恩橋 (ENB) 2011 Q3 法說會逐字稿

Good morning, ladies and gentlemen, welcome to the Enbridge Inc. third quarter 2011 financial results conference call. I would now like to turn the meeting over to Jody Balko. Please proceed.

Thanks, Latasha. Thank you and good morning and welcome to Enbridge Inc's third quarter of 2011 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, and John Whelen, Senior Vice President and Controller.

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 pod cast 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 the same as always. 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 Jonathan Gould and I will be available after the call for any follow-up questions that you may have.

So before I begin, I'd like to point out that we may refer to forward-looking information during the 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. This slide includes 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.

And with that I'd like to turn the call over to Pat Daniel.

Great. Thanks, Jody, and good morning everyone. Thank you for joining us for a review of our third-quarter results. As you know earlier today, we were very pleased to announce that our adjusted earnings for the third quarter were CAD241 million, or CAD0.32 a share. On a year-to-date basis, that puts us at CAD385 million -- sorry, CAD835 million of adjusted earnings or CAD1.11 per share, and this is an increase of roughly 10% relative to the same point last year. You'll note that our GAAP earnings for the quarter of CAD4 million looks a little unusual. This is driven by the mark-to-market impact of several of our hedging programs. You're likely aware we actively worked to remove market price volatility from our businesses, and we will speak in a little more detail on the dynamics giving rise to that accounting and outcome as we go through our morning.

Based on a strong first 3 quarters, we're now very confident that 2011 will be yet another good year for Enbridge. And we're now updating our guidance for 2011 to be near or slightly above the top end of the original guidance range of CAD1.38 to CAD1.48. The strong performance comes from all areas of the business. And of course, one of the main drivers during this quarter is the liquids pipeline segment, where we've seen stronger than expected volumes on the mainline system. You'll recall that increasing volumes now drive higher returns from our Competitive Toll Settlement, that took effect at the start of the third quarter of this year.

I'd now like to just review some of the more recent project announcements that we've made, and of course many of you on the line today will have been part of our annual investor conference in Toronto or New York at the beginning of October. But for any of you that weren't, I would certainly encourage you to take the time to access our replay, go to the transcripts that are available on our website from that very thorough presentation. At that time, the management team spoke at length around about the significant opportunity set that we have ahead of us, and it was right across the organization. What was at the time an CAD8.5 billion secured project portfolio is now even bigger, as we've been successful on several fronts, even since Enbridge Day. As a result we now commercially secured nearly 50% of the total growth capital that we expect to have invested by 2015. We'll continue to update this perspective of course as we announced additional projects along the way.

In our gas businesses we're very pleased to have now acquired 71% ownership of the Cabin Gas Plant Development in the Horn River Basin, and that's from Encana and other areas producers. And our offer to the producers holding the remaining 29% remains open. As it currently stands this represents a CAD1.1 billion investment, and it's a great fit for Enbridge. The Cabin Gas Plant Development enables us to bring our project construction and operational expertise to bear in the Canadian midstream space having of course been in this business for many years in Texas and Oklahoma through Enbridge Energy Partners. And then further, and the long-term, its long-term stable fee-based revenue is really complementary to the reliable business model at Enbridge that we speak so much about. And of course, on top of it all, there is further growth potential from this investment, as in when capacity beyond the initial 2 phases are required. So we're very pleased with that investment.

Also in our renewable power business, you have seen last week that we have acquired a 50% ownership interest in the Lac Alfred Wind Farm project from EDF Canada, and we're very pleased with this opportunity to enter the growing Quebec renewable energy market especially with a partner that has the proven development and operations track record that EDF has. The project of course has the same low risk contractual framework as the rest of our new renewable portfolio, and it's a turnkey project. It has a long-term PPA in place with Hydro Quebec. And just as importantly, it further reduces Enbridge's commitment to -- it reinforces Enbridge's commitment to environmental stewardship and it really progresses us further towards this goal of achieving an environmentally neutral footprint.

