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Operator: Good morning, everyone, and welcome to Portland General Electric Company’s First Quarter 2023 Earnings Results Conference Call. Today is Friday, April 28, 2023. . For opening remarks, I will turn the conference over to Portland General Electric’s Senior Director of Finance, Investor Relations and Risk Management, Jardon Jaramillo. Please go ahead, sir.

Jardon Jaramillo: Thank you, Valerie. 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 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.

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

Maria Pope: Thank you, Jardon, and good morning. Thank you all for joining us today. Beginning with Slide 4, I’ll start by discussing our first quarter results and speak to the key drivers. For the first quarter, we reported GAAP net income of $74 million or $0.80 per diluted share. This compares with first quarter 2022 GAAP net income of $60 million or $0.67 per share. Our non-GAAP net income of $72 million or $0.81 per share. There are 3 primary drivers of our results this quarter: First, we continue to see good load growth. Industrial load, in particular, increased over 8% quarter-over-quarter, as high-tech sectors and steady expansion in the region continues; second, our power costs have increased both as a result of load growth as well as higher natural gas and power prices; and third, cost management remains a key priority, and we expect largely flat O&M for the full year, excluding the impact of Wildfire and major deferrals as was the case this quarter.

In addition, our Q1 results reflect the impact of a $300 million draw from our equity forward, which was completed on March 1. This draw is an important step for our Oregon’s clean energy investment and in resetting our balance sheet for growth ahead. 2023 earnings is forecast to be in the range of $2.60 to $2.75 per share, and we remain confident in our long-term earnings growth rate of 5% to 7%, driven by strong load growth and customer growth as well as attractive capital investment profile and improved operational performance. Moving to Slide 5. As you know, we have been focused on bringing on new renewable and non-emitting resources onto our system, and we’re excited to announce the acquisition of a company-owned battery storage project as part of our most recent RFP.

Seaside Grid, a 200-megawatt facility with total of approximately $360 million of investment, excluding AFUDC. That is expected to begin service by midyear 2025. We’re also announcing an additional 200 million battery storage from the Troutdale Grid facility developed and owned by NextEra Energy Resources with a solid capacity under a 20-year storage capacity agreement. This project is expected to begin service by year-end 2024. We continue to negotiate with a remaining shortlist bidder or a 500 — excuse me, a 75-megawatt company-owned battery storage project and expect negotiations to be finalized in the first half of 2023. Negotiations for this project represent the final chapter of the 2021 RFP. These new Oregon-based projects are significant addition to our existing capital clean energy portfolio and provide grid reliability, resiliency and flexibility.

This will help us manage energy costs, allowing us to deploy stored renewable energy during times of peak demand, partially offsetting market energy purchases. Associated with wind, solar and hydro generation. These battery projects will be an important component in integrating future renewable resources. To finance the Seaside project and other capital needs, we will use a combination of debt and equity and have registered a $300 million at-the-market shelf offering to allow incremental equity issuances. Jim will expand on this in his remarks. On the regulatory front, we filed an inaugural clean energy plan in conjunction with our 2023 integrated resource plan. Net of today’s battery announcements, these integrated documents outlined the 2,300 to 3,300 megawatts needed to meet our future resource needs by 2030.

Also in the first quarter, we filed our 2024 general rate case and have recently established the procedural schedule for the year. The rate case increase has 3 main components: First, 30% as a result of natural gas and purchased energy prices; second, 40% related to capital investment; and finally, third, the balance is due to higher O&M costs associated with compliance and inflation. This rate case also addresses our power cost adjustment mechanism, or PCAM, to facilitate or against decarbonization goals and better reflect current and future operating conditions. We are still in the early stages of this case and look forward to collaborative discussions with the OPUC and stakeholders. We expect to conclude all deferral dockets following resolution of the 2020 Boardman revenue requirement deferral, which we expect to be concluded in the second quarter.

We’re very pleased that the securitization legislation is moving through the Oregon legislature and expect it to be signed to law later this year. If passed, this legislation can help limit customer price impacts from major events. Affordability is essential with significant inflationary pressures and energy price volatility. I commend our PGE colleagues who are incredibly focused on controlling costs. As I discussed last quarter, in 2022, we made progress streamlining our work processes, leveraging technology and improving productivity. And throughout 2023, we have a lot more work to do and are building on the work we have done over the last several years. For example, we’re investing in digital tools to enable operational efficiencies, better resource deployment and improved customer service.

