恩橋 (ENB) 2013 Q2 法說會逐字稿

Good morning, ladies and gentlemen, and welcome to Enbridge second-quarter 2013 financial results conference call. I will like to turn the meeting over to Jody Balko, Vice President, Investor Relations and Enterprise Risk.

Thank you, Adrienne.

Well, good morning, and welcome to Enbridge Inc.'s second-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; and John Whelen, Senior Vice President and Controller.

This call is webcast, and I encourage those listening on the phone lines to view the supporting slides, which are available on our website. A replay and podcast of the call will be available later today, and the 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, that you wait until the end of the call to queue up for questions and that questions are limited to two per person. Please reenter the queue if you do have additional queries.

And lastly, I would remind you that Jonathan Gould and I will be available after the call for any follow-up questions that you may have.

So before we begin, I'd like to point out that we may refer to forward-looking information during the call. By its nature, this information applies certain assumptions and expectations about future outcomes, so we remind you it is subject to the risks and uncertainties affecting every business, including 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 SEDAR and EDGAR systems.

I will turn the call over to Al Monaco.

Thanks, Jody.

Good morning, everyone. Before we begin, just a reminder of where we are in our annual cycle of dissemination. At this point in the year, we're finalizing our long-range plan, which will roll out and Enbridge Day in early October. Then in December, we will set out our 2014 budget. This will drive our earnings guidance and the dividend for next year. I'll start today by recapping our second-quarter results and how we're positioned for the year, then provide an update on recent business activity and the execution on our capital program. We'll wrap up the comments with a mid-year check our key priorities and the longer-term outlook for the business.

Now we are on slide 5. The second-quarter adjusted earnings came in at CAD306 million. This is a solid result, up 12% over Q2 last year. We're pleased with the first half with adjusted EPS at CAD1.00 per share, up 18% over last year. Based on the first-half results and our outlook for the next six months, we're forecasting to achieve our EPS guidance range of CAD1.74 to CAD1.90 per share for the year. If earnings come in at the midpoint of that range, we'll have delivered another strong year with 12% EPS growth over 2012.

Richard is going to take you through the earnings puts and takes and the potential headwinds and tailwinds in a few minutes. What I'll do now is highlight the progress we've made on advancing our strategies across the Company. We've announced more secured projects this quarter, and we're working on others behind the scene.

I will begin on the liquid side with where we continue the buildout of our regional positions. We are often associated with our growing Mainline system, but regional infrastructure is a significant driver of Liquids Pipelines' growth. What is evidenced from the map is that our two large-diameter pipes into Edmonton and Hardisty which feed the Mainline have anchored our ability to tie in several producing areas south and north of Cheecham. Currently, we have nine oil sands projects connected to our Wapasu and Athabasca lines.

The key to our regional strategy is to leverage these two pipes, which will soon have over 1 million barrels a day capacity, to effectively bridge producers volumes until a dedicated solution is required. And a good case in point of that is the new Woodland Pipeline Extension which we announced last week, which Exxon and Imperial have given us the go ahead on. This will be a CAD1.3-billion 36-inch line from Cheecham to Edmonton, and with Kearl volumes migrating onto this line, it frees up capacity on Wapasu so that the bridging cycle can repeat itself for the next producer's early-stage volumes. Once Athabasca twin is completed, we will have approximately 2 million barrels per day of capacity in this Oil Sands corridor.

Also this quarter, we announced CAD300 million development at our Cheecham Terminal to accommodate Surmont Phase II growth, another example of how the regional position provides for more projects down the road. Just drawing a bigger picture on this slide, our regional position is really the launching point for Enbridge delivering the access producer's need to reach the Edmonton and Hardisty hubs and then key North American refining markets.

I'll get to how this links to our downstream Mainline and market extension initiatives in a minute, but all of these projects drive the broader strategy to support our customers and maximizing the value of crude and to ensure Canada realizes fair value for its resources. As you can see, we have a lot going on in this region, and we're working on other initiatives, and we'll provide more definition on those when we're able to do that.

Switching gears now on slide 7 to gas and Enbridge Gas Distribution, two weeks ago, we filed our application for a new five-year incentive regulation model to begin in 2014. You might recall the last five-year term ended in 2012, and we are in a cost-of-service transition period this year. The last IR model allowed us to generate efficiencies that we shared with our customers, and in this case, we passed along about CAD170 million to them over that term.

At the same time, we bolstered our return on average of roughly 200 basis points above the allowed return on equity, so a true win-win. We've also filed our application for the CAD700-million GTA Expansion project that will reinforce our system and provide capacity for growth in the franchise.

On Power Generation, last week we announced a 50% interest in our third Wind Project in Quebec with EDF EN Canada, and the 82-megawatt St. Robert Bellarmin Project is already operational and generating cash flow. Including St. Robert and the 300 megawatt Blackspring Project we recently closed, we now have a well-diversified portfolio of over 1,200 megawatts of net renewable generation that will be fully operational by mid 2014.

