Portland General Electric Co
NYSE:POR
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Portland General Electric Co
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Good day, and thank you for standing by. Welcome to Portland General Electric Company's Third Quarter 2022 Earnings Results Conference Call. Today is Tuesday, October 25, 2022. 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 session. [Operator instructions]
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.
Thank you, Dillon. 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 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 Ajello, Senior Vice President of Finance, CFO, Treasurer and CCO. Following their prepared remarks, we will open the line for your questions.
Now, it is my pleasure to turn the call over to Maria.
Thank you, Jardon. Good morning, everyone, and thank you for joining us today. Beginning with slide four, I'll start by discussing our third quarter results before moving on to long-term growth. This morning, we've reported GAAP net income of $58 million or $0.65 per share, compared with $50 million or $0.56 per share in the third quarter of last year. Our solid results this quarter were driven by strong operating performance and revenue growth.
First, load growth, which came primarily from technology and digital customer’s continues to be robust. Industrial load was up 10% this quarter versus the same period a year ago. Given The CHIPS and Science Act, as well as the focus on semiconductor investments in the State of Oregon, we anticipate several significant semiconductor expansions in our service territory. We're also continuing to see steady business growth in other sectors, as well as continued residential immigration. Overall, we're moving our load growth expectations to 2%, up from 1.5% over the next five years.
From an operating perspective, we are pleased to see that the hard work we're doing across the companies to reduce operating expenses is having an impact. Overall O&M expenses were largely flat with last year's third quarter as savings in several areas offset wildfire mitigation and grid resilience costs.
Third quarter power markets were remarkably volatile as many states in the West set all-time temperature records. In Oregon, at least 12 cities, including Portland so the hottest July and hottest temperatures on record. 2022 also ranked as the warmest August on record in Washington and Idaho and California, so hot temperatures, as well as record drought conditions.
Our generation plants could not have performed better and we're well integrated with power operations contracted and purchased energy supply. Overall, purchased power and fuel expenses increased due to market conditions and to meet significantly higher energy usage. We are pleased to share that we have resolved a number of open deferral dockets, which have been ongoing for many months.
And now provide greater certainty. Overall, we have achieved settlements totaling $130 million, including the 2020 wildfire, the 2021 ice storm, the 2021 power cost adjustment mechanism dockets. These agreements are subject to final approval by the OPSC was an order expected in November. We also anticipate filing an amortization request for the $34 million COVID deferral later this year or in early 2023. Jim will walk through the expected financial impacts of these updates in more detail, but I like to add my appreciation to our PGE leaders and to all other parties for the constructive spirit they brought to these discussions.
Moving to slide five, after a robust and highly competitive process, identifying options that increased renewable energy at the best combination of price and risk for customers. We announced the Clearwater Wind project, one of our benchmark generation bids. Clearwater, Clearwater is part of a broader wind development in Eastern Montana that will generate approximately 311 megawatts of nameplate capacity.
We signed to build to transfer agreement with NextEra Energy Resources for Portland General two-thirds or 208-megawatt ownership share. PGE will secure the remaining third or a 103 megawatts under a 30-year PPA. This is a significant -- excuse me, this is significant step forward in our clean energy transition. As the renewable energy generated at Clearwater complements our long-term plan to remove the remaining coal generation from our portfolio.
PGE's capital investments in Clearwater is projected to be $415 million and the facility is planned to come online by the end of 2023. The Clearwater investment opportunity will have an impact on the capital needed to fuel our growth and rebalance our capital structure, which Jim will touch on shortly.
PGE has been on the forefront of the energy transition for years. We could not be more excited about the great opportunities that we see ahead. In the spring of 2023, we expect to file both our clean energy plan and our next Integrated Resource Plan. These plans will incorporate enhanced analysis and actions to meet evolving energy needs with a focus on reliability and affordability. In the second half of 2023, we expect to launch additional RFPs and not for renewable generation and non-emitting capacity.
Now, let me turn to operating performance and risk management. As I mentioned earlier, this is a very tough summer as we navigated record heat and heightened risk of wildfires. We're focused on making strategic investments and much of the work we're doing to enhance resiliency in the summer also helps us prepare for winter storms. This includes proactively replacing aging equipment, reducing outages, accommodating growth and better integrating renewable resources. We're also making use of the latest technologies.
At our integrated operation center, we're using analytics to better track planned performance and predict potential issues before they arise. We're using advanced modeling and improved tools to better monitor dynamic weather through AI and data analytics, we are proactively addressing issues in the distribution system, reducing costs and increasing reliability.
