Portland General Electric Q4 2023 Earnings Call Transcript

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Provided by Quartr
February 16, 2024

There are 10 speakers on the call.

Operator

Good morning, everyone, and welcome to Portland General Electric Company's 4th Quarter 2023 Earnings Results Conference Call. Today is Friday, February 16, 2024. This call is being recorded and as such, all lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question and answer period. For opening remarks, I will turn the call over to Portland General Electric's Manager of Investor Relations, Nick White.

Operator

Please go ahead, sir.

Speaker 1

Thank you, Daniel. Good morning, everyone. I'm happy you can join us today. Before we begin this morning, I would like to remind you that we have prepared a presentation to supplement our discussion, which we will be referencing throughout the call. The slides are available on our website at investors.

Speaker 1

Portlandgeneral.com. Referring to Slide 2, some of our remarks this morning will constitute forward looking statements. We caution you that such statements involve inherent risks and uncertainties, and actual results may differ materially from our expectations. For a description of some of the factors that could cause our actual results to differ materially, please refer to our earnings press release and our most recent periodic reports on Forms 10 ks and 10 Q, which are available on our website. Leading our discussion today are Maria Pope, President and CEO and Joe Terpich, Senior Vice President of Finance and CFO.

Speaker 1

Following their prepared remarks, we will open the line for your questions. Now it's my pleasure to turn the call over to Maria.

Speaker 2

Thank you, Nick, and good morning. Thank you all for joining us today. Beginning with Slide 4, I'll discuss our 2023 full year and Q4 results and then turn to our outlook for 2024 and beyond. For the full year, we reported GAAP net income of 228,000,000 dollars or $2.33 per diluted share and non GAAP adjusted net income of $233,000,000 or $2.38 per share. This compares with GAAP net income of $233,000,000 or $2.60 per share and non GAAP adjusted net income of $245,000,000 or $2.74 per share in 2022.

Speaker 2

For the Q4, we reported net income of $68,000,000 or 0.67 dollars per share, up from the Q4 of 2022 of $50,000,000 or $0.56 per share. While these are lower than expected results, we remain confident in our long term growth trajectory of 5% to 7% and 2024 guidance of $2.98 to $2.18 per diluted share. To start, challenging weather impacted the quarter with mild conditions across the period and the 2nd warmest December on record. This resulted in very low energy usage and historically low wind and hydro production. As a result, this combination both to our revenue and purchased power and fuel expense performance fell short.

Speaker 2

The power cost challenges we faced in 2023 underscore the importance of risk reductions achieved as part of the 2024 general rate case. This includes 500 megawatts of hydro agreements improving our capacity portfolio and the introduction of the Reliability Contingency Event Provision as part of the PCCAM. These are solid steps in reflecting actual power costs and extreme events. We also have more work to do and look forward to working with the commission, other utilities and regional stakeholders towards a holistic energy framework and solution. Finally, our results also reflect higher costs associated with continued capital investment to support grid resiliency, customer growth and de carbonization.

Speaker 2

Turning to Slide 5. We consistently said that 2023 would be an investment year. Notwithstanding the challenges we faced, we achieved important milestones that have set the stage for 2024, including a constructive outcome in our general rate case. 2024 will be a year of growth supported by 3 key drivers. First, continued load growth led by high-tech and digital customers.

Speaker 2

2nd, capital investment to enable this growth, advance our clean energy goals and strengthen reliability and resilience and third, ongoing operational discipline across our organization. I will touch on each of these in turn. 1st, we expect continued strong industrial load growth supported by state and federal policies. Microchipped was recently awarded $72,000,000 under the Federal Chips Act for $800,000,000 expansion at their facility in Brescia. This is an addition to the multi $1,000,000,000 investments by Analog Devices and others.

Speaker 2

This builds on the state of Oregon's appropriation of $240,000,000 for semiconductor projects, 85% of which are in our service territory. Our capital plan now includes additional strategic transmission investments to enable this high-tech and other customer growth as well as renewable development. Joe will walk you through the updates to our plan in more detail. But at a high level, our transmission projects are largely within our service territory or adjacent. Many of these lower risk projects are reconducting existing lines.

Speaker 2

Related to renewable development, we are currently accepting and evaluating bids for the 2023 RFP throughout the Q1 of 2024 and we'll present the shortlist later in the year. Coming out of our last RFP, Clearwater Wind project came online in January with an impressive 45% capacity factor. And we look forward to our battery storage projects coming online later this year and into 2025. Now on to Slide 6. Utilities across the country are dealing with increasing impacts of extreme weather.

