Good morning, ladies and gentlemen, and welcome to Emera's Second Quarter twenty sixteen 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, 08/09/2016 at 11:00 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 Cain, our new Vice President, Investor Relations. Mark has many years of experience in Investor Relations and and was formerly the Director of Investor Relations for TECO Energy. Thanks for joining the team, Mark.
And why don't you take it over from here?
Thanks, Greg. It's great to be in Halifax today and to be a part of the Emera Finance team now. Joining me from Emera today is Chris Huskelson, 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 fifteen 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. 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 risk. 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'll turn things over to Chris.
Thank you, Mark, and welcome to the team, and good morning, everyone. Merit delivered adjusted net income of $237,500,000 or $1.59 per share in 2016 compared to $48,000,000 or $0.33 per share in Q2 of twenty fifteen. Adjusted net income excluding costs related to the Tico Energy acquisition, was $279,500,000 or $1.87 per share. There were several onetime gains in the quarter, which more than offset the transaction costs associated with our acquisition of Pico Energy. This has been a very productive quarter for Emera.
While there remains 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'd like to touch on some key strategic highlights and milestones Emera reached in 2016 and subsequent to the quarter. I'll 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-twenty sixteen timeline. We welcomed 3,700 new dedicated employees into the Emera family and 1,600,000 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 $8,000,000,000 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 Tampa Electric, we see opportunities for 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 $2.9 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 work sites is now complete and ABB is working on both converter 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-twenty seventeen. A joint venture between Emera Utility Services and Rockstead Power was recently selected to replace Avongoa to complete the high voltage direct current transmission lines. Avongoa 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 best 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 twenty seventeen.
For Emera Energy, natural gas market conditions continued to be weak in Q2 of twenty sixteen, with sustained low absolute pricing, price spreads and volatility. This is a reflection of weather conditions and the resultant reduced demand for natural gas from electricity generation. Mera Energy generated $34,000,000 in margin on gas sales over the quarter, a 12,600,000 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. Merra 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 priced 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, but 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 transmission as part of its effort to meet legislative state GHG emissions reduction 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 one renewables and energy delivery during winter months. In Nova Scotia, we're implementing a plan to provide stable and predictable rates for our customers through to the end of twenty nineteen. We worked with stakeholders and reached agreement on our rate stability plan, which has recently approved was recently approved by the UARB.
With this plan in place, the average annual increase in customer rates is 1.1% for each of the next three years. We're stabilizing rates while at the same time completing the most ambitious transition to renewable energy in Canada. With the rate stability plan in place, all of our customers in Nova Scotia will have stable, predictable and affordable electricity pricing that they can depend on as the end 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 And Power assets. Early in our ownership and with our experience as utility operators, we recognized that the fund was likely overfunded to provide risk protection for customers.
We engaged third party risk advisers to do a detailed analysis. They identified the ability to recapitalize $43,400,000 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're 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 businesses provide stable support for our growing dividend. We target having 75% to 85% of our earnings from regulated businesses. PECO Energy brings this to almost 85%.
We also target a dividend payout ratio between 7075% 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'll turn it over to Greg, who'll provide an overview of our financial results. Greg?
Thank you, Chris. Emera's consolidated net income in Q2 twenty sixteen was $207,800,000 or $1.39 per share. When quarterly results are normalized for the $29,700,000 of mark to market losses, second quarter twenty sixteen net income was $237,500,000 or $1.59 per share. Adjusted net income in Q2 twenty fifteen was $48,000,000 or $0.33 per share. There are several significant items in Q2 twenty sixteen including PECO Energy acquisition costs of $42,000,000 after tax or $0.28 per share, a cash gain on the sale of Algonquin Power common shares of $145,500,000 after tax or $0.97 per share, A gain on the conversion of Algonquin Power's subscription receipts and dividend equivalents into common shares of $53,100,000 after tax or $0.35 per share.
And as Chris mentioned, a gain on the reduction of the Barbados Light and Power self insurance fund liability of $43,400,000 after tax or $0.29 per share. In addition, we had a charge in the quarter of $11,800,000 after tax or $08 per share to recognize state fuel taxes at Emera Energy from November 2013 through to March 2016, of which $2,100,000 related to Q1 of this year. Moving to the segmented results, I'll begin with Nova Scotia Power, which provided net income of $28,400,000 in Q2 twenty sixteen compared to $16,900,000 in Q2 of twenty fifteen. The increase was primarily due to the timing of regulatory deferrals, decreased OM and 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 $80,900,000 compared to $84,900,000 for the same period last year.
