Scott LaFleur - Manager, Investor Relations Chris Huskilson - President and CEO Scott Balfour - Executive Vice President and CFO Judy Steele - President and COO

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

Good morning. My name is Mechel, and I will be your conference operator today. At this time, I would like to welcome everyone to the Emera Fourth Quarter 2014 Results Conference Call. All lines have been placed on mute to prevent any background noise. As a reminder, today’s call is being recorded today, Monday, February 9, 2015 at 10:30 a.m. Atlantic Time. I would now like to turn the call over to Scott LaFleur, Manager, Investor Relations. Please go ahead, Mr. LaFleur.

Thank you. Good morning, everyone. And thank you for joining us for our fourth quarter and year end conference call this morning. Joining me from Emera are Chris Huskilson, President and Chief Executive Officer; Scott Balfour, Executive Vice President and Chief Financial Officer, and other members of the management team. Emera’s fourth quarter earnings release was distributed earlier via Newswire and the financial statements and management’s discussion and analysis are available at our -- on our website at emera.com. This morning, Chris will begin with the corporate update and then Scott will review the financial results in detail. We expect the presentation segment to last about 10 minutes, after which we will be happy to take questions from analysts. Please note, that all amounts are in Canadian dollars with the exception of Emera Maine and Emera Caribbean, where segment results are reported in U.S. dollars. I will take a moment to remind you that this conference call may contain forward-looking information, which involves certain assumptions and known and unknown risks and uncertainties that may cause actual results to be materially different from those that are expressed or implied by the comments. Those risks include, but are not limited to weather, commodity prices, interest rates, foreign exchange, regulatory requirements, and general economic conditions. In addition, please note that this conference is being widely disseminated via live webcast. And now, I will turn things over to Chris.

