Good morning, ladies and gentlemen, welcome to the Emera Q4 2017 earnings conference call and webcast. After the presentation, we will conduct a question and answer session. Instructions will be provided at that time. Please note that this call is being recorded today, February 12, 2018, at 11:00 A.M. Atlantic time. I would now like to turn the meeting over to your host for today's call, Ken McOnie, Vice President, Investor Relations and Treasurer for Emera. Please go ahead, Mr. McOnie.
Thank you, Krista, thank you all for joining us this morning for Emera's fourth quarter 2017 conference call. Emera's fourth-quarter earnings release was distributed Friday afternoon by a newswire, the financial statements and management's discussion and analysis are available on our website at emera.com. Speaking on the call today from Emera is Scott Balfour, Emera's Chief Operating Officer, Greg Blunden, Chief Financial Officer. Chris Huskilson, President and Chief Executive Officer, and other members of the management team at Emera will respond to questions. This morning, Scott will discuss the results from operations and our strategic initiatives, Greg will provide an overview of the financial results. We expect the presentation segment to last about 15 minutes, after which we will be happy to take questions from analysts.
I will take this moment to advise you that this conference call will contain forward-looking information and statements with respect to Emera. Forward-looking statements involve significant risks, uncertainties and assumptions. I'm dealing with a cold. My apologies. Certain material factors or assumptions have been applied in drawing the conclusions contained in the forward-looking statements. Generally, these factors or assumptions are subject to inherent risks and uncertainties surrounding future expectations. Such risk factors or assumptions include, but are not limited to regulation, energy prices, general economic conditions, weather, derivatives and hedging, capital resources, loss of service area, licenses and permits, environment, insurance, labor relations, human resources and liquidity risk. A number of factors could cause actual results, performance or achievements to differ materially from the results discussed or implied in the forward-looking statements. Now I will turn things over to Scott.
Thank you, Ken, good morning, everyone. This morning I'll be discussing our operations for the quarter and year-to-date, along with an update on our strategic initiatives. Greg will follow with a financial update, Chris will join us in responding to your questions. Before speaking to our results, I'd like to highlight a few developments during the quarter. On December 12, 2017, the Maritime Link successfully exchanged power between Nova Scotia and Newfoundland for the first time in history. On January 15, 2018, the Maritime Link officially entered into commercial operation. This transformative interconnection will significantly improve the way that energy is transmitted in Atlantic Canada. The project was completed on time and under its CAD 1.577 billion budget.
The revenue requirements for this project have been included in Nova Scotia rates since the beginning of 2017 as part of a three-year rate stability program in place in Nova Scotia. The Maritime Link is a key piece of Emera's strategy to address the growing demand for more renewable energy in the region. Turning to our fourth quarter results, we delivered adjusted net income of CAD 137 million and earnings per share of CAD 0.64, compared with CAD 104 million and CAD 0.51 per share in the fourth quarter of 2016. These stronger results were largely due to cold weather conditions in the Northeast and strong contributions from Emera Florida. For the 2017 full-year period, adjusted net income and earnings per share were CAD 524 million and CAD 2.46 respectively. Adjusted net income for 2016 was CAD 475 million, with earnings per share of CAD 2.77. However, 2016 results included one-time gains and TECO acquisition costs.
Excluding these items, our 2016 adjusted earnings were CAD 409 million or CAD 2.39 per share. Excluding the one-time impact in 2016, we saw a 28% increase in year-over-year adjusted earnings due to the full-year contributions from Emera Florida and New Mexico and increased contributions from our equity investments in the Maritime Link and Labrador Island Link, offset by lower earnings in Emera Energy and the Caribbean. Adjusted earnings per share when compared to 2016 adjusted earnings excluding one-time items increased by 3%. Growth in earnings per share was impacted by the new shares issued in August of 2016 in conjunction with the TECO acquisition, as well as by the two equity issuances in December of 2016 and 2017. Overall, the company performed very well this year. Our Florida and New Mexico operations contributed CAD 382 million for the year-to-date period. We're particularly happy with the performance of the Florida businesses.
