恩橋 (ENB) 2015 Q1 法說會逐字稿

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 will now like to turn the meeting over to Adam McKnight, Director, Investor Relations.

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 Johnston, Vice President and Controller.

This call is webcast and I encourage those listening on the phone lines to view the supporting slides which are available on our website. A replay at podcast of the call will be available later today and a transcript will be posted to our website shortly thereafter.

The Q&A format will be the same as always. We will take questions from the analyst community first and then invite questions from the media. I would ask that for everyone's benefit you wait until the end of the call to queue up for questions, and that questions are limited to two per person. Then please reenter the queue if you have additional queries. 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 would 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, to 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 will now turn the call over to Al Monaco.

Okay. Thanks, Adam. Good morning, everyone. Before we get to the quarter, I'd just make a couple of comments about the election last night, which I am sure everybody has heard the results of.

As an Albertan, I want to congratulate premier-elect Notley. She and her team have 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 am 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 at hand today. I'm going to start off with the highlights of 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 will come back with our business update, and I will focus mainly on two areas: how we are supporting our customers in this volatile commodity environment, and how we are progressing on the execution of our growth capital program. And I will go through some specific projects there, and then wrap up with the longer-term outlook.

So turning to slide 4, earlier this morning we announced our first quarter results. Earnings came in at CAD468 million or CAD56 a share. That is pretty much in line with where we were projecting to come in, so we are pleased with the quarter.

For the remainder of the year, we expect to see the continuation of strong liquids volumes and a higher Canadian mainline toll, driving earnings higher. We have several projects that are coming into service this year, so those will contribute nicely to earnings growth as well.

The high level takeaway is that Q1 is now under our belt. We are solidly on track to be within our full-year guidance range of CAD2.05 to CAD2.35 share. If we are able to come in at the midpoint of that range, then we will have generated another strong year of EPS growth of almost 16%. John will provide more color on the quarter in a minute, along with our usual take on the headwinds and tailwinds for the year.

On slide 5, the quarter also saw a very substantial 33% increase in our dividend take effect. This extends and bolsters an already strong growth track record on the dividend that we have delivered now over the years. This year's substantive increase stems from a combination of factors being the reliability of our business model, very strong operating performance, and a robust outlook over our five-year plan and beyond.

Part of that outlook reflects the proposed financial optimization we announced in December. So let me provide an update on that with the next slide.

The slide here on number 6 captures in one spot what the financial optimization is all about. There are basically two parts to it. The first has to do with our capital program, which is massive by any measure at CAD44 billion, and for the most part organic. On its own, that program would drive out an exceptional level of visible and reliable growth. The objective now is to further boost the value of that capital program by reducing the cost of funding it.

The graphic on the top left shows the proposed transfer of our Canadian liquids business to Enbridge Income Fund. That is the EIF on this chart. Most of Enbridge's external requirement to fund the capital program will now come from public investors of Enbridge Income Fund Holdings. And that is the ENF on the chart.

The other part of the optimization is an increase in our dividend payout to 75% to 85% of adjusted earnings. The plan is to target the lower end of that range initially, during the period of our heaviest growth capital funding, and before our free cash flow hits its full stride from the projects that we are putting in service.

As we move beyond our peak funding, we expect to migrate our payout to the upper end of the payout range. But, as John will take you through later, even that level of payout will be conservative relative to our peer group and provides further room for growth in the dividend, depending, of course, on the size and nature of our capital program at that time. This all amounts to a win-win, we believe, for both Enbridge and ENF.

Our shareholders benefit from what we expect will be 10% EPS accretion from the transfer. The dropdown, coupled with the dividend payout increase I just talked about, will also support 14% to 16% annual dividend growth out to 2018 from our current base.

The benefits to ENF will also be quite substantial. The trough will completely transform the fund, as it will receive the highest quality and fastest-growing asset base in the Canadian high-yield infrastructure sector. The magnitude and visibility of that growth will drive out an expected annual dividend growth rate of about 10% at ENF, commencing on closing and each year thereafter beginning in 2016 through 2019.