Thank you, Scott, and good morning, everyone. Adjusted net income for 2014 was $319.2 million or $2.23 per share, compared to $259.4 million or $1.96 per share in 2013. This represents the 13.8% growth in adjusted earnings per share year-over-year. Cash flow from operations for 2014 increased 35.1% to $762.5 million. These growing cash flows are allowing Emera to finance an increasing amount of our capital plan from internal sources. Increasing cash flows also provide coverage for our growing dividend. Last September we established a five-year growth -- dividend growth target of 6% per year. The full year results announced today, the positive outlook of our gas generation facilities in New England and the recent sale of our interest in the Northeast Wind Joint Venture, led the Board to approve a further increase of $0.05 per year, bringing our annualized dividend rate to $1.60 per year. This increase will take effect from the regularly scheduled payment in May of 2015, and together with the $0.10 increase announced last September, represents a total of 10.3% increase over the $1.45 dividend rate established in late 2013. The $0.05 is incremental to our 6% target. In keeping with our normal practice, we will address the dividend rate again this September. This increase to the dividend has not changed our dividend approach, but rather reinforces that we are committed to both growth of our dividend and our payout ratio with the range of 70% to 75% of earnings. We will continue to address our dividend regularly in September as we have now for many years. As well, at year end, when we report results, we will ensure that our payout ratio is generally in line with our forward view of the business at that time. Scott Balfour, will take you through the quarter and year end in his remarks, as well as recurrent financing plan to our capital program. 2014 was an outstanding year for Emera, where we both strengthened our balance sheet and move the business forward. One of the ways our balance sheet was strengthened was the divestiture of Northeast Wind Partners. Near-term this was our worst performing asset and although, there were some strategic values to these assets, we believe that value is being replaced by our current concentration in the ISO-New England market. Maritime Link continues to progress on schedule and on budget. In 2014, we laid a strong foundational platform positioning us well for the success of the project. Last April we successfully raised $1.3 billion for the project with the backing of the Federal loan guarantee at the coupon rate of 3.5%. Over a $1 billion in contract have been lockdown and we have over 90% of the contract secured and/or in-hand. Two of the three major contracts have been awarded to world-class suppliers, with the third major contract for transmission construction be awarded shortly. With the vast majority of contracts and costs lockdown, we are gaining even more confidence in the construction budget for this project. Looking to work plan for 2015, we have moved into manufacturing and construction activities. The manufacturing of one of the subsea cables begin soon and by midyear steel for the transition towers will be -- being delivered. Civil construction work is underway at the converter stations sites in Newfoundland and Nova Scotia, and the project team is on the ground with contractors at all project sites. QA inspectors are working with manufacturing facilities and work is progressing well. In Nova Scotia, the focus remains on managing costs to provide affordable, stable and predictable rates for our customers. We continue to work positively and productively with our regulator, stakeholders and the government of Nova Scotia. Nova Scotia Power reached the settlement with stakeholders providing for the collection of the fuel adjustment mechanism balance in 2015. This combined with removal of the efficiency Nova Scotia charge from bills in 2015 means there will be no rate increase for our residential customers. Our current projection will have our total deferrals balance below $100 million by year end, a major step forward from just a few years ago. Gas supply to the Maritimes continues to be a strategic focus for Emera. Stable gas and Deep Panuke are both declining resources and are estimated to be largely diminished by the end of the decade. Shale gas fracking is now under a moratorium in Nova Scotia and New Brunswick, and the potential for more offshore gas resource is unknown. Emera is evaluating the various current and perspective natural gas supply options and expects to complete that evaluation by the end of the year. Key components of the evaluation is the ongoing work of the New England States committee on electricity and the impact -- its actions may have on market design and proposed pipeline infrastructure investments in New England affecting supply to Atlantic Canada. At Emera Energy, our New England gas generation portfolio performed as we expected in 2014 and we are looking to continue to improve in 2015. Some highlights include the signing of the 20-year service agreement with Siemens for maintenance at Bridgeport Energy and the successful completion of our major outage and upgraded Bridgeport that added 22 megawatts of capacity and improved efficiency by more than 2%. In 2015, we will complete an upgrade of the second unit at Bridgeport, which we expect will add another 19 megawatts to the plant’s capacity and further efficiency gains. We are also planning to add an 11-megawatt upgrade to our Tiverton facility. There is more positive news for Emera’s New England generation last week. The results of ISO-New England latest forward capacity auction, FCA 9, which covers the period from June 2018 to May 2019 set a clearing price for the majority of the region at just over $9.55 per kilowatt month for the 34,000 megawatts the system requires. Our Tiverton facility is located in a zone deemed to have inadequate supply and we will receive a premium capacity payment of just over $11 and the planned 11-megawatt upgrade at that facility will receive almost $18 per kilowatt month for seven years. The independent system operator implemented a new approach to setting capacity prices, which in our view as resulted in capacity values much better reflecting the true cost of building new generation in the region. This is an encouraging signal for investment. All told, these auctions results are expected to provide approximately $117 million in revenue over the 2018, 2019 timeframe, approximately $38 million over what we expected from the facilities for the previous 12-month auction period. In New England State, the winter hasn’t been as cold last year and the pricing pressures have decreased. There are LNG imports to the region that have helped with natural gas supply and in turn, electricity pricing pressures, but the need for a supply of clean energy and a decrease in GHG emissions are still significant. The requirement for procurement of clean energy that could include imports of either wind or hydro has not changed. The New England State’s committee on electricity is still active and working on regional solutions to the electricity issues. We’re following the steps the legislators will take to address these issues and are making sure we understand the possibilities and the timing. Recently the Cape Wind offshore project, its PTA was cancelled, reducing the options that New England has to make their clean energy requirements. We will continue working with the governments to demonstrate we can assist in leading long-term requirements for clean energy. In the near-term, our MoU with Central Maine Power seeks to address the AC transmission congestion issues in the region affecting the development of renewable energy. Our first step in the process was the recent announcement of an agreement with EDPR to use a portion of the transmission corridor known as the Bridal Path for their wind project. The Number Nine Wind project is a 250-megawatt project currently under development, west of Bridgewater, Maine. The project is contracted with electric utilities in Connecticut and this right away will help EDPR get the clean energy to market. We will continue to work with Central Maine Power on transmission opportunities and are optimistic that additional opportunities will come to fruition soon. Moving to Caribbean, our plans are progressing through the utility-scale solar plant in Barbados. We’ve start clearing lands and have developed our community engagement plan. Our focus remains on reducing generation alternatives, including lower emissions, gas and renewables with the focus on affordability and fuel cost stability. Plans for 2015 in the Caribbean includes advanced metering infrastructure pilot projects in Barbados and Grand Bahamas. In Grand Bahamas, we’re evaluating a utility-scale solar project as well and production of biofuels will begin in Q4. We’re also exploring a geothermal project in St. Vincent and work on a CNG project from Florida to the Grand Bahamas is moving ahead with environmental assessment having them submitted and soon it will be available for public comments. Our decision on the EA is expected in Q3 of this year. 2014 has been a year of significant progress for Emera and the outlook for 2015 remains strong. With that, I’ll turn things over to Scott to give you more detailed financial update. Scott?

