恩橋 (ENB) 2013 Q4 法說會逐字稿

Welcome to the Enbridge Inc. 2013 year-end financial results conference call. My name is Christine, and I will be the operator for today's call. (Operator Instructions) Please note that this conference is being recorded. I will now turn the call over to Mr. Adam McKnight. You may begin.

Thank you. Good morning and welcome to Enbridge Inc.'s fourth-quarter of 2013 earnings call. With me this morning are Al Monaco, President and CEO; Richard Bird, Executive Vice President, Chief Financial Officer and Corporate Development; Steve Wuori, President of Liquids Pipelines; Guy Jarvis, Executive Vice President and Chief Commercial Officer of Liquids Pipelines; and John Whelen, Senior Vice President and Controller.

This call is webcast, and I encourage those listening on the phone line 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 on our website shortly thereafter.

The Q&A format will be the same as always. We'll 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 the questions are limited to two per person. Please reenter the queue if you have additional queries. I would also like to remind you that I will be available after the call for any follow-up questions that you may have.

Before we begin, I'd like to point out that we may refer to forward-looking information during the call. By its nature, this information implies certain assumptions and expectations about future outcomes, so we remind you it is subject to the risks and uncertainties affecting every business, including ours. This slide includes a summary of the more significant factors and risks that might affect future outcomes for Enbridge, which are also discussed more fully in our public disclosure filings, available on both the SEDAR and EDGAR systems.

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

Okay, thanks, Adam. Good morning, everybody. I'm going to begin by recapping the fourth quarter and annual results and then the progress on our key strategic priorities, as we usually do on these calls. Richard will then take you through the results in more detail, along with our funding position; and then I'll close it out with illustrating the transparency of our growth profile going forward.

Before I do that -- this is now moving to Slide 5 -- I'm going to touch on two organizational changes. As you know, we focus a lot of time at Enbridge here on developing our people and ensuring we have strong players in every area of the business.

A couple of weeks ago, we welcomed Greg Harper to the team. Greg takes over as President of our gas pipelines and processing business unit. You know that covers Alliance, Vector, Aux Sable, our Canadian midstream business, our US gathering and processing unit -- and that includes the recently IPOed Midcoast Energy Partners -- and our offshore Gulf of Mexico business. Many of you know Greg. He certainly brings a deep operational, commercial, and development experience in gas.

And as we announced earlier today, Steve Wuori, who currently leads our liquids pipelines business, will take on a new role as Strategic Advisor, Office of the CEO. As the title implies, Steve will now provide advice to our executive team on strategic matters on the five-year plan, but also beyond that.

Steve is well known in our industry and unmatched in his expertise and passion for the business, but also for Enbridge. He has led the liquids pipelines group through an unprecedented period of growth while, I'll say, an equal intensity on the operating side of the business. The nice thing about this is that we'll continue to tap into Steve's extensive knowledge of the energy business while giving him more time for personal and family interests.

So with that, Guy Jarvis steps into Steve's role and becomes President of Liquids Pipelines, effective March 1. You all know Guy as well, I'm sure. He has a strong background in many areas of the business: commercially, business development, including his previous roles within Liquids Pipelines. I think it's a great illustration of how our development and rotational program here ensures our most talented people are ready to step into important roles.

So now, moving on to Slide 6, fourth-quarter adjusted earnings came in at CAD362 million or CAD0.44 a share. Pretty much what we were expecting.

That brings the year to CAD1.4 billion in earnings, or about 16% higher than last year. Now, that's going to equate to adjusted EPS of CAD1.78 or 11% growth year over year, which we are pleased with from a couple of perspectives.

First, given the size of the capital program, we did some equity pre-funding to keep ahead of the financing curve, and that impacted EPS by about CAD0.04 a share. So absent that, we would have been at the midpoint of the guidance range.

The second thing is we faced a few headwinds on a couple of our Liquids Pipelines systems, but we offset that -- a good part of it, anyway -- in other areas. And Richard is going to go through the pluses and minuses in a few minutes.

So all-in, we are pleased with where we finished up 2013, well within the guidance range, which speaks to the strength and diversity of the asset base.

With that result, turning to Slide 7, we continued our string of industry-leading EPS growth. The reliability of our business model shows up in consistently achieving EPS within a tight guidance range. And dividend growth, as you can see here, tracked earnings. Over the last five years, we had a 12% increase in 2013, and then a further 11% rise effective March 1 of this year.

Over the last decade, we've delivered on our annualized total return of 17%, well above the broader market and the peer group. And we think that track record reflects not just the strategic and competitive position of our business, but our disciplined capital investment approach and very strong business fundamentals through this entire piece.

And those same ingredients, we feel, are more than evident today, which gives us confidence that will be able to continue this track record. So let me briefly recap progress on the three strategies, beginning with Slide 8.

Our first priority, as you know, is to focus intensely on safety and operational reliability. The goal here is quite straightforward: to achieve industry leadership in six key areas. One of those is integrity management, and there's no doubt we have undertaken the most expensive and proactive maintenance program within North America over the last three years.

Key to this is governance, and systems, and safety culture. And just illustrate that, along with our operations and integrity committee that we have as an executive management group here, we've just established a safety and reliability committee of the Board, which monitors progress.

Moving to Slide 9, the second priority is sound execution of our massive capital program. Many of you have heard me say this -- the reason why it's a very close second to safety and reliability is because if we execute well, we'll be able to deliver the 10% to 12% average annual EPS growth rate through 2017.

Key to success, obviously, is being on-time and on budget with our projects. And our major projects group is managing well on that front, and they currently have a slate of 35 projects under their wing.

We brought 11 projects into service last year. 10 were on or below budget and on or ahead of schedule. I think that's a great outcome for the Company. The pie chart at the bottom of the slide here provides the status of the execution program today. You can see we are generally tracking to budget and schedule.

