恩橋 (ENB) 2005 Q1 法說會逐字稿

Good morning, ladies and gentlemen, and welcome to the Enbridge Inc. First Quarter 2005 Earnings Conference Call. My name is Jen and I will be your coordinator for today. [OPERATOR INSTRUCTIONS]. I'd now like to turn the presentation over to your host for today's conference Mr. Colin Gruending, Director of Investor Relations. Please proceed, sir.

Thanks Jen, and good morning everyone, and welcome to our first quarter earnings call. With me today are Pat Daniel, 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 also available to participate in the Q&A session following. I will now remind you that this conference may contain forward-looking information, which involves certain risks and assumptions and uncertainties, that may cause our actual results to differ from those implied by our comments. Some of these risks include weather, commodity prices, throughput volumes, interest rates, and regulatory decisions. These risks are discussed more fully in our filings, which are available publicly in SEDAR and EDGAR systems. The call is being webcast-recorded. For those of you listening over the phone, I encourage you to view the supporting slides available on enbridge.com, which will accompany our remarks. A call replay and transcript will be available later today. I'll now turn the call over to Dan.

Thanks Colin, and good morning everyone. Thank you for joining us. As you know, earlier today we reported very strong 2005 first quarter results, which provide an excellent start to the year for us. All five of our business segments are up to varying degrees, and that's very encouraging for us. Reported earnings for the quarter, of course, were very healthy, $220 million, which is almost double the reported figure last year. That's primarily due to the change in year-end for the distribution business, and we'll get into that in more detail later on.

On a fully adjusted operating basis, as we reconcile in the news release, our first quarter earrings were $205 million or $1.22 per share, which represents about a 7% improvement over the 2004 adjusted number of $1.14. So, I think that result underscores the fundamental health and the diversity of the current asset base at Enbridge, and Steve Wuori will go into more detail on the quarter here in a few moments.

We're very active in Enbridge right now, and I'm going to try to keep my remarks relatively brief as we of course have been communicating with the market, frequently lately, and also because I'm going to be speaking at the Annual General Meeting in some detail in each of these opportunities.

Most of you are aware of the unprecedented level of opportunities we were positioned to take advantage of them in the coming years. This comes really as a result of the continuously depleting conventional supply coupled with growing demand for hydrocarbons, has really created a very substantial need for new energy infrastructure globally, and particularly here in North America.

Our assets at Enbridge are very well positioned to benefit from that additional utilization. And as well, we've really led the pack in assessing and proposing new infrastructure which will lead to new investment opportunities, but which will also enhance the operating leverage of our existing assets, either by supplying additional volumes to that infrastructure or by pulling more volume through them, as we described with some of the initiatives that we have under way. We do find ourselves in comparative situations on almost every front that we're involved in.

We believe though that Enbridge has competitive advantages in each proposal that we put forward, so we believe we could win more than our fair share of the projects and initiatives that we are involved in. Just a quick comment, we really believe that competition is a good thing and it certainly is for the customer, I don't think there's any doubt about that. But it also is for service providers, because it calls for the best, and it helps improve Enbridge and everyone around us. I think it brings out our best because we tend to then embrace innovation, flexibility, and strengthening our customer relations. So, we strongly encourage the competition that is going on in this business today.

Let me now quickly run through some of the key projects that we have underway and I'm going to start with liquids pipeline where we have the most opportunity and where we recently have completed our 2005 long-term oil supply forecast and have now upwardly adjusted our base and our high supply cases for Western Canadian crude oil production. This is based on very comprehensive and proprietary work that we've done on a risk and probability weighted basis and we start and work bottoms up well by well and oil sands project by project basis.

The revised supply forecast supports the need for our proposals that we've already put forward to solve the oil market access issue and we tend to group these opportunities into three geographic areas that I'm going to cover. First of all, regional infrastructure in Fort McMurray, Edmonton area. Secondly, main line expansion with our system across the country and then new market opportunities. And recently, just started out at the regional level.

During the quarter we signed a firm agreement with OPTI Nexen partners to provide medium-term pipeline transportation solutions to move various bitumen blends for them and then later synthetic oil and move that to the Hardisty, Alberta or Athabasca Pipeline. We also expect to finalize a similar agreement with the Surmont Partners very shortly and we will also target other oil sands projects for similar transportation and storage agreement. In addition to that, we expect to secure the necessary volume commitments this year to build our 30-inch $430 million Waupisoo pipeline, which will come from the chieftain station at south of Fort McMurray down to Edmonton. So, we are very well positioned regionally and getting stronger by the day.

In terms of mainline capacity, we continue to advance our mainline capacity addition program, which is south of Superior, Wisconsin and this will be undertaken by our affiliate Enbridge Energy Partners of course and supports the overall strategy of the broadening and expanding markets for Canadian crude. We're currently seeking industry support for a 3-phase capacity expansion initially if we go to Chicago and will involve expansions adding 355,000 barrels a day at a cost of about $700 million US. The third phase would also access the Chicago refining area via Spearhead bi-directional flow north. So, after that, we have very cost effective capacity addition options upstream of Superior but at present the bottleneck is south of Superior.

In terms of new markets, last week, I'm sure you are all aware, we obtained NEB approval to collect partial revenue requirements in our mainline total to support our Spearhead pipeline to Cushing, Oklahoma, and also the ExxonMobil pipeline to the Gulf cost was approved by the NEB. So, having already received FERC approvals to physically reverse Spearhead, we will now focus on effecting that targeting an early 2006 in service date.

We also by the way are considering acquiring the 10% Spearhead that is owned by our partner BP. So, these two pipelines, Spearhead and the ExxonMobil line, now in south bound service should provide access to two new distinct markets, which will benefit our customers significantly and they also will pull more volumes through Enbridge's Spearhead and the mainline systems. So, that is obviously of benefit to us as well. We're also continuing to work on a variety of Greenfield and joint venture alternatives to penetrate the Eastern Pad II and the refineries there.

We believe that the Canadian heavy crude supply picture represents very good opportunity for the Ohio and Kentucky refiners and that they may find it compelling to retrofit their refineries to take more Canadian heavy oil. In addition, we are adapting our Southern access proposal through Enbridge Energy Partners again, which will sequence in after our phased mainline capacity addition program and Southern access will be to extend this line further south from Chicago to either Wood River or the Patoka hub or alternate markets as needed. So, that will be the further push after mainline expansion. The Gateway proposal of course from Alberta to deepwater port in BC is progressing very well.

