CMS能源 (CMS) 2018 Q2 法說會逐字稿

Good morning, everyone, and welcome to the CMS Energy 2018 Second 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.

(Operator Instructions) 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.

Thank you.

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, which 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.

You may have noticed our playlist of Motown songs as you waited to connect our call today, they were a small tribute to our good friend and colleague, Phil McAndrews, who most of you know.

I'd like to take a moment before turning the call over to Patti to congratulate Phil on his retirement.

Phil served as a steady hand in the IR Department for 22 years.

And we've all been fortunate to know and work with him.

Phil, thank you for your dedication to the company.

We're sad to see you go, but it's a well-deserved retirement.

Taking Phil's place will be Travis Uphaus, our new Director of Investor Relations.

Many of you know Travis well and you can expect to continue communicating with me and Travis going forward.

Now I'll turn the call over to Patti.

Thanks, Sri.

Phil has been a great contributor to our company's success and he will be greatly missed.

Frankly, we haven't had enough of Phil just yet.

So later tonight, we're throwing him a surprise party.

If you're listening in Phil, and we know you are, bring your dancing shoes and we'll bring the Motown.

Now back to business.

During this morning's call, I'll cover our financial results for the first half and recap the recently filed Integrated Resource Plan among other updates, and Rejji will provide more details on our financial results and outlook for the year.

We continued to deliver solid results for the first 6 months of this year.

Our adjusted earnings per share for the first half are $1.34 and that's up 29% from the prior year.

We continue to guide towards a full year range of $2.30 to $2.34.

We'd be disappointed if we didn't deliver towards the high end of that guidance again this year, giving us our 16th year of consistent industry-leading financial performance.

Longer term.

We have confidence in our ability to continue to deliver the consistent results on which you've come to rely.

We're reiterating our long-term guidance of 6% to 8% annual adjusted EPS growth and we continue to expect our dividend growth to align with earnings growth.

Our focus and commitment to our triple bottom line, people, planet and profit, underpinned by financial and operating performance is a sustainable and low-risk business approach that continues to deliver for you, our investors and our customers.

In fact, Market Strategies International recently named Consumers Energy as the Most Trusted Brand in the Midwest for business customers.

Our entire capital plan is designed with the triple bottom line in mind.

For example, we currently have a gas pipeline project going on near Grand Rapids.

The project itself will deliver additional capacity to help match the economic growth we're seeing in the heart of our service territory.

It's really exciting.

In fact, we're giving our board members a walking tour of this $47 million project next week to demonstrate the triple bottom line first hand.

As many of you know, there's no place I would rather be than out in the fields with my team with my hard hat and my boots on.

We're utilizing our own employees to do the work because we have the foresight to create a seasonal workgroup for our main replacement program and project like this one.

With the labor market tightening, this is actually proven to be real competitive advantage for us.

The environmental soundness of the project (inaudible) water reclamation process is reducing waste and saving money.

In fact, we anticipate saving millions of gallons of water and millions of dollars on this project alone.

From a safe distance, our Board of Directors and our team will watch along Interstate 96 as our team bores beneath the lanes of traffic.

And I can assure you there will be nothing boring about that.

The passage of the 2016 Energy Law provided us an opportunity to file a long-term generation plan.

This key element of Michigan's legislative framework is forward looking and enables us and the commission to align our long-term generation planning, providing greater certainty as we invest to transform Michigan's energy future.

We're the first utility to file and our team has spent the better part of the year assembling our integrated resource plan with the triple bottom line in mind.

This plan follows our clean and lean generation strategy, which uses modular renewables and demand-side resources to closely match supply with demand and avoid big bets.

What we love about our approach is that it's flexible.

We're required by statute to file an updated IRP every 5 years and are allowed to do it sooner as the business environment changes and technologies evolve.

At the same time, the financial approval portion of the statute gives 3 years of certainty in our supply investments.

Since we don't have any big bets and given the timing of our planned retirements, we're able to space out investments, allowing us to build a more modular generation fleet and a smoother investment plan.

The use of demand response and energy efficiency plays a prominent role in our near-term capacity planning and the 2016 Energy Law enables incentives for implementing these resources.

It highlights the strength of Michigan's regulatory construct, which is directed by very strong legislation.

From a timing perspective, the commission will comment on our IRP within 10 months and then we'll have 60 days to address any feedback before a final order is issued.

Because the IRP results in preapproval of capital expenditures in the first 3 years, future IRPs with larger supply investment plans will provide more forward-looking certainty.

As I noted, the IRP has very little near-term impact to our 5-year $10 billion capital plan.

As we look beyond 5 years, there are $3 billion of potential capital investment opportunities, primarily for solar included in the IRP.

However, the majority of our electric system investments, whether it be the next 5 years, 10 years or beyond, are focused on our distribution system.

When you include our gas system needed investment, it yields at least $50 billion of system-wide opportunity.

Our customers trust us to make prudent decisions to provide safe and reliable energy delivery.

Our biggest constraint is balancing the needs of the system with customers' ability to pay.

We wake up every day, focused on tackling that balance by relentlessly pursuing waste elimination and cost reduction in all areas of our business, which Rejji will discuss in more detail.

Our IRP reflective plan that exceeds our already announced Clean Energy Breakthrough Goals from earlier this year by reducing carbon emissions by over 90%.

Over time, we'll focus on cleaner supply sources as we retire our remaining coal units and replace the Palisades and MCV PPAs with the of buildout of modular renewables.

Ultimately, more than 40% of our supply mix will come from cleaner, renewable sources.

Through these great efforts, my coworkers make me proud and remind me, why we are ranked the #1 U.S. utility by Sustainalytics for the past 2 years in a row.