So in addition to those announced projects, we're continuing to make excellent progress on several other investment opportunities that we spoke to at Enbridge Days. These of course include our liquids pipeline market access initiatives, to expand access for US Bakken crude oil and for Western Canadian crude oil to additional markets in Eastern PADD II and Canada as well as to the US Gulf coast. The progress on these projects has been significant and notable since the signing of the CTS agreement, which has provided toll certainty to our shippers.

And I'll just reiterate my Enbridge Day comment that we've never before seen a broader or deeper array of attractive investment opportunities as what we have today, providing us with a very high level of confidence that we can achieve a growth rate and EPS averaging 10% through the middle of the decade. At the same time of course, we continue to attach the highest priority to operational safety and integrity, as we mentioned at the investor day conference.

So with that brief update on some of the more recent business development issues, what I'll now do is hand it over to Richard to get into the financial results for the quarter in a little more detail. Richard?

Thank you, and good morning. So picking up on slide 10 of the visuals, I'm going to start by spending a few minutes on the difference this quarter between our raw GAAP earnings and the adjusted earnings. And the slide depicts the net adjustments to the raw GAAP earnings to arrive at adjusted earnings over the last 4 years, just to put the current quarter in context. Some of the more significant noise factors that we've adjusted out have been the gains on asset sales, the effect on future income taxes of tax rate changes and the mark-to-market movements on the hedges we put in place in support of our reliable business model, which is playing up the effect in the current quarter. All of the hedges we put in place through financial derivatives are designed to reduce the volatility of cash flow and earnings due to movements in exchange rates or interest rates or commodity prices. And we do that by locking in rates applicable to future cash flows.

Moving to the next slide as an example, the new CTS agreement means that our revenues on the Canadian Mainline are now received in US dollars and shortly before the CTS agreement was approved by the NEB, we were able to lock in the exchange rate at a better rate than the forecast that we based our agreement on, and bring our US dollar exposures in line with the way we've managed our other US dollar exposures, generally about 80% hedged through the 2015 forecast period, a little higher in the front end. So as the future unfolds and the exchange rate fluctuates our cash flows and our adjusted earnings will be relatively unaffected. And as a result, our ability to achieve that 10% average growth rate that Pat referred to will depend largely on the underlying performance of the business, and not much on exchange rates.

So moving to the next slide, slide 12, and coming back to the big difference between the raw GAAP earnings and the adjusted earnings this quarter, we saw the Canadian dollar weaken abruptly and substantially at the end of the quarter, closing at a spot rate of CAD1.04 per US dollar versus CAD0.96 per US dollar at June 30. As the future unfolds, if the exchange rates were to remain at September 30 levels, we would see in each quarter our US dollar revenues coming back as a larger number of Canadian dollars than we were planning on. We would need to use part but not all of these extra Canadian dollars to settle the hedges, which mature and are realized in each quarter.

We would still be ahead of what we were planning on in each and every quarter, and the slide depicts this results, based on an illustrative CAD0.05 weakening. Which ties exactly into our MD&A FX sensitivity disclosure. You can see that the net impact is muted by the hedges as intended, but would still be favorable by about CAD64 million over the period and in fact, that's just the picture that you would see for our adjusted earnings.

Our foreign exchange hedges however are marked-to-market each quarter, under GAAP. So the whole change in the mark-to-market value of the derivatives is charged to the GAAP earnings in the current quarter and that's a CAD248 million number for the example on the slide. So the irony is, even though we would like to see the substantially weaker Canadian dollar of September 30 continue, it does play up that large mark-to-market noise effect you see in the third quarter GAAP earnings.

Moving onto slide 13, I'll next go over the adjusted earnings results which as Pat mentioned were once again stronger than we expected, and are now trending toward the top end of our full-year guidance range or slightly above. You can see from the summary on the slide that all of the segments are up for the third quarter versus the prior year, with biggest increases coming from liquids pipelines, gas pipelines, processing and energy services and the corporate segment. And in fact, it is these same 3 areas that are contributing more than we expected, resulting in the guidance bump.

