Emera Inc (EMA) 2003 Q2 法說會逐字稿

Good afternoon, ladies and gentlemen. Thank you for standing by. Welcome to the Emera, Incorporated, second-quarter financial results conference call. At this time, all participants are in a listen-only mode. Following the presentation, we will conduct the question-and-answer session. Instructions will be provided at that time for you to cue up for questions. If anyone has any difficulties hearing the conference, please press star followed by zero for operator assistance at any time. I will now turn the conference over to Ms. Judy Steel, director of Investor Relations. Please go ahead.

Good afternoon, everyone, and thank you for participating in our call today. Joining me from Emera are Rod Smith, Senior Vice President and Chief Financial Officer, Chris Huskilson, and David Mann, President and Chief Executive Officer is also on the line from Montreal. Emera's Q2 2003 earnings release financial statements and management discussion and analysis were distributed earlier in the day via news wire. These documents along with these opening remarks are also available on our web site at www.Emera.COM.

Today, David will begin with some corporate highlights, and then Rod will review the second-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 the conference is being widely disseminated via live webcast. And now I'll turn things over to David.

Thank you, Judy, and good afternoon, everyone. My comments today will be brief.

Emera's consolidated net earnings were $15.5 million in the second quarter of 2003, compared to $15.7 million in the second quarter of 2002. Nova Scotia Power's net earnings were $3.3 million lower in the quarter, primarily due to a one-time adjustment to its unbilled revenue accrual. This was substantially offset by lower interest expense and a $1.6 million increase in Bangor Hydro's contribution to second-quarter consolidated net earnings. Ron will speak more about the Q2 financial results in a moment.

As indicated in our release materials, Nova Scotia Power does not expect to file a rate application this year for 2004. That is a change from what we had previously indicated and was made possible by two important developments. First, it appears that natural gas prices will remain strong into 2004. Allow be NSPI to continue to*its gas supply and use net proceeds to reduce fuel costs. We are qualified to deliver a favorable fuel cost last year because at this point NSBki has coal requirements contracted for 2004 along with the full gas sales program.

The company has also hedged the majority of its foreign exchange requirements and a substantial piece of its heavy fuel requirement. The second development relates to the writeoff of the Glace Bay generating station. Our regulator has agreed to extend the writeoff period for Glace Bay from 2004 to 2008 if necessary. That provides us with a lot more flexibility to deal with Glace Bay and still maintain our earnings over the next few years.

I also want to note how pleased I am to have Chris Huskilson in the position of Chief Operating Officer for Emera, Inc., where he will oversee the branches of all of Emera's subsidiaries. Chris started his career with Nova Scotia Power in 1980 and today is a well-respected member of our senior executive team. Those of you who have had the opportunity to meet Chris know of his expert understanding of the electricity industry and business and technical acumen. We believe his knowledge and experience will be of great benefit across the Emera group of companies.

So with that, I'll turn things over to Ron.

Thank you, David.

I presume you've all had a chance to reviewer our earnings release materials -- review our earnings release materials. I plan to speak briefly about the highlights. As David noted, Emera's second-quarter consolidated and earnings -- net earnings were $15.5 million in 2003 compared to $15.7 million in 2002. I remind you that due to the seasonal nature of Emera's electricity business, our second-quarter results traditionally make up less than 15% of annual earnings. To put that in context in the first quarter because it's colder and darker, typically contributes approximately 40% of annual earnings.

Quarterly earnings per share were 14 cents compared to 16 cents in 2002, and that reflects two cents delusion from our common -- dilution from our common equity of last year. The earnings per share breaks down as follows. Nova Scotia Power contributed 12 cents compared 17 cents in 2002. Bangor Hydro contributed four cents compared three last year. Emera Energy's operations including Sable and the maritimes and northeast pipeline investments and Emera fuels and energy services all together contributed four cents compared tw cents in 2002. And we spent six cents on corporate costs similar to last year.

Net earnings and NSBI were lower in 2003 primarily due to the adjustment of the unbilled revenue accrual which David mentioned earlier. Let me take a moment to elaborate on this point. NSPI recognizes electric revenues on the accrual basis which includes an estimate of electricity consumed by customers in each period but billed subsequently. That is quite a complex process that incorporates generations, statistics, forecasts of various sorts, line losses, billing data, weather normal and actual patterns, and so on.