For customer growth and load growth from the state's vibrant economy, coupled with reduced O&M, led to a $30 million U.S. dollars or 10% increase in earnings at $316 million U.S. dollars in 2017, the highest in its history. We expect these factors to contribute to similar growth in 2018. Our legacy utilities, Nova Scotia Power, Emera Maine, and Emera Caribbean, performed in line with our expectations in 2017, contributing CAD 206 million of earnings. Nova Scotia Power and Emera Maine were consistent contributors on a year-over-year basis, while earnings from our Caribbean utilities were lower in 2017 as the islands of Dominica and Grand Bahama continue to recover from hurricanes Maria and Matthew. After weaker than expected market conditions in New England for most of the year, Emera Energy's marketing and trading business benefited from the cold weather in the Northeast at the very end of the year.
Higher capacity payments came into effect in June and will continue to benefit the company into 2018. On December 22, 2017, the U.S. Tax Cuts and Jobs Act of 2017, commonly referred to as U.S. tax reform, was signed into legislation. There are a number of specific details that have yet to be clarified, and that clarity is evolving, but a number of provisions will impact our U.S. business operations. Greg will be providing further details on the specifics in a few minutes. Before moving on to project updates, I'd like to provide an update on our recovery efforts from the recent hurricane activity in our service areas. Impact to our annual earnings was minimal due to the storm recovery mechanisms and reserves already in place. In Tampa, Hurricane Irma resulted in almost 60% of Tampa Electric's customers losing power.
I'm proud of the team's exceptional response to the storm, as Tampa Electric was the first utility in the state to have all of its customers restored at the lowest cost per customer. During this past quarter, management has refined our storm restoration cost estimates and pursuant to a settlement agreement filed with the Florida Public Service Commission, we expect to use the savings resulting from tax reform to fully recover Hurricane Irma storm costs in 2018. As you know, Hurricane Matthew hit Grand Bahama in late 2016 with a modest continuing impact on load in 2017. Hurricane Maria, a category 5 storm, resulted in all 36,000 of DOMLEC's customers losing power.
Management has completed its damage assessment and will continue to work closely with the government of Dominica to align our plans to rebuild the electrical system with the government's plan to finance and rebuild the infrastructure and economy on the island. With respect to all our other large project initiatives, we continue to make good progress on all fronts. As I mentioned, the Maritime Link went into service on January 15th. The Labrador Island Link is now expected to be in service in the second quarter of this year. Our investment in the Labrador Island Link will continue to earn AFUDC until the Muskrat Falls Hydroelectric Project is fully operational.
From a growth perspective, we continue to look at opportunities to displace coal-fired generation at Tampa Electric with lower emissions and natural gas-fired generation and even more renewables, with us on a path to install and commission the first 150 megawatts of solar in 2018, which will then immediately result in a $30 million revenue increase pursuant to the solar rate base adjustment mechanism announced in September of 2017. A further 450 megawatts will be installed in the period 2019 through 2021 under the same arrangement. We are actively exploring additional solar beyond that. At Peoples Gas, we're actively looking for opportunities to expand the customer base and gas infrastructure throughout the state. We're excited about the future for this business.
In late July, we responded to the Massachusetts RFP for clean, renewable energy for more than nine terawatt-hours of hydro and onshore wind energy and 1,600 megawatts of offshore wind energy. In January, we were noticed that our proposal was not selected to proceed to negotiation with Massachusetts Electric Utilities for a long-term contract. Despite the unfavorable outcome, we continue to believe that this project would bring significant value to the market. With this belief in mind, we will continue the process to obtain the presidential permit we initiated in 2017. Our use of a subsea cable allows us to bring power directly to Plymouth, Massachusetts, site of the soon-to-be-retired Pilgrim Nuclear Plant, bringing power directly to the Boston Load Center while avoiding congestion in New England without the need for new terrestrial transmission lines.
Over the long term, we believe our proposed Atlantic Link project can help meet the state's and the region's need for clean energy in a very cost-effective manner, and we continue to explore opportunities to advance the project. With the identified growth initiatives that we have underway and the prospects for new investment opportunities in Florida and the possibilities projects such as the Atlantic Link represent, we are very confident in our ability to deliver strong earnings growth and dividend growth over the long term, as reflected by a recent 8% dividend increase in September. I'll turn it over to Greg for the detailed financial results.
