Scott LaFleur - Manager, Investor Relations Chris Huskilson - President and CEO Scott Balfour - Executive Vice President and CFO Bob Hanf - President and CEO, Nova Scotia Power, Inc. Judy Steele - President and COO, Emera Energy, Inc.

Linda Ezergailis - TD Securities Matthew Akman - Scotiabank Ben Pham - BMO Capital Markets Andrew Kuske - Credit Suisse Robert Kwan - RBC Capital Markets Paul Lechem - CIBC

Good afternoon, ladies and gentlemen. And welcome to Emera Third Quarter 2015 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, Monday, November 16, 2015 at 12 o’clock Atlantic Standard Time. I would now like to turn the meeting over to your host for today’s call, Scott LaFleur, Manager, Investor Relations for Emera. Please go ahead, Mr. LaFleur.

Good afternoon, everyone, in Atlantic, Canada, and good morning for the rest of you. Thank you for joining us for our third quarter conference call. Joining me from Florida are Chris Huskilson, President and Chief Executive Officer; Scott Balfour, Executive Vice President and Chief Financial Officer; as well as other members of the management team here in Halifax. Emera's third quarter earnings release was distributed earlier via Newswire and the Financial Statements and Management Discussion and Analysis are available on our website at emera.com. This morning, Chris will begin with a corporate update and then Scott will review 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'll 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. These factors or assumptions are subject to inherent risks and uncertainties surrounding future expectations generally. 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 risks. A number of factors could cause actual results, performance or achievement to differ materially from the results discussed or implied in the forward-looking statement. In addition, please note that this conference call is being widely disseminated via live webcast. And now, I will turn things over to Chris.

