Emera Inc (EMA) 2003 Q3 法說會逐字稿

Good afternoon, ladies and gentlemen. Welcome to Emera's third-quarter results conference call. I would like to turn the meeting over to Miss Judy Steele. You may now proceed, Ms. Steele.

Good afternoon everyone, and thank you for participating in our call today. Joining me from Emera are David Mann, President and Chief Executive Officer; Chris Huskilson, Chief Operating Officer; Ron Smith, Senior Vice President and Chief Financial Officer; and Greg Blundon (ph), General Manager of Finance, Nova Scotia Power. Emera's Q3 2003 earnings release financial statements and management's discussion and analysis were distributed earlier today via newswire. These documents along with a copy of these opening remarks are also available on our website at www.Emera.com.

Today, David will begin with some corporate highlights. Chris will then talk about Hurricane Juan and our restoration efforts following that massive storm. Ron will review the third-quarter financial results. We expect the presentation segment to last about 10 minutes, and then we will be happy to take questions. I will take a moment to remind you that this conference 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 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'll turn things over to David.

Thank you, Judy, and good afternoon everyone. Emera's consolidated net earnings were 11.5 million in the third quarter of 2003, compared to 16.2 million for the same period in 2002. Nova Scotia Power's contribution to net earnings was 11.6 million in the quarter compared to 12.5 million for the same period in 2002. Higher sales and lower fuel costs increased NSPI's electricity margin by 19 million. This was offset by higher taxes, higher Glace Bay amortization, and restoration and repair costs associated with Hurricane Juan.

Bangor Hydro's contribution to third-quarter earnings was 3.2 million which is lower than last year, largely due to a onetime 1.9 million after-tax charge related to its unbilled revenue accrual. Ron will speak in more detail about the Q3 financial results in a few moments.

As you are likely aware, last week Emera announced the sale of its 8.4 percent interest in the Sable Offshore Energy Project to Pengrowth Corporation for $65 million. Our Sable investment put us at the table with the industry leaders in the important early days of Nova Scotia's offshore development. We were proud to be the only Atlantic Canadian company with an ownership interest in the infrastructure, supporting Nova Scotia's offshore. As the region's leading energy company, this was a role that we actively sought out. Having said that, over the last year as we sharpened our focus, we concluded that we were more comfortable with lower risk energy infrastructure investments such as our interest in the Maritimes & Northeast Pipeline.

At the same time, Pengrowth had managed to invest in the onshore assets of the Sable development and was anxious to consolidate its position across the entire project. Of course, the biggest story for our company in the last quarter and perhaps the last century was Hurricane Juan, which blew across Nova Scotia on September 29th. This was the single largest event to occur in our company's history. And as the Canadian Hurricane Center noted, Hurricane Juan will be recorded as one of the most damaging storms in the modern history of Halifax.

As Chief Operating Officer, Chris was in the thick of it, and I'll turn things over to him now to share Nova Scotia Power's story with you.

Thank you, David, and good afternoon everyone. Hurricane Juan was indeed the biggest storm event to ever hit Nova Scotia Power. Juan was a Category 2 hurricane, packing sustained winds of 150 kilometers per hour with gusts reaching close to 180. With winds that strong, you can appreciate the impact on our system and our customers. Let me give you a brief overview of the storm and its devastating force.

The hurricane made landfall in the Halifax area and cut a swath across central Nova Scotia. In the immediate aftermath of the storm, hundreds of thousands of customers representing about half the population of the province were without power. Juan traveled the path of Nova Scotia Power's main transmission and distribution unit, literally our electrical backbone. When the storm subsided, we had lost 700 megawatts out of the expected 1000 megawatts of customer load. Three of our five highest capacity transmission lines were knocked out. On one line, three 120-foot high transmission towers collapsed.

Every single transmission line running into the City of Halifax and surrounding area was lost, and 45 major substations were affected by the storm. Moving out from those substations, every one of the 106 feeder lines in Halifax was brought down, and another 42 feeders were affected in the rest of the province. You can imagine the scope of the cleanup effort that faced us early on the morning following the storm.

