Jason Shore:

Thank you, Harry. 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. And now I'll turn the call over to Garrick.

Rejji Hayes:

Thank you, Garrick, and good morning, everyone. On Slide 7, you'll see our standard waterfall chart, which illustrates the key drivers impacting our financial performance for the first six months of 2024 and our year ago expectations. For clarification purposes, all of the variance analysis herein are in comparison to 2023, both on a year-to-date and a year-to-go basis. In summary, through the first half of 2024, we delivered adjusted net income of $485 million or $1.63 per share, which compares favorably to the comparable period in 2023, largely due to higher rate relief net of investment costs. And while we have seen some glimpses of favorable weather, particularly in June, overall weather continues to be a headwind through the first half of the year, equating to $0.05 per share of negative variance and that figure includes the warm winter weather experience in our service territory in the first quarter, which I'll remind you, have the second lowest number of heating degree days in the past 25 years. As mentioned, rate relief, net investment-related expenses, one of the key drivers of our first half performance resulted in $0.13 per share of positive variance due to constructive outcomes achieved in our electric rate order received in March and last year's gas rate case settlement. From a cost perspective, our financial performance in the first half of the year was negatively impacted by heavy storm activity, including a notable weather system that impacted our service territory in late June resulted in $0.03 per share, a negative variance versus the comparable period in 2023. Rounding out the first six months of the year, you'll note the $0.13 per share of positive variance highlighted in the catch-off bucket in the middle of the chart. The primary sources of upside here were related to solid operational performance at NorthStar and higher weather-normalized electric sales. Looking ahead, as always, we plan for normal weather, which equates to $0.20 per share of positive variance for the remaining half of the year, given the mild temperatures experienced in the final six months of 2023. From a regulatory perspective, we'll realize $0.12 per share of positive variance, largely driven by the aforementioned electric rate order received from the commission earlier this year and the constructive outcome achieved in our recently approved gas rate case settlement, which Garrick summarized earlier. Closing out the glide path for the remainder of the year, as noted during our Q1 call, we anticipate lower overall O&M expense at the utility driven by the usual cost performance fueled by the CE Way and the residual benefits from select sustainable cost reduction initiatives implemented in 2023 such as our voluntary separation plan, among others. Collectively, we expect these items to drive $0.09 per share, a positive variance for the remaining six months of the year. Lastly, in the penultimate bar on the right-hand side, you'll note a significant negative variance, which largely consists of the absence of select onetime countermeasures from last year and the usual conservative assumptions around weather-normalized sales and nonutility performance among other IOs. In aggregate, these assumptions equate to $0.35 to $0.41 per share of negative variance. In summary, despite a challenging first half of the year, we are well-positioned to deliver on our 2024 financial objectives to the benefit of customers and investors. Moving on to our financing plan. Slide 8 offers more specificity on the balance of our planned funding needs in 2024, which at this point are limited to debt issuances at the utility. I'll bring to your attention a relatively modest increase to our 2024 planned financing of the utility. Specifically, we are now planning to issue approximately $675 million in the second half of the year versus the implied estimates in our original guidance of $500 million to rebalance the rate-making capital structure at the utility in accordance with recent rate case outcomes. Although not highlighted in the table on the slide, I'm pleased to report that we have completed all of our planned tax credit sales for the year at levels favorable to our plan and ahead of schedule. I'll also reiterate that we have no planned long-term financings as apparent in 2024, but remain opportunistic should we see a cost-efficient opportunity to pull ahead some of our 2025 financing needs. As I've said before, our approach to our financing plan is similar to how we run the business. We plan conservatively and capitalize on opportunities as they arise. This approach has been tried and true year in and year out and has enabled us to deliver on our operational and financial objectives, irrespective of the circumstances to the benefit of our customers and investors, and this year is no different. And with that, I'll hand it back to Garrick for his final remarks before the Q&A session.

Operator:

[Operator Instructions]. Our first question today comes from the line of Jeremy Tonet of JPMorgan. Please go ahead. Your line is open.

Garrick Rochow:

I would suggest, Jeremy, it's consistent with what we shared in the past, energy and capacity markets that upward pressure continues to be a ripe opportunity and we continue to strike nice bilateral contracts to secure managing capacity prices well above our plan. And so again, it's a good opportunity to continue to do that. And as we've shared in the past, this just continues to strengthen and lengthen our financial performance.

Rejji Hayes :

Jeremy, it's Rejji. I appreciate the question. I would say weather outlook looks fairly good for Q3, but obviously, early days. And I will just say, personally, I don't give a lot of credence to 2-month and 3-month outlooks. I'm much more focused on the 10 days ahead, which appear to be a bit more accurate. And so, we always remain paranoid about weather. And just based on year-to-date, weather has not been all that kind. And so, we'll continue to execute on cost performance-related initiatives. We've had some good success over the last several years in executing on cost management over the course of the year, and we'll continue to do that through Q3. As I mentioned in the first quarter call, it's still premature to start thinking about pull aheads for 2025. I'd say historically, even in the best of years, where weather was really helpful in the first couple of quarters, we still didn't think about flexing up or pull ahead or any of those types of derisking mechanisms until we got deeper into Q3 and had a real good outlook on the fourth quarter. So hopefully, more to talk about from a 2025 derisking perspective next quarter. But at this point, it's too premature to get into that.

Jeremy Tonet:

Got it. Appreciate it. And then if I could just wrap with thoughts on opportunity to service data centers going forward here, and I guess, the interplay with regards to legislation in Michigan, whether that comes to fruition and how that might impact the pace of such type of development.

Operator:

Our next question today is from the line of Shahriar Pourreza of Guggenheim Partners. Please go ahead. Your line is open.

Garrick Rochow:

Sure. I was really hoping for a rate design question.

Garrick Rochow:

Let's talk about this. We definitely see as a part of this energy law, additional upside. That shows up in ownership of asset that shows up in the financial compensation mechanism, both those are true. Let me talk about how they'll play out, though. We're going to file this our renewable energy plan in November, it's a 10-month process. So, we'll know in 2025, kind of latter half of the year, what that looks like. And so, in our 2026 capital plan, you'll see what that means, our 2026 financials both from an FCM perspective as well as what might the ownership mix looks like. And so that's where it will play out. In addition to that, that's probably a portion of the story because in 2026, we'll also file our integrated resource plan, which we'll talk about some of the reliability pieces and some of the work to deliver the capacity component of that. So, between '26, '27, '28, I think that's when you'll see the capital impact as well as the financial compensation mechanism play out in terms of our financials. And I will say this, we've seen some good economic growth in the state. That will show up in our renewable energy plan. We're definitely seeing a greater need than was in our original 2021 IRP. So, I'll leave it at that. And certainly, that will provide additional upside opportunity in terms of capital growth in addition to the energy law.

Garrick Rochow:

I set myself up for that one, didn't I? [indiscernible] here on this call. I will always look for settlement opportunities. I'm also very confident in our team. We put a great case together, and we can go to full distance, just as we did this year in our March order. And so, when I think about this electric rate case, there's some things that have to be figured out to really get some context around the opportunity for settlement. One, I think it's really important to understand that electric cases are more complex than gas cases. So, for example, we had less than 10 intervenors in our gas case. We have a little over 20 in our electric case. That's not abnormal, it's just, it's a more complex case. There's more interested party so we have to navigate through that. I also think it's important to find where staff is and where the Attorney General are at in this case. That will come in September. These are important points to know in the context of settlement opportunity. But I understand that, I am very confident in this case. It is focused on electric reliability. That's well aligned with what the customers are asking for, what the commissioners and the staff are asking for and what I've committed to do and so this case has great capital investments and undergrounding has important work hardening the system and automated transfer reclosures technology on the system. There's important work in O&M and tree trimming, our number one cause of outage and other important maintenance work across the system. We're going to leverage the infrastructure recovery mechanism, we'll certainly look for -- we're going to try another store mechanism in this case as well. And so, we feel confident in our ability to get the very constructive outcome, just given how well aligned we are across commission staff as well as our customers. So hopefully, that gives you some context on the case. Now on rate design, let me just talk a little bit about rate design. Specifically, data centers are not at our economic development rate. We had ex-parte filing that made an adjustment in that, that was approved. And so, in the meantime, they are an industrial rate. We thought our GDP rate and what that does is a better balance, both capacity and energy cost, the cost to serve those customers. The commission as well as the utility has been looking and exploring at the opportunity specific data center rate. But in the interest of time, the GDP is a good proxy for that in our mind. And so well suited from a rate design perspective, from a data center perspective. I also said GDP, I think that's the wrong thing. I was hoping for something different there. Maybe that was -- but GPD is what I meant -- sorry about that Shahriar I had my eyes on the economic [indiscernible] it's election time. I have my mind on other things like what's going to happen with our economy.

Michael Sullivan:

I just wanted to go back to the data center legislation discussion. I think on the last call, you talked about a 230-megawatt data center coming in 2026. Was that contingent on the legislation or your understanding is still moving forward? And are there any other examples of that? Or is everyone else [indiscernible] weighted inflation?

Michael Sullivan:

And is that like a good proxy for how long it takes new load to come on to your system about two years with that one being 2026?

Michael Sullivan:

Okay great. And then separately, just kind of sticking with legislation. I think there were some comments a few months ago from the PSC chair about rate case time lines being a bit impressed these days. Are you hearing any chance of legislation coming up that would revert back to 12 months per cycle from -- and just a general sense for rate fatigue in the state in light of those comments?

Operator:

Our next question today is from the line of Andrew Weisel of Scotiabank. Please go ahead. Your line is open.

Rejji Hayes:

Sure, Andrew. This is Rejji. I'll take, and I appreciate the question as always. Yes, we did see a little bit of a pullback in Q2 versus Q2 of last year for weather normalized sales for electric. I will always caveat and I think you alluded to it that it's a very imperfect science, and the team does a really good job trying to pull these numbers together with real accuracy. But again, it's very difficult to get real precision here. Just so everybody is grounded residential for the quarter versus Q2 of 2023, which is slightly up about 0.1%. And commercial down about 1 point, industrial down about 2 points, excluding on low-margin customer and an all-in blended was down about 1 point and so that is to your comment, unfavorable from the trends we were seeing in the first quarter. But I would say, on a year-to-date basis, the trend remains quite good, and we continue to be surprised for the upside really across all customer classes because our assumptions were incredibly conservative as they always are for the year. And so, we are outperforming across every customer class, what our initial expectations were that were embedded in our original guidance. And so, we are still seeing non-weather sales upside. I'll also note, as I've said before, that we had energy waste reduction incorporated into all of those numbers that you're seeing. And so, you should always add 2% to each of those customer classes because we're delivering the 2% reduction across every customer class year-over-year, and we've been doing that now really since the '08 law or thereabouts. And so, another way to think about those numbers I just quoted that you should add or gross up 2% across each of those, if you want to get the underlying economic conditions. So, we still remain quite good. And then we still remain quite pleased rather with the results. And then when you think about it on a year-to-date basis, where is up about 1 point. Commercial is up over 1%, industrial down about 1 point and all in is up about a little over 0.5%. So again, all things considered, particularly when you gross up for energy waste reduction, we think conditions in Michigan remain quite good really across all customer classes. Was that helpful?

Garrick Rochow:

So, we're seeing a number of great improvements as a result of the investments we have made to date. More needs to be done along those lines. And so, in fairness, I'd give ourselves a B in the context, there's more needs to be done for our customers. And that's evident in the rate case filing that we're doing. Where we've worked a lot, this year is reducing the size of the outage. And so, we've put in a lot of fusing. So, what I mean by that is you have less customers impacted when the tree comes down the line, that's an important work. We've more than doubled our free trimming work over the last three years. That's also provided a benefit when we trim treating there, we see a greater than 60% reduction in the number of outages. You may ask why not 100% because we still see trees outside the right way that impacts our performance. But I would also put it into context, Rejji talked about the last week of June, and there was a larger event in June, but there was a lot more smaller events which we would anticipate. We're trying to shrink the size, which makes restoration easier, but a lot of pockets throughout the state. We brought in a number of resources. We leverage a lot of our existing union resources to be able to respond to that, and we have good response from that perspective. We measure in terms of restoring our customers within a 24-hour window. We want to have all customers restored within a 24-hour window. And last year, in 2023, we're at 90% within a 24-hour window. This year, we're upwards of 95%. And so that shows the directional improvement. Now the year is not done. We've got a lot of work to do. and we'll continue to make some important investments throughout this year. And again, this electric rate case shows the path for more. So hopefully it gives us some context. I know Rejji wants to add to it as well.

Operator:

Our next question today is from the line of Julian Dimelo Smith [Indiscernible] of Jefferies. Please go ahead. Your line is open.

Garrick Rochow:

And here's Rochow. I don't know. I don't know if it has a ring to it. Look I'll give it a try.

Rejji Hayes:

Julian, it's Rejji. I appreciate the question and welcome back. Really good to hear your voice. Let me start with a few of the just premises or working assumptions you offered up in the question. And so, let me start with the debt at the utility, just for factual purposes. And so, we are planning to issue about $675 million in the second half of the year at the utility as part of our financing plan. It was initially $0.5 billion and so we've slightly increased, and that's really just because of our rate case outcomes, which had modestly lower equity levels, and so we'll have more debt at the operating company. And so, I just want to make sure that, that was abundantly clear. And obviously, we'll look to execute on that financing as cost-efficiently as possible, and we'll be thoughtful about maturity profile as well. The outperformance has been, obviously, we always try to deliver on the cost performance side. But as I mentioned in my prepared remarks, rate relief net of investments has been helpful getting constructive orders the electric rate order in early March, the gas rate case last year, we're still seeing the residual benefits from that. And so that's really what's helped us in the first half of the year. And also, though it's embedded in that catch-all bucket, as I noted in my prepared remarks, NorthStar has really outperformed. They had a really soft comp in the first half of 2023, just given last year's plan was a bit more back-end loaded. And there were also some outage-related issues at DIG, given a transformer issue. And so, this year, they've really gotten out of the gate pretty strong. DIG is up about $0.05 year-over-year, and we're seeing the residual benefits from some solar projects that came in late last year. And so, I'd say it's a combination of rate relief net of investments, outperformance at NorthStar as well as some cost performance, as you alluded to, offset by mild weather conditions, which have hurt the top line as well as storms, as we talked about in the prior question. So, I'd say it's a combination of all of that, which gives us just good confidence going into the second half of the year.

Rejji Hayes:

Yes, good question. NorthStar on plan. We anticipated a front-end loaded year for all of the reasons you noted. So, a good portion of NorthStar's performance was on plan. But I will say DIG did surprised a little bit to the upside in the first quarter because operationally, not only are they executing very well, but they're also executing on a lower unit cost basis, which drives a little bit of additional margin there also opportunities for off-peak margin that the team has capitalized on. So, I'd say it's a combination of being on plan because it was a front-end loaded plant at NorthStar, but also so operational efficiency, which we've seen. So that's really the thrust of it at NorthStar.

Durgesh Chopra:

Good morning. Thanks for taking my question. Just -- all my other questions have been answered. I just wanted to see if there's an update on the performance-based ratemaking dotted here coming out of the legislation last year. Where do we stand there? Can you just update us on that, please?

Durgesh Chopra:

Got it. So just kind of the framework of this would be a potential earnings uplift. And then on the downside, a potential penalty on certain metrics. And then when did you say this could go into effect? This is a '25 Item, '26? Just any thoughts there?

Operator:

[Operator Instructions]. Our next question is from the line of Travis Miller of Morningstar. Please go ahead. Your line is open.

Garrick Rochow:

Yes. It's definitely trending higher based on all the economic development activity that is, again, not speculating on that, that is signed or -- and we're out building substations and there's transmission being built to serve these customers. And so, in our renewable energy plan filing, you should anticipate that there's additional sales reference there above and beyond our 2021 IRP.

Garrick Rochow:

Yes, generally speaking.

Garrick Rochow:

Palisade is making forward progress in the state. From a state budget perspective, another $150 million was allocated toward the forward direction of the facility. We're having public meetings that are going on right now on site. So again, forward steps and moving forward that plant. Now I remind you that a PPA has already been struck for the offtake from the Palisades facility that goes to a co-op in Michigan and a co-op in Indiana. So, it's already spoken for. Now we did -- it's good for Michigan that Palisade is returning. And we, at CMS Energy, do not see any adverse impact as a result of Palisade coming back.