In short, we're advancing the digitalization and simplification work that we have scaled over the last couple of years. This quarter, for example, we have focused our work on improvements to our field crew scheduling systems that will in productivity and workflow for our line crews. We're also upgrading our digital platforms for more seamless customer service and interaction. Given the current environment, one area of particular concern is power cost management and challenging wholesale markets especially during critical peak periods. This quarter, we experienced significant volatility driven by intense summer heat.
Western power market conditions are very challenging with their head peak prices of $1,000 per megawatt hour on multiple occasions. Our risk management strategies and strong balance sheet were critical as we navigated these headwinds. Our vertically integrated utility model and 16-generation facilities helped insulate customers from the full impact of the volatility that we saw in the energy markets.
In the current environment, we are frequently generating power to serve our customers at significantly lower energy costs that can be purchased in the open market. I want to recognize the outstanding work of our generation leaders and plant operations. We know that our customers ranging for some of the largest global companies to our neighbors down the block are facing significant financial pressures.
As we look ahead, we're intently focused on making full use of the tools available to us to help manage power costs. We're committed to providing our customers with the ability to take an active role in enabling the clean, the regions clean energy future. Again this year, Portland General's Clean Future program was recognized as the number one green energy program in the country by the National Renewable Energy Lab or NREL.
Before I turn the call over to Jim, I'd like to discuss our financials. And I'd like to touch on the coming quarter and our growth outlook. In the fourth quarter, we expect continued load growth, power cost performance and disciplined O&M management to keep us on track to meet our guidance for the year.
Looking ahead, the progress we've made this year has laid the foundation for substantial investments in 2023 that will position us for significant growth in 2024 and beyond. As such, we're raising our long-term EPS growth guidance for 4% to 6% to 5% to 7%, reflecting investment opportunities ahead.
In sum, we're pleased with our strong performance this quarter demonstrating that providing safe, reliable, affordable and clean energy is the right formula for steady and consistent results.
With that, I'll turn it over to Jim.
Thank you, Maria, and good morning everyone. I'll cover our third quarter results before providing additional details on our outlook.
Moving to slide five, our third quarter results reflect the execution of our long-term strategy, continued growth and demand and effective risk management in volatile power markets. Our regional economy remains solid, as unemployment in our service territory improved to 3.2% relative to 4.3% in 2021, it has remained stable throughout 2022, industrial development and customer growth continue to drive strong demand.
Overall, Q3 2022 loads increased by 1.2% weather-adjusted, compared to Q3 2021. On a non-weather-adjusted basis, total load increased 4.2% year-over-year as average temperatures for the third quarter, the warmest on record in our region. Residential load increased by 3.6% year-over-year, but decreased 2.5% weather-adjusted as we continue to see moderation in COVID-19-related usage trends. Residential customer count increased 1.1%, compared to Q3 2021.
Commercial load increased 0.5% year over year but decreased 1.3% weather-adjusted, as the commercial segment continues its post-pandemic recovery. Steady growth among high-tech and digital services sectors continued in Q3 driving higher industrial loads which grew over 10% year-over-year, or 9.2% weather-adjusted. These high temperatures increased deliveries but they also created challenging power market conditions throughout the West. Our power costs exhibited significant volatility, we managed operational and market risk effectively as the region continues to address resource challenges. We remain acutely focused on managing energy price risks and optimizing operations to limit the customer price impacts of these cost pressures.
I'll now cover our financial performance quarter-over-quarter. We experienced a $0.22 increase in total revenues driven by the 4.2% increase in deliveries led by growing demand from our high-tech industrial customers, while load was up 4.2% quarter-over-quarter. Industrial load growth outweighed residential and commercial load with the change in customer price competition, creating a $0.04 decrease in total revenues, compared to 2021.
In Q3 2021, power costs were high and $0.21 of the quarter-over-quarter earnings change is attributed to headwinds in ‘21 that we normalize for this comparison. As a reminder, Q3 2021 saw conditions that pushed power cost above the $30 million power cost adjustment mechanism upper threshold, resulting in a deferral, which I will discuss again shortly.
This quarter, higher market prices due to resource scarcity in peak periods drove a $0.25 decrease. These impacts were largely related to the impact of serving load during the region's demand peaks in a historically hot summer. Higher purchase volumes to serve load drove a $0.07 decrease, a $0.01 increase to EPS was due to lower operating expenses net of storm, restoration and regulatory program costs that are offset in revenue, primarily because of the lower professional services costs. We saw a $0.01 impact from depreciation and amortization expense due to increased intangible asset balances compared to 2021, reflecting our continued investment in software and technology to increase efficiency across the organization.
