Emera Inc (EMA) 2003 Q4 法說會逐字稿

Good afternoon, ladies and gentlemen, and welcome to Emera year-end results analyst conference call. I would now like to turn the meeting over to Ms. Judy Steele, Director, Investor and External Relations. You may now proceed, Ms. Steele.

Good afternoon, everyone, and thank you for taking part in the call today. Joining me today from Emera are David Mann, President and Chief Executive Officer; Ron Smith, Senior Vice President and Chief Financial Officer; Chris Huskilson, Chief Operating Officer of Emera; a new participant, Ralph Tedesco, Chief Operating Officer of Nova Scotia Power, and Greg Blunden, General Manager of Finance, Nova Scotia Power.

Emera's year-end 2003 earnings release, financial statements, and management's discussion and analysis were distributed earlier today via newswire. These documents are also available on our website at www.Emera.com.

David will begin today's call with a corporate overview. Then Ron will review the year-end financial results, and Chris will look toward 2004. We expect the presentation segment to last about ten minutes, and then we'll take your 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. We promised a return to an acceptable level of profitability in 2003, and I am pleased to report that we have done that. Emera's consolidated earnings increased 45.6 million to 129 million in 2003. This translates into earnings per share of $1.20, compared to 85 cents in 2002 and supported a 2 cents per share increase in the annual dividend for 2004.

In large part, the increase in earnings can be traced to our focus on our core business. Both electric utilities performed well. Nova Scotia Power's earnings rebounded to 112 million, a $26 million increase over last year that was fueled by NSPI's first rate increase since 1996 and a strong natural gas sales, which lowered fuel costs. Bangor Hydro-Electric also produced solid earnings in 2003 despite the impact of a weaker U.S. dollar. Bangor's U.S. dollar earnings actually increased 9 percent to just over $13 million. That represents a regulated rate of return of 11 percent. As you are aware, Bangor operates under a performance-based regulatory regime on the distribution side of its business. In addition to its improved financial results, Bangor also achieved specific targets set out under the ARP (ph) for service reliability and customer service.

We focused on several important projects in 2003, but the one I particularly want to highlight relates to our relationship with our Nova Scotia regulator, the Utility and Review Board. Quite simply, we wanted to make that relationship stronger and more effective, so we began a process of working more closely with our customers and key stakeholders to get broader input on regulatory issues. We improved communications and implemented a stakeholder consultation process in advance of regulatory proceedings. This has also created a more efficient approach to regulatory initiatives.

In 2003, with UARB's support, we have negotiated a settlement of depreciation costs; settled issues with respect to generic rate design and annually adjusted rates; had timely and favorable accounting orders on our tax case, pension and amortization of the Glace Bay plant; and successfully introduced a new rate for industrial customers.

As most of you know, we have had some changes at the executive team level this year, including Chris Huskilson's promotion to Chief Operating Officer of Emera. I also want to take this opportunity to welcome Ralph Tedesco, who came aboard as Chief Operating Officer for Nova Scotia Power in January. Ralph brings 25 years of experience in all aspects of the electricity industry including utility operations, customer service, employee relations, and finance. Most recently, he was the President and Chief Operating Officer of New York State Electric and Gas -- like Emera, an investor-owned utility which serves 1 million electricity and natural gas customers across New York State. We are indeed fortunate to have someone of Ralph's caliber join our senior management team.

Overall, I'm very satisfied with what Emera has been able to achieve in 2003. We improved the bottom line by $46 million. We reduced total OM&G expense by 15 million, or more than 5 percent. We absorbed 10 million more in provincial taxes, 42 million more in income taxes, and a $13 million debt from Hurricane Juan, and paid 133 million in income tax deposits to provide for the Section 21 litigation. And we still managed to generate 20 million of free cash flow after dividends and CapEx, and to pay down 52 million in debt.

On that note, I will turn things over to Ron.

Thank you, David. I presume you've all had a chance to review our earnings release materials, and I will take a few minutes to review the highlights with you.

As David noted earlier, Emera reported consolidated earnings of $129 million in 2003 compared to 84 million for 2002. Earnings per share were $1.20 in 2003 compared to 85 cents in 2002, reflecting higher earnings and the 11 cent dilutive impact of a common share issue in December 2002. Nova Scotia Power contributed $1.04 cents to consolidated earnings and Bangor Hydro contributed 17 cents. All other operations, including our Maritimes & Northeast Pipeline investment, Emera Fuels, Energy Services and corporate business development costs netted out to a loss of 1 cent. That represents a substantial improvement over 2002, and is primarily the result of reduced business development expenditures and increased energy marketing margin.

