Title

Presentation

Portland General Electric Company beats earnings expectations. Reported EPS is $0.697, expectations were $0.62.

Operator: Good morning, everyone, and welcome to Portland General Electric Company’s second Quarter 2024 Earnings Results Conference Call. Today is Friday, July 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.

Nick White: Thank you, Jonathan. 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 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.

Turning to slide 3. 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.

Maria Pope: Thank you, Nick, and good morning, everyone. Thank you for joining us today. Our second quarter results reflect our focus on execution and steady growth trajectory in 2024 and beyond. Starting with slide 4, I’ll highlight key drivers of our second quarter financial results. For the quarter, we reported GAAP net income of $72 million or $0.59 per diluted share. This compares with second quarter, 2023, GAAP net income of $0.39 million or $0.39 per diluted share and non-GAAP net income of $0.44 million or $0.44 per share. These results, which Joe will discuss in detail, were driven by three areas. First, continued growth and demand from industrial customers, primarily semiconductor manufacturing and data centers. Second, second quarter’s mild weather and solid power cost performance.

And third, our continued focus on cost management and risk mitigation. While these results mark an improvement from 2023, we recognize that there is still more work to do. We remain focused on meeting expectations for the year and improving our ROE towards authorized levels. Turning to slide 5, I’d like to start by recognizing my PGE colleagues who worked extremely hard during the regional heat wave. In early July, we saw five consecutive days of record high temperatures, consistent with other areas across the west. Our resilience during this intense period of high heat underscores the value of new processes and training, procurement of additional hydro supply and diverse wind resources, as well as capital investments and technology deployments that strengthened equipment reliability and energy supply management.

These targeted investments also speak to our focus on affordability and how careful planning has reduced painful energy price volatility during extreme events. I also want to recognize the important role that our customers played in this event. They took significant demand response actions to reduce energy consumption by 109 megawatts during peak periods of the heat event. The largest electricity demand shifts we’ve seen. These collective actions during this period of extreme weather made a huge difference. Additionally, throughout this hot period and all of the dry conditions that we are seeing, wildfire mitigation remains a key focus. Our year-round program of system hardening, managing vegetation and sharpening operational practices are key to this risk-based approach.

With wildfire season officially declared in June, we’ve deployed enhanced system protection and control settings including reclosures and switches and other equipment. These enhancements act in conjunction with our monitoring tools and include panoramic AI cameras and weather stations that provide important data and situational awareness to our teams, local agencies, and first responders. As wildfire remains a critical issue for our industry, requiring continued cooperation with regulators, legislators, insurers, public sector agencies as we address this societal wide risk. Shifting to growth, our ongoing renewable generation and capacity RFP remains squarely in focus as we work to achieve our clean energy goals. Bid submission concluded in April and bid evaluation culminated in initial project shortlist filed with the OPUC in early June.

We’re again seeing strong subscription for both generation and capacity resources with a mix of wind, solar, battery, and pumped hydro projects that will move forward for further evaluation. A final project shortlist is expected in August with bid selection this winter. We’re excited to build upon the momentum of the recent RFP projects including clear water wind and three battery projects to provide customers with the next generation of safe, reliable, affordable clean energy resources. Beyond the RFP, PGE is pursuing options to advance the clean energy transition and excess low-cost renewable energy. On our last call, I highlighted PGE’s participation in the CAISO Extended Day-Ahead Market or EDAM aimed at achieving additional renewable energy integration across the west.

Additionally, our transmission work focused on improvements within our footprint is moving forward to support customer growth and we’re also collaborating with tribal partners, Bonneville Power Administration, and other regional utilities and stakeholders to make progress on critical transmission expansion that will facilitate more cost-effective renewable energy supply. For example, in May, PGE signed an MOU with Grid United and ALLETE for development of the North Plains Connector that connects three regions, SPP, MISO, and WEC. These plans highlight the important work our sector is undertaking to build a cleaner and more reliable energy system that enables economic growth for all. Our resource planning work, especially important in the context of the load growth that we’re experiencing across the region, is progressing well.

