CMS能源 (CMS) 2018 Q4 法說會逐字稿

Good morning, everyone, and welcome to the CMS Energy 2018 Year-end Earnings Call. The earnings news release issued earlier today and the presentation used in this webcast are available on CMS Energy's website in the Investor Relations section. This call is being recorded. (Operator Instructions) Just a reminder, there will be a rebroadcast of this conference call today beginning at noon Eastern Time, running through February 7. This presentation is also being webcast and is available on CMS Energy's website in the Investor Relations section.

At this time, I'd like to turn the conference over to Mr. Sri Maddipati, Vice President of Treasury and Investor Relations.

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, and good morning, everyone. Before I review our results for the year, I do want to touch on what you've likely heard in the media. Michigan and the Midwest are experiencing extremely cold temperatures, which are taxing energy delivery throughout MISO and driving record demand on our gas system. The Governor of Michigan has declared a state of emergency given the dangerously cold weather.

Our #1 priority is to keep people safe and warm. We've seen record demand on our systems. And while we're working hard to meet that demand, we did have an incident at our Ray storage field, which is now partially back online. But given the weather and demand, we have asked our customers to reduce their gas usage by turning down thermostats and conserving energy across the state. We thank all of our customers who are doing their part to help Michigan through some dangerous weather, which we expect to last for the next 24 hours.

2018 was a solid year for CMS, which Rejji and I will walk through in great detail, in addition to sharing the company's 2019 goals with the usual emphasis on the triple bottom line.

With another year in the books, we're pleased to report adjusted earnings of $2.33 per share, which is towards the top end of our guidance range as planned. Building on those results, we have raised over 2019 full year guidance range from $2.46 to $2.50 per share, up by $0.01, to $2.47 to $2.51. This reflects growth of 6% to 8% on top of actuals, as we do every year with a bias toward the midpoint of 7%.

It's also worth noting that earlier this month, the Board voted to increase our 2019 annual dividend to $1.53 per share, a 7% increase year-over-year, which was in line with our earnings growth. And we're reaffirming our long-term dividend growth plans as being in line with our earnings growth.

As we look back at 2018, Slide 5 serves as a great snapshot of our triple bottom line in action as we worked hard for our people, our planet and our investors. In fact, we were able to reduce customers' bills by more than $160 million as a result of tax reform and provided over $10 million to our most vulnerable customers to help them pay their bills. We also released our Clean Energy Goal and filed our integrated resource plan, or IRP, that firmly solidified our promise to care for our planet by eliminating coal as a fuel source and producing over 40% of our energy from renewables at the utility by 2040, with up to 6,000 megawatts of new solar and reducing our carbon emissions by more than 90% during the same period. We also expanded our renewable portfolio at Enterprises with a 105- megawatt wind PPA with General Motors and a 24-megawatt solar project with a municipality in Lansing, Michigan. And our triple bottom line is underpinned by our coworkers' performance.

Operationally, we had a busy year as we replaced over 13,000 vintage gas service lines. We also spent a record amount on forestry at our electric business, improving both the safety and reliability of our system. These achievements and others listed on this slide would not be possible without our investors both large and small, who have entrusted with us their savings, and we thank them for that.

Without the broad access to cost effective capital from our investors, we would not be able to make the necessary investments to provide safe and reliable energy to our customers. As we enter 2019, we are now laser focused on delivering for our customers and investors in the current year and preparing for 2020 and beyond. I can tell you safety is top of mind this year and next as it was last year and the year before that. From boots on the ground to safety in the office, every meeting and every job begins with what we call a safety tailboard. All potential hazards are discussed before the job begins and necessary precautions are addressed each day. That may seem simple and maybe not that important. I can assure you, creating and improving a safety culture requires daily attention and all of us here take that very seriously. Beyond that, we are planning to invest over $100 million more than the prior year in improving safety in both our gas and electric systems so that our coworkers and customers are safe.

This year, we'll continue to focus on enhancing our customers' experience through targeted programs, increasing economic growth in our home state and protecting our planet, all while staying focused on our commitment to investors to deliver the financial results you've come to expect. Our priorities are enabled by our implementation of the Consumers Energy Way, which allows us to see and eliminate waste in all of our processes.

Slide 7 highlights our success in attracting new businesses to Michigan. In 2018, we proactively sought and attracted 101 megawatts of load. This is up from 69 megawatts in 2017. This load growth includes key wins from large Internet-based retailers, dairy manufacturing farms and many other industries that chose to bring their business to our state and trusted us to meet their energy needs. We're proud of these wins and the associated economic growth that they offer, including over 5,500 new jobs and $2 billion of investment in our home state just last year.

We'll also highlight that less than 2% of our customer contributions are from the auto industry, leaving us less vulnerable to any one sector of the economy. And we know that when Michigan grows, CMS Energy grows, and we'll continue to support economic development that will diversify our customer base. As we continue to focus on delivering safe, reliable and affordable energy for our customers, our performance is further enabled by our energy laws, which provides a constructive regulatory framework and supports the forward-thinking energy policy.

Today, we have an open seat at the commission, as Rachael Eubanks has been appointed to State Treasurer by our new governor. We'd like to take this opportunity to congratulate former commissioner Eubanks, and wish her great success as Treasurer of Michigan. I have no doubt that she's going to do a great job. We expect that Governor Whitmer will appoint a new commissioner soon. With 2 seats currently filled at the commission, we do have a quorum as evidenced by the recent approval of our electric settlement in early January, and we look forward to working with the administration's pending appointee once publicized and whoever replaces commissioner Saari in July, when his term is scheduled to expire.

