Jonathan Gould - Enbridge, Inc. Albert Monaco - Enbridge, Inc. John K. Whelen - Enbridge, Inc. D. Guy Jarvis - Enbridge, Inc. William T. Yardley - Enbridge, Inc..

Ben Pham - BMO Capital Markets (Canada) Robert Hope - Scotiabank Jeremy Bryan Tonet - JPMorgan Andrew Kuske - Credit Suisse Securities (Canada), Inc Linda Ezergailis - TD Securities, Inc.

Robert Kwan - RBC Capital Markets Robert Catellier - CIBC Capital Markets Praneeth Satish - Wells Fargo Securities LLC Vikram Bagri - Citigroup Global Markets, Inc..

Good day, ladies and gentlemen, and welcome to the Enbridge Inc., Enbridge Income Fund Holding, Enbridge Energy Partners and Spectra Energy Partners Second Quarter Financial Results Conference Call. My name is Sayeed, and I will be your operator for today's call. At this time, all participants are in listen-only mode.

Later, we'll conduct a question-and-answer session for the investment community. 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, Sayeed. 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 and Midstream.

Our joint call will include discussion for all of the Enbridge entities, including Enbridge Inc., Enbridge Income Fund, 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 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 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're 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 forecast, 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 SEDAR and EDGAR systems. So, with that, I will now turn the call over to Al Monaco..

the $1 billion T-South expansion and the $500 million Spruce Ridge projects, all expansions to the BC system. These two further solidify 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 of the 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 $2.1 billion.

That project is nicely accretive and provides solid returns under 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 is 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 businesses need to deliver good operational 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 of 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 could also be opportunities to supplement that with drop-downs of 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..

Hey. Well, 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 Spectrum 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 Liquid Pipelines, where adjusted EBIT was up about $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 $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 a 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 the line to Gas Pipelines and Processing, quarter-over-quarter adjusted EBIT was up sharply as a result of the 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 $80 million, largely due to a full quarters quarter's contribution from Union Gas, which benefited from higher transportation revenue as a result of the Dawn-Parkway expansion project coming into service. EBIT from 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 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.

So 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 two 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 were typically disproportionately strong. As a result, we will 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 the 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 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 slide 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 (22:01) 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 will 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 costs out of both an 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 $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 in the earnings at ENF of about $77 million, which reflected ENF's larger ownership interest in the Fund, following the second – 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 $1.5 billion of new growth capital projects come 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 $1.9 billion and $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, 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, SEPs' quarterly distribution now sits at $0.714 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 coverage of between 1.05 times and 1.15 times.

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've 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 costs containment and the absence of the hydro testing 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 asset, 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 Pipelines business.

Distribution coverage was solid this quarter, as you would expect following the restructuring, just over 1.4 times on a cash basis and 1.14 times including 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 and processing business had been sold at the beginning of the year.

With a 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 $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 $3 billion of equity equivalent capital so far this year through our DRIP programs, equity issuances as by SEP, hybrid securities offerings, and through the equity generated on asset monetizations, including the sale of our stake in the Olympic refined pipelines – refined products pipeline for about $200 million, which we announced today.

We've also successfully raised over $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 $1 billion of outstanding Spectra Energy Capital term debt. The objective of the tender was to reduce longer-term running cost of debt by taking out 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 midyear 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 ready 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. So, that's all I have today and I'll now hand it back to Al for some closing remarks..

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. So, 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 liquids 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 our 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 Sayeed for the Q&A session..

Thank you, sir. We'll now begin the question-and-answer session. And our first question comes from Ben Pham from BMO. Your line is open. Please go ahead..

Okay. Thanks. Good morning..

Hello..

I had a question on your guidance 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, I mean, are you potentially leaning more towards the bottom end of your guidance range than the top end, or is there some potential upside surprises that you didn't see coming heading into the year?.

Well, 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 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 obviously year-over-year results are – in terms of the volumes have moved up just just issue (38:00) last year.

But 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?.

Yeah, 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?.

Yeah, that would be the sum of the Syncrude and the hydro test and some other production-related issues..

Okay.

So normal run rate for Q2 now is heading more towards 2.6 million barrels a day 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..

Okay. Great. Okay. Thanks, everybody..

Okay..

Thanks, Ben..

Thank you. And our next question comes from Rob Hope from Scotiabank. Your line is open. Please go ahead..

Yes. Thank you.

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?.

Hi, 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 and once the project to enters service?.

Yeah. That would be a further improvement. So, the base economics don't assume that..

All right. That's helpful. Thank you..

Okay..

Thank you. Our next question comes from Jeremy Tonet from JPMorgan. Your lines open. Please go ahead..

Just want to touch base on North Dakota and see if – 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?.

Yeah. This is this is Guy Jarvis. So 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 toll. So, our expectation was that we weren'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..

Great. And you mentioned as far as potential future expansions of the Mainline, idling BEP could add 100,000 barrels per day.

Would that be more 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 MVP (41:55) contracts?.

Yeah. Well, so 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..

Okay. Great.

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

Yeah. Certainly. So, we're looking at that very closely.

I think at this stage of the game, there's nothing new to report from our midyear Investor Update, where our analysis of looking out in that 2021-2022 period when you can 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 refineries 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 in 2021 that will kind of allow you to even address the situation at that point as well?.

For sure. I mean 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 a 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, though, all of which gives us pretty good confidence that we shouldn't see a significant impact..

That's helpful. That's it for me. Thank you..

Okay. Thanks..

