Emera Inc (EMA) 2017 Q3 法說會逐字稿

Good morning, ladies and gentlemen, and welcome to the Emera Q3 2017 Earnings Conference Call and Webcast. (Operator Instructions) Please note that this call is being recorded today, November 13, 2017, 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, Denise, and thank you all for joining us this morning for Emera's Third Quarter 2017 Conference Call. Emera's third quarter earnings release was distributed late 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'll be happy to take questions from the analysts.

I will take a 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. Chris will join Greg and I in responding to your questions.

Before speaking to our results, I'd like to focus on a few notable positive developments for Emera. On November 6, the Florida Public Service Commission unanimously approved a settlement agreement enabling Tampa Electric to significantly expand its use of solar power. Once installed, Tampa Electric will have the highest percentage of solar-energy generation in the state of Florida. This project results in Tampa Electric investing about USD 850 million in total through to 2021. This capital investment has not been included in our past CapEx forecasts and is incremental to our growth forecast.

The first phase of the solar construction includes 2 projects totaling almost 150 megawatts and is scheduled to be complete in September of 2018. The subsequent 3 phases are scheduled to be complete by January 1 of 2019, 2020 and 2021. This significant addition of solar energy is a terrific example of Emera's strategy now in action at Tampa Electric, investing in the reduction of carbon intensity in our utilities, creating value for both customers and shareholders. Future organic growth opportunities such as this are in direct support of our communicated strategy and underpin our confidence in delivering on our commitment to grow earnings and our dividend. Successes such as this project contributed to our recent 8% dividend increase announced on September 29.

The approval of solar-power initiative has also served as a capstone event for one of TECO's longest-serving leaders, Gordon Gillette. Gordon played a key role in integrating Tampa Electric into the Emera group of companies and the recent approval for solar expansion in Tampa. I'd like to thank Gordon for his significant contribution and leadership over the past 36 years.

Nancy Tower will become the President and CEO of Tampa Electric upon Gordon's retirement on November 30. Many of you know Nancy already, as she has been with Emera over 20 years, most recently as our Chief Corporate Development Officer. In that role, Nancy was instrumental in making the TECO acquisition a reality, and we know she's very excited to be joining the strong leadership team at TECO during this dynamic time.

The last point of business to address before moving on to the results for the quarter is the appointment of Ken -- Kent Harvey to Emera's Board of Directors. Kent is an accomplished executive with more than 30 years of experience at PG&E Corporation. His experience as a strategic thinker and his knowledge of the U.S.-regulated gas and electric industry will no doubt be of great value to the board and Emera as we continue to grow.

Turning now to our third quarter results, where adjusted net income of $118 million and earnings per share of $0.55 compares with $14 million and $0.08 per share in the third quarter of 2016. Excluding the third quarter 2016 TECO acquisition cost, adjusted earnings for the third quarter of 2016 would have been $133 million or $0.73 per share. Results this quarter were reduced year-over-year largely from timing differences, the impact of a higher share count in 2017 when the comparative for the quarter in 2016 didn't yet include the common share issuance from the acquisition of TECO, and from reduced contributions in the Caribbean.

For the first 9 months of the year, adjusted net income and earnings per share were $387 million and $1.82 compared with $320 million and $1.88 per share. The 21% increase in adjusted net income this 2017 is positive, but reduced contributions, largely from Emera Energy, and the impact of new shares issued in conjunction with the TECO acquisition contributed to the reduction in earnings per share. Notably, contributions from TECO were strong in the quarter, demonstrating the additional earnings power of the business with the acquisition of TECO, particularly in the otherwise traditionally weak third quarter, noting in the same quarter in 2015, for example, our adjusted EPS, excluding onetime gains and costs, was $0.30 compared to the $0.55 this year.

