恩橋 (ENB) 2010 Q3 法說會逐字稿

Good morning, ladies and gentlemen. Welcome to Enbridge Inc. 2010 third quarter financial results conference call. I would now like to turn the meeting over to Mr. Guy Jarvis.

Thank you and good morning. Welcome to Enbridge Inc. 2010 third quarter earnings call. With me this morning are Pat Daniel, President and Chief Executive Officer. Richard Bird, Executive Vice President, Chief Financial Officer and Corporate Development. Steve Wuori, Executive Vice President, Liquids Pipelines and Colin Gruending, Vice President and Controller.

Before we begin, I'd like to point out that we may refer to forward-looking information during this call. By its nature, this information applies certain assumptions and expectations about future outcomes, so we remind you it is subject to the risks and uncertainties affecting every business, including ours. Our slides include a summary of the more significant factors and risks that might affect future outcomes for Enbridge, which are also discussed more fully in our public disclosure filings available on both SEDAR and EDGAR systems. This call is webcast and I encourage those listening on the phone lines to view the supporting slides which are available on our website.

A replay and podcast of the call will be available later today and a transcript will be posted to our web site shortly thereafter. The Q&A format will be similar to past calls. The initial Q&A session is restricted to the analyst community and once completed, we will invite questions from the media. I would also remind you that Pat Murray and I will be available after the call for any follow-up questions that you may have. So, at this point, I would like to turn the call over to Pat Daniel.

Thank you, Guy. Good morning, everyone. Thank you for joining us for our review of the third quarter results.

Before we get into our Q3 results, I would like to update you on the progress of our cleanup efforts related to the spill that we experienced on line 6B this summer in and around the communities of Marshall and the Battle Creek, Michigan. Generally, that cleanup has gone very well. We met the deadline of August 27 for the primary cleanup of the leak site, as you know. By September 27, we had met the deadline for cleanup of Talmadge Creek and the Kalamazoo River and then earlier this week, the E.P.A. confirmed that we've also met the October 31 deadline for cleanup of submerged oil. So, that means we have met the primary cleanup requirements at this point. This, of course, does not mean that we're all done. We're now in the process of beginning longer term monitoring and working along with the E.P.A., the Michigan Department of Natural Resources and Environment and other officials on that long-term monitoring. As I've stated from the outset on this incident, we will be here until the regulators and local residents are satisfied with our cleanup efforts. Addressing the impacts to the people, the communities and the environments affected by the spill was and it remains the top priority that we have at Enbridge.

With regard to the cause of the pipeline failure, we're working with the NTSB and the Office of Pipeline Safety, those investigations are on-going. We will learn from the findings and we will implement whatever changes are necessary throughout our system to ensure that this does not happen again and to share our learnings with the broader benefit to the entire pipeline industry. Over the course of the last three months, we've worked closely with numerous local, state and federal agencies and community organizations in the response and the cleanup of the crude oil spill. I'd like to acknowledge and thank all involved for their contributions and for the excellent cooperation that Enbridge received. And I'd like to personally thank the residents of Marshall and Battle Creek, for their patience over the past couple of months or three months now, when we've had as many as 2,000 workers in their communities working around the clock on the clean-up. We placed the highest priority in our relationships with the communities that we live and work. We've been a part of the Marshall community for more than 41 years and we intend to be around for many more years to come. So, with that very quick status update on 6B, I would now like to just very quickly comment on the third quarter results and update you on some of our projects then I'll turn it over to Richard to walk through the results in a little more detail.

As you will hear, quarter three was another strong quarter for Enbridge financially. Adjusted earnings per share for the quarter were up 26% year-over-year and for the nine months, up almost 20% year-over-year. And this keeps us on track to achieve the upper half of our 2010 guidance of CAD2.50 to CAD2.70 per share. I'm not going to spend a lot of time on the strategic front today. Many of you on the phone, of course, will have been part of our annual investor day meetings in New York or Toronto at the beginning of October where we walked through our plans for liquids pipelines, gas transportation, gas distribution and green energy businesses and then also of course, highlighted the financial strength of the Company. For those of you that were unable to attend, a replay of the webcast and our presentations and transcripts from Toronto are available on enbridge. com in the Investor Relations section, and I encourage all of you that were not able to attend to go through those.

