恩橋 (ENB) 2014 Q2 法說會逐字稿

Good morning, ladies and gentlemen, and welcome to the Enbridge Inc. 2014 second-quarter financial results conference call. I would now like turn the meeting over to Adam McKnight, Director, Investor Relations. Please go ahead.

Thank you Good morning, and welcome to Enbridge Inc.'s second-quarter of 2014 earnings call. With me this morning are Al Monaco, President and CEO; Richard Bird, Executive Vice President, Chief Financial Officer and Corporate Development; Guy Jarvis, President, Liquids Pipelines; John Whelen, Senior Vice President of Finance; Leigh Kelln, Vice President, Investor Relations and Enterprise Risk; and Chris Johnston, 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 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 the same as always. We will take questions from the analyst community first, and then invite questions from the media. I would ask that for everyone's benefit, you wait until the end of the call to queue up for questions, and that questions are limited to two per person. Please re-enter the queue if you have additional queries.

I would also remind you that I will be available for any follow-up questions after the call.

Before we 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 our own.

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 the SEDAR and EDGAR systems.

With that, I will now turn it over to Al Monaco.

Okay, thanks Adam. Good morning, everyone. I am going to begin with a recap of our financial results and then provide a brief update on recent developments. Then, as part of John Whelen's expanded responsibility, he will review the financials in more detail and update our funding position. I will then wrap up with progress on major projects execution, focusing on those expected to come in service this year.

So moving to slide 5, then, earlier this morning we announced our second-quarter numbers. We had another solid quarter, with adjusted earnings coming in at CAD328 million or $0.40 a share, bringing our full-year adjusted earnings to CAD820 million. And that is CAD1.00 per share, in line with last year.

The results came in as we expected, which should put us on pace to be within our full-year guidance range of CAD1.84 to CAD2.04 a share. There are a few puts and takes, and John is going to take you through that in a few minutes.

Let me now to discuss recent updates on new developments, starting with slide 6. As you know, Enbridge was one of the first companies to pioneer incentive rate-making, which aligns us very well with our customers and allows us to earn a good risk-adjusted return on our investment.

Last week, the Ontario Energy Board approved our application for a custom incentive rate-setting mechanism. Essentially, Custom IR combines elements of traditional cost of service and a fully incentivized rate structure. Overall, we see the OEB decision as a fair and balanced one.

The term of this will be five years. The new rates will come into effect on October 1, but they will be retroactive to January 1st. Under the rate-setting mechanism we have here. The base return on equity will be reset annually by formula, with a starting point of 9.4% effective for 2014.

Now, this decision allows for ongoing recovery in rates of about CAD570 million of capital investment on average per year, and that includes investment in special projects like our GTA reinforcement.

There will be a 50/50 incentive sharing mechanism that will allow us an opportunity to earn above the allowed return. And, finally, the decision is in line with what we have assumed for EGD's contributions to Enbridge's overall EPS growth outlook.

In June, we finalized the capital cost estimate for our Line 3 replacement Program, bringing our Class 3 estimate to CAD7.5 billion. That is a CAD700 million increase from the preliminary. The final estimate reflects a thorough analysis through our class estimate process, fully up to date with current construction cost, and based on detailed route analysis and terminal engineering.

Recall that our capital cost exposure was 25% on any increase from the preliminary estimate. So the IJT surcharge will adjust upward to offset 75% of the impact of the higher cost on the program's return on equity.

Return-wise, we will still remain within the low-double-digit range we target for most investments, with the upward tilted profile we've talked about in the past. We are in the early stages of execution here; but, so far, we are estimating completion for the second half of 2017.

We are currently preparing our regulatory filings in both Canada and the US. In Canada, we expect to file with the NEB by year-end; and the first quarter next year for the US.

On to slide 8, which provides an update on our US-sponsored vehicles, beginning with Enbridge Energy Partners. As you know, our goal has been to reestablish EEP as an effective sponsored vehicle, similar to the Enbridge Income Fund -- a low-cost source of funding for both its organic liquids pipelines opportunities and, ultimately, for drop-down of assets from Enbridge Inc.

Over the last year, we've undertaken a number of steps, including joint Enbridge-EEP funding of EEP's organic program; our preferred share investment in EEP; and establishing Midcoast Energy Partners through an IPO, and that was with an initial 39% interest in EEP's gas gathering and processing business.

The latest step, announced last month, was the restructuring of our incentive distribution rights in EEP. Over time, we believe this will result in a larger cash distribution pie generated by EEP which will result in higher absolute level of cash flow to Enbridge and the Partnership's unitholders.

Also in June EEP, announced the first drop-down of additional 12.6% of EEP's G&P business to Midcoast for $350 million. That brings MEP's interest in the asset to 52%.

So the IPO and the first drop fortify, we believe, MEP as a new low-cost funding vehicle for the G&P business, and it releases capital from EEP to support its attractive pipeline project investments.

Both EEP and Midcoast announced quarterly distribution increases yesterday. EEP increased its distribution by 2.1%, effective August 14. And backed by the drop-down, MEP increased its distribution by 4%.

