恩橋 (ENB) 2017 Q2 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Enbridge Inc., Enbridge Income Fund Holdings, Enbridge Energy Partners, and Spectra Energy Partners Second Quarter Financial Results Conference Call. My name is Saeed, and I'll be your operator for today's call.

At this time, all participants are in a listen-only mode. Later, we'll conduct a question-and-answer session for the investment community. During the question-and-answer session, if you have a question, please press * then 1 on your touch tone telephone. Please note that this conference is being recorded. I will now turn the conference over to Mr. Jonathan Gould. Sir, you may begin.

Thank you, Saeed. Good morning, and welcome to the Enbridge Inc. and sponsored vehicle joint second quarter 2017 earnings call. With me this morning are Al Monaco, President and CEO of Enbridge; John Whelen, EVP and Chief Financial Officer; Guy Jarvis, EVP and President, Liquids Pipelines; and Bill Yardley, EVP and President, Gas Transmission & Midstream.

Our joint call will include discussions for all of the Enbridge entities, including Enbridge Inc., Enbridge Income Funds, Spectra Energy Partners and Enbridge Energy Partners. This allows us to provide a consistent, enterprise-wide strategic and financial perspective, while at the same time weaving in specific commentary on the strategy and performance of each of the sponsored vehicles. Note that we've developed additional supplemental information for each vehicle to ensure that we continue to provide full, transparent disclosure for each. Some of this information is appended to the presentation here today and has been posted to the company websites.

As per usual, this call is webcast, and I'd encourage those listening on the phone line to follow along with the supporting slides. A replay and podcast of the call will be available later today, and a transcript will be posted to the website shortly thereafter.

In terms of the Q&A, given the broad agenda we have and the limited time, we will prioritize calls from the investment community only. If you're a member of the media, please direct your inquiries to our communications team who will be happy to respond immediately. We are again going to target keeping the call to roughly an hour, so please limit your questions to one and a follow-up as necessary. But as always, we will ensure that our Investor Relations team will be available for your more detailed follow-up questions after the call.

Now before we begin, I will again point out that we will refer to forward-looking information on today's call, and by its nature, this information contains forecasts, assumptions and expectations about future outcomes. So we remind you that it's subject to the risks and uncertainties affecting every business, including ours. This slide includes a summary of the significant factors and risks that could affect Enbridge and its affiliates, and are discussed more fully in our public disclosure filings available on both the SEDAR and EDGAR systems.

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

Thanks, Jonathan. Good morning, everyone. I'm going to begin with an overview of the Q2 results, then go through our business update. John will walk you through the financial picture, including the sponsored vehicles, and our usual funding status. I'll wrap up with a mid-year progress report on 2017 priorities.

Moving on to Slide 4. As you can see here, EBIT and ACFFO results are up as Q2 was the first full quarter with the Spectra assets in the fold. Recall that given the timing of the deal close, last quarter excluded January and February results, which they usually contribute roughly 30% of the Spectra assets' annual cash flows. Based on these results and our second half outlook, we're on track to meet our full-year ACFFO guidance of $3.60 to $3.90 per share.

Operational performance for all the businesses were strong. We were pleased with the gas transmission business, and renewables had a good quarter as well. The liquids business also ran very well, but was affected by one-time upstream volume disruptions. Volumes were actually up year-over-year again, but behind Q1 mainly because of the Syncrude facility outage. This also had some knock-on effects on heavies, given reduced synthetic diluent available for blending, and the Line 5 turndown for the hydrotest that we conducted backed out some light volumes as well. So the combination of those transitory disruptions impacted EBIT by roughly $50 million or $0.03 per share of ACFFO.

We're expecting the pace of cash flow growth to accelerate in the second half. Volumes are now actually ramping up on the mainline, and we expect record throughput in the second half of the year. That's partly from Guy's liquids teams' work, just finishing up on their planned terminal and crude slate modifications that will further optimize mainline throughput to move another 150,000 per day or so that would otherwise be apportioned from time to time through the year. The second half will also see increased contribution from new projects that came into service this quarter, the benefit from an uptick in FX rates from the hedges we layered on last quarter, and the impact of cumulative synergy capture from the Spectra deal, which began to occur in Q2.

Onto Slide 5 and an update on Line 3. Just for context here first, the replacement of Line 3 is a pretty critical infrastructure project for the economy overall and of course to our system. The line will have the newest and most advanced pipeline technology and provides much needed incremental capacity, bringing it back up to its full capability, to support Canadian crude oil production growth and U.S. and Canadian refinery demand. As you can see here from the map, in recent years, we've actually already replaced some segments of the line in Manitoba, across the border and in Wisconsin. The project is fully permitted in Canada, and we now have all the major permits in North Dakota and Wisconsin in hand. With that, we've finalized the execution plan now and will begin construction this summer on spreads in Alberta, Saskatchewan, and Wisconsin.

Our approach to Line 3 encompasses much more, though, than design, commercial aspects and construction. We've had very extensive and I'll say productive engagement with communities along the way. Our team is focused very early on discussions with the community, listening to concerns, addressing issues, and ensuring that these communities and indigenous partners benefit through jobs, capacity building, training and procurement. We're very thankful for the great input that we've received from communities -- input that helped us make this project better, and that's the way we approach engagement on these types of projects.

In Minnesota, the regulatory process is advancing and we have good transparency on the process and the timelines. And after extensive community meetings here as well this summer, we expect to receive the final EIS in Q3. That'd be followed by a ruling on the need and route from the PUC expected in the spring of next year, so we'd be in a position to begin construction there by next summer. And that would allow us to meet our projected in-service date of the second half of 2019, as we've talked about before.

With the execution plan locked down, we finalized our cost estimate now. Overall capital costs have increased by about 9% relative to the initial estimate when we sanctioned the project back in 2014. That's actually a very good outcome, given the extended project review we've had and changes to the project along the way. We've updated the economics with this new cost estimate, which are unchanged overall as the higher capital is fully offset by lower forecasted operating costs versus the costs that we had originally established back in 2014 and the stronger U.S. dollar.

