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Good day, everyone, and welcome to the Duke Energy first quarter earnings call. Today's conference is being recorded.
At this time, I would like to turn the conference over to Mr. Mike Callahan, VP of Investor Relations. Please go ahead, sir.
Thank you, Alan. Good morning, everyone, and thank you for joining Duke Energy's first quarter 2018 earnings review and business update. Leading our call today is Lynn Good, Chairman, President and CEO, along with Steve Young, Executive Vice President and CFO.
Today's discussion will include forward-looking information and the use of non-GAAP financial measures. Slide 2 presents the Safe Harbor statement which accompanies our presentation materials. A reconciliation of non-GAAP financial measures can be found on duke-energy.com and in today's materials.
Please note, the appendix for today's presentation includes supplemental information and additional disclosures. As summarized on slide 3, during today's call, Lynn will briefly discuss our financial and operational highlights for the quarter. She will also provide an update on key regulatory activity and progress we've made advancing our strategic investment plan. Steve will provide an overview of our first quarter financial results and insight about economic and low growth trends. He will then provide an update on tax reform and our financing plan before closing with key investor considerations.
With that, let me turn the call over to Lynn.
Thank you, Mike, and good morning, everyone.
Today we announced adjusted earnings per share of $1.28, marking a strong start to 2018. It's clear our long-term strategy is delivering results. We made progress on our strategic investments and regulatory initiatives and continue to expand our electric and gas infrastructure businesses with solid customer and volume growth across our service areas. With these results, we remain on track to deliver our 2018 EPS guidance range of $4.55 to $4.85 per share and our long-term earnings growth CAGR of 4% to 6% through 2022.
In response to tax reform and consistent with the plans we shared with you in February, we successfully executed a $1.6 billion equity offering in March. We also remain on track for the additional steps that we outlined, reducing capital by $1 billion over the five-year plan and maintaining a sharp focus on operational cost efficiency. Overall, I'm confident we have the right approach to financing our investments. And S&P reaffirmed our credit ratings and stable outlook in March.
On this slide, we've also highlighted other notable accomplishments during the quarter that demonstrate the dedication of our employees and their focus on delivering affordable, safe, reliable, and increasingly clean energy. This was recognized by EEI [Edison Electric Institute], which ranked Duke Energy number one in safety in the industry for the third year in a row. And on May 1, Forbes honored our commitment to engaging, developing, and retaining our workforce, naming Duke Energy as a top employer.
Turning to slide 5, let me provide an update on our regulatory activities during the quarter. Last year we filed two rate cases, one for Duke Energy Progress and one for Duke Energy Carolinas. In late February, the North Carolina Utilities Commission issued an order in our DEP case, approving new rates associated with our $8.1 billion rate base, including our investments in four new solar projects and gas-fired generation at Sutton and Asheville. The decision approved a 9.9% ROE on a 52% equity component of the capital structure.
The order also clarified coal ash cost recovery. We received approval to amortize $234 million out of a requested $240 million in deferred costs over a five-year period and with a full debt and equity return. Ongoing coal ash costs will be deferred with a return and be considered in the next DEP rate case.
Hearings in DEC ended in March, and in late April we filed a post-hearing brief reiterating our positions in the case. We used the opportunity to introduce a modified proposal of a grid rider for the commission's consideration. We also addressed our views regarding tax reform. We proposed reducing customer rates, accounting for the lower federal income tax rate, and returning unprotected access deferred income taxes to customers over 5 to 20 years. The timeline is dependent upon the nature of the items that created the deferral. Finally, we requested to offset a portion of the revenue decrease with the amortization of regulatory assets, accelerated depreciation, or recovery of environmental expenditures.
We believe our proposals included in the post-hearing brief strike an appropriate balance of delivering value to customers while providing returns to investors and maintaining the strength of the utility's balance sheet. A decision is expected in late May or early June.
In Ohio, we filed a settlement agreement in April, which addresses both the electric distribution rate case and our pending ESP proceeding. It includes the extension of our distribution capital investment rider through 2025, giving us clear line of sight for recovery of our investments. The rider is subject to increasing revenue caps through 2025. In addition, the settlement establishes a new PowerForward rider to recover costs to enhance the customer experience and further transform the grid, including investments as a result of the Ohio Commission's own PowerForward initiative.
Also in April, we received a positive order from the Kentucky Public Service Commission in our electric base rate case. It established a new rider to recover environmental expenditures, including those related to coal ash.