Before I leave this, there are two other factors we watch very closely on execution. First is ensuring that we have good access to capital and liquidity, and that's why we have made it a practice of Richard going through that very thing on these calls. And secondly, ensuring that we have the human resources in place to make that happen. And we are pleased with both of those in terms of what the teams have accomplished.

In terms of the third priority with the growth rate secured on the medium-term, the goal is obviously to extend and diversify the sources of growth beyond 2017. As you can see here, we had another great year in securing another CAD6 billion of new growth.

This really emphasizes, I think, the positive fundamentals that you're all aware of right now in our sector, but also how we're capitalizing on our existing footprint to grow the business. Great example was the capturing of Wood Buffalo and Norlite, which further builds are strategic position in the oil sands to Edmonton/Hardisty corridor.

But we are also able to secure new power projects and gas projects, as well. The most important aspect of this, though, is that these investments are underpinned by strong commercial contracts -- good supply/demand fundamentals which lines up very well with our value proposition that I talked about early on.

Moving to Slide 11, we recently secured another two smaller but important projects. At Christina Lake, we're adding facilities at our Sunday Creek Terminal to support Cenovus and Conoco production there. It's another win; but more broadly, if you look at it, the systems that we are connected to now separately are 11 different oil sands projects, which I think demonstrate our competitive position in this region.

The other project is the 110-megawatt Keechi Creek wind project in Texas. We like this project because it further diversifies our power footprint, and the power offtaker here is Microsoft under a 20-year PPA. With this project, we now have interest in 1,800 megawatts of renewable capacity, so we're starting to gain scale in the power business.

On Slide 12, before I turn it over to Richard, I'll recap the status of some of the more prominent regulatory files we've got on the go. In December, of course, the joint review panel issued its report and recommended that the federal government approve the Northern Gateway project, obviously subject to a number of conditions.

The report was very thorough. And I thought the conditions were tough but certainly fair, and I encourage you to review the findings of the panel. The federal government is expected to make a final decision on the project in July.

We received approval just a couple of weeks ago of the GTE project from the Ontario Energy Board. That was positive. On the Alberta Clipper expansion, as you know, that requires an amendment to the Environmental Impact Statement that was issued when the line was put into service back in 2008.

The expansion happens by adding pumping capacity in two phases: the first being 120,000 barrels per day by July this year, and the second being the remaining 230,000 barrels per day next year in midyear. Based on where we see things at the moment and over the last few weeks, we feel the permit amendment will take longer than midyear issuance that we had expected. That being said, we are undertaking some temporary system optimization efforts that pretty much mitigate any impact on throughput related to the first phase.

On our Edmondson-to-Hardisty mainline expansion, we received the NEB's endorsement just a few days ago. And on Line 9B reversal, we expect the NEB to make its decision in the next few weeks.

There is actually one more. We recently filed -- I think it was yesterday -- the application for the Sandpiper project. And that's an important enabler, as you all know, to our light oil market access program.

So now I'll hand it over to Richard to review the financials and our funding position.

Thanks, Al. I'll pick up the story on Slide 13, with some highlights of the contributions by segment to that 11% adjusted earnings per share growth number. The details are consistent with the full-year outlook discussions that we've had on our prior quarterly calls.

So Liquids Pipelines delivered a strong contribution to 2013 growth, both in the fourth quarter and for the full year, though not quite as strong as we were expecting originally going into the year. The earnings from the mainline were up on throughput growth, but some of that was eaten into by a reduction in the Canadian portion of the joint toll. And the lower Canadian portion reflects an increase in the US toll to recover increased capital spending on the Lakehead system. As indicated in our guidance call, this pattern will be much the same for 2014.

The oil sands regional system finished the year on a lull, both in terms of earnings growth, and as Al discussed, securement of attractive further growth investments. And it will be a source of earnings growth again in 2014.

Seaway contributed to earnings growth for the year, having been in service in 2013 for the full year. It didn't achieve our expectations due to downstream takeaway limitations. The new Jones Creek-to-ECHO lateral, which is now in service, will provide better takeaway flexibility this year.

Gas distribution closed the year flat to the prior year. That was as expected, and with much the same expected for 2014.

Our gas pipelines processing and energy services segment was up on a full-year basis, largely as a result of unusually favorable market conditions for our energy services business, offset by weaker Aux Sable margins. And on our guidance call, we indicated that this segment is expected to give back this gain in 2014, with further tightening of Aux Sable margins and less favorable energy services markets. That trend is already evident in the fourth quarter.

Sponsored investments was another strong contributor in 2013 and should be to an even greater extent this year. During the 2013, Enbridge Energy Partners suffered from some weakness in both its gathering and processing business and volumes on its North Dakota system, both of which are expected to improve this year.

With the successful launch of Midcoast Energy Partners in the fourth quarter of 2013, and the further dropdown planned for the second quarter of this year, Enbridge Energy Partners will have a solid source of funding for its attractive Liquids Pipelines growth projects and should be in increasingly strong contributor in 2014 and thereafter.

The contribution from Enbridge's direct investment in joint-funded US mainline projects was flat for 2013, but should pick up significantly as new joint-funded projects go into service in 2014 and thereafter.

And the contribution from Enbridge Income Fund was also up nicely in 2013, largely driven by the late 2012 dropdown of CAD1.2 billion of Enbridge assets. And as discussed at our Enbridge Day's investor conference, this dropdown into the Income Fund is a funding strategy for Enbridge's overall growth program, which we intend to make repeated use of in the next several years.

Our corporate segment finished the year on a high note, with a nice left from Noverco on the strength of increased volumes from its expanded Vermont asset base, which also benefited from the stronger US dollar on translation back to Canadian dollars.

So all things taken together, we ended up at the middle of the lower half of our original EPS guidance range. As indicated on our prior calls, there were several headwinds and a few offsetting tailwinds relative to our expectations going into the year.

