Mark Kane - VP, IR Scott Balfour - COO Greg Blunden - CFO Chris Huskilson - President and CEO Judy Steele - President and COO, Emera Energy

Linda Ezergailis - TD Securities Rob Hope - Scotiabank David Quezada - Raymond James & Associates, Inc. Andrew Kuske - Credit Suisse Robert Catellier - CIBC Robert Kwan - RBC

Good morning, ladies and gentlemen, and welcome to Emera Q2 2017 Earnings 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 also being recorded today, Friday, August 11th, 2017, at 11 A.M. Atlantic Time. I would 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, Emily, and thank you all for joining us this morning for Emera's second quarter 2017 conference call. Emera's second quarter earnings release was distributed yesterday afternoon via Newswire, and the financial statements and management's discussion and analysis are available on our website at emera.com. Speaking on the call today is Scott Balfour, Emera's Chief Operating Officer and incoming Chief Executive Officer; and Greg, Blunden, our Chief Financial Officer. Chris Huskilson, President and CEO, and other members of the management team at Emera are here to respond to your questions. This afternoon -- or this morning, excuse me, Scott will discuss the results from operations on our strategic initiatives, and Greg will provide an overview of the financial results. We expect the presentation segment to last about 15 minutes, after which we will be happy to take questions from analysts. I will take a moment to advise you that this conference call will contain forward-looking information and statements with respect to Emera. Forward-looking statements involve significant risk, uncertainties and assumptions. Certain material factors or assumptions have been applied in drawing the conclusions contained in those 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 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 made today. In addition, please note that this conference is being widely circulated via a live webcast. And now, I'll turn it over to Scott.

Thank you, Mark. Good morning everyone. This morning, I'll be discussing our operations for the quarter and year-to-date as well as providing an update on our strategic initiatives. Chris will join Greg and I in responding to your questions. Before I dive into our results, let me address a topic that I know you're interested in, the tragic accident at Tampa Electric's Big Bend station in late June. We extend our deepest condolences to the families of those who passed and were injured as a result of this incident. Tampa Electric has established the TECO Relief Fund to raise money for those affected, which TECO has seeded and is additionally matching contributions made to this fund. Internal and OSHA investigations into the cause of the incident are ongoing and are expected to take many months to be completed. Until those investigations are complete, we will not know for certain nor will we be able to comment on the causes. So, turning now to our very strong second quarter financial results, which were driven by improvements at virtually all of our regulated operations. These results present a much clearer picture of Emera's earnings power. They also demonstrate that the addition of the Florida and New Mexico operations dramatically smoothed the seasonality in earnings that we formerly experienced. We delivered second quarter 2017 adjusted net income and earnings per share of $117 million and $0.55 per share compared with $50 million and $0.34 per share in the second quarter of 2016 after adjusting for the items that were one-time in nature last year. For the first six months of the year, adjusted net income and earnings per share were $269 million or $1.27 per share compared with $188 million and $1.26 per share, excluding the one-time items. Earnings from our Florida and New Mexico operations contributed significantly to the improved results. Those companies delivered net income of $103 million or $58 million, net of the $45 million of permanent financing costs in the quarter and $182 million for the year-to-date period or $92 million, net of the $90 million of permanent financing costs. Tampa Electric was able to more than make up for the very