We have made clear progress achieving constructive regulatory outcomes, including modernizing our regulatory constructs. We continue to demonstrate our ability to work with stakeholders to achieve balanced solutions that benefit customers and support our growth plan.
Moving to slide 6, I want to provide an update on our efforts to transform the way we generate energy. With three new natural gas plants either online or under construction, we're committed to reducing our carbon footprint and leveraging the overlap between our electric and gas businesses.
Our W.S. Lee plant, located in South Carolina, began serving customers on April 5, with our Piedmont subsidiary delivering gas using new infrastructure put in place for the project. In Florida, we expect Citrus County to begin operations soon, with Unit 1 online in the fall and unit 2 by the end of the year. This plant, totaling 1,600 megawatts, will allow us to retire two coal-fired units at Crystal River.
In April, we filed a request with the Florida Public Service Commission to recover our investment in Citrus County via the GBRA mechanism once the units are placed in service. Our filing included an increase to the revenue requirement of approximately $200 million per year. New rates are expected to be fully updated in the fourth quarter.
Our Western Carolinas modernization project is progressing and remains on track for an expected 2019 in-service date.
We're also investing in our Commercial Renewables business. We anticipate our 25-megawatt Shoreham solar facility to come online in the second quarter, one of the largest solar projects in New York. This is our first project in New York and expands our Commercial Renewables footprint to 14 states. We put tax equity financing in place for this project and will continue to use this funding source moving forward.
In addition to these clean energy projects, we recently issued two key reports, our annual Sustainability Report and our Climate Report. The Climate Report outline steps we're taking to mitigate risks from climate change and includes analysis of a 2-degree scenario. Importantly, our current plan to achieve a 40% carbon reduction by 2030 is consistent with the pathway to achieving this 2-degree scenario. This new report is another example of our longstanding commitment to the environment and our stakeholders.
Moving to slide 7, let me update you on our natural gas business. We made significant progress on the Atlantic Coast Pipeline in the first quarter, completing approximately 200 miles of tree-felling along the 600-mile route, or approximately 75% of the miles planned for 2018. The remaining miles will be addressed later this fall when the tree-felling window opens again.
In April, we received FERC approval to begin full construction on the Northampton Compressor Station in North Carolina. This marks the second of three compressor stations for which we have full construction approval, representing another meaningful step for the project.
We also requested approval from FERC to start full construction on the West Virginia portion of the pipeline, where tree-felling has been completed or was not required. While we await the final state permits in Virginia, these milestones keep the project on track for a fourth quarter 2019 in-service date.
Turning to Sabal Trail, the lateral line to our Citrus County natural gas plant is in service, allowing us to begin operational testing prior to bringing the plant online to serve customers. FERC reissued the certificate for Sabal Trail, reaffirming that the project will not result in a significant impact on the environment. Recently, the project partners successfully completed the permanent financing, raising approximately $1.5 billion to return capital to the project owners now that construction is complete. Duke's share of the proceeds is approximately $100 million.
Finally, one quick note on the recent FERC NOPR regarding tax reform, Duke Energy's midstream investments in ACP and Sabal Trial are over 90% contracted with negotiated rates and 20 to 25-year contracts. We believe the proposed rulemaking does not impact our projects.
As I turn it over to Steve, our results for this quarter show that the fundamentals of our business remain strong and we are well-positioned as we move ahead in 2018. Our industry continues to transform, requiring us to execute, anticipate, and adapt. That remains our focus, as we invest in infrastructure our customers' value and deliver sustainable growth for our investors. We're delivering on our strategy and I remain confident in our vision to be the leading energy infrastructure company.
So, Steve, let me turn it to you.
Thanks, Lynn.
Let's start with quarterly results. I will cover the highlights on slide 8 and discuss our adjusted earnings per share variances compared to the prior-year quarter. For more detailed information on segment variances versus last year and a reconciliation of reported results to adjusted results, please refer to the supporting materials that accompany today's press release and presentation.
On a reported or GAAP basis, 2018 first quarter earnings per share were $0.88 compared to $1.02 last year. First quarter 2018 adjusted earnings per share was $1.28 compared to $1.04 in the prior year. The most significant drivers of the difference between reported and adjusted earnings in the quarter were charges related to the sale of the retired Beckjord plant in Ohio; the recognition of a valuation allowance related to the Tax Act; charges related to the DEP rate order; and an impairment of Duke Energy's investment in the Constitution Pipeline.