Before moving on to project updates, I'd like to speak to the recent hurricane activity in our service areas. As you know, Hurricane Matthew hit Grand Bahama late last year, and it continues to have a small impact on load this year. In Tampa, Hurricane Irma resulted in almost 60% of Tampa Electric customers losing power. But our team's response to the storm was exceptional. And in fact, Tampa Electric was the first utility in the state to have all of its customers restored. Impact to quarterly earnings was minimal due to the storm-recovery mechanisms and reserves already in place. However, Hurricane Maria, a Category-5 storm, hit the island of Dominica with devastating force. All 36,000 of Dominica's customers lost power. Restoration efforts to date have been focused on specific vital services and humanitarian need, and we've been working with the Government of Dominica as they identify the next priorities for restoration and the magnitude and time line for these efforts. As such, it's still too early to assess the full impact of this hurricane. Our thoughts go out to the citizens of Dominica, and we will continue to provide our support during these difficult times.

With respect to our other large-project initiatives, we continue to make good progress on all fronts in Newfoundland and Nova Scotia, where work is progressing on the Maritime Link Transmission Project, which is on budget and on track to meet the planned January 2018 in-service date. To date, we've spent about $1.4 billion of the projected $1.6 billion project cost.

On September 11, 2017, the UARB approved NSPI's interim-assessment payment on -- to the Maritime Link -- of the cost associated with Maritime Link starting when the Maritime Link is in service. Due to the delay of the in-service date of the Muskrat Falls Hydro Plant, Nova Scotia Power Maritime Link Inc., NSPML, suggested that the UARB agree that depreciation of the Maritime Link be deferred until Muskrat Falls is delivering power. The Maritime Link will still be depreciated over the 35 years -- 35-year life of the power sales agreement with Nalcor, will still provide the contracted energy rights to Nova Scotia, and we will still collect the full amount of depreciation over what is now, essentially, an extended period of access to the Link for Nova Scotians.

The Labrador-Island Link is now expected to be in service about the middle of next year. Our investment in this project will continue to earn AFUDC earnings until the Muskrat Falls hydroelectric project is fully operational, which is now expected to be between mid-2019 and mid-2020.

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. We think our proposed Atlantic Link Project can help meet the state's needs for clean energy in a very cost-effective manner. The line would originate in New Brunswick and come ashore in Plymouth, Mass., the site of the soon-to-retire Pilgrim nuclear plant. This allows us to bring power to the Boston load center and avoid congestion in New England without the need for new terrestrial transmission lines.

In addition, we're looking at opportunities to displace coal-fired generation at Tampa Electric with lower emission natural gas-fired generation and even more renewables while at Peoples Gas, we're looking for opportunities to expand the customer base and gas infrastructure in the state. The potential investments related to the Atlantic Link Project and these other possible Florida initiatives are not included in our current $7.5 billion capital-spend forecast. Our spending forecast only includes items that are known and have regulatory certainty if appropriate.

With the identified growth initiatives that we have under way and the prospects for new investment opportunities in Florida and projects such as the Atlantic Link Project, we look forward to continuing to deliver strong earnings and dividend growth over the long term.

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 quarterly financial statements and MD&A for the third quarter of 2017 Friday afternoon after the markets closed.

In Q3 2017, Emera reported net income of $81 million and earnings per share of $0.38 compared with a net loss of $95 million and $0.52 per share in Q3 2016.

Our third quarter adjusted net income and earnings per share, which excludes mark-to-market adjustments, was $118 million and $0.55 per share in 2017 compared with $14 million and $0.08 per share last year. Results in Q3 2016 include TECO acquisition costs. Removing these charges, adjusted net income in Q3 2016 would've been $133 million or $0.73 per share.

We reported an increase in cash flow of $341 million or a 55% increase to $956 million year-to-date, aided significantly by the addition of Emera Florida and New Mexico operations. For the year-to-date period in 2017, we reported net income of $494 million or $2.32 per share compared with $157 million or $0.98 per share in the 2016 year-to-date period.

