Enbridge Inc.
Q1 2015 Earnings Call Transcript

Published: 7 May 2015

[Operator:]

Good morning, ladies and gentlemen, and welcome to the Enbridge Inc. 2015 First Quarter Financial Results Conference Call. Please note that this event is being recorded. I would now like turn the meeting over to Adam McKnight, Director, Investor Relations.

[Adam McKnight:]

Thank you, Christine. Good morning, and welcome to Enbridge Inc.'s 2015 First Quarter Earnings Call. With me this morning are Al Monaco, President and CEO; John Whelen, Executive Vice President and Chief Financial Officer; Guy Jarvis, President, Liquids Pipelines; Leigh Kelln, Vice President, Investor Relations and Enterprise Risk; and Chris Johnson, 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. [Operator Instructions] I would also remind you that I will be available after the call for any follow-up questions that you might have. Before we begin, I'd like to point out that we may refer to forward-looking information in connection with Enbridge and the subject matter of today's call. By its nature, this information contains forecasts, assumptions and expectations about future outcomes, so we remind you it is subject to the risks and uncertainties affecting every business including ours. This slide includes a summary of the significant factors and risks that could affect future outcomes for Enbridge, which are also discussed more fully in our public disclosure filings on both the SEDAR and EDGAR systems. And with that, I'll now turn the call over to Al Monaco.

[Al Monaco:]

Okay. Thanks, Adam. Good morning, everyone. Before we get to the quarter, I'll just make a couple of comments about the election last night, which I'm sure everybody's heard the results of. As an Albertan, I want to congratulate Premier-elect Notley. She and her team has a lot to be proud of. As a company, we have a lot going on in developing new markets for Alberta's energy, so I'm looking forward to working with the government in the days and weeks ahead. From that front, I was very encouraged by the Premier-elect's comments last night about wanting to build a good relationship with the energy industry, and I would expect nothing less. We look forward to a strong dialogue with the new government. So on to the business in hand today. I'm going to start off with the highlights on the quarter and the status of our financial optimization strategy. John Whelen will then take you through the quarter and provide an update on where we see the remainder of the year. After that, I'll come back with our business update, and I'll focus mainly on 2 areas

[John K. Whelen:]