Lastly, we had a net $0.02 increase reflecting offsetting impacts from a few items, it was a $0.09 increase to other income due to a settlement gain from a buyout of a portion of PGE's post-retirement medical plan, which was partially offset by a $0.03 decrease from the impact of higher interest expense from the Q3 2021 debt issuance of $400 million and a $0.03 decrease due to higher income taxes and $0.01 decrease due to other miscellaneous items.
Turning to slide seven. As Maria mentioned yesterday, PGE and parties submitted a stipulation to the OPUC reflecting an agreement that resolves all matters relating to 2021, under the 2020 Labor Day Wildfire and 2021 February Ice Storm deferrals. This agreement will allow PGE full recovery of the deferred amounts related to 2021 of $30 million and $72 million respectively with amortization over seven years.
PGE and parties also submitted a stipulation to the OPUC, reflecting an agreement that resolves all matters relating to the 2021 PCAM deferral, and -- which would allow PGE recovery of deferred costs of $28 million with amortization over two years beginning January 1, 2023. Combined, these stipulations resolved $130 million of outstanding major deferrals, all stipulations are subject to OPUC approval. We plan to file an amortization request for the COVID-19 deferral, which has a $34 million balance as of September 30, 2022, later this year or early in 2023.
On slide eight, Maria highlighted earlier, we are very pleased to have clarity on a portion of the ongoing RFP with our execution of the Clearwater Wind project contracts with NextEra Energy Resources. Clearwater, our first project to be announced represents a critical step in our clean energy roadmap and provides high-quality renewable generation investment opportunities that will benefit customers and stakeholders as we move toward our 2030 decarbonization target.
This project will be executed using a build transfer approach which will allow us some flexibility when considering the timing and approach to future financing. We are continuing to negotiate with other RFP shareholders bidders for both additional renewable generation projects and non-emitting dispatchable capacity resources. We are optimistic that we will conclude these negotiations by the end of 2022 or early in 2023.
We are continuing to assess the debt and equity needs related to the Clearwater project and other potential RFP project investments, as well as long-term equity needs to rebalance our capital structure for regulatory purposes and maintain our strong credit ratings. Strong balance sheet creates important benefits for both shareholders and customers. We will look forward to finance this growth consistent to and leading up to our capital structure of 50-50 over time and on average.
Turning to slide nine, which shows our updated capital forecast through 2027, we have increased the 2023 forecast by $550 million to reflect the renewable generation investment presented by Clearwater, as well as incremental base CapEx. We have also increased capital forecast for 2024 through 2026 by $75 million, $100 million and $125 million respectively. And are providing a 2027 capital forecast of $800 million. This forecast represents planned investments for technology and software, system resiliency, transportation electrification and grid optimization. Figures for ‘23 through ‘27 do not include any potential expenditures related to possible ownership from the remainder of the current RFP or future RFP cycles.
Turning to slide 10, we continue to maintain a solid balance sheet including strong liquidity and investment grade ratings accompanied by a stable credit outlook. Total availability of liquidity at September 30 is $797 million. We plan to fund investments with cash from operations and the issuance of up to $460 million of long-term debt in the fourth quarter, a portion of which has already closed. We expect to issue this debt under our Green Financing Framework as we continue to seek out opportunities to tie our debt financings to our sustainability strategy through capital investments.
The third quarter reflected the strength of our region, our ability to navigate difficult power cost conditions, and our continued emphasis on controlling O&M expenses. The continued growth trajectory of our service territory is strong and we remain focused on controlling costs and prioritizing spend on the highest return activities like technology deployments that drive efficiency.
We are reaffirming our full-year GAAP earnings guidance of $2.60 and $2.75 per diluted share or $2.74 to $2.89 per diluted share on a non-GAAP adjusted basis. Additionally, we are also increasing long-term load growth guidance from 1.5% to 2%. As Maria described, this increase is enabled by continued growth in high-tech industrial sectors in residential electrification patterns.
Given the renewable investment opportunities presented by Clearwater as well as strong prospect of additional RFP opportunities yet to be awarded clarity on major deferral dockets and anticipated load growth, we are raising our long-term earnings guidance from 46% of 2019 base year to 5% to 7% from a 2022 adjusted earnings this year. We're very excited about the growth prospects supported by both renewable development, as well as resiliency investments.
We are confident the catalyst discussed today, a clear path forward as we strengthen our core mission of providing clean, reliable and affordable energy for all enabling consistent execution of our long-term financial goals and provide value for our customers, our community and our shareholders.