Also in June -- we are now on slide 9 -- the federal government approved the Northern Gateway pipeline, accepting the recommendation of the Joint Review Panel. Obviously, we see this as a positive step. In particular, the JRP report provides very strong evidence that the project can be built and operated safely, that the environment will be protected, and that it is in the national interest.

What was very important to us, though, as a Company was that after one of the most comprehensive reviews in Canadian history, the panel concluded that we went beyond what was required from a regulatory perspective on many fronts; and, in fact, world-class.

While the decision marks the end of the regulatory process, now there is still a lot of work to be done here. Our focus is now to satisfy the Joint Review Panel's 209 conditions. About half of those, you may recall, must be completed prior to starting construction. That should take roughly in the range of 12 to 15 months. Work is underway on meeting those conditions, and we are making good progress.

We are continuing to work with the BC government to respond to their five conditions, as well, for supporting oil pipelines. And as we have said in the past, we are very focused on continuing to engage BC communities and Aboriginal groups.

So, we have a few more steps to go, to work through, before we get to a sanctioning decision on Gateway, including finalization of the cost estimate and commercial agreements.

So now, over to John for more detail on the quarterly numbers.

Okay. Well, thanks, Alan. Good morning, everyone. I am picking up on slide 10, with a little more color on our adjusted earnings. All in all, it was a solid quarter. Adjusted earnings came in at about CAD22 million higher than the second quarter of last year, and in line with our overall expectations, albeit with some puts and takes within individual business units.

Liquids Pipelines' earnings grew by CAD61 million, or close to 40% over the same period last year, largely on the strength of the performance of the Canadian Mainline.

Canadian Mainline earnings growth was driven by strong increases in volume throughput, which I will come back to in a minute. These higher volumes more than offset a slightly lower Canadian residual benchmark toll and a lack of revenue from Line 9B, which will remain idle until its reversal and expansion is completed in the fourth quarter.

Regional Oil Sands earnings were also up over the second quarter of last year on contributions from the Norealis pipeline, which went into service this past April, as well as higher throughput on the Athabasca pipeline. Taken together, other sub-segments of Liquids Pipelines were up modestly over the prior quarter, and were generally in line with expectations.

With throughput on the Mainline system and our Alberta Regional pipeline system expected to remain strong for the rest of the year, we are currently tracking somewhat above our full-year expectation for Liquids segment as a whole.

Gas distribution earnings were down quarter-over-quarter, but this largely reflects the different quarterly pattern of recording gas costs between this year and last year, which will balance out over the course of 2014.

Excluding the impact of gas cost adjustments, EGD earnings were down slightly on higher interest expense and depreciation cost, as we continued to recognize revenue during the quarter at interim rates, pending the OEB's decision on EGD's customized IR methodology that Al mentioned earlier.

With the OEB approval now in hand, we expect to collect the difference between the approved rates and the interim rates that applied in the first half of the year through EGD's quarterly rate adjustment mechanism in the fourth quarter. On that basis, we are still expecting full-year gas distribution earnings to come in roughly flat to last year, and consistent with our original guidance expectations.

Earnings from Gas Pipelines, Processing and Energy Services were down sharply quarter-over-quarter, almost entirely due to weaker performance from Energy Services. In developing our guidance for this year, we had anticipated a decline in the contribution from Energy Services, which has delivered exceptional earnings in the first half of last year on the strength of unusually wide crude oil and NGL location differentials.

However, differentials and opportunities to lock in attractive margins have generally proven to be less favorable than anticipated, resulting in unrecovered demand charges in certain markets where we have retained committed transportation capacity. Weaker differentials in the first half of the year are expected to continue, and have us tracking below full-year expectations for this segment.

Sponsored Investments delivered a strong quarter-over-quarter performance, reflecting higher contributions from Enbridge Energy Partners, given increased throughput and higher tolls on the Lakehead liquids mainline system, as well as stronger performance from the underlying assets in Enbridge Income Fund.

On balance, performance from this segment is tracking our full-year expectations for strong year-over-year growth.

Finally, turning to Corporate, Noverco's contribution to earnings was flat for the quarter and consistent with expectations.

The Other Corporate sub-segment is off from last year, as growing contributions from intercompany financing did not fully offset the negative impact of higher preferred dividends and income taxes during the first half of the year.

For the remainder of the year, we do expect to generate higher net interest margin within this segment, which is consistent with our expectations at the outset of this year.

Turning to slide 11, I want to come back to liquids mainline throughput for a moment, given not only its impact on Enbridge's performance, but also its importance from an industry perspective.

The volume growth we experienced this quarter resulted from higher supply from Western Canadian producers, stronger demand from downstream refiners, and system optimization efforts, which all contributed to drive record volumes on the Canadian Mainline system during the quarter.

As you know, in light of the tight takeaway capacity conditions, we have been undertaking a number of capacity and optimization initiatives over the last year. Capacity has improved through removal of pressure restrictions, and we have also been able to optimize the system through a number of measures, including quality pooling and scheduling re-enhancements to the crude entering and leaving the system.