During Q2 2003, the company improved its process for estimating its unbilled revenue with an enhanced look back test that better allocates unbilled revenue among the various customer classes. That review resulted in a one-time $10 million reduction in NSPI's unbilled revenue accrual with a corresponding charge against second-quarter revenues. The after heat wave tax impact of all this is $6.5 million. This adjustment more than offset modest increases in sales volumes, and the impact of a 3% price increase which we implemented late 2002, such that NSPI's Q2 revenues were $4 million lower or 2% lower in 2003 than in 2002.

Fuel for generation and power purchase continues to be a good news story in 2003. These costs decreased approximately $7 million or 9% to $68 million in Q2 2003 compared $75 million in the second quarter of 2002. Production volume increased 1% to meet higher sales. This was more than offset by an approximately $9 million increase quarter over quarter in proceeds from the resale of natural gas, net of the cost of alternative oil-fired generation. Year to date, fuel costs are $19 million or 12% lower compared to the first six months of 2002.

Bangor Hydro continues to provide solid returns in its contribution to consolidated net earnings increased by $2.2 million year over year. Due mostly to lower OM & G expenses. Earnings before taxes were $2 million in 2003 compared a loss of $1.7 million in the same period in 2002. This reflects modest improvements in all segments, and an increase in the net contribution from the Sable Offshore Energy Project resulting from the recognition in the quarter of previously deferred revenues. Consolidated interest expense was $6.6 million lower the second quarter and $9.3 million lower year to date, reflecting the $150 million equity issue late in 2002 and summarying at Bangor Hydro.

Emera's effective tax rate is above 38% for the quarter and above 32% year to date. That is consistent with our stated SGINS of 30% to 35% for 2003 and 2004. It is higher than last year because Nova Scotia Power is now fully taxable having utilized its available tax losses.

I'll just recap the significant one-time rate of the quarter. Our unbilled revenue adjustment was a one-time expense. And the recognition of some previously deferred revenue and so on was a one-time revenue. After tax, these items net to a $4 million one-time reduction in quarterly earnings.

You will have noticed that we've changed the presentation on our statement of cash flow to use the direct method. We think this is an improvement, and we trust that you will find it helpful.

In the second quarter of 2003, consolidated cash provided by operations before interest in income taxes was $122 million compared to $75 million in Q2 2002. Year to date, the figure is $250 million in 2003 compared to $188 million in 2002. The increase was due primarily to three factors. Lower fuel expenses, higher revenues reflecting Nova Scotia Power's 3% price increase in late 2002, and also colder weather, and a $1 million decrease in inventory as stockpiles of local coal were drawn down. The unbilled revenue adjustment I noted earlier had no cash impact. Properly planned equipment expenditures were $27.2 million in Q2, 2003, up substantially from $6.2 million last year. The 2002 number was unusually low, as NSPI was working to conserve cash in 2002 as it worked through rate case. Another reason for the substantial year-over-year difference was the inclusion in 2003 of $15 million invested in Bangor Hydro in the new transmission line.

2003 will be a strong year financially for Emera. As we continue to see the benefit of significant natural gas sales at fiveable prices which help reduce NSPI's fuel costs. Accordingly, we expect NSPI to earn its allowed return and Bangor Hydro to deliver a solid performance. We're managing to keep other costs well controlled and we expect to deliver a strong bottom line for the year as a whole.

That's it for my financial remarks so now we'll open the floor to questions.

Ladies and gentlemen, we will now conduct the question-and-answer session. If you have a question, please press the star followed by the one on your touch-tone phone. You will hear a three-tone prompt acknowledging your request. Your questions will be pulled in the order they are received. If you would like to at the Cline from the process, press star followed by two. Please ensure you lift your handset if you are using a speakerphone before pressing any keys. One moment, please, for your first question. Your first question comes from Sam Caines from Nova Scotia Capital. Please go ahead.

Good afternoon. I noticed you have $300 million of debt to current portion. I'm curious what you're going to do vis-a-vis the -- your U.S. expectations and how your U.S. debt is changing here because I presume some of that is coming due in the U.S., and more broadly, what is your currency sensitivity going forward now that you've done some hedging? What would it be without it?

