恩橋 (ENB) 2006 Q1 法說會逐字稿

Good morning ladies and gentlemen and welcome to the Enbridge, Inc. First Quarter 2006 Financial Results Conference Call. I would now like to turn the meeting over to Mr. Bob Rahn, Director of Investor Relations. You may now proceed, Mr. Rahn.

Thank you, Michelle. Good morning and welcome to the Enbridge, Inc. First Quarter 2006 Earnings Call. With me this morning are Pat Daniel, President and Chief Executive Officer, Steve Wuori, Executive Vice President, Chief Financial Officer and Corporate Development, Richard Bird, Executive Vice President of Liquids Pipelines and Colin Gruending, Vice President and Controller.

During this conference call we may refer to or speak to certain forward-looking information. Statements made with respect to forward-looking information are subject to a variety of risks and uncertainties pertaining to operating performance, regulatory parameters, economic conditions and commodity prices. A more full discussion of these risks is included in our filings which are publicly available on both the SEDAR and EDGAR systems. This call is webcast recorded and I encourage those listening on the phone lines to view the supporting slides which are available on our website at www.enbridge.com. A replay of the call will be available later today and a transcript will be posted to our website shortly thereafter.

When we move to the Q&A session, could you please limit your questions to one follow-up and jump back into the queue. I would also remind you that I will be available after the call for any follow-up questions you may have. At this point, I’d like to turn the meeting and the call over to Mr. Pat Daniel.

Thanks, Bob. Good morning everyone. Thank you for taking the time to join us and we hope to see at least some of you at our Annual General Meeting this afternoon here in Toronto.

As we reported earlier today, our adjusted operating earnings for the first quarter were $209.5 million which is $0.62 per common share and exceeds the $0.61 consensus forecast that provides a very solid basis for meeting our full-year adjusted operating earnings guidance of $1.65 to $1.75 per common share.

Our liquids business had a very strong quarter and I’m also very pleased with the results reported by our affiliate, Enbridge Energy Partners, whose adjusted quarterly net income was up over 50% from the year before. Steve Wuori is going to elaborate more fully on both of those in just a moment.

The level of potential new infrastructure investment existing in the North American Energy Sector to date really is unprecedented and Enbridge is will positioned to capture a significant portion of that opportunity going forward. Most of you, of course, are aware of the projects that we have under development so what I would like to do for a few minutes is focus on some of the key updates since our January call; and, of course, I’ll start out with the crude oil pipeline business where we’re most active.

We have the potential for $12 billion worth of organic projects over the next five years and we are now in full execution mode to ensure that these projects are in service when they are required by our customers. Today, we announced plans to move forward with the construction of the new $250 million contract terminal facility at Hardisty, Alberta.

Demand for terminal services such as this has been growing significantly over the last several years and this has translated into a significant new growth platform for Enbridge. We currently have 15 million barrels of capacity under long-term contract and another 30 million barrels under development; so a very significant level of activity.

Within our portfolio of potential projects, contract terminals account for upwards of $1.5 billion of investment and half of that is slated for the next two years. These projects, as I’m sure you are aware can be constructed and put into service in a relatively short period of time. They come in relatively smaller, bite-size increments and they provided us with a solid baseline of investment to our planning period.

Moving to the pipeline side of the crude oil business, as expected on March the 2nd, significant volumes of Canadian crude began moving to the Cushing, Oklahoma hub by our Spearhead pipeline. Heavy oil differentials between Chicago and Cushing have narrowed recently for a number of reasons including having this access to an alternative market.

Throughput is a very strong indicator of the value the shippers are assigning to the ability to transport crude to Cushing and the value of this line and deliveries into Spearhead have been in excess of the initial contract and capacity of 60,000 barrels a day and nominations for May are in the order of 96,000 barrels per day, about 76,000 of which are destined for Cushing; so very strong support for this initiative.

Spearhead capacity as you may know is approximately 125,000 barrels today so we do still have some capacity available and it can be fairly easily increased up to 190,000 barrels a day by adding relatively low-cost pumping power; so very good future potential for growth and expansion on that line.

On April 20th, Exxon-Mobile announced that it had commenced deliveries of Canadian crude to the U.S. Gulf Coast through the reverse Patoka Texas pipeline. As you know, Enbridge encouraged the development of this project and like Spearhead a portion of the project costs have been rolled into the Enbridge Mainline Toll and it also reminds you that both projects will pull volumes through our systems. So both the Exxon-Mobile project and Spearhead do pull volumes through our mainline system.

On March the 23rd, [Burke] approved the tolling settlement for our $1.3 billion U.S. Southern Access Expansion which will provide an incremental 400,000 barrels per day of capacity from Edmonton through to Chicago and, as you know, addresses the current bottle neck in our system between Superior and Chicago. Field work has commenced on that project and capacity additions will be phased in over 2007, 2008 and 2009. CAPP, the Canadian Association of Petroleum Producers was supportive of our subsequent proposal to upsize the pipe diameter from 30 to 36 inch in order to accommodate the future low-cost expansion and that will provide an additional 400,000 barrels per day of capacity from Superior into the Chicago hub.

Now we’ve anticipated for some time that additional capacity to U.S. markets over and above Southern Access would be required. And our recently revised supply-demand forecast now shows that oil sands production could reach 2.8 million barrels per day by 2015. And that’s up from the 2.4 million barrels per day that we had previously forecast. So it’s clear that additional capacity is going to be needed; and in light of this we had decided to further increase the pipe size of Southern Access to a 42 inch diameter line to ensure that low-cost expansion capacity will be available when our customers need it.

The next logical expansion into the U.S. is the $1.6 billion - and these are U.S. dollars - Alberta Clipper project which we announced back on February the 1st. Alberta Clipper will move further 400,000 barrels per day of initial capacity from Hardisty to Superior. So it would be the next logical step in our expansion.

The downstream of Chicago we’re very well advanced in discussions with CAPP with respect to the Southern Access extension. And this is a 350 million U.S. project which will provide 300,000 barrels per day of initial capacity from Chicago into the Wind River and Patoka Refining region. Our objective, of course, is to finalize negotiations and design work in the second quarter of this year in order to meet the plans and service dates of late 2009 or early 2010.

Now we’re also moving forward with initiatives to further penetrate the U.S. Gulf Coast and Eastern [Pad] two markets. And piece by piece we’re putting in place a comprehensive pipeline network with the flexibility and supply diverse to U.S. refining markets throughout the U.S., Midwest, the Mid-Continent and the U.S. Gulf Coast all at the lowest available toll. And as you know, we are a very low-cost operator due to the economies that stay on our system.

