Good morning, everyone, and welcome to The CMS Energy 2019 First Quarter Results. The earnings news release issued earlier today and the presentation used in this webcast are available on CMS Energy's website in the Investor Relations section. This call is being recorded. After the presentation, we will conduct a question-and-answer session. Instructions will be provided at that time. [Operator Instructions]. Just a reminder, there will be a rebroadcast of this conference call today beginning at 12 PM Eastern Time running through May 2. This presentation is also being webcast and is available on CMS Energy's website in the Investor Relations section. At this time, I would like to turn the call over to Mr. Sri Maddipati, Vice President of Treasury and Investor Relations. Please go ahead.

Thanks, Rocco. Good morning, everyone, and thank you for joining us today. With me are Patti Poppe, 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 Patti.

Thanks, Sri. Thanks everyone for joining us for our first quarter earnings call. Now, this morning, I will share our first quarter financial and operating results and review our regulatory calendar. Rejji will add more details on our financial results and outlook and as always we will close with Q&A. Despite two large storms, and an unprecedented Polar Vortex, which challenged our electric and gas systems, we were able to deliver solid first quarter earnings of $0.75 per share which are better than our plan. Regardless of changing weather, economy, political or regulatory conditions, we pride ourselves in our adaptability which enables the delivery of consistent financial results on which you come to rely year after year after year. We're pleased to reaffirm our full-year guidance of 6% to 8% EPS growth based on last year's actual results and are biased towards the mid. We're also reaffirming our plans to grow dividends in line with earnings. Our predictability is enabled by our focus and commitment to our triple bottom-line of people, planet, and process, underpinned by financial and operating performance which remains a low risk and sustainable business approach and it continues to deliver for our customers and our investors. Every dollar of our capital plan is invested with the triple bottom-line in mind and we've seen solid support for this thought process over the years but most recently with the settlement of our gas and electric rate cases as well as our integrated resource plan. Our continued focus on needed investments in the safety and reliability of our gas and electric systems and our approach for the cleaner generation fleet with the modular build out of renewable energy has been reinforced by these positive regulatory outcomes. The settlement agreement of the integrated resource plan is a great example of…

Thank you, Patti, and good morning everyone. As Patti highlighted, we're pleased to report our first quarter results for 2019. We're just slightly ahead of plan despite severe weather experienced during the quarter. We delivered net income of $213 million which translates into earnings per share of $0.75 per quarter. Our first quarter earnings per share for 2019 were $0.11 lower Q1 2018 results largely due to heavy ice storms experienced in our electric service territory in February. Like always, we plan conservatively manage the work and continue to be ahead of plan. Despite the storm activity, utility was the key driver of our financial performance in Q1 contributing $0.80 per share largely due to our electric rate case settlement and relatively cold winter in Michigan which benefited our gas volumetric sales [indiscernible]. The Utility strong performance was modestly offset by expected underperformance in enterprises versus Q1 of 2018 with lower capacity sales at DIG contributable to the residual effects of the 2018 MISO planning resource auction, and a planned outage of our Filer City plan, both of which were reflected in our full-year EPS guidance. All-in, we started 2019 right on track and we are confident in our ability to deliver another year of consistent industry-leading financial performance. On Slide 12, you can see the key factors impacting our financial performance relative to 2018 in our waterfall chart. Favorable weather provided $0.08 per share positive variance versus Q1 of 2018 and rate relief net of investments contributed another $0.03. These sources of financial upside more than offset by the substantial storm activity which negatively impacts earnings by $0.10 a share, the aforementioned underperformance in enterprises and the higher effective tax rate. The latter two of which in line with our expectations and as mentioned are already incorporated in our…

Thanks, Rejji. With our unique self-funding model, enhanced by the CE Way, a large and aging system in need of capital investments, a constructive regulatory framework, and a healthy balance sheet to fund our plan cost effectively, we believe our financial performance is sustainable over the long-term. With that, Rocco, please open the lines for Q&A.

Thank you very much, Patti. The question-and-answer session will be conducted electronically. [Operator Instructions]. And today's first question comes from Greg Gordon of Evercore ISI. Please go ahead.