Thanks, Al, and good morning, everyone. I'm picking up on Slide 8 with a more detailed look at our first quarter financial performance by segment, focusing as we do on an adjusted earnings basis. As Al mentioned, consolidated earnings for the quarter came in at $468 million, which is about $24 million below the first quarter of 2014, but pretty much in line with where we expected to be at this point in the year. Liquids Pipelines earnings are actually down a bit on a quarter-over-quarter basis for a few reasons. Firstly, while volumes on the Canadian Mainline were up quite strongly, revenue growth was relatively flat given the impact of a lower Canadian residual benchmark toll that was in effect from August of last year until the end of the first quarter of this year. It is important to note that the residual benchmark toll has just been increased by about $0.10 per barrel effective April 1 of this year; and a surcharge for the Edmonton to Hardisty expansion, which we completed in April, is also now in effect. And we continue to expect the growing volumes in the system, together with incremental toll surcharges for projects that we brought into service over the balance of the year, will drive very strong full year revenue and earnings growth on the Mainline through the end of the year. I would also note the combined earnings from our Western Gulf Coast access pipelines, Seaway and Flanagan. So we're relatively flat over the prior quarter. While these new lines have been very successful in drawing additional volumes to our Mainline system, combined revenue and earnings were impacted during the quarter by the apportionment that we've been experiencing upstream on the Mainline. Shippers on Flanagan South do get a deferral of their take-or-pay obligations to the extent apportionment on the Mainline has affected their ability to deliver into the downstream pipeline. We do see the situation abating over the balance of the year, as new Mainline capacity expansions come onstream, and we expect that combined Seaway Flanagan South system will start to deliver earnings and cash flow growth over the balance of the year. Still within the Liquids Pipelines, our Regional Oil Sands System made a positive quarter-over-quarter contribution driven by incremental income from the Norealis pipeline, which went into service in April of last year, and higher volumes and expansion fees on the Waupisoo pipeline. But this was more than offset by an absence of earnings from the Southern Lights pipeline. As you may recall, we transferred a significant interest in Southern Lights to the Enbridge Income Fund last fall, and earnings from this pipeline now show up in our Sponsored Vehicle segment. On now to Gas Distribution, where earnings came in a bit higher than Q1 2014, mainly due to better performance at Enbridge Gas New Brunswick. First quarter earnings at Enbridge Gas Distribution utility are a little below last year, but this is simply a reflection of timing. We're currently recording revenue based on interim rates until a final rate order is granted. And we'll ultimately collect any differences between interim and final rates through the utility's quarterly rate adjusted mechanism during the course of 2015. So notwithstanding the quarter-over-quarter look, we continue to expect solid growth at EGD on a full-year basis. First quarter earnings from Gas Pipelines, Processing and Energy Services were down compared to Q1 last year for a few different reasons. Firstly, I should point out that this quarter's results exclude the performance of our 50% interest in the U.S. portion of the Alliance pipeline, which was transferred to Enbridge Income Fund and now shows up within Sponsored Investment segment. So the quarter-over-quarter segment results aren't really directly comparable. Secondly, as we anticipated, Aux Sable's results came in lower than the first quarter of last year given the impact of the weaker commodity prices have had on fractionation margins, which means limited opportunities for upside sharing above the base fee we received for plant operations. Thirdly, our energy service businesses delivered a solid quarter despite narrowing location differentials, as they were able to generate strong margins from tank management strategies. However, overall earnings were down relative to the first quarter of last year, when exceptionally cold weather provided an opportunity to benefit from historically volatile natural gas location differentials. Finally and on the plus side, contributions from our Canadian midstream facilities increased this quarter due to higher volumes on our Pipestone system and a step up in the take or pay fees on our investment in the cabin processing plant. [Indiscernible] down the slide, earnings generated from our Sponsored Investments were up significantly compared to the first quarter of 2014. And that strong growth again is the result of a number of different factors. Firstly, Enbridge Energy Partners delivered a higher earnings contribution on record throughput and higher tolls on the Lake Head Mainline system, combined with higher utilization on the North Dakota system. Secondly, EEP's earnings were also positively impacted by the drop down of the remaining 67% interest in the Alberta Clipper pipeline, which closed in early January. Thirdly, Enbridge also benefited from its direct investment in major expansion projects on the Lakehead Mainline system that came into service over the course of last year. Recall that Enbridge holds a 75-intraday percent interest in both the Eastern Access expansion project and the U.S. Mainline expansion project. And finally, a Sponsored Investment segment benefited from growing contributions from Enbridge Income Fund, following the drop down of the Alliance U.S. pipeline and the interest in the Southern Lights pipeline that occurred in Q4 of last year. Rounding out the consolidated picture, the corporate segment came in lower than Q1, largely as a result of higher financing costs, mainly higher dividends on preferred shares issued over the course of last year to fund the company's capital growth program. So all in all, a solid start to the year, not without some puts and takes, but on track with expectations overall. So turning now to Slide 9 in the earnings outlook. Given, as I said, that our performance was pretty much in line with expectations in Q1 and the growth that we anticipate over the balance of this year, we continue to remain comfortable with our adjusted earnings guidance range of $2.05 to $2.35 per share that we originally provided in December of last year. As a reminder, this guidance does not include the impact of the proposed restructuring currently under review by the Income Fund's independent committee, which we believe could add a 10% uplift to EPS on a full-year basis. All in all, the headwinds and tailwinds are pretty much playing out as we anticipated on our year-end earnings call in February. In the category of headwinds, the delay in securing Leave to Open for the Line 9 reversal and expansion is proving to be something of a drag on our earnings outlook. And while Aux Sable will continue to earn steady base fee income, upside sharing revenue is likely to be limited given the impact of the commodity price environment is expected to have on frac margins. We also remain a little cautious on Energy Services. Notwithstanding an encouraging first quarter, the opportunities to profit from location and time differentials generally become more challenging in the downside market. And it will be hard to repeat the performance of last year, which benefited from wide and volatile differentials on both the gas and liquid side of the business. Helping to offset these headwinds are the impact of a weakening Canadian dollar on the portion of our revenue and earnings that weren't hedged at the beginning of the year as well as lower-than-expected financing costs and the impact of some cost-containment efforts across the organization. So coming out of the first quarter, we feel comfortable with our guidance range with the headwinds and the tailwinds still fairly well balanced. Moving on to Slide 10 and the liquidity picture. We continue to maintain very substantial amounts of liquidity in the form of committed lines of credit to ensure we can readily manage our ongoing funding requirements irrespective of market conditions. We currently have close to $8 billion of available standby credit, which is expected to provide more-than-ample capacity and the flexibility to raise long-term capital when market windows are attractive. Our banks continue to be very supportive, and we believe we could even further bolster this liquidity if required. Turning now to Slide 11. This waterfall shows our sources and uses of funds over the current 5-year planning period in the view that you've become familiar with. This view assumes that the proposed Canadian restructuring proceeds as envisioned, and it presents a combined picture for both Enbridge Inc. and Enbridge Income Fund. With ample liquidity in place to manage through any market disruptions and a growing ability to raise meaningful amounts of equity through Enbridge Income Fund and our other Sponsored Vehicles, we continue to believe that our funding requirements over the next 4 years remain very manageable on both the debt and equity side. And finally, if you'll turn to Slide 12. If you think back to the funding waterfall slide I spoke to just a moment ago, one of the things that really stands out is the very significant amounts of internal cash flow that we will be generating over the next few years. We certainly have a lot of interest in our cash flow growth outlook, and we understand its importance to analysts and investors, particularly in light of our announced financial optimization strategy. We are in the process of developing enhanced cash flow reporting, and the current plan is to review a reporting template at Enbridge Day in the early fall and present a long-term outlook using this template. We're working to be in a position to provide cash flow guidance for 2016 later in the year and to start incorporating enhanced cash flow reporting into our results starting in 2016. In the meantime, we think you can get a pretty good sense of the cash flow growth and dividend coverage from our IR materials and from publicly-available information. We originally presented the charts on the left-hand side of the slide at Enbridge Day. For the purposes of this presentation, we define consolidated free cash flow as distributions from our Sponsored Vehicles plus funds from operations from wholly-owned business less maintenance capital. And it clearly demonstrated that accelerating cash flow would support growing dividend. This outlook, which was projected off of a 2013 base year, has not changed materially. As we have discussed, the main driver of the significant acceleration of free cash flow growth is the impact of our record capital program coming into service over the next few years. But another significant contributor is the tapering of our maintenance capital spending, as major onetime integrity projects are completed. The chart on the right illustrates where we sit to a number of our midstream peers with respect to the projected cash flow coverage of dividends in 2015. And as you can see, despite increasing our dividend 33% this year, we still remain at the higher end of the coverage spectrum versus our peers, which is notable particularly when you consider the reliability of the earnings and cash flow generated by our underlying businesses. And with that, I'm going to turn the call back to Al.

