Greg Blunden - Chief Financial Officer Mark Kane - Vice President of Investor Relations Chris Huskilson - President, Chief Executive Officer, Director Judy Steele - President and Chief Operating Officer of Emera Energy Inc., Halifax, Nova Scotia Alan Richardson - President and Chief Operating Officer of Emera Maine, Bangor, Maine

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

Good morning, ladies and gentlemen. Welcome to Emera's second 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, August 9, 2016 at 11:00 o'clock Atlantic Time. I would now like to turn the meeting over to Greg Blunden, Chief Financial Officer. Please go ahead, Mr. Blunden.

Thank you. Good morning everyone and thank you for joining us for our second quarter conference call this morning. Before we begin, I want to welcome and introduce Mark Kane, our new Vice President, Investor Relations. Mark has many years of experience in investor relations and was formerly the Director of Investor Relations for TECO Energy. Thanks for joining the team, Mark. I want you take it over from here.

Thanks Greg. It's great to be in Halifax today and be a part of the Emera finance team now. Joining me from Emera today is Chris Huskilson, President and Chief Executive Officer, Greg Blunden, Chief Financial Officer whom you just heard from and other members of the management team at Emera. Emera's second quarter earnings release was distributed yesterday evening via Newswire and the financial statements and management discussion and analysis are available at our website at emera.com. 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 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. Now, I will turn things over to Chris.

Thank you Mark and welcome to the team. Good morning everyone. Emera delivered adjusted net income of $237.5 million or $1.59 per share in Q2 of 2016 compared to $48 million or $0.33 per share in Q2 of 2015. Adjusted net income, excluding costs related to the TECO Energy acquisition, was $279.5 million or $1.87 per share. There were several one-time gains in the quarter which more than offset the transaction costs associated with our acquisition of TECO Energy. This has been a very productive quarter for Emera. While there remain a theme throughout this year to date, the theme being a mild winter and a late start to summer, Emera's base operations have and continue to perform well and are on track to support our 8% annual dividend growth target through 2020. Greg will take you through the details of the quarterly results later in his remarks, but first I would like to touch on some key strategic highlights and milestones Emera reached in Q2 of 2016 and subsequent to the quarter. I will begin with the closing of the TECO Energy acquisition. On July 1, we acquired TECO Energy. Our teams efficiently moved through the approval process and met our mid-2016 timeline. We welcome 3,700 new dedicated employees into the Emera family and 1.6 million new customers. With the acquisition, Emera now operates in two new constructive regulatory jurisdictions, Florida and New Mexico, which also possess some of the best organic growth in the United States. The combined 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 see additional opportunity to apply Emera's strategy centered on clean, affordable energy to drive growth. At Tamp Electric, we see opportunities for a potential large-scale solar power generation. And at Peoples Gas and New Mexico Gas, we see potential to grow these businesses by expanding the distribution of cleaner burning natural gas to vehicles, industrial customers and new residential customers. The significant earnings and cash accretion expected from TECO Energy combined with the growth for the consolidated businesses has provided the Emera Board confidence to recently increase the annual common dividend by 10% to $2.09 per share and extended the annual 8% dividend growth target through to 2020. Moving to the Maritime Link Project. Construction continues to progress. Early civil construction on major worksites is now complete and ABB is working on both diverse sites in Nova Scotia and Newfoundland. Horizontal directional drilling for cable entry into the Cabot Strait is nearing successful completion. Manufacturing of both subsea cables is progressing with installation on schedule for mid-2017. A joint venture between Emera Utility Services and Rokstad Power was recently selected to replace Abengoa to complete the high-voltage direct current transmission lines. Abengoa has been under global creditor protection and the decision to replace them is a result of their failure to perform and was based on what is in the best interest of the project and our customers. We continue to be confident that the project will be completed on budget and on schedule in late-2017. For Emera Energy, natural gas market conditions continued to be weak in Q2 of 2016 with sustained low absolute pricing, price spread and volatility. This is a reflection of weather conditions and the resultant reduced demand for natural gas and electricity generation, Emera Energy generated $34 million in margin on gas sales over the quarter, a $12.6 million increase over last year. This increase was more than offset by higher short-term fixed cost commitments for transportation and storage which drove the decrease in net margin quarter-over-quarter. Emera Energy manages risk by avoiding exposure to commodity price changes and investing in transportation capacity to provide the opportunity to move gas from lower to higher price markets when conditions are right. The downside risk is known and limited to the cost of the transportation. I should point out that the transportation deal can be profitable overall, but not look that way in any particular period, because the costs are allocated evenly over the term as the related revenue-generating opportunities are seasonal. That is the case for Q2. 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 energy targets. An act to promote energy diversity was approved by the Massachusetts legislature on July 31 and signed into law by Governor Charlie Baker on August 8. The bill mandates a competitive solicitation for long-term contracts to supply Massachusetts with hydro resources and 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 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 Nova Scotia, we are implementing a plan to provide stable and predictable rates for our customers through to the end of 2019. We worked with stakeholders and reached agreement on rate stability plan, which was recently approved by the UARB. With this plan in place, the average annual increase in customer rate is 1.1% 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 around. In Barbados, we maintain a self-insurance fund or SIF to cover the risk to customers against the damage and consequential loss to certain Barbados Light & Power assets. Early in our ownership and with our experience as utility operators, we recognize that the fund was likely overfunded to provide risk protection for customers. We engaged third-party risk advisors to do a detailed analysis. They identified the ability to recapitalize $43.4 million after-tax to Emera, while still maintaining adequate funding to cover the risk for customers. Support was secured from the Government of Barbados, the Trustees of the SIF and the Central Bank and the cash has been received. Our 10 megawatt solar plant in Barbados was recently completed on time and under budget. Power was first generated on June 11, just six months after construction commenced. Total solar generation on the island is now at approximately 23 megawatts and we are looking for more. We are advancing our strategy to move away from primarily oil based generation to more renewable, clean energy sources with a focus on affordability and rate stability. In conclusion, our strong and diverse regulated business provides stable support for our growing dividend. We target having 75% to 85% of our earnings from regulated businesses. TECO Energy brings this to almost 85%. We also target a dividend payout ratio of between 70% and 75% of earnings. While earnings for the balance of 2016 will continue to have adjustments, the underlying base business earnings are consistent with our growth projections and we expect the dividend payout ratio for 2016 to be within our target range. Our earnings growth are on track to support our 8% annual dividend growth target through 2020. And with that, I will turn it over to Greg who will provide an overview of our financial results. Greg?