Nick Campanella:

Just one for me today. So, I know, Rejji, you said you would be opportunistic in your prepared remarks around financing and potentially pulling things forward from '25. I'm just cognizant that you do have kind of you start to issue equity in 2025. And maybe you can just kind of give us some more color? Are you just kind of talking about pulling forward hybrid or debt or is everything on the table, how do you think about that?

Operator:

With no further questions in the queue at this time, I would like to hand the call back to Mr. Garrick Rochow for any closing remarks.

Operator:

This concludes today's conference. We thank everyone for your participation.

Jason Shore:

Thank you, Drew. 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.

Garrick Rochow:

Thank you, Jason, and thank you, everyone, for joining us today. CMS Energy, 21 years of consistent industry-leading results. And what sets us apart is our performance, and it starts with our investment thesis. It is how we prioritize and focus our work to deliver the service our customers deserve in the financial outcomes you expect.

Garrick Rochow:

Thank you, Rejji. Our simple investment thesis is how we run our business and provides us with confidence for a strong outlook this year and beyond. 21 years of consistent industry-leading financial performance, 21 proof point, regardless of conditions, no excuses, just results. With that, Drew, please open the lines for Q&A.

Shahriar Pourreza:

I guess, firstly, just given you have an upcoming electric case. How are you thinking about any kind of incremental construct improvements there? Would you kind of seek an expanded IRM framework? And do you need to address any kind of the rate design issues with C&I rates, especially as you're trying to accommodate new load like data center growth, especially just trying to kind of balance that customer rate impact.

Garrick Rochow:

It's still early days on some of those modeling. So we'll file our REP, Renewable Energy Plan, on November 15. And as I've shared historically here or previous here, there's a broad spectrum of ownership versus PPAs. PPAs obviously have the opportunity for the financial compensation mechanism or if you're going to build everything and own everything, obviously, you have the opportunity to earn your ROE.

Rejji Hayes:

Thanks for the question. All I would add to Garrick's comments is that in our current 5-year plan, what we've incorporated is just a modest amount of PPAs with the financial compensation mechanism, and that's solely because of the fact that any PPA put in place after June of this year would be subject to the new FCM, which is around 9% versus the prior of about 5.5%. And so we have a portion of that, albeit a small portion incorporated in this 5-year plan.

Operator:

Our next question comes from Nick Campanella from Barclays.

Rejji Hayes:

Nick, this is Rejji. I appreciate the question. Yes, as we talked about on our fourth quarter call, we still have about 30% to 35% open margin in the outer years of our plan, really starting in sort of 2026 or second half of 2016 going through 2028. We certainly are seeing attractive reverse inquiry for that open margin on the capacity side. We're sold through on the energy side through 2028 or through the duration of this 5-year plan, but there still are opportunities in the capacity side. And we'll be thoughtful.

Nicholas Campanella:

That is helpful. I appreciate that. And I guess thinking about the rate case cadence and outcomes. On the electric side, the last case to kind of pursue the fully litigated outcome, but on the gas side, you just received staff testimony. And I think, Rejji, I heard you say you get an order in fourth quarter absent a settlement. So just what's your reaction to staff starting point here? And what are your thoughts on being able to settle the gas case?

Jeremy Tonet:

Just want to dive in, I guess, to the sales outlook, came in a bit better than expected, I guess, for the first quarter and for the balance of the year, it looks like that's trending better than expected. And just wondering by customer class, if you could dive in a bit more on the drivers that you're seeing that within each class that is leading to this uptick?

Rejji Hayes:

Yes. I would say, Jeremy, early days. Obviously, we're delighted that 2024 is not 2023 in that we don't have a big storm as well as mild weather to start off the year, which we obviously saw last year. But to be clear, we still saw negative variance in terms of weather, top line-related weather. And so there's still some work to do. And so we are countermeasuring and again, very confident in the outlook. But it's a little early before we start thinking about derisking 2025 and beyond.

David Arcaro:

I was wondering what you're seeing in terms of maybe data center demand in the pipeline. Any uptick in further requests to connect beyond the big kind of megawatt addition that you called out? And wondering if that customer class, I guess, would potentially be involved in the voluntary renewables plan? Any upside potential there?

Garrick Rochow:

We've got a -- we have -- between the manufacturing load this contract and the data center load that's contracted. As Rejji said, it's a nice piece of load growth that we factored in the later years of this 5-year plan, but future 5-year plans. And we're excited about what that means. And there's a strong pipeline, both from a manufacturing perspective and to a degree, the data center perspective as well. I'd be disappointed if some of those projects in the pipeline didn't materialize.

Garrick Rochow:

That's progressed in a constructive way. We had close to 10 or a dozen metrics that were originally proposed. It's narrowed to 4 metrics that are benchmarkable and there's good standards. And so again, a constructive process plays out. There's more work to do from our perspective when we filed comments in the February, March time frame.

Operator:

Our next question today comes from Michael Sullivan from Wolfe.

Garrick Rochow:

Similar to Rejji's comments, from an energy perspective, energy tools and a capacity of the bilateral contracts, much of DIG has been spoken for at attractive -- really attractive position that either meets our expectations or is above our expectations. And so there's really unless you're beyond 2028, and maybe in the 2030s decade, DIG's really not available because it's already been secured and with, again, attractive energy tools and bilateral contracts for capacity.

Garrick Rochow:

It is -- we got primaries in August, and that means early [indiscernible] balance start in June. And so its political season already in Michigan. And so I would anticipate that. Look, the Attorney General participates in all our cases, that's been a historical practice. Sometimes those are more public than other times. We stand, as I shared earlier, by the merits of the case, both in our gas case that's underway right now and this electric rate case.

Andrew Weisel:

Follow up on the rate cases here. Just a couple of follow-ups on the rate cases. So first, I think you just alluded to this to the electric side. You're going to have more capital and more O&M. Just from a headline perspective, should we expect a larger revenue increase request than what we've seen in past [ dialings ] in terms of percent increase to customer bills.

Andrew Weisel:

Okay. Very good. And then procedurally on the gas side. I know this case is unique in that there's no ALJ. Does that change the time line at all or the potential for settlement? You talked a bit about settlement, but the lack of ALJs that factor in at all?

Operator:

That concludes the Q&A portion of today's call. I'll now hand back over to Garrick.

Operator:

That concludes today's call. Thank you for your participation. You may now disconnect your lines.

Srikanth Maddipati:

Thank you, Emily. 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 measure are included in the appendix and posted on our website. As some of you may know, this will be my last earnings call, as I've transitioned to a new role in the company, responsible for electric supply and the implementation of the New Energy Law. While I'm excited for my new role and responsibilities, I will miss working with all of you in the investment community so closely. I want to thank you for the support you've all given me in this company. Jason Shore, a 25-year veteran at CMS, has been named Treasurer and VP of Investor Relations. As I hand over the baton, I'm confident in Jason and our very experienced [indiscernible]. And now, I'll turn the call over to Garrick.

Rejji Hayes :

Thank you, Garrick. And good morning, everyone. As Garrick highlighted, we delivered strong financial performance in 2023, with adjusted net income of $907 million, which translates to $3.11 per share, toward the high end of our guidance range. The key drivers of our 2023 financial performance included strong cost performance throughout the organization, fueled by CE Way, a solid beat at NorthStar and a variety of non-operational countermeasures, such as liability management and tax planning, which more than offset the significant weather-related headwinds experienced throughout the year. And to further underscore the magnitude of cost performance delivered by our workforce, our fourth quarter operating and maintenance, or O&M, expense, exclusive of service restoration and vegetation management, was approximately 25% below the comparable period in 2022 and over 20% below our five year average for this cost category, a truly impressive achievement. All in, we managed to offset nearly $300 million of weather-related financial headwinds, without compromising our operational commitments to our customers and the communities we serve. At CMS, we've had plenty of years of adversity, followed by impressive operational and financial beat, but I can't recall one quite like 2023, a year in which our workforce personified grit and displayed that perennial will to deliver for all stakeholders. To elaborate on the strength of our financial performance in 2023, on slide 10, you'll note that we've met or exceeded the vast majority of our key financial objectives for the year. From a financing perspective, we successfully settled $178 million of equity forward contracts in November and settled the remaining roughly $265 million in forwards in January. As a reminder, these forwards are pricing levels favorable to our planning assumption. The only financial target missed in 2023 was related to our customer investment plan at the utility, which was budgeted for $3.7 billion. We ended the year below that, at $3.3 billion, primarily due to siting and permitting delays at select solar projects. As mentioned in the past, we fully intend to build out all of the solar projects approved in IRP and voluntary green pricing [indiscernible]. And with the Michigan Renewable Energy siting reform bill passed last fall, we should see better progress here going forward. Moving to our 2024 EPS guidance on slide 11. We are raising our 2024 adjusted earnings guidance range to $3.29 to $3.35 per share from $3.27 to $3.33 per share, as Garrick noted, 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, providing $3.74 to $3.80 of adjusted earnings, the details of which I'll cover on the next slide. At NorthStar, we're assuming EPS contribution of $0.16 to $0.18, which reflects strong underlying performance, primarily DIG, and ongoing contributions from our renewables business. Lastly, our financing assumptions remain conservative at the parent segment and our 2024 guidance range assumes the absence of liability management transactions. As always, we'll remain opportunistic in this regard, and we'll look to capitalize on attractive market conditions, should they arise. To elaborate on the glide path to achieve our 2024 adjusted EPS guidance range, you'll see the usual waterfall chart on slide 12. For clarification purposes, all of the variance analyses herein are measured on a full-year basis and are relative to 2023. From left to right, we'll plan for normal weather which in this case amounts to $0.43 per share of positive year-over-year variance, given the absence of the atypically mild temperatures experienced throughout 2023. Additionally, we anticipate $0.23 of EPS pickup, attributable rate relief, really driven by the residual benefits of last year's constructive gas rate case settlement and assumed supportive outcomes on our pending electric and gas rate cases. As always, our rate relief figures are stated net of investment-related costs, which is depreciation, property taxes and utility interest expense. As we turn to our cost structure in 2024, you'll note $0.16 per share of positive variance due to continued productivity, driven by the CE Way, the ongoing benefits of cost reduction measures implemented in 2023, which was our voluntary separation plan which reduced our salaried workforce by roughly 10%, and initiatives already underway. It is also worth noting that our cost assumptions exclude the impact of the catastrophic ice storm we experienced in the first quarter of 2023. Lastly, in the penultimate bar, on the right hand side, you'll notice significant negative variance, which largely consists of the reversal of select one-time cost reduction measures. These are partially offset by the ongoing benefits of our well executed financing plan in 2023, and we're assuming the usual conservative assumptions around whether normalized sales, taxes and non-utility performance, among other items. In aggregate, these assumptions equate to $0.58 to $0.64 per square of negative variance. 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 focus my remarks on those 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, as we balance the needs of the business. As previously mentioned, we have already settled the remaining equity forwards and have no additional equity needs in 2024. Longer term, we intend to resume our at the market or ATM equity issuance program in the amount of up to $350 million per year beginning in 2025 and extending through 2028, which is essentially the same assumption in our previous five year plan, but for the extension of an additional year. We're able to maintain our pre-existing equity needs despite an increase in utility capital plan, given the expectation of strong operating cash flow generation and the ability to monetize tax credits, courtesy of Inflation Reduction Act. It is also worth noting that this morning's decision by Moody's to increase the equity credit ascribed to junior subordinated notes, which represents about 40% of our debt at the parent company, is not embedded in our plan, thus providing further cushion in these metrics. Slide 14 offers more specificity on the balance of our funding needs in 2024, which are limited to debt issuances at the utility, over half of which has been opportunistically issued as noted on the page. And the coupon rate on this newly issued debt is favorable to plan, thus providing a helpful tailwind as we start the year. Over the coming year, we have no planned long term financings at the parent and already redeemed at full maturity in January at par. Longer term, we have relatively modest near term maturities at the parent, with $250 million due in 2025 and $300 million due in 2026. 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 and battle tested workforce remains committed to our purpose-driven organization, and our investors benefit from consistent industry-leading financial performance. Before I hand it back to Garrick, I would be remiss if I didn't take a moment to echo Garrick's praise of Sri, whom I've worked closely with over the past seven years. Sri's contributions to the finance team and the company have been immeasurable since he joined CMS. So thank you, Sri. You're leaving it better than you found it, and I look forward to working with you and Jason in your new roles. And with that, I'll pass it on to Garrick for his final remarks before the Q&A session.

Operator:

[Operator Instructions]. First question comes from the line of Nick Campanella with Barclays.

Garrick Rochow:

Those traditional, what I call, outside of base growth, so those growth drivers outside of traditional rate base – energy efficiency, financial compensation mechanism and DIG – those are powerful in the plan. And you asked specifically about Dearborn Industrial Generation. We are seeing both energy and capacity of prices elevated, particularly in the out years of the plan. We have available capacity beyond 2026 out through the plan. We're layering in contracts, really as we speak, which with attractive numbers and which gives us confidence in our plan, particularly in the out-years through DIG.

Garrick Rochow:

First of all, this is not a new filing. It is a more important filing. It is a bigger filing. As you might imagine, if you're going to achieve 60% renewable by 2035 or 50% by 2030, it has to grow from a size perspective. So it takes on increased importance. It's also important to remember it's based on energy versus the Integrated Resource Plan, which is based on capacity. So that work is underway. And it's really a spectrum. To meet that standard, do you do all PPAs? That's one bookend. Or do you do all ownership? I view it somewhere in the middle. But what's the strength of this energy law is there's a lot of flexibility to be able to start that path to those clean energy ambitions. We've got to think about what the customer impact is. We're still required as a load serving entity to meet resource capacity constraints in the IRP. So that's a consideration. We've got to look at the balance sheet. And here's a really capital light option where we can get an FCM at 9%. That's a really attractive part of this energy law. So there's a lot of dynamics that have to play out in there. That work is underway right now. We will file that Renewable Energy Plan in the second half of the year. We have until 2025 to get it done, but we want to pull that forward into 2024, given the work that has to be done and these milestones that are out there. So we'll file that. The commission has and staff has 10 months to get to a final order. And then that information there will certainly aid our capital plan and the upside from an FCM mechanism, but also flows into our Integrated Resource Plan. And that Integrated Resource Plan should become less complex because of this Renewable Energy Plan work. Ultimately, that then flows into rate cases as we move forward over time on the annual frequency. So, I know Rejji has some more comments on this as well. So, I'll pass it to Rejji.

Operator:

The next question comes from Jeremy Tonet with J.P. Morgan.

Rejji Hayes:

Jeremy, this is Rejji. So, Moody's this morning increased the equity credit that they ascribe to junior subordinated notes, which are more informally referred to as hybrids. It was previously a 25% equity credit. And they're essentially now at parity with S&P at 50%. The reason why that's impactful for us is that we've issued those securities quite a bit over the last five to six years, and so currently represents about 40% of our debt portfolio at the holdco. And so, by them, increasing the equity credit ascribed to this, it really increases, I'd say, the FFO to debt metrics at Moody's by that 50 to 60 basis points. So fairly accretive from a credit perspective to plan.

Garrick Rochow:

Jeremy, things are progressing nicely. I feel good about a constructive outcome. Staff had a great starting spot on what I think can be a constructive outcome and feel confident that we can get there. There's a lot of positive indicators. Support for the important work on reliability. I would say there's a great alignment between staff and, frankly, the commissioners on where we want to go, improve reliability in the state. That's a big part of this electric rate case. And also, positive indicators on the mechanisms that we've talked about in the past, this infrastructure recovery mechanism. We think that's really important from a go forward reliability perspective. It also lines up with [indiscernible] have shared about ring fencing and providing opportunity to capital to see the insight of where those investments are and how they make a difference. And then, finally, our undergrounding pilot. That's seeing support as well. That's an important first step in this resiliency play and our larger ambitions that are evident in our reliability roadmap. So, again, I feel really good about where the case is headed. And we expect the final order on or before March 1.

Shahriar Pourreza:

Just a real quick cleanup question on the CapEx and rate base. Is part of the rate base CAGR increase to that firm 7.5% and the higher CapEx run rate, is that driven by some of the spending and solar delays in 2023, so slightly off, maybe a lower base and timing differences? Or is it driven by new CapEx, the tail end of the plan, or maybe a combination of both, especially since you guys don't really include a lot of CapEx until we get through the approval process right.

