Emera Inc (EMA) 2013 Q4 法說會逐字稿

Good morning. My name is Lisa, and I will be your conference operator today. At this time, I would like to welcome everyone to the Emera fourth-quarter and year-end earnings and results conference call. (Operator Instructions). As a reminder, today's call is being recorded, February 10, 10 a.m., Atlantic time.

I would now like to turn the call to Jill Hennigar, Manager and Investor Relations. Please go ahead, Ms. Hennigar.

Thank you, Lisa. Good morning, everyone, and thank you for joining us for our fourth-quarter and year-end conference call. Joining me from Emera are Chris Huskilson, President and Chief Executive Officer; Scott Balfour, EVP and Chief Financial Officer; and other members of our management team.

Emera's fourth-quarter and year-end earnings release was distributed this morning via newswire, and the financial statements and Management's Discussion and Analysis are available on our website at emera.com.

This morning Chris will begin with a corporate update, and then Scott will review the financial results in detail. We expect the presentation segment to last about 10 minutes, after which we will be happy to take questions from analysts and investors. Please note that all amounts are in Canadian dollars with the exception of Emera's Maine and Caribbean utilities where segment results are reported in US dollars.

I will take a moment to remind you that this conference call may contain forward-looking information, which involves certain assumptions and known and unknown risks and uncertainties that may cause actual results to be materially different from those that are expressed or implied by the comments. Those risks include, but are not limited to weather, commodity prices, interest rates, foreign exchange, regulatory requirements, and general economic conditions.

In addition, please note that this conference is being widely disseminated via live webcast. And now I will turn things over to Chris.

Thank you, Jill, and good morning, everyone.

Adjusted net income for 2013 was CAD259.4 million or CAD1.96 per share compared to CAD230.5 million or CAD1.85 per share in 2012, representing a 6% growth in adjusted earnings per share year over year.

Scott will take you through the details of the quarter and year-end in his remarks. 2013 was a year of significant accomplishment for Emera, and I want to take a moment to review some of the highlights with you.

In November, our proposed Maritime Link project became a reality when we received final regulatory approval from the Nova Scotia Utility Review Board. With that major milestone behind us, we are now focused on advancing the external financing process in cooperation with the government of Canada as guarantor, now, of course, successfully completed their project financing in December, and we're working to put our financing in place as soon as possible expected in Q2.

Just last week, we awarded the subsea cable contract to Nexant, a company based in Paris with cable manufacturing facilities in Norway and Japan. Nexant is an expert in manufacturing and installing subsea cables worldwide. They have demonstrated an ability to provide the best overall value for this project.

On the construction side, we have a busy year ahead of us. This year we are beginning clearing of the rights-of-way and grounds for substations and converter stations. We will begin construction on the transmission lines and award the converter and substation supply contracts.

2013 was a very strong year for Emera Energy's marketing and trading business, which realized CAD60 million of margin before mark-to-market adjustments compared to CAD27.6 million in 2012. I will leave it to Scott to explain the mark-to-market.

The Northeast natural gas markets experienced extreme volatility in the first and fourth quarters of 2013, largely driven by cold weather. To give you a sense of that, in the nine years between January 2003 and December 2012, there were 20 days where the Algonquin Citygate Daily Index, a proxy for New England gas prices, changed by CAD5 or more day over day. The winter of 2011/2012 saw 1 such day; 2012/2013 saw 6; and from November 2013 until January 22, 2014, there were 9 such days.

Emera Energy was well positioned to serve customers during this volatility. They were able to capture value by efficient utilization of transportation capacity to get gas where it was needed.

Emera Energy's three new gas plants have been performing as expected since we acquired them in November. It is still very early days, but we are learning a lot about how they perform in this market. We have seen some very high electricity prices, but gas prices have also spiked with CAD50 daily price movements commonplace, and our focus has been on risk management by ensuring the best economic dispatch possible given the circumstances. So all to say, we're pleased with how we have been managing, and the facilities are performing as we expected. But I want to make it clear, CAD800 power prices generally do not produce windfalls in the wintertime.