Speaker 2

This January, a severe storm brought powerful combination of high winds, ice and snow that led to widespread damage and high power costs. In the face of these extraordinary conditions, we deployed an extraordinary response. This included more than 1800 personnel, crews and support staff working hard to restore power and repair critical equipment. I want to take a moment to acknowledge and thank our teams and partners for all of their hard work in very challenging conditions. The storm came in multiple phases of severe weather and single digit temperatures.

Speaker 2

In the course of about a week, Cruise restored power to over 500,000 customers. This is a great example how our teams are working together efficiently to deliver for customers when they need us most. Our response was informed by lessons learned from the severe storms we experienced in 2021 and we're continuing to improve in what used to be 1 in a decade events. This operational focus is showing up in other ways as well. Our results in 2023 reflect our strong execution on cost management, thanks to the extraordinary efforts of our team to streamline processes, leverage technology and improve productivity.

Speaker 2

As we look to 2024, we continue to build on this progress. To reiterate, we're focused on 3 main areas to achieve growth in the coming year and beyond. First, exceptional customer growth second, execution of our capital plan and third, ongoing operational discipline. As such, we're well positioned to achieve 5% to 7% long term earnings growth. With that, I'll turn it over to Joe, who will walk you through our financial results.

Speaker 2

Thank you.

Speaker 3

Thank you, Maria, and good morning, everyone. Before I walk through the results and outlook, I want to acknowledge that we did not file our 10 ks this morning in line with our typical practice. We are just finalizing the required documentation for the 10 ks and completing associated compliance procedures. As you may know, we finished a new ERP software implementation in the Q4. With the holiday on Monday, you will see our filing posted with the SEC on Tuesday morning.

Speaker 3

Now turning to Slide 7. Our 2023 results reflect continued industrial load growth, dynamic weather and power cost conditions, execution of our capital plan and strengthening our growth foundation. Weather had a meaningful impact on 2023 results, particularly in the second half of the year. We saw 11% fewer cooling degree days and 13% fewer heating degree days compared to 2022. Q4 had historically moderate stretches with our region seeing the 2nd warmest December on record.

Speaker 3

Overall, we experienced 15% fewer heating degree days than the 15 year average. Customer uses was affected by these conditions, but power costs were also challenged as renewables production was significantly impacted during these mild periods. PGE's wind farms generated 23% less energy in Q4 2023 than Q4 2022, requiring generation at PTE's thermal fleet to make up much of the shortfall. Ultimately, these dynamics were a significant headwind in achieving the level of power cost favorability expected for the year. 2023 loads increased by 0.9% or 1.4% weather adjusted compared to 2022.

Speaker 3

2023 residential load decreased 1.7% year over year or 0.5% weather adjusted driven by mild weather and energy efficiency, residential customer count increased 0.8% for the year. Commercial load decreased slightly down 0.3% or 0.2% weather adjusted versus 2022, largely driven by energy efficiency. Healthy industrial load growth continued in 2023, increasing 5.9%. Over the last 5 years, we've observed a 7.5% compound annual growth rate in industrial load as high-tech investments and AI expansion have driven semiconductor and data center demand growth. While total loads in 2023 were below our expectations, our service territory fundamentals and our load outlook remains strong.

Speaker 3

Unemployment in our region of 3.4% trails the national average of 3.7% and we continue to see other public positive indicators. Public and private sector investment points to broader economic development and continued load growth in 2024 and beyond. I'll now cover our financial performance year over year. We experienced a $0.14 decrease in revenues excluding power costs and regulatory program collections driven by a $0.13 increase due to the 0.9 increase in deliveries and $0.27 decrease due to changes in the average prices of deliveries from higher industrial load and lower residential and commercial load. Power cost drove a $0.25 increase in EPS driven by a $0.29 EPS increase due to power cost headwinds in 2022 that reversed for this comparison and a $0.04 EPS decrease from higher power costs than anticipated in the annual update tariff.