On day one we focused on restoring transmission lines and critical facilities, as well as addressing safety hazards. We were assisted by the Emergency Measures Organization in identifying critical customers. Three hundred field crews from Nova Scotia, New Brunswick, Quebec, and Maine supported NSPI, EMO and municipal staff. We were also assisted by 1000 members of the Armed Forces. In the course of the restoration, we replaced approximately 275 transformers, 750 power poles, and had to string over 140,000 meters of wire.

By noon on Tuesday, 50 percent of the customers that had been affected were restored. By Thursday, it was up to 85 percent, and by Friday, 95 percent of our affected customers were restored. The final 5 percent of customers were mostly those in the hardest hit areas where fallen trees and damage in the electrical infrastructure was the greatest. Finally, the last customer was restored by Sunday, October 12th.

I'm proud of the storm response efforts organized and implemented by all our employees. We faced an enormous task and we did it effectively and efficiently and very much safely. In short order, we essentially rebuilt a large portion of our system. It was said that the repair effort was like rebuilding in a few days what had taken 80 years to create.

Customer support during the crisis was ongoing, and we received many letters and e-mails acknowledging our efforts. We also undertook independent research to measure our customers' opinion of our work and found that 89 percent of our residential customers surveyed said that they were satisfied with our response to the crisis. 82 percent were satisfied with how quickly their power had been restored and 72 percent were satisfied with our ability to keep them informed during the outage. A survey of business customers yielded very similar results.

These results are encouraging to be sure, but we also know that there are areas for improvement. We issued a report last Thursday to our regulator that details our response to Hurricane Juan. You can read it on our Nova Scotia Power Website at www.nspower.ca. In our regulatory report, we outlined areas we will examine in preparation for another crisis of similar proportion to Juan, in particular, related to initial damage assessment and then later, customer information processes. Our objective will be to look at ways to improve our response without adding costly permanent infrastructure that may only be required once in a century.

Now I'd like to turn the costs associated with Juan. Costs can generally be broken down into two categories -- repair and restoration, and capital replacements. In total, the cost of Hurricane Juan to the utility was $12.6 million. This includes the lost revenue, crew and other labor costs, repair expenses and capital expenditures. It breaks down as $4 million in operating cost, and $8.6 million in capital cost. We considered the option of seeking a regulatory deferral of the operating cost of Juan until such time as rates could be adjusted to provide for recovery. However, once we determined that we were able to absorb the cost and still earn within our allowed band (ph) for 2003, we felt it prudent to absorb that amount. I'll turn things over to Ron now for further review of our third-quarter financials.

Thanks, Chris. I presume everyone has had a chance to review our earnings release materials, so I plan to speak just briefly about the highlights. As David noted, Emera's consolidated net earnings were 11.5 million in the third quarter of 2003 compared to 16.2 million last year. Year-to-date consolidated net earnings increased 25 percent to 82 million in 2003, compared to 65 million in 2002. Quarterly earnings per share were 11 cents compared to 17 cents in 2002, including the 1-cent dilution impact of the common share issue in the fourth quarter of 2002. The earnings per share breaks down as follows. Nova Scotia Power contributed 11 cents compared to 13 cents in 2002. Bangor Hydro contributed 3 cents compared to 7 cents in 2002. Emera Energy's operations, including the Maritimes & Northeast Pipeline investment, Emera Fuels and Energy Services contributed 2 cents compared to 3 cents in 2002. And we spent 5 cents on corporate and business development costs compared to 6 cents last year.

Nova Scotia Power's contribution to consolidated earnings was $11.6 million, down from 12.5 million in 2002. Higher sales and lower fuel costs increased NSPI's electricity margin by $19 million. This was offset by the hurricane costs Chris referred to and higher corporate income taxes. In addition, for the first time in several quarters, we were in a position to record amortization on our Glace Bay generating station to the tune of $4.7 million.

Bangor Hydro's contribution to Q3 consolidated net earnings decreased by $3.4 million, largely due to a one-time $1.9 million after-tax charge related to its unbilled revenue accrual. This is similar to the adjustment NSPI processed in Q2, but I'll take a moment to refresh your memories on what that's all about. Bangor Hydro, like NSPI, recognizes electric revenues on the accrual basis, which includes an estimate of electricity consumed by customers in a given period and billed subsequently. That is quite a complex process and incorporates generation statistics, forecasts, line losses, billing data, weather normal, and actual patterns and so on. Following NSPI's lead, Bangor Hydro also improved its processes for estimating its unbilled revenue with an enhanced look-back test that better allocates unbilled revenue among customer classes. That exercise resulted in a one-time $3.4 million reduction in Bangor's unbilled revenue accrual, with a corresponding charge against third-quarter revenues. The after-tax impact on the bottom line was $1.9 million.

