Portland General Electric Company (NYSE:POR) Q4 2022 Earnings Call Transcript

Portland General Electric Company (NYSE:POR) Q4 2022 Earnings Call Transcript February 16, 2023

Operator: 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 is being recorded. And as such, all lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there will be a question-and-answer period . For opening remarks, I would turn the conference call over to Portland General Electric’s Senior Director of Finance, Investor Relations and Risk Management, Jardon Jaramillo. Please go ahead, sir.

Jardon Jaramillo: Thank you, Towanda. Good morning, everyone. I’m happy you can join us today. Before we begin this morning, I would like to remind you that we’ve prepared a presentation to supplement our discussion, which we will be referencing throughout the call. The slides are available on our Web site 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 Web site.

Leading our discussion today are Maria Pope, President and CEO; and Jim Ajello, 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.

Maria Pope: Great, thank you, Jardon. Good morning. Thank you all for joining us today. Beginning with Slide 4, 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 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 MMBtu and average Mid-C power prices rose to $265 per megawatt hour, over 5 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 approved upon. While 2022 prices at the Mid-C 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, 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 industrial load growing at 10.6%. Offsetting this impact is a customer mix shift with a return to lower residential pre-COOVID 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. Excluding the impacts of increased wildfire mitigation expenses and deferral items, year over year, generation, transmission, 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 5. Our commitment to affordability remains steadfast and we’ll 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 reduced 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 purchased energy prices with the last 30% reflective of higher compliance costs and inflation as well as operating and financing costs.

In addition, we are 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 investment.

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-emitting dispatchable capacity RFP. We expect to procure 375 megawatts in need that was identified in the 2021 RFP. This includes PGE’s benchmark projects and 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 established 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 and 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.

Jim Ajello: 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 contacts 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 uses 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% whether 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. We 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 $0.73 per share in the fourth quarter of €˜21 to $0.56 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 debt band in the PCAM, creating a unique quarter-over-quarter cost comparison. Given this context, I’ll turn to Slide 6 and cover our financial performance year-over-year. We experienced a $0.40 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 $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, and $0.08 decrease due to higher purchase volumes to serve load in €˜22 and $0.02 decrease due to the change incurred as part of the 2021 PCAM referral settlement. There was a $0.06 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 $0.05 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 $0.05 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. There 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 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 GAAP EPS of $1.60 per diluted share. After adjusting for the $0.14 impact of the 2022 GRC earnings test deferral reduction, we reached our 2022 non-GAAP EPS of $2.74 per diluted share. Moving to Slide 7. As noted earlier, yesterday, we filed a 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 and 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 PCAM. The proposal provides a 90/10 sharing of power cost variances without a debt band 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. is a fair and balanced one and alliance 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 procedural schedule publication expected in the coming weeks. Onto 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 PEG’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 a 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 shortlist 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 could 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 31, 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 financings 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 agreements 24 month term.

Turning to Slide 13. We are initiating full year 2023 adjusted earnings guidance of $2.60 to $2.75 per diluted 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’ve remained 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 and revenue.

2022 O&M included significant efforts to streamline our , improved 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: 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; 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 inline 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, and accelerating how we serve customers in reaching scale in the business, all while keeping headcount flat. 2023 represents 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 as how — 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 $0.4525 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 maybe higher than historical ratios, but we expect this to be a temporary phenomenon. As we turn our undivided detention 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.

Q&A Session

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

Julien Dumoulin-Smith: I just wanted to come back to the extension here and the reaffirmation of 5% to 7%, kudos there. I just want to clarify this and really press a little bit. Obviously, €˜22, you’re ruling 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’ve been the baseline here to reset the actuals, would you still feel comfortable with the outlook in 5% to 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 €˜22 actual given where you came against the actual range with respect to the cascading implications on the 5% to 7%?

Jim Ajello: 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 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’ll be very comfortable inside 5% to 7% range. And so while it’s a hypothetical question and we’re not using the hypothetical to base the forward look, I’m still pretty comfortable and pretty confident in the 5% to 7% range, even if you did.

Maria Pope: So Julien, underlining the 5% to 7% long term is really our fundamental service territory growth that we’re seeing in terms customer usage of 2%. And we’re very fortunate to have a strong technology sector in our area. But we also have — to serve that we see growing need for renewable energy, both wind, solar, battery storage, longer term, even 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 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.

Julien Dumoulin-Smith: And actually, just since we’re talking about the 2% low 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 for the tech sector, et cetera, or is that reading too much into the outlook here?

Maria Pope: 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 turn down 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 Lam 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 CHIP Act and the support of the State of Oregon is giving to this sector we’re fairly bullsish.

Julien Dumoulin-Smith: 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?

Jim Ajello: 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 given this challenging macroenvironment that we’re in, it is taking a little longer. But we’re literally, 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 almost constant procurement cycle for the next four or five years as we get towards the end of the decade to achieve the decarb 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 we’re about to see. And we’ve also provided illustrative rate based growth, and I made the point in the commentary that the 85% CAGR does not include financing. So it’s not a surrogate for , but it just goes to show you the large capital investment needed here in addition to Clearwater 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 an illustration on how we looked at that. And I think this could be conservative.

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

Sophie Karp: 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 me what if upside scenario. And so you guys outlined potential for 8.5% CAGR for the rate base here with certain assumptions, but stopped short of translating that into potential EPS CAGR upside. And I’m just curious how you think about potential like puts and takes here in this upside scenario and 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?