This week brought a substantial piece of good news for the plants. New England capacity pricing for 2017/2018 was set at just over CAD7 a kilowatt month, which is substantially higher than our business case assumption when the plants were acquired and represents approximately CAD30 million of incremental net earnings over 2017 and 2018, all other things being equal.

The Northeast Energy Link continues to progress, and last month the New England States Committee on Energy sent a request to ISO New England for assistance in implementing a multi-staged plan enabling the delivery of 1200 to 3600 megawatts of non-carbon emitting generation into New England through increased transmission. We believe our Northeast Energy Link project will be well positioned to provide a transmission solution for this energy.

In Nova Scotia, the focus remains on implementing productivity initiatives and cost control measures and on reducing heating costs for Nova Scotia customers. One of the most efficient and effective programs for home heat has been our heat pump program. Nova Scotia Power does not sell the units themselves, but we offer on-bill financing to make it easier for customers to switch. The technology uses about a third of the energy of other types of heating such as oil, so there are significant savings for customers, despite the upfront investment required. In 2013 Nova Scotia Power had great success with this initiative with 12,000 residential customers installing new heat pumps, and the focus for 2014 will be converting more oil heat customers in older homes to this technology.

Moving to our Caribbean Utilities, in Grand Bahama we have now completed our three-year turnaround plan for the utility. Our 52-megawatt diesel generation plan is up and running and has already improved system reliability and cost structure for electricity. Outages are down significantly, and importantly, the utility is now earning an appropriate return.

In Barbados, our clean energy strategy for the Island is progressing well. In December new legislation was put in place that supports renewable energy development. Based on a revised integrated resource plan that incorporates more renewables on the system, Barbados Light & Power will build an 8-megawatt utility-scale solar power plant. We are also awaiting a regulatory decision for our investment plan, which would see us constructing 30 megawatts of generation in 2015. We've worked closely with all stakeholders to ensure the success of the nation's renewable energy and efficiency plan, and we believe we're well-positioned to help our Caribbean customers reach cleaner energy solutions.

With that, I will turn things over to Scott, who will give you a more detailed update of our financial results for the quarter and the year.

Thank you, Chris, and good morning, everyone. Our fourth-quarter and year-end results were released earlier today and are now available on the Emera website.

Emera's consolidated net income in 2013 was CAD217.5 million or CAD1.64 per share compared to CAD220.8 million or CAD1.77 per share in 2012. When current year results are normalized for CAD41.9 million of mark-to-market losses, 2013 net income was CAD259.4 million or CAD1.96 per share. Mark-to-market losses were CAD9.7 million in 2012. So when normalized, adjusted net income in the prior year was CAD230.5 million or CAD1.85 per share, representing 12.5% growth in net income and 6.0% growth in earnings per share year over year. This increase in net income is primarily due to higher earnings in our Caribbean Utilities, increased trading and marketing margin as a result of strong New England market conditions, as well as increased income from our equity investments. And I will expand on each of these a little later in my remarks.

When normalizing our 2013 results, you will notice that Emera Energy had larger-than-normal mark-to-market losses of CAD42 million in the quarter, and we thought it would be helpful to provide some additional color on what is driving the significance of these adjustments.

Emera Energy manages the portfolio of natural gas contracts that are substantially balanced on a volumetric and/or daily basis to effectively remove commodity exposure. Included in this portfolio are contracts to buy or sell natural gas wherein gas is delivered in one market but priced at a different market and moved between the two points on firm transportation capacity held by the business. This firm transportation capacity effectively mitigates economic risk on the related commodity. The natural gas component of these arrangements is subject to mark-to-market accounting with changes in the value between the delivery and pricing points recognized in earnings. However, offsetting changes in the value of using the related transportation capacity assets are not recognized under US GAAP. The increase in mark-to-market losses quarter over quarter and year over year reflects volatility in the New England market in the fourth quarter, resulting in larger variances between markets prices used for mark-to-market calculations, as well from an increase in the volume of the business. The related increase in the value of using the associated transportation capacity is not recognized.