This morning, what I would like to do though is to quickly take you through the year-to-date in regards to assets placed in service and newly secured projects. I'm going to go back to the very start of the year. When Enbridge Energy Partners placed into service the CAD140 million expansion of its North Dakota system and this project, as you know, was completed on budget and ahead of schedule. As anticipated, the continued growth of production in the Bakken play has resulted in the expansion being consistently full from day one. And this, of course, is creating further opportunities for Enbridge and I'm going to come back to that in a moment.

In April of this year, we placed into service the CAD3.7 billion Alberta Clipper project which added 450,000 barrels per day of capacity out of Western Canada. And once again, we completed that project on budget and ahead of schedule. On October 1, of this year, we received the first oil on the Alberta Clipper pipeline at our terminal in Superior in Wisconsin. We are very pleased with that milestone.

In July, we placed into service the CAD2.3 billion Southern Lights project and this project is designed to move up to 180,000 barrels per day of diluent from the Chicago region back into Alberta for use in diluting the raw bitumen being produced at an ever-growing rate in the Alberta Oil Sands.

Then in early September, we achieved commercial operation of the 60 megawatt second phase of our Sarnia Solar Farm. Again, well ahead of schedule on that project. At a total of 80 megawatts, Enbridge's Sarnia Solar Project is the largest operating photovoltaic facility in the world and it can generate enough energy to meet the needs of approximately 12,800 homes.

Altogether, we've brought CAD6.5 billion of projects into service in the last ten months. Notably now, all of the projects are generating cash flow. Closing out the year, we're on track to commission the CAD285 million, 100 megawatt Talbot Wind Project as well as the CAD140 million Enbridge Saskatchewan pipeline expansion that's basically on the Bakken play, north of the US border and that will happen during the fourth quarter. So, you can see we've been very busy completing these projects to drive our strong earnings growth and even more significant cash flow growth in the coming years. As well though, 2010 has been a year where we've been able to firm up near to medium term growth plans with the announcement of the number of secured projects which will come into service between 2011 and 2014.

First of all, within our liquids business, we've announced over CAD2.4 billion in projects over the past ten months. First, the Christina Lake Infrastructure serving as a Cenovus project and this CAD250 million project should be in service by late 2011. The addition of those new volumes into our regional oil sands system led to our subsequent announcement in early September of CAD185 million expansion of our existing Athabasca pipeline by the latter half of 2013.

In June, of course, we announced the Waupisoo expansion which was necessitated by the increased capacity commitments made by Statoil and Surmont at their projects. This is a CAD400 million expansion planned to be in service in the second half of 2013. It is going to expand this pipeline to its ultimate capacity of 580,000 barrels a day.

Then in August, we announced the Wood Buffalo pipeline. I think you'll recall this is a CAD370 million project. It is going to serve growing production from Suncor. It is a new 95 kilometer pipeline, will be built in the same right-of-way as our existing Athabasca pipeline and between the Cheecham terminal and the Suncor site.

We signed two more agreements in September adding further to our roster of oil sands projects over the summer. First, we announced that we had been chosen to be the service provider for the Husky Sunrise project. This is a CAD475 million Norealis pipeline system which will include a new, originating terminal at the Sunrise mine site and 112 kilometer pipeline and additional tankage at Cheecham. Closing out the quarter and to accommodate the growing crude production contracted to be shipped to our Edmonton terminal, we announced an agreement with CAPP to expand our Edmonton tank farm by 1,000,000 barrels at a cost of about CAD260 million. So, as the largest operator of oil sands regional infrastructure and with our corresponding ability to provide eased and incremental transportation solutions to producers, we expect to see continued, attractive investment opportunities of this type for some time to come.

As I indicated earlier, the Bakken formation continues to also drive growth opportunities for Enbridge and its affiliates. In August of this year, we announced that we've enough commitments to go ahead with our next Bakken expansion program, increasing take away capacity from the Bakken play by 145,000 barrels per day. That can also be very readily expanded to 325,000 barrels per day. While we already have enough contracted anchor volumes to go forward with the project, we're currently conducting a binding open season to provide additional shippers the opportunity to secure capacity on the same terms, on that project. And this is a very creative solution. It is going to include capital spending of about CAD190 million in our Saskatchewan system, on the north side of the border and then another CAD370 million on our North Dakota assets, south of the border. We'll be utilizing existing assets and right-of-way wherever possible which will help us deliver timely and cost-effective new capacity.