So that's the update on Line 3. Moving to Slide 6 now.

While Line 3 restores the line to capacity, we've got more expansion options shown here that add up to an additional 500,000 barrels per day. The first 175,000 can be achieved shortly after Line 3 goes into service in 2019. Both the DRA and the idling of the Bakken expansion, which flows south of the border into the mainline, are low cost and neither requires any new permitting, which is a big plus these days of course. Beyond that, three other options would add 325,000 barrels of capacity. These are also very timely, cost effective and highly executable, so they suit our customers quite well.

We've also developed, of course, downstream market access solutions on the system that would be expanding Southern Access, Flanagan South and Seaway, which would bring total Gulf Coast access capacity to over 1 million barrels per day. So good flexibility there and some attractive shipper options to utilize the existing system.

Slide 7 is the updated project list for the CAD 31 billion capital program. And as a reminder, these are commercially secured and in execution, so they exclude other development projects that we're working on. As you can see here, we've got excellent diversification by business line, size and geography, which reduces the overall execution risk of the program. The checkmarks here show the CAD 6 billion-plus of projects we brought into service in the first half. The big ones here were Norlite Diluent and the Sabal Trail gas pipeline. Both came in nicely on time and on budget.

Next up, over the second half is another CAD 7 billion going into service made up of more but smaller sized projects, again, spread across gas, liquids, renewables and utilities. Overall, these projects are going to drive a significant amount of cash flow growth over the next few years.

On the next slide, I'll provide a few specific updates. We're on Slide 8 now. On Alberta Clipper, recall that we're seeking an amendment to our existing Presidential Permit here, which would increase the flow across the border on the lines from 580,000 to the full 800,000 barrels per day of capacity. And the permitting process here is moving along well.

On NEXUS, we're ready to go with construction once the FERC forum has been established. Given that delay in the FERC quorum, the in-service date is now going to be 2018. Obviously we're a little bit frustrated with the timing here. This is a great project that is going to be a good economic driver for the local areas, so the shovels are ready to go. Many people are ready to go to work, and customers are actually anxious to get at lower gas prices from the region. The way to look at this, then, is that once we receive FERC approval, construction would take between 7 to 10 months, depending on the season that we actually begin work.

On Valley Crossing, this project is part of our strategy to capitalize on the changing natural gas flows on the continent. It's a critical link in this case between the growing Permian supply and increasing demand in Mexico. Most of the right of way has been cleared. As you saw earlier on the opening slide, we've begun construction on some segments of the line.

Onto Slide 9 and newly secured projects. At our Mid-Year Investor Update, we announced three new ones: the CAD 1.0 billion T-South expansion and the CAD 500 million Spruce Ridge projects, all expansions to the BC system. These two further solidified the already strong competitive position we have in the area by capturing new volume. These are fully backstopped with long-term commitments. They're pretty much cost of service-like here, so they're middle to fairway and exactly what we expected from the Spectra deal.

We've also finalized an expansion of Hohe See's German offshore wind project. That would bring the total investment there to CAD 2.1 billion. That project is nicely accretive and provides solid returns under a long-term PPA with highly creditworthy counterparties there. And there's a 2019 ISD for that one.

More generally on growth though, there's, as everyone knows on the call, a lot of investment capital chasing energy infrastructure. We're going to continue to be disciplined in allocating capital. The best projects for us are those that leverage our existing footprint like the ones that are on this page here.

Lastly, John's going to go through the sponsored vehicle results in a minute here, but let me make a couple of comments on that since this is a joint call covering all of our entities. Our sponsored vehicles are important because of one single reason: they hold assets that are critical to our business objectives, our strategy and the cash generating capability, and they've also proven to be an effective source of capital. To raise capital though, obviously, these business need to deliver good operational and financial results and they need to be strong. ENF, EEP, and SEP performed well this quarter, in line with where we thought, and they're on track to meet their operational and financial guidance targets for the year.

With the completion of our strategic review, and the actions taken earlier on this year, we believe that all the vehicles are now set up well for success going forward. All three vehicles all have high-quality assets with built-in organic growth. And under the right conditions, there also could be opportunities to supplement that with drop downs as stable cash generating assets. The three are all now well-positioned with strong balance sheets, appropriate distribution coverages and attractive value propositions.

So with that, let me hand it to John for his review of the quarter.

Thanks, Al. The structure of my financial review will be much the same as last quarter. I'll start with a consolidated perspective, and then touch on the financial results of each of our sponsored vehicles before coming back to the overall funding picture. I'll pick up on Slide 11 with a review of consolidated performance, focusing on adjusted EBIT at the segment level.

This quarter's results reflect a full quarter of operations for the assets we acquired through the Spectra merger transaction, which does make comparisons to the second quarter a little awkward. So this time around, we'll provide some color on the year-over-year segment performance, but also focus more on how the individual assets within those segments are performing, and starting with Liquids Pipelines, where adjusted EBIT was about CAD 16 million quarter over quarter. This was in part due to an increase in throughput on the Canadian mainline system relative to the second quarter of 2016, which had been affected by the wildfires in Northeastern Alberta. As Al has already mentioned, throughput growth on the mainline would have been significantly higher this quarter relative to last year, but for the impacts of temporary outages at upstream production facilities and the impact of the hydro-testing on Line 5, which occurred in June. As Al noted, in combination, these one-time items had roughly a CAD 50 million impact on EBIT.

Further tempering EBIT growth in Liquids Pipelines was the impact of: mainline apportionment in April and May on the financial performance of downstream pipelines; the absence of earnings from the Saskatchewan feeder system and Ozark pipelines, which were sold subsequent to the second quarter of last year; and the change in reporting practice at the beginning of this year whereby we no longer pick up toll receipts at the EBIT level on certain take or pay contracts with makeup rights if the related contractual volumes aren't shipped.

