Portland General Electric Company (NYSE:POR) Q3 2024 Earnings Call Transcript

Portland General Electric Company (NYSE:POR) Q3 2024 Earnings Call Transcript October 25, 2024

Portland General Electric Company beats earnings expectations. Reported EPS is $0.9, expectations were $0.87.

Operator: Good morning, everyone, and welcome to Portland General Electric Company’s Third Quarter 2024 Earnings Results Conference Call. Today is Friday, October 25, 2024. This call is being recorded, and as such, all lines have been placed on mute to prevent any background noise. After the speakers’ remarks there will be a question-and-answer period. [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, GG. Good morning, everyone. Thank you for joining us today. Before we begin this morning, I would like to remind you that we have prepared a presentation to supplement our discussion, which we’ll be referencing throughout the call. The slides are available on our website at investors.portlandgeneral.com. Referring to slide two, some of our remarks this morning will constitute forward-looking statements. We caution you that such statements involve inherent risks and uncertainties, and actual results may differ materially from our expectations. For a description of some of the factors that could cause actual results to differ materially, please refer to our earnings press release and our most recent periodic reports on Forms 10-K and 10-Q, which are available on our website.

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

Maria Pope: Thank you, Nick, and good morning. I’m happy you can all join us today. Our third quarter reflects PGE’s focus on operational excellence and delivering consistent results. Starting with slide four. For the quarter, we reported GAAP net income of $94 million or $0.90 per diluted share. This compares with third quarter 2023 GAAP net income of $47 million or $0.46 per deleted share. Three key drivers underpinned our results: first improve power cost performance driven by PGE’s acquisition of renewable resources and regional power market stability. This is despite experiencing very low-hydro conditions and summer heat. Certainly significant improvement from tough third quarters of the last several years. Second, execution of thoughtful cost and risk management work, as well as overall strong performance across our operations.

And third, continued robust demand growth led by semiconductors and data center manufacturers and customers. Due to our solid third quarter results and outlook for the full-year, we expensed a portion of the costs related to the January 2024 storm and damage deferral. Given the application of an earnings test, this resulted in a charge to third quarter earnings of $0.11 per share. Joe will cover this more in detail in his remarks. For the full-year, we expect to deliver results in the upper half of our original guidance range. We are narrowing our 2024 adjusted earnings guidance to $3.08 to $3.18 per diluted share. Turning to slide five, we entered 2024 focused on solidifying our energy portfolio by adding 500 megawatts of new renewable hydro capacity, integrating additional wind, and optimizing our generation assets.

Our results this quarter reflect the importance of these investments and work. Similar, energy capacity and additions across the West have helped steady energy markets, even with significantly below hydro conditions and the record-setting west-wide hot summer temperatures, particularly in July. We strategically deployed our generation fleet and procured energy across Western markets to offset the impacts during the most challenging periods. Our power operations and generation teams did an outstanding job. We also saw strong performance from the Clearwater Wind Development officially commissioned in September, which operates at a highly capacity factor and provides important diversity to our generation mix. Notably, there have already been 25-days this year where with the addition of Clearwater, PGE generated more than a gigawatt of wind power.

This is equivalent to serving nearly all of our residential customers with wind-generated energy. We’re excited to complement Clearwater’s success with the incoming constable and seaside battery storage projects, providing even more flexibility and reliability to our system. Clean energy remains a customer focus and a priority, from high tech and data centers to hospitals and municipalities and individual residential customers. For the 15th year in a row, PGE’s voluntary renewable program was ranked number one by [NREL] (ph). More than 25% of our residential and business customers chose to enroll in our green future program. We also made important progress in securing the next generation of reliable, clean, and cost-effective resources. In September, in coordination with the independent evaluator, we submitted the 2023 RFP final shortlist for acknowledgement by the OPUC.

Included on the shortlist are a mix of solar and battery projects that provide critical resource diversity and capacity options. All of these projects help advance our clean energy goals, while also balancing reliability and affordability. We’ve structured this list into two groups at the request of stakeholders. We’ve prioritized and begun negotiations with the top performing bids. Group A, as negotiations continue and we advance through the regulatory process will determine if engagement with the remaining shortlist projects Group B, is necessary. OPUC acknowledgement of the shortlist is expected by late November and contracts are expected to be completed throughout 2025. We received numerous other bids that with continued refinement could be important portfolio additions in the future.

Given our significant need for clean energy and capacity, we expect to file an integrated resource plan update and to conduct a follow-on RFP in 2025. Turning to the 2025 rate review. Since our last call, PGE and parties have exchanged additional testimony and participating in hearings earlier this month. We appreciate the productive dialogue held across multiple settlement discussions during the year. PGE remains laser focused on keeping our customers’ prices as low as possible by driving operational efficiencies. Our third quarter results, which Joe will cover shortly, reflect this focused approach as we prioritize work that impacts power costs, O&M, capital, as well as reduces overall risk. This includes vegetation management that addresses both wildfire and winter storms, power plant and gas storage optimization, and progress on our capital plan to replace aging infrastructure, particularly across our T&D systems and to enhance grid reliability.

We also continue to aggressively pursue and successfully capture billions of dollars of federal grants, production tax credits and investment tax credits, both ourselves and with partners. Most recently, the North Plains Connector, a project led by Grid United, received a $700 million federal grant from the U.S. Department of Energy to the Grid Resilience and Innovation Partnership, which includes upgrades for the existing coal strip transmission line. These grants, as well as investment and production tax credits from our clean energy projects benefit all parts of our business. This includes generation assets, long-lead transmission, distribution enhancement, transportation electrification, workforce development, and more. This powerful, game-changing federal support is helping us keep customer prices as low as possible, while advancing the energy transformation and accelerating technology and innovation.