As we look ahead to the regulatory calendar over the next couple of years, you'll see less rate cases given that we managed to settle successive gas and electric rate cases to close out 2018. The electric rate case outcome was particularly noteworthy, since it occurred 8 months after our filing and is only the second time in our company's recent history that we have settled an electric rate case. The highlight of the settlement includes $200 million for reliability investment, that's $70 million more than ever before, plus the ability to true up costs related to CapEx spending in new business, certain demand failures and asset relocations. This settlement allows us to avoid filing a new rate case until 2020.

Our IRP filing is on track for a final order in the second quarter. We anticipate an order in our demand response filing and our final piece of tax reform related to deferred taxes in the second half of this year.

Lastly, in November, we filed our gas rate case for $229 million at 10.75% ROE with a 12-month test year ending September 2020. This rate case will focus heavily on safety, as we look to replace around 140 miles of mains and 25,000 vintage services among other gas investments. The weather we've been experiencing further highlights the need to continue to invest in our gas system to ensure safety and reliability. We expect a commission order by September of this year.

As we turn to Slide 10, we're reminded of the work that our team does every day to adapt to changing conditions. As you can see, in 2018, we benefited from weather, and we put those dollars back to work, which derisks 2019. We were able to leverage the early favorability to benefit our customers very effectively in the calendar year.

If we experience poor weather and significant storm activity in 2019, we'll rely on those pull-aheads from the prior year, our lean operating system and our ability to optimize work to maximize safety and reliability for the benefit of customers. This strategy allows us to deliver on our financial objectives in the current year while providing a longer runway for our growth in the future.

As Slide 11 shows, we've proven our ability to deliver regardless of who's in office, the make-up of the commission or varying weather or economic conditions. I've said it before, the part of what makes us consistent is our ability to adapt to changing external conditions. And we look forward to working with Governor Whitmer and the commission to serve our friends and neighbors.

And now I'll turn the call over to Rejji.

Thank you, Patti, and good morning, everyone. As Patti mentioned, we're pleased to announce our strong results for 2018 with adjusted earnings per share of $2.33, up 7% from 2017 and towards the high end of our guidance as we predicted. Our adjusted EPS largely excludes modest nonrecurring costs associated with select legal legacy business matters and federal tax reform, which results in a net difference of $0.01 per share between our adjusted and GAAP EPS. As is often the case, we do not carve out much and take the good with the bad with no excuses.

Our 2018 results were largely driven by weather and rate relief net of investments at the utility, as highlighted on the right-hand side of Page 12, which were partially offset by substantial reinvestment activity or pull-aheads as we refer to them, particularly in the fourth quarter, where we had adjusted earnings of $0.40 per share for 2018 compared to $0.51 per share in Q4 of 2017.

In addition to a record level of operating pull-aheads in 2018 at the utility, we also capitalized on nonoperating pull-aheads by prefunding multiple debt tranches at the parent, which was a key driver of the negative variance in our parent and other expenses versus guides. As Patti noted, the numerous reinvestment actions taken in 2018 benefited our customers by enhancing service and reducing costs, while serving to derisk our 2019 financial plans for the benefit of investors, which I'll cover in more detail shortly.

Closing the books on 2018, Slide 13 lists all of our financial targets for the year and our success in achieving them.

I'll highlight a couple of noteworthy items. In addition to achieving 7% annual EPS growth, we grew our dividend commensurately and generated over $1.7 billion of operating cash flow, which exceeded our guidance and was roughly flat with the prior year as anticipated due to the effects of federal tax reform. Our steady cash flow generation and conservative financing strategy over the years continues to fortify our balance sheet, as evidenced by our strong FFO to debt ratio, which was at approximately 18.5% at year-end and also exceeded our expectations. It's worth noting that our outperformance for FFO to debt was in part driven by the prescribed pace at which the benefits of federal tax reform were incorporated into rates, which enabled us to issue less equity than we initially anticipated in 2018.

Lastly, in accordance with our self-funding model, we kept annual customer price increases below inflation for both the gas and electric businesses, all while investing a record level of capital of approximately $2 billion at the utility.

Moving to 2019, as Patti highlighted, we're increasing both the bottom and top end of our 2019 adjusted EPS guidance to $2.47 to $2.51, which implies 6% to 8% annual growth off of our actuals for 2018.

Unsurprisingly, we expect utility to drive the vast majority of our consolidated financial performance, and we continue to target the midpoint of the EPS growth range of 7%.

To elaborate on the glide path to achieve our 2019 EPS guidance range, as you'll note on the waterfall chart on Slide 15, we plan for normal weather, which in this case amounts to $0.27 of negative year-over-year variance given the better-than-normal weather experienced in 2018. However, as I highlighted on our third quarter call, we've largely mitigated that headwind with the substantial reinvestment activity that we exercised in 2018. More specifically, we made a number of discretionary pull-aheads in 2018 that we do not need to repeat in 2019. The operational and financial flexibility afforded by these efforts, coupled with our usual level of expected cost performance should result in a $0.27 positive year-over-year variance, which fully offsets the absence of the favorable 2018 weather.

And while we're on this topic, I would be remiss if I didn't take a moment to thank all of our coworkers for their hard work throughout 2018. While the customer and financial benefits of pull-aheads are relatively easy to identify, what is often underappreciated is the organizational burden that pull-aheads create since we don't usually outsource this incremental work and our coworkers effectively double their efforts to get this work done.

As mentioned, we have mitigated some of our regulatory risk in 2019 with positive outcomes in the early settlements of our previous electric and gas cases. We also have a pending gas case, as Patti noted, for which an order is due in late September. Keep in mind, we're showing the net pickup after the impacts of investment-related costs such as depreciation, property tax and interest expense. We've also embedded the usual conservatism in our assumptions around sales and financing activity. Please refer to appendix Slide 25 for an EPS and OCF sensitivity analysis on said variables among others.