Thank you, Chris, and good morning everyone. Our fourth quarter and year-end results were released on Friday and are now on the Emera website. Emera’s consolidated net income in 2014 was $406.7 million or $2.84 per share compared to $217.5 million or $1.64 per share in 2013. When current year results are normalized for $87.5 million of mark-to-market gains, 2014 net income was $309.2 million or $2.23 per share. Mark-to-market losses were $41.9 million in 2013. So when normalized, adjusted net income in the prior was $259.4 million or $1.96 per share, representing a 23.1% growth in adjusted net income and 13.8% growth in earnings per share year-over-year. The increase is primarily due to strong results from the marketing and trading operation in the first quarter of 2014 and the Q4 2013 acquisition of our New England gas plants. Cash flow from operations in 2014 increased 35.1% to $762.5 million. This increase was also primarily due to the positive impacts of our trading and marketing and New England gas plants. As Chris mentioned earlier, the increase in cash flows will allow Emera to fund a larger portion of its capital program through internal sources. The recent sale of our interest in the Northeast Wind joint venture also provides funds to finance our capital needs. The sale of Northeast Wind Partners for US$223.3 million has a much more significant effect than just the cash proceeds. Our 2015 plans were to spend an additional US$150 million during the year on new projects. Unlike regulated projects, early year accounting earnings accretion is always challenged for these types of projects. Therefore not deploying this capital is in effect accretive to our business. We essentially now have another $375 million to deploy in projects like the Maritime Link and Labrador Island Link which are immediately accretive to the business. Emera’s current capital expenditure plan for the period from 2015 through 2017 totals $3.45 billion. We’ll finance our capital plan for multiple sources including debt, preferred shares, internally generated cash and the sale of Northeast Wind. Our common equity needs to finance this plan are minimal, currently projected to be in the range of 0 to $250 million through 2017. Turning now to our segmented results, Nova Scotia Power contributed $124.9 million to consolidated net income in 2014 compared to $126.0 million in the 2013. The decrease in 2014 was primarily due to the financial impact from the 2012 and 2013 FAM audit disallowance, announced last month. Emera Maine contributed $42.4 million to consolidated net income in the 2014 compared to $38.4 million in 2013. The higher net income was primarily from the positive impact of the stronger U.S. dollar with the positive impacts of higher revenues from distribution and transmission offset by an additional provision taken in the quarter in relation to FERC’s review of New England transmission return on equity levels. Emera Maine has accrued a provision totaling $5.9 million after tax as of December 31, 2014 for the complaints filed with FERC, of which $3.0 million after tax was accrued in the fourth quarter. Emera Caribbean contributed $28.7 million to consolidated net income in 2014 compared to $33.4 million in the 2013. The lower net income was primarily due to a gain recorded in 2013 from the acquisition of a controlling interest in Domlec as well as the reduced investment income from Emera Caribbean’s incorporated self-insurance asset in 2014. The primary reason for the reduced self-insurance fund income in 2014 was a positive adjustment made in 2013 for investment income related to prior periods. The pipeline segment contributed $32.7 million to consolidated net income in 2014 compared to $30.3 million in 2013. The increased net income is primarily due to higher equity earnings from Maritime’s and North East pipeline. Emera Energy delivered adjusted net income of $98.2 million in 2014 compared to $45.1 million for the same period last year. The higher adjusted net income was primarily due to trading and marketing results from the first quarter of 2014 and full year contributions from the late 2013 acquisition of 1,050 megawatts of gas-fired generating facilities in New England. Our corporate and other segment posted $7.7 million loss in 2014 compared to $13.8 million loss in the same period a year ago. The improved results are primarily due to gains on the dilution of Emera’s investment in Algonquin Power in the third and fourth quarter of 2014 as well as certain losses recorded in 2013. These losses were recorded in Algonquin’s discontinued operations and our Atlantic Hydrogen investment impairment. That’s all from my financial review. And we’ll now be happy to take your questions.