Our next question comes from Andrew Kuske of Credit Suisse. Your line is open. Please go ahead..

Thank you. Good morning. Maybe this question is a little bit reminiscent of the Line 3 call in, I think, 2014.

But given you've just done the hydro test on Line 5 and you've had pretty impressive pressure 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..

Yeah. Andrew, it's Guy. I think we're highly confident in the entire network throughout our system. I think your referenced Line 5, all the work is going on there recently has validated our views on its ability to continue to 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 continue to do an integrity digs, and other maintenance, and whatnot. So, 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 (47:09) back since 2010 and you're 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. The Alberta Clipper is 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..

That's helpful.

And then maybe more specifically just on the L3R program, and when you 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 brand-new pipe?.

Yeah. 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 believe, we would avoid approximately $2 billion of ongoing integrity costs on the existing Line 3..

Okay. That's great. Thank you..

That was a factor in the commercial arrangement that we had with the shipper. So that was – that entered into the equation, for sure..

Great. Thank you..

And to just add here, not to extend this one too long. But that's part of our view too as 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 a replacement of the line.

So, that has some benefits, we believe, to communities as well in terms of minimizing ongoing disruption from maintenance activities..

Thank you. Our next question comes from Linda Ezergailis from TD Securities. Your line is open. Please go ahead..

Thank you.

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?.

So, maybe we'll get Guy to talk about the percentage 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. So, 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..

That's helpful..

I think, on the FX side, Linda, both in terms of input costs, we look at that to the extent there's FX exposure entailed 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 $31 billion of secured projects, obviously, there's some already in service and, notionally, I'd 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?.

Well, we 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 a 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. I mean, NEXUS would be probably a good example. But Bill you can maybe comment on the gas side..

Yeah. Well, I think, you actually characterized it well. The near-term projects you have a lot more lock 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 have 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..

Yeah. And 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, it'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 sort of 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..

That's helpful context. Thank you..

Okay. Thank you..

Thank you. Our next question comes from Robert Kwan from RBC Capital Markets. Your line is open. Please go ahead..

Good morning.

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

Yeah. Well, 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. So, it really comes down, I think, to the confidence that we have in the Minnesota approval process here.

And so, 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.

So, the regulatory process as well, I think, we have pretty good transparency into. So, 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 and commuted, 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 cost.

Obviously, we're not going to get into the details of that here, but we're pretty confident in recovery..

Okay. That's great. If I can maybe turn to funding, just a couple questions here. You previously discussed up to $5 billion to $6 billion of additional potential asset sales. I'm just wondering if there's any thoughts on executing on that in 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 $8 billion equities slice?.

Let me start and then I'll get John talk about the buckets there.

First of all, on the $5 billion to $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 value. 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. So, we kind of 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. So, 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..

Hey, 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 sort of 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 $3 billion of equity completed.

Are the hybrids going into that one for one though?.

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

And the other 50% is going in the debt side?.

Correct..

Okay. That's great. Thank you..

Yeah..

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

Hi. Good morning. I was also going to ask the monetization question. You've clearly exceeded your original target, but you've also added to the secured project base and some of your capital estimates are up.

So, I was wondering how much more you might contemplate? And you've sort of addressed that in your previous response, but maybe you can speak to which segments are presenting the best opportunities for monetization?.

Well, I would say – 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, and 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. I mean, 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.

So, 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. So, 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, and yeah, just maybe you can comment on that..

Yeah. We're obviously....

So, in other words, I'm asking if there's any incremental risk that you see as a result of some of the comments on 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 test of the Public Utilities Commission.

And that all of that's going to be able to take place and be prosecuted in a manner 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.

And so, at this point, especially given the Draft EIS, that Guy talked about, I think, we're in reasonable shape there..

Okay. Thank you..

Okay..

Thank you. Our next question comes from Praneeth Satish from Wells Fargo..

Good morning.

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? I guess, 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'll 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 arrangements 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 full contract scenario or in a scenario where we've got a mix of contracts and other tolling mechanisms..

Yeah. And 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 that 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..

Got it. And one of the options you've listed to potentially increase Mainline takeaway is 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 their the need for crude takeaway out of Canada versus, I guess, the need to bring diluent into Canada..

Well, 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 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 there's an – if we run into an environment where that pipeline is more valuable 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..

Got it. Thank you..

Thank you. Our next question comes from Vikram Bagri from Citi. Your line is open. Please go ahead..

Good morning. A 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 MBCs (1:05:37) on DAPL are fully ramped up?.

Yeah. 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 L 3 Replacement project is complete. So, we really don't see this happening prior to Line 3 being replaced..

Okay. And it sounds like if – the line to Clearbrook is mostly full right now. And if I idle the Cromer pipeline those 100,000 barrels will flow on Clearbrook line ultimately. So if you 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.

So, is that the expectation longer term that the spot volumes on these two pipelines combined will dropped by about 100,000 barrels, 150,000 barrels a day..

Well, I think, in theory, you're probably correct, but I think the important point to understand is that if we take those barrels off at 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..

Great. And 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? Can you structure it in a way that EEP exercises part of the option before Line 3 comes online and maybe Southern Access Phase 3 gets exercised later on?.

Yeah..

Go ahead..

Yeah. So, 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 is 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..

Great. Thank you. That's all I have..

Thank you. 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..

All right. Thank you, Sayeed. Tried to squeeze a lot in there, went a bit over time. But as always, our IR team will be available right away to take any additional follow-up questions that folks may have.

So, 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 Partners follow-ups. So, 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..