Mark Kane - VP, IR Chris Huskilson - President and CEO Greg Blunden - CFO Judy Steele - President and COO, Emera Energy Inc., Halifax, Nova Scotia Scott Balfour - COO, Northeast & Caribbean, Emera Inc., Halifax, Nova Scotia

Linda Ezergailis - TD Securities Rob Hope - Scotiabank David Quezada - Raymond James Ben Pham - BMO Andrew Kuske - Credit Suisse Robert Kwan - RBC Capital Markets Robert Catellier - CIBC Jeremy Rosenfield - Industrial Alliance

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 that this call is being recorded today, Tuesday, November 08, 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 and 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 the financial statements and management discussion and analysis are available on our website at emera.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 involves 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, license and permits, environment, insurance, labor relations, human resources and liquidity risks. A number of factors could cause the actual results, performance or achievement 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 will 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 costs related to the 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 segment 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. This strong third quarter results are in line with our expectations. They were driven by the typically high electricity sales At Tamp Electric as a result of summer air-conditioning load. At New Mexico results reflect their continued focus on cost control while results in Mexico were essentially breakeven, there were improvement compared with historically a third quarter loss. I'm 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 that John Ramil, TECO's President and CEO has joined Emera board. Welcome John. And we look forward to working with him in this new capacity. We now have our senior leadership positions in Tampa and Albuquerque in place and a number of TECO and Emera team members has 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 U.S. The combined Emera and Emera Florida in 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. At Peoples Gas and New Mexico Gas, we see the potential to grow these businesses extending the distribution of cleaner burning natural gas to vehicles 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 normal - 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. With joint venture between Emera Utility Services and Rokstad Power is working to complete the high-voltage direct current transmission lines. And today almost $1.1 billion of the $1.6 million project costs 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 legislated 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 I renewables and energy delivery during winter months. In late October we learned that our proposal for the Maine 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 investment. The total energy awarded was slightly less than 1 terawatt hour or only about 20% of the original RFP. There may be opportunities 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 our 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 are 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 stable, predictable and affordable electricity pricing that they can depend on and budget it out. Turning to Emera Caribbean as you know Grand Bahama took a direct strike from at the category 4 Hurricane Matthew. There was extensive damage to the island’s property, livelihoods to the electric grid. Teams from virtually all of the 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're 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 earnings coming from regulated businesses and a dividend payout ratio target between 70% and 75% of earnings. With the addition of 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’re well positioned to deliver strong earnings growth and deliver market-leading total shareholder returns. We're making good progress towards 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 for the $109 million of mark-to-market losses second quarter 2016 adjusted net income was $14 million or $0.08 per share compared with adjusted net income in Q3 2015 of $23 million or $0.16 per share. Excluding the $119 million of costs associated with the 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’s stipulation commitments, TECO Energy stock-based compensation, acquisition related financing cost, non-cash accounting related costs associated with the conversion of the convertible debenture and convertible debenture related interest. I also want to point out that the share count is substantially higher this quarter due to the conversion of the 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 a better than expected results at other operating companies some of which is related to timing. Moving to the segmented results, I’ll 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 that roughly 30% of the earnings from Florida and New Mexico will occur in the third quarter, but about 25% in the first quarter when New Mexico Gas is strongest due to its winter peak load. Earnings in the second and fourth quarters are typically split pretty evenly and slightly more than 20% each. Finally we expect the financing cost 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 in 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 for 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 cost as a result of restructuring actions and higher energy sales at Barbados Light & 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 on the self insurance fund in the second quarter and a decrease in OM&G. Third quarter results from Emera Caribbean do not include any of the estimated pretax $25 million for Hurricane Matthew restoration cost. We expect that these cost 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 for marketing and trading and 2016 was no exception with $2 million of margin compared to $5 million in 2015. In addition higher fuel cost 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 plant continues to perform well with a world-class forced 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 the MD&NA Emera Energy has a number of asset management agreements or AMAs with gas distribution utilities, power utilities and natural gas producers. The AMAs involve Emera Energy buying or selling gas for specific term and the corresponding release of the counterparty’s 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 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’ 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 reduced to zero at the end of the contractor term. And to complicate matters in circumstances whether the receipt point is a liquid or without a representative index like many points in the Marcellus region for example Emera Energy’s has defined an appropriate, correlated liquid point to serve as a proxy in the mark-to-market calculation. We also have to 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 calculations as was the case in Q3 2016 where approximately US$80 million of the unrealized losses incurred during the period relate 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 delivery points Emera Energy has transportation capacities that enables it to move the gas to the point at which it is priced. Our corporate and other segment posted a $151 million adjusted net loss in Q3 2016 compared to a loss of $25 million in Q3 2015. The variance was primarily due 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 the 2015 periods. 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 the conversion of our Algonquin Power subscription receipts. That’s all for my update and now we’ll be happy to take your questions.

