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Duke Energy Corp
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Good day and welcome to the Duke Energy Fourth Quarter Earnings Call. Today’s conference is being recorded. At this time, I would like to turn the conference over to Mr. Mike Callahan, Vice President of Investor Relations. Please go ahead, sir.
Thank you, Kevin. Good morning everyone and thank you for joining Duke Energy’s fourth 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.
With that, I’ll turn the call over to Lynn.
Mike, thank you and good morning everyone. Before we share detail on our results, I wanted to take a moment to acknowledge that this is our first earnings call since the passing of Jim Rogers. Jim was a transformational leader who served with a boundless passion and helped shape the future of our Company and the energy industry. He will be deeply missed.
Now, as Jim would have wanted, let’s move on to our business agenda. Today we announced adjusted earnings per share of $4.72, closing out a successful 2018. We achieved results in the top half of our original 2018 guidance range while also delivering constructive regulatory outcomes and outstanding operational performance through hurricanes Florence and Michael.
We also announced our 2019 adjusted EPS guidance range of $4.80 to $5.20. The $5 midpoint of this range is consistent with our previous guidance for this upcoming year. This growth reflects the strength of our regulated utility franchises, a robust capital plan and recovery mechanisms that will deliver reliable and affordable energy to our customers and returns to our shareholders.
We are extending our 4% to 6% growth rate through 2023 off the midpoint of our 2019 guidance range. This update in our [base yea] reflects the near-term impact of delays in Atlantic Coast Pipeline, which I will discuss further in a moment. We remain confident in the strength of our core businesses and the ability to grow with investments that deliver value to our customers and our shareholders.
Our focus remains on execution and I’d like to begin by highlighting our success in 2018. Slide 4 reinforces our ability to deliver. 2018 marked another year of outstanding performance across the Company with strong financial results, constructive regulatory outcomes and operational excellence. In addition to meeting our earnings commitments, we continued to grow the dividend in 2018, increasing it more than 4%.
We also addressed the impact of tax reform. We achieved fair regulatory treatment across our jurisdictions providing benefits for customers while maintaining the utility’s credit quality. We also issued $2 billion in common equity to further support our balance sheet. We were very active in the regulatory space during 2018. We received constructive orders in our North Carolina rate cases including coal ash cost recovery and completed rate cases for our electric utilities in Ohio and Kentucky.
We also filed base rate cases in South Carolina. And as always, we remained focused on safety. We maintained our industry-leading safety performance for yet another year as well as operational excellence in the face of significant damage from Hurricanes Florence and Michael. Between the two storms, we restored 3 million outages and responded to flooding in many of our facilities due to historic rainfall. With our extensive preparation work and quick response efforts, we kept our infrastructure well protected.
And despite the safe shutdown of the Brunswick Power Station during Hurricane Florence, our nuclear team achieved a capacity factor above 90% for the 20th consecutive year.
This exceptional response was recognized by our industry as we were awarded EEI’s Emergency Recovery Award and I’m very proud of our employees resolve and tireless effort to restore power to the most devastated areas across the Carolinas and Florida.
Finally, last month, we were named to Fortune magazine’s 2019 list of the World’s Most Admired Companies for the second consecutive year, underscoring that we’re on the right path as we deliver value to customers and shareholders.
As we look ahead to 2019 and beyond, Slide 5, emphasizes the strength of the Duke Energy portfolio and the growth profile we have ahead of us. Our diverse highly regulated infrastructure investments are at the core of our robust capital plan. Over 90% of our growth capital will be spent over the next five years across our regulated electric and gas businesses driving strong earnings based growth. These investments are consistent with our strategic vision for our Company in this period of transformation.
Slide 6 depicts the strategic framework that we began sharing with you two years ago and since then we’ve made meaningful strides to modernize the grid, generate cleaner energy and expand natural gas infrastructure. We’ve engaged stakeholders to find solutions as the pace of change in our industry accelerates and we continue our work to modernize cost recovery mechanisms to better align with our investments. Our focus in these areas as well as maintaining our history of strong safety and operational performance enables us to transform the customer experience and deliver value to shareholders.
Let me share an update on the progress we’ve made executing our strategy. Moving to Slide 7, we continue to modernize our grid, which is the largest [P&D] system in the US with over 300,000 line miles across our service areas. We have outlined grid improvement plans in each of our jurisdictions to increase reliability, improve security, offer more options to customers and enable distributed generation.
From smart meters to self-healing grid technologies, we are establishing the foundation for a more intelligent delivery system that provides more information such as usage and outage alerts and minimizes power interruptions. More than 62% of our customers across all six states now have smart meters, keeping us on track to meet our goal of 100% installation by 2021.
We’re also making greater use of battery storage. We announced plans to invest $500 million in storage in the Carolinas over the next 15 years and we’ll maximize the versatility of this technology. Beyond storing and dispatching energy, we will include other system advantages such as supporting electric vehicles. We have an EV pilot program in Florida and our advancing programs in other jurisdictions.