Thank you, Scott, and good morning, everyone. Emera delivered Q3 adjusted net income of $23.3 million or $0.16 per share, compared to $49.9 million or $0.35 per share in the third quarter last year. Further adjusting net income to remove cost related to the pending TECO Energy acquisition, Emera’s adjusted net income was $43.4 million or $0.30 per share. The variance from last year is primarily related to timing at Nova Scotia Power where net income decreased $6 million to $4.9 million this quarter. We expect full year NSPI earnings to grow modestly compared to 2014. Overall, Emera is having a strong year, adjusted net income year-to-date was $242.9 million or $1.67 per share, in line with the same period last year and results are comparatively stronger if TECO costs are excluded. To be clear, these financial results in Emera underlying business remain on track with the earnings growth expectation upon which we established our $1.90 dividend this year and our dividend growth target of 8% per year through 2019. Scott Balfour, will take you through the details of the quarter later in his remarks, but first I'd like to touch on some of the key strategic and operational milestones Emera reached this quarter. I will start with our recently announced acquisition of TECO Energy. On September 4th we announced a definitive agreement to acquire TECO Energy for an aggregate purchase price of US$10.4 billion, including consolidation of approximately US$3.9 billion of debt. Emera has prepared for utility transaction for some time and we found our ideal match in TECO. Our patience and disciplined investment criteria resulted in a transaction that is significantly accretive to EPS and cash flow for Emera’s shareholders and one that advances our strategic objective. The TECO Energy acquisition is expected to be 5% accretive to our EPS in the first full year, growing to more than 10% by the third full year. TECO Energy is a purely regulated utility and pro forma, the acquisition brings our regulated earnings to approximately 84% of total earnings. The acquisition provides additional support to our 8% dividend growth target through 2019 and positions us to potentially extend that growth target beyond 2019. It expands our regulatory platform into robust economic environments and establishes Emera with two strong natural gas distribution platforms, an objective we've had for some time. The transaction remains on track to close in mid-2016. We filed our application with the FERC on October 5th and our submission with New Mexico Commissions on October the 19th. The New Mexico hearing examiner has now been appointed and scheduling conference is expected this month. Finally, TECO shareholders will meet to vote on the transaction on December the 3rd. Beyond the TECO Energy acquisition, Emera’s business continues to perform with a number of important initiatives, beginning with the Maritime Link, which continues to progress as planned, on schedule and within budget. Construction is well underway and foundation preparation has begun at the converter stations sites in Newfoundland and Nova Scotia. Initial shipments from the fabricator of the steel towers have been received and the manufacturing of the submarine cables is moving along as planned in Japan. Overall, risk continues to decrease as the project progresses. We have a high degree of confidence that the cost to complete the project will remain within budget through to completion. At Nova Scotia Power, the focus remains on managing costs to ensure stable, predictable and affordable rates to our customers. We continue to work positively and productively with our regulator, stakeholders and the Government of Nova Scotia. Following a 12-onth public consultation process, the Government of Nova Scotia released their electricity review document on Monday, November the 9th. The document focused on the need for rates stability in the province and the implementation of performance standards, both of which we support. On Tuesday, Nova Scotia Power announced there will be no general rate application for 2016 and the current base cost of fuel application before the regulator should result in a small decrease for most customer classes. NSPI has been working hard to manage cost and is confident it’s going to achieve rate stability through the 2017 to 2019 period. In New England, utilities and state agencies in Massachusetts, Connecticut and Rhode Island filed a procurement request for clean energy last week. This request for proposals, a draft of which has been public in February recently received approval from utility regulators. Bidders have 75 days to respond and therefore, a response in late January is expected. As we indicated last quarter, the three states are now seeking at least 5.1 terawatt hours by long-term contracts of up to 20 years. Through power purchase agreement for energy or power purchase agreements for energy bundled together with associated transmission. Emera intend to respond to this RFP. Emera remain in partnership with Central Maine Power will propose upgrades to the existing AC transmission system to relieve congestion that would enable additional energy from wind farms in Northern Maine and additional flow of clean energy from Canada. These system upgrades will be open to all energy bidders. As well, Emera in partnership with others is actually working on three alternative DC transmission projects that will facilitate the collection and transmission of clean renewable energy resources from Maine and Canada into New England. At least one of these DC projects, the new Atlantic Towing will be bid into this RFP. Massachusetts is also proceeding with discussion of a bill proposed by Governor Baker that would cause a procurement for an additional 18 terawatt hours of Canadian hydropower or wind farm with Canadian hydropower. Emera intends to bid should another RFP result. Moving to the Caribbean, we announced earlier today an offer to purchase the shares held by minority shareholders in Emera Caribbean Incorporated. Emera Caribbean is a holding company for Barbados Light & Power, DOMLEC and our minority ownership in LUCELEC. Emera currently owns approximately 80.7% of Emera Caribbean. Our offer of $33.30 per bidders in cash or Emera depository receipts represents 30% premium to the current share price for ECI. An application has been filed to list the depository receipts on the Barbados Stock Exchange, which will provide Barbadians the opportunity to invest in Emera’s growth and success. The offer has been unanimously approved by the ECI Board of Directors and they have approved supporting agreement for that transaction. Our largest shareholder outside of Emera, Barbados National Insurance Board, along with officers and directors of ECI, who are also shareholders have entered into a lockup agreement, under which they have agreed to tender their shares to the offer. Collectively, these shareholders represent approximately 69% of the ECI shares not held by Emera. ECI shares are thinly traded on the Barbados Stock Exchange and the offer provides value and liquidity to current ECI shareholders. It also streamlines the ownership structure for us. We expect the offer to be completed in December of 2015. The 12 megawatt utility scale solar plant in Barbados is progressing well. The solar plant will have 46,000 solar panels and is expected to be completed by August of next year. With that, I'll turn things over to Scott who will give you more detailed update of the financial results for the quarter. Scott?