Roughly speaking, we hope to complete commercial arrangements in 2005, which would position us to make regulatory filing in 2006 in order to be able to meet the late 2009 early 2010 in service date. The MOU that we've signed with PetroChina as announced last month brings a sizable new market into reach and it's a very good first step, but as we've indicated we do have lots of work there left to do in this project.

I think, a few comments awarded on the mainline oil pipeline tolling agreement, the incentive tolling agreement, but negotiations have not yet been fully concluded or filed with the NEB, so we are not in a position to discuss details on the ITA. However, the framework of the discussions is very consistent with our past disclosures with you.

And it really has the foundation -- as its foundation the base NEB multipipeline return, as we've mentioned, and as well the frame work has additional amounts that Enbridge will have an opportunity to earn through achievements in three areas, one; cost savings as the prior agreements was, secondly; new customers service metrics, and then thirdly; through risk sharing. And the spirit of the negotiation has been Meridian and Santos to provide additional value to our customers, and if we perform extremely well, we have the potential to maintain the level of earnings we've achieved from this part of the business in the past, and I fully believe that our team is up to that challenge.

The agreement will be effective January 1, 2005, so retroactive to January 1, and in the absence of a signed deal we did estimate a probable outcome, which is reflected in our first quarter earnings number. So, in short, we are very well positioned in the crude oil business and have an awful lot on the goal right now.

Moving on and talking about natural gas opportunities, we will start with Enbridge offshore. We and the former Shell team are really quite excited about the opportunities in the Gulf, and you could say that, we are really unleashing the team to pursue those additional opportunities with bigger and also with the usual Enbridge improvements that comes looking at new ventures. We are working very hard now to secure additional leased tie ins beyond those already known for 2005 and 2006. We are also interested in consolidating interest of the remaining three of five pipelines, which are joint venture partners. And of course on top of that we'll look at LNG and oil infrastructure opportunities in the Gulf, again both through acquisition, our Greenfield extensions of the very strong platform that we've now got. And Steve Wuori in a moment is going to provide the first quarter account of this asset in a little bit more detail.

Moving along to the alliance in Vector, our other flagship gas pipelines, we are operating very well on both firms. Alliance is full -- well positioned to expand with Alaska gas in the future. Vector is also full in position to supply additional gas east, particularly to Ontario, given the additional Queen Gas power supply to be built in that province. In addition, I'm moving a little bit further east on the map.

We continue to advance our LNG receiving terminal project in the Deep Quebec, which is targeted in 50,009 in service. I'm sure you aware that review this week the Levis Municipal Council passed a resolution supporting the development of Rebaska, conditional on the project receiving the represent of regulatory environmental approvals, and the federal and provincial joint environmental review is already underway on that project. So, concurrently our project team is procuring regulatory filings and we will make formal application this summer under the BAPE, and the NEBC process. And as I'm sure, you would expect we are very excited about this project. It is the best position site as we've said from the outset to serve the growing markets in Quebec and Ontario and we are pleased with this recent turn of events.

Moving along to Alaska, we will continue to support the Alaska pipeline project and as is very well publicized in this day, Enbridge alliance pipeline and the Alaskan producers are urging the Canadian government to accept a regulatory application under either the NEBC process or the NBA process and to ensure that the feasible -- all feasible applications will be processed in a full, fair and competitive manner. In our view, this project is simply too big and too critical to shortcut or grant exclusivity to one proposal.

Turning to the gas distribution business, our strategy remains to continue to steadily grow this business through new customers connections. Over the next few years, Enbridge gas is expected to continue to be one of the fastest growing and more efficient gas distribution utilities in North America. There are really two highlights for EGD during the quarter. The first is the filing of our 2006 calendar year rates applications, and this, as you know, is a cost to service application to call over 400 million in capital expenditures to connect another 50,000 customers and to provide system integrity capital primarily related to replacement of remaining bare steel and cast iron remains in the system.

The other highlight of course was the OEB's findings from the natural gas forum, and as you recall we've been strong supporter of this initiative, the gas forum initiative. The Board's findings are really directionally consistent with our views with respect to 3 key subject areas, the first thing, performance based regulations, secondly the role of system gas, and thirdly with regard to optimizing storage facilities -- gas storage facilities. There has been a very healthy policy dialogue outside of the hearing room, which is a very good approach in our view, and we are going to continue now to engage the government and intervene us on those matters going forward.

Moving on to our Sponsored Investments segment, Enbridge Energy Partners' operating performance particularly on the gas transmission side was encouraging and they have a number of organic growth projects on the books. Unfortunately the Suncor fire outages and also oil revaluation losses are challenges that have affected their first quarter, but we are of course confident that those issues will be resolved shortly.

Enbridge Income Fund is performing very well. Moving on within international, which is really the fifth platform for this Company. There are two investments continued to perform very well. We sense the performance like clock work and has now for 10 years has been as steady as a rock. And then moving on to CLH in Spain, we are up another 5% during the quarter, approaching 800,000 barrels a day now, and that system suggesting a good start to raise the fourth year as an Enbridge investment.

And as I noted with all of you in the past, we are patiently looking to add the third investment in international, so we feel that was bit well if we can find the right investment opportunity. So, with that great quick went through on some of the exciting things we've got to go off, turn it over to Steve Wuori for his financial remarks and now come back and wrap up in a minute.

Thanks Pat and good morning. I'll discuss the quarter, but I would also note that we placed more emphasis on annual performance or even 5-year and longer term performance, because the industry we are in is long cycle and the business model is build for sustainability, but in terms of our interim progress, it was a good quarter. In 2005, the numbers are clean and the variances are accounted for in the news release, reported earnings are up significantly and adjusted earnings of $1.22 per share, are up 7% year over year. Among a variety of smaller positive variances, this improvement is largely attributed to lower interest cost and also the addition of the Enbridge offshore system, which we closed at the end of 2004. So, I won't repeat everything that's in the release, but I'll just focus on a few things that stand out.

Starting with gas distribution, we have represented the four quarters of 2004 for the gas utilities, so you can see our quarterly progress as compared to the 2004 calendar year. This should better synchronize the calendar quarters after the change in the year ended EGD and also the ending of quarter lag reporting at Noverco and other utilities in the gas distributions and services segment. It also reflects the seasonal rate design changes at EGD that were implemented with 2005 rates.

