Enbridge's (ENB) CEO Al Monaco on Q2 2014 Results - Earnings Call Transcript

Aug. 1.14 | About: Enbridge Inc. (ENB)

Enbridge Inc. (NYSE:ENB)

Q2 2014 Earnings Conference Call

August 1, 2014 9:00 AM ET

Executives

Adam McKnight – Director, IR

Al Monaco – President and CEO

John Whelen – SVP, Finance

Guy Jarvis – President, Liquids Pipelines

Richard Bird – EVP, CFO and Corporate Development

Analysts

Paul Lechem – CIBC

Ted Durbin – Goldman Sachs

David McColl – Morningstar

Kyle Kirst – BMO Capital Markets

Matthew Akman – Scotiabank

Robert Catellier -GMP Securities

Robert Catellier – GMP Securities

Linda Ezergailis – TD Securities

Robert Kwan – RBC Capital Markets

Andrew Kuske – Credit Suisse

Jeff Lewis – The Financial Post

Operator

Good morning, ladies and gentlemen and welcome to the Enbridge, Incorporated 2014 Second Quarter Financial Results Conference Call.

I would now like to turn the meeting over to Adam McKnight, Director, Investor Relations. Please go ahead.

Adam McKnight

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 of Liquids Pipelines, John Whelen, Senior Vice President of Finance, Lee Kelln of Vice President, Investor Relations & Enterprise Risk and Chris Johnston, Vice President & 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 we’ll 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 the 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 system.

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

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’ll then wrap up with progress on major projects execution focusing on those expected to come in service this year.

So moving to slide five then, earlier this morning, we announced our second quarter numbers. We had another solid quarter with adjusted earnings coming in at $328 million or $0.40 a share, bringing our full year adjusted earnings to $820 million and that’s $1 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 a $1.84 to $2.04 a share. There is a few puts and takes and John is going to take you through that in a few minutes.

Let me now discuss recent updates on new development starting on slide six. 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 they fully incentivize rate structure. Overall, we see the OEB decision as a fair and balanced one. The term of this will be five years and the new rates will come into effect on October 1, but that’ll 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 the starting point of 9.4% effective for 2014. Now, this decision allows for ongoing recovery and rates of about $570 million of capital investment on average per year and that includes investment in special projects like our GTA reinforcement.

There’ll 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’ve assumed for EGD’s contributions to Enbridge’s overall EPS growth outlook.

In Judean, we finalized the capital cost estimate for our Line 3 Replacement Program bring our Class 3 estimate to $7.5 billion, that’s a $700 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 detail route analysis and terminal engineering.

Recall that our capital cost exposure was 25% on an increase from the preliminary estimate so, the IJT surcharge will adjust upward to offset 75% of the impact of the higher cost on the programs return on equity.

Return NOIs 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’re in the early stages of execution here but so far we’re estimating a completion for the second half of 2017. We’re currently preparing our regulatory filings in both Canada and the U.S., and Canada we expect to file with NEB by year end and the first quarter next year for the U.S.

On slide eight, which provides an updates on our U.S. sponsored vehicles beginning with Enbridge Energy Partners. As you know our goal is being to reestablish EEP as an effective sponsored vehicle similar to 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, a preferred share investment in EEP and establishing Midcoast Energy Partners through an IPO and that was with an issue of 39% interest in EEP’s gas gathering and processing business.

The last step announced – latest step we rather announced last month was the restructuring of our incentive distribution rights in EEP. Overtime 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 partnerships’ unitholders.

Also in June, EEP announced the first drop dawn of additional 12.6% of EEP’s G&P business to Midcoast for $350 million. That brings MEP’s interest in the assets to 52%. So the IPO in the first drop fortify we believe MEP is a new low cost funding vehicle for the G&P business and it releases capital to 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 nine, the federal government approved the Northern Gateway Pipeline accepting the recommendation of the Joint Review Panel. Obviously we see this as a positive step and 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’s 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 the work with the BC government to respond to their five conditions as well for supporting oil pipelines. And as we’ve said in the past we’re 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 sanctioning decision on gateway including finalization of the cost estimate and commercial agreements.