In fact, our upgraded cloud-based customer system was deployed seamlessly just 2 weeks ago. Our customer information and meter data management system is making it easier for customers to get accurate and timely information and for our teams to execute more coordinated and timely customer service response. Another great example is the implementation of new management and scheduling technologies, which are helping us to more efficiently manage our crews, workflows and field tools, both increasing cost efficiency and reducing cybersecurity risks. With this focus and these improvements, we will continue to target largely flat O&M when compared to prior year, excluding the impact of major deferral amortizations and higher wildfire costs. We also strengthened our organization with the appointment of Ben Felton as our new Chief Operating Officer.

Ben joins us from DTE where he most recently served as Senior Vice President of Energy Supply. Ben brings a wealth of experience built over 30 years across just about every aspect of utility operations and deep knowledge of the industry. We have experienced tremendous growth over the last several years, and our operations are increasingly complex. As we look ahead, we expect that our business and operating environment will only become more dynamic and interconnected, bringing a COO of Ben’s caliber to PGE provides an opportunity to unite several groups, including engineering, construction and operations. Following our 2023 Annual Meeting of Shareholders, I’m also pleased to share that Jim Torgerson has been appointed Chair of our Board of Directors.

Jim has served on the PG Board since 2021 and has extensive knowledge of the utility industry and power markets, including renewable energy development, finance, regulation and risk management. I would like to thank Jack Davis and Rob Brad, who are concluding their Board service. Their wise counsel and vision have helped guide PGE for combined 25 years. We have greatly benefited from Jack Davis, who was our Chair of our Board for a number of years and who has deep industry knowledge, as well as Rob’s experience in environmental law. And then on a final organizational change, you may have seen the release that we issued this morning, announcing that Jim Ajello has decided to retire. Jim came to us in 2020 when the company needed a steady hand to lead our financial organization.

He helped us implement new risk and financial management practices, strengthen our financial foundation and accelerate our clean energy transition. Today, in no small part and thanks to his leadership, we are executing on a refocused strategy, identifying new ways to operate more efficiently and continuing to improve our reliability and resource adequacy. Among Jim’s many accomplishments, I’m especially thankful for his leadership in resetting our balance sheet. We completed a $500 million equity issuance last fall, lost $300 million at the market program today and have raised nearly $1 billion in debt and expanded our bank lines of credit and insurance programs. All of this supports higher levels of clean energy investments, reliability improvements as well as smart grid transformation, positioning us for growth and superior customer service for many years to come.

We are currently conducting a search for Jim’s replacement, including internal and external candidates, to ensure a smooth transition. Jim has agreed to remain as a senior adviser through the end of August after he transitions from his current role at the end of June. Jim, thank you. You’ve made a remarkable difference during your tenure, and we’re enormously grateful. Now before I turn it over to Jim, I’ll close from where I began. Overall, we had a good quarter. We made significant progress to strengthen our organization and accelerate decarbonization and reliability of our energy supply through battery projects announced today. With the clear line of sight to accelerated growth and value creation, we remain focused on providing safe, reliable, affordable clean energy to all customers.

And with that, Jim will walk you through our financial results. Thank you.

James Ajello: Thank you, Maria, and good morning, everyone. I’ll cover our Q1 results before providing additional details on resource planning, capital investment and liquidity and financing outlook. Moving to Slide 6. Our first quarter results reflect sustained demand growth, effective management of continued power market volatility and successful execution of our long-standing cost management efforts. Our regional economy remains solid as unemployment in our service territory held at 3.8% through Q1 2023. Development and demand amongst our industrial customer class has remained strong. We continue to see a strong pipeline of industrial customer projects, particularly high-tech and data center sites ramping in the coming months.

Overall, Q1 2023 loads increased by 1.9% weather adjusted compared to Q1 2022. On a non-weather-adjusted basis, total load increased 4.7% year-over-year, as we witnessed a 9.4% increase in heating degree days. Residential load increased by 5% year-over-year, but decreased 0.9% weather adjusted, which speaks to both cold weather in our service territory and the continuation of usage patterns as our customer practices normalize in the aftermath of the pandemic. Residential customer count growth increased 0.9% compared to Q1 2022. Commercial load increased 1.2% year-over-year or 0.4% weather adjusted as commercial activity also continues to normalize. Industrial load growth remained steady in Q1, growing 8.6% or 8.3% weather adjusted with high-tech and digital customers continuing to lead the segment.

