恩橋 (ENB) 2018 Q3 法說會逐字稿

Welcome to the Enbridge Inc. and 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. (Operator Instructions) 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.

Thank you, Carmen, and good morning, and welcome to Enbridge Inc.'s 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 of Gas Transmission and Midstream. Our joint call will, again include discussion for Enbridge entities in order to provide an enterprisewide strategic and financial perspective. As per usual, this call is webcast, and I encourage those listening on the phone to follow along online with supporting slides. A replay and podcast of the call will be available later today and transcript will be posted to the website shortly thereafter.

In terms of Q&A, given the broad agenda and limited time of available, we will prioritize calls from the investment community only. If you're a member of the media, please direct your inquiries to the communications team, who'll be happy to respond immediately. We're, again going to target keeping the call to roughly 1 hour and may not be able to get to everybody. (Operator Instructions) 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 forecast assumptions and expectations about future outcomes. So we remind you that 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 CEDAR 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 then will 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 4, 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 $5.7 billion of asset sale proceeds with another $1.8 billion expected in the first half of '19. So's that's $7.5 billion in sales versus the original target of $3 billion. On that note we've talked about these additional asset sales getting 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 '18 cash flows, our Q3 debt-to-EBITDA now sits at 4.7x. Well ahead of our target that we set for 2018, of 5x. So good news there and John, will tell you more about how we're going to manage leverage going forward.

Second we've turned off the drip effective December 1, earlier than we projected, a good outcome particularly given our current valuation. So just to clarify here, no new shares issued for the December dividend. Third I think this demonstrates our focus on capital discipline and conservator balance sheet management and enhancing our low-risk business model. We also progressed corporate simplification, reaching agreement with special committees on all of the Sponsored Vehicle buy ins. And we're glad to be combining our 2 Ontario utilities taking effect at the beginning of the '19. So more on those highlights later on and let's now turn to Slide 5, and the results.

Q3 came in nicely with DCF per share at $0.93, up 13% over last year and we're now over 30%, up year-to-date. Same story on earnings at $0.55 per share and $2.01 year-to-date, so significantly, up here as well. The numbers were driven by a great operating performance in our core pipeline, utility businesses, new projects that came online and synergies from the Spectra deal.

As for our full year outlook, last quarter, we said we should be in the top half of our guidance range for the year and there's no change to that outlook.

Moving now to Slide 6 and a project execution update. This is the usual recap of our $22 billion secured project list for 2020, updated for Q3 activity. Two things to note here, we're making very good headway in the program, as you can see, the projects are well diversified by size, geography and business line. We've now brought in the bulk of this year, $7 billion of projects almost a dozen of them into service pretty much on time and on budget, which as everybody knows, is a tough thing to do in a challenging environment these days. Let me cover the 2 big gas pipeline projects, NEXUS and Valley Crossing both successfully completed.

So NEXUS began flowing gas in October, a good job by the team here and again, it highlights our execution capability and the stakeholder engagement in permitting expertise that you need to get Greenfield projects done today. NEXUS, as you can see by the map, is a highly strategy project for us. If you think about it it connects our Texas Eastern system with Dawn, leverages our vector line, which then connects to our Dawn Parkway system and then ultimately, to our Ontario utilities. Roughly a BCF per day in long-term contracts are ramping up in November. Bill is working on more commitments here and we'll continue to see good interest for market connections along the line. Valley Crossing is also done. Again, you can see the fundamental and strategy story here. The system links up low cost U.S. supply with growing export markets in this case gas-fired power gen in Mexico. We'll be connected to significant as upstream supply, including through the new Gulf Coast express pipeline, which we partially owned through our interest in DCP. And we're building on our Texas Eastern Gulf coast position with a recently acquired Pomelo connector and the South Texas expansion coming into service this quarter. This is going to be a big area of focus in the coming years for us, as our network is positioned with significant supply growth and last mile connectivity to capitalize our market pull, do exports to Mexico and U.S. Gulf Coast LNG.

