Emera Inc (EMA) 2016 Q2 法說會逐字稿

Good morning, ladies and gentlemen, and 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 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 of 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, 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 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'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 risk, 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 in 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 achievements 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. Emera delivered adjusted net income of CAD237.5 million or CAD1.59 per share in Q2 of 2016 compared to CAD48 million or CAD0.33 per share in Q2 of 2015. Adjusted net income excluding cost related to the TECO Energy acquisition was CAD279.5 million or CAD1.87 per share. There were several one-time gains in the quarter which more than offset the transaction cost associated with our acquisition of TECO 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 targets 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 Q2 of 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-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 CAD8 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 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 CAD2.09 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 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 a mid-2017.

A joint venture between Emera Utility Services and Rockstad 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 as 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 continue to be weak in Q2 of 2016 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. Emera Energy generated CAD34 million in margin on gas sales over the quarter, a CAD12.6 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 a 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 and associated transmission. As part of its effort to meet legislated 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 I 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 2019. We work with stakeholders and reached agreement on a rate stability plan, which has recently approved -- it 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 a stable, predictable and affordable electricity pricing they can depend on as the end budget [allows].

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 recognize that the fund was likely over-funded to provide risk protection for customers.

We engaged third-party risk advisors to do a detailed analysis. They identified the ability to recapitalize CAD43.4 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'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. TECO Energy brings this to almost 85%. We also target a dividend payout ratio 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'll 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 CAD207.8 million or CAD1.39 per share. When quarterly results are normalized for the CAD29.7 million of mark-to-market losses, second quarter 2016 net income was CAD237.5 million or CAD1.59 per share.

Adjusted net income in Q2 2015 was CAD48 million or CAD0.33 per share. There are several significant items in Q2 2016, including TECO Energy acquisition cost of CAD42 million or CAD0.28 per share. The cash gain on the sale of Algonquin Power common shares of CAD145.5 million after tax or CAD0.97 per share. A gain on the conversion of Algonquin Power subscription receipts and dividend equivalents into common shares of CAD53.1 million after-tax or CAD0.35 per share.

And as Chris mentioned, a gain on the reduction of the Barbados Light & Power Self Insurance Fund liability of CAD43.4 million after tax or CAD0.29 per share. In addition, we had a charge in the quarter of CAD11.8 million after tax or CAD0.08 per share to recognize state fuel taxes at Emera Energy from November 2013 through to March 2016, of which CAD2.1 million related to Q1 of this year.

Moving to the segment results, I'll begin with Nova Scotia Power, which provided net income of CAD28.4 million in Q2 2016 compared to CAD16.9 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 CAD80.9 million compared to CAD84.9 million for the same period last year.

Emera Maine contributed CAD9.7 million to consolidated net income in Q2 2016 compared to CAD13.7 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 CAD19.0 million compared to CAD25.2 million for the same period of last year.

Emera Caribbean's net income increased to CAD58.1 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 CAD67.9 million compared to CAD13.6 million for the same period of last year.

Our Pipeline segment contributed adjusted net income of CAD8.3 million in the quarter, a decrease of CAD1 million from Q2 2015. Year-to-date net income was CAD18 million compared to CAD19.2 million for the same period of last year.

Emera Energy contributed an adjusted net loss of CAD28.7 million in Q2 2016 compared to an adjusted net income of CAD3.4 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 to March 2016 and lower marketing and trading margin, which included a CAD12.6 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 CAD19.2 million.

Our Corporate & Other segment posted a CAD161.7 million adjusted net income in the quarter compared to a loss of CAD100,000 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 cost. Year-to-date, Corporate & Other's adjusted net income was CAD152.7 million compared to a loss of CAD3.1 million for the same period of last year.

Before opening up for questions, I'd 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 US 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 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'd be happy to take your questions.

(Operator Instructions) Linda Ezergailis, TD Securities.

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 are some seasonality in terms of revenues and maybe more of a stable cost outlook. But can you give 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'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, then in the second quarter. As always, our guidance is that we expect the business to be able to deliver between CAD15 million and CAD30 million of net earnings annually with some opportunity for upside.

So we've had a few of those upsides 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 CAD15 million a month in fixed cost transportation and storage and asset management cost, that's dropped off to about CAD12 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's there now at about CAD12 million a month will be CAD6 million a month starting November 1. Now that said, there will 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 expiry has less of an impact in the winter months of course because gas is kind of fundamentally a flow-through in the PPA. It has -- so it's more significant in the summer period. 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 the range of CAD25 million to CAD35 million, 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 first and fourth quarter of 2015 that really enabled us to earn outsized returns there in excess of CAD50 million in earnings.

So the CAD25 million to CAD35 million is kind of what we think right now. We're frankly reasonably all quite open for the rest of the year because 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 CAD25 million and CAD35 million, which is really well above the expectations we had when we actually acquired the asset. And once we get into 2017 of course, we've got a doubling of capacity prices beginning in June, which will add about CAD30 million in capacity revenues to the facilities.