Lastly, I think it is important to note that the underlying economics of these transactions remain attractive and are unaffected by these mark-to-market impacts.

And with that, Nova Scotia Power contributed CAD126 million to consolidated net income in both 2013 and 2012 as higher revenues and electric margin in 2013 was offset by higher interest and income tax expenses.

Maine Utility Operations contributed $38.4 million to consolidated net income in 2013 compared to $35.4 million in the same period in 2012. The increased net income is primarily a result of the impacts of increased load and higher capital spending.

Also impacting Emera Maine's results in 2013 was the $1.5 million after-tax provision we took in the third quarter relating to the expected FERC transmission rate refund for the period from October 2011 to December of 2012 as a result of the expected rate of return on equity reductions for New England transmission orders. This provision reflects the impact if the recommendations of the administrative law judge in regards to the retroactive period is fully adopted by the FERC. The FERC has not yet announced a decision on its rate review for either the retroactive or prospective periods.

Caribbean Utility Operations contributed $32.4 million to consolidated net income in 2013 compared to $23.2 million in 2012. The increase in net income is primarily due to Grand Bahama Power Company's rate structure changes effective July 1, 2012; the acquisition of a controlling interest in Domlec; and [CAD4.2] million of investment income recognized in the quarter.

Pipelines contributed CAD30.3 million to consolidated net income in 2013 compared to CAD27.9 million in 2012. The increased net income is primarily due to lower interest expense as a result of refinancing.

Services, Renewables, and Other Investments contributed CAD16.7 million to consolidated net income in 2013 compared to CAD33.7 million in 2012. Excluding the effect of mark-to-market adjustments, this segment contributed CAD58.6 million in 2013 compared to CAD43.4 million in 2012. As Chris spoke to earlier, the increase is primarily due to a strong year in Emera Energy's marketing business and a CAD24.3 million increase in earnings from our equity investments, which I will take a moment now to break down those equity earnings a little bit.

First, Bear Swamp saw a CAD5.2 million increase in equity earnings year over year, primarily due to Unit 2 returning to service in April after an extended outage that began on July 6, 2012. We also recognized CAD2.6 million of business interruption insurance proceeds related to that outage in the third quarter of 2013.

In addition, Bear Swamp's operations were optimized to capture favorable pricing spreads this year. The market was such that this was often achieved with lower generation than planned but operating when spreads were highly favorable.

We also recognized CAD5.2 million of earnings from our initial CAD67 million investment made in the Labrador Island Link this year.

Northeast Wind's equity earnings are up CAD4.6 million year over year, and that includes a CAD6.4 million supplier settlement we received in the first quarter of 2013 that provided contribution toward ongoing maintenance and repair costs of those turbines.

Lastly, Algonquin's equity earnings are up CAD4.7 million due to having greater ownership interest this year. At the end of 2012, we owned 18.5% interest in Algonquin compared to 24.3% at the end of 2013. Included in 2013's equity earnings is the CAD7 million after-tax loss or CAD0.05 per share that we recognized in the third quarter of 2013 related to Algonquin's CAD33.9 million loss from discontinued operations that they reported in the second quarter of 2013.

Emera also recognized CAD18.1 million, or CAD0.14 per share, of after-tax gains in 2013 from the conversion of Algonquin's subscription receipts to Algonquin common shares compared to CAD22.7 million or CAD0.18 per share in 2012. While we did see a significant increase in equity earnings this year, we did record an after-tax investment impairment charge of CAD7.6 million or CAD0.06 per common share on our investment in Atlantic Hydrogen or AHI. We determined that an impairment charge was appropriate as AHI's path to commercialization is less certain.

That is all for my financial review, and we would now be happy to take your questions.

(Operator Instructions). Ben Pham, BMO Capital Markets.

Congrats on the good quarter there. I just had a couple of questions on energy utility services, just wondering what you can give us an update on the backlog there and just overall level of activity that you're expecting this year.

So you are saying EUS or EES?

It is for EUS.

Okay. So they are actually working quite hard right now to put together their backlog for the year. I would say they've got about 50% of their business in front of them at this point, and they are in the process of continuing to compile activities.