As a result, throughput, ex-Gretna, has improved over the last several months in particular, and we moved a record volume of close to 2.1 million barrels per day in June.

Moving to slide 12. On balance, halfway through the year, we are tracking closely in line with our full-year earnings expectations and guidance range of CAD1.84 to CAD2.04 per share, albeit with some emerging headwinds and tailwinds -- to use one of Richard's favorite analogies.

In the category of tailwinds are the increase volumes on our Mainline and Alberta Regional systems. Improving supply and demand fundamentals, combined with the impact of the system optimization initiatives on our mainline that I just talked about, has generated a strong ramp-up in volume on our liquids pipelines which we expect to be sustained over the balance of the year.

However, this positive driver is largely neutralized by the weaker-than-anticipated performance from Energy Services and, to a lesser degree, by the dilutive impact of common equity that we issued at the end of the quarter to help de-risk our funding program, in view of the increase in our secured capital program.

Turning to slide 13, we continue to make very good progress with our funding program. The capital and bank markets continue to be very supportive of offerings by Enbridge and its affiliates; and, as you can see, on a year-to-date basis, we have now raised approximately CAD5.6 billion -- CAD3.3 billion alone in this most recent quarter.

As noted earlier, we did issue CAD460 million of equity later in the second quarter. We did this proactively, in response to growing capital requirements for Line 3 and a desire to pre-fund a little equity, and create funding flexibility in the face of an historically large and growing capital program.

Moving to slide 14, this chart has become a regular feature of our quarterly calls. It depicts how we are tracking against funding requirements over our five-year planning horizon. Remaining debt issuance requirements are approximately CAD11.6 billion, which we believe is very manageable, given it will be spread over four years and across three different issuers.

Over the course of this year, we have demonstrated our ability to readily raise large amounts of term debt capital in both Canada and the US on very attractive terms.

After taking into account the common equity issued at the end of the quarter, and an even more recent issue of CAD350 million of preferred shares, we have about CAD2 billion of equity or equivalent financing to raise over the remainder of the current planning horizon; which, given the options available to us, also remains very manageable.

Slide 15 puts this into perspective. Basically, we have CAD2.00 of cost-efficient sources of equity capital for every CAD1.00 of equity requirement on our plan. We will, of course, look to fine-tune our funding strategy, if required, to maximize the value captured from the strategy over time and adjust it to the extent we see shifts in our capital program or market conditions. But at present, we believe we have plenty of flexibility and low-cost alternative sources of equity to meet our funding requirements.

And with that, I will turn it back to Al.

Okay, thanks John. I'll finish up with an update on the status of our capital program. Over the next couple of years, we will bring in CAD19 billion of capital growth projects into service, with about CAD10 billion of that this year. The green check marks on the slide indicate the projects that we've brought into service so far.

On line 6B, we replaced all but 50 miles. Replacing 6B will bring capacity to 500,000 barrels per day into Sarina, up from 240,000 a day. That will provide much-needed incremental capacity downstream of Chicago into the upper Midwest and into Ontario. And the timing lines up well with the planned in-service date of the Line 9 reversal later this year.

On our mainline, the horsepower expansion of Southern Access from 400,000 to 560,000 barrels per day went into service this week, as scheduled and on budget. Flanagan South and Seaway are progressing, which I'll provide some more color on in a moment.

Offshore-wise, on Walker Ridge, the Jack St. Malo portion of the Walker Ridge gathering system was mechanically complete as of late June. And it is expected to be placed into service in the fourth quarter after completion of the upstream facilities.

The Big Foot lateral on the Walker Ridge gathering system and the Big Foot oil line are progressing well, with mainline construction complete. It is now expected to be in service in mid-2015.

Finally, we placed Blackspring Ridge into service in May, ahead of schedule and on budget. That is a 300 megawatt wind farm that brings our renewable portfolio to over 1800 megawatts.

Slide 17 highlights the status of the Western Gulf market access program, which is important, obviously, to both ourselves but also our customers. The combination of Flanagan South and the Seaway Twin projects will connect an incremental 600,000 barrels per day of mostly heavy Canadian barrels to the PADD III market. The twinning of the Seaway line was mechanically complete in early July.

On Flanagan South, construction is going well, and we expect to be mechanically complete in early October. Both these projects come with tilted return profiles, and that upward-sloping return profile reflects the phased-in contractual volume commitments that ramp up over time.

I will wrap up with our growth outlook through 2017. Our enterprise-wide capital program now stands at CAD42 billion, CAD37 billion of which is commercially secured, and will be placed into service by 2017. The remaining CAD5 billion represents a number of other projects in development across all the business units.

This program gives us a high degree of confidence that we will deliver average annual EPS growth of 10% to 12% through 2017. And as we have noted in the past, the EPS growth profile will be lumpy, given the magnitude of spending over the next couple of years before projects come into service.

We are also gaining confidence on post-2017 growth, given the recent securement of Line 3 and other projects, along with the tilted return profile impacts that kick in after 2017. There is also room to supplement organic growth through drop-downs, as we referred to earlier, over time to our sponsored vehicles and new growth platforms.