Speaker 3

Serving load during the August heat event and the impact of mild weathering on Q4 renewable Our efficiency and cost management efforts, particularly in Q4 allowed us to keep base O and M nearly flat year over year. Next, a handful of impacts driven by the execution of our long term capital strategy including a $0.16 decrease due to higher interest expenses, a $0.10 increase from higher AFUDC driven by ongoing investment including the recently completed Clearwater Wind Development and a $0.22 decrease due to the dilutive impacts of draws on the equity forward sale in 2023. We had a $0.01 increase from other items including higher returns on benefit plan assets and regulatory interest, partially offset by benefit planned buyout in 2022 that did not recur. Lastly, a $0.05 decrease to GAAP EPS resulting from the Boardman settlement refund bringing us to our GAAP EPS of $2.33 per diluted share. After adjusting for this $0.05 impact, we reach our 2023 non GAAP EPS of $2.38 per diluted share.

Speaker 3

Turning to Slide 8, which shows our latest 5 year capital forecast, 2024 through 2027 estimates are now upsized by 1,200,000,000 as we look to maximize customer value with system wide improvements and emerging transmission investments. These transmission projects will focus on network improvements meant to alleviate congestion, improve adequacy and reliability, enable de carbonization and address customer growth. 2028 transmission projections also include PGE estimated contribution to the Bethel Round Butte transmission line upgrade, which will be undertaken with our longtime partner, the Confederated Tribes of the Warm Springs. This project will be assisted by the previously disclosed $250,000,000 U. S.

Speaker 3

DOE grant awarded to the tribes. As planning and scoping are finalized for this and other grant related projects, we will update our estimates and reflect in future forecasts. We have also refined our expectations for base capital spend to support grid modernization, system hardening and technology investments. As a reminder, this chart does not reflect CapEx related to the possible ownership from the recently launched 2023 RFP, which went to the market on February 2. The competitive bidding process schedule, which is included on our RFP website, anticipates bid submission, final shortlist selection and shortlist submission to the OPUC by mid-twenty 24, project selection is expected in Q3 or Q4.

Speaker 3

This timeline is dependent on the volume and complexity of the bids and we will update you as the competitive process continues. While we are continuing to evaluate timing, increased base CapEx to deliver customer benefits and the incoming battery projects to improve grid flexibility put weight on the scale for a near term rate case filing. In line with our standard process, we will keep you informed of any actions regarding a rate case filing. On to Slide 9. For our liquidity and financing summary, total available liquidity at December 31 is 969,000,000 dollars Our strong balance sheet, investment grade credit ratings and stable credit outlook remain unchanged from our previous disclosures.

Speaker 3

Through December 2023, we've entered into forward sale agreements for $78,000,000 of the $300,000,000 available under the ATM. There have not been any draws in these forward agreements thus far. As we look to the remainder of 2024, we anticipate debt issuances of up to $730,000,000 for the year and we plan to continue our practice of issuing under our green financing framework where possible. On the equity front, capacity under the ATM remains sufficient for our base capital financing needs, including the battery projects currently underway. The ATM provides a helpful mix of capital access and dilution management that supports our ongoing base capital plan.

Speaker 3

Continued management of our capital structure and trending towards our authorized fifty-fifty ratio over time remains a key priority. We maintain flexibility in financing options and remain confident in competitively accessing both debt and equity markets when necessary. As additional capital investment opportunities mature, including from the RFP, we will continue to evaluate our strategy and update you on our financing plans. Turning to Slide 10. We are initiating full year 2024 adjusted earnings guidance of $2.98 to $3.18 per diluted share.

Speaker 3

As Maria noted earlier, the January storm system had a meaningful impact on our service territory and we are continuing to work through the implications of the multi day event. Currently, we estimate storm restoration operating expenses of $35,000,000 to $45,000,000 and approximately $15,000,000 of capital costs to repair impacted assets. Earlier this month, we filed a deferral of these costs under a standing emergency restoration deferral. The conditions to trigger the 1st reliability contingency event treatment under the updated power cost recovery framework were met as the region saw market price spikes, balancing authority alerts and resource adequacy constraints on PGE system. Under the RCE mechanism, PGE is allowed to pursue recovery of 80% of the cost for the RCE above the amounts forecasted in the AUT with the remaining 20% flowing through the existing PCAM.

Speaker 3

We are currently estimating the RCE cost between $85,000,000 100,000,000 These impacts are still being finalized, but we will be able to provide more detail when we report Q1 2024 results. Given the extraordinary and irregular nature of the storm last month, the effects are excluded from our 2024 guidance and will be excluded from our 2024 adjusted non GAAP results to improve the comparability of earnings and to better reflect our ongoing financial performance. We expect this to involve the exclusion of the non recoverable 20% portion of the RCE cost and any operating costs which have been determined non recoverable under existing mechanisms. I will now touch on other drivers of 2024 guidance. As I said earlier, confidence in our service territory remains strong, highlighted by continued low growth from industrial customers and modest increases in the residential and commercial classes.