We’re seeing further validation of our service territory’s trajectory underscored by robust industrial load growth from semiconductor manufacturing and technology infrastructure customers. In the second quarter, industrial load increased 6.2% weather adjusted compared to the same quarter in 2023. Oregon’s leaders remain focused on capturing the benefits of recent legislation and industry tailwinds. These efforts are bearing fruit with additional federal and state CHIP Act funds flowing to local projects. In addition to Intel’s recent $36 billion announcement, LAM Research is completing a new R&D facility in Tualatin. And analog devices in Siltronic are expanding in Beaverton and Portland respectively. We’re also seeing meaningful growth among our region’s data center sector.

These customers are enabled by the transpacific subsea fiber landings on the west side of our service territory, similar to the transatlantic network landings in North Virginia. Growth from both these important sectors represent an exciting opportunity for our region, bringing quality jobs and infrastructure improvements at a level we have not seen in over 50 years. I’ll now turn briefly to our 2025 general rate case, which Joe will cover further in his remarks. Our teams received OPUC staff and intervener testimony earlier this month and will be building off of recent constructive conversations during upcoming settlement conferences. Collaboration with customers, interveners, regulators, and legislators to find creative solutions to opportunities and challenges unfolding in our service territory and industry is key.

We look forward to continuing these discussions, including a workshop later today. As we look to the second half of 2024, our strategy remains firmly rooted in transforming our local system to address growing customer needs, effectively deploying resources to increase our resiliency to extreme weather, managing affordability for all customers. We remain focused on achieving our targets, executing our plan, and delivering value for customers, communities, and shareholders. With that, I’ll turn it over to Joe. Joe?

Joe Trpik: Thank you, Maria, and good morning, everyone. Turning to slide 6, our Q2 results reflect continued focus on execution and cost management, further semiconductor manufacturing and data center growth, and solid power cost performance. Our region saw the effects of El Nino throughout the quarter with slightly warmer conditions in April followed by cooler conditions in May and June. Q2 2024 load decreased by 2. 2% overall but increased by 0. 9% weather adjusted compared to Q2 2023. Q2 2024 residential load decreased 7. 1% year-over-year or 1.1% weather adjusted. This was largely driven by lower usage per customer for continued energy efficiency partially offset by residential customer count increases of 1.7%. Commercial load decreased 4.

2% or 2% weather adjusted driven largely by energy efficiency efforts in the commercial class. Growth among the industrial customers persisted with load increasing 5. 5% or 6.2% weather adjusted. Demand from technology infrastructure, and semiconductor manufacturing customers remained robust and we continued to see a strong pipeline of projects in our area. These dynamics further solidify confidence in our service territory and as such we are reiterating our 2024 weather-adjusted load growth guidance of 2% to 3% and our long-term load growth guidance of 2% through 2027. I’ll now cover our financial performance quarter-over-quarter. We observed a $0.05 decrease in revenues primarily due to weather-driven decreases in deliveries, a $0.09 increase resulting from the rightsizing of our cost structure and improved wildfire mitigation, vegetation management, other O&M, and capital assets serving customers.

An EPS increase from power costs of $0.16 was driven by a $0.04 EPS increase due to power cost detriments in Q2 2023 that reversed for this comparison and a $0.12 EPS increase from derisking actions and mild weather conditions throughout the quarter that drove lower power cost than anticipated in the annual update tariff. Lastly, we had a $0.05 increase from other items including higher AFUDC, higher returns on non-qualified benefit trust assets, and lower income tax expense generally from tax credit impacts partially offset by the diluted impacts of recent equity draws. On to slide 7 for our capital forecast. Our plan for 2024 continues to progress including base investments, transmission projects, and incoming consumable and seaside batteries.

Regarding the RFP, as Maria mentioned, refinements of the bids presented in the initial shortlist filed in June is continuing as expected. The initial shortlist included approximately 3 gigawatts of nameplate renewable and capacity resources made up of 22 distinct bids, many with multiple configuration options. About 45% of these bids included some component of build transfer ownership options. Bid evaluation will continue towards a final shortlist filing next month and we will keep you informed as we are able to share more details. I will again highlight that our capital plan does not include any possible forthcoming RFP projects. Potential updates to our capital forecast would occur upon bid selection and contract execution which is now expected in Q4 2024 or Q1 2025.