mild winter weather with warmer weather than normal this spring. We expect the Florida operations to earn within their respective allowed return on equity ranges. Due to mild winter weather, New Mexico will probably be below our expectations for the year. Emera Energy continued to experience weaker than experienced and expected results due to New England market conditions that were similar to 2016 and an unplanned outage at the Bridgeport generating plant. For the last half of the year, Emera Energy will have the benefit of higher capacity payments that became effective June 1st. We continue to make good progress on our growth initiatives that we expect will grow earnings and allow us to continue to target 8% annual dividend growth through 2020. A quick comment on the timing of our dividend increases. In 2015, we raised the dividend twice; April and October. In 2016, we raised the dividend in July, coincident with the closing of the TECO acquisition. Prior to those two years, the Board historically addressed the dividend at its October meeting, and we expect that the Board would return to that normal pattern this year. In Newfoundland and Nova Scotia, work is progressing on the Maritime Link Transmission Project, which is on-budget and on-track to meet the planned January 2018 in-service date. To-date, we spent approximately $1.4 billion of the projected $1.6 billion project cost. We've completed the laying of the two 187-kilometer subsea cables, and we're currently covering those sections that need protection with rock. The overhead transmission is complete in Nova Scotia and approaching completion in Newfoundland. ABB is continuing work on the converter stations, and testing of the system has begun. We've completed hearings at the UARB for approval by Nova Scotia Power to make the cash payments to the Maritime Link starting next year. Due to the delay of the in-service date of the Muskrat Falls hydro plant, attention has focused on the timing of the start of depreciation. The proposal before the commission is to defer the start of depreciation until Muskrat Falls is delivering power. We will still depreciate the line over the 35-year life of the power sales agreement with Nalcor. We expect the final decision in that proceeding in September. The Labrador Island Link is now expected to be in service about the middle of next year. Our investment in this project will continue to earn AFUDC earnings until the Muskrat Falls hydroelectric project is fully operational, which is now expected between mid-2019 and mid-2020. In late July, we responded to the Massachusetts RFP for clean renewable energy for more than nine terawatt-hours of hydro and onshore wind energy and 1,600 megawatts of offshore wind energy. We think our proposed Atlantic Link Project can help meet the state's need for clean energy in a very cost-effective manner. The proposed line would originate in New Brunswick and come ashore in Plymouth, Massachusetts, the site of the soon-to-retire Pilgrim nuclear plant. This allows us to bring power to the Boston load center and avoid congestion in New England without the need for new terrestrial transmission lines. In Florida, we're continuing to explore opportunities for additional large scale solar facilities, taking advantage of investment tax credits while they remain available for the benefit of customers. In addition, we're looking at opportunities to displace coal-fired generation at Tampa Electric with lower emission natural gas fired generation. The potential investments related to these Florida initiatives and the Atlantic Link Project are not included in our current $6.5 billion capital spending forecast. Our spending forecast only includes items that are known and have regulatory certainty if appropriate. At Peoples Gas, we're continuing to look for opportunities to expand the customer base and gas infrastructure in the state. With the identified growth initiatives that we have underway and the prospects for new investment opportunities in Florida and projects such as the Atlantic Link Project, we look forward to delivering earnings and dividend growth over the long-term. And with that, I'll now turn it over to Greg for the detailed financial results.