To continue to achieve these goals and accomplishments, we know we have to walk the talk.

In the second quarter of this year, we secured the purchase of Gratiot Farms Wind development for consumers.

Once we complete construction in 2020, the project will add 150 megawatts of wind to our portfolio at the utility.

We're doing more work at the utility to expand our renewable portfolio and support our customers' renewable efforts with our renewable tariff.

This program allows our large industrial customers to receive the renewable energy that they're demanding at competitive and affordable prices, while remaining fully bundled customers, no cost shift.

We're delighted to help our customers like Switch and General Motors receive cleaner fuel sources as we devote about 70% of the energy from our crosswinds to wind farm to the program.

Beyond the utility, we're expanding our renewable portfolio at Enterprises with a 15-year wind PPA with General Motors based in Ohio.

This wind farm adds another 105 megawatts of clean power to our Enterprises mix, that will consist of 0 coal by 2020 at the completion of the Filer City conversion to natural gas.

We're pleased to highlight all of this great work we're doing at all levels of the business.

Not only is it better for the environment, but we're supporting our triple bottom line by investing in customer-driven, low-risk opportunities.

Our growth will continue to be driven by our utility, which has a robust backlog of needed system upgrades on both the gas and electric distribution system.

We have a solid portfolio of investments and our plan continues to be derisked with forward-looking filings that enable alignment around strategic investments in the future and provide optionality across the business.

We'll continue to operate our existing Enterprises fleet efficiently and take advantage of opportunities like we saw with the recent wind PPA where we can serve valued customers like GM and invest in projects with similar risk-adjusted returns as the Utility.

When we couple our utility earnings contribution with contracted nonutility growth and prudent financial planning, I think you can see why we have confidence in our ability to continue to grow at 6% to 8% in the long term.

And with that, I'll turn the call over to Rejji to cover our first half results in detail.

Thank you, Patti, and good morning, everyone.

Before jumping into the financials, I would also like to extend my gratitude to Phil for his wonderful service to our Investor Relations efforts over the past 2 decades plus.

Phil, you'll certainly be missed and we hope you enjoy your well-deserved retirement.

As Patti mentioned, we're pleased to announce our strong results for the first half of 2018 with adjusted earnings per share of $1.34, up 29% in the comparable period in 2017, mostly attributable to weather and cost savings.

On a weather-normalized basis, earnings per share for the first half were up 5% versus the first half of 2017.

For the second quarter, we had adjusted EPS of $0.48, which compares favorably to the $0.33 per share that we delivered in the second quarter of 2017.

It is also worth noting that our adjusted earnings per share information for the quarter and year-to-date differs modestly from our GAAP earnings per share data given the exclusion of a $0.01 per share gain realized during the second quarter due to the expiration of an indemnity obligation associated with a sale in 2007.

Although we're proud of these results, we're only midway through the year.

So we'll continue to plan conservatively and manage the business with a focus on executing on our operating plan and identifying cost savings to mitigate future risks to the plan and to perpetuate our self-funding strategy to the benefit of customers and investors.

On the waterfall chart on Slide 12, you can see the favorable comparison of our 2018 year-to-date results versus the first half 2017.

Favorable weather provided $0.28 of positive variance with 2/3 of that coming from mild weather experienced in the first half of 2017.

And cost savings contributed $0.10 primarily from reduced benefits expenses and lower storm or service restoration costs.

Also rate relief net investments provided $0.04 of contribution to the EPS upside relative to the comparable period in 2017.

These sources of positive variance were partially offset by lower non-weather electric and gas usage, largely driven by the successful implementation of our numerous energy efficiency programs.

As we look ahead to the second half of 2018, we remain cautiously optimistic about the glide path required to achieve our 2018 EPS guidance range of $2.30 to $2.34.

This includes normal weather in the second half of the year, modest pickup from our already approved electric rate increase and a constructive outcome in our pending gas case.

Given the weather and cost performance-related tailwinds we've experienced in the first 6 months of the year, we'll be focused on identifying and implementing operational pull aheads and other reinvestment opportunities to mitigate longer-term risks.

Slide 13 shows a good example of the variability that we can experience in any given year.

And more importantly, highlights the sustainability of our business model.

As a reminder, we reinvest in the business during strong periods to derisk future years and to perpetuate our consistent industry-leading financial performance.

At this point, 6 months into 2018, we are currently $0.16 ahead of plan.

But we'll look to pull ahead reliability improvement programs such as forestry and plant maintenance from an operational perspective, and we're always scouring the balance sheet for sources of non-operating savings as evidenced by the early extinguishment of the remaining portion of our 8.75% senior notes in June.

Conversely during periods of mild weather, heavy storm activity and/or other vagaries, we managed to work and reduce operating and non-operating costs to meet our financial objectives without compromising customer service.

In either scenario, both our customers and investors do well.

This approach is supported by our simple, but unique business model depicted on Slide 14, which enables us to deliver consistent, industry-leading financial performance year in and year out.

We have a robust backlog of capital investments, which improves the safety and reliability of our electric and gas systems for our customers and drives earnings growth for investors.

We fund this growth largely through cost-cutting, tax planning, economic development and non-utility contribution - all efforts, which we deem sustainable in the long run.

As such, we are confident we can -- that we can continue to improve the safety and reliability of our electric and gas systems through capital investments, while meeting our customer affordability and environmental targets for many years to come.

We're often asked whether we can sustain our track record of cost-cutting given that we've already reduced our O&M costs by 11% since 2013.

And also because it drives roughly half of our self-funding strategy.

In response, I think, Slide 15 best illustrates our opportunities for future cost reductions.

To provide some perspective, our cost structure is about $5 billion, excluding depreciation, of which over 50% is represented by power and gas supply costs.

