Pinnacle West Capital Corporation (NYSE:PNW) Q4 2023 Earnings Call Transcript

Pinnacle West Capital Corporation (NYSE:PNW) Q4 2023 Earnings Call Transcript February 27, 2024

Pinnacle West Capital Corporation misses on earnings expectations. Reported EPS is $-0.11371 EPS, expectations were $-0.1. Pinnacle West Capital Corporation isn’t one of the 30 most popular stocks among hedge funds at the end of the third quarter (see the details here).

Operator: Good day, everyone. And welcome to the Pinnacle West Capital Corporation 2023 Fourth Quarter Earnings Conference Call. At this time all participants have been placed on a listen-only mode. And we will open the floor for your questions and comments after the presentation. It is now my pleasure to turn the floor over to your host, Amanda Ho. Ma’am, the floor is yours.

Amanda Ho: Thank you, Matthew. I would like to thank everyone for participating in this conference call and webcast to review our fourth quarter and full year 2023 earnings, recent developments and operating performance. Our speakers today will be our Chairman and CEO, Jeff Guldner; and our CFO, Andrew Cooper. Ted Geisler, APS’ President; Jacob Tetlow, Executive Vice President of Operations; are also here with us. First, I need to cover a few details with you. The slides that we will be using are available on our Investor Relations website, along with our earnings release and related information. Today’s comments and our slides contain forward-looking statements based on current expectations, and actual results may differ rely from expectations.

Our annual 2023 Form 10-K was filed this morning. Please refer to that document for forward-looking statements, cautionary language as well as the Risk Factors and MD&A sections, which identify risks and uncertainties that could cause actual results to differ materially from those contained in our disclosures. A replay of this call will be available shortly on our Website for the next 30 days. It will also be available by telephone through March 5, 2024. I will now turn the call over to Andrew.

Andrew Cooper: Thank you, Amanda, and thank everyone for joining us today. I will first cover our fourth quarter and full year 2023 results before handing it to Jeff who will discuss our recent rate case outcome growth outlook and strategy. Afterwards I will finish up with our 2024 guidance and long-term financial outlook. In the fourth quarter of 2023 we achieved a $0.21 increase in earnings per share compared to the same quarter in 2022. This year-over-year improvement was largely driven by a $0.41 uplift in gross margin attributable to increased sales and usage as well as higher transmission revenue and contributions from the LFCR and 2019 rate case appeal. The lack of certain prior period items from Q4 2022 contributed to a $0.21 benefit to other income and expense on a year-over-year basis.

These increases versus the prior year were partially offset by higher O&M expense, depreciation amortization, interest expense and benefit costs. For the full year 2023, we earned $4.41 per share, a $0.15 increase over 2022 surpassing our guidance range of $4.10 to $4.30 per share. A significant factor in this result was a $0.22 year-over-year weather benefit driven by an unprecedented summer heat wave during the third quarter. Overall weather contributed $0.48 in 2023 compared to normal weather. Revenues from adjuster mechanisms, transmission and increased sales and usage were also positive drivers for the year. In addition other income and expense was $0.33 higher year-over-year driven by the lack of certain prior expense items from 2022 and the sale of Bright Canyon assets in the third quarter of 2023.

These increases versus 2022 were partially offset by higher O&M expense, depreciation amortization, interest expense and benefit costs. Overall we ended 2023 with 2% customer growth maintaining the years-long upper trajectory of consistent growth in our service territory. Weather normalized sales growth was within the expected guidance range at 1.5% in 2023 driven by 3.3%growth in our C&I customer segments. I’ll now pass the discussion to Jeff to talk about our rate case outcome growth outlook and strategy before I continue with our 2024 guidance and long-term financial outlook.

Jeff Guldner: Great, thank you Andrew. And thank you all for joining us today. As you all know just a few days ago the commission voted to approve our 2022 rate case. I’m pleased to say that this rate case decision was ultimately reasonable and constructive. I’ll highlight a few of the main outcomes including an improved authorized return on equity, the approval of a new generation rider and a balanced revenue requirement increase among other items. I’ll also discuss our growth outlook and future strategy coming out of this case. Lastly as Andrew mentioned, he’ll provide our 2024 guidance and our long-term financial outlook. After the unconstructive outcome of our 2019 rate case we designed a comprehensive strategy and plan and I’m pleased to share that we have accomplished the goals that we set out two years ago.

