Good morning, everyone, and welcome to Portland General Electric Company's First Quarter 2024 Earnings Results Conference Call. Today is Friday, April 26, 2024. This call is being recorded, and as such, all lines have been placed on mute to prevent any background noise. [Operator Instructions] For opening remarks, I will turn the call over to Portland General Electric's Manager of Investor Relations, Nick White. Please go ahead, sir.

Thank you, Norma. 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'll 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 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. Turning to slide three. Leading our discussion today are Maria Pope, President and CEO; and Joe Trpik, Senior Vice President Finance and CFO. Following their prepared remarks, we will open the line for your questions. Now it's my pleasure to turn the call over to Maria.

Thank you, Nick, and good morning everyone. Thank you for joining us. Portland General Electric is on track in 2024, and the stage is set for steady, normalized growth. After tough weather and extensive customer restoration in January, our results this quarter speak to strong execution. Beginning with slide four, I'll speak to our financial results and key drivers. For the first quarter, we reported GAAP net income of $109 million or $1.8 per diluted share. On a non-GAAP basis, net income was $123 million or $1.21 per diluted share. This compares with first quarter 2023 GAAP net income of $74 million or $0.80 per diluted share. First quarter 2024 GAAP results excluded the 20% non-recoverable cost of the reliability contingency event incurred in the January storm event. Results this quarter, which Joe will discuss in his remarks, were driven by robust low growth from semiconductor and data center customers and our focus on operational execution. This focus was evident throughout the quarter and no more so than during the January storms. Our PGE team members navigated regional resource constraints, gas network disruptions, severe winter conditions that resulted in hundreds of thousands of customer outages. I'd like to again commend and thank my colleagues for their extraordinary work during this challenging event. As we look ahead to the balance of the year and beyond, we remain focused on three main areas. First, rapid transformation of our energy systems propelled by continued investments in our service territory by semiconductor and digital infrastructure customers. Second, executing our capital plan to meet customers' priorities for clean energy and increased grid resilience, and third, delivering on our ongoing commitment to operational discipline by reducing risk, controlling cost, driving efficiency and managing customer affordability. This is a period of rapid growth and transformation for both…

Thank you, Maria, and good morning, everyone. Turning to slide six, our Q1 results reflect continued demand growth from industrial customers, dynamic weather, and ongoing efforts to de-risk our operations. Weather in our area was variable throughout the quarter, with colder conditions in January, followed by more mild conditions in February and March. Overall, heating degree days for the quarter were 8.9% lower than in Q1 2023. Q1 2024 loads decreased by 0.9%, but increased by 1.2% weather adjusted compared to Q1 2023. 2024 residential load decreased 3.6% year-over-year due to mild weather, but increased by 0.5% weather adjusted. Residential customer accounts increased 1.3%. Commercial load decreased 2.1% or 1.3% weather adjusted, driven largely by lower commercial activity, during the January-winter storm. The industrial class sustained its momentum, with load increasing 4.9% for 5.2% weather adjusted. Demand growth for digital and semiconductor customer's supports this growth trend, reinforced by the ungrowing investment, Maria highlighted. We maintain good visibility to our robust pipeline of incoming projects and remain confident in the strength of our service territory. Given these factors, we are reiterating our 2024 weather adjusted load growth guidance of 2% to 3%, and our long-term growth guidance of 2% through 2027 [ph]. I'll now cover our financial performance quarter-over-quarter. We observed a $0.03 decrease in revenues, primarily due to weather-driven decreases in deliveries. An $0.18 increase resulting from the right sizing of our cost structure and improved recovery of wildfire mitigation, vegetation management, other O&M, and capital assets serving customers. Power cost drove a $0.30 increase in EPS, driven by a $0.13 EPS increase due to power cost detriment in Q1, 2023 that reversed for this comparison. And a $0.17 increase in EPS from lower power cost than anticipated in the annual update pair, driven by de-risking actions taken throughout…

Thank you. [Operator Instructions] Our first question comes from the line of Richard Sunderland with JP Morgan. Your line is now open.

Hi, good morning. Can you hear me?

Yes, we can.

Great. Thank you for the time today. You appreciate the color on the RFP process. I'm curious if the projects come through with the pace you expect. What could that potential equity need be? And just for comparison's sake, how should we think about that equity versus equity for the base plan as it stands today?

Sure. Let me have Joe talk to you about our financing plans and how we've reflected them. But overall, with the RFP process, we expect a really robust pipeline of renewable and capacity projects. We should probably have a good shortlist as well as sort of conclusions around the late second quarter, beginning of the third quarter. And we would hope to be able to have contracts executed towards the end of the year, maybe even spilling into the first quarter. Joe, with regards to equity.

Good morning, Richard. As it relates to equity, any equity need coming from the RFP would be incremental to our plan. And we have said that we expect to finance that in both a solution management approach, matching the cash flows to the needs as well as possible, as well as maintaining a 50-50 cap structure balance. As it relates to pricing, we will wait and see how this sizes out. I mean, I think our guidance that we -- I'm sorry, our illustrative presentation that we give on rate-based growth in our investor deck is probably our best proxy to build off of as it relates to equity needs. To Maria's comment, we do anticipate a pretty active RFP process and timing-wise and cash flow-wise, as you think about it, we are looking for projects that are able to come online by the end of 2027 that also align with what is our preferred portfolio.