Within these costs, we have numerous off-market power purchase agreements, 2 of which will offer material cost-reduction opportunities within the next 10 years.

In the near-term, our Palisades PPA is scheduled to terminate in 2022, which we’ll replace with a cost-efficient blend of demand and supply side resources as Patti noted.

And in 2025, we'll have the contractual option to extend our MCV PPA at a materially lower price until 2030 as per our recently filed Integrated Resource Plan.

With fairly conservative assumptions, these actions alone will generate approximately $160 million of annual cost savings over time, which equate to about a 3% rate reduction.

As a reminder, every 1% reduction in customer rates generates about $400 million incremental capital investment capacity.

Further, we expect recurring savings in fuel costs and O&M as we retire our coal fleet over time, most notably Karn 1 and 2 in 2023.

Our power supply-related savings will be supplemented with continued gas and electric system upgrades, which reduce service restoration and leak repair expenses among other benefits, our continued efforts on waste elimination through the CE Way and good business decisions of the past, such as our smart meter installation and attrition management to name a couple.

Lastly, we will continue to seek out non-operating savings through opportunistic refinancings, tax planning or otherwise to meet our financial objectives.

To that end, in July, we implemented a $49 million credit to our gas customers as part of federal tax reform, which reduced their rates by 3% on an annual basis.

And on August 1, we will implement a $113 million credit at the electric utility.

These estimates are in line with our plan and create headroom for future capital investments to the benefit of customers and investors.

The fruits of our cost-reduction efforts and financial discipline over the years are illustrated on the right-hand side of the slide as both our residential electric and gas bills declined relative to inflation over the past 5 years despite approximately $8.5 billion of cumulative spend in those systems over that period.

As we work hard to cut costs to fuel the self-funding strategy, we're also benefiting from solid economic conditions in our service territory.

In fact, Grand Rapids and its surrounding areas, which represent Michigan's second largest population center behind Detroit and make up the heart of our electric service territory, have experienced roughly double the building permit and GDP growth of the U.S. among other attractive economic factors as you'll note on Slide 16.

Year-to-date, we continue to see healthy, weather-normalized cycle billed sales in food manufacturing, fabricated metal products and transportation equipment, 3 of the most energy intensive sectors in our service territory.

We've also done our share to generate economic development opportunities in Michigan, achieving roughly 70 megawatts of new business in 2017 and targeting 100 megawatts in 2018.

A notable example is Amazon's recent decision to open a new fulfillment center in Grand Rapids.

This win will add $150 million of private investment to the area and 1,000 new jobs in Michigan.

By actively sourcing incremental load growth opportunities, we can spread our costs over a wider volume of usage, which further reduces rates for customers.

Looking now to our cash flows on Slide 17.

We anticipate some potential upside in operating cash flow in 2018 due to the prescribed pace at which the benefits of federal tax reform are being incorporated into rates.

We continue to target $1.65 billion of OCF this year, but we may overachieve largely due to timing.

So when we combine this year and next, we don't see a material change in the aggregate cash flow generated of about $3.3 billion and still anticipate a $100 million per annum increase beginning in 2020.

Our strong and predictable cash flow generation supports investment-grade balance sheet at the Parent and the Utility, which is underpinned by a conservative financing strategy.

Our financial discipline as well as credit supportive policies from the state legislature and the commission has led to strong credit metrics and numerous ratings upgrades over the years.

To that end, both Moody's and Fitch recently reaffirmed the solid investment grade ratings of the Utility as part of their annual reviews.

As a reminder, our FFO to debt ratio is projected to be approximately 18% by year-end, which includes the effects of federal tax reform and is in line with our targeted range.

As we look ahead, we believe the strength of our balance sheet, coupled with our self-funding strategy will enable us to prolong our success for many years to come.

And with that, I'll turn the call back to Patti for some closing remarks and then Q&A.

Thanks, Rejji.

To summarize, our investment thesis is driven by a large and aging system in need of capital investment, a growing and diverse service territory, a constructive regulatory statute, a unique self-funding model that's enhanced by the CE Way and tax reforms, and a healthy balance sheet to fund our plan cost effectively.

We are confident in our ability to deliver consistent industry-leading growth and superior total shareholder return over the long term.

With that, Rocco, please open the lines for Q&A.

(Operator Instructions) And today's first question comes from Andrew Weisel of Scotia Howard Weil.

First of all, congratulations, Phil.

It's been a pleasure working with you.

And Patti, I don't think you're supposed to tell him about the surprise party 12 hours early, but I'll let you run your business as you see fit.

Thank you.

It was planned.

Yes.

Thank you.

My first question, weather-adjusted volumes have been a little soft year-to-date.

Obviously, it's very hard to weather-normalize the extremes we've had both years.

My real question is about energy efficiency.

How should we think about the impact going forward?

You mentioned in the slide that the incentive would be rising, your financial incentives.

But how should we think about the impact on volumetric growth?

And then a related question, if you're able to give any detail on numbers around potential incentives for demand response?

Yes.

Great questions, Andrew.

Thank you.

We do expect energy efficiency to continue to grow.

We are at about 1.5% annually.

We're going to 2% and we clearly identify that in the IRP.

It is a key part of understanding our clean and lean strategy.

Reducing that energy waste is an important opportunity, when we are at the same time reducing the structural costs associated with serving that load.

And another important -- there's 2 important points about our energy efficiency program.

First of all, the incentive, which in the 2016 Energy Law was increased to 20% of costs to achieve.

So currently, we're running at about $34 million incentive and that will grow to the $45 million zone in -- by 2022.

But we also have with annual rate filings then we true up our sales annually.

So that gets captured as we go forward.