[Operator Instructions] And your first question comes from the line of Linda Ezergailis with TD Securities. Your line is now open.

Thank you. Congratulations for a strong quarter. I have a question that’s a little bit north of the border, north of Florida. The medial is suggesting that the CEO of Nalcor is in discussions with due to change the terms of the existing contracts for the Maritime Link. Can you comment on some of the conversations at all and what that might be referring to?

Well, 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. And so what we’re concentrating on these days is the surplus and I think what Nalcor has currently – their current view would be that they have a little more surplus from the plan when they originally had anticipated as a result of some reductions in consumption in the province. And so with that being, so then there is a lot to be done to get the surplus power to market and so we’re working with them on that issue.

Okay. And is that the only thing that you are working on them with at this point in terms of…?

Well, as I said, we’re working with them on all aspects of the project and so 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 and just wanted to confirm that’s pre-financing seasonality?

Yes, it is and we would expect the financing to be relatively uniform quarter-over-quarter.

Yes, okay. So then if we look at Q4 of this year based on weather patterns, consumption et cetera that you’ve seen, is it reasonable to impute that relationship this year specifically as well versus what you experienced in Q3?

Yes, I think directionally you’ll be pretty close Linda, obviously weather can have a bit of an impact probably little bit more at New Mexico Gas in the balance of the year then Tampa Electric, but directionally I think you’ll 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 your earnings U.S. dollar. You pay your dividend in Canadian dollars. Can you comment on any updated thoughts on that front?

Yes, we look at foreign exchange Linda, I mean first from a credit metric perspective, we’re relatively not sensitive to changes in the dollar because the amount of U.S. dollar debt we have is relatively propionate to the amount of cash flow we have in the U.S. From a cash flow perspective again we’re relatively hedged and that additional and excess cash flows are committed to U.S. will either be used to reinvest and regulate utilities south of the border or to repay our U.S. denominated debt. So really the balance of exposure we have from a currency perspective is on a 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 dividend in Canadian dollars. The feedback we’re getting from investors, our Canadian investors is that’s what they are looking for, but it’s something that we’ll continue to look at over time.

Great. Thank you.

Your next question comes from the line of Rob Hope with Scotiabank. Your line is now open.

Yes, thank you. Good morning. Maybe moving on to your Caribbean operation, can you touch on your comments on the 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 total. 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 that when you think of the first nine months you do have to take into account the gain that we had on the self insurance fund in the second quarter and there is a little bit of timing, but I think if you are looking at the fourth quarter for Emera Caribbean balance of the year compared to last year I think you’d probably find it to be directionally fairly close.

All right. That is helpful. And then just taking a look at energy and what the note income in Q3. I do realize that you have some benefits moving forward in terms of cost. But can you give us an updated thought 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 questions.

Yes, sure. So through the balance of 2016 what we’ve been seeing for a while is that we’re probably going to be at the low end of our earnings guidance for marketing and training, which is somewhere in the range of $15 million to $30 million. Again it’s challenging to predict because November and December can be big months in marketing and training or they can be more benign. So – but that said I think it’s still fair to say that the low end of the earnings guidance is there and probably it would not be dissimilar for 2017. With respect to the – essentially the asset side of the business, which is largely the New England generating facility, we’ve had a couple of very, very strong years there with $51 and $35 spark spread hedges in the winter season or essentially open going into 2017. The spark spreads are very low at the moment. We think we have more opportunity in the real time market. We do have some hedges in place that will ensure that for example our Tiverton facility stays online, but we’re mostly marking facing for the first quarter of 2017 in the facility, but I do remind everybody that the capacity values are essentially doubling as of June and that will add almost $30 million in new revenue, in the New England assets. So that will be kind of a mitigating factor for what’s currently kind of a weak electricity market.