You can see this first quarter 2004 reconciliation in our news release and the full-year 2004 reconciliation on this webcast and also as a posting on the website under the heading Additional Resources. This information corrects and updates the reconciliation table that we provided to you at Enbridge day last call. Pat talked to some degree about the incentive tolling agreement, I know that many of you are interested in the outcome of that agreement, renegotiation and also the assumptions that we've used to record first quarter earnings.

Note that we really can't communicate more at this time. We do expect to have some thing final and submitted to the NEB in June, at which time we would find the whole to separate conference call to discuss the agreements, subject to the mechanics. I encourage you not to read anything into the delay in finalizing the agreement. We and CAPP (Canadian Association of Petroleum Producers) have been discussing a number of projects such as Spearhead and others, at the same time as the incentive polling discussions have been progressing. Talking about Enbridge offshore, we reported earnings for the quarter of 6 million, this is largely consistent with our expectations and the guidance that we gave at acquisition, which was 30 to 40 million for 2005.

It is important to remember that the guidance reflect volumes from least high ends that are backend related in the year, and production from the recent platforms high and it has been smaller coming on line than we expected due to some producer issues and so we are expecting to be in the lower end of that $30 to $40 million range for the full year.

We measure the overall throughput on what's called the beach throughput or what's landing on the beach and that throughput average 2.7mmBTU per day in 2004. First quarter 2005, averaged 2.9mmBTU per day, and we expect to exit 2005 as we had forecast at above 3.1mmBTU per day. But we are not going to the get there quite as soon as we would have thought in the course of the year, although we will exit at that rate. So, 2006 looks bang on our expectations.

In getting there we expect to see additional volumes from the continued ramp up of new production, from deepwater developments at Holstein, Mad Dogs and Magnolia. Those were placed in service in the January/February or December/January timeframe I guess it was. We also expect additional development in drilling and rework on other connected leases that will raise throughput volumes by the end of the year.

Three new production sources at Thunder Horse, Rigel and 17 Hands will begin deliveries in the fourth quarter, and we also expect another major new production source called Atlantis to be connected and producing by mid 2006. You will know that we begun to consolidate a 100% of the Enbridge income funds consistent with the adoption of variable interest energy accounting rules. Given our 42% subordinated common unit interest we are recording a 58% minority interest. Our earnings calculations are impacted and we have noted our balance sheet line-by-line changes in the news release as a result of that consolidation.

I should comment on foreign currency translation and its impact on our earnings. The weakness of US dollar continues to mildly weaken earnings from our US pipeline assets in the quarter. As most of you know although we do have a robust cash flow hedging program, which locks in project economics with one certain hedges. As disclosed during the quarter, these hedges generated incremental cash flow from $4 million that is not reflected in our earnings. This spot translation effect on earnings therefore represents a decoupling from the longer-term economic reality and represents a slightly frustrating course of accounting.

Finally, in regard to financing I'll recap some of the quarterly activity in regards to financing that we've accomplished in February, Enbridge files a $1 billion Universal Shelf Prospectus in the US and that provides us with ready and diversified access to fund future US or Canadian asset growth. Under that Shelf, Enbridge Inc. successfully issued its first public term debt in the US market. And we did so on attractive terms 300 million US ten-year senior notes that are 490 coupons. This proceeds repaid a US bank credit facility and will partially hedge the new Enbridge offshore earnings stream.

We also issued 250 million of medium term notes in Canada with a 5-year MTM at 395 to refinance higher cost term debt and commercial paper maturities. I think that's an overview of the quarter pattern and now I will turn it back it over to you.

Great, thank you Steve, and again my overall message for all of you really is that Enbridge is extremely well positioned within the industry, both with respect for organic growth opportunities and oil pipelining and increasingly in gas pipelining and gas distribution as well. We all know that acquisition evaluations seem very profitable at this point in time. However, we will continue to keep vigilant and disciplined eye on appropriate opportunities like the Shell deal and in combination the organic growth and that position opportunities really translate into a continued bright future for Enbridge investors. So, Colin I think that concludes our remarks and can we can open it up for questions.

Operator, first question please.

[OPERATOR'S INSTRUCTIONS] Karen Taylor, Nesbitt Burns.

Couple of clean up questions really quickly. Steve, I'd like to ask -- this one is for you. On the presentation on the quarterly numbers for Enbridge Gas Distribution for '04, can you tell me exactly which quarters we have included there -- is it the -- have we included what would have been the second, third, fourth, and fifth quarters from last year in that reconciliation, disregarding what the period would have been for September to December, I guess for 2003?

Scott will take a shot at that one.

In the reconciliation quoted on the webcast, it is the former second, third, fourth, and fifth quarters of EGD, in other words it is the January to December period, which is included in that reconciliation.

So and I just want to make it clear because when we were looking at earnings for fiscal 2004, we disregarded the fifth quarters and now we are disregarding the first quarter, in that sequence. Is that correct?

That is basically correct.

And, I just want to confirm Steve, you mentioned that your booking your back estimate of how the incentive following agreement will look on the liquid system, and that wasn't effect in the first quarter. Is that fair?

Yes, that's correct.

Can you tell me if how much of the dell present between last years numbers and this year's first quarter number. Is it attributable to the agreement versus the oil losses because the oil losses were quite high?

Yes, I think there is a couple of offsetting factors. The oil loss number is offset largely by the uptick in parents earnings brought about by the way that we assess the nickel split, $0.04 Canada, $0.01 US. So, you can roughly regard those as a wash and therefore the downturn or downtick quarter-over-quarter remaining is not a bad reflection of what we assumed.

Okay, and the enriched income fund had a $2.1 million, wanted to describe it as a special distribution of cash from the line to true up the capital structure. My understanding is that would not have affected earnings, it was only a cash item. Is that correct?

Yes, that's correct.

And, just lastly the corporate expenses that $15.5 million for the quarter. Is that the new run rate?

No, I would say that's a little bit light. It is consistent with Q3 and Q4 of '04, but if you look back to 2003, we were at $77 million on the year 2004; we were at $81 million. So, we still think that roughly an $80 million run rate is probably okay for the full year.

Okay, and I had one last quick question just on the Athabasca, and can you just account for the variant sales out, some of the new agreements kicking on that system? Can you just explain why and what?

That's -- without the baskets largely timing and slightly lower operating cost, we did have pretty favorable up cost in the quarter, but some of that is due to timing.

And, what do you mean by timing?

Timing of op costs and other things, and also we do have additional volumes on the system from the sign in of EnCana.