Within liquids pipelines, the strength for the quarter and expected for the full year came primarily from the Canadian Mainline, now operating under the new CTS agreement. The primary factor is throughput volume, which has been a little stronger this year than we expected, including through the third quarter. I'll come back to the Mainline in a few minutes.

Our regional oil sands system is another source of strength in liquids pipelines. Gas distribution was up again this quarter, but we do expect to give back some of the year-to-date strength in the fourth quarter. In gas pipelines, processing and energy services, offshore had another weak quarter for the same reasons as discussed last quarter, and our full-year guidance allows for continued weakness. Aux Sable had an okay quarter but we're expecting a strong finish. Energy services continued to benefit from unusually favorable arbitrage opportunities which we expect to continue during the fourth quarter though not indefinitely, and I'll come back to this business as well.

Sponsored investments are on track with our expectations and corporate is doing a little better, primarily on lower financing costs, and we also expect to start seeing stronger earnings from the Verco. So taken altogether, we're seeing a CAD0.03 to CAD0.04 upward momentum in earnings per share for the full year, relative to our look at the second quarter. Bearing in mind that a good part of this is from the unusually favorable marketing margins.

Moving to the next slide, the one titled CTS revenue determinants, a number of you have been looking for additional information on how to roll forward our CTS earnings, so we've included a discussion of CTS revenue determinants and costs in the MD&A. The revenue determinants that are discussed there can be organized into a formula as laid out on the slide. The only variable in this formula which isn't straightforward is the scale factor. And it's required because, although a significant component of actual revenue does consist of heavy barrels moving from Hardesty to the US border, at the residual bench marked toll. It also consists of various other commodity types and various other receipt and delivery points to which different tolls apply, as well as non-toll revenue and line 8 and line 9 revenues. So the scale factor is intended to allow for these other revenues.

From the third-quarter data, you can back calculate the scale factor to be 1.20. It will tend to be more variable from quarter to quarter than it will be for a full year, and we also expect it to decline over time, as some of the non-IJT revenues that the scale factor is capturing decrease as a percentage of total revenue.

Moving to slide 15, our energy services business model, which I said I would back to, given that it's been a prolific moneymaker this year. Because it's been so profitable, I'll just go into a little more detail on this. Our energy services business employs several distinct strategies to generate earnings. They are simplest to understand separately though in reality many transactions include a combination of these strategies. There are parts of this business which operate on a simple fee for services basis. For example, barrels are aggregated in the field on behalf of producers, dominated on feeder and mainline systems, and delivered to a buyer, all for a fixed fee. This is the bread-and-butter part of the business. It's stable, it doesn't have a lot of profit, but it does provide good insight into where the best markets for crude are, and the challenges of getting it there.

The big money makers are the arbitrage strategies. There are always modest arbitrage opportunities to be captured by a services business with the right assets and skill sets. And some of the time the margins on these arbitrage plays open up quite significantly. They also tend to close back down as competitors figure out how to replicate or as storage and pipeline facilities are expanded. So I won't spend any time on the point in time or storage arbitrage, because I think the concept is pretty well understood, other than to say that Contango can be captured either by storing barrels in a tank or by moving barrels through a pipeline. I'll come back to the location arbitrage with an example of how it works in just a moment.

So you make money in this business either on the strength of your skills in ferreting out opportunities, and the logistical mechanics to capture them, or on the strength of a proprietary asset position, which is located advantageously. But you make the best money when you combine both of these skills and assets, and that's what we do. Our energy services group doesn't own many assets, but it does lease storage and rail cars. And most importantly, it holds nomination rights on a number of key pipelines as a result of its historical use of these lines. So it holds a scarce resource in times of apportionment on these lines, which makes it difficult for others to replicate certain arbitrage plays.

