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spk19: Good morning, everyone, and welcome to Portland General Electric Company's fourth quarter 2022 earnings results conference call. Today is Thursday, February 16, 2023. This call has been recorded and such as all lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question and answer period. If you would like to ask a question during this time, simply press star 11 on your telephone keypad. If you would like to withdraw your question, please press star 11 again. If you do intend to ask the question, please avoid the use of speaker phones. For opening remarks, I will turn the conference call over to Portland General Electric Senior Director of Finance, Investor Relations, and Risk Management, Jardon Jardomio. Please go ahead, sir.
spk10: Thank you, Tawanda. 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 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. Leading our discussion today are Maria Pope, President and CEO, and Jim Agello, Senior Vice President of Finance, CFO, Treasurer, and CCO. Following their prepared remarks, we will open the line for your questions. Now, it's my pleasure to turn the call over to Maria.
spk20: Great. Thank you, Jordan. Good morning. Thank you all for joining us today. Beginning with slide four, I'll start by discussing our 2022 full year and fourth quarter results, as well as touch on a few key drivers. Overall, we delivered solid results for the year despite significant challenges. we reported GAAP net income of $233 million or $2.60 per share for the full year of 2022. After adjusting for the first quarter 14-cent impact of the 2020 wildfire and COVID earnings test write-off, non-GAAP net income was $245 million or $2.74 per diluted share. This compares with $244 million or $2.72 per share in 2021. For the fourth quarter, GAAP net income was $50 million or $0.56 per share. This compares with $66 million or $0.73 per share in the fourth quarter of 2021. As we were specifically impacted by severe late December storms, and extraordinary natural gas and energy market volatility. In December, natural gas prices at regional hubs peaked at over $55 per mm BTU, and average mid-seat power prices rose to $265 per megawatt hour, over five times what we experienced in 2021. The risks and impacts of market volatility are squarely in our focus. We've made improvements to procurement, modeling, and have entered into additional hedges. We're also more actively using natural gas storage at the North Mist facility to mitigate market volatility. Over the last year, our hedging program was effective and is also being improved upon. While 2022 prices at the Mid-Sea increased by nearly 60% the price for our customers paid for power only increased by 14%. As hedges roll off, further energy market-related price increases include 7.7% in 2023 and a forecast of 4.5% in 2024. Load growth continues at a rapid pace, increasing 2% over last year. High-tech and digital customers are driving this increase, with industrialized growing at 10.6%. Offsetting this impact is a customer mix shift with a return to lower residential pre-COVID usage. From an operating perspective, I could not be prouder of the hard work and dedication of our team this year in driving operational efficiencies and navigating extraordinary weather conditions. Including the impacts of increased wildfire mitigation expenses and deferral items, year-over-year generation, transmission, and distribution O&M was up less than 1%, and administrative and other O&M was up 1.2%, as we are laser-focused on cost management to offset the impacts of inflation and other costs. Moving to slide five. Our commitment to affordability remains steadfast and will continue to manage costs aggressively. We are streamlining our work processes, simplifying, leveraging technology, and improving productivity. We have upped our game with regards to aging infrastructure and compliance, replacing and installing critical assets to strengthen our reliability. On the technology front, we've deployed digital tools to enable operational efficiencies and visibility, better resource deployment, and improved customer service. We've decreased the average duration of business impacting events by over 13% and saved thousands of person hours through automation of repeatable tasks. We're also using machine learning to improve restoration forecasting giving our customers greater clarity while we reduce 1.3 million outage minutes in 2022. We are cognizant as well of our broader social impact and responsibility. Our spending with diverse suppliers increased significantly, helping to sustain and strengthen our communities. Jim will go into more detail on our O&M as we are again planning to be largely flat in 2023, excluding the impacts of increased wildfire mitigation expenses and deferral items. Today, we filed our 2024 rate case, or I should actually say yesterday, we filed our 2024 rate case with the OPUC, which includes a 14% price increase. 40% of our request is related to reliability, resiliency, and customer-acquired capital investment. 30% is driven by higher natural gas and purchase energy prices, with the last 30% reflective of higher compliance costs and inflation, as well as operating and financing costs. In addition, we're seeking an authorization for important work to protect and mitigate against climate and significant event risks, such as wildfires. An important aspect of our general rate case is addressing our power cost adjustment mechanism, or PCAM. We have proposed modifications to the power cost regulatory framework to facilitate Oregon's decarbonization goals and better reflect current and future operating conditions. This is not a risk transfer. Rather, our proposal will create a more durable framework that supports customers by fairly balancing benefits and costs and improving the overall mechanism. As in the past, we look forward to collaborative discussions with the OPUC and stakeholders, especially during this period of enormous transformation and significant capital investments. Last quarter, as you know, we announced the Clearwater Wind Project, one of our benchmark generation bids. We are optimistic about the potential ownership opportunities as we continue to negotiate the remaining non-admitting dispatchable capacity RFP. We expect to procure 375 megawatts in needs that was identified in the 2021 RFP. This includes PGE benchmark projects, at potential PPAs that will be critical tools in supporting reliability and helping us manage power cost volatility given the additional wind and solar variable resources coming onto our system. We expect these negotiations to conclude in the first half of this year. In March, we will file our Combined Clean Energy Plan and Integrated Resource Plan. As we've shared previously, these plans will incorporate Oregon's overall decarbonization goals and PGE's associated actions. In the second half of the year, we expect to launch additional RFPs for renewable generation and non-emitting capacity in alignment with those plans. As we continue to lead the way to a clean energy future, reliability and affordability have been and will always be key to this transformation. With the passage of the Infrastructure Investment and Jobs Act and the Inflation Reduction Act, we look forward to working in partnership with local communities, tribal entities, technology companies, and others to secure federal funding for climate and infrastructure investments, helping to reduce customer bill impacts. In 2022, we submitted 180 million in federal grant applications and concept papers. And in just the first six weeks of 2023, we have submitted an additional 300 million of concept papers. This nearly 480 million in grant applications and concept papers are in support of projects, totaling approximately 945 million, targeted towards projects which will range from new technologies that integrate ever-increasing amounts of renewable energy to large-scale transmission. For the full year 2023, we expect earnings to be in the range of $2.60 to $2.75 per share. 2023 represents an investment year. The equity issuance to reset our balance sheet and regulatory lag are temporary headwinds. and our 2024 GRC and RFP investment opportunities establish a clear path to strong performance. Looking beyond 2023, we are confident in our long-term earnings growth of 5% to 7%, driven by strong load and customer growth, an attractive capital investment profile, and improved operational performance that enables exceptional customer service. In summary, Our performance in 2022 laid a strong foundation for long-term growth. We advanced critical decarbonization projects, navigated historic power market volatility, and executed well in face of severe weather. As we look ahead, we are confident that by remaining focused on providing safe, reliable, affordable, and clean energy to all customers, we will deliver strong financial results. With that, I'll turn it over to Jim.
