Emera Inc (EMA) 2016 Q3 法說會逐字稿

Good morning, ladies and gentlemen, and welcome to Emera's third-quarter 2016 conference call and webcast. After the presentation, we will conduct a question and answer session. Instructions will be provided at that time.

Please note this call is being recorded, today, Tuesday, November, 2016 at 11 o'clock, Atlantic Time. I would now like to turn the meeting over to your host for today's call, Mark Kane, Vice President of Investor Relations for Emera. Please go ahead, Mr. Kane.

Thank you, Sean, and thank you all for joining us this morning for Emera's third quarter conference call.

Emera's third-quarter earnings release was distributed yesterday evening via newswire and financial statements and management discussion and analysis are available on our website at emira.com

On the call today from Emera is Chris Huskilson, President and Chief Executive Officer; and Greg Blunden, Chief Financial Officer; and other members of the management team at Emera. This morning, Chris will begin with a corporate update, 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 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 risk, 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 too, regulation, energy prices, general economic conditions, weather, derivatives and hedging, capital resources, loss of service area, license and permits, environment, insurance, labor relations, human resources, and liquidity risk. A number of factors could cause these actual results, performance or achievements to differ materially from the results discussed or implied in the forward-looking statements.

In addition, please note that this conference is being widely circulated via a live webcast. And now, I'll turn things over to Chris.

Thank you, Mark, and good morning, everyone.

Emera delivered adjusted net income of $14 million, or $0.08 per share in Q3 of 2016, compared to $23 million, or $0.16 per share in Q3 of 2015. Adjusted net income, excluding cost related to TECO Energy acquisition was $133 million, or $0.73 per share.

I want to highlight that this is the first quarter that our results include Emera Florida and New Mexico segments, which contributed $109 million to adjusted net income. The net contribution, after the $49 million after-tax permanent financing costs recorded at corporate and other, was $60 million.

These strong third quarter results are in line with our expectations. They were driven by the typically high electricity sales at Tampa Electric, as a result of summer air conditioning load. New Mexico results reflect their continued focus on cost control. While results in New Mexico were essentially breakeven, they were an improvement compared with, historically, the third quarter loss.

I am pleased to report that the integration of the TECO family of companies is proceeding smoothly. As expected, the four senior C-Suite officers retired shortly after closing. We're pleased John Ramil, TECO's President and CEO have joined Emera Board. Welcome, John, and we look forward to working with him in this new capacity.

We now have our senior leadership position in Tampa and Albuquerque in place, and a number of TECO and Emera team members have stepped into new positions with expanded responsibilities. With the addition of the Florida and New Mexico operations, we are above our target of 75% to 85% of earnings coming from regulated businesses, and our dividend is more than covered by regulated earnings.

Emera now operates in two new regulatory jurisdictions, Florida and New Mexico, which also have some of the best organic growth in the US. The combined Emera and Emera Florida and New Mexico businesses expect to have over $8 billion in capital investment over the next five years, and this includes only our committed and visible projects.

Moving forward, we also see additional opportunity to apply Emera's strategy centered on clean affordable energy to drive growth. At Tampa Electric, we see opportunities for potential large scale solar power generation, and at Peoples Gas and New Mexico Gas, we see the potential to grow these businesses, expanding the distribution of cleaner burning natural gas to vehicle fleets, industrial customers, and new residential customers.

Our results at our northern operating companies reflected the continued trend of average weather this summer in Nova Scotia and New England, following the much milder than normal winter. These weather conditions reduced energy sales at Nova Scotia Power and limited trading and energy sales opportunities for Emera Energy.

Moving to the Maritime Link project, construction continues to progress. The project remains on schedule and on budget with an expected in-service date in late 2017. ABB is working on both converter sites in Nova Scotia and Newfoundland, and fabrication of the main transformers is now complete. Manufacturing of both subsea cables is progressing with installation scheduled for mid- 2017.

The Joint Venture between Emera Utility Services and Rockstad Power is working to complete the high voltage direct current transmission lines. And to date, almost $1.1 billion of the $1.6 million project cost has been spent.

Turning to Massachusetts, the State has made a major commitment to clean energy and associated transmission as part of its effort to meet legislative State GHG emissions reductions and renewable targets, an act to promote energy diversity, was approved by the Massachusetts Legislature on July 31 and signed into law by Governor Baker on August 8. The bill mandates a competitive solicitation for long-term contracts to supply Massachusetts with hydro resources or a combination of wind and hydro generation totaling 9.45 terawatt hours.