As Al mentioned, we do expect to see stronger results from Liquid Pipelines over the second half of 2017 as throughput volumes return to the levels achieved earlier in the year and capacity optimization projects work to alleviate apportionment.

Moving down a line to Gas Pipelines and Processing. Quarter over quarter, adjusted EBIT was up sharply as a result of a very large suite of gas pipelines that we acquired through the merger. Overall, performance from the natural gas transmission business was strong and in line with expectations, driven by growing contributions from expansion projects recently placed into service in the U.S., and the continuing solid performance from the Alliance Pipeline under its new commercial model. These strong results in gas transmission were partially offset by weaker performance from the gas gathering and processing business in the face of ongoing weakness in commodity prices which did affect volume throughput, particularly on our legacy Midcoast assets.

Gas Distribution was up CAD 80 million, largely due to a full quarter's contribution from Union Gas, which benefitted from higher transportation revenue as a result of the Dawn-Parkway expansion project coming into service. EBIT from in the Enbridge Gas Distribution utility was also up a little, primarily in this case due to lower operating costs. Weather was not nearly as big a factor as it was in the first quarter, but it did have a modest impact on the bottom line performance at Enbridge Gas Distribution, Union Gas, and in Noverco.

Energy Services was down relative to the second quarter of 2016. At this time last year, the business has been able to take advantage of arbitrage opportunities created by unusually wide basis differentials and quality differentials. So far this year, these opportunities just haven't materialized to the same degree, and we recorded a small loss for the quarter, reflecting unrecovered demand charges on a couple of assets where we hold capacity commitments.

And finally, Eliminations and Other was a little weaker than Q2 of last year: about $10 million. The major driver here was a higher amount of unallocated corporate level costs post the merger that weren't fully offset by synergies realized during the quarter.

Taken all together, adjusted EBIT for the second quarter grew very substantially by about $624 million to a just over $1.7 billion, driven, of course, primarily by the contributions from the new Spectra assets, which in aggregate performed pretty much in line with expectations, but also some puts and takes from the legacy Enbridge assets, including the impact of the outages on Liquids Pipelines, which we don't expect to see going forward.

Turning to Slide 12, you can see how that business performance translated into bottom line available cash flow. ACFFO for the quarter was just over $1.3 billion, up about $458 million from our quarter 2 of last year, and driven largely by the same factors I just reviewed. The growth in adjusted EBIT was offset to a degree by a few "below-the-line" items, including: higher interest costs on incremental debt incurred to fund the organic growth projects brought into service since last year; incremental interest on the debt that we assumed in the merger with Spectra; the inclusion of the maintenance capital programs associated with the legacy Spectra assets; and higher net distributions to non-controlling interests.

Non-controlling interests include the public's interest in our sponsored vehicles. And distributions paid from these Vehicles were up a little quarter over quarter due to the acquisition of Spectra Energy Partners, an increase in dividends paid by Enbridge Income Fund Holdings, and offset somewhat by the reduction in EEP's distribution that we implemented in the first quarter. On a per share basis, ACFFO was lower than the prior quarter, largely due to the shares issues as consideration for Spectra Energy when the deal closed on February 27.

Moving now to Slide 13. As Al noted also earlier, we remain right on track to end the year within the guidance range that we provided last quarter. For the combined company, we continue to expect consolidated 2017 ACFFO to come in between $3.60 and $3.90 per share. You may remember last quarter when we spoke about the outlook for 2017, we noted that our ACFFO guidance for this year wasn't necessarily reflective of an annualized rate. This is in large part due to the timing of the merger that closed right at the end of February, which as Al said, means that we don't pick up the performance of Spectra's assets in January and February, which are typically disproportionately strong. As a result, we'll be well-positioned going into 2018 to deliver strong year-over-year growth.

Looking at the remainder of 2017, we do expect to see an acceleration of ACFFO relative to first half. There's a few factors driving this, as Al noted, including: growing contributions from the Liquids Pipelines; the impact of new projects coming into service in both gas and liquids; growing benefits from synergy initiatives; and a strengthening FX hedge profile. And I'll take a few minutes or a minute on the next slide or so to dig a little deeper into each of these.

Starting with the outlook for Liquids Pipelines, mainline's volume is shown in the top left quadrant of the slide. As Al already mentioned, the outages we experienced at customer facilities in the second quarter are expected to be transitory, and we do expect upstream production and deliveries to the system in the second half of the year to return to the record levels we were experiencing earlier in the year. Importantly, the capacity optimization work undertaken earlier this year will ensure that this growing throughput can be accommodated, and will also serve to alleviate apportionment on the system and strengthen the revenue and cash flow generated by our liquids pipelines downstream of the mainline.

Moving around the slides clockwise, we did get a modest benefit this quarter from a better average hedge rate on our foreign exchange hedging programs as we've been legging into additional hedges of our 2017 through 2019 exposure during the first half of the year when the U.S. dollar was particularly strong relative to the Canadian dollar. About 80% of our exposure to the U.S. dollar is now hedged this year, and the average hedge rate will increase in the second half of the year. So notwithstanding the recent strengthening of the loonie, we expect to see a bit of an uplift from the impact of the higher effective hedge rates, which will more than offset any downdraft on the remaining unhedged exposures.

We'll also see more impact from our greenfield development program. Al gave you the details a little earlier, but it's important to remember that close to $7 billion of new projects will be brought into service in the second half of this year, immediately contributing to incremental earnings and cash flow growth and positioning the company for continued strong growth in 2018.

And finally, while we won't get to pick up a full year of synergies in 2017 given the timing of the merger, we are making very good progress in driving out anticipated savings and we expect to see that benefit ramp up over the course of the year. A very significant component of planned savings for this year was achieved through the restructuring actions that took place in the first half. And we're really starting to see the impact of efforts to wring supply chain and services cost out of both O&M and capital spend as we take advantage of a bigger organization and the economies of scale that brings. We're on track to achieve a 50% of our targeted ongoing run rate synergies by the end of the year, which helps drive growing cash flow in the back half of 2017.