Higher adjusted results in the quarter were principally due to weather, as well as growth in our electric and gas businesses. Within the segments, Electric Utilities and Infrastructure results were up $0.26 compared to the prior year. Weather was the primary driver with a $0.16 increase, as we returned to more normal weather in the first quarter compared to the warmer winter weather a year ago. We also had higher retail revenues from pricing and riders, primarily driven by three factors; generation base rate or GBRA increases in Florida that took effect last year related to our Hines and Osprey facilities; grid riders in the Midwest; and the recovery of qualifying facility power purchases through the fuel rider in North Carolina as a result of HB 589.
We also saw higher retail electric volumes in the quarter, which I'll discuss in more detail in a moment. O&M was favorable $0.04 in the quarter, but this favorability is expected to reverse in future quarters. Finally, the Electric segment benefited from lower income tax expense of $0.06, including impacts of the Tax Act. A portion of this benefit is related to tax levelization and is expected to reverse later this year, as excess deferred income taxes are reflected in customer rates. Higher depreciation and amortization expense partially offset the positive drivers, primarily due to growth in the asset base.
Shifting to our Gas Utilities and Infrastructure segment, results were up $0.03 for the quarter. The increase was largely driven by customer growth and increased investments at Piedmont, including higher rate base from integrity management investments and required infrastructure for our W.S. Lee plant. This is another example of the complementary nature of our electric and gas businesses.
In Commercial Renewables, we were down $0.01 for the quarter. This was driven by lower wind resources compared to last year.
Finally, Other was down $0.04 due to higher interest expense at the holding company and higher income tax expense, including a lower tax shield on HoldCo interest as a result of the Tax Act. The lower tax shield and other impacts on the new law across our business segments, including the timing of these impacts, are consistent with our full-year 2018 planning assumptions. Overall, we had a very solid start to the year and look forward to delivering on our plan in the coming quarters.
Turning to slide 9, let me walk you through our retail volume trends. On a rolling 12-month basis, weather-normalized retail electric load growth was 0.6%, consistent with our long-term planning assumption of 0.5%. The residential class exhibited particular strength, growing 1.9% on a rolling 12-month basis. Importantly, load grew faster than the number of customers this quarter, indicating usage growth per customer. We see this as a positive economic indicator and will continue to closely track customer usage trends. Population growth remains strong in our service territories, especially in Florida and North Carolina, which were ranked among the top five states for population gains in 2017.
We were also encouraged to see strength in the Cincinnati metro area, and Nashville remains one of the fastest growing cities in the country. As we look ahead, positive trends in employment and wages and continued strength in the housing market are expected to drive ongoing residential growth. Residential building permit activity remains high, especially in the single-family category.
In the commercial class, sales across our jurisdictions were slightly down over the rolling 12 months. We continue to see some weakness in large retailers as they compete with online offerings. Yet, strength in leisure and hospitality businesses have offset this to some degree. Small business confidence remains high, providing optimism for future growth in this sector.
Turning to industrials, on a rolling 12-month basis, the sector declined 0.5%. This decrease is primarily due to production declines at a couple of large customers in the middle of last year and recent outage activities. Industries that support sales to consumers, such as construction and housing, continue to perform well, which partially offsets the decline. On a macro level, positive economic growth is a tailwind, with leading economic indicators remaining high.
Overall, we remain confident in our long-term assumption of 0.5% retail load growth in our electric utilities and continue to be optimistic for the economic prospects within our service territories.
Shifting to slide 10, we are making progress in addressing tax reform across our jurisdictions. As we said in February, our approach is to target solutions that provide benefits to customers while smoothing customer rate volatility and supporting the credit quality of the utilities. In several of our jurisdictions, we have proposed using a portion of the lower tax expense to accelerate depreciation, recover environmental costs, or amortize regulatory assets. Our solution at Duke Energy Florida is a great example of this. Earlier this year, we received commission approval to use tax reform benefits to offset Hurricane Irma costs and accelerate the depreciation of older coal-fired generation units.
Elsewhere, revenues recovered via riders will be updated for the lower federal income tax rate as the rider filings are made in the ordinary course. The remaining portions of the tax law, including the treatment of excess deferred income taxes, are being addressed in separate tax reform dockets or in base rate case proceedings. In DEC North Carolina, we expect the commission to address tax reform in our pending rate case and look forward to the commission's decision in the coming weeks. For DEP North Carolina, we recommended addressing tax reform in the next rate case proceedings.