Thank you, Chris and good morning everyone. Our third quarter results were released earlier today and are now on the Emera website. You’ll notice that this quarter Emera’s results were affected by a number of factors in respect of the TECO Energy acquisition, which will continue for the next few quarters. Accordingly we've tried to provide more clarity within our consolidated financial highlights table as to this and other items affecting earnings for the period. We’ll continue to highlight these items moving forward. We’re cutting through all these notable impacts in the quarter. Emera’s underlying business is performing well and remains on track to earnings growth expectations that support our 8% annual dividend growth target through 2019. Emera’s consolidated net income for 2015 was $35 million or $0.24 per share, compared to $28.2 million or $0.20 per share in the third quarter of last year. When third quarter results are normalized from mark-to-market losses, adjusted net income was $23.3 million, or $0.16 per share, compared to $49.9 million, or $0.35 per share last year. EPS for the quarter was $0.30 when further excluding the impact of costs related to the TECO Energy acquisition, with the decrease from last year’s $0.35, a result of the timing of regulatory deferrals at Nova Scotia Power. As Chris mentioned earlier, we expect NSPI's full year earnings to grow modestly compared to that of 2014. Before I discuss our segmented results, I'd like to give an update on our financing for the TECO acquisition. The financing is expected to be structured with between US$800 million and US$1.2 billion of preferred equity and between US$3.4 billion and US$3.8 billion in debt and between US$1.7 billion to US$2.1 billion in common equity or internally generated funds. In early September, we successfully raised $2.185 billion Canadian in convertible debenture financing that will convert to a mirror common shares at closing. This financing is expected to address the common equity needs for the TECO Energy acquisition. We’ll be issuing the preferred equity and debt financing activity closer to acquisition in mid 2016. It’s worthy to note that with the proceeds of the first installment of the convertible debenture now held directly in U.S. dollar treasuries and a currency exchange forward contracts now in place for the second installment that our currency risk has now been eliminated for the full $2.185 billion at a rate of approximately $1.30. This together with the intentions of a significant portion of the preferred share and debt financing to be raised directly in U.S. dollars means we have approximately 85% of the US$6.5 billion required to close the deal actually or effectively hedged, removing the majority of the foreign exchange currency risk between now and deal closing. Turning now to our segmented results, Nova Scotia Power’s net income decreased to $4.9 million in the third quarter of 2015. As mentioned earlier, the decrease is primarily due to timing with NSPI’s full year earnings still expected to grow modestly compared to that of 2014. Emera Maine contributed $14.7 million to consolidated net income in the third quarter of 2015, an increase of $1.4 million compared to third quarter last year. The higher net income was primarily due to the impact of a stronger U.S. dollar. Emera Caribbean contributed $13.6 million to consolidated net income, an increase of $5.4 million compared to $8.2 million for the same period last year. The increase was primarily due to a decrease in OM&G at Grand Bahamas Power, reduced maintenance and payroll cost of Barbados light and power as well as the impact of strengthening foreign currencies. The Pipeline segment contributed adjusted net income of $10.3 million in third quarter 2015, compared to $8.7 million in the same quarter last year. The increase of $1.6 million was primarily due to lower interest expense, increased transmission revenue from Maritimes and Northeast Pipe and the impact of a stronger U.S. dollar. Emera Energy delivered adjusted net income of $14.9 million in the third quarter compared to $10.7 million in the same quarter last year. The $4.2 million increase was primarily due to increased electricity sales and lower income tax expense. The increased electricity sales were primarily due to an outage -- the impact of an outage, an upgrade of the Bridgeport Energy facility in the same period last year. Our Corporate and Other segment posted a $35.1 million loss in the third quarter of 2015 compared to a loss of $1.9 million in the same period a year ago. The variance is primarily due to $29.2 million in items affecting earnings quarter-over-quarter attributable to $20.1 million in after-tax related costs from the pending acquisition of TECO Energy, combined with the $9.1 million after-tax gain on the dilution of Algonquin in the same period of last year. That's all from my financial overview. And now I'll be happy to take your questions.

[Operator Instructions] And our first question is from Linda Ezergailis with TD Securities. Your line is open.

Thank you. Just a question about the Caribbean. I realize there's some simplification associated with the announcement this morning. But are there any possibilities of further consolidation of your partial investments in the region?

