Emera Inc (EMA) 2016 Q4 法說會逐字稿

Good morning, ladies and gentlemen. Welcome to the Emera fourth-quarter 2016 conference call and webcast.

(Operator Instructions)

Please note that this call is being recorded today, Monday, February 13, 2016 (sic - see press release "February 13, 2017") at 11 AM Atlantic Time. I'd now like to turn the meeting over to your host for today's call, Mark Kane, Vice President Investor Relations for Emera. Please go ahead, Mr. Kane.

Thank you, Sharon. Thank you all for joining us this morning for Emera's fourth-quarter and 2016 year-end conference call. Emera's fourth-quarter and year-end earnings release was distributed Friday evening via Newswire, and the financial statements and Management's discussion and analysis are available on our website at Emera.com.

On the call today from Emera is Chris Huskilson, President and Chief Executive Officer, Greg Blunden, Chief Financial Officer, and other members of the Management Team at Emera. 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 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, licenses and permits, environment, insurance, labor relations, human resources, and liquidity risks. 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 live webcast. Now, I'll turn it over to Chris.

Thank you Mark, and good morning, everyone. Emera delivered adjusted net income of CAD104 million, or CAD0.51 per share in Q4 of 2016, compared to CAD87 million, or CAD0.59 per share in Q4 of 2015.

For the 2016 full-year period, adjusted net income was CAD475 million, or CAD2.77 per share, compared to CAD330 million or CAD2.26 per share in 2015. These fourth-quarter results are in line with our expectations, considering the mild start to the winter season in the Northeast.

They were driven by the addition of Florida and New Mexico operations which offset the lower results at Emera Energy. For the year, our companies performed well.

Despite power prices in New England that were well below 2015 levels, Emera Energy delivered results that were as expected in a mild weather year. Emera Florida and New Mexico operations delivered CAD172 million of net income before financing costs of CAD93 million for the six-month period we owned the business. This was in line with expectations and reflects that Tampa Electric is earning near the top of its allowed ROE range.

In Nova Scotia, we have implemented 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 a rate stability plan which was approved by the Utility and Review Board.

In December the UARB approved the refund of over-recovered 2016 fuel costs, which will result in an approximately CAD36 million one-time refund to customers on their bills before April 30 of this year. This will have no impact on 2017 earnings as a result of this refund.

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 they can depend on and budget around.

With the addition of the Florida and New Mexico operations to our business, we were well above our 75% to 85% target for earnings coming from regulated businesses in 2016, and our dividend is more than covered by regulated earnings. We grew our dividend 10% in 2016. As always, we set our dividend within our targeted payout ratio of 70% to 75%, and in 2017 we expect to be near the top of that range.

Moving to the Maritime Link project, construction continues to progress. The project remains on schedule and on budget, and an expected in-service date late this year.

ADB is progressing well with both converter sites in Nova Scotia and Newfoundland. The converter buildings are now enclosed, which will enable the installation of the converter technology and preparation of the AC and DC switch [yards]. Manufacturing of both subsea cables is progressing, with installation on schedule for midyear.

The joint venture between Emera Utility Services and Rokstad Power is working to complete the high voltage direct currents transmission lines, with construction advancing in both Nova Scotia and Newfoundland. To date, approximately CAD1 billion of the CAD1.6 billion project has been spent.

With the growing investment in the Maritime Link project, AFUDC earnings will grow in 2017 from the CAD21 million earned in 2016. After the project goes in service, which is expected at the end of this year, we will begin to have cash earnings.

Now for our continuous construction of the Larbador-Island Link, or LIL. We continue to earn AFUDC on our investment in that project.

As the LIL investment grows, we expect AFUDC to grow in 2017 from CAD24 million earned in 2016. Depending on the final cost of the project, we expect that there will be an opportunity to invest an additional CAD200 million of capital in the LIL project to maintain our overall ownership position.

At Emera Energy, EBITDA from the New England generating facilities was significantly lower quarter over quarter. Market spark spreads were slightly weaker, averaging around $9 in Q4 of 2016 compared to $11 in 2015.