While we did see higher deliveries, driven by colder than typical weather temperatures, we also saw a continuation of higher power prices. Execution of our operational and risk management strategies helped dampen the impact of this weather volatility as intended. These conditions emphasize the resource constraints in our region and changing market dynamics that require continued collaboration among our employees, customers and regulators to address market-driven challenges. I’ll now cover our financial performance quarter-over-quarter. We experienced a $0.22 increase in total revenues, driven by the 4.7% increase in deliveries, led by continued growth amongst our industrial customer class. We saw a $0.05 increase in revenues due to customer composition differences quarter-over-quarter, driven primarily by weather-driven increases in residential and commercial loads compared to 2022.

Higher power prices due to higher purchase volumes to serve load during a particularly cold first quarter of $0.08 EPS decrease. Increases in average market prices during the quarter drove an $0.18 decrease. We saw a $0.04 impact from depreciation and amortization expense, including $0.01, due to higher plant balances year-over-year and $0.03 due to capital cost deferrals in 2022 that did not recur. There was a $0.05 decrease from the impact of higher interest expenses due to higher long-term debt balances. Q4 2022 first mortgage bond issuances totaling $200 million and a $260 million term loan issued in the fourth quarter, which was repaid in March. There was a $0.04 increase due to higher returns on nonqualified benefit trust assets, reflecting improved market conditions compared to Q1 2022.

A $0.02 increase from higher AFUDC compared to 2022, reflecting our continued growth in grid and technology investments. There was a $0.03 decrease due to the dilutive impacts of the $300 million equity draw completed in the first quarter. Lastly, we had a $0.04 increase from other items, including higher miscellaneous income, partially offset by higher property taxes. Much of our results this quarter reflect our trend towards sustained growth with higher depreciation from increased capital investment, interest expense to fund new capital projects and near-term dilution impacts being key drivers. This is an incremental $0.12 year-over-year. As we have mentioned on previous calls, 2023 remains an investment year, and we remain focused on execution that strengthens PGE’s foundation for long-term growth and value.

On Slide 7, for an update of the 2021 RFP. As Maria highlighted, we are pleased to have another addition to our portfolio that will allow us to maintain reliability for customers, provide flexibility to our grid operations to meet changing visions to help us manage power costs on behalf of customers. The 200-megawatt of company-owned battery storage and 200-megawatt of incremental capacity secured under our capacity storage agreement is a critical component PGE’s clean energy future and will enable quick deployment to serve customers during extreme weather events or periods of high demand. Combined with 311-megawatt Clearwater wind development announced in late ’22, of which PGE will own 208 megawatts, the company will invest $775 million in new renewable and dispatchable capacity resources procured to date.

As Maria mentioned, we continue negotiations on a PGE-owned 75-megawatt battery project, and we are optimistic that we’ll enter an agreement in Q2. If an agreement is reached on this final project, PGE will have procured company-owned projects with nameplate capacity of 483 megawatts resulting from this competitive procurement cycle. Other parties in the process garnered a total of 303 megawatts of nameplate capacity. In total, we will have secured 786 megawatts of renewable generation and nonemitting capacity resources, with PGE owning 61% of the capacity procured from this highly competitive RFP. This combination of owned and contracted resources and a mix of technologies allows us to achieve the balance of cost and risk of projects that will provide optimal long-term benefits to customers.

Even while navigating notable macroeconomic challenges, we were able to achieve many of the procurement targets placed on us at the outset of the RFP and make critical progress on our clean energy journey. And I strongly believe we’ve got the best outcomes for our customers. In the wake of our combined CEP and IRP’s filing made in late March, we anticipate issuing the 2023 RFP in mid-2023 and final project selections anticipated in 2024. Turning to Slide 8, which shows our updated capital forecast through 2027. Our 2023 through 2025 CapEx guidance is increasing by $115 million, $180 million and $210 million in each respective year, primarily due to investments in the new Seaside project. This does not include any CapEx that would be associated with the 75-megawatt project still in negotiations.

By Clearwater, the agreement for the Seaside project utilizes a build transfer approach, which provides an ideal mix of risk mitigation and financing flexibility. As a reminder, figures presented here do not include any potential expenditures related to the possible ownership from the remaining portion of the current RFP or future RFP cycles. Turning to Slide 9. We continue to maintain our strong balance sheet and liquidity as well as investment-grade credit ratings accompanied by a strong credit outlook. Total available liquidity at March 31, 2023, is $679 million, which does not include undrawn portions from the existing equity forward or the newly filed ATM. We issued $300 million of common equity under the existing equity forward sales agreement in March.