St. Robert and Blackspring continue the successful relationship we've had with EDS, a world-class renewable developer with a large photo of North American projects. Bigger picture, these projects solidify our position as a leader in this sector where we're currently the largest generator of solar power in Canada and the second largest for wind. Now, as every project competes for capital at Enbridge, I want to reiterate that our renewable projects meet the same stringent economic and commercial criteria that we set out for the rest of the business.

Lastly on new developments, we're now on slide 9, a key strategic priority is to establish Enbridge Energy Partners is an effective sponsored investment vehicle and position the partnership for future growth, particularly given the large inventory of US-based assets at the general partner that can provide a steady diet of attractive drop down opportunities for EEP. In the meantime, EEP has a bevy of excellent organic opportunities, but the size of the capital program to fund that growth is significant for the MLP space and is creating an equity overhang in the enterprise, as we've said before.

We've effected a plan to bridge through this period of growth for EEP with several actions. Over the past quarter, we've invested CAD1.2 billion in EEP preferred shares and established a receivable purchase structure to fund its growth program and further enhance liquidity. EEP also exercised its flexibility option built into the Eastern Access and Mainline Extension joint-funding agreements to have Enbridge fund an additional 15% of those projects. So these actions allow EEP to optimize the timing of its equity issuances in the near term, but they're also attractive investments for Enbridge and optimize the overall financing cost to the group.

A few weeks ago, we announced a monetization of EEP's Gas and NGL Midstream business through an IPO of Midcoast Energy Partners. Now, given that Midcoast is in a registration, I can't comment on the specifics of the IPO, but let me at least outline the strategic objectives of what we are trying to do from Enbridge's perspective.

The IPO basically does three things. One, it establishes an additional source of funding for EEP through the IPO and successive drop downs of the Gas and NGL Midstream business over the next four to five years. Two, it should reduce EEP's cost of capital through a better valuation, which comes from further growth and an optimized value for both the Liquids and Gas Midstream business. And finally, it will focus EEP on the Liquids business.

The ultimate goal here is to establish EEP as an attractive drop down vehicle by lowering its cost of capital so that can take advantage of Enbridge Inc.'s substantial inventory of drop down assets, and of course, this will also release capital for Enbridge to redeploy in attractive opportunities that we have.

Moving now to slide 10, given the importance of strong execution in delivering our earnings and cash flow outlook over the next five years, this slide here gives you a snapshot of where we stand on our capital program and major projects capability. Now, this is a high-level view. You can also find the usual project-by-project status update on our website link for the call. As you can see on the left, the Major Projects Team has done a good job executing with projects that have been brought into service already. In fact, we came in about 10% under budget based on a capital program of about CAD3 billion, and all 10 projects completed on or ahead of schedule.

If you look at the CAD12 billion we have in construction right now, we're only fractionally above budget and have only four minor schedule delays out of 20 projects. We're very pleased with where we stand on those projects right now. All of this looks easy when you put it on a chart like this, but executing these multi-billion-dollar projects is challenging to say the least in the environment that we are in. Our ability to make this happen stems from experienced Project Management Teams, a disciplined gating approach, a very good supply chain management strategy, and regulatory planning.

Flipping now to slide 11, we briefly highlight the status of two of these projects. Our Mainline Expansion Program involves powering up both Alberta Clipper and Southern Access to their full capabilities in stages to meet growing supply. The first phase of horsepower expansions on both segments are due to come in in Q3 of next year. On Alberta Clipper, construction is underway in Canada, and last week, we received regulatory approval from the State of Minnesota.

The remaining regulatory item, as you know, is an amendment to the presidential permit, which is in progress. The expansion of Southern Access portion of the Mainline has started at several pump station and at superior terminal, so everything is on track here to meet the in-service timing of the Alberta Clipper Expansion in Q3 next year.

On our Western Gulf Coast Access initiative, we said a mid-2014 in-service date for the Seaway Twin, but it now looks like we'll be able to advance that to quarter one for next year. The upstream component of the Western Gulf System is Flanagan South, which is going well. The pipe is now staged along the route; construction contracts have been awarded; and the teams are mobilized. From this picture and referencing that to my earlier comments on regional expansions as well, you can see that our Mainline, Flanagan South, and the Seaway System, we have established a large-diameter solution to the US Gulf Coast, and this is being done primarily within the existing rights-of-way, which reduces our footprint.

We think this is a real game changer for Western Canadian producers to maximize the value of their production and to allow Gulf Coast refiners to access this growing heavy supply. The thing that has changed dramatically in just the last few years is that we are seeing huge support from producers to build various routes out of Dodge, and to ensure that we have some margin of excess capacity to protect against not having enough, which as we've seen, comes with a heavy price tag to producers in Western Canada.

Before I hand it over to Richard -- I'm now on slide 12 -- I would like to close the loop on one operational item, which is Line 37, just north of our Cheecham Terminal. As you recall, the huge rainfalls in northern Alberta triggered ground movement on the Line 37 right-of-way, and as a precaution, we shut down the four operating lines in that corridor so that we could fully assess the area. We are very pleased with that outcome in that the protocols that we have worked very well and what became a very complex undertaking given the geotechnical and engineering work that needed to be done in that circumstance.