Right, so how much of the increase would come from timing differences on the cost side versus incremental revenues and earnings from volume?

I think we will have to look that up and split that out for the accounting. Can we do that maybe after the call?

Sure, that's great. Thank you.

Just one quick follow up on that is that in 2004 there was a bit of an extraordinary cost in the Athabasca System, which depressed earnings a little bit there. So, there is a bit of an effect from that as well.

Can you remind me what that was?

It had to do some leak costs in '04

I am sorry, sir what cost?

Leak. Minor leak cost, which were unusual.

Okay, thank you.

Marine Hoe, RBC Capital Markets.

Thanks very much. Just wanted to also follow up on the corporate charge there, can you tell us what the debt balance is, and I guess these unallocated debt balances at the corporate level were for the quarter compared to last year?

No, we can't. I can tell you though that our interest cost experience is pretty favorable. It has been -- due to some of the refinancing activity that I talked about and other things that are worked well for us in the markets. We are having pretty favorable experience with regard to interest cost, but don't have a split for you on unallocated debt.

And, also at corporate it looks like investment and other income has increased a fair note there. What is in that line item?

In that line we have a variety of items. One of the bigger ones is the interest income. For various subsidiaries we do charge that now at a bit of a higher transfer price on debt that would reflect the market cost if they would. So, there is a little bit of income in there, but that is not too indefinitely quarter over quarter.

Okay. Well, yes it looks like actually investment and income almost doubled, so something increased?

I guess we will have to get back to you Marine with that detail.

Okay. And other gas distribution, not a huge item but they increased over last year at $4.8 million compared to $2 million. Can you give us some color on that?

Scott, can you -- do we need to get back --?

No, no need to get back.

I think we don't need to get back you on line as well, Marine.

Sure. Now, going on, I guess in terms of the estimates of the impacts of the incentive agreement on the mainline, you said that we could assume that that the change year over year was largely due to the change in the booking and I guess the assumptions made on that agreement. It looks like that that's a lot less than 300 basis points, is that fair?

We really can't comment on that Marine, because we're in negotiations right now with CAPP, unfortunately. We hope to be able to be complete, and as Steve indicated, no -- not if there is any problem what so ever in negotiation, we used to have so many projects in front of CAPP right now, we haven't been able to get all of these deals negotiated in complete. But unfortunately, we can't comment on the implied ROE because of the negotiations being still open.

Okay. You did mention or I think it was you Pat, might have been Steve mentioned that one of the items was risk sharing, is that throughput risk or can you address that?

No, I can't address that, again unfortunately, because each individual item like that is under discussion and it wouldn't be fair to the negotiations for me to do that. I apologize, Marine.

No, that's fine. We'll just have to wait on that. Pat, you mentioned that you're getting interest from the refineries in Eastern Pad II certainly there is, I guess -- there has been information in the market about EnCana looking at industry-gaining conversion capacity, can you give us any sense of what other refineries are looking where the information's public, what other refineries might be adding that type of conversion capacity?

In terms of publicly stated interest, no I can't, but it's primarily the three Eastern Pad II refineries, that are expected to the be strongly considered in Canadian heavy crude, because of the pricing, Marine. And no public disclosures other than the intention by Premcor and in Canada to work together to see whether it makes sense to be able to take additional Canadian heavy crude there. I think it's fair to say though that that fundamental upon which that study is being based applies to the other refineries in the Eastern Pad II as well.

Okay. One final question. You mentioned with respect to the LNG progress that a federal and provincial joint review is being undertaken, I'm wondering -- can you just take us through the steps that we should be looking for, and perhaps, any critical events that we should be watching for in terms of progress in the development of that project?

The intent right now is to do a summer filing or filing this summer, with regard to the next steps on it, Marine. So you shouldn't expect to see anything other than of course the great news that we got with regard to the levy bout on this recently. So, we'll file in the summer and it will be a combination of BAPE, which is the Quebec-based environmental review agency along with CEAA and NEB. And then, we'll go through that regulatory process.

So, three filings for this summer. One with the Quebec-based environmental review, the NEB, and the last one was?

I stand to be corrected on this, Marine, and we'll get back to you if I am wrong in what I say, but I understand that it's one filing that will be able to be made to the three agencies.

Okay, and so that's the next step, and do you have any idea how long those reviews take? Have they provided any sense or is it just uncertain at this point in time?

I'd say it's uncertain at this point. I don't think that we are in a position to have really been able to work through that process with them and find out when they would expect they will have the decision force. I think it's fair to say though that we're highly encouraged by what we've seen happen. And as you know, the support of the local people on an initiative like this is so important and we have that, we feel very confident going forward.

That's great. Thank you very much.

Hi Marine, before you leave, I think we can knock off one of the the variance in other utilities. And that would include utilities like gas. And if you recall any of our quarter lag as well, so I thing in the release-.

Oh, is that rank of agents ? See your reconciliation Colin, on those --. Okay, that's great. Thanks very much.

Matthew Akman, CIBC World Markets.

Thanks, just wanted to revisit Gateway, and I think you mentioned may be a regulatory filing in '06, as things go as planned. Yesterday, I guess your main competitor was saying that they might have open season that could include pretty significant expansion later this year. So I am just wondering if we should be concerned with that your getting be just by timing here at all, and if not, then why not?

Your question being whether you should be concerned that we're being beat by timing, in other words the same may preside with expansion ahead of us? Is that what you are saying Matthew?

It does seems like their timelines are a little bit in front of yours, and I am just wondering whether that is something that we should be concerned about as a risk. It's the Gateway that they got fast signed up on the trends known expansion before you guys have a chance to even really go to market properly on Gateway?

I would say no, you shouldn't be concerned about that. And the reason why I say that is that I think it is pretty obvious from the review process that we have gone through with Cap on projects like Spearhead and the Exacon, Mobil Reversal and the discussions we have got underway in southern axis, the main line expansion, that there is a purity lengthy process to go through in order to get customers support for this kind of initiative. And this West Cost initiative is one that the producers are going to want to think very hard about before they make a commitment. And the indications that they have got is that they do need the big bulls stroke of an on new line light to Gateway line in order to be able to access the South East Asian markets that we have been out working very hard on for some time. And in fact I would suggest that it's almost the opposite that we are well out ahead of the competition, on that front. So I don't think for a minute that they would approve a project in the short term that would in any way endanger the bigger builder stroke that they have to take to have access to the markets that we need. They are going to stop think -- look at the alternatives and make a very well informed decision. So no, I don't think there will be any rush, rush, sneak it in, before the big project can be put in front of everybody.