Adjusted net income in the 2017 year-to-date period was $387 million or $1.82 per share compared with $371 million or $2.31 per share in the 2016 period. Again, adjusting for the onetime items in the year-to-date period, adjusted 2016 net income was $320 million or $1.88 per share. Adjusted net income increased 21%, while per share figures were modestly lower as a result of the increased number of shares outstanding in the quarter following our 2016 share issuances.

Third quarter net income for Emera Florida and New Mexico operations was $120 million or $77 million net of the permanent financing costs. This net income was $11 million higher than Q3 2016 due to higher base revenues following addition of Polk Unit 2 in January and lower OM&G costs. On a year-to-date basis, Emera Florida and New Mexico contributed $302 million to net income or $169 million net of the permanent financing costs compared to $60 million in the 2016 period.

In September 2017, Tampa Electric was impacted by Hurricane Irma. The majority of Hurricane Irma restoration cost will be charged against an approved storm reserve resulting in minimal impact on our results. 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. In New Mexico, results were comparable to last year at effectively breakeven.

Nova Scotia Power delivered net income of $7 million in the third quarter of 2017 compared to $15 million in the 2016 quarter. The decrease in 2016 for the quarter is due primarily due to timing differences related to expenses and regulatory deferrals. In the 2017 year-to-date period, Nova Scotia Power delivered $106 million to adjusted net income compared to $96 million in the 2016 period. Results benefit from lower OM&G and lower provision for income taxes, partially offset by higher depreciation expense.

Emera Maine recorded Q3 2017 net income of $13 million compared with $17 million in Q3 2016. The decrease is mainly driven by lower capitalized expenses due to lower capital spending. Emera Maine's net income year-to-date was $38 million compared to $36 million for the same period last year. The results reflect lower OM&G expenses and higher revenues due to rate changes.

Emera Caribbean's net income was $12 million in Q3 2017 versus $24 million in Q3 2016, and the net income year-to-date was $30 million compared to $92 million for the same period of last year. The lower results at Emera Caribbean reflect lower energy sales at Grand Bahama Power due to the loss of several commercial customers following Hurricane Matthew in October 2016 and higher interest expense on new debt issued in late 2016.

Q3 2016 also reflected a gain on the sale of investment securities of approximately CAD 5 million. Year-to-date results for 2016 also included the benefit of the $43 million reduction in Barbados Light & Power Self Insurance Fund liability.

Turning to Emera Energy. Emera Energy has endured weak market conditions in the Northeast for all of 2017, reflecting mild weather in both winter and summer seasons. That results in lower gas pricing and reduced volatility.

Our Marketing and Trading business still managed to generate $40 million in gas sales margin in Q3, but that was $16 million lower than in the same quarter of 2016. The impact was mitigated by a $10 million reduction in short-term, fixed-cost commitments for transportation and storage, resulting in a $4 million reduction in net earnings from that business. As you know, most of the Marketing and Trading earnings are generated in January to March and November and December, so we still have some significant opportunity before we close out the year if conditions present themselves. Nonetheless, from where we sit at this point, we believe the best we can expect to do is to make the low end of our normal earnings range of USD 15 million to USD 30 million this year. Hopefully, the weather will return to something approaching normal this winter, such that we can deliver comfortably within our stated earnings range in 2018.

Our generating fleet feels the impact of the weak gas markets due to depressed spark spreads. The unplanned outage of Bridgeport earlier this year did not help things. These negative factors have been mitigated by the doubling of capacity prices in June.

Previously, we noted that we expected 2017 earnings to be in line with 2016 levels, and I reiterate that guidance today. Looking to 2018, things get brighter. We'll see an approximately $40 million increase in capacity revenue, the after-tax impact of which we expect to flow substantially to the bottom line, resulting in a material increase in earnings over 2017 amounts.

We acquired the facilities in late 2013 because we believe there's value in having steel in the ground if acquired at the right price in the right location. Our expectations at the time was that post 2020, we would see non-gas assets retire and that would have a positive impact on capacity energy values. As it turned out, we realized some benefits earlier than anticipated, which was welcome. And today, we are enduring a weaker-than-expected energy market at the moment, which is not welcome. But we still like our original investment thesis. And now that these assets make up less than 3% of Emera's overall total, the impact on the overall risk profile is minimal.

