Good morning, ladies and gentlemen, and welcome to the Emera Q3 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, November 13, 2017, at 11:00 A.M. Atlantic Time. I would now like to turn the meeting over to your host for today's call, Ken McManaman, Vice President, Investor Relations and Treasurer for Emera. Please go ahead, Mr. McManaman.
Thank you, Denise. 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 initiative, 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 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 achievement 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. 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 $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 two projects totaling almost 150 MW and is scheduled to be complete in September of 2018. The subsequent three phases are scheduled to be complete by January 1st 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 29th. 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 30th. 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 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 CAD 118 million and earnings per share of CAD 0.55 compares with CAD 14 million and CAD 0.08 per share in the third quarter of 2016. Excluding the third-quarter 2016 TECO acquisition costs, adjusted earnings for the third quarter of 2016 would have been CAD 133 million or CAD 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.
From reduced contributions in the Caribbean. For the first nine months of the year, adjusted net income and earnings per share were CAD 387 million and CAD 1.82 compared with CAD 320 million and CAD 1.88 per share. The 21% increase in adjusted net income in 2017 is positive, 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 this same quarter in 2015, for example, our adjusted EPS, excluding one-time gains and costs, was CAD 0.30 compared to the CAD 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. Our team's response to the storm was exceptional. 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 Domlec's customers lost power. Restoration efforts to date have been focused on specific vital services and humanitarian need. We've been working with the government of Dominica as they identify the next priorities for restoration and the magnitude and timeline 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 CAD 1.4 billion of the projected CAD 1.6 billion project cost. On September 11, 2017, the UARB approved NSPI's interim assessment payment to the Maritime Link of the cost associated with the 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-year life of the power sales agreement with Nalcor, will still provide the contracted energy rates 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 nine 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 CAD 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 underway 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. 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 about 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 CAD 81 million and earnings per share of CAD 0.38 compared with a net loss of CAD 95 million and CAD 0.52 per share in Q3 2016. Our third-quarter adjusted net income and earnings per share, which excludes mark-to-market adjustments, was CAD 118 million and CAD 0.55 per share in 2017, compared with CAD 14 million and CAD 0.08 per share last year. Results in Q3 2016 included TECO acquisition costs. Removing these charges, adjusted net income in Q3 2016 would have been CAD 133 million, or CAD 0.73 per share.
We reported an increase in cash flow of CAD 341 million, or a 55% increase to CAD 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 CAD 494 million or CAD 2.32 per share, compared with CAD 157 million or CAD 0.98 per share in the 2016 year-to-date period. Adjusted net income in the 2017 year-to-date period was CAD 387 million or CAD 1.82 per share, compared with CAD 371 million or CAD 2.31 per share in the 2016 period. Adjusting for the one-time items in the year-to-date period, adjusted 2016 net income was CAD 320 million or CAD 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 CAD 120 million, or CAD 77 million net of the permanent financing cost. This net income was CAD 11 million higher than Q3 2016 due to higher base revenues following the addition of Polk Unit 2 in January and lower OM&G costs. On a year-to-date basis, Emera Florida and New Mexico contributed CAD 302 million to net income or CAD 169 million net of the permanent financing cost, compared to CAD 60 million in the 2016 period. In September 2017, Tampa Electric was impacted by Hurricane Irma. The majority of Hurricane Irma restoration costs 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 CAD 7 million in the third quarter of 2017 compared to CAD 15 million in the 2016 quarter. The decrease from 2016 for the quarter is primarily due to timing differences related to expenses and regulatory deferrals. In the 2017 year-to-date period, Nova Scotia Power delivered CAD 106 million to adjusted net income, compared to CAD 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 CAD 13 million, compared with CAD 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 CAD 38 million, compared to CAD 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 CAD 12 million in Q3 2017 versus CAD 24 million in Q3 2016, and the net income year-to-date was CAD 30 million compared to CAD 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 CAD 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 CAD 40 million in gas sales margin in Q3, that was CAD 16 million lower than in the same quarter of 2016. The impact was mitigated by a CAD 10 million reduction in short-term fixed cost commitments for transportation storage, resulting in a CAD 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. 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 $15 million to $30 million U.S. 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 through depressed spark spreads. The unplanned outage at 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, I reiterate that guidance today. Looking to 2018, things get brighter.
We'll see an approximately CAD 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 is 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, that would have a positive impact on capacity energy values. As it turned out, we realized some benefits earlier than anticipated, which was welcome, today we are enduring a weaker-than-expected energy market at the moment, which is not welcome. We still like our original investment thesis.
