恩橋 (ENB) 2004 Q3 法說會逐字稿

Welcome to the Enbridge Inc. third-quarter 2004 financial results conference call. I would now like to turn the meeting over to Mr. Colin Gruending. You may now proceed, Mr. Gruending.

Good afternoon, everyone. Welcome to our third-quarter earnings call. With me today are Pat Daniel, our President and CEO; Steve Wuori, Group Vice President and CFO; and Scott Wilson, Senior Vice President and Controller. Pat and Steve have some opening remarks and Scott is available to assist with the question period which will follow.

I'll remind you that this conference may contain forward-looking information which involves certain risks and assumptions, uncertainties that may cause our results to differ from those implied by our remarks. Some of these risks include whether, commodity prices, throughput, volumes, interest rates, regulatory decisions and other items. These risks are more fully discussed in our filings which are publicly available through the SEDAR and EDGAR systems.

The call is also being Internet webcast recorded. And for those of you listening over the phone, I would encourage you to review the supporting slides which will accompany our remarks that are on our website as well. A call replay and transcript will also be available later today and tomorrow respectively. I'll now turn the call over to Pat Daniel.

Good afternoon, everyone. Thank you very much for joining us. As I'm sure you're aware, earlier today Enbridge reported third-quarter net income of $180 million. So together with our very strong first half of the year, our 9-month results now remain right in line with our expectations. This quarter's results were significantly enhanced by about a $98 million gain on divestiture of Alta Gas units, as you know. On an adjusted operating basis our 9-month results were $2.72 per-share which represents an improvement of about 5 percent over 2003's comparable figure of $2.60 per share.

This growth is essentially all organic and from our existing strong asset base. So as we look at the full year 2004 now with one quarter -- or less than one quarter remaining, we remain confident that we're on track to earn our previously communicated guidance of $3.00 to $3.10 per share. And as you know, we're already 90 percent of the way there and therefore I'm going to focus my remarks beyond this year largely. Though I am going to be very brief because we held Enbridge day just 4 weeks ago and I expect that many of you were in attendance at that session and I'll try not to be repetitive.

Just to give a bit of a strategy recap and to reiterate, we continue to consistently execute on our strategy which in summary can be best captured with a half a dozen key points. First of all, we intend to excel in operating energy delivery infrastructure. We, secondly, intend to continue to prudently expand and extend our existing infrastructure network and we've done that very consistently over the past decade.

We also will continue to acquire mature infrastructure through the two low cost of capital vehicles that we have, Enbridge Energy Partners in the U.S. and the Enbridge Income Fund in Canada. We also intend to selectively acquire growth infrastructure at the Enbridge Inc. level and to make measured entry into complementary businesses which has been another Enbridge trademark over the past decade plus.

In terms of positioning, as most of you know, we have outstanding energy demand fundamentals supporting the strategies that Enbridge has. We have a very good existing asset base, unprecedented financial flexibility in the Company and we feel a strong management team and a strong Board of Directors to steward this next stage of our development in the Company. So we're very well-positioned and I don't think I can emphasize that positioning enough. As you know, we spent a great deal of time on that at Enbridge day.

So what's next for Enbridge? Well, quite simply we intend to continue to utilize this position and the competitive advantages that I referred to to lever our way into what is a forecasted next wave of about $60 billion worth of North American infrastructure development and that's for both crude oil and natural gas delivery infrastructure. To just give a bit of evidence with regard to this, over the last 2 years we have at Enbridge identified what we feel is a very robust list of potential organic projects which now we're actively pursuing from regional oil sands infrastructure to new export pipelines to Alaska gas, to CO2 pipelines -- a very diverse group of opportunities.

Many of these projects, as you know, involve long lead times, they involve a significant design phase, a lot of innovation and a lot of commercial negotiation. We've reviewed most of the projects and brought you up to date on them at Enbridge day. so again, I won't run through each one of them. I'd just like to emphasize that we've got a very full slate right now. But what I would like to do is just comment on a couple of events that have occurred recently. And if you would like a further reminder, go into more detail on any of the projects please raise those during the question period. So my remarks will be brief.