Consolidated revenues were consistent year over year at approximately 1.23 billion. Nova Scotia Power's electric revenues increased by $26 million, primarily due to the 3 percent electricity price increase in late 2002. Fuel oil revenues increased $18 million reflecting volume growth and higher commodity prices year over year. And other revenues increased $18 million, including an almost $10 million increase in energy marketing margin due to increased natural gas management services. These increases were partially offset by lower revenues at Bangor Hydro, primarily because Bangor is no longer required to provide standard offer service. In addition, the weaker U.S. dollar has a negative impact on the translation of Bangor revenues into Canadian currency.

Consolidated fuel for generation and power purchased was $90 million lower year over year at $363 million in 2003 compared to 453 million in 2002. $58 million of the decrease was in NSPI, where we benefited substantially from our ability to sell our natural gas supply into high-priced markets and burn less-expensive heavy fuel oil instead. Bangor Hydro purchase power cost decreased by $39 million, reflecting the fact that as we noted above, Bangor is no longer required to provide standard offer service.

As David noted, consolidated operating, maintenance, and general expenses were $15 million lower in 2003, at 269 million compared to 284 million in 2002. NSPI's OM&G increased by $10 million year over year, driven by Hurricane-Juan-related operating expenditures of $6 million. This was essentially offset by savings at Bangor Hydro and the positive impact of a weaker U.S. dollar on Bangor's expenses. So the decrease really came from outside of the electric utilities, which I will talk about in more detail in a moment.

Consolidated income taxes increased by $56 million to 61 million in 2003 compared to 5 million in 2002, primarily due to the fact that NSPI is now fully taxable. Prior to 2003, NSPI was able to eliminate corporate income tax by utilizing loss carryforwards and other deductions.

Consolidated cash provided by operations before interest and income taxes was strong, increasing by $118 million to 551 million in 2003 from 433 million in 2002, largely as a result of higher electric margin in Nova Scotia Power.

You will have noted a change in our reporting structure this year. Instead of using earnings before interest and taxes, our and MD&A now provides analysis to the bottom line for each business segment. With Sable gone (ph), and the electric utilities making up 90 percent of Emera, we've also combined Emera Energy, Emera Fuels, our investment in Maritimes & Northeast Pipeline, and our other corporate business development activities into one section called other operations.

2003 other operations incurred a net loss of $1.7 million, compared to a loss of 21.3 million in 2002. The substantial improvement in results was primarily due to a $9.5 million reduction in business development expenditures reflecting a streamlining of that activity, including a 50 percent workforce reduction early in 2003. And also, due to a $12 million increase in energy marketing margin, reflecting increased natural gas management services.

The high natural gas prices in 2003 resulted in a considerable volume of gas shifted in the U.S. utility distribution market by producers and large industrials. Emera provide gas management services, including commodity acquisition and liquidation, transportation, and scheduling to those exporters, and realized good, low-risk margins. Emera also assisted shippers with their existing transportation positions. I also remind you that last year's numbers include $12 million it one-time write-offs related to our coalbed methane project and various other items.

As I noted, the Maritimes & Northeast Pipeline is included in other. In 2003, equity earnings from this investment were up slightly to $9.5 million, largely due to increased volumes as the Yalma (ph) field came into production.

There has been a lot of talk about the Sable project of late, spurred by some downward revisions in reserve estimates. While we no longer have an ownership interest in Sable, we continue to monitor developments as they might impact the Maritimes & Northeast pipeline. Over the next few years, the volume shipped on Maritimes & Northeast are expected to be as originally forecast. As for the longer term, as with any regulated asset, there are provisions in place to ensure it is owners have a reasonable opportunity to realize the regulated rate of return. Certain contractual arrangements between Maritimes and its shippers -- including terms service, backstop agreements -- should largely insulate the pipeline from the impacts of lower throughputs, should that occur. It's also important to note that we fully expect volumes from sources other than Sable to eventually be shipped on the pipeline, including a Janus deed pen new (ph) project as well as a number of others. There are also several possible nonconventional sources of supply, including LNG and compressed natural gas. So all in all, we're perfectly comfortable with the prospects for Maritimes and Northeast.