So I mean I think it goes without saying because you've been very clear but you had a very rare modest miss versus Street consensus in the quarter because you had such a extraordinary storm activity. But given your historic ability to manage the business, you don't have any concerns about being able to bring in the earnings expectation as you articulated for the year just because the first quarter was challenging correct?

That's correct, Greg. We always adapt, and as we mentioned, we're ahead of our own plan, and so we're very confident in our ability to continue to deliver as always.

Thanks. And then I'm sure there'll be a lot of questions on the regulatory activity. So I'll leave that for other people. I had a sort of an esoteric question on the DTE call yesterday, you talked about why they don't have and I don't think you guys have either a large amount of lithium ion battery storage built into your expectations for future infrastructure needs and they pointed to the fact that because you guys have the Ludington storage facility and it's such a large and unique asset that it really creates the balancing capacity you need so that battery storage may not other than in very unique circumstances necessarily be a big part of Michigan's future needs. Is that a fair assessment or not?

Well first of all, yes, Ludington is storage and it's 2,200 megawatts of storage. So yes we love that. In fact, as you've been there, Greg, I know you visited the site. We have six of the world's largest motors at that location six 500,000 horsepower motors. It is a sight to be seen. So anyone who hasn't been there, open invitation. But yes, so obviously we have a lot of experience actually pricing in storage on a daily basis. What we're waiting for and I think we do see more storage and in fact in our IRP, we have storage towards the latter half of the plan. What we're waiting for is the price curve. And I'm very confident that price curve will materialize. And with all the research that's underway with lithium ion for vehicles today, but maybe there will be a breakthrough in solid state. I look forward to that. I think storage is going to be important on the grid to balance voltage and do voltage control for our solar installations that are going to be distributed across the state. So we are hopeful for storage and a technological breakthrough in that but we don't need it to execute our IRP plan until the last part of the 20-year plan.

Greg, the only point I would add is in addition to Ludington, as you likely know, we also have peaking capacity in the form of our Karn 3&4 facilities which is over a gigawatt. So that also supports us as we flush out the renewable plant.

And our next question today comes from Jonathan Arnold of Deutsche Bank. Please go ahead.

Good morning guys. Yes, just had a question on enterprises and that segment came in at nothing for the first quarter and you said it's going to be more weighted to the second half. Is that really going to be mostly a Q3 segment now with the shift to more of an energy contract, so is it more sort of linear through the second half. Can you just give us a bit more sense on the timing there?

Yes, I would say it's certainly more backend weighted and I would say it's more weighted towards Q3 and Q4, you'll get a little bit of pickup in Q2 but mostly Q3 and Q4. And the reason why that is, Jonathan, is we had lower capacity sales and that had to do with the fact that we had to basically sell about 400 megawatts of capacity at dig in the planning reserve auction in MISO in mid-2018. And as you know the planning year runs from basically May of the prior year to June of the subsequent year and so we've got about two quarters of exposure in 2019 of those lower capacity sales. And the reason why, as you may recall, we had to subject ourselves MISO planning reserve auction is that we held 400 megawatts of capacity in escrow effectively at gas part of the potential Palisades early termination in 2017. And so we'll wear that for a couple of quarters. It's in our plan and so we would expect that that would recover over time, we've already sold through capacity through 2020. And so we feel pick up some in Q2 but most of it in Q3 and Q4.

And so by extension then Q1 of next year should prove to be more positive than Q1 of this year?

Yes, you would think because again we've sold capacity through 2020 around $2 to $3 per kilowatt month. And so we would expect to get a more favorable comp in Q1 of 2020 certainly versus Q1 of 2019.

Okay, great. And then just one other sort of item you talked about expecting energy efficiency earnings to increase from $34 million to $44 million or so and as you implement the IRP. What's the timing on getting to that higher level, is it -- it's not for a year or two or was it sooner than that?

Yes, Jonathan, great question. We're going to phase it and we're going from 1.5% in our electric business energy efficiency to 2% and it's when we get to that 2% that it takes it to $44 million and that'll be mid-2020.