Thank you, Scott, and thank you all for joining us this morning. We released our earnings and filed our quarterly financial statements and MD&A for the second quarter of 2017 yesterday afternoon after the markets closed. In Q2 2017, Emera reported net income of $101 million and earnings per share of $0.47 compared with $208 million and $1.39 per share in Q2 of 2016. Our second quarter adjusted net income and earnings per share, which excludes mark-to-market adjustments, was $117 million and $0.55 per share in 2017 compared to $238 million and $1.59 per share last year. Results in Q2 2016 included a number of items that were considered one-time in nature. Removing those one-time gains and charges, adjusted net income in Q2 2016 was $50 million or $0.34 per share. We reported an increase in cash flow for the quarter with a $378 million or 116% increase to $703 million, helped significantly by the addition of Emera Florida and New Mexico operations. For the year-to-date period 2017, we reported net income of $413 million or $1.95 per share compared with $252 million or $1.69 per share in the 2016 year-to-date period. Adjusted net income in the 2017 year-to-date period was $269 million or $1.27 per share compared with $358 million or $2.40 per share in the 2016 period. Again, adjusting for the one-time items in the year-to-date period, adjusted 2016 net income was $188 million or $1.26 per share. Despite the higher adjusted net income, our earnings per share were comparable as a result of the increased number of shares outstanding, following our 2016 share issuances. Second quarter net income for Emera Florida and New Mexico operations was $103 million or $58 million net of the permanent financing costs. This net income was higher than Q2 2016 due to higher base revenues following the addition of the Polk Unit 2 in January, continued strong customer growth, and more favorable weather in the second quarter of 2017. Florida experienced a very warm spring with degree days 13% above normal and 10% above the comparable 2016 period. On a year-to-date basis, Emera Florida and New Mexico contributed $182 million to adjusted net income or $92 million, net of permanent financing costs, which is comparable to the results in the 2016 period. The strong second quarter weather essentially offset the mild winter weather. With Polk Unit 2 going into service in January, depreciation and OM&G expenses increased, and AFUDC decreased. At Peoples Gas, results were higher than last year with almost 3% customer growth, which resulted in higher sales volumes. And unlike New Mexico Gas, Peoples Gas has a relatively good mix of residential, commercial and industrial customers, which allows it to be profitable even in the summer months. In New Mexico, results were comparable to last year at breakeven, which is normal for the second quarter for a winter peaking local gas distribution company with a mostly residential customer base. Nova Scotia Power delivered net income of $29 million in the second quarter of 2017 compared with $28 million in the 2016 quarter. In the 2017 year-to-date period, Nova Scotia Power delivered $99 million of adjusted net income compared to $81 million in the 2016 period. Results were benefited from lower OM&G costs and lower provision for income taxes, partially offset by higher depreciation expense. Emera Maine recorded Q2 2017 net income of $12 million compared with $10 million in Q2 2016 and year-to-date results of $25 million in 2017 compared to $19 million in 2016. These results reflect lower OM&G costs and higher revenues due to rate changes. The lower results at Emera Caribbean reflect lower energy sales at Grand Bahama Power due to the loss of several commercial customers following Hurricane Matthew in October 2016 and higher interest expense on new debt issued in the fourth quarter of last year. Results in Q2 2016 included the benefit of the $43 million reduction in the Barbados Light & Power Self Insurance Fund liability. Emera Energy reported an adjusted loss of $11 million in the quarter compared with a loss of $29 million in Q2 2016. Year-to-date 2017 was a loss of $1 million compared with net income of $19 million in the 2016 year-to-date period. Results in Q2 2016 included the recognition of $12 million after-tax of prior period sales fuel taxes. Marketing and trading margin increased $12 million to a loss of $2 million compared with a loss of $14 million in Q2 2016. Market conditions in 2017 were similar to those experienced in 2016. The lower short-term fixed-cost commitments for transportation, more valuable transportation positions in the current year, and higher volume of business drove improved results. For the year-to-date period 2017, marketing and trading margin decreased $9 million to $24 million compared with $33 million in the 2016 period. The decrease was mainly due to less favorable transportation hedges earlier in 2017 and lower volatility due to increased gas transportation infrastructure in the Northeast United States. Nonetheless, we would still expect the business to deliver at least at the low end of the earnings band of $15 million to $30 million for the full year. And you may recall from our Q1 call, our Bridgeport plant suffered an unplanned outage on one of its two units in mid-March. And once identified, the -- and once we identified the cause, we elected to take the second unit off-line and addressed the problem proactively. I'm happy to report that both units were back in service as of mid-June and are operating well. However, the outage obviously had an impact on second quarter results. Taking out the positive $20 million pretax impact of the one-time adjustment for sales tax that we booked in Q2 2016, EBITDA from the facilities was $4 million lower quarter-over-quarter, all of which can be attributed to the lower generation from Bridgeport. Our forward hedge position has not changed materially since Q1. We have approximately 400 megawatts hedged beginning November 2017 through to March 2018 at about $12 spark spread around the clock. And in June, we started to see the lower energy margins be offset in part by higher capacity revenues as prices jumped from $3 to $7, which will add approximately CAD30 million in capacity revenues on a year-over-year basis. Corporate and other reported a net loss of $27 million compared with a net income of $171 million in Q2 of 2016. Results in 2016 included the gain on the Algonquin Power transactions, net of the TECO acquisition cost. The loss in the quarter was primarily due to the permanent financing cost of the TECO acquisition recorded in this segment. Also included in corporate and other segment is the $8 million of higher AFUDC on the Maritime Link and Labrador Island Link projects. Year-to-date, 2017 corporate and other reported a $54 million loss compared to net income of $171 million in the 2016 period. The result comparisons were driven by the same factors as the second quarter, with AFUDC on the Maritime Link and Labrador Island Link projects being $15 million higher on a year-over-year basis. Thank you. And we'll now take your questions.