On to slide 8 for our summary of liquidity and financing. Total available liquidity as of June 30 is $990 million. Our investment grade credit ratings and strong balance sheet remain unchanged from our last disclosure. I will note that in June Moody’s changed PGE’s outlook from stable to negative while affirming our credit ratings. We remain closely engaged with both S&P and Moody’s and are working diligently to maintain our existing ratings. We continue to expect debt issuances in the second half of the year of up to $300 million focused on the funding of capital expenditures. Regarding equity, our current base capital plan clarifies our needs for the coming years. For 2024 through 2026, we anticipate an annual need of approximately $300 million to support our base capital investments as well as make progress on our capital structure over the next few years.

As our equity ratio improves, we anticipate a moderate decline in the annual base needs after 2026. We’ve made progress on this strategy in 2024. Let me start by highlighting that we satisfy our equity needs to support our 2024 base capital plan and capital structure management. We drew $78 million under the ATM in Q1 and entered into additional forward sale agreements in Q2 to exhaust the $300 million ATM facility. The ATM portion priced in the second quarter remained outstanding as of the end of June. In preparation for the future and consistent with this plan earlier today, we also registered a new at-the-market filing. This new shelf filing allows incremental issuances over multiple years and includes a forward component much like the previous program.

The refreshed ATM provides another useful tool and optimal flexibility as we navigate our financing plan, enabling opportunistic equity market access and the ability to closely match issuances with accretive investments. Any action under this new ATM this year would be to maintain our strong credit metrics in support of our 2025 base capital plan and our long-term equity ratio management. As always, we plan to opportunistically raise capital in support of rate-based investments and will evaluate potential opportunities to derisk our financing plan using the forward feature. We continue to monitor the RFP bid selection as the RFP bid selection approaches and will keep you informed. Overall, our current expectation is any potential RFP ownership opportunities will be financed in line with our authorized capital structure, and we have confidence in our financing flexibility for potential ownership options.

Our year-to-date financing activities highlight our debt and equity market execution and remain confident in our demand and capability. We are committed to carefully managing our capital structure and dilution, maintaining strong credit metrics, and competitively tapping capital markets in support of accretive rate-based investments that provide strong customer benefits. Turning to the 2025 general rate case, which is proceeding through its intermediate stages. This case remains centered on capital projects providing long-term benefits to all of our customers, including battery storage projects that improve power cost management and grid flexibility, distribution investments to address grid modernization, network reliability and system resiliency in face of increasing extreme weather, and transmission investments to enable customer growth and renewable resource integration.

Opening testimony has been exchanged and multiple settlement conferences are scheduled throughout the summer, including one later today. We look forward to the continued constructive engagement with stakeholders as the case proceeds. Review of the filing will continue through the year for rates effective at the beginning of 2025. All items remain subject to OPUC approval. Our Q2 results display continued execution of our plan for 2024 and beyond. Given our current progress, we are reaffirming our adjusted guidance of $2.98 to $3.18 per share and our long-term earnings and dividend growth guidance of 5% to 7%. As we enter the last half of 2024, we remain focused on cost management efforts, thoughtful capital deployment and careful planning that yields maximum benefits for customers, shareholders and the communities we serve.

And now, operator, we are ready for question.

Operator: [Operator Instructions] And our first question comes from the line of Nick Campanella from Barclays.

Nick Campanella: Hey, good morning. And thanks for taking my questions. So, Joe, you talked about a moderate decline in equity needs after 2026. And I know that you just refreshed the ATM here. So just how do you think about what’s run rate equity per year through 2025 now? And it does sound like that this ATM is in size for any shortlist editions. Is that the right takeaway here? Thank you.

Joe Trpik: Thank you, Nick. Looking through the next few years, the equity need is about $300 million for the base plan as we’ve presented here to both serve the capital plan and the balance sheet repair. After that, you would think to a plan that would be moderately less than that, call it somewhere near half of that needed to sort of maintain that excess of our investments above our internal cash flows.

Nick Campanella: Okay. I appreciate that. And then I guess just in terms of the operating environment through July, the comments on DER response were interesting and just how are you kind of trending versus your baseline and your PCAM now? And I know that you also talked about some derisking efforts in this quarter on power costs that you took advantage of, so just how do you just kind of feel on that for the rest of the year? Thanks.