Moving now to Slide 8, and the execution update on Line 3. In June, you'll recall, we achieved a critical milestone with Minnesota PUC approval. So let me recap what's happened since then and the next steps from here. Probably the most notable item is the agreement we just reached with the Fond Du Lac Tribe on the final route. This deal provides route certainty for us and it also is the best from an environmental perspective. The agreement also provides a new 20-year easement for the entire mainline system through the reservation. I want to recognize that tribal counsel's hard work and engagement with us over the last few months, in particular, but also through the years, as we have with other tribes and indigenous groups. It's a real good example of how serving two equally important objectives through collaboration, protecting the environment and culture and providing economic opportunity for tribal communities. Just by way of 1 example, the Fond Du Lac Tribe is assisting the Army Corps Engineers with that tribal cultural survey. Along the entire U.S. Route. That work just wrapped up last month.

In the U.S. we've committed to deliver over $100 million in economic opportunities to tribes and in Canada, we have some 50 cooperation agreements with indigenous groups and a lot of economic opportunity being shared. In fact, right now, we have 1,000 indigenous workers on the project.

Getting back to Minnesota. In September the PUC published the written order for the Certificate of Need and just last Friday, they issued a written order for the route permit. The route order allowed us to submit the remaining construction and environmental permits to the state agencies, so that's well underway. We expect to see the permits come through in time and we are ready for construction in Q1 and for line to be in service in the second half of 2019. So no change to timing.

Finally, we've completed and tied in the Wisconsin segment and Canada over 60% of the pipe is in the ground. Lots of work you have to do here, but we're pleased with the progress.

Related to Line 3, I'll spend a minute now on the current WCSB crude oil dynamics and the solutions we're working on to help customers, that's on Slide 9.

First it's not totally surprising, but WCSB volumes have increased this year by about 300,000 barrels a day. From what we see from our vantage point, storage levels are at record high, and while rail is providing some relief, it's not enough to bring in the very wide discounts that you see here on the this slide. Obviously, we're seeing this play out in North America generally, given robust supply growth and capacity is yet to catch up in a lot of areas. All of that means that our main line is running very full these days for both heavies and lights. It's not news that these price dislocations like you see in the chart here, screen for new infrastructure and that's what we're focused on.

Over the last 2 years, Guy Jarvis and his team have added over 175,000 barrels per day of capacity through various programs as every last barrel is making a difference. Just to give you a few examples here, utilizing space to move blended heavy during seasonal for light, aligning system maintenance activity with refinery downtime, capacity recovery and tank terminal work. Line 3 will add over 370,000 barrels per day, which provides relief again, but not enough given the supply growth outlook. The situation that we see today is driving renewed interest for incremental WCSB export capacity on the main line. There's up to 200,000 barrels per day of additional capacity available for Alberta barrels after Line 3 goes into service through DRA, agent and redirecting some downstream injections that come farther down the line to open up long-haul capacity for WCSB shippers. These capacity auctions require minimal constructions or regulatory work and they're highly capital efficient for us and our customers. We're also assessing additional pipeline of station upgrades that could add another 125,000 barrels a day of capacity in the early '20s. And finally, we've ramped up our evaluation of Southern Lights, re-reversal and conversion back into crude service for about 150,000 barrels per day.

So clearly some near term challenges for the industry here. But in these projects, we've talked about before, but certainly the current situation in the basin is making this all more relevant today.

On the related note, these market dynamics have also led to significant recent shipper interest in renewing the mainline CTS agreement, recall that the current CTS expires in 2021. We've begun, in earnest, exploring options with customers on the next agreement and it's a bit too early to get into the specifics around what that could look like today. But the interest on that front highlights the competitive position on the mainline system. So now on to Slide 10, and a brief update on regulatory items.

In August, the OEB approved our application to combine EDG and Union Gas, and we've developed a solid business plan around that application. Now just to remind everybody here, this is going to be a mega- scale gas utility. One of the best and fastest growth franchise in North America with over 3.7 million customers and 270 BCF of storage. So that will make us the second largest utility by customers. And first, by volume in North America. We have long history of working with incentive-based regulation, and when you see these 2 utilities sitting side-by-side geographically, the great opportunity to eliminate duplication, while also maintaining our standards for safety and service. Under this framework, our shareholders will benefit from the first 150 basis points of return above the allowed ROE, with 50 sharing of any additional earnings with rate payers. The framework also provides for recovery other than on top of additional investments above a threshold.