On demand response, we've filed recently for a demand response incentive mechanism similar to our energy efficiency.

We expect it'll be in about the $20 million range by that 2022 time frame as well.

That is just a -- we don't have the final determination about that.

But in the Energy Law of 2016, it was also directed that there should be an incentive mechanism for demand response because all of this is about shaving that peak.

Our system is overbuilt for the purposes of serving a peak, and so due to energy efficiency and demand response, we can shave the peak and that's really a very important aspect of our clean and lean strategy.

Sounds great.

My other question is, on Page 9, you showed that you're adding wind in those 3 buckets.

What I'm wondering is about your appetite for wind outside of utility rate base at Enterprises?

I see the new one in Ohio is to service GM.

Is that more about customer service than the earnings contribution?

Or is it all of the above?

Well, all of the above.

It's always about the triple bottom line.

And when we say, people, planet and profit, people are our customers.

And so when a great customer like General Motors has an opportunity that we can serve elsewhere, we do it when it's opportunistic.

We don't have a pipeline of projects.

We're not trying to be aggressive in this part of the business, but when opportunities emerge, whether it's with a customer like General Motors or perhaps a municipality like Lansing Board of Water and Light where we just did a solar project.

The fact is we're good at this stuff.

We have a core competence in building and operating renewable assets.

And so when we can deploy that in a customer-centric way and grow earnings, we're not going to do it with -- we definitely want to grow earnings and have utility-like returns with those projects.

And so it is the triple bottom line in action.

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

Congratulations, Phil.

And thank you as well for many years of help.

My question, Patti, do you have any early sort of feeling on how the commission and stakeholders are reacting to the IRP, in particular, you obviously choosing not to include a gas plant.

And this vision of future with more modular, just any sense of how -- where the pressure points may be in that proposal?

Yes.

We are getting a lot of feedback, and it's all extremely positive, Jonathan, as you can imagine.

I think, surprised might be a word that people would use to say, wow, the utility is actually doing what they've been talking about.

And they've really put the pen to paper to model out how this really clean and lean future could be possible.

And so I will also say that we did a lot of work prior to filing the IRP with stakeholder engagement, with the staff, with the Commissioner, with community groups, environmental groups, our big business customers, et cetera.

And so I think all of that hard work that the team did to enroll others has made this so far so good.

It is a contested proceeding.

So we will, over the next several months, get documented feedback from people who might want to intervene.

I would suggest that the biggest challenge in the IRP is getting the pricing right for these new renewables, which is why in the context of the IRP, we included competitive bidding and the potential to earn on PPAs where someone else has a better price to deliver the new renewables.

That's an important aspect and we made it really clear that this is a packaged deal.

And there's not an opportunity to sort of cherrypick pieces like yes, do all the wind and do all the solar, but don't do competitive bidding.

That's not acceptable.

We want to make sure that the price is right and the model was built around having competitive prices.

So we're pretty excited about it.

I think we are definitely taking a position to put our walk where our talk is, and so far so good.

And this is just a follow-up to that.

It would -- it's clearly you're not proposing bringing DIG into the utility, which you at one point had talked about.

So can you talk to us about your plans for that facility assuming the IRP goes along as filed?

Yes.

We talked long and hard about that and considered it in the model and decided that DIG actually has more value outside of the utility than inside the utility, particularly, at the price that we would have to bring it into the utility to get an affiliate transaction approved.

And so we felt like having it outside the utility has more growth potential, and as more baseload power plants close, there's going to be more demand in MISO for power and so DIG has a good opportunity to continue to serve the market well and be accretive in the long run.

Great.

And then finally, Rejji, you mentioned the contractual obligation at MCV for the option to reduce the price.

I think you said in 2025, but could you just remind us how that works?

How much it can come down?

How much headroom that creates, et cetera?

Yes.

So the current contract is around $55 to $60 per megawatt hour.

And we have estimated that upon repricing and extending 5 years that there'd be at a minimum about $55 million in reductions of fixed costs now.

The equivalent dollar per megawatt hour, I don't have those specifics, but we think about $55 million of fixed cost savings, which makes the contract certainly much more on-market today versus where it is today rather.

Is that an annual number or is that the...

Yes, annual.

That's a run rate savings, and again, that's just fixed cost.

Yes.

And basically, the contract price comes down in half for those 5 years.

Okay.

It sounds like that price isn't necessarily set.

You're talking about needing to kind of rebid or something.

No, no, no.

It's contractually.

It will revise and effectively, as Patti commented, cut in half.

And our next question today comes from Greg Gordon of Evercore ISI.

Phil, congratulations.

After the party, if you don't mind calling me, I wanted to dust off my old CMS oil and gas model on that equatorial model that we used to do together.

That's okay with you?

Yes, you can have it Greg.

Back in 2001 and whatever it was.

You've been around a long time, Phil, you've been great at your job.

Thank you very much.

The question I have is with regard to the IRP.

Forgive me if I haven't read it fully, but is there anything in there that utilizes battery storage technologies for load shift in your market.

Patti, I presume you've looked at this because the lithium-ion battery technology comes from your former story arc at -- in the auto industry.

Is there a place for battery storage given the remarkable declines we're seeing in what the future delivery costs are for that technology in your service territory?

Yes.

We included some battery, but that's the new thing about this IRP.

We have assumptions and we use what we considered conservative assumptions with a 35% reduction in battery costs in most of the scenarios.

There was another scenario where the costs didn't come down as much.

But it turned out that renewables still pen pretty favorably even without a lot of storage.

So I expect, in future filings that the storage component will increase because we expect technology to evolve.

We are very bullish that technology can change, and -- but we wanted to conservatively plan about the changes in the IRP itself.

