Emera Inc (EMA) 2015 Q3 法說會逐字稿

Good afternoon, ladies and gentlemen, and welcome to Emera's third-quarter 2015 call and webcast.

(Operator Instructions)

Please note that this call is being recorded today, Monday, November 16, 2015, at 12 PM Atlantic Standard Time.

I would now like to turn the meeting over to your host for today's call, Scott LaFleur, Manager, Investor Relations, for Emera. Please go ahead, Mr. LaFleur.

Good afternoon, everyone, in Atlantic Canada, and good morning for the rest of you. Thank you for joining us for our third-quarter conference call. Joining me from Florida are Chris Huskilson, President and Chief Executive Officer; Scott Balfour, Executive Vice President and Chief Financial Officer; as well as other members of the management team here in Halifax.

Emera's third-quarter earnings release was distributed earlier 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. 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 in 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. These factors or assumptions are subject to inherent risks and uncertainties surrounding future expectations generally.

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.

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

Thank you, Scott. And good morning, everyone.

Emera delivered Q3 adjusted net income of CAD23.3 million or CAD0.16 per share, compared to CAD49.9 million or CAD0.35 per share in the third quarter last year. Further adjusting net income to remove costs related to the pending TECO Energy acquisition, Emera's adjusted net income was CAD43.4 million or CAD0.30 per share. The variance from last year is primarily related to timing at Nova Scotia Power where net income decreased CAD6 million to CAD4.9 million this quarter. We expect full-year NSPI earnings to grow modestly compared to 2014.

Overall, Emera is having a strong year. Adjusted net income year to date was CAD242.9 million or CAD1.67 per share, in line with the same period last year. And results are comparatively stronger if TECO costs are excluded. To be clear, these financial results and Emera's underlying business remain on track with the earnings growth expectation upon which we established our CAD1.90 dividend this year and our dividend growth target of 8% per year through 2019.

Scott Balfour will take you through the details of the quarter later in his remarks, but first I'd like to touch on some of the key strategic and operational milestones Emera reached this quarter. I'll start with our recently announced acquisition of TECO Energy. On September 4, we announced a definitive agreement to acquire TECO Energy for an aggregate purchase price of $10.4 billion, including consolidation of approximately $3.9 billion of debt.

Emera has prepared for a utility transaction for some time, and we found our ideal match in TECO. Our patient and disciplined investment criteria resulted in a transaction that is significantly accretive to EPS and cash flow for Emera shareholders, and one that advances our strategic objective. The TECO Energy acquisition is expected to be 5% accretive to our EPS in the first full year, growing to more than 10% by the third full year.

TECO Energy is a purely regulated utility. And pro forma, the acquisition brings our regulated earnings to approximately 84% of total earnings. The acquisition provides additional support to our 8% dividend growth target through 2019, and positions us to potentially extend that growth target beyond 2019. It expands our regulatory platform into robust economic environments, and establishes Emera with two strong natural gas distribution platforms, an objective we've had for some time.

The transaction remains on track to close in mid-2016. We filed our application with the FERC on October 5, and our submission with the New Mexico Commission on October 19. The New Mexico hearing examiner has now been appointed, and a scheduling conference is expected this month. Finally, TECO shareholders will meet to vote on the transaction on December 3.

Beyond the TECO Energy acquisition, Emera's business continues to perform, with a number of important initiatives, beginning with the Maritime Link, which continues to progress as planned, on schedule and within budget. Construction is well under way, and foundation preparation has begun at the converter station sites in Newfoundland and Nova Scotia. Initial shipments from the fabricator of the steel towers have been received, and the manufacturing of the submarine cables is moving along as planned in Japan. Overall, risk continues to decrease as the project progresses, and we have a high degree of confidence that the costs to complete the project will remain within budget through to completion.

At Nova Scotia Power, the focus remains on managing costs to ensure stable, predictable and affordable rates to our customers. We continue to work positively and productively with our regulator, stakeholders and the government of Nova Scotia.

Following a 12-month public consultation process, the government of Nova Scotia released their electricity review document on Monday, November 9. The document focused on the need for rate stability in the Province, and the implementation of performance standards, both of which we support.

On Tuesday, Nova Scotia Power announced there will be no general rate application for 2016, and the current base cost of fuel application before the regulator should result in a small decrease for most customer classes. SPi has been working hard to manage costs, and is confident it can achieve rate stability through the 2017 to 2019 period.