As you can see, due to our significant reinvestment activity in 2018 and the constructive regulatory environment, we have a reasonable path to deliver another year of 6% to 8% adjusted EPS growth. Our focus on cost controls, conservative financial planning and proactive risk management underpin our simple but unique business model, depicted on Slide 16, which enables us to deliver consistent industry-leading financial performance year in and year out. We've 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 our investors. We fund this growth largely through cost cutting, tax planning, economic development and modest nonutility contribution, all efforts which we deem sustainable in the long run. As such, we're confident that we can continue to improve customer experience through capital investments while meeting our affordability and environmental targets for many years to come.

As you can see on Slide 17, we've updated our 5-year customer investment plan by rolling it forward 1 year, as we often do on our Q4 call. This adds an additional $1 billion of capital investment bringing the 5-year plan to $11 billion in aggregate, roughly half of which is comprised of gas infrastructure investments.

We continue to focus on the needs of our aging gas system. As reflected in the forecast, increase in gas as a percentage of total rate base from 30% to 40% over the next 5 years, which drives over 7% rate base growth. Please note, the annual details of this plan are included in the appendix of this presentation.

Our capital investment needs remain significant beyond the 5-year period as well. As we work through regulatory proceedings in our financial planning cycle, we expect that the longer-term capital mix will continue to evolve. And we look forward to providing an update to our 10-year capital plan in the second half of the year once we have better visibility on the long-term capacity plan per the outcome of our IRP.

As we've highlighted in the past, the primary constraint on the pace at which we invest capital is customer affordability, and we are confident that we can continue to deliver cost reductions to minimize customer bill increases. Our numerous capital investment programs will enable reduced maintenance costs on items such as service restoration, leak repair and meter reading, among other benefits. We will also benefit from power purchase agreements rolling off in due time, while also realizing fuel and O&M expense savings as we retire our coal fleet.

Speaking of the coal fleet, I'm pleased to report that we've recently renegotiated our fuel transportation rates, which will yield over $150 million in customer savings cumulatively over the life of the new contracts. We also continue to seek out nonoperating cost savings opportunities in addition to the -- in addition to over $1.2 billion of opportunistic refinancings collectively at the parent and utility in 2018. We contributed $240 million into our pension plan in late December to increase the funded status of our pension plans to approximately 90%. This sizable discretionary contribution, coupled with prudent decisions of the past such as closing our defined benefit plan several years ago, utilizing conservative asset return expectations, and employing a balanced asset allocation strategy, among others, has more than offset the unfavorable asset performance experienced in 2018.

In fact, we're estimating about a $6 million reduction in our pension expense in 2019 versus 2018, as noted in the appendix.

To put our strong cost controls into perspective, on the right-hand side of the slide, you'll note that our residential electric and gas bills have decreased on an absolute basis and as a percent of wallet for Michigan residents from 2007 to 2017 despite nearly $15 billion of capital investment over that time frame.

Looking now at our operating cash flow forecast on Slide 19. As mentioned, we received some upside in OCF in 2018 due to the pace at which the benefits of federal tax reform were incorporated into rates. And similar to O&M, we took measures to derisk our 2019 plan, most notably through the aforementioned pension contribution and solid working capital management. As such, we continue to target $1.65 billion of OCF in 2019 and still anticipate a $100 million per year increase beginning in 2020. In aggregate, we are forecasting to generate over $9 billion of cumulative operating cash flow over the next 5 years, which will play a key role in the financing strategy of our 5-year capital plan.

In support of our liquidity planning, we also expect to avoid paying meaningful federal taxes through 2023. This is the result of a strong tax planning and the forecasted layering in of renewable tax credit as we meet the 15% RPS standard in Michigan by 2021. In sum, our forecasted OCF generation, coupled with our tax shield portfolio enables us to continue to finance our capital investment program in a highly cost-efficient manner as you'll note on Slide 30 in the appendix.

On Slide 20, you'll note that we have refreshed the outlook for DIG to reflect positive new developments in our energy contracts. In short, we've successfully amended and extended our existing energy contracts and entered into a new contract at our simple cycle unit in Kalamazoo. The revenue associated with these contract revisions has allowed us to weather the challenges presented by lower capacity prices, and we have reflected this in our guidance for 2019 and our plan going forward.

As you can see, DIG is almost fully contracted for energy and capacity through 2022, so we feel quite good about maintaining the $35 million pretax income run rate. Also if capacity prices were to revert back to recent history of around $3 per kilowatt-month, then we could see an additional $10 million to $15 million of upside. Alternatively, if the market were to tighten to levels comparable to the MISO Cost of New Entry, or CONE, due to looming coal retirements or the establishment of a local [therm] requirement, then this opportunity could more than double.

Suffice to say, the Enterprises team has done an excellent job managing risk and reducing the beta in their portfolio for the foreseeable future.

On Slide 21, we have listed our financial targets for 2019 and beyond. In short, we anticipate another solid year of 6% to 8% EPS growth, with a bias towards the midpoint. This model has and will continue to serve our customers well as they see affordable electric and gas prices from our self-funding strategy as well as our investors who can continue to count on consistent industry-leading financial performance.

As we look prospectively at the consolidated business, our EPS growth continues to be driven by our utility given its robust capital investment needs and forward-looking filings such as the IRP -- and forward-looking filings, excuse me, such as the IRP provide long-term transparency for key stakeholders, which should provide more visibility regarding regulatory outcomes in the future. Outside the utility, we'll continue to operate our Enterprises business with a low-risk mindset. When we couple our earnings contribution with contracted nonutility growth and prudent financial planning, you can see why we have confidence in our ability to continue to grow at 6% to 8% over the long term.

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

(Operator Instructions) Our first question will come from Jonathan Arnold of Deutsche Bank.