There must be an initial solicitation issued by the electric distribution utilities in Massachusetts no later than April of 2017, including transmission. Preference shall be given to proposals that combine hydro generation with new Class one renewables and energy delivery during winter months.

In late October, we learned that our proposal for the main renewable energy interconnect project was not selected under the New England tri-state renewable energy RFP. The bidders that were selected for the most part were smaller projects that did not require new transmission investments. The total energy awarded was slightly less than one terawatt hour, or only about 20% of the original RFP. There may the opportunity to bid this project into the Massachusetts Clean Energy RFP for other opportunities to supply low carbon in the New England market in the future.

In Nova Scotia, we're implementing a plan to provide stable and predictable rates for our customers through to the end of 2019. We worked with stakeholders and reached an agreement on a rate stability plan, which was approved by the UARB. With this plan in place, the average annual increase in customer rates is below the annual rate of inflation for residential customers for each of the next three years.

We're stabilizing rates, while at the same time, completing the most ambitious transition to renewable energy in Canada. With the rate stability plan in place, all of our customers in Nova Scotia will have a stable, predictable, and affordable electricity pricing that they can depend on and budget around.

Turning to Emera Caribbean, as you know, Grand Bahama took a direct strike at the category four Hurricane Matthew. There was extensive damage to the islands property, livelihoods, and to the electric grid. Teams from virtually all of Emera utilities responded to the situation and have worked diligently to safely restore the system. Today, more than 90% of the customers that can take power have the service restored. This has been a tremendous undertaking by all involved, and we are all very proud of the results.

Our strong and diverse regulated businesses provide stability and support to our growing dividend. We have a target of 75% to 85% of our earnings coming from regulated businesses, and a dividend payout ratio target between 70% and 75% of earnings.

With the addition of the Emera Florida and New Mexico, operations, our dividend is more than covered by regulated earnings. We do not anticipate further material costs associated with the TECO acquisition, so future quarters will be more representative of earnings throughout the business.

I'll conclude by saying that Q3 was transformational for Emera. We're successfully incorporating the TECO family of companies into Emera. They've delivered strong results to our consolidated net income, and our other operating companies are performing well.

We are well-positioned to deliver strong earnings growth, and deliver market-leading total share returns. We are making good progress toward achieving many of our strategic goals, and look forward to a bright future.

And with that, I'll turn things over to Greg, who will provide you an overview of our financial results. Greg?

Thank you, Chris, and good morning, everyone.

Emera's consolidated loss in Q3 2016 was $95 million, or $0.52 per share. When quarterly results are normalized, the $109 million of mark-to-market losses second quarter of 2016 adjusted net income was $14 million, or $0.08 per share, compared with adjusted net income in Q3 2015 at $23 million, or $0.16 per share.

Excluding the $119 million of costs associated with TECO Energy acquisition, adjusted net income was $133 million, or $0.73 per share. The acquisition costs included legal banking and advisory fees, the New Mexico Gas company stipulation commitments, TECO Energy stock based compensation, acquisition-related financing costs, non-cash accounting related costs associated with the conversion of convertible debenture and convertible debenture-related interest.

I also want to point out that the share count was substantially higher this quarter, due to the conversion of convertible debentures and the issuance of 51.9 million common shares. Our quarterly financial results were strong, reflecting the results from Emera Florida and New Mexico, which I will discuss in a moment, and the better than expected results at other operating companies, some of which is related to timing.

Moving to the segmented results, I will begin with Emera Florida and New Mexico, which, as Chris previously mentioned, provided $60 million to adjusted earnings, net of the $49 million of permanent financing costs, or $109 million gross. The third quarter is always strong in Emera Florida and New Mexico. We expect the roughly 30% of the earnings from Florida and New Mexico will occur in the third quarter, with about 25% in the first order when New Mexico gas is strongest, due to it's winter peak low.

Earnings in the 2nd and 4th quarters are typically split pretty evenly at slightly more than 20% each. Finally, we expect the financing costs to be consistent quarter-to-quarter for the foreseeable future.