The dramatic change in EBITDA reflects market conditions back in 2014 and early 2015, which allowed us to place very favorable forward hedges on approximately half of our New England capacity for both the first and fourth quarters of 2015. The resultant achieved spark spreads in Q4 of 2015 was approximately $25 compared to $10 in Q4 of 2016 when market conditions normalized and hedging opportunities were materially reduced. We believe that these lower spark spreads will prevail in 2017.

Full-year EBITDA for the New England plants was also lower in 2016 compared to 2015, again reflecting the very favorable hedges in 2015. To put that in perspective, 2015's EBITDA results at CAD140 million were more than twice our forecast when we acquired the facility. If we normalize our 2016 recorded EBITDA for the CAD20 million charge to prior years' fuel taxes, the results were in line with our expectations at acquisition.

The 11th ISO New England forward capacity auction was held on February 6 to purchase capacity for the 2020 and 2021 commitment period. The auction cleared at $5.30 per kilowatt month, down from $7.03 for the 2019/2020 period. The $5.30 was within our expectation of $5 to $7, and in the middle of capacity values for 2017, which are now $3 rising to $7 in the second half of this year.

In 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 and signed into law by Governor Baker last summer.

The bill mandates a competitive solicitation for long-term contracts to supply Massachusetts with incremental hydro resources, new Class 1 renewables or a combination totaling 9.45 terrawatt hours. A draft RFP has been issued by the Electric Distribution Utilities in Massachusetts, with the final RFP due no later than April 1, 2017.

These are expected to be due late July 2017. Preference shall be given to proposals that combine hydrogeneration and new platform renewables.

We believe that Emera can help the Commonwealth meet its clean energy goals through a subsea cable we call Atlantic Link between New Brunswick and the Boston area. We think this will be an extremely viable option to move clean energy into New England.

We have initiated a solicitation process for power over our proposed line. Proposals are due in early April, and contracts are expected to be awarded in June of this year with in-service dates in 2022.

The Emera Florida and New Mexico Companies provide excellent opportunities for rate-base growth. Our capital spending projections for 2017 through 2020 for the Emera businesses is CAD6.5 billion of visible identified investment.

We see additional opportunity to apply Emera strategy centered on clean, affordable energy to drive growth within our businesses. At Tampa Electric we plan to develop large-scale solar power and to reduce carbon intensity of our generation fuel mix through increased use of natural gas. At Peoples Gas and New Mexico Gas, we see potential to grow these businesses by expanding the distribution of cleaner burning natural gas to vehicle fleets, industrial customers and new residential customers.

To fund these investments, in addition to our external financing activities we have redeployed cash within our businesses. Over the past 18 months we have raised over CAD1 billion of cash within our business through actions such as the sale of our interest in Algonquin Power, refinancing Bear Swamp and rebalancing self insurance at the Barbados.

With the TECO acquisition closed and the integration complete, we expect that investors will clearly see the value of our strategies in Emera's earnings power. We will continue to implement our strategy in Florida and New Mexico, which we expect will open the door to additional capital investment over the long term.

We are well positioned to deliver strong earnings growth and deliver market leading total shareholder returns. We are making great progress towards achieving many of our strategic goals, and look forward to a bright future. With that, I'll turn things over to Greg to provide you with an overview of our financial results. Greg?

Thank you Chris, and good morning everyone. Emera's consolidated net income in Q4 2016 was CAD70 million, or CAD0.34 per share. When quarterly results are normalized for the CAD34 million of mark-to-market losses, fourth-quarter 2016 net income was CAD104 million, or CAD0.51 per share, compared with adjusted net income in Q4 2015 of CAD87 million, or CAD0.59 per share.

These results were below market expectations for the quarter for what we believe are a couple of reasons. The first was the results from Emera Energy. Spark spreads for the New England generating facilities were below Q4 2015 levels which, as Chris mentioned, were in part due to the result of a significant portion of Q4 generation hedged to very favorable spark spread levels last year.

Second, market estimates for Emera Florida and New Mexico were higher than actual; however, quarterly results will vary due to weather-related sales and timing of operating expenses. For the year Emera Florida and New Mexico performed as planned, and Tampa Electric earned near the top of its allowed ROE range.

