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.

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 midyear progress report on 2017 priorities. So 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 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 hydro test 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 team's work just finishing up on their planned terminal and crude slate modifications that will further optimize Mainline…

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…

All right. Thanks, John. We're midway through the year here and we 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 increase to 15%, which demonstrates the confidence we have in the overall outlook and, in particular, the Spectra deal. We've further bolstered the financial strength and flexibility. Three actions to note here, began last year, actually, when we prefunded 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 $2 billion, which as John noted, we've now got $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 provided our first midyear 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. 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. Andrew Kuske - Credit Suisse Securities (Canada), Inc: 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. Andrew Kuske - Credit Suisse Securities (Canada), Inc: 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. Andrew Kuske - Credit Suisse Securities (Canada), Inc: 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. Andrew Kuske - Credit Suisse Securities (Canada), Inc: 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.