And finally, in our green energy business, we will be expanding our wind power assets by another 350 megawatts of generating capacity with the announcement in March of the CAD275 million, 100 megawatt Greenwich Wind Power project near Thunder Bay, Ontario. Then in June, as you'll recall, the CAD500 million, 250 megawatt Cedar Point Wind project near Denver, Colorado. That's notable for it being our first entry into the US wind power business. So, with all of that, we remain confident in our 10% annual average EPS growth into the middle of this decade. That's a very quick overview of what's been a very busy year, financially and in terms of bringing projects onstream and announcing new projects. So with that, let me turn it over to Richard to go through the Q3 results in a little more detail. Richard?

Okay. Thank you, Pat. Good morning, everyone. Taking up on slide eight of the slide package, if you're following that. As Pat mentioned earlier this morning, we released our third quarter results and year-to-date reported net income was CAD637 million or CAD1.73 per share. That's a decrease from 2009 when we reported CAD1.255 billion as our earnings which was CAD3.45 per share. And this year year-over-year decrease in our GAAP earnings was due primarily to the year 2009 inclusion of the one-time gain on the sale of our investments in the OCENSA pipeline at Colombia, that was a CAD329 million gain. In addition, this quarter picks up the CAD85 million negative impact from costs associated with our cleanup efforts of lines 6B and 6A. And that's the full accrual of the costs that we've incurred to date plus those anticipated to complete the cleanup.

And in addition, we recorded a mark to market loss on our US hedging program as the dollar moved relative to the prior quarter end. As a reminder, in the third quarter, Enbridge Energy Partners accrued for all expected costs related to the 6B and 6A incidents, however, insurance proceeds cannot be accrued until the dollar value of those proceeds is certain or the cash has been received. And as a result, there will be timing noise within our GAAP results for the next few quarters.

Excluding some of these one-time and nonoperating factors, our adjusted earnings per share for the third quarter was up 26% and year-to-date, 19%. This is ahead of where we thought we would be by this time of year. And although we are comfortable with our guidance, that we should hit the upper half of our 2010 guidance range, we do believe that some of this year-to-date improvement will reverse in the fourth quarter of this year. This is primarily due to the Enbridge system no longer having an earnings profile that is back-end weighted due to the removal of the performance metrics within the 2010 incentive tolling settlement. Also, weaker performance anticipated in offshore pipelines in the fourth quarter.

Finally, although Enbridge Energy Partners contribution to Enbridge should improve its performance over the fourth quarter of 2009, it will not outperform to the same extent that it has so far this year. I'll now take a few minutes to walk you through the main drivers within each segment turning to slide nine.

Liquid's pipelines adjusted earnings rose CAD9 million in the quarter and CAD82 million year-to-date when compared to 2009. Placing both the Alberta Clipper and the Southern Lights project in service, as Pat mentioned earlier. Not only increased our year-over-year earnings but also marked a sharp increase in cash generation as these two very large projects began to collect tolls. In addition, prior to the July 1 in service date of Southern Lights and the April 1 in service date of Alberta Clipper, earnings from the recognition of ADDC on the growing capital belts has further increased earnings in 2010 relative to 2009. The Spearhead pipeline once again had a strong quarter. Including the recognition of make up rights which expired in the quarter for which we then recognized the associated earnings. As well as stronger volumes due to the expansion placed in the service in 2009.

Within natural gas, delivery and services, adjusted results were higher by CAD20 million in the quarter and CAD8 million year-to-date. Enbridge Gas Distributions results improved in the quarter partially due to an increase in earnings related to our customer billing practice where a larger portion of customers bill will be a fixed component and a lesser amount will be variable. This increased earnings in the quarter by approximately CAD6 million over the third quarter of last year, exactly offsetting the reduced earnings earlier in the year from this change which we mentioned on the prior quarters. As you will recall, this rate change only affects the distribution of earnings across the year and has no net impact on the bottom line of EGD. As we have seen all year, EG continues to improve its return under the incentive regulation, though the timing of expenses will result in a claw back of some of this third quarter benefit as we move into the fourth quarter.

Energy Services also had a strong quarter when compared to the third quarter of last year. As its results increased by CAD6 million in the quarter. This was due to improved margin opportunities and natural gas marketing in the quarter. However, on a year-to-date basis, the earnings from Energy Services are still lower than last year as the opportunities within the liquid side of the business in the first half of this year were not at the same level as was experienced in the first half of 2009.