Now onto Slide 11, and the FERC regulatory update as it relates to our gas transmission business.

Because of tax reform and FERC policy changes, the entire industry has been focused on the regulatory landscape for gas. Based on the very detailed works that we've done on this over the last while, we're now very comfortable with our outlook in 2 areas: First, the tax changes have no impact on our negotiated tolling agreements, which make up over half of our U.S. gas transmission revenues. And the rollup of SEP, means that tax recovery disallowance won't apply to any future recourse rate filings. As well, minimal exposure to rate challenges as our recent FERC 501G filings show that we are not over earning on our cost of service systems. Secondly, on Texas Eastern, we're preparing for a full rate case proceeding, the first in almost 3 decades. That the rate case allows us to a re-based the substantial capital we invested over that period and actually, the way we see it there's upside in updating the cost of service factors.

So when we take all of this into account, we believe that we can retain at least the current revenue levels going forward, consistent with our long-range plan outlook.

Finally, let me wind up with the status of the sponsored vehicles. We're very pleased to have reached agreements recently to buy in all of the sponsored vehicles. These special communities undertook a very thorough process and in the end, we believe these were fair outcomes for both unitholders and shareholders. The benefits to sponsored vehicles, their holders in Enbridge are clear. For the Sponsored Vehicle public owners, the effectiveness of the sponsored vehicles from cost and access to capital perspective will continue to be challenged otherwise. In particular, EEP and EEQ will be facing inevitable and consequential distribution cuts as stand-alone entities. With the role-in Sponsored Vehicle investors will be getting security with better liquidity, lower cost of capital, a more diversified set of assets and stronger credit spending than they have today. For Enbridge the roll ups will simplify our structure. Retain more cash, strengthen our credit profile and generate significant tax benefits in the coming years. The first of the votes will happen next week with ENF shareholder meeting, scheduled now for November 6. On the U.S. side, special meetings for EEP and EEQ are targeted for December '17. In the case of SEP, Enbridge holds enough ownership to approve the transaction, so no unitholder meeting here and we expect to close in mid-December. We're pleased with the progress on the sponsored vehicles and we're looking forward to becoming a streamline organization, which will be good for all shareholders.

With that I'll hand it over to John, to provide the Q3 results update.

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 is 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 the Liquids Pipelines, where 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 were up 85,000 barrels per day over the same period last year, driven by growing oil sands production 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 system and all finally, higher contributions from our regional oil sands systems, due in most part to the impact of new projects placed into service later into 2017.

Moving down the slide, adjusted EBITDA from gas transmission and 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 increased by $21 million quarter-over-quarter. The year EBITDA was largely driven by anticipated rate base and customer growth at both utilities as well as the impact of new expansion projects placed into service by Union Gas last year. Weather was not much of a factor in the third quarter for either of utilities. Over the course of year, it has been on average, just a little colder than normal, positively impacting earnings by about $10 million on a year-to-date basis.

Continuing on, Green Power was up slightly about $5 million quarter-over-quarter, primarily due to higher wind resources at the Canadian facilities and contributions from new projects that commenced production last year.

Energy services also continued to generate strong financial results. Adjusted EBITDA increased by about $34 million, when compared to Q3 of last year, driven primarily by wider crude oil and natural gas location differentials, which created more opportunities to generate profitable margins.

Finally, EBITDA reported in eliminations and others was down about $65 million over Q3 2017, mostly due to higher realized foreign exchange hedge settlement losses, that resulted from a stronger U.S. dollar and somewhat less favorable foreign exchange hedge rates, when compared to Q3 of last year. Of course, these hedge settlements reported in E&O were more than offset by corresponding translation gains on earnings generated by our U.S. businesses and investments. So all in all another strong quarter, pretty much right in line with our expectations.