Garrick Rochow:

Let me just reinforce that. And the way I would like to think about, add on to Rejji's good comments there, is that clean energy piece in the supply, it's what's approved in our 2022 IRP. And the upside will be to the tail end because we haven't built in any of this new energy law, as Rejji stated in some earlier comments. So, as that renewable energy plan is filed and eventually approved, then you'll see that it will slightly hit the tail, but even beyond the five years, you can see a nice path of 10 years of investment opportunity as a result of this energy law.

Rejji Hayes:

This just incorporates the current five year plan of $17 billion of utility CapEx. And it's enough work to prepare these five year plans. So we're not thinking about year six through 10, just yet. So I would say that it's, again, just the $17 billion utility CapEx plan and the funding associated there with. But as per my prepared remarks, we're quite pleased that even with that upward pressure on equity needs as a result of that growing capital plan, we didn't have to change the annual amount. So we're still up to $350 million as we were in our prior plan, and it has a lot to do with just good cash flow generation and the plan to monetize tax credits as a result of the IRA.

Garrick Rochow:

We're watching the activity on Palisades. But I just want to remind everybody on the call here, we're not involved in Palisades. And from a PPA perspective, it's spoken for, both with two coops. And so, we're not engaged at all within that process. Now, we hope, from an implication perspective, we think it's great for Michigan, and we wish them well and success in getting the plan up and operational.

Garrick Rochow:

No change in the resource planning. And I would just remind everybody, even with that potential out there, we see great opportunities in energy and capacity that are evident at Dearborn Industrial Generation.

David Arcaro:

Congratulations to both Sri and Jason. Really great working with both of you. I was curious if you could give your latest thoughts on load growth expectations here and whether you're seeing any increased activity in manufacturing or data center growth kind of hit the radar.

Rejji Hayes:

David, I think Garrick summarized it pretty well. And the big takeaway here is we plan conservatively. But what I'm pleased to represent, just to add some numbers to Garrick's good comments is that, you think about the last several planning cycles we've had, we've suggested that we've had sort of flat to stable or slightly declining load growth. And it's always important to remember that our load growth math includes our energy efficiency actions where we're basically reducing load year-over-year by 2%. And so, if you that into account, we've been up about 2% or thereabouts on a gross basis for many years. But this current plan, on a five-year basis, offers about a 1% swing from where we were just in our last five year plan. And so, we're assuming little over 0.5% of growth over this five year plan, again, inclusive of our energy efficiency efforts. And so, even though Garrick highlighted that we have a pretty robust and diverse pipeline of opportunities, all we have embedded in our current five year plan are the two large projects that were announced over the last year or so with Goshen and Ford. And so, that's really all we have incorporated in our plan. And I'll tell you, candidly, we'll be disappointed if that's all we're talking about in the next two to three years, given, again, the breadth and depth of our pipeline today. So good opportunities going forward on the load front. We're already seeing that in the numbers, but I think there's more opportunity going forward.

Garrick Rochow:

We have a historic practice, and we're coming off a four or five – I have lost track now – settlements. And so, that's still part of our makeup. We're still going to look at how to – when a case is underway, how we best reach the right conclusion for our customers and for our investors. And so, we look at those opportunities. I've been on these calls before and said, I look for any opportunity for settlement when the conditions are right. But we're also comfortable going forward because we're that confident on our ability to get a constructive outcome here in Michigan. This gas case that we filed in December, fairly straightforward. I'm hopeful that we can reach a settlement. Again, if it doesn't, that's okay, too. We can get a constructive outcome here in Michigan.

Michael Sullivan:

I know this got asked like a couple different ways, Rejji, but just on the equity needs, maybe if you could just frame how to think about where they could go as CapEx goes higher as we start to roll forward with the REP refresh, like taking into context the ability to use transferability, this cushion you got for Moody's, like CapEx goes up by x, how much could that potentially increase equity?

Michael Sullivan:

Just wanted to check in the latest on the [indiscernible] looking at, performance base rates in Michigan, and where that stands and where you potentially see that going.

Michael Sullivan:

And any sense of just timing on when it could all kind of come to a conclusion?

Operator:

The next question comes from Julien Dumoulin-Smith with Bank of America Merrill Lynch.

Rejji Hayes:

That's quite a bit to unpack there. So let me start with DIG and the OCF implications. And so, everything that we've highlighted in our five year plan, so think about the rate base growth up to 7.5%, we also talked about additional opportunities attributable to energy efficiency, these are the non-rate base growth drivers of the utility FCM, and then we talked about non-utility opportunities with DIG recontracting, all of that is incorporated into our earnings as well as our cash flow generation. And so, we have a page in the appendix that shows about a little over $13 billion in aggregate cash flow generation over the course of this five year plan, and that incorporates some recontracting that we've seen at DIG on both the energy and capacity side, but it does not take into account that open margin that we have on slide 21 in the appendix and the potential opportunities if you see a higher capacity price over time. And so, there is some upside both from an earnings and cash flow perspective. So not all of that is baked into the cash flow. So there's additional opportunity there. Just transitioning over to Moody's, I'll note that the decision to increase the equity credit from 25% to 50% for junior subordinated notes, that's worth about 50 to 60 basis points of FFO to debt accretion. And then, with respect to dividend policy, we've really been very consistent in dividend policy since we sold EnerBank and started to accelerate the earnings growth of the business. And really, the idea has been to trend down to a low 60s percent payout ratio, as Garrick highlighted in his prepared remarks. And so, what that equates to is really decoupled growth between our DPS growth, our dividend per share growth and our earnings per share growth. We've said 6% to 8% toward the high end earnings per share. We'll probably be closer to the low end as the $0.11 increase today implies, and that'll be the plan going forward. Because we do believe that that's a very efficient use of capital to have the dividend policy in that level, so that we can efficiently fund the growth of the business. And so, really, that's how we're thinking about it going forward.

Rejji Hayes:

We feel very good about the credit metrics thing in that mid-teens area, which we have targeted for some time now to preserve the solid investment grade credit rating we've had for many years now, and that's with a longstanding dialogue with the rating agencies. The OCF generation, coupled with the equity needs, up to $350 million, as well as the monetization of tax credits, and again, just a very disciplined dividend policy, all of that allows us to maintain our credit metrics in that mid-teens area. And again, yes, we've increased the utility CapEx plan. We've held on to the equity needs, and those supporting factors allow us to stay in that level. And certainly, there may be opportunity longer term, but we feel very good about the metrics where they are today and don't intend to deviate from our current credit ratings. I don't think that's the implication in your question, but just wanted to say that for the avoidance of doubt.

Garrick Rochow:

Julien, to be clear, this is with respect to the new energy legislation?

Garrick Rochow:

Needless to say, as we've always talked about when we prepare, not just this five year plan or prior plans, but future plan, the key governors will be affordability, balance sheet, and can we get the work done. And as it pertains to new energy legislation, yes, it does create additional opportunities, whether that's on the capital investment side or on contracts with the financial compensation mechanism. But, trust, we will not turn a blind eye to affordability. And what makes us really excited about the opportunity going forward is when you think about our current energy mix and how we're sourcing energy, we have about $1.5 billion that we spend each year on a combination of PPAs as well as open market repurchases that we're paying a pretty high levelized cost of energy on a weighted average basis. And so, with the new energy law going into effect and the opportunities associated there with, we think there's a lot of headroom to get economics on energy going forward without increasing customer bills. Now, there's a lot more process left, as Garrick noted, but we do think there's a lot of headroom already in bills for us to potentially deliver on that triple bottom line where there's nice economic opportunity for investors, but, again, not doing that to the detriment of customers.

Andrew Weisel:

Two questions. Just to elaborate on your earlier comments, first, 2023 CapEx fell short of your target, $3.3 billion versus $3.7 billion planned. Can you just talk about what happened there? I think some of that might have been the solar delays. And then, what happened to that $400 million? It sounds like that was not part of the $1.5 billion increase. So can you just help explain what happened there?

Rejji Hayes:

Andrew, what I would add, I think you're sort of reflecting on Shahriar's question and my response to that, to be clear, we do have some of that spend that we did not achieve in 2023. Some of that is certainly pushed into this new five year plan. It's just the vast majority of the increase in this five year plan versus the prior is driven by reliability related investments. So there certainly is a portion of those deferrals being pushed into 2024 and beyond. But, again, the biggest driver of this new five year plan is reliability.

Rejji Hayes:

Andrew, this is Rejji. I'll take that. So what you're seeing here in that 2024/2025 timeframe is just we do anticipate a pretty big increase in reliability-related investments. And so, that's what's driving a lot of that. Obviously, that's going to be subject to regulatory outcomes. And so, we'll toggle the plan as needed. And I think Garrick's earlier point is well taken that, these plans, you see capital projects come in and out, some get pushed in, some get pushed out. And so, we do anticipate that smoothing out over time. And so, the composition over this five year timeframe may change, but we feel very good about the quantum overall of $17 billion. And so, you may see some of that lumpiness go in and out – sorry, smooth out over time.

Durgesh Chopra:

Rejji, can you quantify for us, of that $13 billion in operating cash flow, how much of that is tax credits monetization?

Durgesh Chopra:

That's like over the five year period, so $100 million a year, roughly speaking.

Durgesh Chopra:

And a quick follow-up. Any update on the storm review process? What's going on there? I know we're expecting a report out, I think in September this year, just any anything you could share there.

Operator:

The next question comes from Travis Miller with Morningstar.

Rejji Hayes:

It's Rejji. On the waterfall chart, just for others, reference for 2024, yeah, the $0.16 of pickup that we're seeing – or that we're anticipating year-over-year, you do see a portion of reversal related to storm activity. Obviously, I mentioned in my prepared remarks that we had a significant ice storm in the first quarter of 2023. And so, we do not anticipate storms of that magnitude year in and year out. But we also have a good portion of CE Way related savings. And I'd say it's about $60 million, or call it $0.15. And you have to think about the puts and takes here. So you've got the reversal of storms, you definitely have cost savings embedded in this current plan, but we also have inflation in other cost categories like salaries, as well as other costs, non-labor related costs. And so, there's a mix of inflation, as well as cost savings to offset or fund that inflation. And then that coupled with the reversal of the storm is what drives that $0.16 per share.

Garrick Rochow:

What I love about this energy law is there is a lot of flexibility. There's just a ton of flexibility in there. And that's a strength. And that's served us well in previous energy laws. If you go back to 2016, Integrated Resource Plan, you build a plan that works for your customers, works for your investors and allows you to deliver the energy supply that you need across your service area. Our focus right now is really on this first step, which is the Renewable Energy Plan. And that is wind, it's solar, it's hydros, we have to hit a milestone by 2030 of 50% and then by 2035 of 60%. Those are important milestones first. So that's our focus right now. Now, we're not taking our eye off the ball. Like 2040, we have to have 100% clean energy. There's a milestone along that journey as well. That will get into the carbon capture, that will get into other considerations and how we meet that. So that's a broader definition where nuclear is part of it, natural gas with carbon capture. I anticipate that, once we get this Renewable Energy Plan finalized, we're going to start looking out there at those other future sources. Right now, we would see it, given our natural gas fleet, as consideration for carbon capture as one of the options, but we're not taking anything off the table. You've got to have a wide open landscape, we've got to do right math, got to make sure we have the right plan for our customers and for our investors. So we're not saying no to anything. So hopefully that helps.

Sophie Karp:

I wanted to ask you about your prospective growth in renewable energy investments. So basically, as outlined by the new law and the filing you intend to make, I guess what we're seeing in other states and other jurisdictions right now is some sort of a push back maybe on those types of investments. And the genesis of that might be different in different jurisdictions, but it seems that the cost is often a barrier. So my question is, how do you plan to sort of avoid that? And what are the steps you've taken to socialize this plan as to not shock the regulators or intervenors or consumers [indiscernible] that becomes reality.

Operator:

Our final question comes from Anthony Crowdell with Mizuho.

Rejji Hayes:

It's Rejji. I would just say it's a pretty big lift, I would think, to get mathematically to that 17% or high teens area that Moody's and S&P have guided us toward if we wanted to get an upgrade. And so, that would require in the absence of additional equity, pretty substantial cash flow generation and/or monetization of tax credits. And so, I don't foresee that in the near term or in this vintage of our five year plan. And I've also just – observing markets now for what seems like the last 15 to 20 years. It really hasn't been worth the cost of getting to those higher credit rating levels. If you think about the juice being worth the squeeze, just the amount of coupon that you can save by having a higher credit rating has not been worth the cost of all the equity issuances and so on. We like where we are right now. We think that's the most efficient area from a credit rating perspective, to issue debt. And really, there's no appetite to equitize the balance sheet in a manner that would allow us to get an upgrade. So we feel good where we are is a longwinded way of saying that.

Garrick Rochow:

Thank you, Emily. And I'd like to thank all of you for joining us today for year-end earnings call. I look forward to seeing you on the road here in the near future. Take care and stay safe.

Sri Maddipati:

Thank you, Harry. 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 measure are included in the appendix and posted on our website. Now I'll turn the call over to Garrick.

Rejji Hayes:

Thank you, Garrick and good morning, everyone. As Garrick noted, we had a solid third quarter, delivering adjusted earnings of $0.61 per share, driven by numerous cost reduction initiatives which have largely offset the headwinds that we have faced throughout the year most recently in the form of a severe storm that hit our electric service territory in August. To put the weather we have experienced in 2023 into perspective, we are approaching a record level of storm activity this year, which further supports the needed investments in our electric system that Garrick highlighted, and we have seen heating and cooling degree days of 11% and 24% below historical levels respectively on a year-to-date basis. That said, we do not make excuses and have implemented numerous countermeasures throughout the year to mitigate these risks and are well positioned to deliver on our financial objectives this year, the benefit of customers and investors. As such, we are reaffirming our guidance for the year and on a year-to-date basis, we're on track with adjusted EPS of $2.06 per share given our progress in the aforementioned countermeasures which I'll elaborate on shortly. In the waterfall chart on Slide 7, for clarification purposes all of the variance analysis therein are measured relative to the comparable periods in 2022. The actuals are quantified on a year-to-date basis and the prospective period reflects the final three months of the year. Starting with actuals with respect to weather. The previously noted unfavorable weather experience in 2023 has driven $0.49 per share of negative go. Rate relief, net of investment-related expenses has resulted in $0.20 per share of positive variance, driven by last year's constructive electric and gas rate case settlements. From a cost perspective, our financial performance through the third quarter has been significantly impacted by higher operating and maintenance or O&M expenses to the tune of $0.21 per share of negative variance due to higher service restoration expenses attributable to storms. However, it is worth noting that our operational O&M expenses exclusive of service restoration expense are down roughly 10% versus the third quarter of 2022, which highlights the significant cost performance we've realized across the business. To that end and as previously noted, we implemented numerous cost reduction initiatives early in the year, such as reducing our use of consultants and contractors, limiting hiring, accelerating longer-term IT projects and eliminating other discretionary spending. We have also supplemented these efforts with a voluntary separation program or VSP that reduced our salaried workforce by roughly 10%. And more importantly, as we leverage the CE Way our lean operating system, we will continue to eliminate waste and increase productivity going forward. Rounding out the first nine months of the year, you'll note that $0.27 per share of positive variance highlighted the catch-all bucket in the middle of the chart. We've seen this bar increase throughout the year, as a result of our continued success in realizing cost savings through financing efficiencies, liability management, strong tax planning and favorable non-weather sales in our electric business during the summer. As we look ahead to the fourth quarter, as always we plan for normal weather, which we expect will have a neutral impact on our financial performance versus the fourth quarter of 2022. And we expect a similar financial impact for rate relief net of investment-related costs as the benefits of our recent gas rate case settlement and our 2022 electric rate case settlement are largely offset by the absence tax benefits associated with the prior gas rate case settlement. From a cost perspective as noted during our Q2 call, we anticipate lower overall O&M expense at the utility, driven by the ongoing benefit cost reduction initiatives, which equates to $0.17 per share of targeted variance. It is also worth noting that the Q4 2022 comp for this bucket is notably soft given the higher-than-average O&M expenses incurred during that period. Closing out the glide path for the remainder of the year, you'll note in the penultimate that yellow bar on the right that we're anticipating $0.23 to $0.29 per share a positive variance. As we've discussed previously, the key drivers here are the absence of significant discretionary actions taken in the fourth quarter of 2022 related to last year's electric rate case settlement and the filing of our voluntary refund mechanism which collectively equate to $0.12 per share. The remaining notable items that we anticipate in this bucket are from North Star our non-utility business achieving its full year guidance and favorable non-weather sales at the utility, which have trended well over the past few quarters. All in, we remain confident in our ability to meet our EPS guidance for the year. And as always we'll take none of this positive momentum for granted and will approach these last two months of the year with the usual degree of paranoia by maintaining our cost discipline and flex additional opportunities as needed to deliver the consistent financial results you have come to expect. Moving on to the balance sheet. On Slide 8, we highlight our recently reaffirmed credit ratings from S&P in August. As you know, we continue to target mid-teens FFO to debt on a consolidated basis over our planning period to preserve our solid investment-grade credit ratings. Our financing strategy and strong balance sheet position us well given the market volatility we've seen recently. At the utility, our annual rate case cadence and the use of forward-looking test years allow us to incorporate higher interest rates into our filings and recover the associated costs with minimal lag. At the parent where funding costs are non-recoverable, we have limited refinancing risk in the near term with $250 million due in 2024 and 2025 and $300 million coming due in 2026. And as noted during our second quarter call, the 2024 maturity has already been prefunded with proceeds from our convertible debt issuance in May. It is also worth noting that 100% of the debt of the parent companies fixed is over 40% is hybrid in nature thus receiving equity credit from the rating agencies. In addition to strong liability management, we have continued to plan conservatively. And debt funding costs have increased in the current environment they remain consistent with the assumptions embedded in our long-term financial plan. As always, we remain focused on maintaining a strong financial position which coupled with a supportive regulatory construct and predictable operating cash flow generation supports our solid investment-grade ratings for the benefit of our customers and investors. Moving on to the financing plan. Slide 9 offers more specificity on the balance of our planned funding needs in 2023. In short, I'm pleased to report that our financing plan for the year is largely completed. In fact at the utility, we've completed all of our planned first mortgage bond issuances for the year at a weighted average coupon of approximately 4.8%, which is below our planned estimate. The only remaining opco financing is a securitization funding to address the recovery of the undepreciated rate base in our recently retired coal facilities. As for the parent company given the timing of the aforementioned convertible bond issuance, we've been able to delay the settlement of the equity forwards at price last year. So the roughly $440 million of forward equity contracts will be settled in the fourth quarter. As I've said before, our approach to our financing plan is similar to how we run the business. We plan conservatively and capitalize on opportunities as they arise. This approach has been tried and true year in and year out and has enabled us to deliver on our operational and financial objectives irrespective of the circumstances to the benefit of customers and investments. And with that, I'll hand it back to Garrick for his final remarks and for the Q&A session.