Joe Trpik: So our operating environment to date when we talked to the power markets, obviously, we had talked to the load’s been down, but we’ve also had seen a limited amount of volatility within in the power markets and when you combine that load being down in the power markets and what opportunities that’s afforded us, we are $52 million below the baseline for the PCAM to date. We do expect by the end of the year that we’ll come back within the dead band considering that the third quarter is the most volatile of our both the market and weather conditions that we’ll see but the derisking to date we feel has really yielded this reduced volatility allowed us to get a little bit ahead of the PCAM and what is this extreme weather so. I think it’s operating effectively and a lot of the derisking we thought would occur has materialized itself so far to this year.

Operator: Our next question comes from the line of Shahriar Pourreza from Guggenheim Partners.

Shahriar Pourreza: Good morning, Joe, Maria and Nick. Good. So maybe just a real high level question for you to start and you guys have the 2% load growth out there, the backdrop obviously seems to be trending above that unlike semiconductor and data center demand. How should we be thinking about how you want to update the street going forward on sort of the earnings growth? Realize you guys want to be conservative we get that but could you get to a point in the next few quarters where you at least speak kind of directionally to where you are relative to the upper half or top end of that 5% to 7%?

Maria Pope: Sure. Thank you, Shah. So, first of all, we are seeing good load growth almost exclusively from the industrial sector and just for perspective half of our industrial sector is semiconductors which has a growth rate that’s a little bit more modest than what you see in the data centers, but probably longer in duration. We’re looking at growth in some of our semiconductor companies over the next decade. 20% of our customers are based in the fastest growing area for that industrial section, our data centers. And there we’re seeing really quite significant growth. In addition to the infrastructure investments of new substations and transmission, what we’re also seeing is need for greater amounts of renewable energy. And we’ll be updating you all with our IRP results, probably in early 2025.

That’s probably what would influence our growth rate more than anything. Most importantly right now, we’re going through a competitive bidding process and are pretty encouraged by the pricing levels that we’re seeing and the robust bids.

Shahriar Pourreza: Got it. So not to kind of paint you in the corner, but could that update be the year-end call sometime in the February timeframe, or is that too early relative to the IRP?

Maria Pope: Yes, I think that’s when we generally give our guidance for the year. I also want to acknowledge that there’s a lot of things that we’re balancing. We’re balancing need for additional infrastructure, obviously, wildfire expenditures, affordability pressures that we’re seeing across the board, as well as just the timing of many of these investments that our customers are making.

Shahriar Pourreza: Right. Okay, that’s helpful. And I know you guys briefly touched on it, but the settlement conference scheduled for today, obviously, there’s been quite an interesting testimony to date, including some strong words from [inaudible]. What are the prospects for settlements in your view at this point? Were you kind of closest and furthest apart here?

Maria Pope: Sure. And I appreciate that we’ve seen quite a bit of vocabulary and positioning within the rate case testimony that’s been provided. We have worked collaboratively over the years and have strong relationships with all of our interveners and parties. And the conversations actually are going quite well and are quite constructive. And we do appreciate that the most important thing is that we’re serving our customers and affordability is first and foremost in mind. One of the things I’d point out is that we recently were rated the top customer experience utility by Forrester in the country for our effectiveness, the ease in which customers are able to work with us in the delivery of our products and services, and really how good they feel about their experience with Portland General. So we’re really proud of all of the hard work that supports our customers day in and day out.

Operator: And our next question comes from the line of Richard Sunderland from JP Morgan.

Richard Sunderland: Hi. Good morning. And thank you for the time today. Starting with transmission, you had some language in the release around your efforts there. I’m hoping you could talk a little bit more about that. I know it’s been topical over the past year. Is this alluding to anything new overall on sort of five year, 10 year capital potential? And if that’s the case, how much of that is in your five year capital plan currently?

Maria Pope: Sure. So as you know, we began breaking out transmission separately in our capital expenditure table because to me, to Shah’s earlier point, our growing customer needs. We really look at transmission in terms of sort of three circles. So the first one is existing rights of way within and adjacent to our service territory and that’s really areas where we’re dealing with dramatic customer growth in certain load areas and certain constraint points that we have in our area. The next is transmission, so across the state of Oregon we’re working with a number of parties most notably the competitive trades of Warm Springs. They received a $250 million grant to expand the transmission line that we own that’s over about a hundred miles that those sorts of projects in collaboration with others and then third really working across the entire region.