In New England, utilities and state agencies in Massachusetts, Connecticut and Rhode Island filed a procurement request for clean energy last week. This request for proposals, a draft of which has been public since February, recently received approval from utility regulators. Bidders have 75 days to respond and, therefore, a response in late January is expected.

As we indicated last quarter, the three states are now seeking at least 5.1 terawatt hours via long-term contracts of up to 20 years through power purchase agreements for energy -- for power purchase agreements for energy bundled together with associated transmission. Emera intends to respond to this RFP.

Emera Maine, in partnership with Central Maine Power, will propose upgrades to the existing AC transmission system to relieve congestion that would enable additional energy from wind farms in northern Maine and additional flow of clean energy from Canada. These system upgrades will be open to all energy bidders.

As well, Emera, in partnership with others, is actively working on three alternative DC transmission projects that will facilitate the collection and transmission of clean renewable energy resources from Maine and Canada into New England. At least one of these DC projects, the new Atlantic link, will be bid into this RFP.

Massachusetts is also proceeding with discussion of a bill proposed by Governor Baker that would cause a procurement for an additional 18 terawatt hours of Canadian hydropower or wind firmed with Canadian hydropower. Emera intends to bid, should another RFP result.

Moving to the Caribbean, we announced earlier today an offer to purchase the shares held by minority shareholders in Emera Caribbean Incorporated. Emera Caribbean is the Holding Company for Barbados Light & Power, DOMLEC, and our minority ownership in LUCELEC. Emera currently owns approximately 80.7% of Emera Caribbean.

Our offer of BBD33.30 in cash or Emera depository receipts represents 30% premium to the current share price for ECI. An application has been filed to list the depository receipts on the Barbados Stock Exchange, which will provide Barbadians the opportunity to invest in Emera's growth and success. The offer has been unanimously approved by the ECI Board of Directors, and they have approved a supporting agreement for that transaction.

The largest shareholder outside of Emera, Barbados' National Insurance Board, along with Officers and Directors of ECI who are also shareholders, have entered into a lock-up agreement under which they have agreed to tender their shares to the offer. Collectively, these shareholders represent approximately 69% of the ECI shares not held by Emera.

ECI shares are thinly traded on the Barbados Stock Exchange, and the offer provides value and liquidity to current ECI shareholders. It also streamlines the ownership structure for us. We expect the offer to be completed in December of 2015.

The 12-megawatt utility scale solar plant in Barbados is progressing well. The solar plant will have 46,000 solar panels, and is expected to be completed by August of next year.

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

Thank you, Chris. And good morning, everyone.

Our third-quarter results were released earlier today, and are now on the Emera website. You'll notice that, this quarter, Emera's results are affected by a number of factors in respect of the TECO Energy acquisition, which will continue for the next few quarters. Accordingly, we've tried to provide more clarity within our consolidated financial highlights table as to this and other items affecting earnings for the period. We'll continue to highlight these items moving forward.

Cutting through all these notable impacts in the quarter, Emera's underlying business is performing well and remains on track to our earnings growth expectations that support our 8% annual dividend growth target through 2019. Emera's consolidated net income for 2015 was CAD35 million or CAD0.24 per share compared to CAD28.2 million or CAD0.20 per share in the third quarter of last year.

When third-quarter results are normalized for mark-to-market losses, adjusted net income was CAD23.3 million or CAD0.16 per share compared to CAD49.9 million or CAD0.35 per share last year. EPS for the quarter was CAD0.30 when further excluding the impact of costs related to the TECO Energy acquisition, with the decrease from last year's CAD0.35 a result of the timing of regulatory deferrals at Nova Scotia Power. As Chris mentioned earlier, we expect NSPI's full-year earnings to grow modestly compared to that of 2014.

Before I discuss our segmented results, I'd like to give an update on our financing for the TECO acquisition. The financing is expected to be structured with between $800 million and $1.2 billion of preferred equity, and between $3.4 billion and $3.8 billion in debt, and between $1.7 billion to $2.1 billion in common equity or internally generated funds.

In early September, we successfully raised CAD2.185 billion in convertible debenture financing that will convert to Emera common shares at closing. This financing is expected to address the common equity needs for the TECO Energy acquisition. We'll be issuing the preferred equity and debt financing activity closer to acquisition in mid-2016.