And now operator, we're ready for questions.
Thank you, sir. [Operator Instructions] And I show our first question comes from the line of Insoo Kim from Goldman Sachs. Please proceed with your question.
Hey, thank you. First question, thanks for the updates on the 5% to 7% EPS growth off of that adjusted ‘22 guidance space. Should we assume that by ‘24, you should be in that 6% mid-point range or is it more and beyond that in ‘25 or another time period?
Hi, Insoo, it's Jim. Good morning. I will tell you that this is a long-term earnings guidance projection. 2023 represents a significant year of investment as you saw the CapEx rise to about $1.1 billion or more. And of course, we're not done with the RFP yet. So it's really hard to be precise with an answer on that, so I do think ‘23 however is a year of investment. And as you know, in this business, you invest that way in order to seek a longer-term growth profile. So that's probably where I believe the answer right now.
Okay. And I guess associated with that, given at least that Clearwater is expected to come online in the year-end 2023, are you expecting from a rate case perspective to try to time, the conclusion or the rate inclusion of that by early 2024?
Well, let me correct perhaps an assumption in your question. So, yes. Clearwater is planned to be in service by the end of ‘23. There is no rate case required to bring Clearwater into rates. We'll use the Renewable adjustment clause. So upon in service that project will go into rates absent any rate case requirement.
That's right. That makes sense. And then just one more if I could. On the OPUC prudency review for the Clearwater wind, what's the timing on that? And is that like a separate docket that needs to be created? Just some clarity there.
Thank you, Insoo. Yes, there is the prudency review that takes place in normal course after the project has been brought online. But we are able to proceed with the automatic adjustment clause mechanism and move the wind energy and the asset into customer prices.
Okay, got it. That's after -- okay. So this -- you don't have to wait for any approval before proceeding with the CapEx?
No.
Got it. Thank you so much.
Do you might remember, we've gone through a fairly rigorous RFP process and also have had bids refreshed all of which has been reviewed by different stakeholders, by the commission and no question that in Oregon we have extensive process.
Makes sense. Thank you.
Thank you. And I show our next question comes from the line of Shahriar Pourreza from Guggenheim Partners. Please go ahead.
Hey, good morning, guys.
Good morning.
I guess, a couple of things to unpack here. First, how should we think about I guess the prospects for what you could own with the balance of the current RFPs you, kind of, laid out in slide eight? Could we see more wind procured or is it leaning towards solar which you wouldn't necessarily own? I guess net-net, you got $415 million so far. So are you still thinking an incremental $600 million to get us to the $1 billion ownership as previously discussed? And I guess how does Company's storage fit into that? Thanks.
So, first of all, the processes are still in process. And we wouldn't want to front-run any conclusion as we continue with negotiations with multiple parties and work with an independent evaluator. So it's just too early to tell, but there clearly are more opportunities and we also are filing our next IRP along with the new clean energy plan that the State of Oregon put in place a couple of years ago that I think will make a difference as we move forward through the decade.
Got it. I guess maybe just another way to ask that is to hit the 5% to 7%, I guess what do you need an incremental above what you just raised today from a capital standpoint?
So as we look at the best available projects for both these risks and lease cost, we're mindful of the deliverability of the energy. Clearly, we're looking at some storage projects that will help with capacity, but there's a lot of complexity in some of the bids so I just think it's too early to tell.
Okay, got it. And then just on the timing and disclosures around sort of the equity, I mean, kind of, with this process, potentially not being finalized till the first quarter, but Jim says early first quarter of ‘23. Does this kind of mean you won't be able to update us at maybe EI, as far financing this plan, as well as maybe the health equity portion of it?
Yes, sure. That's a very good question. We're working on that now. We may or may not be able to update you regarding that, it just depends on how we look at the markets how we see the opportunity to raise capital both debt and equity. I wouldn't want to speculate on the timing of any financing right now. So I'm not sure we'll be able to pin that timing down, I would say stay tuned.
Got it. And then, Jim, just last one for me, just we're sort of thinking about some of the moving pieces for 2023. You have some natural drag from Faraday and other items. Any updated thoughts on how should we be thinking about other line items like O&M and what they could look like relative to ‘22 especially if you're dealing with potentially equity dilution?
I guess, should we assume ‘23 in particular won't be quite linear as we're thinking about the updated 5% to 7% or do you think you've got enough assets in the plan to sort of offset some of those items to maintain within that range even if we're thinking about it from a year-over-year perspective? Thanks.