Mid-2020, okay great. That's it, thank you.

Thank you.

And our next question today comes from Michael Weinstein of Crédit Suisse. Please go ahead.

Hey question on the financial compensation mechanism. So I realize that I guess there's a continuing talks about this, but at 5.88% that's above short-term debt but the long probably below the overall cost of capital, weighted cost capital for the company. I'm just wondering if this is -- this 5.88% that was settled this is like kind of an opening bid like if things go well later on people might be more amenable to raising that number as long as the markets seem okay with it, the solar markets seem okay with it.

Michael, it's good question. So just to be clear the 5.88% that does reflect our WACC or weighted average cost of capital and that was what was agreed to in the settlement. And so we think that's the appropriate level for an FCM particularly given the fact that we'll be able to own and rate base effectively half of the solar investment opportunity over the next few years. And so the 1,100 megawatts that we agreed to effectively through 2024 will get 550 megawatts of that. And then, as you know, the filing and the IRP itself is an iterative process per the statute. And so we've agreed put a settlement to file again in June of 2021, so we'll see what the fact pattern is at that point. Obviously cost of capital moves all the time and so it makes sense to adjust it at that point and suggest something else we'll look to do that at that point.

To be clear, we're really excited about that FCM it gives us optionality in the best way to have the lowest cost energy, delivery, and supply. We're very happy with the outcome of the IRP. We think it really reflects our values and we think it reflects our business model and it just allows our business model of ample CapEx backed up by our ability to do it at the lowest cost to protect customers from affordability constraints. It really fits right into our plan.

Right. Could you I mean could you characterize kind of what the discussions are surrounding at this point over the next month or two? What are the solar advocates want out of this process at this point?

Well to be clear there's a range of solar advocates. We had the Sierra Club, the NRDC sign on to our settlement and certainly their solar advocates. I guess I would consider as solar advocates. We all agree that solar has an important role to play here in Michigan matches our load profile extremely well and combined with things like Ludington and Karn, as Rejji mentioned, we've got a really nice mix of supply. So the conversation has been how to do that at the lowest cost possible. And we feel very excited about the competitive bidding process for the supply resources. We think that's an important stand to take on behalf of the people of Michigan that we want to make sure we have the lowest cost resources on the system and have optionality around the CapEx surrounds that, so that we can invest the next best dollar where it needs to be invested in the entire system. I would say some of the large out-of-state kind of profit maximizing solar developers don't love the outcome because they're going to have to compete on price and not lean on PREPA. And that PREPA loophole doesn't work. And it saddles the Michigan customers with unnecessary high priced solar. And so I would suggest that our commitment to competitive bidding really change the nature of the discussion here in Michigan that we're going to stand for the lowest cost and cleanest energy resources for the people that we serve.

And our next question today comes from Julien Dumoulin-Smith of Bank of America. Please go ahead.

So perhaps just to reconcile this, I mean just at a high-level, the IRP obviously you've got just about over a gig of potential opportunity here split between rate base and PPA. How does that reconcile with your current CapEx budget at the end of the day? And then maybe a second but related question is how do you think about updating the needs for generation over time here. What would that timeline look like and how could that reconcile against what you all have here in the IRP today? And I know that's somewhat of a transient question, right. It'll change over time.

Yes. So, Julien, good question. I would say as it pertains to the five year plan, we don't see a great deal of, I will say, capital investment impact in our five year plan. So, as you know, we're at about just over a $11 billion most of which is wires and pipes capital investment, we've got $1 billion of renewables in our plan but that's largely attributable to wind build out basically to get to the 15% RPS. And so a lot of the capital investment opportunity that's coming out of this settlement agreement is really beyond this five-year plan. So you'll see some of it. We'll take ownership of some of it kind of in the 2022, 2023 period but not a great deal. It's also worth noting that you're going to have Karn 1&2 in the outer years of our plan come out, if we succeed in retiring that plant in 2023 as promised. And so when you think about the puts and takes, you'll see probably a net neutral impact, I'd say in the next five to six years now. The bigger opportunity going forward is, as you look, at the incremental five gigawatts that will build out over the next decade plus I think in year's six to 10 of a potential 10 year plan, you'll see more significant capital investments on the solar side. And so there could be upside there and again we've talked about in the back half of this year offering a new 10-year plan which likely reflects some of that. And then if you think about the capacity build out, I'll say a couple of decades from now in our capacity plan, we're going to be losing over time about four gigawatts of capacity. So you're going to see two gigawatts come out in the form of the MCV and Palisades PPAs and then another two gigawatts come off over the next 20 years retire -- as we retire the coal fleet and so substantial capital investment opportunity on the solar side over time. And we think that offers potentially around $3 billion of capital investment opportunities to think about the spend on the capital side through 2030. So quite a bit of opportunity but early days of course.