Okay, understood. Thanks for the color there. And then, turning to the rate case, appreciate its early, but how is the process unfolding so far? I'm hoping you can frame the revenue ask here versus the prior few cases in thinking across size and composition of, say, capital, O&M, and power. And then, given this follow-up to last year's case, is settlement, the expected outcome here? How should we think about that?

So, sure, I'll start us off on the rate case. So, the rate case focus that we have for this case is mainly about capital. So, I would think of it as 65% of this case is capital, and then 25% O&M and 10% for our power cost. This is a change from our last case. Our last case upon ultimate settlement, over half of the case was power cost. So, we really look at this case as making sure that we're as efficient as possible and really looking for recovery of putting these assets in service, including the battery projects that we've talked about that really drive benefits for the customer. And then, as it relates to settlement, the settlement processes will start next week, as I mentioned previously, and we hope to get aligned with parties to be able to settle. But each case stands on it's own, and we hope to have a pretty open and productive dialogue with all interested parties starting soon.

Okay, got it. I'll leave it there for now. Thank you very much for the time.

Thank you.

Thank you. One moment for our very next question. Our next question comes from the line of Shahriar Pourreza with Guggenheim Partners. Your line is now open.

Hey, guys.

Good morning, Shahriar.

Good morning Maria. Maria, I know this year has kind of a shorter session for the legislature. Can you give us any updates on efforts around maybe a state wildfire fund and what the groundwork, if any, looks like for the longer legislative session ahead? I mean, given what you know today, is this something you could see get done by '25? Thanks.

Sure. We are working on legislative solutions both at the state and the federal level. And on the state side, we have been talking with a number of parties from the forest organization, to representatives and senators to our customers and to leadership across the entire state. Clearly, wildfires is a societal risk and we want to address it from a societal solution, not just one that's solely focused on the utility, but a broad set of solutions that really works for Oregon. And then also on the federal side, there's a lot of discussions taking place from how our forest lands are managed nationally through the U.S. Forest Service and the Bureau of Land Management to also ensuring that not only utilities have access to insurance, but also homeowners and others. This area, combined with all of the operational work that we're doing, the very important operational work we're doing is our number one priority, to keep our customers and the communities that we serve safe.

Got it. Perfect. Thank you for that. And then just on power cost, I mean, you had a substantial deferral during the storms in January and the NVPC is otherwise kind of below the baseline. Can you remind us, is there a cap on the amount you could defer under the RCE construct? Can we just -- I guess, can we just put a finer point on what you saw during the event and how it interacts with the NVPC? And then secondly, how are things, you know, hydro snow-pack looking for the summer peak? Thanks.

Sure. So let me take the first one in terms of the conditions during the January period of time. It was really extraordinary. Early on the January event, Alberta came very close to a true energy crisis and that spilled over into the Pacific Northwest. Later on, a couple of days later, a major storage facility in the Pacific Northwest came offline. And so generators throughout the entire region scrambled. We maximized energy flows coming in from the desert Southwest and California, but we hit a number of transmission constraints. And we also brought in much higher levels of power out of British Columbia. Most of that was hydro-based. What we have seen is that our experience was not too different from some other large investor-owned utilities. Through our RCE mechanisms, we are able to defer 20%, excuse me, we're able to defer 80%, and then we retain 20%, which closed through the PCAM mechanism. There is no cap on that. And we are overall really focused on managing power costs. We've seen them come up quite significantly and big issue for us as well as for others. With regards to hydro conditions, they're pretty similar to where they were last year. Obviously, we're in the springtime and so we'll see hydro pickup in the second quarter. And quite frankly, we have stronger flows than we expected in the first quarter. As you look towards the summertime, there is very little snow-pack in Canada and in British Columbia in particular, where most of our hydro comes and what drives the market price of power through the region. So even though you see year-to-year similarities, I think we are setting up for a very tough power cost summer. Overall, hydro throughout the entire region is about 80% of normal.

Got it. Perfect. Thank you, Maria. Appreciate the color. Thanks so much. We'll see you soon.

Thank you. One moment for our next question, please. Our next question comes from the line of Paul Fremont from Ladenburg Thalmann. Your line is now open.

Thank you very much. I guess my first question has to do with some of the demand that you're seeing on the data center side. Is that demand fully, at this point, incorporated into the IRPs that you filed? Or do you see sort of incremental demand above what you're projecting?