I'm going to shift gears now and speak briefly to the performance of each of our sponsored vehicles, starting on Slide 18 with ENF and the Fund Group, which delivered another very solid quarter of performance. Fund Group ACFFO was up CAD 118 million compared with the second quarter of 2016, largely driven by the Canadian Mainline system. The quarter over quarter uptick in mainline performance was driven by higher throughput relative to the second quarter of last year, as well as a higher residual benchmark toll, which came into effect at the beginning of the second quarter and enhanced the performance of the Canadian mainline. Canadian mainline results in the second quarter would have been even stronger if not for the unexpected upstream outage that we've discussed earlier.

Fund Group performance also benefited from continued strong performance from Alliance and better results from Green Power. All in all, a solid performance from the Fund Group with overall ACFFO growth coming in over 30% higher than Q2 in 2016 and in line with our expectations. The distributions paid by the Fund Group translated into earnings at ENF of about CAD 77 million, which reflected ENF's larger ownership interest in the fund, following a secondary offering completed earlier this year. ENF's monthly dividend was increased by 10% at the beginning of the year, bringing its quarterly dividend up to just over $0.51 per share. And it's well-positioned to continue with annual 10% increases through the next two years or so as new projects continue to be brought into service.

We expect the performance of the Fund Group to continue to strengthen over the remainder of the year as volumes ramp back up on the Canadian mainline, and another CAD 1.5 billion of new growth capital projects coming into service over the remainder of the year. At this time, our guidance remains unchanged from that provided in February. The Fund group remains well-positioned to deliver consolidated ACFFO of between CAD 1.9 billion and CAD 2.1 billion, while maintaining a payout in the range of 80% to 90%.

Turning now to Spectra Energy Partners, or SEP, which announced its second quarter results yesterday evening. At SEP, both ongoing EBITDA and distributable cash flow were higher compared to the second quarter of 2016. The story here is in many respects similar to the Fund Group -- solid performance from core assets and strong growth from new projects coming into service.

The completion of expansion projects on the U.S. Transmission Systems, Algonquin Gas, Texas Eastern, and Sabal Trail, drove higher EBITDA from Spectra's gas transmission pipelines with ongoing EBITDA up almost $100 million year-over-year, and Distributable Cash Flow, or DCF, up $90 million. The increase in DCF was a little higher than expected due to some deferral of maintenance capital that now will be spent later in the year.

SEP continues to increase its distribution each quarter by a $0.0125 per share. And that doesn't sound like much, but it's a pretty significant increase when measured year-over-year. With the announcement of this quarter's increase, SEP's quarterly distribution now sits at 71.4 cents, and that's a pretty healthy 7.5% increase over the declared rate in Q2 of last year.

SEP's performance continues to be right on track, and our full-year guidance remains unchanged from that provided in the prior quarter: ongoing DCF of $1.4 billion to $1.48 billion and annual distribution of coverage of between 1.05x and 1.15x.

Now moving along to Enbridge Energy Partners. Results this quarter were affected by a number of factors, including the completion of the restructuring initiatives that we had been working through. Overall, adjusted EBITDA at EEP was down approximately $92 million compared to the second quarter of 2016 due to a number of factors.

Results from the Lakehead Mainline were largely in line with expectations. The impact of the outages on the mainline that Al and I spoke to earlier were muted at the Lakehead level by the fact that a significant portion of the revenue on that system is generated by cost of service, or similar tolling arrangements, and therefore is relatively insensitive to changes in volumes. That said, we do expect an uptick in performance from Lakehead relative to the first half of the year, primarily due to ongoing cost containment and the absence of the hydrotesting costs that impacted reported second quarter performance.

The overall quarter-over-quarter decrease in adjusted EBITDA primarily reflects a number of factors that we had anticipated and were captured in the 2017 outlook we provided earlier in the year. These included: the expiration of surcharges for the Phase 5 and 6 expansions on the North Dakota system; lower throughput on the legacy North Dakota gathering and rail assets; and the absence of earnings from the Ozark Pipeline, which was sold by EEP on March 1 of this year.

The performance of the Midcoast gas gathering and processing also played up in EEP's results for this quarter as the sale of those assets to Enbridge did not close until just prior to the end of the quarter. With the G&P business now having been sold, and with other restructuring actions now completed, we expect EEP's results going forward to become much more stable and predictable, driven by the low risk regulatory constructs that underpin EEP's liquids pipeline business.

Distribution coverage was solid this quarter, as you would expect following the restructuring -- just over 1.4x on a cash basis, and 1.14x including a coverage of non-cash payment of distributions in-kind. Credit metrics have already strengthened significantly, as you can see, as proceeds from the sale of the G&P business were used to pay down debt as we planned. And we remain on track for further improvements as incremental cash flow is generated from jointly funded investments and greenfield projects coming into service.

The adjusted EBITDA and DCF guidance that we provided for EEP earlier in the year was on a pro forma basis as if the gathering process had been sold at the beginning of the year. With the completion of the restructuring now behind us, and a solid outlook for the Liquids business heading into the last five months of the year, our guidance remains unchanged.

I'll wrap up my segment here on Slide 18 with an update on enterprise wide funding. And we've been making some very good progress on this front. Year to date, we've raised over CAD 7 billion of long-term capital on very attractive terms. As you can see from the table on the left, we've continued to bolster the balance sheet, raising almost CAD 3 billion of equity-equivalent capital so far this year through our DRIP programs, equity issuances by SEP, hybrid securities offerings, and through the equity generated on asset monetizations -- including the sale of our stake in the Olympic refined products pipeline for about CAD 200 million, which we announced today.