One of the more significant tailwinds was our decision to continue to pre-fund a significant portion of the equity required for our five-year capital plan. And as indicated on Slide 14, between common share funding and preference share funding in excess of our growing in plan, our pre-funding actions took us down by about CAD0.04 per share of earnings per share. Nevertheless, we concluded that the assurance of a strong equity base was the more important priority in support of the substantial benefits to come from our longer-term growth program.

Moving to Slide 15, 2013 was another active year for Enbridge with respect to enterprise-wide funding and liquidity actions, aggregating over CAD10 billion. Once again, we focused on bolstering our equity base, with nearly CAD4 billion of equity capital raised across our issuers in 2013. Our other focus was expansion of bank credit facilities, again by nearly CAD4 billion.

Next, on Slide 16 with respect to liquidity, as of December 31 we stood at enterprise-wide general-purpose committed to term credit facilities of CAD17.6 billion. And that's not including another CAD400 million which closed since year end, which will take us to around CAD18 billion of facilities. At December 31 we were carrying CAD12.9 billion of liquidity. Between cash and the undrawn portion of these facilities, that's up by CAD2 billion from this time last year.

Slide 17 is an update of our remaining funding requirements for our 2013 to 2017 five-year capital plan as we continue to whittle the remainder down. On the debt side, we have about CAD13 billion less to go, spread over our three issuers in both Canadian and US debt capital markets and over the next four years. This is very manageable and consistent with our recent annual issuance calendar, and we have that big bank facility cushion held in reserve.

The equity requirement of CAD2 billion is likewise very manageable, and our approach to that is summarized on the next slide. Our preference for funding our remaining equity requirements is to utilize a variety of alternatives, like additional preferred share issuance and like dropdowns to Enbridge Income Fund, which do not involve issuance of additional Enbridge common shares. We have potential sources of approximately CAD3.00 of equity for every CAD1.00 that we need to raise, so we will be selective.

In order to consummate a transaction, these alternative sources must meet two criteria. First, they must represent a favorable cost of capital relative to issuance of common equity; and second, they must represent a favorable cost of capital relative to each other. As I mentioned earlier, we are confident that further dropdowns to the Enbridge Income Fund will consistently meet these criteria and form a core element of our funding program.

I'll finish up on Slide 19 by recapping our 2014 adjusted earnings per share guidance range of CAD1.84 to CAD2.04. As discussed on our guidance call, this reflects a substantial volume of capital investment work in progress not yet generating earnings and cash flow during the first half of the year, though with the equity funding already in place. It also reflects the accretion profile of our tilted return projects, which don't contribute much to earnings per share during their startup year.

And so with that, I'll turn it back to Al.

Okay, thanks, Richard. Maybe just to wrap up here, I'll focus on our growth profile over the next couple of years and the transparency of that. It begins with a record year this year, with 15 projects being brought into service totaling CAD9 billion-plus.

And just as reminder, we've talked before about the flat versus tilted return profile. So that CAD9 billion is split evenly between the two.

It's no surprise that the majority of this capital that you see on the slide here comes from liquids projects -- over CAD7 billion there. I think, though, the takeaway from the picture is that we are doing our part to bring on much-needed pipeline capacity for customers through our key market access initiatives.

This year, we'll open up 1 million barrels per day of new markets for Western, and Canadian, and Bakken crude; and that will help alleviate the price dislocations that have been plaguing the industry. The basic strategy, as you recall, is to get heavy barrels to the Midwest and the Gulf Coast markets, and light barrels to eastern Pad 2, eastern Canada, and the eastern coast.

Our US Gulf Coast Access Project adds 600,000 barrels per day as heavy capacity out of Chicago through Flanagan south. That project is on track through midyear in service. Seaway is expected to take the rest of the way to the Gulf in about the same time frame, mid-2014, doubling existing capacity to approximately 850,000 barrels per day.

On the light oil side, our Eastern Access Program will move crude oil east of Chicago, including into Ontario and Quebec. I won't go through all the projects on the list here, but as you can see, they also cover the oil sands region, gas projects, and renewables.

On to Slide 21: in 2015, another CAD9 billion is slated to come into service. Southern Access Extension will open up 300,000 barrels per day of markets east of Patoka. 2015 is when we're powering up our mainline capability to its maximum. Essentially, that means taking Clipper to 800,000 barrels per day, as we talked about earlier; and Southern Access to 1.2 million barrels per day. Recall, that's a 42-inch line. And the Edmonton-to-Hardisty newbuild is part of that, as well.

The oil sands will be active, with another CAD2 billion coming into service, representing four projects. And we expect to bring the GTA system -- gas distribution system upgrade -- in next year as well, among other projects that you see on the chart.

So in closing, the next couple of slides is meant to bring this all together. Our enterprise-wide capital program stands at CAD36 billion through 2017. You can see that the fully-secured third portion of the bar has increased over the last couple of years to CAD29 billion.

These secured projects provide the excellent growth visibility through our five-year planning horizon and beyond. Equally important, though, to the sheer size of the program is the quality of these investments, which fits squarely in the middle of our fairway.

Slide 23: you've seen this picture before. In a nutshell, the capital program that we've been talking about, in combination with our competitive and strategic positioning, gives us confidence will be able to deliver industry-leading growth of 10% to 12% on average through 2017. As we have talked about in the past, that profile will naturally be lumpy, given the magnitude of spending over the next two years before projects come into service. But the dividend profile is expected to follow earnings, although with a smoother trajectory than EPS growth.

So let me summarize on 24. We are pleased with the 2013 results. Generally, we're making very good progress on the three key priorities as we went through. That includes on-the-ground execution, which is going well in a very challenging environment these days.

Over the next two years, we're expecting, as you saw, to bring in CAD18 billion of projects into service. And Richard and his team, I think, are doing a good job of raising capital related to that program efficiently.

We'll continue development of our new growth platforms that fit the investment criteria that we have for the rest of the business. Bottom line is that there is a high degree of transparency to our expectation of delivering average annual EPS growth of 10% to 12% through 2017.