With respect to dividends, we would expect to see a growth rate tracking earnings per share, but with a smoother profile, as illustrated in the slide.

With the amount of capital we are putting into the ground over the next few years, we will see strong cash flow growth, which provides the potential to accelerate the dividend growth rate above earnings growth; depending on the availability, of course, and attractiveness of capital investment opportunities later on.

So, to summarize, second-quarter results were solid and came in as expected, which puts us on track to be within the full-year EPS range of CAD1.84 to CAD2.04 per share. It was another busy quarter with a number of developments. We are on pace and have a high degree of confidence that we will generate the 10% to 12% EPS growth, with associated dividend per share growth through 2017.

So that wraps it up for our prepared remarks. I will know ask the operator to open the phone lines for questions.

(Operator Instructions) Paul Lechem, CIBC.

Thank you. Good morning. My question is around the tolls, the mainline tolls, and specifically the residual toll that goes Enbridge. It seems like it is dropping a fair bit today, down to about CAD1.53 a barrel versus CAD1.85.

Can you talk about that a little bit, what is driving that, and how should we think about where it goes from here in terms of -- is there a limit to how low it can drop? And what are the dynamics behind why it is going to this level?

Okay, I think you're right on the CAD1.53. Generally, Paul, it reflects the increase in capital on the US side of the system, which has a reverse effect on the toll in Canada.

But, Guy, do you want to provide any more comments on that?

I think our expectation, going forward, is obviously there is continuing capital that is going to be invested on the Lakehead system. But along with a capital is going to be the increase in volumes that we've been talking about. So I think our expectation is that we are expecting to see the Lakehead toll become more stable over the coming years, and as a result, so will the residual toll back to EPI.

And I think your outlook for the business, in terms of the earnings and cash flow, reflects the toll profile we just talked about. So I think it is baked in, Paul.

I might just add to that -- it is Richard -- that if you go back to our guidance comments at the beginning of the year, what Guy just said about volume increases and toll decreases is entirely consistent with what we expect going into the year, that we'd have a relatively flat year in liquids pipelines, on account of continued flow-through of that capital into the toll. But that that would be offset, or slightly more than offset, by the volume increases. But basically, going in, we were expecting a relatively flat performance for liquids pipelines. As John mentioned, that is now looking a little stronger.

Okay. So if I could just have one follow-up, then. Just on that point on the guidance for the full year, and what we have left in the back half of the year, the current IJT or the residual toll that you are getting is already baked into the guidance, there is no -- we shouldn't be thinking that you're moving towards maybe the lower end of the guidance range, given that this drop in the residual toll to you is a pretty significant impact on earnings on (multiple speakers).

No. It is John, Paul -- and as Al said, the toll changes were driven by capital that was known down in the US subsidiaries at the time. And so it was factored into our plan all along, and into the guidance, as Richard mentioned.

Okay, thank you.

Ted Durbin, Goldman Sachs.

Thanks. Wanted to just ask about the interaction between the startup of Seaway here versus Flanagan South. I guess I am wondering how much of a revenue uplift we should see in the third quarter potentially from Seaway starting up. Or do we need to have Flanagan in service before we will truly see the pull-through?

Ted, it is Guy. The base plan had been, and still is, to do the line fill of the Seaway Twin from Flanagan South. So we don't expect to see too much off the Seaway Twin until Flanagan South does go into service. It does have the capability to be line filled at Cushing if the barrels are available and the market signals would suggest that you would want to do that. But at this point in time, we think it will be the base plan that it is filled on from Flanagan South.

Okay, so with a mid-October startup, we should really be modeling sort of a partial quarter impact from both projects?

That is probably fair.

That is probably fair. I mean, if you look at mid-October, obviously there will be a line fill plan that has to come together with the producers. That is certainly mostly in their court, as in terms when they can provide that line fill. But yes, it would be a partial quarter.

That is great. And then if I can ask about just on the financing plans, looking at the amount of preference shares you put out the market, any sort of sense of the appetite to continue issuing or about the rate -- I think it has been about 4.4% you have done the last few years. Or any other thoughts around financing, maybe increasing the DRIP program; you obviously do have -- the CapEx program is much bigger now. Just [some thoughts] there, please.

It is John responding, Ted. And the flexibility certainly is there. Those are two very flexible sources of capital, both the DRIP and the pref shares that we've been able to issue that fit very nicely into our funding strategy and funding plan. The DRIP is something we can manage to a certain degree.

And also as far as the prefs go, there has been very solid appetite -- witness the most recent transaction to be completed in July for CAD350 million. And in the current environment, we see opportunity to continue to do that, to keep that growing part of our capital structure, if you like.

Okay, great. I will leave it at that. Thanks.

David McColl, Morningstar.

Good morning, everyone. So just looking at the latest project list and schedule, it looks like there is about CAD5 billion worth of projects that is either running somewhat overbudget or in the delayed category now.

Aside from the obvious Alberta Clipper issues there, what is driving some of these delays, cost overruns? Just wondering if you can talk about that a little bit, and how we should be thinking about it. And also related to that, are you going to be able to I guess recover those costs through the rate base, for various pipelines? Thank you.