Nova Scotia Power provided net income of $15 million in Q3 2016, compared to $5 million in Q3 2015. The increase was primarily due to the timing of regulatory deferrals and lower OM&G cost for the quarter. Nova Scotia Power's net income year-to-date was $96 million, compared to $90 million for the same period last year.

Emera Maine contributed $17 million to consolidated net income in Q3, 2016, compared to $15 million for the same period last year. Emera Maine's net income year-to-date was $36 million compared to $40 million to the same period of last year.

Emera Caribbean's net income increased to $24 million in Q3 2016 compared to $13 million in Q3 2015. The increase was primarily the result of lower OM&G costs as a result of restructuring actions, and higher energy sales at Barbados Light and Power. Emera Caribbean had year to date net income of $92 million, compared with $27 million for the same period last year. The higher net income was primarily due to the gain realized in the self-insurance fund in the second quarter and the decrease in OM&G.

Third quarter results for Emera Caribbean do not include any of the estimate, pretax $25 million US for hurricane Matthew restoration costs. We expect that these costs will be capitalized and recoverable from customers over time.

Emera Energy was essentially breakeven in Q3 2016 compared to an adjusted net income of $15 million last year. Third quarter results are traditionally modest from marketing and trading] and 2016 was no exception, with $2 million of margin compare to $5 million in 2015. In addition, higher fuel costs at Bayside due to the expiration of favorable gas contract, and higher OM&G in the New England plants contributed to Emera Energy's lower earnings quarter over quarter.

Q3 energy sales volumes and spark spreads were consistent between 2015 and 2016 in New England, and the plants continue to perform well with a world-class force outage rate of less than 2%. The reduced availability quarter over quarter reflects plant outages in Tiverton and Bridgeport.

Year to date Emera Energy contributed adjusted net income of $19 million. Emera Energy's Q3 mark-to-market loss had a material impact on reported earnings in the quarter, so, I want to take a moment to help people put that into perspective.

As we explained in the MD&A, Emera Energy has a number of asset management agreements or AMAs with gas distribution utility, power utilities, and natural gas producers. The AMAs involves Emera Energy buying or selling gas for a specific term and the corresponding release of the counter-parties gas transportation or storage capacity to Emera Energy.

Mark-to-market adjustments on those AMAs arise on the price difference between the point where gas is sourced and where it is sold. At inception, the mark to market adjustment is fully offset by the value of the corresponding gas transportation asset.

Of course, the gas prices move over the term of the AMA, which means the value of the transportation also changes; however, because the two elements are accounted for differently, the gas is mark-to-market and the transportation is amortized evenly. That results in some net mark-to-market gains or losses recorded in income.

Ultimately though the gas transportation assets and the mark-to-market adjustment reduce to zero at the end of the contract term. And to complicate matters, in circumstances where the receipt point is illiquid, or without a representative index, like many points in the Marcellus reason, for example, Emera Energy has to find an appropriate, correlated liquid point to serve as a proxy in the mark-to-market calculation.

We also have too continually assess which points are most correlated, and from time to time change the proxy point. That change can result in a large swing in mark-to-market calculation, as was the case in Q3 2016 where approximately $80 million US of the unrealized losses incurred during the period related to changes in the proxy assumption for two receipt points.

It is important to emphasize that these arrangements have no actual economic market exposure, because regardless of the difference in the value of the gas, between the receipt and the delivery points, Emera Energy has a transportation capacity that enabled it to move the gas to the point at which it is priced.

Our corporate and other segment posted a $150 million adjusted net loss in Q3 2015 compared to a loss of $25 million in Q3 2015. The variance was primarily due to a higher interest expense as a result of the permanent financing of the TECO acquisition and other costs associated with the TECO acquisition that I discussed earlier.

Corporate and other reported year-to-date net income of $19 million compared to a $9-million loss in 2015 period. Year-to-date results included $179 million of TECO acquisition costs that were more than offset by the $199 million of after-tax gains in the second quarter from the sale of our Algonquin Power shares and a conversion of our Algonquin Power receipts.

That's all for my update. And now I will be happy to take your questions.

(Operator Instructions).

Your first question comes from the line of Linda Ezergailis, TD Securities. Your line is now open.

Thank you, congratulations on a strong quarter.

Thanks, Linda.

I have a question that's a little bit north of the border, North of Florida. The media is suggesting the CEO of Nalcor is in discussions with you to change the terms of the existing contracts for the Maritime Link. Can you comment on some of the conversation at all, and what that might be referring too?