Just, Rejji, this might be for you, but I don't think you've given us quite the granularity on timing of spend by segment, at least not recently. So can you perhaps help us see where the $1 billion of incremental electric investment is falling? It looks like 2020 and 2021 are the peak spend years, but I -- yes, I was just not sure what those were before?

Happy to do that. Yes, so you're right, we do crest over the 5-year period in 2021 and that has a lot to do with the renewables and the trajectors and giving them timing of the tax credits. But if you look at the $11 billion in our new 5-year plan versus the $10 billion in our prior vintage, the real difference is, one, you got about $0.25 billion of renewables flowing through our electric supply spend and that, again, is to get us to the 15% RPS. And then you've got about a commensurate increase in electric distribution and gas infrastructure spend as we roll forward 1 year. So I'd say it's a combination of those 3 things: incremental renewables; electric distribution spend as we roll our 5-year distribution plan 1 year forward; and then an uptick in gas infrastructure spend. So it's really those 3 things, Jonathan.

So the renew -- I thought the renewables, the $1 billion of renewables was already in the prior plan?

We had it close to those levels. I'd say we were probably about $0.25 billion south. We were in that ZIP code, but at the end of the day, yes, we wanted to make sure that the renewables we had in the prior plan and this plan reflected what we were seeing in our Renewable Energy plans that we filed in the RFPs.

Okay. And similar topic -- so I think last quarter, I think you said you were planning to give an update to the 10-year view on capital late -- sometime later this year. Are you still thinking that you'll do that? And any sense on timing and what you're specifically waiting for before you do it?

Yes. So we would foresee rolling out a new 10-year plan by the second half of this year, as we mentioned in Q3 and prior to that, I think. I mean, the real gating item as we see it is the IRP. And so we're going to get most likely a preliminary point of view from the commission in April of this year. We get 60 days to respond to that and so that will most likely play itself out by midyear at which point we'll have better visibility on our electric supply spend over the next 10 years, particularly in those outer years, because that's when you start to see a ramp-up of, I'll say, renewables-related spend.

So that's a key data point. And at the end of the day, we also have to spend a good deal of time internally making sure that we can solve the customer affordability equation. It would be irresponsible to roll out a capital plan that we couldn't -- when I say we -- our customers and/or our balance sheet couldn't afford. And so we want to get all of that math right before we roll it out. I can say with great confidence that the $18 billion that we rolled out in the prior vintage in September of 2017 is well stale, and we expect it to be higher than that, but we'll have to spend some more time figuring out how much higher.

I mean, would it be reasonable to think it would be more than double the 5-year plan, given the need to kind of -- the compounding effects?

It's premature to guide you at this point. We have said that we think there's about a $3 billion capital investment opportunity in the IRP in the outer years, and so we would feel pretty comfortable saying that, that will likely be included in the new plan and also we've talked about this sensitivity in the past where basically every $60 million or 1% reduction we can achieve in rates creates about $400 million of incremental capital investment capacity.

And so if you think about our PPAs rolling off and if you think about some of the cost savings we expect as we retire the coal fleet over time on O&M and fuel side, we do think it's going to create substantial headroom to accommodate additional spend. So I'd hate to guide you at this point and give you a directional number, but we think it will certainly be in excess of the $18 billion.

Okay. And just one final thing, how certain are you guys that you will need to file another electric case in 2020? Is there a chance that under this settlement you can potentially go longer?

I think given the needs of the system, it's likely that we will file in 2020, Jonathan. We have -- the settlement this year, we're so happy about it because it does enable certainty in our reliability spend and we don't have to trade off with some of the other more variable programs that often compete for the capital dollars on reliability because we have this new regulatory mechanism. But it isn't -- we didn't settle for a full tracker. We do think there is a basis in this settlement for a tracker in the future. But we know that there's a significant electric investment required and our cost effectiveness is captured there. So we think that we will definitely be filing in 2020.

Our next question will come from Greg Gordon of Evercore.

Couple of questions. I was just a tad late hopping on the call, and I just missed hearing the roll up of the actuals for 2018. And you had commented that there was a reason as to why the corporate overheads came in higher than initially budgeted. What was that, if you wouldn't mind restating that, please?

Yes, happy to, Greg. It was largely due to the significant amount of reinvestment activity both in the operating and nonoperating sides. So in corporate, you're going to have some of the nonoperating related spend embedded in that. And so we took out at least 2 tranches of parent-related debt prematurely in 2018, $100 million remaining from our 8.75% notes, and then $300 million of a 6 handle note around midyear, and so a lot those upfront costs flow through the corporate and other expenses.

Okay. And are you just refinancing at a lower rate or are you diffusing that debt permanently?

Combination of both. Oh, actually. I should be clear. Just to circle back, when you say diffusing, do you mean just taking out altogether?

Were you paying off or are you refinancing it?

No, we're refinancing, just to be clear. So we're extending maturities at a much lower cost.

Okay. I guess, then what's driving the -- if that's sort of a one-time expense to prepay the debt, what's driving the assumption of a flat corporate overhead number this year?

Well, the reality is we've been so proactive over the last several years in taking out, I'll say, high coupon bonds that there really aren't too many opportunities left in the portfolio. So credit to Sri and his team for their wonderful prefunding efforts. But if you look at the rest of the portfolio, both at the parent and the operating company, you really see 4 and 5 handles and I don't think we have maybe one 6-handle left, but we've done a nice job. So I don't foresee too many opportunities to prefund at attractive levels. So that's why we're being fairly conservative in the year-over-year corporate.

Okay. And then my second question was, your FFO to debt came in at 18.5% for '18. You've told us the expectation is that it's going to be around 17% in '19. What's driving that delta? And do you expect movement in your FFO to debt metrics post '19 up or down in any meaningfully way?