Operator:

Thanks very much, Garrick. [Operator Instructions] Our first question today comes from the line of Jeremy Tonet of JPMorgan. Jeremy, your line is open.

Garrick Rochow :

Hey, Jeremy, how are you? Good morning.

Garrick Rochow :

Great question, Jeremy. I feel good about the progress of our electric rate case. And just to give you a little flavor on where we're at with that. In rebuttal we came back at $169 million. And as I shared in my prepared remarks 10.25% ROE and 51.5% equity ratio. And that reflects just the differences in the business from when we built the case to where we're at now in the forward-looking test year. Staff is at $88 million. And so the gap is pretty small between our ask and where the staff is which again I see is very constructive. And so we're really at a constructive starting point in the conversation. And much of that delta is made up with -- it's just really the cost of capital ROE and equity ratio. That's a big piece of the difference. And there's a few other what I call cats and dogs, important cash is the dog nonetheless but things that we are helpful for our customers. And so that's the big difference. Now let's talk a little bit about settlement in the context of settlement. And I've certainly been in a number of these calls where I'm open to settlement and settlement presents itself that's great. And we're certainly receptive to that. But as you pointed out there is an important mechanism in there and there's undergrounding. Those are two key things that we need to see come out of this case. Investment recovery mechanism to have some certainty on our distribution, let distribution investments in this underground pilot. This is important to get started, and there's a real benefit for our customers. And so those are harder to get in settlement just to be fully transparent. Typically, they're a black box when you go through settlement. And so we're prepared to go to the full distance. And I'll just be honest with the entire call it's likely we're going to go the full distance and I have confidence that we can get a really constructive outcome going to a full order.

Garrick Rochow :

Yes. Our non-utility growth continues to be small in the bigger scheme of things. Our primary business continues to be the utility space. So it's about a 95,5 [ph] mix. And as shared in the prepared remarks we expect them to be within guidance range. And so that's a good piece. It continues to be contracted renewables. And again Rejji uses these words singles and doubles. We're not swinging for the fences here. So just thoughtful contracted renewables. They have a utility-like return, long-term contracts assuming no terminal value again really conservative almost utility-like. And then there's the Dearborn Industrial Generation or DIG. And we continue to see upward pressure on energy and capacity prices. And so we're fully contracted out to 2025, with energy and capacity. And so we're filling in 2026 2027 in the out years. We plan conservatively, but those bilaterals and the contracts that we are inking are certainly better than expectations. Now don't read into that a sugar high. You've heard me say no sugar highs in the past. So you can anticipate 6% to 8% growth, on this again expectation toward the high side of that growth. And so we'll continue to reinvest as needed versus the sugar high. So hopefully, that's helpful as we see North Star

Operator:

Our next question today is from the line of Julien Dumoulin-Smith of Bank of America Merrill Lynch. Julien, your line is open.

Garrick Rochow:

Hey, Julien.

Julien Dumoulin-Smith:

I appreciate it. Look just following up on the -- speaking of good work the distribution plan right the $7 billion that you guys talked about there. Can you elaborate just if you think that that's really kind of incremental versus your prior plan? It seems like that's probably kind of a net $1 billion increase over five years. Can you talk about is that incremental, or as you talk about sugar highs is that going to like offset capital elsewhere, if you will to smooth things out? Just curious on how you think about that fitting into the grander plan as you update that more holistically?

Julien Dumoulin-Smith:

Absolutely. Thank you for giving all the context there. In fact speaking of context capacity markets writ large have attracted a decent amount of tension of late and certainly some of the inflationary dynamics around them. Can you speak a little bit to the status of DIG both your contracting status through the long term and more importantly, how you think about your commercial strategy here with pricing as elevated as it seems to be getting in some of these markets. So just curious, on what you guys are seeing and what the opportunity is and how that fits into the plan.

Julien Dumoulin-Smith:

Excellent. And then just quickly if you don't mind, the status of the solar projects just where that stands and the schedule for bringing those into rates. Sorry, just to clarify that. I just wanted to hit that as a last quick one.

Julien Dumoulin-Smith:

Good luck, guys. Thank you so much.

Operator:

Our next question is from the line of Shahriar Pourreza of Guggenheim. Shahriar, your line is now open.

Rejji Hayes:

Shar this is Rejji. Yeah, so we're still in the relatively early stage of building out -- sorry Shar? Shar, this is Rejji if you can hear me. So we're in the early stages of rolling out our five-year plan. So we're still calibrating where -- what the financing needs will be. As I've said before, the estimate that we have in our current five-year plan, where we said up to $350 million a year of equity starting in 2025. I don't see that number materially changing. Now, as the CapEx plan increases again we always recalibrate you may see a slight shift upward but we -- we have to take a look at all of the puts and takes the capital investments the cash flow generation. And I think at the end of the day you're not going to see us with any sort of need to do block equity. I still think even without seeing the numbers we'll be able to double out the equity in those outer years. But again, still early days on those calculations.

Garrick Rochow:

So there's two pieces. And I wouldn't put a negative take on it. All the conversations we have with staff and commissioners continue to be constructive and frankly we're both aligned in the same thing. We want to improve reliability. We have a longer-term view of resiliency. And when we're aligned it makes for constructive conversations. But there's two pieces that I'm hearing in your question Shar. There's one there's the audit that's underway. That was started in September. Liberty Consulting Group is the one doing the work. They've participated with other utilities very skilled organization. Right now they're in the data collection phase that's well underway. We expect an interim report about the end of the year and then a full report likely in the September-ish time frame. It's not about a year report then. But I would just be fully transparent with you and honest I want reliability to improve in the state. I want resiliency and improvement in the state for our customers. And so if they have findings on how we can do work better, my gosh, I'm just going to agree to them. Like we should build that into the next electric grid case. We should do that because we want it better for our customers. And so it doesn't bother me at all. I think this is good that we have an outside party looking and looking at how we can improve. It's only going to add to our reliability road map. And the other thing is on this performance-based rates or PBR, the work group is underway. It was initiated in the first second quarter time frame April-ish time frame I believe. And so that conversation is underway, proposal was put out. We have put comments through that process. We're continuing to participate in work groups. At the end of the day I think you're going to have a nice balance of incentives disincentives from an electric reliability perspective. But the important piece for us is making sure there's a nice line of sight into capital and the capital recovery and there's certainty. That's why we're so focused on this investment recovery mechanism. We also think the same thing is required for storm and some of the O&M expense that occurs in the year. As long as we can navigate all that and get to that point I feel good I feel good. This will lead to good outcomes for our customers.

Operator:

Our next question today is from the line of Andrew Weisel of Scotiabank. Andrew, your line is open.

Garrick Rochow:

Hi, Andrew.

Garrick Rochow:

Well, first of all, I appreciate your analysis. You did a nice write-up on that. It was about a week ago, two weeks ago. So some good work of what's going on in the industry. And so we're highly focused on the supply chain. I'll give it over here to Rejji a minute. He has responsibility for that area. They've done a lot of good work to be able to secure that line of sight. And so when I think about the projects we have underway, particularly those that are in mid-development. The team has done a much better job to make sure we have panels, transformers and the like so we can do that build. Now, there's longer lead times, most definitely. And so you've got to be prepared and you've got to be planned in that but the team has just done a phenomenal job. But Rejji, your team is doing great work, maybe add to it.

Garrick Rochow:

I just got to know something. Just a Rejji's dexterity great CFO, and when you can talk about amorphous core, that's really awesome to see.

Garrick Rochow:

So I'll start with the big picture and the Governor's first term, she came out with her healthy climate plan. And that was a nice plan, supportive of the plan very pragmatic and balances clean energy, reliability of supply and affordability. And the Governor came out in August and said -- now in her second term and came out and said, hey, I want to make a portion of this into law. And that's been in the Senate right now. It started out in committee. And so there are a number of bills that were put together on that as you imagine in Committee there's a discussion and we're actively engaged in that discussion. And so that's moved on now to the full Senate for consideration still has not made it to the House. And so there's important work going on to define what that looks like. But I'll just, again, stand back and look at the bigger picture of this, much like 2008, much like 2016, this legislative body as well as the Public Service Commission continues to provide a constructive approach to the future. And we see a constructive out of these bills, if they even move forward and if they even get agreement we see a path of constructive regulation going forward and a constructive policy going forward. And so -- but that's currently where it stands, Andrew.

Garrick Rochow:

Yes. Thank you.

Garrick Rochow:

Good morning, Durgesh.

Rejji Hayes:

Yes. Durgesh, this is Rejji. I appreciate the question. And I appreciate also the compliments. We are really proud of the work done for the first three quarters of the year offsetting the headwinds we've seen on the weather side both in terms of mild weather as well as the storm activity and the organization has really rallied around the cause. Obviously, when it comes to cost savings, we never discriminate when it comes to operational versus non-operational and we've been quite expansive in our approach. To get to the spirit of your question, I think it's difficult to quantify to what degree the savings will be sustainable. And I do think a decent portion will be because when you think about the separation plan that I mentioned we reduced our salaried workforce by roughly 10% and we do not assume that we will go and re-staff that over the next year or two or even next several years. And so, we'll see sustainable savings from that and that will be a significant portion. Some of the other bigger opportunities. So in Q2 the tender financing obviously that is a one-timer and so we wouldn't count on that being sustained. But there are other opportunities we've executed on. We've been really disciplined and rationalizing our contractor base and some of the consultants we're working with again, we'd like to think we can sustain that. And as I mentioned in my prepared remarks, we accelerated some longer-term IT projects and we think we'll see productivity from those actions for some time now. So I'd say it's tough to really ascribe a specific percentage, but I'd say decent portion should be sustained going into next year and will provide some tailwinds when you think about not just our guidance next year but also affordability because we always look forward to passing on those savings on the customers. And the last thing I'll note is on the financing side, we've seen quite a few efficiencies with the convert where we pulled ahead some costs that we were going to have or some financing needs we had in 2024. That's going to have a sustained level of savings and the operating company financings we've done those in a really efficient fashion at a weighted average coupon of 4.8% below plan. And so we'll see sustained savings from that. So I'd say on the operational and non-operational side you've got some one-timers and then some of that will be sustained but I can't give you a specific percentage at this point.

Rejji Hayes:

That's exactly right.

Rejji Hayes:

Thank you.

Rejji Hayes:

Hi, David.

Rejji Hayes:

Yeah David. Appreciate the question. This is Rejji. So as you think about the glide path to deliver on the guidance we initiated today, we're guiding $3.06 to $3.12 in 2023 and then $3.27 to $3.33 in 2024. And so that implies somewhere around $0.20 of pickup year-over-year to get to midpoint to midpoint or thereabouts. And so as I think about it, obviously, the weather we had this year we're looking at roughly $0.30 of weather and that's just the mild weather experience over the first three quarters of the year and we anticipate basically being flat in the fourth quarter. So you have to imagine that because we plan for normal weather, we shouldn't anticipate that $0.30 of weather impacting us next year. Now the reality is there have been some one-timers as I've mentioned in my prior remarks on the tender financing side. And so we'd have to assume that those don't recur as well. And so when you net the two of those out you get about $0.10 of pickup. And then if you think about the pending rate case we have. We had a very constructive gas rate case settlement in the third quarter of this year that was approved by the commission. We've got a pending electric rate case and then we'll file another gas rate case in December this year. And with the anticipation of constructive outcomes on those proceedings that offers about per-preliminary estimates maybe somewhere between $0.10 to $0.15 net of investment related costs of pickup. And then again a lot of the cost savings I enumerated earlier, we expect a decent portion of those to be sustained and so we'll get additional pickup there. And so you can get to a glide path of that $0.20 per share again for that year-over-year growth relatively easily when you look at those pieces. Now there are always puts and takes. And again there are some things that will roll off going into 2024. And I think what's highly debatable is will we see the same quantum of service restoration expense going into next year because clearly we've had a record level of storm activity as I noted in our prepared remarks. And so as we think about the glide path it's going to be a combination of rate relief, net of investment-related costs with our pending proceedings. We'll see the weather roll off. We'll see some of the one-timers roll off. And then we expect some of the savings from a lot of the cost reduction initiatives to provide a tailwind on a net basis next year as well. So that's what gives us confidence that we can deliver on the 2024 guide. Is that helpful?

Garrick Rochow:

Yeah, it continues to be very positive. And so remember we're in what I'd call a tranche of 1,000 megawatts that is being contracted out. There's significant demand from our customers for those products. We're well over 400 megawatts of contracted lower that continues to grow. And then that's driving to more build from a renewable perspective. And so we've announced even within the quarter the intent to build a solar facility in the current -- coal facility that will help meet some of that -- a portion of that need. So again very robust continued strong interest from our commercial and industrial customers.

Operator:

And our next question today is from the line of Nicholas Campanella of Barclays. Nicholas, please go ahead.

Garrick Rochow:

Great question. I'm glad you're digging into it. That's a fun plan to look at. Right now -- and that's why I shared in some of my prepared remarks like we're not waiting. And the commission has been supportive of additional tree removal or vegetation management. That's more than doubled our spend over the last three years. So that's active work that's underway. There's close to 300 crews that are on our system contracted crews that are out doing that work today and have been over the course of the year. And we -- in those areas where we do the work we see greater than a 60% improvement well underway. In addition to that fusing, 15,000 fuses over the last two years and a plan to do more next year as well. That takes -- when there's an interruption on the system like fuse box in your home. And so rather than the whole home going out you might lose the bathroom or the kitchen. Same type of thing on the electric. We're fusing that. So when there's an interruption, less customers are impacted. We're seeing SADI performance improvement already from the deployment of those fuses. We've never done this level of fusing, never across our history. We continue to add automation. I just saw a great one the other day being able to -- one of the things on our high-voltage distribution system we've got what's called a Victor insulator. Now Victor insulators are prone to failure. That's a known problem. But once you put them on the grid back in the '70s we didn't have the best kind of control on where those went. And so to be able to identify them you got to be able to see the small little D on top of the Victor insulator. Before we got to stick a bucket truck up there to see that. That's very inefficient. Now with drones, with the ability to automatically pull from a picture to see that little D, we're able to find that find those victor insulators and be very strategic about replacing them. So I'm excited about the technology we're bringing to bear as well. And so those are just a few examples. There are hundreds of examples like we are not satisfied with our reliability performance. We are going to make it better. We've seen the improvement over 2022. We continue to be on good pace this year even with the storms. And so -- and we're going to keep the -- sorry with the analogy, we're keeping the foot down on the floor on the accelerator on this.