Our proposals and rate outcomes today on tax reform are consistent with the objectives we outlined on our fourth quarter call. We will continue to respond to our state regulators and other stakeholders in the coming months as these proceedings progress.
Next, let me take a moment on slide 11 to discuss the strength of our balance sheet. As Lynn mentioned, in early March we successfully executed a $1.6 billion equity offering, which included a full exercise of the overallotment option by the underwriters. We also issued $50 million of equity via the DRIP in the first quarter. We will issue the remaining $350 million for 2018 using both the DRIP and our ATM program. Recall that beyond 2018, we intend to continue issuing $350 million of equity per year for the remainder of the five-year plan.
We remain on track to achieve our FFO-to-debt target by 2020. In addition to the equity issuances, our cash flow profile and credit quality are further supported by our regulatory modernization efforts and an active regulatory calendar. This cash flow support includes recovery of deferred coal ash costs, which we are now recovering from our DEP North Carolina and South Carolina retail customers as well as our wholesale customers.
I would also like to remind folks of the material cash flow benefit related to our $1.1 billion of AMT credits that are now refundable under the Tax Act. Beginning in 2019, the value of these credits will be refunded to the company regardless of whether or not we have taxable income. The legislation front-loads the refund schedule, with 50% of the unused credits refundable each year. This has a significant positive effect on our funds from operations over the refund period.
We've also included in our appendix more information on the FFO-to-debt metric, including the implications of coal ash spend, Crystal River 3 securitization, and the effects of purchase accounting. We share these adjustments and the logic behind them with the rating agencies on a regular basis. S&P took a constructive view of the credit quality of the company in March, affirming Duke Energy's current ratings and keeping the company on a stable outlook. In its report, the agency noted two items as credit positive, the commission's approval of coal ash recovery in the DEP rate case order and our commitment to issue equity, including $2 billion of equity in 2018.
Going forward, the agencies will look for continued constructive regulatory outcomes and execution of our long-term plan. We believe a strong balance sheet is necessary to invest on behalf of our customers and investors, and we have taken an important steps to support our credit quality. We remain confident in our equity financing plan. It is sufficient to support the strength of the balance sheet and our growth investments, and we do not expect to issue additional equity over the remaining $350 million per year in the five-year plan.
Before I close, I want to take a moment to remind you of our long-term earnings growth guidance, as shown on slide 12. Our long-term earnings growth CAGR of 4% to 6% through 2022 is based off of $4.60 per share in 2017, the midpoint of our original 2017 guidance. While the midpoint of this year's guidance range is below this growth rate, we expect to be back to the low end of the 4% to 6% CAGR by next year. As our higher rate base growth and regulatory recovery accumulates, we expect to be at the mid to high end of the range in 2020 and beyond.
I'll close with our investor value proposition on slide 13. We continue to offer an attractive 8% to 10% shareholder return that balances the 4% to 6% earnings growth with a strong and growing dividend. Our growth is driven by low-risk regulated investments that are supported by our strong balance sheet. Our attractive yield and demonstrated ability to reliably grow our regulated businesses position Duke Energy as the leading infrastructure investment.
With that, let's open the line for your questions.
We'll first go to Jonathan Arnold with Deutsche Bank.
Good morning, guys.
Good morning.
Good morning, Jonathan.
Steve, you may have given more on this than I picked up in the remarks, so I apologize if that's the case. But I was just wondering if you could give us a little more color into the benefits of tax reform that are retained in the Utilities and Infrastructure segment this quarter, perhaps quantify how much that was, how it's arising, and then to what extent you expect it to be an incremental benefit during the rest of the year.
What we saw in the quarter looking AVA [Average Value Analysis], we saw $0.06 favorability related to income taxes. A couple of things are going on there. I mentioned the accounting levelization rules require smoothing of tax benefits over the year, and that accounts for $0.02 or $0.03 of that favorability. We also utilized some tax optimization efforts that helped provide some benefits in income tax as well. But there is the levelization that will turn around to the extent I described.
And, Jonathan, maybe just to add to that, the overall guidance that we provided in February for the impact of tax reform, we are on track for that. What you're seeing is just some quarter-to-quarter levelization resulting from the application of GAAP, but we are on track with the guidance we gave you in February.