Emera Energy's Q3 earnings before interest and taxes were $700,000 in 2003 compared to a loss of $2 million in the same period in 2002. This was achieved through a $3.6 million reduction in business development expenditures quarter-over-quarter, reflecting the streamlining of this function that we undertook earlier this year. The effective date of the Sable transaction is July 1, 2003. The way the accounting works is that we have to book a loss of $1.2 million pretax, 0.6 million after-tax, to offset the profits we've earned from the effective date, July 1, to the quarter-end date of September 30. And that loss has been recognized in OM&G expense in the third quarter. While there is some complexity to the accounting, the net effect of our sale of the Sable interest is that we recovered book value at June 30, and we will have no net gain or loss after that date, all-in. The sale will obviously benefit our balance sheet as the funds are received over the next three years.

Cash flow continues to be a good news story on the year. Consolidated cash flow from operations before interest and taxes was $150 million in Q3 of 2003, compared to $119 million in Q3 of 2002. Year-to-date, cash flow is $400 million compared to $307 million in 2002. This increase is due to three factors -- higher sales of natural gas, which served to lower fuel expenses; higher revenues, which reflect a 3 percent price increase in 2002; and a $40 million reduction in coal inventory year-over-year as stockpiles of local coal have been used.

Before I close, with all the action lately in the Canadian dollar, I want to give you some sense of Emera's position. Emera has foreign exchange exposure on its fuel costs in Nova Scotia Power and on the earnings from Bangor Hydro in the U.S. portion of the Maritimes & Northeast pipeline. Nova Scotia Power has a natural hedge on some of its fuel, as sales of natural gas are made in U.S. dollars. A 1-cent change in the FX rate would have an impact on consolidated earnings of about $1 million before tax in any given time. We're in a net expense position, so a stronger Canadian dollar has a positive impact on the Company. At any point in time, Emera's foreign exchange exposure for the next 12 months is at least 50 percent hedged, with specific contracts and collars in place to protect the Company from wide swings. That's it for my financial overview and now we will open the floor for questions.

Lisa, we're ready to start the question-and-answer session.

(OPERATOR INSTRUCTIONS) Karen Taylor from BMO Nesbitt Burns.

Just have a couple of quick questions. Ron, as you're going through the segment contribution per share, I got a little distracted because they don't match what you have in the remarks on your Website. Can you just go through what the Bangor contribution was for -- you said it was 3 cents for the quarter versus what last year?

Seven.

Seven?

Yes. It's the same -- I don't know what Ron said, but it's the same document.

I thought that's what I said.

Okay.

Did you see something different on the website?

It's just the remarks from the Website suggested something different. It says Nova Scotia Power contributed 12 cents versus 17, and you said 11 versus 13. Is that your -- ? And Bangor was 4 cents versus 3 cents, and you said 3 cents versus 7.

Why don't look at that after (multiple speakers).

Sounds like something's wrong on the Website.

I think it might be a type on the Website. It's a penny either way.

Okay.

Go with what I said.

Okay. Well, I got what you said, so now I'm okay. The Glace Bay amortization charge of 4.7 million in the third quarter, is that a run rate that we should be looking forward to, or should we expect now the minimum charge of the 1.5?

For this year, Karen, you should expect the minimum charge of 6.2 for the year. And obviously, we have a commitment to do at least that much in years forward.

I was just sort of looking for the fourth quarter number, which will be the 1.5. The other revenue in NSPI is 9.1 million year-to-date. Could you just remind me what that is, please?

Let me make sure.

(multiple speakers) on overdue accounts and I think pole attachment (ph) and a whole lot of trivia. No export sales is in (ph) elective revenue.

Hook-up fees. Odds and ends.

But it's not export sales?

No.

And you did mention that you don't expect a GRA for '04 and you're still there?

Not for '04.

