Welcome to the Enbridge, Incorporated, Enbridge Income Fund Holdings, Enbridge Energy Partners and Spectra Energy Partners' Third Quarter 2018 Financial Results Conference Call. My name is Carmen, and I will be your operator for today's call. At this time, all participants are in a listen-only mode. Following the presentation, we will conduct a question-and-answer session for the investment community. Please note that this conference is being recorded. I will now turn the call over to Jonathan Gould, Director, Investor Relations. Jonathan, you may begin.

Great. Thank you, Carmen. Good morning,, and welcome to the Enbridge, Inc. and sponsored vehicle joint Q3 2018 earnings call. With me this morning are Al Monaco, President and CEO of Enbridge, Inc.; John Whelen, Chief Financial Officer; Guy Jarvis, President -Liquids Pipelines and Bill Yardley, President- Gas Transmission and Midstream. Our joint call will again include discussion for all of the Enbridge entities in order to provide an enterprise wide strategic, and financial perspective. As per usual, this call is webcast and I encourage those listening on the phone to follow along on line 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 Q&A, given the broad agenda and limited time available, we will prioritize call from the investment community only. If you're a member of the media, please direct your inquiries to our communications team who'll be happy to respond immediately. We're again going to target keeping the call to roughly one hour, and may not be able to get to everybody. So, please limit your questions to one and a follow-up if necessary. But as always, we will ensure that our Investor Relations team is available for your more detailed follow-up questions afterwards. Before we begin, I'll point out that we'll refer to forward-looking information on today's call. 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. Slide 2 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'll now turn the call over to Al Monaco.

Good morning. As you saw from our release today, we had another strong quarter. What I'll do this morning is highlight the progress on key priorities. The Q3 numbers and how the year is shaping up, and then a business update. John will then take you through the results in more detail including the funding status. Before that, a comment on the recent incident on our BC gas system. Most importantly, nobody was injured, our response was immediate here and we worked closely with communities to make sure all were safe. We quickly brought back a portion of capacity and repairs on the impacted segment were just completed yesterday. We're also doing assessments to bring the system safely back up to full pressure and working with the National Energy Board on that. And of course, our priority now is to work with our customers to minimize disruption. So turning to slide four, a recap on the progress we're making on the key priorities we laid out at Enbridge Day. In short excellent headway and we're ahead of schedule. The first half of the year laid the groundwork with very strong operating and financial results, accelerating the timing and magnitude of deleveraging actions, moving quickly on simplification and executing well on the capital program. These early actions bore fruit in Q3, we've now received CAD 5.7 billion of asset sale proceeds with another CAD 1.8 billion expected in the first half of 2019, so that's CAD 7.5 billion in sales versus the original target of $3 billion. On that note, we've talked about these additional asset sales giving us a lot more financial flexibility, so there's a few important implications here. First, after repaying debt with a portion of these proceeds and with strong 2018 cash flows, our Q3 debt to…

Well, thanks, Al, and good morning everyone. I'll pick up here on slide 13 with a review of our financial performance for Q3, which was very strong on a quarter-over-quarter basis. As you can see, consolidated adjusted EBITDA was up about 14% or $372 million over the third quarter of last year. The increase was largely driven by the strong underlying operating performance of our base businesses, the impact of bringing new projects into service over the last year as well as ongoing realization of synergies from the Spectra acquisition and cost containment in general. So looking briefly at each of the businesses starting with liquids pipelines, our adjusted EBITDA was up a little over $280 million when compared to Q3 of last year driven by a few factors. Firstly, higher volumes, higher tolls and the impact of higher effective foreign exchange hedge rates on the Mainline system, where average deliveries ex-Gretna were up close to 85,000 barrels per day over the same period last year, driven by growing oil sands productions and enabled by the capacity optimization initiatives we've been undertaking on the system. Secondly, strong production in North Dakota which drove higher throughput on our Bakken systems, and finally higher contributions from our regional oil sands systems due in most part to the impact of new projects placed into service later in 2017. Moving down the slide, adjusted EBITDA from gas transmission in midstream was up $97 million. Here, the quarter-over-quarter growth was driven primarily by expansion projects placed into service in late 2017 as well as higher contracted volumes in Sabal Trail. In addition, the Aux Sable and DCP Midstream businesses both generated higher earnings on the back of higher volume throughput and higher commodity prices. Turning to gas distribution, adjusted EBITDA generated by our combined utilities…