Expanding and extending our mainline system into the U.S. goes a long way in eliminating many of the constraints on oil science production and pricing. But in our mind, it’s not enough; we do need further expansion beyond these expansions into the U.S. Our view is that producers need access to new markets that are independent of the pricing dynamics of the U.S., Midwest in order to completely eliminate the constraints that they currently face. And this is really where our Gateway project comes into play to provide access to the California and Far East markets for crude oil. The successful completion of the Gateway open season supports our view that this is a much needed addition. Interest was oversubscribed and response we plan to upsize the proposed diameter of both the crude and the condensate lines that we had originally planned for Gateway.

Although we haven’t made any recent major announcements with respect to Gateway, we have been very busy and we’re continuing to work now to finalize, press them into agreements with interested shippers as well as advancing through the Aboriginal consultation process; and it’s our objective to file an application with the NEB by the end of the second quarter in order to meet the mid-2010 in-service date.

So that’s a run-through on progress made since the beginning of the year on the heavy oil side of the business. Let me now just turn for a minute to gas pipelines and to some other new growth opportunities.

On the gas side we continue to replicate really what we’ve been doing on the liquids side of the business and that’s to focus on developing pipelines that deliver customer value and improve customer net-backs. At the Enbridge Energy Partners level, field work has now commenced on the 530 million U.S. expansion of the East Texas Intrastate pipeline. As you know, we refer to this as project Clarity. The 700 million cubic feet per day expansion will provide much needed access to markets in Southeastern Texas and the pipeline will also provide access to a number of interstate pipes that service major markets in the U.S. - Northeast and Southeast United States - and it’s this broader access that dramatically improves pricing for producers. The project will be completed in stages and likely will be in service in 2007.

At Enbridge Off-Shore, the U.S. $125 million Neptune Lateral Project is on schedule to deliver about 290 cubic feet per day of gas and about 50,000 barrels per day of oil into the Green Canyon Corridor in late 2007.

The move to other growth opportunities - the completion of the environmental screening report for our 200 megawatt Ontario Wind Power Project represents a very significant step forward in moving to the construction phase and this is in order to meet an in-service date of early 2007 for that wind farm. It’s our further intent to grow the wind power business beyond that; and to that end we have entered into a partnership with Sequoia Energy to pursue between 400 and 600 megawatts of wind-powered development in the province of Manitoba and we’re in the early states of that development.

So that concludes my opening remarks and a quick run-through on progress that we’ve made. I’ll now turn things over to Steve Wuori who is going to review the quarterly results in a little more detail. Steve?

Thank you, Pat, and good morning everyone. I think overall the first quarter of 2006 results reflect solid performance in the business. Reported earnings applicable to common shareholders were 190.9 million for the three months ended March 31, 2006 or $0.56 per share compared to $220.6 million or $0.66 per share in the first quarter of 2005 before any adjustments.

Elimination of the quarter lag reporting for the Gas Distribution Utilities has simplified comparisons of quarter-over-quarter financial performance. After removing the financial impact associated with warmer than normal weather and the previous year’s dilution gains, adjusted earnings per common share for the quarter are $0.62 compared with $0.61 for the first quarter of 2005.

I’ll now turn to the various business segments starting, again, as Pat did with Liquids Pipelines. The $13.3 million increase in performance is attributable to a number of factors. First, on the Enbridge Mainline system, we have improved SEP II expansion utilization and ROE. We have additional earnings from the Terrace expansion, additional earnings from the new Incentive Tolling Settlement and also a decrease in oil loss costs from the unusually high level experienced in the first quarter of 2005 and that resulted in lower operating costs for this quarter.

Increased earnings in feeder pipelines reflects contributions from the Olympic Pipeline interest which was acquired on February 1st as well as the Spearhead Pipeline which commenced operations on March 2nd, as Pat mentioned.

In gas pipes, the Alliance, U.S. and Vector Pipeline contributions were affected by the increased strength of the Canadian dollar this quarter when compared to the first quarter of 2005. The decrease in earnings at Enbridge Offshore Pipelines is largely throughput related. We expect that throughput will be back to pre-hurricane levels by the end of the second quarter and current deliveries to the beach are approximately 90% of pre-hurricane levels.

In strong suit investments, Enbridge Energy Partners had a very strong Q1 as Pat noted. Both the liquids and gas segments in the EEP contributed to the increased earnings. Throughput volumes on the Latex system driven in part by a return of normal sun core delivery levels drove increased operating income in the liquids segment. On the gas side, increased performance was due to both increased volumes and improved processing margins.

The first quarter, 2006 results also include a $2.7 million net to Enbridge non-realized mark-to-market gain on derivative financial instruments used [inaudible] that don’t qualify for hedge-accounting treatment. In gas distribution and services we certainly have warm weather, significantly warmer than normal weather experienced in Ontario and that resulted in $125 million decrease in reported earnings in the gas distribution segment when compared to Q1 of 2005 for EDG specifically. Net of weather impacts and prior year dilution gains, the decreased earnings in EDG are due also to lower allowed ROE of 8.74% this year compared to 9.57% in 2005, as well as increased operating and maintenance costs. And these are somewhat related to timing.

Reported earnings at Aux Sable are lower reflecting the terms of the output agreement with BP. Aux Sable now receives the fixed fee for the output of the plant that eliminates down-side risk in addition to a sharing in the fractionation margin upside. The amount of sharing is determined on an annual basis and therefore any resulting revenue recognition will be recorded in the fourth quarter of this year. I will say, though, that fractionation margins were strong during the first quarter so that is good news. The explanations above really account for the majority of the variance from Q1 2005 and the reported earnings from the gas distribution and services segment overall.

Turning to international, increased earnings are primarily the result of strong demand for storage services at CLH and continued strong throughput levels that we estimate. The storage services certainly, given the value and demand for refined products in Spain, the storage service utilization has really come up and that’s driven a lot of the performance this quarter at CLH.

In the corporate segment, the increase in corporate costs reflects higher interest expense associated with the refinancing of short-term commercial paper with longer-term fixed rate debt as we take advantage of the yield curve to lock in attractive rates for the future.

That concludes my overview of the results for the quarter and I’ll now turn matters back to Pat for concluding comments.

