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Good morning, ladies and gentlemen, and welcome to the Emera Q4 2017 Earnings Conference Call and Webcast. [Operator Instructions] Please note that this call is being recorded today, February 12, 2018, at 11 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, and 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 via Newswire, and 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; and 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, and 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. 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.And now I will turn things over to Scott.
Thank you, Ken, and 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 the financial update, and then 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. And 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 1 point -- $1,577,000,000 budget. The revenue requirements for this project have been included in Nova Scotia rates since the beginning of 2017 as part of a 3-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 $137 million and earnings per share of $0.64 compared with $104 million and $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 $524 million and $2.46, respectively. Adjusted net income for 2016 was $475 million, with earnings per share of $2.77. However, 2016 results included onetime gains and TECO acquisition costs. Excluding these items, our 2016 adjusted earnings were $409 million or $2.39 per share.Excluding the onetime 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 onetime 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 2 equity issuances in December of 2016 and 2017.Overall, the company performed very well this year. Our Florida and New Mexico operations contributed $382 million for the year-to-date period. We're particularly happy with the performance of the Florida businesses where customer growth and load growth from the state's hybrid economy, coupled with reduced O&M, led to a $30 million or 10% increase in earnings at USD 316 million 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 $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 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 we'll 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 15. 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 commission -- to install and commission the first 150 megawatts of solar in 2018, which will then immediately result in a USD 30 million revenue increase, pursuant to the solar rate base adjustment mechanism announced in September 2017. A further 450 megawatts will be installed in the period 2019 through 2021 under the same arrangement, and 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, and 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 9 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. And 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 of projects such as the Atlantic Link represents, 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. Now 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 and MD&A for the fourth quarter and full year 2017 Friday afternoon after the market closed.In Q4 2017, Emera reported a net loss of $228 million and earnings per share of negative $1.06 compared with net income of $70 million and $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 $137 million and $0.64 per share in 2017 compared with $104 million and $0.51 per share last year.We also reported an increase in cash flow of $379 million or 41% to $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 $266 million or $1.25 per share compared to $227 million or $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 $524 million or $2.46 per share compared with $475 million or $2.77 per share in the 2016 period. Our 2016 results included onetime 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 $2.39.Fourth quarter net income for Emera Florida and New Mexico operations was $80 million or $37 million, net of the permanent financing cost. This net income was $18 million higher than Q4 2016 due to higher base revenues following the addition of Polk Unit 2 in January and the lower OM&G costs. On a year-to-date basis, Emera Florida and New Mexico contributed $382 million to net income or $206 million, net of the permanent financing cost, compared to $79 million of the 6 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 costs 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 $23 million in the fourth quarter of 2017 compared with $34 million in the 2016 quarter. The decrease in 2016 for the quarter is due to higher OM&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 $129 million to net income compared to $130 million in the 2016 period.Emera Maine recorded Q4 2017 net income of $8 million compared with $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 $46 million compared to $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 $1 million in Q4 2017 versus $8 million in Q4 2016, and the net income year-to-date was $31 million compared to $100 million for the same period last year. The lower results at Emera Caribbean reflect lower energy sales at Grand Bahama Power due to 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 $43 million reduction in the Barbados Light & Power Self Insurance Fund liability.Emera Energy's marketing and trading margins were consistent quarter-over-quarter at $24 million in Q4 2017 compared to $23 million in Q4 2016. Some cold weather in late Q4 brought opportunity after several quarters of mild weather, but 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 USD 15 million to USD 30 million 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 USD 40 million to USD 50 million 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 12th forward capacity auction, FCA 12, concluded at a clearing price of $4.63, just short of the $5 to $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 [ Beasaw ] 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 nonperformance make it untenable economically for aging or inefficient facilities. Our facilities are efficient and reliable performers, and we believe that we will continue to have an opportunity as the supply stack evolves in the region.Corporate & Other reported a Q4 2017 adjusted net loss of $1 million compared to an adjusted net loss of $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 & Other segment is an increase of $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 & Other reported an $88 million loss compared to net income of $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 $189 million of after-tax gains on the sale of our APUC shares and the conversion of our APUC subscription receipts and $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 noncash income tax expense of $317 million in our 2017 results. This expense results from a revaluation of our existing U.S. nonregulated net deferred tax assets. Going forward, we expect that the U.S. tax reform will negatively impact our consolidated earnings by $25 million to $30 million, representing the after-tax effect of our U.S.-denominated debt resulting from the lower tax rates, partially offset by increased earnings -- after-tax earnings in our nonregulated U.S. generation business.As a result of U.S. tax reform, our MD&A reference an estimated impact to cash flow of approximately $50 million to $200 million on an annual basis. In 2018, as a result of mitigation efforts of the company today, 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 [ file ] with the FPSC includes 2 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.And before we take your questions, I'll turn it back over to Scott to say a few words.
