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Operator: Good morning, everyone, and welcome to the CMS Energy 2022 Year End Results Call. The earnings news release issued earlier today and the presentation used in this webcast are available on CMS Energy’s website in the Investor Relations section. This call is being recorded. After the presentation, we will conduct a question-and-answer session. Instructions will be provided at that time. Just a reminder, there’ll be a rebroadcast of this conference call today beginning at 12 PM Eastern Time running through February 9th. This presentation is also being webcast and is available on CMS Energy’s website in the Investor Relations section. At this time, I would like to turn the call over to Mr. Sri Maddipati, Treasurer and Vice President of Investor Relations and Finance.

Sri Maddipati: Thank you, Adam. Good morning, everyone, and thank you for joining us today. With me are, Garrick Rochow, President and Chief Executive Officer; and Rejji Hayes, Executive Vice President and Chief Financial Officer. This presentation contains forward-looking statements, which are subject to risks and uncertainties. Please refer to our SEC filings for more information regarding the risks and other factors that could cause our actual results to differ materially. This presentation also includes non-GAAP measures. Reconciliations of these measures to the most directly comparable GAAP measures are included in the appendix and posted on our website. Now, I’ll turn the call over to Garrick.

Garrick Rochow: Thank you, Sri, and thank you everyone for joining us today. 2022, an outstanding year at CMS Energy, both operationally and financially. And even more than that, 2022 marks the 20th year CMS Energy has consistently delivered industry-leading financial performance. Many of you have been on this journey with us. And I appreciate you and I thank you. You see us put our words into action. Our performance is supported by our simple investment thesis, which delivers for our customers and investors. We continue to lead the clean energy transformation. Our net zero commitments backed up by the solid plans in approved Integrated Resource Plan, IRP, provide certainty for investments in clean energy and highlight the supportive regulatory construct in Michigan.

Across the company, we are disciplined about taking cost out and working every day to get better. We use the CE Way from corporate functions to the frontline to achieve our operational and financial objectives. This focus keeps customer bills affordable. On the regulatory front, it’s been an incredible year. We sold not one, not two, but three major cases highlighting the top-tier regulatory backdrop in Michigan. All of this leads to a premium total shareholder return you’ve come to expect from CMS Energy. I want to take a few minutes to share some of the big wins we had over the year. First, our commitment to people, our co-workers, who show up every day with the heart of service, and our customers who count on us to be there in any weather with safe, reliable, affordable and clean energy.

In 2022, we were recognized nationwide as the Best Employer for Women in the Utility Sector, a Top Employer for Diversity and one of the Best Large Employers by Forbes, this team of co-workers, who continue to deliver results, utilizing the CE Way. In 2022, our co-workers commitment to being best-in-class in the operation of our generating assets saved our customers roughly $560 million. This is more than double what we delivered in 2021 mean our team continues to drive more value by running our own generation, more efficiently than the market. Just to make this real, in December, during the storm Elliott, when others were short power, this team and these generation assets were exporting energy out of Michigan into MISO. And I’m also pleased with the growth in economic development we’ve seen and helped lead in the state.

As I shared in the Q3 call semiconductors, polysilicon and battery manufacturing, up all calling Michigan Home, 230 MW of new and expanding load with over $8 billion of investment in Michigan. A recent Department of Energy study ranks Michigan as a Top 3 state for planned battery plant capacity further differentiating our state and service territory. Our commitment across the state have delivered more load growth, more jobs and more investment, all of which create an environment. And our state looks strong well into the future. We remain focused on getting ready for that future with our IRP, which delivers even more savings to our customers with roughly $600 million in savings over our prior plan and reduces our carbon footprint by over 60% as we exit coal in 2025 amid 8 gigawatts of store and 550 megawatts of battery through 2040.

We continued our long track record of managing costs and keeping prices affordable through the CE Way, and delivering $58 million of savings in 2022. This level of discipline to continuously improve has been a contributor to the successful regulatory outcomes in our settled electric and gas rate cases, which is highlighted by the $47 million of regulatory mechanisms to support infrastructure investments and assist customers. This year both our customers and investors will benefit from our $22 million voluntary refund mechanism, a $15 million bill credit and $10 million of customer assistance. These regulatory mechanisms de-risk 2023, while providing needed customer benefit. It’s this strong execution in these results that you and we expect and meet our commitment to the triple bottom-line positioning our business for sustainable long-term growth.

2022 marks another year of premium growth. The team continued to deliver regardless of conditions. In 2022, we delivered adjusted earnings per share of $2.89 at the high-end of our guidance range. I’m also pleased to share that we are raising our 2023 adjusted full-year EPS guidance to $3.06 to $3.12 from $3.05 to $3.11 per share, compounding off of 2022 actuals like you would expect from a premium name like CMS Energy. We continue to expect to be toward the high-end of this range, which points to the midpoint or higher signaling are confident as we start the year in a strong position. Furthermore, the CMS Energy Board of Directors recently approved a dividend increase to $1.95 per share for 2023. Longer-term, we continue to have confidence toward the high-end of our adjusted EPS growth range of 6% to 8%, and we continue to see long-term dividend growth of 6% to 8% with a targeted payout ratio of about 60% over time.

And finally, I’m pleased to share we have refreshed our five-year utility customer investment plan, increasing our prior plan by $1.2 billion to $15.5 billion through 2027. I have confidence in our plan for 2023 and beyond given our longstanding ability to manage the work and consistently deliver industry-leading growth. It’s no coincidence that I started my prepared remarks with our investment thesis. We live by it and it works. On Slide 6, we’ve highlighted our new five-year $15.5 billion utility customer investment plan. This translates to greater than 7% annual rate base growth in support safety and reliability investments in our electric and gas systems and paves the way to a clean-energy future when net zero carbon, methane and greenhouse gas emissions.