We've also successfully raised over CAD 5 billion of term debt in both the U.S. and Canadian markets across a range of maturities, the bulk of which has been used to refinance existing or maturing debt at very favorable rates. A portion of the proceeds of these offerings was used to fund a successful tender offer for a little over CAD 1 billion of outstanding Spectra Energy Capital term debt. The objective with the tender was to reduce longer term running cost of debt by taking out a higher coupon debt at lower rates. It was also a first step in eliminating Spectra Capital as an issuing entity, simplifying our funding structure and eliminating a layer of structural subordination -- all with a view to lowering the cost of capital of the merged company going forward.

With the funding actions we have undertaken so far this year, we have taken a significant bite out of the total remaining financing requirement for the company's currently secured growth program. The graph on the right provides a high-level sources and uses perspective from 2017 through 2019. The slide really hasn't changed from the one we showed at our mid-year investor conference in June, other than to more clearly show the funding progress we have already made. While there have been a few puts and takes to our capital spending over this timeframe, the overall funding requirement through 2019 does not change materially.

And a few things to reiterate here. Firstly, a very significant component of the funding for our secured growth program as it currently stands will be provided by internally generated cash flow, which continues to grow significantly over our planning horizon as new projects come into service. Secondly, most of the planned term debt funding over the next three years is for refinancing of existing debt and does not represent incremental leverage or strain on the balance sheet. Appetite for our debt securities continues to be very strong, and we've taken advantage of a receptive market to raise a significant chunk of our three year requirement early in the cycle at attractive rates.

As I mentioned, we have also already made good inroads on the equity side. We believe that the remainder of the equity funding requirement to support our current secured growth program can be readily raised over the next 2.5 years or so through a variety of alternative sources other than follow-on equity offerings. It's important to keep in mind that a lot of the growth projects are being undertaken in SEP and the Fund Group, which have already access to cost effective capital in their own right.

We continue to keep a close eye on our balance sheet and liquidity as we execute on the existing secured growth program. And as we've been saying, if new material investment opportunities come along, over and above those currently secured, we will proactively address any incremental funding requirements at the time of or in advance of any announcement. Our goal remains to stay ahead of our funding requirements and to continue to bring down consolidated leverage as the capital program is executed and assets come into service.

That's all I have today, and I'll now hand it back to Al for some closing remarks.

All right, thanks, John. We're midway through the year here and obviously had a very busy time so far in the first half, so let me just recap. In February, we closed the very large acquisition, the largest actually ever completed in our sector, in just under six months. Three weeks post close, we had our new organization in place - top to bottom. Integration is progressing well, and we're delivering on the targeted synergies, as John mentioned. On June 1, we topped up the dividend -- increased to 15%, which demonstrates the confidence we have in the overall outlook and in particular, the Spectra deal.

We further bolstered the financial strength and flexibility. Three actions to note here. It began last year, actually, when we pre-funded a portion of our equity needs for the capital program. We structured the Spectra transaction as an all-share deal, and we committed to an asset monetization program of CAD 2 billion, which as John noted, we've now got CAD 2.5 billion in - and we've achieved that ahead of schedule.

In line with our objective to streamline, we've simplified DCP, MEP was bought back in, and we completed our restructuring of EEP. And John went through the results for the quarter, which I think were strong for these sponsored vehicles and we're happy with that.

And lastly, we've provided our first mid-year update post Spectra transaction. I think the key strategic themes we noted at that meeting, where we introduced three real themes -- organic growth, managing risk and streamlining -- those are all coming through clearly. We also have, by the way, a full investor update planned for December where we'll roll out the longer term outlook. We're pleased with the progress so far in the year, and we'll remain focused on executing the plan.

Just before the Q&A, let me just wrap up with Slide 20 on the key takeaways. First, this quarter, despite the volume disruptions we saw in the liquid system, we're on track to meet guidance with a strong back half of the year. On the project execution side, we're now proceeding with Line 3. That's the work in Canada and Wisconsin this summer. The rest of the project inventory is moving along well, and we're making great progress adding new projects to organic program, as you saw. We've also wrapped up a lot of work to make sure the sponsored vehicles are strong and positioned for success going forward.

So with that, that ends the formal remarks. I'll now turn it over to Saeed for the Q&A session.

(Operator Instructions) Our first question comes from Ben Pham from BMO.

I had a question on your guidance and directionally, and it seems like your commentary about the uptick in second half suggests at least you'll hit the lower end of your range. But when you think about what happened in Q1 seasonality and Q2 with unexpected supply disruptions: are you potentially leaning more towards the bottom of your guidance range than at top end, or is there some potential upside surprises that you didn't see coming heading into the year?

As you know, Ben, we don't really specify upper and lower ends, unless we see something that gives us pause, or I guess positive on the other side. So right now, I think we're happy keeping with the range, which I guess implies the midpoint. We're not making any changes to that. I think the items that we mentioned earlier on around the volume profile, the FX positives, give us a good confidence around what's going to happen in the second half, along with the synergies accumulating from the Spectra deal. So I think overall we're still pretty comfortable with the guidance range that we've noted.

Okay, that's helpful. And then my second question is on the mainline volumes specifically, and you've -- also year-over-year results are, in terms of the volumes, have moved up just last year. Can you quantify the volume impact from Syncrude at all on the results, and was there anything to do with storage draws during the quarter that mitigated some of the impact?

For the average for the quarter, the volume impact was 115,000 barrels per day. So that's the average for the 90 days. Can I confirm that with you, Guy?

Yes, that would be the sum of the Syncrude and the hydrotest and some other production-related issues.

Okay. So a normal run rate for Q2 now is heading more toward 2.6 then.

Yes, we're ready to take in excess of 2.7 million barrels a day with all the initiatives we've put into place. We're seeing a bit of strengthening in July and further strengthening in August, so the outlook seems favorable.

Our next question comes from Rob Hope from Scotiabank.

Regarding Line 3 replacement. If Minnesota is further delayed, or the Canadian sections are completed earlier than you anticipate, is there the potential that you could realize some of the capacity uplift of the L3R project through some of the optimizations that you've noted, including DRA and BEP, prior to Minnesota being done?