Corporate & Other reported an adjusted net loss of $33 million compared to an adjusted net loss of $151 million in Q3 2016. The loss in 2016 was primarily related to TECO transaction costs recorded in this segment. Also included in Corporate and Other segment is an increase of $7 million related to higher income from equity investments attributive -- attributable to AFUDC on the Maritime Link and Labrador-Island Link project.

Year-to-date 2017, Corporate & Other reported an $87 million loss compared to net income of $19 million in the 2016 period. The results comparisons were driven by the factors as the third quarter, with AFUDC on the Maritime Link and Labrador-Island Link projects being $22 million higher in the year-to-date 2017 period, partially offset by the gains on the sale of Algonquin Power in 2016.

Thank you, and we'll be now happy to take your questions.

(Operator Instructions) Your first question comes from Linda Ezergailis with TD Securities.

I have a follow-up question with respect to the outlook for energy services. I appreciate the updated guidance. But I'm wondering how we might think of, prospectively, in addition to weather, maybe, certain secular shifts in the supply-demand balance in the region suggesting that the $15 million to $30 million run rate might either widen, narrow or shift downwards if there's less volatility as infrastructure gets built out. Or do you see that $15 million to $30 million under normal weather circumstances still being a valid range?

Linda, it's Judy. Somebody asked me this question internally last week, and I said I'd still -- I'm still comfortable with the $15 million to $30 million at this moment. I do think we've had particularly unfavorable conditions in the weather. And until we -- until that moderates a bit, we can't really tell if there's anything beyond that. So if we are -- were going to adjust it downward, it would be by a few million dollars, which seems -- in a good week, we can have that -- we can generate that in a week. So I am still comfortable with the $15 million to $30 million at this juncture. And I would expect that 2018, we are optimistic that we'll, kind of, return to a bit of a more normal range.

That's helpful context. And maybe we can follow up also on the Atlantic Link. Have there been any developments recently, either politically or on the regulatory front or any other work streams that you're working on, that might shift how you're thinking about the project?

No, it's Scott, Linda. So really, at this stage, it's through the evaluation process with the procuring party with the state, and we're waiting on response and reaction from them. And obviously, we continue to do our part in terms of advancing the project in the meantime. But at this point, we're really just waiting for a response to the RFP submission.

And when do you expect that?

Early in the new year.

And do -- are you aware of whether that will be made public or not or...

So in terms -- at some point, certainly, it will be made public. As to timing of their intentions as to the public notification, I am not specifically aware.

Your next question comes from David Quezada with Raymond James.

My first question, just on the Florida solar opportunity. Just curious how the procurement of those solar modules has gone so far and if you see any tightening going on there with the news around the tariff right now.

We've -- thanks, David. It's -- we've actually procured all of the panels. We've already taken that step with no impact of the tariff. So as it relates to the 600 megawatts that we're looking to develop, we've already got that tied down.

Okay, great. Perfect. And then just on the impact of Irma in the Tampa area, I appreciate that the impact to earnings will be minimal. Just wondering if that delays any of the CapEx rollout you had planned in that region at all materially.

No, David. It's Greg. No, it has no impact on it. Fortunately, State of Florida and the recovery of hurricane restoration cost is a well-traveled path. We had previously built up a regulatory reserve or cash reserve from customers to pay for an event such as Irma. And we will be going through a process, again, that's well established to collect that cash back from customers, probably beginning around the 1st of March over 12-month period, and that will replenish the hurricane reserve that we had.

Excellent, that's helpful. And then just my last question. Wondering if you can provide us any thoughts on the tax reform potential bill that's been circulated. I appreciate it's early stage, but just wondering if you had any insight there.

