Emera Inc (EMA) 2013 Q3 法說會逐字稿

Good afternoon, ladies and gentlemen, and welcome to the Emera third-quarter conference call.

I would now like to turn the meeting over to Ms. Jill Hennigar, Manager of Investor Relations. Please go ahead, Ms. Hennigar.

Thank you. Good afternoon, everyone. Thank you for joining us for our third-quarter conference call this afternoon.

Joining me from Emera are Chris Huskilson, President and Chief Executive Officer; Scott Balfour, EVP and Chief Financial Officer; and other members of the management team. Emera's third-quarter earnings release was distributed earlier today via Newswire, and the financial statements and management's discussion and analysis are available on our website at Emera.com.

This afternoon, 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 recorded in US dollars. I will take a moment to remind you that this conference call may contain forward-looking information, which involve 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 this conference is being widely disseminated via live webcast.

And now I will turn things over to Chris.

Thank you Jill, and good afternoon, everyone. Emera delivered Q3 adjusted net Income of CAD38.4 million, or CAD0.29 per share, compared to CAD43.8 million or CAD0.35 per share in Q3 of 2012.

Year-to-date adjusted net income was CAD196.4 million or CAD1.48 per share, compared to $171.9 million or CAD1.38 per share for the same period in 2012. Scott will take you through the details of the quarter later in his remarks.

Beginning with our most recent development on the Maritime Link, on October 21 we filed our compliance filing on market price energy with the Nova Scotia Utility and Review Board. We believe this filing addresses the Board's market priced energy condition through an Energy Access Agreement between Emera, Nalcor, and Nova Scotia Power.

The agreement contains the terms and conditions of a commercial arrangement that will allow NSGI to obtain access to market-priced energy when economically beneficial for its customers. The agreement provides access to market-priced energy that Nalcor has available for export up to 1.8 terawatt hours in each of the years of the agreement, which extends to 2041, and for a average annual amount of 1.2 terawatt hours per year over the term.

The Board has scheduled three days of hearings for November 14, 15 and 18 to review the agreement and submitted evidence from the Company and interveners. Both the filing and the hearing are critical steps for the project as we move towards completing the milestones required to begin construction.

In August, Emera entered into an agreement to purchase three combined cycle gas plants in New England. Transaction will add 1050 megawatts to Emera's generation capacity in the Northeast, and represents a total investment of CAD541 million. The facilities, all of which are of recent vintage, are in Bridgeport, Connecticut; Tereza, Rhode Island; and Rumford, Maine. While these assets will be modestly accretive in the early years, we believe they deliver meaningful value over the long term.

Staying with developments in New England, both Massachusetts and Connecticut recently issued requests for proposals for contracted renewables. Of the 565 megawatts of new contracts awarded in Massachusetts, First Wind was successful in capturing more than 50% of the contracts, which still has to be approved by the Massachusetts Department of Public Utilities.

The clean energy will come from the 147-megawatt Oakfield Wind project in Arusta County, Maine, and the 186-megawatt Binghampton wind project in Somerset County, Maine. The Northeast wind joint venture, which represents our 49% interest in First Wind's Northeast assets, has undertaken the refinancing of its various project and corporate debt facilities into one single facility, which will simplify and reduce costs of the JV's overall lending structure. This refinancing will facilitate the repayment of Emera's CAD150 million loan to the Northeast wind joint venture. We expect the transaction to close early next week.

At Nova Scotia Power, the focus has been on implementing productivity initiatives and cost control measures. Although already one of the most efficiently run utilities in Canada, we continue to look at various ways to find cost savings. We are benchmarking different business units with industry peers, looking at the potential for contracting out some functions, reorganizing several teams to gain efficiencies, and have eliminated 80 positions so far this year, mostly through attrition. These are just some of the things we're doing in an effort to reduce the need for rate increases in the future to support our customers.

In the Caribbean, we remain focused on finding less price volatile energy sources for our customers, and we have proposed a project that would see us moving CNG for the Port of West Palm Beach in Florida to Grand Bahama. Front-end engineering and design studies are 90% complete, and we expect to file the natural gas export application with the US Department of Energy before the end of the year, after which we expect to be in a position to make a final investment decision.