Thank you Chris. Emera's consolidated net income in Q2 2016 was $207.8 million or $1.39 per share. When quarterly results are normalized for the $29.7 million of mark-to-market losses, second quarter 2016 net income was $237.5 million or $1.59 per share. Adjusted net income in Q2 2015 was $48 million or $0.33 per share. There are several significant items in Q2 2016 including TECO Energy acquisition costs of $42 million after-tax or $0.28 per share, a cash gain on the sale of Algonquin Power common shares of $145.5 million after-tax or $0.97 per share, a gain on the conversion of Algonquin Power subscription receipts and dividend equivalents into common shares of $53.1 million after-tax or $0.35 per share and as Chris mentioned a gain in the reduction of the Barbados Light & Power self-insurance fund liability of $43.4 million after-tax or $0.29 per share. In addition, we had a charge in the quarter of $11.8 million after-tax or $0.08 per share to recognize state fuel taxes at Emera Energy from November 2013 through to March 2016, of which $2.1 million related to Q1 of this year. Moving to the segmented results, I will begin with Nova Scotia Power which provided net income of $28.4 million in Q2 of 2016 compared to $16.9 million in Q2 of 2015. The increase was primarily due to the timing of regulatory deferrals, decreased OM&G and lower regulatory amortization, partially offset by DSM program costs that are no longer being deferred. Nova Scotia Power's net income, year-to-date, was $80.9 million compared to $84.9 million for the same period last year. Emera Maine contributed $9.7 million to consolidated net income in Q2 2016 compared to $13.7 million for the same period last year. The decrease was primarily due to the amortization of transmission revenue adjustments. Emera Maine's net income, year-to-date, was $19.0 million compared to $25.2 million the same period of last year. Emera Caribbean's net income increased to $58.1 million in Q2 2016. The higher net income was primarily due to the gain realized from the self-insurance fund and a decrease in OM&G, partially offset by increased income tax expense. Year-to-date, Emera Caribbean's net income was $67.9 million compared to $13.6 million for the same period of last year. Our pipeline segment contributed adjusted net income of $8.3 million in the quarter, a decrease of $1 million from Q2 2015. Year-to-date net income was $18 million compared to $19.2 million for the same period of last year. Emera Energy contributed an adjusted net loss of $28.7 million in Q2 2016 compared to an adjusted net income of $3.4 million last year. This decrease was primarily due to the recognition of state fuel taxes at the New England gas generating facilities for the period of November 2013 through March 2016 and lower marketing and trading margin, which included a $12.6 million increase in margin from gas sales, that was more than offset by an increase in short-term fixed cost commitments for transportation and storage. Year-to-date, Emera Energy contributed adjusted net income of $19.2 million. Our corporate and other segment posted a $161.7 million adjusted net income in the quarter compared to a loss of $100,000 in Q2 2015. The variance was primarily due to the gain on the sale of Algonquin Power common shares and the conversion of Algonquin Power subscription receipts and dividend equivalents into common shares. As well, we had increased income from equity investments partially offset by TECO Energy acquisition costs. Year-to-date, corporate and other's adjusted net income was $152.7 million compared to a loss of $3.1 million for the same period of last year. Before opening up for questions, I would like to give you a quick overview on the financing for the TECO Energy acquisition. The financing was completed in June and outperformed our expectations. The U.S. debt was raised at a weighted average interest rate of 3.6% with an average duration of 15 years, which was well in excess of our expected duration. We also raised over CAD500 million in May through the sale of the majority of our ownership interest in Algonquin. And finally, the final installment payment for the convertible debentures issued to finance the TECO Energy acquisition was due on August 2 and upon receipt of the funds we issued over 50 million shares as the debentures were converted into Emera shares. That's all for my update and now we would be happy to take your questions.