All lines have now been returned to normal operations. We appreciate the patience and cooperation of our upstream producers in managing through this pretty difficult situation, to say the least, and also the dedication of our staff in handling a very complex issue with the safety of the people and environment as the first priority.

So with that overview, I'm now going to hand it over to Richard for the financial update.

Thanks, Al.

Good morning, everyone. I'll pick up the story on slide 13. And the picture by segment is unfolding pretty much as discussed in our first-quarter call. Liquids Pipelines contributed a solid CAD18-million increase in earnings for the quarter relative to the prior year, or about 13%. Our regional Oil Sands System continued as a strong contributor to growth, and it should do so for the balance of the year.

Likewise, the Seaway Pipeline, though not as big as a contributor as originally expected. That is due in part to capacity curtailment associated with downstream take-away limitations, which should be eliminated during the fourth quarter. But it's also due to lower spot volumes as the LLS to WTI differential has tightened in.

Mainline earnings were down for the quarter relative to the prior year, partially offsetting that regional system and Seaway Pipeline growth. This is partly due to the lower Mainline toll that I discussed on the first-quarter call, however, at that time, we were expecting strong volumes in the second quarter, which would more than offset the lower toll.

The stronger volumes did not materialize due to unplanned refinery outages curtailing downstream demand, primarily in April and May. The volumes were back on track in June at rates close to the first-quarter rate, and we continue to expect strong volumes in the second half, offsetting the lower tolls for a roughly flat year-over-year second-half earnings contribution from the Mainline. This leaves us tracking below our full-year expectations for the Mainline as a result of the second-quarter performance.

I'll also mention that our initiatives to improve the effective capacity of the system through relaxing of pressure restrictions following inspection and maintenance, as well as through operating enhancements, those remain on track to be largely completed by year end with some work carrying into the first half of next year. Based on our current volume outlook, we expect to have sufficient capacity to avoid any significant apportionment.

Those of you who follow a very granular approach and monitor what we refer to as the scale factor will note that it has popped up over 1.2 for the second quarter relative to what had been a running rate of about 1.16. This reflects two changes in the underlying Mainline volume mix crossing the border at Gretna. The first is that the proportion of long-haul barrels, those originating at Edmonton or Hardisty has increased in the mix. The long-haul barrels pay a higher toll, which averages up the scale factor.

This is partially temporary as volumes on the Saskatchewan System ramped back up and the Bakken Expansion fills up, though there will be a long-term trend toward long-haul barrels as well. The other factor is that while the Canadian System toll for barrels crossing the border has declined, the toll for local deliveries within Canada has not. This also averages up the scale factor, and it should be a sustained impact. In the near term, a factor of about 1.20 looks about right.

Moving on to Gas Distribution, the quarter unfolded as expected with EGD giving back part of the favorable first-quarter increase and still expected to give back most of the rest in the second half. A favorable court ruling on one aspect of our challenge of the economic expropriation by the Government of New Brunswick means the potential for a better second-half performance on that front.

The notable aspect within Gas Pipelines Processing and Energy Services is another very strong performance by the latter in the second quarter. Favorable arbitrage opportunities persisted through the second quarter. We still expect these opportunities to shrink in the second half, so little further gains relative to last year, though definitely a tailwind for the full year relative to our original thinking.

Within Sponsored Investments, there was solid year-over-year growth in the second quarter from both EEP and the Enbridge Income Fund. The EEP improvement reflects both an increased general partner incentive and the income from Enbridge's CAD1.2 billion bridging investment in EEP. The increased contribution from the income fund reflects higher incentive distributions from that fund and preferred unit distributions stemming from the 2012 drop down transactions, and it's consistent with our expectations.

Within the Corporate segment, I talked about Noverco and its seasonality on the Q1 call. On a full-year basis, we should see solid growth relative to prior year due to the new Vermont Power business, and that's to a greater extent than we had originally expected. Other corporate expense was up in the second order given higher funding costs related our capital programs, including dividends paid on preference shares.

However, this should largely reverse in the second half as recoveries from our operating units back to Corporate increase. Moving to slide 14 and pulling all that together in terms of what it means for full-year guidance, at the halfway point, we are still on track to be inside of our guidance range with headwinds relative to our expectations at guidance time roughly in balance with tailwinds.

On slide 15, you will see our progress on funding our large capital program totaling CAD5.4 billion through the end of July, and that's up CAD3 billion from my last report. We continue to bolster the equity side of our balance sheet with CAD0.25 billion from our share of the Noverco secondary offering plus a hefty pref-share issue.

We've completed a significant amount of equity prefunding activities in the first half of the year, and we are in good shape on our long-term funding plan, as I will speak to in a minute. Also notable is the CAD2.5 billion by which we have expanded our bank credit facilities this year, including CAD1.5 billion that closed in July, bringing our total Corporate facilities to CAD16.2 billion.

Slide 16 compares our current enterprise-wide available liquidity position, including that recent CAD1.5-billion credit facility addition, and it's comparing that with where we stood back at Enbridge Day last Fall. So as you can see, we have added over CAD3 billion to our liquidity pool, ensuring we have ample committed financial resources in support of our capital program.

