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Enbridge, Inc. (NYSE:ENB)

Q3 2010 Earnings Conference Call

November 3, 2010 9:00 AM ET

Executives

Guy Jarvis – VP, IR and Enterprise Risk

Pat Daniel – President and CEO

Richard Bird – EVP, CFO and Corporate Development

Steve Wuori – President, Liquids Pipelines

Analysts

Ted Durbin – Goldman Sachs

Juan Plessis – Canaccord

Matthew Akman – Macquarie

Robert Kwan – RBC Capital Markets

Andrew Kuske – Credit Suisse

Carl Kirst – BMO Capital

Pierre Lacroix – Desjardins

Justin Amoa – Argus Media

Sam Kanes – Scotia Capital

Lucretia Karinaz – Platts

Scott Haggett – Reuters

Operator

Good morning, ladies and gentlemen. Welcome to the Enbridge Inc. 2010 third quarter financial results conference call.

I would now like to turn the meeting over to Mr. Guy Jarvis.

Guy Jarvis

Thank you and good morning. Welcome to Enbridge Inc.’s 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 website 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’d like to turn the call over to Pat Daniel.

Pat Daniel

Thank you, Guy, and good morning, everyone. Thank you for joining us for our review of the third quarter results. Before we get into our Q3 results, I’d 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 27th for the primary cleanup of the leak site as you know. By September 27th, we had met the deadline for cleanup of Talmadge Creek in the Kalamazoo River, and then earlier this week, the EPA confirmed that we’ve also met the October 31st 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 EPA’s Michigan Department and 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 environment 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 ongoing. 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 in 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, three months now, we’ve had as many as 2,000 workers in their communities working around the clock on the cleanup. We placed the highest priority in our relationships with the communities and their 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 and then I will turn it over to Richard to walk through the results in a little more detail.

As you all hear, Quarter 3 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 $2.50 to $2.70 per share.

I am 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, I, 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 am going to go back to the very start of the year when Enbridge Energy Partners placed into service the $140 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 plays resulted in the expansion being consistently full from Day 1. And this, of course, is creating further opportunities for Enbridge, and I am going to come back to that in a moment.

In April of this year, we placed into service the $3.7 billion Alberta Clipper project, which added 450,000 barrels per day capacity out of Western Canada. And once again, we completed that project on budget and ahead of schedule.

On October 1st of this year, we received the first oil on the Alberta Clipper pipeline at our terminal in Superior, in Wisconsin. So very pleased with that milestone.

In July, we placed into service the $2.3 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 that can generate enough energy to meet the needs of approximately 12,800 homes.

Altogether, we brought $6.5 billion in projects into service in the last ten months. And notably now, all of those projects are generating cash flow.

Closing out the year, we are on track to commission the $285 million 100 megawatt Talbot Wind Project, as well as $140 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 that 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 have been able to firm up near-to-medium term growth plans with the announcement of a number of secured projects which will come into service between 2011 and 2014.

First of all, within our Liquids business, we’ve announced over $2.4 billion in projects over the past ten months. Firstly, our Christina Lake infrastructure serving us in all these projects, and this $250 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 $185 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. And this is $400 million expansion plan to be in service in the second half of 2013, and 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. And I think you will recall this is a $370 million project that’s going to serve growing production from Suncor. It’s a new 95 kilometer pipeline, and will be built in the same right-of-ways of our existing Athabasca pipeline and between the Cheecham terminal and the Suncor site.

We signed two more agreements in September adding further to roster of oil sands projects over the summer. At first, we announced that we have been chosen to be the service provider for the Husky Sunrise Project. This is a $475 million Norealis Pipeline system, which will include the new originating terminal at the Sunrise mine site and 112 kilometer pipeline, an 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 (NYSE:CAB) to expand our Edmonton tank farm by 1 million barrels at a cost of $260 million.

So with the largest operator of oil sands regional infrastructure and with our corresponding ability to provide phased 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 have enough commitments to go ahead now with our next Bakken expansion program, increasing takeaway capacity from the Bakken play by 145,000 barrels per day and that can also be very readily expanded to 325,000 barrels per day. While we already have enough contracted anchor volumes to grow for projects, we are 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 that’s going to include capital spending of about $190 million in our Saskatchewan system on the north side of the border, and then another $370 million on our North Dakota assets, south of the border. We will 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 $275 million 100 megawatt Greenwich Wind Power project near Thunder Bay, Ontario; And then in June, as you will recall the $500 million 250 megawatt Cedar Point wind Project near Denver, Colorado, that’s notable for 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 on stream and announcing new projects.

So with that, let me turn it over to Richard to go through the Q3 – to review results in a little bit more detail. Richard?