So we have some storage in it, particularly in the outer years, but I wouldn't be surprised in future filings if that would -- that number would grow and therefore reduce some of the renewable generation because if we can make these renewable assets more dispatchable, obviously, that's better.

And I'm a believer that even with the 4-hour battery with the nature of our peak in Michigan, that could serve as a great complement to existing renewable assets.

And I'll just remind you, we have a lot of experience with storage with the Ludington Pumped Storage Plant, that is a great big battery and we dispatch it every day, so we're very familiar with how it complements to our existing renewables today and how to maximize the value of that storage.

We're excited about the technology breakthroughs.

The automakers are telling us that their batteries aren't going to be available for reuse for some time because they're not failing as fast as they expect and some people are predicting that these EVs are going to have 500,000 mile lifespan, which makes the batteries not available as soon as we'd like, but certainly our relationship with GM puts us in a good position that as they become available we can get creative with grid and applications and seeing where we could deploy modular storage.

That's interesting.

There's a difference between deploying of the battery arm of the assembly line and then deploying a battery that's been repurposed from a used electric vehicle.

So you don’t see the technology yet at least in the story arc of your current IRP competing head-to-head with the gas peaker, the technology hasn't crossed over on a...

Well, we didn't add gas peakers in our IRP.

So about 300 megawatts of solar are in the outer years of the IRP -- 300 megawatts of battery storage rather are in the outer years of the IRP.

And the next question today comes from Michael Weinstein of Crédit Suisse.

Just a follow up on that -- by the way, Phil, congratulations, and have a great retirement.

Just a follow up on that last question.

If -- what kind of a cost decline assumption are you making when you -- you're forecasting $3 billion of opportunity in the latter part of the 10-year plan.

It was pretty far out and we're seeing pretty steep cost declines.

Does that mean we're going to see more megawatts of battery storage and renewables?

Or is there going to be some other -- but that leaves -- cost declines leave room for other types of projects.

Yes.

So we assume 35% cost reduction in solar throughout the life of the IRP.

But I will tell you from the point that we started modeling, and trust me, we did hundreds of different scenarios and sensitivities, it might not have been in the capacity of bitcoin mining and energy use, but it might have come close.

We are modelers, we're running like crazy.

But all of the models that they ran, in total, had about 35% price reduction for solar and for storage.

Your prediction and my prediction are yet to materialize.

There's a lot of discussion about that.

But I will say, from the point we started modeling to the point we filed our IRP, a lot of that 35% reduction in solar, in particular, actually had materialized and it's showing up in some unsolicited bids for solar.

And so we've recently done an IRP that we'll be reviewing and building in those cost savings for future filings, which is why it's so important that this IRP gets refiled on a regular basis to make sure that all the assumptions are correct.

But I would say if the prices dropped more, it would leave room to execute the plan at a more cost-effective method and allow us to do that gas distribution work and electric distribution work that is so important and we have such a backlog to do.

Not everyone will love the clean and lean, not every utility could really subscribe to the clean and lean approach that we have, but the demands for capital in our gas system and our electric distribution system enable us to be extremely cost-effective in all -- in fact demand that we're cost-effective in all aspects of the business.

That's great.

And just another question about the local clearing requirement.

My understanding is that courts rejected it, and I'm just wondering what the next steps are at this point?

Yes.

This issue, first of all, let's just be clear, has no impact on earnings or our guidance or there's no effect of that court order, though we vehemently disagree with the court order.

We -- when the law was passed, and trust me I was at the table, the intent was very clear, that this local clearing requirement be a component because it's -- Michigan has unique characteristics in that we're a peninsula and there's limited transmission import capacity.

Therefore, what the local clearing requirement was designed to do was to establish that if anybody was selling power in Michigan, it had to be some portion of it needed to be in the peninsula.

And so given that, the fact that it was ordered that the commission doesn't have the authority, we completely disagree with.

So we will be taking it most likely to the Supreme Court here in Michigan.

There are others who are joining us, including the commission.

We fully support that the way that they indicated their authority -- exercised their authority was absolutely legal and authorized by the statute.

And our next question today comes from Paul Ridzon of KeyBanc.

I'd like to echo those thoughts on Phil.

Thank you for all your help over close to 20 years now.

Rejji, can you just review what you said about shifting cash flows between '18 and '19.

What's behind that?

And I assume that is earnings neutral because you're -- assuming those funds go to [rate bears] anyway?

Yes.

So to answer your last question first, yes, it's earnings neutral.

No impact on earnings.

The reason why we are anticipating a little bit of upside in OCF this calendar year's because the pace at which the tax-related savings from tax reform are getting returned to customers is a little slower than we'd anticipated and that's because the process that was offered up from the -- by the commission suggests contested cases.

So there is a little process, and rightfully so because we need to make sure that we get the allocations right to the various customer classes, and that's why it's taking a little longer than anticipated.

And so we still plan to return a $165 million to customers.

We initially anticipated most of that are good portion, almost all would be done in 2018, but it looks like that will essentially drip into 2019.

And so as you think about the cash flow forecast, we said we'd be flat on the heels of tax reform for 2018 and 2019 at $1.65 billion.

And so we overachieved to some extent this year.

We expect we'll feel some of that hurt in 2019.

And so you really should think about the 2 years collectively and so assume $3.3 billion over those 2 years, and again, we may be a little bit up this year and a little bit down next year.

And all in over the 5-year period, more importantly, we expect to generate an aggregate $9 billion of cash flow and we should be back on that trajectory of about $100 million per year increase starting in 2020.

Is that helpful?

Very much.

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

So just another quick question on the IRP.

I know you've taken plenty on those, but just to understand.