Okay, so that incorporates some earnings pickup from the fact that the riders won't be implemented till they get implemented and the DEP happening in the next case. Am I my understanding that right?
The cash flow implications of retaining those benefits would be reflected in the results. We are deferring in every jurisdiction, I believe, Steve, tax benefits. So you can think about it as cash flow financing benefit, Jonathan.
Okay, so what you're calling out as an earnings driver is purely the timing. It's not the cash benefit.
That's right. What is an earnings driver here is the levelization primarily that Lynn described. There have been some tax optimization efforts that are in the results. That's separate from the Tax Act issue.
Okay, thank you for that. And just one other topic, can you give us an update of how you feel about your goals that you've laid out in Commercial Renewables and just the state of the market competitive-wise there?
Jonathan, we're on track in 2018 in the Commercial Renewables segment. The variance that you see in the quarter is more weather-related, but the backlog of projects and what we expect to close in 2018 remains on track. As you know, it's a competitive market, and we expect it to continue to be.
Okay, thank you very much.
Thank you.
Thank you.
All right. Next we'll go to Michael Weinstein with Credit Suisse.
Good morning.
Quick question, the 15% to 16% FFO-to-debt target for 2020 to 2022 and 14% for 2018, how much would that be impacted if – how much of that is dependent on the outcome of the DEP case? How could it change positive or negative as a result of the outcome?
Well, I think the DEP case was very constructive. I think it's overall in line with our expectations as a whole...
I'm sorry, but the DEC case.
Okay. We've modeled a number of scenario outcomes. The DEC case we'll learn about in a few weeks, but I think we have a number of levers to pull to still meet our credit metrics over our plan.
Michael, if you look at the DEP case, a very constructive outcome addressing all of the capital, substantially all of the deferred coal ash. We believe we put on a very strong case for DEC, and we'll know more on the specifics late May or June, but I think the precedent established in the DEP case is how you should think about DEC.
And then tax reform would be the addition to DEC that I would point to, and we were specific in our recommendations around tax reform in our post-hearing brief that we filed at the end of April. Our intent has always been that customers should see the benefit of the reduction in rates from 35% to 21%, and we have proposed an amortization period for the unprotected, which we think strikes a good balance.
So as Steve said, we always model a variety of scenarios on these things, but feel like we're on track to deliver those metrics, and we're certainly committed to do that. And if at any point there's a timing or shortfall, we do have levers, as Steve indicated, to make sure we remain on track.
Just to follow up on that, the real question is, the current equity issuance of $2 billion target for this year, does that incorporate even your worst-case scenarios for the outcome of the case, or is there a possibility there might be more?
Yes, it does.
Okay, thank you.
Michael, I think the thing I would think about on tax reform, which is really probably the most significant open item because we don't yet have commission approval, it comes down to the treatment of the unprotected deferred taxes. And so we're not talking about a wide degree of variability for a company of our size. And we're talking about amortization periods ranging from 5 years to 20 years that we proposed. So I think it's important to bound that uncertainty exposure as you think about our confidence.
Got you, but you've bounded – possible outcomes on the unprotected tax refunds are built into that equity issuance plan, right?
Absolutely.
Okay, good. Thank you.
And next we'll go to Steve Fleishman with Wolfe Research.
Good morning, Steve.
Hey, good morning. Good morning, Lynn.
Good morning.
So just first, do you have any sense from Moody's on when they might revisit the negative outlook given the equity issuance you did and the like?
Steve, we can't project with certainty what Moody's timing is. The one thing I would point to though is that their report earlier this year and your outlook action was really centered around tax reform. So I would expect as we move through the resolution of the DEC case, you'll get a clear picture of North Carolina. We already have Florida dialed in. Kentucky is visible, and we have dockets open in both Ohio and Indiana. So I feel like more information is going to become available over the next several months around tax reform in our larger jurisdictions, and we'll certainly be anxious to share all of that with Moody's.
Okay, great. And then the $1.1 billion of refundable AMT credits, so in 2019 and 2020, are you just essentially getting tax money, essentially refunds from the government on taxes?
Yes, that's correct.
That's correct.
Overall, because you also have your NOL and other...
We're getting that as cash.
Okay. And then just technically the $1.1 billion, that's a direct number. That's not like a – do we tax effect that, or is that a direct?
That's a direct number. That's (32:01).
Direct cash, okay. Okay, thank you.
Thank you, Steve.
All right.