Speaker 3

Combined, we assume a 2% to 3% weather adjusted retail load growth for 2024. These load dynamics as well as continued regional investment and a pipeline of incoming projects give us continued confidence in our long run load assumptions expectations, sorry. As such, we are reiterating our long term load growth guidance of 2% through 2027. We anticipate O and M expense raising from $815,000,000 to $840,000,000 which includes $165,000,000 of earnings neutral regulatory deferral amortizations, wildfire mitigation and vegetation management costs and other offsetting items. Net of these items, the midpoint of our O and M range represents a 3% compound annual growth rate compared to 2022 base O and M net of similar offsets.

Speaker 3

We remain committed to deploying the right tools to optimize productivity and provide the highest quality customer service while also managing operating costs. This philosophy coupled with de risking accomplishments and critical investments made in 2023 give us continued confidence in our growth plan. As such, we are reiterating our long term earnings growth and dividend growth guidance of 5% to 7%. As our attention shifts to the year ahead, our core focus remains unchanged, safely serving clean, reliable and affordable energy while providing value to our communities, our customers and our shareholders. And now operator, we are ready for

Operator

And our first question comes from Nicholas Campanella with Barclays. Your line is now open.

Speaker 4

Hey, thanks so much for taking my question. Happy Friday.

Speaker 2

Good morning.

Speaker 4

So I guess just pretty material increase in the base CapEx plan here. So can you just help us understand, are there additional equity requirements beyond kind of the $300,000,000 ATM that you've highlighted in slides? And then maybe I'll just leave it there for now. And then where do you kind of stand in that $5,000,000 to $7,000,000 EPS CAGR with this new CapEx plan? Thank you.

Speaker 2

Sure. Well, thank you very much. So first one of the additions that you're seeing and we pulled it out and separated it from what we had shown you in the past is our transmission investment plan. And that will continue to probably increase as we move forward as well. And then for the regards to your questions on our equity offerings or where we're looking for the ATM, The ATM will cover what we need for the foreseeable future, including the batteries.

Speaker 2

We are waiting to see where we end up with the RFP projects that could be coming in and that could potentially require additional capital. We remain confident in our 5% to 7% growth rate. And you'll see that moving forward with confidence as we look to 2024, which is a really solid year for us given the outcome of our rate case, customer growth and the capital plan that we just discussed.

Speaker 4

Okay. So on the base plan today, it's just the current equity funding needed to do the base plan today. Obviously, that can change as this RFP comes through and we'll see how much you can own versus not. Is that the right message?

Speaker 2

Yes, that's correct, Nick. Thanks.

Speaker 4

Okay. Thank you. And then just, I guess just on the storm expenses, just understanding that you're deferring a portion of it. You kind of talked about this $35,000,000 to $40,000,000 bucket and then this $85,000,000 to $100,000,000 for the RCE cost. Just simplistically, like how much is actually being deferred versus excluded from the non GAAP number in 2024?

Speaker 2

So let me let Joe take that on. And one thing I want to recognize is that this was truly an extraordinary event, not only for the restoration efforts with regards to customer outages, but region wide, the energy markets were really in significant disarray. Joe? Yes. And so Nick, I'll sort

Speaker 3

of answer this a bit in reverse. So as it relates to the cost, the amount that we would expect not to be deferred that would be the operating the exclusion would be between $0.10 $0.15 I think everything else that we talked to would be deferred within one of the two mechanisms that we've mentioned previously. That's helpful. Thank you so much.

Operator

Thank you. One moment for our next question. And our next question comes from Cher Farooza with Guggenheim Partners. Your line is now open.

Speaker 5

Hi, Cher. Good morning. It's actually James for sure. Good morning.

Speaker 2

Good morning.

Speaker 5

So if I could start on the load side, just part of the backdrop is your service territory is in a lot of companies involved in semiconductor manufacturing and AI specific data centers. Can you just give us some color on how AI is providing growth across the customer classes as you see it? And also any detail on what kind of incremental generation or transmission opportunities are being created in the longer term specifically by those customers?