Slide 17 lays out the current status of our long-term funding requirements, which we continue to chip away at during the quarter. Notably, our remaining requirement is down from CAD1.8 billion at our Q1 call to CAD1.3 billion as we continue to stay ahead of the curve on equity side. CAD1.3 billion is well within our capacity to fund through a combination of preferred shares and additional asset monetizations, such as income fund drop downs.

Moving to slide 18, this slide depicts the annual return profile, which characterizes a large portion of our growth projects, the so-called tilted return profile. This may be old news to some of you, but Al and I still run across questions about how we will sustain our growth after 2016 when our current wave of secured growth projects have come into service, and this particular perspective is the biggest part of that answer to that question. Not the only part, but the biggest part.

The horizontal band on the graph represents the level of full life discounted cash flow internal rate of return on equity capital, which is typical of most of our projects we generally describe as low double digits. For a traditional cost-of-service commercial structure, the annual return profile equals the full-life DCF return from the day the project goes into service until the end of its economic life, so we refer to that as a flat return profile. This used to characterize nearly all of our projects, and we still have quite a few that do follow this profile.

However, we also have quite a few where the annual return profile is upward tilted, as depicted by the diagonal band on the chart. These projects still have a full-life DCF return in the low double digits, but they start off in their first full year in service with a return in the high single digits and may require as much as four or more years to climb up to that full-life return level.

Of course, once they reach the full-life return, they must continue to climb above that level into the mid teens or higher in order to average back to the low double digits on a DCF basis. The commercial characteristics which typically give rise to the upward-tilted profile are either shipped or paid contracts with phased increases in the throughput commitment level, or an escalating toll profile, or in many cases, both of those in combination.

The significance of the return profile to our post-2016 growth rate is that a project with this profile, which has its first full year in service in 2016, does makes some contribution to EPS growth in that year. But by far, the largest contribution is in the years following that, and that concentration actually accelerates each year thereafter. That's the best kind of earnings growth of all. It comes without any need to deploy additional capital in order to achieve it.

So moving on to slide 19, that tilted return impact on growth in the post-2016 period would be important enough to take into consideration even if it applied to only 10% of our growth capital, but as the slide indicates, this tilted return portion of our capital program is more than 50% of our CAD28 billion in total commercially-secured capital projects, so it's a very significant factor.

I will finish up so, some comments on our exposure to a rising interest rate environment on slide 20. First of all, in this connection, we still have a component of our earnings which is from cost-of-service commercial structures where our rates to customers would be adjusted upward, not only to absorb higher debt service costs, but also to provide an increased return on equity. And that would apply to roughly one-third of our last year earnings.

Second, there's also a large portion of our earnings, like for example the CTS on the Mainline system, which have commercial terms whereby the tolls escalate in proportion to the rate of inflation. Although this is not a direct offset to higher interest rates, if those are accompanied by an increase in inflation, the result will be higher revenue to absorb increased interest costs and to generate increased earnings.

And lastly and most importantly, we have been anticipating a rising rate environment ever since the global financial crisis, and we have done everything possible to insulate our earnings from such an environment through rate hedges. We have hedged, on average, almost 70% of our floating-rate debt out now through 2017, and we've also fixed the underlying long bond rate on roughly 55% of our expected long-term debt issuances at this point through 2016, and that includes refinancing of maturities of existing debt.

These hedges, together with our foreign-exchange hedges, help lock in the economics on our large capital program. We have paid a near-term opportunity loss price for this cautious approach because rates have dropped further since most of these hedges were placed, but we do have the comfort of knowing that our EPS growth profile will be only very slightly impacted by a run-up in rates.

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

Thanks, Richard.

I'll wrap up by reviewing our overall progress on the key priorities we set out at Enbridge Day last October. The top priority, as we mentioned then, is a safety and operational reliability of our systems, because that simply enables everything else that we do. I am pleased with the progress on several fronts here.

On the second priority, as you saw, we're executing well in the field. We've maintained our financial strength as well through this build-out phase by staying ahead of our funding needs and ensuring that we have ample liquidity, as Richard took you through. And finally, we're making progress on growing the core business and establishing new platforms. So, good overall progress on the three priorities.

This next slide, 22, is the best evidence of progress on that third priority. Our secured project inventory stands at CAD 28 billion, all of which will come into service by 2016. We've also probability weighted the unsecured projects we're working on, and the funding plans that Richard went through account for Enbridge Inc.'s portion of this capital outlook, including the unsecured capital. This slide illustrates that the outlook is obviously very positive. That said, we continue to apply our usual rigor in assessing new opportunities to ensure we maintain our risk-reward profile and investor value proposition. And that means we won't go after every opportunity and we won't win every project.

Finally, here's how all this translates into the outlook for EPS over time. Basically, what it points out is that with inventory of secured and potential capital, we have confidence in our ability to achieve our five-year annual average EPS growth rate of 10% to 12%. And with the discussion today around our tilted earnings profile that Richard went through, our repositioning of EEP, and our projects under development, hopefully, we have provided transparency that we can continue our industry-leading growth rate through the end of the decade.