Richard Bird

Okay. Thank you, Pat and good morning everyone. Taking up on Slide 8 of the slide package if you are following that. As Pat mentioned earlier, this morning we released our second quarter results and year-to-date reported net income was $637 million or $1.73 per share. That’s a decrease from 2009 when we reported $1 billion and $255 million as our earnings, which was $3.45 per share. And this 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 investment in the Ocensa pipeline in Columbia. That was $329 million gain. In addition, this quarter picks up $385 million negative impact from costs associated with our clean-up 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 to clean-up.

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 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 non-operating 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 get 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, the longer having an earnings profile that is backend weighted due to the removal of performance metrics within the 2010 incentive tolling settlement, also our weaker performance anticipated in offshore pipelines in the fourth quarter.

And 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 9. Liquids pipelines adjusted earnings rose $9 million in the quarter and $82 year-to-date when compared to 2009. Placing both the Alberta Clipper and the Southern Lights, its 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 1st in service date of Southern Lights and the April 1st in service date of Alberta Clipper, earnings from the recognition of ADDC [ph] on the rolling capital balances further increased earnings in 2010 relative to 2009. The Spearhead Pipeline once again had a strong quarter, including the recognition of makeup rates which expired in the quarter at which we then recognized the associated earnings as well as stronger volumes due to the expansion placed into service in 2009.

Within natural gas delivery and services, adjusted results were higher by $20 million in the quarter and $8 million year-to-date. Enbridge Gas Distribution’s 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 $6 million over the third quarter of last year exactly offsetting the reduced earnings earlier in the year for this change which we mentioned in 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 but the timing of expenses were result in a clawback of some 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 and its results increased by $6 million. This was due to improved margin opportunities in natural gas marketing in the quarter. However on 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 continued 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 it in the first and second quarters of this year, that combines $0.75 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 cost associated with the two lead incidents. And this strength is due to increased transportation results as a result of the completion of Phase II of the Southern Access expansion in 2009 as well as two quarters earnings from the Alberta Clipper project and the impact of the Phase VI 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 1st 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 to prior year, while 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.

Pat Daniel

Great, thanks Richard and so just let me very quickly summarize. First of all clean-up efforts are progressing well in Michigan. And at this point, our focus is turning now primarily to implementing longer term monitoring programs. Secondly, notwithstanding this field, 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’ve placed into service nearly $6.5 billion in growth projects and we’ve lined up another $3 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 onto the Q&A session.

Question-and-Answer Session

Operator

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

Ted Durbin – Goldman Sachs

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

Pat Daniel

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

Steve Wuori

No, I think that’s right. I think that obviously the agencies will consider a lot of factors in determining a refines, and it will take I am sure into sometime in 2011 before that happens.

Ted Durbin – Goldman Sachs

Okay, thanks. You didn’t talk at all about Gateway, really if this is a long process, so maybe just give us an update on the regulatory process there?

Pat Daniel

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 our quick overview Ted, of where we stand.

Ted Durbin – Goldman Sachs

Okay, and then if I could just one more. If you just look at Bakken take away solution versus some of the competing proposals out there. How would you characterize sort of your proposal versus others? Maybe talk a little bit about – I think you pushed back the open season, what was the thinking there too?

Steve Wuori

Sure. Ted, just a few thoughts there. The reason that we extended the open season to November 30th 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 the 30th.

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 length pipeline, which used to flow south bound, 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 mainline system where you have the flexibility to get to all the markets that the Enbridge system reaches.

So I think 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’s 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.

Ted Durbin – Goldman Sachs

Okay, very good, that’s all for me. Thank you very much.

Pat Daniel

Thanks Ted.

Operator

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

Juan Plessis – Canaccord

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

Steve Wuori

Sure Juan. 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 10 years.

Each of the agreements before has had a certain flavor to it with an emphasis based on the shippers’ 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.

Juan Plessis – Canaccord

Okay thanks. Now you’ve done a good job in the past of picking costs out, do you think there could be more upside on future ITS elements?

Pat Daniel

You mean in terms of cost reduction?

Juan Plessis – Canaccord

Yes.

Pat Daniel

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

Juan Plessis – Canaccord

Great, thank you very much.

Pat Daniel

Thank you.

Operator

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

Matthew Akman – Macquarie

Thanks. This question is probably for Richard. I’m wondering what the full, I guess, impact on Enbridge was of providing any resources to the partnership during this spill? It looks like there only maybe $7 million.

Richard Bird

It was about $7 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.

Matthew Akman – Macquarie

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

Richard Bird

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

Matthew Akman – Macquarie

Okay, thanks for that. A quick follow-up question; on October 27th 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 could just clarify.

Steve Wuori

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

Matthew Akman – Macquarie

Okay.

Pat Daniel

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

Matthew Akman – Macquarie

Okay thanks. That’s all I had.

Pat Daniel

Okay thank you.