Speaker 2

Sure. That's a great question. So on the longer term side, certainly we have been a semiconductor manufacturing center for decades and about 15% of semiconductors are manufactured in our service territory and we expect to see a lot of longer term growth. The construction of those facilities is very extensive. Easier to construct and nearer term growth is the AI driven data centers, both in terms of some of the mega facilities as well as some of the grid edge computing.

Speaker 2

So we are seeing no small shortage of demand from just about every hyperscaler and cloud computer company out there. And it's a really terrific amount of opportunity for us. Most of these companies want 100 percent clean energy. They frequently bring their own reliability backup and are interested in additional transmission, substation infrastructure as well as other. So it allows for significant growth as we move forward.

Speaker 2

For our communities and the other customers we serve, this creates an overall strengthening of our reliability and resiliency as we invest in new infrastructure and it provides important jobs for the region, property taxes and other significant benefits.

Speaker 3

Got you. Thank you. And then just shifting over

Speaker 5

to the regulatory side, Joe, you hinted at this at the end of your prepared. But I assume the timeline for new rates Jan 1, 2025 would be a new GRC filing in the next week or 2. I guess can you just get a little more color on your thoughts on timing?

Speaker 3

Sure. Well, so we haven't finalized our thoughts on timing, but you're correct. Under the regulatory framework in Oregon, it is a 10 month window. So if we want rates to go effect immediately on January 1, a filing would need to occur by the end of this month. We continue to sort of finalize our thinking and approach and we'll obviously communicate that as we have it.

Speaker 3

As I mentioned previously, there are certain items putting weight on the scale of the batteries coming online and some other items that we would expect need a more timely recovery. Okay.

Operator

Thanks guys. Thank you. One moment for our next question. Our next question comes from Julien Dumoulin Smith with Bank of America. Your line is now open.

Speaker 6

Hey, good morning, team. Thank you guys very much for the time. Hey, Maria, thank you. Just following up on the latest from the Oregon PC, just on the rejection of the clean energy plan. I just want to understand a little bit, right, because obviously this is sort of partial, short term versus long term.

Speaker 6

What message are they trying to send here about the 100% target, especially relative to affordability? I'd love to get, in your words a sense of breaking out of the different pieces that are ongoing. And then I got a follow-up quickly.

Speaker 2

Sure. No, it's a great question. And, first of all, this is our first clean energy plan and I want to acknowledge and recognize that our integrated resource plan was acknowledged and we are moving forward under that IRP. There are questions really had to do around more granular admissions modeling. We have been doing day by day admissions modeling and they like to see hour by hour emissions modeling.

Speaker 2

Overall, as you'll also remember, our original IRP had was upsized in July quite significantly for additional energy needs as well as additional capacity needs. And I think there's more discussion among stakeholders and key constituents around the how we're going to meet the additional needs with additional renewable energy and other infrastructure. So it's a good time to have healthy discussion around what is a really dynamic and rapidly growing environment here.

Speaker 6

Yes, it certainly. And just to make sure I'm understanding the key takeaway here. I mean, it seems like there's a broader question about like how you meet the 100% in terms of maybe there's a need for more, again, because I know that at times there's been an acute focus on affordability here and perhaps enabling and ensuring that there's a pathway for affordability. I just want to make sure I'm hearing clearly what direction that this rejection on the long term came from?

Speaker 2

It came from a need most clearly for additional admissions modeling, Julian. But the back story here is that we're seeing pretty significant changes to the upside of energy usage and wanting to really understand the sources, the economics of all of those procurements. As we bring on renewable resources and a Clearwater would be a good example, we're actually not seeing customer prices react as we're displacing higher purchase energy in the market. And so the additional renewables procurement is actually not driving customer prices as much as one would think as we model it forward. It's the overall need for investment in aging infrastructure and supporting significant customer growth that is driving customer prices as we move forward more than clean energy development.

Speaker 6

Right. And actually to that point, I mean, you have a dramatic increase here in transmission and that's not necessarily surprising given what you've been telegraphing in recent periods about the need for transmission. But can you maybe frame out, I mean, how do you think about sort of upside generation given the new level of spend tied to especially transmission here? I mean, should we continue to think about this as being incremental? Do you have a shift in how you think about allocating capital to generation here?

Speaker 6

I mean, I know that you're reaffirming 5% to 7%, but at times perhaps there's been sort of a ceiling on how much you want to push your core rate base considering all the various needs. Is there a push out potentially here in terms of some of the investments or really do we should we consider this as truly incremental upon incremental opportunities?