We executed on a strategy centered on creating shareholder value by creating customer value and we’ve seen significant improvements in our J.D. Power survey results. Not only have we been successful in moving from fourth quartile in 2021 to second quartile at the end of 2023 for both our residential and our business customers, we finished the year second amongst all large investor-owned utilities in phone customer care and in Perfect Power. Reliability has continued to be a top priority and we’re once again top quartile meeting this milestone 10 years out of the last 11. This reliability was put on full display during the summer of 2023 when Arizona broke numerous heat records yet our team delivered outstanding performance for our customers.

Another important goal that we set was to build more collaborative relationships with stakeholders in the regulatory process and we succeeded in achieving supportive regulatory decisions and that include both the efficient implementation of our successful 2019 rate case appeal, as well as the most recent rate case. And finally we focused on shareholder value by deferring any equity issuances and continuing to grow our dividend during this challenging period. Now, I’ll walk through some of the major highlights of the rate case. The commission adopted a net revenue increase of $253.4 million. From the very beginning we focused this rate case on improving the authorized ROE to recognize the risk and the investment needed to serve our rapidly growing service territory and the commission did that.

The commission voted to adopt an authorized return on equity of 9.55% with a 0.25%fair value increment in combination of those two is equivalent to a 9.85 return on equity. With this decision the commission has adopted an authorized return that’s more in line with national averages and it recognizes that we’re one of the fastest growing states in the nation and we need to attract capital in order to fund the investments necessary to reliably serve our customers. In addition the commission voted to approve our request for a system reliability benefit surcharge. This is an important surcharge that will allow us to invest in much needed generation resources to continue to serve our customers reliably and affordably while reducing regulatory lag.

Importantly the SRB will allow for the most cost-effective generation resources to be built for the benefit of our customers and to promote a healthier balance of PPAs and utility-owned assets. Later on Andrew will discuss how the SRB provides future opportunities for CapEx growth. It’s also noteworthy that the commissioners made positive amendments to the revised recommended opinion in order at the open meeting that increased the net revenue requirement and addressed some items that would have created additional regulatory lag. This highlights the improved regulatory environment and our ability to achieve constructive outcomes. However, even at the final net revenue requirement the outcome underscores the continued challenge from lagging historical costs.

We look forward to working with the commission on addressing these lagging costs in the near future through both the regulatory lag docket which will have a workshop on March the 19th as well as through future rate case filings. Now, I’ll share our next step and strategies as we look to the future. We’re focused on solid execution and continue to remain optimistic about our future for many reasons and I’ll discuss each of these reasons in more detail. First I’m optimistic about our attractive service territory and consistent customer growth. Arizona remains among the fastest growing states in the nation. Where other states have been experiencing little or negative customer growth we’ve been benefiting from steady and consistent retail customer growth of 2% for the last few years and project that growth to continue in the range of 1.5% to 2.5% in 2024.

We believe that the constructive business environment with ample job growth, a competitive cost of living and a desirable climate will continue to grow the Metro Phoenix market and benefit the local economy. Focusing on our service territory specifically we continue to see development from a variety of sectors which is helping to diversify our local economy more than ever. The availability of a skilled workforce and our state’s business friendly policies and regulations coupled with our low propensity for natural disasters and our clean energy development potential make us uniquely situated for growth. The tremendous demand that we see from large commercial and industrial customers will help spread fixed costs over increasing sales and has a positive multiplier impact for jobs and surrounding communities.

We’ll continue to focus our economic development approach on helping to attract and expand businesses and job creators. As you can see from this graphic from the Arizona Commerce Authority the diversity of the commercial and industrial growth in Arizona presents exciting opportunities. Our state is seeing growth in a wide range of sectors driven by manufacturing reshoring, the clean economy and digital infrastructure needs which will help reduce the risk of any potential downturns in a particular industry to keep our economy and growth stable. Turning to our regulatory environment, we’ve seen meaningful improvement through the last couple of years. The Arizona Corporation Commission has established a record of balanced and constructive decisions including our most recent rate case and importantly beyond those decisions the commission has also recognized the need to address regulatory lag in a holistic matter and has opened a docket to review and discuss various solutions going forward and as I mentioned we’ll kick off next month.

We look forward to working with the commission on addressing this important issue. In addition, the commission reaffirmed its policy on settlements. Historically outcomes achieved through settlement have delivered new and innovative customer programs and other results that benefit a broad and diverse range of stakeholder interests in our state’s energy future. We believe the nature of the settlement process itself yields more informed constructive and mutually beneficial results. The third reason that we’re confident is the clear path that we’re on in our transition to clean energy. We came out with our clean energy commitment in early 2020 and I’m proud that we’ve made significant progress. We plan on retiring our remaining Challo units by next year and to completely exit coal by 2031.

