CapEx opportunities, and, you know, a commission that's been, you know, very supportive and you guys working well with them. I mean, I don't see anything, you know, on the negative side. I mean, I don't know if you guys agree with any differently, but... Yeah, we continue, right. And Andy, we continue. The rate case outcome, we would agree it was very, very constructive. The growth opportunities that we have, we have previously spoken to are, you know, 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 grants that, you know, there's clearly the opportunities and our sort of a longer term growth plan, you know, the facts that came out during the quarter continue to validate that plan. Oh, okay. People are getting tired of hearing me ask questions, so I'm going to move on. But have a great weekend, guys. Thank you, Andy. Thanks, Andy. Thank you. Our next question comes from the line of Travis Miller of Morningstar Inc. Please go ahead, Travis. Thank you. Hi. Morning, Travis. Good morning. A quick follow-on to some of the discussion earlier. 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 in the third quarter? 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 have had a decoupling mechanism previously, and this decoupling mechanism is a good first step in improving how it's looked. I'd also say that weather has had a significant impact on the third quarter, and that would not have been included. 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? Yes. Absolutely. And as we look at on the power cost side, I, you know, 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've 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 more 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 Power Pool. So all of those things taken together, will improve the situation. Okay, great. That's great. Thanks. Thank you. Thank you. I would now like to turn the call back over to Maria Pope for closing remarks. Madam? 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 and day. This concludes today's conference call. Thank you for participating. You may now disconnect.