Emera Inc (EMA) 2004 Q3 法說會逐字稿

Good afternoon, ladies and gentlemen. Welcome to the Emera third quarter results conference call. I would now like to turn the meeting over to Ms. Judy Steele, Director Investor and External Relations. Please go ahead Ms. Steele.

Good afternoon everyone and thank you for participating in the call today. Joining me from Emera are Chris Huskilson, President and Chief Executive Officer, Randy Henderson, Senior Vice President and Chief Financial Officer, Ralph Tedesco, Chief Operating Officer of Nova Scotia Power, Jim Connors, Emera's Vice President of Regulatory Affairs, and Greg Blunden, General Manager of Finance for Nova Scotia Power.

Emera's Q3 2004 earnings release financial statements and management's discussion and analysis were distributed earlier in the day via NewsWire. These documents are also available on our website at www.emera.com.

Today we will have Chris begin with a corporate update, then Randy will review the third quarter financial results in more detail. We expect the presentation segment to last about 15 minutes, after which we will be happy to take questions from analysts and investors. Please note that all amounts are in Canadian dollars unless otherwise specified.

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 Chris.

Good afternoon everyone. First let me say what a privilege it is for me to take on Chief Executive responsibilities at Emera. It is an exciting challenge, and I look forward to it. I am grateful to David Mann for his leadership over the past eight years, and for the confidence that both he and the Board of Directors have placed in me as his successor.

It is certainly an exciting time to be working in the energy business. Emera and its employees are ready to take advantage of opportunities presented by this ever-changing industry environment. We are experienced in the production and delivery of energy, and that gives us a valuable perspective on the business, the market and the region. I'm confident that together we will build a Company that a sharply focused on providing customers with reliable, low-cost electricity service, and at the same time providing steady earnings that support wise investments in new business opportunities.

I also know that we can play a leadership role in important decisions that our society must make about our energy future, choices that will insure the best response to demands for low-cost, reliable and clean energy.

I have spent the last 24 years with our Company, and I'm very proud of our achievements. We have a tremendous group of talented people. And we have the potential to strengthen the region's economy through our successes.

Now let me turn to the business at hand. Emera's consolidated net earnings were $22 million in the third quarter of 2004 compared to 11.5 million for the same period last year. Quarterly earnings per share were 20 cents compared to 11 cents in 2003. Just over half the earnings improvement is due to two non-recurring charges recorded last year, a $4 million after-tax charge for restoration and repair costs of hurricane Juan, and an approximately $2 million after-tax charge to reduce unbilled revenue at Bangor Hydro. In addition, we realized a $2 million after-tax reduction in interest expense, and remain focused on controlling operating, maintenance and general expenses.

Randy will take you through the details of the financial results shortly, but first I want to update you on the single most important initiative underway at Emera, that is Nova Scotia Power's 2005 rate application. The Nova Scotia Utility and Review Board rate hearing will begin on November 15.

This is the culmination of a process that began May the 28th with the filing our application. Since that time Nova Scotia Power has engaged its stakeholders and participated in information sharing that is unprecedented in Nova Scotia. It has been a positive process that we hope will lead to a productive outcome for all sides.

We have hosted four all day technical conferences, one on the overall application, as well as others on tax, fuel and financial elements. And we have replied to more than 1,000 written questions.

We understand electricity rate increases are never popular. Customers expect utilities to do everything reasonable to keep electricity prices low. And we are proud of Nova Scotia Power's record on this point. Over the past decade we have managed to keep electricity price increases in Nova Scotia well below the rate of inflation, bringing our rates in line with our neighbors and keeping them significantly below rates in the northeast U.S.

Since the last time rates were set in 2002, Nova Scotia Power has done an outstanding job of controlling its costs. NSPI's operating, maintenance and general expenses in 2005 will be below what they were in 2002. The exception is pension costs, which as you know, are affected by interest rates, the performance of the capital markets, and demographics. We are also proud of the job we have done in managing fuel expense. In 2003 and 2004 our effective fuel cost management let us absorb a total of 140 million in new taxes without seeking rates to cover those.

I want to also highlight that the fuel budget included in our 2005 rate application is the same as it was in 2002, once you just for sales increases. That is quite a feat when you consider that coal prices are even higher than they were back then, and that we're incurring $20 million in costs to meet our higher environmental standards.

The stronger Canadian dollar has helped, but we have also been very aggressive about incorporating lower priced petroleum coke into our fuel mix and improving our ability to access rural (ph) coal and manage freight costs with our new coal handling terminal, and also improving utilization at our lower cost thermal facilities.

In fact, our point Point Tupper and Lenganjeren (ph) facilities have been ranked number one and number two in the country in terms of thermal operating performance by the Canadian Electricity Association. We also hired the most highly regarded fuel expert, and in fact our harshest critic from the 2002 rate hearing, to work with us to strengthen our fuel procurement and related processes over the past two years.