It's worthy to note that with the proceeds of the first installment of the convertible debenture, now held directly in US dollar treasuries, and a currency exchange forward contract now in place for the second installment, that our currency risk has now been eliminated for the full CAD2.185 billion at a rate of approximately CAD1.30. This, together with the intentions of a significant portion of the preferred share and debt financing to be raised directly in US dollars, means we have approximately 85% of the $6.5 billion required to close the deal actually or effectively hedged, removing the majority of the foreign exchange currency risk between now and deal closing.

Turning now to our segmented results, Nova Scotia Power's net income decreased to CAD4.9 million in the third quarter of 2015. As mentioned earlier, the decrease is primarily due to timing, with NSPI's full-year earnings still expected to grow modestly compared to that of 2014.

Emera Maine contributed CAD14.7 million to consolidated net income in the third quarter of 2015, an increase of CAD1.4 million compared to the third quarter last year. The higher net income was primarily due to the impact of a stronger US dollar.

Emera Caribbean contributed CAD13.6 million to consolidated net income, an increase of CAD5.4 million compared to CAD8.2 million for the same period last year. The increase was primarily due to a decrease in OM&G at Grand Bahama Power, reduced maintenance and payroll costs at Barbados Light & Power, as well as the impact of strengthening foreign currencies.

The Pipeline segment contributed adjusted net income of CAD10.3 million in the third quarter of 2015, compared to CAD8.7 million in the same quarter last year. The increase of CAD1.6 million was primarily due to lower interest expense, increased transmission revenue from maritimes and northeast pipe, and the impact of a stronger US dollar.

Emera Energy delivered adjusted net income of CAD14.9 million in the third quarter compared to CAD10.7 million in the same quarter last year. The CAD4.2 million increase was primarily due to increased electricity sales and lower income tax expense. The increased electricity sales were primarily due to the impact of an outage and upgrade at the Bridgeport Energy facility in the same period last year.

Our Corporate and Other segment posted a CAD35.1 million loss in the third quarter of 2015 compared to a loss of CAD1.9 million in the same period a year ago. The variance is primarily due to CAD29.2 million in items affecting earnings quarter over quarter, attributable to CAD20.1 million in after-tax-related costs from the pending acquisition of the TECO Energy, combined with a CAD9.1 million after-tax gain on the dilution of Algonquin in the same period of last year.

That's all for my financial overview, and now we'll be happy to take your questions.

(Operator Instructions)

Our first question is from Linda Ezergailis with TD Securities. Your line is open.

Thank you. Just a question about the Caribbean. I realize there's some simplification associated with the announcement this morning, but are there any possibilities of further consolidation of your partial investments in the region?

Linda, it's Chris. Thank you for your question. I think it's something that we'll look at over time. For the time being, we're focused on getting ECI completely consolidated. And we also like the opportunity of being able to put depository receipts on the Barbados exchange and create that opportunity for our customer base there. But it's something we'll look at over time.

Okay. Thank you. And just a follow-up question on Emera Energy, how might we think of your Q4 trading results? Is there any -- it looks like October was mild, but are there any potential infrastructure constraints or maintenance happening? How can we think of what Q4 might hold for your trading business?

Linda, it's Judy. Q4, November, December tend to be strong months in the business, obviously, but it's largely weather dependent. I think it's fair to say that any major pipe maintenance and that kind of thing, people try to get that over with before the winter. So, that's not necessarily a factor. It's really a weather story in these months.

The only other guidance I can really say is that we have said that the business should be able to deliver net income of somewhere between CAD15 million and CAD30 million. And we're -- if everything goes in November and December as we think, we'll be at the high range of that amount.

Great. Thank you. I'll jump back in the queue.

The next question is from Matthew Akman with Scotiabank. Your line is open.

Hi. For Scott first -- I just wanted to clarify and just to confirm that the DSM expenditures probably impacted and dampened the quarter a little bit at NSPI but are not expected to have a full-year impact. Is that the case, Scott?

DSM costs in Nova Scotia Power are being -- pursuant to agreement in place, are being deferred. So, it's having an impact on cash but not earnings. It's really the impact of contributions of non-fuel revenues towards the fuel adjustment mechanism and the timing of the accruals related to that, that's impacting the quarter-over-quarter variance in NSPI this year.

Okay. It looked like it was in OM&G more than anything, which I thought was DSM related.

So, it's -- that same deferral is flowing through. I'm trying to think now whether -- that same deferral is flowing through OM&G. So, it is in that deferral account but it's effectively in the transfer of non-fuel-related items into fuel-related items at the end of the year.