Our adjusted 2016 net income was CAD475 million compared with CAD330 million in 2015. The major driver of the improved results was the addition of the TECO companies for six months, which more than offset the lower results of Emera Energy. In addition gains on the sale of the Algonquin shares and the SIF rebalancing more than offset acquisition costs related to the TECO transaction.

Moving to the segment results. I'll begin with Emera Florida and New Mexico, which provided CAD63 million to adjusted earnings, or CAD19 million net of the CAD44 million of permanent financing costs in the quarter. For the six-month ownership period in 2016 the contribution to net income was CAD172 million, or CAD79 million net of the CAD93 million of permanent financing costs.

The Florida operations continue to enjoy good customer growth. And as I previously mentioned, Tampa Electric continues to earn near the top of its a allowed ROE range of 9.25% to 11.25%.

Nova Scotia Power's net income was CAD34 million in Q4 2016 compared with CAD40 million in Q4 2015. The decrease was primarily due to increased OM&G from higher storm costs and the timing of generating-unit maintenance.

SPI's 2016 net income was unchanged from 2015 at CAD130 million. Nova Scotia Power also continues to earn at the top end of its allowed ROE range of 8.75% to 9.25%.

Emera Maine contributed CAD11 million to consolidated net income in Q4 2016 compared to CAD5 million for the same period of last year. Results in Q4 were driven by lower OM&G and higher transmission rates, partially offset by the loss of two large industrial customers. Emera Maine's 2016 net income was CAD47 million compared to CAD45 million for the same period last year.

Emera's Caribbean net income was CAD8 million in Q4 2016 compared to CAD14 million in Q4 2015. The decrease was primarily due to lower electric margin as a result of lower energy sales at Grand Bahama Power due to the effects of Hurricane Matthew, partially offset by higher energy sales in Barbados due to warmer weather.

Emera Caribbean had 2016 net income of CAD100 million compared to CAD41 million for the same period of last year. The higher net income was primarily due to the net gain realized from the SIF rebalancing in the second quarter and a decrease in OM&G, partially offset by increased income tax expense.

Fourth-quarter results for Emera Caribbean do not include any of the $28 million of Hurricane Matthew restoration costs. We have a regulatory agreement in place that will allow the recovery of the majority of these costs over the next five years with no impact to the all-in rates over that period.

Emera Energy's adjusted net income in Q4 2016 was CAD5 million compared to CAD35 million in Q4 2015. This decrease was primarily due to lower spark spreads of the New England gas generating plant.

Results in Q4 2015 reflected very favorable hedges put in place in Q1 2015 when the region was recovering from the Polar Vortex. Emera Energy contributed adjusted net income of CAD24 million in 2016, about the middle of the range we had forecast in a normal weather year, compared to CAD130 million in 2015 which experienced an unusually cold winter.

Emera Energy's 2016 mark-to-market loss had a material impact on reported earnings in the year, so I want to take a moment to help you put that into perspective. Consistent with prior periods, Emera Energy had a number of asset management agreements, or AMAs, with gas distribution utilities, power utilities and natural gas producers.

The AMAs involved Emera Energy buying or selling gas for a specific term and the corresponding release of the counterparties' gas transportation or storage capacity to Emera Energy. Mark-to-market adjustments on these AMAs arise on the price difference between the point where the gas is sourced and where it is sold.

At inception, the mark-to-market adjustment is fully offset by the value of the corresponding gas transportation asset. Of course the gas prices move over the term of the AMA, which means the value of the transport also changes. However because these two elements are accounted for differently, the gas is adjusted to market but transport is amortized evenly, that results in some mark-to-market gains or losses recorded in income.

Ultimately, though, the gas transportation asset and the adjustment to market reduced to zero at the end of the contract term. It is important to emphasize that, assuming the counterparty performs, these arrangements have no actual economic market exposure because regardless of the difference in the value of the gas between the receipt and delivery points, Emera Energy has the transportation capacity that enables it to move the gas to the point at which it is priced.