Thanks, Steve. The growth opportunities before Enbridge really are very compelling and as I indicated, the pieces are coming together as we had planned. Spearhead, the Exxon-Mobile line reversal, are moving volumes and of course Southern Access is advancing into the construction phase; so those are all very positive moves for our customers. In the Oil Sands Region, we are proceeding with the Surmont and Long Lake laterals as well as the Waupisoo Pipeline project and for the first time today I’ve really profiled the contract terminal business for Enbridge and it is a significant new growth area for the Company and one that you’ll be hearing lots more about in the future. We will continue to very aggressively pursue market extension and expansion initiatives to provide the most effective services to our customers. And, of course, at the same time we’ve got all of these opportunities on liquids business, we’ve seen unprecedented growth in North Texas and East Texas - two areas of significant involvement for us - some very good opportunities in the Gulf of Mexico down the road and, of course, our continued strong growth in the distribution business here in Ontario.

So that concludes the remarks that we had today and at this point we will open it up for questions.

Thank you, sir. [OPERATOR INSTRUCTIONS] And our first question comes from the line of Linda Ezergailis of TD Newcrest. Please proceed.

Thanks a lot. My question really revolves around your growing crude oil storage business. I just wanted to get a better sense of what sort of returns your Hardisty Terminal might be attracting given that your average contract duration is only seven years?

The approximate returns are in the range of 12 to 12.5% return on equity, Linda.

Okay. And then in terms of potential for cost overruns, I’m assuming -- would Enbridge be at risk and what have you done to mitigate that in terms of any initial discussion with suppliers in terms of contracting or anything?

I’m going to ask Richard Bird to respond to that, Linda.

You’re right, Linda, on that particular opportunity, that is full capital cost risk to Enbridge. We’ve gone a lot further down the path of cost estimation and getting firm prices from suppliers than we might otherwise do and that’s part of the reason why this project has been a little bit long in coming; but we think we’ve got the cost exposure reasonably well contained and reasonably well [rounded] for in this project.

And your letters of intent, when will they be firmed up?

Our objective would be to move those -- everybody’s in a big hurry to get the story in the [inaudible] so our expectation as we move forward with binding agreements, storage agreements, over the course of the next month to two and launch the construction in June/July.

Okay. And I may be -- this is the first time we’re hearing about a 1.5 billion of opportunities related to 30 million barrels which I’m assuming the Hardisty Terminal is a part of. Can you provide some more color as to whether they are upstream, downstream and what sort of advantages Enbridge has whether it’s land related, relationship based or whatever in terms of capturing those opportunities?

Sure. Well, it pretty much covers the spectrum from upstream all the way through to downstream. We have got an expansion -- let me start in the downstream end. We’ve got an expansion underway at the Cushing Terminal in the U.S. As you know it’s the biggest crude oil terminal in the U.S. We have expended terminal facilities going in to Superior, Wisconsin. We have this expansion - very significant expansion - at Hardisty. We already operate the largest terminal in the Athabasca Region and we’re expanding that facility. So it’s really everywhere from Fort McMurray through to Cushing. The advantages that we’ve got, of course, the prime advantage is that this terminaling is all interconnected to our mainline system in one way or the other and being the main conduit of crude oil in North America, it’s logical that customers are going to want to connect to that.

We do have some advantages as a result of land in the area as well because we are already an existing operator and with tankage, there are some real synergies with the infrastructure around tankage. Often the piping and pumping infrastructure is a big part of the cost. So adding additional tanks to an existing facility is cheaper than building a grass-roots facility.

And can you maybe split up for us the 1.5 billion between EEP and Enbridge, Inc?

Richard, could you --?

Yes. It’s up roughly 100 million - sorry - 1 billion within Enbridge and the balance within EEP.

Great. Thanks. I’ll jump back in the queue.

And our next question comes from the line of Sam Kanes of Scotia Capital. Please proceed.

Thank you. I was thinking of making a decision to pass, was it a function of the return? Was it focused here on terminaling as just mentioned? What was behind that?

On withdrawing from [Gorway]?

Yes.

Well, the original agreement that we had on Gorway had expired, Sam. We had originally gone into an arrangement with the site people to develop that. We had bid into the Ontario Power Authority’s Request for Proposal. The project had been rejected and our agreement had expired; so it was a case of not being able to effectively renegotiate the position in the new project and we’ll now turn our attention to other opportunities there.

Within Ontario or anywhere in general within North America?

In Ontario. We’ve indicated before and are still adamant on this, Sam, that the only area where we have any significant competitive advantage over anyone else would be in our franchise area where we have capability of gas storage and infrastructure capabilities. So it would definitely be within the Enbridge Gas Distribution franchise area.

Thanks, Pat. I’ll jump back in the queue.

And our next question comes from the line of Karen Taylor of BMO Nesbitt Burns. Please proceed.

Thanks. I just had a couple of numerical questions. Steve, can you break down the 13.3 delta in the liquids segment between SEP II, Harris, CITA and then the oil losses?

I don’t think we’re prepared to do that and get that granular, Karen. I think that the factors that I mentioned in terms of the overall increase are all playing up. We’ve got improved ROE on the SEP II, remember it has a sliding scale of ROE and so on?

Mhh-hmm.

But I don’t think we’re going to attempt to carve up into buckets that small the individual components of the increase.

Well, let me ask the question in a different way, then. Is this sustainable? We heard in the EEP call that the oil losses might not be - so we had a fairly positive number, in fact it was a non-issue in Q1 for EEP - but they clearly suggested that there would be oil losses in the remaining three quarters of the year suggesting that some part of that delta is not going to be sustainable.

Yes. Well, certainly you put your finger on one of the major issues in terms of the swing at the Enbridge, Inc. level. The oil loss experience -- we have new measurement processes in place and I think the whole oil loss picture - for those that are wondering about all this oil loss, it really is costs mostly related to degradation of product rather than losing oil. But the new measurement processes and things that we’ve worked with hard over the last year have really improved the oil loss picture and we think that it is now sustainable in terms of the experience we’re having right now. It’s hard to say in a single quarter that that’s exactly the oil loss experience we’re going to have; but basically, that represents the biggest swing from Q1 of 2005 in terms of the factors that I talked about.

So I think that we would expect to see performance like this but I would not put a pin in it to say that you can multiply this by four to get the new rate for the price of the main system.

Okay.

I think I can elaborate a little bit on that, Steve, and actually Steve mentioned degradation. We’ve made a lot of progress in the last while on all three components of oil loss - degradation, reevaluation and also physical losses; and really, I think, our performance going into the fourth quarter of last year we were already starting to show pretty significant improvements. So if what was said on the EEP call was that we will continue to experience some oil losses, I think that’s a fair statement. I don’t believe we will have obliterated them; although I sure hope we’ve obliterated the new valuation component to that; but in terms of improved performance I would expect it will continue to see significant quarter-over-quarter improved performance on oil losses in the second quarter and in the third quarter. By the time we get to the fourth quarter we will have recognized in the fourth quarter of last year pretty significant low-level of oil losses; so you may not see that same delta quarter-over-quarter in the fourth quarter.