Slide 7. Here we are outlining the timeline and key milestones for the transfer to the income fund. The special committee of the independent directors of the fund and ENF was formed last December after the announcement of the proposal. During the first quarter, we finalized various elements of the proposal and submitted that to the special committee at the end of March. Assuming we reach agreement, there are a few additional steps and an ENF shareholder vote.

At this point, we are maintaining our estimated timing for completing the dropdown, which is midyear this year. At the time we announced the Canadian restructuring, we also indicated that we would review the possibility of a dropdown of our US liquids pipeline assets to EEP. We are still in that process and we expect to have more information on that after the second quarter. Obviously, though, our first priority at this point is executing the Canadian transfer.

So with that recap of the financial highlights, I'm going to pass it over to John for his review of the quarter and the 2015 outlook. John?

Thanks, Al, and good morning, everyone. I am 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 CAD468 million, which is about CAD24 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 pipeline earnings were 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. It 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 CAD0.10 per barrel effective April 1 of this year. And a surcharge for the Edmonton to Hardisty expansion, which we completed into 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 are relatively flat over the prior quarter. While these new lines have been very successful in drawing additional volumes through our mainline system, combined revenue and earnings were impacted during the quarter by the apportionment that we have 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 on stream, and we expect that the combined Seaway and Flanagan South system will start to deliver earnings and cash flow growth over the balance of the year.

Still within 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 little below last year, but this is simply a reflection of timing. We are currently recording revenue based on interim rates until a final rate order is granted. We will ultimately collect any differences between interim final rates through the utility's quarterly rate adjustment 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 US 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 are not really directly comparable.

Secondly, as we anticipated, Aux Sable's results came in lower than the first quarter of last year given the impact that weaker commodity prices have had on fractionation margins, which means limited opportunities for upside sharing above the base fee we receive 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.

Continuing now 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 Lakehead mainline system, combined with higher utilization on the North Dakota system. Secondly, EEP's earnings were also positively impacted by the dropdown 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% interest in both the Eastern Access expansion project and the US mainline expansion project. And, finally, the sponsored investment segment benefited from growing contributions from Enbridge Income Fund following the dropdown of the Alliance US 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 and the earnings outlook, given, as I said, that the 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 CAD2.05 to CAD2.35 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 a downside market. It will be hard to repeat the performance of last year, which benefited from wide and volatile differentials on both the gas and liquids 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 were not 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 tailwinds still fairly well-balanced.

Moving on to slide 10 and the liquidity picture, we continue to maintain very substantial amount 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 CAD8 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 five-year planning period in the view that you have 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 four years remain very manageable on both the debt and equity side.

And, finally, if you will 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 had 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 preview a reporting template at Enbridge Day in the early fall and present a long-term outlook using this template.

We are 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 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 this 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 businesses less maintenance capital. And it clearly demonstrated that accelerating cash flow would support growing dividends.

This outlook, which was projected off a 2013 base year, has not changed materially. As we have discussed, the main drivers of this 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 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 am going to turn the call back to Al.

Okay. Thanks, John. So we are on slide 13 now, and this is our business update for the quarter. First, it is 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 we can do that. So I will 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 have done that. Our heavy toll to Chicago has increased by just over 1% annually from 2011. There are two 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 have added 340,000 barrels per day of mainline capacity through 2014 and hopefully we will be able to eke out another 100,000 or so this year. And that includes our new mainline capacity, which we are able to access as needed through temporary system optimization efforts.

Those increments I am 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 three 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 have also seen the larger well financed producers reaffirm plans to move forward with their oilsands projects.

We are also focused on the near-term, so we have included a view on production growth here over the next couple of years. And this is based on oilsands projects currently in construction that we expect will be brought on through 2017. The increases amount to just over 200,000 barrels per day of growth annually over that period.

See how that is translated, on the right-hand side, to hire 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 CAD8 billion of projects into service at just slightly above budget. Today, we have got CAD23 billion in execution, which we are 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 have got a solid process for managing the supply chain, and that is a big part of what we are doing.