[Al Monaco:]

Okay. Thanks, John. So we're on Slide 13 now and this is our business update for the quarter. First, it's pretty clear that the business model that we have generates strong earnings and dividend growth, but the current price environment is obviously challenging the industry and our customers. Now we have an important role to play in helping those customers during this period of price volatility, and there are a few ways that we can do that, so I'll go through that. The most obvious is to manage the cost structure and provide stable and competitive tolls. And the table on the chart shows we've done that. Our heavy toll to Chicago has increased by just over 1% annually from 2011. There are 2 more significant drivers though related to the volume and price side of the producer equation and how they look at their business. The graph illustrates our recent efforts to increase capacity at minimal cost to shippers. We've added 340,000 barrels per day of Mainline capacity through 2014, and hopefully we'll be able to eke out another 100,000 or so this year. And that includes our new Mainline capacity, which we're able to access as needed through temporary system optimization efforts. Those increments I'm talking about are very important given the capacity constraints the industry is facing. And the third, the map highlights our market access projects that are opening up about 1.7 million barrels per day of new markets, which allows producers access to coastal markets and ultimately world pricing for their product. So together, these 3 factors help to maximize producer netbacks, but they also help assure reliable feedstock supply for our refinery customers. Slide 14 shows the impact of our optimization and expansion efforts. On the left is the current WCSB supply profile, which continues to look strong with another 2 million barrels of growth over the next decade. Yes, some investment decisions have been delayed, but we've also seen the larger well finance producers reaffirm plans to move forward with their oil sands projects. We're also focused on the near term, so we've included a view on production growth here over the next couple of years. And this is based on oil sands projects currently construction that we expect will be brought on through 2017. The increases amount to just over a couple of hundred thousand barrels per day of growth annually over that period. And see how that's translated on the right-hand side to higher Mainline throughput for Enbridge, which averaged 2.2 million barrels per day for the quarter, and that was a record for us. We expect to see that increase for the rest of the year as new capacity comes on. Another area of where we can add substantial value for customers is project execution. Turning to Slide 15 through 2014 and Q1 of this year, we put $8 billion of projects into service at just slightly above budget. Today, we've got $23 billion in execution, which were running pretty close to budget and schedule on. As you all know, the regulatory and permitting environment is difficult today, to say the least. So if we can keep this up, it will be a great accomplishment. Having the capability to manage through these challenges is critical to our customers, especially given large upstream and downstream investments that depend on us bringing projects in on time. And capital cost management is even more critical in the current price environment. We've got a solid process for managing the supply chain, and that's a big part of what we're doing. The graph illustrates here we've done well on pricing for pipe relative to the rest of the market. And given the downturn, we're now chasing a number of opportunities to optimize our cost through value chain. And over the last few months, we've been pursuing several of those opportunities, whether it be for pipe or Mainline contracting and so forth. On to Slide 16. Another capital management example that was good for Enbridge, but very good for customers as well as optimizing the Wood Buffalo Extension project. Basically that involves upsizing the Cheecham-Kirby Lake segment from 30 to 36 inch pipe. We'll then tie that expanded pipe into existing Athabasca Twin Line, which will also expand to 800,000 barrels per day. So that way, we can handle the Wood Buffalo Extension volumes on the Athabasca Twin, and that allows us to defer construction of the Wood Buffalo Extension south segment between Kirby Lake and Hardisty. The benefits of reconsidering that project are that we can redeploy about $400 million in capital from reduced scope. The shippers benefit, though, from lower tolls through a period of price volatility. At the same time, we mitigate our risk of unutilized capacity on the Athabasca system while maintaining our returns. We also retained the option in the longer end to build a new line in the future from Kirby down to Hardisty as volume dictate, and it's great to have that optionality. So all in, a win-win outcome, we believe, for Enbridge and customers. Lastly, we'll continue to support our customers by representing the most economic capacity market access solutions to grow production. Guy went through this chart in some detail on the last call. In the bigger picture, the best way to think about these is low-cost staged bolt-on opportunities. And we think these projects make a lot of sense given the pressure on oil prices. And we've seen the narrowing of basis differential, so they fit quite well in our view. I think it's another aspect of how we're able to leverage the size and scale of our footprint to enhance access to markets in a very cost-effective way. Let's move on now to an update on project execution, this is on Slide 17, where we made good progress on a couple of fronts. Earlier this month, we brought our $1.8 billion Edmonton to Hardisty pipeline into service. You see the details on the chart there. We're pretty pleased on this one as the project came in on schedule and we forecast the project to come in around 5% below budget. Strategically, the line addresses much-needed capacity between the 2 major Alberta hubs, Edmonton and Hardisty. We see a lot more volumes coming out of Edmonton, so we needed to bolster that takeaway capacity. And of course, that capacity is giving producers optionality to deliver production to the preferred hub in Alberta. And the project ultimately supports our downstream market access programs. Moving now to Slide 19, on Sandpiper. Sandpiper is obviously a very strategic project for us, but also Bakken producers and downstream refiners wanting access to light barrels. If you recall, we received strong commercial support for Sandpiper. Marathon is a committed shipper on the line and our partner in this project. This is a very good fit given Marathon's requirements to feed their Eastern PADD II refinery requirements. Our team has been doing a lot of work on the ground here listening carefully to consider that we're addressing people's concerns. In fact, it's a great example, I think, of how we've really upped our game on engaging with communities today. To illustrate that, we've proposed over 20 route changes to the Minnesota regulator. And because of our efforts like these, we received very strong support for this project in the state. A couple of weeks ago, the administrative law judge presiding over our application issued his recommendation to the Minnesota PDC. It was very positive, and he concluded that we've proven the need for the line and recommended granting the certificate of need. But to us, the most gratifying part was the judge's acknowledgment of the thousands of hours that we put in to determine the safest route for this project. The PUC hearing is expected in June; and assuming confirmation of the need, the route permit process will follow with the decision on that expected in '16. On to Slide 20 and the $7.5 billion Line 3 replacement project. The commercial terms were agreed to, as you recall, with our shippers last year. The replacement provides increased system reliability and flexibility for our customers. The project, we believe, is progressing well. In Canada, the NEB recently deemed the application complete, and we expect the hearing to be scheduled for this fall. To-date and this is quite important, we secured 97% of the right-of-way. That's great progress and again reflects the approach we have, the landowner and the stakeholder consultations. Better evidence of that is the agreement we recently reached with the Canadian Energy Pipeline Land Owners Association, that's CAEPLA, as it's known in support of Line 3. In addition to compensations and key elements of the agreement included comprehensive environmental protocol. Having CAEPLA support their replacement of Line 3 is a testament to the ability of both groups to find common ground and something that we're proud of. On the U.S. side, we filed our application with the Minnesota regulator, and a hearing is expected in 2016. And there we have 90% of the right-of-way in the U.S., which again reflects the good relationship we have there with land owners. Moving now to Slide 21 in the Line 9B project. Just a bit of background here for a moment. We did receive NEB approval last March for the project that was subject to 30 conditions, and we were mechanically complete in October last year. The NEB reviewed our adherence to the conditions that they outlined and signed off in February on those shortly after which we filed what we call Leave to Open, which is the final step in the process. While the NEB process has taken time, that reflects the importance of the project to the community and the diligence that they're going through. At this point, we anticipate the NEB will conclude their review and give us the final go ahead this quarter. Line 9 will allow refiners in Ontario and Québec to access reliable feedstock and get themselves off foreign crude, and producers also gain access to new market. In the bigger picture, though, this new source of supply for Eastern refiners will enhance their competitiveness and protect thousands of Canadian refinery jobs. Finally, on to Slide 22 and the GPA project. Earlier this year, we started construction on the project, which is the largest expansion in EGD's history. You can see from the inset map here, the project will expand the system and increase capacity and reliability for our gas customers in the GTA. And it also improves our ability to access additional basins in the U.S. Northeast and particularly the Marcellus. This provides a great opportunity for the gas business here to diversify its sources of low cost, reliable supply for our customers here. And this is a very important project for EGD, and we're on track to complete it for the first -- fourth quarter, rather, of this year. Let me conclude with our outlook, beginning with our record $44 billion growth program, and now we're on Slide 23. $34 billion of that $44 billion is secured and in execution and remains on track to deliver the 10% to 12% EPS and dividend per share growth through 2018, and that's of course our planning horizon that we have right now. Recall that $21 billion of that though attracts what we have been calling the upward tilted return profile, which helps drive EPS growth beyond 2018. And that growth is going to require no incremental capital investment on those projects. The green areas of the bar here showed the progress we've made bringing projects into service through last year and over the first quarter of this year. The blue areas indicate what we expect to see the balance of projects coming in on. The remaining $10 billion risk unsecured category, I think, as most people know, our projects were working on, but not commercially secured. On Slide 24, that brings me to our EPS growth outlook. I think many of you have seen this before. The blue portion shows our base 10% to 12% average annual growth rate through 2018. The yellow layers on the expected 10% accretion to adjusted EPS from the optimization plan. Backed by our secured growth program and financial strategy optimization, this growth outlook remains intact. And we remain confident, by the way, that we can extend our industry-leading growth past 2018 with further investment in the other parts of the business besides liquids pipeline. And that will be supplemented by rising cash flow growth from projects with these tilted return profiles. Slide 25 is the corresponding dividend growth outlook. This reset to the 33% that we had in the dividend effective March 1, obviously, very pleased with. And significantly higher growth rates that comes with that, a 14% to 16% through 2018, also remains intact backed by our secured growth program, the restructuring that we talked about and continued expansion of the payout to the upper end of the range, I've talked about earlier. So just to bring this to close, in summary, on Slide 26. First quarter results were solid and in line with the expectations we had at $0.56 per share. We believe this puts us on track to be within our full year adjusted EPS range of $2.05 to $2.35 for the year, and John went through the headwinds and tailwinds there. We've moved more volumes on the Mainland, which we see continuing. The execution of the record growth program is also progressing well. And earnings and dividend growth outlook to 2018 and beyond remains intact. Finally, we're on schedule to compete the drop down of our Liquids Pipelines business to Enbridge Income Fund later this year. So that wraps up our prepared remarks, and we'll now turn it back to the operator for the question-and-answer session.