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

John Whelen

Okay. Well, thanks Al and good morning everyone. I am picking up on slide 10 with little more color on our adjusted earnings. All-in-all it was a solid quarter. Adjusted earnings came in about $22 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 pipeline and earnings grew by $61 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 tool 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 contribution 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 the liquids pipeline were up modestly over the prior quarter and were generally in line with expectations. The 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 of over full year expectations for the liquid segment as a whole.

GAAP distribution earnings were down quarter-over-quarter but this largely reflects the different quarterly pattern of recording gas cost 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 continue to recognize revenue during the quarter at interim rates pending the OEB’s decision on EGD customized or 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 a roughly flat to last year and consistent with our original guidance expectations.

Earnings from gas pipelines processing 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 had 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 an unrecovered demand charges in certain American markets where we have retained committed transportation capacity.

Weaker differentials in the first half of the year are expected to continue and help us tracking below full year expectations for this segment. Sponsored investments delivered a strong quarter-over-quarter performance reflecting higher contributions from energy Enbridge Energy Partners given increased throughput and higher tools and the 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. There is growing contribution from inter-company financing does 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 the 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 is improved through removal of press 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 $1.84 to $2.04 per share, albeit with some emerging headwinds and tailwinds to use one of Richard’s favorite analogies.

In the category of tailwinds we are the increased 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 diluted 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’ve now raised approximately 5.6 billion, 3.3 billion alone in this most recent quarter.

As noted earlier we did issue $460 million of equity later in the second quarter. We did this proactively in response to growing capital requirements for Line 3 and to desire to prefund a little equity and creates some funding flexibility in the face of 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 $11.6 billion which we believe is very manageable given it will be spread 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 U.S. 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 $350 million of preferred shares we have about $2 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 $2 of cost efficient sources of equity capital for every $1 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 overtime and adjusted 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 out funding requirements.

With that I’ll turn it back to Al.

Al Monaco

Okay, thanks John. I’ll finish up with an update on the status of our capital program. Over the next couple of years we’ll bring in $19 billion of capital growth projects into service with about $10 billion of that this year. The green check marks from the slide indicate the projects that we brought into service so far.

On Line 6B we replaced all 50 miles replacing 6B will bring capacity to 500,000 barrels per day into Sarnia 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 plant in service day of Line 9 reversal later this year.

On our mainline, the horsepower expansion of seven axis from 400,000 to 560,000 barrels per day 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’s 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 liner progressing well with mainline construction complete. It’s now expected to be in service in mid-2015.

Finally, we placed Black Spring Ridge into service May ahead of schedule and on budget. That’s a 300 megawatt wind farm that brings our renewable portfolio to over 1,800 megawatts.

Slide 17 highlights the status of the Western Gulf market access program which is important; obviously the both ourselves but also our customers. The combination of plan Flanagan South and Seaway twin projects will connect an incremental 600,000 barrels per day of mostly heavy Canadian barrels to the Pad 3 market.

Tuning 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 of these projects come with tilted return profiles and that upward sloping return profile reflects the phased-in contractual volume commitments that ramped up overtime.

I’ll wrap up with a growth outlook through 2017. This is now – our enterprise-wide capital program now stands at 42 billion, 37 which is commercially secured and will be placed into service by 2017. The remaining 5 billion represents a number of other projects and development across all the business units. This program gives us a high degree of confidence that we’ll deliver average annual EPS growth of 10% to 12% through 2017.

And as we’ve 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’re also gaining confidence on post-2017 growth given the recent securement of Line 3 and other projects along with a tilted return profile impacts that kick in after 2017.

There is also room to supplement our organic growth through drop downs as we referred to you earlier overtime to our sponsored vehicles and new growth platforms. With respect to dividends, we would expect to see a growth rate tracking earnings per share with a smoother profile as illustrated in the slide.