Thank you, Scott, and thank you all for joining us this morning. We released our earnings and filed our annual financial statements in MD&A for the fourth quarter and full year 2017, Friday afternoon after market close. In Q4 2017, Emera reported a net loss of CAD 228 million and earnings per share of negative CAD 1.06 compared with net income of CAD 70 million and CAD 0.34 per share in Q4 2016. Our fourth quarter adjusted net income and earnings per share, which excludes mark-to-market adjustments and the revaluation of deferred tax assets, was CAD 137 million and CAD 0.64 per share in 2017, compared with CAD 104 million and CAD 0.51 per share last year. We also reported an increase in cash flow of CAD 379 million or 41% to CAD 1.2 billion year to date, aided significantly by the addition of Emera Florida and New Mexico operations.
For the year-to-date period 2017, we reported net income of CAD 266 million, or CAD 1.25 per share, compared to CAD 227 million or CAD 1.33 per share in the 2016 year-to-date period. As Scott mentioned, adjusted net income in the 2017 year-to-date period was CAD 524 million, or CAD 2.46 per share, compared with CAD 475 million or CAD 2.77 per share in the 2016 period. Our 2016 results included one-time gains related to the sale of our investment in Algonquin Power and gains on our self-insurance fund in Barbados, as well as TECO acquisition costs. Adjusting the items, our 2016 adjusted EPS was CAD 2.39. Fourth quarter net income for Emera Florida and New Mexico operations was CAD 80 million, or CAD 37 million net of the permanent financing cost.
This net income was CAD 18 million higher than Q4 2016 due to higher base revenues following the addition of Polk Unit 2 in January and lower O&M&G costs. On a year-to-date basis, Emera Florida and New Mexico contributed CAD 382 million to net income, or CAD 206 million net of the permanent financing cost, compared to CAD 79 million for the six months ownership in 2016. In September 2017, Tampa Electric was impacted by Hurricane Irma. The majority of Hurricane Irma restoration costs will be charged against an appropriate and approved storm reserve, resulting in minimal impact on our results. As Scott mentioned, the cost incurred in excess of the storm reserve, as well as the replenishment of the storm reserve to its original balance, will be recovered from customers in 2018.
At Peoples Gas, results were higher than last year, primarily due to lower depreciation expense and an increased return on investment related to cast iron and bare steel pipe replacement. New Mexico results were more or less in line with last year. Nova Scotia Power delivered net income of CAD 23 million in the fourth quarter of 2017, compared with CAD 34 million in the 2016 quarter. The decrease from 2016 for the quarter is due to higher O&M&G expense due to higher vegetation management spending and the timing of regulatory deferrals. In the 2017 year-to-date period, Nova Scotia Power delivered CAD 129 million to net income, compared to CAD 130 million in the 2016 period. Emera Maine recorded Q4 2017 net income of CAD 8 million, compared with CAD 11 million in Q4 2016. The decrease is mainly driven by lower capitalized expenses due to lower capital spending.
Emera Maine's net income year-to-date was CAD 46 million, compared to CAD 47 million for the same period last year, which was primarily a result of a stronger Canadian dollar in 2017. Emera Caribbean's net income was CAD 1 million in Q4 2017 versus CAD 8 million in Q4 2016, and the net income year-to-date was CAD 31 million compared to CAD 100 million for the same period last year. The lower results at Emera Caribbean reflect lower energy sales at Grand Bahama Power due to the loss of commercial customers following Hurricane Matthew in September 2016, lower sales volume, and an asset impairment charge at DOMLEC following Hurricane Maria in October 2017, and higher interest expense on new debt issued late in 2016 that was incurred to optimize Emera's overall capital investment in the Caribbean.