And I think Judy it’s also fair to say that I mean you’re well positioned in the market because you have lots of pipeline capacity available to you and you have then new units are in good shape. The big question is what the weather is going to do and so Rob I think it’s very difficult for Judy to predict that. It certainly has been very mild and if that continues then earnings will be weak.

That’s fair. Thank you for the color.

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

Thanks. Good morning, guys. My first question is just a follow-up on Emera Energy. Are you able to quantify the cost of the plan 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 in total about $40 million in capital in the facility. If 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 megawatt for the facility and kind of improve the e-rate by 2% or 3%. So 2017 is a more modest capital profile. I can take that out and have someone send that to you.

Sure. Thank you. That’s helpful. And then I guess just one other kind of housekeeping question. I believe the release said, warmer than usual weather in Florida, so would you characterize the earnings from probably Emera Florida is maybe surpassing expectation this quarter or is that reasonable third quarter run rate going forward?

Yes, certainly. I don’t love by characterize necessarily is unusual, I mean in addition to the warmer weather they’ve experienced some low growth and they’ve been investing in the rate base for the $700 million in their power plant. It has been warmer than normal, but it has been for the last 24 months or so. So on a quarter-over-quarter basis, we’ve seen a little bit of pickup in electric sales, but it’s 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 soft.

We’re generally seeing 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 then on top of that we also are going to see the $110 million come in early in January as we bring the power project online. So we are going to continue to see some growth in the revenue line and that will affect our business as a whole.

That’s really helpful. Thank you very much. That’s all I had.

And your next question comes from the line of Ben Pham with BMO. Your line is now open.

Hi, thanks. Just don’t want to follow-up on the Caribbean question. Are you guys looking at earnings before ownership for ownership changes for ECI?

I’m sorry Ben you are referring from the Emera Caribbean piece on the ECI?

It’s more following up on the trying to reconcile your comment Caribbean growth, even if you strip out the SIF and even the restructuring cost last year, it implies negative earnings for Q4, but there should been some ownership changes, first ownership percentage changes, I’m just – are you guys adjusting for that drive outlook?

Yes, so on the quarter-over-quarter base or fourth quarter we’d expect to be relatively consistent obviously to adjust that we’d both – in instances where we have a larger ownership share this quarter than we would have year ago. So the overall business we would expect to perform the fourth quarter relatively consistent with the fourth quarter of last year recognizing that we do have a larger chunk of that, because some the ownership changes. Is that answers your question?

Yes.

Greg, it’s Scott. Maybe I can help a little bit.

Go ahead, Scott, please.

I think you can say that the outlook that we’ve referenced in the MD&A is potentially a little bit conservative. Obviously, there has been lot of changes and impact with self-insurance funds related transactions occurring over the last two quarters, both the second quarter and little bit more in the third and acquisition of the minority interest of Emera Caribbean and sort of acquiring sine if those dynamics, so at the same time obviously is relates to the impacts of Hurricane Matthew on load and in Grand Bahama as well. We’ve remain optimistic as to the net impacts of that not being [deteriorate] [ph] from our financial perspective. Obviously, it will have some near-term impacts in terms of load and light they 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 sort of look at the reconciliation table in the MD&A that set out the transaction issues around some insurance funds, you’ll see that underlying and some OM&G savings and cost savings and little bit of load growth we might give up a bit of that loan growth in the fourth quarter in Bahama's. But a large part of the OM&G savings will be same through after the – trough the fourth quarter and into 2017.

Okay. Thanks for that. And my second question is on the Maritime Link as you have towards in service beginning of 2018, can you walk through the regulatory filings you need to go through and there's some sort of compliance filing in that you need to prove that transmission line is useful for you to get that booked into rates?

Well, so first of all I think the largest piece of this is complete in that Nova Scotia Power has the revenue requirement for Maritime Link in their fuel component, and so that 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 outline the project itself, and so to describe the process of going forward et cetera. And so that will allow for a preliminary assessment, which will be active as of the - end of 2017 and first of 2018. And then after that there will ultimately be a closeout and the final costing review that will get done and it’s unclear at this point whether that will be a paper exercise or rather that will be an active hearing. We don’t know the answer that yet, but those are really the three steps, one of which is complete.