The unbilled revenue accrual -- I know we had this discussion on the second quarter for NSPI. I would have to assume that there is a big chunk of that number that in essence is resulting from prior period -- is that correct?

A chunk of it, yes.

So, how much would be attributable directly to the third quarter? Is it de minimus?

It wouldn't amount to much.

And the foreign exchange loss of 4.7 million for Bangor, how much is that after-tax?

Just look at --

And are you now on a going-forward basis -- you mentioned something about being 50 percent hedged. Is that from -- so you're not fully economically hedged at this point? You're only about half -- is that correct?

Going forward, about half -- on foreign exchange. We are much further hedged than that on fuel cost. But the foreign exchange piece of it only about 50 percent.

So on the fuel cost basis, can you -- ?

Chris perhaps should fill us in on that.

As far as on the fuel side, we are fully hedged on coal and petroleum coke. We have a sales program for natural gas that's hedged. And at this point, about 60 percent of our heavy fuel oil is hedged. So really, the only exposure we have for 2004 is about 40 percent of our heavy fuel oil.

Okay, so when you talk about being hedged completely for coal, coke and the programmed gas sales, and then you different and say we're only half hedged on the foreign exchange, to the extent that these costs are determined in U.S. dollars, can you reconcile the two for me, please?

We actually hedge the price in American dollars and then we have a program for managing the foreign exchange, and at this point in our period, we're at 50 percent for the foreign exchange.

So all of the currency then on the commodity for the fuel costs are hedged in terms of their U.S. dollar cost and then the translation back to Canada is 50 percent?

Yes.

I'm a little confused about your reference to the 4.7 million exchange lots in Bangor. Can you give me a reference? That's not revenue, yes?

That's on the revenue, so what would that translate to in an after-tax contribution to the segment?

Well, if you look on page 9, there is about a $4 million -- 0.4, so a $400,000 negative impact on net earnings in Bangor Hydro as a result of exchange.

Okay, and that's the after-tax number, then -- ?

Yes. And that's the net of the revenue and expense impacts.

Thank you.

Maureen Howe from RBC Capital Markets.

I'm just wondering with respect to sensitivity that you gave for your FX position, the sensitivity -- is that after the hedging that you have talked about?

No.

So, okay --

So we would manage that -- we manage that million dollar change, yes.

You manage the million dollar change and half of that now is basically offset by your hedging position?

The sensitivity is just that -- it's an indicator of how much it varies if there wasn't any hedging, basically. But I guess if you think of it this way, when we're in a position of having half of our U.S. dollars bought ahead, then we are essentially neutral on the Canadian versus the U.S. dollars for a given 12-month period, if you want to look at it that way. And then we take opportunities as they come to improve on that.

Okay, now I'm confused. I thought I was okay. I thought you said you hedged 50 percent of your foreign exchange --

Of the foreign exchange. So we've bought ahead most of the fuel in U.S. dollars. And when we hedge 50 percent -- or acquire 50 percent of the U.S. dollars that we need to eventually pay for that fuel, we're essentially neutral for that period on the Canadian versus U.S. dollar.

Okay. So are you saying, then, Ron, that for the balance of this year, you're neutral on changes in the U.S.-Canadian dollar exchange rates?

At any time when we're around 50 percent, yes. We don't always just stick with that, but at anytime we're at 50 percent, that's where we are -- it comes out neutral.

Maureen, I just want to clarify one point. The 50 percent is kind of a minimum number. We can hedge up from there. But that's kind of --

But as we do that, we're losing whatever benefit there is on the Canadian dollar side. And we do that, as time goes on and the rates are good, we lock in more and more. But as we do that, we're closing our options.

Okay. I'm not sure I'm completely with you on this, but you -- you're saying you've bought your fuel forward --

In U.S. dollars.

That's about half of your FX exposure?

And we have about half of the U.S. dollars available to us that we need to pay for that fuel.

Okay. And then I'm wondering about the sale from SOEP. Basically, you've back out the gain -- or the profit from this quarter and then that's offset against the loss. So I see there's nothing in there for the quarter and --?

No, it's neutral.

(multiple speakers) Can you tell us what you booked in Q1 and Q2 from your investment in Philips?