Speaker 2

Sure. I mean, we have to always keep customer prices 1st and foremost. There's no question that we have seen customer price pressures and we are very attuned to the interest of our customers and keep making sure that affordability stays 1st and foremost. One of the reasons that we have competitive RFPs for renewable generation capacity and energy is to get the very best prices for customers in competitive processes. We have done well in those processes in the past and we hope to continue to be able to deliver the lowest cost, of least risk clean energy resources to customers that is markedly available.

Speaker 2

With regards to transmission, there is some flexibility. Some of these transmission spend was in our historic run rate. Some is new and incremental. We think of this sort of as concentric circles. The first circle being within our service territory really directly impacting being impacted by customer growth.

Speaker 2

The second is to bring clean energy from our area or just adjacent to our areas to our customers. And then the third is broader investments across the Northwest. One of the big increases as you look farther out in the chart in 2028 is the Confederated Tribes of the Warm Springs project on our existing Pelton Round Butte line, where we received a $250,000,000 Department of Energy grant to significantly upsize that existing line, most of which will continue over existing rights of way. So as we look at transmission, we're focused on relatively easy to execute and my colleagues would probably question that transmission is ever easy to execute. But relatively lower risk projects within our service territory focused on repowering and increasing existing rights of way and lines.

Speaker 6

Wonderful. Excellent. And just quick housekeeping on the ITCs here, if you don't mind. Just for the battery, is that going to be reflected like in a single year here or over 5 years? Or how do you think about the accounting for the ITCs here real quickly?

Speaker 6

Again, this is sort of a novel subject in storage and regulated land. So,

Speaker 3

good morning, Julien. So from a standpoint of recognition, as the battery comes online, we'll recognize those ITCs and we would expect since we have 2 batteries, they'll be coming in over 202425 that will recognize those ITCs, what I'll call to the balance sheet. The customer is receiving the benefits of those ITCs that we'll lay out in our next regulatory filing that will be amortized to them. Julie, I think when you get to the real question is once we put them on the balance sheet, the expectation is that we will monetize them somewhat shortly thereafter. So as we recognize them and they have the certainty of the ability to transfer, we will be looking to monetize them.

Speaker 6

Got it. Pretty concurrently. Got it. Excellent. Thank you.

Speaker 6

Yes. So that and that will flow through the income statement?

Speaker 3

The monetization will flow through as a cash flow, right, from the purchase and sale of the ITCs with his income will be income statement neutral.

Speaker 6

Okay. Thanks for

Operator

that Marty. I appreciate it.

Speaker 6

Perfect.

Operator

Thank you. One moment for our next question. Our next question comes from Greg Orrill with UBS. Your line is now open. Good morning, Greg.

Operator

Yes, thank you. Good morning.

Speaker 7

With regard to the rate case coming up, do you have any sort of early thoughts on level of rate increase or sort of thoughts on affordability heading into that?

Speaker 3

Greg, good morning. Doctor. Pich. Obviously, we start our case here always thinking about affordability to the customer also considering we've had a previous case here. I would expect in this case, truly the focus is going to be on the batteries, the assets that have been put in service to continue to advance both reliability, expand capacity on the system as well as small amounts of cost.

Speaker 3

I mean, I think this will be mainly be a truly just an infrastructure update to the plan focused on affordability.

Speaker 7

Got it. Thank you.

Operator

Thank you. One moment for our next question. Our next question comes from Paul Fremont with Ladenburg Thalmann. Your line is now open.

Speaker 8

Thank you very much and thank you for taking my questions. I guess my first is, given the storm deferrals for January, is that something that you would be looking to recover in the rate case that you're filing currently? Or would that fall outside the purview because of it's too recent?

Speaker 3

Good morning, Paul. So the storm recovery actually will fall through 2 separate processes than the general rate case. They'll both be in existing mechanisms. So as it relates to the operating costs and the reconstruction costs, those will come through a deferral rider that will be filed and will have its own proceeding, which is and then the as it relates to the cost of the energy and the RCE event that will go through the PCCAM process. Each will have a bit of a different timeframe.

Speaker 3

For example, the PCCAM process would not be filed until 2025 with the recovery of that would work itself into 2026.

Speaker 8

And then the timing on the OpEx recovery, does that normal would that normally occur within a year's time or shorter than that?