And moving then to the mid-continent arbitrage slide, location arbitrage opportunities do come in many places and with many different commodities. For example, moving condensate from Conway and Mount Belvieu to Edmonton for diluent has been a profitable business for us, but the one that makes the biggest difference in 2011 is a mid-continent light crude arbitrage depicted on the slide. And that depiction is a partial example of the strategy. There are actually many places that crude can be sourced from that are experiencing the mid-continent discount, and many paths that it can be moved on to reach the eastern PADD II market. But the variation depicted on the slide is the simplest.

The Eastern PADD II light crude refinery market tends to price off of LLS at St. James as its default supply option. On a delivered basis, at Patoka, this creates a theoretical arbitrage of up to CAD26 a barrel, based on the recent WTI to LLS discount. It is not possible to capture all of this theoretical arbitrage, but even a modest part of it makes for a nice profit. As I said earlier, it's this business that's a good part of the reason for our latest guidance bump, coupled with the strength in liquids pipelines. But we're certainly not counting on these unusual margin opportunities to persist for long. And with that, I'll turn it back to Pat.

Great, thanks, Richard. So, let me just very quickly summarize, first of all, it's shaping up to be yet another strong quarter for earnings growth. So much so that we are now increasing our earnings guidance to be near or slightly above the upper end of the original guidance range of CAD1.38 to CAD1.48. Secondly, we continue to have great success in securing new projects across all of our business units. And finally, we are even more confident that we can achieve an annual growth rate in EPS averaging 10% through 2015, based on conservative mainline volume and the project securement assumptions.

So that concludes our prepared remarks for this morning. I now would like to ask the operator to open up the phone lines to take questions.

Thank you.

(Operator Instructions)

I would first like to invite all analysts, first for questions and please allot one question at a time and return back in the queue for any follow-up questions. Later, we will prompt for media questions.

(Operator Instructions)

Please stand by for your first question. Linda Ezergailis, TD securities. Please proceed.

Thank you. Congratulations on a very strong quarter. I have a question with respect to your CTS details. My understanding is that there is a provision that allows parties to renegotiate the settlement if Keystone XL is not approved, and I'm wondering if you can elaborate on that, in the event that a presidential permit is not granted. Or, if it's delayed, at what point would a delay potentially trigger a renegotiation? And are there parameters laid out for the renegotiation? Or, do you just start from a totally new beginning?

Linda, the understanding that I have -- Richard or Jody correct me if I'm wrong on this, that if by the end of 2012, the presidential permit has not been granted to XL, then the producers have the right to renegotiate CTS with us, because it has been negotiated under the understanding that that system would ultimately be in place. The parameters around which it would be renegotiated are not defined. I think we just have to work closely with our customers, as we always have, to work out a mutually agreeable toll arrangement with them.

Thank you. And as a follow-up detailed question, your regional oil sands earnings growth year over year is CAD7 million. How much of that can be attributed to a change in your depreciation rate versus higher volumes in tolls?

Jody or --

Yes, I don't have that detail handy, and that's probably going a little more granular than we would go into in our disclosures.

Well, maybe you can just help us understand the magnitude of the change in depreciation rate on an annualized basis?

Yes, I don't have that either, Linda. Basically, we've re-synced the depreciation rates on those systems to reflect the longer tenor of some of the contracts more recently entered into, like the effective 45-year term on the Woodlands pipeline serving the Kearl Project. But I don't have the detailed breakdown of what the impact has been on earnings.

Maybe we can ask the Jodi and Jonathan to get back to you after the call, Linda, and provide what detail we can.

Okay. Thank you.

Juan Plessis, Canaccord Genuity. Please proceed.

Great. Thanks very much. Appreciate the additional information on the CTS. Given that this was the first quarter that the Mainline operated under the CTS, first, could you tell us if the contribution in the quarter was one that would be, I guess for a lack of a better word, a good run rate going forward excluding the impact of throughput?