With the amount of capital we’re putting into the ground over the next few years we’ll see strong cash flow growth which provides the potential to accelerate the dividend growth rate above earnings growth depending on 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 full year EPS range of $1.84 to $2.04 per share. It was another busy quarter with a number of developments. We’re on pace and have a high degree of confidence that we’ll 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’ll now ask the operator to open up the phone lines for questions.

Question-and-Answer Session

Operator

Thank you. We will now take questions from analyst community. (Operator Instructions). Our first question comes from Paul Lechem from CIBC. Please go ahead.

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’s dropping a fair bit today down to $1.53 a barrel versus $1.85. Can you talk about that a little bit what’s 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’s going to this level?

Al Monaco

Okay. I think you’re right on the $1.53. Generally call it reflects the increasing capital on the U.S. 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?

Guy Jarvis

Yes. I think our expectation going forward is obviously there is continuing capital. This going to be invested on the Lakehead system but along with that capital is going to be the increasing volumes that we’ve been talking about. And I think our expectation is that we would like to – we’re expecting to see that the Lakehead tool become more stable over the coming years and as a result so will be residual toll back to EPI.

Al Monaco

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’s a big Paul.

Richard Bird

I might just add to that. It’s Richard. If you go back to our guidance comments at the beginning of the year like Guy just said about volume increases and tool decreases is entirely consistent with what we expected going into the year that we have a relatively flat year in liquids pipelines on account of continued flow through of that capital into the toll but 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 pipeline as John mentioned that’s now looking a little stronger.

Paul Lechem – CIBC

Okay. So, if I can just have one follow-up. And just on that point on the guidance for the full year and what we have left during the back half of the year, the current IJT or the residual holding you’re getting is already baked in to the guidance as know but we shouldn’t be thinking that’s moving towards maybe go lower into the guidance range given that this drop in the residual tolls has a pretty significant impacts on earnings...

John Whelen

No. It’s John, Paul. And also the toll changes were driven by capital that was known down in the U.S. subsidiaries at the time. And so, it was factored into our plan all along entrance the guidance as Richard mentioned.

Paul Lechem – CIBC

Okay. Thank you.

Operator

Thank you. Our next question comes from Ted Durbin from Goldman Sachs. Please go ahead.

Ted Durbin – Goldman Sachs

Thanks. I wanted to just ask about the interaction between the startup with Seaway here versus Flanagan South. I guess I am wondering how much of a revenue uplift you should see in the third quarter potentially from Seaway started to have or do we need to have Flanagan in service before what truly see the pull through?

Guy Jarvis

Ted, its Guy. The base plan had been and still is to do the line field of Seaway twin from Flanagan South so we don’t expect to see too much of the Seaway twin until plan again Flanagan South does go into service. It does have the capability to be landfill 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’s build on from Flanagan South

Ted Durbin – Goldman Sachs

Okay. So, it’s a mid-October startup we should really be modeling sort of a partial quarter impact from both of those projects?

Guy Jarvis

That’s probably fair.

Al Monaco

That’s probably fair I mean if you look at mid-October obviously there will be a landfill plant that has to come together with the producers thus certainly mostly in their quarters in terms of when they can provide that landfill. But yeah, it would be a partially quarter.

Ted Durbin – Goldman Sachs

Okay. 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 about the rate, I think it’s kind of 4.4% you’ve done for last few years since in this or any other thoughts around financing maybe increasing the drip program you obviously do have the CapEx program is much bigger now, just a thought about there, please.

John Whelen

It’s John responding Ted and the flexibility certainly is there those are two very flexible sources of capital both to drip and the pressures that we’ve been able to issue that very nicely into our funding strategy and funding plan. The drip is something we can manage to a certain degree and also the – as far as the press code there has been very solid appetite witness the most recent transaction completed in July for $350 million and in the current environment we see opportunity continue to do that to keep that growing part of our capital structure if you like.

Ted Durbin – Goldman Sachs

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

Al Monaco

Thanks Ted.