Thank you, Greg. So as you all know, Chris will officially retire as President and CEO of Emera on March 29, making this his last investor analyst call. Chris has been CEO of Emera for 13 years, which means he's led more than 50 analyst calls where he mapped out his plans for Emera and shared a vision for growth. And he's been instrumental in making that vision a reality. During his time as CEO, Emera's assets have grown from about $4 billion to $29 billion. Emera's annual total shareholder return has been about 12% compared to 8% for the TSX Utilities Index. The share price is 2.5x 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 a 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'll open the call for questions.
[Operator Instructions] Your first question comes from the line of Linda Ezergailis from TD Securities.
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.
And now maybe we can move to one of the dynamic, I guess, 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?
Yes. Linda, it's Greg. I think we're seeing, certainly from our perspective, I think S&P is taking a 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 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. So I -- we're working through it. We're, I think, probably a little more optimistic than we might have been maybe a few -- a couple of months ago. But 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 -- Linda, it's 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. So our overall view is do 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. But our broad overall approach to where our focus on our balance sheet, and therefore, 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. Now maybe just as a follow-up. You mentioned that you're exploring alternatives to minimize the effects of -- 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?
Yes. 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. And so 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 6. So that means for the first 5, 6 weeks of the year, that will be savings on cash flow going back to customers, but it will also provide a little bit of underpinning for the earnings for this current year, which also happens to coincide with their largest 4 to 5 weeks of the year. So 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, basing them to lower what that [ Act ] would otherwise be. So it's all of those kind of things, but it is very specific, I would suggest, with each and every utility.
Your next question comes from the line of Bob Hope from Scotiabank.
I'd also like to say congratulations and all the best to Chris as well.
Thanks, Bob.
And then I guess, just keeping on the U.S. tax reform theme. I guess, 2 questions here. First, on the ability to properly allocate the U.S. holdco interests. 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 read of the Act, but we -- we're also relying on the engagement and work that Edison Electric Institute is doing. We've had financial advisers look at it as well. And I think, in general, tax -- our tax advisers as well as the industry representatives are feeling pretty confident that, that will be allocatable debt, and therefore, the interest deductibility will be preserved.
Okay. And then if we just kind of look on the downside there. If it is not the case, do you have an estimate of what can happen to EPS or FFO?
Well, we have -- it wouldn't have any effect on FFO because it doesn't affect actually our tax position on the short end. Obviously, it would reduce the amount of loss carryforward you have on the outside. I -- 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. And then just one last quick one. The expectation of how Maine will treat tax reform and the time frame?
So I think there's 2 components to Maine, one is on their distribution. And I think commissions overall, as a general rule, have to make sure that rates are just and reasonable. And just because one cost item that included in rates changes doesn't necessarily mean that, that by itself drives a change. So we would expect and we think what is reasonable on the distribution side that, that would get addressed. And a distribution rate case is 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 1 of every year, and we don't yet have visibility on whether there will be any changes -- back changes in historical rates on that FERC piece.
Your next question comes from the line of Ben Pham from BMO.
Continuing on the U.S. tax reform queries, the cash flow impact, you've highlighted the range of $50 million to $200 million. Could you provide some context on what would have to happen to get to the $200 million context? I mean, some of it is probably the storm recovery portion. And then what does that mean in terms of the FFO to debt ratio, if that were to occur?
Yes, Ben. So 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 expect it to be, and quite frankly, probably a pessimistic view on how each and every regulator would treat it. And -- but as we get through every week, every month, we're feeling more optimistic, I would say, related to that. I think $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. And I'm also wondering, the -- and it's great to see a disclosure in near-term cash flow impact. Would you say that in your longer-term models, 3 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?
Yes, I think so. And 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. And then as we look out further, one of the nuances of this is you'll have a rebalancing of the capital structure in some of our utilities, in particular at Tampa Electric, with the reduction of the deferred tax liability. And that's going to create a rate base 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. So as we get through the next probably 18 months, we're starting to see some positives come out as well. And 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. And last, can I check with you the price of some hedges on New England last time you had a presentation. Any change, any update to that?
