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.
Speaker: Got it. Perfect. Thank you, Maria. Appreciate the color. Thanks so much. We’ll see you soon.
Operator: 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.
Paul Fremont: 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?
Maria Pope: 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.
Paul Fremont: Great. And I guess the most likely period, if you were to settle in the right case, would that be before hearings?
Maria Pope: 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.
Paul Fremont: 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?
Maria Pope: Sure. As you know, we don’t comment on any sorts of discussions along those lines, and we’re not changing our policy.
Paul Fremont: Great. I think that’s it for me. Thank you.
Maria Pope: Thank you.
Operator: 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.
Maria Pope: Good morning, Greg.
Gregg Orrill: 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?
Joe Trpik: 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.
Gregg Orrill: Okay, thanks, Joe.
Operator: Thank you. [Operator Instructions] Our next question comes from the line of Willard Grainger with Mizuho Securities. Your line is now open.
Willard Grainger: 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?
Joe Trpik: 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.
Willard Grainger: 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.