Linda, we continue to work directly with Nalcor on an ongoing basis, both as it relates to the construction and the timing of the project, as well as the movement of the energy from the Muskrat Falls plant. What we're concentrating on these days is the surplus.

I think what Nalcor -- their current view would be that they have a little more surplus from the plant than they originally had anticipated, as a result of some reductions in consumption in the province. With that being so, there's a lot to be done to get the surplus power to market. And so, we are working with them on that issue.

Okay, and is that the only thing you are working with them on at this point?

As I said, we are working with them on all aspects of the project. It's an ongoing direct relationship that we have with them.

Okay, thank you. And moving on to TECO, I appreciate the update on the seasonality. I just wanted to confirm that pre-financing is seasonality?

Yes, yes it is, Linda. We would expect the financing to be relatively uniform quarter over quarter.

Okay, and if we look at Q4 this year based on weather patterns, consumption, et cetera, that you have seen, is it reasonable to impute that relationship this year, specifically, as well, versus what you experienced in Q3?

Yes, I think, directionally, it will be pretty close, Linda. Obviously, weather can have a bit of an impact, probably a little bit more in New Mexico Gas in the balance of the year than Tampa Electric. But, directionally I think you will be fairly close.

Okay, that's helpful. And with the closing now behind you of the acquisition, are there any updated thoughts on foreign exchange, hedging policy? You've got about 70% of earnings US dollar -- you pay your dividend and Canadian dollars. Can you comment on any updated thoughts on that front?

Yes -- you know, when we look to foreign exchange, Linda, first from a credit metric perspective we're relative not sensitive to changes in the dollar because the amount of US dollar debt we have is relatively proportionate to the amount of cash flow we have in the US.

From a cash flow perspective again, we're relatively hedged and that additional excess cash flows that come out of the US will either be used to re-invest in a regulated utility South of the border, or to repay are US denominated debt. So, really the balance of the exposure that we have from a currency perspective is on our reported earnings, and it's just very difficult to put a hedge in place, an economic hedge in place on accounting earnings and feel very good about it.

At this point, we're planning to keep our dollar -- our dividend in Canadian dollars. The feedback we are getting from investors, our Canadian investors is that's what they are looking for. But it's something we will continue to look at over time.

Great, thank you.

Your next question comes down the line of Robert Hope, Scotiabank. Your line is now open.

Yes, thank you, good morning.

Hi, Rob.

Thank you. Maybe moving on to your Caribbean operation -- can you touch on your comments and MD&A where you expect 2016 adjusted earnings to be relatively consistent with prior years?

But that said, your first nine months so far for the most part surpassed last year's totals, so does that imply a sharp step down in Q4, potentially, as a result of the hurricane?

No, Robert, I think one of the things -- when you think of the first nine months, you do have to take into account the gain that we had in the Self Insurance Fund in the second quarter. And there is a little bit of timing, but I think if you're looking at the fourth quarter for Emera Caribbean balance of the year compared to last year, I think you would probably find it would be directionally fairly close.

All right, that is helpful. And then just taking a look at energy and what the -- what the note in coming Q3, I do realize you do have some benefits moving forward in terms of costs, but could you give us some thoughts on your marketing opportunities there as well as your generation opportunities there through the balance of the year and into 2017?

And, Judy, maybe we would defer to you to answer Rob's question?

Yes, sure. For the balance of 2016, what we've been saying for a while is that we are probably going to be at the low end of our earnings guidance for marketing and trading which is somewhere in the range of $15 million to $30 million.

A gain is challenging to predict because November and December can be big months in marketing and trading, or they can be more benign. So, with that said, I think it's still fair to say the lower-end of the earnings guidance is there, and probably it would not be dissimilar for 2017.

With respect to essentially the asset side of the Business which is largely the New England generating facility, we had a couple of very, very strong years there with $51 and $35 spark spread hedges in the winter season. We're essentially open going into 2017. The spark spreads are very low at the moment. We think we have more opportunity in the realtime market.

We do have some hedges in place that will ensure that, for example, our [10%] facility stays online, but we are mostly market-facing for the first quarter of 2017 at the facilities.

I do remind everybody capacity values are essentially doubling as of June, and that will add almost $30 million and new revenue in the New England assets, so that will be kind of a mitigating factor for what's currently kind of a very weak electricity market.