But on Spearhead, just a reminder that we do have an open season underway. It will conclude at the end of this week and if there's sufficient interest in that project we'll then go back to the Canadian Association of Petroleum Producers with a new proposal to reverse that line. We should know more about this very soon as a result of the conclusion of that open season.

On our Gateway project to the West Coast we're making very good progress on securing Southeast Asian markets to complement what we feel are strong California markets for this project. It's a work in process and we will keep you up to date on it as it goes. Similarly at Fort McMurray to Edmonton corridor, good progress is being made. Please stay tuned on that one and we will update you shortly as we continue to make progress.

Moving to the gas distribution utility, on Monday we received a decision from the Ontario Energy Board with regard to our 2005 rate case. We're generally pleased with the regulator's decision. Recall that we had previously settled about 80 percent of the issues with interveners prior to this summer's hearing and we've been awaiting resolution of just a handful of issues that were left over from the ADR process.

The decision approved a number of relevant requests; most notably the change to the utility year end to a calendar year basis, the collection of some deferred taxes, sharing mechanisms with regard to gas and transportation capacity purchasing and a storage agreement with Union Gas. This decision really confirms that 2005 will be a cost of service year and we will have a rate base of approximately $3.4 billion and an expected ROE of 9.57 percent. As you know, that rate base continues to grow at a record pace with new customer additions. So again, we're pleased with the decision.

You'll recall that one of our objectives in 2003 and 2004 was to really strengthen the utilities regulatory interface and to reduce negative surprises with regard to regulatory decisions. I'd just like to comment that we're encouraged with the tone and the balance of this decision from the OEP. We're pleased with the increasingly progressive approach that the Board is taking to policy setting in Ontario.

The natural gas forum, for example, is currently underway and is looking at a number of very relevant issues including the potential for incentive regulation which we still intend to be very involved in. It's also looking at the role of system gas and the potential benefits from using storage. With the recent trends that we've had in our decisions through 2003 and 2004 and with these new initiatives through the forum I would observe that we're making very good progress on this regulatory objective.

So we continue to explore a number of alternatives to set rates for '06 and '07 including the possibility of a multiyear incentive arrangement and more on that at a later date. So let me stop there with my brief introductory comments, turn it over to Steve Wuori who's going to run through the quarterly numbers and then I'll come back in a few moments. Steve?

Thanks very much, Pat. I will dive into the numbers for the quarter in a minute, but on the whole, if you step back and think about the quarter I really think there are two key take aways. First of all the results are exactly as expected and they really position us, I think as Pat noted, to achieve our full year guidance and another year of steady, above average -- above industry average certainly EPS growth.

Secondly, the quarter was again very clean from an accounting perspective with just three non-operating items including the Alta Gas gain which we previously announced, a little bit of colder-than-normal weather and another dilution gain at Enbridge Energy Partners. Again to help identify these and enhance the predictive value of our results we published the table in the news release. As we noted previously, we're working hard to keep the numbers clean and easy to understand and this should continue when we change the gas distribution year end to coincide with the rest of Enbridge this coming January 1st, and we'll come back to that in a minute.

Looking at the quarterly performance a little mare closely, the reported earnings were 180 million or $1.07 per share. Excluding significant variances second-quarter adjusted operating earnings were 43 cents per share which is up from 38 cents last year when you compare them on a similar basis. In short, earnings are higher due to solid contributions from liquids pipelines, the Aux Sable gas liquids plant, the Vector gas pipeline and lower corporate costs. We'll look at now some of the quarterly highlights on a segment-by-segment basis.

Liquids pipelines is up about 3 million over Q3 last year. The crude oil system, which is the largest component of that segment, generated 48 million for the quarter which is up due to the change in allocation of the tariff's 5 cent tolling surcharge affected in April of 2004 and lower O&M spending which will likely prevail through the fourth quarter. And as you see in the U.S. feeders and other lines, we are conservatively expensing our business development work on various projects and that amounted to about $1 million during the quarter.