I would also offer that the capital opportunities on our entire system are not -- we don't require all of our investment to go into supply. It's not; I would say the investment mix of the past. The opportunity to have distributed resources is going to require a significant amount of grid investment as well to make sure that we can integrate those distributed resources into the grid and make sure that our reliability is high. So the mix between distribution and supply is going to shift to distribution as well as in our gas system. And so when I talk about looking for the next best place to put a capital dollar, everyone can remember and always remember that this is not a question of building up rate base. This is a question of how best to affordably deliver the capital that delivers the customer value and customer service, the reliability; all of those things are driven by how much capital is required in the system. So the system needs are driving the CapEx. We're not trying to backfill CapEx and searching for CapEx and using supply as a means of doing that. We're trying to figure out the best way to deliver the services for customers with all the CapEx that needs to be done and to be able to do that affordably.

Got it, excellent. And just to clarify this, I know you have got billion-ish in the plan today for renewables. When you talk down the materiality of 2022, 2023 solar, it's more because it's something of a rounding within the wider plan contemplated?

Yes, that's -- that's right. So you basically in the outer years of plan, you'll start to take ownership of some of that 550 megawatts. But again as we always talk about the constraint on our capital is really affordability and so we think based on the five-year plan, we rolled on our Q4 call that little over $11 billion of aggregate capital investment is what our customers can comfortably afford as well as our balance sheet I might add. And so the composition of that capital investment program may change a touch as we look at the outer years of the plan. But I would say for now it's primarily wires and pipes. Again you may get additional solar but we think $11 billion is right at this point in time.

And today's next question comes from Stephen Byrd of Morgan Stanley. Please go ahead.

Wanted to go back to everyone's favorite topic, the financial compensation mechanism really interesting and really innovative approach. I guess the mechanics that ultimately got used here is a bit different than what you had proposed but it strikes me that the result is broadly in line with the approach that you had initially proposed, is that a fair characterization?

That's a fair characterization. At the end of the day, we wanted to first of all be toward agnostic around who builds and who owns these assets. We wanted to make sure that we had the proper alignment that we have the lowest cost supply resources on the system. And so conceptually, what we're talking about is making sure that the reflection on our balance sheet of our being this high quality off-taker for any kind of contract there's no way a developer gets that contract or the financing approved without us being the off-taker that that's reflected and there's an impact on our balance sheet at least the way S&P calculates. And so conceptually that's what the FCM is intended to represent. And so we're very happy with this outcome. We think it's a new standard and it really gives us a position to advocate for customers fully.

That makes sense. And then my next question is really longer-term when you think about renewables in your discussion with the variety of parties in the state, this concept of basically splitting ownership versus PPA a 50/50 split beyond the 1,100 megawatts in there kind of near to medium-term. Is that an approach you think that has buy in, in the longer run within the state?

Well it is and it worked for the 2008 Energy Law as we filed subsequent IRPs. We could revisit it. We actually didn't go in asking for the opportunity that our original filing did not include an opportunity for us to be guaranteed, the right to own. But through the discussions and that's what's healthy about a settlement process you can have really in-depth discussions with the parties to come to a conclusion that everyone really can live with. And so the settlement process has served, I think the people of Michigan very well in this scenario and certainly you, our investors, are equally well served through the outcome of this IRP.

And our next question today comes from Praful Mehta of Citigroup. Please go ahead.