And I think, Judy, it's also fair to say that you're well-positioned in the market because you have lots of pipeline capacity available to you, and you -- your units are in good shape. The big question is, what's the weather going to do?

So, Rob, I think it's very difficult for Judy to predict that. It certainly has been very mild, and if that continues, earnings will be weak.

That's fair. Thank you for the color.

Okay.

Your next question comes from the line of David Quezada, Raymond James. Your line is open.

Thanks, good morning, guys. My first question is a follow-up on Emera Energy. Are you able too quantify the cost of the plant outages that you had there in the quarter?

And maybe just remind us what the schedule is for maintenance over the next 12 months?

Yes, so, we would have invested a total of $40 million in capital in the facilities, I think, in 2016. I don't have the breakdown of that right in front of me at this moment.

2017 is lighter than that. We did have a 50-day outage at Tiverton, which added 20 extra megawatts to the facility and improved the heat rate by 2% or 3%, so 2017 is a more modest capital profile. I can dig that out and have someone send that to you.

Sure, thank you. That's helpful. And then I guess one other kind of housekeeping question. I believe the release said warmer than usual weather in Florida.

So, would you characterize the earnings from Emera Florida is maybe is surpassing expectations this quarter? Is that a reasonable third quarter run rate going forward?

Yes, certainly. I don't want to characterize it necessarily as unusual. In addition to the warmer weather, they've experienced some load growth and they been investing in the rate base with a $700 million investment in the Poke Power Plant.

It has been warmer than normal but it kind of has been for the last 24 months or so, so on a quarter over quarter basis, we're seeing a little bit of pickup in electric sales, but it's kind of been a natural trend that we've seen over the last couple of years. So, in general, probably slightly positive in the quarter but I wouldn't say materially so.

We are generally saying about 2% growth in that market, just slightly less than that, which turns into $15 million, to $25 million of revenue growth on an annualized basis.

And on top of that, we also are going to see the $110 million come in early in January as we bring the [Polk] Project online. So, we're going to continue to see some growth in the revenue line, and that will impact our business as a whole.

That's very helpful. Thank you very much. That's all I had.

Thank you.

And you're next question comes from the line of Ben Pham, BMO. Your line is now open.

Hi, thanks. I just wanted to follow up on the Caribbean question. Are you guys looking at earnings before ownership -- or after an ownership changes for ECI?

Sorry, Ben, your referring to the Emera Caribbean piece on the ECI? (inaudible - multiple speakers). Sorry, go ahead.

Yes, it's more follow up on trying to reconcile -- you had a comment on the Caribbean growth and even if you strip out the SIF and even the restructuring costs last year, it implies negative earnings for Q4. But there have been some ownership changes -- or some ownership percentage changes. Are you guys adjusting for that to drive outlook?

Sorry, yes. So, on the quarter over quarter basis -- or on the fourth quarter we would expect to remained relatively consistent. Obviously, you would have to adjust that it's in instances where we have a larger ownership share this quarter than we would have a year ago.

The overall business we would expect to reform fourth quarter relatively consistent with the fourth quarter last year recognizing we do have a larger chunk of that because some of the ownership changes. Does that answer your question?

Yes.

Greg, this is Scott, maybe I can help a little bit. I think -- I think you could say the outlook that we referenced in MD&A is potentially a little bit conservative.

Obviously, there have been a lot of changes and impacts with the Self Insurance Fund related transactions occurring over the last two quarters, both the second quarter and a little bit more in the third, and the acquisition of the minority interests of Emera Caribbean Inc sort of driving some of those dynamics. So, at the same time, obviously, it related to the impacts of hurricane Matthew on load and in Grand Bahamas, while we remain optimistic as to the net impacts of that not being as material from a financial perspective.

Obviously, it will have some near-term impacts in terms of load and the like that might have tempered our optimism for the fourth quarter a little bit. So, all in all the business underlying is performing well.

I think we are seeing some strong performance, and, I think, if you were to look at the reconciliation table in the MD&A that sets out the transactional issues around the Self Insurance Fund, you'll see that underlying it, there's been some OM&G savings, some cost savings, and a little bit of load growth. We may give up a little bit of that load growth in the fourth quarter in the Bahamas, but a large part of the OM&G savings will be sustained through the fourth quarter and into 2017.