While these advancements are critical, let me now turn to the safety of our coworkers, customers and communities, our top priority. Extreme weather, natural disasters and in particular across the West, wildfires. These are not just a utility issue, but a societal one. Addressing wildfire risk requires maximizing the investments in our capabilities and continued sharpening of our mature year-round wildfire mitigation program. It also requires collaboration with federal, state, and local agencies and actively supporting potential regulatory and legislative solutions at the state and national level. We are working with partners and policymakers on potential legislation to ensure that utilities in Oregon and across the country can continue providing safe, reliable, and affordable electricity service.

Addressing this risk in a holistic fashion is critical for customers, communities, employees, and shareholders, all stakeholders. Finally, turning to demand growth. Year-to-date industrial demand has grown more than 9%, compared to 2023. Extending the trajectory we’ve observed for the last five years. This further highlights the attractiveness of our service territory to a diverse customer base, including data centers and an ecosystem of semiconductor research and manufacturing customers. By working closely with our customers, communities, and policymakers, we’ve had a long running visibility to these trends. This has informed much of our strategy. Meeting these growing energy needs reinforces our decision to join the Energy Day-Ahead Market.

This will help lower power costs, increase resilience and improve access to diverse resources and clean energy across the West. We are also focused on enhancing our transmission capabilities in multiple phases and areas. First, maximizing performance and alleviating bottlenecks in our existing rights of way. And second, working closely with partners on lines adjacent to our service territory, like the collaboration with the North Plains Connector, to execute a reliable and affordable clean energy transition and extend the reach of the Western network. This work is critical as we continue to support customer growth and advance our shared decarbonization goals. Looking ahead, this quarter’s strong operations focus on execution and robust demand growth drove our performance.

We integrated a significant amount of renewable resources, experienced stable power markets, and served our growing customer base. We remain focused on providing safe, reliable, and affordable clean energy. With that, I’ll turn it over to Joe. Thank you.

Joe Trpik: Thank you, Maria, and good morning, everyone. Turning to slide six, our Q3 results reflect improved regional power cost conditions and continued robust demand growth from our industrial class customers. Our region again experienced warmer conditions than normal throughout the quarter, but conditions were slightly cooler than last summer. Q3 2024 loads increased by 3.9% overall and 5.3% weather adjusted, as compared to Q3 2023. Q3 2024 residential load decreased 1.2% year-over-year, but increased 0.9% weather adjusted. Residential customer count increased by 2.1%. However, this was partially offset by energy efficiency driving lower usage per customer. Commercial loads remain relatively flat with a slight decrease of 1% or 0.1% weather adjusted driven largely by energy efficiency.

The industrial class continues to experience chunky growth this quarter, compared to the modest growth seen in Q3 last year. Industrial load increased 15.7% or 16.4% weather adjusted. This increase is driven by demand from digital infrastructure and semiconductor customers emphasizing growing load opportunities within our area. These results, as well as continued visibility to a pipeline of further expansion reinforce our expectations for near and long-term growth across our service territory. As such, we are reiterating our 2024 weather adjusted load growth guidance of 2% to 3%. We are also reiterating our long-term load growth guidance of 2% through 2027. We will continue to evaluate this for potential revision in conjunction with our next IRP, which we plan to file in Q1 of 2025.

I’ll now cover our financial performance quarter-over-quarter. We observed a $0.10 increase in revenues primarily due to increased deliveries to our industrial customers. An EPS increase from power costs of $0.45 driven by a $0.07 cent increase due to power cost detriments in Q3 of 2023 that reversed for this comparison, and a $0.38 EPS increase from favorable power cost conditions seen throughout our territory and the region. Compared to a very challenging Q3 2023, we saw far less market volatility and operated in a lower price environment. Overall, average Mid-sea, Day-Ahead Peak prices were more than 40% lower throughout the quarter than last year. Improved market stability and market prices were driven by a handful of factors, including higher-than-expected gas and hydro storage levels due to the mild winter earlier in the year, higher penetration from 4,000 megawatts of new battery storage and 1,500 megawatts of new solar throughout the desert Southwest and California, and significant heat events occurring in early July when hydro runoff remained prevalent, which helped avoid pronounced price spikes.

We also saw the benefits of renewables that we added to our portfolio, including new hydro capacity and contributions from clear water winds, which performed consistently throughout the summer. The combination of favorable conditions and actions taken by our team drove lower power costs than anticipated in the annual update tariff. A $0.05 decrease from operating maintenance expense, net of improved recovery and deferral related items driven primarily by service restoration during the heat events during the quarter. A $0.05 increase from other items including higher returns on non-qualified benefit trust assets and lower income tax expense generally from tax credit impacts. Lastly, as Maria mentioned earlier, we had an $0.11 decrease from a deferral release related to the January 2024 storm and damage deferral.

As of the end of Q3, we have forecasted that our full-year 2024 regulated ROE would be above the 9.5% threshold used for the emergency storm deferral earnings test. As a result, we have decreased that deferral from $45 million to $28 million and taken a corresponding charge in the third quarter. This means that due to our expectations of improved 2024 results, storm costs that would have been collected from customers will likely decrease. We will reassess this earnings test and the related impact to the deferred amounts related to the January storm based on the actual regulated return on equity for the end of the year. This test is unique to 2024 and became applicable when we had a major storm deferral earlier this year. It became relevant to our results when we had such a favorable third quarter performance and we’ve exceeded our original outlook.