The graph illustrates here, we have done well on pricing per pipe relative to the rest of the market. And given the downturn, we are now chasing a number of opportunities to optimize our costs through the value chain. And over the last few months, we have 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, was optimizing the Wood Buffalo extension project. Basically, that involves upsizing the Cheecham- Kirby Lake segment from 30- to 36-inch pipe. We will 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 CAD400 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 return.

We also retain the option in the longer run to build a new line in the future from Kirby down to Hardisty as volumes dictate. And it is great to have that optionality. So all in, a win-win outcome, we believe, for Enbridge and customers.

Lastly, we will continue to support our customers by presenting the most economic capacity and market access solutions to grow production. Now, Guy went through this chart in some detail on the last call.

And the bigger picture -- the best way to think about these is low-cost, stage bolt-on opportunities. And we think these projects make a lot of sense given the pressure on oil prices, and we have seen the narrowing of basis differentials. So they fit quite well in our view.

I think it is another aspect of how we are 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 in a couple fronts.

Earlier this month, we brought our CAD1.8 billion Edmonton to Hardisty pipeline into service. You see the details on your chart there. We are pretty pleased on this one as the project came in on schedule and we forecasted the project to come in around 5% below budget.

Strategically, the line addresses much-needed capacity between the two major Alberta hubs, Edmonton and Hardisty. We see a lot more volumes coming as at 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 Pad 2 refinery requirements.

Our team has been doing a lot of work on the ground here, listening carefully to ensure that we are addressing people's concerns. In fact, it is a great example, I think, on how we have really upped our game on engaging with communities today.

To illustrate that, we proposed over 20 route changes to the Minnesota regulator. And because of our efforts like these, we have 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 PUC. It was a very positive and he concluded that we had proven the need for the line and recommended granted 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 then follow with a decision on that expected in 2016.

On to slide 20 and the CAD7.5 billion line 3 replacement project. The commercial terms were agreed to, as you recall, with the 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 a hearing to be scheduled for this fall.

To date -- and this is quite important -- we have secured 97% of the right-of-way. That is great progress and, again, reflects the approach we have with the landowner and stakeholder consultations. Better evidence of that is the agreement we have recently reached with the Canadian Energy Pipeline Landowner Association -- that is CAPLA, as it is known -- in support of line 3. In addition to compensation, some key elements of the agreement included comprehensive environmental protocol. Having CAPLA support the replacement of line 3 is a testament to the ability of both groups to find common ground, and something that we are proud of.

On the US side, we filed our application with the Minnesota regulator and the hearing is expected in 2016. And, there, we have 90% of the right-of-way in the US, which again reflects the good relationship we have there with landowners.

Moving now to slide 21 and 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 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 the Leave to Open, which is the final step in the process. But, while the NEB process has taken time, that reflects the importance of the project to the community and the diligence that they are going through.

At this point, we anticipate that the NEB will conclude their review and give us the final go-ahead this quarter.

Line 9 will allow refiners in Ontario and Quebec to access reliable feedstock and get themselves off foreign crude. And producers also gain access to a 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 GTA 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 US 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 are on track to complete it for the first -- fourth quarter, rather, of this year.

Let me conclude with our outlook, beginning with our record CAD44 billion growth program, and now we are on slide 23. CAD34 billion of that CAD44 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 is, of course, our planning horizon that we have right now.

Recall that CAD21 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 show the progress we have 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 CAD10 billion of risk unsecured category, I think as most people know, are projects we are working on but not commercially secure.

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 layer is 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 of the 33% that we had in the dividend, effective March 1, obviously very pleased with, and the significantly higher growth rate that comes with that of 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 talked about earlier.

So just to bring this to a close and summary, on slide 26. First quarter results were solid and in line with the expectations we had at CAD0.56 per share. We believe this puts us on track to be within our full year adjusted EPS range of CAD2.05 to CAD2.35 for the year.

And John went through the headwinds and tailwinds there. We have moved more volumes in our mainline, 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 are on schedule to complete the dropdown of our liquids pipelines business to Enbridge Income Fund later this year.

So that wraps up our prepared remarks, and we will now turn it back to the operator for the question and answer session.