[Operator:]

[Operator Instructions] Our first question comes from Linda Ezergailis from TD Securities.

[Linda Ezergailis:]

I have a question with respect to the temporary release to Seaway and Flanagan South. What was the earnings effect on that apportionment and [ph] relief? And I guess for Spearhead it wasn't relief, but there was still lower earnings. And how quickly will that dissipate over 2015? Is this still going to be a material comment in Q2? And then, with respect to making up that take or pay, does that extend the period of the take-or-pay payments? Or is there some sort of accelerated catch-up in the near term once the apportionment dissipates?

[Al Monaco:]

Okay. Linda, John, take that one.

[John K. Whelen:]

Sure. Linda, I won't comment specifically on the client Seaway Flanagan South, perspective. We usually don't get too much down into that level of granularity. What I will tell you is the impact of upstream apportionment on that toll does start to abate over the balance of the year. It will be less of a comment as we move on through the year, over the course of the year, in terms of that impact over time. The take or pay obligation is -- it is a deferral. It's not a dismissal of that obligation, if you like. It could be made up in periods where there is excess capacity on the system at any time if they are shipping above their contracted capacity. And, if it isn't, it would then be tacked onto the end of the contract. Have I got that pretty much right?

[Al Monaco:]

Yes. That's correct.

[Operator:]

Our next question comes from Rob Hope from Macquarie.

[Robert Hope:]

Maybe just a follow-up to Linda's question. I'm just hoping you can just walk me through the volume dynamics. We saw the Mainline volumes up quarter-over-quarter, yet the Seaway and Flanagan income was down quarter-over-quarter. Can you just add some additional color there?