Okay. Separately, the refinancing of Bear Swamp is obviously positive. You guys pulled a bunch of money out. But I'm just wondering, on the other side of it, if there's anything, Scott, you can say about the earnings impact of that on an ongoing basis for Bear Swamp earnings.

Yes. Really it's just the impact of higher interest expense now at Bear Swamp that will reduce the aftertax income at Bear Swamp and therefore our 50% portion of it.

Okay.

So, it will have an impact on earnings with benefit of the distribution of cash to both partners.

But, again, Matthew, though, that's against rising capacity payments, and so there's certainly an offset there.

Okay. Thanks for the reminder. Thanks. Those are my questions, guys.

The next question is from Ben Pham with BMO Capital Markets. Your line is open.

Okay. Thanks. Just wanted to clarify the -- just catch up on the DC transmission lines that you're planning to bid in. Did you say that you're planning to bid in one of them, the Atlantic Link, or you're not sure which one you're going to bid in yet?

What I said was that, for sure, Atlantic Link will bid in. Whether the other ones do or not will really depend on whether there are proponents, suppliers that want to select them. But in the case of Atlantic Link we believe that it is quite flexible from a scaling perspective and, therefore, we want to put it forward. And, as I said, the other ones may bid in, as well, but this one will for sure.

It's a new project. We certainly believe that it actually is extremely well positioned, both to draw energy from northern Maine, as well as from New Brunswick, as well as from Nova Scotia and Labrador. So, when you look at its potential to balance the region into the Boston market, we think it's a very well-positioned project.

Okay. And you own 100% of that, Chris? Is that --?

That's our current positioning on it. But we expect that we will ultimately select a delivery and partner, as well. But, for now, that's the position.

Okay. And can you remind me how, just with the Nova Scotia Power, you talk about the GRA being -- not having a filing in 2016. But can you remind me how the Maritime Link filings work just over the next couple years? And with the new policy coming out, does that impact how the rates kick in overall?

Certainly our intention would be to file the Maritime Link case in either 2017 or early 2018, that kind of time frame. But we expect that Nova Scotia Power, as it looks at its three-year fuel requirements, will bring in what they currently know about Maritime Link. And so, when -- Nova Scotia Power's been talking about what effect they believe that, that will have, and that would certainly include the Maritime Link. So, that's the way they're thinking about it. Bob's on the line, as well. He may want to add something to that.

Yes, I would, Chris. Thanks, Ben. The plan would be to file the fuel side of the application to facilitate rate stability for 2017 and 2019, inclusive of the anticipated costs related to Maritime Link. So it's included.

Okay. You guys are really hedging out the fuel costs next couple years, right?

That's one of the things that I think will allow us to be more certain about where fuel is going, is to increase the fuel hedging component. And, as well, you have to remember that, by the time we hit that time frame with Maritime Link on, we'll have upwards of 35% to 55% of the energy that can come from essentially fixed-cost components. So, the volatility of fuel for Nova Scotia Power will go down quite a lot as the Maritime Link comes on. That's one of the benefits that we've always known we would see from that investment. And, again, Bob may want to add to that.

I think we're in a very unique and positive position for customers in Nova Scotia to have rate stability and it is because of that portfolio and that shift. So, it's very positive, as Chris has stated.

Okay. Got it. Thanks for taking my questions.

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

I guess my question's for Chris. It's been a little bit more than two months since you announced the TECO deal. If you could give us maybe some insights to your conversations you've had with regulators and other pertinent parties in both New Mexico and also in Florida.

Yes, Andrew. What we've been working hard to do is to make sure that we keep everybody involved, stakeholders across both of those states involved and aware of what we're up to. The transparency of this transaction, we think, is critical to its success, so that's been an important thing.

Generally speaking, the transaction will not have an effect on rates for customers. And therefore -- and we will be adopting all of the approaches, stipulations, and so on that TECO Energy adopted -- say, for instance, in New Mexico -- but also there are rate settlements in place, in Florida, today and all those things continue to remain intact. So, there is a lot of stability, I believe, for customers from this transaction.

We've had specific meetings with interveners, certainly both the staff at New Mexico and also the attorney general's consumer advocacy group. We've certainly met with those various stakeholders. And we're working hard to ensure that we're able to at least propose a settlement, in this case. In fact, I misspoke in my remarks. The scheduling conference is now scheduled for December 10. When you put all those things together we believe that we're progressing well and we'll continue to be available to stakeholders as this moves forward.