Now I will turn things over to Chris.

Thank you, Ron. Having managed to restore our earnings in 2003, we're determined to sustain the pattern. In Nova Scotia Power, we expect to earn our allowed rate of return for 2004. We anticipate a traditional 2 to 3 percent growth in our sales revenues. And we are off to a very good start already this year in Q1.

Our largest expense item is fuel. And we have more than 90 percent of the BTUs secured for the year, including some margin on planned natural gas sales. Presumably, we won't have another 100-year event like Hurricane Juan, so that will provide some offset for an impact of higher pension costs.

We expect Bangor Hydro's earnings to be consistent with 2003, generating a return on equity at the midpoint of their earnings band. The paper industry in the state is currently enduring a downturn, and that has a small negative impact on revenues. But we expect Bangor Hydro's continued focus on cost reduction to mitigate any earnings impact.

We have some capital additions planned for 2004. Nova Scotia Power is proposing to install a second 50-megawatt gas-fired combustion turbine at Tufts Cove, our Dartmouth facility, and is currently in the midst of technical conferences with stakeholders on the need for this additional capacity. NSPI also planning to construct a new coal pier (ph) at the Strait of Canso. They will handle larger vessels. This will enable the company to source its coal supply globally, which has both financial and environmental benefits. In Bangor, we have plans to install automated meter-reading technology this year, and to continue to advance our proposed international power line to New Brunswick.

As we continue to pursue opportunities for growth, leveraging the electricity business will be our priority. Our focus is on regulated transmission and distribution, and also on low risk generation. We will continue to manage our business development efforts prudently and wait for the right deal. But when that opportunity presents itself, we will be ready to capitalize.

And now we'd be very pleased to take your questions.

(OPERATOR INSTRUCTIONS) Bob Hastings, Raymond James.

Thanks for the increased disclosure this year. And congratulations on getting out of Sable in time before the write-off.

Just a general question -- on the Nova Scotia Power, you've said that you expect to earn your allowed return there. And when I look through the outlook on the revenues, it's up 2 or 3 percent, fuel costs are flat, OpEx -- anyway, when I go through all of those outlooks and put it together, it would seem to me with the income tax rate where it would be that you'd actually be down over last year. Can you make a comment there?

I think primarily -- a couple of areas. First of all, we do, as you said, see some revenue growth. And secondly, we're also able to manage our fuel cost down a little bit more year over year. And so there -- our average cost for fuel will be little bit less in 2004. And that's pretty much where it's coming from.

Okay, and you have to offset with the increased provincial tax -- and the new tax that's there -- and then depreciation being up as well -- $8 million?

Yes, that is correct.

Okay. And I noticed your income tax overall was down in the fourth quarter. The rate seemed to have dropped down to -- I think it was 24 percent, versus the higher rates, around 36 percent in the previous quarter. Can you give us some sort of color on the tax rate there?

Bob, during the year we do our best to estimate what the tax rate is going to be on the whole for the year as we see the year developing and put that number into the quarter. So we were conservative enough in that to make sure that we did not get a rude surprise in the fourth quarter, and it turned out we were more conservative than we needed to be. So when we worked out the actual numbers based on the final year-end result, we got that -- what would appear to be anomaly in the fourth quarter. So it's just a smoothing (ph) through the year.

Okay, I thought it might be that. But I just wondered, too, if that was sort of a sign that things are looking a little bit better for 2004 on the tax front?

No, you shouldn't expect that. No.

So the average tax rate in 2004 --?

I think what we've said, Bob, is 30 to 35 percent is a reasonable number. It probably gets closer to 35 as we go forward.

Maureen Howe, RBC Capital Markets.

I would like to reiterate Bob's comments that the increase disclosure is much appreciated. Going on to -- back to the equity component -- or back to the ROE at NSPI, I was wondering if you could tell us what the average equity component was for the year at NSPI in terms of a dollar figure, as well as a percentage of rate base, and then what the earned return was during the year as well?

Hi, Maureen -- it's Greg Blunden. It was 38.5 percent of rate base. And our allowed return for regulated purposes was 10.4 percent.

And that was the earned return?

Correct (multiple speakers) -- for regulatory purposes.