Looking at gas pipelines, alliance U.S. earnings are down slightly due to the impact of the stronger Canadian dollar. And even though there is a similar foreign exchange impact on Vector, the Vector earnings contribution doubled to 3.5 million due to the additional 15 percent interest that we acquired in the fourth quarter of 2003 and also improved transportation margins from the capacity available for short-term contract on that line. We are pleased to report that Vector has been running full at 1 BCF per day and, further, that it is fully contracted through 2006.

Looking at the sponsored investments segment, the contributions from Enbridge Energy Partners and the Enbridge income fund were about on par with the prior year. There isn't really a lot to add about the fund which reported I believe this Tuesday. It is performing at or above our expectations. The Enbridge Energy Partnership which reported last week is also performing very well, reflecting a good mix of organic volume growth in the systems and also accretive acquisitions.

Our earnings contribution from the partnership in this quarter is essentially flat as the growth was offset by three non-operating factors. The first of which is a onetime negative FERC decision on a rate refund matter relating back to 1996 on the Kansas pipeline system and our share of that ruling was about 1.5 million. Second, the fact that we now own a little bit less of the partnership, 11.6 percent versus 12.4 percent in the previous year following the secondary offering in September -- common unit offering. That did dilute us down to 11.6 percent. And thirdly, the impact of the weaker U.S. dollar in translating the partnership's income into Canadian dollars also had an impact.

Looking at the international portfolio, earnings were down slightly from the prior year quarter while CLH volumes were up about 75,000 barrels per day or about 10 percent to a total throughput of 800,000 barrels per day. The earnings pick up includes out about $1 million share of onetime retirement costs associated with the retirement of the tanker fleet and some trucks, or lorries as they are called in Spain, and the closure of other small non-core facilities. The other reporting line in international reflects the expensing of some business development costs that we incurred earlier this year. Ocensa remains right on budget at about $8 million per quarter.

The gas distribution and services segment as a whole had a very good operating quarter and the largest asset within that segment is Enbridge Gas Distribution. On a weather normalized basis and reflecting the new unbilled revenue accounting recognition, EGD's third-quarter results translate into a loss of about 26 million which is very consistent with the prior year quarter on a comparable basis. To be clear, the previously discussed unbilled revenue accounting change has now fully reversed itself among the first three quarters of the year and the fourth quarter will not be affected. This practice we will continue going forward into future years and hopefully the adjustments associated with that are now pretty well recognized.

We're also pleased, as Pat noted, the OEB has approved the regulatory year-end change for the utility to commence January 1, 2006. No more quarter lag. To effect this the utility's October to December 2005 quarter will be a sub quarter using unchanged rates. Given that kind of regulatory visibility and our desire to transition quickly so as to build comparative measurement for you sooner, Enbridge Inc. will adopt the change for consolidating reporting purposes 1 year earlier, January 1, '05, and we will no longer quarter lag after that.

So Enbridge Inc.'s 2004 annual results will include five quarters from the utility, the four lagged quarters through September 30, '04 plus the Q4 2004 quarter. We reviewed this quarterly grouping at Enbridge day and there is a slide on today's webcast that walks through this and should make it fairly clear as to how the quarters are grouped. Effectively Enbridge's normal full year earnings are unchanged. What is changed, though, is that now the utility's seasonality moves from being a front-end weighted year with very large contributions historically in the first two quarters to one that is more book end like with the large winter quarter contributions in Q1 and Q4 -- unless weather patterns change pretty dramatically.

The other highlight in the distribution and service segment is Aux Sable which performed strongly earning 4 million during the quarter. This represents about a $5 million improvement over the comparable 2003 quarter and is due primarily to more favorable fractionation margins together with a continued focus on risk mitigation. We have locked in some reasonably positive margins on all mandatory production and on about one-third of our optional liquids production.

The length of the current risk management program extends in varying degrees to about midyear of 2005. We and our partners in Aux Sable have also worked to remove the must-run operating nature of the plant. And going forward, when it is uneconomic to extract, Aux Sable will have more options to leave higher content liquids in the Alliance gas stream. We're very pleased with this development at Aux Sable and it should significantly enhance the value of the plant and our 43 percent interest in it.