Andrew Tuask, UBS .

Pat, if you could just give us some of your prospective on what we are seeing with the refinery transaction announcements recently, in particular the Bolero transaction and then just Marathon's intensions, with regards to Ashland and how that translates into your credit dispersion strategy?

Very difficult for me to comment on, Andrew, because it is 30 days with regards to the Valero deal. I don't see any thing at all in that deal that would change the dynamics of what we have going on. And for example, wouldn't think for a minute that they would change their -- you know, the expected delivery patterns and in fact I think it may even be a little bit of opportunism with Valero to be able to have access to this growing Canadian supply and positioning themselves with their refineries to take advantage of that. As you know it is the one area of growing supply in North America, coming out with the oil sands. So if any thing I would give a favorable nod there. And you know, the other issue that I think everyone is keeping an eye on is, what the intend may be around SITCO going forward. And again, I thank that Canadian crude has very firmly won that refinery as an amount has for a number of years now. And it's highly unlikely that any change of ownership would change that. It's going to be very hard to compete with Canadian crude that part in north. So I would for the -- any thing its a bit of a puzzle to bring to this. Andrew?

I would agree that transaction is potentially favorable given the on some of the refineries within the Midwest marketplace. Now from a pipeline in perspective, how do you tap into some of the refineries which currently don't take hay in crude, and particularly those in eastern Ohio and down at the Kentucky, and what's your strategy on that? These are some linkages, just the pipelines don't as such flow into your lines at this point?

The key thing, sit down and work very hard with the refinery customer to make them aware of what the alternatives are in terms of crude and also pipeline interconnection. We were working with each and everyone of them individually. We tried to ensure that we can maximize their access to a variety of crudes. So it is a -- it really is a lots of issue other and hard work to try to ensure that everyway possible from getting into those markets. And as you know, we worked very hard with the existing infrastructure and also greenfield opportunities to build if we can deploy the existing infrastructure.

I think, just to add to that Andrew, if you think back to '99 when we did the Toledo pipeline that is an example, exactly what Pat is talking about working with the refineries in Toledo, BP and Marathon at that time to convert to heavy oil from Canada. We then built the Toledo pipeline, which involved some new builds but also the lease of the line from Wolverine Pipeline. So putting those things together pretty creatively is that I think something that we really focused on and try to know every asset that may possibly made to be available.

Let me ask one final question just related to your offshore system and we recently read that Shell's reports and problems with its Mars platform. How do you see that affecting your throughput volumes within the Gulf of Mexico and you mentioned earlier on that it is going to be skewed more towards the back end for this year and then in particular any earnings impact you might see just coming up on Mississippi Canyon?

Well I think as Steve indicated overall that we feel that the majority of the issue here that we have been looking at has been timing issue and that as we are back in this and as we exit the year this year, we expect to be very much on target as those facilities some of which had some technical problems come back on stream. But also as a result of the number of new opportunities and we are very encouraged by what we see in terms of new development activity and in particular one recent transaction which we had indicated very strong continued interest in Gulf of Mexico which simplifies as being paid for assets there. So we will be and continuing to do a well-by-well analysis but expect as we approach year-end we are going to be very much on the targets.

Had your reference on the very good prices over the Star oil deal?

Yes.

Linda Ervigalus, CD Newcrest.

With respect to your offshore system, is a 100% of the financing represented on your earnings line for that asset?

No. We are basically, on the earnings line, we assume a 50,50 capital structure for the offshore assets and slow down in the Corporate line will be the interest costs associated with the fact that we finance the equity portion with debt. And so there, and so far we have got pretty favorable interest cost experience related to that portion. So I think that is where you see the offset.

And with respect to your Enbridge system earnings, is it reasonable to assume that the seasonality has not changed for 2005 within your assumptions because historically what we have seen is flat quarter-over-quarter throughout the year. Can you help me understand, is there any changes there?

Talking about crude system seasonality?

Yes, historically we have seen kind of a flat earnings pattern over the year and I am just wondering if your assumptions reflect any sort of changes to that seasonality or lack thereof?

No that wouldn't be a variable that we would have changed.

And can you comment a little bit more on your international investment opportunities? What are you looking at in terms of asset types, would it be more on the oil side, would it be more on the gas side, and what sort of geographies are you seeing more of the opportunities?

Okay. As you know then they were very pleased with the two liquids opportunities what we have got right now, the one in Columbia and the one in Spain, and therefore I guess our first reaction is to try to repeat that kind of success and you know with in liquids movements crude oil or refined product are really that kind of favorite for us. So that would be kind of priority one. On the other hand at the same time that I would say that it seems to be more gas pipeline development opportunities available right now and our geographic focus has been in Europe, primarily to a certain extent South America but we haven't seen any real good opportunities in South America so we are focusing mainly in Europe to use that base in Spain to look either at.expanding the oil or refined product pipeline networks that we're involved in are gas pipelining opportunities.

Now, you mentioned there is more gas pipeline development opportunity. Were you looking at greenfield or brownfield opportunities or you're looking at share acquisitions of more mature assets?

We are looking at both, but it's very difficult to get involved in the big greenfield development without a fairly strong presence on the gas pipeline side there. So, you know, our most likely entry would be acquiring a position in an existing gas pipeline, but again we are opportunistic and if we saw the opportunity to be involved with greenfield and to repeat the kind of success that we had in Columbia with their greenfield development, we would definitely be there.

Good. Now, in terms of looking beyond 2005, I know you have reaffirmed earnings guidance range of 3.20 to 3.30. Is there any change to your long-term target of 8-10% EPS growth in the competition of, you know, 5-6% organic, 3-4% acquisitive?

No, I think that is still a very fair assumption, Linda, and all I can I say is that particularly over the last quarter, while we have really pruned up the number of those opportunities and my level of confidence in that number just gets better every day. I have never seen such a slice of opportunities in front of this Company in all the time I have been here. So, we are very comfortable with that, and we realized that that is the rate, that is probably twice the industry average, but we're still well positioned, we think we can deliver on that.

Final question with respect to kind of your last quarter business lines. I am wondering given your recent divestiture of oil to gas, if you consider midstream gas processing in Canada to be less core or let's say in your non-east investments and specifically have you looked at monetizing the value of Aux Sable at all or expanding your presence there I guess?