You will note that about 40% of our customer investments support renewable generation, grid modernization and maintenance service replacements on our gas system, which are critical as we lead the clean energy transformation. Bottom line, we have a long and robust capital runway. Beyond our core investments, we have growth drivers outside of traditional rate base. This includes adders built into legislation where incentives on our energy efficiency and demand response programs and the financial compensation mechanism, FCM we earn on PPAs. We also expect incremental earnings provided by our non-utility business NorthStar Clean Energy as they see continued growth in their contracted renewables, as well as better pricing from capacity and energy sold at our DIG facility.

We continue to earn a 10.7% ROE on renewables to meet our renewable portfolio standard and are in the process of completing Heartland Wind Project in 2023. These regulatory incentives are a core part of Michigan’s energy law which with our strong regulatory construct continues to support needed customer investments. In addition, the Energy Law provides certainty of recovery before looking 10-month rate cases in regular fuel tracking mechanisms and allow us to help smooth the impact of commodity prices for our customers. I used the word incredible to describe this earlier. We delivered across the board the settlements in IRP and our gas and electric rate cases providing more certainty for 2023 customer investments. This wasn’t by accident. We have a supportive law, strong regulatory construct and our improved regulatory approach enables us to work with multiple parties on complex cases and provide the best outcome for our customers and investors.

And we plan to continue the strong performance in the next rate case cycle. We filed our gas case in December and we file our next electric rate case later this year with those outcomes providing further certainty for 2024 customer investments. We know a robust customer investment plan in strong regulatory construct loan do not support sustainable growth. Our customers count on us to keep their bills affordable. Inflation has been top of mind for many throughout 2022 and remains so as we enter 2023. First, I’ll remind everyone that CMS Energy is well positioned as it relates to the key sources of inflation including labor, materials and commodities. In addition, we delivered roughly $150 million in CE Way savings over the last three years and estimate over $200 million in large, episodic savings as PPAs expire and as we exit coal generation.

We’re also seeing significant new and expanding commercial and industrial load in our service territory. There is a broad spectrum of growth. Some customers have opened new facilities this year and some are in early construction. These new sales opportunities, both in the short and long-term, allow us to spread our costs across a growing customer base, ultimately reducing rates for all of our customers. It should be no surprised why I’m pleased with 2022, and confident in the 2023 outlook. This proven approach continues to deliver. Now I’ll pass the call over to Rejji, who will offer additional detail.

Rejji Hayes: Thank you, Garrick, and good morning, everyone. As Garrick highlighted, we delivered strong financial performance in 2022 with adjusted net income of $838 million, which translates to $2.89 per share at the high end of our guidance range. The key drivers of our full year 2022 financial performance were higher sales, driven by favorable weather and solid commercial and industrial load. The latter of which is indicative of the attractive economic conditions in our service territory and rate relief net of investments. These positive drivers were partially offset by higher expenses attributable to discrete customer initiatives, which reduce bills, support our most vulnerable customers and improve the safety and reliability of our gas and electric systems.

Our strong performance in 2022 provided significant financial flexibility at year end, which, as Garrick highlighted, enabled us to de-risk our 2023 financial plan to the benefit of customers and investors, which I’ll cover in more detail later. To elaborate on the strength of our financial performance in 2022, on Slide 10, you’ll note that we met or exceeded the vast majority of our key financial objectives for the year. From an EPS perspective, our consistent performance above plan over the course of 2022, enabled us to raise and narrow our 2022 adjusted EPS guidance on our third quarter call. From a financing perspective, we successfully settled $55 million of equity forward contracts as planned and more notably opportunistically priced approximately $440 million of equity forward contracts at a weighted-average price of over $68 per share.

To address the parent company’s financing need for the pending acquisition of the Covert natural gas generation facility in support of our IRP. The only financial target missed in 2022 was related to our customer investment plan at the utility, which was budgeted for $2.6 billion. We ended the year just shy of that at $2.5 billion, primarily due to the timing of a wind project in support of Michigan’s renewable portfolio standard, which was largely pushed into 2023, and is now under construction. Moving to our 2023 EPS guidance on Slide 11, as Garrick noted. We are raising our 2023 adjusted earnings guidance to $3.06 to $3.12 per share from $3.05 to $3.11 per share with continued confidence toward the high end of the range. As you can see in the segment details, our EPS growth will primarily be driven by the utility as it has for the past several years and we also assume modest growth for non-utility business NorthStar Clean Energy.

Finally, we plan for limited activity at the plant given the lack of financing needs in 2023, beyond the settlement of the aforementioned equity forward contracts for the Covert acquisition, while maintaining the usual conservative assumptions throughout the business. To elaborate on the glide path to achieve our 2023 adjusted EPS guidance range, as you’ll note on the waterfall chart on Slide 12, we’ll plan for normal weather, which in this case, amounts to $0.20 per share of negative year-over-year variance, given the absence of the favorable weather we saw in 2022. Additionally, we anticipate $0.14 of EPS pickup attributable to the rate – attributable to rate relief, largely driven by our recent electric and gas rate orders and the expectation of a constructive outcome in our pending gas rate case later this year.

As always, our rate relief, figures are stated net of investment-related costs such as depreciation, property taxes and utility interest expense. As we turn to our cost structure in 2023, you’ll note $0.04 per share of positive variance attributable to continued productivity, driven by the CE Way and other cost reduction initiatives underway. Lastly, in the penultimate bar on the right hand side, we’re assuming the usual conservative estimates around weather-normalized sales and non-utility performance coupled with the benefits of the significant reinvestment activity deployed in the fourth quarter of 2022 through a regulatory filings and traditional operational pull ahead. These assumptions equates to $0.19 to $0.25 of positive variance versus 2022.