spk07: Thank you, Maria, and good morning, everyone. Our 2022 results reflect both the upside of our service territory, but also the challenges we face as our region undertakes the energy transformation journey. Strong load growth continued, but we also faced difficult power market volatility and severe weather that impacted our performance. First, some context for operating conditions. We witnessed continued demand growth as well as changing load patterns as habits have shifted from the height of the pandemic in 2021 to more normalized usage in 2022. Overall, 2022 loads increased 2% weather adjusted compared to 2021. On a non-weather adjusted basis, total load increased 3.4% year over year. driven by cold periods in the spring and winter and a historically warm summer. In 2022, Portland saw the hottest July and August temperatures on record and extreme winter temperatures in December caused a new winter peak for the first time since 1998. Residential usage increased 1.4% on a non-weather adjusted basis, but decreased 1.4% weather adjusted As COVID-19 related usage trends moderated from the elevated 2021 levels, residential customer counts increased 1.2% during the year. Commercial usage increased 0.1% non-weather adjusted, but decreased 0.5% weather adjusted as commercial growth has slowed slightly in the aftermath of the pandemic. compared to the high growth levels in the segment in 2021. The industrial class continued on its rapid growth trajectory, with industrial loads increasing 10.9% on a weather-adjusted basis, or 10.6% weather-adjusted, as high-tech sectors' steady expansion in our region continued. Similar to much of the country, we have seen some signals of moderation in our regional economy, remain confident in the fundamentals of our service territory. A healthy pipeline of construction and interconnections gives us line of sight to load expectations in 2023 and beyond. As such, we are reaffirming our long-term load growth guidance of 2% through 2027. As Maria noted, our quarterly EPS decreased from 73 cents per share in the fourth quarter of 21 to 56 cents per share in the fourth quarter of 22. We relied on all available strategies to mitigate the impact of historic volatility in the Pacific Northwest in the closing weeks of 2022. But demand during cold weather stretches and sustained high prices created financial impacts that could not be entirely overcome during this volatile time. Despite these conditions, our financial liquidity remains strong, and we closed 2022 having served 39% of retail customer load from specified non-carbon emitting energy sources during the year. You will also remember that in fourth quarter 2021, we had already surpassed the $30 million upper dead band in the PCAM, creating a unique quarter over quarter cost comparison. Given this context, I'll turn to slide six and cover our financial performance year over year. We experienced a 40 cent increase in total revenues compared to 21. including a 63 cent increase in eps due to the 3.4 increase in deliveries led by growing demand from our high-tech and digital industrial customers partially offset by a 23 cent decrease in eps changes due to changes in customer price composition with industrial load growth outweighing residential and commercial load power costs increased in net two cents compared to 2021 made up of $0.27 increase attributed to the headwinds in 2021 net of the 2021 PCAM deferral that we normalized for this comparison. Higher market prices driven by resource scarcity in peak periods, primarily driven by serving load during periods of severe weather and market volatility, drove a $0.19 EPS decrease. An $0.08 decrease due to higher purchase volumes to serve load in 2022 and 2 cent decrease due to the change incurred as part of the 2021 PCAM referral settlement. There was a 6 cent decrease to EPS attributed to higher operating expenses, net of storm restoration and regulatory program costs that are offset in revenue, driven primarily by increased wildfire mitigation, vegetation management, and grid hardening efforts that increased in 2022. It was a 5 cent impact from depreciation and amortization expense driven by higher plant asset balances in 2022 compared to 2021, mostly for transmission distribution and intangible technology assets. There was a 5 cent decrease due to higher property and payroll taxes. a $0.09 decrease due to higher interest expense driven by increased long-term debt balances throughout 2022 with higher interest rates, including our Q3 2021 and Q4 2022 debt issuances. It was a $0.09 decrease driven by the local flow-through tax adjustment recognized in 21, which did not recur in 2022. We had a net $0.02 decrease reflecting offsetting impacts from a handful of items as follows. A $0.07 decrease due to lower returns on the non-qualified benefit trust compared to 2021. A $0.04 decrease due to lower AFUDC driven by lower quick balances in 2022. a $0.09 decrease due to the settlement gain and the buyout of a portion of PGE's post-retirement medical plan, and finally, a $0.01 decrease due to other miscellaneous items. Lastly, we experienced a $0.14 decrease to GAAP EPS as a result of the application of the earnings test on major 2020 deferrals established in the final 2022 GRC order, which brings us to our gap eps of 160 per diluted share after adjusting for the 14 cent impact of the 2022 grc earnings test deferral reduction we reach our 2022 non-gap eps of 2.74 cents per diluted share moving to slide seven as noted earlier yesterday we filed the general rate case with the oregon public utility commission to review our cost of providing service and approve new prices to take effect in January 2024. The GRC filing requests recovery of essential capital investments of nearly $859 million in upgrading the grid to improve reliability, resiliency, and capability to deliver safe, reliable, and clean electricity to customers. This includes the Faraday Hydro Project, which was placed into service in January of 2023. The requested price increase reflects a rate base of $6.3 billion, an increase of $859 million, or 16%, a return on equity of 9.8%, a capital structure of 50% debt and 50% equity, a cost of debt of 4.32%, and a cost of capital of 7.06%. As Maria discussed, the filing also includes a proposed modification of the PCAMP. The proposal provides a 90-10 sharing of power cost variances without a deadband mechanism. Additionally, the proposal provides for full recovery of costs prudently incurred during specific reliability contingency events. Finally, recovery or refund over multiple years as each year's recovery is subject to a rolling customer price impact cap, which limits the annual price changes for the mechanism recovery or credit to 2.5%, meaning any variance causing price changes above 2.5% is carried to the following year or continued collection or credit. Ozil is a fair and balanced one and aligns the interests of our customers with the company. We look forward to engaging with stakeholders during the red case process, which would take about 10 months, with a procedural schedule publication expected in the coming weeks. On to slide 8 for an update of our 2021 RFP. The Clearwater project announced in the fourth quarter is now under construction with project completion still estimated by the end of 2023. Maria touched on the ongoing negotiations relating to the remaining non-emitting dispatchable capacity and I will reiterate that this includes PGE's benchmark projects. Negotiations are going well and we continue to be optimistic about our ownership opportunities for battery storage resources. We are hopeful to share the outcome of these negotiations in the first half of 2023. We are also continuing negotiations for incremental renewable generation projects as part of the 2021 RFP. If contracts for additional generation projects are not achieved in the 2021 RFP, we would include them in our next RFP. With the conclusion of the 2021 RFP on the horizon, we are now beginning to turn attention to the 2023 resource planning and procurement processes. We recently filed notice with the OPUC that an RFP in 2023 is needed to procure resources to be forecasted capacity needs and to make continued progress towards Oregon's decarbonization targets. We will file PGE's first clean energy plan by the end of March, outlining PGE's strategy to meet decarbonization targets under the Oregon law, along with the 2023 integrated resource plan. We will recommend the initiation of the 2023 RFP process by the third quarter of 2023 and hope to select the final short list and submit a request for acknowledgement to the OPUC by the end of 2023. Turning to slide 9, which shows our refreshed capital forecast through 2027. As a reminder, figures for 2023 through 2027 do not include any potential expenditures related to possible ownership from the remainder of the current RFP or future RFP cycles. Slide 10 includes a visual illustration of investment opportunities through the end of the decade to meet our 2030 emission standards. For additional context, our 2022 capital expenditures were $811 million, including accruals, exceeding the previous guidance of $750 million, as we continued our efforts to modernize and optimize the grid, deploy technology to drive efficiencies, and invest in critical infrastructure. Turning to slide 11, you can see that our rate-based trajectory through 2027, considering both rate-based capital expenditures and the Clearwater project, and when considering RFP opportunities, additional RFP opportunities at an assumed 25% ownership rate, which could be conservative. The illustrative capital investment trajectory plus additional opportunities stemming from the current and future RFP cycles will enable us to achieve our 5% to 7% long-term earnings growth guidance goals. This is an opportunity outlook and not reflective of earnings growth as the plan requires equity and debt capital to consummate. Turning to slide 12, our balance sheet remains strong and we continue to maintain our investment grade credit ratings accompanied by a stable credit outlook. Total available liquidity at December 31st, 2022 is $938 million. And I'll note this does not include counting any of the equity forward that is now in place. As we look ahead to 2023, we anticipate a debt issuance of up to $250 million later in the year, in addition to the $100 million funded earlier this year. We will continue to issue debt under our green financing framework whenever possible to continue our practice of tying debt financing to our sustainability strategy through capital investments. We also anticipate issuing common equity in 2023 under the existing equity forward sale agreement executed in 2022, beginning with approximately $300 million in the first quarter. Remaining draws against the equity forward will be completed by the end of the agreement's 24-month term. Turning to slide 13, we are initiating full year 2023 adjusted earnings guidance of $2.60 to $2.75 per dollar to share. I'd like to walk through a few key drivers that will help us achieve this target in 2023. As I mentioned previously, we remain confident in the fundamentals of the service territory and anticipate continued growth in demand, led by our high-tech and digital customers with more modest increases in residential and commercial load. Combined, we assume 2.5 to 3% weather-adjusted retail load growth in 2023. While our total 2023 O&M guidance midpoint stands at 705, this includes approximately $45 million of deferral amortization that will be offset in other income statement lines. Net of this amortization, $655 million of O&M is roughly flat with the normalized 2022 O&M of $659 million, which excludes the impact of the 2022 GRC deferral reduction and storm costs offset in revenue. 2022 O&M included significant efforts to streamline our work processes, improve productivity through the organization, and provide the highest quality service to customers. This hard work and our lessons learned will yield efficiency in 2023 and will help our cost management strategy. Just a few examples. We trimmed 3,300 line miles of vegetation to reduce wildfire risk. We replaced and installed over 8,200 power poles. We launched an outage priority automation program aligning crew scheduling with restoration priorities. We decreased the average duration of business impacting events by over 13%, saving thousands of person hours through automation and repeatable work. We achieved a reduction of 1.3 million in customer outage minutes. We accomplished a time to complete customer design projects from 80 to 60 days, and our line ops productivity increased 40%. Looking back since 2019, our core O&M after deferrals has grown in line with inflation. During the same timeframe, we've absorbed a significant set of increases in wildfire mitigation expenses while increasing our customer footprint by 5%. Deliveries went up in that time period by 10% to energy retail customers. And the rate base increased 24% since 2019. Accelerating how we serve customers and reaching scale in the business, all while keeping headcount flat. 2023 represents a critical investment year that will strengthen PGE for sustained long-term growth in years to come. We remain confident in our growth trajectory and reiterate our long-term earnings growth of 5% to 7%. based off of 2023 adjusted actual results. To be clear, our outlook for the long-term growth prospects is unchanged. Using our actual 2022 result as a starting point provides clarity for the calculation and how we believe we are able to move more meaningfully into the range by 2025. We are also reaffirming our long-term dividend growth guidance of 5% to 7% for 2023. We expect to be near or slightly above the top of our 60% to 70% payout ratio. Regarding dividends, Our board recently declared a dividend of 45.25 cents per share. Our 2022 full-year declared dividend was $1.79, which completed our 16th consecutive year of dividend growth, with the last five years at a 5.8% compounded annual growth rate. Due to dilution expected in 2023, the dividend payout ratio may be higher than historical ratios, but we expect this to be a temporary phenomenon. As we turn our undivided attention to the year ahead, we remain committed to our core mission of providing clean, reliable, and affordable energy and executing our long-term financial goals while delivering value to our customers, our community, and our shareholders. And now, operator, we're ready for questions.
spk19: Thank you. Ladies and gentlemen, as a reminder to ask the question, please press star 11 on your telephone. and wait for your name to be announced. To withdraw your question, please press star 11 again. Please stand by while we compile the Q&A roster. Our first question comes from the line of Julian DeMolen Smith with Bank of America. Your line is open.
spk08: Thank you. Thank you, Tina. Hey, good morning. Thanks for the opportunity. Hey, listen, I just wanted to come back to the extension here and the reaffirmation of 5-7. Kudos there. I just want to clarify this and really press a little bit. Obviously, 22, you're rolling forward on the actuals as the baseline here, but clearly 22 was towards the lower end of the overall range here. Again, I just want to hear if you say, for instance, came in towards the midpoint of 22 and that would have been the baseline here to reset the actuals, Would you still feel comfortable with the outlook in the 5-7? I know that's a little bit of a what-if type question, so hopefully it's fair. But with that said, I just want to make sure we're crystal clear about any potential signaling of moving to a 22 actual given where you came against the actual range with respect to the cascading implications on the 5-7.