I think at this point, Ben, it would be fair to say that our backlog is a little lower than where we saw it this time last year, but the pipeline of opportunities is significantly greater. So we're looking forward to a better year for the US in 2014.

Right.

Okay. And then are you -- is the correct to think that you are mostly focused on organic growth in that segment, or are you looking at acquiring any smaller contractors?

No, we're not focused on acquiring contractors, and you have to remember that that business for us is primarily one that helps facilitate our other activities. So we see it as a backstop to our construction activities in Newfoundland. We also see it as ensuring that we have the capacity to do things like respond to storms and those kinds of things. So we actually have that business primarily as a support to the other parts of the business.

Okay. And is your expectation to ultimately do work for the Lower Churchill Project?

Well, we certainly would not turn it down if it came to us, but at the end of the day, they are all competitive processes. And so we have to make sure that we would win that effort. We do see certain competitive advantages for that entity, but at the end of the day, there's lots of competition out there.

Okay. And just one final one, how do you record the revenues on the projects? Is it a deposit-type of structure there? I mean how do you look at your accounting on the revenue side of things?

It is all percent completion. So if we are 10% complete on a job, we record 10% of the revenues.

Okay. Great. Okay. That is it for me. Thank you.

Paul Lechem, CIBC.

Just, Scott, on the write-down on Atlantic Hydrogen, just wanted to be clear, was that in your adjusted earnings number or was it removed?

No, the only thing that we have adjusted for when we talk about adjusted earnings and adjusted EPS is removing the impacts of mark-to-market.

All right. So that is actually in the results, the CAD0.06 impairment charges in the fourth --?

That is correct.

On the Maritime Link, it wasn't you said in the write-down to get financial closure before the end of Q2. Is that a little later than originally expected? I thought it might have been Q1 that you were targeting for. Can you give us any updates in terms of what the process is there, and if it is a slip, what might be contributing to that?

Yes, so there is no slip. I think one of the important things to understand is, as it relates to the federal loan guarantee and the agreement with Canada, there is a requirement for us to achieve a certain milestone that is described there at the Maritime Link financial close within 90 days of Nalcor's financial close. We are on target to achieve that in the first quarter, but in terms of being a place where we're actually in the market raising funds, the reference there is we expect that to happen as soon as possible before the end of the second quarter.

I got you. In terms of the gas pipeline activity, you talked a little bit about what is going on in New England, and Spectra Energy is talking a little bit about new projects they are developing there, including potentially reversing Maritime and Northeast. Can you talk a little bit about what your involvement is in that and any other opportunities you seeing in terms of pipelines in that region?

So I think if we back up and look at the situation from a Maritime Canada perspective, one of the things that we're working on is the strategy for gas for Maritime Canada. Because if you look at the declines in [Soie] or if you look at the declines that will happen, quite quickly, on Deep Panuke, we only really have about eight years of gas that we can count on. And so we are working on a strategy that would see ensuring that we have gas in this marketplace, and so that is really the over-arching piece.

If investments occur in Maritime's, then we would participate in those on our pro rata share, 12.9%, and we would also be looking to see how the region will get supplied with gas as time goes forward. So that's still a bit of an open question. We have some time in front of us, but at the end of the day, we need gas in Maritime Canada in order to meet all of the objectives that we have as a region, both from an economic perspective and also from a clean energy perspective.

And so that will be something that we will see more activity on as time goes forward.

Got you. Okay. So stay tuned. Thanks, Chris. I appreciate it.

Juan Plessis, Canaccord Genuity.

Good morning and congratulations on a strong quarter. Chris, you mentioned in your comments that higher electricity prices in New England doesn't necessarily translate into a windfall for the recently-purchased New England assets. I was wondering if you can tell us how much those plants contributed to fourth-quarter net income?

We will leave that to Scott. You want to talk about it?

So we acquired the plants November 19, I think, so we owned the plants for about six weeks. And while six weeks is not an appropriate time to extrapolate from, of course, because the diodes go on, but there was roughly a CAD6 million contribution from those three plants during that period.