On to slide seven for our capital forecast. We’ve made meaningful headway in our 2024 plan, but we have modestly revised our 2024 and 2025 CapEx forecast based on year-to-date progress. We’ve elevated our capital program to support customer growth, reliability and decarbonization and we’re proceeding thoughtfully to build the rigor to execute at this level in the long run. Our latest battery projects, Constable and Seaside remain on schedule and are expected to come online at the end of 2024 and in the middle of 2025, respectively. We are pleased with the nearly 1.7 gigawatts of solar and battery projects on the 2023 RFP shortlist. As a reminder, our current forecast does not include any potential build transfer RFP projects. Updates to our capital forecast from the potential RFP project ownership would occur upon bid selection and contract execution.

We expect to execute final contracts over the course of 2025 with build transfer agreements expected to be finalized in the second-half of 2025. All projects are expected to be in service by the end of 2027. On to slide eight for a summary of liquidity and financing. Total available liquidity as of September 30 is just over $1 billion. Our investment-grade credit rating, strong balance sheet and outlook remains unchanged from our last disclosures. In the third quarter, we drew $100 million previously priced under our legacy $300 million ATM program. The residual amount priced under the facility was unissued at the end of September, but we expect to draw the remainder in Q4 to support our base capital plan. I’ll reiterate that we’ve satisfied our equity needs to support our 2024 base capital plan and capital structure management and any further action in 2024 would focus on maintaining strong credit metrics or derisking our long-term financing plan.

We expect debt issuances in the last quarter of the year of up to $300 million, focused on the funding of capital expenditures. As we highlighted on our last call, for 2024 through 2026, we anticipate that the annual equity need of approximately $300 million to support our base capital investment and continue to strengthen our balance sheet over the next few years. We anticipate our base — annual base needs to taper after 2026 as our capital structure improves. We’re carefully assessing equity needs from the potential RFP investments as contract negotiations proceed. We continue to expect financing RFP ownership opportunities in line with our authorized capital structure. Consistent with our long-standing practice, we’ll continue to pursue financing options that maximize accretion in customer value, minimize dilution, maintain our strong credit ratings and manage our capital structure.

Turning briefly to the 2025 rate case, which is proceeding through its final statements. As Maria noted, settlement discussions continued throughout the quarter and the hearing was held in early October. Grief filings are scheduled for the end of October and early November, ahead of oral arguments scheduled for mid-November. For the 2025 AUT, we have reached agreement in principle with the parties to resolve all remaining issues and anticipate filing a stipulation in the coming weeks. We remain committed to being engaged with all stakeholders and appreciate the collaboration and discussions that have occurred to-date. As we reflect on the quarter and turn to Q4, the results displayed the continued manifestation of our long-term strategy. Through September, our team has been laser-focused on executing our plan, creating certainty in our 2024 results and setting the stage for 2025.

This includes our efforts to maximize the benefits from favorable power market conditions we’ve seen through Q3. Our power cost processes operating on an annual basis, resetting each year as part of the annual update tariff or AUT. While less extreme weather and improved market conditions helped reduce the volatility in 2024, we recognize the AUT will reset in 2025 and our performance may be closer to an established baseline based on market dynamics next year. As such, we have deployed high-impact actions to lock in the value of favorable positions and reduce risk ahead of the winter storm and heating season to provide both strong customer service and deliver on expectations for the year. This has caused some positive elements of our 2024 plan to shift from Q4 to Q3.

We also have less favorable power cost expectations in Q4 2024 than last year. In Q4 2023, the market conditions enabled outperformance relative to AUT assumptions. Our outlook for Q4 2024 indicates market conditions that are moderately unfavorable relative to the AUT. With this line of sight to Q4 and given our year-to-date progress, we remain confident in our ability to strongly deliver for the full year. As such, we’re narrowing our 2024 adjusted earnings guidance from $2.98 to $3.18 per share to the upper half of the range or $3.8 to $3.18 per share. Based on our current projections, we are forecasting that the earnings at the top of our current range would result in us reaching authorized regulatory ROE levels. To the extent that we see results favorable to our expectations, such favorability could be impacted by a deferral of the earnings test I mentioned earlier.

We are also reaffirming our long-term earnings and dividend growth guidance of 5% to 7%, supported by the strength of our service territory, robust capital opportunities and our improving operational execution. As we turn to the closing months of 2024, our ongoing focus of providing clean and reliable energy, while keeping customer costs as low as possible, remain unchanged. We are continuing to prioritize operational excellence and execution, allowing us to deliver maximum value to our customers, shareholders and the communities we serve. And now, operator, we’ll be ready for questions.

Q&A Session

Operator: Thank you. [Operator Instructions] Our first question comes from the line of Richard Sunderland from JPMorgan.

Maria Pope: Good morning, Richard.

Richard Sunderland: Hi, good morning. Good morning, thanks for the time today. A couple of different topics to hit on the storm deferral release. Just wanted to understand if that’s just NVTC favorability driving you to earn above that 9.5% ROE test? Or are there other factors? And it sounds like this is the case, but could a market improvement this quarter relative to today’s expectations drive the release of the remaining deferral?

Joe Trpik: So to your first part, yes, it’s mainly driven by favorable NVTC performance. And to the extent that we were to continue to outperform our expectations there would be a commensurate reduction in that deferral.