Okay, thanks for that. And my second question is on the Maritime Link. As you head towards in-service beginning of 2018, can you walk through the repertory filings that you'd need to go through? Is there some sort of compliance filing that you need to prove that the transmission line is used and useful for you to get that booked into rates?

First of all, I think that -- I think the largest piece of this is complete in that -- in that Nova Scotia Power has the revenue requirement for Maritime Link in their fuel component. And so, that's kind of the first step in this.

What's going on right now is that Maritime Link is filing with the regulator to [opine] the project itself -- so to describe the costs that have gone forward, etc. So, that will allow for preliminary assessment, which will be active as of the first of those end of 2017, first of 2018. And then after that, there will ultimately be a close out and the final costing review that will get done.

And it's unclear at this point whether that will be a paper exercise or whether that will be an active hearing. We don't know the answer to that yet, but those are really the three steps, one of which is complete.

Okay. And maybe just Nova Scotia lastly -- on the base business. How do you think about realized ROEs through 2019 as you build up some deferral counts and you get some tax benefits there? I think you are deriving. Do you expect to be within your historical range?

Yes, Ben, it's Greg. Obviously, the Nova Scotia Power ROE range is the 875 to the 975, and even with the build up of the referrals we anticipate because of the [rate stability] agreement, there may be periods of time like we're in right now where we're over collecting on fuel.

All to be said is we would fully expect that there would be no change in that range between now and the end of the decade, and that we will continue to earn within that range.

Okay, that's helpful. Thanks, everybody.

Thanks, Ben.

( Operator Instructions).

Your next question comes from the line of Andrew Kuske, Credit Suisse. Your line is now open.

Good morning.

Good morning.

Maybe just a question on the FX side of things, and how you're thinking of FX in relation to future financing and then also the underlying evaluation?

And I ask this question in part because if you look across the border there is clearly a rate dichotomy that is building in the US and possible rate increases in the future, whereas in Canada possible rate declines -- at least on the overnight. How does that factor into your thought process on the asset situation (inaudible) financings on the debt?

Yes, Andrew, it's Greg. I think a couple of things to think about. I mean, the majority of our financing that we did for the TECO acquisition was in US dollars. And so that provided a bit of a natural hedge in terms of our earnings perspective.

We don't have any material financing requirements over the next few years on either side of the border. So, to be quite frank, a 25 basis point changes in the US aren't going to have much of an affect on us. We do, however, believe that if interest rates rise in the US and stay lower in Canada, it could have an affect on the currency -- likely a weaker Canadian dollar, which would be beneficial to the performance business.

But at this point in time, where short-term small changes in Fed rate for example, is unlikely to have much of an effect on to our business performance.

Andrew, I think the other thing I would suggest is that over the next three, four, or five years, is turn attention to pay a fair bit of the debt that we have in the US.

Our objective would be to retire TECO finance completely over that relative time frame. And so, we're working down that path as part of this whole thing.

Okay, very helpful. And then, I guess, maybe a related question. If you are in an environment where the US dollar strengthens versus CAD and effectively have more (technical difficulty) on a Canadian dollar basis, how does that color your thoughts on (technical difficulty) and payout ratio and all of those things?

Andrew, you are breaking up a little bit on your question, but I think the question was if we have a weakening Canadian dollar, what does that do to our dividend payout ratio?

Yes, exactly.

So, a weaker Canadian dollar will likely mean, obviously, our US dollar earnings would get translated at a higher rate than they otherwise would, which would push our earnings up. All things being equal or would cause our dividend payout ratio to go down under that scenario and of course the alternative would also be true.

I guess, Andrew, we really haven't formed a view of just how far, you know, if we just assume for the moment the US dollar rises quite dramatically between the Canadian dollar or vice-versa or whichever way you want to say, I would say we haven't formed a view of whether that would change our payout ratio or not.

At this point, in and around the $1.30 -ish range which is really where the transaction took place, we're very comfortable with the metrics we put forward, which is to say that we want to payout between 70% and 75%. If that became more dramatic in either direction, we would probably reassess. But for now we don't see a change in that as we sit today.

Okay, that's very helpful. Thank you.

Your next question comes from the line of Robert Kwan, RBC Capital Markets. Your line is now open.