Jim Ajello: I think we’re going to be providing incremental clarity as we win 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 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, taking into account a generation that’s owned by others, DER and other needs that are taken care of. It’ll assume accretive projects. It’ll assume that we financed at a 50/50 debt equity structure. And you could assume too that as we enter 2023, the balance sheet repair will be almost done. We’ll 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.

Sophie Karp: And it’s fair to say that you would go about issuing equity in a similar fashion as you were sort of gone about it so far? Can I resolutions?

Jim Ajello: Yes, maybe not. I think, given the nature of these projects, which are mostly build on transfer, I think that’ll continue. That means that we won’t want to overequitize 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. 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.

Sophie Karp: My other question is more, I guess, philosophical question. So pretty significant power price — energy prices volatility and power in the gas that you guys sustained, as you highlighted. As you look at the buildout plans in the region, particularly for electric generation, right? 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?

Maria Pope: 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. So as we look going forward, you’re asking the million dollar question that, that we’re all trying to figure out.

And what we take is sort of what I’d say is an all above 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 shock 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 — it’s again, an all above set of solutions.

Operator: Our next question comes from the line of Alex Mortimer with the Mizuho Group.

Alex Mortimer: So we’ve seen high natural gas prices kind of across 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?

Maria Pope: Yes, there is. And actually one of the things that’s really interesting is what happened this last December was sort of a — whatever things spike as they did is the 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 re 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 reracked 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.

Alex Mortimer: And then just in terms of guidance, both in 2023 and then kind of over the long term with the 5% to 7%. Basically what gets you either to the high or 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?

Jim Ajello: 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 tell you that I think that our confidence level has actually increased in the last five or six months.

Maria Pope: And I also would add that we are really well poised to bring to Oregon and to our customers significant federal funding, whether it’d be for reliability and resiliency and let’s say BRIC grants from FEMA, whether it’d be in infrastructure grants and partnerships with transportation organizations across the State of Oregon and the IIJA, whether it’d 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 customer price impact of a clean energy transition.

Jim Ajello: 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 one, I’m really pleased about how we’ve attacked the federal programs that are available. And 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 and if your concept paper is accepted you’re invited to make a bid. We’ve had no rejections on the concept papers. Concept paper rejects are at 50% right now, so all of our applications and concept papers so far are moving forward. So I think that’s a good sign.

Alex Mortimer: And then, just finally, we’ve seen headwinds obviously across the industry, whether it’d 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 5% to 7% today?

Maria Pope: 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.

Jim Ajello: 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 5%, kept our head count flat. And we’ve grown the rate base pretty significantly, right? So we’re getting scale in the business. So that’s the continued focus that we have against a difficult macro environment.

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

Travis Miller: 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?

Jim Ajello: 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 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 upstorage project in the acknowledgement list that’s there. And when we turn the crank on the next RFP and in the middle of this year, call it — I’ll call it, July 1 for 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.

Travis Miller: All those would be, I guess, for lack of a better term, traditional renewable energy. And we’re not load management or anything like that though, right?

Jim Ajello: 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.

Travis Miller: And then one longer term, the range you provided out through 2030 at 2.2 to 3.1. What are the underlying assumptions as item, 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?

Maria Pope: 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 Colstrip investments 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 were 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 of 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.

Operator: Our next question comes from the line of Nicholas Campanella with Credit Suisse.

Nathan Richardson: It’s Nathan Richardson on for Nick. 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?

Maria Pope: As we look at our PCAM, 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. 55% of the energy generated across the northwest is hydro based and we’re roughly, and you can see it in the 10-K in our disclosures, we’re roughly a little bit over 80%, and that’s the low, but it’s in particular a 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.

Jim Ajello: So one way to shorthand it is we entered 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. But we essentially are reset essentially are reset at the beginning of early January 1.

Operator: Our next question comes from the line of James Kennedy with Guggenheim Partners.

James Kennedy: 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 for

Maria Pope: You know, it’s just normal commercial negotiations in a time of extraordinary supply chain challenges. 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.

Jim Ajello: Yes. It’s a question of a few months, James 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.

James Kennedy: And then just one kind of nuance question. I really like Slide 11, but I’m just curious, one of the footnotes, you assumed about 25% ownership of the midpoint. I guess just how did you kind of arrive at that number?

Jim Ajello: So we stepped back, and we wanted to provide this sort of illustration to help you understand what the opportunity is. Just wanted to be somewhat conservative. But also take into account what we saw happening in the rest of the market, the PPAs, third party agreements, community solar, DER, I mean, you name it. So we tried to have a holistic look at what we would need to do to make the decarb goals possible. And so I think, over time, I would say that we won a higher percentage, and I’ll let Maria add onto 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.

Maria Pope: We’ve sometimes surprised ourselves with the number of sales 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 leased risk. And we work very hard to make sure that our bids are set up where 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.

Operator: I’m showing no further questions in the queue. I’d now like to turn the call back to Maria Pope for closing remarks.

Maria Pope: Thank you very much for joining us today. We appreciate your interest in Portland General and we look forward to seeing you all soon. We very much appreciate the robust questions. Thank you.

Operator: today’s conference call. Thank you for your participation and you may now disconnect.