Finally let's look at corporate costs which were lower than the prior year quarter due to a number of smaller items including lower interest expense from lower debt levels and also lower corporate tax expense. As you'll recall, we had spent more in the first two quarters and we now see corporate costs averaging down in the back half of this year. We continue to think that the quarterly run rate will average about $20 million per quarter.

So those are the quarterly highlights, Pat, and I'll now turn it back to you.

Thanks, Steve. And I don't have a lot to add. I think the key message I'd like to leave with you today really is that Enbridge is very well positioned within the industry and we do have an excellent slate of new investment opportunities in front of us today. We continue to show quarter-over-quarter and year-over-year that Enbridge really is among the very best, I feel, in North America in terms of generating organic business development opportunities. That really concludes our formal remarks. Colin, we can now open it up for questions.

Alright, Jacques (ph), if you want to begin the question period now.

(OPERATOR INSTRUCTIONS) Maureen Howe, RBC Capital Markets.

Just coming back to corporate expense, in the explanation in the MD&A it states that there's some variance due to timing of corporate activities. And on page 4 of the notes to the financial statement there appears to be a large corporate tax recovery of about $32 million. I'm just wondering, you gave a run rate of $20 million per quarter, was there anything unusual in that $32 million tax recovery or is that just part of your normal tax planning?

First of all, the tax line moves with the investment and other income line, and so you have to really look at the two of them together. But there are several factors in the tax line that create some variance. The main recoveries in this quarter were related to FX losses on debt where a U.S. sub holds Canadian dollar denominated debt which, because of the strengthening Canadian dollar, results in a higher debt obligation effectively. So that would have increased the tax recovery. The offsetting would be in the investment and other income line.

Okay. And then moving on into liquids pipeline, again the explanation in the MD&A was that there was higher earnings from the Enbridge system which reflected timing of operating and maintenance, but also it said a higher share of a surcharge. And I'm wondering -- this would be the tariff surcharge. And I was wondering, who else is getting a share of the surcharge?

That relates to the 5 cent tariff surcharge that was for some time directed 1 cents to Enbridge pipelines in Canada, 4 cents to Enbridge Energy Partners. And under the agreement it was designed to flip back on April 1, 2004 so that's what happened. And so Enbridge Pipelines from that time forward received 4 out of the 5 cents. And I'm not aware of any third parties that have a call on any of the rest.

So it's just (indiscernible) then?

That's right.

Okay. And then in terms of the timing of operating and maintenance expenses, again, is this something that will reverse in Q4 or what does that represent?

I think generally the trend that we see here should continue into '04. We don't anything on the horizon in the current quarter that's going to change that.

Okay. Alright, well that's it. Thanks.

Linda Ezergailis, TD Newcrest.

A quick question on the foreign exchange exposure that you might have. What would be the year-over-year impact on earnings from that?

I think in '04 we're probably going to look at about a 4 cent translation drag in earnings due to the U.S. dollar weakening, Linda. Now we have that substantially hedged on an economic basis, but in terms of the earnings affect I think that's roughly what we expect.

And when you say you have it substantially hedged on an economic basis, can you give us a sense of duration? Is that for your expected duration of the assets that you hold in foreign jurisdictions or --?

Yes, Linda, some of the hedges here are long-term hedges in excess of 10 years.

Okay, thank you. And with respect to your Gateway project, do you foresee perhaps any delays in decision-making by potential shippers if they start experiencing cost overruns similar to what we saw just yesterday in C&Q Horizon project?

Linda, that's always hard to tell. The feeling that we have, though, from industry is that they are starting to realize more and more the urgency of developing that alternate market and we have not noticed any suggestion of delay. In fact, if anything the pressure is on us to try to move that project along as quickly as possible to meet a late '08 or '09 timeframe. So certainly very aware of the announced increase and that is something I know that is of concerned to the producers and has been for some time. But the economics are strongly in favor of continuing to develop that market.

When I look at the heavy/light differentials right now, I guess they're trending up this year -- I think average to date something like 1360 versus a low of something like 860 in 2002. Right now that differential has ballooned out to just over $20. In your mind, is this going to be sustainable going forward? Is that the new reality and if they were to contract down to what level would that start -- or reducing the urgency of producers to access these new markets that are heavy crudes?