Just wondering if we could come back -- and I know, Ron, you made a few comments about the improvement in energy marketing earnings and talked a little bit about the natural gas management services being provided. And I think you mentioned shippers on the pipe. But I'm just wondering if you can tell us a little bit more about who those shippers are? Are they producers? Are they LDCs down in the U.S.? And a little bit more about what type of services are being provided there, and maybe what the outlook might be, I guess, for 2004 for the earnings from energy marketing?

Maureen, this is Chris. Well, I guess first of all, we've dramatically increased our volumes of gas that we've been handling on the pipe. We've gone from a very small number in 2002 up to about 50 Bcfs for 2003. We have also been able to increase the number of counterparties that we've been dealing with. And we're really moving a very large amount of Canadian gas that's on -- most of the Canadian gas is actually being shipped south at this point. So we've been able to increase the number of counterparties to about 50. And so -- we can't get into all of the various names of those counterparties. But it has become quite a good business for us. And it's very much a service-based business.

So just so that I understand -- and help me with us -- you're arranging transportation for these parties on the pipe. Is that essentially what you're doing?

Dealing with the transportation, and also sort of matching up counterparties with suppliers.

Okay, all right. And then the outlook for 2004 -- you'd expect kind of -- the same sort of level of activity and perhaps earnings contribution in 2004?

Well, we think certainly that the activity levels will continue to be fairly high. It is somewhat dependent on what prices actually do. And so there probably is some decline in prices this year. But -- so it may not be as good as last year. But I think it will still be pretty strong.

Okay, and then just one final question -- and this probably really -- I'm sure there is -- an obvious answer to this, so I apologize in advance. But on the financial statements, the segmented amounts -- there's an intercompany revenue item of 105 million, and there is in the other category -- that's under NSPI -- in the other category, there's an intercompany expense of 98.6 (ph). And that's a lot larger amounts than we have seen in other years. And I am just wondering what's driving that?

That is simply gas that -- NSPI gas that was remarketed by energy services. The vast majority of it is that.

So coming back, then, to this gas marketing business. Is a lot of the profit being driven by a remarketing NSPI gas --a lot of the profit there?

No -- some, but not what you would call a lot. They have many other pieces of business.

Matthew Ackman, CIBC World Markets.

Chris, I want to discuss your CapEx plans for the year a little bit. And specifically, I guess, let's start with just the 50 megawatts of generation you're talking about adding. Why are you thinking about adding that this year? Is that to serve Nova Scotia, or for export, or -- what's your thought process there?

Well, in fact, Matthew, we've actually seen quite a strong load (ph) growth this year -- in fact, the last two or three years. The economy in Nova Scotia has been doing very, very well. And so we have seen quite significant growth. And so we believe that it's important that we can continue to serve customers in just as reliable a fashion as we have in the past. And this unit will help us to do that. As well, in off-peak season, then certainly there will be some ability to export this unit.

And just following on that, would you expect to get some kind of rate base treatment for that asset?

Absolutely. At this point in time, we've proposed to the customer base and to the regulators that we would include this in rate base.

And then you talked about some automated meter-reading investments at Bangor. Can you talk about -- or just tell us how much you plan on spending there and how do you get a return on that capital?

In fact, that's quite an exciting project from our perspective. We're in the process of being able to have complete coverage of automated meter reading for that entire service territory. And really, the way that -- first of all, it's about a US$15 million expenditure. And the way that it will return is basically by making it much more efficient to read those meters. So certainly, we'll need less labor to read the meters. And we'll also be able to have a much more accurate understanding of what our customers are doing.

Okay. And if I could, just maybe one question on cash flows -- cash flow from operations for the year was very strong -- kind of comparable to last year, despite depositing 133 million with Revenue Canada. You don't breakout necessarily sort of changes in working capital. Is that a big missing piece in that puzzle? Or maybe you could just clarify that?

Matthew, it is part of that picture, if you like. So that includes most of the changes of working capital. And we did things like reduce inventories, reduce receivables, increase payables. There's some working capital pieces moving in the right direction, as you can see from the balance sheet. So that's part of the picture.

But I mean, that's a big -- 133 million of additional deposit with Revenue Canada, and still 240 million in cash flow from operations. What kind of -- what do you see as sort of a run rate there?