Operator

Thank you. Our next question comes from David McColl from Morningstar. Please go ahead.

David McColl – Morningstar

Yeah, good morning everyone. So, just looking at the latest project list and schedule, it looks like there is about $5 billion worth projects that either running somewhat over budget or in the delayed category. Now, aside from the obviously Alberta Clipper issues there what’s driving some of these delays cost over I am just wondering if you can talk what 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 cost to the rate base through various pipeline? Thank you.

Al Monaco

Okay David. Well I guess bigger picture here we’re actually quite pleased with where we’re at the project schedules and the costs if you look at some of the numbers generally we’re not that far off or 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’re related to the permitting process primarily but overall I think we’re pretty much on track as far as the recovery of the cost that really depends on the jurisdiction we’re 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 market generally as far as permitting.

David McColl – Morningstar

Okay. So, I guess just to follow-up on that and clarify it that you’re not really seeing a lot of pressure on the labor front broadly across North America but it’s really more regulatory issues that seem to be causing that?

Al Monaco

Yeah, that’s 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 I am moving that into the United States we’re less susceptible to the volatility in labor cost and that we can call in those key contractors to provide the pricing than would be more on the locked-in variety I guess is the 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’re not focused necessarily on one particular area where you’ve 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.

David McColl – Morningstar

Great, thank you very much. I’ll probably jump back in the queue.

Al Monaco

Okay.

Operator

Thank you. Our next question comes from Kyle Kirst from BMO Capital. Please go ahead.

Kyle Kirst – BMO Capital Markets

Thanks. Good morning everyone. 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 bucker some foundation some tankers under the Great Lakes as far the right away there. I didn’t know if that was something that was a minor CapEx project or it could become a major CapEx project that in turn could pressure up Lakehead tools and then put pressure down on the IJT I just wanted to make sure I was keeping in front of that.

Al Monaco

Guy is going to comment on that Kyle.

Guy Jarvis

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

Kyle Kirst – BMO Capital Markets

Okay. So, that order that came out really that’s pretty much as far as just kind of support what you have been doing as far as adding support in the Great Lakes.

Guy Jarvis

Yeah so, it wasn’t necessarily an order Kyle. We have an easement with the State of Michigan that covers how we manage the pipeline of the straights or Straits of Mackinac. We’re 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’re done we’re 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.

Kyle Kirst – BMO Capital Markets

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 I guess with Marathon now we will be a cost of service sort of rolled in rate such that if and indeed new pipeline coming, there won’t be a threat to the economics from many unused capacity on Sandpiper, how should we think about that?

Guy Jarvis

Yes. Kyle it’s Guy again. Sandpipers are a bit of combination in that we do have contract with Marathon. So, that takes – that solidifies your revenue stream for a substantial portion of the volume, the volume then that are in Coleman Carriage are being managed in a kind of a cost to service rolled in fashion for that balance and would be subject to the competitive pressures in that market. We still been looking at these other alternatives and the destinations that they’re targeting we still believe that Sandpiper and our base system targeting Eastern Canada with Line 9B when its complete and with the Marathon commitment has got our assets positioned very well competitively.

Al Monaco

Yeah, I think that 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 axis extension we can get it and to Eastern Pad 2 and then into Eastern Canada as Guy said that’s really a very good fit between the quality of the crude and their refining capacity in that Eastern Pad 2 area. And then add on the fact that we’ve got that Big Anchor commitment bodes well for us so, we feel we’re in pretty good shape.

Kyle Kirst – BMO Capital Markets

Great, I appreciate all the color guys. Thank you.

Al Monaco

Okay.

Operator

Thank you. Our next question comes from Matthew Akman from Scotiabank. Please go ahead.

Matthew Akman – Scotiabank

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

Guy Jarvis

Matthew it’s Guy and yeah 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’s very competitive and our ability we had those rates in place today to go much higher and take them further would be very difficult to competitive circumstance.