Yes, it's a very good and popular question right now. Yes, I would say to you, hold tight until February when we give that ‘23 guidance. I mean, by the time that will also round we should have a better perspective on those further RFP activities, how we're going to finance all of that. And just what the opportunity is for the investment. So other than all of the guidance that we gave today around the long-term load growth, the deferrals you have -- robust new CapEx schedule, so we're trying to -- here into 2023 without providing specific EPS guidance there. I think you've identified some of the clear headwinds that we've got and -- but we'll be back to you in February on the call with respect to the actual ‘23 EPS guidance.
Okay, got it. We'll see you guys in a couple of weeks. Thanks.
Thanks, Shah.
Thank you. And I show our next question comes from the line of Angelica [indiscernible] from Bank of America. Please go ahead.
Hey, it's actually Julien. Hey, good morning. Thanks for the time and the opportunity.
Thanks, Julien.
Hi. And congrats again on the rise here. So I wanted to follow-up on Shahriar's question. First off, how do you think just about ‘24 here, I know that ‘23 might have some moving pieces as you say, large spend, equity, et cetera. But ‘24 I mean, I know you launched and raised this 5% to 7% here off of ‘22 base very specifically. Are you there and confident in being within that range for ‘24 here as you kick off on this?
Julien, as we look at our guidance, it's really first and foremost, based upon our customers' energy usage that we're seeing. The infrastructure that we have built and they have built. And so continued growth from that aspect, as I think you know we have a number of high-tech companies particularly semiconductor manufacturers in our service territory and they have been growing and will continue to probably accelerate that growth over the next couple of years.
Clearwater is clearly a great addition as we make the energy transition and add more renewables, but we also would expect to see more battery storage, more demand response. We see the transition really accelerating along clean energy and that's what makes us feel very confident in the 5% to 7% longer-term growth trajectory.
Yes, I've been asked this [Technical Difficulty]. If I may just -- speaking over the longer term, I mean, I think you all put out a target by the end of the decade of 3 gigawatts to 4 gigawatts of procurement with a gigawatt of non-emitting capacity as well. I mean, that would imply a pretty hefty pace of procurement here through the back half of the decade in tandem with this 5% to 7%. Can you talk a bit more specifically about your expectations on the cadence of these RFPs and prospects for your ownership? Again, and basically, if you can, how does that reconcile within the 5% to 7%, I mean what kind of assumptions are you making about those future RFPs as it pertains to the 5% to 7% itself?
So there's a lot of questions in there, Julien. I think the first and foremost is our long-term procurement of renewable energy and then obviously the capacity that's going to need to be associated with that to keep the system reliable. As I mentioned, this -- later this winter early spring, we will be filing the clean energy plan, which was the result of legislation that went in place just a little while ago in Oregon really targeting for us an 80% reduction in our emissions off of 2010, 2012 time period.
And so we have quite a bit to -- need to procure that will also be associated with our integrated resource plan, which we have used as a planning tool for decades and as well as many of the other kinds of planning that we're doing around the grid and distributed energy resources, as well as electric transportation and others that we're working to combine all of these. I think it would be too soon to tell handicap which would be company owned or which would be third-party owned, this most likely going to be a mix. And I think you'll also see needed transmission built within our service territory but also adjacent to our service territory across the West.
It clearly is a period of time of investments and we're also mindful of our customer prices. It's really important that is, our load growth continues that we're able to take those fixed costs investments and spread them over a growing customer base because affordability in Oregon is extremely important not just to our residential customers and just small businesses, but to many of those larger multinational companies that are challenged today. So we're balancing all of those things as we move forward. And again, feel confident in the 5% to 7% growth.
Yes, okay. So the bottom line it's not pedicure and that’s still any outcome on the RFPs itself customer growth?
Let's give you confidence of that number.
So Julien, let me just -- right, let me just add to that. If you run a classified rate-based model based on the CapEx that we presented today without any other RFPs, so I think you'll come to the same conclusion.
Got it, excellent. Thank you, guys, to clarifying that. And one quick clarification just on the medical buyout here. Can you just clarify, was that assumed in guidance for the year? I know that there are constantly moving pieces here but --
Yes it was, Julien.
Okay. Excellent, guys. I'll leave it there. Congrats again. Cheers.
Thank you.
Thank you. And I show our next question comes from the line of Sophie Karp from KeyBanc. Please go ahead.
Hi, good morning, and thank you for taking my question. And congratulations on the season raise and the long-term guidance refresh. I wanted to ask you about the O&M, it's a bunch of moving pieces in the O&M, our guidance revised for the year. Could you maybe help us crystallize, how much of the change relates to the inflationary pressures that you may be seeing and what do you see -- how do you see the development into 2023?