(Operator Instructions) Linda Ezergailis, TD Securities.

I have a question with respect to the temporary relief at Seaway and Flanagan South. What was the earnings effect on that apportionment and 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 it 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?

Okay Linda, John can take that one.

Sure. Linda, I won't comment specifically on the combined Seaway and 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 relief 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 is 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?

Yes. That is correct.

Okay. That is helpful. Thank you.

Rob Hope, Macquarie.

Maybe just a follow-up to Linda's question; I am just hoping you could 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 add some additional color there?

Yes, so 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 the apportionment situation that we have seen on the mainline.

So I think the issue that is 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 are not 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.

Yes. Just to add onto that, I think Guy is right about that. But, just in terms of the segment that we are 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 have got volumes heading down the mainline. So we tend to look at the economics on a project-wide basis. So it is hard to look at just one segment like we have there and come to any conclusions. We're actually pleased with the volumes that we are seeing on the mainline. So the project is pretty much, as Guy said, where we expect it to be at this time.

All right. Thank you for the color. And maybe one follow-up question, just in terms of acquisitions, given the commodity price environment, are you seeing better opportunities to either tack on or are new platforms presenting themselves?

You are right about the commodity price environment. I would say, on the midstream side of things, probably less opportunities there; that is 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 are always looking for opportunities to build out the strategy. And we have certainly got our ears to the ground on things and we always look at things. But nothing, I would say, that is transformative at this point that we are considering.

Matthew Akman, Scotiabank.

A couple 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.

Yes. Well, I guess we share your hope on your comment around Line B. 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 are 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 is not just sourcing crude from Western Canada. Just given its strategic position, crude could be sourced from the Bakken as well for Line 9. And, as you know, the refineries there in Montreal and Quebec City area are ideally suited to run light. And so that makes a lot of sense as well. So, yes, it is an opportunity. But right now we want to make sure we are focused on the ball that is right in front of us.

Okay. Thanks. And my other question is related to storage opportunities. A couple of competitors have announced quite large storage expansions 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 am just wondering how you see Enbridge opportunities in that area playing out over the next 6 to 12 months?

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 have done a pretty good job in terms of identifying pipe capacity requirements.

But I think your comment is on the mark, because generally we have been probably a little bit behind as an industry in getting enough tankage. And it is extremely important, particularly in this environment where we have got some constraints to be able to stage crude, either upstream or downstream, both for operational reasons and as we have seen with this price volatility for merchant purposes and capitalizing on contango.

And I will 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 is why you are seeing some more activity in the industry. Guy, what about our plans?

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 of tanks is not unlike the competitive dynamic that we see in the oil sands, where there is 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 are pretty confident about that we are 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 are after services that we don't have the capability to offer at our terminal.

Okay. Thank you very much guys.

Paul Lechem, CIBC World Markets.

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 is 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?

Paul, it's guy. 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 have got going on in the system. So we are 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 are going to be in reasonably good shape to get the barrels there.

In terms of downstream of Patoka, near-term we don't have a plan for downstream of 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 that we succeed in doing that, that we will require additional market access. And we are 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 are confident in how that is going longer-term potentially there as well.

You know, Paul, I think it is a good question because it really goes to 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 US Gulf Coast, whether that is 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 will see that vision realized. But that is the ultimate goal, particularly, as I said, in this environment where you have got this pressure and differentials and absolute oil prices.

Okay. Thank you for that. If I can just ask one quick follow on, for John, maybe. The international joint toll typically adjusts twice a year, on April 1 and then July 1. I was just wondering if we can expect another adjustment this July 1 for the IJT. (multiple speakers)

(multiple speakers) 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 place in connection with Edmonton to Hardisty and other projects over the course of the year. Guy?

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 is the adjustment we are 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 two.

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

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 is going to be upwards, but not substantial.

Okay, thanks Guy.

Robert Kwan, RBC Capital Markets.

Just on the EEP review, I know you have got the stated focus of the review being a similar transaction to ENF. I guess, though, when you do 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?