Rob, I think the way to look at that is that the capacity will be restored once the full line gets replaced. So I think that's the assumption that you should use.

All right, that's helpful. And then just another question on Line 3. Regarding your commentary on the project economics being maintained with the higher capital cost, does this also include a volume uplift from DRA and BEP, or would that further improve estimated margins once the project enters service?

That'd be a further improvement, so the base economics don't assume that.

Our next question comes from Jeremy Tonet from JPMorgan.

Just wanted to touch base on North Dakota and see what you thought the impacts would be with Dakota Access Pipeline entering service on the rest of your system, given that's such a large draw relative to production there.

This is Guy Jarvis. Things to this point in time are playing out pretty much as we had expected. Our legacy North Dakota mainline that delivers over to the broader mainline system in Clearbrook has extremely competitive tolls. So our expectation was that we aren't going to see much volume erosion on that system at all, and in fact, it has continued to operate pretty much at capacity.

On our Bakken Pipeline expansion, where we bring the barrels back up into Canada into the mainline at Cromer, we have about 100,000 barrels a day of take or pay contracts, and we're seeing the volumes run very close to that level. We have seen some of the spot barrel opportunity on that pipeline taper off, but that was pretty much as expected.

And you mentioned as far as potential future expansions for the mainline, idling BEP could add 100,000 barrels per day. Would that be for light service or for heavy? Could you talk a little bit more about how that interplay would work and given that you do have these MBC contracts?

We'd have to negotiate an arrangement with our customers, obviously, in terms of the potential implications on those shippers. Our goal would be to optimize the crude slates on the system to try and turn that 100,000 barrels a day of light capacity into a heavy opportunity.

And then just one last one. I was just wondering if you could refresh us. If PMX and the Keystone XL both come online, could you walk us through how that would impact the mainline system if there's competition for barrels there as far as the impact on your profitability?

Certainly. We're looking at that very closely. I think at this stage of the game, there's nothing new to report from our mid-year investor update where our analysis of looking out in that 2021 -- 2022 period, when you contemplate possibly having two competing pipelines in play, suggests that the impact to our overall Liquids Pipelines business of that situation is likely to be small. And certainly when you consider it in the broader context of Enbridge overall, it gets even smaller.

I think one of the things that gives us confidence in that is just given the nature of the system here on the mainline, obviously with the scale of the system, our tolls are very competitive. So, in terms of attracting spot barrels, we would see us as being extremely competitive. And the other part of it is -- a lot of those refiners in that U.S. Midwest and Gulf Coast area like the diet, if you will, of what we're moving. And we're directly connected to in total of about 1.9 million barrels per day of actual refining capacity. So from a number of perspectives, including the fact that we've got some upstream and downstream take or pay commitments which would draw barrels on the mainline, I think we're in decent position, even in a two new pipeline scenario.

Would it be fair to say with the CTS expiration 2021, that would allow you to even address the situation at that point as well?

For sure. If you look at our options here in a scenario where we are impacted, I guess if you will, I guess we've just gone through, we don't think that's going to be material. But certainly, renegotiation of the CTS is probably a very good value add we think for the customers in that it's worked well for long time, and extending that into the future would make a lot of sense and generate value, at least in our view. That's probably the primary option. But obviously reverting to cost of service arrangement, which has been done in the past, would also be an option as is contracting portions of the mainline. So, we've got a lot of flexibility, as Guy alluded to, all of which gives us pretty good confidence that we shouldn't see a significant impact.

Our next question comes from Andrew Kuske from Credit Suisse.

Maybe this question's a little bit reminiscent of the Line 3 call in I think 14, but given you just did the hydrotest on Line 5 and you've had pretty impressive pressures through the line, could you just talk about the overall pipe portfolio and just your confidence in the existing assets in the ground, and compare that with just the vintage of L3R and what's going on there? Or the original Line 3, that is.

Andrew, it's Guy. I think we're highly confident in the entire network throughout our system. I think you referenced Line 5. All the work that's gone on there recently has validated our views on its ability to continue operate well into the future. We're looking at every segment of every pipeline and have a high degree of confidence in all of it. Clearly, Line 3 historically has been the one that required the most investment. And along with that investment came the disruption with our landowners as we continued to do an integrity digs and other maintenance and whatnot. In that case, it was an issue of the best economic outcome is to replace the entire line. We don't have anything else in our line of sight right now that would suggest we would need to be replacing any of our other lines.

I think it's a good observation, though, Andrew. It'd be back since 2010, and you were aware of this, the amount of capital, maintenance capital we've put into the system has been very significant. That's been intentional. And obviously we want to be conservative on this front. As to the vintages, and if you think back, we replaced Line 6b, Line 3 is being replaced. Alberta Clipper is a brand new pipeline just about. Line 4 is not that old. So we're pretty happy overall with the overall portfolio of the vintages, I guess, if you want to look at it that way.

And then maybe more specifically, just on the L3R program, and we think about replacing that line and starting the construction in Canada this summer. How much will integrity capital effectively fall off as you replace the old pipe, which clearly had some issues, with the brand new pipe?

I think, Andrew, going back to, again, the time that we announced the deal, I think the numbers that we had publicly stated at the time was we believed we would avoid approximately $2 billion of ongoing integrity costs on the existing Line 3.

That was a factor in the commercial arrangement that we had with the shippers, so that entered into the equation for sure.

Great, thank you.

I should just add here, not to extend this one too long. But that's part of our view to this, to the benefits of the replacement. If you think about the integrity program that would otherwise go on for a number of years, it would obviously be disruptive in absence of the replacement of the line. So that has some benefits we believe to communities as well in terms of minimizing ongoing disruption from maintenance activities.

Our next question comes from Linda Ezergailis from TD Securities.

With respect to your updated Line 3 replacement costs, I'm wondering if you can give us a sense of how much is locked in either through already procured parts versus maybe some hedging put in place for FX, et cetera. And of the component that is not locked down, can you describe the nature of it, whether it's labor, steel, or something else?