[Operator Instructions]. Your first question today comes from Linda Ezergailis from TD Securities. Your line is open.

Thank you. I have some questions with respect to your energy services business and some of the trading activities there. I am just wondering, I realize there's some seasonality in terms of revenues and maybe more of a stable cost to [indiscernible], but can you give us a sense for the balance of the year, what sort of fixed cost commitments for transportation and storage you might have in place? And what you are seeing in terms of market dynamics at this point for Q3 and the balance of the year?

Great. Linda, it's Judy. So the gas market continues to be relatively weak, but it has provided a little bit more opportunity lately than in the second quarter. As always, our guidance is that we expect the business to be able to deliver between $15 million and $30 million of net earnings annually with some opportunity for upside. So we have had a few of those upside years lately but 2016 won't be one of them. It's kind of hard to forecast precisely because of course November and December are often very important to the overall yearly results. But that said, at this point we do expect to wind up at the lower end of our guidance range. Just to give you a little bit more perspective on it, if you think to Q2, we probably had about $15 million a month in fixed cost transportation and storage and asset management cost. That's dropped off to about $12 million now in July, August and half of that will be gone completely by the end of October. So all other things being equal, what they are now at about $12 million a month, will be $6 million a month starting November 1. Now that said, there will be new business that will come along between now and then and we will make assessments to those at the market value of anything we would be interested in that regard. But it gives you a sense of the cost profile.

That's very helpful, Judy. Now just following up on the power side of the equation. Bayside Power, can we use Q2 as a new run rate? Or is there some seasonality there with the expiry of some favorable natural gas contracts?

Well, the natural gas contract expiry has less of an impact in the winter month, of course, because gas is fundamentally a flow-through in the PPA. So it's more significant in the summer periods. What I would say is, probably Q2 would be the weakest, I guess, to some extent and if we get a little bit of a rebound in power prices which have been very, very weak through this summer, through Q2 and Q3, base site should be a able to do a little bit better. See, the impact of the gas was magnified by very thin spark spreads of late. In the summer months, the gas contract is actually preferable to New England market pricing. It's just not as attractive as it was before.

Okay. That's helpful. And maybe that's good segue into your New England Power operations and what you are seeing there and what the outlook is, from a market dynamic perspective?

So I am going to normalize for our tax adjustment in order to give a sense of the operational perspective on the facilities. But basically, 2016, the earnings there will be lower than 2015. So we expect somewhere in the range of $25 million to $35 million. That is normalizing for the effect of the tax adjustment this quarter. So that is clearly less than (2015, but I will remind you that we have some very lucrative hedges in the first and fourth quarter of 2015 that really enabled us to earn outsized returns there in excess of $50 million in earnings. So the $25 million to $35 million is kind of what we think right now. We are frankly reasonably all quite open for the rest of the year because spark spreads have been thin and we think the realtime market will deliver more than that. So we haven't overly hedged. So I can't predict with exactness where we will wind up. But I think it's reasonable to think between $25 million and $35 million, which is really well about the expectations we had when we actually acquired the asset. And once we get into 2017, of course, we have got a doubling of capacity crisis beginning in June, which will add about $30 million in capacity revenues to the facility.