Okay. Thanks, John. I'll just do a quick summary of what you heard today then. It's been another busy and successful quarter. The results came in nicely putting us in good position to finish in the upper half of the 2018 DCF/share guidance range. We're pleased with the progress on our priorities here, the size and speed of non-core asset sales has gotten us to a pure play pipeline utility model quickly and has accelerated deleveraging. We've met and exceeded our credit targets earlier than expected and now turned off the DRIP. We've advanced our streamlining objective with the sponsored vehicle buy-in agreements, we've put up strong operating and financial results. We continue to execute on projects including Line 3 permitting in Minnesota which will drive significant cash flow growth, and that underpins our 10% annual dividend growth outlook through 2020. It's a challenging equity market right now but we continue to focus on the things that we can control, namely delivering results and accomplishing our strategic priority, ultimately this will drive long-term value. Wrapping up on slide 21, just to remind everybody, our Annual Investor Conference is coming up on December 11 in New York and we'll be webcasting that live. And as we alluded to earlier, we'll roll out our new strategic plan, our business unit leads will talk about the drivers of growth going forward and will update our financial guidance and outlook. We look forward to seeing many of you there. So, with that let me hand it back over to the operator to open up the lines for Q&A.

Thank you. And we will now begin the question-and-answer session. Our first question comes from Jeremy Tonet with JPMorgan. Your line is open.

Good morning.

Hi, Jeremy.

Just wanted to start off with Canadian takeaway and if there was any thoughts as far as the apportionment process, any approvements that can be made there or any other thoughts? I know you guys have done some work there. And just when you go further downstream, all of this crudes hitting upper PADD II here and just wondering where you think it goes at that point? I mean, I think a Capline reversal would make a lot of sense to bring that down to the Gulf, but maybe the refiners in that area don't want that to happen. Just wondering if you could opine on that and how would that impact you guys?

Maybe we'll let Guy handle that one.

Yeah. So Jeremy, first on in terms of the apportionment process, you're right, we've been discussing our nomination in apportionment process for many months with our customers and we're continuing to do so. I think until those discussions have concluded, we're probably not going to get into any of the details of what's been examined at this time. Speaking more about market access, clearly once Line 3 comes into service end of – towards the end of next year, we're going to be in a situation where our system is really well balanced in terms of the capacity that we can provide and the market access that we can provide into PADD II into our downstream pipelines, Line 9, Southern Access Extension, Flanagan South. Clearly, as we've had more interest recently coming from shippers about the potential to do some of these staged expansions on the Mainline we have to look into the market access opportunities and many of our shippers are interested in potentially trying to get more barrels to the Gulf Coast. And I think it'll – whether it's something down Flanagan South or whether there is a potential Capline reversal if those partners find their way to that, I think our shippers are interested in both.

Jeremy maybe I'll just add, I think at this point of where we are with all the constraints you see not just out of Western Canada but other parts of North America, if you just look at the basis differentials. Obviously, we're going through a difficult time right now just given the massive supply growth that we see throughout North America. But I guess in the bigger picture, in Western Canada we'll see some new capacity coming on, I think other parts of North America as well. So I think looking out a couple years two, three years I think we see a more positive outlook. And given the competitive advantage that North America has in finding supply at very low cost including in the oil sands, I think once this clears up I think we'll be in much better shape and I think we've got to be patient through the next year or two here.