It's Greg, David. It is early days. But if you start with what has been, kind of, tabled, it has been a material change, I would say, from where things were, maybe at the beginning of the year in some of the blueprints. So it is clear at this point that there seems to be consensus on a couple of things, including an overall reduction in tax rates. But specifically, for our sector, a carve-out for the utility sector so that they will be not required to do 100% expensing of CapEx. We'll still be able to have deductibility of interest expense. And so given that it's early days and first cut, some of the things that we're, obviously, very sensitive to in our sector seemed to have gone our way. And obviously, we'll continue to spend time monitoring it and working with EEI in the U.S. to ensure that through the process that nothing negative happens to us.

Your next question comes from Rob Hope with Scotiabank.

Maybe just first on the generation side. I appreciate the reiteration of the expectation that 2017 will look like 2016. Just want to get some additional color on that. Is that based on, I guess, what you've seen, kind of, halfway through Q4? And is this largely being driven by the higher capacity pricing? Or are you also seeing kind of energy margins that tick up as well?

So it is mostly a result of the doubling of capacity since June. We do have about just over 400 megawatts hedged around the clock at a USD 12 spark spread starting November 1, which is helpful. So it's a bit of a combination there. But there's no doubt that the capacity prices are very -- capacity values are very valuable in these current market conditions.

That is helpful. Moving down south to Florida, saw TECO's CapEx get ticked up. Can you help us understand, I guess, first and foremost, how CapEx will track for the solar investment? And whether or not incomes -- income should largely track the capital investment as well?

Robert, it's Greg. The way that I think, kind of think of it, the first 150 megawatts we would expect to be in service by the end of '18. 2019 is a little bit heavier year at 250 megawatts, and then in 2020, another 150 megawatts and the balance in 2021. So obviously, that capital investment gets made over time. As Scott has indicated, obviously, there is some front-end loading of costs for things like land and procurement of panels. But I think, directionally, you can assume that the profiling of earnings will be pretty much consistent with the megawatts that go into service over those 4-year periods.

Your next question comes from Ben Pham with BMO.

Just had a couple of questions on TECO. So you've reaffirmed your CapEx guidance, and you've been approved for -- to solar investments with SoBRA. And also, I think your base rates at TECO are going to be frozen for a number of years as you build up the solar. So my question is, I'm curious, how do you plan to manage your ROE at the base TECO and maybe some levers you can pull there, you can earn your ROEs when you're spending CapEx there outside of solar?

Yes. So I think with the addition of the clarity on the SoBRA, we now have a revenue stream that will fully fund at target equity thickness, at target ROE that program over the next 4 years. And with -- as it relates to base rates, with both an effort to control costs and the reality of a growing load profile in that state, remember, that state of Florida has much more positive economic profile than some of the other places that we operate today. The combination of those 2 things leaves us confident in the ability to continue to earn within the ROE band that we have set for us over the -- over that 4-year period.

Okay. So is that load growth is what was driving this need for solar? Is it some of the -- some generation that's retiring, you head towards late decade?

Well, it's really a combination of the 2, and frankly, just to view that this is economic for customers. And so Tampa still has a very high-carbon intensity to its generation fleet. They still have a healthy amount of coal in the generation mix there. And so now with the impact of the cost of solar and the installed cost of solar reducing to a level as well as the value of tax credits that assist with solar that gets in the ground quickly, it is an economic value proposition for customers to install that. And that allows us to moderate the balance of the fleet. But you're right, there is a growth profile within the load forecast and within the state of Florida in terms of thinking about the profile of load, and the hours where load intensity is high, solar matches up very well with that load profile.

And Ben, it's Chris. The only other thing I would add to that is that when you actually think about this from a customer's perspective, the customer is going to see about -- just something less than a 1% increase when you net out the value of the fuel that is saved as a result of the solar, and you actually look at the growth that's going to come in the system through that period, the net effect on customers will be about 1% on an annualized basis, just slightly less than that. And so that's what makes it affordable. And as Scott said earlier, getting the carbon intensity of this business down more in line with the average across the state is a very much a target for us, and our customers are supportive of that.