That's great. Thank you, Judy.

You are welcome.

Thanks Linda.

Your next question is from Robert Hope from Scotiabank. Your line is open.

Yes. Thank you. Just moving on to the Maritime Transmission Project, just regarding the Labrador-Island Link, seeing the cost increase there and the push out of the in-service dates, can you just clarify when you expect to earn cash on those assets? Is it when they are place in service, I guess, in mid-2018? Or will it be when they actually start generating or transmitting electricity?

So at this point, we are expecting those facilities to go into service in late-2017 and so they will begin generating cash at the first of 2018. And the other thing is, we actually haven't seen a cost increase. In fact, we are still in very, very good shape to be on budget for the cost of that project. And so we would say, even though we have been squeezed a little bit on time because of the DC, the change in the DC contractor, we still expect to be able to get that project in on time and on budget and it would be in-service and used for the first of the 2018.

Sorry. I was referring to the Labrador-Island Link.

Sorry. Okay. I though you were talking about Maritime Link. So Labrador-Island Link is expected to be, as you said, in the middle of the year. We will be able to continue to earn AFUDC on that project up until it goes in-service. And so the cash earnings will happen when it goes in use and useful.

Okay. And then given that you are really in control of the schedule there, do you have any potential remedies if the contractor there goes slower to match up the in-service date there with when Muskrat Falls will begin to generate power?

Well, again, so that project is coordinated, I think first and foremost, with getting the transmission system in service and we are very confident that the transmission system will be in-service in the early to mid part of 2018. And so I think that that's where that project is right now. From a cost perspective, as you know, we are protected and once the transmission system goes in-service, we will be able to access other resources in the network. And so I think that that's the way things will evolve at that point.

All right. That's helpful. And then just one follow-up. With little over a month under your belt regarding TECO, can you jus t update us with any opportunities you are seeing there or challenges that you are seeing now that you have the assets in hand?

Well, first of all, I think the close went very well. We were very pleased with the way things came together. TECO has had a good first six months of operation. They were on plan or just slightly better than plan for the first six months. And it's been a very, very warm July. So we will get the benefit of earnings from TECO Energy for the second half of the year. I think the Tampa area had 29 days about 90 degrees in the month of July and Q3 is always the highest value period for the entity. So we are quite pleased with how things are going there. Sales are very strong and the business is doing well. As it relates to working together, things are also going very well in that regard. I think as people know, things are very stable in that market. We have Gordon Gillette, who is the current president of Tampa Electric and the Florida operations will continue in his role and Gordon is doing a very good job for us. And the same thing about Ryan Shell in New Mexico. So that creates a lot of stability for the people in that market and for the business itself. And so we are excited to be engaged.

Good. Thank you. Thank you for the insights.

Thanks Robert.

Thanks Rob.

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

Thank you. Good morning. Just a couple of quick questions on TECO. First of all on the financing. I thought in the original financing plan, there was expectation that there were going to be some preferred shares issued. It ended up being all debt. Any thoughts about the capital structure and need to shift into more breadth to try and increase the equity percentage, what's the financing outlook for this?

So we will complete the financing on it, Paul if you recall, the U.S. hybrids that we issued effectively have the same treatment for the rating agencies as preferred shares and what we always said is, we would issue in and around $1 billion to $1.2 billion in some combination of U.S. hybrids or Canadian perhaps. And obviously our preference was to have as much in U.S. dollar denomination as possible, which is why we did the full $1.2 billion in U.S. hybrids.

Got you. Thanks, Greg. That's helpful. Just also on TECO, can you remind me again when are the nearest upcoming regulatory decisions that we need to worry about in Florida or New Mexico.