Moving on, Slide 14 summarizes how that underlying performance of our business has translated into bottom line cash flow. Consolidated distributable cash flow for the quarter came in at about $250 million higher than Q3 of last year, driven largely by the very strong uptick in EBITDA that I just went through. The significant factors impacting year-over-year DCF for the quarter are broken out on this slide. You'll see that maintenance capital during the quarter was slightly lower than Q3 of 2017. This is mostly a reflection of specific programs that were undertaken in Q3 of last year in the Canadian G&P business that weren't part of our 2018 maintenance plan. With the closing of a portion of the sale, of the Canadian G&P assets on October 1, we do expect maintenance CapEx for 2018 to come in slightly lower than our original full year guidance of $1.3 billion.

As you could also see cash flow benefited from higher distributions from our equity investments as a result of strong business performance from a number of our joint ventures, notably the Alliance Pipeline, DAPL and DCP, all of whom have had very strong years thus far. These positive contributors were partially offset by higher distributions to noncontrolling interests as well as higher financing costs, both of which result directly from incremental financing we raised at Enbridge and our sponsored vehicles over this last year to fund our secured growth profile. As Al has already mentioned, on a per share basis, DCF for the third quarter came in at $0.93, up about 13%, when compared to the third quarter of 2017 rather and a little over 30% on a year-to-date basis.

So turning to Slide 15. After another solid quarter let's look at the outlook for the full year. Al has already delivered the punchline. We continue to expect to deliver full year DCF per share in the top half of our original guidance range for 2018. This is largely based on the stronger business performance from our core businesses through the first 9 months of the year as well as better than expected arbitrage opportunities in our energy services business.

Looking ahead to the fourth quarter, we expect to continue to see, a strong operating results from core businesses, along with incremental earnings and cash flow contributions from the Nexus and Valley Crossing transmission projects, which as Al just mentioned, went into service last month. Over the scope of the remediation plan is still being finalized, we don't expect the material financial impact in the fourth quarter related to the BC pipeline incident, and believe that we ultimately be able to recover lost revenue and costs through insurance and/or regulatory mechanisms. So while there may be a few puts and takes heading into the final 2 months of the year, on balance our outlook for 2018 has not changed, since our call after the second quarter. We continue to expect DCF per share to come in the upper half of our original guidance range, which was $4.15 to $4.45 per share. We will be refreshing our longer-term outlook at Enbridge Days, but with the Line 3 replacement project on track for completion in 2019, we do continue to expect distributable cash flow and dividends per share to grow at a 10% CAGR from 2017 through 2020.

Turning now to Slide 16, and briefly the performance of our sponsored vehicles. I'm starting with Spectra Energy Partners or SEP, where ongoing EBITDA in the third quarter of 2018 increased by $7 million over the same period last year. The increase in EBITDA primarily reflected incremental contributions from organic growth projects that were placed into service over the course of 2017. However, that EBITDA growth did not translate into, an increase in ongoing DCF relative to 2017. It was more than offset by higher maintenance capital and higher interest expense quarter-over-quarter. Also a small portion set to year-over-year EBITDA growth reflects on allowance for equity during construction booked for Nexus and other small regulated projects undertaken over the last year by our gas transmission group, which of course, gets eliminated in the determination of DCF. NEXUS and some of these other projects have actually come into service since the end of the quarter and have begun delivering cash flow to the bottom line.

SEP also announced yesterday, a quarterly distribution of $0.07765 per share, an increase of $0.0125 per share over the distribution paid in Q2, consistent with our previously communicated guidance. This distribution will be paid on November 29 to all unitholders of record on November 21. As Al mentioned earlier, we'd expect this from to be final distribution, as the SEP roll-up transaction is now targeted to close in mid-December.

Moving along to Enbridge Energy Partners or EEP on Slide 17. Q3 EBITDA and DCF for EEP were both slightly lower than 2017. The decrease was mostly attributable to lower revenue in the Lakehead System, which is a result of the combined impact of U.S. tax reform and the change in FERC income tax policy on the portion of EEP's revenue is derived from tolls based on a cost of service formula, which we have discussed at some length on earlier calls this year. The negative impact was partially offset by the increased EBITDA generated by the Bakken system, which as I mentioned earlier, continues to benefit from strong throughput from growing production in that region. EEP declared a quarterly distribution last week of $0.35 per unit, which will be paid on November 14 to unitholders of record on November 7. If unitholders vote to approve the EEP buy-in as we expect. This would also be the final quarterly distribution to be paid by EEP.