For regulatory treatment of our grid costs, we have rider mechanisms in the Midwest and a multi-year rate plan in Florida, both efficient methods for recovering our investments. We are also making progress to modernize how we recover costs associated with these investments in the Carolinas. In South Carolina, the commission approved our deferral requests for certain grid investments. We have since filed rate cases for our DEC and DEP utilities. Our request includes multi-year rate plans to efficiently recover our grid improvement investments while providing rate certainty for customers.
In North Carolina, the DEC rate case order provided additional guidance. It stated the commission encourages ongoing grid investments and staying up-to-date on the latest technology, but they lack statutory authority to approve our requested grid rider. This feedback is useful as we continue our stakeholder engagement during the legislative session of the General Assembly currently under way. We are committed to advocating for reasonable solutions and we look forward to working collaboratively with stakeholders over the coming months. Our customers want a smarter energy future and our grid improvements will deliver just that.
Moving to Slide 8, let me share an update on how we’re reducing our environmental footprint. We have outlined plans to reduce our carbon emissions by 40% by 2030. This target is consistent with a pathway to achieving a 2-degree scenario and we are well on our way to meeting our goal. We’ve retired more than 6 gigawatts of coal generation since 2011 including to two Crystal River Units in Florida retired in December.
Over the next six years, we plan to retire another 1,200 megawatts of coal generation and replace it with lower carbon alternatives such as renewables and natural gas fire facilities. In 2018, we put both our W.S. Lee and Citrus County combined cycle plants into service and our Western Carolinas Modernization Project is on track for a late 2019 [in-service date]. These plants enable us to serve our Carolinas and Florida customers with cleaner, more efficient energy.
In addition, our 11 nuclear units are fundamental to providing carbon-free generation to our Carolinas customers and essential to our long-term carbon reduction goals. As we look forward, we are evaluating subsequent license renewal for these facilities for an additional 20 years to continue serving customers with the reliable service they expect.
And finally, we have a strong commitment to renewables and continue to invest in both our regulated and commercial renewables businesses. In Florida, we are building up to 700 megawatts of solar under our existing settlement agreement including our Hamilton plant that came online in late 2018. New rates were effective in January as approved under the Solar Base Rate Adjustment mechanism.
In North Carolina, we are actively participating in the ongoing RFP process for 680 megawatts of solar energy under House Bill 589. Our regulated and commercial renewables businesses submitted competitive bids and we expect to be notified of the results in March. Projects will be placed in service by January 2021. Beyond the opportunity in North Carolina, our commercial renewables business is seeing strong demand for utility scale wind and solar projects across the US and is well-positioned to capture a meaningful share.
We have visibility to a strong pipeline of future projects including over a 1,000 megawatts in late stages of development. This includes the recently announced 100 megawatt Lapetus solar project due to come online in the fourth quarter. The business successfully began using tax equity financing for new projects including our Shoreham Solar facility in New York that went into service last July. We will continue using tax equity to finance future projects.
We also continue to seek a minority partner for our existing wind and solar portfolio as we look to recycle and reinvest capital from our assets. We have received interest from a number of bidders and if we are able to reach an agreement, expect to announce the transaction this spring and close this summer. We expect to use proceeds to displace future debt issuance needs.
Moving to Slide 9, natural gas will play a major role in a cleaner energy future and we are leveraging the overlap between our electric and gas businesses to provide better service to our customers. Our LDCs have strong customer growth and with decoupling and other non-volumetric mechanisms in place, this growth translates into higher margins. The gas utilities also have solid capital investment opportunities consistent with our priority to deliver safe, reliable service, we continue to invest in integrity management.
Piedmont is also providing the infrastructure to deliver gas for our dual-fuel projects at the Belews Creek and Marshall coal-fired facilities, which are expected to be completed over the next three years. We will use coal firing of natural gas at these plants in a similar project recently completed at the Rogers facility to reduce our carbon emissions and increase our flexibility to manage costs.
Finally, we began construction this year on our $250 million Robeson LNG facility, which we expect to begin serving customers in 2021. These projects demonstrate the complementary nature of our franchises and advantages of joint planning to provide savings to customers.
Moving to Slide 10, let me update you on the status of the Atlantic Coast Pipeline. We remain committed to this project and the critically important benefits the pipeline brings to our region. Our Carolinas service territories are currently served by only one major interstate pipeline. ACP will bring needed diversity of supply by adding a second interstate pipeline with access to lower cost Marcellus and Utica gas. It will provide system pressure to Piedmont’s distribution network in the eastern part of North Carolina allowing for cost effective service to new customers. And ACP will provide important infrastructure in an underserved area, increasing economic development in this part of the state.
Over the last year, we have made significant progress working with state and federal agencies to complete permitting for the project. In 2018, we received major permits from the North Carolina and Virginia Departments of Environmental Quality. We also recently received the air permit for the Buckingham Compressor Station in Central Virginia. In the fourth quarter of 2018, there were a number of developments that impacted the project’s scheduling cost. These developments include rulings from the 4th Circuit Court of Appeals on the Biological Opinion and the permit to cross under the Appalachian Trail.