[Operator Instructions] And your first question comes from the line of Linda Ezergailis from TD Securities. Your line is open.

Thank you. Congratulations on a strong quarter. With respect to the Atlantic Link RFP bid, can you walk us through kind of what the next steps are and what sort of -- kind of competitive dynamics we might want to watch over the next while to ultimately determine whether politics or other factors might influence the outcome of that process?

So, Linda, its Chris. First of all, we've put in a bid for the Atlantic Link that would see the project be built at around 1,000 megawatts. And so it's a DC link that would go from Coleson Cove, New Brunswick to the Pilgrim facility in Massachusetts at 1,000 megawatts. The bid that we put in is a combination of hydro, so about two terawatt-hours of hydro energy from New Brunswick and Newfoundland, and also about another 3.6 terawatt-hours of wind that would be a combination of a number of new projects in the region. And so it's a very solid bid, I believe, but also, at this point, it's only about 65% utilized. And so that actually gives the project a pretty good position in that there's incremental optimization that can be done by the state of Massachusetts as they look at this project. When we think about it from an overall schedule perspective, we're expecting that in the New Year, so in early 2018, we would hear, I think in the January timeframe, hear how we've done competitively. And if, in fact, our project is selected, then we would actually enter into a discussion and negotiation with the parties at that time. So, when we look across the spectrum of the competitors, we feel like this project is very well-positioned. It has a lot of REC -- Class I REC quality energy. It has hydro and it has flexibility and it enters the system at a very good place in that it would be displacing energy that would today come from a nuclear plant in that region. So, by putting that altogether, we think the project is well-positioned.

And just as a follow-up, with respect to local stakeholder discussions, have you started to engage the communities that would be involved? And I would assume that the footprint is not very visible or disruptive, but can you maybe comment on that process?

Yes. And in fact, we have been very engaged with the various stakeholders that are involved. In fact, we received letters of support from a number of the communities affected; most notably on the Massachusetts side is the Plymouth area around the Pilgrim plant. Also, though, we've been engaging First Nations and also engaging fishers that would fish in the area where the project would proceed and as well parties on the Brunswick side. So, we have actually that engagement well underway. And I think to your point, the project is reasonably low impact relative to some of the other terrestrial projects that are being built. And as you can imagine, this, for us would be a follow-on from the work that we've done with Maritime Link. And in fact, if you look at the way the Canadian side has looked at that project, there was -- it was deemed by the CFO to have very, very low impact on the environment. So, when we think about this project, we think it does position well relative to stakeholders and relative to the environment and so that should be a very large positive. We do have to continue through the permitting process and we will be doing that as part of -- as an ongoing effort.

Okay. Thank you. And just as a follow-up maybe for Greg. Was helpful to get a sense of the degrees of above normal that Florida was I'm assuming that's Fahrenheit, not Celsius. But can you maybe help us understand the financial net income effect in weather to-date as we look to try to normalize results and help us with our forecasting? I realize it might not be an exact science, but any sort of directional indications you could help us with would be appreciated.

Yes, I don't have any specifics in front of me, Linda. I mean, certainly, Tampa has experienced some, I'd say, warmer-than-normal weather in over the past number of years. So, I think it calls into question, I think, what is the actual normal number. But they probably had a run now of three, four years where, in particular, over the course of the summer and going into fall, where temperatures have been warmer than historically they've been. If -- I'd have to get back to you in terms of what the actual effect would be on a top line basis. I just don't have it in front of me.

Okay. That would be helpful. Thank you.

Thanks Linda.

Thanks Linda.

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

Yes. Thank you. Maybe a follow-up on the Atlantic Link question there. That project seems to be the lead horse right now in terms of the strategy of getting power from the north into the south. But beyond this existing coal, can you just update us on your longer term thoughts on some of the other projects that you have proposed there in the past and potential opportunities there?