Yes, I would say it's a couple of things. And so, first, we talked about the prescribed pace at which the effects of tax reform are being passed on to customers. And so we initially assumed at the beginning of 2018 that we'd have an outflow of around, call it, roughly $200 million, and that's both sort of credits A and B to reflect the reduction in the current rate that flows through base rates from 35% down to 21%. And then we thought there may be resolution on the deferred tax-related refund to customers. That obviously has -- was a little bit too aggressive an assumption. And so the fully adjudicated process will extend well into 2019.

And so we had about, I'll say, $150 million of upside from an OCF perspective in 2018 because the outflows back to customers did not occur during this year. Now there is no P&L effect, but there's certainly is a cash flow impact. So we expect there will be a headwind in the form of giving those dollars back to customers in 2019. And so that's, I'd say, the largest source of the variance year-over-year. And then what you also see too is just the realities were increasing our annual run rate for capital investments. So we're going from $2 billion a year at the utility to $2.25 billion. And so funding that also has credit metric implications, and we're also still assuming that the equity ratio at the utility is at that sort of 52.5% level and so that's going to require infusions from the parent down there and we do debt fund a portion of that. And so that's really what's driving us to that 18.5% or thereabouts down to what I'll say is approximately 17% in 2019, and we expect to stay at that level for the foreseeable future. Is that helpful?

That's extremely helpful.

Our next question will come from Michael Weinstein of Crédit Suisse.

So could you talk a little bit about the equity issuance needs of $150 million a year? I guess that's a long-term plan, and how that differs from the $70 million. Like what's the increment between those two?

Yes, sure. So similar to what I described in terms of the variance in our FFO to debt metrics year-over-year, it's really -- it's a few things, Michael. It's again the increase in our capital spend rate. So our run rate, historically, has been about $2 billion or at least over the last couple of years and now will be at $2.25 billion with an increase in the new 5-year vintage, the $11 billion in total. So assume an about $2.25 billion per year at the utility. So that's going to drive our sort of leverage-related needs and our equally needs as well.

And then, again, we're assuming that our equity component of our ratemaking capital structure will stay at 52.5%, and so that's going to lead to fairly substantial equity infusions from the parent into the utility, most of which we fund with equity issuances, and so you have a couple of things there. And then the other reality is in '18 again we did not have as significant an outflow for tax reform back to customers as we'd anticipated. And so we didn't issue as much equity in 2018 and so some of that will flow into future years.

And so we assume, again, we're going to -- our run rate will be about $150 million per year of planned equity issuance. We will be proactive about that as we can. So we did a good deal of forwards in the fourth quarter of last year while we thought our stock was at a relatively attractive price and so we've taken a lot of the price risk off the table in 2019. And we'll see where we end up going forward, but we think that that's a reasonable level. If you're doing $150 million per year and you look at that as a percentage of market cap, we definitely think that that's doable in an ATM program.

Got you. And looking at the DIG slide, in the old slides, right, you had a $75 million opportunity from a 750 capacity price going out into the future and now it looks like it's $95 million. Is there -- maybe I just misunderstood why that -- I don't know if you explained that before. Maybe you could explain it again?

No, I mean, the math that we have, it really is looking at just the potential opportunity that you would have if you have either a local clearing requirement established in Michigan, and we think the jury quite literally is still out on that, or just given the tightening we expect in the bilateral capacity markets, as you see, inevitable coal retirements in Zone 7 and throughout the region. And so the math is basically rolled forward a year, we're assuming somewhere around 750 and that coupled with the extension and amendment of existing energy contracts with some of our big contracts at DIG is really what's fueling a little bit of that incremental upside.

But needless to say, we have not incorporated that into our plan. We're assuming what you see on the page here for 2019 about a run rate of $35 million of pretax income that we think will last for the foreseeable future. And as you probably noted in the table above, we really have derisked the portfolio a good deal by amending and extending energy contracts and selling forward capacity fairly ratably over the last several months.

I see. So a lot of the upside -- or a lot of the benefits or reason why it's more stable is energy contracting even though the capacity pricing has been softer?

That's right.

Our next question will come from Julien Dumoulin-Smith of Bank of America Merrill Lynch.

This is actually [Eric] on for Julien. But I just wanted to ask if you could discuss progress around the IRP filing thus far and what could drive further confidence in renewables spend beyond that $1 billion RAP through 2021 in the current plan, specifically with the remainder of the solar ITC safe harbor period in '22 and '23?

[Eric,] we're making good progress in the IRP. As I'm sure everyone knows, we were the first IRP to be filed and processed here in Michigan, the hard work that we did to get lots of stakeholder input before we filed has made for very constructive discussions throughout the process. Because it is a complicated process, we are planning on it going to its full regulatory time line, which would be a first preliminary order from the commission in April and then a final order in June, and we're looking forward to working through the remainder of that process.

To your question about additional renewables to the plan, what we have in the plan right now reflects no additional incremental renewables as a result of the IRP, that would be premature to do before we have a final order in that. So right now what we have built into the plan is meeting the renewable portfolio standard through our RAP.

And then just regarding 2022 and '23, presumably, I know you mentioned the customer affordability side of the equation. If you were to have a supportive IRP result, could we potentially see incremental renewable spend in '22 and '23 supported by, say, lower fuel costs with replacements and whatnot?

The driver for the renewables is demand on the system and what's required both to meet the law, but also to meet the needs of customers for their demand for energy. There is -- we do -- we have published our time line of retirements of our coal plants, and we also do have the retirement of the PPAs. But in the 2023 time horizon, the Palisades PPA that comes off doesn't require additional capacity to backfill it. We've replaced it with energy efficiency demand response and other sources in the short run. So I don't think that would drive incremental renewables in that time horizon.

Our next question will come from Ali Agha of SunTrust.