Finally, turning to Slide 18 and highlights for ENF and the Fund Group. The fund continued its strong performance with third quarter DCF up $228 million over the third quarter of 2017. The uptick was driven primarily by the Liquids Pipelines business. As mentioned earlier, the performance of the Canadian Mainline has improved year-over-year driven by a throughput, higher throughput, a higher benchmark toll and a higher effective exchange rate on hedges used to convert U.S. dollar toll revenue into Canadian dollars.

Fund group DCF also benefited from higher contributions from new regional oil sands pipelines and related facilities that were placed into service last year. EBITDA contributions from Alliance pipeline were up slightly on a quarter-over-quarter basis on the strength of higher demand for seasonal firm service. In mid-October, ENF declared a monthly dividend of $0.1883 per share, which we paid on November 15, to shareholders of record on October 31, irrespective of the outcome of the shareholder vote on the ENF buy-in to be held on November 6. Assuming the transaction is approve, ENF shareholders will continue to hold their Enbridge Inc. shares that they receive in the buy-in will also be entitled to the common share dividend payable to Enbridge Inc. shareholders on December 1.

I'll wrap up my section here on Slide 19 with a few comments on funding and the balance sheet. Fair to say, that we continue to make very solid progress on the plan we laid out at Enbridge Day a little less than a year ago. With the closing of part one of our sale of the Western Canadian gathering and processing assets, we have now received over $5.7 billion of proceeds from asset sales to date this year. This together with the issuance of hybrid securities and strong financial performance throughout the year so far has enabled us to accelerate deleveraging at an even faster pace than originally envisioned. With the balance of proceeds from asset sales, scheduled to come in the first half of 2019, we now have created significant financial flexibility, which enables us to suspend the drip beginning in December, earlier than we would have contemplated last year. And still bring consolidated debt-to-EBITDA to below 4.5x by 2020, while building out the balance of our secured growth program.

To be clear, the remaining equity funding we need through 2020 to support our current secured growth program will be supplied by internally generated cash flow together with a very manageable amount of term debt funding. So we're on funding mode now. The bar chart on the lower right depicts the leverage reduction we were targeting at the time, we rolled out our investment and funding plan, last December. Our target was to achieve and then maintain consolidated debt-to-EBITDA at less than 5x. But we also recognized that in challenging market conditions it's important that we operate with a certain level of additional flexibility and cushion. There being more on this on our next Enbridge Days in a few weeks, but going forward, we plan to manage debt-to-EBITDA between 4.5 and comfortably below 5x. As Al has already pointed out, we achieved trailing 12-month consolidated debt-to-EBITDA metric of 4.7x this quarter, so we are already operating well within this revised target.

Recall that our projections at last year's Enbridge Days, which are shown on the chart, indicated that consolidate debt-to-EBITDA would be well below 4.5x based on our current secured plan. This will provide some additional flexibility to self fund new organic projects in 2020 and beyond. Those projections from last year will be update at Enbridge Days, but I can tell you now that the trajectory is substantially unchanged.

So all in all, another very solid quarter with strong year-to-date performance and a good progress on the balance sheet, which positions us very well from a financial perspective heading into the end of the year.

And with that I'll turn it back to Al to wrap up

Okay. thanks, John. I'll just do a quick summary of what you've heard today. 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 project 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 that's accelerate deleveraging. We've met and exceeded our credit targets earlier than expected and have turned off the drip. We've advanced our streamlining objective with the sponsored vehicles 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 we can control, namely delivering results and accomplishing our strategy 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 rollout our strong -- our new strategy 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.

(Operator Instructions) Our first question comes from Jeremy with JP Morgan.

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

Maybe will let, Guy handle that one.

Yes. So Jeremy first in terms of the apportionment process, you're right. We've been discussing our nomination and 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 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 in Line 9, southern access extension and 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 will -- whether it's something down Flanagan South or whether there is the 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 Western Canada, but other parts of North America, if you look at just 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 for a couple of years, 2, 3 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 will be in a much better shape. And I think we've got to be patient through the next 1 year or 2 here.