[D. Guy Jarvis:]

Yes. It's Guy. Certainly, the volumes were strong on the Mainline, and that was exactly what we had expected. Out of the Mainline, in terms of Seaway and Flanagan, I think the volume outlook that we have achieved in the first quarter on Flanagan South and the Seaway Twin was actually a little bit stronger than our budget, despite that the apportionment situation that we've seen on the Mainline. So I think the issue that's kind of missing in the mix of the performance is that the base Seaway system volumes were down and the performance of the base Seaway system was down in Q1. I think lots of people in the industry are aware of the volumes in Cushing, growing in storage. And the result of that inventory growing in Cushing is that the volumes aren't exiting and looking to get to market. So the combination of competition in the marketplace and the growth in the storage inventories has impacted the base Seaway system.

[Al Monaco:]

Just to add onto that. Guy is right about that. But just in terms of the segment that we're looking at there with Flanagan and Seaway, the way we tend to look at this is more of a combined basis economically because obviously, you've got volumes heading down the Mainline, and so we tend to look at the economics on a project-wide basis. So it's hard to look at just 1 segment like we have there and come to any conclusions. We're actually pleased with the volumes that we're seeing on the Mainline. So the project is pretty much, as Guy said, where we expect it to be at this time.

[Robert Hope:]

All right. Maybe 1 follow-up question. Just in terms of acquisitions, given the commodity price environment, are you seeing better opportunities to either tack on or new platforms presenting themselves?

[Al Monaco:]

You're right about the commodity price environment. I would say, on the midstream side of things, probably less opportunities there. That's simply because the business model that most of us employ isn't directly sensitive to commodity prices, in most cases at least, certainly not for us. So the opportunity set is probably a little bit less. Having said that, though, we're always looking for opportunities to build out the strategy, and we've certainly got our ears to the ground on things, and we always look at things. But nothing, I would say, that's transformative at this point that we're considering.

[Operator:]

Our next question comes from Matthew Ackman from Scotiabank.

[Matthew Akman:]

A couple of project updates and possible opportunities for expansion I wanted to touch on. First is 9B, hopefully that will be up and running shortly. I'm just wondering if the delay in Energy East is creating opportunities for potential expansion of Line 9, maybe even on an earlier time frame or higher probability than you had hoped?

[Al Monaco:]

Yes. Well, I guess we share your hope on your comments around Line B. Our current expectation is that we should be able to get it in, in the second quarter here. On the broader question around the competing pipelines and what that means for Line 9B, I think, for sure, we have some room to expand there. But obviously, right now, Matthew, we're focused on ensuring that we can get the line into service. And hopefully that happens in due course here, but there is some additional capacity that could be brought to bear. And of course, on Line 9, it's not just a sourcing crude from Western Canada just given its strategic position. Crude could be sourced from the Bakken as well for the Line 9. And as you know, the refineries there, in Montreal and Québec City area, are ideally suited to run light and so that makes a lot of sense as well. So, yes, it's an opportunity, but right now we want to make sure we're focused on the ball that's right in front of us.

[Matthew Akman:]

Okay. My other question is related to storage opportunities. A couple of competitors have announced quite large storage expansion in the main hubs in Alberta. And Enbridge has been a bit quiet there, though opportunities have been identified. Maybe this is a question for Guy, but I'm just wondering how you see Enbridge opportunities in that area playing out over the next 6 to 12 months.

[Al Monaco:]

I will make a general comment, then Guy will want to say something, I'm sure. I think the dynamic in North America has been very interesting. We've done a pretty good job in terms of identifying pipe capacity requirements. But I think your comment is on the mark because generally we've been probably a little bit behind as an industry and getting enough tankage. And it's extremely important, particularly in this environment where we've got some constraints to be able to stage crude, either upstream or downstream, both for operational reasons, and as we've seen with this price volatility for merchant purposes and capitalizing on Contango. And I'll add as well on the energy services area, it's certainly something that we benefited from and our ability to capitalize on basis and ability to blend different types of crude. So I think generally, there are some good opportunities here, and that's why you're seeing more activity in the industry. Guy what about our plans?

[D. Guy Jarvis:]

Yes. So we still do have some additional opportunities that we foresee at our Hardisty storage facility ourselves. One of the things that we caution people about in terms uptakes is not unlike the competitive dynamic we see on the oil sands where there's a huge locational advantage that you have in terms of where your assets are located. There is a lot of advantage or disadvantage, depending on the connections that are required. So we're pretty confident that we're going to have an opportunity in the pretty near term to build out the remaining Hardisty contract terminal capability that we have, but we certainly do see others contracting with other parties. And generally speaking, in a lot of those circumstances, they're after services that we don't have the capability to offer at our terminal.

[Operator:]

Our next question comes from Paul Lechem from CIBC.

[Paul Lechem:]

Wanted to ask about the southern access extension pipeline that the MD&A says is targeting a Q4 2015 in service. Just wondering, around that pipeline, what's your ability to deliver volumes to that from the mainline given the apportionment that we saw in Q1? And then, further to that, what are your plans downstream of Patoka? I just wonder how you see your extension to the Eastern Gulf playing out over time. And does Marathon's involvement in that project in Sandpiper, in the Capline, does that have -- does that play into that decision and timeframe?

[D. Guy Jarvis:]

Paul, it's Guy. So Southern Access Extension is on target to come into service towards the end of the year. When you think about the upstream, you have to look at other expansions we've got going on the system. So we're pretty confident that our Line 3 maintenance and flexibility program that we put in place in the fall of last year is going to allow us to take advantage of the incremental capacity on the system that will result from the Alberta Clipper stations. Moving down into the Lakehead part of the system, we are currently right in the throes this month of expanding the Southern Access pipeline up to 800,000 barrels a day. So there is additional capacity coming into service upstream of Southern Access Extension before it does go into service. So we think we're going to be in a reasonably good shape to get the barrels there. In terms of downstream of Patoka, near term, we don't have a plan for downstream in Patoka. The plans for taking those barrels away would be in the hands of our shippers on Southern Access Extension. As we talked in the last call, we are evaluating these opportunities that Al referenced earlier to kind of bolt-on and add increments of capacity to our system upstream. We will reach a point, if we succeed in doing that, that we will require additional market access. And we're continuing to evaluate all of those options for additional volumes on Flanagan South, for the potential to get to the Eastern Gulf, and further down the road after Line 9 is up and running and we're confident in how that's going longer-term potentially there as well.