As well, earlier today, we announced an upcoming change to our Board of Directors. Our current chair, John McLennan, will step down on May 7, 2014, immediately following our annual general meeting, and subject to shareholder election, Jackie Sheppard will assume the role of Chair on the same day. Jackie has been an Emera Director since 2009, and her extensive knowledge in the energy industry and experience as a corporate executive and corporate director has proven valuable to the Emera Board. John has, and continues to provide leadership and council to both myself and our management team, and has lead the Board through a period of significant growth. John will remain on the Board, and we look forward to working with both John and Jackie as we make this transition.

All in all, its been a good quarter, and we're pleased with the progress we've made so far this year. In light of our progress and strong results, in October the Board of Directors approved an increase in the quarterly common share dividend for an annualized rate movement from CAD1.40 per year to CAD1.45 per year. This increase reflects the Board's confidence in our future earnings prospects and the continuing success of our strategy.

With that, I'll turn things over to Scott, who will give you a more detailed update on our financial quarter results.

Thank you Chris, and good afternoon everyone.

Our third-quarter results were released earlier this morning, and are now on the Emera website. Emera's consolidated net income for the third quarter of 2013 was CAD28.8 million or CAD0.22 per share, compared to CAD44.7 million or CAD0.36 per share in the third quarter of 2012.

As Chris mentioned earlier, when the Q3 results are normalized from mark-to-market gains and losses, 2013 adjusted net Income was CAD38.4 million or CAD0.29 per share, compared to CAD43.8 million or CAD0.35 per share last year. Impacting the results this quarter is the CAD33.9 million loss from discontinued operations at Algonquin Power recorded in their second quarter of this year. The majority of Algonquin's loss was due to a writedown of its energy from waste facility that was deemed no longer strategic to its business. Emera owns 24.4% of Algonquin, and accounts for its equity earnings, a quarter in arrears to the quarter Algonquin reports such earnings.

This resulted in Emera recognizing an after-tax loss of CAD7 million, or CAD0.05 per share in the third quarter, in respect of this loss from discontinued operations by Algonquin. Also to note, adjusted net Income for the third quarter of last year included CAD2.7 million, or CAD0.02 per share, of after-tax gains from the conversion of Algonquin subscription receipts into Algonquin common shares. There were no similar gains recognized in the third quarter this year.

Nova Scotia Power contributed CAD14.4 million to consolidated net income in the third quarter of 2013, compared to CAD22.6 million in the third quarter last year. The decrease was primarily due to the impacts on AFUDC, allowance for funds used during construction, and tax expense from a reduced capital spending program this year, and the comparative impact of the reversal of a CAD5 million receivable allowance in 2012. NSPI's rate base and earnings for the full year are expected to remain consistent with those of 2012 and NSPI anticipates earning within its allowed ROE range.

Maine Utility Operations contributed $9.2 million to consolidated net income in the third quarter of this year, compared to $11 million for the same period last year. The lower net income is primarily due to the impact of the expected FERC transmission rate refund for the period from October 2011 to December 2012, as a result of expected rate of return on equity rate reductions for New England transmission owners, for which Bangor-Hydro took a $1.5 million after-tax provision in the quarter. This provision reflects the impact, if the recommendation of the Administrative Law Judge, in regards to the retroactive refund period, is fully adopted by the FERC. The FERC has not yet announced the decision on this rate review for either the retroactive or prospective period.

Caribbean Utility Operations contributed $11.4 million to consolidated net income in the third quarter of 2013, compared to $7.2 million the same quarter last year. The higher net income was primarily due to operational cost savings in Grand Bahama Power Company and a $1.7 million increase in other income due to the recognition of a regulatory asset in GVPC.

Pipelines contributed CAD8.2 million in the third quarter this year, compared to CAD6.8 million last year. This increase is due to reduced interest expenses.

Excluding the effect of mark-to-market adjustments, Emera's services, renewables, and other investments contributed CAD2.3 million to consolidated net income in the third quarter of 2013, compared to CAD7.3 million in the third quarter of 2012. The decrease is primarily due to the CAD7 million after-tax impact of Algonquin's loss from discontinued operations, as previously mentioned, as well as the comparative impact of the CAD2.7 million after-tax gains recognized in the third quarter of last year on the conversion of Algonquin subreceipts into Algonquin common shares.

These effects were partially offset by improved earnings from Emera's equity earnings in Algonquin, excluding the impact of the discontinued operations, and as well as from the Bear Swamp facility.

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

(Operator Instructions)

Your first question comes from the line of Juan Plessis from Canaccord Genuity. Your line is open.