Well, I guess as we've looked at it, Robert, and really seen how the market, both from an energy perspective as well as from a stakeholder perspective has responded to some of these projects, that is what's caused us to propose this project in this way. So, we -- as you know, we have looked at other potential projects in the past, everything from the line that we were going to take down the interstate to the green line and others. And in the end, what we have come to understand is that this project probably comes forward with the most merit and the most optionality. And so if you think about the way this project will draw energy, it can draw energy from Northern Maine, it can draw energy from all the Maritimes and Atlantic Canada and ultimately could supply the opportunity for Hydro-Québec to deliver some energy as well. And so this line actually has a lot of scope when it comes to being able to access various sources of energy and creates a lot of flexibility. At the end of the day, the state is going to have to decide whether or not it wants that additional flexibility because there are projects that have been proposed that are pretty straightforward coming from one source with one line. And so at the end of the day that's what the decision will be. But we believe the fact that we're bringing this into an area of the state that needs energy that is losing a source and the fact that we're actually creating a tremendous amount of optionality is what the merits are for this project. And so that's why we would have selected this one as the one to put forward in this case. But as you can imagine, there are, in fact, a lot of parties involved here, three different utilities that are engaged. And as well, obviously, we've worked well with Entergy to get a position at Pilgrim. And then we also have a number of different, I think, seven different wind producers who are involved. So, it was quite a complicated project to put together, but we're comfortable that we've got it in the right shape.

All right. Thank you for that context sir. And then just switching gears onto the cash flow and balance sheet. Can you provide some updated thinking on your financing plan moving forward? I guess, does the potential push-off of, I guess, $50 million of depreciation for the next two years at NSPI will increase that financing need?

Robert its Greg. I mean, obviously, by pushing off the question of depreciation that would have a relatively modest impact on our overall. I mean, we're operating under a base with cash flow around $2 billion a year. So, that by itself is not going to cause any material change to our financing plans.

All right. So, then the expectation is still kind of the debt pref equity kind of year, year, year guidance that you've given in the past?

Yes, that's correct.

All right. Thank you.

You're welcome.

Yes. And the target capital structure continues to be the same as we presented.

Thank you.

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

Thanks. Good morning guys. My first question, I'm wondering if you have any thoughts on the solar panel -- the Suniva solar panel trade case ongoing right now, and do you see that having any impact to your business there in Florida potentially?

Yes, David, it's Scott. So, yes, certainly, it's tightened up the market as it relates to the procurement of panels. But our efforts in Florida have allowed us to -- have a line that we think would still allow us to procure, deliver, and install panels on a basis of continuing availability into the investment tax credit. So, that continues to be our focus and we think we're in good shape.

Okay, great. And then my only other question, just I guess now that you've had a decent chunk of time now with the former TECO assets, are you getting to a point now where you might turn your focus back to M&A? And then just how do you think about your opportunities out there?

Yes, I mean, frankly, I don't think we're thinking about M&A any differently today than we always have, which is our primary focus continues to be on growth within the businesses that we have and looking for development opportunities to invest in projects like the Atlantic Link, but always looking to explore opportunities that we think would tie in strategically and make sense financially. So, we continue to think about and explore M&A opportunities. But as in the past, we always continue to be selective in what we decide to proceed with and ensuring that it fits our own view as to return hurdles and strategic fit with our business. So, I'll just say, from our perspective, nothing has really changed in our lens around looking at M&A from what it's been over the last number of years.

And Scott the only thing I would add to that is that I would remind analysts that we have committed to the market that we're going to delever the balance sheet over this next number of years. And so in any event, that likely puts us in a smaller range if we think about M&A than a larger range. And so I think that's the other thing we've been saying to people. I wouldn't rule out doing something small, but very unlikely we do something large at this stage, primarily because of the fact that we're committed to delevering.

Okay, great. That's very helpful. Thank you.

Thanks David.

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

Thank you. Good morning. Question just relates to backfilling your capital program in really the out years at the end of the decade. And so when I look at the capital forecast you've got, your regulated Canada business effectively falls off at a faster rate than the U.S., and the U.S. holds pretty static. And I guess the question really is where do you see the upside potential from the asset base, is it coming from Canada or more U.S. upside?