And with earnings growth, of course, comes a growing dividend. We believe that this combination of growth and yield that Enbridge provides is a key differentiator between ourselves and the more conventional yield-sensitive investments. So on the last slide here to summarize, it was a solid quarter, in line with where we thought we'd be. We remain on track to achieve full-year guidance of CAD1.74 to CAD1.90 a share. We continue to execute on our business strategies, adding new products our record inventory, and we are proactively managing our liquidity and funding requirements. And finally, project execution in the field continues to go well.

So that wraps up our comments, and I would like to pass it back to the operator to start the Q&A.

We will now take questions from the analyst community, followed by media questions.

(Operator Instructions)

For everyone's benefit, please limit yourself to one question and one related followup as appropriate and return to the queue for additional lines of questioning. And we have Juan Plessis on the line with a question. Please go ahead.

Thanks very much. A lot of color in your introductory remarks today. Just wondering, first -- Energy Services had a great first half, and earnings are expected to moderate in the second half. Just wondering if you can give us some color on what you're seeing in that segment with respect to locational differentials currently?

This business falls within Richard's purview, so maybe you can touch on that, Richard.

Sure. Well, everybody is probably pretty well aware that a number of the high profile differentials have shrunk down quite significantly over the last little while, and that is both locational differentials and also grade differentials as well. And those are the two things that tend to create arbitrage opportunities for the logistics business in Energy Services. So in some cases, we managed to put in place longer-term arrangements that will reduce the volatility of those opportunities to us, but on the whole, although the second half is looking to be strong as it was last year, it's not looking to be any significant degree stronger than it was last year.

Okay. Thanks for that. And just wondering if you can talk a bit about how you see the Mainline volume shaping up over the rest of the year and going to 2014. And I'm trying to get at with respect to the pipeline pressure restrictions coming off, and just wondering what quantum of volume increase you expect to be opened up due to that lifting of pressure restrictions.

Steve, do you want to take that?

Sure. Good morning, Juan. It's hard to specify exactly what the pressure restriction lifting, which is happening over the rest of the year on various lines, it's hard to separate that out because at the same time, we're working with the industry on co-mingling light types of crude, which helps improve the tankage utilization, streamlining schedules from feeder pipelines, and we are doing a lot of things with basically a strike-team approach every day that are designed to look at every piece of inefficiency where we would define inefficiency as pipe capacity that isn't available due to constraints otherwise.

So the pressure restrictions will -- lifting will help that. There's probably 200,000 to 300,000 barrels a day of available capacity if you unlocked everything with pressure restriction lifting, better utilization of the terminals, and so on, and that's the goal that we are working toward. But that would give you a rough idea of what could be available as the year goes on.

That's going to depend on supply and demand. As you saw the second quarter, there were downstream turnarounds that affected our volumes. Those are done. We should have more upstream supply coming on, and that should be a match for unlocking that extra capacity. So that's the way we're looking at that. And that's mostly on the heavy crude system, which is really the one that's more under constraint than the light crude system.

Just more generally, Juan, if you look the multitude of expansions that we have across the system, and particularly in the Mainline, the expansions are all geared to essentially match the supply profile that we see coming out of Western Canada. So, we should be well set to meet the supply, and that upstream capacity should be balanced with the downstream market access initiatives that we are taking out through 2015 and '16.

Great. Thanks very much.

And we have Robert Kwan from RBC Capital Markets on the line with a question. Please go ahead.

Thank you. You made a number of references to your thoughts on EEP, and I'm just wondering, as you look at the drop downs, especially with the positive receptivity that we are seeing in the US right now, despite the EEP needs to fund the CapEx, does this change your thinking about trying to affect a drop down in the middle of the EEP capital plan, or do you really want to see that completely out of the way before you (multiple speakers) the drop downs?

Sorry, Robert. Thank you.

We see this really as a two-phase approach. I think the best thing for the partnership is that's able to manage through the current funding that it has given the very good organic projects that's on their plates over the next two years. I think what we are trying to do, though, ultimately is position the partnership for these drop downs, so I see that happening more in phase 2 after we are able to digest all of this organic growth in front of us. So once that clears with hopefully better valuation and a very large slate of opportunities for drop downs, we are hoping that that will provide some further growth and further for the partnership, but as I said before, releasing of capital at Enbridge Inc. in the second phase.

And the other question I've got is on Flanagan South. Just wondering if you can provide a little bit more color as to where you are in the progress there. It's not that material, but you've changed the timing to Q3 '14 from previously mid '14. I know that's technically about the same, but just wondering if there's anything that seems to be slowing down the progress a bit.

Actually not. It's actually the opposite, I would say, Robert. I think our official date is July 1, so that may be where some of the confusion is. We probably call that Q3. But things are going extremely well on Flanagan South.

As you know, it crosses four states, but in every case, we have very good support from the community. And it's one thing I didn't mention in the remarks, but it's good to see that the community receptiveness all through that piece has been very strong with the opportunities we are providing this in those local communities. As far as the work under way, as I said in my remarks, we've basically staged everything we need to. We are mobilizing the crews, and we're ready to go, so on that one, we feel pretty good.