Our corporate and other segment posted a CAD17 million adjusted net loss in Q4 2016 compared to a loss of CAD7 million in Q4 2015. The variance was primarily due to higher interest expense as a result of the permanent financing of the TECO acquisition.

Corporate and other reported a 2016 net income of CAD2 million compared to a CAD16 million loss in 2015. Results in 2016 included an after-tax cost of CAD166 million related to the acquisition of TECO, which was more than offset by the CAD189 million of after-tax gains in the second quarter on the sale of Algonquin shares and the conversion of the Algonquin subscription receipts, as well as the remaining sale of Algonquin shares in December 2016.

Corporate and other has a mark-to-market loss in 2016 of CAD114 million related to foreign exchange contracts put in place for the TECO transaction. This loss was the reversal of the mark-to-market gain recorded in Q4 2015.

In prior periods corporate and other included earnings from our investment in Algonquin. With the sale of our ownership interest last year we no longer have an ownership interest in Algonquin. The Algonquin investment provided good returns over time and we raised approximately CAD700 million through the sale of these shares, which helped fund the TECO acquisition and provide funds for future capital investments.

In addition to the cash raised through the sale of Algonquin, we raised an additional almost CAD335 million through a common-share sale in the form of a bought deal in December. This cash will be used for general corporate purposes such as funding our investment in the Maritime Link and Labrador-Island Link projects through to the end of this year. That's all for my update, and now we'll be happy to take your questions.

(Operator Instructions)

Your first question comes from the line of Linda Ezergailis from TD Securities. Your line is open.

Thank you. I realize it's an early -- still early in the year but can you give us a sense of some puts and takes in terms of what you're seeing in your New England generation and trading business? We had a pretty significant storm there very recently, and not sure how that might affect gas transportation constraints, power capacity?

Maybe with some load shedding as well offsetting any strength in pricing. Maybe you can walk us through the puts and takes and how you're seeing Q1 shaping up?

Linda, it's Judy. You're right to say it is very early. January is generally a decent month. It was a decent month for us in our trading and marketing business.

I'd say that we committed around our own forecast. Gas prices have picked up a little bit, which helps our business, gives us a little bit of a better bid/ask spread on most days.

With respect to the weather and the storms, not really too much affect there, to be honest. January was warmer than normal, and so that does tend to suppress volatility a little bit. And we'll see now what February and March will bring.

I will say it would be very premature for me to say anything about the quarter one month in in essentially the biggest quarter of the year. So I'm not going to go that far.

Spark spreads are in and around the $10, $11 range, which is the summer peaking season in the electricity market anyway there. But if you're going to have a generally mild January, that's not going to do too much for spark spreads. Again, of course, when you say puts and takes when we look out to June, we will start to see essentially a doubling of our capacity value, which will help, particularly in light of relatively, don't call them weak, but normal spark spreads, certainly less than we had been able to hedge out over the last year.

Thank you. Maybe I'll move on a bit south of there. I realize weather can be fickle, but maybe someone can comment on what the weather and load and customer demand has been like so far year to date in Florida and New Mexico?

Yes, I think in general the results in Florida have been pretty much on plan. As it relates to New Mexico, it has been a bit mild there. And so probably a little bit below plan in that circumstance.

Okay, that's helpful. Maybe just thoughts on integration with TECO. Any further iterative thoughts beyond what you've shared in December on cost and revenue synergies?

Yes, I mean we're at a pretty stable position there now, Linda. We're very happy with where that integration has gone, and we see lots of opportunity around that business. Our real focus there is on the growth of the business, and you'll see us really focusing primarily on growing the solar side which is just early stages there.

But as well we see opportunity to do some conversions on the gas side. So those are really the big things for Tampa Electric. Then we're also seeing some reasonably good growth on the gas LDC as well. That's really where our focus is. The businesses are working really well together.

Great, thank you.

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

Yes, thank you for taking my questions. Just wanted to touch on your 2017 to 2020 capital plan of CAD6.5 billion. That seems to be a bit of a step up from what was initially put out at the Investor Day in December. Just want to get a sense of what some of the puts and takes are on your longer-term capital plan here.

Yes. I think Rob, it is the same as the plan we would have put forward. We may have been talking about 2016, as well at the time at about CAD8.2 billion in total. But from 2017 to 2020, it is CAD6.5 billion.