Yes, and Juan, I think it's very important to note that there was a tremendous amount of influence this quarter from what was going on in New York as well. And so we saw extremely high gas prices. That doesn't necessarily connect to New England electricity prices.

And the other thing is that ISO New England was switching to oil quite often, as well, which is an appropriate thing to do. So when you look at all those disconnects that exist between the price of electricity and the way that gas gets priced, that is why high, high electricity prices don't always translate into great returns for the plants.

But I think if you think about it in terms of what we expect from those plants and when we looked at them in the first place why we bought them, they are performing as we expected them to. And it's not unusual to see spikes in prices, both on the gas side and the electricity side, and it is more about their contribution over the long term, not the short term. We're not looking for windfalls. We are looking for steady growth in value over time.

So I then take you to the 2017/2018 auction that just happened, and we're very, very pleased with the way that that has unfolded. We do see a substantial portion of capacity being retired in New England now, which is one of the reasons why we felt getting into the gas side at this time would be the right thing to do.

And so I think we are well positioned. We certainly paid what we feel is a competitive price for those plants, and they will perform as we expected them to, I believe.

Thank you for that. Can you also tell us what your realized ROE was in 2013 at NSPI?

I help here. Thanks for the question and I would say that we are within the allowable range of return.

Okay. Thanks.

Andrew Kuske, Credit Suisse.

Just a question as it relates to the New England power markets and just looking strategically where a number of your plants are, there was a recent transaction in just the paper space with Verso acquiring NewPage and then really asking this question in the context of Rumford. In your portfolio, do you think there's going to be any benefit from this consolidation of -- you are a pretty energy-intensive business happening in New England. Will you see any contractual opportunities that you're going to have spinning out of this?

Andrew, it is Judy. As you know, or that most people, I think, are aware, Rumford has essentially operated as a peaker, and I have referred to it previously as the opportunity in the portfolio. So everything we see happening in the New England market of late makes us feel more optimistic about Rumford's long-term potential. That said, I wouldn't talk about anything specific at this early stage, but we're certainly optimistic about its potential.

And I think, Andrew, important to note that Rumford would have been part of the capacity market, and so we're pleased that will make a bigger contribution than it has traditionally been making recently.

And I guess it is closing the deal I would say at six weeks in the last quarter, and before I get to the actual real question, you said CAD6 million contribution in six weeks. Was that earnings, or is that EBITDA? What was the contribution? Was it earnings?

Yes, that was earnings, yes.

Okay. That is helpful. And then just as you look at where you are now with the plants, are you receiving a lot more inquiries from people, so inbounds, and then also better outbound conversations on contracting up the plants for a longer period of time, higher price levels on the contracts versus your expectations?

So we are having a lots of conversations about the plants. Certainly people are very interested in them. To be candid, we're really focused on scheduling the plants into the ISO New England market at this 10 seconds, and we want to understand and digest the operational capabilities of our plants and understand how they really fit in the market before we talk significant contracting opportunities. So our first focus is on making sure that the asset management for the facilities is at a Emera standard so that we can count on their availability going forward and also understanding what are the market dynamics throughout a full calendar year in all seasons. So that when we are in -- should we find ourselves in conversations about either hedging or contracting them, we are coming at it from the proper perspective.

Yes, and Andrew, I think if you take the three facilities separately, at [Tiberden] we're pretty comfortable with where it sits today. Rumford, as Judy said earlier, there is opportunity, and we need to uncover that opportunity before we would want to lock it down in any way. And with Bridgeport, there is still -- it still has availability challenges that we're working through. And so again, we would want to really have that working the way it can work so that we really would be able to rely on it and then and therefore look at having it serve more directly some customers.

So it's just a bit early. You won't likely see us do much with those plants before we have gone through a full cycle, and we're much, much more comfortable with where we are from an asset perspective.

The only thing I will add to Chris's comment is we do -- if the market gives us opportunity to hedge little chunks, we have taken advantage of that 50 to 100 megawatts at a time. But essentially the plants are -- we are leaving the plants open at this 10 seconds while we get our arms around them.