This application is about an expenditure that we don't control, mainly taxes. Our taxes have tripled since the last time rates were set in 2002. It is a step change in our cost structure. Intervenors have advanced their propositions against our proposal. There may be days when the rhetoric is hot, but there is no denying the fact that the taxes have substantially increased and are not reflected in rates.

We've also asked -- been asked to implement a fuel adjustment mechanism which is common in utilities from across North America. The hearing will be challenging, but I'm confident that our regulator will properly balance the interest of our customers and our investors. And I believe our request is completely justified. Ralph Tedesco and I will be on the stand in day one to make that case.

With that I will turn things over to Randy for the rest of the third quarter update.

First of all, let me say it is a pleasure for me to take on the CFO responsibilities at Emera, and to participate in my first earnings call for the Company. I am looking forward to some good discussion today.

As Judy mentioned, our results were released earlier today and are on the Emera Website. I will take a few minutes now to review them with you. Emera's consolidated net earnings were $22.1 million in the third quarter of 2004, compared to 11.5 million for the same period in 2003. As Chris noted, much of the increase is due to the fact that the 2003 comparative earnings were low. That's because we had $4 million of costs and after-tax for restoration and repair associated with hurricane Juan, and a $1.9 million after-tax reduction to unbilled revenue in Bangor Hydro.

Consolidated earnings for the first nine months of 2004 were $98.4 million compared to $81.7 million for the same period in 2003, primarily for the reasons I just noted, plus the $6.5 million after-tax reduction in unbilled revenue that NSPI recorded in the second quarter of 2003. Quarterly earnings per share were 20 cents compared to 11 cents in 2003.

Nova Scotia Power's contribution to consolidated net earnings was $19 million in the third quarter of 2004 compared to $12 million for the same period in 2003. The hurricane Juan costs recorded last year were a key factor in the improvement quarter over quarter. We've also been focused on controlling OM&G costs, but please recognize the timing of expenditures can easily move $1 million between quarters.

In addition, after-tax interest expense was $1.5 million lower quarter over quarter, reflecting savings from refinancing of long-term debt in the fourth quarter of 2003, and the redemption of a $140 million midterm note in Q1 of this year with cash flow and short-term debt. All of these positive events were somewhat offset by increased depreciation and increased provincial grants in lieu of taxes.

Turning now to Bangor Hydro, our U.S. subsidiary's contribution to consolidated net earnings was $4.8 million in the third quarter of 2004 compared to $3.2 million for the same period in 2003. As we noted earlier, this is mostly due to the $1.9 million after-tax reduction in unbilled revenue in 2003. A stronger Canadian dollar reduced earnings by approximately $300,000 in the quarter.

Now as you may be aware, Bangor Hydro is in the midst of stranded cost rate application. This is required every three years to true up the stranded cost amortizations for under and over recoveries that occur primarily because sales claims and the cost of the out of the money power purchase contracts are never quite exactly as predicted.

The Company's filing proposes a 30 percent reduction in the average annual revenue requirement for the 2005 to 2008 term. This would be largely offset by a reduction in the regulatory amortization of amortization of a large out of the money power purchase contract is now complete. Bangor Hydro filed its evidence on September 30. Technical conferences are being held throughout the fall, with hearing dates set for mid-January, if necessary. New rates would be effective March 1, 2005.

Emera's other operations, which include businesses outside of our regulated electric utilities and our corporate costs, recorded a $2 million improvement quarter over quarter. An increase in energy marketing margin and savings interest expense offset the elimination of offshore gas infrastructure revenue due to the sale of our Sable investment late last year.

Equity earnings from our investment in the Maritimes & Northeast Pipeline were lower quarter over quarter. And that is primarily because the cost related to phase 3 are not yet in rates. Maritimes & Northeast Pipeline in in the midst of a regulatory application to address this, and we look forward to a timely resolution of that.

I want to highlight today that we expected earnings to be strong through the third quarter. This is important because we knew there would be an upward pressure on fuel costs in the last three months of the year. Specifically, the opportunity to earn margins on natural gas sales has been reduced as a result of changes to the pricing structure in the supply contract effective November 1.

In addition, we have been advised by a coal supplier that we will not be receiving contracted quantities of low sulfur coal scheduled for the fourth quarter of this year. As a result, we are forced to purchase replacement supply at higher markets prices. As you all know, NSPI must source its fuel on the world market and is subject to risks and changing commodity prices and supply constraints.