Year-to-date results for 2016 also included the benefit of the CAD 43 million reduction in the Barbados Light & Power self-insurance fund liability. Emera Energy's market and trading margins were consistent quarter-over-quarter at CAD 24 million in Q4 2017 compared to CAD 23 million in Q4 2016. The overall weak market conditions for the bulk of 2017 resulted in annual earnings falling slightly short of the low end of Emera Energy's $15 million-$30 million US guidance, a risk that we noted in Q3. That said, we are continuing to be comfortable with our long-standing earnings guidance for 2018.
On the generation side of the business, 2018 will see an approximate $40 million-$50 million US increase in capacity revenue, the after-tax effect of which we expect to flow substantially to the bottom line, resulting in increased earnings over 2017 amounts. Last week, ISO New England's 12-4 capacity auction, FCA 12, concluded at a clearing price of $4.63, just short of the $5-$6 forecast and 13% lower than last year's FCA 11. That price represents an approximate $10 million reduction in revenues for Emera Energy between the 2021 and 2022 capacity years, including $2 million related to our Bear Swamp investment. While that price still represents the highest capacity value in North America, we do not believe it is sufficient to attract new material builds.
Our assessment is that anyone with steel in the ground of any quality will realize sufficient future capacity payments when penalties for non-performance make it untenable economically for aging or inefficient facilities. Our facilities are efficient and reliable performers, and we believe that we'll continue to have an opportunity as the supply stack evolves in the region. Corporate and other reported a Q4 2017 adjusted net loss of CAD 1 million, compared to an adjusted net loss of CAD 17 million in Q4 2016. The loss in 2016 was primarily related to a loss on the disposition of APUC shares. Also included in the corporate and other segment is an increase of CAD 6 million related to higher income from equity investments attributable to APUC on the Maritime Link and Labrador Island Link projects.
Year-to-date 2017, corporate and other reported an CAD 88 million loss compared to net income of CAD 2 million in the 2016 period. This was primarily due to interest expense as a result of the permanent financing of the TECO transaction, offset by increased contributions from Maritime Link and Labrador Island Link. The 2016 results included the CAD 189 million of after-tax gains on the sale of our APUC shares and the conversion of our APUC subscription receipts, and CAD 166 million of after-tax TECO acquisition costs. I would like to take a moment to address the expected impacts of U.S. tax reform on Emera's U.S. operations. As a result of U.S. tax reform, we have recorded a non-cash income tax expense of CAD 317 million in our 2017 results. This expense results from a revaluation of our existing U.S. non-regulated net deferred tax assets.
Going forward, we expect that the U.S. tax reform will negatively impact our consolidated earnings by CAD 25 million-CAD 30 million, representing the after-tax effect of our U.S.-denominated debt resulting from the lower tax rates, partially offset by increased after-tax earnings in our non-regulated U.S. generation business. As a result of U.S. tax reform and MD&A reference, an estimated impact to cash flow of approximately CAD 50 million-CAD 200 million on an annual basis. In 2018, as a result of mitigation efforts of the company to date, we expect the midpoint to be a reasonable expectation. Identified initiatives include the netting of Tampa Electric storm restoration cost recovery against the utility's estimated 2018 tax reform benefits, once approved by the Florida Public Service Commission. The settlement filed with the FPSC includes two separate dockets, which will allow us to true up and recover any differences in 2019.
Additionally, the impact to cash flow will be mitigated further in 2019 due to the refund of alternative minimum tax credit carryforwards. We are continuing to monitor the evolution of U.S. tax reform and are exploring alternatives to minimize the earnings and cash flow impact to the company. Before we take your questions, I'll turn it back over to Scott to say a few words.
Thank you, Greg. As you all know, Chris will officially retire as President and CEO of Emera on March 29th, making this his last investor analyst call. Chris has been CEO of Emera for 13 years, which means he has led more than 50 analyst calls, where he mapped out his plans for Emera and shared a vision for growth. He has been instrumental in making that vision a reality. During his time as CEO, Emera's assets have grown from about CAD 4 billion to CAD 29 billion. Emera's annual total shareholder return has been about 12%, compared to 8% for the TSX Utilities Index. The share price is 2.5 times what it was when he became CEO, and the total shareholder return under his leadership has been about 380%. It would be an understatement to say that Chris has shaped this company.