You’ve seen our work with the Bonneville Power Administration and they’ve announced $2.3 billion of transmission expenditures. Many of those would benefit our customers in this area and then also looking at things like the North Plains Connector with Grid United and ALLETE bringing together three different regions across the entire country to enable access to not only renewable energy and different geographic environments and time zones but areas where there’s already excess renewable energy currently in the ground. So we really look at this as a sort of risk adjusted for a company like Portland General way of addressing transmission and rapid customer growth.

Richard Sunderland: Understood, that is helpful, thank you. And then separately appreciate some of the commentary you offered earlier on wildfire season and the enhanced line settings. Could you expand a little bit on what you’re seeing across local conditions and relative risk this year versus prior years and similarly I guess I’m also curious how state and federal engagement is trending in your view on a framework to address this risk.

Maria Pope: Sure. So first of all, I want to note that much of the state of Oregon is in a level five condition. This is was in a recent change driven by many of the lightning storms that have taken place over the past week to 10 days. There are currently over 130 fires burning in Oregon, many of which are east of the Cascades or much farther south of the state towards the California border. We take fire very seriously and in particular are monitoring its impact on our more remote facilities. We do not have any wildfires currently burning in our service territory. And we’ve long been focused on wildfire prevention and really around planning and investments and system hardening. Mitigation, we’ve significantly taken up our vegetation management, recognizing the impact of the last three years extraordinary heat, starting with the heat dome back in June of 2020.

We’ve seen extensive tree mortality that has increased the vegetation risk quite a bit. And so recognizing the science around that, we’ve really taken up our spend in that area. And then third, really detection and early mitigation. And that gets to your question around how we work with first responders. We work at the most local level in every county and community with firefighters, first responders, and community leaders who are very focused on the danger of wildfire and who have a lot of questions and interaction with us. But most importantly for those first responders, they’re able to access the same data that we do to the AI cameras and directly into those cloud providers to provide response that’s much faster than we would have been able to do otherwise.

Operator: Our next question comes from the line of Paul Fremont from Ladenburg Thalmann.

Paul Fremont: Great. Good morning. I’m hoping to get a little bit more clarity surrounding the equity, the planned equity issuance. Should we assume the $300 million is issued evenly, $100 million each year, ‘24 through ‘26, and the ‘78 million that’s been issued so far this year, would that imply that there’s another $20 million of equity planned for this year?

Joe Trpik: Good morning, Paul. How are you? So the equity plan, to be clear, is $300 million per annum. The $78 million that we had issued this year, we have the remainder of the $300 million that we plan to use for financing this year for our debt incremental capital, and then we need $300 million per year for the next two subsequent years to fund the capital plan and address the balance sheet needs before we tail down to a more modest level of equity need to fund the incremental capital.

Paul Fremont: Okay, so the $100 million this year would be incremental to finishing off the existing ATM?

Joe Trpik: So no, the ATM, so we’ve issued and drawn $78 million on the year. We have the remaining amount that we have issued that we would anticipate we would draw in the second half of this year to fund our capital plan. So there would ultimately be draws in this year of $300 million in 2024.

Paul Fremont: Okay. So $300 million total in ‘24 and then in ‘25 and ‘26 $100 million a year?

Joe Trpik: $300 million a year. Our capital plan, yes, our capital plans in ‘25 and ‘26 average a little bit more than $1.2 billion and that incremental amount among our — above our operating cash flow that’s available would be coming from debt equity and to address some balance sheet and prepared to get us to our optimal cap structure.

Paul Fremont: Okay, great. And then when is the North Plains Connector, when would that be completed in terms of construction?

Maria Pope: Sure, they’re looking at utilizing the faster NEPA processes of just a couple of years and having shovels in the ground in 2027 with completion about 2029.

Paul Fremont: And is that at all in your current CapEx plan?

Maria Pope: No, it’s not.

Paul Fremont: And then weather so far this quarter, can you give us a sense of, I guess what the weather’s been like so far in July for you?

Maria Pope: Sure. First of all, following up over on a very mild second quarter, we had extreme temperatures setting records for the first part of July in most areas of the state and in particular in our service territory. Since then, temperatures have moderated and been much cooler. Overall, conditions are quite dry and we are seeing hydro conditions that are actually slightly deteriorated from this time last year with the Columbia River in particular at about 75% and 73% versus right around 80% last year. So we have pretty intense conditions for the balance of the third quarter and then hopefully we will begin to see cooler trends with changing patterns as we go forward into 2025.