Maybe we'll get Guy to talk about the percent that's locked in and then, I don't know John if you want to comment on FX.

Linda, at this stage of the game, we're really very confident in the estimate that we've now got out of there. We have strong visibility into the pipeline contracting market, particularly in Canada now that we're beginning. As you mentioned, a significant level of pipe and other materials have already been procured, and the project is pretty much fully complete from a detailed engineering perspective. We feel very good with where we're at. I think the one final area that will require some fine tuning, but obviously the estimate reflects our best outlook, is ultimately locking down the construction contracts for the segments in the U.S.

I think on the FX side, Linda, both in terms of input costs, we look at that to the extent there's FX exposure until, and those are part of the program. And then obviously in terms of the overall hedging of our liquids mainline system, it's part of that program. It's taken into account as part of that program. So to some measure, both inflows and outflows have been hedged.

That's helpful context. Now just as a follow up more broadly of your CAD 31 billion of secured projects, obviously there's some already in service, and notionally I would expect the recently secured ones, the cost estimates would not be as locked down and secured as ones already well underway. But can you give us a sense of what percentage of that is locked down, realizing that obviously scope changes, et cetera, might change that a bit?

We'd have to probably go back and dig that up for you, Linda. I think generally speaking, it's really driven by the degree of engineering and design. And I think I would say -- I'll ask Bill to comment too on the gas ones -- I would say that generally we're pretty well advanced on all of these projects. They've been in the hopper for quite a while. So really, there's probably some negotiating to be done, as Guy alluded to, in the U.S, but generally speaking, we've advanced the design on these by a long way. NEXUS would be probably a good example. But Bill, you can maybe comment on the gas side.

I think you actually characterized it well. The near-term projects, you have a lot more locked down and a lot more certainty in those numbers, and then the further out you go, the more likelihood of variability. I think from the gas perspective, we also had some mitigation in place on a number of these projects, Linda, that would include anything from roll in or negotiations with customers where we've got some sort of adjustment to the rate of capital if capital changes.

Linda, maybe just a couple of examples here as I scan the list again. If you look at the offshore wind projects, for example Rampion and Hohe See, that's a fair chunk of capital. And those are pretty much fully locked down on cost side, so there's a few examples like that. It varies by project, but generally, we're not as fussed by the cost estimates, I would say, at this point on most of the projects.

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

I'm just wondering, coming back to Line 3 or L3R, if Minnesota denies or significantly delays, I'm just wondering, do you have an agreement cap to either directly recover the costs in a surcharge or indirectly maybe them not objecting to the inclusion rate base?

Maybe let me put some context behind this one first, Robert, so that you get a feel for how we've gone through the decision making around this. It really comes down I think to the confidence that we have in the Minnesota approval process here. As I alluded to earlier, if you look at Line 3, it really is a critical infrastructure. And it's no different than how people look at roads or airports or rail and refineries, and so the project needs to get done. It's critical infrastructure, and it's in everybody's interest that it moves forward. The regulatory process as well, and I think we have pretty good transparency into.

The base case for us is that we've got a good degree of confidence in the need for the line. Everybody seems to agree with that generally. We've got good transparency. And if you look at the project itself, using existing corridors and the approach that we've used in communities, I think the real answer to the question is that we've got pretty good confidence in Minnesota approval. We do have some commercial underpinning that gives us confidence that we would be able to recover costs. Obviously we're not going to get into the details of that here, but we're pretty confident in recovery.

If I can maybe turn to funding, just a couple questions here. You previously discussed up to CAD 5 billion to CAD 6 billion of additional potential asset sales. I'm just wondering if there's any thoughts on executing on that 2017. And then the other one, just in terms of the equity in the buckets, I'm just wondering from a hybrid perspective, how does the bucket account for only 50% of equity credit from the rating agencies, or is it just hybrids falling into that CAD 8 billion equity slice?

Let me start, and then I'll get John to talk about the buckets there. First of all in the CAD 5 billion to CAD 6 billion, I think we've talked about that number in the context of -- obviously with a very much larger asset base now, it always makes sense to review that asset base to see if there's some opportunities to generate some value in excess of our hold values. So that's the real driver there. Certainly the other part of that, though, is having an additional suite of potential optimizations that might help us to minimize equity requirements otherwise would make sense if that value's there. We use that as a bit of a buffer, or as one of the potential tools in the inventory, to address overall equity needs. So it's a bit of a toggle, I guess, depending on where we are and what we see in value for those opportunities.

We've got a circle around some potential things that we'd look at. I wouldn't say we're in any panic to execute that in 2017, but it'll depend where we are on other sources of capital.

Robert, it's John. On the hybrid side, we would look at those hybrid securities, the ones that we're contemplating issuing, at generating about 50% equity credit. So when we look at the amount of capacity that we have out there in terms of the nominal dollars that we might be able to issue of hybrid securities preferred shares -- I would lump those into the same category -- we would give it a 50% weighting in terms of their equity equivalency, if you like. And that's based on the treatment that the bulk of the rating agencies would give us.

Right, but I'm just looking at the chart from the CAD 3 billion of equity completed. Are the hybrids going into that one-for-one now?

No, the hybrids are going in at a 50% weight.

And the other 50 is going in the debt side?

Correct.

Our next question comes from Robert Catellier from CIBC Capital Markets.

I was also going to ask the monetization question. You've clearly exceeded your original target, but you've also added to the secured product base, and some of your capital estimates are up. I was wondering how much more you might contemplate. And you've addressed that in your previous response, but maybe you can speak to which segments are presenting the best opportunities for monetization?