Remaining draws against the equity forward are expected to be completed by the end of the agreement’s 24-month term. Looking to the balance of 2023, we anticipate debt issuances of up to $300 million, which we plan to issue under our green financing framework to continue our practices of tying debt financing to our sustainability strategy through capital investments. We also registered a $300 million at-the-market shelf offering today. The ATM incorporates a forward component to match spending needs and provide improved optionality for increased equity offerings to support our upcoming clean investments. We intend to finance new CapEx in line with our 50-50 authorized capital structure. Any use of the ATM will be strategically timed to fund capital investments when conditions are optimal.

This strategy will help us attract capital at competitive prices to the benefit of our customers. We will continue to manage dilution carefully as we aim to align equity issuances with cash payments for rate base investments where possible. In terms of our 2023 outlook, our first quarter results reflect the continuing strength in our fundamentals in the service territory as well as our consistent operational execution. We remain laser-focused on cost management and thoughtful investment in high-return activities that drive more effective and efficient operation. And we look forward to additional deployments that will yield strong results for our customers and shareholders. We also maintain our confidence in 2023 load growth, led by sustained growth from high-tech and digital industrial customers and modest growth from residential and commercial customers.

Combined, we still anticipate weather-adjusted load growth of 2.5% to 3%. With respect to dividends, last week, our Board approved a dividend increase of $0.09 per share on an annualized basis, which represents a 5% increase. This increase is consistent with our long-term dividend growth guidance of 5% to 7%, while observing a dividend payout ratio target of 60% to 70% over time. As I highlighted previously, our service territory fundamentals, improved operating performance and attractive capital investment profile will allow us to achieve our long-term earnings growth guidance of 5% to 7%. As we reflect on the first quarter and turn towards the remainder of ’23 and beyond, our foundation for growth is robust. We look forward to executing on our long-term financial goals and providing value to our customers and shareholders alike by delivering safe, affordable, reliable and increasingly clean energy.

As a result of these factors, we are reaffirming our full year adjusted earnings guidance of $2.60 to $2.75 per diluted share. Before we open the line for questions, I want to thank you, Maria, and the great team and the Board at PGE for this opportunity to work so closely together. It’s been an honor and a privilege. It will be a very bittersweet moment for me when I leave 4 months from now. And I would do everything that I can to help continue our momentum and affect the smooth transition. But between now and then, we have plenty of work to do. And now, operator, we’re ready for questions.

Operator: . Our first question comes from Shahriar Pourreza of Guggenheim.

Shahriar Pourreza: Just, Maria, starting with the remainder of the ’21 RFP, is the implied capital cost for Seaside a useful proxy for that smaller 75-megawatt opportunity? And secondly, what’s the time line for that? Do we have to wait for the 2Q call? Or could we get an 8-K between now and then?

James Ajello: Shahriar, it’s Jim. I’ll take that one. So the final project, the 75-megawatt project, is still under negotiation. So I won’t cite an exact capital cost because we’re still finalizing that. But if you look at the totality of the 2021 RFP results to date, it’s been pretty much coming in as we expected, about $1,900, $2,000 a KW of installed capacity. Since we have really good current pricing from very similar storage projects, I think you can extrapolate pretty easily what that project could come in at. But until that contract is signed and inked, we have an agreement on the actual capital cost we’ll have to extrapolate. But I think it’s pretty easy right now.

Shahriar Pourreza: Got it. And then you guys proposed to modify the PCAM in the case realized. It’s obviously early innings, but maybe at a high level, is this something we could see parts of get through? Or is it an all or nothing process, I guess, put differently, could we see changes to the sharing ratios but not removal of the dead bands? Just trying to understand what the pathways forward are here?

Maria Pope: Sure. So first of all, I think it’s too early to speculate where we’ll end up. But the proposed changes to the PCAM represent pretty significant changes to the power markets as well as to reliability. So when we look towards the Western resource adequacy program, we look at how power markets are operating today. It’s time to update and bring to date really this mechanisms that we’ve had in place for a long time. So it’s an important set of changes not only for the company but also for the customers, and we look forward to working collaboratively with parties.

Shahriar Pourreza: Perfect. That was all the questions I had. Jim, congrats on sort of Phase 2 of your retirement. I think you’re obviously a little too long to retire, little to long to retire, but we’ll discuss that over drinks.

James Ajello: Thanks, Shahriar.