First question. Just looking at your quarterly disclosure on weather normalized sales on the electric side, I mean, we -- the electric sales weather normalized were negative and 3 of the last 4 quarters ended up negative for the year. Just wondering, what's kind of driving that? And can you just remind us what you've assumed for weather normalized electric sales going forward?

Sure, Ali. So I will not try to spend too much time on the soapbox around the imperfections and shortcomings of weather-normalized math. But I do think that it is flowing through the numbers, particularly if you take into account the stark contrast between weather in 2017 and 2018. So I would start there. But then as you look at just the numbers that are on the page, putting that aside, so we are approximately 0.5% down blended for electric for 2018. And it's really important to note that, that customer usage level reflects our efforts to reduce customer usage year-over-year through energy efficiency, where we get compensated to do that.

And so we've been at this for now about 10 years, if you go back to the prior energy law in 2008, and so now it's a 1.5% bogey. And we expect to clear them. We've cleared it the last year and we expect to clear it this year as well, and so you'll see that flowing through 2018. So what does that mean? So when you're negative 0.5% on a blended basis for electric, if you gross it up, you're at about 1% for electric. And so we still think of that, that on a normalized load basis is comparable to what most folks are seeing across the country.

And then if you peel the onion a little bit and you look at residential, it was down about 0.3%. So you gross that up, you're up over 1%. Commercial was up about 0.3%. Again, gross that up, you're down over -- you're up a little under 2%. And so we still see pretty good trends there and I think what's also important to note is that if you look at the economic conditions in our service territory, they still remain quite good, and so we always point to Grand Rapids, that's in the heart of our electric service territory, and you pick a metric, whether it's GDP, unemployment, population growth, building permits, all those statistics are trending better than the national average. And so we continue to feel quite good about the economic conditions in our service territory.

So, yes, the numbers, I think, on the surface may appear a little suboptimal, but, again, we think there's a lot more to it. You asked about going forward. We assume roughly flat over the planned period at the utility, again, weather normalized and net of energy efficiency. So I'd say our expectations are relatively tempered. And then the IRP, which spans over a longer period, we're assuming about 0.25%.

So again, we plan very conservatively. And the last thing I'll say is we also aren't reactive when it comes to normalized load growth expectations. We have very prosperous economic development programs; and Patti highlighted in her planned remarks that we hit 100 megawatts in 2018, up from 69 megawatts the prior year. And so we really feel like we're doing all we can to support economic development, and our service territory certainly relative to other service territories across the country looks quite good.

Okay, that's very helpful. Second question, perhaps for Patti as well. I mean, you've got a new governor, obviously, in place now. By the middle of the year, you'll have 2 new commissioners out of 3. Just wondering, how you're thinking about the regulatory framework in the state. And do you expect any changes once all of this is settled going forward?

Well, we're looking forward to learning the governor's plans on our current open position at the commission. With commissioner Saari and commissioner Talberg there, that's 6 more months of that quorum and with the addition then of a new commissioner, we look forward to that appointment.

I would say that one of the strengths of the Michigan regulatory environment is that it's captured in the statute. And so our energy law that was passed originally in 2008 and then further improved in 2016, provides a lot of continuity in regulatory planning. And so we do have a great working relationship with the new governor. Many of her staff are people we've worked with in the past. And so we're quite optimistic that she'll make great appointments to the commission, and we'll look forward to working with them. And like our track record has been, independent of commissioner changes, governor changes, economic changes, weather changes, we have the core capability of adapting to those changing conditions. We have a lot of confidence in our ability to adjust and adapt as necessary.

Okay. And lastly kind of related to that, my understanding is through -- because of term limits there's been a fair amount of turnover in the legislature as well. As you look out over this session or even beyond, anything in particular for us to keep an eye on or that you're keeping an eye on, anything that could either tweak or change the energy law in any way, any expectations on that front?

Well, you're right, Ali. We have term limits in Michigan. It was a good concept. In practice, it's pretty difficult because we do have a lot of turnover. The good news is, it took a lot to pass the 2016 energy law. It was bipartisan, wide support. We have 2 strong committees in both the House and the Senate. We're really excited about the leadership appointments in both the House and the Senate. And so as far as we are hearing from the legislative leadership, both from the governor's office as well as the Senate and the House, they've got other very important issues that need to be attended to. No-fault auto insurance, the roads, education in Michigan are really taking top priority for the current legislature and the governor, and we're happy to work with them and help make those improvements.

But I think the general consensus is the energy law that was passed in 2016 was a great and difficult body of work, and so it's really still in the implementation phase of that law, and we don't expect changes to it in the short run.

Our next question will come from Praful Mehta of Citigroup.

So maybe first just on this extreme weather events, right, whether it be 2018 summer or now the winter, and this polar vortex. Just want to understand, if these kind of events continue, does that sit within the IRP and the load planning that you have? Do you think it changes any of the infrastructure needs? And does that change potentially the growth profile? So any color on that or thought around that would be helpful.

Well, so specifically on the electric side, if that's what you're asking about, the IRP, first of all, has the ability to be refiled every 3 to 5 years. So if we start to see a material load difference then we would plan accordingly. I will say that even yesterday, for example, where MISO had issues in the Midwest, we were plus 1,000 megawatts in Michigan of supply. So our planned forecast IRP that we published, I think, reflects a very conservative perspective about being able to deal with the kind of the peaks that occur on the electric system.

And on the gas system, I think, traditionally, our system is well equipped and capable of serving this volume of load. Our interruption yesterday was driven by an equipment failure at our largest storage field. But normally, under any kind of even these extreme conditions, we would have been well equipped to serve that load. And in fact, yesterday morning, when we hit our peak load, our system worked perfectly and we had ample supply and ample ability to deliver that supply. And we've not had to curtail any residential customers even through this unprecedented weather event with the shortfall of our Ray storage field included. So very proud of the team and how we're handling this situation, but the system definitely is robust and prepared for the future.