Sponsored investments adjusted earnings continue to be strong in the third quarter. Enbridge Energy Partners contribution increased in the quarter and is up 23% year-to-date. The performance in the third quarter was primarily a result of increased incentive income earned by Enbridge as a result of the distribution increases announced by [Enbridge] in the first and second quarters of this year. The combined CAD0.075 per quarter per share increase represents 3.5% increase since last year and Enbridge is now entitled to 50% of this increase as a result of the partnership distribution levels now being in the high split range.

Year-to-date, earnings at the partnership are also stronger. That's, of course, after adjusting for the costs associated with the two leak incidents. And this strength is due to increased transportation results as a result of the completion of phase two of the Southern Access expansion in 2009, as well as two quarters of earnings from the Alberta Clipper project and the impact of the phase six expansion of the North Dakota Feeder system which was placed into service in January of this year. These positives were somewhat offset by decreased performance within the gas segment of EEP due to lower volumes and NGL pricing year-over-year. Alberta Clipper US also positively impacted earnings as the US portion of this project was placed into service on April 1 of this year. The earnings within the quarter and year-to-date reflect Enbridge's 67% of the after tax earnings from Alberta Clipper US, as well as our share of the AEDC booked in the first quarter. And finally, corporate costs in the third quarter are consistent with prior year, while our year-to-date costs have experienced increased financing costs, somewhat offset by the earnings from the Sarnia Solar project. And with that quick review of the third quarter results, I'll keep my comments short and pass it back to Pat for a few quick wrap-up comments.

Great, thanks, Richard. Let me very quickly summarize. First of all, cleanup efforts are progressing well in Michigan and at this point, our focus is turning now primarily to implementing longer term monitoring programs. Secondly, not withstanding the spills, the third quarter was a strong one for the Company and we're well-positioned to be in the upper half of our guidance range for 2010. And finally, to date, this year, we placed into service nearly CAD6.5 billion in growth projects and we've lined up another CAD3 billion in new projects expected to come into service over the next two to three years. So, with that very quick wrap-up, we can move on to the Q&A session.

Ladies and gentlemen.

(Operator Instructions)

Your first question comes from the line of Ted Durbin with Goldman Sachs. Please proceed.

Good morning. If I could just start off with the spills, can you give us a sense of the magnitude of the fines that you might incur there and when you might have a better sense of the timing of what those fines would be?

Ted, at this point, we can't really give a good estimate on that. I think that the timing is that it probably would be at least into mid-year next year. But Steve Wuori, you might want to just clarify that.

No, I think that's right. I think that, obviously, the agencies will consider a lot of factors in determining any fines. And it will take, I'm sure, into sometime in 2011 before that happens.

Okay. Thanks. You didn't talk at all about Gateway. I realize this is a long process. Can you just give us an update on the regulatory process there?

Sure. The application, of course, is in. With the NEB and at this point, we would expect a hearing probably in the fourth quarter of next year. Continue to work with stakeholders and along the way. But right now, that's a quick overview, Ted, of where we stand.

Okay. And then if I could -- just one more, if you just look at your Bakken takeaway solution versus some of the competing proposals out there, how would you characterize your proposal versus others? Maybe talk a little bit about -- I think you pushed back the open season? What was the thinking there, too?

Sure. Ted, just a few thoughts there. The reason that we extended the open season to November 30 was that a number of companies that we were in discussion with indicated that they needed that time in order to secure internal approvals, including board approvals, to make commitments and so we decided to move it to November 30. I think that the Bakken solution that we have is really two-phased. By the end of this year, we're going to bring 25,000 barrels a day of increment on by reversing the portal link pipeline which used to flow southbound and now has been idle for the past three or four years. And so, that will be an immediate partial solution beyond what we put in service in January. And then the big Bakken expansion program with the new pipe into Saskatchewan and then into our main line at Cromer, Manitoba puts it into the main line system where you have the flexibility to get to all of the markets that the Enbridge system reaches. So, I think there -- that we feel that the Bakken expansion program is of sufficient scale. Pat mentioned that it's a 145,000 barrels a day of initial capacity. And we could readily expand that to 325,000. That the largest solution that's out there. And we really think that, that is what's needed given the production profile coming out of the Bakken

Okay. Very good. That's all for me. Thank you very much.

Thanks, Ted.