And next we'll go to Julien Dumoulin-Smith with Bank of America Merrill Lynch.
Hey, good morning.
Good morning.
Good morning.
Hey. So I wanted to follow up on a couple of things. First, if we can go to the modernization side of the equation, starting with Ohio, PowerForward, obviously that's success on that front. Does that change your CapEx at all? Obviously, it wouldn't be too meaningful. And then secondly, related to that, can you talk on the outcome of the latest rate cases in the Carolinas and to what extent that might shift things?
So we're pleased with the result of the settlement in Ohio, Julien, but we need to get through a commission process. So there are hearings in July, but feel good about the settlement we were able to bring to the table. I think the PowerForward part of that rider will include projects that will impact customer experience, so our replacement of customer systems will be included in there. But we'd also expect the Ohio Commission, as they continue their work on their initiatives, to perhaps identify some things that we could invest in. Those would be incremental to our plan. So overall, I would look at the result – the settlement in Ohio as being consistent with our plan with modest upside.
And in the Carolinas, I think we talked a number of times about grid investment being a priority in the Carolinas. We'll be watching closely the results of the DEC case and then determining our strategy for legislation in 2019 and beyond to see if there's additional legislative certainty that we need to provide in order to set a pathway for further investment in the Carolinas. So that's what I would share with you about modernization in the Carolinas.
Excellent. And then turning back to the overall guidance, not to wordsmith things too much, but I just wanted to understand what you're saying about 2019 guidance. Last time, I think you guys talked about being "within the guidance range by 2019." And I think this go around, you talk about being back to the lower end of the 4% to 6%. Is that something to do with the timing of the equity and within the plan, or am I just being too nitpicky here?
Julien, the message has been the same. If you go back and reference where we were in February, it has always been low end of the range in 2019 and then mid-to-high in 2020 and beyond as we see the rate base growth and the investment and so on. So no change in message, but we'll be at the low end of the range in 2019.
Excellent. Sorry, just quick nitpicky thing on the tax side real quickly. Obviously Ohio, that issue I think got pushed out from the settlement conversations. What's the latest expectation on resolving that?
There's a docket in Ohio. I'd expect it to move through a process in 2018, Julien, but I don't have anything more specific than that.
Excellent, thank you all very much, best of luck.
Thank you.
All right, next we'll go to Ali Agha with SunTrust.
Thank you, good morning.
Good morning.
Good morning.
Good morning. First, Steve, I wanted to just make sure I had heard something earlier when you talked about first quarter and some timing-related issues. One was tax levelization, as you clarified. If I heard you right as well, I think you mentioned there was about a $0.04 pickup in O&M, also timing related that would reverse over the course of the year. Did I hear that right?
Yes, that's correct.
Okay.
We've seen some favorable O&M in the first quarter, but some of that was related to timing of purchases and so forth, so that may turn around.
Okay, got it. And then secondly, when I look at the rate base data that you've given us through 2022, at least just looking at that data, it appears that the growth in rate base actually slows down 2020 and beyond. So I'm just wondering how to reconcile that with the point that earnings growth should actually accelerate 2020 and beyond. So how do we reconcile those two things?
Ali, I would first think about 2020 as being the completion of a number of important projects that we'll begin to see impact and then fuller impact. So ACP, Western Carolina, the step-in in Florida, the riders in Ohio and Indiana, environmental spend in Indiana. And then as you get further out in the period, we will continue to drive investment in our strategic priority areas of grid, clean energy, gas, and renewables. And those plans will be more fine-tuned as time progresses. What we've given you is ranges and expectations, but we will fine-tune the numbers in 2021 and 2022 as we get closer.
Got it. And last question, Lynn, remind us also. When is the next big rate case cycle that we should think about once you're done with the North Carolina cases now over this planning period?
So as I think about jurisdictions, we're set in Florida if the settlement is improved. Ohio is in good shape. We just finished a case in Kentucky. We have a number of trackers in Indiana. We continue to think about is it time to come in for a full case, so that's something that will be under evaluation.
And then the Carolinas, we'll be anxious to see the results of the DEC case, and that will inform our timing. But as we've talked about a number of times, we believe the investment profile in the Carolinas matched with great value and benefits to customers is a good one. We're looking for ways we can modernize the construct. And in the interim, we'll be filing cases to deliver returns to investors and match those benefits to customers. So we'll have more specifics though on the timing after we digest the DEC case.
Got it, thank you.
Thank you.