There's really no change in that plan. It includes a substantial amount of activity around the business of things like hydro in Nova Scotia, things like some more investments around the generation facilities in Tampa, and also things like AMI being added to the system. Those are the kinds of things that are there.

In both locations we're continuing to storm harden the systems, and that activity is paying off from a reliability perspective as well. So that's really the essence of those capital spends.

All right, thank you for that follow-up. Then just maybe looking after 2017, can you give us a sense of your financing plan for the upcoming year?

Rob it's Greg. We were obviously fairly heavy in the capital markets last year, including in the month of December when we sold a balance of Algonquin and did an equity issue. So we don't have any material requirements in 2017.

We have a couple of minor rollovers that we have to do on the debt side, but for the most part, nothing we need to do at all. We still will, on a periodic basis, tap the equity market when it makes sense in that $0 to $300 million range. But from where we sit right now, we don't have any specific requirements.

I appreciate that. Thank you.

Thanks, Rob.

Your next question comes from Mark Jarvi from Desjardins. Your line is open.

Good morning. Question going back to the CapEx was, if I look at what was in some recent marketing material versus what's shown for the US utility business, looks like it's up about CAD100 million in 2017. Is that just a timing issue or is there some new opportunities you've identified since you've taken control of the business?

Yes, it would be timing at this stage. As I said earlier, we have identified some opportunities to do more on the solar front and on the gas side, but those are not in our numbers yet.

Yes, Mark. I think there was some solar investments that slipped from the fourth quarter of last year that will get done in the first quarter. Obviously when we're talking Canadian dollars, you can get a little bit of foreign exchange variance quarter over quarter or year over year. So I wouldn't read anything into CAD100 million on a year-over-year basis.

Okay. Just going back to the comment about what your earning at Tampa Electric, is there anything aside from general factors like weather, that would maybe limit you from continuing to achieve near the top end of the range in 2017?

No. I mean, it's a very well run utility. They are still experiencing customer growth and as a result load growth. Certainly normal weather would be necessary.

Obviously the amount and volume of storms always has an effect on the utility's ability to earn. But from where we sit today, we would expect somewhat consistent performance out of Tampa Electric in 2017 as they performed in 2016.

My final question is, when you think about the transition projects, the Maritime Link and Labrador-Island, looking through the balance of the year, what items or what timelines would we really be looking to get past to fully derisk the projects? What kind of remaining items are there that keeps you guys up at night?

Well I think two really big things that are going to be time-related will be the installation of the cables. Those cables are -- one of the cables is actually beginning its [Lodo] right now onto its shipping barge. So we're expecting that cable will arrive here in a couple months, and we'll end up starting that campaign probably in early May.

Making sure that we get the cables installed kind of one after the other, that's going to be an important piece. It will begin to happen in late spring, early summer.

The other big thing is getting all the transmission completed. As you know, we went through a change in transmission contractor, and so it's a little bit tighter than it was before. So as we enter the summer we would expect to have those transmission lines completed.

That will be important to moving into the commissioning stage. But as we sit today, we would still expect to be able to energizing those circuits in and around the October time frame.

Okay, that's helpful. Those are my questions.

Thanks, Mark.

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

Thank you, good morning.

Good morning.

I know this is a smaller part of your business, but I'm just curious on what you're seeing in really the Southeast portion of New Mexico on just the gas LDC business, in particular given all of the Permian activity that's spilling over from Texas and into New Mexico, and just the ramifications it has on the outlook for the growth of your LDC business in the State?

Well, we're certainly focused on growing that business, and primarily by getting to customers that we're not able to serve today. So we actually have a fairly substantive initiative on in the State to actually extend service to a number of communities. That's something we're working hard at right now.

The other thing is, is that there's a real desire on behalf of the State to move more gas to market. So we're also looking at how we might help facilitate that. We move some gas across the Mexican border today, and we would be working to see if it's possible to move some more.

Those are really the two biggest things that we're doing right there at this point. We're also, though, looking at revitalizing the strategy for that business, and we're just in the process of doing that today, looking right across the energy spectrum to see what else we might be able to do in that State. For us it's still a bit of early days.