Sure. So as you know, we did our first-ever plan and follow-on IRPs last year. About this time last year, we filed a supplemental to that and took up the energy demand by about 40% from what we were projecting previously. After you look at the efficiency of combined technologies and what we were seeing in some of the new deployments that we have, as well as how we're using the distribution system more effectively, that came down to about 14% overall. But it's a 40% increase in demand. It is a huge increase. And it certainly got everybody's attention. And I think that it's absolutely what we're going to be probably the floor on what we'll see as we move forward. Just for perspective of our industrial customer base, about 20% are digital data center type customers. The real bulk of our industrial base is really actually semiconductors. And about 15% of semiconductors in the U.S. are actually manufactured in our service territory. And most recently, the state of Oregon created a matching fund to the CHIPS Act. It's about $240 million, $250 million. And 85% of the allocation of those funds, which goes to specific companies, are companies who have operations in our service territory. So we've continued growth from not only from data centers, but also from semiconductor manufacturers through the next decade that will probably only get higher, not lower.

Great. And I guess the most likely period, if you were to settle in the right case, would that be before hearings?

No, I would imagine that we'll probably have a number of discussions and workshops with staff and parties. We try and settle before we ever get to a commission or order or whatnot. We generally are a pretty collaborative state as we work through issues. Obviously, customer prices has always been and will continue to be a major focus for us, and we've had some pretty big increases. So these conversations are going to be a challenge.

And then last question for me. Can you just reiterate in terms of M&A, whether, you know, what the company would be open to or not open to in the future potentially?

Sure. As you know, we don't comment on any sorts of discussions along those lines, and we're not changing our policy.

Great. I think that's it for me. Thank you.

Thank you.

Thank you. One moment for our next question, please. Our next question comes from the line of Gregg Orrill with UBS. Your line is now open.

Good morning, Greg.

Good morning. Thank you. So back to the drivers for the quarter, there was the management of power costs, which was a $0.17 benefit. How does that flow through or the PCAM or where does the PCAM stand?

Good morning, Greg. This is Joe Trpik. So as you may recall, the PCAM has an asymmetric dead band of $15 million below before a sharing calculation is done or $30 million above. Where we sit currently? So during the quarter, you know, really what we saw was the pretty productive management of cost and also a stable market. We didn't see the volatility that we had seen in prior periods on gas prices, things like that. So where we sit currently is we are $19 million below the PCAM baseline. Currently now, part of that is due to the shaping of the way that the rates are set in the automatic adjustment tariff as it goes through the year. We've disclosed in the 10-Q that we think will be somewhere around the edge of the baseline by the end of the year. But we do sit that $19 million stable to the baseline currently.

Okay, thanks, Joe.

Thank you. [Operator Instructions] Our next question comes from the line of Willard Grainger with Mizuho Securities. Your line is now open.

Hi, good morning, everybody. Maybe just one, if you can unpack for us a little bit. Understand there's two buckets with costs associated with the January storm. You have the $75 million RCE associated with the RCE event and then a separate $48 million. Could you maybe talk to how you're thinking about the timing of the recovery of those dollars?

Sure. Good morning, Willard. The reason that they are separate like that, and I'll talk to you, is they are recovered under two different regulatory mechanisms that they're covered on. I'll start with the $75 million deferral. The $75 million deferral is an RCE deferral under the PCAM. As it relates to the timing, that recovery will be assessed in a process that will go through mid-2025, and we would expect currently that the recovery of whatever amount is settled in that process would start in 2026. The reason I say expect, the RCE mechanism is new and the methods will be part of the -- recovery will be part of that discussion. Separately, we incurred $48 million in O&M in capital costs as it related to the physical restoration of the system during that storm period. In Oregon, there are provisions that allow for the recovery of those costs when a state of emergency is declared and there's such damage. That proceeding has started, and that cost proceeding has started, but the timeline is not set. So there's a filing made, there's a timeline underway. If I had to put an expectation, at some period in 2025, once it's settled, there would be a recovery, but right now there's not a set close date for the proceeding for me to be able to say what date that recovery would occur. Nor do we have until the proceeding and what the time period of that recovery could be. It could be a short period or up to several years based on what decisions are made.

Appreciate the color. And then maybe one more on the extended Day-Ahead market proposal to join the CAISO. Would that allow you to get any sort of FERC at ROE adder or any sort of incremental transmission build to the capital plan? And maybe how should we be thinking about that? Thank you.

Yes, that's a good question. No, it would not. It's a part of an ISO. There is no RTO in the West, and we're probably quite a ways off from that if we ever do get to an RTO. It allows us to move from the energy and balance market, which is essentially a real-time market to the Day-Ahead. And there's some pretty significant customer benefits that we'll realize from that, but also some important operational benefits as we maximize the diverse renewable resources from the desert Southwest and extensive solar to the Pacific Northwest Hydro and all of the wind energy in between. So it allows for really a more planful portfolio effect and builds upon the really good work that has already been done through the energy and balance market.

Great. Thank you.

Thank you.

Thank you. I'm currently showing no further questions at this time. I'd like to hand the conference back over to Maria Pope, President and Chief Executive Officer for closing remarks.

Great. Thank you for joining us today. We appreciate your interest in Portland General, and we look forward to connecting with you soon. Thank you very much.

This concludes today's conference call. Thank you for your participation. You may now disconnect. Everyone have a wonderful day.