Paul Fremont: And then sort of last question for me, any thoughts on the timing of when you would potentially follow your next rate case, and is that dependent on sort of what happens with the RFPs?

Maria Pope: It’s certainly, there are a lot of conditions. The first one is the current rate case that we’re in and the ongoing discussions is really where we’re focused. And based on that and many of the items that we filed to try and be able to create more of a gap versus annual rate cases would be really I think something that everybody would benefit from if we could find a way to those sorts of solutions.

Operator: Our next question comes from the line of Sophie Karp from KBCP.

Sophie Karp: Hi. Good morning, guys. Thank you for taking my question. A couple of high level questions from me. I’m just kind of wondering, as your growth potential accelerates and need for investment growth going forward, would you still think that ATMs is the right vehicle to raise equity for the type of growth, or would you eventually pivot to some other forms of financing? Like, what was the tipping point for that?

Joe Trpik: Yes, I do think, yes, at some point other forms of finance are going to make sense. The ATM works. It allows us some flexibility as it relates to our base capital plan, as it relates to both the RFP outcome that we would expect here in the fourth quarter or first quarter of next year, as well as any potential additional growth that comes or is identified through the next IRP, evaluating other forms of financing based on the size and scale of those is something that we’ll have to do to just really maximize our options and flexibility. So, yes, I think the ATM works in the base, but we’ll think as we talk to the growth.

Maria Pope: And, Sophie, I want to also acknowledge that we’ve really been working to maximize government grants and tax equity. Projects currently sort of in the works are close to about $2 billion of federal funds. Obviously, the $1 billion hydrogen hub for which we’re contributing the Boardman’s site, an offtake agreement and water rights, as well as the $250 million, as I mentioned, for transmission line that’s in the state of Oregon. But in addition to that, the $50 million of smart grid investments, as well as the PTCs and ITCs of our most recent wind farm in Montana, and then some of the batteries, is in excess of $400 million, directly reducing the, are offsetting the investment that we’ve made in those and reducing the impact of customer prices and our financing needs. And so we would also expect from the future RFPs to be able to utilize PTCs and ITCs very effectively.

Sophie Karp: Got it, thank you, this is helpful. And then I was just kind of curious if there’s been any evolution in your thinking about the forming of the whole core. I know that’s something that’s been discussed, it’s been topical, but I’m kind of curious if you guys thinking about the time in there, is that something that’s still very long term for you?

Joe Trpik: So currently there’s nothing in our immediate plans as it relates to a holdco, but as we talk to the longer term continued growth of the company and the future RFPs, evaluating a holdco, the benefits that it would have if we had one to the customers and to the structures, clearly something we’re considering, but it is not something that is immediately sitting in thought.

Maria Pope: Sophie, it’s interesting we’re one of the few utilities that doesn’t have this fairly common structure. I think there’s three of us left in the country and so obviously we’re taking a look at how we maximize low cost financing to benefit the investments that we need to make on behalf of customers.

Operator: And our next question comes from the line of Gregg Orrill from UBS.

Gregg Orrill: Yes, thanks. Good morning. Thanks for taking the question. The RFP shortlist, what information gets made public around that in terms of which we expect to see there and then how do you think about going from the shortlist to the selection in December or early next year?

Joe Trpik: So the shortlist, I’ll sort of go back in history. So when we get to the RFP shortlist, that disclosure will be similar to what you would have seen the last time we had this disclosure. It’ll have technical disclosures about the different sites, the size of the megawatts, the bill, if it’s a bill transfer, ownership versus PPA. So that will be the information that comes out on the shortlist. Subsequent to that process, the work will be, and obviously the shortlist started this, an assessment from the least risk, least cost of beginning the contract negotiations from the highest scored on down and working through that process. And then as those contract negotiations settle is when we would declare is it a PPA or is it a bill transfer and layer that into either a capital plan or a power cost plan for the company.

Operator: And our next question comes from the line of Julian Dumoulin -Smith from Jefferies.

Julian Dumoulin: Thank you very much.

Maria Pope: Julian, we missed you for a quarter.