Speaker 3

That recovery will be up to discretion with the commission. Normally, these storms are recovered over due to their magnitude and the significance over an extended period. The last time we had a storm recovery of this nature, it was recovered over 7 years.

Operator

Okay.

Speaker 9

And we will also look

Speaker 3

to just as an I was going to say, we'll also look to the eligibility for either of these for securitization, which will obviously change can change the recovery stream as well.

Speaker 8

Okay. And then looking at the higher base CapEx, how should we think about that relative to your bidding into the renewable RFPs? Would you be looking to win less in the RFPs given sort of the magnitude of the CapEx increase or would there be sort of no change in terms

Speaker 2

of your bidding strategy? So our bidding strategy today, our bidding strategy going forward and our bidding strategy in the past has always been the same and that is to have the most competitive projects for the least cost and least risk for customers. And those projects are winners. They're good for customers and they're good for financing.

Speaker 8

Okay. And then it looks like there's a $200,000,000 to $300,000,000 annual increase in CapEx each year. Should we look at the incremental amount of spending as being funded roughly 50% with equity? Is that sort of a fair way to think about the financing?

Speaker 3

Yes. I think when we look to the long term financings here, we continue to look to over sort of using flexibility, manage our capital structure, continue to move towards fifty-fifty. So assumption that over time that would be looked at it at that balance level, it would be a reasonable way to look at it.

Speaker 8

Great. Then my last question is a big step up I think in transmission and spend in 20 28. And I was just wondering what sort of what's the explanation of that?

Speaker 2

Sure. That's the an answer to Julian's question earlier, that's the Pelton Roundview to 230 Lawn that's planned to be increased to 500 kV in partnership with the Confederated Tribes of the Warm Springs. We previously announced a $250,000,000 grant for that work from the Department of Energy. Obviously, that project would cost more than $250,000,000 It's over 100 miles long and it would be a multi year project. The 1st year we're anticipating in 2028.

Speaker 8

So would the level of transmission spending sort of stay at that higher level for several years?

Speaker 2

Probably for a couple of years after that in 2029, 2030, the transmission line and the increase also opens up a good portion of the central part of Oregon for additional renewable development in partnership with the tribes. We currently co own several hydro facilities with them. And so this will allow for significant expansion, particularly of solar energy, but really making the central part of Oregon and the Confederates of the Warm Springs reservation an opportunity for further development through 20 28 and beyond.

Speaker 8

And then my last question, with sort of the step up in CapEx, what type of rate base growth does that give you on a percentage basis through 20 28?

Speaker 3

So Paul, in the sort of the sister document that we also filed this morning for the base capital, which includes the transmission, which includes the line that Maria just mentioned, that would put us at right around an 8% rate base growth. And then we've also in that update made some scenarios regarding an RFP outcome and that update would put you at a with a 25% outcome would put you at a 9.2% rate base growth through 20

Speaker 8

Great. Thank you.

Speaker 2

Thank you.

Operator

Thank Our next question comes from Travis Miller with Morningstar. Your line is now open.

Speaker 7

Thank you.

Speaker 5

Good morning, Travis.

Speaker 7

Good morning, everyone. Quick question on the battery stuff. That increase in the 2024 number, is that incremental projects? Or is that some kind of carryover spending from 2023?

Speaker 3

Specifically as it relates to the battery, that is the 1 RFP moving out. In fact, the battery spend you see in 2024 and 2025 was all existing from that RFP and it is the first set of spend is more than it's the consumable project or the smaller battery and then the spend that goes into 2025 is the seaside battery, which is the larger one.

Speaker 7

Okay. I was thinking about the comp from previous capital update, which was I think $100 and something million to $235,000,000

Speaker 3

And these are the same batteries. We have not added any projects. This is the update to the pricing for those same batteries.

Speaker 2

So there were some payments that went from 2023 to 2024.

Speaker 7

Got it. Okay. Okay. Yes. So I was thinking.

Speaker 7

And then related on that, how much of the battery specifically CapEx and those payments do you anticipate you'll be able to get into the rate case given that and correct me if I'm wrong, given that they're probably not going to be done, right, operational in the next

Speaker 3

But when we update the so when we do the filing, the filing will use a future amount of rate base. So we'll use an end of 2024 rate base and we will when we decide to file, we will place a structure in there that would expect recovery of the batteries on their in service date. The first, the constable battery, which has an in service date somewhere right around at the end of 2024 and then also then the seaside battery as it goes in service in 2025. As you may recall in our prior case and when we file whenever we file our next case, we will address the RAC or the renewable adjustment clause that allows for renewables to go into service. We previously had requested policy as well as potentially consider other policies to ensure that the batteries are timely into service similar to other renewable assets.