Robert Hope, Scotiabank.

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-2018 or will it be when they actually start generating or transmitting electricity?

Yes. So at this point, we're expecting those facilities to go in 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'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 change of 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 for first of 2018.

Sorry, I was referring to the Labrador Island Link.

Okay, I thought you were talking about Maritime Link. So 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 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. 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?

No, 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 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 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. 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.

Paul Lechem, CIBC.

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 that ended up being [on desk]. 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?

So we're [complete] the financing on it, Paul. If you recall, the US hybrids that we issued effectively have the same treatment from the rating agencies as preferred shares and what we always said is with issue in and around CAD1 billion to CAD1.2 billion in some combination of US hybrids and Canadian prefs. And obviously, our preference was to have as much in US dollar denomination as possible, which is why we did the full CAD1.2 billion in US hybrids.

Just on -- also on TECO, can you remind me again when are the -- what are newest upcoming regulatory decisions that we need to worry about either 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 CAD110 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.

In New England, the tristate clean energy RFP looks like it's 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 tristate 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 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 know whether he wants to add anything to that.

Not just that the evaluation team did indicate that the analysis was complicated and that was one of the reasons for the delay, they issued that method at the end of 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.

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 a 9.45 terawatt hours of new supply which will be some combination of hydro and wind or at least Class I renewables. So anyway, I think that 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 on board, your regulated assets increased 85%, are you looking at any potential increases in the non-regulated side of the business in terms of any new power assets or 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, 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 businesses 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.

Andrew Kuske, Credit Suisse.

I guess the question is for Chris to start off with, and it's just in light of legislation in Massachusetts being signed yesterday. How do you look at Emera's role? And playing in that market is obviously 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 remain broadly. So how do you think about the best investment proposition from an Emera standpoint given the change in legislation in the Northeast?

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're very competitive on the transmission side. And that's really the way we look at it.

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 will 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 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, 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 within 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 and in those areas as well. And so 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 TECO deal. I believe the comment was that the duration that you've got in the market was in excess of what you're 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 were 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 CAD8 billion of opportunity over the next five years and we think that that will continue to grow.

Robert Kwan, RBC Capital Markets.

If I can come back to just 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 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 focused 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 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, our own and operating, will still be somewhat under-utilized. And so there is opportunity for more to be done to fill up that project and to ensure is 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 Maritime, 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 overland issues that we're seeing on transmission?

Well, so far anyway it 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&G cost savings that we saw in the quarter, was some of that timing or deferrals or make ups 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 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. So, we've made sure that the 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 the Emera Energy, if I'm pulling some of the numbers that I think Judy had mentioned earlier in the call, you've been targeting CAD15 million to CAD30 million of net income from the marketing and trading side. And I think you mentioned CAD25 million to CAD35 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 maybe just clarify that?

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

So basically if I add those two pieces, that's CAD40 million to CAD65 million and then we'd add Bear Swamp on top of that, and that's kind of how you're thinking about the build up to 2016.

Yes.

Are there any other major pieces that are missing?

Well, Bayside's in there, but it can't be -- it's not CAD5 million one way or the other.

Ben Pham, BMO.

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

Yes. So the market has been weak. We haven't realized on our transportation capacity investment the way we have we generally like to and we still got a couple of more relatively heavy cost months in than there in July, August and September. So as I said, it is very challenging for us to predict with precision training 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 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.

Yes, 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 so 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.

And because you've purchased some more transportation, I 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 the short-term, is that you're trying to more the short-term impact on 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, so 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 the 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 and 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 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're not -- we can't shrink our way to growth and earnings by not buying transportation capacity, but just if you look forward from the position we're in today, all other things being equal a significant chunk comes off. And as it's re-bid in a weaker market, the market value of the capacity is actually lower in terms of its absolute dollar cost.

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

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

So it's not a change in law. Emera -- it's actually a tax on Emera Energy's sales of gas and in fact we've been selling gas in Connecticut since 2003, but not to any end users. And so we, 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 inter-company 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, it's -- obviously it's a much smaller number on an annualized basis than it is one of a 30-month period.

The answer to kind of what's the bottom line 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 bumps Bridgeport out of the market, that could happen, probably not; 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 is 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, on an annualized basis, assuming that the worst case happens in every circumstance, it's probably -- it could be CAD5 million on Bridgeport's cost of fuel. But the worst case won't be the driving force every time, but I put that out that as just a fencepost.

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

And if I can squeeze in another one, just with the TECO transaction you mentioned, you're heading towards 85% regulated exposure, you are at the high end. And you've created a lot of value in the New England gas plants and it seems like there is a disconnect between plant's capacity payments and some of the merchant-like gas plants out there. So are you part of -- is there a possibility you could potentially monetize those assets and redeploy in maybe some other gas plants at some pretty attractive prices today?

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 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.