So I guess fair to say, if we are looking ahead a year, so 12 months from now, we are having the same kind of conversation, and in the 12 months that just passed, you would have contracted out small blocks of power here and there where it was opportunistic to do so. But really this year is more about -- 2014 is more about just figuring out the plants, the operations of the plants and feeling very comfortable before you take much bigger positions on a contracted basis.

Yes, perfectly said, yes.

Yes, that is well said.

Okay. Thank you so much.

Robert Kwan, RBC Capital Markets.

Just wondering if you can give an update on the Northeast Energy Link project -- just where it stands, next milestones -- particularly in light of the Maritime Link approval and your New England plant acquisition?

Maybe we will just ask Gerry to jump into that.

I can do that. Thanks, Robert.

Well, I think we continue to develop the project and move it along from a siting perspective, we still continue to move to the process in siting it along the interstate corridor in the state of Maine. And that progresses.

But I think one of the key developments is, as Chris mentioned in his opening remarks, with the New England States Committee on Energy short -- or I guess that is long for NESCOE -- they recently sent a request to ISO New England for some assistance in implementing a couple of things -- some help with enabling the delivery of 1200 to 3600 megawatts of additional capacity for bringing non-emitting resources into New England, as well as some gas pipeline capacity. And I think that is a significant development and an opportunity for the project, and we will be well-positioned, I think, to respond to what we expect is a request or an RFP for some help in getting those resources into New England.

Yes, and I think, Robert, on the generation side, certainly First Wind continues to have a very nice pipeline of projects in front of them, and we're looking forward to seeing how those might fit into this. And you have to remember that NEL actually has First Wind as its participant from a funding perspective.

The second thing would be that we're also looking at what can be done with excess energy from the Maritime Link because there will be energy over and above Nova Scotia's needs and Newfoundland's needs. And so that can also provide an opportunity for the future there as well. So making sure we have a portfolio and transition together will be important as we start to try to respond to what the needs are in New England.

Okay. And your comments that you don't want -- you probably want a full cycle before you contract the New England plants. Does any of that also have to do with the potential to use those plants to firm up power for Northeast Energy Link, or is that completely separate?

Well again, I don't know that it is completely clear what the New England states want right now. I mean I think they have now suggested that they want to make some changes to how they are acquiring energy. There's been some work in Connecticut recently and some legislation passed. There has been some discussion certainly in Massachusetts, as well.

So until we actually understand exactly what it looks like, it is hard to say. But to the point, we have work in front of us on those power plants. We need to get them brought into the fold, so to speak. And so we are not ready to do anything with them yet anyway, but that provides us lots of flexibility as we see what the state's desire is and outcome.

Okay. Just on Emera Energy and this may be coming a little bit back to an earlier question as well, but you have the comment that you want to expand your geographic reach, including the Marcellus, where you are already moving some volumes. So you have discussed the desire for infrastructure before, but I'm just wondering as that is away from what you want to do in Atlantic Canada for gas supply, what are your thoughts on owning physical infrastructure there, and is there anything to watch out for in 2014?

Well, Judy may want to comment, but it is always the case for us that it really depends on -- it has to be core to our business. So if we were to be a major shipper on a piece of infrastructure, then that would be a reason to potentially have more ownership. But at the end of the day, we're also happy to ship out other people's pipes.

I think it really just depends how the infrastructure continues to evolve for us. And I think you understand our strategy is about synergies and adjacencies to assets. So we have just put some new assets into the portfolio. So that creates new adjacencies and new needs. So we're going to have to look at what those needs drive from an investment perspective. But it is all -- the opportunity keeps changing as we continue to add to our investment portfolio.

Okay. That is great. Thank you very much.

Maury May, Wellington Shields.

Most of my questions were about New England, and most of my questions have been answered, but I was just wondering whether you could take a shot at the long-term earnings potential for marketing and generation in New England, and you can use a wide range, if you like?

So it's Judy. I will speak first about marketing. I think -- so 2013 was an extremely strong year in energy trading and marketing, and that was really a result of what I will say, at least at this 10 seconds, looks like unusual market conditions.