Now that these assets make up less than 3% of Emera's overall total, the impact on the overall risk profile is minimal. Corporate and other reported an adjusted net loss of CAD 33 million compared to an adjusted net loss of CAD 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 CAD 7 million related to higher income from equity investments attributable to AFUDC on the Maritime Link and Labrador-Island Link project. Year-to-date 2017, corporate and other reported an CAD 87 million loss compared to net income of CAD 19 million in the 2016 period.
The results comparisons were driven by the same factors as the third quarter, with AFUDC on the Maritime Link and Labrador-Island Link projects being CAD 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, we're now happy to take your questions.
Ladies and gentlemen, to ask a question, please press star one on your telephone keypad. We'll pause for a moment as questions come into queue. Your first question comes from Linda Ezergailis with TD Securities. Your line is open.
Thank you. I have a follow-up question with respect to the outlook for energy services. I appreciate the updated guidance, 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 CAD 15 million-CAD 30 million run rate might either widen, narrow, or shift downwards if there's less volatility as infrastructure gets built out. Do you see that CAD 15 million-CAD 30 million under normal weather circumstances still being a valid range?
Linda, it's Judy. Somebody asked me this question internally last week, I said I'm still comfortable with the CAD 15 million-CAD 30 million at this moment. I do think we've had particularly unfavorable conditions in the weather, until that moderates a bit, we can't really tell if there's anything beyond that. If we're going to adjust it downward, it'd be by a few CAD million, which seems in a good week, we can generate that in a week. I'm still comfortable with the CAD 15 million-CAD 30 million at this juncture. I would expect that 2018, we're optimistic that that will kind of return to a bit of a more normal range.
That's helpful context. Thank you. 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. Really at this stage, it's through the evaluation process with the procuring party, with the State, we're waiting on response and reaction from them. Obviously, we continue to do our part in terms of advancing the project in the meantime. At this point, we're really just waiting for a response to the RFP submission.
When do you expect that?
Early in the new year.
Are you aware of whether that will be made public or not?
At some point, certainly will be made public. As to a timing of their intentions as to public notification, I'm not specifically aware.
Okay. Thank you.
Your next question comes from David Quezada with Raymond James. Your line is open.
Thanks. Morning, guys. 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.
Thanks, David. We've actually procured all of the panels. We've already taken that step with no impact of the tariff. As it relates to the 600 megawatts that we're looking to develop, we've already got that tied down.
Okay, great. Perfect. 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, the 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. 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 a 12-month period. That'll replenish the hurricane reserve that we had.
Excellent. That's helpful. Thank you. Then just my last question. Wondering if you could 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 have any insight there.
It's Greg, David. It is early days. 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. 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 not be required to do 100% expensing of CapEx. We'll still be able to have deductibility of interest expense. Given that it's early days in first cut, some of the things that we're obviously very sensitive to in our sector seem to have gone our way. 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.
Appreciate that. Thank you. That's all I had.
Your next question comes from Rob Hope with Scotiabank. Your line is open.
Yes. Good morning, everyone. Maybe just first on the generation side. 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? Is this largely being driven by the higher capacity pricing, or are you also seeing kind of energy margins tick up as well?
It is mostly a result of the doubling of capacity since June. We do have about just over 400 MW hedged around the clock at a $12 spark spread starting November 1, which is helpful. It's a bit of a combination there. There's no doubt that the 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 income should largely track the capital investment as well?
Robert, it's Greg. The way to think of it, the first 150 MW we would expect to be in service by the end of 2018. 2019 is a little bit heavier year at 250 MW, and then in 2020, another 150 MW, and the balance in 2021. 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. 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 four-year periods.
All right. Thank you.
You're welcome.
Your next question comes from Ben Pham with BMO. Your line is open.
Okay, thanks. Good morning.
Good morning.
Just had a couple of questions on TECO. You've reaffirmed your CapEx guidance, you've been approved for the solar investments with SoBRA. Also, I think your base rates at TECO are going to be frozen for a number of years as you build up the solar. My question is, I'm curious, how do you plan to manage your ROE at the base TECO and maybe some levers that you can pull there that you can earn your ROEs when you're spending CapEx there outside of solar?
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 four years. 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, the State of Florida has much more positive economic profile than some of the other places that we operate today. The combination of those two things leaves us confident in the ability to continue to earn within the ROE band that we have set for us over that four-year period.
Is that load growth is what was driving this need for solar, or is it some of the generation that's retiring you had towards late decade?