We are working diligently with our project partners to resolve these specific issues in the federal courts to resume construction as soon as possible. We expect a hearing at the 4th Circuit related to the Biological Opinion to take place in May. It is possible this issue could be resolved by the third quarter allowing construction to resume on Phase 1 of the pipeline route. Separately, the 4th Circuit vacated the US Forest Service permit for the pipeline to cross under the Appalachian Trail, stating the agency lacks jurisdiction to approve the crossing. We strongly disagree with the court’s decision on this matter, which is counter to decades of pipeline crossings beneath the trail.
ACP and the Department of Justice have requested an en banc review of this decision with the fall 15-member court. We expect to hear in the next few weeks if the court will hear our petition. In addition, various paths exist to address this issue including the judicial path already being pursued as well as legislative changes or federal administrative action. Given the current delays, we’ve adjusted estimates for project schedule and cost. Our overall timeline assumes we’re able to resume construction this fall and have the entire project in service in 2021.
We will pursue putting the pipeline in service in phases with the Phase 1 portion in service in late 2020. After successful conclusion of the Appalachian Trail matter including a potential appeal to the US Supreme Court, the Phase 2 portion will be completed the following year. Should resolution of the challenges currently before the court proceed more quickly, this timeline could advance. This new timeline also entails an increase in project costs, now estimated between $7 billion and $7.8 billion and as a reminder, Duke’s share of these costs is 47%. We will continue to provide updates throughout the balance of this year on this important project.
Before I turn it over to Steve, I want to close by recognizing the Duke team for another year of strong execution. We delivered on our 2018 commitment. We addressed challenges that came our way with two historic hurricanes and court actions on the Atlantic Coast Pipeline and we are clear on the growth and value we will deliver in the future. With a portfolio of well-positioned utilities supported by customer growth, a robust capital plan and constructive regulatory outcomes and a solid growing dividend, Duke Energy is positioned to deliver value to our customers and strong returns to our investors.
Now, let me turn the call over to Steve.
Thanks, Lynn and good morning everyone. 2018 was a solid year for the Company. As shown on Slide 11, our full year adjusted earnings per share of $4.72 was in the top half of our original 2018 guidance range and well within the narrowed range we provided in November. For the year, our electric utilities grew from higher pricing and rider revenues, including a partial year’s contribution from the North Carolina rate cases. In addition, load growth was very strong and we had positive results in O&M from our continued cost management efforts. Weather was favorable for the year, but was partially offset by higher storm costs from a very active hurricane season. Finally, our electric utilities saw higher depreciation and amortization on a growing asset base.
Our gas segment also contributed to year-over-year growth driven by Piedmont’s margin contribution and as Lynn mentioned, we closed on our first tax equity finance solar project this year, driving higher earnings in commercial renewables. As expected, a lower [tax yield] on holding company interest as a result of the Tax Act partially offset the growth at our operating segments.
Overall, we are pleased with the strong execution across the Company. Looking ahead, we’ve set our 2019 adjusted earnings per share guidance range at $4.80 to $5.20 per share with a $5 midpoint. This represents 6% growth over 2018 and is consistent with the guidance we previously provided, demonstrating our commitment to achieving our earnings objectives.
We’ve put together a strong plan for 2019. Earnings will be supported by our investment programs and associated recovery activities across our utilities as well as new projects in commercial renewables. In addition, we expect load growth, continued cost management efforts and ongoing AFUDC associated with the Atlantic Coast Pipeline to contribute to our results.
Turning to Slide 12, we’ve extended our long term earnings growth expectation of 4% to 6% per year through 2023. This is based off the midpoint of our 2019 EPS guidance range of $5 per share. Our growth over the next five years will be supported by a $37 billion growth capital plan, one of the largest in our industry. These investments will drive strong earnings base growth for our electric and gas businesses supporting our earnings growth objectives.
Approximately half of our capital plan is committed to our energy grid investments at the electric utilities including expansion of services to new customers and our ongoing efforts to strengthen the grid.
We will also continue to invest in our regulated nuclear units and transition our generation fleet to cleaner energy sources such as natural gas and renewables. We plan to continue renewables development in both our electric utilities and commercial business. In commercial, we have increased our capital investment to reflect the strong demand for projects in this business and we’ll continue to utilize tax equity financing on new development projects.
In our gas segment, our LDC investments will support new gas infrastructure such as the Robeson LNG project, new customer additions and integrity management. For our midstream business, ACP will continue to drive earnings growth. Our investments remain aligned with our vision to modernize the energy grid, generate cleaner energy and expand natural gas infrastructure. We will also strategically deploy capital, optimizing timing of our investments and minimizing regulatory lag.
Turning to Slide 13, let me highlight a few trends we’re seeing across the business that further support our earnings objectives. As noted on previous calls, our service territories are greatly benefiting from the population migration to the southeast. Customer growth in our jurisdictions remain strong and for the first time in six years, we saw an overall increase in usage per residential customer in our electric utilities. Within the commercial class, ongoing data center expansion and strength in hospitality and other services further supported growth. These factors drove retail electric load growth of 0.9% in 2018. We are encouraged by these results and we’ll monitor these trends moving forward. We continue to assume 0.5% annual retail load growth throughout the five-year financial plan.