So that wraps up our formal remarks here. Now I'd like to turn it over to the operator to begin the Q&A session.

Thank you. We will now begin the question-and-answer session. (Operator Instructions) Paul Lechem, CIBC.

My questions are on the mainline, and first one relates to the volumes. EEP a couple of days ago on their guidance outlook for 2014, had some pretty strong volume expectations for the Lakehead system, up about 200,000 to 400,000 barrels a day versus 2013.

So I was wondering if Enbridge, on the Canadian side of the border, would expect a similar kind of lift over 2013 volumes? That would imply roughly 1.9 million to 2.1 million barrels a day ex-Gretna. Is that something you think you could achieve as well? And if so, what would it look like for the year?

Okay. Let's turn that one over to Guy Jarvis.

Good morning, Paul. Yes, we think we can achieve a similar type of increase on our system. It's really a function of two things. We've been very active for a large period of time here now in terms of extracting as much capacity out of the mainline system as we can. We've had some success in that at the end of the year of 2013.

We've got a few other things that we're doing here early in 2014 to improve the capacity of the system. We've also been very active on our own and in consultation with industry in examining exactly how we can schedule the system more effectively. And we've identified a number of things where we think we can improve the utilization of that higher capacity, as well. So the combination of those two leads to this stronger volume outlook.

And maybe just to add, I think what we're seeing -- the supply ramp of the oil sands looks to be as we expected, so that's going well. On the downstream side, Paul, I think the refinery configuration lighting looks to be on track, so that will bring some demand -- additional demand. So I think overall, we're pretty positive on volumes in 2014 for the Canadian side as well.

Okay. Secondly, then, on translating the volumes into earnings, I was just wondering -- I think the next reset on the Lakehead system's hole comes on April 1. Just wondering what we should think about, or how we should think about, the update through the current CAD1.80 for your residual toll?

Directionally, should it be in the same region? Should it be up, down? How should we think about the factors that go into that?

Okay, well, Richard is going to look at that one, Paul.

So I think I touched on this in our guidance call back in December. So yes, the volume picture is very strong for the mainline in 2014, but we're going to see a very similar pattern to what we saw in 2013, with significant capital expenditures on the Lakehead system over the course of 2012, contributing to a bump in the Lakehead tolls.

And so a good part of the benefit of that volume lift on the Canadian system will be offset by a reduction in the Canadian portion of the US/Canada international joint toll. And the mainline net-net is going to be not all that much different to 2014 and 2013 the way that we see it at the moment.

Okay. Thanks very much.

Robert Kwan, RBC Capital Markets.

Just a kind of high-level question as you looking at the guidance for 2014, and recognizing it came out not that long ago -- but has anything happened since then that you're seeing as either a tailwind to that or a headwind, whether that be things like the Clipper delay and offset versus some optimization?

Yes, thanks, Robert. Yes, as you pointed out, it hasn't been that long. And so far, being just about a month and a half in here, we think we are pretty much on track. We haven't seen anything in any parts of the business that would indicate that we would be off considerably from what we had got into. So I think at this point, we're sticking with where we were.

Okay. Maybe just turning, then, to Enbridge Energy Partners and what they put forward. Their funding is in a lot better shape with Midcoast. That equity is down to a fairly low number now.

So with that funding in better shape, have you changed any of your thoughts given the receptivity in the MLP market, the dropdowns, and also the high GP valuations that are out there in terms of timing for executing any dropdowns from the EMB level into EEP?

I don't think so, Robert. Obviously, the monetization of our assets at the corporate level are priority for us in terms of what Richard pointed out around our opportunities for funding.

I think in the immediate term, the two drop-down vehicles that are most attractive from a funding point of view and evaluation point of view on both the receiving end and the monetizing end are Midcoast -- certainly, that's well positioned, we think -- and as Richard alluded to a couple of times, I think, the Enbridge Income Fund is probably the other one that's the top priority.

So I would say that those two would be first in the queue. And then as EEP clears its financing requirements and starts to build its momentum through the cash flow that is coming from all these projects that are coming forward, I think that's probably third in the queue.

So EEP needs to clear -- from your perspective, EEP needs to clear the funding completely? And would that also include the takeback of the joint funding arrangement first?

I wouldn't say needs to clear it completely, simply because, as you pointed out, the funding is going to be -- is manageable in the next few years. But I think we need to start seeing some of that cash coming in from these new projects coming into service over the next couple of years. That will obviously start moving us forward. And I think that's probably the timing that we are talking about.

I think Robert is right in that the first priority for EEP would be to exercise its option to take back the extra 15% that it has the option to on existing joint funding arrangements.

Yes, exactly.

Great. Thanks, Al. Thanks, Richard.

Ted Durbin, Goldman Sachs.

I'm wondering if you can elaborate a little bit more on the Clipper expansion and some of the optimization activities you are taking on there to mitigate some of the delay?

Okay, well, maybe I'll take that one first, Ted. One of the advantages of having the scale that we do with a 2 million barrels a day plus system and 6 lines in the right-of-way is that it does allow you these opportunities to optimize.

We've been thinking about this for a while, given the -- what I referred to earlier, that slower process on the Department of State side. So I'm not going to get too specific, but essentially there are a few things -- a couple that come to mind. Certainly, a drag-reducing agent and our ability to add that to the system would improve flow. In addition to that, optimizing commodity types on the various lines we have to create some additional capacity.

So I think those kinds of actions can be put in place by midyear, generally. Some may take a bit longer, but we should be in good shape for this year with those kinds of efforts. Steve, do you have anything else to add on that?

Yes. I think, basically, the first tranche of the Alberta Clipper capacity is 120,000 barrels a day. And we really think that through what Al just talked about and a few other things that we're doing to the system, we'll mitigate that so that we are good until -- the next tranche of the Alberta Clipper comes in the middle of 2015, which takes it to 800,000 barrels per day, by which time, of course, we should have the amendment in place.