Got you. That's super helpful color and great performance by infrastructure, so that's phenomenal. Maybe moving on more on the financial side, the pension funding aspect. You had $240 million in '18. Could you remind us, is there any plan to have any incremental funding in '19 that's currently in your plan or is there any need to fund '19 or '20?

Yes, there's currently no obligation based on the funded status to fund the pension in 2019. We basically pulled forward about $100 million of required spend in 2019 through this contribution in December of '18. So I think at least for '19, there is not an expected contribution. 2020, I don't believe there's one either. But we think that we derisked the plan most importantly rather significantly by this discretionary contribution in '18.

Got you. And then in terms of parent and other, obviously, there was a big move. Just to understand that impact on parent and other, you clarified that this was mostly related with one-time costs of refinancing and taking out older debt with more, obviously, cost-efficient debt at the parent level. Is that the entire impact or are there other impacts at the parent level that we should be aware of?

Well, I think in addition to the proactive refinancings which have associated make-whole costs, I mean, obviously, every year because the business is growing and we're funding capital investments, we will have incremental increases in parent debt, which is basically new money financing that we do each year. And so we did issue some hybrids in, I think, a couple of tranches in 2018, so you'll see interest -- incremental interest expense associated therewith. So I'd say that's another source of drag that you see in the corporate.

Got you. And that '19 level that you have, is that the expected level of interest expense at the parent? And the EPS at the parent, is that expected to stay flat from there or how do you see the parent earnings going forward post '19?

Yes. I mean, remember you've got a few things in there, and so we'll expect incremental interest expense given the growth of the business, and so you'll have that flowing through at the parent and clearly that's nonrecoverable. We do have also a little bit of drag that we talked about on our Q4 call of last year, and that's because of the impacts of federal tax reform, where the -- just the net deductions that you get at that level are just aren't worth as much that they were previously.

But I think the other impact too is that we have EnerBank following through those numbers and so that will also be impacting the parent and other expense, because EnerBank is a component of that and as we always have talked about in the past, we do expect that EnerBank will grow in excess of the consolidated business. And so you see that as a little bit of an offset of those other, I'll say, sources of drag.

Our next question will come from Travis Miller of Morningstar.

I was wondering if you could talk a little bit about some of the puts and takes, how you think you achieved that settlement deal when you've had some issues trying to do that in the past. Just what was the key to that settlement?

Well, I think there are a couple of things that were critical to the settlement. We're very proud of the fact that we were able to settle that, but I think it's a reflection of the quality of the regulatory environment, as we've mentioned over the last couple years, with Chairman Sally Talberg at the public service commission, she's done an excellent job building the quality staff, helping raise the bar for the quality of our filings, her requests of the 5-year electric distribution plan combined with the visibility that the commission and the staff had on our integrated resource plan. You can imagine their ability to see how a filing fits into those long-term plans is a much better way to do good regulation and make good decisions on behalf of the citizens of Michigan.

So I would attribute it to a lot of hard work by our team to have good long-term plan, a request by the commission to see those plans and have them be public so that we can have good discussions with critical stakeholders, and then a willingness to make good decisions together and have a settlement for the best interest of all customers. So very happy with that outcome. I think it really sets the ground and the framework for future orders as well as future cases regarding our electric investment strategy and cost savings that we can pass along to customers through those filings.

Okay, great. And then one other on the whole electric rate case in general. What kind of distribution upgrades either in the -- that were approved in the rate case for future would be needed to integrate the level of renewables? Is there anything at the distribution level and perhaps how much and what would be needed in terms of grid upgrades to integrate?

Yes. Yes. Of course, that's definitely -- we'll have a key eye on the distributed energy resources and how to integrate those into the grid. I would suggest in this filing it's more about the basic blocking and tackling of poles and conductors and substations, transformers, making sure that the equipment that is on the system is robust and reliable. Our 5-year electric distribution plan is a $3 billion investment strategy that has more of the high technology attributes at the latter half of the 5-year plan. So including better visibility through SCADA systems on the distribution system, our ability to have control remotely, our ability to see the operations of the grid to do more looping and smart switching on the system, all of those investments are throughout the 5-year plan, but more back-end weighted.

So this specific settlement really is focused on the backbone and the basics of the electric distribution system. I often say, you can't put fancy whizbang technology on poles that are falling over. So make sure we've got the poles secure, we've got the right conductor, transformer, substations and then we'll bolt on the technology to the best service of customers throughout the distribution plan.

Our next question will come from David Fishman of Goldman Sachs.

Congrats on another solid year. Just following up on the regulatory items that you were talking about. It seems like when I was reading a little bit of the staff testimony, it was actually pretty favorable with regarding an earnings sharing mechanism. And I know this is meant to coincide with a tracker, but I was just curious if this is something in a future filing you might be -- you might pursue separate from a tracker?

I think what we believe about this current electric rate case settlement is that this deferred accounting that we agreed to really is a first step in direction of tracker -- of a tracker for future filings. And so that again comes with, as we build trust, we have a tracking mechanism, for example, on the gas system for our enhanced infrastructure replacement program. And over the last couple years, we've done a great job of doing precisely what we said we would do, and that gives confidence then to the commission that they can do preapprovals in a more routine, formulaic tracking mechanism, but we're quite satisfied with this outcome of the settlement, and we think it foretells well future filings.

Our next question will come from Andrew Weisel of Scotia Howard Weil.

Just -- first, I want to clarify something I think Rejji answered in an answer to Ali's question about demand growth. I think you said you're expecting flat, maybe up a 0.25%, but in your Slide 16 you show 1% growth from sales and economic developments. How do I reconcile those? Was that purely energy efficiency?