I guess on that point real quick, Southern lights seems there's a lot of demand to convert that into takeaway. How quickly can at something like that be effected. And you talked about CTS renegotiation there. Just wondering, seems like there's a lot demand to incentivize you guys to optimize it and get as much as possible. Seems like rates would been in favorable position at this time, given all that the demand in may be some sooner rather than later. Any thoughts you could share there?

Well, I think, this the thought that I would share is, from -- when -- 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 change. 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 BC it is looking at options to reverse and put incremental capacity. And so we're all over options like that.

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

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. I'm wondering how that environment impacts the negotiation process. And in particular, what your timing expectations might be for a renewal?

Yes, 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 1 of the competing pipelines is targeted 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, there's going to be a relief on that front.

Okay, that makes sense. And I suspect more follow up has a same answer, but we're hearing more about producer shortage in the short term. So wondering, if you have any initial thoughts on 2019 volumes? And 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 factors other than just peer 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 we're in the discounts, so 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 is on the mainline system, because of number of factors, including the markets. It sees and so forth. So I don't see it impacting our volumes going forward. We're full than we expected, be full next year, that's the start of the bottom line, I guess.

Our next question comes from Linda with TD Securities.

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 will be the most important criteria, whether it be further strategic focus in your core business? Or maybe financing additional growth opportunities, whether it's prefunding 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 comment on other kind of less core, current business will 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 3 big businesses are very core to us and we don't see anything happening there. The criteria, I think, will, all 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 on at this point on 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.x 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 a G&P related. I guess, though, 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 are in good basins. So I think, given the more than doubling of our asset sale target that we had there's no immediate rush on this, given where they are and the work they are doing. I think we've demonstrated that we'll make good capital allocation decisions, when we see good value and will 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 variable for my assumptions next year will the timeline of L3R, and I've done my best. But I'm just wondering, when we might get better clarity on tightening the in-service date of the second half of 2019? And what key factors we 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, you might miss some construction windows? Or are you going to give us an update, I guess on the 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 team is looking at a wide range of potential options and have 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 industry and that the planning that we're doing, but it's going to be very, very difficult to pin down the date any further.

I think, Guy's got that exactly right. I don't know if this helps you or not, but I think we've talked about this before. Obviously when we're looking at '19 numbers, we need to make some assumption. We've assumed, November 1, I guess, may be for simplicity, but that's the numbers that have been included within our outlook in '19. So that's, I guess, that's the best we can do at this point.

Our next question comes from Dennis Coleman with Bank of America Merrill Lynch.

I guess, there's been a lot of good questions asked. On Line 3, are there -- is it all done now in terms of the approvals and whatnot, no other hurdles or now it's just in 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 time line and a 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, major permitting work, if you will, after that assuming all that goes well we'll be able to get into the field and begin with the construction activity. So I don't know, if that helps you, Dennis. Anything to add on that Guy.

The only thing I would add Al is, there is 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 the 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 not held through rehearing.

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

Perfect. May be just an 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 will we likely start to see the benefits of that come through the income statement?

You're talking about the utilities here, right?

Yes. Yes, I am.

I think the easiest way to think about 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 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.

Our next question comes from Ben Pham with BMO.

I have 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 option to benefit on share count. But then there's an outflow of cash. So can you talk about the -- what CapEx you can self-fund on the balance sheet? Is it that part of $6 billion and then, does that mean 6% self-funded growth, 8%. I mean, you've talked about that before, and just some more context on that?

Ben it's John. It's probably a little early to get into detail are 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 your way out of line in terms of cash in terms of kind of balance sheet capacity we have. We'll spend more on that probably as Bill and our other business senior leaders will go through opportunities that they have in front of them to build that plan up. Fair to say a significant generic emerging balance sheet capacity with actions that we've taken.

Okay. I'm kind of $5 billion or so it's a little bit hybrids in there. So I mean if -- the CapEx starts to rise in the future years and then, I guess, we looked at the spread a big spread there on that financial flexibility, hybrids, asset sales before external equity?

Yes, 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 were up to but generally as John said, I don't think you're too far out with our estimate.