We also remain focused on managing our cost structure. We have demonstrated strong capabilities in this area over the last five years, offsetting inflation and absorbing an increase from the Piedmont acquisition, to keep non-recoverable O&M costs flat. Moving forward, we will continue implementing digital solutions to streamline and automate processes including the use of new technology and data analytics to keep O&M flat over the next five years.
Our cost management and capital optimization strategy is underpinned by our ability to align spend with customer needs and the expected regulatory calendar in order to minimize lag and earn our allowed ROEs. As you can see on Slide 14, our utilities maintain healthy ROEs and we expect this to continue as we execute on our regulatory calendar and recover our investments. We have modern regulatory recovery mechanisms in place in many jurisdictions. In Florida, customers and investors benefit from the predictability of the multi-year rate plan, which went into effect January 1st and lasts through 2021.
In Ohio, the commission approved our global settlement in late December, providing clarity for our grid improvement program through 2025. As we look ahead, we expect significant rate case activity in 2019. We intend to file for updated rates at our Indiana, Piedmont Natural Gas, and DEP North Carolina utilities. We are also evaluating a rate case for DEC North Carolina.
In South Carolina, we expect to complete the pending base rate cases that we filed last November. Evidentiary hearings are set for March 21st and April 11th for DEC and DEP respectively. If approved by the commission, we requested rates effective June 1st for both cases.
As Lynn mentioned earlier, we have asked the commission to approve multi-year rate plans to support our investment programs. We look forward to working with relevant stakeholders to achieve constructive outcomes for our customers and investors.
Moving to Slide 15, let me walk you through our 2019 financing plan. We are committed to maintaining a strong balance sheet, which supports our credit ratings and ability to efficiently fund our [$50 billion] capital plan. Given a growing body of investment opportunities and hurricane-related financing needs as well as ACP delays, which particularly affect our 2020 outlook, we’ve modestly increased our expected equity financing by $150 million per year.
We expect to issue our annual equity amounts through a combination of our DRIP and ATM programs. Our planned equity issuances combined with our investment recovery strategy support our credit metrics over the planning horizon. Also, recall that our FFO-to-debt ratio is further supported by our refundable AMT credits, which we expect to receive between 2019 and 2022. We believe this financing plan prudently manages the balance sheet to support Duke Energy’s credit quality and maintain financial flexibility as we execute our long-term strategy.
Shifting to Slide 16, we understand the value of the dividend to our shareholders. 2019 marks the 93rd consecutive year of paying a quarterly cash dividend and we remain committed to continue growing the dividend in the future. We finished 2018 with a dividend payout ratio above [75%]. As we have said previously, our aspiration is to reduce that payout ratio over time, more in line with our peers, particularly given our robust capital plan.
Over the near-term, we will moderate our dividend growth to better position ourselves within a payout ratio range of 65% to 75%, trending to the midpoint of this range over the five-year period. We believe this additional flexibility positions the Company for sustainable dividend and earnings growth over the long-term, while maintaining the strength of our balance sheet.
Before we open it up for questions, let me turn to Slide 17. Our attractive dividend yield coupled with earnings growth from investments in our regulated utilities provide a compelling risk-adjusted return for shareholders. We have a history of operational excellence and an achievable financial plan making Duke Energy a solid long-term investment opportunity. We are positioned to deliver results for both customers and shareholders and are confident in the plan we have for 2019 and beyond.
With that, we’ll open the line for your questions.
Thank you. [Operator Instructions] We will now take our first question from Greg Gordon, Evercore ISI. Please go ahead sir.
Hello good morning.
Good morning, Greg.
A couple of questions. When -- looking at the earnings guidance, one, I noticed that there’s a significant increase in expected earnings contribution from the commercial renewables segment ‘19 over ‘18. So can you talk about how you’re driving that? Is that from taking in ITCs or is that just a big step up in expected investment in getting plants online. And then the second question as it relates to that is if I look at the overall expectation for what AFUDC earnings were going to be from ACP in [‘19 reported] low versus now, how much of a change was that, that you had to overcome?
Sure. Greg thanks. On commercial renewables, we have just seen a lot of market opportunity and as we look back at our history in this business, there are times as customers not only have an interest in renewables, but there is interest in pursuing the tax credits to a great extent. We’ve seen a bit of a cyclical nature to this and has had a good track record in pursuing and achieving wins with a number of these projects. So, you’re seeing the benefit of that in 2019. It includes both wind and solar projects and we have the majority of what is reflected in 2019 guidance already committed based upon work that the team has had under way in 2018.
So, I think about the portfolio of businesses that we operate, commercial is a part of them and when we have an opportunity to pursue growth, we do that and you’re seeing that in 2019. I think when you look at allowance for funds, one of the other things to keep in mind on allowance for funds trend is we did put a large capital project in service at the end of ‘18, that’s Citrus and so some of the trend line that you see between 2018 and 2019 is a result of that in-service date of that generating station.