Matthew Akman – Scotiabank

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

Guy Jarvis

You know Matthew I know we are in discussions with our partner there to get that matter going again but I don’t have an idea on the timeline to take it through the process.

Matthew Akman – Scotiabank

Okay. Just on a different area maybe this is for John, on your slide 15 of the presentation, you quantified $3 billion of equity I guess potential from asset monetization, sponsored vehicle drop downs. I am just wondering what was behind that number thought process and whether it just sort of represents the amount of equity you’d take back to or cash equity you’d take back to Enbridge versus you know the sort of magnitude of the drop down in totality?

Richard Bird

So I think maybe I’ll take that one Matthew it’s Richard. And that number is basically looking at normal course continuation of the drop down strategy that we’ve been following with the income fund and potentially some assets that might move into for example Noverco just based on the magnitude of transaction that we’ve affected in recent years and supposing that potentially we could replicate one of those year or something in the magnitude of one of those year.

Matthew Akman – Scotiabank

Okay. Thank you. Those are my questions.

Al Monaco

Okay. Thanks Matthew.

Operator

Thank you. Our next question comes from Robert Catellier from GMP Securities. Please go ahead.

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’s not the one that you consider commercially secured at 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 sort of market dynamics there, the supply demand and competition picture.

Al Monaco

Okay. Sure it’s Al here Robert. Well yes you’re 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 into the Canadian side of the border. So fundamentally we like the prospects forward I think we’re 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’re still working through some issues there and talking with Spectra and DTE on potential involvements. So I wouldn’t say that we wouldn’t participate at the point we’re still working it through but generally we’re positive on the dynamics there.

Robert Catellier – GMP Securities

So this isn’t 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?

Al Monaco

Well of course that’s a competitive issue and what we’re focused on as a company in these kinds of situation is to see who will step out, step up from the both the producer side and the market side to underpin the project obviously from our point of view we need substantial level of commitments on an investment like that before we proceed. So that’s sort where the stage that we’re at.

Robert Catellier – GMP Securities

Okay. Thank you.

Al Monaco

Okay.

Operator

Thank you. Our next question comes from Linda Ezergailis from TD Securities. Please go ahead.

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 really it’s not huge dollars but when do you might expect to spend the rest of your cost on that front and what we might think of the possible range of in service state beyond 2015?

Guy Jarvis

Linda, its Guy. So we’re continuing to evaluate that as we speak sort of say there has been a number of developments in the oil sands region that kind of change the mix of our expectation of volumes and largely those changes have been positive for Enbridge and we’ve secured the Woodland extension and we have secured the Wood Buffalo for the Fort Hills volumes. But it does have an impact on the volume mix that we had planned for Athabasca twin. So we’re currently in the stages of evaluating that, but I think it’s probably in one to two year timeframe.

Linda Ezergailis – TD Securities

Great. Thank you. And just a follow up maybe we could just get an updated view on your outlook for pipeline versus crude by real economics it seems that you’re getting more volumes back on your system, is that sustainable or do you see there being the potential over the next year to swing back to crude by real oil and the light oil heavy side?

Guy Jarvis

Linda, it’s 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 further down the road Sandpiper and we start bringing those higher price light markets or access to those higher price light markets to our system that we’re going to continue to shore upward defense against the rail. I think we stated previously there is going to be some markets served by rail like the West Coast and whatnot that we’re probably going to be continued to be served by rail but for those markets that we have access to we’re becoming more and more confident in our competitiveness.

Linda Ezergailis – TD Securities

And what about on the heavy side of the equation?

Guy Jarvis

Well on the heavy side of the equation for us we’re full and we expect to be full so from a real point of view it’s truly dealing with the excess volumes that are available on Western Canada that ourselves and others can’t move.

Al Monaco

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

Linda Ezergailis – TD Securities

Great. Thank you.

Operator

Thank you. Our next question comes from Robert Kwan from RBC Capital Markets. Please go ahead.