Okay, David. Well, I guess you know, bigger-picture here, we are actually quite pleased with where we are at with the project schedules and the costs, if you look at some of the numbers. Generally, we are not that far off our budget if you look at the totality of our capital program. So obviously a difficult environment, and I would say if there are some delays they are related to the permitting process primarily.

But overall, I think we are pretty much on track. As far as the recovery of the cost, that really depends on the jurisdiction we are talking about and the specific project, as far as the pass-through. So that will just depend on the commercial terms.

But I guess maybe the overall point is that we are still pretty pleased with where we are with all the project completions and status, just given the difficulties in the marketplace generally, as far as permitting.

Okay. And I guess just to follow up on that and just clarify it. You are not really seeing a lot of pressure on the labor front, broadly across North America. But it is really more regulatory issues that seem to be causing this.

Yes, that is a good observation. In fact, particularly in Canada, we have managed to enter into a number of frame agreements, we call them; and as well now moving that into the United States where we are less susceptible to the volatility and labor cost, and that we can call on those key contractors to provide the pricing that would be more in the locked-in variety, I guess is a way to put it.

So the other thing to take into account there, David, is our labor force across the entire continent is quite dispersed. So we are not focused necessarily on one particular area where you have got an imbalance between demand and supply for labor. So we're generally seeing that fairly manageable. It takes a lot of effort, and the frame agreements help us do that.

Great, thank you very much. I will probably jump back into the queue.

Carl Kirst, BMO Capital.

Thanks. Good morning, everybody. If I could just jump back to the IJT for a second on the mainline, only because I think I saw that there may have been a regulatory order on the Lakehead system to perhaps buttress some foundation, some anchors under the Great Lakes, as far as the right-of-way there.

I didn't know if that was something that was a minor CapEx project, or could become a major CapEx project that, in turn, could pressure up Lakehead tolls and put pressure downward on the IJT. And I just wanted to make sure I was keeping in front of that.

Okay, Guy is going to comment on that, Carl.

Good morning, Carl. That program of installing screw anchors on Line 5 has been going on for many years now. And the program that we have got lined up for this year would not fall into the category of a significant capital expenditure that would be material to the overall toll.

Okay. So that order that came out, really -- that is pretty much as far as just kind of supports what you have been doing, as far as adding additional support in the Great Lakes?

Yes. So it wasn't necessarily an order, Carl. We have an easement with the state of Michigan that covers how we manage the pipe under the Straits of Mackinac. We are on our two-year interval of underwater inspection of that pipe. And then based on what we find in that inspection, we need to go back in and make whatever repairs are necessary.

We had notified, in some of our communication with the state, what our plans were this summer to address issues that we had found in our most recent underwater investigation, and had indicated to them that when we are done, we are going to be in full compliance with the easement. And they have basically just responded saying, yes, please do that work to be fully compliant.

Excellent. And one follow-up question, if I could. With respect to, I guess this is really more on Sandpiper, we've seen a few more I guess proposals of new oil pipelines coming out of the Bakken. I just wanted to revisit the economics on Sandpiper to make sure that I am clear.

Is this something that -- I guess with Marathon now, we will be a cost-of-service sort of rolled in rates, such that if indeed new pipelines come in there won't be a threat to the economics from any unused capacity on Sandpiper. How should we think about that?

Yes. Carl, it is Guy again. Sandpiper is a bit of a combination, in that we do have a contract with Marathon. So that takes -- you know, that solidifies your revenue stream for a substantial portion of the volume. The volumes, then, that are in common carriage are being managed in a kind of cost-of-service rolled-in fashion for that balance and would be subject to the competitive pressures in that market.

We still, in looking at these other alternatives and the destinations that they are targeting, we still believe that Sandpiper and our base system targeting Eastern Canada with line 9B when it is complete, and with the marathon commitment, has got our assets positioned very well competitively.

Yes, I think the point was key around the markets. When we look at the quality of the crude coming out of the Bakken obviously being highly light variety, and the fact that through Sandpiper and through Southern Access Extension, we can get it into Eastern PADD II and then into Eastern Canada, as Guy said -- that is really a very good fit between the quality of the crude and their finding capacity in that Eastern PADD II area. And then add on the fact that we have got that big anchor commitment bodes well for us. So, we feel we are in pretty good shape.

Great, appreciate all the color guys. Thank you.

Matthew Akman, Scotiabank.

Good morning. On Seaway, there has been a little bit of back-and-forth on the tolling. And there is disclosure that you may look at going back on market rates again. Is that because maybe under the new market rate policy, the toll could be possibly more favorable than under what the ALJ is proposing recently?

Mattew, it is Guy. And, yes, that is the premise upon which we would like to have market-based authority and have the potential for stronger rates. But obviously, if you look at the situation there today, it is very competitive. And our ability, had we had those rates in place today, to go much higher and take them further would be very difficult with the competitive circumstance.

What do you think the timing of resolution of the tolling issue is, potentially if you do go back to FERC under the new policy for market rates?