Speaker 7

Okay, great. That's really helpful. And then different question, given the increase in the capital spending and your comments around trying to get back to the certain capital structure, what does that mean for the dividend and dividend growth you anticipate?

Speaker 3

Our expectation is as we continue to grow, we are committed to drawing the line as it relates to our 5 to 7% earnings growth and that similar dividend growth. So we have no expectation of changes in our dividend growth rate off of our previously communicated point.

Speaker 7

Okay. In line with earnings.

Speaker 5

That's correct.

Speaker 7

Okay. That's all I had. Thanks so much.

Speaker 2

Thank you. Thank you, Travis.

Operator

Thank you. One moment for our next question. Our next question comes from Willard Granger with Mizuho. Your line is now open.

Speaker 9

Good morning. Hi, good morning everybody. Good morning. Just a question, sort of coming back to the equity, I see in the balance sheet the debt to cap. You finished 2023 with around 56% debt to cap.

Speaker 9

When do you think you'll be closer to the allowed 50% that you got in the last rate case? Thanks.

Speaker 3

Sure. Good morning, Willard. So we look to as we built the 5 year plan, we've considered a path that will get us towards that 50% over that period with some flexibility on the timing in between peers considering the RFP or considering the considering with and without RFP scenario. So we have sort of a series of flexible strategies that will work us there over what I'll call this longer planning.

Speaker 9

Understood. Thanks for the clarity. And then maybe just thinking about the battery storage, is that something that you'd likely see more of with some of the load growth? Or do you think that the generation spend is more geared towards traditional renewables?

Speaker 2

Well, I think we'll see both. Clearly capacity is important as we in particular with all of the volatile weather that we're seeing. So I think you'll see additional batteries coming through RFPs. And I think you'll see more traditional renewables of wind and solar. There are also some pump storage projects and some other projects that are farther out that independent power producers have been working on.

Speaker 2

And so I think this is going to be what I call the all above set of solutions as we move forward. We're also working very closely with customers on their energy usage and flexibility as well as standby generation to bring all of the resources to bear through this transition.

Speaker 9

Thank you. I'll leave it there. That's super helpful.

Speaker 2

Thank you.

Operator

Thank you. I'm showing no further questions at this time. I would now like to turn it back to Maria Pope for closing remarks.

Speaker 2

Great. Thank you very much. We appreciate your interest in Purellon General Electric. We're excited about 2024, our continued growth at high-tech digital customers, our capital plans to support that growth in renewable development, as well as our continued focus on operating costs and operational excellence. We look forward to connecting with you soon and thank you very much for joining us today.

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Key Takeaways

  • Portland General reported full-year GAAP net income of $228 million ($2.33/share) in 2023 versus $233 million ($2.60/share) in 2022, with Q4 net income rising to $68 million ($0.67/share) but falling short of expectations, while 2024 adjusted EPS guidance is $2.98–$3.18 amid a 5–7% long-term growth outlook.
  • Unusually mild weather in Q4 (the 2nd warmest December on record) led to low energy usage and 23% less wind generation, driving higher purchased power costs that are being addressed via 2024 rate-case provisions including 500 MW of new hydro agreements and a Reliability Contingency Event framework.
  • 2023 was an “investment year,” culminating in a constructive general rate case outcome and setting 2024 growth drivers: strong industrial load from high-tech semiconductor expansions, renewable RFPs with the Clearwater Wind project online, upcoming battery storage, and sustained operational discipline.
  • During the January storm, over 1,800 personnel restored power to more than 500,000 customers, incurring $35–$45 million in operating costs and $15 million in capital costs, plus an estimated $85–$100 million under the RCE mechanism, with 80% recoverable and 20% excluded from 2024 adjusted results.
  • The five-year capital forecast through 2027 was upsized by $1.2 billion to support transmission upgrades (including the Pelton Round Butte line upgrade backed by a $250 million DOE grant) and grid modernization, financed via up to $730 million of 2024 debt issuance, ATM equity access, and a target ~50:50 debt-to-equity ratio.
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Earnings Conference Call
Portland General Electric Q4 2023
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