Yes. Thanks, Sophie. Thanks. Thanks for the question. So, yes, so inflation has been a thorn in our side really all companies in this space and we're doing our best to fight against it. But let me just level-set on O&M, let's take the top of the range at $660 million, which you see here in the form of -- the way I look at the $660 million is -- I eliminate the storm deferral amounts which are coming back in revenue. So that's -- it's about $10 million or $11 million. And then you've got the disallowance that came in the first quarter. So altogether that's about $27 million, so the way I level our O&M now is, I did do use it to about $633 million, right.
So once you start with that sort of baseline, I think, it's fair to say, you start thinking about all the factors that are impacting O&M and it's clear O&M in the form of wages outside salaries services that we purchase of all increased dramatically in the last year or so. So what's that factor? I'm not exactly sure, but we are certainly doing everything we can to offset that. And I think, in the third quarter, if you dig into the numbers with us, you'll find that there has been a moderation here that we're starting to see an improvement over the strategies that we've got plus using technology to be more efficient. So we're not just looking at this as -- how much can we cut in the way of costs. It's about making sure we get more done, but the same dollar making sure more efficient optimizing CapEx that will improve O&M and the like. Those kinds of strategies.
Thank you. This is very helpful. Another question I had is on the, I guess the benefits of the IRA rates and the new tax credits outlined there, et cetera. Should we think about the price tag on Clearwater as the final number that already contemplates all possible benefits that you can get for that type of project or would not -- would that number, kind of, move around as you did for the treasury guidance and can -- potential benefits from the bill in the same, I guess for other projects, how incorporated our -- is the new fiscal regime into your RFPs at this point?
Sophie, thank you. So with regards to more specifically Clearwater, there will be [Technical Difficulty] tax credits associated with that facility, which will reduce the overall impact in the customer prices and we would expect to use those in the normal course. With regards to the overall IRA, IIJA and other federal funding, we currently have a couple of projects from the Department of Energy rather distributed energy test beds, the Oregon Department of Energy around their smart grid same project that we have in our service territory.
And we would expect to have significantly more in the future. Clearly, it's important as we look at some of the above market costs of newer technologies to bring in those kinds of funds and we hope to be well-positioned to do that both for reliability and resiliency projects, but also as we continue to invest in the clean energy transition.
I guess maybe -- I don't think that's contemplated this yet. But is there a way through tax equity arrangements to reduce the upfront capital need? Not necessarily, I guess surprised, but the need for equity maybe or is that something that is not doable within the regulated contract?
Certainly. So first of all, many of the rules have still not yet been written with regards to the inflation reduction after IRA. So we'll need to see how those are. And we'll also need to see if you're talking about monetizing any of those credits, what the market looks like at that time. But certainly, funds from the federal government or from the federal government that moved through state agencies here in Oregon would reduce our overall need for equity or debt financing as we move forward and it's going to be an important component to our clean energy plants.
Sophie, without belaboring the point, I would say that, recall that when the bids came in initially in the summer-time, we asked for a refresh and that's because there were, I'd say pretty significant inflationary pressures around all these RFP projects, but we also asked bidders to make sure that they included their best estimates for the benefit of the IRA for our customers, because that's where these benefit goes at the end of the day.
And so I think we have some benefit in projects like Clearwater, but clearly this redundant term, I don't think we're all the way there yet, it's early on and we'll do the same for the other IFP -- RFP projects as we go. And what's really great about the IRA for a company like this without a holding company, without an affiliate of all these projects that we are competitively awarded in a very simple structure -- ownership structure and we'll be able to normalize or opt-out of that tax normalization structure and monetize tax credits.
So I think this is a significant opportunity for us. If you will, probably in the next round of projects as the IRA gets more defined and as the market for tax credits gets modified, it's just not there yet, frankly.
Got it. Super helpful. Thank you. That's all from me.
Sure.
Thank you. [Operator Instructions] And our next question comes from the line of Anthony Crowdell from Mizuho Group. Please go ahead.
Good morning, Maria. Good morning, Jim.
Good morning.
Maria, if I could just start off, I wanted to just follow-up on, I think to Julien's question, I know there were many maybe with this first one, it was related to I think ‘24 year earnings CAGR your update. But I actually want to go from the start. Is it fair to assume that we should be using the midpoint of the revised ‘22 guidance of like $281 million as our anchor of growing the 5% to 7%?
Yes.
Great. Thank you. And then just as I move from there, I think that -- and I hope I got these numbers wrong. I think the company was seeing lagged roughly maybe 50 basis points to 70 basis points. You've updated your load forecast at 2%, does that change the regulatory lag that the company has experienced?