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

Julien Dumoulin-Smith: And Jim I wish you the best of luck. I’m sure I’ll see you more around here. And Ben, best of luck to you. It’s pleasure indeed.

James Ajello: Thank you.

Julien Dumoulin-Smith: Just following up here quickly on the ATM, I saw the $300 million. I just — how do you think about the timing related to that? I typically wouldn’t ask. But obviously, you’ve got a pretty steady cadence of potential CapEx revision higher here such that you could really need further capital revisions and further capital injections later. How do you think about sort of the cadence of the new equity raise here?

James Ajello: Yes, good question. So let’s go back to basics from the October offering, right? $500 million. Let’s — and part of the proceeds there was to reduce debt. So we dramatically improved our ratios and the like. About — I would say about $300 million out of that $500 million offering address the balance sheet. And closing the quarter here, we’re getting close to 49% equity. So mission accomplished, right? And then we had a little more than a $400 million investment in Clearwater. And so therefore, a couple of hundred million dollars is applied there. So between the balance sheet and Clearwater, those proceeds are being applied towards progress payments and the like and strengthening the financial condition. With respect to the new projects going forward, they’re very substantial equity investments.

And frankly, looking ahead to closing out the project that we haven’t signed yet, pretty much going to size that ATM to capitalize these new projects going forward, including the debt that we’ll issue towards the end of this year in the second half, I would say. So that will help us as we go. The ATM will last us through the termination period of the registration statement, which is August 2 years hence, so a little more than 2 years to go there. And of course, the equity forward is a 2-year arrangement. So I think we’re well set up between these 2 transactions to capitalize everything that we need, including having fixed the balance sheet and the strong prospect of this final 75-megawatt storage project. So you’re quite right. In the implication, we need a lot of financing, but we’re now set up to do that.

And of course, I’d like to go into the 2023 RFP, seeking projects in 2024 with a little bit of tailwind, so we can confidently bid on those projects as well.

Julien Dumoulin-Smith: Right. And Jim, if you can clarify this. I mean I know the 2-year forward structure. But as you say, you’ve already sort of allocated the equity you raised last fall. I mean is the dilutive impact as you think about this spread out over to? Or do you think that this is more concentrated on the far end of that just to make ?

James Ajello: It will definitely be spread out over a couple of years. And the reason being is that the way we’re going to fund these projects is based on progress payments as these projects are delivered with milestones to us. So on a quarterly basis, these company-owned projects will require progress payments to the contractors and vendors that we have that are delivering them. So there’s a schedule of these things, and then we’ll be drawing against the equity and debt that we have to pay those bills. Plus, don’t forget, another $800 million of kind of base capital that’s inherent in the plan. So with this year’s $1.3 billion and next year’s increase in guidance, we have a very substantial capital plan here that’s running, call it, 3x depreciation.

Julien Dumoulin-Smith: Excellent. And just two quick clarifications, if I can, related to, first, industrial loads still intact, not seeing any pullback from the tech side of the equation. Just want to clarify that. Obviously, you guys have Intel and others in new service territory. And then related here, percent expectation on the win for future RFPs. I mean you guys want a pretty hefty amount here proforma for that last project. Still confident about what that means for future RFPs?

James Ajello: So on the first point, I see, we see load growth in the industrial sector proceeding along at mid- to high single digits as we go. And I’m sure Maria will comment in a minute. And then quickly on the second question, yes, I cited 61% win rate on this last RFP, but I really can’t speculate on the go-forward. It’s just too soon to tell. We haven’t even issued the RFP yet. So standby for that. So…

Maria Pope: Julien, on the load side, we continue to see load growth really across the board. Our migration continues, customer count was up just slightly shy of 1% in the first quarter, and that’s the winter quarter. We also continue to see the commercial come off, while in residential is down a little bit in terms of usage is that reflecting people really back to work and post-COVID environment. And for the last several quarters, really, the story is all about industrial growth. And we have about 15% of the semiconductors that are manufactured in this country are manufactured in our service territories. So there are many of those manufacturers, who are adding to their current facilities and expanding, in addition to what you see across many aspects of the country, which is digital and cloud computing organizations, expanding their operations.

James Ajello: Data centers in this neighborhood are going to generate demand for 150 megawatts of new load this year alone, just as an example.

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

Sophie Karp: And Jim, you will be greatly missed when you retire. A couple of questions I have here. So on the PCAM request, I was wondering if you can remind us the regulatory history of this. Specifically, if you requested in the past to have it modified and what the outcome was, sort of trying to glean how much appetite the stakeholders might have for modification of this loan entrenched mechanism?