spk07: Yeah, Julian, it's Jim. I don't consider this a rebasing. I would say that The context here is when we released new earnings guidance in the third quarter, we didn't have actual 22 numbers, right? And so I think it's quite fair for people to take the midpoint of the range and start to extrapolate from there. But I hope we were always clear on basing it off the 22 actual results. And as you're implying, we had a rough end of the year given weather and volatility. But the bottom line is I would still be comfortable in achieving the 5% to 7% range, even if earnings were a little bit higher, adjusted earnings were a little bit higher in 2022. The opportunity that we have to grow the business is still significant. We feel that we'd be very comfortable inside the 5% to 7% range. And so while it's a hypothetical question, and we're not using, you know, the hypothetical to base the forward look, I'm still pretty comfortable and pretty confident in the 5% range, even if you did.
spk20: So, Julian, you know, underlining the 5% to 7% long-term is really our fundamental service territory growth that we're seeing in terms of customer usage of 2%. And we're very fortunate to have a strong technology sector in our area We also have to serve that. We see a growing need for renewable energy, both wind, solar, battery storage, longer-term even some pumped hydro storage. But in addition, the growth that we're seeing is putting pressure on our distribution infrastructure, and we're also seeing replacement of aging assets and developing out a bidirectional smart virtual power plant. And then we're also seeing increasing needs for transmission. So all of those projects combined with a strong load growth makes us confident in the 5% to 7% long term.
spk08: And actually, just since we're talking about the 2% load growth here, I mean, just can you elaborate a little bit? Is it shaped differently considering some of the headlines we've seen here in early 23 and specifically what that does to the tech sector, et cetera? Or is that reading too much into the outlook here?
spk20: No, that's a really good question. It's something that we've looked a lot at ourselves. Near term, we feel very confident in the growth rate because much of the capacity is already built out by the semiconductor as well as digital customers. So it's really filling out capital investment that they have already spent as they're continuing to contract with their customers. We have not seen a turndown in the semiconductor area. I would note that most of the semiconductor work that we do here for our customers relates to R&D and other cutting edge developments. So if you think of having a lamb research in our service territory, as well as much of the R&D areas for Intel and others, it's not quite the same commodity semiconductor manufacturing that you see in other states. We're very fortunate. And as we look at the investments from the CHIPS Act and the support the state of Oregon is giving to this sector, we're fairly bullish.
spk09: Got it.
spk08: Excellent. And then just the cadence of developments, I mean, obviously you guys are quite constructive here on the setup on some of the renewable developments here. But in terms of the procurements themselves and data points from a near-term perspective to kind of give you affirmation on your specific ability to own some of these opportunities, Maybe that was in Jim's comments. Can you review that in brief here, just where we stand and what should be the expectation here on those data points here in the next few months?
spk07: Yeah, sure, Julian. So we're working towards the capacity or battery sets right now. We have been working towards that for a number of months now. I would say that, you know, given this challenging macro environment that we're in, It just takes, it is taking a little longer, but we're literally, you know, I'll call it a number of months away by the end of the first half of the year. So still have a lot of confidence there. That will still be a very substantial capital investment. Stay tuned for that. But as we get closer to announcing that, we'll also provide updates on how we're going to finance that as well. But I think that that's an opportunity that will be there. There may even be some generation opportunity in this first set, but even if it's not there, it'll roll into the next RFP, which will begin very soon after the mid-year point as well. So as we've discussed in the past, we're going to be in an almost constant procurement cycle for the next four or five years as we get towards the end of the decade. to achieve the DCARB goals. So we've added a couple of slides here for you, slides 10 and 11 in particular, which show you the opportunity set that's there. These are numbers that are embedded in our working group and our clean energy plan that you're about to see. And we've also provided illustrative rate-based growth. And I made the point in the commentary that that the eight and a half percent CAGR does not include financing so it's not a surrogate for a small but it just goes to show you the capital investment needed here uh in addition to clear water that we have in front of us so we're really optimistic um and this is really at a 25 ownership rate so i think uh you know a lot of folks including yourself were asking for a bit of a a bit of an illustration on how we looked at that. I think this could be conservative.
spk09: Excellent. Well, thank you, Jim. We appreciate the time today, and we'll speak to you soon, all right? Sure.
spk19: Thank you. Thank you. Please stand by for our next question. Our next question comes from the line of Sophie Carr with KeyBank. Your line is open.
spk27: Hi, good morning. Thank you for taking my question.
spk28: I wanted to ask you about the slide 11 here in particular, which you just referenced. I think it's very helpful in terms of showing the what-if upside scenario. And so you guys outlined a potential for 8.5% CAGR for the rate base here with certain assumptions, but stopped short of translating that into a potential EPS CAGR upside, and I'm just curious how you think about potential like puts and takes here in this upside scenario in financing equity needs and how regulatory lag under various scenarios, how would that translate into the EPS CAGR, and when would we have some more clarity on that?
spk07: Yeah, Sophie, thanks for the question. I think we're going to be providing incremental clarity as we, when, actual projects, right? And so since we have two more procurement cycles plus the wrap-up of the current one, I don't want to be presumptuous about that and present an earnings model based on, you know, this growth rate. But you can assume a couple of things, I believe, which is fair. This is at a 25%, I'll call it handicapping of the total opportunity, you know, taking into account a generation that's owned by others, you know, DER and other needs that are taken care of. It'll assume accretive projects. It'll assume that we finance that a 50-50 debt equity structure. And you could assume, too, that as we enter 2023, the balance sheet repair will be almost done, will be a long way into adding to the equity ratio. So it's a bit of a clean start for growth. In terms of the balance sheet, we've asked for a 50-50 ratio in this new rate case. So I'm not providing an earnings model against this, but if I were to look at this from that 8.5% illustration that we have, that's why we call it illustration, not guidance. You'd have to assume 50% equity and 50% debt, but this at least gives you the numbers upon which to do that modeling.
spk28: All right. Thank you. And it's fair to say that you would go about issuing equity in a similar fashion as you are sort of gone about it so far? Maybe not.
spk07: Yeah, maybe not. I think given the nature of these projects, which are mostly billed on transfer, I think that'll continue. That means that we won't want to over-equitize the projects on day one. because they haven't been built yet. So what we'll do more than likely is use forward equity and private place bonds with also delayed draws. So both features, both markets have delayed draw opportunities so we can actually fund progress payments with equity and debt as we go. That'll be the best and most efficient structure to fund the projects. So we have no negative arbitrage, if you get my drift.
spk25: Yep.
spk07: So I certainly like the at-the-market program as a technique as we go into this latter part of the year. So that's what I'm thinking right now.
spk28: Thank you. Thank you. My other question is a more, I guess, philosophical question. So pretty significant power price, energy prices, volatility, and power in the gas that you guys have seen, as you highlighted. As you look at the build-out plans in the region, particularly for electric generation, would you say that the way the generation stack is poised to evolve here is likely to reduce or increase this volatility in the future?
spk20: That's a great question, and I think what we're going to see is a significant increase in distributed energy resources rooftop solar in particular, but also more locational-based battery storage, which will not necessarily help the seasonal changes, particularly those that could be caused by multi-year drought, but will certainly reduce the fluctuations on a 24-hour basis as we have solar periods versus wind periods versus hydro periods. And I think you'll see overall less volatility But we could see more longer-term seasonal issues, particularly with multi-year drought periods or multi-year high precipitation and high wind periods. You know, Sophia, as we look going forward, you're asking the million-dollar question that we're all trying to figure out. And what we take is sort of what I'd say is an all-or-none set of solutions. We're looking at every alternative because as we move forward, particularly with the growth we have, we're going to need the diversity of all of those resources and the ability to respond and maintain reliability at the lowest cost for customers. The most expensive way to handle a transition would be to create a great shop for customers, and we need to be prudent here, particularly as we're seeing higher and higher reliability issues. I'd also say we're working much more closely across the entire West in terms of integrated markets, in terms of partnerships between high-tech companies, large and small, to regional and global hydro players. And we're, again, an all-above set of solutions.
spk26: Thank you. I appreciate the call.
spk19: Thank you. Thank you. Please stand by for our next question. Our next question comes from the line of Alex Mortimer with the Mizzou Hope Group. Your line is open. Morning, Alex.
spk11: Hi, thank you very much. Good morning. So we've seen high natural gas prices kind of across the Pacific Northwest, even as we've seen decreases in other areas from other hubs in the country. Is there any ability you have to diversify from your hub?
spk20: Yes, there is. And actually, one of the things that's really interesting is what happened this last December. Whenever things spike as they did, it's a confluence of multiple events. Clearly, you had very hot weather turning very cold quickly without the period that many of the storage facilities across the West were able to refill. You also had pretty dry December, so you had many hydro participants who had actually sold forward energy and needed to fulfill those contracts, putting unusual pressure on the market. And then you had, as Jim mentioned, super cold weather and usage that spiked. So I think as we look to going forward, how we create stronger hedging strategies, more diversity in resources, Additional partnerships, again, for more diversity is all part of our strategy as we move forward and will have an incremental benefit. The other is, as we looked at last year, we had forecast very strong industrial demand driven by semiconductor industry, cloud computing, and other digital capabilities. But it exceeded even our expectations. And so as we go into 2023, we've really re-racked the way we think about our customer load and different customer segments. And so that will give us – that's much more aligned to our hedging strategy throughout the entire year that is already in place. So, yes, we're doing more, and we already have done much of that.