So yes, it's a matter of looking at the system, looking at how to optimize, primarily, the movement of heavy crude, which is where the constraint is in the system and will be as BP Whiting ramps up, and as we have the path opened up to the Gulf Coast with Flanagan South and the Seaway expansion.

So all of that seems to be fitting together. And I think by using the DRA, or the drag reducer, and the various ways that we're looking at batching all of those lines, we're able to mitigate pretty much all of that expected increase.

That's great. And then maybe you can talk a little bit more about Gateway and some of the 209 conditions. How does that impact, in your view, the capital cost of project, the returns on that project? Are there any reopeners you might try to go back to your shippers with on that? Maybe just talk about Gateway a little bit?

Sure. Well, the conditions -- actually, we're just in the middle of reviewing all those for that exact reason, to assess their implications. We've been doing that. We look at the cost estimate anyway. So those two together will sort of bring us right up to date, I think, in the next little while here as to what it will cost.

I don't think at this point we should imply anything about what it could mean to the project or the returns. Obviously, we're going to be very careful about how that will look to us from a return perspective going forward, but I think it's probably a little bit too early to tell what's going on there specifically.

But I think there's been another element of the project, as we've been talking about, aside from reviewing the conditions and the cost estimate, we're really looking to, I think, reengage with some of the First Nations where we haven't made progress that we'd like to see. So that would be another priority for the project, and that will happen over the next few months.

Okay. Thanks very much.

Matthew Akman, Scotiabank.

Thanks very much. Wanted to ask about Sandpiper. Al, you mentioned an application, I think, had just been filed. And could you just update us on commitments there? I think there was a further open season or solicitation of capacity following the Marathon agreement?

That open season just closed a while ago. We did receive some additional commitments, but I think for that pipeline, we certainly wouldn't be proceeding without enough commitments. We had established that prior to this open season.

So we are proceeding with the project, and hence the application. So I think you can take away that -- normally, Matthew, for these kinds of projects, we need a substantial amount committed before we proceed. And that's where I'll leave it. We've achieved that.

Are you seeing, just in terms of general trends, increased support for pipelining out of Bakken, given some of the regulatory and safety concerns on railing that product?

Steve, do you have some comments?

I would say yes. Our system in North Dakota, as you know, bottomed out in early Q2 of last year in terms of throughputs. That's when rail was really in its full heyday out of the Bakken.

We've seen a return of volumes through the rest of 2013 and now in early 2014, and it's hard to say what it's driven by. Of course, there is the safety and regulatory overlay that you talked about, which is still largely an unknown on the rail side of the industry.

And then the second thing, of course, is differentials, which have become more attractive for our pipe connections. And I think the thing to really look to with regard to Bakken pipe movements is the opening of our Line 9, for one thing, which will give a path for light crude to Montreal and Quebec City; Flanagan South and Seaway expansion opens up both a heavy and light oil path; and then, of course, ultimately, Southern Access Extension is going to open up eastern Pad 2.

So that's why we're working so hard on market connections for the Bakken crude, but we've already -- without those -- started to see the return to pipe. And it's probably driven by both factors. And each producer and shipper has to make up their own mind as to what they're going to do.

It's pretty hard to pin exactly what the rail overlay and regulatory concerns will amount to. But there's no doubt that in terms of trend, there is a greater interest in that. However, rail in the near term always provides great flexibility for shippers to various markets. And some markets like California and Washington state will -- and Philadelphia will always be, for the foreseeable future, rail markets for Bakken crude.

So it's a good baseload of rail. But then around the edges, with volumes that could go to the Gulf Coast or could go into eastern Canada right now, we should see that returning to pipe, especially as these market outlets are established.

Yes, it's probably fair to say, too, that there is quite a wide spectrum of producers, Steve -- that, obviously, some of the smaller ones would be less prone to look for pipe, at least as far as long-term commitments; whereas the larger ones and on the downstream side, in this case Marathon, ideally suited for those longer-term commitments.

Thanks for that. Just one follow-up for Richard. There was some disclosure around comprehensive hedging policies, and I don't know if the disclosure was new or not. But in any case, can you just update us on where you are with US dollar exposure and hedging, generally?

Sure. No real change on that front from what we have discussed in the past. I think at Enbridge Days we provided a forward look on our hedging program, and there's no significant change there.

So on the dollar, we're pretty significantly hedged going out through 2017; less significantly hedged thereafter. So as the Canadian dollar has weakened off -- well, frankly, whether it strengthens or weakens, it won't have much impact on our growth rate through 2017. But directionally, we are not fully hedged, and so weaker Canadian dollar is better for us, but not a whole lot better.

As we move beyond 2017, those hedges tail off. We do have some in place, but not to the same extent. So post-2017, we would see a bigger lift if the weaker dollar persists out to that point in time. And certainly, all the latest forecasts are suggesting that it will.

Okay. Thanks, guys. Those are my questions.

David McColl, Morningstar.

I wanted to kind of revisit an issue that I raised a few years ago specifically around project inflation. What's kind of prompting this is really an improving economic outlook in North America.

So over the past few months, we've seen some very minor inflation. Not necessarily Enbridge projects, but minor inflation bumps within Alberta; and as we see maybe -- big maybe -- Keystone XL being approved in the coming weeks, possibly coming online 2017, Energy East's project, albeit not necessarily as labor-intensive in Alberta, I'm wondering if you're becoming a bit more concerned with project inflation -- North America, in general, and specifically Alberta?

And maybe just to leverage off that question on your hedging strategy for exchange rates, maybe flipping around a little bit, do you take a similar approach to project costs such as labor and materials once they are in your secured capital outlook? Thank you.

Well, maybe I will take the first part of that, just generally on project execution. I think that's one of the reasons why we're so focused on making sure we have a very capable project execution team.