Since our clean energy commitment we’ve procured nearly 5,000 megawatts of additional clean energy and storage and issued another all-source RFP for an additional thousand megawatts of reliable capacity including at least 700 megawatts of renewable energy. With the approval of the SRB mechanism in this rate case we’re even better positioned to establish ownership in these new clean energy assets for our customers benefit. The fourth reason I’m optimistic about the future is because of the tremendous amount of growth and opportunities we have in our FERC jurisdictional transmission business. We’ve increased our core transmission spend for the next three years and expect to have a much greater need for transmission capital spend over the next decade.

We recently filed our 10-year transmission system plan with the corporation commission showing five critical transmission projects that are needed to strengthen resiliency, support the growing energy needs of our customers, and allow for greater access to a diversity of resources in markets across the region. The total investment for APS’s portion of these projects is estimated to total over $5 billion over the next 10 years. We look forward to developing this critical infrastructure that’s necessary to continue to provide safe and reliable service to our customers. And finally and I’m optimistic about the future because my entire management team and I have been committed to executing a customer-centric strategy that will allow us to deliver exceptional customer service.

As I mentioned earlier we’ve made significant progress in our J.D. Power survey results and have moved from fourth quartile in 2021 to second quartile at the end of 2023. Additionally we’re focused on delivering on our goal to provide reliable energy to our customers in the most affordable manner. Increases in our rates remain well below the rate of inflation even with the latest rate case decision. We remain focused on customer affordability and keeping it central to our plans to provide long-term sustainable growth. That focus coupled with continued cost management creates rate headroom for the future. I’ll now turn the call back over to Andrew to provide guidance and share our long-term financial outlook.

Andrew Cooper: Thanks Jeff. I’ll now discuss our 2024 guidance and future financial outlook. For our 2024 outlook we are establishing an EPS guidance range of $4.60 to $4.80 per share reflecting the additional revenues from our recent rate case outcome with new rates effective March 8th. This revenue is partially offset by continued drag from increased expenses not captured in our historical test year. As Jeff mentioned this rate case was balanced and constructive and this decision will create a solid foundation from which we will grow. However it is important to highlight that we continue to face significant regulatory lag due to the timing of our historical test year which ended June 30th of 2022. This lag is mainly due to higher interest rates on borrowed capital, higher depreciation due to increased rate-based growth, lower contributions from pension on service credits, and increased O&M expense due to planned generation outages.

We are encouraged by the commission’s focus on holistically addressing regulatory lag through the newly created regulatory lag docket. We are committed to addressing these current costs in our next rate case and working with the commission to find solutions to reduce these impacts on our current construct. Our commitment to mitigating regulatory lag is a priority aiming to preserve our financial stability and build shareholder value between rate cases. Diving a bit deeper into 2024 the largest positive driver of our guidance will be new revenues from the implementation of the rate case decision. Other positive drivers are expected to include increased revenues from sales growth, the LFCR, and the full-year impact of the 2019 rate case appeal outcome.

The most significant year-over-year negative driver is expected to be weather due to the record-breaking heat wave we saw in 2023 as we plan for normal weather. Other negative drivers are expected to be higher depreciation and harmonization expense, increased financing costs, and higher O&M primarily due to planned outages. Turning to customer growth, as Jeff mentioned, we once again expect our customer growth to be within the range of 1.5% to 2.5%, which continues to highlight the attractiveness of our state and service territory for customer in migration. For 2024 sales growth, we expect 2% to 4% growth of which 2.5% to 3.5%is driven by extra high load factor C&I customers. These sales create operating leverage and ultimately rate headroom for all customers.

We’ve seen a steady ramping of these customers and anticipate they will continue to ramp through 2024. Longer term, we expect our weather normalized sales growth to be within the range of 4% to 6%through 2026 with 3%to 5%of this growth driven by our large C&I customers. Turning now to what we strive to provide investors going forward I will discuss our financial outlook and goals. We are rebasing our long-term EPS growth guidance of 5% to 7%off the midpoint of our 2024 guidance range of $4.60 to $4.80 per share. While our financial plan supports this growth rate for the long term, our goal is to work toward a more consistent and timely cost recovery profile. We have already made solid progress toward reducing regulatory lag with the commission approving the system reliability benefit surcharge.