Robert Kwan – RBC Capital Markets

Good morning. If I can come back to the Lakehead tolls but actually thinking about it more of 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 am wondering is how much upside if any do you have as you increase and 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 U.S side and therefore being a tailwind on the Canadian side?

Guy Jarvis

I just take a stab there I am trying to absorb it here but I think we got Robert, Richard is going to take a shot at it.

Richard Bird

So on a go forward basis Robert all of 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 components of the system so that’s a basic fact pattern and in terms of upside as volumes grow, pretty well on track I think with expectations that we’ve had all along that under the CTS arrangement when you net out the U.S effects and bring them back into Canada, we will continue as we expand volumes to drive a net upside. And at this point we’re through the original CTS capacity and what’s really driving that upside is the mainline expansions and the incremental charges associated with the Line 3 replacement program as we move forward.

Robert Kwan – RBC Capital Markets

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

Al Monaco

I don’t think I can, I don’t have that particular the rate down at the tip of my tongue, so maybe that’s something we should follow up with offline and see if we can provide you with some additional direction on that.

Richard Bird

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

Robert Kwan – RBC Capital Markets

Okay. That’s great. And just the other question I had was, Norealis it looks like you upside now to a 24 inch pipe, just wondering is that just a view as discussions you had to-date or have additional contracts have been signed over and above foretells and if there is any color is to why that cost – the capital cost estimate hasn’t changed yet?

Guy Jarvis

Robert, this is Guy. I think the primary driver and you may be picked it up a little bit with your last part of your question. As we got in and did the engineering and look that the cost estimation that became very evident that the cost upsize it was very minor compare to the potential upside that we provide so we elected to go with the large diameter. They gives us a greater opportunity to secure more customers and ultimately drive a better return on that asset.

Al Monaco

So, you get 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’re running at lower power so it tends to be more efficient from an operating point of view as well so that helps.

Robert Kwan – RBC Capital Markets

Okay. But nothing in the way of new contracts over and above foretells.

Al Monaco

No.

Robert Kwan – RBC Capital Markets

Okay, that’s great. Thank you.

Operator

Thank you. Our next question comes from Andrew Kuske from Credit Suisse. Please go ahead.

Andrew Kuske – Credit Suisse

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

Guy Jarvis

Yeah. So, let me address that in three different ways. We’re looking to optimizing our system first and foremost by how much of the design capacity do we have available. I think there I would say we’re in the ninth inning. We’re 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’s available month in and month out. And I would say as we get into the third quarter here in progress that we will probably in the eight innings seven to eight innings in regard to that effort.

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

Andrew Kuske – Credit Suisse

Okay, that’s very helpful. And then a little bit different but still relate on crude systems. With Apache basically – 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 away standpoint for gateway and future making things maybe a little bit easier on a go forward basis for that project?

Guy Jarvis

It’s a good question there, Andrew. My gut feel is no. I mean we spent number of years and with much expertise supplied to the Northern Gateway route we’re 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’s my gut feel on it.

Andrew Kuske – Credit Suisse

Okay, that’s helpful. Thank you.

Guy Jarvis

Okay.

Operator

Thank you. Our next question comes from David McColl from Morningstar. Please go ahead.

David McColl – Morningstar

Hi. Good morning everyone. I guess and thanks for taking this second question. Just wanted to shift gears and discussing I guess on a fairly strategic level. We’ve talked about Colombia in the past and I am 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 has a potential interest 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?

Guy Jarvis

Yeah. Well, first of all in terms of where we are on Colombia initiative, I would put that in certainly the development stage timing here. I think we’re making good progress. We’re pleased with the relationships we have there with producers and particular senate which is of course in line with Ecopetrol so I think we’re doing well there.

It’s certainly a longer term project and it’s 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’d say that’s probably the next big milestone is making sure we can nail those things down.

So, we like Colombia for the reasons we 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 were 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’re working on there.