Okay. It seems like pretty interesting investments, then. I missed some of your responses to the U.S. tax reform question. And I'm just -- and I don't think I've seen anything impacting the solar credits like ITC. Is that -- can you confirm that?

Yes, that's correct, Ben.

Your next question comes from Robert Catellier with CIBC.

I only have one question that hasn't been answered yet. It has to do with the energy services. So understanding that you're still confident that the business can earn that base level of earnings, what would cause you to change your outlook and/or reduce your commitments, the commitments that you make to Pipelines in that segment?

So the commitments that we make to Pipelines, that's a very dynamic situation that we're in all the time. And the value of those commitments kind of changes materially based on market conditions. So we would -- in fact, we would have seen that our bids on several pieces of pipe that we might have had in the past, we didn't win auctions on those this time around. We're comfortable with that, because frankly, we tend to be more conservative when we're making those investments in these periods when it looks like there's not that much market opportunity. So we all kind of continue to monitor that in real time and adjust our strategies that way. I think that the -- what would perhaps cause us to make an adjustment, we -- there is more pipe into New England. It's hard to assess the true impact of that until we get really what we would consider to be a normal weather year, so once we do experience that, we may -- it may kind of lead us to a different conclusion. But at this moment in time, to be candid, on days when we do see normal weather patterns, they -- market activity has kind of returned to what I would consider to be normal. Do I think there's going be any $100 gas in New England anytime soon? Probably not. But that's not how we -- we're not managing the business for the $100 gas base. So I accept that -- those are the kinds of things that would cause us to make an adjustment. But we don't see the need to at this moment.

Okay, that's helpful. So should we take away from your comments that at this point you do have enough commitments under normal condition -- conditions to earn that base level of earnings?

Yes, yes. So we've got -- we're a resource, we've got -- again, it's all -- we've a different set of transport commitments around the fringe every single year. We have a material amount invested this year, and if the opportunity -- if the market presents the opportunity, we've got the pipeline to move the gas around.

(Operator Instructions) Your next question comes from Robert Kwan with RBC Capital Markets.

If I can start with Florida. There is a statement in the MD&A talking about due to warmer-than-normal weather last year, there's an expectation that you expect or you expect annual sales to fall below 2016 levels. That being said, I think, year-to-date, you are already down. I'm just wondering, that statement specifically with some of the tailwinds such as the Polk revenues coming in as well as tailwind from the benefits on the refi at TECO Finance and then just general growth. Just taking all of that in its entirety, are you able to, kind of, just frame what you're looking at for Q4 versus, say, what you did last year?

I mean, we -- I think, Robert, and it's Greg, we would expect Q4 to be pretty much consistent on an ROE basis with what we had in Q4 of last year, recognizing that the overall rate base of Tampa Electric is slightly higher because of the Polk facility going into rate base in January of this year. Directionally, we're at this point in time in the year where, where they'll ultimately land up in the quarter, will be somewhat dependent on the weather and just how hot it remains in Florida over the balance of the year. But we would expect it to be slightly positive in the fourth quarter of this year compared to last year, all things being considered.

Okay. And then maybe just finishing up on dividend policy. You had the 8% growth and the 70% to 75% payout ratio. I'm just wondering, do you feel that this is achievable through the plan if power energy margins and Marketing and Trading remain at depressed current levels? Or does the ability to achieve the 8% growth within the payout ratio range assume a recovery on both fronts?

Yes, Robert, it's Scott. So I think -- I mean -- I think the way to think about the payout ratio is that it's a long-term guidance. It's not, sort of, a fiscal year by fiscal year thing. We have had periods where our payout ratio is below our range. And we have had and will have periods where our payout ratio is above the range, and really what it comes down to is a view and a confidence that over the longer term, our dividend rate will be within that payout range, even though in short periods of time, we may see it higher or lower than that range. So at this point in time, we remain confident that our 8% dividend growth profile is -- remains our target. We remain comfortable with that.