Or was there something in the quarter that may have helped improve earnings like future tax benefits that may not necessarily be recurring? And secondly, with the integrity plan and the line replacement on 6B, should we be looking to see the US portion of the IJT increasing?

First of all, Juan, with regard to the first part of the question, I think it's fair to say that this should be a reasonable run rate, recognizing that with the volume sensitivity, it will depend on production and volumes out of the oil sands and out of the Bakken. But I think there's really nothing unusual outside of volume that drove the very strong performance to date. I'm sorry, the second part is with regard -- oh, the IJT. Richard, can you comment on the splits on the IJT?

Sure. So, a couple things. One is as Pat said, there isn't anything unusual about quarter, although I think we likely will see that scale factor that's referred to on the slide, something that tends to drift downward over time. And yes, with respect to the IJT and the split of that IJT, the additional capital on 6B will be one of the factors that will play into that but of course, there are other factors that play into that as well.

Okay. Thanks very much.

Thanks, Juan.

Carl Kirst, BMO Capital Markets. Please proceed.

Thank you. Good morning everybody. Also, great quarter and do appreciate the color here on the CTS.

Actually, Richard, you had just sort of hit on the scale factor, and as you sort of reiterated, the expectation for it to perhaps drift down over time. I didn't know if maybe there was any additional color we could get on that in the sense that, is that something that ultimately you expect to drift down to parity over the life, over the 10 years of the contracts? Or is it something that could come down a little bit of a sharper angle? I don't know if there's any more color that could be added on that?

Yes. Probably not a lot, until we get another few quarters of experience, Carl. But I don't foresee it coming down abruptly. It's just that there's a whole pile of mix, what I call mix factors, that will change over time as we move ahead. And generally, our cross-border shipments will tend to be bigger as a percentage of the total, and so those extra revenues that are being picked up by the scale factor will be smaller as a percentage of total.

So, driving directly off of cross-border volumes and fults will give us slightly lower impact as we move forward through time, but I don't expect it to be in an abrupt change. It's probably hardly going to be noticeable over the period of a quarter. As we get out five years, it might be more noticeable.

That's helpful. Second question really is just looking at the overall better volumes on the Mainline, also trying to kind of get a sense of, has that dynamic continued here into November? And I guess one of my questions is, are we seeing anything abnormal in those volume flows? Or is it just purely a function of production out of the oil sands, out of the Bakken?

Because what I was trying to get to was, is there any -- you noticed or you mentioned the mid-continent arbitrage. I didn't know if there was an arbitrage going on from Canada to PADD II such that we were seeing a correlation for instance between the great results of energy services as well as the higher volumes in the Canadian Mainline, and I just wanted to be cognizant of that if that were true.

Well, I think it's fair to say, Carl, that there isn't any particular factor, other than the general issue around CTS, and the tolling certainty that shippers now have that makes it even more attractive for a spot barrel to move in our system, and for shippers to commit to the Enbridge system as a result of that.

You know, just strong production of course, because of relatively strong crude oil pricing. And we'll see that strengthen up further through the US Midwest markets as more refining capacity moves to be able to process Canadian heavy. But nothing unusual in that, that would cause that to significantly swing.

No, that's very helpful. And then as far as those current volumes lasting into November, have we continued to see that? Has it been more variable?

I haven't seen the October numbers yet, but certainly our expectation is that we'll continue to see roughly comparable strength in the fourth quarter as what we've seen in the first 3 quarters.

Great. Thanks, guys.

Matthew Akman, Scotia Capital. Please proceed.

Good morning, everyone. Couple questions on marketing. First of all, Richard, you mentioned that there is some asset lease agreements that you guys have in place. I'm just wondering approximately how long those last.

Those are typically fairly short-ended rail cars, a matter of years, tanks in some cases going out five, ten years.

Okay. Thanks. And separately on marketing, given your ramp up in the overall field services business in Canada, is there any interest in the organization in NGL marketing in Canada in the same way as someone like Cura does?