Given you've run many sensitivities on it, where are the pressure points?

And then are there any areas that you feel either gas prices go up or anything else that could spike up that could lead to either push back or any responses from the commission or anybody else who kind of response to the IRP?

How do you see that playing out?

Yes.

The purpose for running all those scenarios and sensitivities is to choose and our preferred plan is the most resilient to changing conditions, whether it be gas prices or maybe the technology does not evolve as fast or maybe load doesn't materialize.

An important part of our clean and lean strategy here is that as we add modular resources, we can more quickly build out supply to match demand as we know it's materializing.

It is so much more dynamic, flexible and adaptable, which is the secret frankly to our financial success.

Our whole business model hinges on our ability to be adaptable and be flexible under changing conditions, no matter what they are.

And so this IRP is reflective of our tradition of no big bets, being able to have a plan that's both cost-effective for customers, but flexible as conditions change.

And so we really think the preferred plan is definitely the most resilient over a variety of changing -- potential changing factors.

And then we get to refile -- we're required to file every 5 years and if something material changes earlier than that, then we could file sooner.

Okay, fair enough.

That's super helpful.

And then secondly on the operating cash flow point and for 2018 and '19, Rejji, it's fair enough to look at it on a combined basis, but just wanted to confirm, does that include the refunds for deferred income taxes?

Or is that separate from that $1.65 billion?

Yes.

That $1.65 billion does not include the deferred income tax giveback.

Now what we've highlighted is that, we think the total ADIT that will be returned to customers over time is $1.6 billion.

And that's largely the protected class of accumulated deferred income tax associated with property.

And so we think that if you add that to the $1.65 billion, that's probably another, if you take it over the average life of the assets, another $50 million to $60 million.

So it's not included in that calculation, but rightfully so because the initial filing to decide how and the pace at which that money gets paid back, that has yet to be filed, that's scheduled for October 1 and then there will be contested case of our process beyond that.

And so I think, it's not until about 2019, when we will have a resolution as to exactly how much and when and at what pace.

Is that helpful?

Yes.

That's super helpful.

And on the unprotected side, is that the same kind of concept where you kind of wait to see how it plays out first?

Yes, that will be part of that calculation C filing that we'll provide in October.

And there we do have actually a pretty decent amount of both unprotected liabilities and assets that we'll have to think through.

And there isn't the same level of clarity that you have around the protected class where it effectively follows the principles of normalization.

There is a lot more ambiguity in the code as to how you treat the unprotected classes.

Got you.

Fair enough.

And then, I guess, from last call, just to follow up, if there is anything incremental on EnerBank from a strategic perspective that we should be aware of?

Nothing has changed on EnerBank.

And our next question today comes from Julien Dumoulin-Smith of BOA.

Congratulations, Phil.

Congratulations, Travis.

Everyone's moving up here, I like it.

So perhaps just to follow up on a quick question here.

I suppose, first with regards to the IRP.

Can we just quickly discuss the $3 billion incremental and the time line to see some of that reflected in the program.

I suppose, given the fact that, that's predominantly oriented at least in your words towards solar, how does the ITC commence construction safe harbor drive some of the decision and time making and could you actually see some CapEx dollars even flow out as soon as next year just to try to qualify some of the assets given just how solar oriented the incremental generation might be?

So a big part of when we will do solar is when we need the additional capacity on the system.

And we don't show in the near-term requiring new, large capital investments around new solar to be added to the system.

So the model definitely shows that in the outer years, and we factored in the ITC ramp down, and so this extension of it will affect the modeling in some of those years.

We do have an RFP out for some small amount of solar in the near term, but the big bulk of it really comes in the outer years.

And again, tax treatment is one of the sensitivities and we assumed the current tax treatment and solar still pend because keep in mind, Julien, in Michigan, our peak is in the summer.

And MISO gives a 53% capacity factor to solar on peak.

And so it has a higher capacity factor than wind because it is available when we need it, which is on those hot summer days in Michigan.

So it lines up very nicely.

And when combined with demand response, that is a very good combination and mix for us.

Understood.

Okay.

And then a little bit, perhaps, turning back to the last series of questions on, perhaps, the equity ratio.

I know there is a variety of different pieces that contribute to rate base growth relative to earnings power growth of the core utility.

Can you comment a little bit about the potential for higher authorized equity ratio and how that might mesh into your financial plan?

And I know that the deferred tax balance is also kind of meshed into this as kind of previously described too?

So...

Yes.

Julien, I think you characterized it appropriately.

I mean, there's a lot that would go into that equation.

As you know, we plan conservatively, and so you have really a few sources of inputs that would impact the equity thickness now.

At the end of the day, it's ultimately the Commission's decision.

But you have the ADIT return that I talked about earlier.

And so at a minimum if you assume $50 million to $60 million will be returned to customers over, say, a 25- to 30-year period, that's going to, by definition, as you reduce that 0 cost to capital, that represents about 20% of the ratemaking capital structure, you're going to have some level of equity thickness accretion over time, and so that would create upward pressure on the equity thickness.

At the same time, the Commission has asked us to glide path down to a level closer to 50-50 over the next, say, 5 or 6 years now.

That perspective from the commission was offered up prior to tax reform.

And so once the law was enacted in December of last year, we have made the point in subsequent filings both in our gas case as well as our electric case that we filed in May, that has obviously balance sheet implications, and so the glide path should be reconsidered.

And so I think you put all that in the vegematic then my sense is, we ultimately would like to see the equity thickness kind of level out and stay fairly consistent with where it is today, but it all remains to be seen.

But suffice to say, we'll plan it conservatively.

Is that helpful?

Absolutely.

And the time line, just getting that clarity, I imagine this is probably in tandem with the same '19 dockets that you alluded to just now with the taxes?