Sure. So first of all, our lag is a little bit larger than that just under 1%. And continually, we work to reduce that lag over time. Certainly, the footprint of the company helps with reducing that as we get larger, those items, and hopefully, they get smaller or don't change become a smaller part of the total on a percentage basis, but it's our goal to continue to strengthen that.
I appologize. What is delayed -- maybe I don’t know, 70 basis points to 90 basis points or what is the appropriate --
Sure. It's a little closer to 90 basis points right now.
Okay. And just lastly, I guess, Faraday comes in some cost pressures and I apologize if you answered this earlier. Just what is your assumption for rate case timing in your long-term growth rate? I think the company historically is filed in February, make your filing the February for new rates the following January, just what is baked into your assumption of the long-term plan.
Sure. So, as you may recall, our last rate case was filed after about 2.5 years, we were in the middle of COVID and we were very concerned with regards to customer prices and we kept our increases very modest through that period of time. And actually it was, just this last May that customer prices were increased to reflect that rate case. So as we move forward, we will take a look at where we are. And in particular, some of the additional costs that we're seeing come onto the system both for resiliency and grid hardening and most importantly for Wildfire costs. So we're going to be looking at all of these things as we analyze what we do next.
And Anthony, I'll add to that. I would not assume any changes in the annual utility tariff filing, the fuel tariff filing that we have here. So I think that's something that's fixed by our concept.
Great. Thanks so much for taking my questions and congratulations.
Thank you.
Thank you.
Thank you. And I show our next question comes from the line of Aditya Gandhi from Wolfe Research. Please go ahead.
Good morning, Maria and Jim.
Good morning.
Good morning.
So just on the rate case, could you please clarify, when you go in for rate case and as it relates to your equity ratio, just given the forward test year, would you essentially -- again this is assuming that you do an equity forward and you have to draw on it. Would you have to draw on your forward sort of before you file or at the time you file or just given your forward test year, can you sort of file later in the year? Could you please clarify that?
Sure. So just for perspective in background, we target over the long term and sort of on average about a 50-50 capital structure. And just also for perspective, Jim mentioned it earlier, but we have no holding Company debt or anything else, a very simple structure. And we -- our last rate case -- we were below that 50-50 and we filed went through the entire a nine, 10 month process and ended up with a 50-50 capital structure.
So I think we have a good understanding with parties as well as with the commission that we target 50% on average over time. So that -- how that would impact the rate case or not, I just think it's one factor amongst that as we take a look at what we might follow next rate case.
Got it. That's helpful. And then just going to your 5% to 7% growth rate, so you have a higher capital plan and you're pointing to more sales growth in the RTOs. But you have some equity nature base business, which is at present under equitized and also some equity needs related to your RFP, and then you've also pointed to a higher capital plan. So maybe there's some equity needs related to that increased CapEx maybe not, but just because we don't have sort of like a full picture of what your financing refresh looks like, how should we think about the shape of your 5% to 7% especially sort of beyond 2023?
Yes, Aditya, I'll take that one. So I do think the CapEx guidance that we disclosed today is as best as we could see it right now. We're not even finished with the current RFP cycle. And as I've said, we are hopeful that by the end of the year or into the first quarter, we'll see more results that are beneficial. So I'll not revise upwards the guidance that we just gave you. But I would say to you that there is opportunity in that CapEx plan as well. So it's a little hard, therefore to size whether that capital plan will be, we know and we've discussed many times the need to return over time.
And on average, as Maria just said, literally the cap structure for the Company per regulation and I would assume also that once that is, if you will, taking care of what you'll see us incremental capital investments like Clearwater out of the box funded on a 50-50 basis in order to maintain the overall. So we'll size this and be ready for the opportunity as it comes. I'll just tell you that these markets are extremely volatile and difficult to project given the hawkish nature of the Fed and the way the equity markets are performing. So it's a question that we -- your question is one we wrestle with all the time.
Okay. That's helpful. Just one more if I can squeeze out and so. As far as your deferrals are concerned, I noticed that for the PCAM before didn't get the full amount. Please correct me if I'm wrong, but do you essentially have to take a charge to earnings for the $2 million that you won't be able to recover for PCAM? And if so when would that charge be? Thank you.
So there is a -- what you've obviously noticed on page seven, you see the delta between the ‘21 balance at the end of this quarter and the $28 million recovery, right. So that would be in the fourth quarter that $2 million.
Got it. Okay, that's helpful. Thanks, Maria. Thanks, Jim.