We really concentrated our strategy work in Florida because we did see that being the larger piece of the business. Now we're turning our attention to New Mexico, and we're quite excited about what we see there, but it's just a little bit too early to start talking about what that will turn into.

Okay, that's helpful. Maybe just keeping on the natural gas theme. What opportunities are you seeing on an incremental basis within effectively New England? This is really about Maritimes Northeast and the asset base you have on either enhancing connectivity, expanding lines. What do you see, especially given the tone has really changed in the last few months in the US, as far as the ability to build pipeline seems like a lot more favorable now than it was a few months prior?

Yes. I think the biggest challenge and opportunity I think in the region in the Northeast is to figure out what the next steps look like as the supply base off Nova Scotia continues to decline. There is going to be need to invest around that in order to make sure that gas continues to be delivered into this region in both the State of Maine and also into the Maritimes.

I think that's where our concentration is going to be in the short term. But as you know, we continue to look really hard at how we can invest around the gas businesses in the South, and that probably would be a bigger concentration for us today.

Okay, great. Thank you.

Thanks, Andrew.

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

Good morning. Maybe I can come back to marketing and trading. Judy, can you comment on the volume of the book for the 2017 year versus 2016, and if there's any comments you can give on the underlying costs or pricing?

I would say the volume of the book is relatively consistent. Just to give you a sense, Robert, in 2016 we would have moved an average of 1.1 Bcf a day of gas. We are relatively consistent with that year over year.

We did have our second successful bid for Enstar's business. They are the largest LDC in the Northeast, and we've got that business now again through to November of this year. So that is a determiner of volume and throughput.

The AIM pipeline project is now fully in place. So I think there was about [90,000] perhaps or so short on [325,000] in total of that project that was a little bit late coming on.

That is all up and running at this point. The expectation has been that will serve to dampen New England volatility a little bit. We'll see how that plays out.

It's hard to make the judgment when you have kind of a warm January of whether or not -- what the real impact of that is, but it would be our expectation to some extent in that it may pressure the basis between New England and New York as well. That remains to be seen, and we're going to kind of watch carefully and see how that plays out.

So we always talk about marketing and trading managing to earn somewhere between CAD15 and CAD30 million annually. This year, 2016, we're at the low end of the range. I'd say we don't expect that we're going to blow the high end out in 2017, but we do believe we will be kind of probably comfortably in the middle there.

Okay, that's perfect. Thanks, Judy. With respect to the Florida, New Mexico utilities, do you have what the 2016 full-year numbers are, either in USD or CAD?

Robert, they would have filed their 10-K, I think, over the weekend, as well.

Are the numbers completely swappable back to the way you're reporting?

No. The 10-K that was filed was the Tampa Electric only. So it would only be picking up Tampa Electric and Peoples Gas. It would not pick up New Mexico, nor would it pick up TECO services.

Okay. On a comparable basis to the guidance you've given, do you have what the 2016 full-year numbers were?

Just give me a second, Robert, to pull it out. I think they were about $2 million or $3 million ahead of where they were a year ago.

Okay.

2016 year to date was $278 million for all three of their businesses, for Tampa Electric, Peoples Gas and New Mexico Gas.

Okay, perfect. And this is last question I've got, as it relates to whether it's the mass RFP or just anything else that's going on, and then your Atlantic Link project. Have there been any discussions around what a proposed border adjustment tax may or may not do in terms of the interest and receptivity of Canadian electrons coming into the market?

I would say not really at this stage, Robert. It is quite unclear as to how that might reflect. I think the only one thing that we know is that obviously most of the energy that we're talking about will come from Canada in the end, and so it will all be on a level playing field.

I do think that is a small advantage for Atlantic Link because we do expect that we're going to get offers from the State of Maine to be brought back into Canada and then down through the Atlantic Link. That's something that we're working through right now.

We've had a very strong response to our request for our offer. We're quite excited about that, and in fact, some of those projects would be US to Canada to the US again. So again, don't exactly know how that will get treated by any tax changes, but we think that at least can be a benefit that would exist with Atlantic Link.