Okay. And the oil losses, obviously they are very much related to the new ITA, so when you’re talking about lower degradation, lower evaluation and lower physical losses that would also then spin into the ITA returns, does it not?

Revaluation doesn’t -- revaluation losses are outside of the ITA but physical and degradation are inside.

Okay. Can I ask about the foreign exchange and then I’ll get back in the queue. What was the total foreign exchange effect on earnings in Q1 and what was the difference between your average and realized effects in Q1 ’06 versus Q1 ’05?

Steve, you want to take that?

Yes. I think the effect in the quarter was about $0.01 per share of drag because of the strengthening Canadian dollar all in all and also the Euro effect coming from CLA. So in total I call it just about a penny a share. I think it’s just a little bit under that.

So the second part of your question, Karen, was --

I’m sorry. If it’s not -- well, what was the average realized rate from your perspective during the quarter versus Q1 ’05?

Karen, it’s Colin. On the U.S.D. rate, averaged about 1.17. Of course [ascends] is hedged at about 1.40. And the Canadian/Euro exchange rate is 1.39.

And that was all for Q1 ’06?

That’s correct.

Okay. Thank you.

And our next question comes from the line of Maureen Howe of RBC Capital Markets. Please proceed.

Thank you very much. Just coming back to the breakdown between the liquids, you didn’t mention the SEP II triggering the ROE in the MD&A so if we’re looking at the Terrace, the tolling, the ITS and the oil loss, and there was only 100,000 barrels per day of pick-up quarter-over-quarter, I’m assuming that the oil loss and the tolling, the ITS, are really the vast majority of the 13 million?

Rich, if you want you to --?

Yes. Well I think you’ve correctly run the inference that the smallest of the four factors that Steve mentioned would be the SEP II effect. The other three factors would be roughly comparable in size and there would be other factors beyond that that Steve didn’t mention that would account for a small portion of it; but I wouldn’t single out any one of oil losses, increased Terrace performance and the metrics contribution as being materially different from one to the other.

Okay. And I’m wondering, Richard if you can just perhaps explain the revaluation issue and how it’s being resolved?

Well, the revaluation issue results from the fact that we view on the system end up with positions both short and sometimes long with respect to crude oil. For example, on the degradation side we generally convert light crude into heavy crude which results in us - if we don’t do something about it - having a short position in light which we owe back to shippers and a long position heavy. And our objective is to close those positions out as quickly as we possibly can so that if there is a change in the price of light and the price of heavy and the differential between the two, we don’t get impacted by that change. But if we do hold a position across the month-end and there is such a change in the prices, we could either make money or lose money on that position.

Our objective is to take our overall position to zero and our position in individual commodities to zero and that’s been a bit of a challenge operationally but it’s something that as crude oil prices have expanded and as the volatility has expanded and we’ve experienced some significant revaluation losses as a component of overall oil losses that we started paying more attention to; so we put in place -- one major change that we made is we put in place something called an automatic balancing system where rather than having to undertake and negotiate commercial transactions to eliminate those positions, we have an automatic settling with shippers to eliminate those positions to a significant degree at a predefined formula price. And it seems to have been quite effective. We’ve got those revaluation losses down very significantly.

So is it fair to say, Richard, that there’s been a material change in Enbridge’s exposure to this type of volatility perhaps going forward?

Yeah, I’m not sure that I would characterize it as material just because it is one factor that affects earnings but it certainly has made a positive difference on the bottom line and we would expect it to continue to do that for the full-year.

Okay. Thanks, Richard, I’ll get back in the queue.

And our next question comes from the line of Andrew Fairbanks of Merrill Lynch. Please proceed.

Good morning, guys. Just curious about the capital spending inflation rates for pipeline projects that you are considering in your operating areas; there’s quite a bit of cost inflation in the energy industry in general - maybe not so bad in pipelining - but just wondered if you had a rate there that you’re thinking of as you look at many of these long-term projects? And then also, just curious if you have any concerns on getting not so much labor but equipment as well. Do you think there’s enough compressor capacity out there that you’d be able to get the equipment you need for these projects on time if you push ahead with some of these major efforts?

Maybe I’ll give a general response to that, Andrew, and then I’m going to ask Richard to try and quantify if he can the inflation rate issue for you. Generally speaking, we -- well, first of all we are seeing increases in costs, equipment, materials and people costs, as a result of a very high level of activity; and not only in the industry but generally on North American-wide basis. We are probably not quite as susceptible to that as many of our partners and customers are in Western Canada because our construction is more geographically spread and hence isn’t as dependent on the local labor market like Fort McMurray or Edmonton, for example; because as you know our products are right across North America.

Not only that, we tend to draw on different crews many of whom can be residenting in North America and again not resident in a very tight geographic area. As well, because of the size of the Company and the number of projects that we have underway, we’ve been able to make some moves to secure things like mill space for pipe construction that has been advantageous in that we - as I said have so many projects on the go - that we’re able to tie up the mill capacity knowing that we’re going to need it for one project or other and been able to tie it up at very advantageous pricing. So because of the size of the Company, the fact that we’ve got such a big slice of organic growth projects, we’ve been able to minimize our costs. That doesn’t mean to say that there isn’t still inflation and you’re seeing that everyday right now. And, Richard, I don’t know whether you can quantify that on what the inflation rate currently is in the pipeline construction business, per se?

Well, I think it does vary from project to project - geography, size and everything else. But on some of the bigger projects we are certainly anticipating that there will be significant increase in costs relative to what might have been experienced on a unit cost basis in projects that were constructed over the last year or two; and in the order of 20% over a two year period in cost escalation, certainly I think would be in the ball park of what we would expect to experience and on, again, some of the larger projects we are going to have to put a lot more time and effort into procurement of equipment, services, labor, pipe lay contracts and contractors and likely will find ourselves working in some form of alliance in some of those cases to ensure that we share the risk and share the build-up exposure associated with the providers of those services being in a position to meet our needs as we go forward.

And then I guess, Richard, on top of that in the case of many of our projects we also have an overall capital cost sharing mechanism in place with our customers and it varies from project to project the extent to which we do that.

That’s correct.

That’s great. Thank you.

And our next question comes from the line of Matthew Akman of CIBC World Markets. Please proceed.