Maria Pope: Sure. That’s a great question. And first of all, we’ve had that — this mechanism in place even before I joined the company. And it really related back to the Boardman coal plant and the idea of risk sharing in terms of operating performance for a plant where there were a lot of operating aspects to it. Today, where our thermal deployment is fixed and actually more variable when the wind is not blowing, the sun is not shining, the mechanism no longer really applies what it’s largely a renewable-based system based on wind, solar and other natural resources as well as the import and export throughout the entire Western Interconnect to maximize renewable resources across the market footprint of the entire West. And when you also look at the reliability concerns that we as well as every aspect of the country have for resource adequacy and the advances that the Western Power Pool has made getting their FERC approval last quarter and moving forward towards the Western resource adequacy program, it’s really time to take a wholesale relook at the mechanism is not common across the industry.

In fact, we’re a far outlier, and we look forward to working with parties to figure out a mechanism that will work better going forward in this new environment, or I should say this continually evolving environment.

Sophie Karp: Right, right. And that’s a very helpful color. And then just a high-level question about the service territory. I’m wondering if you see any shift in the kind of demographic trends in your territory where I don’t know, historically, you relied on the population inflow, right? And is that still the case? Is that maybe changing where industrial commercial load will be the main driver for you going forward? Just kind of curious if there’s any change there.

Maria Pope: It’s also a good question. There are several different reports that have different data with regards to in-migration. What we continue to see is in-migration that is at or a little bit higher than the integration that we’ve seen over the last decade. So north of 1% in-migration. What we also are seeing is continual advances in renewables that is attributed and that’s actually part of our strategy. And as you may know, this area has long had a history of energy conservation, and we’re one of the leaders in terms of that area, not only as the utility, but as an entire state. So I think you’ll — we will not see as much load growth from residential or commercial. And so most of the load growth will come from industrial, but we’ll continue to see customer growth.

The one area that — that’s not included in that is electric vehicles. We’re the fourth largest market for electric vehicles and have the second highest penetration in the country. And we have a number of, I think, tremendous opportunities with some of the IRA dollars going to our customers, who are already looking to expand their use of electric vehicles. And in particular, we have a number of fleets who are looking at last mile delivery, and Daimler has their electric truck manufacturing actually located in our service territory as well. So there’s a lot of moving pieces in terms of the load side, but most of it continues to be fairly robust. We believe in our 2.5% to 3% load growth for this year in our long-term forecast.

Operator: Our next question comes from the line of Anthony Crowdell of Mizuho Group.

Anthony Crowdell: And Jim, congratulations. Tom Brady also retired too, I guess.

James Ajello: Okay. Thank you for that.

Anthony Crowdell: If I could follow-up to Julien’s question, but maybe flip the question around. And this is related to the success that company has had in winning the RFPs. The 39% that maybe the company did not win, could you talk about — was it strictly on price that the company didn’t win? Or are there other factors to how the company was not successful in that 39% of the bidding?

Maria Pope: There’s a lot of factors come in. We do — we take a broad look and work with an independent evaluator. And so it’s the least risk, least price, and all these factors come into play. And it’s a fairly transparent process with the independent evaluator and the commission. So I do think that the competitive nature really helps deliver the best projects for the best value for customers over the long term.

Anthony Crowdell: Great. And then if I could just pivot I think a trial began earlier this week related to some wildfire damage associated with another utility in the state. I think it was Pacific. Just curious if that creates more scrutiny on Portland? Or does that provide an opportunity for more spending for resiliency?

Maria Pope: Well, we can’t comment on anything that’s going on in terms of litigation, whether it pertains to ourselves or any other utility. And I think, if you look at wildfire, we’re really focused on doing the right thing, making sure that we’re protecting our customers, investing in our grid, and we have a good solid program that we’ve developed over a number of years.

Operator: . Our next question comes from the line of Travis Miller of Morningstar.

Travis Miller: Congratulations, job well done, Jim.

James Ajello: Thank you.

Travis Miller: Question on the Seaside. What’s the rate timing in terms of recovering that investment that you’re thinking about? Would it be a lump sum in a rate case in 2025, 2026? Or is there a chance to get payments along the way?