[Al Monaco:]

Paul, I think that's a good question because it really goes to sort of the big picture strategy here. And you could look at these segments individually, and I think your question is good. I think in the big picture, when you kind of put all the pieces of the puzzle together, our goal is to make sure that we can get more capacity into the U.S. Gulf Coast, whether that's the Western Gulf or the Eastern Gulf. And I think this Southern Access Extension is important piece of that. And then as Sandpiper and Southern Access come through and we get more capacity, I think we'll see that vision realized. But that's the ultimate goal particularly, as I said, in this environment where you've got this pressure in differentials and absolute oil prices.

[Paul Lechem:]

Okay. If I can just ask 1 quick follow on for John, maybe. The international joint toll typically adjusts twice here on April 1 and then July 1. I was just wondering if we can expect another adjustment up this July 1 for the IJT?

[John K. Whelen:]

[indiscernible] I need to check with Guy. We have had an increase that just went into effect, as I mentioned, on April 1. And we will see the impact of additional surcharges coming into plays in connection with Edmonton/Hardisty and other projects over the course of the year. Guy?

[D. Guy Jarvis:]

Yes. So the adjustment usually takes place on April 1 is related to the Canadian residual toll, not the overall international joint toll. So that's the adjustment we're talking about for April. July 1 of the year is the point in time when the escalator around the international joint toll is renewed or reestablished, so there will be 2.

[Paul Lechem:]

Okay. And can you give anything -- any comment around the magnitude of that on July 1?

[D. Guy Jarvis:]

I don't know offhand other than I think the expectation is based on the escalators -- the underlying factors that drive the escalation that it's going to be upwards, but not substantial.

[Operator:]

Our next question comes from Robert Kwan from RBC Capital Markets.

[Robert Kwan:]

Just on the EEP review. Just, I know you've got the stated focus of the review being a similar transaction to ENF. I guess, though, when you come out with the decision, is it going to be more of a yes or a no? And if the answer is no, will you also come up with a specific alternative path forward? Will that be articulated in terms of vision for moving forward with EEP?

[Al Monaco:]

Well, Robert, that's actually a tough question to answer because I guess it could be in between that spectrum. But look, we're going to be pretty fulsome when we have concluded this review either way. And it may very well be that it's a fulsome potential drop down similar to ENF. It may be -- it may not be, but it could be somewhere in between. So I'm not trying to be vague, it's just that we're right in the process right now of determining what the best option is. And like I said, hopefully, we can be patient and wait for the second quarter when we should be done, and hopefully we can be fulsome then.

[Robert Kwan:]

Yeah. That actually is helpful. Just to be clear, though, I think what you're trying to say though is you are going to come out, though, with a clear vision one way or another. It could be anything between yes or no, but it will be very detailed to the market as to how you're going to proceed?

[Al Monaco:]

Yes. I get your point. Yes, so I think what we will do is with the benefit of the announcements that we're doing right now, we would give the clear position on what the plan is between those 2 spectrums, or at either end, and we'll be very clear about that. It's not something that we would come out and say we're still thinking about this and we'll get back to you next. This is a priority. We set ourselves out to review the unit's opportunity. I think the only point I was making earlier in the remarks was that the priority at this very moment is the next month or 2 to try and finalize this Canadian drop down transaction, and then we'll put the same vigor towards the U.S. evaluation and come out with our thoughts on it.

[Robert Kwan:]

Sure. Okay. And then, just a second question around mainline volumes, and this is Slide 14. You've got kind of where we exited or where we were in Q1 and where you could get to. Just in terms of the capacity increases and understanding what's in and what's out, what capacity increase is in there? Is that kind of Clipper Phase II being inter-tied into Line 3, or is it's something else?

[Al Monaco:]

Yes, the chart, if you think through 2015, assumes that we can optimize the capacity that we're building now for Alberta Clipper with the temporary optimization initiatives that I think you're aware of it.

[Robert Kwan:]

So roughly speaking, it looks like eyeballing it gets you to about 2.5 million barrels a day?

[Al Monaco:]

Yes.

[Operator:]

Our next question comes from Andrew Kuske from Credit Suisse.

[Andrew M. Kuske:]

The question is for Al and it just relates to your natural gas assets and in particular, if you could just give us an update on your standing on NEXUS. And then just a little bit of maybe the opportunities and the potential risks around your assets, primarily EGD and Alliance, as it relates to your prospective natural gas flows from the Marcellus and the Utica.

[Al Monaco:]

Okay. Well, it's a good question, Andrew. On NEXUS, our view of this is actually it's a very strategic project from a number of perspectives. You know what the Marcellus and Utica are going to do. There's a very high degree of clarity around that production profile over the next decade. So it's obvious that we're going to see a lot of production growth out of there. NEXUS is a very good way to get that production moving. And the fact that Ontario is such a strong market from many perspectives, the whole thing makes a lot of sense for us. So we're keen on it. And the fact that we can utilize Vector to move that capacity is very strategic as well. So for us, it's a good full value chain connection all the way into the market. In terms of EGD, from their perspective, being able to access a basin like this in a very significant way is very important to our goal there to diversify the sources of gas supply. And I think from their perspective, obviously, the utility goes through their own analysis. They're pretty keen on the project as well. So from a midstream investment point of view, we like it. We like the connection between it and Vector. And from a utility point of view, we think it's pretty strong as well. With respect to Alliance, we think that this is actually playing out pretty much as we thought. There's a lot of gas moving into the Alberta market along with liquids. And Alliance, we have always felt, provides a very good option for producers, and particularly in BC, to move that liquids rich gas that would otherwise be pounding into the Alberta market to another market which is very strong. I think you can see that playing out with the basis widening out between these 2 region. And as well, we've had really good success in recontracting up for Alliance. In fact, we're just about there, I would say, in terms of full capacity on the line now through recontracting with an average term, say, in that 5-year range. So from that perspective, we feel pretty good about that part of the strategy as well.