That's an interesting aspect. If I could ask just one follow-up then. At one point there was -- you made some investments in the wind side in Maine with Northeast, and is there any thought of continuing to look at generation assets where there's that strategic benefit of potentially backing some of your projects?

Well I think the -- we probably wouldn't be investing in Maine, just because it just gets complicated relative to the distribution ownership there. But I do think that we have a lot of good counterparties that will and are willing to invest there.

As it relates to Canada, though, I do believe that we would be happy to back some projects in order to ensure that we do get the amount of supply that we require. We have been in contact with some counterparties who are interested in that. So for sure, one of the things we want to do is make sure that we get enough energy to fill that line, and so far it looks very positive, lots of interest. But we're always willing to play a role, as we were quite good at building those assets, as well.

That's great. Thank you very much.

Thank you.

Your next question comes from Robert Catellier from CIBC. Your line is open.

Thank you. First just a quick housekeeping item. There was a comment in the press release about Emera Maine moving to large industrial customers. Can you quantify that or talk about the materiality?

Yes. It's Alan Richardson here. Basically it's about CAD1 million after-tax 2016 and another CAD1 million after-tax 2017, and then it comes out as the rates adjust. So that transmission formula rates adjust over time. There's a little bit of a lag there.

Okay. It doesn't sound like it's material. Just another question here. When you look at establishing a new equivalency agreement with the government of Canada about phasing out some of the coal-fired plants, do you think there's any risk to the useful life, or any risk to stranded -- having stranded capital, or do you expect any loss there that might be recovered over time?

No. I mean, I think that is the whole point of extending the equivalency out through time. First of all, we believe that we will be able to perform better than the cap that has been set for us, and as we perform better what the equivalency agreement would allow us to do is carry forward those emissions through time. But on the other hand we don't really expect to run those facilities a lot, but we do expect them to be there to back up some of the purchases we would do from places like Newfoundland and Labrador. So it will allow us to have capacity without actually having to emit any real material emissions.

Okay, that's helpful. My last question is, where are you focusing your tax reform law lobbying efforts in the United States? Which elements are really the most important to Emera?

Well, the industry is really, I think, very focused in this area. Through Tampa Electric and Emera Maine we're members of Edison Electric, and so that's where the industry is speaking on this topic. The two things that I would say the entire industry is aligned on are, one, interest deductibility. The industry does see that's beneficial to customers.

Secondly, also on the issue of accelerated depreciation. We would say that creates inter-generational issues, and probably is not necessarily a benefit to customers either. So both of those topics I would say that the entire industry is thinking the same way and concerned about the effect it will have on their customer base, and our customer base as well.

Okay, thank you.

Thanks, Robert.

(Operator Instructions)

Your next question comes from David Quezada from Raymond James. Your line is open.

Yes, thanks. Good morning, guys. Just a quick question on the Massachusetts RFP, the clean power transmission potential projects there. Appreciate that it seems like Atlantic Link is probably the front runner, but any update on any of the other potential projects you've been looking at in that region, the Maine new energy interconnect and the other two?

Yes. I mean, I think those are projects that likely will have a role, as well. In fact, depending on how much energy actually gets proposed out of the State of Maine, the Maine interconnect project could in fact be necessary to get that energy to New Brunswick. We'll have to see what the balance of energy on each side of the border is. But we do see those projects as being important to continuing to reduce bottlenecks in the transmission system and do expect that they will have a place.

In the case of Atlantic Link, we believe it's a competitive project and we'll put it forward that way. We also believe that particular project, not only does it actually deliver US energy into the US market and it also, we believe, will come into a location in the Boston area that will be important to security and reliability of the system for Boston. When we look at those things, those are all nice advantages that the project has.

Okay, great. Thank you very much. That's all I had.

Thank you.

Thanks, David.

(Operator Instructions)

We do not have any questions at this time. I'll turn the call over to the presenters.

Okay. Well, thank you very much, folks. We really appreciate your participation on the call today and also your interest in Emera. We hope everyone has a safe day. It's a pretty stormy day here in Halifax. Take care.

Thank you.

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