To say he remade it would be a better description, and we certainly would not be in the position we are today without him. Along the way, he assembled and developed a strong leadership team that has been inspired by his vision. We plan to do him proud by continuing the record of success that he has established. On behalf of the entire team at Emera, thank you, Chris. Your brilliance, dedication, vision, and hard work have transformed our company. We will miss you, but we are ready and excited to continue your work and to continue to build Emera. With that, we will open the call for questions.
If you would like to ask a question, please press star then the number one on your telephone keypad. Again, that is star then the number one on your telephone keypad. We will pause for just a moment to compile the Q&A roster. Your first question comes from the line of Linda Ezergailis from TD Securities. Please go ahead, your line is open.
Thank you. Before I ask my question, maybe I just wanted to wish Chris all the best in his retirement and congratulations on a very successful career.
Thank you, Linda.
Maybe we can move to one of the dynamic conversations you're probably having right now with your debt rating agencies. Can you comment on how the debt rating agencies are looking at some of the effects of U.S. tax reform on your business and how that might inform your financing plans going forward?
Hi, Linda. It's Greg. I think we're seeing, certainly from our perspective, S&P is taking the view that they're waiting to see it unfold and how individual companies are going to react to it because the implications of it will be different by company, and quite frankly, even within a company, different by the various utilities that they own. Moody's, on the other hand, I think has formed probably a little bit more of a pessimistic view. They changed the outlook on, I think, 23 or 24 companies a few weeks ago, and obviously changed our outlook in December in part of the pressure on it. We're working through it. We're, I think, probably a little more optimistic than we might have been maybe a couple of months ago. I still think it's a little bit too early to tell what the long-term implications are.
I think the other thing I might add, though, Linda and Scott, is that we've stated our intention to return our capital structure to our targeted level by the end of the decade. Tax reform has not changed that initiative. Our overall view as to our financing plan and approach to it fundamentally is not different. Of course, we're mindful of credit metrics and achieving certain thresholds. That obviously continues to be a focus. Our broad overall approach to where our focus on our balance sheet and therefore our approach to financing over the period between now and the end of the decade is fundamentally not different from where it was before.
Okay, that's good to know. Maybe just as a follow-up, you mentioned that you're exploring alternatives to minimize the effects on earnings and cash flow of this U.S. tax reform. You mentioned the AMT refund next year, the storm recovery this year. Can you maybe comment on what other alternatives there might be at your disposal, potentially?
Well, again, I think, Linda, it gets into every one of our U.S. utilities is going to go through a normal regulatory process to rebalance rates to reflect the lower income tax expense. Just, I think it was last week or the week before, Peoples Gas reached an agreement where their adjustment in 2018 will not be effective until February the 6th. That means for the first five, six weeks of the year, that'll be a savings on cash flow going back to customers, but it'll also provide a little bit of underpinning for the earnings for this current year, which also happens to coincide with their largest four to five weeks of the year. It's things like that.
It's being able to utilize maybe some of those savings for some of our other utilities that have distribution rate cases facing them to lower what that ask would otherwise be. It's all of those kinds of things, but it is very specific, I would suggest, with each and every utility.
Okay, thank you. I'll jump back in the queue.
Thanks, Linda.
Your next question comes from the line of Robert Hope from Scotiabank. Please go ahead. Your line is open.
Good morning, everyone. I'd also like to say congratulations and all the best to Chris as well.
Thanks, Robert.
I guess, just keeping on the U.S. tax reform theme, I guess two questions here. First, on the ability to properly allocate the U.S. holdco interest, is that based on your current reading of the act, or do you expect that will be as a result of kind of some additional clarity moving forward there?
Robert, it's Greg. It's certainly based on our current reading of the act, but we're also relying on the engagement and work that Edison Electric Institute is doing. We've had financial advisors look at it as well. I think in general, our tax advisors as well as the industry representatives are feeling pretty confident that that will be allocatable debt and therefore the interest deductibility will be preserved.
If we just kind of look on the downside there, if it is not the case, do you have an estimate of what could happen to EPS or FFO?