You know, Matthew, I know we are in discussions with our partner there to get that matter going again. But I do not have an idea on the timeline to take it through the process.

Okay. Just on a different area -- maybe this is for John. On your slide 15 of the presentation, you quantified CAD3 billion of equity potential from asset monetization sponsored vehicle drop-downs.

I'm just wondering what is behind that number or thought process, and whether it just sort of represents the amount of equity you would take back to -- or cash equity you would take back to Enbridge, versus the sort of magnitude of the drop-down in totality?

So I think maybe I will take that, one Matthew. It is Richard. And that number is basically looking at a normal course continuation of the drop-down strategy that we have been following with the income fund; and, potentially, some assets that might move into, for example, Noverco, just based on the magnitude of the transactions that we have affected in recent years; and supposing that potentially we could replicate one of those a year, or something in the magnitude of one of those a year.

Okay. Okay, thank you. Those are my questions.

Robert Catellier, GMP Securities.

Thank you, and good morning. I just wanted to talk about the NEXUS gas transmission project for a minute. I know that is not the one that you consider commercially secured this point. But now that the MOU has expired, I wondered if you could give a comment on the way forward there. And specifically if you can comment on the market dynamics there, the supply demand and competition picture.

Okay, sure. It is Al here, Robert. Well yes, you are right, the MOU expired. But we obviously remain very interested in the project from a development point of view. Obviously, the supply fundamentals in the area are very strong. And there is a natural market upwards and to the Canadian side of the border.

So fundamentally, we like the prospects for it. I think we are working through what the sort of commitment levels are there from producers. And of course we also have an interest from the market side of the equation, which is through our Enbridge Gas Distribution utility, in terms of diversifying its supply.

So, overall, we see that as a good project. We are still working through some issues there, in talking with Spectra and DTE on potential involvement. So I wouldn't say that we wouldn't participate. It is at the point we are still working it through. But, generally, we are positive on the dynamics there.

So this isn't a question, then, of maybe the Utica gas getting squeezed a little bit by Marcellus growth, or potentially this project competing head-to-head with maybe some other options for that gas?

Well, of course. That is a competitive issue. And what we are focused on as a Company in these kinds of situations is to see who will step out, step up, from both the producer side and the market side to underpin the project. Obviously, from our point of view, we need a substantial level of commitments on an investment like that before we proceed. So that is sort of the stage that we are at.

Okay, thank you.

Linda Ezergailis, TD Securities.

Thank you. I have a question with respect to your Athabasca pipeline twinning project. Can you give us a sense of -- I realize it is not huge dollars -- but when you might expect to spend the rest of your cost on that front, and what we might think of as a possible range of in-service dates beyond 2015?

Linda, it is Guy. So we are continuing to evaluate that, as we speak, so to say. There has been a number of developments in the oilsands region that kind of have changed the mix of our expectation of volumes. And, largely, those changes have been positive for Enbridge in that we have secured the Woodland extension, and we secured the Wood Buffalo extension for the Fort Hills volumes. But it does have an impact on the volume mix that we had planned for Athabasca twin. So we are currently in the stages of evaluating that, but I think it is probably a one- to two-year timeframe.

Great, thank you. And just a follow-up, maybe we could just get an updated view you on your outlook for pipeline versus crude-by-rail economics. It seems that you are getting more volumes back on your system. Is that sustainable? Or do you see there being the potential over the next year for the swing back to crude by rail, either on the light or the heavy side?

Linda, it is Guy again. We are seeing a lot of volumes coming back, both to our Bakken system and to our Enbridge Saskatchewan system from rail, as differentials have kind of tightened up. We expect, as line 9B comes on and then further down the road Sandpiper, and we start bringing those higher-priced light markets -- or access to those higher-priced light markets to our system, that we are going continue to shore up our defense against rail.

You know, I think we've stated previously, there is going to be some markets served by rail, like the West Coast and whatnot, that we are probably going continue to be served by rail. But for those markets that we have access to, we're becoming more and more confident in our competitiveness.

And what about on the heavy side of the equation?

Well, on the heavy side of the equation for us, we are full, and we expect to be full. So from a rail point of view, it is truly dealing with the excess volumes that are available in Western Canada that ourselves and others can't move.

Yes, I think that is the point in that. On the heavy side, there is not much doubt that, as Guy said, we are full now. But if volumes come on as we expect them to in the supply side, you know there is still going to be a continuing role for rail. And, of course, many of the producers are quite developed in terms of rail loading facilities in Western Canada. So it is still going to be there, a big chunk probably on heavy, until we get the rest of the pipe capacity sorted out and online.

Great, thank you.

Robert Kwan, RBC Capital Markets.

Good morning. If I can come back to the Lakehead tolls, but actually thinking about it more over the medium- to longer-term. I am just wondering what portion of the Lakehead toll is a full cost-of-service basis? I guess what I'm wondering is how much upside, if any, do you have as you increase some ramp-up volumes on the system, particularly when we get Alberta Clipper into service, and that having the impact of lowering that toll component on the US side, and therefore being a tailwind on the Canadian side?

We are trying to absorb it here. I think we got it, Robert.