Sorry. No, we haven't, and as you know Aux Sable is an integral part of the alliance pipeline and it is difficult to kind of separate the two in lot of ways. We have been very pleased with the recent performance of Aux Sable and there are a number of steps that have been taken now to give us a much higher degree of comfort. If you had asked me that question and I think you did, come to think of it, 2 years ago, I would have said, `Yes, we probably would like to move on Aux Sable if we can ever get it healthy we would like to access.` But we have taken a number of steps as you know with regard to heat content, control downstream, heat content requirement downstream, and also hedging strategies such that we no longer expect to see the same kind of downside risk on Aux Sable. We feel quite comfortable going forward that we can ride out the cycles that inevitably come in our liquids business. So, I think it is fair to say that we're happy with it today and because it is an integral part of the alliance operation, we don't have any intent to exit.

Now, would you consider increasing the scale of your midstream and gas processing operations outside of it or --?

Sure, we would consider doing that and I say that simply because as you know one of our real strengths is to gradually move along any value chain. We have done that so successfully starting with the gas distribution business, moving into gas pipelining. We've done it in the oil pipelining business, moving into and storage and hence whenever we see an opportunity that is closely aligned in the value chain, we are quick to take advantage of that. So, if we saw the right opportunity, we would, recognizing again that our objective is to be in fee for service kind of activities owning and operating the assets without commodity risk. And sometimes that midstream business carries more commodity risk than we are comfortable with. So, it would have to be assets that are basically fee for service for us.

Great, thanks, Pat.

Thanks, Linda.

Dominique Parker, Credit Suisse First Boston.

Just a couple of clean-up questions. The $30-40 million indication for your Shell offshore, that's in Canadian dollars?

Yes, that's Canadian dollars.

Okay. And so lower-end of the range for this year, but for next year would it be at the higher end of that range, in other words, about $40 million?

I don't think we are prepared yet to give you a range for 2006, but just sticking to the 2005 guidance and noting that we are expecting to be in the lower end.

Okay. And with the Garden Banks acquisition, was that included in your purchase price of the 613 million that you announced in November?

No, it wasn't. The Garden Banks acquisition just closed in the last six weeks or so and so we don't have -- that was not included in original and that's why the add-on acquisition that we hope to continue to pursue.

And can you disclose what the amount was for that Garden Banks acquisition?

We are under confidentiality with the seller, Dominic, so I really can't.

Okay and just another question with respect to Enbridge Gas distribution. Probably a question for Scott. The QonQ comparison, does that include that $26 million regulatory disallowance that happened in Q4 2003?

No. That would get recorded in December quarter 2003, Dominic.

What I mean is the reconciliation of QonQ. The way I understood that it was that the QonQ reconciliation and comparison is -- we are comparing Q1 2005 to Q4 2003?

No. The QonQ is the January through December period. So the item that you referenced was in the prior year, Dominic.

Winfried Fruehauf, NB Bank Financial.

I have proposed to ask a few questions with reference to the page numbers of your release but I do have another one that is -- does Enbridge propose to act as an aggregator for crude oil that could be shipped through Gateway?

Win, that is a consideration that we have had and may well be prepared to do in acting as an intermediary between the refiners and buyers and producers and the reason for that is that many of the producers don't want to enter into the rather lengthy discussions around the long-term supply arrangements that they might have with the refiner and they are looking for some company to act on their behalf. Our intent will be to work closely with them to see whether we can get refiner to producer direct discussions going and if not then we will consider acting in an aggregator role.

Thank you. The other questions are with respect to the release and I'd start on page four if I may, revaluation of oil losses. How large was the total amount? On which pipelines did most of them occur and if the Terrace surcharge had been in effect for the entire year, what would those losses have been?

Win, this is Scott. Let me take the last part of your question. The Terrace surcharge is unrelated to the oil loss. Calculate just on the Terrace nickel for a second.

No, I thought that too but I found it little curious that you sort of mentioned that in one breath more or less?

Well, I think the intention there was to imply they roughly offset each other.

I see. So, getting back if I may to the first question. How large were they in the quarter and where did most of them occur?

The total losses were around $2 million, Win, and as you know, oil losses come from really three factors - physical losses, revaluation losses and finally degradation and the latter two are affected quite a bit by crude prices and heavy light differential. So, but it is about $2 million which is not a bad number for --

And what would have been the number 1 & 2 pipelines where most of those losses occurred?

It is just on the mainline system. I don't think we can split it out by line, Win.

This excludes then any other lines you have in Canada?

Such as Athabasca for example, I think it is fair to say it's Enbridge System, the mainline.

And does the Athabasca System also run into this difficulty?

Not so much. It doesn't have nearly the complexity of the mainline system and so therefore it doesn't run into this issue. It's also much shorter system and has little anchorage point so long and so much less an issue on Athabasca.

Okay. Page 4, stated reparations on Frontier Pipeline. Is that a one-time event? What is to be made to? And if it's not a one-time event, how likely are those reparations to recur?

Yes. I mean, that's a historical item. That was -- first ordered us to make those four reparations on an over charge basically that we have at the head end of the frontier system. And so we were ordered in '03 and the first quarter of '04 to make those reparations and so, what you are seeing in the '04 numbers is just the last of that reparation taking place in the first quarter of '04 and that was about $1.4 million in Q1 of '04. So, that is now over and done with, but it did trickle into the first part of 2004, so that you do see some affect there.

Okay. Page 5, regarding EEP, what is it that doesn't make EEP sort of come together and show perhaps more or less quarterly improvements in its income contribution?

Well, there are a few things, I think, EEP would have talked about. But there was a mark-to-market hedge redesignation that affected their earnings to the tune of just over $8 million at the EEP level, and that's another -- I talked about `accounting`. I'll say you that's another one for sure and that is hedge is that really were redesignated with no economic impact, however, accounting rules FAS 133 requires you to mark those to market, and so there was that mark-to-market loss incurred at EEP and you are seeing that reflected up through here.

And what share, you said again -- if you can remind me that your booking there or including?

Well, we have about 11.5% interest.

Bu that number seems to vary a little bit, okay. And is that the most important reason why we have seen -- see this variance year-over-year?

I think, there is some FX effect as well, due to the relatively strong Canadian dollar in the first quarter and maybe you'll say that the government is seeing to that the Canadian dollar is not staying as strong in the second quarter. But, certainly in the first quarter there was some FX effect that would have affected the earnings being coming out from EEP as well. So, you could include that. We also have a slightly lower ownership interest income in EEP because of a dilution associated with an equity issuance that we didn't participate at EEP. So, I think those are the main factors.