While this mechanism will enable more timely cost recovery for utility-owned generation, we must first develop these projects before the mechanism begins recovering costs. Therefore, this mechanism has the potential to create strong value in the future, but we must first work through the natural development cycle and get projects in service. In addition, the commission has reiterated its policy on settlements which may streamline future rate case filings while creating even more collaboration between parties. Finally, we will engage with regulators to holistically address regulatory lag through the newly created docket and commit our cadence of future rate cases to ensure we are recovering our material costs. We are allocating $6 billion for investment through 2026, contributing to a 14% increase in our capital investment profile compared to this time last year.

This plan incorporates additional capital investment in generation that will qualify for the new SRB mechanism. In addition, an increasing portion of our capital plan is directed towards bolster in our FERC jurisdictional transmission infrastructure. Average annual spend is now more than double what it was as recently as five years ago. We have designed a well balanced capital allocation strategy that optimizes our ability to receive timely recovery for investments while providing reliable service across our rapidly growing service territory. Importantly, the SRB will expand our capacities of self-build generation to meet customer needs while reducing lag. Projects that meet the requirements of the all-source RFP and compete from a cost and reliability perspective would qualify for recovery through the SRB.

We expect approved projects to be included in rates within approximately 180 days of in-service, significantly shortening the time between investment and recovery on those assets compared to a traditional rate case. Recovery will be at the prevailing weighted average cost of capital less 100 basis points until a future rate case. This discount will provide customers an immediate benefit while achieving rate gradualism and reducing lag. We have highlighted five potential near-term opportunities to secure project cost recovery through the SRB with final outcomes dependent on ongoing procurement processes. Additional opportunities are also expected to arise based on future RFP outcomes and projects aligning with this mechanism. The expansion of our capital investment plan is poised to drive substantial rate based growth.

Consequently, we are revising our rate based growth guidance to an annual CAGR of 6% to 8%. In addition, with the adoption of the SRB, we now expect an increase in tracked capital, which will reduce regulatory lag in the future. By increasing our transmission spend and generation investment that qualifies for the SRB, we expect a double the amount of tracked capital which will improve our ability to receive timely cost recovery and reduce the amount to be recovered in future rate cases. To fortify our capital structure and support our robust capital expenditure plan, we are planning to issue a mix of debt and equity securities over the 2024 through 2026 period. Our principal goal is to have a healthy capital structure at the utility with no less than 50% equity.

We have noted since 2021 the need for up to 500 million of equity to support a balanced utility capital structure. You’ll recall this was deferred over the past two plus years as we sought to inflate shareholders as we work to improve the regulatory environment in Arizona. The capital structure need has grown by an additional 100 million to 200 million over that time and will be required to true up our equity ratio. At the same time, our CapEx profile has grown by almost 15%, nearly $1 billion over a four-year window. While we will pursue a blend of financing solutions across APS and Pinnacle West to address our investment objectives, sources of incremental capital may include up to $400 million of additional equity or equity-length securities over the period, size to approximately 40% of this incremental CapEx. The financing options for this incremental CapEx may potentially include at the market issuances, but we will continue to evaluate alternatives to common equity.

As we advance into 2024, our dedication to cost management continues to guide our operations. Core O&M is declining year-over-year despite continued inflation, which supports our long-term goal of reduced O&M per megawatt hour. Notably, planned major outages are scheduled for four corners in a five, Redhawk and West Phoenix, with refilling outages at Palo Verde, marking a critical phase in our maintenance strategy. The four corners outage at Unit 5 specifically is the last major planned outage at the unit before its retirement, with the last major planned outage at Unit 4 scheduled for spring of 2025. Despite these necessary planned outages, our commitment to operational efficiency and lean practices remains intact for the long term. Our goal of declining O&M per megawatt hour is strongly established and underscores our effective cost management with rapid growth in our service territory.

The second chart on this slide highlights our success in maintaining O&M cost increases below the rate of inflation since 2017, outperforming both national CPI trends and more specifically, local inflation rates in Phoenix. This achievement is a testament to our unwavering focus on optimizing operations and fostering a culture of efficiency across our organization. We continue to provide an attractive dividend yield as part of our total shareholder return and maintain a goal of managing our payout ratio into a sustained range of 65% to 75% in the future. With a solid track record of annual dividend growth, we understand the importance of returning value to our investors. We are committed to working diligently to ensure our dividend remains competitive.