Richard Sunderland: Understood. Very clear there. Separately, Maria, you mentioned in the scripts cost work that you have been executing on. I’m curious how you see O&M trending going forward. Do you expect continued increases? Are there areas to offset some of the inflation elsewhere?

Maria Pope: Sure. It’s a great question. We have been investing significantly in our wildfire resilience and ensuring that our system is safe as particularly in our high fire risk zones. We have also done quite a bit of work to drive efficiencies across our operations. And with the additional growth that we’re seeing, we’re able to spread those fixed costs over more customers. And so we are absolutely seeing efficiencies across our operations. That includes also our deployment of capital as well. We had good success with some of the opportunities we’ve seen in the IT area as we’re keeping head count largely flat while we’re growing our base of work and serving more customers.

Richard Sunderland: Got it. And just to squeeze in one last one. You talked about 50-50 equity funding on the RFP CapEx. I know that’s been out there for a while. Curious if you see ITCs potentially helping with the funding, meaning lower equity needs because of those ITCs?

Maria Pope: Absolutely. And you should know that we put it in the queue. There’s quite a bit of ITCs and PTCs associated with the Clearwater Wind farm as well as with the battery storage that we’re bringing online. But it’s an important part of our financing going forward in addition to all of the federal grants that we’ve received. It’s really a way that we can bring those federal dollars to the state of Oregon and keep customer prices as low as possible as we lead in a clean energy transition.

Richard Sunderland: Great. Thanks for the time today.

Maria Pope: Thank you.

Operator: Thank you. [Operator Instructions] Our next question comes from the line of Shar Pourreza from Guggenheim Partners.

Shar Pourreza: Hey, guys.

Maria Pope: Good morning, Shar.

Shar Pourreza: Good morning. Maria, I think that the prefiling deadline for the upcoming long session, the state legislature is in the few weeks, sometime around December 13th. Can you speak to any preliminary discussions around wildfire legislators at this point, be it a fund like we’ve seen in other states or some legal protections. So maybe just a bit more color from your prepared? Thanks.

Maria Pope: Sure. Shar, as you know, we have long been focused on wildfire work, not only for all the work that we do in our service territory and across our operations operationally to reduce the risk of fire. But we’ve also been advocating both in the federal and the state level for appropriate legislation for changing some of the rules with regards to working in the rights of way as well as how liabilities are handled. We’ll continue to focus that work, and we are working extensively with parties at the national level and in particular, at the state level. I think you’ll see multiple bills with regards to wildfire at the coming session. And that’s really important because we’ve a lot of forest companies in this state as well as other land management agencies. And there is a wide a silo concern over the threat of wildfire, and we saw significant fires this past summer in the eastern part of our state, none of significance in our service territory.

Shahriar Pourreza: Got it. Perfect. And I know Maria, you touched a little bit on sort of the industrial growth. But just in light of some of the issues Intel’s having. Can you maybe speak to the durability of industrial growth you’re seeing 50% of that mix is semiconductors? I guess what percentage of that is Intel?

Maria Pope: Sure. So broadly speaking, 15% of semi-conductor manufacturing takes place in our service territory, not just in the state of Oregon, which has a digital manufacturing capacity. There are five key companies that operates in our area on semi-analog devices, Lam research. You have Microchip as well as Intel. About more than half of Intel’s patents were created here and other engineers and scientists that led to those that research and advancements in their science has really resulted in an ecosystem of semiconductor manufacturing in this region that the state has supported significantly, and we do not expect any changes in that and the strength of the manufacturing that we see out of the Intel campus. We also are seeing growing areas that are adjacent to semiconductor manufacturing.

So that’s air separation companies to EDA research and development companies like Keynes Design Systems, Synopsys and Mentor Graphics as well as many others. We also are seeing quite a bit of growth in data centers, as you know. So it’s a balanced growth portfolio. About half of our load today in this high-tech space is semiconductors, 20% in the fastest growing is data centers and 30% is sort of general manufacturing, but very much with a high-tech focus.

Shahriar Pourreza: Got it. And then just one last one for me. Just some commentary in the RFP docket around transmission congestion, it just impacted kind of your ability to interconnect sufficient resources to hit that 2030 target. Does the transmission CapEx you have in plan for ’28 relieve that? Or is there more work to be due in ’29 and beyond as we’re thinking about that potential spend increase?

Maria Pope: Yes. Absolutely. There’s no question, and that’s one of the reasons that we separated out our CapEx spending because we need to do more to relieve that congestion, and we have a focused group of leaders within the company who are getting that work done. We’re also partnering with entities across the state. And one of the grants that we have received is $250 million in conjunction with the confederate tribes the Warm Springs to expand the line that we own between here and the reservation where we co-own hydro facilities for significant additional renewable development. I mentioned on my prepared remarks, the North Plains Connector. But I think you’ll see transmission projects that we will continue to do, continue to bring online as well as partner with others across the region.

It’s important that we are able to access renewables that in many parts of the country are being curtailed because there is not enough transmission to bring those two customer usages. So in many instances, there’s no incremental generation costs associated with the construction and building out of that transmission network.

Shahriar Pourreza: Got it. Perfect. Thanks, guys. That answers it. Congrats on the results and see you in a couple weeks.

Maria Pope: Thank you. Nice to talk to you.

Operator: Thank you. [Operator Instructions] Our next question comes from the line of Nicholas Campanella from Barclays.