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

If I can may be just follow on that leverage side and kind of the 4.5 of 5x, just to confirm kind of in the chart, does that only included 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 for the bars on the left?

That's right, Robert.

If I can maybe 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 flow as you discussed at the 2017 at your Investor Day. The other question being, the system has been highly apportioned, and you generally talked about you've moved call it roughly 2.6 million barrels a year-to-date. I guess if everything was running optimally, what do you see as the maximum volumes to ex-Gretna. And are shippers asking you for additional operational tankage build outs whether that's upstream or downstream. And could you roll that into 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 is -- there are numerous different protections against volumes. So I don't think there is anything new there in terms of incentive tolling agreement, CTS, the potential contracting. I think all of those things are the 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 on the mainline. So that is something that we're evaluating in conjunction with the other options. But there's nothing definitive of it at this stage to put forth on that. Going to the next question, we are full. I think if you look back 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. And that's a scenario where all the production is performing, the pipeline is performing and the refineries are all product performing, and that's all it takes for us to get 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 operational issue but we're not able to use that operational storage to as a longer term inventory. And the time line to build new tanks isn't really going to solve any of these higher volume issues that we're seeing right now either.

Our next question comes from Tom Abrams with Morgan Stanley.

I just want to ask couple of questions about Line 3, a 3 part 1, but as you complete it, is there a possibility that you, A, complete the section at south and east of Clearbrook such that you can get more volume out of the Bakken for quarter say before the rest of the line comes up? Secondly, what is your thoughts around when the pipe that runs currently from the Bakken to Line 3 up into Canada, goes empty. And thirdly, you've already completed a lot of construction on the West Side of the 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 other side

Yes. So to get to -- again, I'll take this in order. We don't currently have any plans to kind of conduct a segmented startup 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 make it onto the mainline system, because they are consumed locally in that. So there is no plan around that. We've talked about this potential ceasing the deliveries out of North Dakota to allow the Albert barrel 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 barrels, when that exits the Express system. And so we got to do some work on that, the market access element of that as well, but there are underway and we're working on it. We just don't have a solution right now.

Yeah, you maybe committed to light. The other question I have is 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 number you can put around those 2 items?

I think on the tax side, we talked about extending the nontaxable horizon, at least out another 2-plus years. I think that's we've typically talked about in terms of the benefits related to the buy-ins from various different components.

I think, as I recall, that's applying to the U.S. tax position. So think of it as extending the 0 tax position from 2020 onwards by another couple of 3 years. I think on the Canadian side as well, with the ENF rollup that allow us to basically maintain their 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.

Our next question comes from Patrick Kenny with National Bank Finance.

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. May be I'll start with it. I guess maybe our view is that this project has been so extensively reviewed and through a very comprehensive regulatory process that took literally 3 years, including 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. And 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 under construction say, this time next year?

Yes. 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. 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 a -- what we think is going to be 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 can sneak in one last one here, just to circle back on Robert's second 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 a significant portion uncontracted and open for the smaller producers that might not be able to sign 10-year-plus contracts?

We do know, we're going to have to keep the proportion, if we go down that path, you have to keep proportion of the system available for spot. In terms of 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. So we don't see any regulatory impediments to moving that direction, if that's what we agree to with our shippers.

Our next question comes from Joe Gemino from MorningStar.

Quick question following up on mainline. I know you've talked a lot about 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 or maybe a little hesitant to then contribute to current capacity on the mainline, potentially being a situation when 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 we are like today. Where apportionment is high and price differentials are wide. That's a symptom of 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 competitive landscape here and our system matches up. And the reality is, if you look at it from a tolling perspective, just given the scale of the system that we have, very, very low cost and then, that's driving actually why you're seeing a lot of interest in talking about the new CTS. So the tolls are very, very competitive. Let's not forget to the system is what we refer to as, complex, in other words we can handle 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's this is system is very conducive to balance sheet -- 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.

And the last question comes from Dave with Prudential.

Just looking at the your 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 for the parent holding that debt as well? Just wondering what the outcome there will be?

We'll 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 will 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 although we've announced, but we will be talking about that at Enbridge Days.

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 have covered a lot of ground here today, went 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.