spk11: Perfect thanks for that color and then just in terms of guidance both in 2023 and then kind of over the long term with the five to seven basically what gets you either to the higher low end both in the near and long term and then is there any bias with how things stand at the moment within that range?
spk07: I would say that there's no particular bias at this moment. we are leveraged to the RFP opportunities that we have. Really, those are where we're going to reach the upper limits of that guidance range. But I would say increasingly, even since Last October, when we first talked about increasing this guidance range, that we are more confident now that we can be comfortably inside that range with what's in front of us. I'll leave it more qualitative at the moment and just, you know, tell you that I think that our confidence level has actually increased in the last five or six months.
spk20: I also would add that we are really well poised to bring to Oregon and to our customers significant federal funding, whether it be for reliability and resiliency and let's say BRIC grants from FEMA, whether it be an infrastructure grants and partnerships with transportation organizations across the state of Oregon and the IIJA, whether it be in terms of clean energy through the IRA. We are focused in being successful in these areas. We've already started with a number of applications and are really working hard to make a difference as we go through a significant transition to reduce the otherwise customer price impact of a clean energy transition.
spk07: Yeah, and I think I would add two things to Maria's commentary. Number one is that, of course, given that the Treasury rules on the Inflation Reduction Act are not yet promulgated, we think there's upside. We're just not sure how to calculate that yet and where the market is going to monetize the credits. That's point number one. And point number two, I'm really pleased about how we've attacked the federal programs that are available. And, you know, Our concept papers and our grant applications are so far put against $945 million in total project opportunity. And we haven't had one concept paper rejected. And the way it works is you submit a concept paper. If your concept paper is accepted, you're invited to make a bid. We've had no rejections of the concept papers. concept paper rejects are at 50% right now. So all of our applications and concept papers so far are moving forward.
spk06: So I think that's a good sign.
spk11: Okay, thank you very much. And then just finally, we've seen headwinds obviously across the industry, whether it be natural gas, interest rates, inflations, et cetera. I was just hoping you could provide any sort of color on your assumptions on when some of these headwinds may abate going forward. just given the reaffirmation of the five to seven today?
spk20: Well, your guess is as good as ours. We are expecting to see continued inflation through 2023, hoping that it will moderate. But clearly, particularly when it comes to electrical equipment, in particular transformers and other capital investment, we are continuing to see steep demand robust prices and working very hard to improve our processes, our systems, and our efficient deployment of all of that equipment to mitigate the impact of all of those external factors on our customer base.
spk07: I just can't guess, right? It's too hard, but we can just do what we've been doing, right? We've grown deliveries 10%, customer count five, kept our head count flat, And, you know, we've grown the rate base pretty significantly, right? So we're getting scale in the business.
spk06: So that's the continued focus that we have against a difficult macro environment.
spk02: Excellent. Thank you. I'll leave it there, and good luck with the year.
spk06: Thank you.
spk02: Thank you.
spk19: Thank you. Ladies and gentlemen, as a reminder to ask the question, please press star 11 on your telephone. Please stand by for our next question. Our next question comes from the line of Travis Miller with Morningstar. Your line is open.
spk14: Travis Miller Good morning. Thank you. Just on the 20, following up on that 2023 or rather 2021, the RFP, the projects to come, When you break out that 375 and then the remaining, are there technology differences that you're looking at in that 375 and then that remaining up to 200? Yes.
spk07: Yes, Travis, there are, right? So in addition to the wind and possibly more wind, solar, of course, there is an opportunity for substantial battery efficiency. sets in there. We're working on some right now, and that's what we hope to announce by the end of the first half. There is one pump storage project in the acknowledgement list that's there, and when we turn the crank on the next RFP in the middle of this year, I'll call it July 1 for or pointers, you know, we'll see additional technologies. We're technology agnostic, right? It's all about pricing for the consumers, managing the load and the grid, and integrating them efficiently. So we expect to see more diversity as we go.
spk14: Okay. All those would be... I guess for lack of a better term, traditional renewable energy. We're not load management or anything like that though, right? DER.
spk07: I think there's a lot of DER going on, but not necessarily as part of this procurement process. I also think that we will see additional players come in. So the dynamics could evolve, competitive dynamics could evolve here as this decade unfolds. So stay tuned for that, and we'll keep you updated.
spk14: Okay, perfect. And then one longer term, the range you provided out through 2030 at 2.2 to 3.1, What are the underlying assumptions? Aside, I'm thinking you probably have that same type load growth, but are there retirements in that assumption? Are there other load shaping assumption within that number? And what's embedded in that number or that range?
spk20: No, it's a great question, and there are a number of assumptions, and probably as we look forward, there's more variability than we've ever seen in our industry. We do not have any retirements included in any of those assumptions of any of our assets, with the exception of we are planning on getting out of our coal strip investment and not having that energy delivered to our customers here in Oregon. We also have, and this relates a little bit to your earlier question to Jim, we are fairly advanced when it comes to a virtual power plant. So we are incorporating distributed energy resources, some of which we own, but many of which our customers own and will increasingly own in the future. We also have a number of load management programs which help with some of our hedging. And we're also looking at the adoption rapidly in this area of electric vehicles. As you know, Oregon and our service territory is one of the top five leaders of EV penetration in the country. So there's a number of items that are impacting our load forecast and our asset growth forecast over time.
spk13: Okay. Perfect. I appreciate it. Thank you.
spk19: Thank you. Please stand by for our next question. Our next question comes from the line of Nicholas Campanelli with Credit Suisse. Your line is open.
spk12: Morning. Hey, everybody. It's Nate. Oh, hi. It's Nathan Richardson on for Nick. Thank you for taking my question. I just wanted to ask, what's assumed for the PCAM in 23, if you haven't covered that already? Is it the baseline or is it still a headwind there?
spk20: Okay. As we look at our PTAM, we forecast basically at the annual update tariff, so there's no forecast. I do think that as you look at our power costs and you look at the entire region, it's important to note where we are with hydro conditions. Fifty-five percent of the energy generated across the Northwest is hydro-based, and we're roughly, and you can see it in the 10K and in our disclosures were roughly a little bit over 80%. And that's low, but it's in particular low in comparison to last year, where you saw mid-C and others at 110%. And so we have forecast those lower hydro levels into our energy prices for this coming year. And I think that's an important sort of calibration in terms of the risk balancing of 2023?
spk07: So one way to shorthand it is we enter the year flat based on the AUT, which is the baseline, if you want to call it that, of the PCAM. So obviously things change. We saw that last year.
spk06: But we essentially are reset at the beginning of every January one.
spk22: Great. Thank you very much.
spk09: Thank you. You're welcome.
spk19: Thank you. Our next question comes from the line of James Kennedy with Guggenheim Partners. One moment. Your line is open.
spk24: Hey, guys. Good morning.
spk15: I apologize if I missed this a little earlier, but the slippage of the 2021 items in the RFP process, what is actually driving that? Is it the bids that were rebid? Is it the deadline for the RFP itself? I guess just what would drive that schedule?
spk20: You know, it's just normal commercial negotiations in a time of extraordinary supply chain challenges. You know, we've had a number of solar projects recently that have been laid as they have been laid across the country. And we want to make certain that as we are negotiating that all of these projects will be delivered as expected. And it's a challenging environment out there, but it's nothing unusual.
spk07: Yeah. It's a question of a few months, James, you know, the long arc of these, you know, projects. I'm not concerned at all. And also, batteries are unusual in the sense that they're modular, right? So we're always looking at the grid and what kind of storage and capacity is needed around the grid. And we're able to work with the vendors to size those projects appropriately based on the latest information we have. So as you go further in time, you have more information about the grid and you can actually design more. around that, but we're talking about very modest differences in timeframe.
spk15: Okay, perfect. And then just one kind of nuanced question. I really like slide 11, but I'm just curious, one of the footnotes, you assumed about 25% ownership of the midpoint. How did you kind of arrive at that number?
spk07: Yeah, so we stepped back and we wanted to provide this sort of illustration to help you understand what the opportunity is. We wanted to be somewhat conservative but also take into account what we saw happening in the rest of the market, you know, the PPAs, third-party agreements, community solar, DER, I mean, you name it, right? So we tried to have a holistic look at what we would need to do to make the DCARB goals possible. And so I think, you know, over time, I would say that we won a higher percentage and I'll let Maria add on to this because of her history here, in terms of utility scale generation. We've been much more successful on that. But this 25% is more a piece of the pie of the more holistic energy mix that we have.
spk20: You know, we've sometimes surprised ourselves with the number of self-builds or ownership opportunities we've had through RFPs. And I think it's because we take very seriously... the need to be cost competitive and least cost, least risk. And we work very hard to make sure that our bids are set up, the customer price impacts first and foremost, as well as the overall functionality with the portfolio. So hopefully we will be as successful as we have been in the past, but it's highly competitive, which is important in terms of driving costs to their lowest levels. which is a challenge through a significant energy transition and something we need to always stay constantly vigilant on.
spk16: Cool. Makes sense. Thanks, guys.
spk19: Thank you. Thank you. I'm sure no further questions in the queue.
spk20: Thank you very much for joining us today. We appreciate your interest in Portland General, and we look forward to seeing you all soon. Well, I very much appreciate the robust questions. Thank you.
spk19: To raise and lower your hand during Q&A, you can... The conference will begin shortly.
spk18: To raise and lower your hand during Q&A, you can dial star 1 1. Thank you. Music Playing Thank you. you Thank you. you Bye. Thank you.