Now we'll go to Michael Lapides with Goldman Sachs.
Hey, guys. Thank you for...
Hello.
Hey, Lynn. Thank you guys for taking my call – my question. I actually have a couple. The first one is can you quantify under tax reform and the tax law changes at a companywide level for your regulated operating companies? And I'm just looking for the total company level, not by subsidiary. What is the excess or unprotected add/fit (38:43), that balance? What do you estimate that to be, that likely over multiple, multiple years will likely get refunded back to customers?
We've got about $6.3 billion of excess deferreds on our books, Michael, total company. And of that, about $4.5 billion is protected, and unprotected is about $1.8 billion.
So the $4.5 billion should qualify under normalization like we saw after the 1986 Tax Act and go back to customers over a long life period, and the other staff, it's more negotiable?
That's correct.
Okay, thank you. The other thing, and this is more of a regulatory or rate-making question. When you look at your capital spend forecast over the next couple years, how much of that – is there a rule of thumb of how much of that capital spend is covered via trackers or riders versus covered via traditional historical looking rate case processes?
It will vary per jurisdiction, Michael. Certainly, we have a number of trackers in the Midwest that cover a lot of the capital there. We got the multiyear rate planning in Florida that provides us very efficient recovery. The Carolinas, the larger jurisdiction which has a lot of the CapEx, has fewer trackers at this point in time. So it's hard to give a rule of thumb there for the enterprise as a whole.
Got you.
Michael, in the Carolinas, as you know, modernizing has been a priority. So if you think about HB 589, we now do have tracking mechanisms in the Carolinas around renewables, and we've put in front of the commission grid tracking. So our objective over the five-year period is to make progress in the Carolinas. But I think if you look at the Midwest and Florida, substantial, over 50%, 60%, 70% perhaps are covered by trackers in those jurisdictions.
Got it, thank you, Lynn. And thank you, Steve, much appreciated.
Sure.
Thank you.
And next we'll go to Praful Mehta with Citi.
Thanks very much. Hi, guys.
Good morning.
Hello.
So, Steve, just to clarify – and by the way, slide 23 is very helpful in terms of the deferred taxes. But just to clarify, on that $1.8 billion of unprotected, what amount do we have clarity right now of the five years, and what amount is uncertain in terms of the timing of the refund? And the reason for the question, just to give you the context, is I was just trying to figure out where in that FFO-to-debt range can your metrics vary depending on the outcome of the deferred income taxes.
Sure. Of the $1.8 billion of unprotected excess deferreds, about $1.1 billion is at DEC and about $300 million is at Duke Energy Progress, so the bulk of it is in the Carolinas. The remaining portions are in Indiana and Florida. So the big piece of that is in the Carolinas.
And I think, Praful, as you think about this DEC case, we'll get some visibility into the unprotected for DEC within the next couple months. And we've put forward a proposal of amortization between 5 and 20 years, tying that amortization period to the asset class, the nature of the items that resulted in the deferred taxes. And as I've said a moment ago, we'll learn more from the commission as we see the results in the DEC rate case.
Got you, fair enough. That makes sense. But just so if there is pushback or a request for faster refunds than what you have currently assumed, I guess, in your metrics, your FFO-to-debt metrics, does that put pressure on credit at all, or do you think most scenarios that you can get back in terms of the rate case or the settlement are kind of incorporated within your current plan?
Praful, we're confident on this. If you think about $1.1 billion over a 5 year or 10-year period and the scale of the company, the amount of capital we spend, the regulatory activity that we have to generate cash flow, we feel like we have scenarios and levers that we can exercise and manage variability. So I'd leave it at that. Steve?
Right, I would echo that as well. We have efforts under capital optimization looking at our O&M spend that can help offset this, just a number of levers to pull.
Got you, fair enough. That's helpful. And then secondly on tax equity, I saw that with one of your solar projects, you're looking at tax equity financing, and you mentioned this will be a bigger part going forward. It sounds like it makes sense given your cash tax profile. How attractive is the tax equity market right now? How big a player do you look to be in that tax equity? I'm assuming that is a part of your FFO-to-debt strategy as well to improve metrics. So just a little bit of color around that would be helpful.
Sure, the tax equity market is still very viable. It is in fact being used at our Shoreham facility, our solar farm in New York, and we'll continue to utilize that. As you mentioned, our tax position puts us as a candidate for that. And I think the markets there, it is an important part of our Commercial Renewables profile. So we'll utilize that as we go forward.