James Ajello: All of these projects, Travis, are eligible for AFUDC. So that’s starter. Secondly, it is our belief that projects such as this are eligible to be treated under our renewable adjustment clause. Now that clause was implemented probably 15 or more years ago. But projects like this were not really contemplated at this kind of scale or even this type, and we certainly didn’t have a grid like we have today. So we have sought clarification in the recently filed rate case that the RAC, or the renewable adjustment clause, applies to the recovery of these investments because they are associated with the build-out of renewables, that’s a keyword, a key phrase, a key concept in terms of deploying the RAC. If for some reason, which we don’t think is appropriate, but if for some reason, it’s judged not to have the RAC apply, we will have to seek ordinary rate case treatment to get those assets into rate base.

Maria Pope: What I would also add is from an operator’s perspective, these will be really important investments that will help us balance the grid, improve stability, the volatility from wind and solar is hard. And these assets couldn’t come on any sooner, and we really look forward to them enhancing our increasing renewable portfolio. It will be very important as we move forward for the stability and reliability of our system.

James Ajello: Just to put a cap on that, Travis, the decarbonization plans we have are so significant that I don’t think we can do it without these kinds of battery resources. So they are a linchpin, I believe, in the build-out of renewables and achieving the decarb plan that we have.

Travis Miller: Okay. That’s helpful. In that RAC, just as a quick follow-on. Would Clearwater also qualify? Or would it be just essentially Seaside and future projects?

James Ajello: The Clearwater project clearly qualifies for the RAC treatment.

Travis Miller: Okay. Very good. And then high-level question. Hydro impact, do you expect anything material this year just based on the snowpack levels there?

Maria Pope: Sure. so as you probably have seen in our 10-Q disclosures, we continue to have low hydro in the Columbia River and basin about 85%, 86%. That is a big deal. While projects are running at 104, is at 93, pricing and availability across the entire region is based on the Columbia. So we’ve seen a downward. If you look at the numbers, you can see an increase in thermal use in the first quarter and you see a decrease in our ability to purchase hydro. One of the things that also took place was really cold in February and March. And so all of that snowpack stayed in amounts. And so I think you’ll see dramatically improvement in the second quarter. And we hope to have some of that around for the third quarter, but that’s really where we will see the big impact of the lower amounts versus last year.

And last year, I remember it was quite significantly above normal. In addition, we have an extraordinary situation of California having almost 200% hydro conditions as they deal with a lot of water. So all of us in the West are beneficiaries of that, in particular, obviously, California, but they haven’t had these kind of conditions in 40 or 50 years.

Operator: Our next question comes from the line of Andrew Stewart Levi of Hite Hedge.

Andrew Levi: Guys, can you hear me well?

James Ajello: Yes, Andy.

Maria Pope: Yes.

Andrew Levi: Good. Okay. You’re retiring Jim, you don’t retire. You’ve done a really amazing job. So I thank you for that and I thank Maria for hiring you and the guys you are actually really nice and happy team together. So…

James Ajello: Thank you, Andy.

Andrew Levi: Yes. I’m sure they’re sad to see you go as retire. Okay. So questions. I have a couple of questions, so just bear with me here. I guess, first, just on the ATM. I guess it just sounds like the $500 million of the forward, that kind of gets you through Clearwater. And then the incremental equity is for your current — the batteries and as you said, the $800 million base plan. Is that kind of the way to think about it?

James Ajello: Generally fair to say, I think, the $500 million will take us a little further than that. And then the ATM will bring us into that next phase of capital, the battery project or hopefully projects.

Andrew Levi: Right, right, right. Yes, probably $500 million plus or something if you add the last 75 megawatts. So…

James Ajello: If you add the last one, we should cross over $500 million for those battery projects, if we’re able to close the last one.

Andrew Levi: Right, exactly. So just as far as the timing of the ATM like when it may begin, I guess, that’s more of a — because if you kind of look when you need the money, it’s like $70 million, $130 million, $160 million. Is the ATM more of a ’24 exercise?

James Ajello: It might be. We’ll want to be opportunistic. The share price has increased since the Block transaction of last year. And there’s opportunism plus there’s risk management, right? We have known significant capital expenditures. So we want to make sure that we manage those coming expenditures wisely and as anti-dilutive way as possible. So that’s the balancing act here. And we’ll be able to use some debt to, if you will, bridge some of those payments. And we’ll be able to dollar cost average, as you would imagine, the use of that money. So it’s a great tool for us, considering the large $4 billion of capital over the next 5 years that we really have. So we talk a lot about incremental capital, but base capital over 5 years is $3 billion, right? So we are in a heavy growth phase as we look forward here.