Good morning. Just coming back to Maritime Link and (inaudible) and I guess, Muskrat Falls, I am just wondering with the federal loan guarantee top up -- that seems like a good sign. There was some color about both Nova Scotia and Newfoundland and Labrador remaining committed to the project.

I was wondering if you could provide some color around that. Specifically, if you think or if you know if there is going to be in-service date commitments.

Well I think -- Nalcor, -- let's back up a little bit. So, our commitment has and always is to get the Maritime Link in-service in the 2017 -- end of 2017 time frame.

As we understand it, the transmission in Newfoundland is likely to be in-service at the latest in the early part of 2018 as well. And so, that's been -- I think that's been described by the parties, and I think that continues to be the case.

As it relates to the power plant, Nalcor has put forward a timeline they expect the power plant to come on and that sees full power in the 2020 time frame. And they haven't changed that. In fact, the work they are doing continues to confirm that's a very valid timeline for the project and would continue to be something we would expect to happen.

So, I think the only real issue here is the fact that there is more money going into the project. And so the commitment by the Newfoundland and Labrador government and the Canadian government to help support that, I think we see as very positive. The project is critically important for the region. The transmission loop it creates allows us access to more and more energy through this period.

And I think it also facilitates, collectively in the Atlantic Canada, providing service into the New England market. We continue to see the opportunity to do that. We continue to work hard [up] with the Atlantic Link, and we are seeing opportunities for us to actually continue to move the project forward.

When we think about how this is going, I think that the timeline has now been defined, and I believe that, that timeline will be met based on the way that things are progressing.

In terms of the extra commitment that the feds are providing, is it your understanding though that Nalcor will be held to 2020?

As I said, I think Nalcor has made that commitment from a plan perspective, and I don't think anything has changed that.

Okay, I have seen that was in your presentation earlier but in terms of the [will] equity investment 2017 has gone down quite a bit. Is that just shifting into 2018?

Fundamentally, in fact, the schedule did slow down a little bit this year, but we see it picking back up for now.

So the specific reduction in the equity injection in 2017 -- ?

It is simply about spend, Robert. If the project is progressing, which it now is, then the spend will be progressing as well.

Robert, this is Greg. We do see probably a little bit of spending move primarily in the fourth quarter of 2017 and into the first quarter of 2018.

Okay, that's great. And maybe a last question here. I know you didn't make a lot of detailed statements around federal carbon plan, and I know there's a lot of details to be worked out.

I'm just wondering how you are approaching this in terms of -- is a collaborative approach with the Nova Scotia Government at this point to try to explain all of the good things you are doing in Nova Scotia around the renewable portfolio standard, and try to get something offset here from what the feds want on the carbon side?

Yes, I think, Robert, first and foremost as we sit today, we're already 36% below 2005 levels. And the current plan that we have, which really allows our business to continue to perform in a good way, but also continues to reduce carbon with CS at 58% below 2005 by 2030.

In effect, our business has a cap on carbon emissions, and that cap is substantially below the levels that would be admitted based on the plan that Canada's put forward.

So, when you put that all on the table, I think Nova Scotia is in a very good position to continue to work with the feds to come up with a good win-win solution for the sector and for the province. And we believe that, that firm position allows us to comply as we go forward.

So, and, we do think that the work that was done a number of years ago that came up with the equivalency approach, it was innovative at the time, has produced real carbon reductions, and we think we can continue to work in that kind of direction.

Okay, that's great. Thank you, Chris.

Thank you.

Your next question comes from the line of Robert Catellier with CIBC. Your line is now open.

Thank you. I have a few -- one cleanup question on the weather. I just wondered if it was possible to quantify the impact of warmer weather on adjusted earnings? And, specifically, for Tampa Electric but also an aggregate for all the utilities? Maybe it's something we can take offline if you don't have a number handy, but trying to gauge the impact on the Q3 results.

Yes, it has an effect on the Q3 results, but it's not an exact science as you can appreciate trying to determine how much of the load is directly attributed to the weather versus other changes. Especially, when you look at a very, very short period of time.

Certainly, when we looked at its warmer than normal weather at Tampa Electric and certainly Barbados, in particular, experienced the same thing; the alternative would've happened in our Northeastern businesses somewhat uneventful summer in New England, depressed power prices for a while.

We can certainly take it offline to see if we can do something on it but I would be a little bit reluctant, Robert, to put too much emphasis on it.