Julian Dumoulin: We skipped one day, didn’t we? Excellent. Well, look, it’s a pleasure to chat with you guys. Let me try to clean up on a few things from the queue here if you guys don’t mind. Speaking of missing out on something here, the Grid United announcement here with Skelly, the 20% ownership stake, right? How do you think about the timeline for HashNet out from the MOU? Because to me, you talk about 2027 construction starting. In theory, you’ve got to get that resolved prior and potentially you also need a holdco structure in place prior. How do you think about the timeline here for all these pieces to come together and when you’d be in a position to formalize that MOU into an ownership stake, presumably over the next couple of years?

Maria Pope: Yes, I think that’s exactly it. It’s going to take us a couple of years. So we look forward to discussions with Michael Skelly and his group, as you note, and are very impressed with the advancements that they’ve already made, the easements and permits they have in hand, and as well as some of the equipment that they’ve already put on order to ensure that they don’t run into any supply chain issues. There’re also other partners that they’re having conversations with, and I think you’ll see further announcements with other Pacific Northwest and other utilities.

Joe Trpik: And I think, Julian, just to add to on the ownership side and the 20% stake, that is somewhat an open dialogue right now. I do agree, there’s structures of everything, since it has not been declared at all from a jointly owned plant, which would not really require a holding company to own it as an investment or another one, which may require a holdco, are things that are all going to be evaluated as we work through this and the other partners come in.

Julian Dumoulin: Yes, absolutely. But it sounds like, but on the holdco side, that would need to get resolved prior as well, just to confirm that, too, over the next couple of years.

Maria Pope: Not necessarily.

Joe Trpik: Only to the extent that we were holding it in a holdco. There are structures where this type of investment could be, or interest could be held within the current regulated entity. That clarity of holdco only will be only dictated by the ultimate ownership structure as it plays out.

Julian Dumoulin: Right, yes, understood. And just in terms of cash, I just want to come back to this ATM question. I want to ask it in the context of I saw the Moody’s announcement here in the interim. See the equity ratio where it stands. When you talk about $300 million per year, how do you think about kind of teeing up and truing up against maybe some of the issues highlighted there with the credit backdrop? Is there kind of a true up here or do you think through the period at the $300 per annum kind of trajectory that these other issues would resolve themselves as well in tandem?

Joe Trpik: Yes, I think if we look at this holistically, yes, when we designed the plan and talked at $300 million per annum for the next few years, we have sort of a conservative balance sheet here, right, one of the most conservative in this sector, and we believe that path to get to where we get to should address all of sort of the driving to the capital structure of managing our credit metrics and ensuring that we have the right strength in our balance sheet. So it was designed considering all of those over that three year period.

Julian Dumoulin: Right, got it, okay, excellent. And then just a quick one here on cash, how much was that storm, I mean, the heat wave here, there’s some language here in the Q, how much cash would that be in terms of which you were to go and securitize recovery on a deferred manner?

Joe Trpik: So, and we’re talking the heat wave that just occurred in July after the quarter close.

Julian Dumoulin: Yes, sorry, not storm, heat wave.

Joe Trpik: Yes, so this heat, the heat wave that we just occurred has, we have not formally quantified it is significantly less than a January event. And it does, we believe at least on initial assessment meet the definition for a few of the days as a reliability contingency event, but at relatively not significant numbers, especially when you put it in context of other I’s event. And it’s something we’re quantifying it, but so we haven’t assigned dollars to it, but it isn’t anywhere near the magnitude of these other events, and we’ll disclose that in the third quarter to the extent that it’s even significant. So, it is not something that is driving our financing activities here. It is not something I expect to have any impact on our overall financing plan for the year.

Julian Dumoulin: Right, excellent. And just lastly, the RFP timing, what was the cause of that delay, just quickly?

Joe Trpik: The delay to move us into August, it is just the right, there’s a regulatory process, some administrative items that we’re honestly just dotting a few I’s, crossing a few T’s as we’ve worked through this, if they are normal administrative items that move things a couple of weeks. It was nothing unusual or out of the ordinary.

Operator: This does conclude the question and answer session of today’s program. I’d like to hand the program back to Maria Pope for the remarks.

Maria Pope: Thank you. And thank you for joining us all today. We appreciate your interest in Portland General Electric and we look forward to connecting with you soon. Thank you and have a great day.

Operator: Thank you, ladies and gentlemen, for your participation in today’s conference. This does conclude the program. You may now disconnect. Good day.