Okay. I do have a question from Ben Pham from BMO Capital Markets. Your line is open.

Okay. Thank you and good morning everybody. I just want to go back to your budget of $3.5 billion in CapEx through 2017. Is that for the Maritime Link and lower that, are you taking consolidated CapEx for that?

It’s the consolidated -- so it’s equity and debt-related costs that will be both equity debt and equity financed for the Maritime Link, i.e. the total project cost from Maritime Link and just the equity portion of our investment in the Labrador Island Link.

Okay. And then when you talk about the funding for that, is there any numbers you can share on the preferred share side and is that’s what’s driving the common equity range?

That’s right. In fact if you look in the Investor Presentation that’s online, there is actually a pie graph in there that will show the various components of that, with the range for each but the range for preferred share financing within that would be $500 million plus or minus $200 million, sort of that kind of range.

Okay. Great. And then I just wanted to check the capacity prices increasing in the back end in New England, is that driving down the returns for New England merchant assets on the acquisition side?

Driving down? It’s Judy Steele.

So it’s driving up the returns for those merchant assets as a result of the fact that there are getting capacity payments.

Sorry. I meant driving down the required returns for those plants?

So, I wouldn’t say so, not materially.

Okay. So the markets still pretty hot then for the value you see in New England.

I would say there is a widespread between the bid and the ask in many cases.

Okay.

Yeah. I think, Ben, expectations have become very-very high relative to where they were as a result of these capacity auctions. And so that does make the market a lot tighter than what it would have been before. And so that’s reflected in how we look at that market.

Okay. Great. T hat’s it for me. Thanks everybody.

Thank you.

Your next question comes from Paul Lechem from CIBC. Your line is open.

Thanks. Good morning. Can I just ask about the amount you accrued in Maine for the change in the trend or the complaints around the transitional returns? Can you explain a little bit better? I was just trying to understand for the various commentaries that you’ve written in your MD&A. What drove the further amount that you accrued in Q4 and what’s the outlook from here?

Yeah. Paul, it is Scott and Gerry, feel free to chime in. But there has been a total of three complaints that have been filed. They all relate fundamentally to the same issue, which is the appropriate level of return on equity for pool transmission assets in New England for FERC regulated transmission projects in New England and through the process, it is not yet finalized. But substantively clear with work done. The recommended rate is 10.57% with various adders that can apply to that but that base rate of 10.5% and the issue is around the refund period. And when the process started, it involved a 13-month refund period that was the first complaint that sort of set and established that. And thereafter, the following complaints have really been to ensure that that refund period continues to apply, while the decision process continues to work its way through. So, the second and third complaints we have in effect are accrued at the same rate as we previously accrued for the first complaint, referencing that 10.57% recommended level for base ROE?

Basically, it’s just an extension of the accrual period while the FERC contemplates the various outcomes. So once this is all just said, there will be no further wayward looking amounts you need to accrue at that point in time?

That’s correct.

Okay. And trying to understand, it seems like you expect the decisions at the beginning of next year now at the earliest? There is another year to go.

Yeah. I mean, I wouldn’t say we have a perfect window, as to when to expect the decision. I think that many that have felt that the decision was imminent for quite a long time but at this point, yeah, we like others are sort of waiting the final decision. But in the meantime, we are accruing on the assumption that 10.5% recommended rate is what ultimately gets decided.

And so will there another catch-up? If it hasn’t being decided by the end of this year, will there be another catch-up in terms of another accrual at the end of this year in Q4 of this year to get you to that 10.5%?

On a go-forward basis, we are accruing at that 10.57%.

Okay. And not to drag -- I apologize for dragging this up. What will then -- what period then did it cover then the one you booked in Q4 of this versus last year, the growth?

Gerry, you want to help me with that?

Well, I don’t have the period in front of me but I think a simple way to say that the 10.57% going forward will continue to need to be accrued until the 10.57% goes into rates. So until the rate adjustment occurs, which may likely happen in mid year, this year then we will continue, need to make adjustments for that.