Operator:

Our next question today is from the line of Travis Miller of Morningstar. Travis, please go ahead.

Garrick Rochow:

It's going to be -- those will get woven into electric rate case filings. And so the plan by itself will get some comment, but that's not a contested filing. What will happen is those -- that will be the -- it's truly a road map. It's really a vision of where we're headed and the important pieces that have to come together for that. And so, those get brought into electric rate case filings and then with commission support they can be approved. I would just highlight one thing, one announcement we've had here in the last couple of weeks though Department of Energy grant of $100 million. That really jump starts some of this important work. And so, again to the previous question, we're not waiting around. We see some opportunities to put this to work immediately. But again the regulatory process is through the rate cases.

Garrick Rochow:

Yes, you should expect an annual rate case type filing and I would just offer to in these particularly with the interest rates the way they are 10-month rate cases and forward-looking test years and the kind of the annual strategy really eliminates some of that drag that you get with higher interest rates. And so, there's a lot of benefits of that approach.

Garrick Rochow:

It will still be a one-year approach. The IRM is not big enough at this point. It's a starting spot. And over time, we'd look to enhance that. The first step is to get it in place which is part of this current electric rate case.

Garrick Rochow:

Thank you, Travis.

Sophie Karp:

Hi, good morning. Thank you for taking my questions. A lot of questions have been answered but I wanted to ask you about the cost of capital and like the ROEs, right? So a bit of a push-pull in Michigan as in many other states right now. I'm just kind of curious how the conversations about the need for higher ROE lending with the stakeholders at the commission. Like I'm not sure a few people are catching on to how fast the rates have risen and that really needs to you're going to have some adjustment to how they are as viewed I guess in the last few years. So any color on that would be helpful.

Sophie Karp:

Got it. Thank you. And then maybe if I can squeeze one more in. You've been doing your underground in pilots. And I'm just curious what have you learned so far from this pilot project maybe in terms of cost or approach that needs to be taken. Curious if you can provide any color on how that is going.

Sophie Karp:

All right. Thank you so much.

Operator:

And our next question today is from the line of Anthony Crowdell of Mizuho. Anthony, your line is open.

Garrick Rochow:

Good to hear from you, Anthony.

Ross Fowler:

Hi, Garrick, hi, Rejji how are you?

Rejji Hayes:

Hey, Ross. How are you?

Garrick Rochow:

So I don't know if I have any auto analogies for this one. We talked about this in great detail and I provide probably a long answer maybe too long an answer on the Q2 call. So I'll try to be brief but this is just the next step in that. And so what I shared back again briefly what I shared in Q2 was recall that we had some 3G meters that were no longer supported. Our vendor could not meet some of the supply chain needs again considered a carryover from the pandemic and did not meet some of the read required reads out in the field. And so that creates some billing issues for our customers. That's a problem. And the Public Service Commission clearly identified that. And so we shared in our Q2 call that that issue is behind us. We filed a report in August and this is the next step to reach resolution. And so I don't it's an important step. It gets us to the final end of this with the commission. I don't see any spillover impact into the electric rate case or in any other filings.

Garrick Rochow:

Thank you, Ross.

Garrick Rochow:

Thanks, Harry and I'd like to thank you for joining us today. We'll see you at EEI. Please take care and stay safe.

Sri Maddipati:

Thank you, Michelle. Good morning, everyone, and thank you for joining us today. We apologize for the delay as we're experiencing technical difficulties. If you have any questions and we're unable to participate on the call, please feel free to give me or Travis Uphaus a call after this earnings call. 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.

Rejji Hayes:

Thank you, Garrick. And good morning, everyone. We had a strong second quarter, delivering adjusted earnings of $0.75 per share, driven by numerous cost-reduction initiatives foreshadowed on our Q1 call, which I will elaborate on shortly. Our financial performance over the past few months has materially offset the weather-driven challenges we faced in the first quarter. As such, as Garrick noted, we are reaffirming our guidance for the year. And on a year-to-date basis, we're on track with adjusted EPS of $1.45 per share, given the back-end weighted nature of our plan this year. As you can see in the waterfall chart on Slide 7, weather has been a significant headwind to our financial performance in the first half of this year, driving $0.37 per share of negative variance versus the comparable period in 2022. Rate relief, net of investment-related expenses has resulted in $0.06 per share of positive variance versus the first half of 2022, driven by last year's constructive electric and gas rate case settlements. From a cost perspective, our financial performance in the first half of the year has been significantly impacted by higher operating and maintenance, or O&M, expenses to the tune of $0.15 per share versus the comparable period in 2022, attributable to storm restoration costs in the first quarter. However, it is worth noting that our operational O&M expenses, which represent the majority of our O&M expense and primarily exclude costs associated with our energy waste reduction programs and employee benefits, have trended favorably during the second quarter and we're down roughly 10% versus the second quarter of 2022. So we're seeing the fruits of the numerous operational cost-reduction initiatives we put in place earlier in the year, such as reducing our use of consultants and contractors, limiting hiring, accelerating longer-term IT cost-reduction initiatives, and eliminating other discretionary spending. And of course, leveraging the CE Way, our lean operating system. We anticipate that our strong cost performance will continue as we move through the second half of the year. Rounding out the first six months of the year, you'll note the $0.18 per share of positive variance versus the first half of 2022, highlighted in the catch-all bucket in the middle of the chart. The primary source of upside here was related to financing efficiencies. In short, we capitalize on attractive conditions in the convertible bond market by pricing an $800 million issuance and using the majority of the proceeds to pre-fund future parent company financing needs. Usually, pre-fundings like this are subject to negative carry. However, given the current inverted yield curve, we've managed to reinvest the proceeds at deposit rates favorable to the underlying funding cost. Lastly, we used the balance of the proceeds from the convert offering to tender a portion of select bonds well below par, which has de-levered our balance sheet. All in, this opportunistic financing transaction was earnings accretive and has further strengthened our liquidity position. Looking ahead. As always, we plan for normal weather, which equates to $0.06 per share of negative variance versus the comparable period in 2022. Due to the absence of strong sales of the electric utility driven by last year's warm summer, we anticipate that the estimated negative variance attributable to weather will be more than offset by rate relief, net of investment-related cost, which we have quantified at $0.08 per share versus the first half of 2022. Our estimates reflect the terms of our recently filed gas rate case settlement agreement, which is subject to Commission approval, and the residual benefits of our 2022 electric rate case settlement. Closing out the glide path for the remainder of the year. As noted during our Q1 call, we anticipate lower overall O&M expense of the utility driven by the ongoing benefits of the aforementioned cost-reduction initiatives, some expected favorable year-over-year variance related to service restoration costs, and the usual cost performance fueled by the CE Way, which collectively equates to $0.26 per share of positive variance versus the comparable period in 2022. Lastly, as we discussed during our first quarter call, we're assuming modest growth at NorthStar and the benefits associated with the roughly $0.12 per share, a pull-ahead exercise in the fourth quarter of 2022. As per our original guidance, all in, we estimate these items will drive $0.17 to $0.23 per share positive variance versus the comparable period in 2022. In summary, we've made great progress to offset the challenging weather experienced in the first quarter, but needless to say, we'll continue to plan conservatively and execute as we always do. Moving on to the balance sheet on Slide 8, we highlight our recently reaffirmed credit ratings from Moody's. As you know, we continue to target mid-teens FFO-to-debt over our planning period. As always, we remain focused on maintaining a strong financial position, which coupled with a supportive regulatory construct and predictable operating cash flow growth, supports our solid investment-grade ratings to the benefit of customers and investors. Moving on to the financing plan. Slide 9 offers more specificity on the balance of our planned funding needs in 2023, which are limited to debt issuances at the utility. This includes both first mortgage bond financings and a securitization financing to address the recovery of the undepreciated rate base at the recently retired Karn coal facilities. As for the parent company, given the timing of the convertible bond issuance, we've been able to delay the settlement of the equity forwards that priced last year, so the roughly $440 million of forward equity contracts will be settled commensurate with the needs of the business over time. As I've said before, our approach to our financing plan is similar to how we run the business. We plan conservatively and capitalize on opportunities as they arise. This approach has been tried and true, year in and year out, and has enabled us to deliver on our operational and financial objectives, irrespective of the circumstances, to the benefit of our customers and investors. And this year is no different. And with that, I'll hand it back to Garrick for his final remarks before the Q&A session.

Operator:

Thank you very much, Garrick. [Operator Instructions] Your first question will come from Jeremy Tonet of JPMorgan. Please go ahead.

Garrick Rochow:

Hi, good morning, Jeremy. How are you?

Jeremy Tonet:

Good, good, thanks. Maybe just wanted to start off with the undergrounding pilot, if we could, and just wondering if you could expand a bit more I guess on what would define success there or I guess future outlook for how quickly that could fold into the plan in larger size over time.

Jeremy Tonet:

Got it. That's helpful, thank you for that. And storms have been topical in Michigan, obviously, in recent time here. And just wondering if you could provide a bit more color, I guess, on your efforts, hardening efforts and where you stand, where do you want to be to improve resiliency there, and just kind of how you feel local stakeholders are aligned against those - against this outlook in the state.

Jeremy Tonet:

Got it, that's helpful. I'll leave it there. Thanks.

Operator:

Your next question comes from Julien Dumoulin-Smith at Bank of America. Please go ahead.

Garrick Rochow:

Hi, Heidi.

Heidi Hauch:

Hi. Just first question, noting your plans to file another IRP in the next year or two, do you see any read-throughs for your next IRP related to the latest peer IRP settlement approved by the Michigan PSC, either from the coal retirement front, renewables investments or otherwise? Thank you.

Heidi Hauch:

Great, thank you. And then a second question from me, can you comment on the latest MPSC investigation into the natural gas meters and new service delays? How are you planning to address or improve these issues, and are there any potential capital opportunities that may result from this investigation? Thank you.

Heidi Hauch:

Thank you.

Michael Sullivan:

Hi, everyone, good morning. Can you hear me okay?

Rejji Hayes:

Good morning, Mike.

Rejji Hayes:

Yes, Mike, thanks for the question. Yes, we will still plan to settle the equity. It will likely be, I'll say the back half of this year and deep into the second half, so call it late Q3 or in Q4. But we do still plan to settle the equity over the course of this year.

Rejji Hayes:

No, the convert transaction was for all intents and purposes, when you take into account all the puts and takes, is effectively credit-neutral, maybe modestly accretive. And then the delay of the equity settle, again it's still going to take place over the course of this year, so again, all credit-neutral. And so we'll still be right in that mid-teens area and well in alignment with the expectations of the credit rating agencies so we can maintain our investment-grade ratings.

Rejji Hayes:

Thank you.

Garrick Rochow:

Thanks, Michelle. I'd like to thank you for joining us today. We'll see you on the road too. Take care and stay safe.

Sri Maddipati:

Thank you, Billy. 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.

Rejji Hayes:

Thank you, Garrick, and good morning, everyone. For the first quarter of 2023, we delivered adjusted net income of $204 million or $0.70 per share, largely driven by unfavorable weather and costs related to service restoration as a result of the significant storm activity that Garrick noted earlier. To elaborate on the impact of weather on sales, given the well-publicized warm winter experienced in the Midwest, the number of heating degree days in our service territory during the quarter were approximately 18% below normal weather pattern. The atypically warm weather, coupled with a strong comp in the first quarter 2022 resulted in $0.27 per share of negative variance versus the comparable period in 2022, as noted on Slide 7. Rate relief, net of investment-related expenses, resulted in $0.03 per share of negative variance as last year's constructive electric and gas rate case settlements were offset primarily by the roll-off of tax benefits realized in the first quarter of 2022 associated with the prior gas rate case settlement as expected. From a cost perspective, as mentioned, our financial performance in the first quarter was significantly impacted by higher operating and maintenance or O&M expenses attributable to storm restoration costs, which resulted in $0.20 per share of negative variance versus the first quarter of 2022. It is worth noting, however, that given the elevated storm costs we've seen over the last few years, we have incorporated fairly conservative assumptions for this cost category in our full year forecast. Looking ahead, as always, we plan for normal weather, which equates to $0.14 per share of negative variance versus the comparable period in 2022 due to the absence of strong sales at the electric utility driven by last year's warm summer. We anticipate that the estimated negative variance attributable to weather will be more than offset by rate relief net of investment-related costs, which we have quantified at $0.17 per share versus the comparable period in 2022. Our underlying assumptions for rate relief are largely driven by last year's successful gas and electric rate case settlements, and we have assumed a constructive outcome in our pending gas rate case. Closing out the glide path for the remainder of the year, as noted during our Q4 call, we anticipate lower overall O&M expense to the utility driven by the usual cost performance fueled by the CE Way. And in light of the weather-related headwinds in the first quarter, we have supplemented our planned productivity for the year by limiting hiring, reducing our use of consultants and contractors, accelerating longer-term IT cost reduction initiatives and eliminating other discretionary spending among other activities. These cost performance measures will support the $0.28 per share of positive variance versus the comparable period in 2022. And I'd be remiss if I didn't mention that none of these actions will impact the safety and reliability of our electric and gas business. Lastly, as we discussed during our fourth quarter call, we're assuming modest growth at NorthStar and the benefits associated with the roughly $0.12 per share of pull-aheads achieved in the fourth quarter of 2022 as per our original guidance. And to offer further risk mitigation of the financial headwinds encountered in the first quarter and provide additional contingency should we need it, we have supplemented these opportunities with anticipated cost savings at the parent largely in the form of opportunistic financings and tax planning, which in aggregate, we estimate will drive $0.36 to $0.42 per share positive variance versus the comparable period in 2022. Before moving on, I'll just note that though our track record of delivering on our financial objectives over the last two weeks -- two decades speaks for itself, we remain perpetually paranoid in our financial planning process. More bluntly, we always do the worryings, so you don't have to. And to that end, I'm pleased to report that we've already begun to see the benefits of the numerous countermeasures implemented in the first quarter. As such, I'm highly confident that we will realize the balance of expected savings over the course of the year. Moving on to the financing plan. Slide 8 offers more specificity on the balance of our planned funding needs in 2023, which are largely limited to debt issuances at the utility, a good portion of which has already been priced and/or funded over the past several months. As we have noted in the past, the parent's contribution of the funding needs of the Covert acquisition is in place with roughly $440 million of forward equity contract. This equity will be issued in connection with the acquisition of the facility and we have assumed the associated EPS dilution in our full year guidance. While we don't have any further required financing needs at the parent this year, we will continue to evaluate opportunistic financings to derisk our future funding needs if market conditions are accommodative. Our approach to our financing plan is similar to how we run the rest of the business. We plan conservatively and capitalize on opportunities as they arise. This approach has been tried and true year in and year out and has enabled us to deliver on our operational and financial objectives, irrespective of the circumstances, to the benefit of our customers and investors, and this year is no different. And with that, I'll hand it back to Garrick for his final remarks before the Q&A session.

Operator:

[Operator Instructions] Our first question today comes from the line of Jeremy Tonet from JPMorgan. Please go ahead, Jeremy, your line is now open.