Sure.
Thank you.
Thank you. And I show our next question comes from the line of Nicholas Campanella from Credit Suisse. Your question please.
Hey, good morning. Thanks for getting me in here.
Hi, Nick.
I'll just try to ask and like -- are you get some more direct way like, do you need to wait for the RFP results before sizing your total equity needs here? Or just how should we kind of think about that, because I know there's a lot of moving pieces.
Yes, thank you for understanding that. That's really what I was trying to get across to in detail there in a moment ago. I don't think it's necessary to wait. Absolutely, we could -- we can track where we are in the pace of negotiations and try to figure it out and consider market conditions. So it's not necessarily the case that I have to wait. But I'd have to be pretty confident, right, because I don't want to over-equitize and dilute more than we have to. We want to size the financing both debt and equity against our capital needs, right. So I don't want to get out over our skis and create dilution that's not necessary.
Okay. No that’s helpful, Jim. And then, last quarter you kind of talked about being at 46% versus the 50% authorized. Could you just give us a quick update there and understand the comments as well that this is an overtime situation, but is 200 basis points improvement or the right way to think about it still? Thanks.
Yes. Now that I hear people repeating what we say, I think we're in the right ballpark now. So, I think by the end of the year, I estimate that we'll be approximately 46% plus. And the notion of making it happen over time suggests to me that -- and I look back at the history, we've operated in many cases at 48% plus 49%. We've also operated at 51%, 52% over a long period of time. So yeah but I don't think that's a bad estimate, right. I think that's fine.
Yes. All right.
As we said, just to repeat over time in on average, right, because it's the way we look at it, the way the commission looks at it we look back and we look forward on the projections. So repeat after me over time and on average.
Thanks a lot. We’ll see at EI, I appreciate it.
See you then, bye-bye.
Thank you. And I show our last question comes from the line of Chris Ellinghaus from Siebert Williams Shank and Co. Please go ahead.
Hey everybody. How are you?
Hey, Chris.
Good.
Maria, you mentioned two things that are interesting. One, you sort of talked about tech expansion in your service area. I was just kind of curious is -- are those sort of Bolton expansions and you're talking about new fabs and where do you see that in sort of your investment horizon here?
Sure. So as we speak, there are Bolton investments taking place. And I would also expect that we would see some new fabs as well.
Okay.
We are very fortunate to have the talent base that has created a number of really strong semiconductor manufacturers of the software companies that support their tools, as well as many fabulous companies as well. And so this is a period of a lot of growth in that area and we're fortunate to have a fair amount of it.
Okay. The other thing you talked about was transmission needs. Are you talking new lines or merely expansions?
I think it'll be a little bit of both. With an emphasis on expansion whether that is existing lines or existing corridors, as you know, transmission is a real challenge. And we'd like to be able to reduce all of the permitting, sighting, variety of issues that takes place with transmission and move as quickly as possible to ensure reliability of our service territory and the entire grid. So that's where our main focus will be, but it will be a little bit of both.
Okay. So, back to the base rate question, you've tended to try to avoid rate increase -- base rate increases in years where you have new assets coming into customer rates. Should we expect you'd be trying to avoid any new base rates for 2024?
So first and foremost, we're very confident of build pressure for customers and keeping things affordable, particularly during a period of time where you see a lot of volatile commodity prices. And so energy affordability and accessibility is really important to how we think of all of our planning. So we don't have any one conclusion one way or not, but I will tell you that as we look forward through this energy transition and the change in natural gas prices, as well as other things, affordability, as well as reliability of first and foremost as we make this clean energy transition.
Okay. Have you got any updates on your Faraday strategy?
The project is moving along. We expect that it will be online a little bit after the first of the year. Generating power maybe been a little bit sooner than that was one of the units and it's getting completed and has certainly been a project challenged by wind and ice storms, as well as the wildfires that went through there and the early COVID experiences. It's been a challenging project, but we're getting to the conclusion.
Through cost recovery thoughts?
Yes. So it is -- was part of our last rate case. And we have requested a separate rider, which is something that we were worked well for us when we brought on the selective water withdrawal system and some of our fish handling systems on the chutes. We were not able to obtain that so bringing that into customer prices would require a rate case.
Okay. Thank you so much.
Thank you, Chris. Nice to talk to you.
Thank you. This concludes our Q&A session. At this time, I'd like to turn the conference back over to Maria Pope for closing remarks.
Well, thank you all for joining us this morning. We appreciate your interest in Portland General Electric and we look forward to connecting with you soon. Thank you very much.
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