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

Yes, Ben, it's Greg. So obviously the Nova Scotia Power ROE range is the 875 to 925, and even with the buildup the deferrals, we anticipate because of the rate agreement, there may be periods of time like we’re in right now we’re actually over collecting on fuel. All of this said, we would fully expect that to 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, it’s helpful. Thanks everybody.

[Operator Instructions] Your next question comes from the line of Andrew Kuske with Credit Suisse. Your line is now open.

Good morning. Maybe just a question on the FX side of things and just how you’re thinking about FX in relation to future financing, and then also just the underlying valuation? And I have a question in part - if we look across the border, there’s clearly a rate dichotomy that is building in the U.S. market also above rate increases in the future, whereas in Canada, possible rate declines [indiscernible] on the overnight? How does that factor into your thought process on the asset ways that answers on the debt?

Andrew, it’s Greg. I mean 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 U.S. dollars, and so that provided I guess 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, 25 basis point changes in the U.S. are going to have much an effect on us. We do however, believe if interest rates rise in the U.S. and they stay low on Canada, could have an effect on the currency likely a weaker Canadian dollar, which would be beneficial to our performance business. But at this point in time, we're - short-term small changes in the fed rate for example is unlikely have much effect on business reports.

And Andrew, I think the only other thing that I would suggest is that over the next three, four, or five years, it’s our intention to pay down a fair bit of the debt that we have in the U.S. In fact our objective will be to retire people finance completely over that relative timeframe. And so we are working down that path as part of this whole thing.

Okay, very helpful. And then I guess maybe just a related question, if we are in environment where U.S. dollar strengthens versus CAD and then effectively more – and - wholesale on the Canadian dollar basis. How does that color your thoughts on for the next - dividend payout ratio and all of those things?

So Andrew, you’re breaking up a little bit on your question. But I think the question was if we have a weakening Canadian dollar, what is that due to our dividend payout ratio?

Yes, exactly.

Yes, so weaker Canadian dollar will likely mean that obviously our U.S. dollar earnings will get translated at a higher rate than otherwise would – which would push your earnings up all things being equal. That would cause our dividend payout ratio to go down under that scenario and of course the alternative would also be true.

I mean I guess Andrew, we really haven't formed a view of just how far - if we just assume for a moment that the U.S. dollar rises quite dramatically against the Canadian dollar or vice versa whichever way you might have say, I would say we haven’t formed a view as to whether that would change your payout ratio or not. At this point in and around the $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 probably reassess. But for now we don’t see a change in that as we said today.

Okay, very helpful. Thank you.

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

Good morning. Just coming back to Maritime Link, Labrador-Island Link, and I guess Muskrat Falls and just wondering with the federal loan guarantee top up that seems like a good sign, but there were some color about both Nova Scotia, Newfoundland, and Labrador remaining committed to the project. I’m just wondering if you could provide some color around that specifically if you think or if you know there’s going to be in service day commitments.

Well I think - I guess it’s back up a little bit. So our commitment hasn’t always is to get that Maritime Link and service in the 2017, end of 2017 timeframe. As we understand it, the transmission in Newfoundland is likely to be in the 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 that they expect a power plant to come on and that sees I think full power in the 2020 timeframe. And they haven’t changed that in fact the work that they’re doing would continue to confirm that that is a very valid timeline for the project and would continue to be something that we would expect to happen. So I mean 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 Atlantic Canada providing service into the New England market. And we continue to see the opportunity to do that. We continue to work hard on Atlantic Link and we’re seeing opportunities for us to actually continue to move that project forward. So when we think about how this is going, I think the timeline has now been defined and I believe that that timeline will be in that based on the way things are progressing.

Great. But in terms of the extra commitment that the feds are providing, do you – is that your understanding though that Nalcor will be held to 2020?

Yes, 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’ve seen that was in your presentation earlier, but just in terms of the real equity investment in 2017 has gone down quite a bit? Is that just shifting into 2018?

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

So with this specific reduction in the equity injection in 2017 is…?

Well, it’s simply about spend, Robert. So if the project is progressing, which it now is then the spend will be progressing as well.