We work hard to manage this risk through a rigorous fuel procurement strategy and utilization of hedging instruments. So let me assure you we're pursuing all options, including legal action to remedy this situation, but in the meantime we need to have the replacement fuel to meet production requirements. We expect that these items, plus the normal upward pressure on fuel costs as higher commodity prices start to phase in, will offset the earnings gains made to the end of the third quarter. Accordingly, we expect full year earnings to approximate 2003 levels, with NSPI earning within it allowed rate of return, stable contributions continuing from Bangor Hydro, and ongoing good cost performance across the organization.

Cash flow continues to be strong. Consolidated net cash provided by operating activities was $94 million in the third quarter of 2004 compared to $115 million for the same period in 2003. This reflects lower cash received from customers due to timing of bills and higher income tax payments.

That's it for my financial review. Thank you very much. And now we will be happy to take your questions.

(OPERATOR INSTRUCTIONS). Linda Ezerdalis (ph) from TD Newcrest.

A follow-up question with respect to your effective earnings guidance for 2004. When you say that earnings will approximate 2003 levels, is that reported earnings or are you normalizing for hurricane costs or anything like that?

Those would be reported earnings.

And just another quick question. With respect to your defaulted contract in Q4, was that a long-term contract that might impact 2005, or was that just a short-term three-month contract?

Ralph Tedesco. That contract would have some spill over in 2005.

So then does this mean that all of the actions that you're considering, whether it be legal, are you considering some sort of regulatory relief and/or refiling of your 2005 rate case? And if that is the case, then is there risk of your schedule being pushed back in terms of getting a timely decision?

The short answer is no. At present we simply consider this a dispute with a vendor, and we would expect to recover most -- a significant portion of those costs regardless. We are standing behind our filing as filed.

And then is the vendor of credit quality? Can you elaborate as to why they defaulted? Was it an operational disruption? Is it a bankruptcy situation, which I wouldn't imagine given the high coal prices out there, but can you maybe elaborate as to why they defaulted?

I can't elaborate, but recognizing that we had instituted legal action I prefer to stay away from specifics, other than to say I think most folks were aware of the change in market prices that has occurred over the last several months. They're quite different than the price that we had entered into this contract at.

Final, final question on this whole coal situation. Can you give an indication as to what percentage of your fuel requirements this particular contract was for in Q4?

(technical difficulty).

Sorry, I have a little blip there. You have to say again, Ralph.

Sorry, I would estimate that this contract and the change in price would be something on the order of 1.5 percent in '04.

I'm sorry. A percent and a half --?

Of our fuel budget.

Of your fuel budget in '04 and '05?

Yes, -- yes a similar amount.

Sam Caines from Scotia Capital.

(technical difficulty) a little further on the 20 million. Is that pretax or after-tax what you're looking at a higher fuel costs in Q4, first of all?

That would be pretax.

Then of that 20 million pretax you inferred, as we work through your fuel budget, 1.5 percent disposed here on this defaulted contract, which hopefully you will get back next year in your earnings. Would the rest then -- if by implication be the difference in gas costs?

Yes, it is -- it is a couple of things. It is certainly both gas margins and volumes have affected as well as increased load.

In that case your volume changed. Can you give us guidance? I know you won't do that on priced, but on volumes, can you give us guidance on that -- on how that has changed?

I would say about $5 million.

Okay. In total. I will leave it at that. Shifting, Bangor Hydro, their demand was extremely strong across all asset classes '04 versus '03, residential, commercial and industrial. Is there something extraordinary going on in that market? What has changed year-over-year? Your sales volume was up 8 percent.

It is Greg Blunden calling -- or speaking. There has been -- what we are experiencing in Bangor is really strong growth in those residential areas. It is not one -- it is both residential and commercial. It doesn't appear to be one specific thing. But we have seen, for example, a lot of new big-box stores open up in our territory. We have seen some growth along the coastal parts of our territory. And then keeping in mind from year-over-year comparison, we also have the unbilled revenue adjustments in 2003, which is driving part of the change.

But that is revenue adjustment. Technically that was volume adjustments as well, right?

Right.

So it's a combination of things. So if you had to guess an organic number, I guess we can go back and it work out. Would it be more like 2 or 3 percent?

I think in those particular classes that would be appropriate.

Last thing for me. One of the power -- coal-based power companies in Canada has an extraordinary major overhaul program going on with their particular coal assets in Alberta. I've never seen you mention those over the years. I presume it is because you attempt to accrue, or stepping back a little bit maybe it is for you Judy and Randy. Do you accrue into your major overhauls? Because surely you have the same type of issues every ten years on your boilers and turbines and what have you in your major overhauls of your coal-fired plants. How do you account for yours?

Basically the maintenance -- any maintenance or capital on the coal-fired power plants are occurring in the year that they are incurred. And what I would suggest is, as Chris mentioned in his remarks, the performance of our thermal facilities has been outstanding where we have got three of our units recognized in the top 10 in Canada.