I guess on that point, real quick Southern Lights, it seems like there's a lot of demand to convert that into takeaway. How quickly could something like that be affected and you talked about CTS renegotiation there, just wondering, it seems like there's a lot of demand to incentivize you guys to optimize it and get as much out as possible. I mean, it seems like rates would be in a favorable position at this point given all that demand and maybe this gets done sooner rather than later, any thoughts you could share there?

Well, I think the thought I would share is, if we look at the fundamentals, we certainly think there's an opportunity for that to happen. We're stepping up our conversations both with our customers on that line and potential crude oil customers to try and sort through just whether in fact there's a commercial solution here that the shippers are interested in. So there's, certainly to your comment, there's interest and we're pursuing it.

On Southern Lights, I think that was the first part of your question. I think, Guy, we're in discussions already there with the customers that currently move product in the other direction, and it is a good opportunity. And this is the nature of the beast these days, looking at options to reverse and put incremental capacity, and so we're all over options like that.

Great, I'll stop there. Thank you for taking my question.

Okay.

Thank you. Our next question comes from Robert Catellier with CIBC Capital Markets. Your line is open.

Hi, good morning and thank you for the comments. I have a similar question to the last one. Obviously, the differential environment speaks to the demand for pipeline infrastructure, but it's quite an unusual time for the differentials, and I'm wondering how that environment impacts the negotiation process, and in particular, what your timing expectations might be for a renewal?

Yeah. Robert, it's Guy. We're not seeing the current situation having much impact on those discussions. The existing CTS runs through mid-2021, and I think there's a lot of expectation in the marketplace that by that time Line 3 is going to be in service. We know at least one of the competing pipelines is targeting to be in service by that time. So I think the producers and shippers on our system are sensing that by the time this new agreement goes into service that there's going to be some relief on that front.

Okay. That makes sense. And then I suspect my follow-up has the same answer, but we're hearing more about producer shut-ins in the short-term. So I'm wondering if you have any initial thoughts on 2019 volumes and I know it's a bit of a short-term question but how extensive do you think shut-ins can get from your customer group?

Well, I guess, it's Al here Robert. Tough for us to tell, certainly we've heard the same sort of rumblings. I think the other factor though other than just pure production is the amount of storage that's sitting there all over Western Canada that is really at extremely high levels. And so it's not just a matter of production, it's a matter of clearing out the amount of storage and we've seen that play out elsewhere in North America as well. So I would say, in terms of our system, the nature of it and where the discounts are, I don't see it affecting the volumes on our line certainly in any negative way. The reality is that every barrel wants to get out and the most ideal exit point in egress is on the Mainline system because of a number of factors including the markets it feeds and so forth, so I don't see it impacting our volumes going forward.

Okay. Thank you.

We're full and we expect to be full next year. That's sort of the bottom line I guess.

Great.

Okay.

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

Thank you. I know we'll get some fulsome updates at your upcoming Investor Day, but maybe you can just help us think about how you might consider further asset sales and what would be the most important criteria whether it be further strategic focusing your business or maybe financing additional growth opportunities whether it's pre-funding or in conjunction with any sort of new project announcements? And specifically, I'm thinking of DCP and how you're thinking of it and maybe a comment on other kind of less core current businesses would be appreciated.