Praful, the capital that we laid out with you in February is still a good planning assumption for Commercial Renewables. We just look at tax equity as a tool we'll use to put that capital to work.
Got you, fair enough. Thanks so much, guys, I appreciate it.
Thank you.
Sure.
Next we'll go to Shar Pourreza with Guggenheim Partners.
Hey, good morning, guys. My question is...
Hi, Shar.
Hi. Lynn, my questions were just answered. Thanks so much.
All right, thank you.
All right.
Bye, guys.
Okay. We'll go to Paul Ridzon with KeyBanc.
Good morning.
Good morning, Paul.
Good morning.
At renewables, you were down $0.01, which you attributed to wind resource. Was that a net number? In other words, did you have growth from incremental projects more than offset by more than $0.01 of core wind resource?
Yes, that's a net number.
Assuming wind resource had been flat, what would the segment have done?
I'd have to look at that a little bit further, Paul. But the results were down $0.01, and that's primarily due to wind resource and there's some additional resources, but it's not significant.
Okay, thank you. And then back to Steve's question, the $1.1 billion of AMTs, so what net number will you be receiving from the IRS next year? Do you expect the full $550 million?
Yes, in the range of that amount, 50% of the $1.1 billion, we'll get that next year.
And that's net of what you'll be paying the IRS. In other words, you'll be not a cash taxpayer?
That's the amount from the AMT, and we're not a cash taxpayer on any other front. And the AMT...
Thank you very much.
...is not tied to taxable income in any way. It's just an amount you get regardless of where you're at on your tax return.
Thank you.
Thank you.
And we'll take our last question from Christopher Turnure with JPMorgan.
Good morning, Lynn and Steve.
Hi, Chris.
I appreciate the extra detail on Atlantic Coast. That was very helpful. Thank you for that, just a couple clarifications. Could you maybe give us a little bit more on how you're feeling in North Carolina about the grid mod rider? Staff didn't like it but did admit that they would prefer that it has a cost cap and some other conditions if they did approve it. So how are you feeling there, and how much does the tax benefits to the customers in general kind of weigh in on commission and intervener thinking there?
So on the grid investment, Chris, I think what we saw in the hearing is just a continuation of a good discussion about the nature of the investments, the benefits they can deliver, the impact on customer bills. And so as we put together our post-hearing brief, we really addressed a number of the issues that were expressed during the hearing process and put in front of the commission what I would call kind of a step-in for the rider, a three-year proposal with a cap that was responsive to the feedback that we received.
So I would think about this as being a continuation of our strategy to keep the conversation going about the grid. I actually think there's a very little disagreement about the need for the investment. I think the benefits to customers are clear, and we are trying to find the right way to put that investment in place for the benefit of customers in a way that makes sense to the commission, public staff, et cetera.
I think tax reform represents a great opportunity because you have an opportunity to reduce impact to customers, at the same time you're driving investment. So I think they're complementary in that regard. And so we look forward to continuing the dialogue. And as we've shared previously, we have thought about the grid investment and modernization as being dual-track. Focusing on the regulatory process certainly, but also having legislation is something that we would also consider as we continue our work to modernize regulation.
Okay, that's helpful. I think we'll have to wait and see there. And then just two tax clarification questions, when do you expect to become a cash taxpayer again? And I guess that question would exclude any noise from the AMT credit you're getting the next two years.
And then the second question is just on the South Carolina approval from the commission on tax reform there. Do you pay a return to customers on the deferred balance?
On the first question, we do not expect to be a cash taxpayer in our five-year plan, so it's after 2022 when that happens. And help me on your second question again on South Carolina.
So you guys just got the okay a couple weeks back to defer taxes and not have it addressed by the commission until your next rate case filings there.
Yes.
In the interim, do you pay a return on that deferred tax liability owed to customers?
No, we're just deferring those costs at this point.
Okay.
Then the commission will determine how to deal with that at that time of the proceeding. We're just deferring those benefits right now.
Okay, that's good to hear. Thank you, guys.
All right, thanks, Chris.
And it looks like we have no further questions at this time, so I'd like to turn it back over to Ms. Lynn Good, for any closing remarks.
We want to thank everyone for participating, good questions today. We look forward to connecting with you over the next several weeks. And I appreciate your investment and interest in Duke Energy.
That does conclude today's conference. We thank everyone again, for their participation.