Nicholas Campanella: Good morning. Hi, I like how they said Campanella there. Hey, so I just want to ask on the rate case, you settled the you’re going to settle the AUT. Just what’s the ability to kind of settle cap structure, ROE and other components at this point? Are you kind of willing to kind of take that to a fully litigated route? And then just thinking forward as we go forward in the state, do you see settlements is still something that you can continue to get done in next rate cases? Or just how should we kind of think about that? Because in my time covering the company, it’s one of the few times that you haven’t settled. Thank you.

Joe Trpik: Good morning, Nick. This is Joe. So as it relates to the case. We continue to have open dialogue and the settlement window is open, but — in reality, we haven’t been far apart, but we haven’t been able to settle. So at this point, we’re comfortable writing either a settlement or working this through to litigation. We have built as we have gone through this a well-structured case of the evidence in that. So we continue to be hopeful that we’ll find a way here to settle some of these items, but we also, at the same time, are prepared for and have planned for the possibility of taking this case to the commission.

Nicholas Campanella: Okay. That’s super helpful. And then I guess just you talked a little bit about managing affordability in your prepared remarks. And I — it’s super exciting to see kind of the rate base growth continue to inflect higher, especially as you kind of add in these new CapEx opportunities. How are you kind of thinking about balancing all that as the CapEx just continues to scale higher here. Is it — as you wrap in these RFP awards and these build-own transfers, is that purely one for one incremental to the CapEx plan? Is there any kind of offset in the CapEx plan to manage affordability. How should we think about that?

Joe Trpik: So I’ll start on this and Maria may add in. So as it relates to the RFP, generally speaking, those are incremental to our plan. But of course, a lot of these resources that are coming online also do drive benefits. For example, the Clearwater assets that came online were a reduction to the customer bill for the energy that they were we’re replacing. And that’s key to as we work through these RFP processes when we’re selecting the project, we are evaluating them based on cost and risk and risk being, of course, risk to be able to execute and deliver. And then also as a reminder, on affordability, a lot of these projects have the ITCs or PTCs with them that are turning back to the customers, which helped drive affordability as well.

So affordability is key as we’re working towards the clean energy plan and working towards our — the policies for 2030 and beyond, but we never stop thinking about affordability and ensuring that we’re aligning that with the customers as well.

Nicholas Campanella: And then my last one is just on the RFP that it sounds like you’ll be filing a new one in ’25. Just in terms of the process and when you eventually get to the awards, what’s the time line for capital around that? Is it late ’20 — is it end of decade or is it early 2030s or could any of this kind of make it into the ’27, ’28 window? Just trying to understand that.

Joe Trpik: So our current — so we talk to the potential new RFP. So the new RFP that we’re talking about, the potential that we would file at some time in the beginning of next year, either done concurrently with an IRP or in a linear fashion. We have an expectation that those assets would be requested to come on service by 2028. So 2028, I guess we could see that could go to ’29. But considering our needs on the system, both from a renewable energy as well as capacity, we would expect whatever the next RFP is to have assets delivered in that ’28 or so period.

Nicholas Campanella: That’s really helpful. Appreciate the time today, and have a great Friday.

Maria Pope: Thank you.

Joe Trpik: Thanks, Nick.

Operator: Thank you. [Operator Instructions] Our next question comes from the line of Julien Dumoulin from Jefferies.

Unidentified Analyst: Hi, good morning.

Maria Pope: Hi, Julian.

Unidentified Analyst: Hi, it’s Brian on from Julien. Just the upcoming RFP, how much capacity is actually remaining after you complete the 2023 RFP?

Joe Trpik: Yes. So I’ll pull that up as we’re talking here. But just as a reminder, when we kicked off the 2023 RFP, the needs of that IRP at a midpoint were 3,200 megawatts. So we will update the IRP, which has the expectation of potential growth, which will redefine that item. So if you take that we had 3,200 megawatts of need, the nameplate of both groups A and Group B is 1,700 megawatts total. Again, just as an understanding, we will be acting and we’re in discussions with Group A and then we will evaluate the needs for those Group B items. But so they’re — you have 3,200 megawatts is what our need was before this RFP. We have 1,700 megawatts of nameplate gear, and then we will update that with the IRP in the first quarter of next year.

Unidentified Analyst: Okay. Great. And any milestones we should look for the Northern Lands connector? Are you still the only for 20% is still impact? And then also remind of the Confederated Tribes of Warm Springs CapEx profile in the five years. Is it all within the five years or does that project extend past 2028?

Joe Trpik: So I’ll start with on the North Plains connector, we continue to proceed with our 20% stake. There will be — there are, at this point in time, specific dates of milestone. We will be adding partners we will make disclosures when our commitments continue to expand. Right now, we have a memorandum understanding that it is not binding. So — but there will be updates that proceed as new partners and that project proceeds. As it relates to the Confederated Tribes of Warm Springs, this is a reminder, we have placed in the plan that you currently see the first year of that project is in 2028. We would expect that to be a multiyear project going out beyond our current forecast period that we show, you would expect as a normal transmission project that you’ll get a few years out of that. Just as a reminder, tying this back to the grant, that is the project where the competitor tribes have are participating in one of the grants with the federal government.

Unidentified Analyst: Okay. And then just lastly, you mentioned the tax credits as a means to offset some of the equity financing. Could you just talk more specifically on the strategy with Constable and Seaside. I think as part of the rate case, the refund to customers over five or 10 or 20 years is being evaluated? Just wanted to get your thoughts.