My recollection tells make it was 4 point something. But Greg's just looking here. 4 million EBIT.

For 2 million net income.

Two million net income. And was that sort of equal across each quarter? Like one and one?

Yes.

And this is a small point, but in your after-tax calculations for -- in particular for Bangor, it looks like you are using a 40 percent tax rate, which seems a little rich, but is that we should be using for Maine?

We have said the overall consolidated -- the best thing to do is do an overall kind of consolidated tax rate at somewhere between -- somewhere around 35 percent.

Right, which seems to be consistent with your effective rate.

Yes.

Okay, that's great. Thank you very much.

Sam Kanes from Scotia Capital.

Just curious about your coal inventory meaning (ph) you're down to about 79 million of total inventory. What percentage of that would coal? Just get a feeling. And how much lower can you take that or would want to take that from running your operations?

We're just looking up the number.

On the coal side, we're just about at the point where we want to be for inventories at this stage. We're in the process now of improving our transportation networks for coal, and as we do that, then we'll be able to begin to reduce those inventories again. But at this stage, we're at about the level that we want to be at.

What percentage of that 79 million is coal?

Right now, 30 million of it is coal.

30, 79 -- okay. Switching topics, your margin expanded sharply in fuel oil sales versus cost of fuel oil sold. You look like you went to 1.9 million 9 versus 0.9. Is that a new run rate, something special happen there -- just good penetration of market or comparison to other feels? How would you define that?

Really, it's mostly because last year was a poor year in the market generally for that business, and the margins were very tight. The competition was such the margins were very tight.

So strictly competition -- nothing beyond?

Yes. And this year is more normal. This year is like 2001 was, and this year's more like the kind of year we would normally expect in that business. So I think you should look at 2002 as an anomaly. It is slowly growing, but that's not a big factor.

Switching back one last time and how you're going to book -- if you have a discount rate or IRR against the cash steam that you are about to get over three years for your sale? Somehow, that all washes into -- I know it's neutral to book value, but how do you recognize it from a cash out/cash in point of view?

You mean from an accounting point of view?

Yes.

The accounting is done simply on the book values, without any discounting on the cash flow to come later.

Okay, so you --

We're carrying a large receivable for the next few years.

And there is no discounting against that receivable? It's some kind of internal rate of return? It's just raw, sample accounting?

Plain old receivable.

Okay, thank you.

Mr. Winfried Fruehauf from National Bank Financial.

Good afternoon. First a question on revenues versus cash received from customers on the cash-flow statement. I do appreciate there are reasons why the numbers are different, but I'm wondering if you could please reconcile for the third quarter of this year $281 million of revenues versus $305.5 million of cash received from customers in the third quarter?

Generally, I would think that the difference -- first place I'd look would be the swing in Accounts Receivable, but I haven't done the exercise, so I don't know if it work quite like that. Maybe you have, Win.

No, I haven't had that much time, because you're never so generous to give us poor analysts time to think out too many questions. So could we maybe -- ?

That is the immediate thing that comes to mind. The thing in the receivables would always be a difference.

Could we maybe go over that subsequently after this call?

Sure.

Thank you. What is your estimate of lost revenues during the Hurricane in total?

1.2 is what we believe.

1.2 million in lost revenues?

Yes.

And the associated margin is $400,000?

Something like that, yes.

Emera Energy, if I back out of the $5 million of OM&G, the $1.2 million related to SOEP, I get 3.8 million, and that compares with 2.9 million in the quarter last year, which seems to be a large increase, given that you have scaled back your activities in Emera Energy. So what would be the reason for this relatively large increase?

There could be some timing and moving things around. But the services business has expanded over the past year considerably. And that is run rate OM&G type expenses, as they carry out that business.

Are you still spending time and effort and money on Falcon Storage?

Some, but not aggressively. There is not much happening there right now. We're just keeping track of it.

How did you end up negotiating a fixed-price contract at Bangor that expires in February of next year being above market?

Are you talking about the Calpine contract?

There is, I believe there's the Calpine contract, but you're out of the money and you're going to recover that through the stranded cost account. But I'm sort of wondering how you managed to get yourself into that mismatch of cost and revenues in the first place?