Not in a big way, I guess, Matthew. Realize that we are now just entering into the Canadian midstream business, and don't have the same position either on the gas or NGL side that we would have in Texas and Oklahoma, where we do have marketing associated with some of the gas and some of the NGLs that we move. Also, remembering that Aux Sable and Alliance are the main points to which the NGLs get directed, and that marketing is done through the owners and through the Aux Sable liquids plant.

Okay. Thanks. And just one more question if I might, this is for Richard, on your tax profile, on the supplementary cash flow information, looks like you guys haven't paid any cash tax this year. You've transferred the renewables down to ENF, which I presume had some nice tax attributes. So, I'm wondering if going forward in the next 2, 3 years you think you're going to pay much in the way of cash -- is your cash tax rate going to rise?

No, I don't think so.

Okay. Thanks, guys, those are my questions.

Thanks Matthew.

Robert Kwan, RBC Capital Markets. Please proceed.

Good morning. Just on CTS and the scale factor and what's in there, I know you mentioned oil allowance revenues and some terminalling. I'm just wondering whether it's better to think about that number almost as an absolute dollar amount, where the oil allowance is going to move with crude pricing and then terminalling should probably grow as volumes grow?

Well, the oil allowance will tend to grow as volumes grow, as well, so it will be a factor not just of crude prices, which by the way, we tend to hedge, as we do with most things, but also on volumes, because oil allowance is a percentage of volumes.

So I guess is it better to think about it though as more of an absolute dollar amount in the quarter? And if that is the case, was that absolute amount in the quarter pretty representative of where you think you'd be?

Yes. It was representative of the volumes that were shipped during the quarter.

Okay, that's great. Thanks. And then just last question I have, you talked about in energy services and one of the advantages being historical apportionment rights, and you highlighted Ozark there. And Ozark's kind of reached a point on nominations that seem to be a little bit ridiculous just given the constraints.

So, I'm just wondering, have there been any complaints from other shippers, given your position in the line as well? Or is it very well documented that the historical rights are definitely for the benefit of your energy services division?

I have heard nothing to indicate any concern about our participation on the line as a shipper, Robert. And you know, I think that's pretty well known title, which is our energy services business unit has been on the line in good times and bad, since we first put the asset into operations. So no, there's been no issue there.

Okay. That's great. Thanks so much.

Paul Lechem, CIBC. Please proceed.

Thank you. Good morning. I believe the open seasons for the Flanagan South and Wrangler Pipelines have ended. Is there any comments you can make on how those went? And as a corollary to that, given the uncertainty of the Keystone XL process, are there any thoughts about expanding the Flanagan South to a larger volume than the initial capacity you laid out?

So, Paul, we received significant commitments on both the Flanagan South and the Wrangler segments in the open seasons, and as is always the case with an open season, the commitments include conditions, sometimes some terms, sometimes the rate at which volumes ramp up or whether participants are interested in equity, and we're currently in discussions with shippers now to accommodate those conditions.

So, it's a little early for us to give a definitive response to that, but we expect to conclude those discussions with sufficient volumes to proceed with both segments of the line, but you're going to have to wait just a little bit longer for us to be able to firm that up. And we have not really seen any move as a result of, to answer the second part of your question, any move to see a change in the volumetric commitments as a result of uncertainty around XL. But we're pleased with the response that we received on both those open seasons.

Thank you. And if I can fit one more question in, given the volume of projects that you've moved forward over the last quarter, has that put your international expansion efforts, have they taken a little bit of a backseat here? Or are you still looking to go forward on that front?

We're still looking to go forward on that front, and as we indicated at Enbridge Days, it's not that we see any urgency in a number of the new initiatives that we have at Enbridge, whether it's international, whether it's power transmission or the potential to get into gas-fired power generation. No dramatic urgency on those.