I think in terms of Atlantic Coast Pipeline, there’s no question that even as early as four months ago, we were expecting more capital to be deployed in ‘19. You may remember when we talked in November, we were projecting an in-service in ‘19 for part of the project and the rest in 2020. So, we have a slowdown in that spending, that resulted from some of the court decisions in December and we have reflected that in our guidance. We continue to remain committed to the plan and we’ll work through this -- committed to the project, but I think we have some work to do around the core challenges in order to get construction going again.
Okay, just a follow-up on the first answer. So, the pace of activity is higher and that’s fantastic. Congrats on that, on the renewables segment, but is the earnings contribution partially driven by monetization of tax credits either ITCs or through tax equity and then is that what’s driving the big increase?
Sure. There’s certainly tax equity included in those results. Greg, you may recall that we’ve been talking about tax equity as we had more clarity from tax reform on what our own tax position was. We have been pursuing tax equity. We’ve closed our first project in July and have continued and plan to continue using that technique as we go forward. And so what you see in ‘19 is not only a combination -- not only investment tax credit related to solar, but there’s also wind in those numbers.
Okay. I’ve got more questions, but I’ll go to the back of the queue. Thanks, bye.
Thank you, Greg.
Thank you. We will take our next question from Michael Weinstein of Credit Suisse. Please go ahead.
Good morning, Michael.
Hey Mike.
Hi, Lynn. Good morning. Hey, just a follow-up on Greg’s question, so when you take in tax equity, you’re booking that as earnings, is that true?
Steve, you want to talk about tax equity.
Yes, the utilization of tax equity in the financing does guide you to certain accounting rules and on most of these renewable projects, whether it’s tax equity or not, a lot of the recognition of the earnings is driven by the tax benefits, which is in the early stages of the project. Tax equity doesn’t change any of that. The tax equity structures however do vary and how quickly income is recognized in solar and wind projects. So, it’s not all upfront necessarily, but most of these renewables projects certainly with tax equity and also without are going to have earnings recognition in the early years depending on PTCs or ITCs.
Got you. Is there -- can you quantify how much of the $230 million is from tax equity and tax credits? And then related question to that is the guidance going forward fpr 4% to 6% through 2023, is how much -- what happens to the commercial renewable segment during that period? Is this a contributor to that 4% to 6% or as tax credits perhaps fall off, is that a subtractor from it? And maybe you can fill us in on that.
Yes, Mike, I would respond to the first part of the questions by saying tax attributes are an important part of the net income for anyone who invests in renewables. So, you should think about it that way. And I think over the five-year period, we see commercial renewables, based on the pipeline that’s in front of us having a more meaningful impact in the early part of the plan and then I would think about over the longer-term, our approach being opportunistic. Again, if we see demand, we’ll pursue it, but we really look at this business as being complementary to the 4% to 6% growth that we’re driving in the utilities.
Another -- just one more question on earnings growth. Are you -- did you actually quantify how much of the AFUDC drop off in 2019 is impacting earnings?
All of the AFUDC. I’m not sure I understand the question. Michael, could you do that again?
What’s the cents per share impact of that?
It’s approximately $0.05 that we’re seeing from the lower spend pattern that we’re estimating...
This is Atlantic Coast Pipeline.
Atlantic Coast Pipeline. That’s correct. And a rule of thumb on Atlantic Coast Pipeline is that it provides about $0.05 of earnings -- AFUDC earnings per quarter, but we’re seeing the slower spend impact by about $0.05 and we’re working through that with our guidance the $5 we’ve accounted for that.
Also, you said that rate base growth is 6% going forward and you used to talk about 7% as a result of tax reform from the return of excess deferred taxes. Is that still a possibility -- is there is still -- is it just that the return of excess deferred tax is slower in the early years and that’s why you’re still at 6% or is 7% still possible?
Mike, I think there’s always upside potential on regulated investment. We just progressed our guidance a year forward and 6% we believe is a good planning assumption. We have -- we focus on the ‘19, ‘20, ‘21 most heavily and will continue to develop and originate investments into ‘21 or I’m sorry ‘22, ‘23, but I think 6% is a really solid plan and we do have upside potential.
And Mike, I think some of the math here comes into play. When you’ve got a starting year that does not have the effect of tax reform in it and then you’ve got a change such as we saw in the out years that can lead to a higher percent. It depends on what year you’re starting. If you’re starting with a year that has the impact of tax reform layering in throughout the period, that can affect the percent, but as Lynn said, our early years have very strong growth typically the out years, we develop as we move along and 6% is a good number for our rate base growth.
Thanks a lot for the update.
Thank you.
We will now take our next question from Jonathan Arnold of Deutsche Bank. Please go ahead sir.
Good morning guys.
Good morning.
Good morning.
Quick question just on -- I understand you’ve rebased the starting point for the 4% to 6% growth to $5, but you were saying before that you’ve expected to sort of dip below off of the original base and then kind of get sort of to the high-end at the end of the plan. It doesn’t seem to be what you’re saying now off the new base. So I just want to clarify whether we should still be thinking that or whether it’s more sort of middle of the range would be a core assumption from this new base?