Garrick Rochow:

I have confidence in our ability to deliver. That's the first point, Jeremy. And we know there's a lot of year remaining. And so really in all our efforts, we look to build contingency out throughout the year. And so maybe if I just take a step back because I know this is a popular question today and just talk about our playbook. Rejji alluded to it, but let me offer a little more specifics. And I'd break it into really five areas. The first one is we plan conservatively. And you know this, Jeremy. We've done this year after year after year. That's what leads to our consistency, one of the reasons we had consistent financial performance. And also, we talked about this in Q4. What we did in 2022 to derisk the year. And then just adding to Rejji's points, we budget for storms, and we buy it conservatively for storms because we know they occur throughout the year. And so in many cases, this is just a weather story. So the first piece is just we plan conservatively. The second piece of the plan is the CE Way. And you -- this is another strong suit for us. And I'll remind everybody, it's industrial engineering, and it's a lean operating system. It's science, it is proven throughout the years for many different companies. And I see a great opportunity that we continue to deliver on year after year. Scheduling optimization is one example underway right now. We're making capital IT investments to get other efficiency improvements. It improves customer satisfaction while reducing costs. Our run rate has typically been around $50 million a year, as you know, and there's a lot more muscle we have there. The third piece is really around the labor piece. And that is what you would expect. We released some consultants. Our contractors are flexible, so we dialed that down a bit. We pinched back on overtime and then we hold on hiring. And so those things help as well. The fourth area is really discretionary spending. It's limiting conferences and travel and some of the training. And you think that's small, but it's actually big when you apply it across the entire company. And then the fifth piece and Rejji hit on it was, good tax planning and just opportunistic financing. And so that's the recipe. And as I said, this isn't our first rodeo. If you go back to the pandemic, we had to find $100 million. 50% of it came through the CE Way, 50% through other actions, very similar to what we're doing right now. And so we're going to chin this bar, and we're going to add some contingency throughout the year. So I feel very confident in our ability to deliver and to weather whatever Mother Nature throws at us throughout the year.

Garrick Rochow:

First things first, this is a good and constructive starting point. If I was just to dissect it a little bit for you, what we saw from staff in the AG as far as ROE was better than previous staff and AG positions. And so that bodes well for an ROE and some of the financial metrics. The other important piece is we build that -- remember, we built that case over Q3 and Q4 last year. And so gas prices were rising. We also saw some expense from pension OPEB perspective, but when you fast forward to today, those have changed. And so gas prices are lower. We snapped the line at the end of the year on pension and OPEB expense. And so we got a $212 million ask, but that effectively pulls that down because the fact pattern is different than what we saw when we built the case. And then the big piece is that people are talking about here is the sales forecast. And there's about $10 million, $12 million difference there. And so let me walk through that. We have used this method since 2010 to project sales. It's a 15-year regression type model. We haven't changed a bit. It's tried and true and it's accurate. And here's the important point. Back in 2010, the commission ordered us, let me repeat, the commission ordered us to use this method. That was in case U15986. And so we're doing exactly what the commission told us to do. So we feel like really good about where we're positioned there. And so there's a lot of cats and dogs, but bottom line, take this away, it's a good constructive starting point. The other thing you asked about settlement, we'll always look for the opportunity for settlement, but again, we sit in a very constructive jurisdiction. So I'm very comfortable taking it to the end and getting it forward from the commission.

Julien Dumoulin-Smith:

Good morning, team. Let me follow up on the first question here just around the uptick in usage, nonutility tax and other. You guys elaborated on it. So not only have you pressed some of those levers to see the quarter-over-quarter change in '23 and the range, right? You're talking about $0.36 to $0.42 of positive offsets there now, but in addition to that, you've got further levers to go to the extent in which they might materialize. I just want to make sure I understand the comment from earlier.

Julien Dumoulin-Smith:

Excellent. Fair enough. And then just following up on some of the conversation on regulatory mechanisms. You talked about including an investment regulatory mechanism in your upcoming case. Can you talk about what that looks like? And perhaps talk about that in parallel with some of this conversation on ring-fencing here? I mean how do you think about reincenting to isolate spending on specific subject areas? It sounds like this IRM might be related? And then Also, maybe you could talk about ring fencing in the context of veg management efforts.

Julien Dumoulin-Smith:

Yes, absolutely. So perhaps let me just make sure I'm hearing you right. This would that help address some lag related considerations, perhaps shift timing of future cases? Or is this principally about accounting and accountability back to the commission to just make sure the dollars and cents are getting spent in the right bucket?

Julien Dumoulin-Smith:

Got it. Excellent. And then on the veg management, just quickly, just with respect to that side of the equation, obviously, been a lot of focus on that front. Your commentary saying that you've increased it from 2020, helpful. Any further efforts in that regard? And obviously, there seems to be an acute desire or need for that. How do you think about allocating even more in that direction at this time?

Rejji Hayes:

Yes, Julien, the only thing I would add is that when we think about the planning year and particularly years in which we have a little bit of upside or contingency, usually vegetation management is one of the first items that comes up on the Flex list. And last year, in fact, and we were -- had a little bit of upside that was weather driven. We did about $5 million or so of flex related to vegetation management. So our actuals, even though we've budgeted around $100 million as Garrick noted for last year, I think our actuals were closer to $105 million, certainly over $100 million. And so Flex is an opportunity for us to do additional vegetation management. And then remember, we have that voluntary refund mechanism, which is also a vehicle through which we can do incremental operating expenses. And so the current voluntary refund mechanism that we have outstanding, we've targeted about $8 million towards additional vegetation management this year out of the $17 million that we allocated to the electric business. And as you know, we obviously pulled that lever in Q4 of last year for $22 million all in. And again, a portion of that will be allocated towards vegetation management, assuming we get Commission approval. So that's the other mechanism we have as well.

Shahriar Pourreza:

Sorry if I missed this, but I just wanted to maybe just round out the storm discussion. I guess, do the storms -- do they -- will they lead to more resiliency spend? Is it going to increase CapEx? Or do you see offsets to CapEx? Are you going to sort of seek any kind of new mechanisms? I mean, some things are already in rider-like items. Would resiliency kind of get that similar treatment? I guess overall, just how do these storms kind of change your thoughts around the 5-year plan?

Shahriar Pourreza:

Yes. And I guess the question is, should we be looking at these incremental investments as extending the runway of your growth or accretive to your growth?

Shahriar Pourreza:

Got it. Got it. And then maybe just shifting to financing. Financing is -- it's been a bit of a tough headwind, but interest rates seem to have moderated year-to-date. I guess how are you trending versus the embedded interest cost and plan in terms of '23 and maybe even opportunities for some cushion versus '24 since rates have come down versus your original expectations?

Operator:

Next question today comes from the line of Durgesh Chopra from Evercore. Please go ahead. Your line is now open.

Garrick Rochow:

Yes, broadly, from the storm audit perspective, so they started that last fall. And in the process of selecting the vendor right now or the firm right now, and we anticipate that to start in the September time frame. But I'll remind you the big picture perspective on the storm audit is that, we're both aligned. That being the Commission and CMS Energy aligned that we need to improve reliability. And so I really view this as an opportunity to be able to get further alignment on the needed investments in our system. I'll give you a great example of undergrounding. We want to do more undergrounding. And if we look at our Midwest peers, they're around 35%, 40% underground. We're at 10%. It goes back to Shar's question. Is there opportunities for investment? There's a lot of them. And so we see that as important. You can look at the EPRI, Electric Power Research Institute and they'll say undergrounding improves reliability, depending on if it's three phase or single phase by 50% to 90%. And so this is a great example where we need -- with the storm model, we can utilize this to get better alignment on immediate investments in the system. And once we have that alignment, then again, we can move forward and get greater certainty around those investments. Does that help, Durgesh?

Garrick Rochow:

I don't see anything punitive. No.

Garrick Rochow:

Yes. I'll tag team with Rejji. Just the context around this. These are pretty small dollars. And the bottom line, we have this option to file a voluntary refund mechanism. And we did that in 2022, the dollars are booked in 2022, but it's not a cake walk, like it's not assured that you're going to get approval, staff and the commissioners have a say in that, right? And they really telegraph the importance of incremental forestry and some other things with our customers in terms of helping out those low-income customers. And so they've really given us another opportunity at the bat, and we filed that here on April 21 to reflect the commissioners and staff comments. And so I feel good about getting to a positive outcome on that and it's just navigating kind of the back and forth of the process, Durgesh.

Operator:

Next question today comes from the line of David Arcaro from Morgan Stanley. Please go ahead. Your line is now open.

Garrick Rochow:

Great question. Let me -- I think perspective is really important here because often in Lansing, just part of bill. There's a lot of back and forth, and there's media releases and then you just got to kind of clear the air and talk about it from a big picture perspective. And so I'll remind our listeners here that in the governor's first term, she introduced a healthy climate plan. And in fact, one of the members on my direct staff was one of the stakeholders in that process and was involved in the review and kind of the language around it. And then I participated with a group of about eight to 10 CEOs and the governor in the review process. And so that -- the governor's called the climate plan lines up really well with where we're headed from a state perspective, but also lines up well with our current IRP and the like. Now the legislature has -- the Senate specifically, has introduced some new builds that are a little bit more aggressive, but I want to remind everybody, this is the back and forth of Lansing. And that's the first starting point. That's the first valley you might say. And so we're going to continue to navigate that and move forward with that and manage that process. Ultimately, at the end of the day, if it requires something -- for us to do something sooner, we'll do that sooner. And that will mean more capital investment opportunities. But I want to let everyone know it's really manageable and, again, well aligned with where we're already headed.

Rejji Hayes:

David, this is Rejji. Appreciate the question. Yes, weather normalized trends, I will admit we were scratching our heads a little bit at the trends that we saw. And just for everyone's benefit, we saw residential about 2.5 -- a little over 2.5% off versus Q1 of 2022. Commercial, a little over 3.5% off versus Q1 of 2022. Industrial was flat excluding one large low-margin customer. And then total was down about a little over 2.5% versus Q1 of last year. And I would say it's really early days. We are still digging into the data. I would just start by saying, as hard as our sales forecasting team works, weather normalized math is a combination of art and science. And when you see, I'd say, dramatic weather like we saw in Q1 of last year, where it was extremely cold and then a pretty warm winter as we noted earlier, Q1 of this year. You can see a good degree of imprecision in those calculations. And so I say all that to say, we're looking at it with a little bit of a skeptical eye because the reality is we're still seeing very strong economic indicators in the service territory. Our customer count specifically for commercial, we're up almost 0.5% -- over 0.5% to almost one point across the electric and gas businesses residential customer counts are still up. And while we have built into our guidance, that continued return to work, we're still seeing a good level of really not every company in Michigan at this point has four, five days in the office. And so we still think as we get into the summer months, we may see some of that favorable mix we've seen in the past. And so I would say early days, there's probably a little bit of noise in the data. And I'll just say on the industrial side, we were flat again versus where we were last year, but we couldn't have a more robust economic development pipeline borne out of a lot of the constructive federal legislation that's been passed over the 18 months. And we continue to look at our trends versus pre-pandemic and across every customer class we're doing as well, if not better, than what we were doing pre-pandemic, particularly when you take into account our energy efficiency programs, which effectively reduced our load year-over-year by 2%. And so again, I don't think what you're seeing in Q1 and then the data is indicative of the economic conditions in Michigan. I think it's just more a weather-normalized math versus anything else.

Michael Sullivan:

You guys answered a lot here. I just had a couple of small follow-ups on what's already been discussed. So just on the undergrounding, can you maybe just give us a sense on what the long-term target is there? How much of the system you are looking underground and over what period of time you'd like to get there?

Michael Sullivan:

Okay. Very helpful. And then kind of a similar question just following up on the IRM. I think the context you gave on the gas side was helpful in terms of where it started and where it's gotten to. Can you maybe frame that on the electric side? And I know you haven't officially filed the next case yet, but just kind of where that could start and ultimately go?

Operator:

The next question today comes from the line of Andrew Weisel from Scotiabank. Please go ahead. Your line is now open.

Garrick Rochow:

I'm glad too. Thank you.

Garrick Rochow:

So what are the things -- we're doing some -- we've done a lot of -- I shouldn't say a lot, but we're doing a lot of work with our undergrounding crews right now. And that price for undergrounding, particularly on a single phase, is approaching the price of overhead. It's not quite there yet, but close. And so we're in the range on single phase maybe like $250,000 a mile for undergrounding. Again, it's directional bore. And give or take, it depends on the conditions of the soil and homes and other things, but that's roughly the number. And so they're really quite comparable or growing comparable in terms of that price point. And so again, we've got pretty fertile soils. We have pretty soft soils. And so we're not in rock and some of those things, which helps from a cost perspective.

Andrew Weisel:

Okay. Great. Next one, are you able to tell what's the deferred fuel cost balances now versus at year-end?

Andrew Weisel:

Very good. One quick follow-up, if I may. Holtec, I know there's not a whole lot new for you to announce, but can you just give an updated thought on the timing of potential updates there with the state versus the timing of your next IRP, which I believe is likely to come next year.

Andrew Weisel:

Okay. I guess the more specific question was, would the timing of your IRP potentially be influenced by the timing of Palisades resolution?

Operator:

Next question today comes from the line of Alex Mortimer from Mizuho. Please go ahead. Your line is now open.

Garrick Rochow:

There's been a lot of conversations and there will continue to be more conversations on this important work of undergrounding. We'll be doing some additional piloting within the context of this proposed electric rate case, and then we'll continue to look at other opportunities to build out on that. But going back to the storm model, this is really our opportunity to get further alignment with the Commission on the important investments that need to be made to improve reliability and resiliency. And I would suggest that both the Commission, staff and the company and all our coworkers here, too, are really well aligned on ensuring that we're improving reliability and resiliency. You talked about the affordability piece as well. And that's clearly top of mind. Part of that is we leverage the CE Way, not only to improve our operations and maintenance expense, but we utilize it to improve capital efficiency. So that dollar goes further. Just like I shared earlier, we continue to look at opportunities to bring the cost down of undergrounding and frankly, of all our capital work.

Garrick Rochow:

So when we introduced in Q4 call, we introduced our $15.5 billion capital investment plan. And that had more electric distribution and electric related spend in that plan was like $6.1 billion of that, which was an increase. We're not changing our capital plan at this point because we increased it just here in the last call. That may change over time because we look at that capital plan every year. And as I've shared, there's a long runway of opportunity there. And so as we get certainty around these investments, as we build out that 5-year electric distribution plan, that will be an opportunity to look at the longer-term capital piece. Now going back to the growth piece. 6% to 8%, we said confidence toward the high end, and that puts it in that range of 7% to 8%. Historically, I've said this, I'll say it again, there are no sugar highs, and we go for consistency year after year. And so that's we compound of access. That's the quality of earnings that we aim for and we will continue to repeat year after year, because we know that's what our investors value.

Operator:

The next question today comes from the line of Ross Fowler from UBS. Please go ahead. Your line is now open.

Garrick Rochow:

Let me start with Germain Phillips. And it was -- I have great respect for Germain. He was a great commissioner, and we saw constructive outcomes. And he left the legacy at the Commission, and I'd put it into three areas. One, he really moved electric vehicles in the state. And it was forward-thinking and progressive about that work. And then in addition to that, there was a lot of work and grid monetization and optimization of the grid that he helped position within the commission. And the third piece, and this is -- have really played out nicely over the course of the pandemic is he was laser-focused on low income and vulnerable customers. And I give him credit as well as the Commission for the work. We have the lowest bad debt levels across the industry. And so we've taken care of our low-income customers during some of the toughest times during this pandemic. And so much of that credit goes to Germain Philips. But I'll also refer you to -- he's got a public statement out there. He's successful, but so is his wife is successful. And his wife has went after new opportunities, and so many thanks, and congratulations to both Germain, his wife and his family as they pursue different career opportunities. This Commission has functioned well in the past with two commissioners. And we've got two constructive, experienced commissioners in place. And so I'm not worried about the interim at all. And if you look historically as well as with this governor, Governor Whitmer here, they've been very thoughtful about the placement of commissioners and found experience and well-suited commissioners to continue the constructive environment, regulatory environment in Michigan. We do know that the governor is out -- the governor's staff is out looking for a new commissioner. That process is underway, but we don't have a deadline or a date out there and when that will take place. But again, I have confidence in our governor to continue the long-standing tradition of this jurisdiction in a constructive jurisdiction. I'm going to pass the call over to Rejji here to talk a little bit about the financial information to your second part of your question.

Ross Fowler:

Yes, that's helpful, Rejji. I guess in the past, you've been able to have that discussion with the Commission. It's really onetime and what's permanent. In the context of any debate around that, right? As you look at some of that CE Way money and then some of the sort of hiring freeze stuff. I guess the risk from my perspective is the Commission would say, well, you have a bunch of onetime stuff in there and some of that permanent, can we get some customer bill relief out of that more permanent basis. But maybe contextualize that risk around discussions you've had about that in the past and their understanding of what's onetime and what's not.