That actually was a contract that was negotiated with that supplier prior to our taking over the business. But at that time, energy prices in Maine were quite high. And so the staff at Bangor Hydro at the time negotiated that agreement to mitigate the high cost of electricity. They had that contract then approved by their regulator and included it as part of the standard offer of service that they were providing at the time. And so if that contract is owed (ph) the money, which is right at this moment in time, it gets recovered in the stranded cost.

Would you please provide in total dollars the earnings contributions of Emera Energy and Corporate in the third quarter this year and last year?

In total dollars, the contributions of --

Emera Energy to your net earnings and of Corporate to net earnings.

I think that's what I had in my summary, but are you thinking of something different?

No, I think you only mentioned cents per share. I'm looking at --

I see. You're looking for dollars. Do we have that handy?

Perhaps, Win, I could follow up with you on that.

That's fine. Last item is on a net-net basis, taking financing costs and everything else, including the kitchen sink into account that is associated with SOEP, what would be for 2004 the net-net loss in income contribution?

Very, very small -- minimal.

Less than a penny a share?

Yes.

That's all I had. Thanks very much.

Andrew Cuskey (ph) from UBS.

Just a question on what sort of the strategic retrenchments with the recently announced dispositions -- just curious as we look out over the next few years on a number of initiatives, really where do you see the company headed? Are you just refocusing mainly on your two existing utilities or are we going to see any incremental M&A? And if that's the case, what is your outlook on things like PUCA (ph)?

First of all, we felt in the circumstances that it was appropriate that we move out of our investment with SOEP. It was aggressive from our point of view on a go-forward basis in terms of the opportunities that we want to focus on in the coming years. It does not indicate our lack of interest in infrastructure that might be associated with gas and the development of gas in the offshore. So of course we continue to be interested in our investment in the pipeline.

The reality is, from our point of view, as we continue to follow the energy bill in the United States with great care, there is every prospect that PUCA will be repealed as part of that, but as most of you know, FERC will probably pick up some jurisdiction in respect of M&A activities that would take place on the part of holding companies in the United States, but that a lot of the details that are quite onerous in terms of the SEC oversite will no longer be in existence, so we will see some relief from that, I think.

If I may ask another question just related to your natural gas pipeline business and a bit of an extension on that? There's a number of LNG facilities that have been proposed in Atlantic Canada and also in the Northeast. What is your view on LNG and the viability of some of those facility proposals, and would you want any involvement in that portion of the value chain?

First of all, we wouldn't see any particular involvement in terms of an investment in infrastructure of the facilities. We, of course, are extremely interested in the activities as a source of gas supply to us. It's really very difficult to comment on the viability of these proposals. It may very well be dependent on how far the U.S. East Coast regulators and politicians are prepared to go in terms of allowing some additional construction down there. It's obviously closer to the market. Should there still be some moratorium, if I could use that word, on the construction of facilities there, then I think that, quite frankly, some of the things that are being looked at here in Atlantic Canada may have a future.

That's good. Thank you.

Bob Hastings from Raymond James.

A couple of things. In terms of Hurricane Juan, is there any lingering impacts that we will be seeing in the fourth quarter financially?

I would think not, Bob. We've done our best to estimate the effects. I suppose whatever the estimate is off by will show up, but it shouldn't be much -- we're pretty confident.

Okay, great. And in Nova Scotia Power, their operating maintenance expenses, even excluding the impact from Hurricane Juan, were up about 8 percent year-over-year. I'm just wondering why that kind of increase and what you expect going forward?

Hurricane Juan itself was about a $6 million expense before tax, and so you see that in the expense line.

Sorry. I took that out and it was still an 8 percent increase.

The rest of the items are primarily timing items. We have moved around a fair bit of maintenance on our power production sides this year and there are a number of vegetation management programs on the distribution system that we've changed the timing of. So it's primarily timing.

Thank you. And I looked back to the third quarter of last year and the numbers are the same on the bottom line, but they have been restated a little bit going through some of the lines, such interest cost, etc. Just wondering what reclassifications or why they were done?

Perhaps that's best taken offline. I'll look that up for you.

Thank you. I guess that's fine. Thank you.