Thanks. Just want to continue to pursue oil pipelines and the really good earnings in the quarter. I’m just wondering if you could characterize, Enbridge is now having a little bit more upside to volumes especially on Terrace with the improvement there and, obviously, that was driven by year-over-year volume improvements because Lake had ran really well in the quarter.

Yes. And as you know, Matthew, in the U.S., there’s no downside volume protection; at least there’s a range of volume protection but it’s a relatively low level of protection in partnership compared to the Canadian side and hence you see more leverage when crude oil volumes go up in the partnership than you do in Canada. But you do see some positive effect on both sides of the border.

But I guess your question really relates to whether there is further upside associated with further volume increase?

Yes. Especially on Terrace.

Richard?

Sure. Well, Terrace does have some sensitivity to volumes because the surcharge, obviously -- the higher the volumes the more volumes were in the surcharge on. But there is also a base toll component of Terrace to performance, as well, in that the base toll goes up and the revenue that we’re entitled to on Terrace goes up and that component, I think, will have peaked this year. So small positive volume variance going forward but the toll variance component of Terrace performance will lead off so I think it’s still fair to say that volume sensitivity is going to be primarily through what we pick up coming through incentive income from the partnership as volumes pick up through the partnership.

Okay. That’s very helpful. And then follow-up on Southern Access Project. You’ve oversized to 42 inches and 36 was approved by CAPP. Is there an incremental cost to that additional six inches of pipe diameter and, if so, how does it get paid for since I presume 36 inch was allowed [foreign rates] and maybe 42 wasn’t --?

Yes. The arrangement that we have on -- let me say first of all, the cost of the upsize is around $137 million, Matthew. And the arrangement that we currently have with the shippers is that Enbridge will cover that difference in exchange for the power cost savings as a result of going to the larger diameter line. And those cost savings are significant, of course, in that the larger the diameter, the less power it takes to put the crude oil through the system. So that’s the arrangement that we’ve made with our shippers at this point, at least they most likely tell me the outcome.

And if I could just elaborate on that. We’ve actually put forward - the shippers - that we’re prepared to either do the incremental expansion on the same tolling principles as the base project which is cost of service surcharge or alternatively the approach that the CAPPs described where we do it, we keep the capital cost but we keep the power savings and we have committed that we will work with shippers over the next several months to resolve with them a commercial arrangement toll principle for this increment that they are satisfied with.

Okay. Great. Thanks very much.

And our net question comes from the line of Andrew Kuske of UBS. Please proceed.

Thank you. When you look at just the pace of infrastructure development, energy infrastructure development within Alberta at this stage in time, what’s your biggest concern at this stage really from just a broad perspective first, and then as it specifically relates to Enbridge?

Can I give you a surprising answer to that question?

Sure.

My biggest concern with regard to the pace of development is not what you would consider a conventional answer in terms of concern about scarcity, resource or escalating material costs; my concern is very much rooted in the direction that Enbridge is working and that is that we broaden out the markets quickly enough for this volume coming on-stream to ensure that we maximize the net-back and get the best pricing available for our customer and I think that there is potential opportunity lost by them if we don’t get these projects on-stream quickly enough. And I think that that’s the best value add and the healthiest way for the customers to look at this is to broaden the markets as quickly as possible.

So that’s really what we’re undertaking to do what with Spearhead and what Exxon-Mobile has done with the Gulf of Mexico line, what Southern Access does, Alberta Clipper and Gateway.

The conventional answer that you probably expected in terms of concern was around people and resourcing and, as you probably know, almost everyone of the projects being proposed in oil sands now is coming up with some innovative way to address that whether it’s building an air strip so that they can fly people in and access broader markets; whether it’s bringing potentially foreign labor in; whether it’s more fully packing the Canadian labor market, almost all of them have ways of improving the access to people and I would suggest that the people challenge is probably bigger than the material cost challenge along the way.

And then just as a follow-up on that on the market access issue, has it become a bit easier in the past month or so since Spearhead’s been running and since the Exxon line’s come up and running to really convince shippers of the economic benefit they receive on the net-back issue when the market starts to broaden out? And then really as an addendum to that, do you see this as being somewhat analogous to what happened when Alliance came online on the natural gas side back in 2000?

Yes. First of all, in answer to the first part of your question, I think that the shippers are definitely aware of the benefits that are being achieved as a result of both Spearhead and the Exxon-Mobile line coming on-stream and broadening the markets and the narrowing of differentials associated with that. It has been a very significant benefit and I think it help proves up the value to them of doing that. There’s no doubt. And we’ve received very positive feedback and comments on that. So there’s no doubt about it.

Yes, I do consider it analogous to the Alliance situation and, again, a very good example of improving the net-backs for the customers by ensuring that there’s adequate capacity out of the region; and in our case we have to make sure there’s not only enough capacity but it goes to a bigger variety of markets to ensure the best possible value.

There is a little bit of an almost down-side twist to it in a way, I guess, Andrew, in that as you know we are - we feel - a well-respected Company in this business. I think we’ve been viewed as maybe moving a little bit too fast and too aggressively in some cases and we’re doing that very much in the interest of our customers to make sure that those markets are opened up on a very timely fashion. So we’re moving very fast but we think that’s necessary to get this done.

That’s great. Thank you very much.

And our next question comes from the line of Winfried Fruehauf of National Bank Financial. Please proceed.

Thank you. In your earnings guidance for 2006, you must have assumed a foreign exchange rate. What is that rate and what is the sensitivity if that rate were $0.01 too low or $0.01 too high?

Okay. Well, we assumed for the sake of assembling the outlook a 1/20 U.S. dollar exchange rate was baked into that. I don’t know that I have a quick sensitivity on -- did you say $0.01 Canadian cent, up or down?

Yes.

Win, this is Colin. I don’t have that at fingertip, but one way to look at it is if you held to the $0.90 dollar which for basing today kind of costs and through the balance of the year, you’d probably see a total, I guess call it a budget variance of something like $12 million or $13 million on the U.S.D.

And have you a plan B to address a 90 cents dollar to say nothing about a 100 cents dollar? And if you have it, what is it?

In terms of a plan to address -- I mean we do hedge the cash flows of our foreign investments so from an economic perspective, we have a hedging policy in place that we follow. So that will continue irrespective of where the dollar goes. As you know, it’s almost impossible to hedge earnings. We effectively have that with our CLH cost investment, an earnings hedge; however with every other U.S. Dollar investment, we don’t and effectively can’t hedge the earnings. But the cash flows and the underlying investments in many cases are hedged.

So what you are saying is - I do know about your cash flow hedges. What you are saying is that wherever the dollar goes that will impact you one way or another. Is that correct?