Yeah. Actually, Paul, I have now got it in front of me. So, the first complaint covers the period up to December of 2012. The second complaint then carried it from January 13th to March of 14th and the third complaint carries it forward from not March 14th, theoretically through to September of ’15.

Thank you. Can I ask little bit now that your outlook for CapEx? You mentioned in the MD&A you expect to have an equity investment of between $150 million, $175 million on the Labrador Island Link this year. What determines the timing on that? Is it milestone related or is there some agreement around there? Can you give us the updates on when we should expect that?

Yeah. It’s really -- Paul, it’s really just based upon the profile of capital spend for Nalcor, as it relates to Labrador Island Link and the reason why it’s a little less predictable of that timing, the milestone becomes when they hit their approved equity thickness under the federal loan guarantee. Right now, all of those costs are being funded by debt and once the debt has caught up to the appropriate debt to equity ratio at that point forward similar to the Maritime Link at that point forward, the project costs are financed -- pursue debt and equity. So that becomes the milestone when the equity checks start to be invested again as once the debt is caught up to the debt to equity ratio.

One last one, just trying to understand, in your MD&A here you mentioned on page 54, you talked about your CapEx forecast for 2015 and you have $43 million under corporate. And on line in your Investor Presentation, you have a $200 million number. I was just wondering if you could square those two numbers away?

So, I’m not sure. Clear, you are looking -- yeah, I have got a table in front of me. What are you looking for, Paul?

On page 54, it says corporate and other that’s $43 million in forecast CapEx for 015?

Yes.

On line in your Investor Presentation. On line, there is a $200 million number.

So, I think the difference is likely the flip of APUC sub receipts into common shares and I suspect also it maybe a timing difference between version, Paul, as it relates to the capital spend or the investment expected for Northeast Wind?

Okay. I got you.

But I think one table might have got caught up to the sale and one didn’t?

Okay. I got you. Okay. Thanks very much. Appreciate the stuff.

Thanks, Paul.

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

Thank you. Good morning. I guess this question is probably for Scott but I think anyway can feel free to pipe in on it. And it relates to the rate environment that we’re in right now. As you’ve seen the Canadian 10-year right now sub-1.50 and we’ve got negative rates in several areas around the world on the short end and even on the long end of the curve. So how do you think about the interplay of rates with your business, I know you’ve really got those three broad categories of your equity valuation, but in particular the dividend bump today, just the financeability of debt and prefs, and then just the return frameworks you have on your regulated assets?

Yeah. I mean, we obviously think about all of those things, Paul, and interest rates have an impact on our business in a bunch of different ways and some of them compete with each other obviously, as it relates to capital markets, low interest rate environment, obviously decreases our cost of debt and preferred share financing and also obviously has a positive impact generally on cost of equity in -- at a low interest rate environment as we are seeing with the kind of process that the FERC has gone through, also has a related, not direct but related impact on returns on equity within regulated businesses. So in a rising interest rate environment, of course cost of capital can be expected to increase. But so too over time again not direct, because ROEs are sticky, but overtime so too can earnings that come from those regulated businesses, as ROE adjust to different interest rate environments.

I think the other thing, Andrew, that it’s affecting us is that there is a quite a difference between Canada and the U.S. right now and the question is whether that spread continues to widen and even the foreign exchange challenge. So we actually are seeing quite a bit of effect from the debt side right now. And I think as you know, almost 50% of our business is now denominated in U.S. dollar as a result of investments we’ve made over the last few years.

Okay. That’s very helpful. And then just maybe one follow-up on that. If you’re to issue debt today, what kind of spreads do you think you would have on the regulated business where it’s not as big a concern as in the pass-through generally speaking, and then also on unregulated activities?

Yeah. So I think debt corporate spreads for NSPI for example have not changed materially over the last little bit. So the cost of debt financing for NSPI really gets a direct benefit with changes in the underlying Bank of Canada rates. And so we would see funding rates for NSPI in the low 3% range today depending on what kind of term that we go and of course the curve is still upward sloping. So all that sort of factors in. And the unregulated business, of course it’s a different environment, whether we are financing in the U.S. or Canada, the rate structure is little bit different. And to some measure, some of our new financing activities were increasingly focused on trying to move finance incremental debt generally at the OpCo level and not at the HoldCo level. And in some cases that has a positive impact in terms of the cost of debt. In other case, it can have a negative impact depending on the nature of the asset. But to your question, spreads haven’t materially changed over the last 12 months.