Jonathan, we committed to delivering at the low-end of the range for ‘19 and we’ve done that by hitting the $5 and then we’ve set 4% to 6% off of $5, which is within that guidance range we had talked about previously, but certainly the midpoint has been affected by the near-term uncertainty around Atlantic Coast Pipeline, both the scheduled delay and the cost increase. And so as we look at 2019, if Atlantic Coast Pipeline goes quickly, we do still have the potential to get to the high-end of the range in ‘20, but we believe a planning assumption within that range is more realistic until we can work through these legal challenges.
So, we just thought it was appropriate given where we are with that project to reset the base, but I think it’s -- there’s a great deal of overlap between what we’ve given you here and where we were previously and we continue to believe strongly that we have a strong growth plan that we’ve put in front of you.
Okay and then just a quick housekeeping one. I noticed you had a fairly sizable write-off at the Citrus County in the fourth quarter. Why would that be?
We have -- we’re in the middle of a contractual -- finalizing a contractual dispute with Fluor. Jonathan, you may have seen some press coverage of this as they have been finalizing that project. We are in the middle of this and from an accounting standpoint, recognized exposure, but that isn’t the end of the story. We still have legal remedies that we’re pursuing that we would expect to resolve in 2019.
Okay. Thank you, Lynn and then just one other thing, it has been reported I think in the press and also exciting Duke spokesperson that you’re one of the bidders pursuing Santee Cooper. I just wonder if you could speak to that at all and specifically what your criteria would be and just remembering back to Piedmont, you’d talked about it being very unique and adjacent and therefore something that was very high priority for the Company, so I’m just curious if you have any comments.
Jonathan, throughout the process that South Carolina has undertaken, our objective has been to support the state and the state has called for and been actively seeking investment interests in Santee Cooper. We are one of the four parties that has met the qualifications. We have submitted a couple of proposals for the state to consider, but I would also say this is very early stage. There’s a law that needs to be passed, the General Assembly needs to make some decisions and that could take some time here in 2019. So, we remain committed to our organic growth plan and supporting the state of South Carolina as they look at alternatives.
Okay. I think I’ll leave it there. Thanks very much guys.
Thank you, Jonathan.
We will now take our next question from Shahriar Pourreza of Guggenheim Partners. Please go ahead.
Hey, good morning guys.
Hi Shar.
Hey Shar.
Most of my questions were answered, but Steve let me let me ask you, because you talked about sort of the drag from sort of the AFUDC and the pushing out of ACP. Does sort of your current outlook include refunds from the unprotected add it that could potentially have an effect of actually sort of raising the rate base? So I’m kind of curious, I mean we’ve -- obviously if you look at the guidance now and the rebasing, it looks somewhat a little bit lower than the sort of the prior guide, how is sort of the refunds of unprotected added, how does that sort of play into the growth picture?
Well, yes, Shar, we have worked with our regulatory commissions in the various states on the handling of income tax refunds related to the Tax Act and the excess deferred tax flow backs and that’s incorporated into our plan, it’ll vary per jurisdiction. Some states are giving it back over a 10-year period. Some states are offsetting it with other types of costs such as storm cost in Florida, but that’s being weaved through the plan and that does have the impact of raising rate base as well and we do have that as a growth item in our rate base that we’ve talked about in the past. So that’s in there.
Okay, so that’s in there. Okay and then Lynn I know you’re working through a legislation around sort of grid mod and how to sort of think about potentially getting a rider mechanism, but assuming legislation doesn’t sort of time the well the way you’re anticipating, you guys are going to be in for serial filings on an annual basis. So, how should we sort of think about the spending of that profile, assuming that you don’t get legislation, maybe the commission approves trackers, but if you don’t and you’re going to be in rate cases, do you see sort of -- any sort of downside to that grid mod spend?
Shar, I think the capital we’ve put in front of you is capital that we would spend under the rate case scenario as well. So, we have contemplated both scenarios in our long-term guidance. So I don’t see a lot of downside to grid spend as a result of what you’re describing.
Okay. Got it and just lastly on Santee Cooper, obviously the bids are confidential, but can you just maybe elaborate whether there would be an interest to do a management service agreement around that system versus an outright acquisition?
So, Shar, we have looked at both of those and have put proposals on the table that would accomplish both objectives.
Perfect. All right. Thanks guys.
Thank you so much.
Thank you.
We will now take our next question from Julien Dumoulin-Smith of Merrill Lynch. Please go ahead.
Hey, good morning everyone.
Good morning.
So just a few clarifications of some prior questions here. Just starting out on the commercial renewables spending plan, is that mostly contemplated to be solar just as we start to calibrate our models on future tax credits. Obviously ITC versus PTC and then also just given the differing accounting treatments, that’s a one year accounting on the ITC not five-year, right?
Let me catch up on that for a moment, Julien. There’s a mix of solar and wind in both ‘19 and ‘20. I would say a [little heavy] of solar in ‘19, but a mix of both in both years and under the accounting model that Steve was talking about before, you do have an opportunity for a range of recognition, two years to seven I think on solar and then PTC. So, Steve you want to add to that?