Thanks, Al.

And we have Linda Ezergailis from TD Securities on line with a question. Please go ahead.

Thank you. I appreciate the update provided on the Eastern Gulf Crude Access Pipeline, but I am wondering if we can get just a little bit more color on how the FERC process is going, and I realize your partner is championing that process, and just some commentary around the open season process and overall timing of that project?

Okay. Maybe I'll start out. On the FERC process, we thought we would get something back in June, but we knew that was a little bit tight, so we should see something this quarter, at least that is the hope, and that's the advice from our partner, Energy Transfer, on that one. As far as the open season, that process is being extended to mid August, so we are having good discussions with potential shippers there, as well as the open season upstream in the Southern Access Extension Project. So I would say we'll be in good shape to figure out where we are exactly on the project by mid August, and we'll see where we are there.

Steve, do you have anything to add there?

No. I think the interest is there. There are a number of parties that are studying the offering. Some have asked for more time, and we may think about that as we look at the whole project. The fundamental of getting Canadian heavy crude and Bakken light crude or western Canadian light crude into that Eastern Gulf Coast market is a pretty powerful one, and so there is that fundamental interest, and we're just going to continue working it to see how to translate that interest into the firm commitments that we need.

Thank you. Just as a follow-up, do you expect that to have to be cost competitive with maybe tankering from the East Coast down there?

It will have to be cost competitive from a few fronts. There's barge movements taking place of Eagle Ford crude from Corpus Christi over into the Eastern Gulf market at St. James in the Mississippi market there, so it will have to be competitive with that, keeping in mind that the Eagle Ford crude is an extremely light crude that has different characteristics than some of the feed stock that the refiners would prefer.

So it'll need to be competitive with that, and also with the movement of Canadian heavy oil, which is really the -- one of the linchpins of all of this. It will have to be competitive with other ways of getting Canadian heavy crude there, which predominantly will be coming off of the Houston-Port Arthur area and across. So I think it shapes up well, but those would be two of the competitive forces that it will have to address.

I think that's a good point, the last one, and if you look at the Gulf Coast, essentially how this transportation needs to be priced is to be competitive with other ways to get to the Gulf, particularly through our Flanagan South and Seaway Twin. So I think we're going to be pretty competitive into that entire Gulf Coast market, both the east side and east side.

And we have Paul Lechem from CIBC on line with a question. Please go ahead.

Thank you. I wondered if you could give us some more insight into the new incentive regulation that you are proposing for Enbridge Gas, what it might look like. Do you expect to be able to increase your equity thickness over previous rounds?

Do you think you can maintain the same kind of incentive structure? Can you give us any thoughts about that? And then also, on the process, is this going to go in for a full rate case? How should we think about how long it takes and the process to get a new agreement?

Thanks, Paul. On the first part, we are hoping that the mechanism that we have to share savings is largely the same as what we've had in the past. There may be some differences. If you go back to the comments on the GTA project, for example, something like that that's a specifically identified capital project will need to be accounted for in the rate structure that we land on.

But generally, we'd like the previous regime where we've had a good sharing of savings with rate payers, as I've described, so we are hoping that is largely the same. As far as the process, we filed, as I mentioned. I'm not sure it's going to need a full rate hearing. The way this has worked the past, and the way we would expect it this time again, is to talk to the interveners, work through what's on their minds, and then hopefully come to a settlement where we can see the next phase of this incentive regulation go forward beginning in 2014.

Thank you very much.

So that should -- my guess is that should be completed by the end of this year, and even if it spills over, we are likely to see the rates apply from January 1, 2014 anyway.

Thank you.

And we have Ted Durbin from Goldman Sachs on line with a question. Please go ahead.

Good morning. First question is on the backlog here, the $9 billion of unsecured projects. I am wondering if you can just characterize what those look like. Is it still focused on the Liquids? You've got the Woodland Extension now, now secured. Maybe a little bit more gassy. Just talk about that -- the nature of that backlog and maybe the return profile as well.

As the nature of it, I'm going to say it's generally not that much different than the secured profile. Maybe, as you point out, there may be a little bit more gas and power in there, but generally, we're seeing a lot of opportunity still within the liquid side of the business. That's certainly where the infrastructure is required in the very short term, so it is probably weighted more to that side of the business.

As far as the return profile, as I alluded to in the points earlier, we pretty much are seeing the same profiles, at least we are assuming that, in those projects. We are going to have to make some decisions, obviously, when those projects come to being more secured and determine whether or not they fit the return threshold that we set for the businesses that we're looking at there and the projects that we're looking at relative to the embedded cost of equity for each of those projects. So it's going to be pretty rigorous, and we'll go through it the normal fashion.

Next was just on terms of these drop downs to EEP. The longer term, do you see virtually all the US assets ultimately down at EEP, or is this -- how does the timing work there? And then, would you consider taking back maybe equity in EEP in exchange for assets rather than taking back cash or preferred equity or some of the other things that you have done. Just talk through your thoughts there.