Your next question comes from the line of Juan Plessis with Canaccord. Please proceed.

Thanks very much. With regard to discussions you're having with shippers on incentive tolling on the main line, can you give us any color on your sense of timing and perhaps the direction that the shippers are going in this?

Sure. I think that the discussions have been going well for a number of months. Of course, we struck the 2010 ITS that we're operating under right now. That does have roll forward provisions in the event that we don't have a longer term agreement made. But we're certainly progressing those discussions and I think are capturing all of what the shippers are most concerned about for the coming five or ten years. Each of agreements before has had a certain flavor to it. With an emphasis based on the shipper's concerns and needs and that this one will be no different. It really will resonate to whatever is of greatest concern and opportunity to the shippers going forward. I won't try to predict exactly what that flavor is at this point.

Okay. Thanks. Now, you know, you've done a good job in the past of taking costs out. Do you think there is -- there could be more upside on future ITS settlement?

You mean in terms of cost reduction?

Yes.

I think there always is. Of course, the biggest, lowest paying in crude was picked in the early parts of the incentive's holding arrangements back in the '90s and early 2000s. But absolutely, there's always opportunity to make the system more efficient through not only straight cost reductions but also in the way the lines are configured and the various crude types that we move in those lines in terms of power costs.

Great. Thank you very much.

Thank you.

your next question comes from the line of Matthew Akman with Macquarie. Please proceed.

Thanks. This question is probably for Richard. Wondering what the full -- I guess impact on Enbridge was of providing any resources to the partnership during the spill? It looks like, only maybe CAD7 million?

There was about CAD7 million of labor charged by Enbridge to the partnership because of people from Canada that came down to assist on the spill. So, that would be part of the cost that's been provided for by the partnership and Enbridge would be reimbursed for that amount.

But in terms of the big ticket items there, did the partnership fully absorb those on its balance sheet in the quarter?

Yes. The partner picked up all of the costs, both actually incurred and expected, in the crude -- the remainder of those in its quarter. Both would include all third party costs and all costs of Enbridge personnel involved in the spill.

Okay. Thanks for that. Quick follow-up question. On October 27, you guys announced that Enbridge Gas would be holding a binding open season for some storage that you're developing. I'm just wondering what the commercial model is on that storage? I understand it to be market-based type rates but maybe you can just clarify?

That's something we probably should get back to you on, Matthew.

Okay.

I don't think we've got the answer here. We'll get back to you on that, Matthew, for sure.

Okay. Thanks. That's all I had.

Okay, thank you.

your next question comes from the line of Robert Kwan with RBC Capital Markets. Please proceed.

Morning. Just on the spill costs, can you just talk about what the non-insured portion of the amount that you booked, I know you talked about CAD3 million net to you in lost revenue? Were there any other impacts that you normalized out?

Well, we normalized out the full amount of the cost indicate what the impact of the spill would be in terms of the non-insured costs, the components are the loss of revenue on both the 6B and 6A spills and the insurance deductibles. Beyond that, all the expenses that were incurred, we would expect to recoup substantially all of those from insurance with the usual back and forth discussion that we would expect to go through with the insurance discussion with the insurance adjusters on specific details of those costs.

Okay. So there's no other major buckets that you don't expect to be covered at least from the provision you took during the quarter?

That's correct. With the proviso the fines and penalties would not be covered by insurance.

Right. But you didn't provide for that during the quarter, did you?

That's correct.

No.

Okay. So, just -- the other question I had is you've got the dispute on Clipper and you're in discussions, as you've mentioned with shippers. You've got ITS out there. And then the Southern Lights dispute. You know, are you looking at all of these -- are all of the discussions separate items or are you talking with the shippers about maybe one kind of larger comprehensive agreement that might be covered under the new ITS going forward?

Well, Robert, it is kind of yes and no. I think, to that question. With regard to Alberta Clipper, the -- we have agreed with those that were opposing and with the agreement of the NEB to suspend that hearing that had been planned for early November and roll those discussions into the comprehensive toll settlement discussions. So, as you implied, it will become part of a broader discussion with regard to Southern Lights. That is a separate issue and under discussion.

Okay. So, bottom line, maybe excluding Southern Lights, we could end up with some sort of black box type settlement here, rather than say specific impacts on either line?

So, yes, maybe I'll have Richard just comment on exactly how that will be wrapped in.