From an earnings perspective.

From an earnings perspective.

Yes. That $12 million to $13 million, is that pre- or post-tax?

I think it’s after tax, Win.

Okay. And now that EEP seems to be finally coming into the making, when do you expect to receive the first premium distribution for EEP?

Well, I think that we’re sitting at about $3.79 distribution and the $3.96 is the point at which we hit the high splits and Steve, do you have a forecast as to when we would expect to be in to that --?

No. It won’t be in 2006, Win. But I think it would be difficult, probably inappropriate, to try to speculate about when a distribution increase would take us to that level; but from the 3.70 to the 3.96 is something we have to work on and, of course, EEP now in this quarter, had a very strong distribution coverage ratio. We’re going to watch that very closely and make sure that that remains strong. So that goes into our thinking as we consider distribution policy. But I don’t think it would be good to try to speculate on when we would hit the high splits. I don’t think it’s imminent, though.

But could it be as early as 2007?

Well, I think one of the -- I’ll give you kind of a generic and general answer to that - when one of the trademarks of MLPs and in particular the RMLP is the stability and security of distributable cash and we would want to see a significant track record of performance to ensure the maintainability of distributions along the way. So as Steve said, it’s really inappropriate to try to forecast it anymore specifically than that. But as we see the growth, the distribution should follow with the sustained growth.

And then just for clarification, this $1.20 exchange rate you have been assuming the inverse which is 83.3 cents? Is the 12 million to 13 million the difference between 83.3 cents and 90 cents?

It would be a weighted average factoring in Q1 actuals.

I’m not quite sure if I understand what you’re saying.

Well, Win, as you know it was $0.90 for Q1, right? So it would be a weighted average of forecast of $0.90 and --

Well, but I -- I have started by asking you about what the underlying exchange rate assumption is for your earnings guidance for 2006 and I was told that out of 20 Canadian which is 83.3 cents, then I asked for the full-year impact and was told that $12 million to $13 million post-tax, so my question naturally is if the - at that $0.90 - so my question naturally is, is the 12 million to 13 million the difference between 83.3 and 90 cents on an annual basis?

Yeah, I’m not sure if I still follow you, Win, but the $0.90 would be that I would comment it was $0.90 from here, forward.

All right. Thanks.

And our next question comes from the line of Brian Purdy of First Energy. Please proceed.

Hi guys. I just wanted to go back to the terminaling and storage assets that you are putting in. And obviously you’ve mentioned that you’ve got a lot of future prospects. I was wondering if you have an idea of if industry production was to rise by 9 million barrels per day over the next five years, how much storage is really required either from Enbridge or another party to accommodate that kind of production increase?

I’ll maybe just comment generally and then I’m going to ask Richard to try to quantify that a little bit, Brian. First of all, it’s a combination of factors that results in the demand for storage facilities prior to the volumetric increase and that results in an increase in the amount of working storage we need in the system; but then also we are a fee per service operator so we’re not involved in the marketing business. However, with volatility in crude oil prices, this does present others with marketing opportunities. So to a certain extent it’s volumetric driven, to a certain extent it’s dependent on market dynamics to the extent to which people are looking to store crude oil over a period of time. So those dynamics are working very much in favor of adding storage and it would appear to be very much in the interest of customers in a long-term basis particularly in terms of these deals. But, Richard, can you maybe quantify it to assume we have another million barrels a day, what the might --?

I actually don’t think we have any rule of thumb that would do that for us because technically speaking we’re talking about term storage here and incremental volumes don’t drive any automatic amount of term storage. They do drive additional break-out tankage but that’s not what we’re talking about here. This is commercially oriented and I think it really is a combination of higher prices and higher-priced volatility.

The fact that as we get further and further into oil sands development the impact of a facility being down has such a greater effect than it would have done historically that it’s motivating quite a range of players - producers, refiners and young marketers - to see value in having access to storage. But it’s not certainly the more oil you have floating on the system, I guess the more there is there for them to store, but I don’t think there’s any automatic relationship that we can derive.

Okay. Well, maybe a follow-up then. If you were to assume that Gateway was going to go forward and, thus, Western Canyon Crew have another market that they would have access to, do you think that would increase the demand for storage just given the fact that you’re saying it’s term storage and there would be different - another set of market dynamics there? Or would it in fact, reduce the amount of storage required just because there would be different options at any given time for oil to go to?

Well, I think first of all, again, we’re talking here merchant storage and outside of the working storage - pipeline - obviously it’s going to be working storage associated with the Gateway project. I think it’s fair to say that the more alternatives that customers have to move their crude oil the more storage is required so that they can play one market and one outfit versus another and enhance -- my gut sense would be that the more alternatives they’ve got the more storage they’re going to build; particularly at kind of the junction point with Gateway going from Edmonton that would result in increase in storage capacity in Edmonton; somebody may want to move their crude via Gateway one month and to Chicago another.

Okay. And when you mentioned sort of your 30 million barrels of prospects under development and storage, is that -- would those be at Edmonton and Hardisty primarily or are there other locations as well?

As I mentioned before, we also have Cushing, Oklahoma terminal and then also the Superior, Wisconsin where we’ve got some tankage under development.

Okay. Sorry about that. Thanks very much.

And I believe the [Pritchard] Griffith is as well.

Yes. There’s actually a number of locations south of the border and north of the border. There’s Hardisty, Fort Saskatchewan and Athabasca are primary locations.

And our next question is a follow-up question from the line of Linda Ezergailis. Please proceed.

Thank you. For your Aux Sable over earnings sharing with BP, did you receive any cash in the quarter? Will you be receiving that all in Q4? And if you did not receive any cash, what would it have been based on how Aux Sable performed in Q1?

Colin, can you speak to that?

Sure, Linda. It’s Colin. We did receive cash and we would receive more product even annually, obviously. I don’t think we’ll give you the amount of that. Obviously, it would be a little irresponsible if it is, in fact, income. We would have booked it if it is contingent on annual measurement crudes. So I think we’ll hold off on that.

Okay. In terms of if current [fax] spreads were to prevail for the balance of the year, I guess, similar to your FX sensitivity response to Winfried, what would be the value of the benefits to Enbridge under that scenario?

Colin?

Haven’t got that crunched, Linda.

I think that is something we’d have to get back to you on.

Okay. Thanks.

And our next question comes from the line of [Vaheer Kahn] of Baker, Gilmore and Associates. Please proceed.