Operator

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

Robert Kwan – RBC Capital Markets

Good morning. Just on the spill costs, can you just talk about what the noninsured portion of the amount that you booked? I know you talked about I think $3 million net to you on lost revenue. So were there any other impacts that you normalized out?

Richard Bird

Well, we normalized how the full amount of the costs to indicate what the impact of the spill would be. In terms of the noninsured costs, 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.

Robert Kwan – RBC Capital Markets

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

Richard Bird

That’s correct with the proviso that fines that penalties would not be covered by insurance.

Robert Kwan – RBC Capital Markets

Right. But did you then provide for that during the quarter, did you?

Richard Bird

That’s correct. No.

Robert Kwan – RBC Capital Markets

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

Pat Daniel

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

Robert Kwan – RBC Capital Markets

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

Pat Daniel

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

Richard Bird

So I think that the most important thing to understand on the Southern Lights FERC matter Robert is it’s really – it’s really a matter as between shippers, it’s as a matter between a non-committed shipper and non-contracted shipper, and a contracted shippers, and we’re pretty much in the neutral [inaudible] is what the magnitude of the spot tool 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 floor so to speak when they signed up that the spot shipper would like that to be a lower number, and so FERC will have to decide on that. It has a very minimal financial impact on us.

Robert Kwan – RBC Capital Markets

Okay. So the contracted shippers don’t have an out if kind of the economic or what they thought they were getting into changes based on referred decisions?

Richard Bird

Probably do not.

Robert Kwan – RBC Capital Markets

Okay great, thanks very much.

Pat Daniel

Thanks Robert.

Operator

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

Andrew Kuske – Credit Suisse

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

Pat Daniel

Well, I think it’s fair to say Andrew that if you go back to the original multi-pipeline formula, any assets 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.

Andrew Kuske – Credit Suisse

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

Pat Daniel

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 kind of the base fundamental rate is not – obviously it’s 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 a competitive region like the oil sands region that really doesn’t form a big part of the negotiation.

Andrew Kuske – Credit Suisse

And then just a question on a little bit of a 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 of a robust discussion on what you’ve done from the higher standpoint and just how you see the organization changing from a people and manpower perspective?

Pat Daniel

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

Andrew Kuske – Credit Suisse

And also a bit of the changes in your business. I mean, obviously you’re biasing into renewable powers – to renewable power to a certain degree and you’ve got a lot more projects of a smaller size than bigger projects that you’ve had in the past.

Pat Daniel

We – well, first of all as a result of the changes that we made October 1 – and then I’ll come back and answer the latter part of the question – but with regard to the October 1 change, it’s really to emphasize the areas like operations, pipeline integrity and control center operations. So it doesn’t really impact the higher 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 is well to ensure that we exchange information operationally from the safety and in an 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 expanding and grow that group. And it’s been a combination of people from within the company and external hires. And I’ve mentioned this before, but it’s one of the areas of such a degree of enthusiasm and it’s a very good way to attract good young new people to the company.

We found that is one of the quotes easier areas to recruit new people into the organization and that is most recognized that the future holds great promise in the renewables business and enhance through a lot of new ensuring business development people looking to get into the business.

Andrew Kuske – Credit Suisse

That’s very helpful, thank you.

Pat Daniel

We think – just a general comment is, well, and 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 got lot of people prepared and willing to accept and take on new responsibilities.

Andrew Kuske – Credit Suisse

That’s helpful, thanks.

Operator

(Operator Instructions). Your next question comes from the line of Carl Kirst with BMO Capital. Please proceed.

Carl Kirst – BMO Capital

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 30th is that to round out the 145,000 initial phase or could that potentially mass volumes that would go higher into that expansion, if you will? And also along that front, how much capital cost would it actually take to go from that 145 to 300 plus number?

Pat Daniel

Yes, it’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 the commitments we need for the initial build of the system in 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.

And the conclusion of that is, at what point will we need to expand that 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’s very cost efficient, because once you’ve laid the pipe, you can always add the intermediate pump stations.

Carl Kirst – BMO Capital

So this is just pumping that’s being added then.

Pat Daniel

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

Carl Kirst – BMO Capital

Exactly. Okay, thank you.

Pat Daniel

Thank you.

Richard Bird

Thanks Carl.

Operator

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

Pierre Lacroix – Desjardins

Thank you very much. Yes, I just want to come back a little bit on the midstream business, you had a 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?

Pat Daniel

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 damaged and skill set into the midstream business in Canada, assuming that midstream business opens up a little more to third-party players from the tradition of having and 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.

Pierre Lacroix – Desjardins

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?

Pat Daniel

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 timeframe. But as always in doing the business development, it takes the 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.

Pierre Lacroix – Desjardins

Thanks very much.

Pat Daniel

Thanks Pierre.

Operator

Your next question comes from the line of Justin Amoa with Argus Media. Please proceed.