Okay. Well, I guess maybe to the first part of the question, when you step back from it, we've got some, let's call it, non-core assets still in the house. Generally speaking though the last three big businesses are very core to us and we don't see anything happening there. The criteria, I think would be as they usually are, we've got a couple of these assets still in the hopper for potential sale and it's really going to depend at this point on the type of valuation that we see for those. I mean, we're in good shape from a balance sheet perspective, but certainly if we see good value coming our way which we have as you've seen throughout 2018 on some of the deals that we've done, I think that's probably the main one. Certainly, providing additional financial flexibility is always good for us especially when you can attract good values. We'd be very keen on putting away some more flexibility if the valuations are there, but I think overall, as John described, being in that 4.5% to 5% range gives us a lot of comfort already. But certainly we could build more if we see the right values. In terms of DCP, this is in the non-core asset category simply because the majority of the business is G&P related. I guess so, to be fair, they've done a very good job in transitioning their business to more fee-based component, more contracted capacity, great job on lowering costs. I think their NGL volumes and obviously the price outlook now are attractive, and they're in good basins. So, I think given the more than doubling of our asset sale targets that we had there's no immediate rush on this given where they are and the work they're doing. I think we demonstrated that we'll make good capital allocation decisions when we see good value and we'll continue to monitor that. In the meantime DCP is performing well and working well for us from a financial point of view.

Appreciate that context. And just as a follow-up, one of the biggest variables in my assumptions next year would be around the timeline of L3R and I've done my best. But I'm just wondering when we might get better clarity on tightening an in-service date of the second half of 2019. And what key factors should we be looking for in terms of where it falls in that range. Specifically, I'm wondering, for example, if you don't start to get everything you want in Q1 or might you miss some construction windows or are you going to give us an update I guess on Investor Day and I just need to sit tight?

Linda, it's Guy. I don't know if there's going to be a particular date or event out there that you can point to that will give any of us that further granularity that you're looking for. Clearly, our executive team is looking at a wide range of potential options and how you go faster or potentially go slower. We have proven historically, if you go back to the days of our construction of Alberta Clipper that you can execute these things quite quickly if you're well-planned and we think, we're going to be. So we're confident in that guidance to the second-half of next year based on our history and the planning that we're doing, but it's going to be very, very difficult to pin down a date any further.

I think, Guy has got that exactly right. I don't know if this helps or not, but and I think, we've talked about this before. Obviously, when we're looking at 2019 numbers, we need to make some assumption. We've assumed November 1, I guess maybe for simplicity, but that's the numbers that have been included within our outlook in 2019. So I guess that's the best we can do at this point.

Thank you.

Thank you. Our next question comes from Dennis Coleman with Bank of America Merrill Lynch. Your line is open.

Yeah. Great. Thanks for taking my call this morning. I guess – there has been a lot of good questions asked. On Line 3, is it all done now in terms of approvals and whatnot? No other hurdles or now it's just the planning stage?

Well, maybe Guy can chime in if I miss something here. But essentially, the key point of permitting we were looking for was the Written Order for the route and that came out last Friday. And what that allowed us to do is put in all the applications that are required at the state level, and those include water crossings, conventional things of that nature, easements, that kind of thing, all of that went in earlier this week. So really there's a timeline and process for that that's going to unfold here over the next quarter generally. And so that's how we see the next phase of major permitting work, if you will, after that, assuming all that goes well then we'll be able to get into the field and begin with the construction activities. So I don't know if that helps you, Dennis, anything to add on that, Guy?

Yeah, the only thing I would add Al is, there a rehearing process within the Minnesota Public Utilities Commission, but we're very confident in the strength of the PUC decision in terms of the thorough process they followed with a complete EIS on multiple routes, multiple opportunities for the public to participate through open houses and hearings, and written testimony, and then a lengthy hearing itself. So we feel confident that there's not going to be any issues with the PUC approval being upheld through rehearing.

One of the things that was alluded to was how we plan and [Technical Difficulty] (48:43) large scale projects, and obviously there's a very large team of professionals that know how to manage timelines and depending on when certain permits come in and a very robust way of moving and changing, depending on what happened. So I think that's the main point here is, we're very happy with the robust process we've got for being able to move depending on what happens permit timeline wise.

Perfect. Thanks for that, and maybe just a unrelated follow-up, if you can just maybe walk through the mechanics of the amalgamation process and is there a transaction closing, how does it all work? And when might we start to see the benefits of that come through the income statement?

You're talking about the utilities here right?

Yes. Yes, I am.