First of all I would suggest the urgency to access new markets is broader than just heavy crude. It's recognized that with the increased production out of the oil sands, whether it's upgraded or not, there is going to be a need to push beyond existing markets. But I think to more specifically respond to your question, part of the reason for the widening of differentials, of course, is the significant increase in the price of WTI. I think we'll see a normal contraction occur as crude price falls. If it falls, I should say. But there is a very strong demand for additional market for both upgraded and heavy crude.

Just a final quick question. How much did you spend on your Gateway project in the quarter and to date? And where is it being expensed or are you putting some on the balance sheet?

I believe we have spent about $7 million to date, Linda. I don't know what the number is on the quarter, but that has been expensed as we go.

Okay. And where would it be? Would that be in the BD in the liquids business or is that at the corporate level?

It would be in the liquids pipelines.

Great, thank you.

Karen Taylor, BMO Nesbitt Burns.

Can we just come back to the liquids system for a quick second? And I think we talked previously -- I don't know when we talked about all of this -- but we talked about a run rate per quarter of about 40 million. So can you maybe break that increment that we saw this quarter down between deferred maintenance and the reallocation of the toll? Because the 5.1-4.1 split rather and then the reversal of it, that's been known for quite some time. So, when we talked about the 40 million run rate for the quarter one would have presumed that that was already in there. So can you talk about the increase of 4 million and break it down between the new expenditure plan on the liquids system versus the toll reversals?

Karen, maybe I'll take that -- it's Colin here. I think the 40 million a quarter was meant to be fairly broad and averaged over multi quarters. Certainly this quarter is a little higher. The tariff's surcharge -- if you just do the math -- the delta basically now getting 4 cents instead of 1.

On what volume?

Pardon me.

On what volume?

The surcharge is on all shipped volumes.

I beg your pardon.

It's on shipped volumes.

Okay.

So for about 1.5 million barrels a day there.

So we're not getting -- because we've got this layering of agreements. We've got system expansion plans, we've got the tariffs. Are we earning above that threshold level -- I believe it's system expansion plan two where you've got the 760 for a level and you go up to a transition where you're technically at risk for a little bit and then you do quite well above. Are we earning above the floor yet on system expansion plan two? Or are we in that transition where we've got a little bit of earnings risk?

No. We're at the floor level on SEP-2, Karen. That would be 7.5 percent based on current utilization.

So of the increase that we saw, roughly 4 million, you're telling me 4 cents of that applied with 1.5 million barrels a day will get me the delta pretax?

Probably not. Then there's some O&M that I think we've talked about that looks to be a little bit lower in the third quarter and likely the fourth quarter.

When you say a little bit, is that 1 million or 2 million or 3 million? Is it going to substantially increase the run rate from the segment from the 40 million we discussed to the 45 million level?

I don't think so. Not materially. I think low 40s is what we kind of see and have seen and that is that we based our average on.

So low 40s means 40 to 45 million, correct? In between that range.

Approximately. Yes, I think we have said about 40 million a quarter if you look at it on an extended basis and divide back it is probably going to be about that. I am not sure we are equipped to get a lot more surgical right now.

I am just trying to establish a run rate because we talked about this before so I just want to make sure I understand where the numbers are coming from. The corporate expenses I know you explained it to Maureen but it is a long day and I would like you to just come back to it again. The 16 then is below your average run rate that you would foresee going forward, is that correct?

Yes, that is right. We had quite a bit lower expense, about $3 million of lower interest expense due to much lower levels of debt. Essentially we use the Alta Gas proceeds to pay down short-term debt. And so the debt levels are lower, interest expense is therefore lower by a fair bit and that actually makes up a lot of the delta there. And then there was the lower tax expense line as well, as I explained earlier. Those are the main things in motion on the corporate line.

Right. So assuming that we have nothing that would recommit that 300 odd million -- almost 400 million from Alta Gas plus other operating cash flows -- that free cash flow that has not been otherwise committed for the year, Q4 should be closer to the 16 level than to the 20, is that fair?