Emera Maine contributed $9,700,000 to consolidated net income in Q2 twenty sixteen compared to $13,700,000 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 $19,000,000 compared to $25,200,000 for the same period of last year. Emera Caribbean's net income increased to $58,100,000 in Q2 twenty sixteen. The higher net income was primarily due to the gain realized from the self insurance fund and a decrease in OM and G, partially offset by increased income tax expense.
Year to date, AmeriCaribbean's net income was $67,900,000 compared to $13,600,000 for the same period of last year. Our pipeline segment contributed adjusted net income of $8,300,000 in the quarter, a decrease of $1,000,000 from Q2 twenty fifteen. Year to date net income was $18,000,000 compared to $19,200,000 for the same period of last year. Mira Energy contributed an adjusted net loss of $28,700,000 in Q2 twenty sixteen compared to an adjusted net income of $3,400,000 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 to March 2016 and lower marketing and trading margin, which included a $12,600,000 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 $19,200,000 Our Corporate and Other segment posted a $161,700,000 adjusted net income in the quarter compared to a loss of $100,000 in Q2 twenty fifteen. 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 Tico Energy acquisition costs. Year to date, corporate and others adjusted net income was $152,700,000 compared to a loss of $3,100,000 for the same period of last year. Before opening up for questions, I'd to give you a quick overview on the financing for the Tico 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 fifteen 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 Tico Energy acquisition was due on August 2, upon receipt of the funds, issued over 50,000,000 shares as the debentures were converted into Emera shares. That's all for my update and now we'd be happy to take your questions.
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'm just wondering, I realize there's some seasonality in terms of revenues and maybe more of a stable cost outlook. But can you give us a sense of the balance of the year, what sort of fixed cost commitments for transportation and storage you might have in place? And what you're 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 15,000,000 and $30,000,000 of net earnings annually with some opportunity for upside. So we've 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 $15,000,000 a month in fixed cost transportation and storage and asset management costs. That's dropped off to about 12,000,000 now in July, August. And half of that will be gone completely by the October.
So all of the things being equal, what's there now at about $12,000,000 a month will be $6,000,000 a month starting November 1. Now that said, there'll be new business that will come along between now and then and we'll make assessments about the market value of kind 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 has less of an impact in the winter months, of course, because gas is kind of 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, Bayside should be able to do a little bit better. The impact of the gas contract 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 a good segue into your New England power operations and what you're seeing there and what the outlook is from a market dynamic perspective?
So I'm going to kind of normalize for our tax adjustment in order to give a sense of the operational perspective on the facilities. But basically 2016 will be the earnings there will be lower than 2015. So we expect somewhere in a range of $25,000,000 to $35,000,000 That is normalizing for the effect of the tax adjustment this quarter. So that is clearly less than 2015, but I'll remind you that we had some very lucrative hedges in the 2015 that really enabled us to earn outsized returns there in excess of $50,000,000 in earnings. So the $25,000,000 to $35,000,000 is kind of what we think right now.
We're frankly reasonably quite open for the rest of the year because the Spark spreads have been thin and we think the real time 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 25,000,000 and $35 which is really well above the expectations we had when we actually acquired the assets. And once we get into 2017, of course, we've got a doubling of capacity crisis beginning in June, which will add about $30,000,000 in capacity revenues to the facilities.
That's great. Thank you, Judy.
You're 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 projects, just regarding the Labrador Island Link, seeing the cost increase there and the push out of the in service date. Can you just clarify when you expect to earn cash on those assets? Is it when they're placed in service, I guess, in mid-twenty eighteen?
Or will it be when they actually start generating or transmitting electricity?
Yes. No. So at this point, we're expecting those facilities to go in service in late twenty seventeen. 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're still in very, very good shape to be on budget for the cost of that project. And so we would say even though we've 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 and useful the first of twenty eighteen.
Sorry, I was referring to the Labrador Island Link.
Sorry, okay. You're talking about I thought you were talking about Maritime Link. So Maritime Labrador Island Link is expected to be, as you said, in the middle of the year. We'll 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 used and useful.
Okay. And then given that you're not 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 Muscat Falls will begin to generate power?
Well, again, so that project is coordinated, think, first and foremost with getting the transmission system in service. And we're very confident that the transmission system will be in service in the early to mid part of 'eighteen. And so I think that that's where that project is right now. From a cost perspective, as you know, we are protected. 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 a little over a month under your belt regarding TECO. Can you just update us with any opportunities you're seeing there or challenges that you're seeing there that you're seeing now that you have the assets in hand?