Andrew Levi: Well, that actually leads to my next question. And — so you have this 5% to 7% growth rate out there. Obviously, you have a tremendous amount of CapEx/rate base growth that there’s obviously some lower the EPS growth a little bit. But this latest CapEx update, to get you firmly, I guess, within the midpoint of your 5% to 7% growth rate, if not higher, is that kind of the way to speak about it, and that’s EPS growth that we’re talking about?

James Ajello: That’s right. I mean I think we had a lot of confidence in this plan. A year ago or thereabouts when we increase the growth rate, we were questioned a great deal about can you get there? And now the questions are coming, how much higher can you go? And I want to point out one thing here, which is that we need to be very careful as we prosecute this growth plan regarding customer bills. We have to be very deliberate as we execute so that we respect the customer value proposition. The rate base growth here, you might have seen in the larger investor presentation, was increased slightly. It’s got a CAGR of about 8.6%. And I think we illustrated in the other slides that the procurement phases that we’re in only require about a 25% win rate of these RFPs to get us squarely in the range of the 5% to 7%.

So I think we’re bearing out, proving out that we can get there, and we’re going to pause on that growth rate guidance and execute. If we execute well, we’ll reevaluate that.

Andrew Levi: Okay. But I guess the answer to my question was, yes, right?

James Ajello: Essentially yes.

Andrew Levi: Okay. And then the last question I have, just as you go to your walk for the first quarter and then you see like a combo of $0.26 of kind of higher power prices for no better way to put it, whether it’s a higher load or the impact of higher prices, how does that kind of incorporated into the PCAM because is that all like — because you have $0.22 of upside from sales, is that $0.26 kind of apples-to-apples when it comes to recovery or the PCAM? And then my additional question to that is, as you get — whether it’s the battery storage or other renewables coming online, whether it’s contracted or whether you own it, to that take away under the volatility? And I understand you’re trying to get the PCAM changed. I get that. That’s — but as far as the volatility and being so dependent on the spot market or the forward market, will that kind of — you look at this $0.26, if you kind of have these assets operating today, would those numbers have been lower?

Maria Pope: So it’s a great question, Andy. And if you’re getting at actually some of the implications of an energy system that is largely based on renewables. And so when you’re at a tail conditions, prices spike, people are using more electricity than a forecaster is in our annual update tariff. And you can see that overall in the first quarter, energy cost us $13 million more than we expected. That’s one of the reasons we look forward to the batteries, whether they be owned or contracted, to be able to smooth out some of these — the volatility. The projects themselves are 4 hours in duration. And so they really will be able to keep us through the changes between different times of day and different market conditions, not necessarily adding long-term capacity that would add to, let’s say, a drought year or a year, but they absolutely will have an impact, and there’s no differentiation between whether we own them or not.

But we — again, we look forward to them coming online, they’ll have a good impact as we move forward.

James Ajello: And I expect that we’re below the dead band. I don’t think there’ll be any refunds this year. So just in terms of the operability of the PCAM, that’s my outlook right now.

Andrew Levi: I guess — yes, just real quick, just what I’m a little confused about, I guess, is because your total PCAM hit is not — even if you’re completely below that dead band on the bottom, it’s not like $0.18 or $0.26. I guess I understand there’s a formula in that. But some of that $0.26 is not all kind of PCAM lost earnings for the company, right?

Maria Pope: So overall, in the first quarter, margin was largely flat. So what we picked up an additional load and mix, we lost in serving that load and mix with higher energy prices. I think, given the volatility, we’ve done a lot of things to improve our management through these extraordinary times. But as you saw at the end of December as well as some of the first quarter, we saw gas prices none of us ever thought we would see. So it’s too early to call it for the full year. But there’s no question that these additional resources will make a difference. And with every quarter, we hope to do better.

Andrew Levi: Okay. What was the PCAM negative hit in the first quarter? Did you guys quantify that?

Maria Pope: $13 million.

Andrew Levi: $13 million of pretax?

Maria Pope: Yes.

Operator: I’m seeing no further questions at this time. I turn the call back over to Maria Pope for any closing remarks.

Maria Pope: Great. Thank you very much for joining us today. We appreciate your interest in Portland General Electric, and we look forward to connecting with you soon. Thank you all. Take care. Bye-bye.

Operator: Thank you. Ladies and gentlemen, this does conclude today’s conference. Thank you all participating. You may now disconnect. Have a great day.