spk19: Good morning everyone and welcome to Portland General Electric Company's fourth quarter 2022 earnings results conference call. Today is Thursday, February 16, 2023. This call has been recorded and such as all lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question and answer period. If you would like to ask a question during this time, simply press star 11 on your telephone keypad. If you would like to withdraw your question, please press star 11 again. If you do intend to ask the question, please avoid the use of speaker phones. For opening remarks, I will turn the conference call over to Portland General Electric Senior Director of Finance, Investor Relations, and Risk Management, Jardon Jardomeo. Please go ahead, sir.
spk10: Thank you, Tawanda. 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 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. Leading our discussion today are Maria Pope, President and CEO, and Jim Agello, Senior Vice President of Finance, CFO, Treasurer, and CCO. Following their prepared remarks, we will open the line for your questions. Now, it's my pleasure to turn the call over to Maria.
spk20: Great. Thank you, Jordan. Good morning. Thank you all for joining us today. Beginning with slide four, I'll start by discussing our 2022 full year and fourth quarter results, as well as touch on a few key drivers. Overall, we delivered solid results for the year despite significant challenges. we reported GAAP net income of $233 million or $2.60 per share for the full year of 2022. After adjusting for the first quarter $0.14 impact of the 2020 wildfire and COVID earnings test write-off, non-GAAP net income was $245 million or $2.74 per diluted share. This compares with $244 million or $2.72 per share in 2021. For the fourth quarter, GAAP net income was $50 million or $0.56 per share. This compares with $66 million or $0.73 per share in the fourth quarter of 2021. As we were specifically impacted by severe late December storms, and extraordinary natural gas and energy market volatility. In December, natural gas prices at regional hubs peaked at over $55 per mm BTU, and average mid-seat power prices rose to $265 per megawatt hour, over five times what we experienced in 2021. The risks and impacts of market volatility are squarely in our focus. We've made improvements to procurement, modeling, and have entered into additional hedges. We're also more actively using natural gas storage at the North Mist facility to mitigate market volatility. Over the last year, our hedging program was effective and is also being improved upon. While 2022 prices at the Mid-Sea increased by nearly 60%, the price for our customers paid for power only increased by 14%. As hedges roll off, further energy market-related price increases include 7.7% in 2023 and a forecast of 4.5% in 2024. Load growth continues at a rapid pace, increasing 2% over last year. High-tech and digital customers are driving this increase, with industrialized growing at 10.6%. Offsetting this impact is a customer mix shift with a return to lower residential pre-COVID usage. From an operating perspective, I could not be prouder of the hard work and dedication of our team this year in driving operational efficiencies and navigating extraordinary weather conditions. Including the impacts of increased wildfire mitigation expenses and deferral items, year-over-year generation, transmission, and distribution O&M was up less than 1%, and administrative and other O&M was up 1.2%, as we are laser-focused on cost management to offset the impacts of inflation and other costs. Moving to slide five. Our commitment to affordability remains steadfast and will continue to manage costs aggressively. We are streamlining our work processes, simplifying, leveraging technology, and improving productivity. We have upped our game with regards to aging infrastructure and compliance, replacing and installing critical assets to strengthen our reliability. On the technology front, we've deployed digital tools to enable operational efficiencies and visibility, better resource deployment, and improved customer service. We've decreased the average duration of business impacting events by over 13% and saved thousands of person hours through automation of repeatable tasks. We're also using machine learning to improve restoration forecasting, giving our customers greater clarity while we reduce 1.3 million outage minutes in 2022. We are cognizant as well of our broader social impact and responsibility. Our spending with diverse suppliers increased significantly, helping to sustain and strengthen our communities. Jim will go into more detail on our O&M as we are again planning to be largely flat in 2023, excluding the impacts of increased wildfire mitigation expenses and deferral items. Today, we filed our 2024 rate case, or I should actually say yesterday, we filed our 2024 rate case with the OPUC, which includes a 14% price increase. 40% of our request is related to reliability, resiliency, and customer-acquired capital investment. 30% is driven by higher natural gas and purchase energy prices, with the last 30% reflective of higher compliance costs and inflation, as well as operating and financing costs. In addition, we're seeking an authorization for important work to protect and mitigate against climate and significant event risks, such as wildfires. An important aspect of our general rate case is addressing our power cost adjustment mechanism, or PCAM. We have proposed modifications to the power cost regulatory framework to facilitate Oregon's decarbonization goals and better reflect current and future operating conditions. This is not a risk transfer. Rather, our proposal will create a more durable framework that supports customers by fairly balancing benefits and costs and improving the overall mechanism. As in the past, we look forward to collaborative discussions with the OPUC and stakeholders, especially during this period of enormous transformation and significant capital investments. Last quarter, as you know, we announced the Clearwater Wind Project, one of our benchmark generation bids. We are optimistic about the potential ownership opportunities as we continue to negotiate the remaining non-admitting dispatchable capacity RFP. We expect to procure 375 megawatts in needs that was identified in the 2021 RFP. This includes PGE benchmark projects, at potential PPAs that will be critical tools in supporting reliability and helping us manage power cost volatility given the additional wind and solar variable resources coming onto our system. We expect these negotiations to conclude in the first half of this year. In March, we will file our Combined Clean Energy Plan and Integrated Resource Plan. As we've shared previously, these plans will incorporate Oregon's overall decarbonization goals and PGE's associated actions. In the second half of the year, we expect to launch additional RFPs for renewable generation and non-emitting capacity in alignment with those plans. As we continue to lead the way to a clean energy future, reliability and affordability have been and will always be key to this transformation. With the passage of the Infrastructure Investment and Jobs Act and the Inflation Reduction Act, we look forward to working in partnership with local communities, tribal entities, technology companies, and others to secure federal funding for climate and infrastructure investments, helping to reduce customer bill impacts. In 2022, we submitted 180 million in federal grant applications and concept papers. And in just the first six weeks of 2023, we have submitted an additional 300 million of concept papers. This nearly 480 million in grant applications and concept papers are in support of projects, totaling approximately 945 million, targeted towards projects which will range from new technologies that integrate ever-increasing amounts of renewable energy to large-scale transmission. For the full year 2023, we expect earnings to be in the range of $2.60 to $2.75 per share. 2023 represents an investment year. The equity issuance to reset our balance sheet and regulatory lag are temporary headwinds. and our 2024 GRC and RFP investment opportunities establish a clear path to strong performance. Looking beyond 2023, we are confident in our long-term earnings growth of 5% to 7%, driven by strong load and customer growth, an attractive capital investment profile, and improved operational performance that enables exceptional customer service. In summary, Our performance in 2022 laid a strong foundation for long-term growth. We advanced critical decarbonization projects, navigated historic power market volatility, and executed well in face of severe weather. As we look ahead, we are confident that by remaining focused on providing safe, reliable, affordable, and clean energy to all customers, we will deliver strong financial results. With that, I'll turn it over to Jim.