It wouldn't have any effect on FFO because-
That's true
It doesn't actually affect our tax position on the short end. Obviously, it would reduce the amount of loss carryforward you have on the outside. We do not have an estimate. I don't have an estimate in front of me in terms of what it would be if it was entirely disallowed.
Okay, just one last quick one. The expectation of how Maine will treat tax reform and the timeframe?
I think there's two components to Maine. One is on their distribution. I think commissions overall, as a general rule, have to make sure that rates are just and reasonable. Just because one cost item that's included in rates changes doesn't necessarily mean that that by itself drives a change. We would expect, and we think what is reasonable on the distribution side, that that would get addressed in a distribution rate case that's likely to happen later this year at Emera Maine. The other side of it is how it gets treated for the FERC-regulated transmission. Those tariffs get trued up in the June 1st of every year, and we don't yet have visibility on whether there'll be any changes, back changes in historical rates on that FERC piece.
Thank you.
You're welcome.
Your next question comes from the line of Ben Pham from BMO. Please go ahead. Your line is open. Ben, can you please press star one? Please go ahead. Your line is open.
Okay. Sorry about that. Continuing on the U.S. tax reform queries, the cash flow impact, you've highlighted the range of CAD 50 million-CAD 200 million. Could you provide some context on what would have to happen to get to the CAD 200 million context? I mean, some of it's probably the storm recovery portion. What does that mean in terms of FFO to debt ratios if that were to occur?
Ben. I think that obviously the CAD 200 million is a bookend, is how I would describe it. That would have to ultimately be the result of the final codification of the legislation being different than what we would have expected to be, and quite frankly, probably a pessimistic view on how each and every regulator would treat it. As we get through every week, every month, we're feeling more optimistic, I would say, related to that. I think CAD 100 million of FFO is kind of like 50, 60 basis points on our FFO to debt metrics, just to give you a rough idea of the magnitude.
Okay. I'm also wondering, it's great to see that disclosure in near-term cash flow impact. Would you say that in your longer-term models, three years plus, that these impacts that you're seeing from corporate tax reform, it's largely positive to what you guys were thinking about before heading in?
I think so. Certainly the refund of the alternative minimum tax payments probably wasn't quite as apparent in mid-December as it is now, which will certainly help us in 2019 and 2020. As we look out farther, one of the nuances to this is you'll have a rebalancing of the capital structure in some of our utilities, in particular Tampa Electric, with the reduction of the deferred tax liability, and that's going to create a rate-based investment opportunity, which of course will come with a return that will be supporting both our earnings growth as well as our dividend growth and our cash flow. As we get through the next probably 18 months, we're starting to see some positives come out of it as well.
Of course, on top of all of this, customer rates would be lower than they otherwise would be, which means our product is more affordable than it otherwise would be, which we think is a good thing for the business.
Okay. That's good to hear. Last, can I check with you priced some hedges on New England last thing at a presentation. Any change there? Any update to that?
I can't remember, is it Ben that
Ben, yes.
Yes.
Yeah. Ben, just kind of as an update for the remainder of this winter, just through March, we have about 90% of Bridgeport hedged at $13 around the clock. In the summer, this year, we've got about 40% of Bridgeport hedged at $9 U.S. A little tiny bit already for next winter. There's been kind of some upticks, so we're picking off a little bit as we see that happening. We've got about 20% of Bridgeport's nameplate hedged at $15 around the clock, then 30% for the seven months for this summer at Sorry, I'm just reading a note here, I think I read it twice, anyway, that's fine.
Okay.
I'm going to repeat it. We've got about 90% of Bridgeport hedged at CAD 13 for the rest of the winter. For the summer, we've got about 40% at CAD 9 around the clock, and we've got a little bit for next winter already at 15% at CAD 15 around the clock.
Okay. All right. Thanks, everybody.
Your next question comes from the line of Andrew Kuske from Credit Suisse. Please go ahead. Your line is open.
Thank you. Good morning. I'll ask my obligatory tax question second. Just on the capital deployment plans that you've got. In 2018, you're looking at Emera Florida and New Mexico at $1.3 billion U.S., and that's a pretty significant step up from the CAD 717. How do you think about just the sustainable capital deployment in those utilities in the next few years?