We are less sensitive to the Alberta market per se. A lot of the projects, as you can imagine, are dispersed throughout North America; therefore the labor pressures aren't as significant, or at least they are dispersed. We have a lot of focus on supply chain for the reasons you are pointing out, and we have some pretty good frame agreements in place for both pipe as well as mainline construction.

There is sufficient mainline construction we see right now, even with all the projects going on throughout North America. So we're pretty good on those two fronts. And so we're feeling like we're managing the inflation risk well at this point. Obviously, we'll keep on top of that.

Richard, do you want to talk about the FX part of this?

Well, I think the question more had to do with hedging labor, materials costs, not FX. So it would be more appropriate for Steve.

Steve, do you have anything else?

Yes. Well, I think in addition to what Al said, we several years ago started to not only lock down pipes, pumps, motors, and valves, which are the main components; and we've pretty well locked those down for all of our forward projects -- but also the contractors. And maybe that goes a little bit more to your question, David, in inflation in the contracting environment.

Knowing that the slate of projects that we have ahead of us can keep contractors working year-round, which is unusual in the pipeline construction industry, we've actually constructed agreements with a number of contractors, the big mainline contractors in the US and Canada, to keep them working year-round. And we think that secures the best contractors and the best crews and equipment that know that they can work year-round. And so it works for them, and then it also gets us the best costing and the most predictable costing.

So I think by virtue of having enough projects to keep contractors working all the time, that has really stabilized that outlook. And we're really not subject to the wild fluctuations that you might see in an environment where you get a lot of projects in the industry going at the same time. So we are pretty comfortable with that, starting from the Alberta region oil sands area, all the way through to the Gulf Coast.

Thank you. So I guess that also applies to Sandpiper? Just wondering if we should be a little bit concerned about Sandpiper inflation in that specific kind of region?

No, I think, actually, we've got a lot of work going in North Dakota already on the system. We have a number of contractors that are part of the group that I just talked about that have the longer-term frame agreements. And we would look to deploy them on the Sandpiper construction and blend that together.

As Flanagan South completes, that's going to free up some capacity; we move into things like Sandpiper and Southern Access Extension. Line 6B is completing, so the big mainline contractors involved there are freeing up. So we're looking at it on a matrix basis all the way out through the completion of all those projects.

Okay, that's good. Thank you very much.

Andrew Kuske, Credit Suisse.

I guess it's a high-level question, really directed to Al. I guess, just over the years, your organization has had a great track record of really rotating people around in various roles, and you yourself have done that in a number of roles over the years.

So when you go externally and hire someone like Greg Harper, is that really a view that you want to go into another business line or an existing business line in just a bigger way than you have been before, and you didn't have that expertise internally in order to kickstart it?

Yes. I'm not so sure about that, Andrew. I think whenever we look at filling those kinds of senior positions -- in this case in particular, we have some very good internal candidates as well; and Mark Mackey, for example, did a great job in his acting role leading that group over the last year or so.

But obviously, when you're building a team and continuing a team, you're looking for the best people. I think generally speaking, we go inside. We have great capabilities internally. And as you point out, the rotations that we undertake are very much helping to ensure that we do develop our people internally. And they are ready, as you saw with Guy's appointment that we discussed earlier.

So I don't think there's anything that would indicate we are necessarily changing our view on natural gas. I think you know that we are very positive on gas going forward. It's going (technical difficulty) the future for Enbridge. And I think in this case we saw Greg as an excellent way to round out the team and make sure we have the best possible team in place. So that's how I would characterize it.

Okay, that's helpful color. And then I guess a related question, but also a little bit, different directed towards Steve. Clearly, you're taking on a new role at this stage in time; and I'd just like to get a little bit of your prospective in your 34 years of where you see the future of the oil development -- or oil pipeline development, really, with an outlook in the next five? Because you're locked and loaded for the next few, but when you look into, say, the back half of the decade or the back portion of the decade versus what you saw in the first 34 years of your career?

Yes, what will I see in the second 34 years? Thanks for the question, Andrew. And it has been fascinating to see the pipeline industry, particularly in the oil pipeline side of North America, go from pipelines basically pointed inward from the Coast to pipelines all wanting to get pointed outward and go to Tidewater. And I would say that that should continue with the production outlook in, of course, the Alberta picture, both the oil sands -- but also, the light oil plays that are very prolific in Alberta.

You know, years ago, we used to always show charts that showed a 2% to 5% annual decline rate in western Canadian light oil production. And that has now flattened and is actually rising.

So you're going to see a lot of that, along with the much talked-about shale plays of the Bakken, the Eagle Ford, and the Permian and other areas of production in the US. And barring a huge price change that would disincent that production in any of those areas, I think I absolutely see that continuing. And it will actually, then, do two things.

One is create a tremendous incentive for US refineries, particularly on the Gulf Coast and to some extent the East Coast, to look at excluding more refined product to the world, which has already been increasing dramatically in the last two or three years.

And then it'll open up the question also at exports. Certainly there aren't restrictions on Canadian crude exports from either Canadian or US supports, but there are restrictions on US crude production being exported other than to Canada and Mexico, and in the case of Alaska North Slope to Asia.

So that's certainly going to bring that oil to the fore. I think it's inevitable that more exports for the economic benefit of the US and Canada are going to become necessary and desirable. So I think those are the things that I see going ahead as far as I can see. And it really is fascinating to think about this new role, where hopefully, with a little more time to think, Al, I can deploy some of those thoughts to the strategic direction of Enbridge. So that's very exciting to me.

Okay, that's very helpful. Thank you.

Juan Plessis, Canaccord Genuity.

Getting back to your currency hedge position, you mentioned that you're substantially hedged through 2017. Can you tell us the rate at which you're hedged?

Go ahead, Richard.