Well, in terms of the size of the potential, it's -- I'm going to take a rough guess and say it is at least CAD10 billion of assets that are available. It's likely going to be more, actually. But it's really a question of how fast and how effective the partnership can absorb the level of capital that we have to drop down.

The other factor is, of course, the nature of the project, and obviously, the partnership is ideal for absorbing a very stable cash-generating asset, so timing comes into play. So some of the projects, obviously, that we are working on right now with EEP and our interest in those projects, obviously, wouldn't be categorized for drop down until those are operational and generating steady cash flow.

As to whether or not we take back units, I think, given that -- we look at EEP as a financing vehicle part -- as part of the overall structure at Enbridge, so I would say that generally we would prefer to take back cash. But obviously, as you have seen, there are situations where we may invest as well alongside.

Great. And then if I could ask a quick one, probably for Steve here, you mentioned the co-mingling of the light and the ability to maybe get some extra capacity. I am just wondering where you are in that process, if you can quantify that, above and beyond the pressure restrictions, what additional capacity you might be able to get to come out of Western Canada down to the US?

Actually, Ted, most of the co-mingling would be on the heavy streams that have grown in number and are very similar in their assays. So where we are with that process is that we have been working with the industry for about 1 year to 1.5 years on not only a co-mingling but a quality pooling initiative where people get paid for their constituent components and quality.

That is making good progress, so that's -- I think the best way in our view to handle co-mingling is to then have a quality pooling that allows the right assignment of value for various streams, even though they are very similar. So mostly, it would be on the heavy crude side, and it's wrapped up in that 200,000 to 300,000 barrels a day that I mentioned of available pipe capacity. That's before the first tranche of Alberta Clipper capacity comes on in mid 2014.

So, that's the goal that we are working toward, and I don't think I will try to split up within 200,000 to 300,000 how much would be co-mingling, how much would be pressure restriction lifting, how much of it would be streamlining of feeder pipeline schedules, etc.

That is great. That is it for me. Thank you very much.

At this time, we'd like to invite members of the media to join the queue for questions.

(Operator Instructions)

For everyone's benefit, please limit yourself to one question and related followup as appropriate and return to the queue additional lines of questions. Thank you. And we have Jeff Jones from Globe and Mail on line with a question. Please go ahead.

I am just wondering if you could maybe provide a little bit of background and expectation as to what the Presidential Permit amendment process is, what it entails for Alberta Clipper. Do you foresee any potential roadblocks with regard to the regulatory process or political process in the United States?

Sure, Jeff. Well, first of all, there has been a lot of discussion around the Presidential Permit process for XL. I don't really see this as the same kind of issue. What we need to do is submit for an amendment to the Environmental Impact Statement, so it's not the same process. Similar, but obviously, not as involved. In this case, as you know, Jeff, we've got the pipeline in the ground. It's been in the ground since 2010. What we are talking about here is simply adding horsepower to an existing pipeline. So as far as what pipeline companies do in their lives, this is a very benign type of increase in capacity. I think the other thing is that there is no timeframe being set for this environmental assessment, but we'd hope that it would be early next year. In the meantime, though, we are proceeding with off-site work around fabrication so that we can make sure that we optimize the timing.

And by the way, just as a further point, for this first phase, we're not talking about adding stations. This is adding capacity to the station so that the footprint is really not being affected at all with this initial increase in capacity.

And Jeff, we did receive Minnesota Public Utility Commission approval last week for the work, so we now have approvals on both sides of the border. And then, as Al said, the State Department just has to look at the amendment to the Environmental Impact Statement. But there is no new pipe involved, and it is only an addition of pumping horsepower, so it is quite straightforward.

And just as a follow-up, the questions are related in that they're both about oil pipelines. Do you foresee a problem with the potential overbuild to Eastern Canada now?

Maybe we could answer it this way, Jeff. If you look at the supply profile that's expected out of the Western Canadian Basin, and maybe this is what you're getting at, even if XL is built, and we are assuming it does in 2015, we are going to need all the pipelines that have been announced. The other thing that has happened here that's important is -- and this is what obviously has been affecting producers through discounting of prices is that everybody has come to realize, and which we have been saying for a long time, is that you need a certain level of buffer or excess capacity as well to manage through difficult periods.

So, I do think that based on the supply profile we see that we're going to need all of the pipes. With regard to Eastern Canada, we obviously have foreseen the need there as well, and we have firm commitment to support the reversal of Line 9, which should provide about 300,000 barrels per day of capacity into the Quebec market, and that should be available in 2014. So we are working on it, and we are executing as quickly but prudently as possible to make sure that happens next year.

Okay. So in your view, then, Eastern Canada basically becomes -- must become an export market, then, if you're looking at possible 1.1 million a day on Energy East plus 300 for Line 9 reversal. That's a lot of oil.

Yes, that's probably not a bad assumption. Obviously, there's local markets after you hit the Eastern Coast that are available for export, but generally, you're right. There's a lot of crude there, and it's going to have to find a home.

Thank you very much.