Richard is going to just take a shot at it.

Sure, yes. On a go-forward basis, Robert, all the major expansion projects that are underway at the moment, as well as the Line 3 replacement program, are all cost-of-service. And Lakehead integrity, going forward, is about 50% cost-of-service and about 50% covered by the normal escalation in the index toll component of the system. So that is the basic fact pattern.

And in terms of upside as volumes grow, pretty well on track, I think, with expectations that we have had all along that under the CTS arrangement, when you net out the US effects and bring them back into Canada, we will continue as we expand volumes to drive a net upside.

And at this point, we are through the original CTS capacity, and what is really driving that upside is the mainline expansions and the incremental surcharges associated with the Line 3 replacement program as we move forward.

So just if I am clear, is it roughly half of the Lakehead toll might be new facilities? And therefore as volumes ramp, that toll will actually decline, and that it is really just that remainder that will be subject to the PPI, plus, I think, 265?

I do not think I can -- I do not have that particular rate down at the tip of my tongue. So maybe that is something we should follow up with offline, and see if we can provide you with some additional direction on that.

Sure.

It feels like with all the capital and just the magnitude of it, it would be slightly more than half. But we will try to follow up on that.

Okay, that is great. Just the other question I had was Norlite -- it looks like you have upsized it now to a 24-inch pipe. Just wondering, is that just a view as to the discussions you have had to date? Or have additional contracts been signed over and above Fort Hills, and if there is any color as to why the cost, the capital cost estimate hasn't changed yet?

Robert, this is Guy. I think the primary driver -- and you maybe picked it up a little bit with your last part of your question there -- is as we got in and did the engineering and looked at the cost estimation, it became very evident that the cost to upsize it was very minor compared to the potential upside that it provides. So we elected to go with the larger diameter that gives us a greater opportunity to secure more customers, and ultimately drive a better return on that asset.

Yes, so you've got more volume upside with really not much increase in capital cost when you start looking at the numbers carefully. The other part of that is with the larger line, you are running at lower power. So it tends to be more efficient from an operating point of view, as well. So that helps. It helps.

Okay, but nothing in the way of new contracts yet, over and above Fort Hills?

No.

Okay, great. Thank you.

Andrew Kuske, Credit Suisse.

Thank you. Good morning. I guess my first question is for Guy. And it just relates to the capacity optimization that has been done. And I guess just maybe in baseball parlance, what inning of the game do you believe you are in at this stage? Is it still early innings of the game, or are you towards the latter portion of the game, and there is not really much more to eke out?

So let me address that in three different ways. We look at optimizing our system, first and foremost, by how much of the design capacity do we have available. I think there, I would say we are in the ninth inning. We are really well along the way. The next stage we go to, then, is how do we continue to optimize, within that design capacity, to maximize the operating capacity that is available, month in and month out. And I would say as we get into the third quarter here, and progress, that we will probably be in the eighth inning, seventh or eighth inning in regard to that effort.

And in the final area of optimization is really just we do day in and day out, month in and month out, both within our organization and in consultation with our producer customers and our refiner customers, to ensure that each day we are using as much of that capacity as we can. And we had a really strong performance in June, which would suggest we were in the ninth inning of that exercise. And our target here is to try and keep us in the ninth inning of that.

Okay, that is very helpful. And then little bit different, but still related on the crude systems, with Apache basically exiting their LNG project to the West Coast, do you see any sort of interesting dynamic if the Pacific Trail pipeline comes to the market, really just from a right-of-way standpoint for Gateway; and the future making things maybe a little bit easier on a go-forward basis for that project?

It is a good question, Andrew. You know, my gut feel is, no. I mean we have spent a number of years, and with much expertise applied to the Northern Gateway, we are pretty pleased with that. So I don't see much in the way of benefits there if that were to come free, for example. That is my gut feel on it.

Okay, that is helpful. Thank you.

David McColl, Morningstar.

Good morning, everyone. Thanks for taking this second question. I just want to shift gears and discuss something on a fairly strategic level. We've talked about Colombia in the past, and I'm curious if you have maybe any updates on that.

And related to it, I am wondering if there has been any thought about viewing Enbridge as a potential entrant into Colombia-- re-entrant 2017, 2018 -- as maybe an opportunity to pivot into Mexico when it opens up, given that TransCanada already has a decent little foothold there on the gas side?

Yes, yes. Well, first of all, in terms of where we are on the Colombia initiative, I would put that in certainly the development stage timing here. I think we are making good progress. We are pleased with the relationships we have there with producers, and particular Cenit, which is of course aligned with Ecopetrol. So I think we are doing well there.

It is certainly a longer-term project, in that it is going to take some time to work through the environmental and permitting issues there; and, importantly, develop the project from a commercial point of view. I would say that is the probably the next big milestone is making sure we can nail those things down.

So we like Colombia for the reasons we have stated before: great fundamentals, in terms of supply; and obviously they are looking to access Pacific markets as well. The fiscal and regulatory processes in Colombia we are very familiar with, given our history there. So we like the country. And hopefully there will be something further on the major project that we are working on there.