We'll find out around where we end up, I'd say, on a case-by-case basis.

In our recent electric case at the end of March, we were at 52.5% and then the gas case that’s currently pending.

I think we're ending up around there, call it, 52.5% equity relative to debt based on the staff position and the ALJ's position.

So we'll see where we're at in a case-by-case basis, but so far trending good as I see it.

Trending well I should say.

Right.

Perfect.

And just to be clear about this last little detail on the IRP, the less than 225 megawatts qualification here.

I presume almost the entirety of what you're talking about in terms of incremental generation given the modularity element, would does not require the same kind of approval process, right, it would all fall under that threshold?

Correct.

And so we put that in the no big bets category.

This is -- the modular plan can match supply and demand more quickly and then we can have faster turnaround when we add new supply.

And the next question today comes from Ali Agha of SunTrust.

First question.

I wanted to -- the point you all make when you look to get your CapEx plans is, the big constraint you put is that customer rates should be at or below inflation in terms of growth rate.

So when you apply that, I just wanted to find out, how much capacity do you have over your 10-year plan to increase CapEx if you need it?

I'm assuming that entire $3 billion can be absorbed if it comes to fruition.

But do you have even more capacity than that.

How should we be thinking about that?

So Ali, I would just start by saying, as you know, we really do our detailed modeling on a 5-year basis.

And so as you know on the heels of tax reform, when we provided our 5-year plan that was revised to take tax reform into account, we increased it from $9 billion to $10 billion.

And we believe that we have -- with that sort of capital investment program we can comfortably keep rates on a total basis when you include the commodity cost at or below inflation.

So we feel good about that on a 5-year basis.

We've not yet provided a new 10-year plan.

But we have noted in the IRP that it does create $3 billion of incremental supply opportunities.

And so it's too premature at this point to tell whether you take the $3 billion plus our prior plan of $18 billion and that we can comfortably afford.

And so there's more modeling to come on that.

But I would say, at this point, we're certainly going to stick to our principles as we think about the next 5-year tranche and we are going to try to make sure that we can afford to spend that as well as the CapEx on an annual basis and make sure that we don't again compromise our principles around customer affordability or balance sheet strength, I might add.

Right.

So -- but fair to say that at a minimum, if it comes to that, the $3 billion increment can be absorbed on a...

We will certainly make sure that we can absorb it if we're going to offer up a plan that includes that for sure.

Right.

And then separately, as you alluded to this as well.

So you still have some high-cost debt at the holding company at the parent level.

Can you just remind us what the earnings opportunity is from either paying that off or refinancing that just from a big picture perspective?

And is that all built into the 6% to 8% growth rate targets that you have out there?

Yes.

So refinancing opportunities are not baked into the plan, or at least I'll say premature refinancing opportunities are not baked in the plan.

And whether as it pertains to EPS accretion and upside, that's all a function of, obviously, the cost of debt that you get for the new money.

And so it remains to be seen in the levels of accretion that we'll potentially get.

We did get about a penny or 2 of upside on the remaining tranche of our 8.75% notes that we took out, which we'll realize next year, but we still have, I think, at least 1 or 2 six handles at the parent coming due, I’d say, the next big tranche is in Q1 of 2020 from a maturity perspective.

So we'll keep an eye on it.

But I think it's too premature at this point to talk about accretion dilution when we haven't thought about what the cost of debt will be that will take it out and also what the tenor will be.

So there are a lot of variables that go into that math as you know.

But that's a cushion that you still retain as you track your 6% to 8% target.

It's certainly an opportunity and so we always think about sources or levers that we can pull either up or down to make sure that we can continue to prolong this path of 6% to 8% growth over the long term.

And our next question today comes from Chris Morgan of Macquarie.

It's actually Angieszka Storozynski from Macquarie.

Two quick follow-ups.

So one is, you mentioned that your IRP would allow you to actually potentially earn on PPAs, which I've never seen, and so I'm just wondering how that's going to be structured?

And secondly, given that more and more Midwestern utilities seem to be stepping away from adding gas-fired generation, does it change your views how your semi-matured assets will be perceived as far as contracting and then demand for these assets going forward?

Great questions, Angie.

First of all, our earning on the PPA is a part of our competitive pricing expectations associated with adding new renewables.

So obviously, we're biased towards owning the assets, and that would be our preference.

We've learned over time that long-term PPAs, no matter how competitive they're when you sign them, are inflexible over time and can lock our customers into paying more than they should.

And so when we own the assets, we've more flexibility about how and how long they're operated.

And so it definitely is a preference.

However, we're also very committed to competitive pricing for customers.

And so in the event that somebody -- if we do a solicitation for a new solar and new solar bids come that are competitive that are supplied by someone else, well, then we would want to make sure that our balance sheet and our investors are rewarded for being able to back up their financing for those new assets.

So there's no doubt that they would be leveraging our balance sheet and we think that investors should be rewarded for that.

So we have a commitment -- or we have a proposal that would allow for that.

There'll be lots of discussion and, as I mentioned, the IRP is a contested proceeding.

And so I think, that definitely will be a point of discussion with interveners and with the commission and how that shakes out.

In terms of the role that baseload gas plays, I will say, we at CMS are uniquely positioned because we do have 2 utility baseload plans, our gas plants Zeeland and Jackson as well as our Ludington Pump Storage.

When you ask about -- so they provide nice baseload combination to our renewables and incremental renewables.

When we talk about then DIG, you bet DIG plays a role in the future to provide that baseload continuity and dispatchability that's a benefit to Michigan, to their potential customers as well as to MISO.

So they definitely -- like I mentioned earlier, we see more value for DIG outside the utility than in at this stage for that reason.