Well, I mean, 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 planned for the first six months. And it's been a very, very warm July.
The Q so we will get the benefit of earnings from PECO Energy for the second half of the year. I think the Tampa area had twenty nine days above 90 degrees in the month of July and Q3 is always the highest value period for the entity. So we're 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've 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. And so that creates a lot of stability for the people in that market and for the business itself. And so we're excited to be engaged.
Good. Thank you. Thank you for the insights.
Thanks, Robert. Thanks, Robert.
Our next question comes from Paul Letcham from CIBC. Your line is open.
Thank you. Good morning.
Good morning, Paul.
Good morning. Just a couple of quick questions on TECO. First of all, on the financing, I thought in the original financing plan, was expectation that there were going be some preferred shares issued and it ended up being all debt. Any thoughts about the capital structure and need to shift into more perhaps to try and increase the equity percentage? What's the financing outlook for this?
Yes. So we're complete the financing on it, Paul. If you recall, The U. S. Hybrids that we issued effectively have the same treatment from the rating agencies as preferred shares.
And what we always said is, we'd issue in and around $1,000,000,000 to $1.2 in some combination of U. S. Hybrids or Canadian prefs. And obviously, preference was to have as much in U. S.
Dollar denomination as possible, which is why we did the full $1,200,000,000 in U. S. Hybrids.
Got you. Thanks, Greg. That's helpful. Just on also on CECO, can you remind me again when are the nearest upcoming regulatory decisions that we need to worry about direct intent in Florida or New Mexico?
Yes. Well, so I mean, 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, we're in a settlement agreement there on that issue. When it comes to Florida, there actually is a change in rates coming.
As with most regulated electrics, fuel costs are passed through. And in fact, there's 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, we'll see about $110,000,000 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.
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 mean, think it's 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 as a sign that it's a complicated issue and that people are considering it carefully.
I don't know whether Alan Richardson is on the line. I don't whether he wants to add anything to that.
No, just that the evaluation team did indicate that the analysis was complicated, that was one of the reasons for the delay. They issued that message at the July. And they've indicated that they will contact the winning bids as they select them. So we're certainly very hopeful that we'll 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've 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 one renewables. So anyway, think that that's a very positive next step. So in fact, I mean, 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 TCO is on board and your regulated assets have increased 85%, are you looking at any potential increases in the non regulated side of the business in terms of any new power assets. There are a number of packages on the market at present. Just wondering if there's any interest in any of those asset packages or any others?
Yes. I mean, obviously, Paul, we don't go into specifics. But I mean, I
think our strategy hasn't changed. We're 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.
Our
next question comes from Andrew Kuske from Credit Suisse.
You. Good morning. I guess the question is for Chris to start off with and it's just in light of the legislation in Massachusetts being signed yesterday. How do you look at Emera's role in playing in that market? Because obviously, you have 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 an Emera standpoint given the change in legislation in the Northeast?
Yes. Well, so Andrew, 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're very competitive on the transmission side.
And really the way we look at it. I I think 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 a 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. And 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 maybe just an extension of your comments on integrating Atlantic Canada and then providing some power maybe into the Northeast. Do you see some opportunities for Merit 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 I mean, we've been working very closely across the region with the utilities in the region. I think it's well known that we've worked on joint dispatch with NB Power and we've worked to try to come up with the optimum approach to assets in the region. So that's really what our focus is. If you look at Atlantic Link, that proposal is out of New Brunswick. In fact, we believe that the best connection point for New England and the Maritimes is from New Brunswick.
And so we've worked closely with them in those areas as well. And we're 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 financing around the Tico 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. I mean, Andrew, we're very pleased with the way the financing has gone. And in fact, what we're seeing, as was asked earlier, now that we're on the ground in Florida and New Mexico, it's very positive. We've already identified $8,000,000,000 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 legislation. And just wondering if you can elaborate on your thoughts as to how you see this potentially playing out specifically for some of the transmission projects that you've put forward. And I'm also just wondering, do you have any thoughts just with the delays going on at Musgrat Falls, how you think Massachusetts might view that versus say Hydro Quebec that has in place resources load following resources?
Well, I mean, guess, of all, one of the things that Massachusetts just did was focus more on 2022, I believe, than 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 of the resources are on and operating, will still be somewhat underutilized. And so there's opportunity for more to be done to fill up that project and to ensure that we're 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 Northern Maine and certainly resources that exist 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'll continue to work on.
Do you also see that being a benefit being an underwater cable, just given some of the overland issues that we're seeing on transmission?