So Linda, it’s Chris. Thank you for your question. I think it’s something that we’ll look at over time. For the time being, we’re focused on getting your ECI completely consolidated and we also like the opportunity of being able to put depository receipts on the Barbados Exchange and create that opportunity for customer base there but it’s something we’ll look at over time.

Okay. Thank you. And just a follow-up question on Emera Energy. How might we think of your Q4 trading results? Is there any -- looks like October was mild but are there any potential infrastructure constraints of maintenance happening or how can we think of what Q4 might hold for your trading business?

So Linda, it's Judy. So Q4, November, December tend to be strong months in the business obviously but it's largely weather dependent. I think it's fair to say that any major pipe maintenance -- I'm not going to think people try to get that over with before the winter. So that's not necessarily a factor. So it's really kind of a weather story in these months. The only other guidance I can really say is that we have said that the business should be able to deliver net income of somewhere between $15 million and $30 million. And if everything goes in November and December as we think, we'll be at the high range of that amount.

Great. Thank you. And I'll jump back in the queue.

Thanks Linda.

The next question is from Matthew Akman with Scotiabank. Your line is open.

Hi. For Scott, first, I just wanted to clarify and just to confirm that the DSM expenditures probably impacted and dampened the quarter a little bit at NSPI but are not expected to have a full year impact. Is that the case, Scott?

Yeah. So DSM isn’t constant. Nova Scotia Power being pursuant to agreement in place are being deferred. So it's having an impact on cash but not earnings. It's really the impact of contributions of non-fuel revenues towards the fuel adjustment mechanism and the timing of the accruals related to that, that's impacting the quarter-over-quarter variance in NSPI this year.

Okay. Just it looked like it was an OM&G more than anything which I thought was DSM related?

So that’s same deferral is flowing through. I’m trying to think now whether -- so that same deferral is flowing through OM&G. So it is a net deferral account but it’s effectively in the transfer of non-fuel related items into fuel related items at the end of the year.

Okay. Separately the refinancing of Bear Swamp is obviously positive. You guys pulled a bunch of money out. But I'm just wondering on the other side of it, if there’s anything Scott, you can say about the earnings impact of that on an ongoing business for Bear Swamp earnings?

Yeah. I mean, really just the impact of higher interest expense now at Bear Swamp that will reduce after-tax income of Bear Swamp and therefore 50% portion of it.

Okay. Got it.

So it will have an impact on earnings with benefit of the distribution of cash to both partners.

But again Matthew that’s against rising capacity payments and so there is certainly an offset there.

Okay. Thanks for the reminder. Thanks. Those are my questions guys.

Okay. Thanks.

Your next question is from Ben Pham with BMO Capital Markets. Your line is open.

Okay. Thanks. Just wanted to clarify the -- just catch-up on the DC transmission line. Are you planning to bid in? Did you say that you’re planning to bid in one of the link or you are not sure which one you are going to bid in yet?

What I said was that for sure, Atlantic Link, we will bid in. Whether the other ones do or not, will really depend on whether there are proponents suppliers that want to select them. But in the case of Atlantic Link, we believe that it is quite flexible from a scaling perspective and therefore, we want to put it forward. And as I said the other ones may bid in as well but this one, we will for sure. I think it's a new project and we certainly believe that it actually is extremely well positioned both to draw energy from Northern Maine, as well as from New Brunswick, as well as from Nova Scotia and Labrador. So, when you look at its potential to balance the region into the Boston market, we think it's a very, very well positioned project.

Okay. And you own 100% percent of that, Chris, is that the ownership?

Yeah. So that’s our current positioning on it. But we expect that we will ultimately select delivery and partner as well but for now that’s the position.

Okay. And can you remind me how, just with the Nova Scotia Power, you talked about that you already, not having a filing in ’16, but can you remind me how the Maritime Link filings work just over the next couple years and just with the new policy coming out? So does that impact us out as the rates kick in overall?