But they are long-term growth platforms that we think will continue to put forward this tremendous growth story at Enbridge, beyond the middle of the decade. So, we have not changed in any way our approach on international, still looking at prospects in South America and also some potential, as we indicated, to feed LNG into the Asian market from countries like Australia, Indonesia, et cetera. Certainly not slowing that down. We expect it will be part of the long-term growth story of Enbridge.

Thank you very much.

Thanks, Paul.

Your next question comes from the line of Steven Paget.

(Operator Instructions)

Again, Steven Paget, FirstEnergy. Please proceed.

Good morning. We've been hearing about possible bottlenecks, anticipated at Superior with lots of capacity going in, of course, but maybe not so much demand pull. Is this behind the 50,000 barrel a day Line 5 expansion?

The Line 5 expansion is primarily to feed through to our Eastern Canadian and PADD II expansion strategy, where we're seeing the demand from the perspective here in Alberta to push crude oil further East and potentially in the longer term totally reverse Line 9 to be able to have access to the East coasts.

So, it's really more of a demand for incremental crude oil, in Eastern PADD II, and in Canada, than it is a bottleneck at Superior. We also, of course, as we're just discussing are looking at the same kind of a Southern access, pull and push. But it's primarily to feed that Eastern market, Stephen.

Okay. Thank you. That's it for me.

(Operator Instructions)

Carl Kirst, BMO Capital Markets. Please proceed.

Thank you, sorry. Just a quick follow-up on Cabin Gas, and just with respect to the initial capital that's been put in for Phases 1 and 2, if we do hit Phases 3 and beyond, will there be sort of an incremental pick up on marginal returns because of the fixed asset base?

Or is it as Phases 3 and beyond get done, as we put in more processing trains, for instance, that we're going to kind of maintain sort of the original fee-based targeted 12% type ROE? Just wondering how the future development potential may play out.

We should have Al Monaco here to respond to that. But Richard, can you address it?

Yes. The revenue model for subsequent phases is very similar for the first phase, Carl. So, no, we don't capture scale benefits. Those effectively are passed to the customer, and we continue to earn roughly the same rate of return.

Great. That clears it up. Thank you so much.

Thanks, Carl.

Scott Haggett, Reuters. Please proceed.

Hi. I'm wondering, given the uncertainty of Keystone. Should the line not proceed, what capacity does Enbridge have to take up those volumes and move them to the US market?

Sorry, Scott, you were a little bit hard to hear, but I think your question is along the lines, should XL not proceed, what capacity does Enbridge have? And it's very hard to give you a one number answer to that, because, as always in a system as big and as complex as ours, the bottleneck shifts from one area to another.

I think it's fair to say that the current bottleneck that we have in our system would be from Superior down into the Chicago and Flanagan area. But suffice it to say that we do have sufficient capacity available, and/or relatively low cost expansions to be able to accommodate most of, at least, the early volumes of what would have moved on Keystone XL.

Thank you.

As a reminder, ladies and gentlemen, we would like to invite media for more questions.

(Operator Instructions)

Justin Amoa, Argus Media. Please proceed.

Hi, thanks for taking my call. I just wanted to follow-up on Wrangler and Flanagan South. Do you guys see the decision or the success of Wrangler as contingent upon the delay, or disapproval of Keystone XL?

No.

Okay. And could that project still move forward if the COA pipeline is reversed?

Yes. It could. And COA of course, if reversed, would bring additional capacity to the Cushing South area. But as well, we see the potential for, at some point in time, further capacity again beyond that.

Okay. So is there room for 3 pipelines out of Cushing to the Gulf coast? Or 2 in your opinion? How do you see that?

I think -- it's a very good question, Justin. I think the question is over what term and what period of time you're talking. I think we've made the point at Enbridge right from the outset, that the best way to introduce a bigger volume of Canadian crude oil into the Gulf from what is currently moving is incrementally, so, I think in a lot of ways, having several horses in the race is good to gradually move further crude into that market.