spk07: Thank you, Maria, and good morning, everyone. Our 2022 results reflect both the upside of our service territory, but also the challenges we face as our region undertakes the energy transformation journey. Strong load growth continued, but we also faced difficult power market volatility and severe weather that impacted our performance. First, some context for operating conditions. We witnessed continued demand growth as well as changing load patterns as habits have shifted from the height of the pandemic in 2021 to more normalized usage in 2022. Overall, 2022 loads increased 2% weather adjusted compared to 2021. On a non-weather adjusted basis, total load increased 3.4% year over year. driven by cold periods in the spring and winter and a historically warm summer. In 2022, Portland saw the hottest July and August temperatures on record, and extreme winter temperatures in December caused a new winter peak for the first time since 1998. Residential usage increased 1.4% on a non-weather-adjusted basis but decreased 1.4% weather-adjusted As COVID-19 related usage trends moderated for the elevated 2021 levels, residential customer counts increased 1.2% during the year. Commercial usage increased 0.1% non-weather adjusted, but decreased 0.5% weather adjusted as commercial growth has slowed slightly in the aftermath of the pandemic. compared to the high growth levels in the segment in 2021. The industrial class continued on its rapid growth trajectory, with industrial loads increasing 10.9% on a weather-adjusted basis or 10.6% weather-adjusted. As high-tech sectors, steady expansion in our region continued. Similar to much of the country, we have seen some signals of moderation in our regional economy. remain confident in the fundamentals of our service territory. A healthy pipeline of construction and interconnections gives us line of sight to load expectations in 2023 and beyond. As such, we are reaffirming our long-term load growth guidance of 2% through 2027. As Maria noted, our quarterly EPS decreased from 73 cents per share in the fourth quarter of 21 to 56 cents per share in the fourth quarter of 22. We relied on all available strategies to mitigate the impact of historic volatility in the Pacific Northwest in the closing weeks of 2022. But demand during cold weather stretches and sustained high prices created financial impacts that could not be entirely overcome during this volatile time. Despite these conditions, our financial liquidity remains strong, and we closed 2022 having served 39% of retail customer load from specified non-carbon emitting energy sources during the year. You will also remember that in fourth quarter 2021, we had already surpassed the $30 million upper dead band in the PCAM, creating a unique quarter over quarter cost comparison. Given this context, I'll turn to slide six and cover our financial performance year over year. We experienced a 40 cent increase in total revenues compared to 21. including a $0.63 increase in EPS due to the 3.4% increase in deliveries, led by growing demand from our high-tech and digital industrial customers, partially offset by a $0.23 decrease in EPS due to changes in customer price composition with industrial load growth outweighing residential and commercial load. Power costs increased a net $0.02 compared to 2021, made up of 27-cent increase attributed to the headwinds in 2021 net of the 2021 PCAM deferral that we normalized for this comparison. Higher market prices driven by resource scarcity in peak periods, primarily driven by serving load during periods of severe weather and market volatility, drove a 19-cent EPS decrease, an 8-cent decrease due to higher purchase volumes to serve load in 22, and 2 cent decrease due to the change incurred as part of the 2021 PCAM referral settlement. There was a 6 cent decrease to EPS attributed to higher operating expenses, net of storm restoration, and regulatory program costs that are offset in revenue, driven primarily by increased wildfire mitigation, vegetation management, and grid hardening efforts that increased in 2022. It was a 5 cent impact from depreciation and amortization expense driven by higher plant asset balances in 2022 compared to 2021, mostly for transmission distribution and intangible technology assets. There was a 5 cent decrease due to higher property and payroll taxes. a $0.09 decrease due to higher interest expense driven by increased long-term debt balances throughout 2022 with higher interest rates, including our Q3 2021 and Q4 2022 debt issuances. It was a $0.09 decrease driven by the local flow-through tax adjustment recognized in 21, which did not recur in 2022. We had a net $0.02 decrease reflecting offsetting impacts from a handful of items as follows. A $0.07 decrease due to lower returns on the non-qualified benefit trust compared to 2021. A $0.04 decrease due to lower AFUDC driven by lower quick balances in 2022. a $0.09 decrease due to the settlement gain and the buyout of a portion of PGE's post-retirement medical plan, and finally, a $0.01 decrease due to other miscellaneous items. Lastly, we experienced a $0.14 decrease to GAAP EPS as a result of the application of the earnings test on major 2020 deferrals established in the final 2022 GRC order, which brings us to our gap eps of 160 per diluted share after adjusting for the 14 cent impact of the 2022 grc earnings test deferral reduction we reach our 2022 non-gap eps of 2.74 cents per diluted share moving to slide seven as noted earlier yesterday we filed the general rate case with the oregon public utility commission to review our cost of providing service and approve new prices to take effect in January 2024. The GRC filing requests recovery of essential capital investments of nearly $859 million in upgrading the grid to improve reliability, resiliency, and capability to deliver safe, reliable, and clean electricity to customers. This includes the Faraday Hydro Project, which was placed into service in January of 2023. The requested price increase reflects a rate base of $6.3 billion, an increase of $859 million, or 16%, a return on equity of 9.8%, a capital structure of 50% debt and 50% equity, a cost of debt of 4.32%, and a cost of capital of 7.06%. As Maria discussed, the filing also includes a proposed modification of the PCAMP The proposal provides a 90-10 sharing of power cost variances without a deadband mechanism. Additionally, the proposal provides for full recovery of costs prudently incurred during specific reliability contingency events. Finally, recovery or refund over multiple years, as each year's recovery is subject to a rolling customer price impact cap, which limits the annual price changes for the mechanism recovery or credit to 2.5%, meaning any variance causing price changes above 2.5% is carried to the following year or continued collection or credit. Proposal is a fair and balanced one and aligns the interests of our customers with the company. We look forward to engaging with stakeholders during the rate case process, which would take about 10 months, with a procedural schedule publication expected in the coming weeks. On to slide eight for an update of our 2021 RFP. The Clearwater project announced in the fourth quarter is now under construction, with project completion still estimated by the end of 2023. Maria touched on the ongoing negotiations relating to the remaining non-emitting dispatchable capacity, and I will reiterate that this includes PGE's benchmark projects. Negotiations are going well, and we continue to be optimistic about our ownership opportunities for battery storage resources. We are hopeful to share the outcome of these negotiations in the first half of 2023. We are also continuing negotiations for incremental renewable generation projects as part of the 2021 RFP. If contracts for additional generation projects are not achieved in the 21 RFP, we would include them in our next RFP. With the conclusion of the 2021 RFP on the horizon, we are now beginning to turn attention to the 2023 resource planning and procurement processes. We recently filed notice with the OPUC that an RFP in 2023 is needed to procure resources to be forecasted capacity needs and to make continued progress towards Oregon's decarbonization targets. We will file PGE's first clean energy plan by the end of March outlining PGE's strategy to meet decarbonization targets under the Oregon law, along with the 2023 integrated resource plan. We will recommend the initiation of the 2023 RFP process by the third quarter of 2023 and hope to select the final short list and submit a request for acknowledgement to the OPUC by the end of 2023. Turning to slide 9, which shows our refreshed capital forecast through 2027. As a reminder, figures for 2023 through 2027 do not include any potential expenditures related to possible ownership from the remainder of the current RFP or future RFP cycles. Slide 10 includes a visual illustration of investment opportunities through the end of the decade to meet our 2030 emission standards. For additional context, our 2022 capital expenditures were $811 million, including accruals, exceeding the previous guidance of $750 million, as we continued our efforts to modernize and optimize the grid, deploy technology to drive efficiencies, and invest in critical infrastructure. Turning to slide 11, you can see that our rate-based trajectory through 2027, considering both rate-based capital expenditures and the Clearwater project, and when considering RFP opportunities, additional RFP opportunities at an assumed 25% ownership rate, which could be conservative. The illustrative capital investment trajectory plus additional opportunities stemming from the current and future RFP cycles will enable us to achieve our 5% to 7% long-term earnings growth guidance. This is an opportunity outlook and not reflective of earnings growth as the plan requires equity and debt capital to consummate. Turning to slide 12, our balance sheet remains strong and we continue to maintain our investment grade credit ratings accompanied by a stable credit outlook. Total available liquidity at December 31st, 2022 is $938 million. And I'll note this does not include counting any of the equity forward that is now in place. As we look ahead to 2023, we anticipate a debt issuance of up to $250 million later in the year, in addition to the $100 million funded earlier this year. We will continue to issue debt under our green financing framework whenever possible to continue our practice of tying debt financing to our sustainability strategy through capital investments. We also anticipate issuing common equity in 2023 under the existing equity forward sale agreement executed in 2022, beginning with approximately $300 million in the first quarter. Remaining draws against the equity forward will be completed by the end of the agreement's 24-month term. Turning to slide 13, we are initiating full year 2023 adjusted earnings guidance of $2.60 to $2.75 per dollar to share. I'd like to walk through a few key drivers that will help us achieve this target in 2023. As I mentioned previously, we remain confident in the fundamentals of the service territory and anticipate continued growth in demand, led by our high-tech and digital customers with more modest increases in residential and commercial load. Combined, we assume 2.5 to 3% weather-adjusted retail load growth in 2023. While our total 2023 O&M guidance midpoint stands at 705, this includes approximately $45 million of deferral amortization that will be offset in other income statement lines. Net of this amortization, $655 million of O&M is roughly flat with the normalized 2022 O&M of $659 million, which excludes the impact of the 2022 GRC deferral reduction and storm costs offset in revenue. 2022 O&M included significant efforts to streamline our work processes, improve productivity through the organization, and provide the highest quality service to customers. This hard work and our lessons learned will yield efficiency in 2023 and will help our cost management strategy. Just a few examples. We trimmed 3,300 line miles of vegetation to reduce wildfire risk. We replaced and installed over 8,200 power poles. We launched an outage priority automation program aligning crew scheduling with restoration priorities. We decreased the average duration of business impacting events by over 13%, saving thousands of person hours through automation and repeatable work. We achieved a reduction of 1.3 million in customer outage minutes. We accomplished a time to complete customer design projects from 80 to 60 days, and our line ops productivity increased 40%. Looking back since 2019, our core O&M after deferrals has grown in line with inflation. During the same timeframe, we've absorbed a significant set of increases in wildfire mitigation expenses while increasing our customer footprint by 5%. Deliveries went up in that time period by 10% to energy retail customers. And the rate base increased 24% since 2019. Accelerating how we serve customers and reaching scale in the business, all while keeping headcount flat. 2023 represents a critical investment year that will strengthen PGE for sustained long-term growth in years to come. We remain confident in our growth trajectory and reiterate our long-term earnings growth of 5% to 7%. based off of 2023 adjusted actual results. To be clear, our outlook for the long-term growth prospects is unchanged. Using our actual 2022 result as a starting point provides clarity for the calculation and how we believe we are able to move more meaningfully into the range by 2025. We are also reaffirming our long-term dividend growth guidance of 5% to 7% for 2023. We expect to be near or slightly above the top of our 60% to 70% payout ratio. Regarding dividends, Our board recently declared a dividend of 45.25 cents per share. Our 2022 full-year declared dividend was $1.79, which completed our 16th consecutive year of dividend growth with the last five years at a 5.8% compounded annual growth rate. Due to dilution expected in 2023, the dividend payout ratio may be higher than historical ratios, but we expect this to be a temporary phenomenon. As we turn our undivided attention to the year ahead, we remain committed to our core mission of providing clean, reliable, and affordable energy and executing our long-term financial goals while delivering value to our customers, our community, and our shareholders. And now, operator, we're ready for questions.
spk19: Thank you. Ladies and gentlemen, as a reminder to ask the question, please press star 11 on your telephone. and wait for your name to be announced. To withdraw your question, please press star 11 again. Please stand by while we compile the Q&A roster. Our first question comes from the line of Julian DeMolen Smith with Bank of America. Your line is open.
spk08: Thank you. Thank you, Tina. Hey, good morning. Thanks for the opportunity. Hey, listen, I just wanted to come back to the extension here and the reaffirmation of 5-7. Kudos there. I just want to clarify this and really press a little bit. Obviously, 22, you're rolling forward on the actuals as the baseline here, but clearly 22 was towards the lower end of the overall range here. Again, I just want to hear if you say, for instance, came in towards the midpoint of 22 and that would have been the baseline here to reset the actuals, Would you still feel comfortable with the outlook in a 5-7? I know that's a little bit of a what-if type question, so hopefully it's fair. But with that said, I just want to make sure we're crystal clear about any potential signaling of moving to a 22 actual given where you came against the actual range with respect to the cascading implications on the 5-7.