I think the other thing to note though, the seasonality of the business has now changed quite a bit with both summer -- summer peaking businesses and winter peaking businesses together. And so I think that seasonality is something we need to make sure, and we will spend more time on that as we go forward so that people can understand that better.

Okay, just specifically on Tampa Electric, though, it looks like you hit 1.6% customer growth but 6.9% electricity volume growth so just, on first appearance it looks like it was actually -- had a pretty good affect on the weather and a pretty good affect on the quarter.

Yes, and it's actually a third piece as well, Robert. There's also some economic grow. For example, you might have more commercial customers come on that would account for one customer, but obviously, impact growth as well. But, certainly, on a -- it was no question it was warm in the third quarter in the Tampa Electric service territory this year.

Okay, thank you.

And you're next question comes from the line of Jeremy Rosenfield, Industrial Alliance. Your line is now open.

Thanks, just a couple of maybe more strategic questions. Just first on the Tri-state RFP and the results that came out of that. How do you interpret the lack of a desire for transmission and sort of proposals, and the results of that RFP?

I mean, I guess, first and foremost, I think, there's still an open need for clean energy. That's the first thing I'd say, and I guess, when you think about looking for something like about four terawatt hours of energy, it's probably not enough to drive the scale of project that's required to actually bring that in, in a competitive fashion, from an energy delivered perspective.

So, I think the Tri-state was a little too small in order to drive additional infrastructure. And so, I think we would expect that if you think about what Massachusetts is looking for, it's now large enough to drive infrastructure. We think that, that's something that will happen.

We -- I would say we were hopeful that the relatively small incremental transmission builds that were needed for the A/C system might will fall under the Tri-state RFP, but I think what we've learned is that even that burden is a little too much at that scale. So, I think will see how it unfolds as Massachusetts takes it's step into this area.

But, certainly, infrastructure is going to be required if clean energy is going to get into that market. And, certainly, the in-markets solutions are more expensive than the out of market solutions with infrastructure.

We do know those two things. And so, at the end of the day, it will depend on the various jurisdictions decision-making relative to what they want to pay for clean energy.

Right, okay. And then also, maybe just another sort of strategic question. When you think about next steps to growing the overall Emera business, following on the TECO acquisition, how do you sort of think about additionally regulated utility acquisitions, US market opportunities versus, let's say, generation capacity additions, either a mix of contracted in merchants or fully contracted assets? What's the give and the take there?

I guess, first of all, I don't think we have changed our point of view that we're mostly focused on organic growth of our businesses, and that acquisitions are something we will do from time to time when they make sense to us.

But that we're continuing to be primarily focused on organic growth in the business. Today, we see about $8 billion of capital in front of us for our business over the next five years. That's certainly supports the growth rate that we talked about, and a little bit back to Andrew's question from before, the fundamental thing about dividend is that we have targeted 8% growth and we see our capital program has provided the capacity to do that. That is kind of the first piece.

The other thing is, as we're entering and have now entered both the Florida and New Mexico market, we do see a lot of opportunity there. Certainly, there is a desire in both markets to see more and more clean energy come into the various induces. And so, from a -- if you think about generation, our focus will be on solar generation in Florida to start. And that we see a lot of opportunity to do that. And also in conversion of higher carbon users into lower carbon users relative to the use of our gas systems.

When we put those two things together -- those are not in our $8 billion of growth that we see. That will provide incremental growth over that period and beyond, I would say.

And so, that's really where you're going to see us spending a lot of our time, focus, and also I think that, that type of growth is a whole lot more predictable and more incremental. Therefore, I would say easier to control overall.

And probably better return on the capital being invested as well, would you say?

Well, we always prefer to invest without premiums as opposed to with premiums, and capital going into our businesses (inaudible).

Great, thank you for that additional color. That's it.

Thank you.

There are no further questions at this time. I turn the conference back to Chris Huskilson for closing remarks.

Thank you, very much. And I'd really like at this point to acknowledge all of the hard work that went into delivering the results for this first quarter of post-closing of this transaction.

I know that the finance groups as well as the operating teams all worked extremely hard, and I would say, did an outstanding job in completing both the reporting and producing the results.

And so, I think it's a very exciting time for our existing business and also a very exciting time for our new businesses. Thank you to them, and thank you for your continued interest in our Company. Have a good day.

And this concludes today's conference. You may now disconnect.