So, I think the most important thing to understand on the Southern Lights FERC matter, Robert is that it is really a matter as between shippers, it's as a matter between a non-committed shipper, a non-contracted shipper and the contracted shippers. We're pretty much in the neutral -- what the magnitude of the spot toll will be, which the contracted shippers benefit from having that as a high number, and that was one of the benefits of the effectively contracted for, so to speak, when they signed up. And the spot shipper would like that to be a lower number, (inaudible - background noise). It has very minimal financial impact on us.

Okay. So, the contracted shippers don't have an out if the economic -- or what they thought they were getting into changes based on a FERC decision?

No, they do not.

Okay, great. Thank you very much.

Thanks, Robert.

(Operator Instructions)

Your next question comes from the line of Andrew Kuske with Credit Suisse. Please proceed.

Good morning. Just in the context of the interest rate environment that we have right now, it is very good from a financing perspective and pushing debt into the market but the flip side of that is do you see returns coming under great pressure, either from a regulated standpoint or really just on a contractual basis, given the financability of certain assets now is much lower than it has been, historically?

Well, I think it is fair to say, Andrew, that if you go back to the original multipipeline formula, any asset subject to that formula and its annual variations based on a 30-year long Canada bond would be subject to some downward pressure, in light of interest rates. Recognizing we have very few assets subject to that. And hence, but, so -- and the majority of the settlements that we've got are negotiated settlements. But assets that are subject to that, yes. You would expect to see some downward pressure.

But even just on a negotiated basis, your shippers primarily, and to what degree are the conversations becoming a little bit more contentious on the rates of return that you receive, in part, just because debt costs are so cheap right now?

Well, to date, we haven't really experienced that and, as you know, that's been one of the real strengths of our system overall is our very strong competitive positioning where we're kind of the base fundamental rate is not, obviously, it is part of something like a comprehensive toll settlement, that could well be the case. But if you look at a competitive region like the Bakken or competitive region like the Oil Sands region, that really doesn't form a big part of the negotiation.

And then just a question on a little bit of a different track. Obviously, at the investor day, you announced some organizational changes at the top. But just throughout the organization, as your business is changing and your business mix is changing a little bit, could you just give us a bit more robust discussion on what you've done, from the hiring standpoint and just how you see the organization changing from a people -- from a people and manpower perspective?

And sorry, Andrew. This is as a result of the organization changes we made October 1?

But, also a bit of the change to your business? Obviously, you're buying into renewable powers to a certain degree and you've got a lot of -- a lot more projects of a smaller size than bigger projects that you've had in the past?

Yes. Well, first of all, as a result of the changes that we made October 1, then I'll come back and answer the latter part of the question, but with regard to the October 1 change, it is really to emphasize areas like operations, pipeline integrity and control center operations, so it doesn't really impact the hiring plan. It's elevating in terms of reporting relationship and seniority in the Company and then the structuring of the operating committee that I mentioned at investor day, as well, to ensure that we exchange information operationally from a safety and integrity point of view across all business units in the Company. And those positions have all been filled internally.

With regard to renewables, we, of course, do continue to hire and expand and grow that group that has been a combination of people from within the Company and external hires. And I've mentioned this before. It is one of the areas of such a high degree of enthusiasm and it is a very good way to attract good, young, new people to the Company. We've found that it is one of the quotes, easier areas, to recruit new people into the Organization in that most recognize that the future holds great promise in the renewables business and hence, there are a lot of new engineering business development people looking to get into the business. I think -- just a general comment as well in that we've always maintained that we've got a very deep bench at Enbridge, and the fact that we have had relatively low turnover in this Company for a number of years now, we've had a lot of people prepared and willing to accept and take on new responsibilities.

That's helpful. Thanks.

(Operator Instructions)

Your next question comes from the line of Carl Kirst with BMO capital. Please proceed.

Thanks, good morning, everybody. I think most of my questions have been answered. Maybe one clarification, if I could, on the Bakken expansion. The binding open season that was extended to November 30, is that to round out the 145,000 initial phase or could that potentially amass volumes that would go higher into that expansion, if you will? And also on that front, how much capital costs would it actually take to go from that 145,000 to the 300,000 plus number?