And our next question comes from Andrew Kuske from Credit Suisse. Please go ahead.

Thanks. Good morning. Just a question as it relates to an increasing issue in the industry, just insurance costs. From what we've seen from some of the recent spills that have happened and then the tragedy in Quebec, how do you think about insurance costs just from a coverage standpoint, the willingness for insurers to actually cover the industry, costs, deductibles? Is there some kind of Government intervention that actually comes in at some point in the future?

Richard, do you want to take a shot at that?

Yes. Well, as you might expect, insurance costs generally have been rising of late, and all aspects of insurance is tougher than it was historically. We were able to modestly increase our coverage this last go around from CAD660 million general liability insurance to CAD685 million. We would have taken more if had been available at a reasonable price, but that was pretty much capping out at least what the market availability was to Enbridge, so -- and recent developments are not going to help that.

Do you think we're heading down the path of, effectively, surety bonds for the industry for covering certain incidents? I mention that in part just because of some of the criteria that have been imposed on Gateway.

Well, and not just Gateway. I think you've seen an announcement by the Federal Government to the -- what will be a Canadian-wide regulation requiring provision of financial resources to support addressing any major incident, and I think there is probably going to be a fair bit of thinking done and innovation done on different financial structures that could be put in place to provide the assurance to the Government and the public that there will be resources to address any spill. Of course, the primary line of attack is to minimize the likelihood of such a thing happening in the first place, but you are right, Andrew, there will be alternative financial structures to address that small residual risk.

So then finally, the final point on this, do you see this as being -- all of these developments effectively being better for the larger companies that are better capitalized, bigger balance sheets, more assets for handling, essentially, the environmental changes, the insurance costs and the obligations are being put on the industry to a much greater degree than the smaller ones that might not be able to operate in that kind of environment.

That's a possibility. I think it's probably too soon to see that, and I wouldn't rule out the possibility that there is some form of -- and maybe this is something you were getting at a little earlier -- some form of industry-wide financial solution, structural solution as opposed to a pipe-by-pipe or company-by-company solution, and that would avoid putting that very difficult circumstance on some of the smaller pipelines that you just referred to.

Generally, though, Andrew, you are making a good point because what we've noticed, certainly, there is a lot more regulatory scrutiny these days. And we feel very confident in our technical capabilities, which -- going to be tested as the industry goes through this pendulum here that we're going to go through over the next several years. So, I think you're right in that there will be, certainly, maybe an advantage in some ways to larger companies with very strong technical capability.

Thank you very much.

And your last analyst question comes from Pierre Lacroix with Desjardins. Please go ahead.

Thank you very much. Just a quick one on the growth opportunities that are unsecured, on that CAD9 billion, Al, you mentioned on the Liquids side. Could you give a bit more color on what areas are the most likely to happen eventually? Is it going to be on new assets or boosting investments on current pipelines that you have? Or where it's going to go, is it going to go south, east, west? Maybe a bit more color would be helpful.

Well, maybe the way to think about it is if you look at the Mainline -- well, the map over all for Enbridge, I would start with the regional side. As you've seen with the announcement of the Woodland Extension, we are in a very good position there, so there are some other opportunities that we are working on very diligently in the upstream side of our business above -- or upstream of the Mainline. So I would say that's number one.

Then if you look downstream beyond the Mainline, there's various market access initiatives that we have announced but also that we're working on that could come to fruition. Then I wouldn't put out of the realm potentially further capacity increases on the Mainline even in addition to what's already been announced. So I have to say it probably encompasses the whole map for us, Pierre.

I maybe one final. You must have -- in the past, you talk about the international opportunities. I recognize that you are fairly busy these days, so is it still on the burner? Is it on the front, on the back burner? Where is the position right now on your to-do list.

Maybe to use your analogy and extend it, as you point out, our plate is pretty full these days, and we've got another course or two to chew through, hopefully, in the next while, as well. I would put the international opportunities as certainly very tasty, but maybe on the dessert side of the table at this point. We've got our focus down to three countries, Peru, Colombia, and Australia. It doesn't mean we wouldn't look at something else, but those are the top three.

And we're in the good position of having that big plate. We don't have to rush into anything on the international front right away. So we are taking it slow and looking at opportunities, so certainly, as we progress through the next five, six years, that presents a very good opportunity to further enhance the growth down the road.

Thank you very much.

Thanks, Pierre.

As there are no further questions, I'd like now to turn the call back to Jody Balko for any closing remarks.

Thanks, Adrian.

Well, before we end the call, I just want to make you aware of some changes to the Enbridge Investor Relations Team. Jonathan Gould, who many of you know, has accepted a new role in our Corporate Development and Planning Group, and on behalf of the Management Team, I want to thank Jonathan for his contributions to Investor Relations. He has added tremendous value, and we wish him continued success in his new role.

Succeeding Jonathan is Adam McKnight, who was most recently in our Corporate Controller's Group leading the Pension Fund Investments Team. You will have an opportunity to get to know Adam as he transitions into his new role. But in the interim, Jonathan Gould and I are available for any follow-up questions that you may have after today's call. Thank you, and have a good day.

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