Sam, the -- we don't worry too much about the balance sheet of Bangor being in U.S. dollars. That's just what it is. It's a U.S. investment. And moves up and down with the currency fluctuations. As does the bottom line. But there is -- substantial short-term debt in both Bangor and NSPI, and in Bangor, we -- in July, we've refinanced a considerable amount of that, see if I can find the right amount. $30 million in July has been refinanced at Bangor over an average 10-year life at 5.3%. That's a change that has occurred.

Okay.

And we -- we expect that in the next while, we will extend some of the term of the debt in NSPI, some of it. On the other hand, there is room in our capital structure for short-term debt. And we certainly won't be eliminating all of it, and obviously the rate advantages are considerable with a normal curve in the market as we have now.

And the currency effect on a one-cent change in the Canadian dollar, is there any effect at this stage?

You mean the bottom-line effect?

Yeah.

Well, really the only bottom-line effect would be that Bangor's U.S. earnings and other things like the pipeline's U.S. earnings would be less valuable with -- with an improving Canadian dollar. But it's -- the difference in the overall context of Emera is not enough to worry ourselves about --

Okay, that part has not been hedged then.

No. We don't hedge that.

Okay. And I guess just to -- step out of the queue for a second, but without -- with one more question. The 38% tax rate in Q2, you gave the same guidance you gave us in Q11. What was the a-- Q1. What was the anomaly and it is that expected to continue in Q2 in future years?

No, there's smaller numbers in Q2 and there are different tax characteristics. It worked out to a big number in the quarter. For a year as a whole it will be in the range.

Nothing pops out then?

Not nothing or changed there.

Okay. Thanks, John.

Sam, it's Judy. I like to always make the point that Nova Scotia Power's fuel costs are largely denominated in U.S. dollars, so the impact of that is far and away greater than the impact in Bangor, and it works the opposite way. So a weaker Canadian dollar will move the opposite in Nova Scotia Power, right?

You're next question comes from Bob Hastings from Raymond James. Please go ahead.

Yes, thank you. Just on the Glace Bay and the change, the extension of the deferralled if for another four years which -- deferral period for another four years which is good news, how much flexibility do you have there? What's the impact in the second half? Do you have to take that amount in the second half so that will weigh on the second-half earnings?

Yeah. Bob, our arrangement now going forward is that we will take a minimum of $6.2 million each year. Previously, we didn't really have any minimum. So we will in the second half of 2003 take at least that. And as always, we would hope to do more faster, and we would hope it doesn't take us that many years to finish this process. We still have flexibility, except we do not have flexibility any longer to depreciate less than $6.2 million. It will be at least that much each year.

And that's all going to hit in the second half for this year?

For this year will hit in the second half. As I said, we think that's managable within the overall picture and will be in satisfactory returns.

Okay, good. Thank you very much.

Your next question comes from Maureen Howell from RBC Capital. Please go ahead.

Thank you very much. Just on the unbilled revenue, can you give me a sense of -- over what period of time the balance had accumulated.

The last time we looked really closely at this whole involved process, it was apparently five years ago. So I guess that's your answer. I -- within the five years, I don't have any idea what was more one year and less in another. But obviously over that five years, we had close to $5 million in revenue. It's not that big.

Okay. And just -- in terms of Bangor, in trying to really understand what's going on with the purchase power there, in your annual report on page 24, you state that with respect to Bangor, the 2003 purchase power costs would approximate 2002 levels, but then the decrease -- then decrease substantially in 2004 because of a contract expiring in February of that year. But -- but they haven't proximated 2002. In fact, they're down sharply.

There's probably two elements there, Chris. I'll start, Chris, might have something to say about this. One of the elements and I think the one that is most obvious to you now between 2002 and 2003 is that early in 2002, the requirement for Bangor to buy power for purposes of the standard offer ceased.

Right.

They aren't doing that anymore.

Right.

And it is there in the first quarter of last year, and that's a big difference.

Was that not anticipate thend when you wrote the annual -- anticipated then when you wrote the annual report?

You quote it and I don't have it to look at. It could be maybe we were talking about one thing and it sounded like another there. That's possible that that happened.