Okay. That's very helpful. And then, my second question, somewhat related, is to Scott, just on FX exposure as you see that today. And then, just with the prospective closing of TECO, let's just say, mid-year next year, how you think about your FX exposure from now until then, and then beyond.

I think, Andrew, as mentioned briefly in the remarks, we've now effectively hedged all of the CAD2.185 billion equity that's in place by way of taking the proceeds from the first installment, and they're now held in -- directly in US dollar treasuries. And then, the second installment we've put forwards in place. So, the average rate at which we've hedged that out right now is CAD1.30. So, in a sense providing some mitigation against the dollar -- the Canadian dollar that's further depreciated since that time, so that's good. And with the balance of most of the debt in preferred/hybrid financing in our plan looking at directly raising US dollar-based activity, really puts us in a place where 85% of that CAD6.5 billion is now hedged.

So, we're feeling reasonably good about that. Not to suggest that we won't look to hedge out a little bit more, but that 85% number we're feeling reasonably confident about that gives us some certainty. It will add some accounting, mark-to-market type volatility for us between now and closing. But, economically, I think we've done the right thing in terms of putting that hedge in place.

And then, of course, as we think about the currency-related exposure to the transaction, really, we worry about devaluation of the Canadian dollar between now and close, and then appreciation of the Canadian dollar after close. And there, too, it's really part of the debt strategy that will provide a meaningful part of our risk mitigation opportunity as it relates to currency. So, the more US dollar debt from a balance sheet and economic perspective, but also from an earnings and cash flow perspective, does help to mitigate that risk.

And even thinking about today, we have more than 50% of our operations are non-Canadian but most of our debt is Canadian. So, looking at things like reconstituting some of our existing debt through derivative-type product in order to think about perhaps moving more of our existing debt to US dollar pay will incrementally help to mitigate that risk post-closing, as well. So, those are all things line of sight or us today.

That's very helpful. Thank you.

The next question is from Robert Kwan with RBC Capital Markets. Your line is open.

Good morning. If I could just come back to some of the transmission projects. Chris, can you talk without how Atlantic Link -- the other two projects, NEL and the third, I don't know if it's Maine Green or something else -- but can you just talk about how the three interplay? Do you see -- even if you bid all three in, is it almost either/or? Do you think that there's merits to maybe have multiple projects move forward?

The reason that there are three, Robert, first and foremost, is because they functionally actually work to different areas within the region. When it comes to the NEL, the original project, that was primarily about just simply increasing the transfer capacity in the lower part of the state of Maine and through New Hampshire. So, that project continues to be valuable for that purpose. But it doesn't get at some of the more northerly projects that will be required in order to get some new clean energy available. So, a project like the Green Line, which is the other one that's essentially starting in the state of Maine, that gets further north and is able to consolidate some more of that energy, and then go subsea as a secondary approach.

But then if you look at the Atlantic Link, what it does, it's able to gather energy from the much broader region. And we believe it's well positioned to collect the most energy. And that's really the issue for this first RFP, is most of these projects are much larger than 5 terawatt hours. So, to be able to make them economic is a bit of a challenge. And that's why the Atlantic Link, we believe, will be closest to economic, although it will still be challenged at 5 terawatt hours.

What these projects are all really focused on is the next step, which I referred to in my remarks, related to the work that Governor Baker is doing to try to increase the clean energy component. And so, if you take the two amounts together you could see as much as 23 terawatt hours being required. That will require at least two DC projects to get that to happen.

And so, when we think about this RFP, we're mostly focused on the AC upgrades in the state of Maine. That, by itself, will be several hundred million dollars of upgrade, I think something in the order of CAD300 million to CAD400 million for Emera Maine. And those will, I believe, be the lowest cost projects that can actually gather the wind that likely will be bid and also increase the capacity out of Canada. So, when you put all that together, we figure that, that's probably the most competitive opportunity. But then, for the larger initiative, when that comes together, it's going to be multiple (inaudible) projects.

Okay. And, given you've got a hand in a few different projects, are you going to be going out to customers separately or do you think that there's a possibility that you can somehow integrate the offering to allow potential customers to offer into either/or, giving them the choice, depending which one goes forward?

To be clear, all of these projects will be open to any energy providers that want it. It's a little bit complicated because a transmission project can't be bid in by itself. It can only be bid in, in conjunction with suppliers. They all have to be open. But, fundamentally, we would say that certainly the work that Central Maine Power and Emera Maine are doing, I think that will be able to be bid in support of a number of potential projects. And we also think that the Atlantic Link will also be able to be bid in support of some potential projects.