Hi. Good morning, gentlemen. With respect to - I mean this will not come back to the business, the gas distribution segment, you know? Obviously, like rather than play the crucial role in the performance of the business but longer-term and given that the business of has the hard CapEx given the rate of this fiscal subscribers. Do you think that the code can return in this business given the lower lauded rates that are returned on equity? And what else can you do to so called bring the value out of that business in your statements?

And you’re talking about the distribution business in general?

That’s right - general. But I said that this is a 20% or 30% or more of your total business. You know?

Yes. That’s right. And it’s a very important 20% of our business, 25% of our business approximately. First of all, with regard to your comment on lower ROE, as you know through the natural gas forum with the OEB last year we would now expect to move to an incentive tolling mechanism or Performance Based Rates Mechanism as they refer to it in the 2008 timeframe and we feel that will offer us some upsides in terms of return on equity potential.

We continue to add over 50,000 new customers in the business every year so there is good growth potential in the business and one point that we are very aware of is that it’s a very credit-friendly part of our business; and because of the stability in the cash flow and the low-risk nature of the business, the rating agencies look very favorably on it; so it is an important part of maintaining our credit rating and we also feel that over time there may be the potential to use the gas load associated with the distribution business to anchor some involvement in pipeline projects. And we’ve discussed this with the regulator, we’ve discussed it with the natural gas forum and they’ve indicated to make an application if you are interested in doing that. It’s certainly not a slam-dunk but we think that we may have the ability to use the load to do that.

So the distribution business continues to be very important to us and realize, also, with regard to weather that there is a formula that defines normal weather and it’s based on the weather, the degree days over the past -- every weighted to the past five years. And therefore, our definition of normal is getting warmer all the time. And, hence, we expect that over time that we will realize some significant weather upside here because -- unless we see a continual warming, after warming, after warming and I personally don’t think that’s very likely. So the definition of normal now is a pretty warm year and there appears to be a bit of upside on weather --

Right.

And if I could just that -- the other thing that I think is out in front of us is PBR, the performance based rate making coming up in the utility, that should drive considerable value. We’ve long believed that that kind of [incentavised] arrangement that’s worked so well in the liquids pipeline system was describing -- that that has driven a lot of value and that really is a cultural thing that we look forward to. So I just wanted to reemphasize that.

Right. I appreciate that; but I’m just saying that given - the gas distribution, [Novelco], the new grounds rig gas services and most of the events are technically are -- their contributions are declining from an overall perspective. And do you foresee some kind of income trust can work in this business given the lower growth rate and foreseen?

Let me respond to the income trust part of that. First of all, we’ve got a lot of confidence in terms of the growth and the importance of this segment for our business for the reasons I indicated. We think both strategically and also in terms of bottom line contribution that we’ll only get better going forward and we do like the credit-friendly nature of the business. The income trust issue is one that we have considered and we have talked openly about with investors; however, I think it’s fair to say that until something can be resolved with regard to recovery of tax in rates with the regulator, the value associated with putting an asset like this into an income trust would be negligible. So that issue is one that would be very difficult to resolve and hence makes it, in many ways it’s a logical trust asset but in others ways it’s not for that primary reason.

Okay. Great. Thanks very much.

And our next question is a follow-up question from the line of Maureen Howe. Please proceed.

Thanks very much. Just a follow-up question on the Terrace earnings during the quarter. And I apologize for it but I obviously perhaps don’t fully understand how the tolls for Terrace work. I always thought that it was a rider on all the volumes that were shipped on the main line and the expansion and I’m not sure what this base toll is and I’m not sure how it bleeds off and I’m wondering if, perhaps, Richard you could just walk me through that so I understand. Because, again, I come back -- I thought it was a rider and if we take that 100,000 barrels a day incremental volume and what I thought the rider was, it certainly doesn’t explain the increase in magnitude that I think we’re talking about here.

Well, that rider applies to the incremental barrels that are flowing through the Terrace capacity, the $0.05 surcharge. So we get no surcharge if there’s no utilization of Terrace capacity and we’ll get $0.05 on every barrel if it is. But we also get the base toll on the entire Terrace capacity whether it’s used or not under the provisions of the transportation revenue variance feature where we’re held to respective volumes. So that entire toll is applied to the entire Terrace capacity irrespective of how it’s utilized.

So if that toll is higher one year than it is in another year, the Terrace segment or silo, so to speak, contributes additional revenues and earnings as a result of that higher toll. And our toll has been rising over the last few years so that’s been a component of the improvement in Terrace earnings. But as our toll begins to go down which we expect that it will do, as Terrace builds up and we get the benefit of those volumes, that effect will no longer occur.

So it’s the impact of the entire -- when you talk about the base toll, you’re not talking about a base [Harris] toll, it’s the base mainline toll applied to the Terrace expansion?

Exactly.

Okay. And just another question, and it’s coming back to the Enbridge Gas Distribution and the question, I guess, is you mentioned timing differences and you also mentioned higher O&M costs, so is there potential that we’ll see perhaps better than we might expect performance in future quarters of this year due to timing of expenditures and maybe expenditures that may have been taken in Q1 and therefore are not required in subsequent quarters?

Yes. I think that would be accurate, Maureen. There was a higher level of spend especially in the first two months of the year that I think we should see normalized to some extent through the year; so that O&M experience is not expected to recur in the coming quarters; so that’s pretty accurate.

Okay. Thanks very much for that.

And our next question is a follow-up question from the line of Karen Taylor. Please proceed.

I just had a really quick question on the need for additional capital. We’ve always presumed that you would not seek new equities over the next year or so and that you would prefer to sell the Preferred Shares that you have in Enbridge Income Fund before you would access the equity market. Is that still a reasonable assumption?

Yes, Karen. That is a reasonable assumption and as you know we do have a very large capital budget going forward over the next five years, but there are a number of issues associated. Of course, part of that is shared with the partnership. We also have the potential for equity partners on projects like Clipper and Gateway and do have some existing balance sheet capacity today; the opportunity to sell-down further the interest in the income fund and all those things combined result in us, at this point, not seeing any need for equity.

And I just want to confirm that the Southern Access Extension is still an Enbridge Corp sponsored project non-EEP. Is that right?

Yes. That’s right.

Okay. Thank you.

And our next question is a follow-up question from the line of Winfried Fruehauf. Please proceed.

I always get a [inaudible] on thin ice when I listen to you, Pat, when you talk about [inaudible - highly accented language] volumes. You mentioned by 2015 you might see now 2.8 million barrels a day instead of 2.4. Are you referring here to diluted [Vichman]. Are you referring to upgraded Vichman or are you referring to sort of a combination of both?

We’re referring to a combination of both, Win.