Well, thank you. You've lowered your 2013 CapEx at NSPI in Maine. Is that a timing issue that shifts CapEx into 2014, or is that a reduction in planned capital projects?

Bob Hanf here for Nova Scotia Power. So it's not a shift. It is part of our program to look at costs throughout the Company. And so it's not a shift in that sense, if that answers your question.

And this Garry Chasse, President of the Maine utilities. I would just say that, similar to our past history, some of the projects that we've done have been large and lumpy. So to a large extent it depends -- it is dependent on the timing of those projects as to the level of capital in any one year.

Okay, great. Thank you for that. And just wondering if you could update us on your 2013 capital spending program,. You've spent CAD252 million in total in the first nine months of the year.

What are you planning to spend for the full year? And also while we're on the topic of CapEx, then perhaps you can tell us what your capital requirements are for 2014?

So it's Scott, Juan. So I think the best place to guide you in terms of our CapEx requirements would be the Investor Relations slide deck that shows not just the profile for 2014, but beyond that as well. As it relates to 2013, of course the largest component of the balance-of-year capital spending will be the closing of the purchase of the three gas plants in New England, as well as the completion of the capital programs for both Nova Scotia Power and Bangor-Hydro, which are also already announced.

In fact, that lower capital program that Bob referred to for Nova Scotia Power is consistent with the plan that was announced earlier this year. So they are generally on track with that, but for the balance of 2013, really the big component of it is the purchase of the three gas plants in New England.

Okay, thank you, Scott. Moving onto the Caribbean. What is the proposed legislation in Barbados with respect to the addition of renewable generation, and what could that mean for potential investments for Emera?

Juan, it's Chris. Just -- it's really just a relook at the markets there. There's a real strong objective to get some more renewables into the market and to introduce things like some of the pilot programs we've had where we've had net metering and other things on the books already.

And so what we're going to end up seeing, as was consistent with our strategy, you're going to see a lot more renewable investment occurring in that marketplace. So it really is focused in that area, and we've been working with the Department of Energy and also stakeholders in that market to move that all forward. So we're expecting to see some legislation introduced either this Fall or early in the Winter, and that will actually implement that approach.

Okay, thanks, Chris. And do you expect any impact from the new 25-year license that was issued at Dominique Electric?

No, I think that was an expected outcome. As we were entering that market, one of the things we were doing was spending time with the government. And as you know, in that particular situation, they're a large shareholder of the entity as well, but it was a matter of spending time with the government.

Again, they were interested in how we might develop and implement renewables in that marketplace. And so there is work going on around geothermal and other initiatives there. So I think that that's business as usual in that location.

Okay, great, thank you very much.

Well thanks, Juan.

Your next question comes from the line of Paul Lechem from CIBC. Your line is open.

Hi, thanks, good afternoon.

Hi, Paul.

Just going back on the CapEx questions for a second. I was wondering, what's a good pace level of sustaining CapEx for an SPI and the Maine utilities?

So Bob Hanf for Scotia Power, the answer is about CAD175 million a year.

For the Maine utilities, we would expect about $26 million to $27 million per year for base level of capital.

So around SPI then, the CAD200 million you're now expecting to spend this year is just a little more than the sustaining level of CapEx. So I was just wondering, what kind of programs got pushed out from this year that you were hoping to, originally hoping to include in the year, what kind of things are you deferring?

So we had a very careful review of all of our spending, and insuring that we didn't violate our safety standard, our reliability standard. And that we found projects that we could move into the next year without impairing those first two tests.

And so that's the nature of those decisions. And so we're quite comfortable that we're going to meet our reliability and our safety standards.

And I think -- Paul, it's Chris. The other thing that's changing in the market is, as we look at the potential of having Maritime Link come into the marketplace, it does change how we look at where the generation is going to come from in the future. And so the amount of investment that needs to happen across the fleet and the way renewables will get integrated changes a bit and I think that's starting to reflect in the future.

The other thing that also should be noted is that Nova Scotia Power has had great reliability results in the last of couple of years. In fact, I think last year was the best reliability in 40 years.

And so we've been investing in reliability over the period. We believe that we're in pretty good shape now, and so that that changes the program as well. So all of these things get assessed over time, and those assessments actually turn into actions in a future year.

Got you. With the FERC decision out there, I guess recommendation out there, just wondering does this change your view of investments in Maine on the transmission side, and not just what you have with Bangor right now but the Northeast Energy Link down the road? Does this change, if returns on transmission are lower, does this change your outlook for to building Northeast Energy Link?