I agree with you. I think just given our position in Colombia and where 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 entrance. So, I think there is a good opportunity there. There obviously in significant need of pipeline infrastructure whether that’s oil and gas, so we see this as particularly encouraging. I wouldn’t say we have anything immediate there. We’re going to watch to see how these regulations work through and then we’ll keep our finger around the pulse and see where we go there.

David McColl – Morningstar

Alright, thanks. I appreciate the commentary.

Guy Jarvis

Okay.

Operator

At this time we would like to invite members of the media to join queue for questions. (Operator Instructions) And your last analyst question comes from the line of [Angel] from Morgan Stanley. Please go ahead.

Unidentified Analyst

Hi. Good morning. Thank you for your presentation. Just touching on one of the previous caller’s questions about project delays I mean that’s means this week on obviously Northern Gateway, Lakehead, Flanagan South which you touched on Line 9 and Line 3 replacement. I was just wondering if you could shed any lights on these and perhaps whether there are any other delays or cancellations expected in the future. And so what the likely timing these delayed projects is likely to be?

Guy Jarvis

Well as I alluded to earlier on, I think there is – when we talk about delays, we’re talking about certainly in the current environment. Some of them in the months category and I don’t really think that’s too abnormal in terms of how you get these projects done.

Obviously they’re very large, they’re very complex. They turn on state or provincial permits. There is a lot more consultation that’s going on and working through with communities on what needs to be done and making sure that we bring them up to speed in the project and that they have comfort around the safety of the project.

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

Unidentified Analyst

Okay. Thank you very much. Just to sort of touch on that I mean – you mentioned the gas contracts and the potential developments in Colombia I was wondering if you had any outlook on potential new pipeline or placement projects in the future?

Al Monaco

With respect to which area?

Unidentified Analyst

No, just simply whole North America looking at pipeline extension or replacement.

Al Monaco

Okay, sure. Well, the short answer is yes. We’re 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 while the project there 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.

Unidentified Analyst

Okay. Thanks very much.

Al Monaco

Okay.

Operator

Thank you. Our next question comes from [Ashaq from Platt]. Please go ahead.

Unidentified Analyst

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?

Al Monaco

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

Guy Jarvis

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’re 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 the way to the Gulf Coast.

Unidentified Analyst

Okay. And the capacity is 140,000 barrels a day?

Guy Jarvis

Yeah. That would be the maximum unloading capability that we’re planning now.

Unidentified Analyst

And we’re looking at two unit trains a day?

Guy Jarvis

Yes.

Unidentified Analyst

Okay. And any timeline for startup of this at all?

Guy Jarvis

We really haven’t got it cashed in stone just yet but I think it’s safe to say we’re targeting early 2016.

Al Monaco

Yeah. Of course these things as you know depend on ensuring that we got good customer interest and commitments to use the facility. So I think that’s the phase we’re in on that one.

Unidentified Analyst

Okay. Thank you.

Al Monaco

Okay.

Operator

Thank you. Our last question comes from Jeff Lewis from The Financial Post. Please go ahead.

Jeff Lewis – The Financial Post

Hi. Thanks for taking my question. Just as a follow up to plans for that rail terminal. Is that dependent on assumption that you don’t get the presidential permit amendment for Clipper or would you go ahead with that rail terminal anyway?

Al Monaco

Go ahead.

Unidentified Corporate Participant

I think we would plan to go ahead with it anyway, we have indicated in prior calls that we’re 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, five years.

Guy Jarvis

Yeah. I think the environment we’re in producers and refiners are looking for optionality and that’s 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’re willing to commit to use the facility than 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’s how we look at it on the big picture.

Jeff Lewis – The Financial Post

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

Guy Jarvis

That’s a good question. Anybody have that. As I recall it’s in the $150 million range but we would have to check that and we can get back to you if it’s quite different we will get back to you.

Jeff Lewis – The Financial Post

Okay. Thank you.

Guy Jarvis

Okay.

Operator

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

Adam McKnight

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

Operator

Thank you. Ladies and gentlemen, this concludes today’s conference. Thank you for participating. You may now disconnect.

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