I heard that loud and clear. Congratulations. Just curious as to when their next pit stops are if you make going forward?

We have some outages scheduled for next year at our Tesco (ph) Trenton and Point Tupper facilities.

And are there any -- other than the ordinary normal course of business, are there any environmental extension requirements, delays for specific equipment for pollution reduction, or just simple normal course (multiple speakers)?

In terms of pollution reduction, as was mentioned in the remarks, our rate filing for 2005 reflects $22 million in lower sulfur fuels to comply with new sulfur dioxide standards. As well we have approximately $20 million in capital that we will be investing at our Trenton facility to curtail fly ash omissions there.

Karen Taylor with BMO Nesbitt Burns.

Just a couple of questions on the mark-to-market in the quarter. Back in the notes to the ND&A that was 4.5 million. Was that pretax?

Yes.

Can you confirm where all of those gains are? Earlier in the press release or in another part of the note it said that 1.1 million after-tax, or 1.7 million pretax, appeared to be related to NSPI's generation. Where's the other 2.8 million in pretax gain? Is it all in NSPI?

I can answer, yes, the entire 3.3 million is all in NSPI.

So 3.3 million is the after-tax?

In the note -- in the ND&A the 3.3 million is all NSPI, and that is a pretax number.

But then the gains during the quarter is 4.5, right?

Sorry, 4.5 in the quarter, yes, you are correct, sorry.

So it is 4.5 --.

My apologies, yes, 4.5 in the quarter.

And it is all NSPI. Is it all in fuel costs?

Yes.

The hedging impact that you put in the notes, I'm sorry, it is very small, it is less than 1 million. I think it is less than half a million. Is that simply the net effect of the hedging arrangements in place? So that would be in your financial and commodity instruments on page 15? And is the hedging impact recognized in earnings? Is that the positive affect on earnings of .4 million realized in Q3? So what I interpret that to say that absent these hedges the overall performance in Q3 would have been lower by roughly half a million?

Sorry, Karen, which --?

On page 15 of the Management Discussion and Analysis.

We are -- required accounting from the CICA to breakout when we settle any of our hedges the difference between what is the value at that point in time and the value of the contract. So in effect if you have an in the money contract because you hedged your FX father out, this is just the delta between that on either an interest rate swap or a FX contract. And so it all flows through those particular line items on the income statement.

And where's that in interest expense?

The 1.2 would be in interest expense.

And the other is in fuel.

Fuel. As is identified there, yes.

And then that 1.6 goes back to the 4.5? Or is it separate and total from that?

That would be separate and total -- separate from that.

Okay.

But the 1.6 would actually have been realized as opposed to the 4.56, which is unrealized mark-to-market.

Right. I wanted to make sure. The negative foreign exchange effect on Bangor, in the release it says, or at least it implies, that it is significantly larger than what I think you stated -- somebody stated in the remarks of it being 300,000 after-tax? First of all, is it 300,000 after-tax or before tax?

The 300,000 would be after-tax.

In the notes, the discussion, it talks about on page 8, and it seems to imply that the foreign exchange effect during the quarter was larger. Let me ask you since it is 300,000 for the quarter, what is it year-to-date?

Year-to-date I believe it is 1.7 million.

Okay.

We can confirm that off line.

Is that after-tax or pretax?

That would be after-tax. That would be taking the U.S. dollar earnings as a differential, the after-tax strength of the foreign exchange differential rate.

That's fine. And can you just talk to me about part of the hearing on the stranded assets, one of the things that Bangor did not want have to have happen was to have them review the equity cost of capital implied in all of that revenue requirement. Can you give me some sense for -- and if you -- and I guess the staff said, well they get to consider this item? Can you give me some idea about the earnings sensitivity at Bangor to a 100 basis points change in the allowed ROE as it relates to the stranded assets in Canadian dollars?

Yes, it is Chris. It is about $1 million, in that neighborhood. And the reason that we thought that that shouldn't be opened up is because it was settled in what was called the Mega Case in Maine. And we expected that that Mega Case would cause -- would last through this time frame.

So just to make sure I understand, for a 100 basis point change in the ROE supporting the equity portion of the stranded assets, it is about $1 million in earnings per annum at Bangor?

That's about the impact.

Canadian?

Yes.

After-tax?

All of those things.

Bob Hastings (ph) from Canacord (ph).

Good results. One of the questions I guess I have is, if I can go back to the fuel supplier question just to clarify something. I think you said you have instituted legal action?

Yes, we have.

So isn't it public then?

The outcome is not decided. That's all I was referring to.

Okay. Now, but I just wondered if something is filed (multiple speakers) --?

No, of course, no, the legal action itself is yes public. I was just -- I didn't want to get into debating the merits of the case.

So who was it instituted against?