Well, that’s right. What Lynn referred to is correct. You can structure the solar deals with tax equity so that the income recognition can be spread over one year to seven years as an example and we’ll do what suits us and makes the most sense to us in that situation. The wind projects, the PTC recognition is typically over the seven year period.
Right, and just to go back to the question about what’s reflected in the outlook that maybe squaring the last question, the procurement that you talked about, I believe, North Carolina earlier up to 800 megawatts. Is that contemplated in the outlook that you’re disclosing now first. And then separately with respect to that also just curious is that all outside or within the utility, just with respect to where you’re allowed or intend to participate from?
So on HB -- HB589, I think Julien is your question for North Carolina. So, we have over the five-year period, put some additional capital in commercial renewables reflecting the potential impact of 589 and all of that capital is sitting in commercial renewables. So, you may, if you compare back to last year, you’ll see about [$1 billion] more, which is reflecting of not only market conditions, but also what we hope to pursue in North Carolina.
Thank you. And then one quick clarification here, the ACP range that you’ve delineated $7 billion to $7.8 billion. I think that’s slightly different than what Dominion talked about $7 billion to $7.5 billion, I know this will pick you, but just curious. Any slight changes or is this more about the configuration that you guys are thinking about?
Julien I appreciate that question because it’s right on top of what Dominion disclosed. They just talked about it in two phases. So $7 billion to $7.5 billion, assuming more timely resolution of the Appalachian Trail. If the Appalachian Trail goes to the Supreme Court, they said another couple of hundred million. All we did was put up the whole range together.
Understood. Thank you for the clarification.
Yes, right on top of Dominion.
Thanks.
Thank you.
We will now take our next question from Praful Mehta of Citibank. Please go ahead.
Thanks so much. Hi guys.
Good morning.
Hello.
Good morning. Hi. So maybe with all the earnings questions addressed mostly, maybe we touch on credit. As we look at Slide 15, firstly you talked about equity issuances going up a little bit through the plan. Is that driven by pressure from the agencies to kind of shore up the credit a little bit? Or can you just give us a little bit more color of what specifically was driving the increase in equity need?
So Praful, we are committed to our ratings, we’ve demonstrated that with our response to tax reform and as we look at the increase in cost in Atlantic Coast Pipeline that we’re projecting as well as the fact that we spent $1 billion this year on storm response. We thought it was appropriate to bring some additional equity into the plan in the form of the DRIP and ATM. This gives us some flexibility for uncertainty and we’ve also talked about the fact that we will consider pursuing securitization of the storm cost as well, which we think is positive for credit. So, all of this is within the context of maintaining the commitment to our balance sheet while also responding to impacts to the business.
Got you. That’s super helpful then. So in terms of the FFO-to-debt metric, then as I look at again Slide 15, the AMT credit I’m assuming is helping support the credit and the FFO-to-debt through the 2020 time frame, but it seems to be going up even though the AMT is rolling off by ‘22. So just wanted to understand like what’s driving the uptick in FFO-to-debt in that ‘21 to ‘23 time frame, even though AMT is in fact rolling off during that same period?
Sure, Steve you want to take that?
Sure. Praful, a couple of things are happening here. Number one, we’ve got the exploration or the conclusion of the heavy spend on coal-ash in the Carolinas that will end essentially in ‘19 and then that spend level will drop. So as you get coal-ash expenditures built into rates and the actual cash expenditures go down, that can certainly help cash flows.
In Florida, we’ve had in 2018, three generation projects: Citrus County, Osprey, Hines Chillers go into rates. So those will turn into cash annuities as well. In 2019, we will complete the Western Carolinas modernization project and get that into rates and that’s over a $1 billion of investment. So we’ve got a number of activities that are aligned there. Additionally, when Atlantic Coast Pipeline goes into service that’ll – [in 2021] in that time frame, when that’s completed, that’ll turn into a strong cash annuity. So, we’ve got some big projects rolling through rates that’ll help push up FFO.
Got you. Perfect. And then just finally just clarifying in 2020, the increase in Holdco debt, is that driven by the increase in commercial renewable investment that’s funded by parent debt or is there something else driving the 33% to 34% Holdco debt in 2020 time frame?
Well, I think you’ve got a couple of things going on here. You’ve got certainly the delay in ACP, so that puts some pressure there. We’ve got expansion of the commercial renewables as well. Those types of issues as we have lag on recovering hurricane cost of over $1 billion that can put some stress on holding company debt as well. So those are some things I’d point to.
Yes and Praful, I wouldn’t point to any single item. I think this is kind of just the financing of the whole picture including, the results of ‘18 and what we’re looking at for ‘19.
Understood. Again, thanks so much guys.
Thank you.
Thank you.
We will now take our next question from Michael Lapides of Goldman Sachs. Please go ahead.
Hey, guys thanks for taking my question. One or two just minor items when I think about the commercial renewable business. How do you think about what’s the right scale and size of this business, meaning relative to everything else. When you’re thinking longer-term and kind of what you want that business to look like relative to the core regulated subsidiaries?