Yes. I mean, I think there's a balance, but there's no question that the growth opportunities in a market like Florida where there's economic growth going on in that jurisdiction. And you've heard this stat before, 1,000 people a day moving to the State of Florida. So, aside from all the things that we do as it relates to our investment in cleaning generation, in infrastructure renewal, there's also growth in that market that provides an added opportunity to think about capital investment opportunities from what we would see in some of our other markets. But to answer your question, we see balance between them. Obviously, Atlantic Link is something that if we're successful with that, would add significant capital investment profile. And the timeline that you're talking about, the reference that I made earlier to the potential to convert coal to gas generation in Florida would be another opportunity in that same kind of window. And so all of those -- and many other things that we continue to work on within the businesses across the portfolio would give us the confidence that we'll continue to round out that capital investment profile. And what shows us to that tail-off is simply because we don't put those things in our pipeline into that capital spending profile.

Maybe just as a follow-up to that answer. When you think about Florida and maybe just the balancing act of solar capital deployment and then the coal to nat gas conversions, which has a multiple sort of spinoff effects for you through the rate base, how do you think about the size of that opportunity because it is multifaceted for your entire asset base within Florida?

Yes, I think because of the scale of the business and the opportunity in Florida, the scale of the capital is also of significance. So, we would see the solar and the gas conversion type opportunities of well over $1 billion, approaching $2 billion in total just in Tampa Electric. But of course, we've got opportunities in Peoples Gas as well in that market. That isn't just a Tampa area business, but across the state with significant penetration opportunity for us with gas infrastructure in that state as well, and not to leave out New Mexico where we see opportunities to not only continue in a program infrastructure renewal, but also customer addition and expansion of the infrastructure in that state as well. So, the largest scale opportunities are the ones that I would have referenced as to solar and gas conversion in Atlantic Link. But the significance of some of the more ordinary course items within the business is also a meaningful part of the opportunity in front of us.

Okay, that's very helpful. Thank you.

Your next question comes from the line of Robert Catellier from CIBC Capital Markets. Your line is open.

Hi, good morning. Thanks for your updates on the Atlantic Link Project, but I wanted to get back to that for a second specifically. I just want to understand how the merits of not using -- not having terrestrial transmission requirements fit in the overall selection criteria, understanding that the project, as you described it is competitive on the other elements. How significant are these stakeholder issues in their scorecard in project selection?

Well, I think it all -- Robert, it all comes down to build ability, whether you can build it or not. And we would be certainly of the view, as we sit today, that no different than Maritime Link that this project is very much a project that can be built. And so as you know, many of the other projects have faced challenges as it relates to building terrestrial projects. And so this particular project begins on the shore of New Brunswick. And in fact, the Coleson Cove power plant is right on the coast. And so there's a horizontal directional drill that would happen from the seabed up into the substation. And so essentially, other than adding transformers and converters, nothing would happen on land in New Brunswick. And exactly the same thing actually would happen near Plymouth, Mass at the Pilgrim site. There will be a horizontal directional drill up from the seabed into the substation there as well. And so at the end of the day, there really is no activity that happens other than inside substation fences on land for those projects. When it comes to the ocean side, again, I think the science has been well done in the area. There's a lot of cable going in the water in a lot of different places in the world. And as I just said, we have experience having just put cable on the water here in the Maritimes and worked with stakeholders and worked with fishers and worked with Department of Fisheries and others, including Transport, and I think understand how this can best be done in a way that is benign to the environment and benign to things like the fishery. And so those are the advantages that this has. But from a criteria perspective, it just cannot be permitted and cannot be built. And I believe that we can demonstrate that this can be permitted and built. And then as you point out from before, there are lots of other merits at this project, both its ability to collect energy and its ability to optimize between the two systems, which is quite unique, I believe, to this project.

Okay, that's helpful. And then my other question is on Emera Energy, both in your comments here and the MD&A references on less fixed transportation commitment for pipelines. And I'm wondering if that's a permanent change in strategy or direction to produce risk in that business, or is this a short-term response to market conditions?