Well, the interest expense wouldn't change a lot, because that's going to be constant.

Right.

And Steve, the foreign exchange impact on that Canadian dollar debt in the U.S. sub is likely to see the tax expense reverse somewhat. So I think the $20 million level is a better level than the 16.

Okay. And on Alliance was the -- again, I know you talked about it, I just want to be perfectly clear that the foreign exchange consequences are unchanged in the sense that that's the predominance of the variance, it that right?

From Alliance U.S?

Yes.

Yes.

Does Alliance U.S. have any of the peculiarities in terms of the crossover between taxable and non-taxable that we saw earlier in the week on Alliance Canada?

That's further out in the decade I believe, Karen -- that issue with Alliance U.S.

And further out in the decade means --?

Further out in the decade, like it's '04 now, so --.

So it's not '05 or '06?

I think it's just a bit beyond that.

Okay, that was it. Thanks.

Bob Hastings, Canaccord.

Steve, you mentioned that earnings were exactly as expected, but the one thing I noticed is while the earnings are coming in exactly as expected the organic growth seems to actually be doing better than originally thought and been able to offset the lack of acquisition growth. So if that's the case I'm wondering -- and I don't mean to be splitting hairs here -- but I'm wondering as we look out into '05 are things trending along better organically than you thought and makes your earnings numbers or growth targets going forward a little easier particularly with these acquisitions?

Well, I think, Bob, that it's been a very good year organically and we don't see any significant change in that. So we're very pleased with that level of organic growth, but I'm sure you'll agree that has been a long-standing trademark of the asset base that we've got and we would expect to see that continue going forward.

Okay. So does that mean that going forward your growth rates internally might be a little better than you were originally looking for?

No, we're still feeling that 8 to 10 percent over a reasonable period of time for EPS growth is about right and that tends to be 5 to 6 percent organic and 2 to 3 percent acquisition. The acquisition number based on just our historical record over the last decade and similarly with the organic growth. So we're still comfortable with that.

Okay. And a different topic then. In the Aux Sable, given that the new agreement is in place to be able to run that thing through when the economics dictate, i.e. bad economics, that basically limits your loss. If that had been in place what would have been the worst quarterly losses on a reported basis? I guess it would have really just been your depreciation and financing costs, is that right?

Basically, yes, because you'd be in a position where you wouldn't have to operate the plant.

So my question is what is your depreciation and financing cost currently at Aux Sable?

You'd probably have to add in some fixed operating and admin. costs as well. (multiple speakers) I'd have to double check, but I'm guessing it's around $3 million a year kind of thing after tax.

That sounds about right, Colin.

Thank you very much.

(OPERATOR INSTRUCTIONS) Matthew Akman, CIBC World Markets.

Pat, we're getting close to the end of the year, I wonder if you can give us any sense of the timing for finalizing the tolling agreement Enbridge system that comes up at the end of the year?

Not really, Matthew. We're in negotiations right now with the producers and it's very important that those negotiations remain private and that we not discuss them publicly. We're still very hopeful that we will have a new incentive tolling agreement in place by the end of the year, but to go into any more detail wouldn't be fair at this point. But we're pleased with the way things are going.

Okay, thanks. I guess just clarifying on gas distribution, someone said -- maybe it was Pat or Steve -- that there's 3.4 billion of rate base. Maybe this is a question for Scott, I don't know. But in the presentations on Enbridge day there was a slide that looked more like -- that actually showed 3.15 billion of rate base and that's a fairly material gap. I'm just wondering what the number is.

The 3.4 that Steve mentioned is the updated number.

Okay. And what's the difference between the two numbers attributable to?

I think the number we were using -- Colin, go ahead.

I was just going to say -- if you think about the delta from the 3.1, I think, Scott, the 3.1 might have been the 2003 rate base which is the last rate base we had. And if you remember, '04's rates were essentially rolled forward from '03 without a rate base increment. So what you're seeing, I think Matthew, is 2 years worth of essentially customer growth.