Michael, I would say it’s complementary, but given the size of the regulated businesses we operate on electric and gas, it will always be a modest contributor. We’re talking about $200 million of net income. So we’ll continue to grow it opportunistically. We think it’s, there’s an incredible wave of support for renewables. We think it’s the growing part of the generation portfolio in the US, we want to be a part of it, but it will take a long time for it to have a meaningful percentage impact on the portfolio of the Company, given the size and the growth profile of what else we operate.
Got it, but when you think about the commercial renewable business and its growth rate that’s embedded in your multi-year four or five-year EPS growth rate guidance, do you assume that, that business like the gas utility and pipeline business grows at a faster rate than the core electric utilities? Does it grow more in line with the electrics or beneath that? I’m just trying to -- I’m trying to parse a little bit about what’s in the guidance levels?
Yes, so it grows faster in the short-term part of the plan, Michael, and levels off in the back part. By the time 2023 rolls around, we begin to enter a period where we have some wind projects reaching their PTC expiration. So, I would think about it as being a stronger contributor in the front end than the back end.
Got it and then last one just curious tax rate and guidance seems to be a little bit on the low side. Is that anything at the Utilities or is that all -- and I think someone touched that. Is that all just related to tax credits as you bring assets in the service on the commercial renewable side? And then should we assume that tax rate stays at that -- consolidated tax rate stays at that level through the whole guidance period or does it creep up over time?
Michael, the tax rate could change over time. We’ve lowered it because primarily to give back of EBIT. We’re starting to push those taxes back through to rates in our various jurisdictions and that’ll push the effective tax rate down. Now there’s an offset in revenues as you give these taxes back and lower rates, but it will change the effective tax rate.
Now the addition of renewables and the credits associated with that will also push it down, but a player in here is the excess deferred taxes that are being given back. So as we move through time, we’ll look at how that excess deferred are giving back whether that’s ratable or whether there’s fluctuations in that and those types of things plus the renewables cycling up or down, those things could push the effective tax rate around a bit.
Got it. Thank you, much appreciated.
Thank you, Michael.
We will now take our next question from Andrew Weisel of Scotia Howard Weil. Please go ahead, sir.
Good morning, Andrew.
Good morning.
Good morning.
My first question is on the outlook for CapEx and midstream. How much of that is more than just -- of [$2.9 billion] included. How much of that is more than just the main ACP. In other words, do you have expansions at ACP? Do you have other greenfield projects? What else is in that bucket please?
It’s primarily ACP, Andrew. We’ve actually dialed back in this five-year plan expansion capital until we have a better sense of in-service and completion of this project. We have a little bit of placeholder capital, maybe $250 million sitting out there in ‘22, ‘23, but I would think of it as primarily ACP.
Okay, how would you describe your appetite for more greenfield midstream construction going forward? If you saw another opportunity come along, how willing would you be to jump on it?
That’s a really good question, Andrew. You’re catching us mid-cycle here in Atlantic Coast Pipeline. We’re a believer in the infrastructure. I think one of the things that gets overlooked in this discussion of these pipelines is how critical they are to our customers and we think about our Piedmont system and the need to continue to provide pressure for growth in that area. We think about the infrastructure in North Carolina supporting economic development and our power system, which has a lot of renewables in the eastern part of the state. So, we’re a believer in the infrastructure investment. We’ve learned a lot about how to move through these, the stakeholder engagements, it’s important to permitting, et cetera. So we like the business I think, but we’d be thoughtful about what opportunities exist that we might want to pursue.
Got it. It makes sense and just a quick one on the dividend. Before I ask a question, could you repeat what was the targeted payout ratio you had for five years out?
So, we have indicated a range of 65% to 75%, Andrew, but we’d like to moderate our payout ratio. We’re above 75% today. By the end of the five-year period, we’d like to be closer to 70%, still committed to strong growth of the dividend. We think our yield is very attractive. We have a long standing history of growing the dividend, but believe that some moderation of the payout ratio positions the Company for more sustainable growth given our robust capital plan.
Okay, but just to clarify there, back of the envelope math to me suggests around a 3.5% CAGR. You previously guided to 4% to 6% just as recently as EEI. What would you say were the biggest deltas then as far as being a bit more conservative on the dividend growth?
I think this near-term uncertainty that we’ve experienced around Atlantic Coast Pipeline and/or where we’re looking at ‘20 and ‘21 is being influenced in that way. And then as we think about $1 billion of hurricanes that we’ve experienced, we also think about our desire to continue growing with a very robust capital plan. We believe all those things taken together represent a very attractive dividend plus growth profile for our investors and think that moderating the dividend payout ratio as part of that whole picture makes a lot of sense.
All right. Thank you for clarifying.
Thank you.
This concludes today’s question-and-answer session. I would like to hand the call over to Ms. Lynn Good for any additional or closing remarks.
Very good. Thank you, Kevin. Thank you all for participating today for your questions. Our IR team will be available both today, tomorrow and ongoing for any further questions. We appreciate your investment in Duke Energy. So, thanks so much.
Ladies and gentlemen, this concludes today’s conference call. Thank you for your participation, you may now disconnect.