And I think, Andrew, just from a net result perspective, our cost of debt has continued to decline. There is no question about that.

That’s extremely helpful. Thank you.

Thank you.

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

Good morning. If I can just start with that cleanup question here on Maine mix if I am understanding it. So the provision you took in the fourth quarter was really completely related to prior periods.

It’s catching up sort of the ROE, assuming a 10.57% base rate through to and including December '14.

Right. And I think as you mentioned, there should be no provisions going forward I guess unless that 10.57% itself was changed. Is that correct?

That’s correct.

Okay. Just looking at financing, and I think you’re kind of leading us in the direction between what you did at the investor dinner and then talking about with the increased FFO, you’ve got more of your CapEx being funded internally -- with internally generated funds. But just with the New England capacity auction in the line of sight, it gives you into starting mid 2017 now up to mid 2019, do you think you’re getting really to the point now where you are self-funding absence of any acquisitions, given the past due results were better than what you were thinking back in early December?

Yeah. I mean, I think our view was that we would have seen a continuation of the trend with capacity prices through FCA 9, the auction that just cleared. So I think some of that thinking had to some measure factored in. And I think from our perspective, Robert, I think we would still be very comfortable with saying that our common equity financing needs are between 0 and 250, certainly not more. And obviously we wouldn’t say 0 if we didn’t see that there is a scenario where it could be. But I think thinking of the range of 0 to 250 is still the right way to think about it.

Okay. Maybe I could ask it slight differently, just in terms of what you said in the past of typically expect Emera view out for all different forms of financing in the capital markets, but common equity specifically over 18 to 24 months I guess with the sale of Northeast Wind and the increased FFO. Is that something that probably isn’t a relevant way to be thinking about your financing on a go forward basis?

Yeah. I think it all factors into the mix. And as we sit today, our liquidity, our capital structure, and our balance sheet is, as we sit today, in pretty good shape.

Okay. Just last question, you’ve got some comments here on in the outlook section with respect to at least directionally where you’re expecting earnings in '15. Just for the Caribbean with statement consistent with prior year, is that in Canadian dollar, or is that in U.S. dollar terms?

U.S. dollar terms.

Okay. That’s great. Thank you.

Thanks, Robert.

Your next question comes from Matthew Akman with Scotia Bank. Your line is open.

Hi. Thanks. Good morning. For the Maritime pipeline and the Brunswick, Chris you had some opening comments on that and there is some preliminary proposals out there from some of the big pipeliners on getting gas into -- more gas into the northeastern, some comments directly about the Maritime’s actually? And Emera has been pretty quiet about that despite that you guys do have investments in the one pipeline that get you there. I am just wondering if you’re working behind the scenes with some of the other pipeline companies, or have your own plans or how you see yourselves getting involved in that potential opportunity?

Matthew, it’s certainly an important area for us. And we do say that gas to the Maritime is a strategic issue for us that we are focused on, but there are lot of different moving parts. Even just the fact that the Atlantic Basin LNG price has declined dramatically over those past relatively short period of time is an optionality that exists. The fact that Maritime actually has close to 300 million a day of load that it has to supply in some form and the fact that New England is working their way through how they are going to supply gas, those things are all factors that we are looking very carefully at. At the end of the day, we do think that there is something to be done there. We do think that that will turn into some investment potential for our business. And -- but it’s still a bit unclear as to exactly what the right route is at this moment. I think the interesting think development that we’ve seen just in the past short while is that Encana has announced that they’re going to shut in Deep Panuke for this next summer. So what we’ve found originally might be an eight to 10-year window before we saw no gas in the pipe could be as early as this summer. So it does certainly focus the mind on where the molecules will come from over that period. And again, as I said, I think, there will be something for us to do as we get that, as that whole thing unfold.

Okay. Thanks. That’s all I had.

Thanks, Matthew.

And your next question comes from Linda Ezergailis from TD Securities. Your line is open.

Thank you. Congratulations on a good quarter.

Thank you, Linda.

Some questions about your capital plan, can you just confirm that, in your -- most recent investor presentation, your pie chart of ranges, that’s based on organic CapEx, not contemplating any sort of acquisition?