And Robert, it's Chris. The only other thing I would add to that is that -- and as we become more and more regulated, and I think if you look at it this year, we're probably 99% regulated from an earnings perspective, then we're less concerned about the payout ratio creeping up a little bit. Because really, that payout ratio was always to recognize the fact that we would have unregulated volatile earnings. And that's really what drove us to those numbers in the first place. And so if we don't have a material amount of unregulated earnings, then we're less worried about it creeping up a little bit.

Got it. So just -- I guess to be clear, Scott, with your answer, given you're focused more on, call it, the medium to longer term, is it fair though that you are banking on a recovery in the unregulated businesses? And put differently, if you don't get that or back to Judy's, we're not going to move the range now, but if there is a possibility you might in the future that, that movement in the unregulated guidance would potentially put downward pressure then on the ability to deliver 8% growth?

No, I mean, Robert, we're not -- so the view that the Judy gave in terms of the guidance range for energy services remains our -- remains consistent with our view and our forecast. So we're not counting on being able to overachieve that range that Judy gave as to what we'd expect the normal market conditions to be able to be a component part of the contribution towards our dividend. But what's important is that all parts of our business are delivering growth. And obviously, you're seeing, we're seeing now some of the higher-growth profile that the execution of Emera's strategy in Florida can start to deliver. And as a combination of all those things, as I say, it gives us continuing confidence that, that dividend target for us remains appropriate.

And Robert, maybe I'm just going to get a little more pointed about this. You are assuming in that question, the way it's phrased, that we're not going to grow the rest of the regulated business at the rate that we've been growing. And so what I would say to you is that we've just delivered a solar solution for Florida that's going to add to our capital investment. We're working on gas conversions, and that will turn into a really good outcome for customers based on what we're seeing right now. And we expect more solar to come into our business as well. And we also have the Atlantic Link in front of us, and we have work going on overall in the regulated business. So as I said, your question is presupposing that it takes unregulated earnings for us to grow at that pace, and I would say, that that's not a good assumption.

Okay. So actually then given the positive developments that we've seen, especially on the regulated side, is it fair to say that if the unregulated side remains depressed, that you can absolutely deliver the 8% growth? And if within the 70% to 75%, if we do get a recovery, that's the type of activity that could either extend the 8% or drive the payout ratio below the 70% range based on everything you're seeing right now?

We have to keep growing our regulated business, but we see the opportunity to do that.

Your next question comes from Jeremy Rosenfield with Industrial Alliance.

If I can continue on the Emera Energy, just for a second here. I'm wondering if from a strategic perspective, you're comfortable with the current asset mix within that portfolio. Or if maybe there is an opportunity to go out and to improve the risk-return profile by adding an asset into the portfolio at some point over the longer term?

You want to take that one?

Sure. Unfortunately, I missed the very front end of the question. So -- but based on the tail end, I'll assume that the -- to your question is, sort of, more strategic around that business. And I think, we continue to think about those assets as we did when we acquired them, which is, as Greg made in his remarks, we saw value in the acquisition, with a view as to what the long-term profile for that market was. And frankly, we saw some of that long-term value appreciation that we saw our market appreciation happen quicker. And then it fell away somewhat. So our strategic commitment to those plants really hasn't changed from what it was. It continues to deliver an earnings profile that is consistent, not inconsistent with what we saw when we originally acquired. We continually look to our business development efforts around how to optimize the portfolio in terms of acquisitions and if that ever make sense, divestitures. But I wouldn't say there's nothing imminent on that front as we look right now. We are always looking for what the right thing to do from a value perspective is, and right now, we wouldn't see something of compelling nature on either side of that trade.

There are no further questions queued up at this time. I'll turn the call back over to the presenters.

Okay. Well, thank you very much for participating in the call today. It certainly -- we're continued to be very excited about where Emera is going, and things like the investment in solar are part of that for us. So again, thank you very much for participating. And we hope you all have a great day.

This concludes today's conference call. You may now disconnect.