Well, certainly, our intention would be to file the Maritime Link case in either ‘17 or early ’18, that kind of timeframe. But we expect that Nova Scotia Power, as it looks at its three year fuel requirements, we will bring in what they currently know about Maritime Link. And so when -- Nova Scotia Power has been talking about what effect they believe that that will have and that would certainly include the Maritime Link. So that’s the way they are thinking about it. And Bob’s on the line as well. He may want to add something to that?

Yes. So, I would, Chris. Thanks Ben. So the plan would be to file the fuel side of the application to facilitate rate stability for ’17 and ’19, inclusive of the anticipated cost related to Maritime Link. So it’s included.

Okay. You guys are really hedging out the fuel costs next couple of years, right?

That's one of the things that I think will allow us to be more certain about where fuel is going, is to increase the fuel hedging component. And as well, I mean, you have to remember that by the time we hit that timeframe with Maritime Link on, we will have upwards of 35% to 55% of the energy that can come from, essentially fixed cost components. And so the volatility of fuel for Nova Scotia Power will go down quite a lot and as the Maritime Link comes on and that's one of the benefits that we've always known we would see from that investment. And again, Bob may want to add to that.

Yeah. I think it’s a very unique and positive position for customers in Nova Scotia to have rate stability and it’s because of that portfolio and that shift. So it’s very positive as it put us clearly.

Okay. Got it. And thanks for taking my questions.

Thanks, Ben.

The next question is from Andrew Kuske with Credit Suisse. Your line is open.

I guess my questions for Chris. And it’s been a little bit more than two months since you announced the TECO deal. And if you could just give us maybe some insights to your conversations you’ve had with regulators and other pertinent parties in both New Mexico and also, Florida?

Yes, Andrew. And what we've been working hard to do is to make sure that we keep everybody involved, stakeholders across both of those states involved and aware of what we are up to. The transparency of this transaction, we think is critical to it success. So that’s been an important thing. I mean generally speaking, the transaction will not have an effect on rates for customers. And therefore -- and we will be adopting all of the approaches, stipulations and so on that TECO Energy adopted, say for instance in New Mexico. But also there are rate settlements in place in Florida today and all those things continue to remain intact. And so there is a lot of stability, I believe for customers from this transaction. We've had specific meetings with the interveners, certainly both the staff at New Mexico and also the Attorney General’s, Consumer Advocacy Group. We’ve certainly met with those various stakeholders. And we are working hard to ensure that we are able to at least propose a settlement in this case. And in fact, I misspoke in my remarks. The scheduling conference is now scheduled for December, the 10th. And so when you put all those things together, we believe that we are progressing well and we will continue to be available to stakeholders as these moves forward.

That’s very helpful. And then my second question somewhat related, is to Scott just on FX exposure. And as you see that today and then just with the perspective closing of TECO, let’s just say midyear, next year, how you think about your FX exposure from now till then and then beyond?

Yes. So, I think, Andrew, we mentioned briefly in the remarks. We’ve now effectively hedged all of the $2.185 billion Canadian equity that’s in place by way of taking the proceeds from the first installment and they are now held in directly in U.S. dollar treasuries. And then the second installment, we put forwards in place. So the average rate at which we've hedged that out right now is a $1.30. So in essence, providing some mitigation against the dollar that's -- Canadian dollar that’s further depreciated since that time, so that's good. And with the balance of -- most of the debt in preferred/hybrid financing in our plan and looking at directly raising as U.S. dollar-based activity really puts in place over 85% of that $6.5 billion is now hedged. So, we are feeling reasonably good about that, not to suggest that we won’t look to hedge out little bit more. But that 85% number, we are feeling reasonably confident about, that gives us some certainty. It will add some accounting, some mark-to-market type volatility for us between now and closing. But economically, we’ve got -- I think we've done the right thing in terms of putting that hedge in place. And then of course as we think about the currency related exposure to the transaction. Really, the devaluation of the Canadian dollar between now and close and then appreciation of the Canadian dollar after close and too it's really part of the debt strategy that will now provide a meaningful part of our risk mitigation opportunity, as it relates to currencies to the more U.S. dollar debt from a balance sheet and economic perspective. But also from an earnings and cash flow perspective does help to mitigate that risk. And even thinking about today, we have more than, 50% of our operations are non-Canadian, but most of our debt is Canadian. So looking at things like reconstituting some of our existing debt through derivative type product in order to think about perhaps moving more of our existing debt to U.S. dollar, pay will incrementally help to mitigate that risk post closing as well. So those are all things line of sight for us today.