Yes. And again, I think that was laid out in one of our Enbridge Days charts. But generally, we are hedged at stronger levels for the Canadian dollar than where is currently trading at. So our average hedge rate over that period of time would be CAD1.05 per US $1.00 compared with -- we're in now CAD1.10 at the moment, I think, in terms of spot rate.

Okay, great. Thank you for that. And with respect to Aux Sable, have you hedged any of your expected NGL volumes at Aux Sable for 2014?

At this point, no.

Okay, great. Thank you.

Steven Paget, FirstEnergy Capital.

Let me congratulate Steve on his new role. My favorite Steve quote was: if ever there was a beautiful crude, it is the Bakken. And who could forget the time he called Cushing a pricing sewer? Steve, you'll be handing Liquids Pipelines off to Guy, but I'm curious, who will take on your role as head of major projects?

Byron Neiles, who reports to me currently, is the head of major projects and has been for some time, and really is providing very effective leadership to that. He's been reporting to me. He's going to report directly to Al, actually.

Yes, that's right. And if you think about the program that we have in front of us, Steven, and the fact that the major projects group is really an enterprise-wide execution team, that makes sense to have that report to myself.

Well, that's good news. We remember his presentation from Enbridge Day. Could one of you please give us a detailed update on Flanagan? So with the injunction denied, what's been put in the ground, and what's left to be installed?

Well, we'll see if the other guys can chime in. We're about 80% welded up on that, and probably 70% with the pipe in the ground. So I think it's going fairly well. There's a couple of areas that we still need to clear from a permitting perspective. But generally, I think that project is going quite well.

Very good productivity and quality indicators on the construction process. Coming in fairly well, close to budget. So I think things are going okay on that one. Mid this year is when we are expecting to have that in. Steve, did I miss anything there?

No, I think those are the main points. It's rolling along very well. The denial of the injunction -- that actually wasn't against Enbridge directly. It really was a suit that was filed against various federal government agencies. That denial actually was fairly powerfully worded, saying that the case put forward to delay the project was not a strong one. So that's, I think, very positive.

Excellent, thank you. Those are my questions.

Linda Ezergailis, TDC (sic - TD) Securities.

Maybe this is a question for Guy. Congratulations on your new role, and congratulations to Steve. The system optimization on the main line that is underway -- what might be the associated cost if there is any materiality associated for that? And how much of that might be absorbed by shippers?

Thanks, Linda. Many of what -- the options that we're looking at are very low cost. So we would expect that they would have no material impact on either tolling requirements, or returns, or our earnings. Based on that, we're really not anticipating that we're going to have to engage our shippers about those costs.

Okay. And with respect to energy services -- I don't know, maybe someone else can help me with this. I'm assuming the activity level has been increasing as the business has increased, and that has contributed to some of the growth in earnings.

But a lot of the volatility that we're seeing -- so Q4 was a record low, whereas 2013 earnings were a record positive income year -- should we expect to see those highs and lows kind of decline as differentials stabilize? Or will those higher volumes naturally increase volatility, as well?

Sure, it's Richard. I'll take that one. So I think just about everything you've said, the answer is yes to, Linda. The scale of the business has expanded in recent years, so the sort of base running rate would be higher in 2013 than it would have been historically, and probably a bit higher again. But the opportunity set we don't expect to be as variable moving forward.

It does always move up and down, and so there is always some inherent variability in the ability to capture the really good arbitrage opportunities. And that will continue to some degree. I don't think we're likely to see the level of volatility that we've seen in 2013 continue on into the future.

But as we indicated in guidance, 2013, even with the fourth quarter, was a fantastic year for our energy services business, and a little higher than what we would see the ongoing run rate for that business to be.

Okay, that's helpful. And just a cleanup question: fourth-quarter regional pipeline -- there was a favorable adjustment associated with reducing production of a third-party revenue sharing mechanism on Athabasca. What was the size of that adjustment?

Let me see. John, do you have that at your fingertips? Go ahead.

Yes, it was about CAD12 million.

Great, thank you, and congratulations on a good quarter.

Thank you. At this time, I would like to invite members from the media to join the queue for questions. (Operator Instructions) Kelly Cryderman, The Globe and Mail.

I was wondering, Mr. Monaco, if you can give us more details about the Alberta Clipper delay, and why there seems to be a delay with that permit -- whether the State Department has given you any feedback on that?

Well, as you can appreciate, Kelly, in the environment that we are in, regulatory permitting and the regulatory process generally takes more time. I think we had baked in some of that contingency when we originally forecast midyear 2014.

It's turned out that it's going to take a little bit longer, from what we see. We'll have a look at how things progress over the next couple of months. At this point, we're not forecasting when we will receive that permit.

But I think the point of all this is that -- it's our understanding that this amendment is a relatively routine matter. But as I said, it still takes longer in this environment. So remember that this pipe is in the ground. We're using existing right-of-way. The construction required here is very, very minimal. The capacity that's being added is being done through horsepower alone. So hopefully we'll move along quickly.

Is it concerning to you that another pipeline carrying oil sands crude to the US apparently is facing delays with the US State Department for something that had been once a pretty regular amendment or a pretty uneventful amendment?

Well, I wouldn't categorize it in that way at this point. Certainly, as I said, things take a little bit longer; but we are hopeful that it will move along from here. As I indicated, I think there's a lot more questioning or intervention by various groups. I think the regulatory authorities are doing their best to work through what they need to, and that's the process we need to follow.

And that's the environment of which you are speaking, when you say in this environment? That there is more questioning by outside groups?

Well, right. There's more questioning by environmental groups. But as well, the general public in ensuring that the right processes are in place.

Thank you.

Carl Kirst, BMO Capital.

Hi, this is Leah on for Carl. I just wanted to go back to energy services. If you could provide some more detail on the loss in the fourth quarter -- what was kind of driving that CAD19 million loss and mark-to-market loss?

Okay, Richard?