Okay. So I think the easiest way to think of it is, new rates will go into effect on January 1. So that's sort of the starting point for the amalgamated utilities operating as a single business. Between now and then, obviously we're doing a lot of planning around organization and cost structure and so forth. So basically we're on a runway, we've got the application approved. We'll do that planning and we'll be ready to operate as a combined business for those utilities as of January 1 with new rates in place.

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

Okay. Thanks, Dennis.

Thank you. Our next question comes from Ben Pham with BMO. Your line is open.

Okay, thanks. Good morning.

Good morning.

I had a question on the DRIP suspension and you've gone a long way in getting this decision through, have done a lot of work, scenario analysis. And so when you look at that cash flow, outflow, inflow next couple of years, I mean there's obviously the benefit on the share count, but then there's an outflow of cash. So, can you talk about what CapEx you can self-fund on the balance sheet? Is it still that $5 billion to $6 billion and then does that mean 6% self-funded growth, 8%, 10%, I think you talked about that before, I mean just some more context on that?

Ben, it's John. It's probably a little early to get into detail around that. We will have substantial capacity to self-fund, as you describe it, between internal cash flow and capacity on the balance sheet with those parameters that I talked about in my opening remarks. Order of magnitude is in and around that level that you described in terms of a fair amount of capacity to be able to invest in new organic projects and/or acquisitions going forward. So I don't think you're way out of line in terms of – in terms of the kind of balance sheet capacity we'd have, we'll spend more time on that probably as the Guy, Bill and our other business unit leaders go through the opportunities that they have out in front of them to build that plan up. Fair to say, a significant emerging balance sheet capacity with the actions that we've taken.

Okay. I think I'm getting kind of the $5 billion or with a little bit of hybrids in there. So I mean if you – the CapEx starts to rise in the future years, and then I guess we look to that that big spread there on that financial flexibility, hybrids, asset sales before external equity?

Yeah. I think you're talking about the chart that we're showing on page 19, and I think that's absolutely right. Aside from the range that John talked about we've got lots of potential buffer there for other options depending on what we're up to, but generally, as John said, I don't think you're too far out with your estimate.

Okay, all right. Thanks everybody.

Okay.

Thank you. Our next question comes from Robert Kwan with RBC Capital Markets.

Good morning. If I can maybe just follow on that leverage side and kind of the 4.5 and comfortable of 5.0 times, just to confirm kind of in that chart, does that only include EBITDA associated with projects that are already secured. And then in terms of reaching the consolidated debt that's inclusive of turning off the DRIP and doesn't have any additional funding per the bars on the left?

Yeah. That's right, Robert.

Okay. Perfect. If I can maybe just finish here then with the Mainline, a couple of questions. First, can you just talk about the common carrier system versus contracted and if you've got a preference or is it more about securing a volumetric floor as you discussed at the 2017 mid-year Investor Day. The other question being, the system has been highly apportioned and you've generally talked about it being full, you've moved, call it, roughly 2.6 million barrels a day ex-Gretna year-to-date. I guess if everything was running optimally, what do you see as the maximum volume to ex-Gretna. And are shippers asking you for additional operational tankage build up whether that's upstream or downstream. And could you roll that into a rate base?

Okay. I'm going to try and tackle those in order. First, when it comes to the Mainline contract, obviously we've demonstrated over the years there are numerous different ways to kind of provide protections against volume. So I don't think there's anything new there in terms of our incentive tolling agreement, CTS, the potential for contracting. I think all of those things are things that we talk to our customers about all the time. Certainly, there is a degree of interest in the contracting mechanism and what that could potentially look like on the Mainline. So that is something that we're evaluating in conjunction with the other options. But there's nothing definitive at this stage to put forth on that. Going to the next question, we are full. I think if you look back to, I think, kind of the fourth quarter of last year, our record throughput levels were I think close to 2.75 million barrels a day. That's a scenario where all the production is performing, the pipeline is performing and the refineries are all performing and that's really what it takes for us to get to those very high throughput. So we certainly think we can do that and potentially a little bit higher if all the other pieces of the puzzle come together. In terms of the operational storage, our operational storage is just that it's operational. So we might have an opportunity here and there to hold somebody's batch for a few days to help them manage through an operational issue, but we're not able to use that operational storage as a longer term inventory. And the timeline to build new tanks isn't really going to solve any of these higher volume issues that we're seeing right now either.