Yes. Well so I think both entities are in a very stable position from a regulatory perspective. If I just start with New Mexico, we won't be seeing any need for rates until the latter part of the decade and in fact they were in a settlement agreement there on that issue. When it comes to Florida, there actually is a change in rates coming as with most regulators of electric, fuel costs are passed through and in fact, there has been declining fuel rates in general in Florida because of gas pricing and the amount of gas that is being used there. But as well, we also have the Polk project coming on stream. It gives us the ability to generate a lot more of our energy on gas and therefore provide some real value to customers there from that perspective and that project, under a settlement agreement, will see about $110 million of new revenue come to the business as those assets go into service. And so that's really the only change other than normal fuel changes that we expect over the next reasonable period of time.

Okay. Thanks, Chris. In New England, the tri-state Clean Energy RFP looks like it got delayed. Any thoughts around what that means? Are you still in the running there? Do you feel you have a better position than previous? Can you discuss what's going on, on the tri-state side?

Yes. I think the simple answer is, that it's always a very complicated process to decide. I think they received something like 21 different proposals for a substantial amount of energy, potentially more than 20 terawatt hours. So it is hotly contested from that perspective and so we would just take it is a find that it is a complicated issue and that people are considering it carefully. I don't whether Alan Richardson is on the line. I don't know if he wants to add anything to that.

No. Just that the evaluation team did indicate that the turnout was complicated and that was one of the reasons for the delay. They issued that method at the end of July and they have indicated that they will contact the winning bid as they select them. So we are certainly very hopeful that we will get a call shortly.

Okay. And I think, Paul, what's also very optimistic is what Massachusetts has just done relative to their need for clean energy. They have been passed into law an act that will require at least 9.45 terawatt hours of new supply, which will be some combination of hydro and wind or at least Class I renewable. So anyway, I think that's a very positive next step. So in fact, the market is looking now for about 15 terawatt hours in total, which will be something that will take at least a few suppliers to meet.

Okay. Last question. Now that TECO is onboard and your regulated assets have increased 85%, are you looking at any potential increases in the nonregulated side of the business in terms of any new power assets? There a number of packages on the market at present. Just wondering if there is any interest in any of those asset package or any others?

Yes. I mean obviously Paul, we don't go into specifics, but I think our strategy hasn't changed. We are still very focused on making sure the business is regulated. We continue to be interested in having some portion of the business unregulated and market facing. And so that's important to us. It's important to the way we do business. And it's also important to our ability to assess those markets and to do well in those markets. So that continues to be the case but nothing to announce.

Okay. All right. Thanks Chris.

Thank you.

Thanks Paul.

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

Thank you. Good morning. I guess the question is for Chris to start off with. And it is just, while the legislation in Massachusetts being signed yesterday, how do you look at Emera's role in playing in that market is obviously of multiple ways to do that? You can do it from the power side, transmission side and then have some impact on the distribution side, not in Massachusetts, but in Maine broadly. So how do you think about the best investment proposition from Emera's standpoint, given the change in legislation in the Northeast?

All right. Well, so Andrew, I think our focus is always on the transmission side. That's really what we believe our strength is and our positioning is best. We think about the generation part of the portfolio as an enabler to investing in the transmission. And so we will essentially do what we need to do to make sure that we are very competitive on the transmission side. And that's really the way we look at it. I think if you can't also at this point underestimate what's going on with the Canadian Federal Government and how that may play into the whole carbon issue and we would be strong proponents of having Atlantic Canada work in collaboration with New England to come up with the best outcome from carbon perspective. We think Atlantic Canada, including Quebec, actually are really well-positioned to be able to both supply energy and also integrate more closely with the market in New England. I think that that's the type of thing we would be promoting. But for us, that means transmission.

Okay. That's very helpful. And then they maybe just an extension of your comments on integrating Atlantic Canada and providing some power maybe into the Northeast. Do you see some opportunities for Emera to be involved in New Brunswick Power's repowering of certain assets that is prospectively on the horizon, especially on the hydro side?

Well, so we have been working very closely across the region with the utilities in the region. I think it's well known that we have worked on joint dispatch with NB Power and we have worked to try to come up with the optimum approach to assets in the region. So that's really where our focus is. If you look at Atlantic Link, that proposal is out of New Brunswick. In fact, we believe that the connection point for New England and the Maritimes is from New Brunswick. And so we work closely with them in those areas as well. And so we are open to continue working collaboratively and we believe that we do have something to bring.

And then finally, if I may, just a question just on the some financing around the TECO deal. I believe the comment was that the duration that you got in the market was in excess of what you were looking for in the beginning of all this. So on a longer-term accretion basis, is this a bit more modestly positive than you set up in your modeling?