It's really a combination of the two. Frankly, just a view that this is economic for customers. Tampa still has a very high carbon intensity to its generation fleet. There's still a healthy amount of coal in the generation mix there. 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. That allows us to moderate the balance of the fleet. 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.
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's going to see 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. 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 very much a target for us, and our customers are supportive of that.
Okay. It seems like pretty interesting investments. I missed some of your response to the U.S. tax reform question, and I don't think I've seen anything impacting the solar credits, the ITC. Can you confirm that?
Yeah. That's correct, Ben.
Okay. All right. Thanks, everybody.
Thank you.
Your next question comes from Robert Catellier with CIBC. Your line is open.
Hi, good morning. I only have one question that hasn't been answered yet, and it has to do with the energy services. 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 the commitments that you make to pipelines in that segment?
The commitments that we make to pipelines, that's a very dynamic situation that we're in all the time. The value of those commitments kind of changes materially based on market conditions. In fact, we would've 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. We'll kind of continue to monitor that in real time and adjust our strategies that way. I think that what would perhaps cause us to make an adjustment, 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. Once we do experience that, it may kind of lead us to a different conclusion. At this moment in time, to be candid, on days when we do see normal weather patterns, the market activity is kind of returned to what I would consider to be normal. Do I think there's going to be any 100-dollar gas in New England anytime soon? Probably not, but we're not managing the business for the 100-dollar gas base. 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. Should we take away from your comments that at this point you do have enough commitments under normal conditions to earn that base level of earnings?
Yeah.
Yeah. Okay.
We're resourced. Again, we have a different set of transport commitments around the fringe every single year. We have a material amount invested this year, and if the market presents the opportunity, we've got the pipeline to move the gas around.
Okay, got it. Thanks.
Again, to ask a question, please press *1 on your telephone keypad. Your next question comes from Robert Kwan with RBC Capital Markets. Your line is open.
Morning. If I can start with Florida, there's a statement in the MD&A, talking about due to warmer than normal weather last year, there's an expectation that you expect annual sales to fall below 2016 levels. That being said, I think year to date, you're 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 think Robert, and this is Greg. We would expect Q4 to be pretty much consistent on an ROE basis 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 they'll ultimately land up in the quarter will be somewhat dependent on weather and just how hot it remains in Florida over the balance of the year. We would expect it to be slightly positive in the fourth quarter of this year compared to last year, all things being considered.
Okay. Then maybe just finishing up on dividend policy. You've got the 8% growth and the 70%-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?
Yeah, Robert, it's Scott. I think the way to think about the payout ratio is that it's a long-term guidance. It's not 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. 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. At this point in time, we remain confident that our 8% dividend growth profile remains our target, and we remain comfortable with that.
Robert, it's Chris. The only other thing I would add to that is that, as we become more and more regulated, 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. That's really what drove us to those numbers in the first place. 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. 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? 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?
Yeah. Robert, the view that Judy gave in terms of the guidance range for energy services remains consistent with our view and our forecast. We're not counting on being able to overachieve that range that Judy gave as to what we'd expect in normal market conditions to be able to be a component part of the contribution towards our dividend. What's important is that all parts of our business are delivering growth, and obviously we're seeing now some of the higher growth profile that the execution of Emera's strategy in Florida can start to deliver. It's a combination of all those things that, as I say, gives us continuing confidence that that dividend target for us remains appropriate.
Robert, maybe I'm just going to get a little more pointed about this. You're 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. 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. We expect more solar to come into our business as well. We also have the Atlantic Link in front of us, and we have work going on overall in the regulated business.
As I said, your question is presupposing that it takes unregulated earnings for us to grow at that pace, I would say that that's not a good assumption.
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? If within the 70%-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.
Okay, that's great. Thank you.
Your next question comes from Jeremy Rosenfield with Industrial Alliance. Your line is open.
Yeah, thanks. That was a great line of questioning. I appreciated that and the answers there before. 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's 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.
Sure. Unfortunately, I missed the very front end of the question. Based on the tail end, I'll assume that the question is sort of more strategic around that business. 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. Frankly, we saw some of that long-term value appreciation that we saw, our market appreciation happen quicker, and then it fell away somewhat. 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 ever it makes sense, divestitures. I would say there's nothing imminent on that front as we look right now. We're always looking for what the right thing to do from a value perspective is. Right now, we wouldn't see something of compelling nature on either side of that trade.
Okay, great. Thanks.
Thanks, Jeremy.
There are no further questions queued up at this time. I turn the call back over to the presenters.
Okay, well, thank you very much for participating in the call today. Certainly, we continue to be very excited about where Emera is going and things like the investment in solar are part of that for us. 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.