Okay.

Just on the PPAs.

I mean, I understand that you're trying to minimize the costs for your ratepayers.

But PPA does embed a certain return, and so a return on the PPA plus a return equivalent to the rate base value of that PPA, wouldn't that be actually earning a return twice on the same project?

No, no.

Because if the asset was owned by someone else, you're not earning the return twice.

What's happening is the only way that, that developer can earn -- can get financing for a large capital investment like that is to have a quality offtaker like us and to be able to leverage our balance sheet with credit capability to show that they can then have a quality offtaker.

So it's just giving recognition to the fact that we are the backstop and therefore our investors should be recognized for that.

And our next question today comes from Andrew Levi of ExodusPoint.

Actually I think I'm all set.

I mean, the only other question I have, the markets [are developing].

Just looking at the auto industry yesterday and the last couple of days, talking about steel and that cutting into their margins, obviously, you get it back through rate recovery.

But just -- are you seeing the same thing as far as whether it's pipe replacement or whatever other type of construction that you guys are doing?

We're not seeing it yet, but I'm sure we will.

It's impossible that all the prices of commodities are going upward.

Longer term purchasers, we buy -- we're not buying on a daily basis like the automakers are.

And so when we sign fixed contracts for supplies, for construction projects, we're more forward.

And so again, this modular build-out of renewables actually protects us from some of that too because we can build in time and adopt a plan if prices change and if they become more expensive, we can adapt to different plan.

So I would say that we definitely don't have the same kind of exposure that the autos have.

Our last question comes from Paul Patterson of Glenrock Associates.

Congratulations, Phil.

So a lot my questions have been answered.

Just back to the Michigan court appeals and Greg's question, does -- you mentioned that it doesn't impact earnings.

What impact does it have, if, in fact, the Michigan Court of Appeals ruling holds?

So the way -- the reason why we were fighting to get that corrected is because currently AESs leverage excess capacity on the market and pass along to their customers, to our retail open access customers basically for free.

And that's a cost shift to all utility customers.

So without correcting this local clearing requirement of new generation sources then our customers continue to pick up the tab for alternative energy suppliers customers, the retail open access customers.

And so it's all about price competitiveness.

And we've gone to the mat on this because we think it's wrong.

And we think there is 2 issues.

One, we have to have visibility where the power is going to be supplied and because of the constraints of the peninsula, it really does need to be -- some portion of it really does need to be located in Michigan.

And in the absence of having a local clearing requirement and alternative energy suppliers then we have to build it and our customers have to pay for it, even though it's benefiting retail open access customers.

It's a big cost shift.

It's complicated.

It's not transparent.

And I can see how the appellate court was confused about it because it is complicated.

And that's why we spent so much time on the legislation and that's why the Commission played such an important role sifting through a complex issue like this.

That's where we support our Commission and we think that they're absolutely in the right place on this issue.

Do you think it impacts the value of merchant capacity in Michigan?

Well, yes, because if a local clearing requirement was instituted, DIG would be more valuable because it is in Michigan.

But that really is not factored into our plans.

We definitely didn't build the LCR into DIG's forward-looking earnings.

What we really are talking about here is price competitiveness and standing for our utility customers.

Fair enough.

And then with respect to the PPA proposal -- making the impact of a PPA be reflected in the regulatory proceeding with respect to the sort of parasitic -- sort of addressing the parasitic issue of somebody having a PPA with you guys.

Would you guys be indifferent, I guess -- I apologize, I haven't read the full IRP, but, I mean, if it was the contract versus a -- I guess, if you could just elaborate a little bit more on how you guys stand with respect to somebody winning a PPA versus you guys building the solar facility would have, if you follow.

Yes.

I do, Paul.

Paul, it's a good question.

Indifferent is not the right word, we're not indifferent.

We would definitely prefer to own the asset, there's no doubt about that.

However, we also recognize that we want price competitiveness in Michigan.

And so if a PPA with our earning on it is more competitive for customers, then that would be an alternative we would entertain on behalf of customers.

And we have so much CapEx required in the rest of the business that it actually frees up capital to be deployed to other critical assets.

So that's really how we think about it.

We've just had all this experience with PPAs and we talk about them all the time that when we sign the PPAs they were great prices.

20 years later, it feels like, golly, why do we have these PPAs.

We'd like to have more flexibility.

And so we've just learned over time that PPAs sound good on paper, you can make the numbers pen.

But then in reality, conditions change and you’d like to have the kind of flexibility that can better serve customers.

Okay.

Awesome.

And then just finally one clarification about the question Julien was asking and your answer on capital structure.

You guys said that you were being conservative.

Did you mean conservative being that you guys were modeling in a lower equity ratio?

Or would it be more conservative than that?

Could just elaborate, is that what you meant?

When we say conservative, like I said, ultimately, we'd like to see if the current levels of about 52.5% equity relative to debt, we'd like to think given the implications of tax reform given the realities of the ADIT being paid out over time and having that natural equity thickness accretion.

We'd like to stay where we are today.

But we'll model with some assumption that, things may change over time.

And so when I say conservative, it means that we're not going to take too bullish a position on where the commission may end up here.

Is that helpful?

Okay.

That is helpful.

Because sometimes you might think equities ratio being higher is more conservative.

But -- okay, that's it.

And congratulations, Phil.

This concludes the question-and-answer session.

I'd like to turn the conference back over to Patti Poppe for any closing remarks.

Excellent.

Thanks, Rocco.

Thank you, everyone, for joining us this morning.

And we really look forward to seeing you at our upcoming events.

Thank you, ma'am.

This concludes today's conference.

We thank everyone for your participation, and have a wonderful day.