As always, we’ll adapt to changing conditions throughout the year to mitigate risks and deliver our operational and financial objectives to the benefit of customers and investors. On Slide 13, we have a summary of our near and long-term financial objectives. To avoid being repetitive, I’ll limit my remarks to the metrics we have not yet covered. From a balance sheet perspective, we continue to target solid investment grade credit ratings and we’ll continue to manage our key credit metrics accordingly. To that end, we’ll look to settle the equity forward contracts for the Covert financing in the second quarter of 2023 and have no additional planned equity financing need until 2025. In the outer years of our plan, we intend to resume our At The Market or ATM equity issuance program in the amount of up to $350 million per year in 2025 through 2027, given the substantial increase in our five-year utility customer investment plan.

And as such, you can expect us to file a – perspective supplement to reflect this revision to our ATM program later this year. Slide 14 offers more specificity on the balance of our funding needs in 2023, which are limited to debt issuances at the utility, a good portion of which has been priced and or refunded over the past several weeks as noted on the page. In fact, the $825 million of utility bond financings address to date include the $400 million tranche of debt financing required to fund the acquisition of Covert in the second quarter. So we have fully de-risked our financing needs for that critical component of our IRP well in advance with attractive terms to the benefit of customers and investors, which I’ll cover in more detail later.

To elaborate on the strength of our financial performance in 2022 on Slide 10, you’ll note that we met or exceeded the vast majority of our key financial objectives for the year. From an EPS perspective, our consistent performance above plan over the course of 2022, enable us to raise and narrow our 2022 adjusted EPS guidance on our third quarter call. From a financing perspective, we successfully settled $55 million of equity forward contracts as planned and more notably, opportunistically priced approximately $440 million of equity forward contracts at a weighted average price of over $6 to $8 per share to address the parent company’s financing needs for the pending acquisition of the covert natural gas generation facility in support of our IRP.

The only financial target missed in 2022 was related to our customer investment plan at the utility which was budgeted for $2.6 billion. We ended the year just shy of that at $2.5 billion, primarily due to the timing of a wind project in support of Michigan’s renewable portfolio standard, which was largely pushed into 2023 and is now under construction. Moving to our 2023 EPS guidance on Slide 11. As Garrick noted, we are raising our 2023 adjusted earnings guidance to $3.06 to $3.12 per share from $3.05 to $3.11 per share with continued confidence toward the high end of the range. As you can see in the segment details, our EPS growth will primarily be driven by the utility as it has for the past several years, and we also assume modest growth for our nonutility business, North Star Clean Energy.

Finally, we plan for limited activity at the parent given the lack of financing needs in 2023 beyond the settlement of the aforementioned equity forward contract for the Covert acquisition, while maintaining the usual conservative assumptions throughout the business. To elaborate on the glide path to achieve our 2023 adjusted EPS guidance range, as you’ll note on the waterfall chart on Slide 12, we’ll plan for normal weather, which in this case amounts to $0.20 per share of negative year-over-year variance, given the absence of the favorable weather we saw in 2022. Additionally, we anticipate $0.14 of EPS pickup attributable to rate relief, largely driven by our recent electric and gas rate orders and the expectation of a constructive outcome in our pending gas rate case later this year.

As always, our rate relief figures are stated net investment-related costs such as depreciation, property taxes and utility interest expense. As we turn to our cost structure in 2023, you’ll note $0.04 per share of positive variance attributable to continued productivity driven by the CE Way and other cost reduction initiatives underway. Lastly, the ultimate bar on the right-hand side were stemming the usual conservative estimates around weather-normalized sales and nonutility performance, coupled with the benefits of the significant reinvestment activity deployed in the fourth quarter of 2022 through our regulatory filings and traditional operational pull ahead. These assumptions equate to $0.19 to $0.25 of positive variance versus 2022. As always, we’ll adapt to changing conditions throughout the year to mitigate risks and deliver our operational and financial objectives to the benefit of customers and investors.

On Slide 13, we have a summary of our near- and long-term financial objectives. To avoid being repetitive, I’ll limit the metrics we have not yet covered. From a balance sheet perspective, we continue to target solid investment-grade credit ratings, and we’ll continue to manage our key credit metrics accordingly. To that end, we’ll look to settle the equity forward contracts for the Covert financing in the second quarter of 2023 and have no additional planned equity financing needs until 2025. In the outer years of our plan, we intend to resume our at-the-market, or ATM, equity issuance program in the amount of up to $350 million per year in 2025 through 2027 and given the substantial increase in our 5-year utility customer investment plan.

And as such, you can expect us to file a prospectus supplement to reflect this revision to our ATM program later this year. Slide 14 offers more specificity on the balance of our funding needs in 2023, which are limited to debt issuances at the utility a good portion of which has been priced and/or funded over the past several weeks as noted on the page. In fact, the $825 million of utility bond financings addressed to date include the $400 million tranche of debt financing required to fund the acquisition of Covert in the second quarter. So we have fully derisked our financing needs for that critical component of our IRP well in advance with attractive terms to the benefit of customers and investors. And as a reminder, the acquisition of the Covert natural gas facility will enable us to exit coal generation in 2025 and which makes us one of the first vertically integrated utilities in the country to do so.

To conclude my remarks on Slide 15, we’ve refreshed our sensitivity analysis on key variables for your modeling assumptions. As you’ll note, with reasonable planning assumptions and our track record of risk mitigation, the probability of large variances from our plan is minimized. Our model has served and will continue to serve all stakeholders well. Our customers receive safe, reliable and clean energy at affordable prices. Our diverse workforce remains engaged, well-trained and in our purpose-driven organization, and our investors benefit from consistent industry-leading financial performance. And with that, I’ll hand it back to Garrick for his final remarks before the Q&A session.