So if I was really trying to predict on the go forward, I would definitely dial back from 2013's earnings level. So I would say at a base now where we are used to probably say CAD5 million to CAD10 million of net earnings, I would say it is probably now CAD15 million to CAD20 million would be the range.

Okay. And how much of that in New England, Judy?

Pardon me?

How much of that in New England?

It is substantially in New England. That is where the business is located primarily, in New York state.

Okay.

And with what we're moving out of Marcellus. So that would be -- that is essentially the trading and marketing business overall.

Okay.

So I would say now the range. And, again, whenever I'm talking about the trading and marketing business, I would have to say, it is very difficult to predict the weather, which is a key driver of earnings. However, we do have some longer-term contracts in place now and a little bit of a portfolio. And that, in addition to what we have basically been able to generate in our cash business on a daily basis, I would say CAD15 million to CAD20 million is a reasonable earnings target range for the business to deliver.

Okay. Now moving to the generation side with Bear Swamp and the three new gas plants, what could be the potential there?

So we have talked about the three new gas plants on acquisition and said that they were modestly accretive over the next five years once we had taken advantage of all of our cross-border tax financing opportunities, et cetera. So that means CAD0.01 to CAD0.02 of accretion based on forecasts at the time of acquisition. So I would say that is positive earnings, but the accretion is modest.

And we will be kind of, I guess what I would say, expanding our disclosure with respect to the plants to give people a way to -- a little bit better ability to try to model them before the first-quarter results come out. So when the --.

Okay. That CAD0.01 or CAD0.02 really is before last week's results of the Forward Capacity Market Auction at IOS New England, right?

Yes, but that is for 2017/2018.

Yes, I understand, okay. But you were mentioning like five years, and that would take us into 2019.

Yes, that is true. Yes.

Yes, okay. Well, anyhow, folks, very timely purchase of New England capacity. I congratulate you there.

Matthew Akman, Scotiabank.

I wanted to ask about the renewable opportunity in the Caribbean, and you have talked about some of the utility-scale solar. I'm wondering if you have sized up the potential envelope there over the next few years of capital investment opportunity and whether that would be pursued in rate based or separately and also whether with any partners?

Matthew, and Scott may have some numbers to give you, but I think how this is evolving is that we are seeing, at least on the renewable front in Barbados, a desire for a lot more solar to be built. And so it really comes in two different categories. One would be utility scale. And so we expect -- we have one project in front of us. Probably there is an opportunity for another project of that kind of scale.

And then on top of that, we expect there to be some closer to the meter projects that could see another somewhere between 6 megawatts and 10 megawatts, as well. So it is that kind of scale that is going to happen.

At this point, we see this primarily being done through the utility, and it would likely be others that would do the smaller-scale, closer-to-the-meter stuff. And then on top of that, there's just a need to put some more high efficiency generation in place. And in that case, it would be -- we're looking to put dual-fuel capacity into the Spring Garden plant. So today it is all heavy fuel oil fired, a little bit of light oil. We are looking to get natural gas into that facility and put dual fuel in as many of the facilities as possible.

So we will be about clean primarily on the solar front and then cleaner or lower intensity by getting some cleaner fuels involved and some higher efficiency involved. So that is our general plan. I think as well, there is the chance that we will see some either biomass or solid waste facilities built on that Island as well, and we are certainly open to participate in those but probably won't be leading either of those.

That is Barbados. We continue to be very interested in geothermal on a couple of the Islands and continued to do work in those areas, and it would be helpful that those resources will pan out. We have some exploratory work going on right now on a couple of Islands.

And then lastly, we would continue to see opportunities on Grand Bahama potentially to go to biofuel there, and that is an area that we are working in.

So that is I think the way we will see this evolve, at least for our participation, and then there's certainly a lot of support for alternative energy sources. I think, first, gas, but then secondly, renewable and more things like solar.

Chris, you talked about closer to the meter. Are you talking about rooftop, and if so, is that an opportunity for Emera or a threat?