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

Thank you. Our next question comes from Tom Abrams with Morgan Stanley. Tom Abrams - Morgan Stanley & Co. LLC: Great. Thanks. I also want to ask a couple of questions about Line 3, a three part one, but as you complete it, is there a possibility that you, A, complete the section at Southern East of Clearbrook such that you can get more volume out of the Bakken for a quarter say before the rest of the line comes up. Secondly, what is your thought around when the pipe that runs currently from the Bakken through Line 3 up into Canada goes empty? And thirdly, you've already completed a lot of construction on the West side of that system, is there a possibility or a contemplation of dropping some volumes down through Empress – I'm sorry Express into the broad Wyoming area to try to get some relief over to Cushing on another pipe besides Platte?

Yeah. So to get to – again, I'll take these in order. We don't currently have any plans to kind of conduct a segmented start-up of Line 3 to deal with volumes coming in off of the North Dakota system at Clearbrook. A lot of those volumes actually don't even make it on to the Mainline system because they're getting consumed locally in that. So there is no plan around that. We've talked about this potential of ceasing the deliveries out of North Dakota to allow the Alberta barrels to flow long haul. It is still something we're working on. What we're finding is that just by the competitive nature of what's going on in North Dakota, those volumes are down currently and we're actually looking closely at that right now to see if there isn't something that we can do a little bit more near-term to seize on the fact that those volumes are down currently. When you look at the Express system, we do think that we might have an opportunity to get some incremental volume out of Express, we're working that through. The challenge we have with that is what do you do with the heavy barrel when it exits the Express system? And so we've got to do some work on the market access element of that as well, but they're underway and we're working on it, we just don't have the solution right now. Tom Abrams - Morgan Stanley & Co. LLC: Yeah, you may be committed to light. The other question I have is a financial one on the roll-ups or the buy-ins of the sponsored vehicles, you called out tax benefits and credit profile benefits. Are there numbers you can put around those two items?

I think on the tax side, we've talked about extending the non-taxable horizon at least out another two plus years. I think that's what we've typically talked about in terms of the benefits related to the buy-ins from various different components.

Yeah. I think as I recall that's applying to the U.S. tax position, so think of it as extending the zero tax position from 2020 onwards by another couple, three years. I think on the Canadian side as well with the ENF roll-up, that allow us to basically maintain the cash taxes we've got in Canada at the same level for a number of years, so that's the high level take on it. Tom Abrams - Morgan Stanley & Co. LLC: Excellent. All right. See you guys in a few weeks. Thank you.

Okay. Thank you.

Thank you. Our next question comes from Patrick Kenny with National Bank Financial.

Hey guys. Just on Line 3, do you see any risk at all around a new Governor coming into Minnesota, just as it relates to obtaining the outstanding permits in a timely fashion?

Well, it's Al, maybe I'll start with that. I guess maybe our view is that this project has been so extensively reviewed and through a very comprehensive regulatory process that took literally three years including an environmental impact statement. So I think there may be changes in government, but I think the bottom line is that this has been so robust that we don't see the basis for how that would change anything on Line 3 going forward. That's our point of view.

That's great. Thanks, Al. And then maybe for Guy, so after Line 3 is in service, can you just remind us how much capital would be required for that 275,000 barrels a day of incremental capacity beyond 2020? And whether or not you think shippers would underpin that capital, if we assume that KXL is under construction say this time next year.