Ross Fowler:

Fantastic. So I'm with you on the $80 million in cost cuts and then there's like an incremental $50 million between the sort of year-end call back in this deck and that other usage category kind of went through in the answer to Julien's question.

Operator:

There are no additional questions noted at this time. So I'd like to pass the call back over to Mr. Garrick Rochow for any closing remarks.

Operator:

This concludes today's conference. We thank everyone for your participation.

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.

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.

Operator:

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

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?

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?

Shahriar Pourreza:

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

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?

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.

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?

Jeremy Tonet:

Got it. That's very helpful. Thanks.

Garrick Rochow:

Thank you, Jeremy.

Unidentified Analyst:

Hi, Good morning. This is [indiscernible] 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?

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.

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 [indiscernible] 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?

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.

Unidentified Analyst:

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

Operator:

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

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.

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?

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.

Operator:

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

Andrew Weisel:

Hi good morning everyone.

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?

Andrew Weisel:

Yes.

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?

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?

Andrew Weisel:

Okay fair enough. Thank you very much.

Operator:

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

Garrick Rochow:

Good morning, David.

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.

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?

David Arcaro:

Okay got you that make sense, thanks so much.

Durgesh Chopra:

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

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?

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?

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?

Durgesh Chopra:

Thanks so much. Appreciate the time guys, thank you.

Operator:

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

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?

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.

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.

Garrick Rochow:

Thank you.

Travis Miller:

Good morning everyone, thank you?

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?

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.

Travis Miller:

Okay very good, that's all. Yes that's all I have, appreciate it.

Operator:

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

Operator:

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

Sri Maddipati:

Thank you, Maxine. 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.

Rejji Hayes :

Thank you, Garrick. And good morning, everyone. As Garrick noted, our third quarter results are a continuation of the strong performance we have delivered throughout the year, keeping us ahead of plan and positioning us well to achieve our financial objectives in 2022. To elaborate, year-to-date, we have delivered adjusted net income of $662 million or $2.29 per share, up $0.11 per share versus the comparable period in 2021, largely driven by favorable weather, including more normalized storm activity in our service territory and healthy economic conditions in the state. The waterfall chart on Slide 8 provides more details on the key year-to-date drivers of our financial performance versus 2021. As Garrick mentioned, our solid year-to-date performance has driven our revised 2022 adjusted EPS guidance, which reflects an increase in the lower end of the range to $2.87 from $2.85. So our 2022 adjusted EPS guidance has now been raised and narrowed to $2.87 to $2.89. As noted, favorable sales continue to be the primary driver of our positive year-over-year variance, largely driven by weather, equating to $0.13 per share of positive variance. Our strong sales were partially offset by planned increases in operating and maintenance or O&M expense, largely driven by customer initiatives, which are embedded in rates to improve safety, reliability and our rate of decarbonization to the tune of $0.03 per share of negative variance versus the first 9 months of 2021. It is worth noting that the aforementioned year-over-year increase in O&M expense was partially offset by lower service restoration expense versus the comparable period in 2021 as anticipated. Lastly, the $0.01 per share of positive variance in the final year-to-date bucket reflects higher non-weather sales of the utility attributable to continued strong commercial and industrial load in our electric business, slightly offset by a drag of the parent from our preferred stock dividend and select regulatory items. As we look to the fourth quarter, we feel quite good about the glide path to achieve our revised full year EPS guidance range. As always, we plan for normal weather, which we estimate will have a positive impact of about $0.08 per share versus the comparable period in 2021. We're also assuming - we are also assuming $0.11 per share of positive variance versus the fourth quarter of 2021 attributable to rate relief associated with the October 1 implementation of new rates from our constructive gas rate case settlement earlier this year. And these estimates are stated net of investment-related costs such as depreciation, property taxes and interest expense. In addition to said cost, our plan assumes increased O&M expense in the fourth quarter versus 2021 for key customer programs such as vegetation management, one of the most effective measures to reduce system outages. And I'll note that we're on course for a record level of vegetation management spend in 2022, given our focus on improving the reliability of our grid. We also expect to continue to benefit from normalized storm activity, which nets to $0.11 per share positive variance versus the comparable period in 2021. To close out our assumptions for the remainder of 2022, we assume the usual conservative assumptions for our non-utility business and weather normalized load at the utility. We have also maintained a healthy level of contingency given our strong year-to-date performance which when coupled with our non-utility and load assumptions equates to $0.17 to $0.19 per share, a negative variance highlighted in the [indiscernible] chart. As such, we have substantial financial flexibility heading into the final three months of the year, which increases our confidence in delivering for customers and investors in 2022 and beyond. Turning to our 2022 financing plan on Slide nine. I'm pleased to report that we have successfully completed our planned financings for the year with $800 million of debt issuances at the utility priced at a weighted average coupon of 3.9% which is well below indicative levels in the current environment. \ And while our plan did not call for any financing at the parent this year, we opportunistically priced approximately $440 million of equity forward contracts during the quarter at a weighted average price of $68 per share. Our timely execution of the equity forward locks in attractive terms for the parent financing needs of the pending acquisition of the new covert natural gas generation facility. The settlement of the equity forward will largely occur in the first half of 2023 concurrent with the acquisition timing and in accordance with our recently approved integrated resource plan. Staying on the balance sheet. As we move into the winter heating season, we have preserved a strong liquidity position, which supplements our use of commercial paper. And needless to say, we'll continue to monitor market conditions to try to lock in attractive terms for future financing opportunities at the utility. Lastly, it's important to highlight that we have no debt maturities or planned financings at the parent in 2023 and virtually no floating rate exposure outside of the utility, which largely insulates our income statement from future interest rate volatility. Our opportunistic a prudent financing strategy reduces cost while limiting uncertainty in our cost structure, enabling us to fund our capital plan in a cost-efficient manner for the benefit of customers and investors. And with that, I'll turn the call back over to Maxine to open the lines for Q&A.

Garrick Rochow:

Yes. Thanks, Insoo, for your question. A couple of things on this. I think it's important to understand, particularly in August here had some storm. We performed well during the storm. But again, it's catching a little media attention. And I think one of the things that's really important to recognize here in Michigan is the impacts the great Lakes and what Lake Michigan does to the weather and storms. And then also just a longer-term trend we see is increasing wind speeds across Michigan in part due to climate change. And the bottom line is we see a real investment opportunity and resiliency. The commission has been supportive of many of the reliability and resiliency efforts in our electric rate case, but there's more to do. There's more to do in this space. And so I really view this as a collaboration where we can work to. Again, I think we're both the commission and the company are well aligned here in what we need to do in terms of reliability and resiliency. So I really view it as an opportunity where those opportunities are and create the path to improve that for our customers.

Garrick Rochow:

There is a first effort that's due here in November 4th. I would imagine the audit takes place over much of the fiscal year of 2023. And again, I see that as a collaborative effort. We want the same thing. We have the same goal, and it's really aligned to make sure we have all the right measures and investments in place to achieve that goal and they're at the right speed and pacing.

Garrick Rochow:

Yeah. The short answer is yes, on Covert and the financing is in that piece. But I'm going to just step back and think of the bigger picture here. And so how I think about this and how we think about this as a company. So this guidance here is 6% to 8%, and we expect toward the high end. We really think that offers a premium across the sector. And we've been doing this for 20 years of industry-leading financial performance. And then I think what's unique about us, and again, differentiates us and there's a strength and frankly, a premium is that we rebase off of actual. So we do this time and time again. And so we're not in the sugar highs. It's a long-term play where we're going to continue to deliver towards the high end. So I feel good. We feel good about the guidance we've offered here today at 305 to 311 and one more thing on this. I want to make sure everyone understands, too, that this is an important balance, a balance of our customers, other stakeholders like regulators and legislators as well as you, our investors.

Operator:

Our next question comes from Shar Pourreza from Guggenheim Partners. Please go ahead. Your line is now open.

Garrick Rochow:

Hey, good morning, Shar.\

Garrick Rochow:

I'll tag team this with Rejji here. This IRA is really beneficial for our industry and beneficial for our customers. And so as you know, we've laid out our IRP to 8 gigawatts, the storage build, it's a nice plan. And we go in every three to five years to revise that. And so in the short term, I really see the benefit of the IRA in this production tax credit flowing right to our customers. That's the $60 million per year versus plan. So that, again, keeps our customers' costs low, frankly. And remember, this IRP had $600 million of savings already baked in over that, and this is incremental to that. So again, feel good about that. In respect to my other comments, we'll file, refile our IRP in three to five years. And with this - with the IRA, there's upside opportunities in terms of our tailwind opportunities in terms of pulling renewables forward, potentially Poland storage forward. We'll have to take a look at that. Again, I see this as a real advantage to utility-owned solar and storage versus PPAs. I know Rejji, you may have additional comments.

Shar Pourreza:

Okay. Got you. Sorry, just a quick follow-up. It's just I guess you guys have never had a shortage of capital growth opportunities, right? It's always been a function of bills and rates being at kind of the governor, customer rates. I guess, the $60 million incremental in customer savings, does that allow a pull forward of some of that spend because you have that incremental headroom? Or do we have to wait for the additional IRP filing? I guess I'm just trying to figure out how that plays in.

Shar Pourreza:

Okay. Perfect. And then maybe just a quick one for Rejji. Just I guess beyond the Covert purchase as you guys are looking at your 5-year plan enrolling in more IRP spending into plan, including renewables, do you anticipate any associated financing need or the issuance last quarter took care of those needs as we're thinking about the current plan and slightly beyond the current plan, I guess?

Shar Pourreza:

Okay. Perfect. The last point was always trying to get Thank you so much guys, I appreciate it .

Operator:

Thank you. Our next question comes from Jeremy Tonet from JPMorgan. Please go ahead. Your line is now open.

Garrick Rochow:

Hey. Good morning, Jermey. How are you?

Garrick Rochow:

Sure. I'll start, and I know Reg will offer some context around it as well. So again, I want to remind everybody, as I stated earlier here that it's 6% to 8% toward the high end, and we're pleased with that. And that includes Colbert [ph] As we've said, the Colbert strengthens and lengthens our plan here. And so when I think about this, this is again, we're playing a long-term game here, where we have this consistency and repeatability of delivering industry-leading financial performance. And so - that's how we're thinking about it as we move in 2023 and then even in the outer years. But Rejji, you walked through some of the specifics, please.

Jeremy Tonet:

Yes. No, that's very helpful. And I just wanted to pivot a little bit to battery storage, if I could. And just wondering if you could provide some more thoughts on how you think the system could potentially change over this decade, especially if renewable penetration ticks higher than planned from IRA benefits? And is there anything else you're watching out for on this front?

Rejji Hayes:

And Jeremy, the only thing I would add is it's important to remember that the IEP is iterative in nature. And so we'll be filing one for the stature at a minimum every 5 years, but our bias will likely be to file sooner than that. And so importance of that and the benefit of it is that as we see a potential descent in the cost curve, whether to Garrick point, it's lithium-ion or any other storage technology, we can incorporate new assumptions in upcoming IRPs.And so We’re assuming in the full plan over the next 15 to 20 years, about 550 megawatts that Garrick noted the 75 megawatts in the short term. But it's a larger portfolio longer term. And again, if the cost curve permits it, we'll look to pull some of that forward and potentially expand it, particularly with the optionality provided with the ITC using it for stand-alone storage as well as opting out of normalization, which is helpful, too.

Garrick Rochow:

Well, I offer a couple of comments on Palisades. So if we get into technical questions, like we don't own the plant, we don't operate the plant anymore, and we no longer have a purchase power agreement, which was a significant savings for our customers and power supply costs over the course of the year. So technical questions and related questions that should be really directed to old tech or maybe the Department of Energy and the like. But bottom line, here's what we've shared with the Governor's office and with the Michigan Public Service Commission. We'll be open to a purchase power agreement. It has to be much more competitive and much more market-based than it has been historically. And we would expect financial compensation mechanism on that PPA as a new purchase power agreement. So that's really what I'd offer on Palisade at this point.

Garrick Rochow:

Thanks, Jeremy.

Julien Dumoulin-Smith:

Good morning, team. Thanks for the time. Appreciate it, Listen, just maybe just starting – hey thank you. Just starting with preliminary, right? I want to focus on that work. Can you emphasize or can you can you piece apart why you used the word preliminary at the outset? What are the moving pieces in your mind, if we can go back to that quickly in terms of when you pivot to a more finalized guidance and what you're watching here in the next few months? I just want to clarify that.

Rejji Hayes:

Julien, the only thing I would add in addition to just it's Q3 and we'll rebase off of actuals in Q4 and take into account any contingency deployment over the next couple of months. But the other variables is obviously we have a pending electric rate case, and so we'll have a little bit a couple of months more of visibility into how that's trending. We're certainly in the process of evaluating potential settlement. And so we'll see how things go there. And then at that point, we will have filed the gas rate case. And so we're still thinking through the size and implications of that, and we'll assume a constructive outcome there, but still some variables in place. So that's the other bit of information we'd look for as we establish our 2023 final guidance on our Q4 call early next year.

Garrick Rochow:

The RF - so just for context, I know you know this, Julien, but for context for others on the call, there's 700 megawatts within this IRP that's 500 megawatts is dispatchable 200 megawatts of clean energy. That RFP has been issued. It was issued at the end of September. That's going to play out. It's done through a third party because of the potential for an affiliate transaction with the DIG. So that plays out. We anticipate those proposals to be submitted in the December time frame. Those will be evaluated again by the third party. That will take to February. And then we anticipate we'll have some direction in that in the May time frame. I'll likely share it at the May earnings call time line. So that's how it's going to play out. I do not know who will participate in that. Again, it's by a third party. Should Holtec choose to participate with the Palisades plant, and if it comes in at a competitive price, it may be an option out there. And again, because it's not an affiliate, we would earn a financial compensation mechanism or a return on that. So that's the approach that would be - would play out here over the course part of the next eight months.

Garrick Rochow:

Thank you.

Operator:

Our next question comes from David Arcaro from Morgan Stanley. Please go ahead. Your line is now open.

Garrick Rochow:

Well, just a little background, too. And so I was really pleased with the team. And we did a lot of work on this electric rate case to improve the quality of the case. And I believe and see it's evident in the fast position on that. It's a constructive starting point that they provided in August. And so as Rejji shared, we're looking at the potential for electric rate case settlement. And so that will continue until the case is final. We anticipate PFD in December and then a final order in February. So that's the current status. And then just the longer we have the opportunity we're a 10-month cycle. And so it will be in early in 2023, would we consider another filing another electric rate case. And that's a little far out for us in terms of - we got to want to see how this one plays out and make sure we're making the right investments for our customers.

Garrick Rochow:

That's a great question. And I appreciate you started with our customers because that's a key piece. And so just let me give you a little fact here to this. And so, in 2021, we had $75 million of state, federal and some company funds that went to our customers. In 2022, that number was $79 million. And again, just for context, October to October as the fiscal year for state.\ And so I'm really pleased that we've been able to get money in the hands of our customers. And you'll see from a quarter, our customers have a lower debt balance or bad debt balance on their bills. They're not carrying a big balance. And in fact, from an uncollectibles perspective, we're in a quartile 1 position. So I feel good because our customers are starting out in a better position. Now I'm certainly empathetic and sympathetic to their needs. And so what we know about our customers, when we look at their bill, about 80% of the gas bill is consumption. It's about 90% on an electric bill, we can influence that. We can influence that through our energy waste reduction, energy efficiency programs, and we are doing that. And that's great for our customers. In addition, we're about 30,000 thermostat - the thermostats or those that are most in need, vulnerable customers to help them, again, control the use. We're pushing again with nonprofits and other state and federal funds. And so our focus is clearly on our most vulnerable customers here in this time. And then broadly, as a company, and you asked the question really, have we seen material prices increase? Absolutely, 17% year-over-year. But there's a lot of things we're doing to mitigate that. particularly in the CE Way, $50 million of O&M waste reduction, $90 million -- approaching $90 million on a capital perspective. Our plants ran just again, they ran phenomenally - over the summer months. They got a low heat rate, gas and coal. MISO [ph] was bouncing all around the volatility of the market. Cars were steady state. We saved our customers $500 million year-to-date, \looks like $700 million by year-end. Again, we used our gas assets, all these storage fields to help manage gas cost impact. So those are the here and now. And then we have a whole host of episodic cost savings $200 million Palisade for PPA, Palisade PPA [indiscernible] $30 million of OEM there. So IRA in that PTC, again, I can go on and on. But you can see we're squarely focused cost reduction for our customers, creating the necessary headroom so we make the right investments to improve the system again for our customers to manage that. And I know Rejji has even more to offer.