Garry, I might jump into that one. So Paul, I think at the end of the day the question is whether we're going to get a fair return in the marketplace. It's too early to tell exactly where the FERC is going to come out on that, but we believe its been a fair process.

And so we're looking forward to an outcome. And as long as we can raise the capital and see a reasonable return from the investment, then we'll be certainly continuing to work down that kind of a path.

Fair enough. Last question from me, On the Northeast Wind, you mentioned there was some recent RFPs in New England for renewables and [fresh wouldn't] have done quite well on that. Does that mean -- are there any new projects that they are going to be building that could be vended into the partnership? Or how should we think about the opportunity there?

Paul, it's Judy Steele. So First Wind has about half a dozen projects kind of at various stages of development. I would say that in -- we'll kind of know as we get further along into 2014 which ones will be moving ahead first, but the expectation is that they would have additional projects that would meet the hurdle rates inherent in their transfer agreement, and we would expect to be making additional investment.

And you'd expect some clarity on that some time through mid-2014?

Yes.

It's Paul. If you take the two projects that are referred to in the notes, that's about CAD150 million worth of spending from our perspective, and as long as they meet the transfer agreement then you'll see those show up in the joint venture.

Okay. Are those operating facilities already?

No.

No, not yet. They are under development, and would expect to be operating by the end of 2015.

I got you. Okay, thank you.

Thanks.

Your next question comes from the line of Ben Pham from BMO Capital Markets. Your line is open.

Thank you. Good afternoon, everybody. Just wanted to check the rate filing in Nova Scotia. Is that planned for next year?

I think it's too early to stake out. We're doing a very careful review right now, and we'll be in a better position in the near future to make that statement.

Well, and I think, Ben, we're under a settlement agreement as we speak, in Nova Scotia. And so I think that's the guidance you should take at this point.

I was just thinking more beyond that and preparing for that. That's fair enough. And just on New England, is it just FERC approval that's the gating factor right now?

Sorry, could you repeat that?

Just on the New England acquisition. Is it just FERC approval, or just what's left there in terms of that you need to get approval for to get that transaction done?

Yes, fundamentally it's FERC approval, which we believe is imminent. So we would be expecting to close, certainly within the quarter, and hopefully within the month of November.

I think, Judy, it's fair to say, Ben, that there was no intervention on that FERC process. So it's moved along quite quickly.

Yes.

Okay, that's good to hear, guys. Just the last question is on your liquidity levels, and I notice your cash balances is quite high. Just a bit more than, a lot more actually than I've seen in the past. And just can you comment there, where your liquidity is right now? And there was any need for working capital items that could have brought it down post Q3?

So, yes. At the end of the third quarter, remember we had done a medium-term note within Nova Scotia Power in the second quarter, and it was repaid the day after the end of the third quarter. So the first day of the fourth quarter that existing -- there was an existing maturity that we effectively refinanced early. So we were sitting with that capital for a couple of months because we did a note issue earlier in the year that was then used to repay the maturing mark-to-market on the first day of the fourth quarter.

Great. That's it for me.

Thanks, Ben.

Your next question comes from the line of Jeremy Rosenfield with Desjardins. Your line is open.

Thanks, good afternoon, everybody. So just going back to Nova Scotia for a second. I'm curious, have you advanced talks at all with the political leadership on what they would like to see in terms of changes for the market structure, and potential changes for NSPI, and what kind of financial impact that might have?

Bob Hanf here. So it's early days. We have not received any proposed legislation to review. We have met with the minister and members of the department, and have had very constructive meetings. And we very much look forward to working with them on these important matters.

So still a little bit too early to know definitively they would like to go, and it's kind of something that they are in discussion with, they haven't come with a proposal at this point?

It is too early, and we look forward to working with them.

Okay. Just coming back on the discussion around the First Wind assets. Just want to clarify, you wouldn't necessarily wait for a project to be placed into service before bringing that project into the partnership. So that's not one of the hurdles, if I'm understanding correctly?

Right, you are correct, yes. But there are a series of milestones that First Wind, as the developer, has to cross before they're able to bring the project forward for consideration.

Okay, perfect. And then maybe you can just clarify something for me from the provision that was taken at the Maine utilities, does the provision cover the full estimated impact if the proposed changes in rates were to be enacted? Or is this sort of a partial provision and then there could be some additional amount that you could take in the future?