spk07: Yeah, Julian, it's Jim. I don't consider this a rebasing. I would say that The context here is when we released new earnings guidance in the third quarter, we didn't have actual 22 numbers, right? And so I think it's quite fair for people to take the midpoint of the range and start to extrapolate from there. But I hope we were always clear on basing it off the 22 actual results. And as you're implying, we had a rough end of the year given weather and volatility. so but the bottom line is i would still be comfortable uh in achieving the five to seven percent range even if earnings were a little bit higher adjusted earnings were a little bit higher in 2022 the opportunity that we have to grow the business is still significant we feel that we'd be very comfortable inside the five to seven percent range and so while it's a hypothetical question and we're not using, you know, the hypothetical to base the forward look, I'm still pretty comfortable and very confident in the 5% range, even if you did.
spk20: So, Julian, you know, underlining the 5% to 7% long-term is really our fundamental service territory growth that we're seeing in terms of customer usage of 2%. And we're very fortunate to have a strong technology sector in our area. We also have to serve that. We see a growing need for renewable energy, both wind, solar, battery storage, longer-term even some pumped hydro storage. But in addition, the growth that we're seeing is putting pressure on our distribution infrastructure, and we're also seeing replacement of aging assets and developing out a bidirectional smart virtual power plant. And then we're also seeing increasing needs for transmission. So all of those projects combined with a strong load growth makes us confident in the 5% to 7% long term.
spk08: And actually, just since we're talking about the 2% load growth here, I mean, just can you elaborate a little bit? Is it shaped differently considering some of the headlines we've seen here in early 23 and specifically what that does to the tech sector, et cetera? Or is that reading too much into the outlook here?
spk20: No, that's a really good question and something that we've looked a lot at ourselves. Near term, we feel very confident in the growth rate because much of the capacity is already built out by the semiconductor as well as digital customers. So it's really filling out capital investment that they have already spent as they're continuing to contract with their customers. We have not seen a turndown the semiconductor area i would note that most of the semiconductor work that we do here for our customers relates to r d and other cutting edge developments so if you think of having lamb research in our service territory as well as much of the r d areas for intel and others it's not quite the same commodity semiconductor manufacturing that you see in other states we're very fortunate And as we look at the investments from the CHIPS Act and the support the state of Oregon is giving to this sector, we're fairly bullish.
spk09: Got it.
spk08: Excellent. And then just the cadence of developments, I mean, obviously you guys are quite constructive here on the setup on some of the renewable developments here. But in terms of the procurements themselves and data points from a near-term perspective to kind of give you affirmation on your specific ability to own some of these opportunities, Maybe that was in Jim's comments. Can you review that in brief here, just where we stand and what should be the expectation here on those data points here in the next few months?
spk07: Yeah, sure, Julian. So we're working towards the capacity or battery sets right now. We have been working towards that for a number of months now. I would say that, you know, given this challenging macro environment that we're in, It just takes, it is taking a little longer, but we're literally, you know, I'll call it a number of months away by the end of the first half of the year. So still have a lot of confidence there. That will still be a very substantial capital investment. Stay tuned for that. But as we get closer to announcing that, we'll also provide updates on how we're going to finance that as well. But I think that that's an opportunity that will be there. There may even be some generation opportunity in this first set, but even if it's not there, it'll roll into the next RFP, which will begin very soon after the mid-year point as well. So as we discussed in the past, we're going to be in an almost constant procurement cycle for the next four or five years as we get towards the end of the decade. to achieve the DCARB goals. So we've added a couple of slides here for you, slides 10 and 11 in particular, which show you the opportunity set that's there. These are numbers that are embedded in our working group and our clean energy plan that you're about to see. And we've also provided illustrative rate-based growth. And I made the point in the commentary that that the 8.5% CAGR does not include financing, so it's not a surrogate for Irving's Mall, but it just goes to show you the more capital investment needed here in addition to clear water that we have in front of us. So we're really optimistic, and this is really at a 25% ownership rate, so I think a lot of folks, including yourself, were asking for a bit of a a bit of an illustration on how we looked at that. I think this could be conservative.
spk09: Excellent. Well, thank you, Jim. We appreciate the time today, and we'll speak to you soon, all right? Sure.
spk19: Thank you. Thank you. Please stand by for our next question. Our next question comes from the line of Sophie Carr with KeyBank. Your line is open.
spk27: Hi, good morning. Thank you for taking my question.
spk28: I wanted to ask you about the slide 11 here in particular, which you just referenced. I think it's very helpful in terms of showing the what-if upside scenario. And so you guys outlined the potential for 8.5% CAGR for the rate base here with certain assumptions, but stopped short of translating that into a potential EPS CAGR upside, and I'm just curious how you think about potential like puts and takes here in this upside scenario in financing equity needs and how regulatory lag under various scenarios, how would that translate into the EPS CAGR, and when would we have some more clarity on that?
spk07: Yeah, Sophie, thanks for the question. I think we're going to be providing incremental clarity as we, when, actual projects, right? And so since we have two more procurement cycles plus the wrap-up of the current one, I don't want to be presumptuous about that and present an earnings model based on, you know, this growth rate. But you can assume a couple of things, I believe, which is fair. This is at a 25%, I'll call it handicapping of the total opportunity, you know, taking into account a generation that's owned by others you know, DER and other needs that are taken care of. It'll assume accretive projects. It'll assume that we finance that a 50-50 debt equity structure. And you could assume, too, that as we enter 2023, the balance sheet repair will be almost done, will be a long way into adding to the equity ratio. So it's a bit of a clean start for growth. In terms of the balance sheet, we've asked for a 50-50 ratio in this new rate case. So I'm not providing an earnings model against this. But if I were to look at this from that 8.5% illustration that we have, that's what we call illustration, not guidance. You'd have to assume 50% equity and 50% debt. But this at least gives you the numbers upon which to do that modeling.
spk28: All right. Thank you. And it's fair to say that you would go about issuing equity in a similar fashion as you are sort of gone about it so far? Maybe not.
spk07: Yeah, maybe not. I think given the nature of these projects, which are mostly billed on transfer, I think that'll continue. That means that we won't want to over-equitize the projects on day one. because they haven't been built yet. So what we'll do more than likely is use forward equity and private place bonds with also delayed draws. So both features, both markets have delayed draw opportunities so we can actually fund progress payments with equity and debt as we go. That'll be the best and most efficient structure to fund the projects. So we have no negative arbitrage, if you get my drift. Yeah. So I certainly like the at-the-market program as a technique as we go into this latter part of the year. So that's what I'm thinking right now.
spk28: Thank you. Thank you. My other question is a more, I guess, philosophical question. So pretty significant energy prices volatility and power in the gas that you guys have seen, as you highlighted. As you look at the build-out plans in the region, particularly for electric generation, would you say that the way the generation stack is poised to evolve here is likely to reduce or increase this volatility in the future?
spk20: That's a great question. And I think what we're going to see is a significant increase in distributed energy resources rooftop solar in particular, but also more locational-based battery storage, which will not necessarily help the seasonal changes, particularly those that could be caused by multi-year drought, but will certainly reduce the fluctuations on a 24-hour basis as we have solar periods versus wind periods versus hydro periods. And I think you'll see overall less volatility But we could see more longer-term seasonal issues, particularly with multi-year drought periods or multi-year high precipitation and high wind periods. You know, Sophia, as we look going forward, you're asking the million-dollar question that we're all trying to figure out. And what we take is sort of what I'd say is an all-or-none set of solutions. We're looking at every alternative because we move forward, particularly with the growth we have. We're going to need the diversity of all of those resources and the ability to respond and maintain reliability at the lowest cost for customers. The most expensive way to handle a transition would be to create a great shop for customers, and we need to be prudent here, particularly as we're seeing higher and higher reliability issues. I'd also say we're working much more closely across the entire West in terms of integrated markets, in terms of partnerships between high-tech companies, large and small, to regional and global hydro players. And we're, again, an all-above set of solutions.
spk26: Thank you. I appreciate the call.
spk19: Thank you. Thank you. Please stand by for our next question. Our next question comes from the line of Alex Mortimer with the Mizzou Hope Group. Your line is open. Morning, Alex.
spk11: Hi, thank you very much. Good morning. So we've seen high natural gas prices kind of across the Pacific Northwest, even as we've seen decreases in other areas from other hubs in the country. Is there any ability you have to diversify from your hub?
spk20: Yes, there is. And actually, one of the things that's really interesting is what happened this last December. Whenever things spike as they did, it's a confluence of multiple events. Clearly, you had very hot weather turning very cold quickly without the period that many of the storage facilities across the West were able to refill. You also had pretty dry December, so you had many hydro participants who had actually sold forward energy and needed to fulfill those contracts, putting unusual pressure on the market. And then you had, as Jim mentioned, super cold weather and usage that spiked. So I think as we look to going forward, how we create stronger hedging strategies, more diversity in resources, Additional partnerships, again, for more diversity is all part of our strategy as we move forward and will have an incremental benefit. The other is, as we looked at last year, we had forecast very strong industrial demand driven by semiconductor industry, cloud computing, and other digital capabilities. But it exceeded even our expectations. And so as we go into 2023, we've really re-racked the way we think about our customer load and different customer segments. And so that will give us – that's much more aligned to our hedging strategy throughout the entire year that is already in place. So, yes, we're doing more, and we already have done much of that.