It's hard to look at it on a line-by-line basis. I've said before and would say again -- we expect NSPI to generate free cash flow after CapEx dividends, and we expect Emera to generate free cash flow after CapEx and dividends. And I think it's a testament to that that we actually accomplished those things this year when we had such heavy cash expenditures required. But line-by-line -- I wouldn't try and do that for you, because that would require all of the moving parts of the working capital, which obviously move dynamically through the year, and we can't know now which way they're going to move. We try and manage them as best we can to maximize cash.

Winfried Fruehauf, National Bank Financial.

I did not see a fourth-quarter financial statement. Is that something that you could make available, please?

Sure, Winfried. We didn't make those widely available, but we can post those on our website.

That would be helpful. And I have sort of some questions. The first one is on page 26, we do see a review of other for 2003. And I am just wondering which of the items -- which of the amounts would not recur in 2004?

There is a list of one-time items at the front of the MD&A.

I saw that, but the problem is I don't know, for example, whether is an SOEP processing cost associated with the fees or so --

Yes, let me just go down the list here, Win. The SOEP processing fees will not recur. Most of the depreciation will not recur, because most of that was SOEP. A small amount of the OM&G would relate to SOEP. And that is the only thing that would not recur. Obviously, the numbers will vary with circumstances.

What about the income tax recovery?

Well, that -- if the pattern was the same, and if these were net expenditures, there would still be an income tax recovery. If they were less net expenditures, would result in less income tax recovery. But the reason that's there is because when you add back the Maritimes & Northeast number which is after-tax, it's simply recovery on the various expenditures that are in there.

And the tax rate appears to be reasonably high. Would that mean that the rate of recovery would also be reasonably high?

Yes, when you take out the nontaxable things from this column, you end up with a normal tax rate in the 40 percent range.

Okay. And what would be sort of the run rate for your business development expenses for 2004?

The run rate in terms of staff and the kind of retainer relationships you'd have with advisors that would always be there is in the range of $3 to $4 million now -- so not much. Obviously, money is spent as we look at particular things, although we've become much more careful about that lately. But it's still necessary, obviously, to do that if we're looking at anything in a big way. So it would tend to slide up from that. But no matter -- by any account, it's much more modest in 2002.

Okay. And still on that page 26 -- fuel oil sales of 91.4 million -- if you would be kind enough to turn to page 4, we see fuel oil revenues of 84.5 million. Just wondering what the difference might be?

Win, it's Judy -- there are some intercompany fuel oil sales, so we report the growth number in the MD&A. But on consolidation, $7 million of sales gets eliminated.

Okay. And what is now left to amortize, if anything, at Glace Bay?

That I think is in one of the notes, isn't it? (multiple speakers)

I think it only says about mostly sort of recovered, but I don't know what that means in terms of dollars.

Sorry, Win, we're flipping a page or two here -- 22.5 million as of December 31, 2003.

And over what period and at what rates do you expect to amortize that balance?

That will be over the years to 2008, at most, at 6 million a year, 6.2 million a year, minimum. And depending on circumstances, it could be faster.

Okay. I was a little bit puzzled in trying to reconcile for NSPI the changes in revenues and so on. And I will just tell you what my puzzlement is.

When we look at the increase in total revenues -- and don't trust my math, but it looks like about 3.05 percent year over year -- I see really in terms of revenue per gigawatt-hour a 0.54 percent increase. You did have a 3 percent general rate increase. And I am just wondering why those numbers are not different?

Win, it's Judy. There's a couple of things that you kind of have to work in. We did, you'll remember, in the second quarter have an adjustment to unbilled revenue. That would impact that calculation. I believe there was also a reduction in annually adjusted rates which apply to industrial customers and which tend to be driven by fuel costs. So if fuel costs come down, they come down. So those kinds of things serve to offset the volume growth and the -- and keep in mind, it was an average 3 percent price increase.

I recognize that, but when I sort of express it in terms of revenues per gigawatt-hours, it's only up by about half a percent. And that does seem to be just a little bit odd when you have about a 3.05 percent increase in revenues and a 2.5 percent increase in gigawatt-hour sales. But I guess the answer might be the change in the way you account for revenues.

Yes. There's lower export sales, too, Win, which -- that contains the pricing a little bit, too. (multiple speakers) Is there anything else? Do you agree?