It's Scott speaking. So the provision effectively relates to the full impact of the refund period of the retroactive period, which is the one at which we have more, a little more clarity in terms of guidance from the Administrative Law Judge. So yes, it reflects the full impact of that, if the FERC accepts the recommendation of the Administrative Law Judge.

Okay, perfect, excellent. That's it for me at the moment, thanks.

Thanks a lot.

Your next question comes from the line of Robert Kwan from RBC.

Good afternoon. Maybe just go back to Maine here, and with respect to the provision you took. As we look forward here, what ROE are you booking into rates, and are you taking, essentially, a change in assumptions on ROEs?

It's Scott again, Robert. At this point we've fully taken the impacts of the retroactive period. There's less clarity on what the ROE impact will be, if any, on the prospective period.

And so we're continuing to record earnings at the existing rate, and when we have better information then we can reflect that. But for now that's the best information we have.

Okay, makes sense. Then just turning to funding. Can you just, I don't know if you have any update since we've last spoke, on the funding plan for both the New England acquisition and also the base business timing amounts. Is there any change in the way you're looking at the New England acquisition capital structure? And then also with what you're doing in the First Wind refinancing and the proceeds that are going to be upstreamed, does that change as well any of your thoughts on the equity side of funding for those acquisitions?

Certainly, the funds from the refinancing of Northeast Wind joint venture will be used in contribution towards the financing requirements for the gas plant purchase. The balance of the proceeds required to close will be a combination of bridge financing, interim debt financing, and internal cash resources.

And then in good time, likely early in the New Year as it relates to the debt strategy for that acquisition, that gives us time to put permanent financing into place. So we'll close on that basis and look to optimize the debt financing for that acquisition early in the New Year.

As it relates to the balance of the financing needs for the Corporation, obviously we continue to proceed along the path that we've chatted about before in terms of working to balance our capital structure towards our target. And so nothing changed in that regard from previous conversation.

Okay, just last and kind of a small clean-up question. If I'm reading that it was isolated to the quarter, Bear Swamp, were the business interruption proceeds received during the quarter, and were they material?

Yes they were, and they were approximately CAD3.5 million.

After-tax?

No, before.

Okay, great. Thanks Judy. Thank you.

Thanks Robert.

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

Thank you. Just a follow-up question on Bear Swamp. Is that the full proceeds of the business interruption, or might there be more coming?

No that's pretty much it.

Okay, that's great. Thanks, Judy. And another clean-up question. What might be an appropriate corporate tax rate -- run rate to use?

I think 31% would continue to be the appropriate rate, and we do provide a tax rec table every quarter in the MD&A, and continue to use that as guidance as well.

Great, thank you.

Thanks, Linda.

Your next question comes from the line of Andrew Kuske from Credit Suisse. Your line is open. Andrew, your line is open. You may be on mute. Your next question comes from the line of Matthew Akman from Scotiabank. Your line is open.

Thank you very much. Wanted to chat about the deferrals at Nova Scotia Power for a sec. I guess one of my favorite topics for 3.30 PM on a Friday afternoon.

Seriously though, the fuel costs seem to have gone down in the quarter year over year. Obviously they're up for the full year, year over year. And so there's been a FAM build-up, but I'm wondering whether that FAM is going to start to turn down now that the fuel costs look like they're better on a year-over-year comparison. I don't know if it's for Scott or who it's for?

Matthew, it's Bob Hanf. I can take that. So as we look to the rest of the year, I think the costs are certainly more aligned with our forecast, and so we believe most of that pain is behind us. So I think we're in a good position for the remainder of the year. So I think you've captured it, Matthew.

And on the rate stabilization regulatory balance, it's CAD13 million. Is that expected to go up, down, or sideways, I guess, by the end of the year?

So we expect it to be flat, Matthew.

So end year at CAD13 million or end year at zero? CAD13 million. Okay. Thank you very much, guys. Those are my questions.

Thanks, Matthew.

(Operator Instructions)

Your next question comes from the line of Jeremy Rosenfield, It's a follow-up, from Desjardins. Your line is open.

Great, thanks. Just one other clean-up question. At Grand Bahama, in terms of the earnings sharing mechanism, I'm just curious how much was booked last year relative to the, I think it was $1.7 million this year?

It would have been nothing but bust there, Jeremy.

Okay, perfect, thanks.