But the potential would be in there at some point in time for all of them to proceed on the basis of the huge refining capacity in the Gulf, and the very big reserves and resources available in the oil sands and in the Bakken.

Thank you.

Bradley Olson, Bloomberg. Please proceed.

Hi. My question is just about what potential you see out there for opposition -- excuse me -- what potential you see out there for opposition to these two alternatives. Is there any chance that the same people who have turned against the Keystone XL line would begin to focus on these alternatives that you're proposing? That's actually something that TransCanada's CEO, Russ Girling, told us at some point in an interview.

I wasn't aware of that comment, Bradley, but you know, what we're talking about is expanding in existing right-of-way and existing systems, putting further volume through existing systems in an incremental way, rather than a big, new construction project. So, I would find it surprising with the opposition to that, it's basically expansion of an existing service that we are referring to, and I guess in pretty much all cases, use of existing right-of-way.

I guess the idea is, the Cushing, the Gulf line, as far as I know, wouldn't be existing right-of-way. That's just what I wanted to ask, if the same folks that are targeting Keystone XL and Northern Gateway might sort of turn their interest as it looks like there may be issues surrounding the Keystone XL pipeline? Just so also I can clarify, TransCanada's CEO did not say that particularly about Enbridge. It was just a general comment about other pipeline options.

Oh. And by the way, I certainly agree with that point, that opposition to something that is as well supported as XL is not a good precedent for the industry. We think it's very important to be able to keep this country in North America operating efficiently to be able to deliver energy to those that need it. And so I think that's very relevant.

Going back to your point about Cushing South, our intention would be to be adjacent to or very near existing right-of-way. It may not be actually on the right-of-way, but it wouldn't result in a significantly different route. So, it would be extension and widening of existing right-of-ways in most cases.

Thank you.

Thank you.

Nathan Vanderklippe, Globe and Mail. Please proceed.

Hi, just following on some of these recent questions, but do you have a sense of how many years of expected growth in Canadian oil production you'll be able to manage with your existing system?

Nathan, that's -- so what you're saying is with the existing system, with no change at all, I'll have to get back to you and quantify a number there, because we've got bottlenecks at various points in the system, I can't give you the exact number on that. But it's important to note that we can accommodate significantly more capacity with very low capital.

For example, the next expansion of our Alberta Clipper project is a relatively low capital incremental pumping capacity. Now, we do have constraints south of Superior from the Superior to the Chicago area, again, incremental pumping capacity. Relatively low cost expansion from where we are, but hard to give a definitive answer to your question.

And just a clarification, with regards to your energy services business, did I understand correctly that you are able to move some of those volumes by rail to achieve some of these arbitrage opportunities?

Yes. Yes, we are. Yes.

Thank you.

Gray Gothard, Energy Intelligence. Please proceed.

Hi. I was just wondering if you could give a couple more details about the Line 9 reversal plan. I was just wondering if you had a timetable in mind, and if you had any thoughts as to how much capacity a reversal of Line 9 could, what that capacity of Line 9 would be? And also, if you had any worries about the East Coast US PADD I refining segment, since so many of those refineries are up for sale or might be shuttered. Thanks.

Line 9 reversal is in a stage of discussion with potential users, and the discussions range all the way from use of Canadian crude oil in Montreal to the potential to move the crude oil to Portland, Maine, and reversing the Portland pipeline and around into the Philadelphia market. And my recollection -- somebody correct me if I'm wrong, but I think we are at capacity on Line 9 reversed in the range of 170,000 barrels a day. And I'm getting nods around the table.

The issue with regard to Philadelphia refineries is 1 that we stay in touch with very closely. There is pretty strong indication that being able to move Canadian light or synthetic crude into that market would help with the viability of those refineries, and I think that's an important consideration as they look at their futures. So, that's one of the drivers, is really to address and improve the economics of that refining business in the Philadelphia area.

Thanks.

Okay.

I'd now like to turn the call over to Jody Balko for closing remarks.

I don't have any further items. Thank you very much.

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