I'm sorry?

Who have you instituted legal action against?

The supplier is AMCI.

AMCI? It is located out of where? Where's the legal action?

The legal action that we have undertaken is here in Nova Scotia.

Okay. And can you say where -- how far you are in that legal action? You haven't had a hearing or anything?

No, papers have been exchanged. And I think we are on the precipice of discovery.

Okay. Thank you. And they are not technically bankrupt, or they haven't filed for bankruptcy?

No.

Okay. I won't go any further there then thank you. OpEx at -- the operating expense at Nova Scotia Power was very impressive in the quarter. If you adjusted last year's number for hurricane Juan even then your expenses were still down something like 11 percent year-over-year in the third quarter, which is phenomenal. But there wasn't really an explanation if there is major items in that to achieve such a good reduction. Basically it is a $5.3 million reduction. So can you maybe give us a little bit more clarity on how you are able to get such a great performance?

Some of it again year-over-year is the difference with the hurricane costs being reflected and not reflected. There's also a little bit in there that is reflecting timing of certain O&M expenditures of contracts that we had hoped to let (ph) that have not yet been let, but probably would be in the fourth quarter.

Okay, but I stripped out the hurricane Juan in my numbers and the expenses were still down 5.3 million. So is the rest of it is all timing and contracts?

I think for sure as Chris mentioned in his remarks, we continue to be pretty sharply focused on our O&M, OM&G expense. And I think some of that is reflective of that. But again I would also suggest timing is a good amount as well.

Okay, I mean I clearly it is an impressive performance. I was just trying to get some better breakdown on it. Thank you.

Winfried Fruehauf from National Bank Financial.

My questions are on the other. First regarding Maritimes & Northeast, what is the amount of expenses both pretax and post-tax that you have to be allowed to recover in the rate case?

Give it a minute there, Win.

The filing is for a proposed increase in approximately $31 million in revenue requirements. It is Randy here.

Okay. And what does that translate into earnings on an after-tax basis?

I am just trying to do some number crunching here. What it represents at the Maritimes Northeast level is a 14.25 percent ROE on about a 43.5 percent equity base. And I don't know if we have the detailed calculation on what he asked us for.

We would anticipate if the entire rate was approved that it could be upwards of a $2 million incremental earning for our share of the pipeline.

Per year?

Per year, yes.

Okay. And regarding Maritimes & Northeast one is reading all kinds of wonderful things about LNG and so on. Has your Company started to back any of the two leading proposals, the one in New Brunswick and the other one in Nova Scotia?

It is Chris. I think the best way to put that would be to say that we are working with the performance of LNG on the pipeline -- anywhere along the pipeline. From our perspective we would like to see an LNG proposal come to fruition somewhere along the Maritimes & Northeast Pipeline.

And it mis a little bit too early to tell exactly which one of those components is going to be successful, and so we continue to negotiate with all of them. We see ourselves as having a gas need. And so we do see ourselves as a potential base customer for one of those stations. And we also see the need to have one of those stations actually come into the system. So we're supportive of getting LNG in the system, and that is where we are right now.

I hope there is no doubt that either or both projects if they proceed will be using Maritimes & Northeast rather a greenfield pipeline?

I think that is a pretty good bet. Certainly there will be opportunity -- there is capacity available for sure, and there's relatively low-cost expansion capacity as well.

Which one of the two proposals, the one in Nova Scotia, the one in New Brunswick, what is the time frame for either one?

I think both proponents would see them coming on stream somewhere between 2007 and 2010, just depending on the overall time frame for securing contracts and customers and getting all those things pull together. That is the time frame.

Regarding business development expenses can you maybe describe the nature of business developments that you are pursuing? And also what sort of a quarterly or annual run rate might be?

It is Randy here. We are exploring obviously low to moderate risk opportunities across the spectrum that we're involved in generation and NT&B (ph) and in the Northeast. And we probably going forward would see a run rate of 1 to $1.5 million per quarter for business development costs.

And if these investments came to fruition, would you -- would they represent a partnership interest on your part?

Every investment is different and you always look to find the optimal structure for your partner, for your tax situation and so on. So it is pretty hard to say when in a general sense.

And regarding energy marketing margins, you mentioned that the prospects for future margins would be reduced relative to the past because of the newly negotiated gas supply contract. Can you give us any guidance and as to what a quarterly run rate might be?

At this point we are -- we have through the end of November to agree on a price, and we're still working on that. But I will say that we have reflected what we think to be a reasonable number in our 2005 rate filing.

Can you refresh my memory please as to what that number is?

As far as the specific on the gas contract, no, again because we're negotiating, but the overall fuel ask in the 2005 rate filing is $377 million.