Turning to our credit ratings, following our recent rate case resolution and other developments in the Arizona regulatory climate, we are working with the rating agencies as they evaluate our credit. Healthy investment grade credit ratings are pivotal to our financial profile as they contribute to reducing borrowing costs, thereby directly benefiting our customers through more favorable financial conditions. We are adjusting our FFO/debt target range to 14% to 16% to properly balance the financing needs of the company and solid credit metrics. Our balance sheet remains strong, reinforcing our financial foundation. This balance sheet strength provides us flexibility to navigate the current interest rate environment and strategically address our near-term maturities as well as ongoing and future investment needs.

Looking back at the last few years and the strides we’ve made, we are enthusiastic about our future and the potential of the company. Overcoming the setbacks of the prior rate case, we achieved the goal set forth during the preceding two years and we’ve aligned closely with the commission and stakeholders to secure a constructive outcome in this rate case. While challenges such as regulatory lag persist, our commitment to seek collaborative solutions with stakeholders, ACC staff, and the commission remains firm. Our dedication to keeping customer costs affordable is evident through our efficient O&M practices seeking to ensure that rates and costs stay below inflation during this period of unprecedented growth in our service territory. With a more constructive regulatory environment and a continued focus on affordability, we look forward to approaching the future with a clear vision and optimism for our customers and investors.

This concludes our prepared remarks. I’ll now turn the call back over to the operator for questions.

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Q&A Session

Operator: Certainly. Everyone at this time will be conducting a question and answer session. [Operator Instructions] Your first question is coming from Shar Pourreza from Guggenheim Partners. Your line is live/

Unidentified Analyst: Good morning, guys. It’s James Howard [ph] on here for Shar.

Jeff Guldner: Hey, how are you?

Andrew Cooper: Hi, James.

Unidentified Analyst: Hey, so just a couple of quick questions here. After your upcoming presumably ’24 equity issuance, what would you expect your typical funding cadence to look like? And obviously, over the next couple years, we’re kind of going forward beyond that. It’s been a special situation waiting for the ROE to come back up in this last rate case. So we just want to get a sense, especially now that you have the SRB and as rate-based growth is picking up. You mentioned both ATM and hybrids. How would you characterize your preference between implementing a regular ATM, annual ATM, and then continuing to space out equity issuances?

Jeff Guldner: Sure, James. Thanks for the question. Fundamentally, if you think about the financing plan, you have the equity need that we’ve identified, which we’ve talked about for a long time. It’s up to $500 million. And we’ve now true that up to an additional 100 to 200 that we need, to make sure that the equity ratio at the utility is strong. And at 51.9% equity ratio that was approved in the most recent rate case is a good example of a solid consistent with the market type equity ratio. And so that’s kind of that need, and I think what you’re focused on is what is the cadence for some of the — that up to $400 million that I mentioned earlier to support future CapEx. And really, the way we think about it is what is the structure or type of issuance that would allow us to meet the needs of that CapEx as it’s incurred.

And certainly, an ATM program is one option that would allow us to draw equity periodically and have proceeds that match up with our capital. The capital need is relatively consistent across the period. And I just want to be clear that up to $400 million that is future capital spending as you work through the next three years of our plan. And so, we’re very flexible in terms of thinking about what the options available are to us, whether an ATM or some sort of equity like security. We’ll look at all those options. We don’t have a strong preference. I think we want to make clear that as we think about our capital structure, we think about our CapEx plan, something that has a — there will be external financing needs for the company to support that CapEx. And they could include equity type products.

I think we’ll continue to evaluate over the next few years what product matches up best and what market is most available to us. But I do cite the ATM as an example because of the way it allows that periodicity to match up against CapEx, which is ultimately what we’re solving for over the longer term, both from the increases in transmission spend on the FERC side and then generation spend that we expect would be eligible for SRB.

Unidentified Analyst: Got it. Thank you for that. That makes a lot of sense. The second question last time I had is turning to your SRB, how should we think about the 42% figure you call out on slide 25? This is just a high-level question. Is that just projects which could potentially be eligible for the SRB if you were to win them in an all-source RFP? Or are you expressing any sort of probability of these projects ending up in plan?

Andrew Cooper: Yes. So the projects that we’ve listed out are examples of the opportunities when you think about we’re currently in our 2023 RFP where we ask for all-source resources. And so the five projects listed there cover that span of time. And we’re still negotiating with third-party developers around PPAs. These projects are still in that very early stage of development. They are examples of the potential that we have within the existing window that we’re in for this RFP. There will be future RFPs and future time spans that match up. But one of the things that we wanted to emphasize here is that for a long time we’ve been talking about feeling hamstrung for bringing competitive projects forward because of capital limitations and uncertainty around recovery.