Joe Trpik: So sure. Specific to Constable and Seaside, which are eligible for ITC, if you value the two of them combined, you’d get somewhere around approximately $150 million over time. So our policy is to refund them to customers over a period that we align with the regulator, right? And as you mentioned, the refund period for these are not set, it will be somewhere between five and 15 years. But on the financing side to that, we also have had agreement with the OPUC as it relates to being able to monetize these tax credits on the front end as long as we — and be able to do it, I should say, within a discount of 10%. So we’ve generally taken approach where these — when these tax credits are earned, we will monetize these tax credits, thereby reducing our equity needs, and that equity need reduction will be tied to how long that amortization period is.

Unidentified Analyst: Okay, great. Thank you, very much.

Joe Trpik: I was going to say just this year, we have monetized $31 million in credits this year, and we do have certain agreements for future monetization as well.

Unidentified Analyst: Understood. Thank you.

Operator: Thank you. [Operator Instructions] Our next question comes from the line of Michael Lonegan from Evercore ISI.

Maria Pope: Good morning.

Michael Lonegan: Hi, thanks for the questions. So on the RFP, you previously paid out 25% ownership that you assumed in your illustrative rate base growth rate base growth, example. So the final shortlist here could be towards 50% ownership, it looks like. Just wondering how you’re thinking about where this positions you to land in the range of your 5% to 7% EPS growth forecast? Obviously, the additional CapEx could come with incremental equity that you’ve spoken to.

Joe Trpik: I think currently this RFP, obviously, you measure how we do in either Group A or group. But no matter how you look at it, all of this continues to align us within the earnings band as we had mentioned. So the success of these RFPs, assuming we continue to execute with would be consistent with our earnings expectations within the growth bit.

Michael Lonegan: Got it. Thank you. And then secondly for me, on the pending rate case, you can see that some items, you revised your as with some like you with further request for the investment recovery mechanism and the related storage policy. Just wondering if you see an opportunity to ask for these in the next rate case. I think you’ve alluded to annual filings going forward.

Joe Trpik: Yes. I think each case, as you know, stands by itself. And what we’ve been trying to do in these cases is be responsive to the stakeholders on things of obviously managing affordability but also managing the timing of cases in that. So yes, I believe we’ll continue to have dialogue over items like an and IRM items as it relates to trackers for storage solely to continue to align to their goal. So yes, for this case, we’ve pulled some of them out. But I think we’ll work through potentially, there have been discussions of a multiyear framework going forward. But I would think that these type of proposals will come forward in the future. And so I think there’s possibility for them. I think tools like this will be needed to consistently meet the clean energy goals and meet the expectations of the timing of rate cases and other matters.

Michael Lonegan: Great. Thanks for the time.

Maria Pope: Thank you.

Operator: Thank you. [Operator Instructions] Our next question comes from the line of Travis Miller from Morningstar Inc.

Travis Miller: Good morning. Thank you.

Maria Pope: Good morning, Travis.

Travis Miller: Hi, sticking on that rate case, and you answered a lot of questions around the settlement and what’s going on there. But what do you see high level is the difference between perhaps this rate case and the settlement negotiations and the past several where you’ve been able to settle? Are there certain issues or certain things that have come up that are making it less possible if that’s the right way to put it to settle?

Maria Pope: Sure. That’s a really good question. And I’d say that the biggest distinction in the discussions and overall dialogue in this rate case is that some parties have focused a lot on the press and sort of the broader inflationary environment?

Travis Miller: Okay. Okay. So more public animosity, again, if it’s very worth than past settlements — is that the way to…

Maria Pope: I think that’s the — those are the tools that they’ve decided that are helpful to where they want to go and what they want to accomplish.

Travis Miller: Okay. Statutory is there a settlement period end — or can you continue to try to settle throughout the oral arguments?

Joe Trpik: I believe I won’t be precise here, but I believe it remains open not until we get, once we get to the hearing, that’s when the period, I believe would…

Maria Pope: Yes, and I want to reiterate that we have had extensive discussions. Overall, they have been very constructive and that we’re not far apart with most parties. But so far, as we know, we’ve not been able to reach a settlement. And I think that likely could be where we end up.

Travis Miller: Okay, perfect. And then one different subject. When these industrial customers are coming to you, the new ones and ask them for — to get on the system, what are they saying as the reason for choosing your system, right, apart from the fact that there are a lot of semiconductors, et cetera, in that area. Is it access to the grid is really easy, the low cost of power? What are some of the things they are telling you they like about…

Maria Pope: So for the significant manufacturers and particularly those for whom power quality and power factors are very important. That absolutely is a consideration I would also say that there’s an ecosystem of talent, whether it starts from our community colleges to our universities and to the overall environment that has been built up over several decades of really significant talent in this region. There’s no question that the subsea communications cables from the Pacific, which terminate in Oregon, just as the Atlantic cables terminate in Virginia have an impact on data centers as well as other companies. And I think there’s also much of our customer base is really focused on clean energy, and we have been a leader when it comes to delivering clean energy and options for those customers, particularly those that want to go faster, further towards 100% clean energy.

Travis Miller: Sure. Okay, that’s great, Thanks so much.

Maria Pope: Thank you.

Operator: Thank you. [Operator Instructions] Our next question comes from the line of Anthony Crowdell from Mizuho.

Anthony Crowdell: Hey, good morning, team. Just a couple of quick questions. I appreciate all the detail. I know we’ve talked a lot about the tax credits. When the company gives forward year guidance or will the company start giving us how much they’re assuming in ITCs for each year?