Sure. Well, it was really a combination of things. One was the arbitrage opportunities that had been so profitable earlier in the year, which we had been indicating were going to close up a fair bit if anything swung during the fourth quarter -- closed quicker than we might have thought that they would, further than we ever really thought they would.

And a lot of that has since reversed itself, so that is not necessarily going to be a factor going forward. But we also had in place a hedge of some capacity that we had put in place, which was intended to hedge the margins on that capacity. And that hedge didn't function the way that we had intended it to work during the fourth quarter. So we took a loss on that hedge during the quarter, and that was a realized loss.

Okay. Just to clarify, was that related into oil or gas volumes?

Well, we could carry capacity on a number of lines. We have both oil and gas. Some of them are Enbridge facilities; some of them are third-party facilities. And we do from time to time use financial hedges to manage the contracts on all of those facilities. So I don't think I'm going to get down into specific details on what facilities were involved.

Okay. Thank you for the color.

Scott Haggett, Reuters.

Just to elaborate on that CAD58 million hedging loss, was this just a trait gone bad? Was there more color you can offer on exactly what happened here, and why these transactions are no longer probable to occur?

Okay. I think you're probably referring to something else. There wasn't a CAD58 million loss on the hedge. That was just the subject of the last question. It was nowhere near that magnitude.

I think what you're referring to are some positions that we closed out earlier in the year and the gain that related to a physical position that we had in place, and that we took the physical position down, and therefore took the hedge position down at the same time. That was a first-quarter matter I think you're referring to.

Yes, I was just reading from your release. It was for 2013. Excluded a one-time realized loss of CAD58 million incurred to close out derivative contracts you used to hedge forecasted energy services transactions.

Yes, that was something we covered back on the first quarter of 2013.

Great. Thanks.

Lauren Krugel, The Canadian Press.

I had a couple of questions about Alberta Clipper. Just wondering if you could provide any clarity at all on what kind of order of magnitude we're talking about in terms of the delay? Weeks, months, years? So that would be helpful.

And also, having observed what TransCanada has been through with Keystone XL, whether that's changing how you approach cross-border pipelines from here on out?

Okay. Well, no, it's not years. Certainly our view at the moment is that -- will first of all, we're not going to provide an estimate as to when we'll get the permit. We'd like to see a few more milestones reached before we come to that conclusion. But we fully expect to receive the permit, as Steve said earlier, with mid-2015 expansion.

Certainly we would hope to get the permit much sooner than that, but I think the point is we expect the second phase of that expansion to be in on time in mid-2015. So we're working very closely with the Department of State, and we are moving along as best we can.

And I think maybe the other point that's important here is that the 120,000 barrels a day of capacity that we had expected to be in service by the middle of this year related to that permit is something that we've got a number of temporary system optimization workarounds, so we're -- from an earnings perspective, we're not sensitive to that delay.

Okay, and the second part?

Sorry, can you just repeat that part?

Having watched how politicized the Keystone XL debate has become, is that changing the way you approach cross-border pipelines? Is there anything to be learned from observing what TransCanada has been through over the past several years?

Well, I think, obviously, things take longer in this environment that we're in. I don't think we want to draw any conclusions about the political environment. It's not something that we can control.

What we control is the fullness of our application. In this case, as we said earlier, this is a fairly routine matter. The pipeline is already in the ground, so we're hoping that we move this along as quickly as possible.

Okay, great. Thank you very much.

Jeff Lewis, National Post.

I've got two questions, unrelated. On Gateway, it looks like the costs have inched up from last quarter. Can you just explain what accounts for the increase?

Yes, I think, Jeff, you're referring to not actual cost increase. I think there was some difference in how the cost was characterized. So the CAD6.5 million that we've been talking about, that hasn't changed.

I think when you add on the impact of financing that CAD6.5 billion, I think that's where the CAD7.9 billion that has been referred to comes from. So there's been no change in the base cost estimate. Having said that, though, obviously we're looking at revising the cost estimate. And we're doing our detailed analysis on that at the moment.

But last quarter, the expenditures to date were CAD0.3 billion. And this quarter, they're CAD0.4 billion.

Oh, okay. If that's what you're referring to, that is the cost of the regulatory process, which is borne by ourselves and our funding participants. And so that's just an elapsing of time and costs related to the regulatory process through this period.

Okay. Unrelated question: on Alliance, how do you see throughput on that pipeline changing with the continued growth of associated volumes in the Bakken and possible LNG exports on the West Coast here?

Well, we're running full our on Alliance right now. Obviously, it changes from month to month in small increments; but essentially, we're running at 1.6 Bcf per day, which is at capacity.

I think with respect to your question on LNG, certainly that will take some time to work itself through. Remember that Alliance is a liquids-rich line. And obviously, there's a lot of opportunity for liquids growth, both in Alberta and BC. And Alliance is extremely well situated to attract that liquids-rich gas in the future under any circumstance, in that we have the Aux Sable facility near Chicago that is ideally suited to process those liquids. So we think the prospects for Alliance still look very strong.

You don't see a re-contracting risk emerging at all for that line?

Oh, well there will be re-contracting that occurs at the end of 2015. We are working with our customers and other potential shippers on the line to move to re-contract the line at that time. But as I said, fundamentally, Alliance is well positioned for the future.

Okay, thanks.

Linda Ezergailis, TD Securities.

I just had a follow-up question on the Alliance pipeline. Wanted to get a sense, maybe, of an updated timeline on where you are in discussions with various potential shippers on that system for contracts beyond 2015, and when you might have an anchor of precedent contract security?

I'm not going to get specific on that, Linda, but it is a good question. I think that we're, I would say, very actively discussing the potential re-contracting for term. Right now, I expect that realistically we'll probably get closer on this as we move forward and closer to the re-contracting date at South. I think that's probably the reality of the situation.

Great, thank you.

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

Thank you, Christine. We have no further -- nothing further to add at this time. I'd remind you that I'm available for follow-up questions that you may have. Thank you and have a good day.

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