Garrick Rochow: Thank you, Rejji. Our simple investment thesis is how we run our business and has withstood the test of time. It delivers in a very balanced way for all our stakeholders and enables us to consistently deliver our financial objectives. 2022 was an outstanding year, marking our 20th year of industry-leading financial performance. I’m confident in our refresh $15.5 billion utility customer investment plan, the ability to execute on it and in our regulatory construct to support it as well as our solid track record of managing costs we keep customer bills affordable. Finally, we deliver regardless of conditions, not by luck, or accident, but by a great team who runs a proven model, who sees discipline in the work. This is what led to an outstanding 2022 and provides for a strong outlook in 2023 and beyond. With that, Adam, please open the lines for Q&A.

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Operator: Our first question comes from Shahriar Pourreza from Guggenheim Partners. Shahriar, your line is open. Please go ahead.

Shahriar Pourreza: Thanks. Good morning, guys. Good morning. So just Garrick, couple of quick questions here. The CapEx update now includes Covert. Can you maybe comment on the impacts of IRA in the plan you presented today? The Clean Energy segment went from 2.8 to 3.1. So it was kind of a fairly modest increase. Were there sort of any assumption changes around tax equity utilization? Or do you anticipate another IRP update would be needed for more fundamental changes to the Clean Energy outlook? Thanks.

Garrick Rochow: Thanks Sharh. The $15.5 billion plan, as you indicated, includes Covert and a nice tranche of renewables. And I’ll also point out from a VGP perspective, that’s that large customer renewable program. It includes the first tranche of that as well. And so happy to dive in a little bit deeper here. But remember this, that Covert and our renewables build is spelled out in our integrated resource plan. So that’s the nature of this 5-year plan, both from a renewable and the development of renewals, the Covert acquisition as well as storage and storage deployment. So that’s set. And that IRP really serves as the prudency review and then we go through the regulatory cases to recover on those. And so that plan reflects that.

Now your specific question on the IRA, that’s additional benefit for our customers. as we’ve shared, that production tax credit offers savings directly on the execution of that plan. By 2026, that’s about $60 million a year of savings for our customers. And so that IRP when we originally filed it was around $600 million or settlement, I should say, was around $600 million of savings for our customers. That only grows as a result of the production tax credit and the IRA. And so that’s the nature of how we’re applying that. I would remind you as well, based on AMT, we don’t anticipate being subject to AMT for really the remainder of the decade, the way that’s framing up. And so I don’t know, Rejji, do you want to add any additional comment to Shar’s question?

Rejji Hayes: No, I think you laid it out pretty well, Garrick. The only thing I would add, you did ask about tax equity at the utility, we’re not assuming a tax equity for financing for any of these projects.

Shahriar Pourreza: Got it. Okay. Perfect. And then just lastly, just a question on your updated guidance and sort of the embedded assumptions. You’re showing $0.04 of cost savings as a driver for ’23, but also highlighted roughly $30 million or about $0.10 of cost savings related to Kam 1 and 2 Covert retirements. What level, I guess, of cost inflation is embedded in the $0.04? Is there a headwind on labor materials? And then more importantly, how are you sort of thinking about that O&M flex beyond that $0.04? Is it closer to the $58 million you achieved in ’22?

Rejji Hayes: Yes, sure. I’ll cover most of this, and if Garrick wants to add certainly can. To answer your last question first. We’re assuming around $45 million to $50 million of cost reductions attributable to the CE Way. So that’s what we have embedded in the plan. And we’ve been pleased to observe over the last several years now that we’re at a run rate now of about $45 million, $50 million, which we hit really the pandemic, sometimes necessity is the mother of invention. And so prior to the pandemic, the run rate was about $10 million of O&M reduction. And then we had a really nice inflection point during the pandemic of about $40 million to $45 million of CE Way-driven savings, and that’s — we’ve held on to that some time.

And so that’s the working assumption embedded in the plan. I would say Kam 1 and 2, we do anticipate those savings coming through. We’ll see some of that in our power supply costs with just less coal procurement, but also, obviously, on the O&M side, there’s clearly less staffing attributable to gas plants versus coal. So you’ll see some of the savings there. And so that’s largely the inputs that we have flowing through that cost productivity line item or the $0.04 that you’re seeing in the waterfall from 2022 to 2023. Is that helpful?

Shahriar Pourreza: It is. That’s helpful, Rejji. Thank you, guys. That’s all I had. Congrats on the quarter. Appreciate it.

Operator: The next question comes from Jeremy Tonet from JPMorgan. Jeremy, please go ahead. Your line is open.

Jeremy Tonet: Hi, good morning. Just wanted to start off by digging into Dig a little bit if possible. And if I look at Slide 20 here, just wondering if you could walk us through, is this implant or is this upside plan? And just if you could elaborate a little bit, I guess, the future plan for DIG flip to the market or do Michigan customers want the asset? Just trying to see what’s happening there. What could happen there?

Garrick Rochow: I like the way you teed that up. We’re going to dig into DIG. It’s kind of like my Ferrari comment when I talk about DIG. I mean you may not know this, but the big plan itself is right across from the River Rouge plant where they make the Ford Lightning. And I just happened to get me a Ford Lightning about three weeks ago. So it performs well better than Ferrari. I’ll tell you that. So we’re going to call the Ford F-150 lightning in the garage from now going forward. But bottom line, here’s what we do at DIG. And it’s been a historical practice, which really serves us well as we layer in capacity contracts, multiyear capacity contracts and energy contracts over time. And as everyone knows, energy prices and capacity prices have been continuing to rise.

There’s that upward pressure in there. And so as we layer in these contracts, it’s provided additional benefit, additional return from that facility. And so that’s what we’re reflecting those contracts that have already been inked, you might say, for the improvement in performance. Now we anticipate that to continue to improve as we layer in additional contracts, particularly in — we’re about 50% contracted both for energy and capacity if you get out to the year ’26, ’27 in that time frame. So there’s potential for upside there. And I’ll have Rejji walk through what that upside looks like here in just a moment. But why don’t you do that, Rejji, then I’ll conclude.