Thank you.

Your next question comes from the line of Paul Tam from Credit Suisse.

Good afternoon. It's Andrew and Paul. Apologies about that earlier on.

It's okay, Andrew.

Small technology issue on our end. Just a question as it relates to the New England plants that you're about to close on in your existing power portfolio. What's your expected hedging outlook on the pro forma plants once you actually close the deal?

So Andrew, it's Judy. I would say that's under development. Generally, we would look to kind of hedge out the contracts and plants to some extent, and leave ourselves with some upside for the days when it's really nice to have. I think, though, what we're going to do is digest the plant, and evolve that strategy over the first few months.

I think, Andrew, though from a strategy perspective, we're not buying these things to have market-facing activity. Our overall approach is we believe that these plants are well positioned, both in the marketplace and also from a timing perspective.

We're very happy with what we've paid for these facilities, and we believe that that will create future economic value for us. The other thing is, is that Judy's team does a tremendous amount of work in this marketplace. They are moving around 1 billion cubic feet of gas a day now, and so that gives them great opportunity to understand how to source cash for these facilities and how to ultimately put producers and consumers together, and that's really what the long-term plan is for these facilities.

When we can find a producer that's interested supplying and a consumer interested in buying, that's really where we want to go. And so that's really what our longer term play is, but for sure, in the very short-term, we're going to be market-facing, but that's an early versus a late approach.

So I guess just a follow-up to that. On a longer term basis, do you see any opportunities to have these plants supply power into Nova Scotia? And when you really think about power flowing down from the Nalcor projects, and then there's the provisions on market-based power. Could you see some power from these facilities flowing back in into Nova Scotia? And then sort of bigger, broader question also is, is there an opportunity on a longer term basis to see these plants eventually included in a rate-based construct as some coal facilities come offline in Nova Scotia?

Well I think first of all, certainly as the market in the whole region evolves, we think that these facilities will be more and more important, because there are coal facilities coming off in the southern market. As we've seen recently, nuclear plants are beginning to be delicensed. And so there's a lot of change happening in the marketplace. And so again from that perspective, we think these plants are well positioned.

As it relates to the Maritimes, there's really a big open question right now as to whether or not we have gas supply in the Maritimes or not. We're looking forward to having the Encana project come on and be a reliable gas supply in this region but that, even as that happens, it's a very short-term situation. They may be there supplying gas for 5, 8, maybe 10 years, and then beyond that, it's uncertain as to where gas is going to come from.

So what we think about these facilities is they provide us with a hedge where we can in fact produce electricity and move electricity versus having to move gas. And so we're in a position where we can watch and participate in the market evolution in this region, participate in the market evolution in New England, and it gives us that kind of flexibility.

If we think specifically about Bridgeport and Tiberton, they are well positioned in their current markets, supplied by independent pipelines, and I think that they will continue to be very strong market players in those Markets. The Rumford plant is a totally different situation. It's a relatively underutilized facility, and ultimately needs to get a higher utilization. And that's the biggest opportunity in this portfolio right now. So how we turn that into a much higher participation plant will continue to be an open question for the next little while.

But anything from contracting it locally, making it a swing plant for energy coming out of Canadian hydro, or maybe even physically moving the facility. All those things are on the table at this point. And we'll just move along through time and see what the best approach is.

That's very helpful, and then if I may just ask one follow-on question, and just an update on title and what you've done there? Its gone very quiet, and I know you had the [test] project a while back. Is there anything going on, on the title side?

It has gone a bit quiet, although what's going on right now is the feed-in tariff is before the Nova Scotia regulator. So I think most proponents are waiting to see what ends up happening with the feed-in tariff and where that goes. And then I think once that's in place, you'll see some more activity occur.

We continue to be engaged with a number of suppliers. Certainly Open Hydro being one of them, but others as well. And if the circumstances are right, you could certainly see us investing again in that resource, because we do believe in it for the long term. And we just have to get the right circumstances to make that work.

Okay that's very helpful, thank you.

Thanks, Andrew.

There are no further questions at this time. I will turn the call back to Chris Huskilson for closing remarks.

Okay, well thank you very much, and thank you all for your participation in the call today. We'll be participating in EEI next week, and we're hopeful that we'll see a number of you there at that conference. So thank you all very much and enjoy your weekend.

Ladies and gentlemen, thank you for your participation. This concludes today's conference call and you may now disconnect.