Because in this year's interim, you say -- I mean, I appreciate that the standard offer expired in March, 2002. But I think what you're talking about there is the expiring of a contract to purchase power. And anyways --

Maureen it's Judy. I think one thing that's important to remember is all of the purchase power contracts and essentially the money have been factored into Bangor Hydro's stranded cost recoveries. So -- so there is not really any bottom-line impact to the swings that occur from period to period. Perhaps the easiest thing is for us to try and chat off line about it --

Sure.

In terms of trying to make it work for you.

Sure. That's fine. In terms of the one-time recognition of deferred revenue, you mentioned the net amount, when you net that off against the deferred revenue and I think you said that the after-tax impact is $4 million on earnings. Does that mean that this is a one-time recognition of revenue is $2.5 million after tax?

Yes.

Okay. And then the other thing I was wondering about is the change in the depreciation rate. Is this change that occurred this quarter, is this catchup, or is this a new run rate?

Two changes have occurred. One is as we recognize the revenue, we obviously need to do our best to match expenses to that. So we have also recognized appropriate depreciation to go with the added revenue. Standard, basic bookkeeping on that one.

So that's like a one-time item then, Ron?

It's part of the one time and part of the net that we just talked about. The other thing that we've done is with this little boost, we've carefully looked at our overall expectations of through-put for the assets. Remember the nature this deal is that we get a fee, but we are at risk on volume. So we're always sensitive to that because it's the only thing of business interest to us really. Everything else works smoothly. And we have taken a conservative view of what that expected through-put would be and built it into the numbers. These are not meant to -- meant to say anything about the project as a whole. Other than we're being really conservative.

So I guess you just said it's not meant to say anything about it as a whole. But does it reflect your view perhaps of, you know, lower expected future production of this particular basin and reserve and being cautious in that regard?

We are using a cautious and conservative approach to that question. We obviously do not have as much knowledge as other players in that -- in that question, that whole business.

Okay.

We're going conservative.

Okay. Okay. So, you know could for the quarter then, I think this quarter there's something like or is it $5.6 million in depreciation. Last year same quarter is $1.6 million. How much of that $5.6 is a one-time in your estimation?

Judy's coming up with that.

Okay.

Okay. It anticipate the one-time element is about 1.5.

Okay. So I mean when we look at this net number of $4 million, Ron, should we be adjusting for this $1.5 million? The $4 million is --

You probably should. The way we're accounting for it now, this -- this business is not going to be very profitable for us going forward. It will be profitable, but marginally.

And then the $1.5, is it before tax? Would it be something to closer -- closer to one after tax?

Yes.

Okay. And just if I might on -- on the gas costs and coal costs for next year, you fully hedged them at this point in time. I guess you haven't hedged the FX component of the coal. Maybe --

The majority of it we have.

Have you? Oh could okay. Okay. Can you tell us what those expected expenses are for next year? Little -- the revenues and all that --

Yeah. Fair enough. I've looked at Chris. If he's comfortable he could. Maybe a bit of a reach.

Yeah. The -- I think what I can tell you is that the call prices going forward are slately less than we're paying this year. We've been able to -- to set up contracts for petroleum Coke that also are at a reduction to this year. And what we've been able to do is put a call collar around -- put a collar around the gas sales program that has given us at least the bottom certainty. Certainly there's upside in the gas program. And we would hope that some of that upside would come to pass. It's hard to actually pin down the absolute number. What we can do, though, is say that we're -- we're confident that the minimum number we're going to hit or the maximum number I guess I should say that we're going to hit on the fuel side is going to allow us to earn our regulated rate of return.

So Chris, on the gas side, is it a collar or a floor?

So in the case, it's actually different in each period. But in the winter and in the summer period, it's actually put a collar in place.

Okay.

So we've set a floor up for the -- the later period. So in actual fact, we've got some of each on the go there. The collar is actually quite wide, though. It does give us a fair good bit of opportunity.

Okay. And then finally, probably more relevant, Ron, can respect to comparing to the previous question. You mention that you expect to earn your RE -- your ROE. Can I ask at what equity component are you calculating? The deemed equity component, or are you assuming that you have more equity on your balance sheet and it's a higher than deemed equity component?