Rejji Hayes: Yes. So just to go back to the page you referenced, Jeremy, Page 20 in the deck, you see these dark blue bars here at around $30 million. That’s a pretty good run rate for the economics we have locked in through capacity and energy contracts here in 2023. And then as you get to the outer years of the plan, you see these light blue sensitivities in the stacked bar chart, and that represents the opportunity if we start to see continued tightening and therefore, improved economics in the bilateral market. And so in the event we see capacity prices go to about $4.50 per kilowatt month. You can see the incremental upside here from a pretax income basis. And then if it gets closer to CONE, and I’ll remind everyone that Zone 7 is priced pretty much at CONE for 2 of the last three planning resource auctions.

You could see us at a higher level than that with about $25 million of upside. And so as Garrick noted, we wouldn’t see those economics until the out of years of the plan, but there’s some opportunity as margin opens up in sort of the ’25, ’26, ’27 time frame.

Garrick Rochow: And let me just conclude there. So there’s — that upside is not in the plan, just to be really clear about that. And to the degree there is upside I want to make sure everyone’s clear, there’s no sugar highs, right? We deliver 6% to 8%, and we have confidence toward the high end. So I just want to be clear on expectations going forward.

Jeremy Tonet: That’s very helpful there. And I just want to continue, I guess, with kind of bleed or element to the point here. And looking at the back half of the planned growth drivers outside of rate base. Can you walk us through time line for clarity on the pieces there? Just wondering if there’s conservatism on those items as we look at kind of outside of rate base growth later date?

Rejji Hayes: And just — thank you for the question, Jeremy. And just for everyone’s reference, this is the content we have on Slide 6 of the deck. And so we’ve always talked about the additional growth drivers beyond the rate base as a result of the very constructive legislation. We have in Michigan. And so there’s the energy waste reduction opportunities that we have, and we earn economic incentives on that. There’s a financial compensation mechanism that we get on PPAs that has been solidified now in two integrated resource plans. And then there is the 10.7% ROE that we get on renewable projects associated with the renewable portfolio standard of Michigan, which we’re still executing on. And then there’s additional contribution from North Star.

And so all of those offer growth to our earnings profile above and beyond what we get in the rate base. And so that 7% or so you’re seeing for rate base growth. These would be additive to that. And I would say you get steady contribution for the majority of these. Jeremy, to get to your question. And so with respect to energy waste reduction, we do expect that to increase gradually over the course of the plan. The PPAs. Those will actually ramp up as we do more solar on the contracted side attributable to the IRP. And then we’ll see probably more front-end loaded the wind opportunity and then just steady growth at North Star. And so that’s really how you should think about the economic opportunity for those non-rate-base opportunities over the course of the plan.

Jeremy Tonet: Got it. That’s very helpful. Thanks.

Rejji Hayes: Thank you.

Garrick Rochow: Thank you, Jeremy.

Operator: The next question comes from Julien Dumoulin-Smith from Bank of America. Julien, your line is open. Please go ahead.

Unidentified Analyst: Hi, Good morning. This is on for Julien. My first question is to just to elaborate on the DIG economics and the opportunity there, how do you see the move from a seasonal auction in MISO or two seasonal option MISO from an annual auction kind of impacting that opportunity, if at all? And how should we think about that there?

Rejji Hayes: Yes. So we are assessing MISO’s new rules around sort of the seasonal auction. I still think when you cut through it, whether it’s a historical process of the new process, you’re still going to see a continued tightening of Zone 7. It’s still a peninsula. You still have limited transmission importation access to the southern border, and you still have Covert retirements. And so when you have those sort of construct, you’re going to see just an imbalance between supply and demand and DIG will start to open up in those outer years. And so we anticipate, as I said before, that we’ll potentially see more attractive economics as energy and capacity starts to free up in the outages of the plan. The degree to which it’s more attractive, we’ll see.

I think, obviously, there’s — it’s early days. But we certainly think what we’re showing on the page and that Slide 20 offers at least a representative or is at least indicative as to where prices may go if we see continued tightening. Again, those light blue bars, that upside opportunity is not incorporated in our plan to be very clear.

Garrick Rochow: And just to add to that, that old seasonal construct is out there to address resource adequacy. And when you — the capacity that has been applied over units has the potential to actually reduce some capacity of units. And so that the need grows, certainly in the short to midterm across all of MISO, including Zone 7. So the value of a place like in a facility like DIG should only improve for Rejji’s comments.

Unidentified Analyst: Great. That’s helpful. And switching gears a bit here. Can you quantify the aggregate voluntary regulatory mechanisms in 2022? And as we think about the updated 2023 guidance range, do you have any voluntary mechanism embedded in the range at this time?

Rejji Hayes: Yes. So to answer your last question first, Heidi, we do not presuppose any VRM for the 2023 waterfall, or sorry, for our 2023 guidance, and none of that’s incorporated in the waterfall, I should say. With respect to the components of the refill mechanism, we just filed that earlier this year, to be clear, it’s $22 million and we’re going to allocate a portion of that towards excess capital investments over the course of ’22 attributable to emerging capital work like asset relocations demand failures on new business. And so that’s a portion of it on the electric side. And then we allocated a good — the balance of it towards our gas customers, particularly those who are most vulnerable, and we think that’s a very prudent use of those resources during these challenging times for customers. And so that’s really the spirit of it. Were you also getting at the electric rate case settlement commitments as well?

Unidentified Analyst: Yes, yes, correct. And the donations as well as how we should think about kind of what informs the guidance?

Rejji Hayes: Yes. And so there’s none of that incorporated into the 2023 guide either and just to round out the numbers here. So in the electric rate case settlement, we committed to a $15 million bill credit that will benefit customers in 2023. And again, we recognize the expense of that in 2022, and then there was a $10 million again of low-income customer support, again, recognized in 2022 and customers will benefit from that over the course of this year. And so that’s really how it works. And none of that is presupposed in our 2023 guide.