Hi, so maybe just firstly on the quarter on the storm cost, this is something we've seen across the space where companies have utilities have had challenges with storm costs. What is the threshold we should be thinking about as it relates to CMS in terms of what size storms are recoverable, what size storms are not. And how does this, how do you see this going forward as an impact to your earnings?

Yes, it’s a good question, Praful. So recoverable, I will go about that in a couple of ways. So there's recoverable in the form of what's in rates and then there's recoverable in the form of we do have transmission and distribution insurance which also offers a little bit of risk mitigation. And so in terms of what's in rates, the amount of storms that we realized over the course of Q1 is already in excess of what's currently incorporated in rates. And so we do plan conservatively and so in our budget we did assume that there would be service restoration needs in excess of what's in rates. And then as you think about the insurance programs we have in place then it's a function of the deductibles you have and whether a particular storm exceeds that deductibles. And that's what allows you to get recovery and so as you may recall, when had the significant storm activity in March of 2017, we actually got quite a bit of claims back our way because of the level deductible at that point. And admittedly deductibles have gone up a bit. And so I would say that you need a pretty substantial storm activity to get insurance recovery but we did get some recovery of the storms we saw in early February in the Grand Rapids area. Is that helpful?

Yes, that's super helpful color. Appreciate that. And maybe for the second question, you guys talked about the runway of the plan where the cost management clearly is something that you guys have executed successfully and one important part of that is PPAs ruling off. I guess as these PPAs do roll off, do you see limited scope going beyond that or do you see this horizon of the ability to kind of manage costs and keep rates low while you build out on CapEx even beyond that PPA roll off?

Praful, the cost savings as far as I can see and it's certainly the PPAs, I like to call those are well -- I call them our cash for clunkers because those PPAs are out of market. They're high priced and when we replace those with fuel free energy, it really is an amazing combination to grow earnings while we're reducing costs for customers. So certainly we've got in the five-year plan ample cost savings but beyond that our abilities that we are creating to our consumers energy way to see and eliminate waste on demand are still in their early stages. I'm just watching the team really develop the skills to see and eliminate waste that reduces the human struggle for our co-workers as they're attempting to serve customers and at the same time reduces costs and improves the customer experience. And so rest assured there is our simple, unique business model has lots of runway. This model lives; we've got ample CapEx, lots of costs yet to be reduced. And then that just protects our customers from affordability constraints and enables positive regulatory outcomes and improves service to customers every single day. So rest easy the model live.

Great story guys. Really appreciate it. Thank you.

Thanks Praful.

Thank you.

And our next question comes from Andrew Weisel of Scotia Howard Weil. Please go ahead.

Hey good morning everyone. Just another question on the SCM, the WACC I believe is as you previously discussed a little bit. It's relatively low as 5.88% but I believe that's because of the deferred taxes in your capital structure right. So can you remind us what percent of the cap structure is deferred taxes and over how many years you expect to work that down to zero?

Yes. So you're right, Andrew, and so the 5.88% WACC that we agreed to as part of the financial compensation mechanism that is on an after-tax basis, it does take into account what I'll call about 20% or just under that of deferred federal income taxes that are a component of a rate making capital structure. I can't tell you exactly when that will amortize down to zero. But I can say directionally if you think about the glide path for refunding customers effectively, the deferred income taxes that we collected over the last several years as part of normalization and then also as part of the settlement for unprotected assets and liabilities at some point will be returned to customers. I would say you'd have a gradual somewhere between $35 million to $45 million reduction in that deferred federal income tax component of a rate making capital structure over the next several years. So probably 35 to 45 years depending on the asset class, electric amortizes a little faster because it has a shorter useful life than the gas assets. And so my sense is about 35 to 45 years that ticks down.

I certainly hope to not following your stock when that happens.

As you like.

You previously said you don't expect the cash taxpayer payer until 2023. Is that still the case given the solar plants?

That's right. And I would just qualify it a little bit. We expect it to be about a partial cash taxpayer at that point and more closely to a fully -- a full cash taxpayer by about 2024.

Okay, great. Then lastly, what do you think about, I know the plan for the next three years is just solar and beyond that you talked about solar and batteries. What would it take for your wind to become a part of that plan going forward?