[Andrew M. Kuske:]

Okay. That's helpful. And then just maybe 1 brief follow-up on NEXUS. As that project files the FERC application later this year, really at this point led by Spectra and DTE, do you plan to be one of the project proponents officially at that stage?

[Al Monaco:]

Well, absolutely, since it would be ideal for us to be in the project. We're speaking with both DTE and Spectrum right now. That's our ideal situation. Obviously, we'll have to work through the commercial underpinnings to ensure that we've got good solid throughput commitments on the line. As you know, that's always the issue with building new pipes, so we're working on that with them. And that's the hope is to be involved in the project as soon as we can come to some terms.

[Operator:]

Our next question comes from Steven Paget from First Energy.

[Steven I. Paget:]

On your waterfall chart, your $1.5 billion equity requirement, if I recall correctly, is roughly equal to the preferred shares Enbridge Inc. is looking to buy in the fund post drop down. So my question, why not seek a public alternative for that funding? And it seems it might eliminate your equity requirement.

[John K. Whelen:]

Robert -- sorry, Steven, it's John. That actually does represent a public funding requirement that we're looking for at the end of the day, various forms of equity or equity alternative. So we had some flexibility, and I think the beauty of the structure that we've come up with, to some degree, is we can manage around that at the end of the day. But quite frankly, we'll respond. The whole point of this model is if we see an opportunity to raise capital on attractive terms in different parts of the organization, we will tap that market. So your point is well taken. There's a variety of different ways we can get there and easily bring that amount down. I think that's really the point of the slide.

[Al Monaco:]

I think, one of the -- just add on to John's comment, one of the things that we're cognizant of with this structure around this drop down is to ensure that Enbridge Income Fund holdings, or ENF, was positioned well to go to the market in amounts that would not result in an overhang. So if we find, as we move through the next few years, that the $600 million to $800 million that we have assumed, which the Income Fund Holdings would tap the markets for, if that's available in a greater way, then you're right. The equity requirement would come down at Enbridge. But I think this is a good, prudent approach to the financial structure that we've got. And we'll see, as always John said, it gives us some pretty good flexibility.

[Steven I. Paget:]

John, thank you. Could you maybe please comment on your discussions with Enbridge's bond holders surrounding the drop-down transaction?

[John K. Whelen:]

Sure, it's John again, Steven. We've been in an ongoing discussions and meetings with fixed income investors, just like we always are, in and around Enbridge credit in general and the impact of the transaction. I think they're starting to get a better understanding of the transaction itself. We've certainly structured the transaction to be credit-neutral. We actually think it will serve to improve metrics -- credit metrics, that is, of the Parent Company. Consolidated leverage essentially unchanged. And really, the cash flow is available to service debt at the corporate level are relatively unchanged as well. That said, we have to go through a process clearly with the rating agencies, and we're right in the middle of doing that as we speak. So we're keeping an ongoing dialogue, I guess, with the fixed income community and, as I say, hope to be working through that as we also work through the broader capture transaction.

[Operator:]

Our next question comes from Robert Catellier from GMP Securities.

[Robert Catellier:]

One of the elements in the NEB's platform was a potential increase to provincial taxes. And should that come to pass, how material do you think that is to the restructuring strategy and for the ENF in particular to be able to achieve your accretion targets?

[Al Monaco:]

Well, I guess, first of all, Robert, at this point recognizing that it was part of the E&P platform, I think we're going to have to wait and see how that shakes out in terms of any potential tax increases. For us, John, maybe you can comment, it doesn't feel to me like that would be material impact to the transaction just given the number of jurisdictions that we have other than Alberta. But I don't know, John, if you got any feel for that right now?

[John K. Whelen:]

With the caution, but we're not sure what the regime might look like. I don't think tax plays a major role at the end of the day in our assessment of this particular transaction in isolation in that it could play out in a bunch of different raises, but we don't see it affecting the outcome, in particular. It's not a tax-driven transaction per se, might be a way to put it, so. I don't think it's a project capture issue, it might be a broader issue just generally for corporations in Alberta.

[Operator:]

We will now take questions from the media community. [Operator Instructions] And your last analyst question comes from Linda Ezergailis from TD Securities.

[Linda Ezergailis:]

Just a detailed question on Aux Sable. It says in your report that you've exceeded currently permitted limits for volatile organic material. Can you maybe describe how you might become compliant with, if it involves some capital expenditures or maybe derating the facility a little bit and when that might be resolved?

[Al Monaco:]

Yes. That has to actually do, Linda, with interestingly around the initial design of the facility as opposed to anything that's happened recently here. But we've been engaged with EPA on this, well, at least, Aux Sable management has. And we see that actually shaking out over the next while here. We don't have for you an estimate today of what it might take. We're just not far enough along with the EPA in the process. But I think we've had some very early engagement and it's been good dialogue, and we'll see where that shakes out.

[Operator:]

Our next question comes from Jeff Lewis from The Globe and Mail.

[Jeff Lewis:]

I just had a question on the election here in Alberta last night. Wondering, given the incoming Premier's comments on advocacy for projects like Northern Gateway and the fact that she seems to be pulling away from that or not keen to advocate for a project like that. I'm wondering, from your point of view, what impact that has as you seek to build some of these larger scale projects and specifically Gateway? Are you concerned about losing an advocate in Edmonton?