Okay. The other one is on page 9. Looking at the deliveries in the two quarters, 2032 million barrels versus 2102 million, on what lines did you see most of the delivery erosion, and at what point do these -- if this continues, the decline deliveries, at one point would your earnings be affected?

Well, the Suncor fire and everything that has attended it is really the base reason, not only does the Suncor outage itself, but Suncor also supplies to a number of other operators. And in addition, there has been operating problems with some of others at Syncrude and Shell. So, the Athabasca, actual volumes would have been affected, however, Athabasca is throughput protected. Volumes on the mainline would have been affected but through the transportation revenue variance, we do have protection there. Most of the affect, you would have seen coming through at EEP.

Okay. So, that's another factor that has affected the EEP -- EEPs earnings?

Yes, absolutely, because EEP does not have crude oil throughput protection and its so very direct effect on EEP. Now, EEP also has tremendous performance from its GAAP assets that tended to offset that. So, as EEP would have reported the entire picture was not as bad as you might expect from that kind of a knowledge.

Now, I'm sorry, I have to go back to page 4. The offshore pipelines, do we know for sure now, who takes the volume risk for this entire offshore pipeline system, is it Enbridge, is it the producers or what is it?

Well, the way those contracts are structured and their life of lease, and so basically what that means is that any gas that is going to flow from a lease for its entire life is going to come through those offshore systems to the extent that, as we are experiencing right now, the ramp up in volumes due to down hole problems and other things to the extents that those volumes are delayed, we do see that effect and you are noticing that in the offshore in this particular quarter. So there is always a timing issue when you ramp up new production, but I think the key is that every bit of gas that comes out of a given lease will flow through these lines, sometimes little later than expected. But that gas is going to flow through the lines.

Thank you, the last question finally, you must be happy. On page 10, if I take gas, sales revenues and the cost of gas and calculate a gross margin, I get if my numbers are correct a $158.2 million the first quarter 2005 versus a $114.9 million a year ago. If that is indeed the correct way of calculating a gross margin, what accounts for this very large difference?

I think we will have to come back to you on that one, Win.

All right.

That would be okay?

Certainly, and thanks very much for your patience.

Bob Hastings, Canaccord Capital

Two general questions. The first one is the -- there is a lot of construction activity going on in Alberta and we've seen these kind of periods before we've seen huge cost increases accompanying those, are you seeing some evidence of that now? We haven't seen any changes to any of your construction. Do you see pressure coming there and do you think that will have any impact on the projects?

At this point, we don't think so Bob. We are very much aware, of course, of the increasing construction cost here recognized that in the pipeline business, we basically call on a little bit -- quite a bit different construction crew and a more transient group where for the challenges in Alberta are due to the localized nature of the construction work being primarily in Fort McMurray in Edmonton. So it has the limited skilled workforce to call on, whereas the pipeline construction crews, they tend to live and work all over North America and can be rallied from any point for a major project. We have gone through in some detail our estimates recently to ensure that they are up to speed not only with regard to this labor cost, by current steel cost and we do feel comfortable with the level of estimate that we've got out there, and we will continue to refine those as we go along. But we are comfortable with what we have done to date.

So, the other major oil pipeline will remain nameless seeing increases of 30 to 40% on their project you don't think impacts you?

Well, it depends on where their original estimates started from, and it might have been 30% increase from their original estimate but we are comfortable with our original estimate. We had built that kind of factor in.

Okay, and that just happened from the time that the annual report came up, the first quarter report came up by the way. But anyway, and in the other comment the question was the -- I noticed in lot your comments regarding ITA and some of the other projects you are looking at involve taking on some additional risk, and I know you have done that from time to time for projects such as Vector and -- but I sort of sensed for a while there that you wanted to sort of not take on too much risk. Can you give us just some comfort, you know, sort of how far you are willing to on that risk profile to get the higher ROE?

Yes, first of all I don't find the two statements inconsistent at all and that taking on a little more risk for us is still operating at a very low risk profile, and so we of course have looked at each and everyone of these risks and are comfortable with those that we are taking based on our experience, our operating experience and you know, for example our ability to meet some of these performance metrics, we are very comfortable with the level of expertise and operating experience that we are going to be able to do that, and you know any of the issues around construction risk or pipeline integrity risk or whatever we have got the experience behind us to feel comfortable in taking them. But I -- as you know well, Bob we are still very very low on the overall risk spectrum.

Okay, and I just wanted to ensure that you weren't going to be moving too far out there?

No we are not. This is a low risk investment and we don't feel the need to move out there. As you know, we very nicely resisted that risk during that temptation, I guess you could say during the marketing and trading run up a few years ago. We stuck to our knitting and to the lower risk investment, and that's where we intend to stay.

Great. Can you clarify how much you may be have invested in all your activities on looking at projects that may be on your balance sheet?

We are expensing those cost Bob, and until we have a very strong season of support and in indications from shippers the projects are going to go, we expense them. So, we don't carry any significant balance sheet cost associated with that off.

Karen Taylor, BMO Nesbitt Burns.

Just two really quick follow up questions. Can you tell me what percentage of your total debt is a short versus long term, short term versus long term?

Yes. We operate in a policy range of 15 to 25% and we are fitting at about 22 right now Karen, floating.

And you anticipate lowering that when you get into mid-to-potentially lower end of the range towards the year your going to stay here?

Actually, we been in the 20 plus percent range, never more than above 23 for the last year or two, and quite honestly we fund very effectively on the short end and so we looked to optimize around that. We watch very closely to see what we should lock in, but I think we are entirely comfortable within the range that we are in and I don't see a need for us to consciously drift lower for the 15% end right now.

Okay. And just, I don't know who this question, may be it's for Pat on CLH. And is there any update on what the Spanish government intends regarding ownership interest, there where some talk about reducing ownership interest on a maximum names basis to size percent and that issue didn't resolved or otherwise didn't define such that Enbridge would be exemptive?

It hasn't been otherwise defined. The reference that I think you're making with the newspaper article that implies that the shipper owners might have to sell down to a maximum of 5%. There has never been any indication that the non-shipper owners, the independence like Enbridge would have to do so on, in fact in meetings that we've had with government officials, we've been assured that, that is not the intense. The concern is more around someone that has a shipping interest and also a major equity position in the CLH operation. So, that may impact even or provide an opportunity for us if we could some how go through the current allowed cap of 25% has been independent, the larger would apply, and the independent should be able to go even beyond the 25% level, because we don't have any shipping interest. So, we are working on that, but if anything we think it will provide an opportunity on the stress.