If I just might clarify a point from earlier, with reference to the posting on the Web. I think, Karen, if you look you'll find that that's actually -- that the numbers that you were referring to were the Q2 numbers. So indeed, the correct numbers are as Ron -- in terms of the EPS breakdown, are as Ron presented them in his remarks, and that posting is there on our website under the Q3 earnings remarks.

Karen Taylor from BMO Nesbitt Burns.

Judy, I caught that remark and we did notice that it was the Q2, and we haven't -- or I couldn't see the Q3 on the Web, but I'll go back and check again. And my other questions have been answered. Thank you.

(OPERATOR INSTRUCTIONS) Maureen Howe from RBC Capital Markets.

Actually it's Fi Lee (ph) here. I was just wondering about Bangor Hydro. It looks like even after you take into account the FX impact and your adjustment, the one-time adjustment, that the earnings are still down a bit year-over-year. Is there any other factors behind that decrease in the net earnings contribution from Bangor?

There is on an annual basis, year-to-date this year, there is about $1.3 million worth of allocated costs from Corporate overhead that for internal reporting purposes that we've allocate to Bangor Hydro, that had not been there a year ago.

If that reflected just in Q3 or is that also being reflected every quarter this year?

It's been spread almost evenly by quarter.

Okay. And the 1.3 is for the quarter last year -- for this quarter?

1.3 would be year-to-date this year; it would be 400,000 in the quarter.

Thank you.

Matthew Ackman (ph) from CIBC World Markets.

Can you talk about your hedging strategy on coal going forward from 2004?

Yes, I can. At this point in time, 2004 is in very good shape. As I said earlier, only the heavy fuel oil is open at this time. For 2005, we're in the process right now of reworking our transportation infrastructure, and so our expectation at this point is that we're going to be able to move to a broader access, to more of the various coal basins across at least the Atlantic. So we're in the process right now of doing to things -- securing some transportation that would allow us to go a little further afield, and also beginning to discuss with suppliers in those markets for some longer-term supplies. That's active work right now, and we'd expect to be making progress in that early in 2004.

If you felt that you had to go for a rate increase to cover higher coal costs, when would you start working on that?

I think we've already said that we're going to be able to go through 2004 without being in front of the regulators. And until we've done this work relative to what we think the price structure will be and what's available in those broader markets, it's very hard to say whether that's a requirement or not.

Okay, but it sounds like you're working towards maybe some kind of longer-term deals?

Yes, we are, in fact. We didn't want to go very much longer-term with our current transportation infrastructure because we were really limited either to the East Coast of the United States or to Venezuela and Columbia with our current infrastructure. But as we build out some more -- some broader infrastructure, we will be able to go further afield. And so, it's now time to start going that extra step.

How are you bringing the regulator along in that process so that the same thing doesn't happen as last time, where the if coal costs do increase you get squeezed for a period of time?

We have regular discussions with the regulator and we are in the process of keeping them up-to-date on all of these developments. All in all, the expansion of our capacity from a transportation perspective will allow us ultimately to get at lower-cost coal, and so it's an overall move towards being able to give us more flexibility and lower cost. And so we are keeping that information flowing to the regulator and sharing our strategies with them.

Thanks for that. If I can ask for next year on cash flow -- first, you expect to be probably free cash -- significantly free cash positive next year after dividends. Is that a fair statement, Ron?

Yes.

Could you just sort of -- maybe this is a similar question as Andrew was trying to get at. What are your order of priorities strategically in terms of the purpose of that. If you sort of look at acquisitions or dividend increases or debt repayment, can you give us some sense of what your priorities are?

We're certainly still interested in the new business areas that we've talked about as being within our target type of business and geography and so on. But in the absence of good accretive opportunities, it will be debt repayment for the most part. And that is way it will work for the foreseeable future. We have the capacity to do some things if we find the right things to do. If we don't, the balance sheet could always use a lift.

And what about dividends? Is that something you'd look at?

Dividends we will always look at, but we don't see any massive change either way in the dividend payment.

What about on earnings? I don't know -- you're not really in the game of earnings guidance, but do you still look for -- I think at one point you sort of said you could try and do sort of 5 percent type of earnings growth off of a base of whatever comes out this year. Is that a target that you look for still?