Yeah. So again, coming back to – those first tranches of incremental Mainline capacity that we believe we can provide are very low capital. So when we look at them, our operating assumption is that we don't need to pursue any surcharges from our customers to support them. We can simply continue to collect our CTS toll or whatever the new tolling mechanism that will be in place beyond the current CTS is going to provide what we think is going to be a good solid return for Enbridge. So that's one of the beauties of those opportunities is the low cost and the fact that we don't need to pursue surcharges. I think to go to the second question in terms of customer support for them. We're going to have to see how that plays out. It's clearly going to be a function of their views of not just our capabilities but where these competing pipeline opportunities are at. And we'll just have to see how that plays out.

Sounds good. If I could seek in one last one here just to circle back on Robert's question around common carrier versus contracted structure on the Mainline. Do you have clarity at this point from regulators with respect to your ability to move towards a fully dedicated system or do you envision having to keep a significant portion un-contracted and open for the smaller producers that might not be able to sign 10 year plus contracts?

Yeah. We do know we're going to have to keep a portion – if we go down that path, you'll have to keep a portion of the system available for spot. In terms of the clarity around doing it, we have already demonstrated within Canada on the TMX system that there is an ability to have a hybrid system of contracts in spot capacity. And so we don't see any regulatory impediments to move in that direction if that's what we agree to with our shippers.

Great. Thanks Guy. Thanks Al.

Okay.

Thank you. Our next question comes from Joe Gemino with Morningstar.

Hi guys. Quick question, following up on to the Mainline. I know it's been about a lot regarding potential conversion to long-term contracts. How do you think about those producers who may have committed to pipeline expansions such as Keystone XL and Trans Mountain expansion that have committed capacity to those pipelines but not (01:04:43) maybe a little hesitant to then contribute or to commit capacity on the Mainline potentially being in a situation where they have double capacity?

Well, I guess, my only reaction to that is that that's their business to make those decisions. It's certainly not an easy one for them in an environment like we are today, where apportionment is high and price differentials are wide, that's a symptom of a lack of pipeline export opportunities and how individual producers will react to make decisions to protect themselves against that in the future is going to be a very individual decision for them.

I think it's an interesting question though because if you think about it, it really comes down to sort of the competitive landscape here and how our system matches up. And the reality is if you look at from a tolling perspective just given the scale of the system that we have, very, very low cost and that's driving actually why you're seeing a lot of interest in talking about a new CTS. So the tolls are very, very competitive. Let's not forget too the system is what we refer to is complex, in other words we can handle a very wide variety of crude slates and that's not always the case in other systems. Probably, the biggest one is the optionality that our system provides to all of the best markets and that's a big driver. The fact that there is – the system is very conducive to balance sheets, producer balance sheets, so all-in I think that's really the bigger picture here is that the system is extremely well positioned from a competitive point of view.

Thanks. I appreciate that. Thank you

Okay.

Thank you. And our last question comes from Dave Winans with Prudential.

Hey guys, just looking at the amalgamation of our MLPs and such, what's going to happen with the debt down at Spectra Energy Partners' and Enbridge Energy Partners. Is it going to get cross guaranteed with parent holding that debt as well? Just wondering what the outcome there will be?

Yeah. It's John speaking here. We will make some of those decisions in connection with the closing of those transactions and probably more to come at Enbridge Days. I think you can be assured that we'll have the debt holders in mind as we work through the various mechanics for funding strategy, debt funding strategy, debt funding structure going forward. Nothing specific at this stage though that we've announced but we will be talking about that at Enbridge Days.

Thanks, guys.

Okay. Thank you.

Thank you. And ladies and gentlemen, this concludes our Q&A session for today. I would like to turn the call over to Jonathan Gould for his final remarks.

Great. Thank you, Carmen. We covered a lot of ground here today, we're a little bit over time, but as always our IR team will be available right away to take any additional follow-ups that anyone may have. So thank you everyone for your time and interest in the Enbridge companies and have a great day.

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