Okay. So that number that you were showing was really an outdated number -- when you showed it at Enbridge day? Okay. And then I guess just staying with gas distribution, the natural gas forum that's there -- and I don't know if this is for Pat or Scott, whoever's close to gas distribution here -- there's some possible options being explored of transferring system gas to a third party. And right now obviously gas distribution buys at a commodity and sells at a markup. But is that something that Enbridge would be supporting? And I guess if so, does that mean you'd be in that retail -- competitive retail business or out of it or what's your view on that, please?

Well, we, as you know, were there, Matthew, in terms of the retail energy services business and felt that it really didn't fit for us. We recognized the importance of the utility being a system gas provider and a provider of last resort and would suggest that the regulator is likely going to want to continue that. But if it where a third-party business it's probably not something that Enbridge would be involved in. We withdrew from that business once already.

Okay, thanks very much.

Dominique Barker, Credit Suisse First Boston.

I just wanted to get your opinion. Do you think that PBR is going to be instituted in Ontario in '06 or '07?

That's pretty difficult to tell, Dominique. I think with the forum underway right now we're probably better off holding our opinion on that until we get through these discussions. We have sensed a positive attitude from interveners and the regulators with regard to trying to implement some effective system of PBR. But -- very important that we go through the proper process, hear everyone's views and opinions on it and do it right. So it's very hard to tell on timing. I think we'd be better positioned to that when the forum completes and we've got everybody's views on the table.

And then I just have another question with regards to the Athabasca system. I just wanted to ask about volume increases. Have you seen volume increases? What's the capacity utilization on the system right now? And what are your expectations going forward just with all of the new oil sands projects coming on?

We have a capacity of 570,000 barrels a day on the line and I believe we're at 225,000 today, Dominique, contracted -- on the line. Sorry, what was the last part of the --?

Just with regards to -- I would have expected more growth from that system with regards to more oil sands coming on. And I just wanted to know if -- one, if there is extra capacity on the system which it sounds like there is, and what your prospects are for the future?

I think the prospects are very good as evidenced by the memorandum of understanding that we have with OPTI/Nexen with regard to long lake volumes. And we are very aggressively working to bring other new shippers onto the line as well. So we're very, very optimistic that that line is going to fill up and not only that -- that that will lead to strong demand for the construction of this Waupisoo pipeline that we're proposing from Fort McMurray to Edmonton. So we're very gung-ho and optimistic with regard to Athabasca; it's been a great investment.

Great, thank you.

Sam Kanes, Scotia Capital.

Pat, one of your competitors an hour ago gave a bit of an outline on their oil pipeline project -- Miocene (ph) before year end they're trying to some I guess develop some form of collective expressions of interest. And then for mid next year attempt to an open season. With respect to a late 8, '09 startup of Gateway, what would your best guess on the pathway be of that movement towards firm shipper contracts I guess is what ultimately everybody wants to get?

Yes, that's very difficult to forecast, Sam, because we're in discussions right now, but we do need a significant critical mass in order to anchor a major investment like this. And discussions are underway both with downstream markets and refiners who would take crude oil through the system and upstream producers. I find it very hard at this point to forecast when we would be able to go to any kind of formal open season on it. All I can say is that we've been quite encouraged and particularly with regard to the interest in Southeast Asia with regard to the commitments that they might make to the line. So we should have a much better feel early in the new year as to whether we're going to be able to move some of those through to firm contractual arrangements.

Have some conceptually come in and said I'd like a piece of this pipeline too. We saw, for example, the government of Alaska say I'll help out with some of that pipeline spending. Has anything like that happened at the Alberta level or any upstream or downstream player so far in general?

We don't have any contractual volumes yet. We do have strong interest with a number of producers and a number of refiners. We haven't talked to the Alberta government with regard to royalty crude. We do know that they are supportive of broadening markets. We know the BC government is supportive of the idea of the development of further outlet to the West Coast, but we don't have any firm -- we haven't asked for any firm contractual volumes at this point either though.

Okay, thanks.

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

Alright. Thanks for joining us, everyone. We appreciate your interest in Enbridge and we'll be around for follow ups if necessary. Thank you.

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