That's a great question, Carl. And part of the open season is designed to explore that question, as to how soon the expansion of the Bakken expansion would need to take place. And that really is what we're doing. We have all of the commitments we need for the initial build of the system and the 145,000 barrels a day capacity system. And part of the open season is to give shippers the opportunity to sign up for term deals at favorable rates. And that's part of what we'll decide at the conclusion of that, is at what point will we need to expand to the higher capacity. I don't have the capital number off the top of my head for that expansion. That will have to come out later. But generally, it is very cost-efficient because once you've laid the pipe, you can always add the intermediate pump stations.

So, this is just pumping that's being added then?

Yes. Well, the basic Bakken expansion program involves new pipe in North Dakota and Saskatchewan. The expansion of that would be simply horsepower.

Exactly. Okay. Thank you.

Thank you.

your next question comes from the line of Pierre Lacroix with Desjardins. Please proceed.

Thank you very much. Just wanted to come back a little bit on the midstream business. You had the discussion about that in the investor day. And your interest to go back to that business. Do you have any kind of update to provide at this point?

Really, no update at this point, Pierre. As you know, we're big in that business in the US. And our comment was that we felt that we could translate some of that competitive advantage and skill set into the midstream business in Canada, assuming that the midstream business opens up a little more to third party players from the tradition of having it handled primarily by producers. So, we've got a few things that we're looking at but nothing substantial that we're able to announce at this point.

Okay, great. And also on the international front, you mentioned Australia, Chile. Anything special going on there for now or anything to expect in the next six to 12 months on this side?

Well, we're continuing to work on a couple of good opportunities and it wouldn't surprise me if we have something over the next six to 12 months, to use your time frame. But as always, in doing business development, it takes time to work projects up to a level that meets our discipline and hurdles. So, but I will say that I'm encouraged by some of the opportunities I see for us internationally.

Thanks very much.

Thanks, Pierre.

your next question comes from the line of Justin Amoah with Argus Media. Please proceed.

Hello, thanks for taking my call. During your investor day, you outlined the Monarch and Eastern extension pipeline projects. I'm wondering what kind of timing you're thinking around an application approval and then subsequent construction of those projects?

Sure, Justin. It is Steve. The Monarch project generally would fit into the 20 -- in service, end of 2012 time frame. Early 2013 so, backing up from that, I wouldn't predict exactly when we would file anything. But we're working to a time line like that for the Monarch project.

In terms of Eastern extension, as I said at Enbridge Day, there is a need to move light crude east and that really is the driver, especially as Pat to, refineries convert to run Canadian heavy oil, there will be a surplus of light, that we think needs to go east. There are a number of different possible ways of doing that, that we're working on. And I can't be specific right now as to exactly which of those ways we will ultimately choose. But there is a combination of some existing pipes as well as new build possibilities for that.

Okay. Thank you. And I know you guys have also been looking at reversing Line 9. Is that something you're still considering?

Yes, Line 9 reversal, which we called the Trail Breaker project about three years ago or thereabouts, really depends on a number of factors. First of all, that it is not needed in westbound service and it still is being used continuously to move crude west from Montreal to Southwest Ontario. And then also, the equation with regard to Line 9 reversal, involves the demand in Montreal for Western Canadian oil and also it would also depend on the reversal of one of the Portland pipelines down to Portland, Maine. So, there's a few pieces and variables in that, that we'll continue to work as part of this whole Eastern Access question.

Okay. Thank you.

Thank you.

(Operator Instructions)

Your next question comes from the line of Sam Kanes with Scotia Capital. Please Proceed.

Just a general question, it has to do with Shell Gas and liquids component of Shell Gas. Run across a couple of folks that seem to be convinced that Marcellus liquids are what some folks from Texas are deploying more cap to than less, lately. Given that oil at CAD84 and gas below CAD4 and the bias is toward Haynesville and Barnett being somewhat drier, at least relative to Marcellus. Are you seeing any of that type of flow and is there -- what type of exposures could there be to the asset mixture with an EEP on this?

Sam, we definitely are seeing kind of a flow. In fact, a good part of the gas-oriented drilling that's occurring in North America right now is chasing liquids rich gas, for the obvious reason of the basic 20 to 1, oil to gas pricing that we're seeing. That has been a huge benefit to us and at Anadarko. And as you know, the most recent acquisition that we did in the Anadarko was to take advantage of that trend and as you also know, we have been looking at opportunities to get the liquids out of the Marcellus and either over into the Aux Sable plants or into Sarnia. So, yes, that definitely is a trend. And, I would suggest that it will be around as long as we have this. I was going to call it disconnect between oil and natural gas prices. But, I'm beginning to think it is the norm rather than the disconnect. So, yes. Very strong trends in that direction. And to other liquids rich gas plays in North America.