Yeah. That’s correct. There’s no acquisition-based capital assumed in there.

Okay. And how might you think of what additional capacity you would have over the next couple of years to make an acquisition or would that substantially probably require external financing?

I think it would depend on the nature of the acquisition. So but I think that sort of the balance sheet as it sits we’ve got sort of an equity thickness that I think we’re very comfortable with, arguably it might be a little thicker than where we have seen that in the past, but we’re certainly, I think, in the right zone. I think it put us in a position where we could sort of think about a broader based capital plan that what’s currently included within the 3.45, but that’s financing need against the 3.45 sort of external financing requirement of about $800 million. Certainly, if the capital plan grew from that than, yes, it would likely increase the need for capital market related support. And Linda, the only think I’d add is that, we do have a focus internally in the business on cash generation from internal sources. And so we are looking at various ways that we can do that and continue to see that as a very, very important target for the business.

Okay. And just as a follow-up of some earlier lines of questioning. With respect to acquisitions, is it reasonable to say that with the drop in the value of the Canadian dollar and heightened results in the New England capacity markets that making any sort of an additional acquisitions of power plants in New England is becoming tougher and tougher?

So I think these things are always ebb and flow and I think -- and that is the case. We don’t restrict ourselves to just in New England market. We’re looking at all the different markets where we move gas and where we actually have our presence. And so I think, over time we will continue to add to our gas generation compliment but we’ll do it in a very careful and selective way. Discipline is the name of the game at Emera, it always has been and always will be. And we’ll definitely find ways to mine some value out of the market.

Okay. And just a clean up question on the quarter, I don’t know maybe this is the question we could take offline but your OM&G in Maritime generation dropped quite a bit year-over-year. How might we think of an appropriate run rate for operating cost, I guess, in your generation business generally going forward?

So Linda, its Judy. The change quarter-over-quarter in the Maritime generation was the result of refusing some savings in Brooklyn Power and also reduced EOH fee out of Bayside. So we’re probably -- that is the real material change kind of into the run rate, which would probably save us about $1 million a year we think. So going forward, we would expect to be about $1 million -- all other things being equal. I would expect overall that OM&G in the Maritime generation to come down about $1 million.

Versus the full year 2014 actual?

Yes.

Okay. Great. Thank you.

You have one more question from Paul Lechem from CIBC. Your line is open.

Thank you. Wanted to ask about the MPUC ongoing I guess, or is it ongoing. The appeal process around the First Wind transaction now that you’ve sold it, I’m assuming that that appeal of the MPUC decision is now dead or is it still ongoing?

No. Paul, it’s still ongoing. So that process does have to play out and we will continue to participate in it. Basically, it involves Algonquin as well, of course. So we’re going to continue to support the MPUC defensive decision. And I think, it’s important for us to follow through and the expectation is that, that will presumably be resolved within 2015.

I think Paul, the other thing to think about here is that one other things that Maine is doing is trying to figure out where it wants to be relative to both holding company and utility ownership generation. So it is an active discussion in the State of Maine and I think what we’ve done to date has continued to energize that discussion in an important way. And so we’re working today to continue to see where that’s going to go and it is a strategic issue we believe for the customers in the State of Maine. We believe that the utilities can improve the cost structure and the more that the utilities and their holding companies are involved in this market, the more, the better cost will be for customers and so we think that that’s something that Mainers will embrace

Thanks. So is the 25% -- the limit of 25% holding you have in Algonquin, is that part of -- is that wrapped up in this decision or is that now a separate issue? Is that 25% limit to still hold?

It is part of the issue but only because Algonquin is a competitive supplier in that particular market and owns a small amount of generation in Northern Maine. So, Algonquin could get out of that situation easily by divesting a relatively small block of generation, just a few megawatts.

So while they still hold that, is that limit that 25% limit to your holding in Algonquin?

We would require another approval, as long as they continue to be generators in the State of Maine, that’s correct.

Okay. Got you. Thanks, Chris.

Okay. Thank you.

I have no further questions at this time. Mr. LaFleur, I’ll turn the call back over to you for closing remarks.

Okay. Well, thank you very much. We certainly appreciate everyone’s interest today in Emera. And hope you all have a great afternoon. Thank you very much.

Thank you everyone. This concludes today’s conference call. You may now disconnect.