Well, I think we see it more as a collaboration, and I think it is still up in the air as to whether we would participate at that level. I think we're open if -- want us to participate. But on the other hand, we are also comfortable with having others do that kind of work, as well.

Okay. Thanks very much, guys.

(Operator Instructions). Jeremy Rosenfield, Desjardins.

So just a few clean-up questions. On the New England plants, just curious if there's any major outages that are planned for the coming year for those plants?

Yes, Bridgeport has a major outage coming in the fall of 2014.

Is that like a 60-day outage?

Yes.

Okay. Perfect. Just on the trading margins, I wanted to make sure I understand perfectly, or as well as I could, in terms of the volatility of pricing, is that what is really impacting the opportunity to produce higher margins rather than, let's say, when prices go up and then stay up versus go down and stay down?

So the volatility is a key factor. I would say the absolute value of pricing can create margin opportunities that are bigger than if the prices are essentially at 10% of those levels.

But I think, Judy, it is important to note that it is cold weather. So cold weather drives volumes. And when volumes get driven, then people need to be served. And so whether that be the next unit, the next generation unit has to come on and is expected to come on or whether it be a little bit more energy for a utility, those kinds of things are all parts of what we're able to be there and serve.

And so I think it is the volume as much as anything, and the volume then drives volatility and on and on it goes.

Okay. And just based on what you are seeing so far in the first quarter, is there any sort of early indication that the cold weather carryover has been positive so far?

So January was a very -- the conditions continued into January. So whether or not -- it has eased off a bit in February, but certainly December's conditions continued into January.

Okay. Perfect. Just moving to the CapEx forecast for 2014, there is CAD300 million now that is associated with Maritime Link. Is the timing for that investment essentially upon financial close?

Yes, there is obviously ongoing investment that is happening with Maritime Link, so financial close is not holding back any of our construction, development, design-related activities. But regardless, most of that investment will happen in the back half of 2014 rather than the first half.

Yes, but it primarily is driven by contracts that we are letting. So, for instance, we let the cable contract. That will now have a schedule of payments. As we continue -- and I think we're close to letting the ground clearing contracts. That will have a schedule of payments. And so it is that kind of thing that will start driving spending. And then the financing, it just puts it in a bubble.

I just have one other clean-up question, and maybe this is better to be answered off-line. But it just relates to a note about regulatory amortization on NSPI, something related to pre-2003 income tax regulatory amortization -- CAD27 million that was a difference in the first quarter of this year versus the fourth quarter of last year.

Sure. I think that is Section 21 that you are referring to, and that was accelerated for the year. So it has been paid down or off.

Okay and --

That one is now gone.

Yes, it is gone. Correct.

But there was something recorded in this quarter that wasn't recorded previously.

We just took more of it this year, so that entire -- so effectively it is all taken down now, so that account is now at a zero. So there was a year-over-year change.

Right. I understand. Okay. So this was the last of it that would have been taken?

That is correct.

Okay. Perfect. Great. Those are my questions. Thanks.

Linda Ezergailis, TD Securities.

I have a question with respect to your Corporate expenses, how we might think of an appropriate run rate for the next year or two, and specifically within Corporate expenses, how business development expenses might be trending as well?

Sure. So, within Corporate, obviously, there are Corporate costs, and then there is offsetting income, largely interest-related income. So excluding the impacts of tax and pref dividends and interest expense and revenue, Corporate costs in 2013 were about CAD33 million.

And I think, by and large, Linda, thinking about Corporate costs in relation to our revenue and looking at that percentage is probably, if you try to model it, is probably as close as you can get. As the Company continues to get bigger, of course, Corporate costs will get larger.

Yes, business development costs can be a little bit lumpy within there. So that is a little harder to predict, but certainly business development activity continues to be a focus for us. And so it is reasonable to assume that our business development costs in 2014 will be higher than what they were in 2013.

Great. Thank you.

We have no further questions in queue. I will turn the call back to the presenters for closing remarks.

Okay. Well, thank you very much, and as always, we appreciate people's interest in Emera and your participation in this call today. So thank you very much, and enjoy the rest of your week.

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