Justin Amoa – Argus Media

Hi, 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 in application approval, and then subsequent construction of those projects?

Steve Wuori

Sure Justin, it’s Steve. The Monarch project generally would fit into the 20 – in service end of 2012 timeframe, early 2013. So backing up from that I wouldn’t predict exactly when we would file anything, but we’re working to a timeline like that for the Monarch project. In terms of Eastern Extension, as I said at Enbridge Day, there was a need to move light crude needs and that really is the driver, especially as PADD II refineries convert to run Canadian heavy oil, there will be a surplus of light that we think needs to go East. And 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 pipe as well as new build possibilities for that.

Justin Amoa – Argus Media

Okay, thank you. And I know you guys have also been looking at reversing Line 9, is that something you’re still considering?

Steve Wuori

Yes, Line 9 reversal which we called the Trail Breaker project about three years ago or thereabouts, it really depends on a number of factors. First of all, that it’s not needed in West Bound service and it still is being used continuously to move through the West from Montreal to Southwest Ontario.

And then also the equation I think with regard to Line 9 reversal involves the demand in Montreal for Western Canadian oil and also it would also depend on a reversal of one of the Portland pipelines down the Portland mains. So there is a few pieces and variables in that that will continue to work as part of this Eastern Access question.

Justin Amoa – Argus Media

Okay, thank you.

Pat Daniel

Thank you.

Operator

(Operator Instructions). Your next question comes from the line of Sam Kanes with Scotia Capital. Please proceed.

Sam Kanes – Scotia Capital

Just a general question, it has to do with shale gas and liquids component of shale gas. I 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 is $84 and gas below $4, and that the bias is towards Haynesville and Barnett being somewhat dryer, 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 within EEP on this?

Pat Daniel

Sam, we definitely are seeing a 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 region of the basic 20 to 1 oil to gas pricing that we’re seeing. That has been a huge benefit to us and the Anadarko.

And as you know the most recent acquisition that we did in the Anadarko was to take advantage of that that trend. And as you also know, we have been looking at opportunities to get the liquids out of the Marcellus and either rove her into the Aux Sable liquids plant [inaudible].

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’s the norm rather the disconnect. So, yes, very strong trend in that direction and to other liquids rich gas plays in North America.

Sam Kanes – Scotia Capital

Does that by the inference stand, I mean there is some form of exposure to the existing asset base within EEP?

Pat Daniel

Well some assets will be probably less drilled and some more. Like I say, Anadarko where we’ve –

Sam Kanes – Scotia Capital

It’s a plus.

Pat Daniel

Is a big plus, that 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 Anadarko that we’re losing in the other bases.

Sam Kanes – Scotia Capital

I see the phase of those was the net position for you.

Pat Daniel

Yes. And it’s been a net positive for us, Sam.

Sam Kanes – Scotia Capital

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

Pat Daniel

Richard.

Richard Bird

Yes, no, that hasn’t really changed. At this point, we’ve got, in fact only the pictures [inaudible] at Enbridge Day is 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 bit more than that besides.

Sam Kanes – Scotia Capital

Thanks Richard. Thank you.

Operator

Your next question comes from the line of Lucretia Karinaz [ph] with Platts. Please proceed.

Lucretia Karinaz – Platts

Hi. Quick question is, earlier you were talking about the reversal of the 25,000 barrels a day pipeline, I think you said it was called Portal Link. Could you elaborate on that a little bit? I’m not very familiar with that pipeline or where – from where it runs to and the timeline on that.

Steve Wuori

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 a 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 in the North Dakota into our North Dakota system and over to our mainline at Clearbrook, Minnesota.

And 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 south bound for a number of years.

We are 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 all, it’s very low capital and it will give about a 25,000 barrel a day capacity increase existing the Bakken.

Lucretia Karinaz – Platts

And the extension of the Saskatchewan project, again, from how much more capacity will you have then? And I’m guessing where does that connect to the mainline?

Steve Wuori

Yes, the Saskatchewan system phase two expansion which is underway now is going to add a 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.

Lucretia Karinaz – Platts

Thank you very much.

Steve Wuori

Thank you.

Operator

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

Scott Haggett – Reuters

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?

Pat Daniel

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 it 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, do you have anything to add Steve, I don’t think we’d expect to have significant cost change. It may, as you know, we’re accelerating 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 the change.

Steve Wuori

I think that’s right. And I think that we certainly are in discussion directly and also through associations in Washington in discussion with the regulators, and looking at where the pipeline legislation is likely to go.

But I think 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.

Scott Haggett – Reuters

Great, thanks. Just one more thing. Is there a cost estimate yet for the St. Clair River crossing?

Steve Wuori

That is going to be around $11 million.

Scott Haggett – Reuters

Okay, thank you.

Operator

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.

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