Does that by inference then mean there's some form of exposure to the existing asset base within EEP?

Well, some assets will be probably less drilled and some more. Like I say, Anadarko --

-- is a plus.

Is a big plus. We probably won't see quite the same level of activity in the Barnett and the Haynesville but for sure, we're picking up more in the Anadarko than we're losing in the other basins.

I see. That's -- you what you said, what I was coming at, where's the net position for you?

In other words, the net has been a net positive for us, Sam.

Thanks, Pat. And just -- albeit it has only been a month and I don't think that much new capital has been deployed or allocated but, where you stand currently on free equity availability for acquisitions or other here, I imagine hasn't changed much but maybe it has? I don't know.

Richard?

Yes, no that hasn't really changed at this point. We've got -- effectively, the picture is the same as it was at Enbridge Days. We've got ample free equity to accommodate everything that we anticipate we're going to secure over the next five years and probably a little more than that, besides.

Thanks, Richard. Thank you.

your next question comes from the line of Lucretia Cardenas with Platts. Please proceed.

Hello. My quick question is earlier you were talking about the reversal of the 25,000 barrel per day pipeline. I think you said you said it was called Portalink? Could you elaborate on that a little bit? I'm not very familiar with that pipeline or from where it runs to and the timeline on that?

Sure. Lucretia, it's Steve. We built that pipeline in around 1996 after we had acquired the Saskatchewan and the North Dakota systems and we connected them together with the line called the Portal Link. And at that time, the reason for it was that the production in Saskatchewan was overwhelming the capacity of our Saskatchewan system and there was excess capacity in the North Dakota system. So, we built the Portal Link to make use of the excess North Dakota capacity and to get crude from Saskatchewan down into North Dakota into our North Dakota system and over to our main line at Clearbrook, Minnesota. Since then, of course, the Bakken projects have come on very strongly and basically filled up everything in North Dakota. And for that reason, we shut the Portal Link down in about 2006. And so, that line sits ready having flowed southbound for a number of years. We're now in the process of reversing it by the end of the year and we'll flow it north into Saskatchewan, where we now have a little bit of extra capacity, especially with the Saskatchewan expansion coming on by the end of this year. So, that's really what that's all about. It's very low capital and it will give about a 25,000 barrel a day capacity increase exiting the Bakken.

And the expansion of the Saskatchewan project, again, from -- how much more capacity will you have then, and I'm guessing where does that connect to the main line?

Yes, the Saskatchewan system phase two expansion which is underway now, is going to add 125,000 barrels a day of capacity in Saskatchewan going over to a terminal at Cromer, Manitoba which is where it connects to the main line.

Thank you very much.

Thank you.

Your next question comes from the line of Scott Haggett with Reuters. Please proceed.

Sorry, I was just wondering if I can get some sense of your thoughts on what the regulatory regime in the US will be following the spills and what kind of -- whether or not you expect increased costs for compliance with that regulation as we go forward?

Scott, at this point, I think it's probably too early to say. We really don't expect much, if any, increase in cost. As you know, Enbridge's program was always well within all of the regulatory guidelines and even if there is -- for example, a tightening up in terms of inspection period or in-line inspection period, we were inspecting far more frequently than was required by regulation in the past. So, that wouldn't necessarily change anything. So, at this point, and I'm kind of looking to Steve, if you have anything to add, Steve, I don't think we would expect a significant cost change? It may, as you know, we're accelerating of some of the dig and remediation on Line 6B but those were costs that were planned and it's only a timing issue rather than a change in costs ---

-- I think that's right. I think that we certainly are in discussion directly and also through associations in Washington in discussion with the regulators and looking at where pipeline safety legislation is likely to go. But I think that, that as Pat said, our program has been very robust from a capital and operating cost perspective all through the years and we may refocus some of that, but at this point, I don't think there is any step change that's contemplated.

Great. Thanks. Just one more thing. Is there a cost assessment yet for the St. Clair River crossing?

That is going to be around CAD11 million.

Okay. Got it. Great. Thank you.

There are no further questions in queue at this time. Ladies and gentlemen, that concludes today's conference. Thank you for your participation. You may now disconnect. Have a great day.