[Al Monaco:]

Okay Jeff. It's Al. First of all, I would say that energy is such a critical issue to Alberta. I'm really not that concerned that it's not going to get the right attention or the right support from the new government. With respect, specifically, to Gateway, I haven't spoken to Ms. Notley on the project. My understanding is that she has raised concerns about a couple of projects and their ability to succeed. But ultimately, I believe that the new government does support market access. That will be obviously something that government would be focused on. I'm looking forward to speaking with her about projects, not just Gateway though, but our entire market access strategy, just given how important it is to Alberta and the rest of Canada. I look forward to taking the Premier Elect through the benefits, but also the safety measures and the amount of work that we've undertaken on the side of safety and environmental protection, as well, the discussions we've had with the 26 First Nations partners that we have and how we're coming along on fulfilling the conditions of the work we're doing. So I guess, ultimately, the way I look at things is that it's really up to industry to make a case for the projects. Both ourselves along with the customers that are working with us are diligently working on this. We've spent a lot of capital to get to this point, about $500 million between us. And frankly, we think that the view is worth the climb here on this project. And hopefully with some further discussion, the Premier Elect would agree with that.

[Jeff Lewis:]

Okay. And just a quick follow-up on the Line 9. You were speaking about the potential for extra capacity on that pipeline. Can you just clarify on just what sort of room is left to expand and whether that is a concrete idea or whether you were just musing about it?

[Al Monaco:]

I guess, Jeff, from a capacity point of view, yes, there is incremental capacity that's available. I wouldn't say it's material or relative to the base commitments of around -- or capacity around 300,000 barrels. It's probably in the 10% to 15% to 20% range, somewhere in there. But as I said earlier, it's not something that we have on the books right now, but it is theoretically possible.

[Operator:]

Our next question comes from Chester Dawson from Wall Street Journal.

[Chester Dawson:]

My question is somewhat similar to Jeff's, not about Gateway specifically, but in terms of the incoming governing party in Alberta's position on royalties, which they hope to review. Are you at all concerned that that's going to impact volumes on the system going forward, especially your expectations for built-in growth? And secondly, in terms of Gateway, would that have any material impact? If so, how much if that project was not able to go forward because of the change in government?

[Al Monaco:]

To be honest with you, I think we're just way too early in the process here. I think we're going to wait and see how things unfold. Obviously, the government will want to get settled and do their own assessment of what their priorities are. So I think we're too early in the game to draw any conclusion from it. I -- As I said earlier, I will say that the government will obviously be focused on the energy file, just given its importance to Western Canada and Canada overall. So at this point, I think it's too early.

[Chester Dawson:]

Okay. And just in terms of the money spent on Gateway, I think, you said $500 million. Is there any -- if you had to cancel the project, would that be the sum total of your costs? Or would it be potentially higher than that?

[Al Monaco:]

Yes, just to clarify, that amount of capital is split about 50-50 between ourselves and the funding participants or the customers/producers that we have working with us. So that's the accumulated costs right now in total. And about half of it relates to monies we've spent over the last decade or so.

[Operator:]

And your last media question comes from Iris Kuo from Argus Media.

[Iris Kuo:]

I was wondering if you could update us on a couple of projects, firstly, Northern Gateway. And then, secondly, your potential plans to build out crude by rail facilities at Flanagan and Cushing.

[Al Monaco:]

Okay. I'll take the Gateway project. I think it was a year ago or so that we, after the approval of the project by the government based on the joint review panels recommendation, that we said we were going to reengage with First Nations communities. We are doing that and working away diligently on that. We are also working on some other things related to the project around addressing the regulator's conditions. So those are the 2 main things that we are doing. At the same time, we're always trying to assess whether or not we can refine the cost estimate and find some other opportunities to improve the costs. So those are the main things that we're doing at the moment, so we continue to work on the project. Guy, on the rail side?

[D. Guy Jarvis:]

Yes, so on Flanagan South rail, clearly, that was an opportunity that we've talked to our customers about as a stopgap measure to lack of pipeline capacity out of Western Canada. To this point in time, we've been unsuccessful in securing the commercial support we would need. There's still a lot of uncertainty in terms of the window in which it would be needed and the size of the commitments that will be made. So we continue to, kind of, slow play it. It is an option that is out there in the industry, if somehow it's determined that it would be needed for a long period of time, but right now, it's not actually being developed. Over at Cushing, I think, again, not a lot of active development around rail on our behalf over there. The focus is really largely around our Seaway asset and maximizing its value.

[Iris Kuo:]

Okay, great. And then just one housekeeping item. I'm a little unclear on where things are with Alberta Clipper. Did you guys get a presidential permit for that? Or is the line doing interconnect already slowing or is it both? Where are things with Alberta Clipper right now?

[Al Monaco:]

Okay. Well, on the permit itself, we're going through the process there with the Department of State. And just to clarify, this is an amendment to an existing presidential permit, which we're pursuing with the Department of State. So we're working through. We've provided information to the environmental contractor that's been retained by the Department of State. We've provided all the information that we've been asked for. They're working on it. Our understanding is that they have what they need from us and should be close, hopefully, to putting together the supplemental environmental impact statement. And so that's where we are in the project now. With respect to optimization measures, as we've been talking about over the last year or so, we do have some temporary measures that we can use to move additional barrels across the border. We're using those opportunities right now, and we can expand that if needed.

[Operator:]

Thank you. I would now like to turn the call back to Adam McKnight for closing remarks.

[Adam McKnight:]

Thank you, Christine. We have no further comments at this time, but I'd like to remind everybody that I will be available after the call for any follow-up questions that you might have. Thank you for joining us this morning, and have a great day.

[Operator:]

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