Well, Robert, that is actually a tough question to answer because I guess it could be in between that spectrum. But, look, we are going to be pretty fulsome when we have concluded this review either way. And it may very well be that it is a fulsome potential dropdown similar to ENF. It may be -- it may not be. But it could be somewhere in between.

So I am not trying to be vague. It's just that we are 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.

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

I get your point, yes. I think what we would do is with the benefit of the analysis that we are doing right now, we would give a clear position on what the plan is between those two spectrums or at either end. And we will be very clear about that.

It is not something that we would come out and say, well, we are still thinking about this and we will get back to you next (technical difficulty). This is a priority. We set ourselves out to review the US 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 two to try and finalize this Canadian drop-down transaction. And then we will put the same vigor towards the US evaluation and come up with our thoughts on it.

Sure. Okay. And then, just a second question around mainline volumes. And this is slide 14. You have got kind of where we were in Q1 and where you could get to. Just in terms of the capacity increases and understanding what is in and what is out, what capacity increase is in there? Is that kind of Clipper phase 2 being inter-tied into Line 3 or is it something else?

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

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

Yes.

Okay great, thank you.

Andrew Kuske, Credit Suisse.

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 potential risks around your assets, primarily EGD and Alliance, as it relates to your prospective natural gas flows from the Marcellus and the Utica.

Okay. Well, it is a good question, Andrew. On NEXUS, our view of this is actually very strategic project from a number of perspectives. You know what the Marcellus and the Utica are going to do. There is a very high degree of clarity around that production profile over the next decade, so it is obvious that we are going to see a lot of production growth out of there.

NEXUS is a very good way to get that production moving. And fact that Ontario is such a strong market from many perspectives, the whole thing makes a lot of sense for us. So we are keen on it and the fact that we can utilize Vector to move that capacity is very strategic as well. So for us, it is 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 are 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 the utility point of view, we think it is pretty strong as well.

With respect to Alliance, we think this is actually playing out pretty much as we thought. There is 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 two regions.

And, as well, we have had really good success in re-contracting for Alliance. In fact, we are just about there, I would say, in terms of full capacity on the line now to re-contracting with an average term, say, in that five-year range. So from that perspective, we feel pretty good about that part of the strategy as well.

Okay. That's helpful. And then just maybe one 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?

Well, absolutely. Since it would be ideal for us to be in the project, we are speaking with both DT and Spectra right now. That is our ideal situation. Obviously, we will have to work through the commercial underpinnings to make sure that we have good solid throughput commitments on the line. As you know, that is always the issue with building new pipe, so we are working on that with them. And that is the hope, is to be involved in the project as soon as we can come to some terms.

Okay. That's very helpful. Thank you.

Steven Paget, First Energy.

On your waterfall chart, your CAD1.5 billion equity requirement is, if I recall correctly, roughly equal to the preferred shares Enbridge Inc. is looking to buy in the fund post dropdown. So my question, why not seek a public alternative for that funding? And it seems it might eliminate your equity requirement.

Steven, it's John. That actually does represent a public funding requirement that we would be looking for at the end of the day at various forms of equity or equity alternative. So we have some flexibility and I think the beauty of the structure that we have come up with to some degree is we can manage around that at the end of the day.

But, quite frankly, we will respond. But 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 is a variety of different ways we can get there and easily bring that amount down. I think that is really the point of the slide.

And I think, just to add on to John's comment, one of the things that that we were cognizant of with this structure around this dropdown 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 CAD600 million to CAD800 million that we have assumed, which the income fund holdings would tap the markets for, if that is available in a greater way, then you are right. The equity requirement would come down at Enbridge. But I think this is a good, prudent approach to the financial structure that we have got, and we will see as it unfolds. As John said, it gives us some pretty good flexibility.

Al, John, thank you. Could you maybe please comment on your discussions with Enbridge's bondholders surrounding the dropdown transaction?

Sure. It's John again. We have been an ongoing in 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 are starting to get a better understanding of the transaction itself. We have certainly structured the transaction to be credit neutral.

We actually think that it will serve to improve metrics -- credit metrics, that is, up at the parent company. Consolidated leverage is essentially unchanged. And, really, the cash flows available for the 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 are right in the middle of doing that as we speak.