That's certainly a desirable place for us to get to in terms of our business model, but we are not there. We haven't demonstrated that. We don't have that kind of inherent growth in the businesses that we have. So that's a place we would like to find -- we'd like to have the Company get to; we have not got there. Some modest earnings growth we can reasonably expect out of the businesses we have. Not on that magnitude.

Okay, thanks. That's all my questions.

Sam Kanes from Scotia Capital.

I'd like to come back to transportation of coal. Transportation rates around the world have gone up to 2, 300 percent for spot market for Panamanic (ph) ships that carry coal. What are the coal contractual arrangements you have vis-a-vis transportation, and have you in fact locked up certain vessels prior to the spike in the freight index?

For 2004, we are in the -- we have our vessels and transportation locked up. As we move into 2005, we're expecting to move into the broader market, and so that again is something that we will be doing in the first quarter of 2004.

On your transportation routes, I'm sure you monitor spot freight rates. How much have they moved up?

At this point, we've -- our contracts actually are renewing at very, very similar rates to the ones we have.

Do you figure because you had the one-year extend option or are you negotiating in the open market for those? (multiple speakers) changed?

I think in large part it's because of the nature of the transportation we're using and the fact there is a very, very tight back haul relationship in the particular market where we are.

I see. That's what I'm coming to, then. So you're picking up back haul rates at all times?

There is virtually a balance flow between the commodity -- gravel and the rock commodities that are leaving the area where we're bringing the coal and the coal that's coming in. So there's a good balance there.

I see. So that's shielding you from other traffic routes?

It's certainly helping.

Thanks.

Winfried Fruehauf from National Bank Financial.

Before I ask the question, I wanted to just add that to the best of my knowledge, at least one -- either national ocean-going line has been fined for collusion and probably more charges outstanding. Obviously, we don't know whether they will lead to convictions, but I wouldn't put too much credence in the run-up in spot freight rates. Question I wanted to ask is, during the Hurricane, did you use the natural gas that you otherwise might have burned and sold it into the export market, or did you have -- make an arrangement that would enable you to recall this gas that you really didn't use, in the fourth quarter, for example? And also, with respect to that Hurricane, would there be a benefit in the fourth quarter and maybe first quarter of next year in the sense that inventories of fuel that you had on hand you didn't use because you didn't generate?

On the first question on natural gas, the Hurricane actually had a very narrow path. So it didn't actually interrupt the supply from Sable. So that gas would have continued to flow right straight through the piece. During the storm, we did lose the generating station for a short time, but we got it back fairly quickly, and so the gas would have basically gone where it normally would have gone.

And what about your coal and maybe coke inventories that were not run down either at all or not to the same degree as without the Hurricane?

No, the actual volumes of reduction in load that we had were fairly small -- fairly dramatic in the first day for a period, but in general, it didn't interrupt any of our deliveries and it also didn't really cause us to change our production very much. A lot of the energy that we would've otherwise consumed internally got generated out into the market, and that would have continued the plants to operate in very similar ways.

So are you saying that your fossil fueled generating stations really kept on generating and you were able to sell some of this electricity outside the province?

Yes, except for a relatively short period of time when we would have lost one station as a result of that, that really was the case. I think the other really important point is that we lost an awful lot of our distribution customers, but all of our industry was almost unaffected. And so some of our largest customers continued to consume just normally. The width of the storm track was in the order of 50 to 75 miles wide, and so it actually had a very, very narrow focus right on this area, in the Halifax regional area, and up through Colchester and Pictou counties.

Thanks very much.

Thank you. There are no further questions. I would like to turn the meeting back over to Ms. Steele.

Thank you.

Thank you very much. Before we sign off, I want to thank all of you for your participation today and your interest in Emera. Perhaps I could leave you with one final thought on the quarter. It's our view that Nova Scotia Power's response to Hurricane Juan was indicated of the strength and expertise of this organization. We prepared and implemented a storm recovery effort which saw 95 percent of our affected customer base return to service within five days. And this was following the most significant devastation to the transmission and distribution system in our Company's history. We mounted this endeavor efficiently, safely and with the strong support and appreciation of our customers. And I'm very proud of all of the efforts of our employees. So with that, I thank you very much for your attendance.

Thank you. At this time, we would like to thank all participants for joining us today. The conference has now come to an end. Thank you for using Bell Conferencing Solutions and have a nice day.