With the SRB, you have here a list of opportunities that demonstrate that that 10% to 15% of megawatts that we’ve been developing historically has that upside into a range much closer to kind of that 35% to 50%that we thought was potential based on looking at our own pipeline. So within the window of the existing RFP and the time period we’re talking about, you take the megawatts that we expect need to be built from a utility-scale perspective over that window and what megawatts are available to us as potential opportunities. That’s the 42%you see there. Will all these projects be built? We’re still in that development timeline. We’ll make that determination as we go along. The CapEx in our three-year plan that we believe is probable includes generation capital related to potential SRB projects, but we’re not breaking that capital out granularly.

But the 42% is representative of that upside opportunity relative to our prior view of our investment profile on the generation side.

Jeff Guldner: And James, its Jeff, as you know, it’s still very specific on the negotiations of the individual projects. And there’s really two things we’ll be trying to capture with these SRB projects. One is the benefit, long-term benefit to customers that would be better than if you just did a PPA. And then the second is, as was mentioned at the hearing, from a reliability standpoint, when we build the projects, they come in on time. So when we have a critical need for a summer and we’re developing the project, we’ve been good at getting those in timely and you have more risk when you have a PPA and somebody can slide the in-service date. And sometimes that makes it self-optimal. But it’s a pretty project-specific analysis that you’ll have to go. So I think just showing representative projects was what we were trying to get across here, but the details will matter and those will come up in the negotiations with these projects.

Unidentified Analyst: Perfect. Thank you. That’s exactly what we were looking for in terms of an answer. It looked like an opportunity set to us, but we had a few inbounds and people were asking us to clarify. And so we did. Thank you so much. That’s all we have.

Jeff Guldner: Thanks, James.

Unidentified Analyst: Appreciate it.

Operator: Thank you. Your next question is coming from Nick Campanella from Barclays. Your line is live.

Nick Campanella: Hey, good morning, everyone. Thanks for taking my question.

Jeff Guldner: Yes. Hi, Nick.

Nick Campanella: Hey. So I guess it’s good to see the ACC is kind of heading in the right direction here, especially acknowledging the capital investments you’re putting in and working on the earned ROI lag. I guess just how would you kind of characterize under-earning this year, just as a on maybe that ACC rate base from a percentage basis and how much do you think you can kind of get back in the upcoming rate case filing versus what could be addressed in the ROI lag docket? Thank you.

Jeff Guldner: Let me, I’ll start, Nick. And, you know, the challenge with this case in particular was that we came into it with a very inflationary environment that we haven’t seen before. So you had a lot of the kind of lag that, you know, flat interest rate environment you don’t necessarily see as pronounced. I think probably the biggest one that Coop mentioned in the narrative was the interest cost, because we’re actually lowering the embedded interest cost in this case that just was decided, but our interest costs are significantly higher. And so those are hopefully the things that will get picked up in the regulatory lag docket. And so structurally, I think it’s kind of open right now as to seeing what they want to focus on.

It’s good, again, that they’re actually focused on this as a real issue, that if you’re in a historical test year jurisdiction like Arizona and you don’t have trackers or other things to pick up some of that regulatory lag, and particularly when you get into an environment like we’re in now with the higher inflationary pressures, you can really come out of a case with some significant baked-in lag, which then actually then means when you come in for your next case, you’ve got a higher ask because you’re not getting the right gradualism as you pick it up. And so Coop, if you want to maybe talk, we do what we can to mitigate it. There’s some structural stuff that you just can’t do, and you have to come in with a subsequent case, and then hopefully this regulatory lag docket gives us some visibility on mechanisms or structures that you can use that mitigate it.

Andrew Cooper: Yes, Nick, we haven’t quantified the lag because it varies year-to-year, but the drivers that you should think about, and Jeff mentioned one in the context of interest expense, that’s certainly one we have a 3.85% embedded cost to debt in this case, but the two debt issuances we’ve done since the case are in the mid 5% range to the low 6% range. So substantially above it, we knew going into the case, we really wanted to focus on getting the ROE back up to the right level. We had a good equity capital structure, and so in terms of the elements of WACC, the cost of debt was one that we de-emphasized in this case. It created a lower revenue requirement, but we do need to recoup that to be more representative of forward financing costs.