So we are keeping an ongoing dialogue, I guess, with the fixed income community and as able working through that as we also work through the broader capture transaction.

Robert Catellier, JMP Securities.

One the elements one of the elements in the NDPs platform was 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?

Well, first of all, Robert, at this point, recognizing that it was part of the NDP 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 meet like that would be a 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 have got any feel for that right now.

With the caution that we are 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 up in a bunch of different places. But we don't see it affecting the outcome in particular. It is not a tax-driven transaction, per se, might be the way to put it. So I don't think it is a project capture issue. It might be a broader issue just generally for corporations in Alberta.

We will now take questions from the media community. For everyone's benefit, please limit yourself to one question and a related follow-up question as appropriate and return to the queue for additional lines of questioning. (Operator Instructions). Linda Ezergailis, TD Securities.

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

Yes. That has to actually do, Linda, with -- interestingly, around the initial design of the facility as opposed to anything that has happened recently here. But, we have been engaged with the EPA on this -- well, at least Aux Sable Management has. And we see that actually shaking out over the next little while here.

We don't have for you an estimate today of what it might take. We are just not far enough along with the EPA in the process. But I think we have had some very early engagement and it has been good dialogue and we will see where that shakes out.

Jeff Lewis, The Globe and Mail.

I just had a question about the election here in Alberta last night. Wondering, given the incoming premier -- 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 am 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? Thanks.

Okay, Jeff, it's Al. First of all, I would say that energy is such a critical issue to Alberta, I am not really that concerned that it is 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 the government would be focused on. I am 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 have undertaken on the side of safety and environmental protection.

As well, the discussions we have had with the 26 First Nations partners that we have and how we are coming along with fulfilling the conditions of the work we are doing.

So I guess ultimately, the way I look at things is that it is really up to industry to make the case for the projects. Both ourselves along with the customers that are working with us are diligently working on this. We spent a lot of capital to get to this point, about CAD500 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.

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 what sort of room is left to expand and whether that is a concrete idea or whether you were just musing about it? Thanks.

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

Chester Dawson, Wall Street Journal.

My question is somewhat similar to Jeff's. Not about Gateway, specifically, but in terms of the incoming governing party and Alberta's position on royalties, which they hope to review. Are you at all concerned that that is 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?

To be honest with you, I think we are just way too early in the process here. I think we are going to wait and see how things unfold. Obviously, the government will want to get settled and do their own assessment of what the priorities are. So I think we are too early in the game to draw any conclusion from it. 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 is too early.

Okay. And just in terms of the money spent on Gateway, I think you said CAD500 million. Is there any -- if you had to cancel the project, would that be the sum total of your cost or would it potentially be higher than that?

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 is the accumulated cost right now in total.

Okay. Thank you.

About half of it relates to monies we spent over the last decade or so.

Iris Kuo, Argus Media.

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.

Okay. I will 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 two main things that we are doing.

At the same time, we are always trying to assess whether or not we can refine the cost estimate and find some other opportunities to improve the cost. So those are the main things that we are doing at the moment. So we continue to work on the project. Guy, on the rail side?

Yes. So, on the Flanagan South rail, clearly that was an opportunity that we talk to our customers about as a stopgap measure to lack of pipeline capacity out of Western Canada. To this point in time, we have been unsuccessful in securing the commercial support we would need.

There is still a lot of uncertainty in terms of the though window in which it would be needed and the size of the commitments that would be made. So we continue to kind of slow play it. It is an option that is out there for industry if somehow it is determined that it would be needed for longer period of time, but right now it is not actively 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.

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

Okay. Well, on the permit itself, we are 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 are pursuing with the Department of State. So we are working through.

We have provided information to the environmental contractor that has been retained by the Department of State. We have provided all the information that we have been asked for. They are 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 is where we are in the project.

Now, with respect to optimization measures as we have 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 are using those opportunities right now and we can expand that if needed.

Okay. Thank you.

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

Thank you, Christine. We have no further comments at this time, but I would 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.

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