That’s very helpful. Thank you.

Thanks, Andrew.

The next question is from Robert Kwan with RBC Capital Markets. Your line is open.

Good morning. Taking just back to some of the transmission projects and Chris, I don’t know, can you talk about how Atlantic Link, are the other two projects NEL and the third, I don’t know if it’s Maine Green or something else? But can you just talk about how the three kind of interplay do you see, even if you bid all three in, is it almost either, or do you think that there's merits to maybe have multiple projects moving forward?

Yeah. I mean, the reason that there are three, Robert, first and foremost is because they functionally, actually worked to different areas within the region. So when it comes to the NEL, the original project, that was primarily about just simply increasing the transfer capacity in the lower part of the State of Maine and through New Hampshire. And so that project continues to be valuable for that purpose. But it doesn't get at some of the more northerly projects that will be required in order to get some new clean energy available to a project like the Green Line, which is other one, that's essentially starting in the State of Maine. That gets over to further north and is able to consolidate some more of that energy and then goes subsea as a secondary approach. But then if you look at the Atlantic Link, what it does is, it is able to gather energy from the much broader region. And we believe it is well-positioned to collect the most energy and that's really the issue for this first RFP, is most of these projects are much larger than 5 terawatt hours. And so to be able to make them economic is a bit of a challenge and that's why the Atlantic Link we believe will be closest to economic, although it will still be challenged at 5 terawatt hours. What these projects are all really focused on is the next step, which I referred to in my remarks, related to the work that the government, Baker’s doing to try to increase the clean energy component and so if you take the two amounts together, you could see as much as 23 terawatt hours being required. That will require at least two DC projects to get that to happen. And so when we think about this RFP, we are mostly focused on the AC upgrades in the State of Maine. That by itself will be several $100 million of upgrade. I think something in the order of $300 million to $400 million for Emera Maine. And those will, I believe be the lowest cost projects that can actually gather the wins that likely will be bid and also increase the capacity out of Canada. So, when you put all that together, we figure that that’s probably the most competitive opportunity. But then for the larger initiative, when that comes together it’s going to be multiple DC projects.

Okay. And I guess given you’ve got a hand in a few different projects, are you going to be going out to customers separately? Or do you think there's a possibility that you can somehow integrate the offering to allow potential customers to kind of offer into either or giving them a choice depending which ones go forward?

Well, to be clear, all of these projects will be open to any energy providers that want it. And so I mean, that's a little bit -- it’s a little bit complicated because the transmission project can’t be bid in by itself. It can only be bid in conjunction with suppliers and so they all have to be open. But I guess fundamentally, we would say that certainly the work that the Central Maine Power and Emera Maine are doing, I think that will be able to be bid in support of the number of potential projects. And we also think that the Atlantic Link will also be able to be bid in support of some potential projects.

Okay. Just moving to Nova Scotia and as an integrated utility, you’ve don’t a good job kind of disaggregating the delivery charge and then isolating fuel with the FAM. Just wondering as you go forward here and specifically, the commentary or the discussion around Maritime Link, can you give us some color as to how you see, say the industrial user group, the consumer advocate, government and so UARB. How much of the understanding as rates come together just the way you've negotiated the agreement with all the upfront power and is that providing a significant benefit to drive down the fuel. How that's been thought of in terms of rate stability?