3 percent took effect as well November 1st of last year. On the year-over-year change, it's probably much closer to 2 percent.

That's right. So we have two months of the 3 percent last year.

Okay.

Too heavy months, Ron says. And that's a good point, too.

And I may just have one more if I can find it quickly enough. On your cash flow statement, where you say cash received from customers -- this is on page 6 of the addendum or supplement -- I see there cash received from customers of 1,232,600,000. And on page 4 of the release, there is a number that is 1,231,300,000. The number is reasonably close, but it doesn't quite match it. And in terms of reconciling cash paid to suppliers and employees looking at the consolidated income statement I, have some difficulties in coming up with the 667.1 million that is shown on the cash flow statement.

So the differences in receivables and payables would affect those numbers -- cash flow statement being the amounts actually received in and paid out.

Right, and I recognize that. I'm just wondering if you had reconciliations of these items. And there's also cash paid to noncontrolling interest in the cash flow statement -- 14.2 million. In the income statement, it's 13.2 million. This may, again, be sort of a timing difference or so of where you might have paid something that belonged in a different quarter ahead of time or so?

I suspected that that one, the different has to do with the appropriate accounting for taxes. That's usually a bugbear when you get into that preferred dividend accounting.

So is there any way of reconciling then the cash received from customers and paid to suppliers and employees with the income statement?

Frankly, Win, we haven't provided the breakdown in accounts receivable of all the amounts. And in order to do that, we'd have to do that. If there is a (ph) difference is really change in customer receivable year over year.

Any you have to net out the impact of securitization.

Final question I have is -- what was the end (ph) corporate impact of the change in the exchange rate 2003 over 2002?

In other words, if you had had the 2002 foreign exchange rate, U.S.-Canadian exchange rate for 2003, what would the impact have been on your earnings?

Win, the exchange rate that actually affects our earnings of course would include all of the hedges that we had on before the year even started and through the year. So you'd have to go to the average -- what you mean, I guess, is what's the difference given the average rate that affected our financial statement?

That's correct.

We would have to calculate that. But we could.

Thank you very much, and I would appreciate it if you would.

Andrew Cuskey, UBS Securities.

With respect to your fuel outlook at NSPI, it states in the MD&A that you expect your fuel expenses in 2004 to approximate 2003 levels. Just more specifically on that, to what extent have you locked in natural gas sales from the gas you have for -- (indiscernible) Tufts Cove (ph) into 2004, and what levels have you locked those in at?

Yes, we have collars around our natural gas sales right now out through all of the month. And those range -- they probably have -- in the order of a 75 cent to a dollar kind of range on the collar. And so there's some flexibility, some variability left. But what that's done for us is locked in about 90 percent of the BTU revenue and fuel cost -- effectively, 90 percent of the fuel cost, and from a BTU perspective, is now secured. And the rest of it will float a little bit with those kinds of prices.

So you have about 10 percent floating, and that's -- I thought I heard you say for the month -- or for the year?

That's for the year 2004.

And what's your fuel outlook when you look at -- for all the fuel that you have -- coal, oil, natural gas, for '04 and then also into '05?

From what perspective?

From a pricing perspective -- and then also, if we could just clarify on the hedges?

Well, for 2004, as we said, the price -- the rate will be about the same as we had in 2003. And for '05, it returns -- again, very similar from a costing perspective, to 2003 as well at this point, as we see it. And as far as from a hedging perspective, at this moment we have about 25 percent of the fuel out into '05 hedged. And so we're now at the point where we're starting to work on '05.

Question of a different vein, but relating to CapEx, which was asked earlier on -- to what extent are you looking at renewables within the province in particular because of some of the emissions you have coming off of your coal plants?

Certainly, renewables are an important part of our future. And in fact, today we have about 9 percent of the production in the provinces from renewables, either hydro or biomass or from the wind itself. Right now, we are looking at the possibility of some biomass projects, and also the possibility of some wind projects. We're doing a fair bit of work these days to characterize the wind resource in coastal Nova Scotia. And we'd see ourselves as working through that over the next couple of years to understand just how much it can contribute. We've committed right now to take the output from a project that's just been announced in December of about 30 megawatts of new wind. And we think that over the next year, we probably will be looking for about another 1.5 percent of wind or biomass energy for this period.