We're assuming that NSPI will earn adequately on the equity on its balance sheet. We're assuming that that will continue to grow as it pays out its normal dividends and earnings its normal income.

Okay. Thanks very much.

Okay.

Your next question comes from Karen Taylor from BMO, Nesbin Burnes. Go ahead.

Thank you. Ron, I want to step back and make sure I am getting all of these one-time items right. You've got a $6.5 million charge relating to the revenue recognition from NSPI that I would add back, right?

After tax.

After tax.

Yep.

Then I have a $2.5 million pull-in on the deferred revenues from SOEP could right?

Yep.

Plus, I also have then a $1 million add back on the -- with the one-time depreciation charges. Is that correct?

No, that's in the 2.5.

It's in the 2.5 --

What those -- those two are all there is. No other one-time things.

So the SOEP is the deferred revenue and the depreciation.

Yep.

Okay. So the net, as you said, is then four. Okay. Contribution -- so the NSPI just again on the one-time item, that was a five-year catchup?

Well, all it means is five years ago was the last time we looked at it closely. So --

There's --

There's that much time that went by between the time we developed this way of doing it and the time we now approved it.

Okay. The fuel cost mix, I'm assuming that the oil generation simply offsets all of the gas that was sold.

That's right.

And then you -- in other words, higher production during the quarter of 1.5%, would that have increased your total fuel cost then by $15.5 million? Sorry if you answered this earlier. Then offsetting by the $8.5 million of net reduction in fuel costs due to the higher oil but natural offset with the natural gas sales. Is that right? For a total net gain of $6.6 million?

In the quarter. Yeah. I think the increase in cost is closer to seven than 15, in that order.

So the higher production of 1.5% was then $7 million increase in fuel?

Yeah. The -- the increase in fuel costs from low growth alone would be that increased production was above $7 million.

Okay.

We did have a fairly good hydro run through the period and that helped the situation.

When you see that the natural gas revenues, the natural gas sales net of the oil and purchase power costs reduced costs by $8.5 million to get a net of 6.6, how does that work? Maybe I'm missing something today.

Well, it's probably little more complicated than we can work out right here. Maybe something Judy can talk to you about later.

Okay.

Make it work for you. They've worked through the numbers, and we can find it later. If that's okay.

Okay.

There are always plusses and minuses that occur. For instance, we would account for, say, an efficiency change in the production separately from the low growth itself.

Okay.

Some of it may exist as we -- as we burn more varied source of fuels. Sometime the efficiency changes on the units, and there would be -- it would be accounted for in some of the areas. We could give you more detailed accounting off line.

Okay.

It is -- you've got it right, though. The higher load, a little more hydro, and a little more gas. Those things working in concert.

More gas revenues --

More gas revenues. Pardon me, yes. So I'd be happy to take you through a reconciliation after we finish up.

Okay. I'll give you a shout. Just on the depreciation, what's the target rate that's being discussed right now? A range for '03, '04 be and '05? How much would that range have to shift upwards before you would then have to file a read application for '04? 2004 that is?

What we've actually had conferences now and a think we're in our third round of conferences with stakeholders on this issue. What we've done is put a phase-in plan in place for stakeholders. We're suggesting that depreciation should change around $10 million starting in 2004. And do that at $10 million a year through that period. So that -- that's where we, you know, that's what we've put forward as a proposal right now. With that proposal on the table in actual fact because of sort of natural depreciation growth, I think the number that it would change for the year would be about $14 million.

Year being '04, sorry?

Yeah, for '04, we'd see about $14 million more in depreciation. With that kind of a number on the table, we're able to get through '04 at regulated rates of return. Certainly if it were to double, that would be -- that would be more of a problem for us.

Okay. So '04 versus what you would have otherwise reported in '04, you're talking about an incremental $10 million.

That's correct.

Sorry, an incremental $14 million --

No, an incremental 10. But the depreciation would be growing anyway.

Okay.

Off of newer plant coming into --

So that's in our plans, Karen.

Right. Then in '05 it grows another five in aggregate. Presumably thereafter. You can tolerate all of that before you have to make a read application.

Yeah. Through next year, we're confident of that. As I say, it's in our plans, but it is not yet accepted by the regulator that this study is appropriate. We don't know now what the rates are ultimately going to be or what the phase-in period is going to be.