Maria Pope: That’s a good question. It will dovetail with the renewable projects that we’re bringing online or the storage projects that we’re bringing online. And so as we give you more color with regards to those projects, we’d be happy to give you the associated tax savings or investment tax savings that will come with each of those projects. In general rule of thumb, it’s 30% or north of the capital amount of the project. It’s a very significant ability to reduce customer prices with these tax credits.

Anthony Crowdell: Great. And then I think you spoke about earlier I hope I’ve the numbers right, load growth for this year, I believe it’s like 2% to 2.5%, but long-term, it’s 2% and you’re going to revisit that on the — when you file the 2025 IRP. So does that — just understanding the cadence, right, if that’s correct, do we potentially get an update on the long-term load growth on the fourth quarter call?

Maria Pope: Yes. I don’t know if we will have all of the analysis complete by that time. We have been doing updates on our load growth as we have seen significant changes. I probably think you’ll see it closer to March for the IRP update. But suffice it to say, we have really good, diverse solid load growth. And that’s important as we look at our cost structure overall and our ability to deliver cost effectively for customers.

Anthony Crowdell: Great. And I guess just my last question. I believe politically Washington State and Oregon are somewhat aligned. It appears that Washington State is getting less green. I think on this year’s ballot in Washington state, there’s some like — I don’t know if I characterize like anti-green bill, but there’s a bill where they’re going to ban any restriction on gas going to new buildings, may revoke some RPS standards. I’m just curious if Oregon is seeing any of that? Are you seeing the state get less green?

Maria Pope: Sure. I think, first of all, we have different policies when it comes to clean energy and carbon reductions. And first and foremost, for us as a customer, we’re really guided — as a utility, we are really guided by our customers and their interest. 25% of our customers voluntarily pay to a little bit more on their bill for 100% clean energy. And many of our largest high-tech customers as well as municipal customers, hospitals and others participate in our green future programs, having 100% clean energy for them as well. So one of the key reasons for this is that we have been able to bring on new clean resources very economically. As Joe was mentioning, the Clearwater Wind Project actually has reduced customer prices this year to date and is a significant part of how we build out our portfolio, as has additional hydro contracts, and we look forward to the battery stores we’re bringing them online.

Anthony Crowdell: So just to recap, you’re not seeing any ballot initiatives on changing any of the state’s policies on renewables or green?

Maria Pope: There could be discussions out there that we’re not aware of, but we don’t see any balloting initiatives.

Anthony Crowdell: Great, thanks so much for taking my questions and congrats on a good quarter.

Maria Pope: Thank you.

Joe Trpik: Thank you.

Operator: Thank you. [Operator Instructions] Our next question comes from the line of Chris Ellinghaus from Siebert Williams Shank.

Chris Ellinghaus: Hey everybody.

Maria Pope: Good morning, Chris.

Chris Ellinghaus: Maria, sort of customer growth has been accelerating in the last few quarters. Can you sort of talk about where that’s coming from? And is that sort of some of your new data centers, semi customers increasing employment?

Maria Pope: Sure. So first of all, as Joe mentioned in his remarks, he noted that this customer growth could be chunky. And we have seen it go up and down at different levels between quarters because some of it is significant. 50% of our customer — our industrial customer base is semiconductor manufacturing. 20% is data centers and then 30% is other manufacturing. It is overall that industrial segment that is growing the fastest and the 9% that I mentioned before. We also continue to see in-migration in most of our counties, and continued new connections. So all of that is very positive.

Chris Ellinghaus: Okay, great. You’ve had a really great effort on net variable power cost this year. Your — can you sort of provide us a little color. You’re derisking of supply effort, while the AUT gets reset every year is sort of your lengthening strategy. Should we think about you being able to be more in line with the AUT going forward? Or was this year more market-related sort of factors?

Maria Pope: Sure. So first of all, it starts with our own generation facilities and the folks that run those operations and the exceptionally good work that they have done. Next, it is the integration of our generation with resources that we procure either in long-term contracts and partnerships or in shorter-term partnerships. One of the goals we have also had is to build out what comes from the distribution system. We call it on a sort of a wonky terms, our virtual power plant as 25% of our systems energy capacity by 2030 will come from that area. And that provides an important stabilizing ability for us, and we have put a lot of time and effort into that work. We also procure power from across the entire region and are entering into the California independent system operators day-ahead market.

We’ve had terrific success in the energy and balance market and this past year, we have seen power flows really begin to change quite significantly as excess solar out of California combined with their battery storage has flattened overall market conditions and allow for a much more significant inflows of power into the Pacific Northwest from other regions that are higher and generating solar power and others. We also see overall that many of our peer utilities have done many of the same actions that we have, and that’s provided more capacity throughout the entire system. We’re collectively working together through the Western Power Pool on resource adequacy to ensure that the trends that we saw in the third quarter, which could significantly reverse the prior couple of years, very volatile and negative results on the power cost side, continue into the future.

Chris Ellinghaus: Okay. Great. And lastly, somebody asked about balancing costs in the RFPs. But theoretically, the sort of data is expanding almost exponentially, and you also have electrification ahead. So when you’re thinking about RFP resources and costs, do you also think about there is potentially huge load growth that continues for a pretty extended period. So do you think about the opportunity cost of getting short in that kind of environment? And just wanting to add resources to prevent getting behind the curve.