Let me just first say, I don't think we have any assets that at this point where we feel like: boy, we need to deal with something because it's weak. It's really a question of, as I said earlier, where can we see value in excess of what we're holding that asset at. So that is really -- I'm not trying to be fuzzy about this, but the reality is it really depends on what kind of opportunities we see for the assets. Certainly, the core -- Bill's core gas transmission side of the business, the utilities which we have, we're very pleased with now -- Guy's core mainline systems and the related upstream and downstream pipes, those aren't going anywhere. Really, it would have to be something that's more at the margin in any of those categories that we don't see a lot of growth in. So there's a few odds and sods. There's always possibility, I suppose, of doing some kind of -- having an external investor come in for certain pieces. But that's not something that we have a lot of priority on right now at the moment anyway. It really depends on the situation and where we see value coming at us in the future here. So that's how I would put it, Rob.

Okay. And just on Line 3, and specifically on the timing. I assume your guidance about the second half of 2019 for an in-service date includes whatever you've learned from some of the comments that were filed on the draft EIS. Just maybe you can comment on that. I'm asking if there's any incremental risk that you see as a result of some of the comments on the EIS.

We don't believe so. Our take on the EIS is that it's going to be issued here in the upcoming quarter. We believe that the Department of Commerce and the agencies that have been involved in preparing it are confident that it's going to meet the adequacy tests of the Public Utilities Commission. And that all of that is going to be able to take place and be prosecuted in a matter that preserves the existing schedule that is out there with the ALJ, which would have a recommendation in February of next year.

I think it's a good question. Maybe I'll just add though, Rob, is there has been a lot of work so far through the consultation process with communities, whether it's Native American communities, indigenous tribes in Canada and so forth, around identifying issues that are of concern. And a lot of times, frankly, we get very good input and advice from local communities on things that we could do better. So we've already made a lot of changes to the routing or particular aspects of construction that have addressed concerns. At this point, and especially given the draft EIS that Guy talked about, I think we're in reasonable shape there.

Our next question comes from Praneeth Satish from Wells Fargo.

Just on the CTS renewal discussions. Is there any insight you can provide on how much of the capacity could ultimately be firmed up with take or pay contracts? Is there a target you have in mind?

No, we don't have a target in mind, and we really don't have an estimate. I think until we get down the road of actually having something that we put out to the market to consider, it's really hard to gauge. We do know that what we're hearing from some of our customers is that they want priority access on our system, and they're willing to enter into contractual agreements to get that priority access. So, we're evaluating how we could make that work, and how that would manifest in terms of tolling in either a full contract scenario or in a scenario where we've got a mix of contracts and other tolling mechanisms.

I think your initial reference was the CTS renegotiation. And just for clarity, the mechanism there that protects us is a floor. And that's something that we would have to consider what the right floor level is for any renegotiation of CTS that would provide the protection, given that the volumes out of the basin now are considerably higher than what they were when we entered the original CTS arrangement back in 2011.

One of the options you've listed to potentially increase mainline takeaway is I believe a reversal of Southern Lights. I would have imagined that pipeline is pretty heavily utilized right now. So I guess I'm just wondering how you balance there the need for crude takeaway out of Canada versus the need to bring diluent into Canada.

I think I would address it in two manners. First off, we're always watching the fundamentals: natural gas and NGLs in Western Canada and what that outlook, what might lead to in terms of local availability of diluent products. So that's one angle of what we're always looking at. I think the second angle of it then becomes optimizing the value of pipeline transportation. If we run into an environment where that pipeline is more evaluable to the industry in oil service, then we think we would probably be looking to put it into oil service as opposed to condensate. So it's really an option that's out there for ourselves and for industry.

Our next question comes from Vikram Bagri from Citi.

Couple of questions on your pipeline to Cromer. Can you provide more color on how your discussions are going on with the existing shippers, timing of idling the pipeline, and if you could reverse the flow longer term? In terms of timing, would you look to idle the pipeline in first quarter of next year when MBC's on DAPL full ramp up?

I think going back to my comment earlier about that plan, really what we're focused there is on trying to allow that plan to create more ability to move heavy barrels on our system. Our ability to do that is limited until the Line 3 replacement project is complete. So we really don't see this happening prior to Line 3 being replaced.

Okay. It sounds like if -- the line to Clearbrook is mostly full right now. And if you idle the Cromer pipeline, those 100,000 barrels will flow on Clearbrook line ultimately. So to accommodate the line to Clearbrook, those 100,000 barrels, the total combined barrels on these two pipelines have to drop by 100,000 barrels a day. Is that the expectation longer term -- that the spot volumes on these two pipelines combined will drop by about 100,000, 150,000 barrels a day?

I think in theory you're probably correct, but I think the important point to understand is that if we take those barrels off of the Bakken Pipeline, there's going to be other revenue that's coming to the organization to offset that revenue loss. In terms of what happens to those barrels and where they go in North Dakota, ourselves, we'll be working with the customers to figure out what path they want to take for those incremental barrels, or they may seek to find their own outlets.

One last one, if I may. And I apologize if I missed this. The exercise of EEP's option on the mainline series of projects, can it be done before Line 3 comes online? Or can you structure it in a way that EEP's exercise is part of the option before Line 3 comes online and maybe Southern Access phase 3 gets exercise later on?

I think clearly we could consider that with EEP in terms of exercising the option before it comes into service, but I don't think there's really any value to EEP in terms of doing that. It would seem to make more sense for them to exercise the option at the times when the cash flows are coming in the door.

We have reached our time limit and are not able to take any further questions at this time. I will now turn the conference call over to Mr. Jonathan Gould for final remarks.

Thank you, Saeed. I tried to squeeze a lot in there. Went a bit overtime. But as always, our IR team will be available right away to take any additional follow-up questions that folks may have. As a reminder, contacts there are myself for Enbridge Inc., Adam McKnight for Enbridge Income Fund and Enbridge Energy Partners, and Roni Cappadonna for all Spectra Energy Partner follow ups. Thank you, everyone, for your time and interest in the Enbridge companies, and have a great day.

Ladies and gentlemen, thank you for participating in today's conference. This concludes our program. You may now disconnect and have a wonderful day.