Okay. I'm sorry if I missed this. I got distracted with something else while you were explaining it. The changes in the royalty agreement, can you quickly explain to me other than the depreciation, is there anything else material in that agreement that has changed?

No, not really. It hasn't been substantially revamped. It just -- it gave us the ability to recognize revenue sort of -- where we spent money really instead of waiting for plaint to come onstream --

Sorry?

We didn't change the cash flow. We were getting money anyway. Previously we had to defer it the way it was written until the asset being built created some revenue for the project. Now we get the revenue by virtue of spending the capital money.

So is that cash revenue, cash revenue or is it like an FUDC?

No that's accounting revenue. And it always was cash revenue, but we were building it up as a liability in deferred revenue. And now we can recognize it as medium revenue.

So you recognized the revenue --

The fee revenue on our asset as we build them before they go into service.

As we have been earning revenues since we took over the assets, we have been deferring a portion of them because of the way the contract was written. The contract has been changed that allowed us to recognize that previously deferred amount.

Okay. The asset imparment, however small, of .3 million of good will, what asset in particular does that relate to? Or project development expenses and so on?

Yeah, that's a small subsidiary --

Sorry?

A small subsidiary by the name of Cablecom?

Cablecom?

Provides services for us --

I'm sorry, I didn't catch that.

Reduction services -- Small construction services company.

So is it totally gone or just been impaired and still operating?

I think that road to good will that was on the balance sheet of that little company off -- the company's still there. It's a tiny little thing. So, you know, you've been pursuing gas storage in northeastern United States and other areas. How are -- what's the total accrued costs to date on project development activities, and --

Remember, as we go now, we write those things off. All we have is --

The historical -- Little leftover stuff. There's -- that we've not yet dealt with. There is the storage project in New York. We still have. We're actively pursuing it. It's in various stages of approval, open seasons, so on.

Uh-huh.

It's on the books now for I think $2.6 million dish

That's right.

And we have two other equity-type investments for a total of three -- $3 million. And that's about it for those kind of things. Sorry, there are also costs which related to the second time Bangor, Bangor costs that were there when we bought it. And they're still on the balance sheet because we anticipate that there's a lot of discussion going on around it right now. Eventually, that second time will be dealt with --

Okay. Thank you very much.

Your next question comes from Matthew Ackerman from CIBC World Markets. Please go ahead.

Thanks. I want to look forward to 2004 and ask first about the tax issue and whether your understanding or thought that you can earn a full regulated return implies also that you'll be earning on the amount that you've deposited with revenue Canada. Because you did set up I think a deferral for regulatory purposes. What you earn on that mandate next year, is that your expectation?

Yes, Matthew. We are clear that that tax that was deferred, not paid in previous years, was of substantial benefit to ratepayers. Now that we've haddy to pay it, it's in our view a regulated asset -- had to pay it, it's in our view a regulatedded asset and we've to pay it. An amount on which we expect to earn.

Thank you for that. Looking forward to '04, then, if you have good visible on earnings, sounds like, you know, you have good visibility probably on cash flows, as well. And if you don't have to make deposits like but with revenue Canada, you know, looks like you're going to be significantly free cash positive. Any strategic directions you could share with us in terms of what you would do if you come out in that position, whether it be acquisitions of a type of nature or dividend increases?

Well, it will be nice to be in that position next year. Hopefully we will be for anything that we can see now. There aren't -- there aren't any changes in the way that we're doing things. We'd like to announce at this point in time. But we certainly will have the luxury in the next little while now that we've got the section 21 thing paid off. To think about that.

How much free cash do you think you would have had this year if you didn't have to make the payment?

Probably this year I guess the range of $50 million to $60 million without that. Next year I think will be better.

Okay. And shifting for a second, can you just inform us whether you have any significant pension issues that might, you know, involve having to make major -- any significant contributions that aren't factored into your plans or anything like that.