Well we do have 525 megawatts of additional wind that we're going to be adding to achieve our renewable portfolio standard in the near-term so that's underway. What we see about wind is it's getting harder and harder to site. And so as we did the analysis for the long-term, distributed solar really matches the load curve here in Michigan combined with we do have 1,200 megawatts of base load gas plus the Ludington pump storage. We have our base load power really available. And so solar because it's distributed, because it's modular, because we can build it fast, and because that cost curve is occurring so fast that we really do see that combined with the current one we have the 525 additional megawatts of wind is the right mix.

And our next question today comes from David Fishman of Goldman Sachs. Please go ahead.

Just following on I think with Stephen's IRP question, is there an expectation or goal that when you re-file in 2021 or at some other point for the larger six to 10-year option you said that CMS can show effectively that utility owned renewables is more economic than some of the third-parties prices that you expect to see or you haven't seen as a result may be easier in the future to get a guarantee higher than 50% for owning?

I think I would say that because of the way the law was written and then we do these ongoing filings, it does mean the plan is adaptable and can change over time. If we do demonstrate that we're the most cost effective then I think that will be compelling. What I would suggest is that being able to build 50% is a really great position to be in and being able to then deploy our capital elsewhere in other parts of our system that are in high demand really works for our model because again I can't overemphasize the amount of capital that the system demands relative to customers ability to pay and the balance sheet to be able to afford, it's a constant internal battle for where the next best capital dollar is. And so having some optionality on the supply side actually really works for us especially with the SCM. It really is a great mix for us in our opinion and as we do future filings of course the plan can adapt and change as conditions change and that's really the secret, one of the secrets I would say at CMS. There's no big bet strategy. Modular, adaptable, changing conditions, whether it's weather or politics or the economy this is what's special about us. We adapt to those changing conditions because we can because we don't have big bets. As I mentioned only 15% of our $11 billion CapEx plan are projects over $200 million and half of those are preapproved renewable projects. So the fact that our plan has so much flexibility in it going forward is part of our strength and part of the secret that we can continue to deliver year after year after year that premium growth six to eight reliably.

Okay. Thank you for the very thorough explanation. So that makes sense helps to provide you a good bit of balance and flexibility. One small follow-up just more a housekeeping item. I think there was a small outage for TS Filer because it's no longer going to be repowered. I was just wondering does that spill over at all into the second quarter.

There may be a touch of it spills in the second quarter but I wouldn't say it's a material amount. And it's also important to note that Filer yes, it's a contributor to enterprises performance but it's not a significant contributor, dig really dictates the vast majority of the financial performance of enterprises.

Right. Okay. I think as I said before the dig, you all have one more quarter of material headwind that should kind of go back to being the bilateral market second half?

That's right. Given just the timing of the planning year versus the calendar year.

And our next question comes from Shahriar Pourreza of Guggenheim Partners. Please go ahead. Hello Shahriar your line is open, perhaps you're muted.

Oh sorry about that. It’s actually Constantine for Shahriar here. Yes, I was on mute. A lot of great disclosure and a lot of the questions have been answered. One kind of high-level on the IRP and the 6,000 kind of megawatts of long-term solar. Are you thinking about kind of a timing or a shape to how I guess the point I know you talked about the 1,100 megawatts are being a little bit more tailwind in the five-year plan. But beyond that kind of how linear is deployment?

Yes, it's ahead of the retirements because obviously we don't want to wait for the retirement date and then start to build the solar, so we front feet, I would say the plan and then it spreads across the time horizon up to the point that our last coal unit Campbell 3 retires. And so it really is a relatively smooth across the 20-year time horizon. But just again as conditions change, load materializes more or less that's the strength of this plan that it's modular and we can adapt.

And ladies and gentlemen, this concludes question-and-answer session. I would like to turn the conference back over to Patti Poppe for any closing remarks.

Thanks, Rocco, and thanks everyone for joining us this morning and we certainly look forward to seeing you all out on the road.

Thank you. This concludes today's conference. We thank everyone for their participation. Have a great day.