Yes. It would be.

Yes. Andrew, we are very pleased with the way the financing has gone and in fact, what we are seeing as it was asked earlier, now that we are on the ground in Florida and New Mexico, it's very positive. We have already identified $8 billion of opportunity over the next five years and we think that that will continue to grow.

That's great. Thank you.

Thanks.

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

Good morning. If I can come back to just the Massachusetts legislature and just wondered if you can elaborate on your thoughts as to how you see this potentially playing out specifically first on the transmission projects that you put forward? And I am also just wondering, do you have any thoughts just with the delays going on at Muskrat Falls, how you think Massachusetts might view that versus say Hydro-Quebec that has in place resources, load following resources.

Well, I guess first of all, one of the things that Massachusetts just did was focus more on 2022, I believe that on 2020. So I think that that's very helpful through our eyes, because there is quite a lead time for some of these large-scale projects. And I think it certainly means that Muskrat, surpluses from Muskrat, are certainly in the mix. The other thing I would say just on that side is that as we sit today, the Maritime Link, when all the resources are on or operating, will still be somewhat underutilized. And so there is opportunity for more to be done to fill up that project and to ensure that we are doing everything we can to get clean resources to market. So I think there are some things to be done there for sure. I think when it goes beyond that, we believe that the Atlantic Link is the best positioned project in the market. It's able to draw energy from a Northern Maine and certainly resources that exists there. It's able to draw energy from the Maritimes. It's able to draw energy from Newfoundland and Labrador. And it's also able to draw energy from Quebec through the New Brunswick connection. So when we look at that project, it is probably the project that is best positioned to collect the most diverse sources of energy and we think that's an advantage which we will continue to work on.

Do you also see that a benefit of being an underwater cable, just given some of the overland issues that we are seeing on transmission?

Well, so far anyway, it seems easier to get those types of projects permitted. And clearly we now, as a team, have some very, very good experience in doing that work at least in Canadian jurisdiction. And so we would believe that that is a good leg up for that project.

Okay. Perfect. If I can just ask a few very small questions here. The utility services joint venture, is that expected to be noticeable in the results?

That's not our focus. Obviously we wanted to be productive but it's not our focus. Our focus is to get the job done. And we have always said that if we had challenges on the transmission side that we have the capability of doing that work and so this is coming to fruition.

Okay. And then just on the Caribbean side, the OM&G cost savings that we saw in the quarter, was some of that timing or deferrals or makeup or is that a more sustainable number, in your view?

Yes. I think we have seen the cost structure change in the Caribbean as a result of the work that the team has done there to make sure that we are not putting pressure on rates. Certainly that region has gone through some difficult challenges as the economy has changed. And so we have made sure that that utility is cost competitive and is doing a good job in it's market and so that would be sustainable.

Okay. And then the last, just back to the Emera Energy. If I am pulling some of the numbers that I think Judy had mentioned earlier in the call, you have been targeting $15 million to $30 million of net income from the marketing and trading side. And I think you mentioned $25 million to $35 million from the New England business. I don't know if that was inclusive of Bear Swamp. So I don't know if you can basically clarify that?

No, it wouldn't have been that. I was just referring to our owned assets there, Robert.

Okay. So basically if I add those two pieces, that's $40 million to $65 million and then we would add Bear Swamp on top of that? And that's kind of how you are thinking about the build up to 2016? Are there any other major pieces that are missing?

Well, base sites in there, but it's not $5 million, one way or the other.

Great. Okay. That's great. Thanks very much.

Thanks Robert.

Your next question comes from Ben Pham from BMO. Your line is open.

Okay. Thanks. Good morning everybody.

Good morning Ben.

Good morning Ben.

I just wanted to go back to Emera Energy, just a couple maybe some more detailed questions. Just hearing the commentary on the guidance there, I think you mentioned the lower end of the range. It seems that you are using some pretty conservative assumptions in the back half. I just wanted to clarify that. It seems like it's pretty much assuming pretty low pricing and perhaps not exercising the transportation capacity that you bought this quarter?