They're all in our plans. It's certainly pensions are a major concern to a lot of companies these days, which is why you're asking about it. We expect pension expense and NSPI to roll up into the $20 million-plus range over the next few years. Given regular assumptions going forward. And we now have a bunch more conservative assumptions than we did in the recent past. We're down in the 7.5% return assumption. We were as high as 9.75% in 2001. We will also have to make contributions which will be greater than they've been in the past. Contributions will go up likely around $5 million in each of the next three years to something in the mid 20's ongoing after that. There is a cash implication. And these are significant impacts. Bangor we don't quite have the numbers nailed down. But the trend will be the same direction. And thank goodness these are good cash-positive businesses that we have that we can afford to keep up with all this and still generate free cash, which we can. So it's painful, but it's not in any way crippling or debilitating for us.

Okay. Thanks. That's all I have.

Your next question comes from Winifred Fruhoff from National Bank Financial. Please go ahead.

Good afternoon. Staying with pensions and NSPI, would any increase in pension expenses become part of the regulated cost of service?

Yeah, it would year by year. When, as it is expensive. Then when we get into another rate case, there t will be another major item of scrutiny.

Are you telling me that there's doubt about your ability to be kept whole on that issue?

I would have no doubt about it. It's always just very hard to explain to people that never understand it because it's usually complex. So there's always interveners that want to drill down -- go into the whole thing. But we have appropriate assumptions that are not out of line either positive or negative from business generally. And they're defensible. As you know, pension expense needs to be done the way it needs to be done. So I wouldn't for the moment expect a problem at the end of the day. I would expect a lot of discussion when we get into another rate case.

Okay. Regarding deferred revenues at SOEP, what period does that -- the deferred revenues cover?

Well, it would be the revenues on the new assets we've been building that have not yet gone into service. So it isn't really a period thing. It would be -- will be that amount that applies to the revenues that are not yet -- for the plant that's not yet in service.

When did you start incurring expenses?

Somewhere last year.

Okay. So starting this -- in the third quarter of last year, that's the period when you started deferring revenues?

we have had to defer revenues ever since we've been investing additional funds in that. Since we made the original purchase. The original purchase was back in mid 2001. Whenever the project started to build new assets, which was sometime last year, I think, I don't know when, we had to start deferring the revenues that related to our piece of those new projects.

So --

We got the cash immediately, but we had to defer it in terms of revenue recognition.

Okay. Something like two years or so, two --

Less than that. More like a year plus.

Okay. Okay. And as far as the second quarter is concerned, what must the currency effect on your reported earnings from -- from Bangor Hydro --

Anita, would you like to guess? In the second quarter -- I don't know if the Canadian dollar changed that much in the second quarter. If I recall. Might have been more in the first quarter.

Could we take that off line then maybe?

Yeah, we would have all that.

Okay.

And -- we would have all that.

Okay. And what were the significant items for the increase in corporate expenses in the second quarter?

That's in the catch-all account, Winifred. And I think the biggest change is the result of some moving around, intercompany charges for coal transportation that were kind of paid through Emera last year and are netted in Nova Scotia Power this year. There's not a ramp-up of --

Not a ramp-up of overhead --

If that's what you're concerned about --

Yeah.

I don't want that to be happening now.

No. I was wondering with -- if you were on some business development expense that's nobody knows about --

No. We're going the other way, Win.

Can you please repeat how much more money you would have to spend to -- toward the completion of Gray Hawk.

If it was to go to full development, each property and there are several, four I think. Each one would be a project in the range of $50 million U.S. And we would be -- half players there. So maybe $25 million U.S. projects for us at the moment. The only one being contemplated is the first one.

Right.

And if that worked out well other others would follow.

And a project allotment expenses for Gray Hawk included in corporate? Or are they --

It would be part of the Emera Energy picture as we go, we're writing that off through Emera Energy.

So you're expensing some FCR incurred each quarter?

More or less. We equity account for that basically. It's a share investment. And we -- money goes in and we account for our share of losses. There's obviously no revenue because it's developed. Losses are written off as money spent.

Okay. So one point of being your share of losses directed to Gray Hawk in the second quarteredder and the first quarter of this year?

Judy tells me $500,000 --

This total for the six months?

Is that U.S.?

That's Canadian. And no, I think it's probably that in each quarter, Winifred.

Okay. Thank you very much.

Your next question comes from Andrew Kirsch from U.S. Bunting, Inc.