Okay. Just moving to Nova Scotia and, as an integrated utility, you've done a good job disaggregating the delivery charge and then isolating fuel with the FAM. I'm just wondering as you go forward here, and specifically the commentary -- or the discussion around Maritime Link, can you give us some color as to how you see, say, the industrial user groups, consumer advocates, government and UARB, how much of the understanding as rates come together, just the way you've negotiated the agreements with all the upfront power, and that providing a significant benefit to drive down the fuel, how that's being thought of in terms of rate stability?

I think, first and foremost -- and I also would ask Bob to chime in -- but I think, first and foremost, that additional power up front, what it's doing, really, is helping offset the early-stage cost. Because, as you know, these projects are always most expensive the first day because they're amortized capital and every day thereafter they get lower cost. So, we've been able to bring some additional power in to do that.

And on top of that, as well, we've also been able to negotiate with Nalcor, and in aid of the approach that the UARB was looking for, some incremental energy, as well. And that can be upwards of 1.8 terawatt hours on top of the essentially terawatt hour that will come with the project. So, when you put all that together, it gives Nova Scotia tremendous flexibility and a very great ability to stabilize costs.

And that's really -- to the question, that's really what the focus has been. Over the years, we've seen a lot of volatility on the high-carbon fuel side. And so, now this will provide the utility the ability to stabilize and to select how much of the clean energy they want at any given time. And, Bob, do you want to talk about the stakeholder approach?

Sure, Chris. Robert, the year-long review with the government on the (inaudible) review, we were certainly involved deeply and traveled around the province. The message from all of our stakeholders and all our customers was really about reliability, predictability, and stability in rates.

So, we're encouraged by the report that was issued last week by the government. It's really about policy changes that enable rate stability. Chris has described the portfolio and the fact that renewable energy is reducing our alliance on fossil fuels. So, historically, I think we're just in a terrific position to work with our customers and provide the rate stability that they need and require.

Okay. Just to be clear, though, transitioning from a bit of a period where you've certainly done things to help stabilize fuel cost, but there still was some volatility where historically you've had very stable delivery charges to one, as you go forward here, where it's going to be more stabilizing the total rate. Is there that understanding that the delivery charge is likely to increase faster but offset by good reduction both in the amount and the volatility in the fuel charge?

In 2015, there was no increase. In 2016, there will be no increase. And our target around the fuel side is less than inflation. So, that is our view going forward.

So, Robert, I think it's not the right assumption to assume that delivery charges will go up. We would say that we've done a good job of getting -- managing costs around the delivery side. So, we actually believe that we'll actually have a lot of stability there, as well.

Okay. That's great. Thanks very much.

(Operator Instructions)

The next question is from Paul Lechem with CIBC. Your line is open.

Thank you. Good morning. As you move towards the closing of TECO, just wondering, is there any need or any opportunity to expand your Emera Energy business down there in either the gas or the electric trading side of the business?

Certainly, Paul, when we look at doing business in new service territories and new regions, we certainly will look at our entire offering in the region. So, I would say it's too early to say whether or not we're going to be doing business in that area with Emera Energy. But we certainly would look now at those regions and see whether or not there's something where they can bring value to customers. And certainly if they can, then we would look to do that.

Some of the early-stage thinking that we have right now would be that we've been working on getting gas into the Caribbean region for some time. People's Gas is very well positioned to do that. In fact, they're very focused on compressed natural gas today. We just achieved an export permit. We would think that some of that working together might work well. And, as you asked, then the next step is whether any of our other businesses would be able to achieve some good linkages and adjacencies with the businesses in total.

That's helpful. Thanks. On Algonquin, I understand you're updating the strategic investment agreement. Can you give us any thoughts there about where that is at? And does it signal potentially a move towards a long-term exit of that investment?

The update in the agreement is really just maturing it to our current situation. We've been under share restrictions for quite a number of years there. We believed, and so does the Company, that there's no need to have those share restrictions anymore, so those will be eliminated. But beyond that, we'll also reinforce and re-describe the areas where we'll work together, and we continue to see opportunities to do that. So that continues to be the way we look at that business.

Okay. Thanks, Chris.

And it appears that we have no further questions at this time. I'll turn the call back over to our presenters.

Okay. Certainly thank you very much for taking the time this morning and your participation in the call. And we hope you have a great rest of the day. Thanks a lot.

Ladies and gentlemen, this concludes today's conference call. You may now disconnect.