Andrew, it's Scott. Certainly, a big part of the uptick, of course, in 2018 is coming now from the investment in solar with a profile around in-service of the first 150 MW this year, as I mentioned earlier, and about double that in 2019. There's a lot of capital that's going in the ground in support of that 600 MW of solar, which frankly we're really excited about from the company's perspective, but also from customers' perspective, as it relates to the opportunity to clean that generation base and start down the path of renewable energy in that market.
Okay, that's helpful. Maybe just on the bit of a tax question, how do you think about just the tax changes that came out last year in the U.S. and just some of the match funding principles? Because if we've got certain assets that you have immediate expensing for qualified assets, some of those assets do have a bit of a duration. How do you balance that immediate expensing with just traditional match funding principles and a balance sheet that you're trying to de-lever?
What's interesting, the immediate expensing doesn't really have much of an effect on the majority of our business because of the regulated nature. The immediate expensing is for tax purposes, and because of our existing tax losses that we're carrying forward, it's really nothing more in our mind other than an extension of bonus depreciation, it doesn't change our overall earnings and/or cash expectations in 2018 and 2019.
Okay. That's helpful. Thank you.
Thank you.
Your next question comes from the line of Robert Catellier from CIBC Capital Markets. Please go ahead. Your line is open.
Hey, good morning, everyone. Another U.S. tax reform question. With the revision out of Moody's to your outlook, the funds from operation impact of the U.S. tax reform, is there a case to be made to apply for added equity thickness or increased ROEs at some of your utilities?
I don't-
Necessarily think so at this point in time, Robert. If you think back to the Moody's report in December, they reaffirmed the ratings of all the regulated utilities themselves. Our U.S. utilities, as a general rule, have reasonably healthy capital structures. Some of them have higher ROEs than others. I think for the most part, I don't think it's going to open up that much of an opportunity for the utilities that we have.
Okay. As an alternative regulatory strategy, do you see additional opportunity to accelerate some CapEx and maybe use that as an offset? Is that the primary regulatory strategy other than the recovery of the storm costs?
Yeah. In some respects, that's an example of that. Certainly, whether we look at additional solar at Tampa Electric or the conversion of our Big Bend plant from coal to natural gas. Whenever you undertake large capital projects, you're always sensitive to what the impact is on customer rates. With customer rates maybe seeing some downward pressure because of tax reform, all things being equal, that should create some headroom for incremental capital investment. Ultimately, it's got to be capital investment that is good for the customer over the long term.
Okay, thank you.
You're welcome.
Again, if you would like to ask a question, please press star, then the number one on your telephone keypad. Your next question comes from the line of Robert Kwan from RBC Capital Markets. Please go ahead. Your line is open.
Morning. You've talked about kind of early discussions with the rating agencies. I'm just wondering, in terms of your general strategy, though, are you committed to the ratings that you've got? Are there plans to add another agency to the mix?
No, we're committed to our long-term capital structure, Robert, and the ratings we have. At this point in time, we're not contemplating adding an additional agency to the mix.
Okay. I guess just in managing then those target metrics you were looking at, if you're going to be losing some cash flow as part of this and just holding the FFO metric, what types of things would you be looking at then in terms of just kind of the form or the arithmetic around debt reduction to continue to hold the metrics constant?
Yeah. I think, Robert, we've talked about a couple things already. We've identified what the implication of tax reform will be on cash flow for next year. One of the things we've done now is we've reached an agreement to collect the storm costs in Tampa Electric entirely in 2018 as opposed to between 2018 and 2019. Again, we've got the alternative minimum tax refund starting in 2019. We're going to see some ability to probably reinvest additional equity into Tampa Electric as those deferred tax losses or liabilities get shrunk. I'd say it's any and all of those things. There's a lot of moving pieces, obviously, in our business, and we're focused on optimizing each and every lever we have.
All right, for sure. Okay. The 3%-5% negative impact on EPS, combine that with the cash flow side of things, puts pressure on the payout ratio. How are you thinking about that then with respect to your dividend growth rate?