Garrick Rochow: And so if I pull up and look at the big picture here, this is why the Michigan regulatory construct is so strong. You have these mechanisms, whether it’s the settlement or whether it’s a voluntary refund means that allow us to derisk the future year and offer additional customer benefit. And that’s exactly what this $47 million is. And so this gives us — this is why I’m so confident, we’re so confident in our ability and the outlook for 2023.

Unidentified Analyst: Great. Thank you so much. And congrats again on the results.

Garrick Rochow: Thank you, Heidi.

Operator: The next question is from Michael Sullivan of Wolfe Research. Michael, please go ahead. Your line is open.

Michael Sullivan: Good morning. One thing I picked up on in your comments of front Garrick was I think you said improved approach on the regulatory side as kind of being key to some of the settlements last year. Can you just give a little more color on what you meant by that and what that means going forward in terms of like being able to consistently settle?

Garrick Rochow: Well, you remember Q4 call last year. And I was in this spot, and we were saying, hey, we need to improve. We didn’t get the best order out of the commission. And we said a couple of things on that call. One, we needed to improve our testimony in our business cases. And we did that. We took two months. We delayed the case by two months, and that’s exactly what we worked on. We also adjusted our approach for the electric rate case and how we deliver that and interface with the staff on it. That was a learning that we took from our integrated resource plan filing, we extended that to our electric rate case. And then as we got to August, we saw staff position, it was a very constructive staff position because of all the work that had been done in the testimony and business cases, the improvement that had been done.

And that was the foundation. So once you have that constructive foundation, that constructive point where staff is, then it’s really an opportunity to work through settlement. And that’s exactly what we did working with a number of interveners, the Attorney General, the staff, business community, residential community as well as number of environmental interveners to really have a very constructive outcome with this electric rate case. And so as I look forward, we’re going to continue to deploy those methods. We’re going to continue to improve the process going forward so that we can set ourselves up for settlement or if we have to go to the final order that we can get a constructive order.

Michael Sullivan: Great and thanks, that’s really helpful. And then just shifting to the CapEx plan and the clean energy spend. Can you guys just quantify like how much on a megawatt basis of renewables you’re looking at over the plan and what that looks in terms of split between solar storage, wind?

Garrick Rochow: Let me – I’ll take a crack at it here and Rejji will jump in a little bit too. So in our IRP, there’s – obviously, we’re replacing coal. And so, I’ll just kind of walk through the whole piece of it, so you can see every component of it. So we’re going to add about 1.2 gigawatts, that’s the Covert facility. We got this RFP out there for 700 megawatts, 500 is dispatchable, 200 is renewables, which will have a PPA for that will get enough financial compensation mechanism on that portion of it. And then in addition to that, we got about 1.2 gigawatts of renewable build-out in that plan that’s spelled out in our IRP. And again, 8 gigawatts over the longer piece of 1.2 roughly in that 5-year window. That’s a mix of wind and solar.

. And then bottom line, we have also in here, what I call energy efficiency and demand response. Those are also play out in that window as well. And then if you’re doing the math on this, we’re also keeping Kam 3 and 4 around. That’s part of it as well, but that’s just more of a capacity look. And so, we’re in the process of constructing a wind farm right now. That’s part of our renewable portfolio standard. That’s the one Rejji mentioned in his comments. It’s under construction that’s about a couple of hundred megawatts of that plan. And the remainder out there is roughly solar and solar build. I will add this, and Shar asked this question earlier and I didn’t finish it. But we also have in this plan 300 — roughly 300 megawatts of voluntary green pricing.

This is our large customer renewable program. We’ve talked about this over previous calls. It’s about 1,000 megawatts. We have ability to build and we have subscriptions for that. And we’ve got our first, you might say, tranche of subscriptions. And then we’re building the first – over the course of this plan, we’re building the first 300 megawatts. Is that helpful?

Michael Sullivan: Very helpful and also, add thanks a lot.

Rejji Hayes: And Michael, the only thing I’d add is that you asked about storage as well. I think Garrick have numerated every last bit, and I’ll just add storage. We’re assuming around 75 megawatts storage in the plan. I mean, obviously, longer term for the IRP, we’ll do more than that, but over the course of this five-year plan, about 75 megawatts.

Michael Sullivan: Great, thanks again. Take care.

Operator: The next question is from Andrew Weisel from Scotia Bank. Andrew Weisel, please go ahead. Your line is open.

Garrick Rochow: How is the new baby?

Andrew Weisel: Hi good morning everyone.

Garrick Rochow: How is the new baby?

Andrew Weisel: Good, she is sleeping through the night this week it’s a miracle. I just want to elaborate on an earlier question about the non-rate base drivers. I guess my question is what are the offsets if rate base is growing faster than seven plus these adders you’re clear that we shouldn’t expect more than 8% growth, no sugar highs. So what’s keeping the growth below 8%? Is it the equity in the outer years or something else?

Rejji Hayes: Andrew hi, it’s Rejji. The only thing I would add is that to Garrick’s comment is if you ever need help getting your baby sleep feel free to play back this call. We try to make these calls to the extent . But to get to your question, I would say, yes, you will see some equity dilution in the outer years of the plan. So as I mentioned, we’ll be getting to up to $350 million of equity from ’25 through 2027. So that’s some of the offset to the non-rate base opportunities. And then we will have some parent funding costs in the outer years of plan beyond equity. So we’ll start issuing a little bit of debt. And so that’s the other bit as well. So I’d say it’s largely on the funding side. I mean is this helpful.

Andrew Weisel: Yes.

Garrick Rochow: If I just add to it. It’s also the mindset that we have. We’re going to – we’ve got great mechanisms in the state in this construct with the VRM that allow us to offer benefit in the next year for our customers and for our investors and that really helps to derisk. And so, that’s another reason why we think about it towards really the long-term versus one year in a sugar high.