Good morning. A question on coal outlook. You stated on the hedge for 2004, if we look at some of the unrest we've seen in the coal markets, in particular where you source coal from previously and then just in the U.S., there has been a concern recently just on some Schuster bonds that eastern coal producers do have. How do you see this unfolding and your outlook beyond 2004?

Right now, there are a number of different things going on in coal. Even sure in Nova Scotia. We're looking at potentially having a greater domestic supply occurring as the leases begin to be issued. So one of the things we're looking at is that there's some uncertainty as to how much we're going to have to import. About 1/3 of our solid fuels now are coming for petroleum Coke, as well. And so we've been -- so those factors all come in to say that our volumes for import coal will probably decline a little bit through that period. But as far as that all goes, what we're looking to do now is -- is go out a bit further, and begin to take up a piece of coal in the outperiods over the next little while. And so we're going to start to look at the longer term relationships over some of this impoured coal.

What do you see as an ideal contract as far as in terms of length? Then also from source?

Well, right now, I think we like the three-year kind of time frame. And so we'll be -- we'll be certainly looking to put some together in that kind of time frame. We would continue to source some from the U.S. and some from South America. But we're also currently looking at some of the other basins. And we'll be making some decisions later this year about where we might go with those other basins.

Considering that you're looking at 1/3 of your solid fuels being petroleum Coke, from an emissions standpoint personal responsibility and also in the context -- standpoint and the context that you've had no gas generation in the last quarter, how does that unfold for from an emissions standpoint for SSP Sni

Later in '05 and '06, we will burn more gas. That's something that will come into our mix. And some of that Coke will back out. Some of that will happen.

Just one final question. Environmentally related. Just in terms of mercury emissions, any steps you've taken to really reduce mercury emissions to date? Or are you really waiting until there's further guidance from the federal government on really any rules related to mercury emissions?

Fundamentally right now, we're dealing with mercury by sourcing. We're ensuring that the sources that we use for -- for coal have lower mercury contents. So that's our fundamental step right now. But as you say, right now we're watching where the federal government is going to go, and we'll act when there's some certainty as to where we may have to go.

All right. Great. Thank you.

Ladies and gentlemen, if there are any additional questions at this time, please press the star followed by the one. As a reminder, if you're using a speakerphone, lift the handset before pressing any keys. We have a followup question from win fried Fruhoff from National Bank Financial. Go ahead.

Thank you. Sorry for revisiting deferred revenues. If the deferred revenue started somehow in the second half of 2001, then I would think that a portion thereof has got to pertain to the second quarter, which then would be properly included as operational income in the second quarter of 2003. Do you know what that amount would be including the associated depreciation?

Yes. So in other words we brought in the whole thing at the end of the quarter. Some of it would have belonged in the quarter.

Yes.

Yeah. I hear what you're saying, you're probably right. I don't know if we know. Bear with me. Actually, I think we do know. Maybe we do, Judy said.

Judy is always the last resort. The rock of gibraltar.

Okay. This is -- this is -- I think the answer to your question, Win. Of the revenue element, about $3 million was preJanuary 2003, and about $1.5 million was therefore in each of Q1 and Q2 of '03. So in terms of where our adjustment came --

Yes?

And the -- the depreciation change would kind of be equally split between the first and second quarter of 2003.

Okay. And what would that amount be?

About a half a million dollars or a little more than that in each quarter.

Okay. Okay. So do we then really add back -- we add back if we have taken out the entire deferred revenues and the appropriate depreciation, are we adding back then something like $1.1 million per quarter?

Well --

As being properly included in either the first quarter or second-quarter revenues for 2003? Or earnings I should say.

What -- you'd be closer than you would be without making any adjustment. That sounds like it would be a ballpark reasonable thing to do to get a picture as it would have looked.

Okay. Okay. Okay. So then the $4 million net or so is then a larger number than $4 million.

Not much. But maybe a little because of that quarterly -- that one quarterly effect.

Right. Right. Okay. We'll figure it out. Thanks.

Ms. Steel, we have no further questions -- steel, we have no further questions at this time. Please continue.

Thank you, everybody, for joining in Emera's 2002-2003 conference call today. We appreciate your interest. And encourage you to enjoy the rest of your summer. Thank you.

Ladies and gentlemen, this concludes the conference call for today. Thank you for participating. And please disconnect your lines.