O&M is the other one where if you think about the test year, we were in a period of mid 2021 to mid 2022 as our test year. I like to say it was during the time where the Fed was still talking about inflation as transitory, but if you look at it relative to our 2024 O&M guidance, you’re talking about somewhere in the neighborhood of $100 million of incremental O&M, and that’s what’s a really good from our perspective O&M story, where year-over-year, we are bringing O&M down despite having a full year of higher wages at some of our business units and on a — that’s on a core basis. And even with the higher amount of planned outages given the four corners outage, you’re still talking about a less than 2% O&M increase to the midpoint of our guidance range.

So a good story, but a lot of historical O&M to catch up on. Pension, which we’ve talked about in the past, fortunately is not a story. If you look at the guidance walk to 2024, no further impacts from pension. In fact, it’s a penny positive on the non-service credit side, but we are carrying with us the 2022 market impacts of the impacts to our pension asset, as well as the substantial changing discount rates year-over-year. And so we’ll need to recoup that as well. And then the final one and you’ll see that again in our walk this year, increases in depreciation related to plan going to service. A great story from this rate case, that’s the one area where we got 12 months to post-year plan plus one major project that fell outside that 12-month window.

But our 2024 projects include some IT investments, which have a shorter depreciation life and will contribute further to that lag. So, we’re excited to get into the opportunity to have a dialogue with the commission and stakeholders about these issues. And of course, we’ll continue to look at the cadence of future rate cases to address them as well.

Nicks Campanella: Thanks for laying all that out there, really appreciated. I guess Andrew, just on this five to seven growth rate, I think in the past, it’s been tough to kind of extrapolate that linearly off of the base year just because of the rate filing cadence. Can you just kind of give us a flavor of how you’re thinking about it? I guess you’d have new rates in mid-’25, but then as you get past that, you start to ramp this SRB capital potentially, you have some of the first transmission opportunities you highlighted. So, do you kind of start to grow linearly in ’26 and beyond or how do you kind of think about that? Thanks.

Andrew Cooper: Yes, it’s a really great question, Nick, because we have the investment profile. We have fortunately the customer rate headroom. The IRA is a TBD. We’ll see where that goes. But we really have the profile to grow that 5% to 7% over the long term. And much of the conversation we’ve been having here has been about the regulatory lag kind of embedded in a historical test year. And so, if we could address that and go into a more stable price environment, we certainly have the opportunity to create more smooth cost recovery. Over the medium term, the SRB is a significant contributor to that, because you basically double the amount of tract capital that you have that are going through some form of adjuster mechanisms.

So, between the transmission spend and the SRB eligible generation spend, you’re having a much smoother pace of recovery, where your customer, your sales growth is supporting any O&M increases and supporting the needs of a growing distribution system, and then your transmission and generation spend is tracked. So, we view our ability, once we’ve caught up on these historical lagging costs, to be in a place where that cost recovery profile can smooth. We see the past to 5% to 7% either way, but it is really addressing some of these near-term pinch points that come out in the last few years of inflation that we need to address to get to the other side of that. Between the SRB and sales growth, because as you look at the long-term sales growth, not only is it providing some top line, but it’s also, as I mentioned earlier, blunting some of the O&M and ensuring that we create operating leverage out of those increased sales.

Nicholas Campanella: Thanks for that. I appreciate the time.

Jeff Guldner: Thanks, Nick.

Operator: Thank you. Your next question is coming from Michael Lonegan from Evercore ISI. Your line is live.

Michael Lonegan: Hi, good morning. Thanks for taking my question. So, you’ve talked about your equity issuance plan, balancing your capital and intended to balance your capital structure to greater than 50% equity at the APS level. Obviously, you lowered your FFO to debt target to 14% and 16%. Just wondering if ideally, you know, more specifically, if you’re looking to target as high as 52%equity at APS, the structure to match the rate case outcome, and then where you anticipate lending, you know, on FFO to debt metric this year and over your plan?

Andrew Cooper: Yes, Michael, I think there’s two pieces to the equity capital structure story. One is, we never want to fall too far behind, because the equity ratio has been an issue that, through the last two rate case cycles, for example, with nearly a 55% in 2019 and then nearly 52%in this most recent rate case, it’s been an issue that’s largely not been one that has been subject to a lot of debate. It’s the actual capital structure at the end of the historical test year. And we think that a balanced capital structure, a little bit more than 50%equity at the utility is an appropriate one. It’s consistent with national averages. As I mentioned earlier in my remarks, the 51.9%that we got in the last rate case is a solid capital structure.