David Arcaro:

Okay. Great. A lot of helpful points there. Thanks so much. And see you soon.

Operator:

Our next question comes from Travis Miller from Morningstar. Please go ahead. Your line is now open.

Garrick Rochow:

Good morning. Travis.

Garrick Rochow:

It's a little bit of both, but the immediate piece is really in the space of distribution. So these companies are located here, like if you take HSC as an example, or Hemlock Semiconductor they're building out that load right now. And so we're looking at the existing substation, how do we offer additional redundancy and build out. In the case of Goshen, again, they're constructing their facilities, so a little further behind from a start point. But again, you're going to be running electric line and build a substation dedicated to that facility. And so the first steps really show up in the distribution space for investments. And you'll see those as part of our 5-year capital plan to be able to, again, build and construct those. And then really there's a beautiful part of the integrated resource plan which continue to look out 20 years and balance the demand needs and the supply needs. And right now, we look long on capacity, really through 2031. So we have room to grow and add these investments. But as that - as Michigan continues to grow, and we continue to add low, we'll make adjustments as we move forward in our subsequent IRPs from a supply side. Is that helpful? Travis?

Garrick Rochow:

Yeah, take care.

Anthony Crowdell:

Good morning, Garrick. Good morning, Rejji. Congratulations on a great quarter.

Anthony Crowdell:

And I apologize, this is real semantic I understand if you just want to ignore the question. But I think about - you talked about the IRP maybe strengthen and lengthen the CMS plan. And then when I fold over to earnings guidance of 6% to 8% towards the high end - if I look at '23 where it's kind of preliminary, it's right now at 7% more than midpoint. I guess I'm trying to reconcile 6% to 8% towards the high end. Is that just take 6% out of out of our planning assumptions? Or is 6% to 8% towards the high end/

Anthony Crowdell:

Okay. Let's shot at it and then I'm finished. If I look back in the last 18 years, you guys delivered very consistent 7%. Do you view the performance when I look back '18 that you hit the high end of that 6% to 8% range?

Anthony Crowdell:

Perfect. Thanks and looking forward to seeing you in Hollywood.

Michael Sullivan:

Hey, good morning.

Michael Sullivan:

Just wanted to ask on - just with your own renewables becoming more competitive post IRA, I think the current plan has 50% ownership in there. What is the CapEx associated with that? And if you were to be cost competitive across the board and go to 100%, what would that look like theoretically?

Michael Sullivan:

In the current –yeah, , either way, whatever is easiest for you. The current 5-year plan, the IRP that just got approved/

Michael Sullivan:

Okay. That's super helpful. And then just kind of following along that, again, this is kind of theoretical. But if you start finding that you are more cost competitive more regularly here. Do you limit that at all if that introduces more equity needs into the plan?

Michael Sullivan:

Thanks, Rejji. Super helpful.

Garrick Rochow:

Thanks, Maxine, and thank you, everyone, for joining us today. Look forward to seeing you at EEI in a few weeks. Take care and stay safe.

Sri Maddipati:

Thank you Elliot. 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.

Rejji Hayes:

Thank you Garrick, and good morning everyone. As Garrick noted, we had a strong first half of the year are ahead of plan and are well positioned to achieve our financial objectives over the next six months and longer-term. To elaborate for the first half of 2022, we delivered adjusted net income of $499 million, or $1.73 per share, up $0.09 per share versus our 2021 first half results largely driven by favorable weather and economic conditions in the state. The waterfall chart on Slide 7 provides more detail on the key year-to-date drivers of our financial performance versus 2021. As noted, favorable sales have been the primary driver of our positive year-over-year variance to the tune of $0.16 per share driven by weather. From an economic standpoint, we've continued to see strong commercial and industrial load in our electric business, while weather-normalized residential load continues to exceed our plan assumptions and pre-pandemic levels. Rate relief net of investment-related expenses contributed $0.03 per share of upside, as we continue to benefit from our prior gas and electric rate cases. These sources of upside were partially offset by increased operating and maintenance or O&M expenses largely driven by customer initiatives, embedded in rates to improve safety, reliability and our rate of decarbonization, which equated to $0.07 per share of negative variance versus the first half of 2021. We also note the $0.03 per share of negative variance in the final year-to-date bucket, which is primarily driven by investment costs related to the 2019 rate compressor station incident for which we are not seeking recovery at this time, as per our recent gas rate case settlement agreement, and the company's recent commitment to donate $5 million in support of income based bill assistance for our electric customers as per our IRP settlement agreement. These sources of negative variances are partially offset by the aforementioned strong non-weather sales performance in the first half of the year. As we look to the second half 2022, we feel quite good about the glide path to achieve our EPS guidance range. As Garrick mentioned, we had a constructive outcome in our gas rate case. The approved settlement agreement at $170 million significantly de-risked our financial plan, and when coupled with our December 2021 electric rate order provides $0.10 per share positive variance versus the second half of 2021. The forecasted rate relief net of investment-related costs in the second half of the year more than offsets our estimated impact of normal weather, which we assume will provide $0.01 per share a negative variance versus the comparable period in 2021. Moving on to cost savings. We continue to anticipate lower O&M expenses of the utility driven by the expectation of a more normalized level of storm activity this year versus the atypical levels experienced in 2021, which I'll remind you equated to $0.16 per share of downside in the third quarter of 2021 versus our financial plan. We also expect the usual solid cost performance driven by the CE Way as well as other cost reduction initiatives in motion. To close out our assumptions for the second half of the year, we assume normal operating conditions at enterprises given the outage at DIG in the fourth quarter of 2021 and the usual conservative assumptions for weather-normalized load at utility. Lastly, it's worth noting that we have accrued a healthy level of contingency given our strong year-to-date performance as illustrated in the $0.24 to $0.28 of negative variance highlighted and the penultimate bar of the chart, which increases our confidence in delivering for you our investors. Moving on to the balance sheet. On slide 8, we highlight our recently reaffirmed credit ratings from all three rating agencies. As you know we continue to target mid-teens FFO to debt over our planning period. As always, we remain focused on maintaining our strong financial position, which coupled with the supportive regulatory construct and predictable operating capital growth supports our solid investment-grade ratings to the benefit of customers and investors. Turning to our 2022 plan financings on slide 9, we continue to plan for $800 million of debt issuances at the utility. And while our plan does not call for any financing at the parent this year we are currently assessing funding options for the acquisition of the Covert natural gas facility in the first half of 2023 as per our approved IRP. As a reminder, the current financing plan for Covert assumes the issuance of hybrid securities. However, we're evaluating alternatives including using our existing ATM equity issuance program given the relative costs in the current environment. It's worth noting that this would be accretive to the previously provided $0.03 or $0.04 per share of EPS accretion attributable to the purchase of Covert and further strengthened our 6% to 8% long-term adjusted EPS growth outlook. Lastly, we have preserved a strong liquidity position, which supplements our use of commercial paper over the coming months. And with that, I'll turn the call back to Garrick for some concluding remarks before Q&A.

Operator:

Thank you very much, Garrick. [Operator Instructions] Our first question comes from Shar Pourreza from Guggenheim Partners. Your line is open. Please go ahead.

Shar Pourreza:

Hey, guys. Good morning. Garrick pretty clear-cut print here. But just given sort of the regulatory outcomes that are now secured like the IRP, the gas settlements, looks like the electric rate case is on track. As we're kind of thinking about maybe the cadence of updates is the plan to still update CapEx and financing in the fourth quarter? I guess just given the visibility we have why not provide a full guidance and capital update sometime in the third quarter or EEI time frame? I guess in other words given the regulatory execution that you've clearly highlighted today, could you provide early indication on growth 2023 numbers out of schedule?

Shar Pourreza:

Okay got it. And then just obviously, looking at the results year-to-date how 2022 is shaping up, July looks like a strong weather month. And obviously, you guys are – as you highlighted, you have normal weather planned for the remainder of the year. Does a strong third quarter weather push you ahead of guidance? And maybe what are sort of some of the offsets and moving pieces there that we should be thinking about because just looking at the results to date, it seems like you're well ahead of your numbers but...

Shar Pourreza:

Okay. Terrific. Thanks, guys. Appreciate it. Thanks for the details.

Garrick Rochow:

Good morning, Jeremy.

Rejji Hayes:

Hey, good morning, Jeremy, it's Rejji. I appreciate the question. Obviously, we feel quite good about the load trends we're seeing in our service territory and I'll just remind folks on some of the specifics. And so we had residential down a little over 0.5%. So that's year-to-date versus year-to-date 2021 commercial and industrial. And as always our industrial excludes one large low-margin customer, up about 3% and then all in up about 1.5 points. And so we feel quite good about that. And particularly with respect to residential, we continue to see that good stickiness with the hybrid workforce, which likely will be a trend that continues on. And obviously that's a high-margin segment. And so relative to 2019 residential is up about a little over 2%. And so again that stickiness just really carries on. We continue to see from an economic development perspective, just good activity in the service territory. And obviously, with some of the news in D.C. yesterday, I would think that the CHIPS Act and some of the other legislative items that may be coming down the pipe could lead to more economic development opportunities or increase the probability of some of the stuff that is coming in Michigan's way or is in the prospects for Michigan. So very encouraged with the load trends and anecdotal again, we're hearing from our customers that they continue to feel good about the economic environment. So I feel quite good about the road ahead. And going forward again we continue to anticipate that you'll start to head back to those pre-pandemic levels. And so we would anticipate that from a residential perspective, but we continue to be surprised to the upside and commercial and industrial continue to trend very well. So that's our take on load at the moment.

Jeremy Tonet:

Got it. That's very helpful there. And then I just wanted to pivot a bit towards MISO. We've seen some capacity constraints there and that's led to some delays in equivalent retirements. Just wondering should we be thinking about any implications to CMS here or anything else that you want to share on this front?

Jeremy Tonet:

Got it. That's very helpful. Last one if I could hot off the press climate BBB package. Climate package being supported by management here. Any preliminary thoughts at this point?

Jeremy Tonet:

Great. That’s helpful. I'll leave it there. Thanks.

Michael Sullivan:

Hey, everyone. Good morning.

Michael Sullivan:

Hey, Garrick. Rejji, I wanted to go over to you on just the latest commentary on the potential looking at common equity for financing Covert. I think that was an $815 million project. Any sense of how much the equity could be and how materially the $0.03 to $0.04 accretion could change?

Michael Sullivan:

Okay super helpful color. And then last question, what do you guys think about making it three for three with settlements this year with the pending Electric case?

Michael Sullivan:

Great. Thanks a lot.

Operator:

Our next question comes from Julien Dumoulin-Smith from Bank of America. Your line is open.

Rejji Hayes:

Yeah. So Julien just to be clear you're talking about the alternative minimum tax with respect to last night's –

Rejji Hayes:

Okay. Yeah, with respect to climate bill. So, again as Garrick noted we're still digesting. I think it's about 700 pages, and our folks in federal affairs and on the tax side are really, really good at what they do and their fast readers, but 700 pages is a lot to digest in 12 hours. But I'd say, basically, what we've done so far as I understand it the structure that's contemplated is consistent with what we were talking about around EEI several months ago, where there's a three-year average on pre-tax operating income around $1 billion. And if you're below that threshold, you're not subject to the minimum tax. And so from our perspective given our size we would likely not chin that bar for some time. Now needless to say, we aspire to at some point because we're a growing company. But in the short term, I think, we'd be perhaps not subject to it initially. And we're still looking at -- again, if it's structured how it was when we were talking about this at EEI, you could apply tax credits through up to 75% of the tax liability. And again, we're still looking to see whether that's in the bill but that's how it was structured initially. And so I'd say, there's a bit more work to be done on our side before we can speak to it. But I'd say, to cut through it in the short term we don't think there's a significant impact on us again given our size. And if they apply that three-year average of $1 billion of pre-tax operating income we just wouldn't chin that bar for a little while.

Rejji Hayes:

Yeah. From a pension perspective, again, our story has been quite good for some time now. As you may recall, we have been very active in making discretionary contributions to our pension plan over the year particularly in years in which we were pretty flush from an OCF perspective. And so we're well overfunded. At this point, we're -- we have two pension plans and both are over 120% funded. Clearly asset experience is tough for most, but we have relatively low equity content in our pension plans. And I would say based on how our pension is structured at this point we're a bit more levered to interest rate movement. And with discount rates effectively going up year-over-year, we actually see it in the short term as a net benefit. And so we actually are seeing actually, a little bit of upside particularly since we recently remeasured our plan. So from our perspective, it's actually net positive at the moment and we feel quite good about the level of funding for the plan.

Rejji Hayes:

No. No.

Rejji Hayes:

Yes. So obviously, our rate construct is a little nuanced but it would help us as well because obviously it would allow us potentially, if you think about the 8 gigawatts of solar that we're going to be executing on over the next 15 to 20 years we're currently structured to at a minimum own about half of that. And if we can be more competitive, because of that benefit with the – obviously, the elimination of normalization then we could potentially pencil the own projects in a manner that's comparable with the PPA or contracted portion. And that would make a case for owning more than 50% over time. And so obviously, that could add to rate base opportunities. So we feel quite good about, what we've read today. But again, obviously more to digest.

Rejji Hayes:

Thank you

Rejji Hayes:

Hi, Andrew.

Rejji Hayes:

Yes. Andrew, thanks for the question. I would say starting with that $0.24 to $0.28 a negative variance in the six months to go bucket of that waterfall chart on Page 7, that is a combination of conservative planning. And so that's really a catch-all bucket. And so we've got in their non-weather sales assumption year to go. We've got a little enterprises performance and so -- and some parent expenses. So there's conservatism, as it pertains to those variables, but the vast majority of that is just contingency that we've accrued, just based on the performance in the first half of the year. And so obviously, weather was -- has been a big help. It's offered upside to plan. We've seen a little cost performance as well and a little bit of non-weather upside. So sales have been strong as well as cost performance and that's, what's driving a good portion of that bucket. So it's really just where we've parked the contingency, which gives us a lot of flexibility which kind of segues into the second part of your question about what we're doing with respect to pull ahead. And so I would say, at this point because we still have six months ago, we really tried not to do a whole lot because we still have to get through storm season and see where Q3 is which not just from a store perspective, but also in terms of earnings contribution that's usually where we have the vast majority of our EPS contribution. So we've been cautious. We've done a little bit more with respect to forestry and we've done a little bit more reliability work. Obviously, we made some commitments as part of the IRP and gas settlements with respect to low income support. And so those are things we like to do, and we'll continue to evaluate opportunities for pull-aheads to de-risk 2023, some more going into the second half of the year. It's also important to remember, we also put in place a really nice regulatory mechanism a few years ago our voluntary refund mechanism, which effectively allows us to make decisions late in the year from an operational pull-ahead perspective get effectively the accounting benefit, in the current year and then a commitment to do work in the subsequent year. And so that gives us even more flexibility, as we head into the Q4 and deep into Q4, if we're seeing upside that's in excess of plan. It just gives us a bit more flexibility to commit to more work and again see the sort of accounting benefits of that in the current year. So a lot of flexibility going forward. We've made some moves to date from an O&M, pull ahead perspective. But again we're obviously, cautious at this point because we've got a lot of Q3 left and we're waiting to see what happens with storms and weather.

Rejji Hayes:

Yes. To answer the last question first, if you put aside the potential funding of Covert as we mentioned on the call today with potentially considering equity, there is no plan to issue equity beyond that until 2025, as per our initial guidance when we rolled out our $14.3 billion five-year plan in Q1 of this year. So we're still committed to not issuing equity through 2024 or more specifically until 2025, but for the funding of Covert. And in terms of how we'll time that and how we'll think through that obviously we'll look at the valuation of the stock versus the relative cost of other hybrid securities and we'll look to be opportunistic from time to time. And we've seen just great pricing in the past with those dribble programs. And so, we'll look to utilize some of that. But again, I think we've got a lot of flexibility because we're not scheduled to acquire Covert until May of next year. So quite a bit of time to evaluate and we'll be opportunistic and dribble out so likely over the coming months.