Maria Pope: Sure. It’s a really good question. And as we look at the RFP results, we’re balancing reliability, affordability and the pace of our transition to ever-increasing amounts of clean energy. We also have brought on existing resources, hydro contracts from the Columbia River and some of the PUDs that operate in those regions through our partnerships with them and with others. We look at this as a broad set of strategies, knowing that one of the key factors for clean energy transition is that it is affordable for all of our customers. We serve everyone in our service territory and affordability and keeping prices as low as possible is also very important in this transition.

Chris Ellinghaus: Okay, thanks everybody. Appreciate it.

Maria Pope: Thank you.

Joe Trpik: Thank you.

Operator: Thank you. [Operator Instructions] Our next question comes from the line of Paul Fremont from Ladenburg Thalmann & Co. Inc.

Maria Pope: Hi, Paul.

Paul Fremont: Thank you. Hey, good morning.

Joe Trpik: Good morning.

Paul Fremont: It looks like there’s $55 million reduction in generation spending this year. Some of that looks like a delay and some of that seems to be offset with higher distribution and general technology spending. Can you sort of document what happened there?

Joe Trpik: So if you’re talking — Paul, if you’re talking to a full year, we just have a lot of — we’ve had some timing movements as we’ve executed some of that generation is things like land purchases for items, things like that. So I mean, what we really are that we continue to pretty effectively execute our plan. We saw some items as we work through the year that we’re going to be a little delayed. So we’ve shifted. If you look between the update between the two years of the capital plan, we pretty much net to 0. There’s a little bit of some — as projects get their money colored differently, but there’s no real substantive change to our plan other than just the timing of execution.

Paul Fremont: Great. With the OPUC expected to certify the results of the RFP in November, how long is it going to take for you to actually execute the contracts so that we see it showing up in your capital spending forecast?

Joe Trpik: As specifically as it relates to the build transfer items, we currently anticipate it will be the second-half of 2025. As we’ve started into the discussions with the party and applying our experience for some similar agreements in the past, that seems to be what the time frame will end up being here. But we will update parties, obviously, to the extent that changes, but that is our current expectation.

Paul Fremont: And I guess I can see sort of the second bucket B, but with respect to A, wouldn’t you have sort of enough information to update after you get OPUC acknowledgment?

Joe Trpik: I think if it relates to having a date once we have the acknowledgment we’ll be able to — I agree, we’ll have more precision. I mean if your question is will we be able to generate a little bit more certainty to say, hey, it’s very likely to be, say, the second half with those? Yes, I would think as we get not only the approval because we’re already dialoguing with the parties. But as we continue to dialogue here and lock down certain provisions, which are critical for us to have a contract, yes, we — hopefully, we’ll have updates here and tighten some of these down. But again as we’re moving on this — if I could just — if we’re moving on this delay, nothing in our dialogue with the parties, even as we’re talking to time of the contract is changing our expectation that the assets will be delivered by the end of ’27.

Paul Fremont: And then aside from ITCs or tax credits, I mean, have you thought of other ways to potentially reduce the equity need of the company?

Joe Trpik: So yes, we continue to evaluate other approaches to the company. I know there’s been discussion at times of different financing structures and different products, and we do continue to evaluate them. Some of them take some more detailed actions. And the way I like to look at this is we are like resolute in being focused on the wildfire and addressing what is the broadest issue to the company. And as we start to get alignment on that, evaluating and taking action on potentially other designs and processes will come more into light, but we think it is critical as we continue to evaluate, but to act first and be aligned on wildfire and then we’ll subsequently address some of these different potential approaches we can take to financing our growth.

Paul Fremont: And then, I mean, if you were to potentially establish a holding company, would you consider selling down a minority stake in the utility?

Joe Trpik: So I don’t want to give guidance on any transactions, but I would just tell you that as you know, we are evaluating all options here, Paul, that would come from that. So there’s nothing that isn’t on the table to ensure that we can serve our customers safely and reliably and manage our growth.

Paul Fremont: And are settlements in Oregon, do they need to be unanimous or could you do a partial settlement in Oregon?

Maria Pope: We can do partial settlements in Oregon. It’s not common. And it is what we do end up settling. But we’re not necessarily in common times.

Paul Fremont: Well, I understand that. But I think what you said is that with a number of the more significant parties, you’re — you think you’re close. Why not go with the partial settlement and wouldn’t that put you in better standing going into a final OPUC decision?

Maria Pope: If we could get to that resolution, then that probably would be a good idea. I’m not sure we could get to that resolution. But we have had thorough discussions, and we have a solid record even if we do get to an Oregon Public Utility Commission decision.

Paul Fremont: And then last question for me. I mean, I think the base of your EPS growth is still sort of 2022. Is there — are there any thoughts to potentially updating that at some point in time, the base here?

Joe Trpik: The answer is yes, at some point in time, honestly, we would like to get some time under our pocket, right? We have said as a company that we want to deliver and meet our expectations and goals here. We are in the sort of the middle of doing that right now. So that is something we continually evaluate. But I think showing we can execute first under the plan we have would be the first item before we decide that it’s time to look to an update or a rebase on.

Paul Fremont: Thank you. Thank you very much.

Maria Pope: Thank you.

Joe Trpik: Thank you, Paul.

Maria Pope: Great questions.

Operator: Thank you. At this time, I would now like to turn the conference back over to Maria Pope for closing remarks.

Maria Pope: Thank you all for joining us this morning. We appreciate your interest in Portland General Electric, and we look forward to connecting with you soon. In particular, we’ll probably see many of you at the upcoming EEI Financial Conference next month. Thank you, and have a great day.

Operator: This concludes today’s conference call. Thank you for participating. You may now disconnect.