It's Judy speaking. No, I wouldn't say it's a permanent change. A lot of the transportation we have at any given time, we are acquiring in competitive bidding processes. So, the question is often what our view of a term piece of transformation might be worth compared to what other people might think it'd be worth at a given point in time. So, what we have in terms of transportation can move by a million -- a couple of million dollars a month or so just based on the outcome of those competitive bidding processes. So, we are always conscious of financial commitments we're making for transportation and like to make sure that, of course, we're at least going to kind of recover all of our investment with an opportunity for upside. The challenge we can have in the summer months is we can have an economic piece of transport that's very lucrative in the dead of winter, but we have to pay for it through the year. So, long story short, most of it is acquired competitively in auctions. We're constantly updating our forward views and determining how much we're prepared to pay. And sometimes, we are the -- sometimes, that means we win the bid and sometimes, it means that we lose out to competitors.

Okay, that's very helpful. Thank you.

Thank you, Robert.

Our last question comes from the line of Robert Kwan from RBC Capital Markets. Your line is open.

Hey good morning. Maybe I'll come back starting with Atlantic Link. Just when you've modeled out your bid versus some of the others, Chris, you've talked a lot about the benefits of really having just New Brunswick and then the Commonwealth versus not having to deal with other states. Do you think, though, in terms of the bid evaluation stages, that the amount that's applied to those types of qualitative factors will capture your bid strong enough to get you through to nearly kind of that more nebulous last stage?

Well, Robert, I actually think there are probably two major factors that come into this evaluation for the state. And I think, first and foremost, the merits of this project on its own and ultimately, it's going to come down to prices as part of that, as part of those merits. But I do -- I would like to believe that the flexibility and the optimization capabilities of this project are going to come to bear. And replacing -- or coming into a substation where a nuclear plant is retiring is certainly a good feature. But the other thing about this is, I mean, we've actually bid about five point -- I think its 5.6-ish terawatt-hours in the 9.45 that they're looking for. So, in fact, they can actually fill in part of the requirement with another project. And that could also provide them with some flexibility, whereas in some circumstances, one project fills the whole bill. And in our case, they have the ability to select something else as well. And I think there are some projects out there that could nicely combine with this to give the state even more optionality. So, to me, it really will depend on just how much of a credit they give to this lower than the 9.45, the ability to bring somebody else in, and the ability to optimize into the future. We're only using 65% of the capacity of that line in this bid. But certainly, over time, the line can be completely loaded, and there's lots of clean energy for that. So, that could be very much lower cost energy for them as they think about it. And it's not terribly different than the way we look at the Maritime Link. The first step of the Maritime Link was to get it in and get the base amount of it covered and that's what the regulatory structure did. But in the end, Nova Scotia has received some incremental energy that is very valuable as well and continues to have the ability to receive more incremental energy. So, I think the same feature can exist in Atlantic Link and we'd be hopeful that that gets considered by the parties as we look at the merits of the project.

Understood. Maybe just then, Chris, as you referenced Maritime Link, I'm just wondering, when you look at your planning and forecasting once you place it into service, what do you think the likelihood is of material amounts of power flowing on the line, either into Nova Scotia or out of Nova Scotia pre-Muskrat Falls?

Well, so pre-Muskrat Falls, I think there'll be a lot of energy flowing on the line. Obviously, it will be one way until the Labrador Island Link gets connected. But once that gets connected, which will be in Q2, I believe, of 2018, then we're connected to the Churchill system. And as soon as you're connected to that, you're connected to 34 terawatt-hours of hydro, and so there's lots of potential for energy to flow.

Okay. So, you're expecting fairly material flows on Maritime Link when it's in service, whether it's recall power or at the beginning, you flowing power into the island?

Yes, absolutely. And I think the other aspect that comes into that is that we will be connected, and when I say we, I mean, Maritime Canada will be connected to a fairly large hydro system right off the bat. Newfoundland has approaching 2,000 megawatts of hydro on the island. And so even just being able to optimize between the thermal systems in the Maritimes and the hydro system in Newfoundland will create value for the customers across the entire region. And that's something that we're looking to be able to do right away as well.

Okay. That's great. Thanks very much.

Thank you.

There are no further questions at this time. I will now turn the call back over to the presenters for closing remarks.

Okay. Well, thank you all for your attention and your interest in Emera and I hope you have a great day. Thank you.

Thank you.

This concludes today's conference call. Thank you for your participation. You may now disconnect.