Yes. So as the market has been weak, we haven't realized on our transportation capacity investment the way we generally like to. And we have still got a couple of more relatively heavy cost months in there in July, August and September. So as I said, it is very challenging for us to predict with precision trading and marketing because November and December often make the year. So right now, I would agree, we are being conservative, but not overly so, to be honest. I would say, the low end of the range feels comfortable guidance for us based on the experience we have had so far this year. There is also a little bit of new pipe capacity coming on in New England, which could dampen volatility which generally is a money making opportunity for us, that volatility. So keeping that in mind as well, we are cautiously optimistic. That said, very cold November and December would be a very nice surprise.

Ben, I think it's worth understanding that that New England is evolving. It's evolving because new pipe capacity is beginning to come in place and then the volatility of weather is always there. And so there always seems to be some stickiness if people have seen low pricing because of low volatility of weather or weather not showing up then that tends to hang in the market for a little while. And so, as Judy said, more volatility on the weather side could change things dramatically quickly.

Okay. And because you have purchase some more transportation, I think you characterized as short-term than do you have some optionality of additionally volatility later this year, but when you think of the short-term, is that frankly the short-term impact in the quarter or more like one year commitment on the capacity? Or is it more five years that we have seen before?

No. So far and away, the majority of capacity is a year or less. Some of it is seasonal. That's just the nature of how it winds up generally getting released. So we have relatively larger commitment coming into this summer. Half of them are rolling off by the start of winter season in November. We will have an opportunity to bid on some new capacity going forward, because again the transportation capacity is an enabler to the business. The fact that we had a lot in the summer, we also had a lot during the winter and we managed to make more margin quarter-over-quarter in the winter of 2016 and 2015 despite the fact that market conditions were a lot less appealing. So it was the transportation capacity that enabled that. So we can't shrink our way to growth in earnings by not buying transportation capacity, but just if you look forward to some of the position we are in today, all other things being equal, a significant chunk comes off. And as it's rebid in a weaker market, the market value of the capacity of is actually lower in terms of its absolute dollar cost.

So Ben, I think the main point is, it's short-term and known. And that's the primary issue.

Yes.

Okay. I just wanted to say the segment more just a lot of in there. On the gas plant side, the state tax, was that a change in law that came out of nowhere and going forward is that going to, just the business there, is it going to attract additional that state tax?

So, it's not a change in law. It's actually a tax on Emera Energy's sales of gas. In fact, we have been selling gas in Connecticut since 2003, but not to any end-users. And so in the course of doing some work earlier this year to get set up to actually sell to a third-party end-user, we realized that this tax could apply to us and that it could apply to our sales, our inter-company sales, essentially to Bridgeport Energy. So we had to do a bit of a true up there from the period of time between when we bought Bridgeport Energy to now. So that is just on the adjustment. Going forward, obviously it's a much smaller number on an annualized basis than it over a 30-month period. The answer to what's the bottomline impact is, it depends. So some days you would think that -- so it has to be factored into Bridgeport's cost of gas, So on certain days, that might mean that extra cost of gas from Bridgeport out of the market. That could happen. Probably not significant enough to do that. On other days, it could mean at Bridgeport winds up being the absolute marginal unit, which means it's setting the price of power and because it is setting the power with the gas tax in it, we are effectively recovering that completely from the market. So there is no bottomline impact in that circumstance. And then there is other days where we are not the market setting entity and it's just a straight increase to Bridgeport's cost of gas. I am probably getting way a little bit further down in the weeds here. All I have to say, on an annualized basis, assuming that the worst-case happens in every circumstance, it's could be $5 million on Bridgeport's cost of fuel. But the worst-case won't be the driving force every time. But I put that out as just a sense post.

And Ben, it's Greg. The guidance Judy gave you for balance of the year, the generating plants would in fact incorporate that into those numbers.

Okay. Great. And if I can squeeze in another one, just with the TECO transaction. You mentioned you are heading towards 85% regulated exposure at the high end and you have created a lot of value in the New England gas plants and it seems like there is a disconnect between plants or capacity payments than some of the emerging like gas plants out there. So probably is there a possibility you could potentially monetize those assets and redeploy in maybe some other gas plants at pretty attractive prices today?

Ben, the only thing I have to say to that is we are always looking at our portfolio and we will make decisions as plan unfolds. But there are no plans to do that at this point.

Okay. Thanks guys. Thanks everybody.

Thank you.

Thank you.

And we have no further questions in queue at this time. I will turn the call back over to the presenters for any closing remarks.

Okay. Well thank you very much for taking the time today for your interest in Emera and we hope you have a great day.

This concludes today's conference. You may now disconnect.