Well, so far anyway, seems easier to get those types of projects permitted. And so 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. It's not obviously, we wanted to be productive, but it's not our focus. Our focus is to get the job done. And we've 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 and G cost savings that we saw in the quarter, was some of that timing or deferrals or makeups or is that a more sustainable number in your view?
Yes. I think we've 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're not putting pressure on rates. I mean, certainly that region has gone through some difficult challenges as the economy has changed. And so we've made sure that that utility is cost competitive and is doing a good job in its market. And so that would be sustainable.
Okay. And then the last, just back to Emera Energy. If I'm pulling some of the numbers that I think Judy, you had mentioned earlier in the call, you've been targeting 15,000,000 to $30,000,000 of net income from the marketing and trading side. And I think you mentioned 25,000,000 to $35,000,000 from the New England business. I don't know if that was inclusive of Bear Swamp.
So I don't know if you can Yes. Maybe just clarify
No, it wouldn't have been. I was just referring to our owned assets there, Robert.
Okay. So basically if I add those two pieces that's 40,000,000 to 65,000,000 and then we'd add Bear Swamp on top of that? That's kind of you're thinking about the buildup to 2016? Are there any other major pieces that are missing?
Well, Bayside's in there, but it can't be it's not $5,000,000 one way or the other.
Right. 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.
Wanted to go back to Emera Energy. Just a couple of maybe some more detailed questions. Just hearing commentary on the guidance there, I think you mentioned the lower end of the range. I mean, it seems that you're using some pretty conservative assumptions in the back half. Just wanted to clarify that.
It seems like it's premature assuming pretty low pricing and perhaps not exercising the transportation capacity that you bought this quarter.
Yes. So I mean, the market has been weak. We haven't realized transportation capacity investment the way we generally like to. And we still got a couple of more relatively heavy cost months in there in July, August and September. So as I said, it is very been 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 like comfortable guidance for us based on the experience we've had so far this year. There is also a little bit of new pipe capacity coming on in New England, 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 could would be a very nice surprise.
Yes. I think, Ben, I think it's worth understanding 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 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've purchased some more transportation, think you characterized as short term, then you have some good optionality if there's some volatility later this year. But when you think of short term, is that you're referring to more the short term impact in the quarter or more like a one year commitment on the capacity? Or is it more kind of the five years that we've seen before?
Yes. No, no. Far and away, the majority of our capacity is kind of 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 commitments coming into this summer. Half of them are rolling off by kind of the start of the 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 2016 than 2015 despite the fact that the 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 and earnings by not buying transportation capacity. But just kind of if you look forward from the position we're in today, all other things being equal, a sniff and chunk kind of comes off. And as it's rebid in a weaker market, the market value of the capacity is actually lower in terms of its absolute dollar cost.
So again, I think the
main point is it's short term and known and that's the primary issue. Okay.
I just want to state the segment more, a lot of numbers in there. On gas plant side, the state tax, was that a change in law that came out of nowhere? Is that 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 sales of gas. And in fact, we've been selling gas in Connecticut since 02/2003, 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 would apply to us and that it could apply to our sales, our intercompany sales essentially to Bridgeport Energy. So we kind of 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 kind of is just on the adjustment. Going forward, obviously it's a much smaller number on an annualized basis than it is over a thirty month period. The answer to kind of what's the bottom line impact is it depends. 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 bumps Bridgeport out of the market.
That could happen. Probably not significant enough to do that. On other days, it could mean that Bridgeport winds up being the absolute marginal unit, which means it's setting the price of power. And because it's setting the price of power with the gas tax in it, we're effectively recovering that completely from the market. So there's no bottom line impact in that circumstance.
And then there's other days where we're not the market setting entity and it's just a straight increase to Bridgeport's cost of gas. I'm probably getting way a little bit far down in the weeds here. All that to say, you know, on an annualized basis, assuming that the worst case happens in every circumstance, it's probably it could be $5,000,000 on Bridgeport's cost of fuel. But the worst case won't be the driving force every time. But I just I put that out as just a fence post.
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're heading towards 85% regulated exposure, you're at the high end. And you've created a lot of value in the New England gas plants. And it seems like there's a disconnect between plants with capacity payments and merchant like gas plants out there.
So I mean, are you is there a possibility that you could potentially monetize those assets and redeploy and maybe some other gas plants at some pretty attractive prices today?
Mean, Ben, the only thing I have to say to that is we're always looking at our portfolio and we'll make decisions as time unfolds. But there are no plans to do that at this point.
And we have no further questions in queue at this time. I'll 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.