Yeah. Our view is, we've talked about our target dividend growth rate of 8% through to 2020, that we remain committed to that target. We know that one of the reasons of transitioning from an EPS growth target to a dividend growth target is that EPS growth can be lumpy. With the dividend growth target of 8%, it does mean our payout ratio will move around a little bit through the period. There have been times where our dividend payout ratio has been lower than our target, and times like it is now, where it is a little bit higher than our target.
Our view is to continue to grow a dividend at a level that we feel is sustainable and achievable based on the growth opportunities that we have in front of us, and a view that dividend payout ratio will balance out in and around our target over time. That continues to be our view today.
Understood. If I can just finish then with Atlantic Link. Did you receive any feedback as to where you finished in the RFP and just with some of the issues that Northern Pass is having? Are there any kind of thoughts or discussions as to how you might be positioned if they came back, in terms of the process?
No. The process hasn't provided any color or detailed feedback, and that isn't unusual or unexpected given the status of that procurement and award. We believe the words that I spoke earlier, that we think our project adds value for not just the state of Massachusetts, but frankly, for the region. That view hasn't changed as a result of the outcome of this RFP. We know that the whole thing has taken on an interesting dynamic now with the news out of New Hampshire. We'll continue to assess
The market and the news around the procurement and the specific RFP as it becomes more clear. In the meantime, we'll continue to proceed with our application and seeking of presidential permits and continue to assess what the timing and path for our project is. As we stand right now, we still see this as a project of value, and we expect to continue to proceed with our permitting process.
Great. Thank you. Chris, all the best for a well-deserved retirement.
Thanks, Robert.
Your next question comes from the line of Jeremy Rosenfield from Industrial Alliance. Please go ahead. Your line is open.
Thanks. Just one follow-up on the Atlantic Link question. I'm just wondering if that project has any potential for a future RFP, not Massachusetts, but just more broadly, other RFPs that are being contemplated in New England. Also, as a sort of second opportunity for Atlantic Link or maybe a similar project, if you've considered large-scale transmission associated with some of the potential offshore wind projects that have been proposed for the Eastern Seaboard.
I think with the words that I used in saying that we think this project has value not just for the state of Massachusetts, but for the region as a whole, I think you are picking up on the right theme. That there will be other opportunities to enhance the viability of this project. It's not singularly dependent upon this RFP. The region as a whole is seeking more clean energy. We think the Atlantic Link provides an economic path to bring that energy to market, whether it's for this particular project or for another over time. Jeremy, I think the only other thing I would add is that you have to look at where this project is positioned relative to the strength of the transmission system in both locations. This project is extremely well-positioned for New England. There is clean energy behind this project.
There is a system opportunity to reinforce the system in a place where a nuclear plant is going out of service. I think that this project will find a home at the right time.
Okay. Thank you for that. Maybe just one other question. I think it was back in Investor Day or Investor Dinner, there was some mention about the potential to convert the Big Bend Power plants in Tampa, or outside of Tampa, rather. Just wondering if there has been any advancements on that side and whether that is a project that may get accelerated with some of the headroom that we've talked about or you guys have talked about just earlier on the call in terms of being created from the tax reform.
Yeah. We are not looking at that project as specifically linked to tax reform. Certainly, we see that as a project that has potentially tremendous benefits for customers. We are pursuing that with vigor. There's lots of work still to do. It's early days, but it's a project that, as I say, we think is in the best interest of customers.
Great. Okay. That's it for me. Thank you very much.
There are no further questions in the queue at this time.
All right. Well, thank you very much. It's Chris, and just a few final comments from me. As Scott said earlier, it is my last analyst call before retirement, and so it certainly has been, I think, a very positive transition between myself and Scott. I want to congratulate him, and wish Scott and the team all the success in the future, which I know that they'll have. I also want to express my thanks to the analysts and investors who are on the call today. You've all been very supportive of the business over the past 13-plus years, and I very much thank you for that. It's been an honor and a privilege to work with you and with my team to serve our customers over this period. Thank you very much, and we appreciate your interest in Emera.
This does conclude today's conference call. Thank you for your participation, and you may now disconnect.