It is consistent with where averages are around the country. And while in any given year, we want to make sure that we’re trying to stay above 50 so we’re not in a catch-up situation. We are going to look at any time period, what does the overall WACC look like? What’s the right rate, question from going into a rate case, and want to make sure that the WACC overall is one that’s affordable to customers. So it’s really a balance, that equity that we talked about earlier, the up to 500, which now needs to be true up a little bit higher. If you look at our 10-K and you calculate the APS equity ratio, it’s below 50%. And so, this is the capital that we believe we need to get to the right spot going forward. This is all balanced with credit metrics.

The 14% to 16% you mentioned is an opportunity for us to balance the needs of our capital investment plan and having solid investment credit ratings. We’re still in conversations with the rating agencies as they’ve been watching the regulatory environment over the last two years and expect to continue to work with them to, you know, clarify where they’re coming out now that the rate case is complete.

Michael Lonegan: Great, thank you. And then secondly, for me, regarding your sales growth forecast through 2026, you’re guiding a 4% to 6% through that 26 period versus 2% to 4%this year. Obviously, you’re expecting large C&I customers to come online. Just wondering how we should think about sales growth in ’25 and specifically and also in ’26 when we see the spike or is it consistent in those two years?

Andrew Cooper: Yes. And we haven’t been granular between the two because as we’ve seen over the last two years and we conservatively forecast our sales growth. And I think we learned a lot last year in terms of the ramp rate of some of these larger high-low factor customers, both on the advanced manufacturing side and the data centers. And so, we forecast conservatively and there can be some variability in true year as far as you’ve got a data center box. And if you’ve got an anchor in there and you can keep building it out, that happens over time. And so for these large customers, we’re not sharing a granular view between ’25 and ’26. I would say that, you know, a Taiwan semiconductor, which is one of the larger new customers that we have coming in, and they’re committed to full ramp up of their first fab in the first half of 2025.

And the ecosystem of other companies that surrounds them is part of that sales growth rate. And so their timing, reaching that full production and then having a full year impact of that in 2026 kind of gets you to the terminal year there of the growth rate range. It doesn’t give you an answer to your question on ’25 versus ’26 exactly. But the trends that we watch are fundamentally the ramp rates of each of these customers and our team is having regular conversations with each of them and has a pretty close pulse on what their ramp looks like.

Michael Lonegan: Great. Thanks, Andrew.

Operator: Thank you. Your next question is coming from Paul Patterson from Glenrock. Your line is live.

Paul Patterson: Hey, good morning.

Jeff Guldner: Hey, Paul.

Paul Patterson: Just really quick sort of from bookkeeping questions. I apologize if I miss this. What’s the timing of your next rate case? Do you guys expect to file it?

Jeff Guldner: Yes, Paul, we haven’t have not picked the timing for that. The regulatory lag docket is starting on March 19th. And so that’s going to be the first workshop. I expect the commission is going to engage probably most of this year in conversations around that docket. And I think consistent with what we had kind of shared at EEI, we’d want to see how that docket’s evolving and make sure that if there’s opportunities to have a better structure in terms of a different process that picks up regulatory lag, you would want to wait until you see how that docket plays out. So we have to balance that continuing to watch with the progress on that within just the regulatory lag that Andrew has talked about earlier.

Paul Patterson: Okay. You anticipated my next question, which to follow-up on that, when do you think you said you expected to be engaged with it this year? Always hard to sort of predict when a docket like that would be resolved. But do you have any sense? I know it’s really early, but I’m just curious. Do you have any idea when that — when you think that might be — we might get a conclusion or at least a better idea about where they’re headed on that?

Jeff Guldner: Yes, I think if you watch probably the initial dockets, I’m guessing they’re probably going to have some conversation around the timing that they look for that. I would not be surprised, particularly because I think the start of this docket waited until all the utilities were through their rate cases. So we had a TEP case, a UNS case. And so I think they’re just waiting for our case to get cleared before opening this generic docket up and looking at the utilities. And given the focus that I think the commission has indicated around dealing with regulatory lag, I would not be surprised if you got a pretty good progress throughout this year. And that the idea would be done in 2025 and beyond if there’s a clarity in terms of a process or an approach to take that that’s when you start seeing utilities begin to adapt the recommendations or whatever comes out of the docket. But you got to watch early on and just see how it begins to develop.