Okay. Now if I may just ask one final question, and it's a little bit of a nitpicky one, and it relates back to when the Bangor deal was done -- you did a fairly good job -- a very good job, in fact -- of insulating yourself from any risk around Maine Yankee. And just curious -- if we look at the investments and equity earnings and just the carrying value of and Maine Yankee Atomic Power -- $4 million at this stage. Just what's left in that vehicle at this stage?

Not much. But I don't know if we have it specifically here.

We can probably get that for you off-line, Andrew. It's just --

I know it's not material. I was just curious as to what that was at this stage.

(OPERATOR INSTRUCTIONS) Karen Taylor, BMO Nesbitt Burns.

I thought I was not going to get my questions asked. Just a very quick question about the investment on this gas turbine. Given that there is a prudency test, or an assessment that's scheduled for 2007, I believe, on the Maritimes & Northeast by the producers and so on, and the potential that monies could be held back -- when you're looking at this plant, how are you justifying rolling something like this into your rate base, given that the supply outlook for this facility is so very uncertain?

You're talking about gas supply for our new turbine?

Yes.

Yes, well, first of all the turbines that we're installing are all dual-fueled. They're able to run on either light oil or natural gas. And secondly, we also continue to see gas available in the area. You know, there's probably 3 or 350 million a day of sort of native load now on the Maritimes & Northeast system. And we believe that one way or the other, whether that's through back-haul of gas, or whether that's through more discoveries offshore, or whether that's through LNG coming into the system somewhere, that there will also be gas in that pipe. And so -- the combination of the duel fuel capacity for the facility, and also the fact that there will be gas from one direction or another on the pipe, we believe that those are very good and important environmental investments for the utility.

You're not particularly worried about the recovery of those assets in the long run from repairs?

Certainly, not at all.

Or -- I mean, I assume the UA Aubry (ph) is going to do a very thorough prudency review when they approve it. Is that correct?

Absolutely. And as well, we have traditionally had some combustion turbines on our system. Today, we have about 225 megawatts of light oil fired gas turbines, which are in the process of converting to, again, dual-fire to gas as well. So this is capacity that's very, very good for the electrical system. It's very flexibility, it's very fast. And in the case of the new units that we're adding, it's actually just as efficient as our larger plants. And so it really does work very well as a part of the flexibility that we have in our generation system.

The guidance that you gave for Bangor regarding the fact that you'll earn in the same sort of range as you did this year -- does that take into account that you're not going to get the deferral account requested for the Fort James Operating Company agreement that was just recently disallowed by the board down there? It was (ph) about 3.9 million U.S. in revenue -- or created a revenue deficiency, I guess? So you would have that same outlook, notwithstanding the loss of the deferral account?

You're talking about the Georgia-Pacific rule?

No, it's about -- just trying to find my -- it was a special rate contract between Bangor and the Fort James -- so notwithstanding the fact that you didn't get the deferral accounts, you expect to be able to make that up elsewhere?

Yes, we do.

Okay. The timing of the move from sort of a 35 percent equity that's allowed, or at least factored into your tolls -- you're sitting right now sort of just a sniff I guess below 38 percent. So do you expect to be fully at the 40 per cent actual level in '04?

We will get close to 40 percent in '04 -- probably not over it.

And you assume that -- if I looked at your regulatory calendar in the release, there is no GRA plan for 2005 at this point?

Pardon me?

Do you anticipate filing for General Rate Application for '05?

We're actually, Karen, just in the process of doing our planning for '05. And so there are a lot of -- as you well know, there are a lot of moving parts in our business. And we're working our way through those plans now. And it's really far too early to say where we might go for prices for 2005.

So you just don't know at this point?

It's just too early in the planning stage.

Okay. I wanted to come back and just clarify something that believe you addressed earlier from Maureen on the energy gas marketing services activities. To the extent that you are remarketing gas that's from Nova Scotia Power -- and I am presuming the cost of that gas is a rate base item, or one that's recovered through your cost of service -- that would imply that any profits from those activities would be plowed back into the regulated revenue requirement -- and of course, to reduce the regulator fuel cost. Is that correct?

Karen, the gas contract belongs to NSPI. And there is a very good code of conduct around that. And we follow the processes carefully. The net result of that is that NSPI gets full value for their gas in any transaction that is done with us or with anyone else. It's all carefully monitored and launched. And we're very conscience of it.