I agree with you. I think just given our position in Colombia, and where we see Mexico in the future, obviously these changes that have been brought down are very positive, and that they are going to encourage a lot more investment. You can just look at the billions that are being forecasted there annually for upstream investments there, particularly from foreign entrants.

So I think there is a good opportunity there. They are obviously in significant need of pipeline infrastructure, whether that is oil and gas. So we see this as particularly encouraging. I would not say we have anything immediate there. We are going to watch to see how these regulations work through, and then we will keep our finger on the pulse and see where we go there.

All right, thanks. I appreciate the commentary.

Thank you. At this time, we would like to invite members of the media to join the queue for questions. (Operator Instructions). Andrew Lindsay, Morgan Stanley.

Hi, good morning. Thank you for your presentation. Just touching on one of the previous questions about project delays. There was news this week on obviously Northern Gateway, Lakehead, Flanagan South -- which you have touched on -- Line 9 and Line 3 replacement.

I'm just wondering if you could shed any light on these, and perhaps whether there are any other delays or cancellations expected in the future, and sort of what the likely timing of these delayed projects is likely to be.

Well, as I alluded to earlier on, I think there is -- when we talk about delays, we are talking about, certainly in the current environment, some of them in the months category. And I don't really think that is too abnormal in terms of how you get these projects done. Obviously they are very large; there are very complex; they turn on state or provincial permits.

There is a lot more consultation that is going on, and working through with communities on what needs to be done, and making sure that we bring them up to speed on the project, and that they have comfort around the safety of the project.

So I think, generally, it is a tough environment to get projects done. But as I said earlier, I am very pleased with the overall state of where we are, from a schedule and cost point of view. So there is probably some puts and takes, but generally I think we are pretty much on target.

Okay, thank you very much. Just to further touch on that, I know you have mentioned the gas contracts and potential developments in Colombia. But I was wondering if you had any outlook on potential new pipeline or replacement projects in the future?

With respect to which area?

No, simply whole of North America. Looking at pipeline extension or replacement.

Okay, sure. Well, the short answer is yes. We are very optimistic about energy development in North America. And of course, with that, goes a lot of requirement for infrastructure. Whether you look at that on the oil side, which is probably I would say less so because of all the projects that are currently being proposed. But certainly on the gas side, there is a huge demand for new infrastructure. So we feel very positive about the fundamentals that will drive new infrastructure investments on this continent for sure.

Okay, thanks very much.

Ashok Dutta, Platts.

Hi guys. I presume this has been talked about earlier, but just wanted to cross-check here. I wanted to ask about the Midwest terminal, the rail unloading one. Could I just ask you to give me some details on that, please?

Sure.

Guy is close to that, so he can speak to it.

Good morning. We talked earlier on our conversation about how rail outlets for Western Canadian heavies are still needed. Within Alberta, Al mentioned there is a lot of rail loading capability already in place. What we are looking at doing is potentially building a rail unloading facility adjacent to the receipt point of our Flanagan South pipeline. So that additional heavies could exit Alberta by rail, be unloaded in Flanagan, get on Flanagan South and the Seaway Twin, and find their way to the Gulf Coast.

Okay, and the capacity is 140,000 barrels a day?

Yes, that would be the maximum unloading capability that we are planning, yes.

And we are looking at two unit trains a day?

Yes.

And any timeline for startup of this at all?

We really haven't got it cast in stone just yet. But I think it is safe to say we are targeting early 2016.

And of course these things, as you know, depend on ensuring that we have got good customer interest and commitments to use the facilities. So I think that is the phase we are in on that one.

Okay, thank you.

Jeff Lewis, Financial Post.

Hi, thanks for taking my question. Just as a follow-up to plans for that rail terminal, is that dependent on an assumption that you don't get the presidential permit amendment for Clipper, or would you go ahead with that rail terminal anyway?

I think we would plan to go ahead with it anyway. We have indicated in prior calls that we are working on optimizing our system to deliver the expected capacity we would otherwise get from Alberta Clipper. And we believe that the basin continues to need more outlets for that crude for the foreseeable four or five years.

I think the environment we are in, producers and refiners are looking for optionality. And that is where the rail part of this comes in for us. And to the extent we can provide that optionality to our customers at a reasonable cost, and they are willing to commit to use the facility, then it makes a lot of sense. Because obviously the cost are minimal, relative to the value that can be created by opening up these markets. So that is how we look at it in the big picture.

It sounds as though it is early days, but is there any CapEx estimate for that project, the rail terminal?

That is a good question. Anybody have it handy? As I recall, it is in the CAD150 million range. But we would have to check that, and we can get back to you on it. If it is quite different, we will get back to you.

Okay. Thanks.

Okay.

Thank you. As there are no further questions, I would like to turn the call back to Adam McKnight for any closing remarks.

Thank you. We have nothing further to add at this time. But I would like to remind everyone that Leigh and I will be available after the call for any follow-up questions that you may have. Thank you. and have a good day.

Thank you, ladies and gentleman. This concludes today's conference. Thank you for participating. You may now disconnect.