Andrew Weisel: Sounds good. And then on the equity, the number went up. It was up to $250 million, now it’s up to $350 million in ’25 and beyond. Just wondering what’s the driver of that increase? And I know it’s up to, but why did it change?

Rejji Hayes: Yes, so it’s a good question, Andrew. And just to be clear here. So obviously, the capital investment plan has increased materially from the prior vintage. So we were $14.3 billion in the prior five-year plan, we’re now $15.5 billion. And we’re effectively addressing the Covert needs and that drives about $800 million of that increase. But the balance, we still have incremental investment opportunities above and beyond Covert. And so it’s really to balance out the funding for that additional CapEx and obviously maintain our credit metrics kind of in that mid-teens area, which we’ve always targeted for my prepared remarks. But I will also our general rule of thumb, obviously, is we always want to avoid block equity and we still think even at that level of up to $350 million per year, even where the market cap is right now that’s up 2%.

And in a perfect world, the market cap will continue to grow, and it will be a much smaller relative to the market cap at that point. So, we think we can triple that out comfortably without any overhang or material pricing risk.

Andrew Weisel: Agreed, it’s definitely not a risk. Just trying to understand does that mean it’s going to be more than $250 million and less than $350 million, the way you see it now?

Rejji Hayes: I would say up to $350 million per year.

Andrew Weisel: Okay fair enough. Thank you very much.

Garrick Rochow: Thank you.

Operator: The next question comes from David Arcaro from Morgan Stanley. Please go ahead. Your line is open.

David Arcaro: Hey good morning thanks for taking my question.

Garrick Rochow: Good morning, David.

David Arcaro: Good morning, I was wondering if you could just specify what you’re assuming for load growth in the latest outlook. You had some good commentary too about industrial activity in the state. What are the recent trends you’ve been experiencing with resi and C&I activity as well?

Rejji Hayes: David, this is Rejji. I’ll take that. So let me start with what we saw last year, and it was very consistent with our commentary over the course of each quarter, but we just continue to see good load growth on a weather normalized basis in Michigan. And so, we were down about 1% for residential as we have been highlighting that was actually a little better than plan. But then on the commercial side, we were up over 1.5%. And then industrial, excluding one large low margin customer, up over 2.5% so all in, about a point or 1% on a blended basis. And our expectations are, I’d say, a little tempered going into 2023. And so, we anticipate being a little south of that. And so, we would say probably flat to slightly up all in.

Resi continuing to come in as people continue to go back to work. But still commercial, I’d say, roughly 0.5 point in industrial between 1.5% to 2%. So we still anticipate decent load growth, and that does not include any of the robust economic development opportunities that we see in our pipeline at the moment as a result of the Chips and Science Act, the Inflation Reduction Act, we continue to see lot of activity, whether it’s semiconductor fabs, as Garrick known in his prepared remarks, battery, EV battery supply chain or other energy-intensive businesses. We do hope that we’ll see some more, lumpy load opportunity in outer years of the plan so more to come on that.

Garrick Rochow: Yes, I just would add to that under Rejji’s good comments there. The Chips Act and the IRA and even the IIJ, that’s a super acronyms there. But bottom line, they’ve helped our business, and they’ve helped a number of other businesses here in the state from a growth perspective. In addition to that, we’ve been working closely with the legislature with the Governor’s office or site incentives that really make our state as competitive as other states that are offering site incentives. That comes in terms of not only investment in the site from a state perspective, but also incentives to locate here, which has been very helpful. We introduced an economic development rate, which further encourages growth here in the state, and we’re seeing some nice some nice low growth over the last year and commitments to Michigan, and I expect more here in short order.

And so, I’m excited about that and what that means for our state, both from an investment perspective, growth perspective and particular jobs perspective.

David Arcaro: Great thanks for all that color, very helpful. And I was just wondering, just looking out the equity needs later in the plan and the balance sheet and cash flow at that point. I was wondering, are there any cash flow impacts that come over time potentially from IRA or as you start ramping up renewables and with tax credit dynamics, anything that could help operating cash flow, free up cash flow to further invest at that point that we should think about just as your investment profile shifts in that direction?

Rejji Hayes: Yes, it’s a good question, David. So we currently are assuming about $12.5 billion of operating cash flow generation over the duration of this plan. So a healthy level, and that’s kind of run rate of $2.5 billion or so per year. So clearly, we’ll benefit, as Garrick noted earlier, from just lower costs as a result of the production tax will now apply to solar investments. Whether there’s incremental upside opportunity for OCF, we’ll see. But we try to plan conservatively, and we feel pretty good about the estimates for OCF and the financing plan going forward. And I think it’s also worth noting that we don’t anticipate being a material payer of federal taxes through the duration of this plan we’ll be a partial taxpayer you start to get to ’24 and ’25, but federal tax cash payments are not a material source of outflow over the course of this plan.

And that’s kind of been sort of our norm for some time now. So the team continues to do a very effective tax planning to minimize that outflow.

David Arcaro: Okay got you that make sense, thanks so much.

Operator: The next question comes from Durgesh Chopra from Evercore. Durgesh, your line is open. Please go ahead.

Durgesh Chopra: Hey team, good morning and thank you for taking my question.

Garrick Rochow: Good morning, Durgesh.

Durgesh Chopra: Hey good morning Garrick, thank you for taking my question. Hey just Rejji, I want to go back to the equity financing plan. So the CapEx in both ’25 and ’26 was raised by $100 million, and that seems to all sort of go the equity from $250 to $350 million. Did the assumptions change in cash flow or did anything else change or you’re just building some flexibility in this line. So if you could just talk to that, please?