Now isn't it a little bit one-sided to on the one hand point at the likelihood or certainty of having to pay more for gas without also acknowledging that perhaps those higher costs might be offset, if not more than offset, by favorable pricing in the market?

If we look at what we're currently paying in that contract, it is -- it would be very, very difficult to make up the kind of margin that we're currently enjoying.

But you have some pretty nifty people engaged in marketing. Are you saying that they are expected to be incapable of finding lucrative high-priced markets that would more than offset the increase in the cost of gas?

I agree with you. They are very, very good at what they do. But they cannot invent market pricing nor increase gas volumes.

No, but there are different approaches to markets. There's a variety of markets you can sell into, spot, fixed, one year, two year or whatever. So out of all these options are you still saying that you expect to simply earn lower marketing margins going forward?

In the regulated business, that is exactly what we're expecting, because the component of the contract that sets gas pricing right now is very low in comparison to what we would expect it to be reset.

Maureen Howe from RBC Capital Markets.

Most of my questions have been answered, but not to beat a dead horse, but just coming back to this gas contract. You did mention that you're still in negotiations. What would be your negotiating power here? It seems to me gas is a pretty marketable commodity. What is the give and take?

In this particular contract there is an amount set as well as there is an arbitration clause in the contract that has an upper limit on it. And so somewhere between the market price and that limit is what we're trying to figure out.

Okay, but getting back to what is your negotiating power, I guess going into arbitration is your negotiating power? Is that right?

That's right. That certainly part of it. And there are other aspects of the contract and performance under the contract that is part of our thinking as well.

And you mentioned earlier that there is a volume impact associated with the contract. And I'm wondering if you can help me with that? And maybe I have just forgotten, I thought that the original contract was for approximately 60 million cubic feet a day. And does that drop off on November 1?

I would not necessarily say it will drop off a November 1, but I think you are familiar with the fact that the Snowy (ph) field production numbers have been declining.

Right.

And as a result of that, we have been experiencing some cuts in gas volumes.

And so your contractual arrangement is tied to production?

No.

So why would it be falling off then?

Because under the contract there is a right to substitute fuels under the contract, and that is occurring. And while we are receiving BTUs the value is different.

Okay, so you're getting liquids instead of methane?

Yes, in some instances. That's right.

And can you tell us how much of the volume is subject to substitution?

From our perspective, one of the things that we're talking about is we don't think any of the volume should be subject to cuts. And without getting into negotiating details, but anything that is reduced is subject to substitution under the -- by the terms of the contract.

In BTUs?

Essentially correct, yes.

But that is a point of contention between you and the supplier?

Yes.

Then just I'm wondering if we can get an update on the transmission project, if anything has happened since August?

I'm sorry could you repeat that please?

Give an update on the transmission line in Bangor, if there has been any further movement in moving that project forward since the approval that was received in August? I think it was August.

I think the most recent update would be that we have now filed our route announcement. And we have put forward -- and begun the process of going into environmental approval. We expect that process to take between 10 and 15 months just depending on what kind of things that we encounter as we go along. But that is really where we are right now.

And is there any -- have you got any preliminary indications, any push back, any idea of support from communities or lack thereof?

The stakeholder process that we have been working since the beginning of this project has been pretty active across all of the stakeholder group. And we have had I would say very good support from most of the stakeholder groups. And in fact even the environmental groups seem to be quite comfortable with the way we're proceeding. And we'll see as we keep going here.

And so in light of that then are you still looking for a 2007 in-service date?

That is still our target. And we think that that is achievable.

Matthew Ackerman from CIBC World Markets.

I wanted to ask a question or two about your fuel budget for next year. I think you said it was filed for maybe just over $300 million. And that was in I guess May of this year, and clearly energy commodity prices have lifted considerably since then. And there is also this contract dispute I guess on the coal side. So can you just remind us, or less know of how much of your fuel you have hedged for next year? And how you are tracking I guess relative to the budget you filed in the rate case?

We filed for $377 million in the rate case. About 80 percent of our coal is hedged, about 90 percent of our petroleum coke, about 85 percent of our heavy fuel oil, and about 85 percent of our transportation it hedged in '05 and, about 60 percent of gas. So at least at this point we feel pretty good. We have also we have something called annually adjustable rates, and we have recently filed with regard to those a budget equivalent to $393 million. And the other thing I would remind you is we have also filed in 2005 for a fuel adjustment mechanism.

And are you seeing any issues on transportation contracts from the coal suppliers?

At this point no. And the other thing that we have done in that regard is made investment in the international coke (indiscernible) that we think will provide us advantageous pricing from both the transportation perspective as well as access to new markets.

But that won't be effective in 2005, will it?

Yes, it will.

When do you expect to have that in service now?

We're expecting it will begin to be able to take deliveries probably sometime late the first quarter, early second quarter.