Yes. So long term over the 5 years, we expect flat to a 0.25% for growth. So that is first and foremost. I'm just referring to the 5-year period. But this page often, I think, is the source of confusion. When we talk about sales growth in this simple, perhaps, unique model slide, Slide 19, that you referenced, we're not suggesting that long term we're expecting 1% sales growth. What we're talking about on that page is how much sales growth contributes to the self-funding strategy. And so when you look at the pieces, we say cost reductions 2 to 3 points, that means cost reductions fund half of our capital investment [or] rate based growth to alleviate the burden to customers, and so sales is a component of that equation, as is tax planning, as is nonutility contribution. And so those are the pieces that allow us to fund about 3 quarters in aggregate of our rate base growth so we can keep total rates, customer prices, bills at or below inflation. And so it's a little bit difficult to follow the way it's positioned on that page, but we're not implying 1% growth for the long term.

Got it. Okay. And then just a follow-up on the sell side. Any updated thinking with marijuana now legal? Have you seen any activity around grow houses, increased demand and if and when this could turn into a meaningful driver? Or could it add complexity of demand, unexpectedly spikes in a house or warehouse without you guys getting sufficient warning?

Yes, those are all great questions. And we are working on evaluating what the effect will be. From what we've seen from other jurisdictions, anywhere from 1% to 4% additional load as a result of the legalization of marijuana has been experienced elsewhere. We're not forecasting that in our plan yet at all. The regulations are still being defined and are clarified, and they are slightly different than other states. We are the only state in the Midwest and so there is a potential that it could be a driver here.

We're actually working very proactively to identify who those growers would be. We've had inbound contacts from large growing entities that want to come and locate here and -- which is great, because if we have advance notice then we can plan where best to place that new, quickly growing load. So we definitely haven't built into anything into our plan, but we are actively working with the growing community to make sure that we are prepared to serve.

Great. Then one just last one here in terms of the gas storage. So, obviously, you've asked customers to conserve usage during this cold snap. My question is, how were gas storage levels going into this week's polar vortex? And in the past, have there been instances where the reservoirs ran dry or close to it and how did that work mechanically?

Yes. No, we had ample supply. In fact, our storage fields were perfectly prepared and ready to serve even peak demand. It's early in the season. So certainly we have abundant supply. If a day like this happened in April, that would be a challenge to the system because our annual cycle is to draw off the field throughout the winter season. However, we had ample supply. The disruption at our Ray storage field was the equipment that is able to then deliver the stored gas to the system. And so that's where the bottleneck was yesterday and today, but it certainly wasn't lack of abundance of gas. We have some of the largest natural -- naturally occurring storage fields in the nation -- in the continent, right here in Michigan, and so we have ample supply. It was just a matter of getting it distributed effectively.

Great to hear. Stay warm. I see -- it feels like it's negative 32 in Jackson. So I guess, I can't complain about 5 degrees in New York.

Yes, we're definitely setting records in demand, there's no doubt about it.

Our next question will come from Shar Pourreza of Guggenheim Partners.

I apologize if this was covered. I, unfortunately, had to hop on a little bit late. Just in your sort of IRP discussions right now that you're going through, is there sort of any dialogue or any movement around potentially earning on the PPAs? I mean, I know, obviously, your interest would be to own, but is there still an option right now to earn on the PPAs?

Yes, and if you read the staff's filing, they did not object to the earnings mechanism, they just had a different formula, which yielded a much lower earnings mechanism on top of the PPA. But like all things, that is definitely open for negotiation. The staff also filed that we would be able to own 50% of the supply. So there's lots of room, I would suggest.

What I appreciate very much is that all of the stakeholders have been working together for the best integrated resource plan for Michigan. This is a long-term plan. It has long-term ramifications. Some of the current methods of people being able to, for example, purpose solar being added to the system at a uncompetitive price is not in the best interest of customers, even though we're fully supportive of additional solar being added to the system. So we think the integrated resource plan has created a great framework. Our willingness to offer up a market driven avoided cost calculation through competitive bidding creates the open platform for this earnings mechanism so that a developer who is leveraging our balance sheet, that the cost of that impact on our balance sheet is adequately reflected in their bid is, we think, a very constructive framework, and we like the direction of the conversations that have been happening here with all the critical stakeholders. So I would suggest that we're making good progress.

And then I just want to confirm, this is incremental to your plan, right? So when you think about your planning and assumptions and how you guide, this is something that would be incremental?

We would say yes, it would be incremental, but don't forget, we always are working towards that 6% to 8%, right? And so everything we do is in the -- for the purpose of solidifying our consistent, repeatable, reliable performance. And so all of these outcomes add up to a total picture that is predictable in total. And that's what we know you love about us, and that's what we really work toward every day.

Noted, noted. And just one last question, Patti, and it's a little bit -- little more of a minor question is just around not getting the tracker or at least potentially punting it. Did that impact at all as we think about your 10-year plan that we'll see very shortly? Did that impact the profile of the spend at all?

No. Because, again, we're pretty happy about the agreement and the settlement because it does create a framework for a long-term tracker, but we didn't plan on long-term trackers. We don't object to coming in annually and describing what our spend plan is and that in fact allows us to be more adaptive to changing conditions, and we're pretty satisfied with that arrangement. So we were very happy with the outcome of the settlement and not to say we wouldn't appreciate more formulaic ratemaking, but we're okay standing up to the scrutiny of an annual filing as well.

Ladies and gentlemen, this will conclude our question-and-answer session. At this time, I'd like to turn the conference back over to Patti Poppe for closing remarks.

Thanks, Allison. Thanks, everyone, for joining us this morning. And we're bundled up here in Michigan working to stay warm. We hope you are where you are. We look forward to seeing you on the road.

Thank you. And the conference is now concluded. We thank you for attending today's presentation. You may now disconnect.