Rejji Hayes: I would say it’s more flexibility than anything else. I mean, I would say it’s not as formulaic. It’s a $100 million increase in the given year equates to 400% equity financing. I think it’s more you see about $400 plus million of incremental capital investment above the prior plan and exclusive of Covert. And so, we’re just trying to fund that as thoughtfully as possible. But it’s not as formulaic as incremental $100 million in ’25 and therefore, incremental $100 million, it’s much more is a little more art than that. So I would just say just because there is some flexibility. And hopefully, we don’t have to do as much of that. But for now, the guidance is up to $350 million per year, and we think that prudently funds the business and keeps those credit metrics in the mid-teens level to keep the credit ratings we have that we’ve worked very hard to achieve.

Durgesh Chopra: Awesome that makes sense. And then maybe just on the Slide 12 here. The $0.19 to $0.25 usage, non-utility tax and other, can you give a little bit of a more detailed breakdown of what’s usage and some of the other items, if you can?

Rejji Hayes: Yes, so usage non-weather sales, I just provided that in the other question. But like I said, it’s flat to slightly up, I would say, about – 25 basis points up all in. We expect residential down over 0.5% as folks come back to pre-pandemic levels. And then you’ve got commercial up about 0.5 point and then 1.5% to 2% for industrial, again, excluding one large low margin customer. The other big bucket within that $0.19 to $0.25 is just, remember. We had a little of discretionary activities in the fourth quarter. So namely, you’ve got the VRM which was $22 million, and then you’ve got another $25 million of electric rate case commitments and so all in that $47 million of Q4 lack is about $0.12. That does not need to take place in the fourth quarter of this year.

And so when you think about that comp of Q4, ’22 versus Q4, 2023, you see a lot of that in there. So I’d say it’s a combination of those sort of discretionary items that don’t need to recur. And then you’ve got – I’d say relatively modest load assumptions. We’ve got a little bit of uptick in NorthStar as well. That’s the other component of that. And as you can see, we delivered actuals of $0.12 per share at NorthStar in 2022 and the guide for this year 2023 is $0.13 to $0.16. So that’s a piece of it as well. It’s really those pieces. Is that helpful?

Durgesh Chopra: Yes, absolutely. Usage and half of it looks like the Q4 flex from ’22 to ’23 and a couple of pennies at NorthStar?

Rejji Hayes: Bingo.

Durgesh Chopra: Thanks so much. Appreciate the time guys, thank you.

Garrick Rochow: Thank you.

Operator: The next question comes from Anthony Crowdell from Mizuho. Anthony, your line is open. Please go ahead.

Anthony Crowdell: Hey good morning, thanks for squeezing me in here. Just hopefully two quick ones, one was on DIG. Is there a desired amount of capacity you want to leave open in the plan? Do you look longer term and say we want to keep 50% open or 40% open? Are you guys are more opportunistic on that?

Garrick Rochow: Well, right now, if you look at ’23, ’24, ’25, it’s 100% or pretty close to it. So we want to in the upcoming two to three years, we want to fully subscribe – from a capacity and energy perspective. And as you layer in contracts time you get up to 2025, ’26 it approaches 50%. So there’s room there. And absolutely, we’re going to take advantage of opportunities in the energy and capacity markets to layer that in so some longer-term contracts to see really to take advantage of the opportunity out there is with energy and capacity prices. Does that help, Anthony?

Anthony Crowdell: Yes, absolutely. And then lastly, if I want to maybe look a little longer here, your next IRP filing, I mean the IRP, the guys finished, I guess, I don’t know, the ’22 or ’21, very successful, transformational. What’s the timing of the next IRP? And what’s that going to look like?

Garrick Rochow: It just feels like I got through that this year with the settlement, like I’m celebrated. I’m still in my victory lap of that IRP. It was a landmark. And now you’re asking about the next one, yes.

Anthony Crowdell: Parked and Lightning in the garage before you do the victory lab yes.

Garrick Rochow: So we have to be in there within five years. It’s usually a three to five years though. We don’t have a plan yet on when that will be. It usually helps to be in around three years just because of the timing of the cycles and of recovery, but no set time yet at this point Anthony, sorry, I can’t give you a date yet, but we’ll work towards here – the next few years.

Anthony Crowdell: Great, thanks so much for taking my questions.

Garrick Rochow: Thank you.

Operator: The next question is from Travis Miller from Morningstar. Travis, please go ahead. Your line is open.

Travis Miller: Good morning everyone, thank you?

Garrick Rochow: Hi Travis, good morning.

Travis Miller: You actually couple questions ago, you answered my question about unpacking that other $0.19 to $0.25 on next year’s earnings. Just one quick follow-up to that, the usage so that’s seven that you used $0.07 on the 1% change in the electric side, especially, is that on the numbers that you talked about in terms of what’s in the guidance or is that incremental to what’s on that guidance to you? You understand my question?

Rejji Hayes: Yes, I do follow you. Yes, so the sensitivities that you see Travis on Page 15. This just highlights what the EPS impact would be if we saw another point good or bad relative to plan. And so, the sensitivity around on the electric side is about $0.07 for every percent. Now it obviously depends on mix. And so we’re assuming, like I said, for the usage, about, call it, about 0.25% up on a blended basis with resi coming down a little over 0.5% commercial, about 0.5% up and then industrial 1.5% to 2%. And so modeling purposes, that’s sort of the base case. And then if we saw any deviation, that’s what the sensitivity, provides visibility on. Does that address your question?

Travis Miller: Yes, yes absolutely. And that could be weather sensitivity, right that’s not necessarily just why they’re normal I think weather benefit or determines.

Rejji Hayes: Yes, that’s exactly, right.

Travis Miller: Okay very good, that’s all. Yes that’s all I have, appreciate it.

Garrick Rochow: Thank you.

Operator: We have no further questions at this time. So I’ll hand the call back to Mr. Garrick Rochow for concluding remarks.

Garrick Rochow: Thanks, Adam. I’d like to thank everyone for joining us today for our year-end earnings call. Certainly hope to see you on the road over the next coming months. So take care and stay safe.

Operator: This concludes today’s call. Thank you very much for your attendance. You may now disconnect your lines.