Okay. And would you rather have more upgrading in the Athabasca area or more upgrading at the refinery level?

Well, are you asking what we would rather? I think it’s fair to say that we would rather a scenario that maximizes value for our customers and, therefore, results in the most logical development of the oil sands and heavy oil resources. And I personally think that will be a combination of additional heavy crude cracking capacity downstream, some upgrading within the province of Alberta and in combination meeting that overall need.

As you know, if it’s all Vichman production alone, then we’ve got a real challenge with regard to condensate supply as [inaudible] and also there is a desire by many of the producers to further upgrade their product to try to get some premium pricing for their different grades of crude. So I think we’ll see a combination. The economics would definitely appear to be favorable to add heavy crude packing capability in the Midwest based on the differentials that we are seeing today, as well.

I was just in my simple mind thinking that if you were to move, just hypothetically, only upgraded or synthetic crude oil you would require much less pipeline capacity as compared to that diluted Vichman. Is that not right?

Yes. That’s right because, of course, when you’re moving the diluted Vichman, about 30% of the volume is the dealing with itself. So in terms of pipeline volume and pipeline capacity you would be requiring - if it were all strictly diluted Vichman - but I guess what I’m saying is that I don’t think that that would result in the most expedient development of the oil sands because of the shortage of [diluent] and that’s in part the value of the upgrading in Alberta. So I think to maximize the development and hence the volumes over time, it would be best if we see a mix and match approach taken.

I appreciate that point but I was sort of thinking now you’re looking at 42 inch pipe instead of 36 inch for Southern Access and suppose one morning you wake up, you’ve gone with 42 and all of a sudden the producers have decided to no longer ship diluted Vichman but only upgraded Vichman. Would that not cause a problem? You might have an oversized pipeline.

No. I don’t think so. Based on the forecast that we’re seeing that 42 inch would be fully utilized even if there is a high degree of upgrading in Western Canada. And, again, that I think shows a confidence in the producers and ourselves in the probability of that growth occurring.

And on that issue, I’m reluctant to sort of mention pipeline names such as Keystone or TMX 2 and 3 or so, but how do you assess currently your competitive position versus others that are planning to implement new pipeline facilities across the border?

Well, that’s a question that I could spend some time responding to. Let me try giving you a quick response. And you said across the border, so I assume you mean to the U.S. market rather than to the West Coast? Or are you talking about both?

Oh, no, no. Just across the southern border.

Just across the southern border. Okay. Well, the primary competition that we face there would be with regard to the potential for the Keystone project of TransCanada proceeding and we feel that our project has got so many significant advantages over that that it’s unlikely that we will face that competition. The reason being that our project is lower in capital costs. It’s lower in toll. It uses existing right-of-way and hence doesn’t have the Green-feel development associated with it. It provides a variety of product and timing of shipment alternatives that is not available through the one-line the competition would be offering. We don’t have challenges in terms of taking part of the existing grade phase out of one service and putting it into another which creates a regulatory challenge. So there really are six or seven reasons why we think there’s a significant damage; the prime one being the fact that the toll that we’re offering is going to be significantly lower.

What about your friends to the West TMX 2 and 3?

Okay. Again, I was concentrating primarily to the U.S., Midwest. But with regard to TMX 2 and 3, I think that will allow some expansion out to Vancouver. It doesn’t, in our mind, compete with our Gateway project which is a much bolder stroke off the West Coast simply because we don’t see the kind of volumes that could move through trans mountain expansions through the Vancouver Harbor to properly address the challenges that producers are going to have with broadening out markets. We think they need to get a bigger volume to market than the Vancouver port can handle.

So what you seem to be indicating is sort of akin to my thinking. If I understand you correctly, you’re suggesting that given the location of the terminal in the port of Vancouver, it is unlikely that we would see much larger tankers showing up under the [Inaudible] Bridge without residences and businesses and whatnot, and environmentalists raising cane. Is that what you’re saying?

Well, I think that’s right and it’s really impossible to get a VLCC into Vancouver Harbor and that’s where we’ve chosen the deep water Kitterman port because we need the VLCC for the economics of waterborne transportation in order to really make Gateway hum. And so your assumption just is right in regard to this.

Thank you very much. It’s been helpful.

And our final question is a follow-up question from the Line of Sam Kanes. Please proceed.

The native Aboriginal issues and progress on Gateway right-of-way, did the federal government solve anything over night here with their budget with respect to their proclamation or do you need more help from them in some more specific fashion?

I must admit, Sam, as a result of the fact that we’ve been in Board meetings and have the Annual Meeting today, I have not looked at the budget from the perspective of how it might impact on Gateway and any First Nations issues. As you probably know, we’re in consultation right now with First Nations people and I believe we have 42 First Nations peoples that we’re in discussion with along the Gateway right-of-way. We’re pleased with the progress that’s being made on those discussions and they will be working through a consultative process both with us and with the federal government in conducting it but I must admit I don’t know how today’s budget would affect that - or yesterday’s budget would affect that.

I was referring to the proclamation of $500 million that was applied to be for the [McKenzie] Valley First Nations’ people. That’s where that thought is coming from and also the fact that there was a somewhat controversial article in the [Globe] Mail about six weeks back that affected your stock price and it sounded like a few groups were not involved to date. Maybe they are now. Maybe that’s what you’re saying in terms of the progress.

Well, I think the article that you are referring to in the Globe Mail was an expression of concern by some First Nations people around the consultation process with the federal government. It was the [Carrier Secany] peoples and their concern was around the federal government consultation process and not consultation directly with Enbridge; so I would argue that probably the potential for rising interest rates more likely had an effect on our stock than the Globe Mail article, Sam. But --

[Inaudible] or flow of fund sentiment change [inaudible] sector. But if you need something from the federal government here, is this happening in parallel or do you know if it’s progressing or that’s what I’m coming to, I guess. Your progress might be great but there’s still another leg to this that’s necessary.

Well, it will happen in parallel and, in fact, the federal government is working on the process that will be employed and exactly how that’s going to be structured; so we don’t expect any delays or problems associated with it. Again, discussions that we’ve had along the way have been very favorable to the development of the Gateway project and we undoubtedly will have challenges and concerns that need to be addressed along the way as is always the case. And we’re comfortable that we’re going to be able to overcome those in a timely fashion.

Thanks, Pat.

I am currently showing we have no further questions at this time.

Well, thank you very much everyone. We very much appreciate your time and Look forward to the next call.

Ladies and gentlemen, thanks for your participation in today’s conference call. This does conclude your presentation and you may now disconnect. Have a great day.