So, can exactly the desire with international offset, is that possible that you could increase your interest in CLH and then qualify that they are project are not?

I'd love to, yes. I would really like to be able to do that, but I wouldn't hold out a lot of hope, because right now there is an existing 25% ownership counts there.

Sam Kanes, Scotia Capital.

Let me come back to the risk profile of the offshore sell out for a minute. You have life of lease, obviously with the contracts you signed for gas production from various fields, what happens in a case of, I guess having a major short fall from the expectation on that field such as say that issue with right now or Alaska or other places where there has been a major hick up or do you have so many hundreds of fields that doesn't matter?

I think you did on the key points at the end there Sam. There is so many new developments in fields and wells, this of course is a much more broadly defined developed fields and five different corridors that we operate through. So, we are going to have some disappointments along the way. We are also going to have some very positive surprises with operations that exceed their expectations.

Just extend that over. What happened to that situation?

Well, if the volume fell off then the volume in our system will fall off.

If you take the risk of that volume metric disappointment come in the end. Because it's 40% decline rate there. Is it a similar 40% decline rate here for particular fields.

I think you're talking about the shallow water decline rate and on the Shell preferred regulated area. That decline is there just because those were the first areas that we've explored a lot of years ago. But there's no such decline rate in the deep water.

For which you said, it is?

I don't have a number for you, Sam. But I know that the number you just referred to is clearly the more matured Shell.

Okay. The Shadow oil deal the implications is that -- was that a neighboring pipeline premium is what you paid or they are sold as to negotiations levels, which -- in the case and or your view of the opportunities that Shell didn't see? What's that all to you? Do you know who is compared to your particular offshore assets?

For this -- their acquisition is a not pipeline asset that was producing assets. Our expiration leases in assets. My only reason to mentioning it was that it's good to see companies making big investments in Gulf of Mexico, because the infrastructure position we got there. So, we're pleased to see that.

Your offshore infrastructure and it had 90 days with it -- seen notice of Kaiser announcing and offloading a few LNG tankers somewhere offshore in the Gulf of Mexico. That wasn't through your systems I take it, but could it be -- and have you talked with Kaiser as it's his offshore offloading bridge he's got, the LNG bridge?

First of all, no, it wasn't and I'm not aware of this -- had any discussions with Kaiser, Sam.

Conceptually it seems that what he is trying to use is infrastructure like yours now to do just that kind of all offshore?

And you know, we are looking at a couple of opportunities and where there are planned and permitted LNG facilities in the Gulf with marine studies underway right now before the projects proceed that are very close to the pipeline infrastructure that we operate. And it's a pretty logical lead to say that the things to do would be the tie those volumes into our pipelines. So, we are working with the couple of the LNG project performance right now to provide the transportation infrastructure for them.

Okay, still with LNG for last minute or so. The vote, it's final, it's academic I guess, but how is the split was it -- we didn't see any detail on it?

I'm not sure that we're allowed to say. It was very very strongly in favors and wasn't even closed and I'm going to not give you the exact count, because I'm not sure that we're allowed to say that. But it was very strongly favored.

It was very strongly favored then you start capitalizing your LNG development costs they announced?

We have still got the regulatory process to go through but you know what we think about it.

Last question from me. May I have on your slide back -- I don't have access to it at this moment but you elevated your base case and high case for oil production. You mentioned that in your later study. Is that publicly available yet? What relative levels are those?

We -- our normal process is that we collect this information on a well-by-well, project-by-project basis from the producers and then what we do is sit down and review it with the producer community. And I don't believe Colin that we would have taken that public -- usually then becomes part of our presentation. Once we've got producers sign up on that, but I don't think you have as yet.

Obviously in the near term in the next couple of years, Sam, those low and high spikes they are essentially steady state with those projects at lead times. The older years reflect all these -- that major project announcement that we started to factor in.

We'll find out when we're able to make that public, Sam, and make sure we get it out to the investment communities as soon we can.

Thank you.

Marine Hoe, RBC Capital Market.

Thanks very much. Just wanted to come back to the expensing of -- expenses supposed being capitalized and wondering where is that occurring in the liquid pipeline segment? I don't see any other category there that might include the expense. Was that happening at the corporate level?

No. To the extend there are business development costs being incurred in the business units owing that they won't quantify for deferral, they are being expensed within the business units.

So, they would be in occurrences and liquids -- that would be in SEDAR pipelines and other then, Scott.

Yes. That's correct. That's what we do.

Okay. And is there anything being expense then in terms of business development -- at the corporate level?

There are some minor cost savings expense there as well.

But, that's pretty minor?

Yes, they're not significant.

Okay. That's it. Thank you very much.

Winfried Fruehauf, NB Bank Financials.

Thank you. On the offshore pipelines, somebody mentioned that your permanent financing is not in place as yet. Assuming it were in place, would your offshore pipelines have, sort of, their own financial statements, if you wish, they would then assume whatever corporate's debt has been raised, they would assume that debt and look after their own equity financing?

I don't remember saying that permanent financing isn't in place because we really did with the US $300 million-debt issuance, that really was targeted to refinance the acquisition facility, Win, so that's pretty well behind us and now you will see, as I mentioned earlier, the interest costs associated with that are going to be reflected in the corporate line, going forward. So, I don't think we are looking at a separate P&L for shore, offshore or anything like that or the offshore assets.

I see. Okay, thanks very much.

Win, if I could just come back to a question you raised earlier with respect to the Gas Distribution segment. If you go to the segment at earnings between quarters 2004 and 2005, you'll see that there are variances that are really accounted for by the quarter lag issue. The 2004 numbers remain on a quarter-lag basis because we haven't restated 2004 at the consolidated level. Of the 2005 number is the January to March, so what you're really seeing in gas distribution and services on that segmented table is the October to December 2003 period, B to B be January to March in the Q105 table.

Okay.

Okay? So, as it relates to margin, so that's probably something that could be followed up after the call and --, but that I think is accounting for a lot of it.

Okay, thanks. And I shall.

This concludes our question and answer session. Please proceed to closing remarks.

Thanks operator and thanks everyone for joining us. That concludes our call and again thanks for your interest in Enbridge. Have a great day.

Thank you for your participation in today's conference. This concludes the presentation. You may now disconnect. Have a great day.