Is it -- is Ben who is asking now? Yes. So Ben, just kind of just an update, for the remainder of this winter, just through March, we have about 90% of Bridgeport hedged at $13 around the clock. And in the summer this year, we've got 40% of Bridgeport hedged at USD 9. And a little tiny bit already for next winter, there's been kind of some uptick, so we're picking up a little bit as we see that happening. We've got about 20% at Bridgeport same place hedged at $15 around the clock and about -- and then 30% for the 7 months of -- for this summer at -- sorry, I'm just reading the note here, and I kind of -- I think I read it twice. But anyway, that's fine. So I'm going to repeat it. We've got about 90% of Bridgeport hedged to $13 for the rest of the winter. For the summer, we've got about 40% at $9 around the clock, and we've got a little bit for next winter already at 15% around the -- at $15 around the clock.
Your next question comes from the line of Andrew Kuske from Crédit Suisse.
I'll ask my obligatory tax question second. But just on the capital deployment plans that you've got. So in 2018, you're looking at Emera Florida and New Mexico with USD 1.3 billion, and that's a pretty significant step-up from the $700 million in '17. How do you think about just the sustainable capital deployment in those utilities in the next few years?
Yes. So Andrew, it's Scott. So 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 megawatts this year, as I mentioned earlier, and about double that in 2019. So there's a lot of capital that's going in the ground in support of that 600 megawatts of solar, which frankly, we're really excited about from the company's perspective but also from customer's 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. And then maybe just on the 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. But 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 then the balance sheet that you're trying to delever?
Yes, what's interesting, I mean, the immediate expensing doesn't really have much of an effect on the majority of our business because of the regulated nature. And 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 the extension of bonus depreciation. And so it doesn't change our overall earnings and/or cash expectations in 2018 and 2019.
Your next question comes from the line of Robert Catellier from CIBC Capital Markets.
So another U.S. tax reform question. With the revision out of Moody's Street 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. And so -- and our U.S. utilities, as a general rule, have reasonably healthy capital structures. Some of them have higher ROEs than others, but 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?
Yes, I mean, in some respects, that's an example of that. But 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 take -- undertake large capital projects, you're always sensitive to what the impact is on customer rates. And 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. But ultimately, it's got to be capital investment that is good for the customer over the long term.
[Operator Instructions] Your next question comes from the line of Robert Kwan from RBC Capital Markets.
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? And are there plans to add another agency in the mix?
No. I mean, we're committed to our long-term capital structure, Robert, and the ratings we have. And at this point in time, we're not contemplating adding additional agency to the mix.
Okay. I guess, just in managing then that -- 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?
Yes. And so I think, Robert, we've talked about a couple of things already. So 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're -- we 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 in the Tampa Electric as those deferred tax losses or liabilities get shrunk. So 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.
Okay. For sure. Okay. And then the 3% to 5% impact -- negative impact on EPS and then combine that with the cash flow side of things puts pressure on this payout ratio, how are you thinking about that then with respect to your dividend growth rate?
Yes. So our view is that we've talked about our target dividend growth rate of 8% through 2020 that we remain committed to that target. We know that the -- one of the reasons of transitioning from an EPS growth target to a dividend growth target is that EPS growth can be lumpy. And so with the dividend growth target of 8%, it does mean our payout ratio will move around a little bit through the period. And there have been times where our dividend payout ratio has been lower than our target. And at times, like it is now where it is a little bit higher than our target, and 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, that dividend payout ratio will balance out in and around our target over time. And 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. So the process doesn't -- hasn't provided any color or detailed feedback, in that it's 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 the -- 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. But we'll continue to assess the market and the news around the procurement and specific RFP as it becomes more clear. But 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. But as we stand right now, we still see this as a project of value, and we continue -- expect to continue to proceed with the permitting process.
Your next question comes from the line of Jeremy Rosenfield from Industrial Alliance.
Just one follow-up on the Atlantic Link question. I'm just wondering if that project has any potential for future RFP, not Massachusetts, but just more broadly, other RFPs that are being contemplated in New England, and 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 project that have been proposed for the eastern seaboard.
Yes, 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're 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. And 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.
And 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. And this project is extremely well-positioned for New England. And so 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. And so I think that this project will find a home at the right time.
Okay. Maybe just one other question, in -- I think it was back at Investor Day or investor dinner, there was a mention about the potential to convert the Big Bend power plant 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 it would be created from the tax reform.
Yes, so we're not looking at that project as specifically linked to the tax reform. But certainly, we see that as a project that has potentially tremendous benefits for customers, and so we're 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.
Your next question comes from -- I'm sorry, there are no further questions in the queue at this time.
All right. Well, thank you very much. It's Chris. Just a few final comments for 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. And so 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. So 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.