And is some of your hedging from suppliers that will use that platform?

I'm sorry?

So you are actually going to have -- you have contracts in place to use that platform in '05 then?

We have some contracts in place, yes, for '05 for that platform.

Thanks for that update. And then just a last area I wanted to touch on is acquisitions. There's a fair number of power plants for sale in the Northeast. You have always said that's a target area. I am just wondering given where energy commodity prices are, what kind of fuel source would you be preferring at this point if you have your druthers? Do you have any preference, kind of coal plants, hydro, natural gas? If you could just to talk about the kind of things you would be most interested in?

I think -- it is Chris -- I think probably the best way to look at it is that we would always be looking to any facilities we were pursuing to be low-cost producers in their region or to be contracted facilities. And either one of those categories would have us be interested. And so the hydros and the coals are the kinds of facilities that we would be interested in right now.

And what are your criteria -- a lot of the companies say that an acquisition has to be immediately accretive. Have you guys sat around yet, Chris, and had a chance to talk about, these are our criteria for making an acquisition? Do you have anything like that you could share with us?

It is Randy here, and accretive is good. And it is certainly one of our criteria.

But you haven't sort of drawn a line in the sand that something has to be immediately accretive or something like that?

I think if it is not immediately accretive we want to look very, very hard at some of the other aspects around it. So accretive early is where we are at as well.

Andrew Cuskey from UBS.

If you could just elaborate on your relationship with Brascan and the state of Vermont? I now I've asked this question on really past conference calls. But is there any further color you can give us on that relationship? And there's just been some news flow coming out of the city of Rockingham in Vermont that they have potentially are seeking financing for a plant that they did pick up from U.S. Gen New England. Would you care to comment on that at all?

It is Randy here. We have been working with Brascan over the last few months and the reference to Rockingham -- is the town of Rockingham has an option to acquire a hydro facility in the Bellows Falls area that was part of the U.S. Gen assets, and we're working with Brascan and the town and the state to see if there is an opportunity there.

I guess just to follow-up on that. As it relates to the stalking horse bid process that is going on on the U.S. Gen New England assets, how did you see the values from your own opinion that were paid as the initial bids? In particular TransCanada did a 505 million, and there's about 4 percent break fee on that. How did you see that stacking up against the metrics that you would evaluate the transaction with?

I think the short answer to that is that we're not the stalking horse.

Okay. And then just one quick question on the coal default with AMCI. If memory serves me correctly, they are basically out of Connecticut. Do they have any assets in Nova Scotia of significance?

Yes.

And do you have a liquidated damages clause within the contract?

We have a variety of provisions in the contract that we think will hopefully serve us well.

Winfried Fruehauf from National Bank Financial.

I would like to return to the gas contract. Do I understand correctly that while you are not necessarily entitled to 16 million cubic feet of gas a day, you are entitled to the caterific (ph) equivalent of 60 million cubic feet of gas a day?

I'm saying roughly there is a substitution provision in the contract that is there as protection.

Now given that the value of liquids relative to dry gas can swing widely, how are you actually in a position of sort of projecting that with respect to liquids and gas treating it as offshore fuel, that your marketing opportunities in 2005 or after November of this year will be less than they have been before november of this year?

We have a reasonable expectation as to what we would expect any changes in volumes to be. And we would expect them to be comparable to what we have previously seen. So I think from that perspective we feel pretty comfortable with the projections we have made.

With respect to Page 11 of your release, the energy marketing margin that is referred to there of 3.9 million for the third quarter 2004, I take it this really has nothing to do with marketing natural gas or liquids. This has all to do with energy services?

Yes, that's correct.

And when I asked earlier for a guidance with respect to that margin, I meant guidance with respect to energy services. So in other words, to repeat my question, what is your quarterly or annual guidance with respect to energy marketing margins going forward?

It is Randy here. And really that is a very tough one to provide guidance on. I think you can see some consistency in the last couple of quarters. The first quarter of this year was very, very good. It is difficult to say whether that is something we could repeat or not going forward into 2005. So is just a question I think not able to be answered properly at this time.

Okay. But do I take it that at least directionally you are aiming at improving the 2004 performance in 2005?

I think that is again very difficult to answer. I think every business would say we are always looking to improve what we did this year next year. But in this case the nature of the business makes it a very difficult one to cement that kind of answer down.

All right. So this then might be one of the swing factors that we're looking at for 2005?

It is Judy. I guess we would characterize 2005 -- 4 as a very big year in that business. And I don't know -- we would like to be able to repeat it, but we wouldn't want to guide you to the fact that we would be able to do that every year.

Dominique Barker from Credit Suisse First Boston.

I don't have the benefit of being in Nova Scotia or visiting anytime soon, although I would like to. I wanted to get a favor flavor for the local reaction to your electricity price increases. Is this something that appears in the newspapers, something that is talked about?