Robert, we do see probably a little bit spending move primarily in the fourth quarter of 2017 into the first quarter of 2018.

Right. Okay, that’s great. And maybe just a last question here, I know you didn’t make a lot of detailed statements here around the federal carbon plan, and I know it’s - there’s a lot of details to be worked out. Just wondering, how you’re approaching this in terms of - is it a collaborative approach with Nova Scotia government at this point to try to explain all of the good things you’re doing in Nova Scotia around the renewable portfolio standard and try to get something offset here from what feds won on the carbon side.

Yes, I mean 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 would see us at 58% below 2005 by 2030. So in effect our business has a cap on carbon emissions and that cap is substantially below the levels that would be emitted based on the plan that Canada has 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 providence and we believe that firm position allows us to comply as we go forward. And we do think that the work that was done a number of years ago that came up with the equivalency approach that was innovative at that time and has produced real carbon reductions and we think we can continue to work in that kind of direction.

That’s great. Thank you Chris.

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

Thank you. I just have a few and just really one clean up 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 in aggregate for all the utilities. Maybe it's something we can take offline if you don’t have that number handy but just trying to gauge the impact it had 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 weather versus other changes especially when you look at a very, very short period of time. Certainly when we looked at it’s warm in the normal weather at Tampa Electric and certainly Barbados in particular experience the same thing. The alternative would have happened in our Northwestern 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’d be a little 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 peaking businesses and winter peaking businesses together. And so I think that seasonality is something we need to make sure and I think we’ll spend more time on that as we go forward so that people can understand that better.

Okay. Just specifically on Tampa Electric it looks like it had 1.6% customer growth but 6.9% electricity volume growth. So just on first appearance that looks like there was actually pretty good affect for the weather and pretty good affect on the quarter.

And there is actually a third piece as well Robert is, there is also some economic growth. So for example you might have more commercial customers come on that account for one customer but obviously impact growth as well. But certainly on a - there was no question that it was warm in the third quarter in the Tampa Electric service territory this year.

Okay. Thank you.

And your next question comes from the line of Jeremy Rosenfield with Industrial Alliance. Your line is now open.

Okay, thanks. Just a couple of maybe more strategic question. 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 trend mission sort of proposals and there is also that RFP.

Well, I mean I guess first and foremost I think there is 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 4 terawatt hours of energy it’s probably not enough to drive the scale of project that’s required actually bring that in a competitive fashion from an energy delivered perspective and so I just 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 larger enough to drive infrastructure and we think that is something that will happen. We would say that we were hopeful that the relatively small incremental transmission builds that were needed for the AC system might well fall into 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 we’ll see how it unfolds as Massachusetts takes its step into this area but certainly infrastructure is going to be required if clean energy is going to get into that market. And certainly in-market solutions are more expensive than the out-of-market solutions with infrastructure. So I mean we do know those two things and so - but at the end of the day it will depend on the various jurisdiction’s decision making relative to what they want to pay for clean energy.

All 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 TECO acquisition, how do you sort of think about additional regulated utility acquisitions that have to market opportunities versus let’s say generation capacity additions either a mix of contracted and merchants or just wholly contacted assets. What's the like for guess there - given the take there?

Well, I mean I guess first of all I don’t think we’ve changed our point of view that we’re mostly focused on organic growth of our businesses and the acquisitions are something that we’ll do from time to time when they make sense to us. But that we continue 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 certainly support for growth rate that we talked about and I guess a little bit back to Andrew's question from before the fundamental thing about dividend is that we’ve targeted 8% growth and we see our capital program is providing the capacity to do that. So that’s kind of the first piece. The other thing is as we are entering and have now entered both the Florida and New Mexico market, we do see lots of opportunity there. I mean certainly there is a desire in both markets to see more and more clean energy coming into the various end users. And so if you think about generation, our focus will be on solar generation in Florida to start and we see lots 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. And so when we put those two things together those are not in our $8 billion of growth that we see. So 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 an awful lot of our time, focus and also I think that type of growth is a whole lot more predictable and more incremental and therefore I would say easier to control over all.

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 [indiscernible].

Great. Okay, thank you for that additional color that’s it.

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

Okay, well thank you very much and I’d really like at this point to acknowledge all the hard work that went into delivering the results for this first quarter 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 with our new businesses. So 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.