spk11: Perfect thanks for that color and then just in terms of guidance both in 2023 and then kind of over the long term with the five to seven basically what gets you either to the higher low end both in the near and long term and then is there any bias with how things stand at the moment within that range?
spk07: I would say that there's no particular bias at this moment. we are leveraged to the RFP opportunities that we have. Really, those are where we're going to reach the upper limits of that guidance range. But I would say increasingly, even since last October when we first talked about increasing this guidance range, that we are more confident now that we could be comfortably inside that range with what's in front of us. I'll leave it more qualitative at the moment and just, you know, tell you that I think that our confidence level has actually increased in the last five or six months.
spk20: I also would add that we are really well poised to bring to Oregon and to our customers significant federal funding, whether it be for reliability and resiliency and let's say BRIC grants from FEMA, whether it be an infrastructure grants and partnerships with transportation organizations across the state of Oregon and the IIJA, whether it be in terms of clean energy through the IRA. We are focused in being successful in these areas. We've already started with a number of applications and are really working hard to make a difference as we go through a significant transition to reduce the otherwise customer price impact of a clean energy transition.
spk07: Yeah, and I think I would add two things to Maria's commentary. Number one is that, of course, given that the Treasury rules on the Inflation Reduction Act are not yet promulgated, we think there's upside. We're just not sure how to calculate that yet and where the market is going to monetize the credits. That's point number one. And point number two, I'm really pleased about how we've attacked the federal programs that are available. And, you know, Our concept papers and our grant applications are so far put against $945 million in total project opportunity. And we haven't had one concept paper rejected. And the way it works is you submit a concept paper. If your concept paper is accepted, you're invited to make a bid. We've had no rejections of the concept papers. concept paper rejects are at 50% right now. So all of our applications and concept papers so far are moving forward.
spk06: So I think that's a good sign.
spk11: Okay, thank you very much. And then just finally, we've seen headwinds obviously across the industry, whether it be natural gas, interest rates, inflations, et cetera. I was just hoping you could provide any sort of color on your assumptions on when some of these headwinds may abate going forward. just given the reaffirmation of the five to seven today.
spk20: Well, your guess is as good as ours. We are expecting to see continued inflation through 2023, hoping that it will moderate. But clearly, particularly when it comes to electrical equipment, in particular transformers and other capital investment, we are continuing to see steep demand robust prices, and working very hard to improve our processes, our systems, and our efficient deployment of all of that equipment to mitigate the impact of all of those external factors on our customer base.
spk07: I just can't guess, right? It's too hard, but we can just do what we've been doing, right? We've grown deliveries 10%, customer count five, kept our head count flat, And, you know, we've grown the rate base pretty significantly, right? So we're getting scale in the business.
spk06: So that's the continued focus that we have against a difficult macro environment.
spk02: Excellent. Thank you. I'll leave it there, and good luck with the year.
spk06: Thank you.
spk02: Thank you.
spk19: Thank you. Ladies and gentlemen, as a reminder to ask the question, please press star 11 on your telephone. Please stand by for our next question. Our next question comes from the line of Travis Miller with Morningstar. Your line is open.
spk14: Travis Miller Good morning. Thank you. Just on the 20 following up on that 2023 or rather 2021, the RFP projects to come. When you break out that 375 and then the remaining, are there technology differences that you're looking at in that 375 and then that remaining up to 200? Yes.
spk07: Yes, Travis, there are, right? So in addition to the wind and possibly more wind, solar, of course, there is an opportunity for substantial battery efficiency. sets in there. We're working on some right now, and that's what we hope to announce by the end of the first half. There is one pub storage project in the acknowledgement list that's there, and when we turn the crank on the next RFP in the middle of this year, I'll call it July 1 for or pointers, we'll see additional technologies. We're technology agnostic, right? It's all about pricing for the consumers, managing the load and the grid, and integrating them efficiently. So we expect to see more diversity as we go.
spk14: Okay. All those would be... I guess for lack of a better term, traditional renewable energy. We're not load management or anything like that, though, right? DER.
spk07: I think there's a lot of DER going on, but not necessarily as part of this procurement process. I also think that we will see additional players come in. So the dynamics could evolve, competitive dynamics could evolve here as this decade unfolds. So stay tuned for that, and we'll keep you updated.
spk14: Okay, perfect. And then one longer term, the range you provided out through 2030 at 2.2 to 3.1, What are the underlying assumptions? Aside, I'm thinking you probably have that same type load growth, but are there retirements in that assumption? Are there other load shaping assumption within that number? And what's embedded in that number or that range?
spk20: No, it's a great question, and there are a number of assumptions, and probably as we look forward, there is more variability than we've ever seen in our industry. We do not have any retirements included in any of those assumptions of any of our assets, with the exception of we are planning on getting out of our coal strip investment and not having that energy delivered to our customers here in Oregon. We also have, and this relates a little bit to your earlier question to Jim, we are fairly advanced when it comes to a virtual power plant. So, we are incorporating distributed energy resources, some of which we own, but many of which our customers own and will increasingly own in the future. We also have a number of load management programs, which help with some of our hedging. And we're also looking at the adoption rapidly in this area of electric vehicles. As you know, Oregon and our service territory is one of the top five leaders of EV penetration in the country. So there's a number of items that are impacting our load forecast and our asset growth forecast over time.
spk13: Okay, perfect. I appreciate it. Thank you.
spk19: Thank you. Please stand by for our next question. Our next question comes from the line of Nicholas Campanelli with Credit Suisse. Your line is open.
spk12: Morning. Hey, everybody. It's Nate. Oh, hi. It's Nathan Richardson on for Nick. Thank you for taking my question. I just wanted to ask, what's assumed for the PCAM in 23, if you haven't covered that already? Is it the baseline or is it still a headwind there?
spk20: Okay. As we look at our PTAM, we forecast basically at the annual update tariff, so there's no forecast. I do think that as you look at our power costs and you look at the entire region, it's important to note where we are with hydro conditions. Fifty-five percent of the energy generated across the Northwest is hydro-based, and we're roughly, and you can see it in the 10K and in our DISCLOSURES WERE ROUGHLY A LITTLE BIT OVER 80%. AND THAT'S LOW, BUT IT'S IN PARTICULAR LOW IN COMPARISON TO LAST YEAR, WHERE YOU SAW MID-C AND OTHERS AT 110%. AND SO WE HAVE FORECAST THOSE LOWER HYDRO LEVELS INTO OUR ENERGY PRICES FOR THIS COMING YEAR. AND I THINK THAT'S AN IMPORTANT, YOU KNOW, SORT OF CALIBRATION in terms of the risk balancing of 2023?
spk07: So one way to shorthand it is we enter the year flat based on the AUT, which is the baseline, if you want to call it that, of the PCAM. So obviously things change. We saw that last year.
spk06: But we essentially are reset at the beginning of January 1.
spk22: Great. Thank you very much.
spk09: Thank you. You're welcome.
spk19: Thank you. Our next question comes from the line of James Kennedy with Guggenheim Partners. One moment. Your line is open.
spk24: Hey, guys. Good morning.
spk15: I apologize if I missed this a little earlier, but the slippage of the 2021 items and the RFP process. What is actually driving that? Is it the bids that were rebid? Is it the deadline for the RFP itself? I guess just what would drive that schedule?
spk20: You know, it's just normal commercial negotiations in a time of extraordinary supply chain challenges. You know, we've had a number of Solar projects recently that have been laid as they have been laid across the country. And we want to make certain that as we are negotiating that all of these projects will be delivered as expected. And it's a challenging environment out there, but it's nothing unusual.
spk07: Yeah, it's a question of a few months, James, you know, the long arc of these projects. I'm not concerned at all. And also, batteries are unusual in the sense that they're modular, right? So we're always looking at the grid and what kind of storage and capacity is needed around the grid. And we're able to work with the vendors to size those projects appropriately based on the latest information we have. So as you go further in time, you have more information about the grid and you can actually design around that, but we're talking about very modest differences in timeframe.
spk15: Okay, perfect. And then just one kind of nuanced question. I really like slide 11, but I'm just curious, one of the footnotes, you assumed about 25% ownership of the midpoint. How did you kind of arrive at that number?
spk07: Yeah, so we stepped back and we wanted to provide this sort of illustration to help you understand what the opportunity is. We wanted to be somewhat conservative but also take into account what we saw happening in the rest of the market, you know, the PPAs, third-party agreements, community solar, DER, I mean, you name it, right? So we tried to have a holistic look at what we would need to do to make the DCARB goals possible. And so I think, you know, over time, I would say that we won a higher percentage and I'll let Maria add on to this because of her history here, in terms of utility scale generation. We've been much more successful on that. But this 25% is more a piece of the pie of the more holistic energy mix that we have.
spk20: You know, we've sometimes surprised ourselves with the number of self-builds or ownership opportunities we've had through RFPs. And I think it's because we take very seriously the need to be cost competitive and least cost, least risk. And we work very hard to make sure that our bids are set up, the customer price impacts first and foremost, as well as the overall functionality with the portfolio. So hopefully we will be as successful as we have been in the past, but it's highly competitive, which is important in terms of driving costs to their lowest levels. which is a challenge through a significant energy transition and something we need to always stay constantly vigilant on.
spk16: Cool. Makes sense. Thanks, guys.
spk19: Thank you. Thank you. I'm sure no further questions in the queue.
spk20: Thank you very much for joining us today. We appreciate your interest in Portland General, and we look forward to seeing you all soon. Well, I very much appreciate the robust questions. Thank you.
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