So I just want to make sure I understand -- so would the gas marketing services be buying the gas at -- I guess, a value -- which would be based on some fair market test, which is transparent -- and then potentially inventorying that gas and remarketing it later?

No. You're right about the first part -- buying it at a value that's transparent, a fair market value. But our marketing business does not sit on the commodities at all. They basically buy and sell immediately. The only risk we have in that equation is credit risk. And that is a valid risk. We do end up selling commodities to parties for which we have to wait to collect the money until settlement date.

So how do you make money then, other than charging a credit-related fee?

By knowing the market on both sides.

So you're buying from -- I want to understand -- if you're not inventorying the gas, is there any material, temporal difference between when you effectively buy it from NSPI and when you sell it to a third party?

None.

Are you making a bit off your spread on that sale, then?

There would be a modest spread -- I'm not what sure what the term you used means.

Well, it's just that (multiple speakers) paid for it versus what you're selling it for. Otherwise, you know, I don't see how you're making margin.

Some of the source of margin is actually discounted transportation. There is some transportation that is generally available in the U.S. And we are able to, in some cases, field (ph) discount of transportation and a few things like that. So there are a number of different components that allow us to have a bit of a spread in the transaction that we do. NSPI actually does business with three to five counterparties on an ongoing basis. And Emera Energy is only one of those counterparties. And so NSPI is doing that business on a regular basis. And Emera Energy is participating in that as a competitive member.

Right. Okay, and I guess just a very last question -- Judy, I think you mentioned that your effective tax rate again for '04 is between 30 to 35 percent -- closer to 35. Is that correct?

Yes.

Bob Hastings, Raymond James.

Thank you. Just one question on the depreciation on the Bangor Hydro, the study that you're doing -- can you give us maybe a little bit more color on that? And sort of -- I don't know, I know it's early in days, but if there's any (ph) -- have you ever seen (ph) the transmission, distribution -- sort of timing of the study when this will be dealt with?

It's a little early for that. There's no one here that's directly involved in that. It is in process now, and will go through the NPUC (ph) process in due time when it's ready. It's time for a review is the message. There's no fixed time for that right now.

Okay. So this should have no impact on the current fiscal year. It's sort of a --

No, no, no.

Okay. Just maybe a general question -- with all of the rage of income trust, have you given any thought to that, because you're starting to pay taxes? And what do you think?

It's a very interesting concept.

Do you have anything else?

No.

Read the papers. We're watching.

Winfried Fruehauf, National Bank Financial.

Thank you. Regarding the turbine you plan to install at Tufts Cove, is that one of the two turbines whose value you wrote down earlier this year?

Yes.

And what would be the installed carrying cost per megawatt for that turbine following the write down?

I think it's in the order of $700 to $800 a kilowatt -- that kind of neighborhood.

700 to 800?

Yes.

That seems to be a fairly attractive number. I don't see why you would have difficulties getting that into the rate base.

We agree with that. Thank you.

Thank you.

One more, if I may. On Bangor Hydro, what are your plans to -- with respect to what appears to be an inefficient capital structure -- do you expect to let this grow and earn maybe 1 percent or so? Or have you any plans to request either an increase in the common equity ratio? Or what are your plans?

Are you suggesting, Win, that -- the capital structure is quite strong now?

Yes. Too strong.

Yes -- well, arguably. There are -- the one we discussed earlier is one investment opportunity for Bangor, the meter-reading project. And we continue to look at the possibility of additional transmission investment. But we certainly wouldn't see over the medium-term the balance sheet of Bangor becoming much stronger. But it is good and solid now. And we will withdraw cash as it's not required down there. But there's no particular number that we're managing in a micro way around.

I liked what you were saying about withdrawing cash. Thanks very much. That's all I have.

Thank you. I would like to turn the meeting back over to Ms. Steele.

Thank you.

Thank you, everyone, for participating with us today. In closing, let me say that Emera has had a much improved 2003. We focused on our core electricity businesses, controlled costs, streamlined activities and increased cash flows. These improvements supported our 2 cent dividend increase. We recognize that a solid earnings and a secure dividend are vital to our shareholders. And we're pleased to have restored both in 2003.

Thank you very much for your continued interest in the company. Have a good weekend.

Thank you, Ms. Steele. At this time, we would like to thank all participants for joining us today. The conference has now come to an end.