Well, I mean I think first and foremost and also would ask Bob to chime in. But I think first and foremost that additional power upfront is -- what’s its doing really is it’s helping offset the early-stage cost. Because as you know, these projects are always most expensive the first day because they’re amortized capital and every day thereafter they get lower -- lower cost. And so we've been able to bring some additional power in to do that. And on top of that as well we've also been able to negotiate with Nalcor and in aid of the approach that UARB was looking for some incremental energy as well. And that can be upwards of 1.8 terawatt hours on top of the -- essentially terawatt hours that will come with the project. And so when you put all that together, it gives Nova Scotia tremendous flexibility and a very greater ability to stabilize cost and that’s really to the question, that’s really what the focus has been. Over the years, we’ve seen a lot of volatility on the high carbon fuel side. And so now this will provide the utility the ability to stabilize and to select how much of the clean energy they wanted at any given time. And Bob, do you want to talk about the stakeholder approach?

Sure. Chris, I’m Robert. So that the year-long review with the government on distributor view, we were certainly involved deeply and traveled around the province. And the message from all of our stakeholders and all our customers was really about reliability, predictability and stability in race. And so we’re encouraged by the report that was issued last week by the government and it's really it's really about policy changes that enable rate stability. And Chris has described the portfolio in a fact that renewable energy is reducing our reliance on cost of fuels. So historically, I think we’re just in a terrific position to work with our customers and provide the rate stability that they need and require.

Okay. Just to be clear though I guess, transition from a bit of a period where you certainly don’t think to help stabilize fuel costs but there still was some volatility where historically you've kind of had very stable delivery charges to one as you go forward here where its going to be more stabilizing the total rate like it -- that understanding the delivery charge is likely to increase faster but offset by good reduction both in the amount and the volatility in fuel charge?

So in ‘15 there was no increase and ’16 there will be no increase. And in our target around the fuel side is less than inflation. So that is our view going forward.

Yeah. And I -- and so, Robert, I think it's not the right assumption to assume that the delivery charges will go up. We would say that that we've done a good job of getting managing cost around the delivery side. And so we actually believe that that we will actually have a lot of stability there as well.

Okay. That’s great. Thanks very much.

Okay. Thank you.

[Operator Instructions] Your next question is from Paul Lechem with CIBC. Your line is open.

Thank you. Good morning.

Good morning.

As you move towards closing of TECO, I’m just wondering is there any need or any opportunity to expand Emera Energy business down there and either the gas or the electric trading side of the business?

Well, certainly, Paul, when we look at doing business in new service territories and new regions, we certainly will look at our entire offering in the region. And so I would say, it's too early to say whether or not we’re going to be doing business in that area with Emera Energy. But we certainly would look now at those regions and see whether or not there's something where they can bring value to customers and certainly, if they can’t then we would look to do that. I mean some of the early stage thinking that we have right now would be that that we've been working on getting gas into Caribbean region for some time. Peoples gas is very well-positioned to do that. In fact, they’re very focused on compressed natural gas today. We just achieved an export permit. We would think that some of that working together might work well. And as you asked and the next step is whether any of our other businesses would be able to achieve some good linkages and adjacencies with the businesses in total.

Hey. That's helpful. Thanks. On Algonquin there is -- you guys are -- I understand you are updating strategic investment agreement. Can you give us any thoughts there about where this is does the signal potentially move towards the long-term exit of that investment.

So the update in the agreement is really just maturing it to our current situation. And so we've been under share restrictions for quite a number of years there. We believed and so does the company that there's no need to have those share restrictions anymore and so those will be eliminated. But beyond that we’ll also reinforce and re-describe the areas where we will work together and we continue to see opportunities to do that. So that continues to be the way we look at that business.

Okay. Thank, Chris.

Thank you.

And it appears that we have no further questions at this time. We’ll turn the call back over to our presenters.

Okay. Well, certainly, thank you very much for taking the time this morning and to -- and your participation in the call and we hope you have great rest of the day. Thanks a lot.

Ladies and gentlemen, this concludes today’s conference call. You may now disconnect.