I think if I could characterize the reaction as someone who is from away, as they say in here for just about year, I would characterize the reaction as not atypical of most any rate increase that is put forth. Rarely when I characterize rate increases as something that would be warmly received by the public. But I think most people here understand that our taxes have dramatically increased, and that is the reason behind the filing.

Is it that something that appears prominently in the local newspapers or not really?

From time to time it may appear in the business section.

I just have another question just with regards to your Canso (ph) facility. And I don't know if you in a position to answer this yet, but how are your negotiations going with other commodity users?

We're continuing to pursue the sale of the terminal, and the obvious outcome will depend on those negotiations. We're looking to either add value to our shareholders, as well as make sure that we realize the value that we had assumed we could realize in terms of transportation savings and the like when we built the facility. In either of event, we feel pretty good about that facility being built.

And do you expect to give us an update with regards to how that is going to be structured, whether it goes into rate base or whether you actually do share it with other commodity importers? Do you expect to have some news I supposed in Q1 2005?

I think that that is fair that we would have that sorted out probably in Q4.

(OPERATOR INSTRUCTIONS) Maureen Howe with RBC Capital Markets.

Just a couple of things. First of all, with the fuel adjustment mechanism that you filed for, is that a mechanism where you basically book budget and then variations get debited or credited to a deferral account? Or do you actually have a range within which you manage your fuel costs. And then outside of those ranges you get the tiering up, or the credits and debits to the deferral account?

Fuel costs as we filed it is that customers would pay the actual cost of fuel, no more, no less. And that we would in an effort to smooth out or damp out any changes that might occur, we would spread any changes over a twelve months period going forward. And so over time we would expect that those normal ups and downs would damp out and therefore provide stable prices.

Right. Okay. Is there any concern that, I guess there is less risk, but there's also last ability to manage to your allowed ROE if you give up that management of your fuel supply.

Yes, and we have reflected the fact that we have applied for a fuel clause in our ROE ask, which is 10.2 percent. And just as that is -- that ask reflects the lower risk associated with the fuel costs, which will actually serve to save our customers money.

And just coming back to this other category in the energy services line, I guess in particular. You say that it is difficult to predict, although with the exception of Q1 where I think the margin was close to 9 million or just over 9 million, it has been running just under 4 million pretty consistently quarter to quarter. So was Q1 just a very unusual opportunity that you guys were able to capitalize on, and it is something of the neighborhood of 3.7, 3.8, 3.9 more typical? Or are you saying there just simply isn't a typical run rate?

I think all we're saying is that it is a very dynamic business and that prices do move a lot in that business. And it is just very hard to predict that is going to continue to be performing as good as it has this year. We have been extremely pleased with how it has performed this year. We think the people in that group have done a very good job. And we would like to hope that that could continue, but we're not going to count on it, that's for sure.

And going back to Q1, if I recall what you said in your interim there that there is volatility in gas markets, I think is what the explanation was, I might thereon. Was that a very unusual situation unlikely to be repeated or --?

It was. You know a couple of things actually came together. It was the first time that the Maritimes & Northeast Pipeline was connected to the Algonquin System and so gas was delivered over Algonquin for the first time. As well we saw (indiscernible) prices hitting, I think it was $87 an MM through that period. And so we were able to provide services to generators and others in that area that allow us to earn some pretty good margins.

Karen Taylor from BMO Nesbitt Burns.

Could I just clarify, I don't know when in this conversation this was stated, but I think it was Ralph that said that on the renegotiation of this gas contract that somewhere between market price and the maximum price in arbitration is where you are going to settle out. We are aware of an arbitration process for another company in the group that's got a gas contract, and the arbitration price is in fact in excess of market price. Could we actually end up with that situation here where you're out of the money on the gas costs, and then you can't basically sell the gas for any margin whatsoever? Is that a problem?

No, I don't think that's a risk, again, by the nature of the way the contract is structured and the parts of the contract are being renegotiated.

So as it sits today, subject to the renegotiation of other clauses, could you end up with an arbitration price determined that is higher than market?

I don't think so. In fact I am confident no.

There are no further questions registered at this time. I would now like to turn the meeting back over to Mr. Chris Huskilson.

Thank you very much. Before we sign off I want to thank you all very much for your participation say and for your interest in Emera. I want to leave you with this one last thought. Emera's electric utilities are the foundation of its business. We will remain sharply focused on running them well for the benefit of our customers and our investors alike. And we will continue to look for solid opportunities to grow our business in the northeast of North America, to build on our expertise in electricity generation, transmission and distribution. Thank you very much, and have a great weekend.

Thank you. The conference has now ended. Please disconnect your lines at this time. We thank you for your participation, and have a good day.