Earnings Call: Q3 2018

Nov 2, 2018

Welcome to the Enbridge Incorporated, Enbridge Income Fund Holdings, Enbridge Energy Partners and Expektra Energy Partners 3rd 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 Whelan, 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 online 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 and A, given the broad agenda and limited time available, we will prioritize call from the investment community only. If you are a member of the media, please direct your inquiries to the communications team who will 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, so please limit your questions to 1 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 forecast assumptions and 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 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 $5,700,000,000 of asset sale proceeds, with another $1,800,000,000 expected in the first half of twenty nineteen. So that's $7,500,000,000 in sales versus the original target of 3,000,000,000 dollars 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. 1st, after repaying debt with a portion of these proceeds and with strong 2018 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. 2nd, 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. 3rd, I think this demonstrates our focus on capital discipline and conservative balance sheet management and enhancing our low risk business model. We also progressed corporate simplification reaching agreement with the 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 2019. So more on those highlights later on, let's now turn to Slide 5 and the results. Q3 came in nicely with DCF per share $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 great operating performance in our core pipelines and 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 $22,000,000,000 secured project list through 2020 updated for Q3 activity. 2 things to note here. We're making very good headway on 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's $7,000,000,000 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, good job by the team here. Again, it highlights our execution capability and the stakeholder engagement and permitting expertise that you need to get greenfield projects done today. Nexus, as you can see by the map, is a highly strategic project for us. If you think about it, it connects our Texas Eastern system with Don, leverages our vector line, which then connects to our Dawn Parkway system and then ultimately to our Ontario utilities. Roughly Bcf per day long term contracts are ramping up in November. Bill is working on more commitments here and we'll continue to see good interest from market connections along the line. Valley Crossing is also done. Again, you can see the fundamental and strategic 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 upstream supply, including through the new Gulf Coast Express Pipeline, which we partially own through our interest in DCP. And we're building on our Texas Eastern Gulf Coast position with the recently acquired Palmello 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 on market pull through 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 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 the Tribal Council'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 2 equally important objectives through collaboration, protecting the environment and culture and providing economic opportunity for tribal communities. Just by way of one example, the Fond du Lac tribe is assisting the Army Corps of Engineers with the 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 $100,000,000 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 the 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 to be ready for construction in Q1 and for Line to be in service in the second half of twenty nineteen, so no change to timing. Finally, we've completed and tied in the Wisconsin segment and in Canada over 60% of the pipe is in the ground. Lots of work yet 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 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 mainline is running very full these days for both heavies and lights. It's not news that these price dislocations like you see on 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 troughs for light, aligning system maintenance activity with refinery downtime, capacity recovery and tank and 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 mainline. There's up to 200,000 barrels per day of capacity available for Alberta barrels after Line 3 goes into service through DRA drag reducing agent and redirecting some downstream injections that come further down the line to open up long haul capacity for WCSB shippers. These capacity options require minimal constructions or regulatory work, and they're highly capital efficient for us and our customers. We're also assessing additional pipeline and 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 a 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 EGD 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 3,700,000 customers and 270 Bcf of storage. So that will make us the 2nd largest utility by customers and first by volume in North America. We have a long history of working with incentive based regulation and when you see these 2 utilities sitting side by side geographically, it's a 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 $50,000,000 sharing of any additional earnings with rate payers. The framework also provides for recovery of and on capital for additional investments above a threshold. Now on to 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 work 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 roll up 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 501 gs filings show that we're 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 rate case allows us to rebase 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 sponsor vehicles. We're very pleased to have reached agreements recently to buy in all of the sponsor vehicles. These special committees here undertook a very thorough process and in the end, we believe these were fair outcomes for both unitholders and shareholders. The benefits to sponsor vehicles, their holders and Enbridge are clear. For the sponsor vehicle public owners, the effectiveness of the sponsor 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 standalone entities. With the whirlwind, sponsored vehicle investors will be getting a security with better liquidity, lower cost of capital and more diversified set of assets and a stronger credit standing 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 E and S 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'd expect to close in mid December. We're pleased with the progress on the sponsor vehicles, and we're looking forward to becoming a streamlined 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 was very strong on a quarter over quarter basis. As you can see, consolidated adjusted EBITDA was up about 14% or $372,000,000 over the Q3 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 $280,000,000 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 sand 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 $97,000,000 Here, the quarter over quarter growth was driven primarily by expansion projects placed into service in late 2017, as well as higher contracted volumes on Sable 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 $21,000,000 quarter over quarter. The higher 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 Q3 for either of the utilities. Over the course of the year, it has been on average just a little colder than normal, positively impacting earnings by about $10,000,000 on a year to date basis. Continuing on, Green Power was up slightly, about $5,000,000 quarter over quarter, primarily due to higher wind resources at our 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 $34,000,000 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 other was down about $65,000,000 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 and O are 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 is translated into bottom line cash flow. Consolidated distributable cash flow for the quarter came in at about $250,000,000 higher than the 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 and P business that weren't part of our 2018 maintenance plan. With the closing of a portion of the sale of the Canadian G and P assets on October 1, we do expect maintenance CapEx for 2018 to come in slightly lower than our original full year guidance of 1,300,000,000 dollars As you can 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 non controlling interests as well as higher financing costs, both of which result directly from the incremental financing we raised at Enbridge and our sponsored vehicles over this last year to fund our secured growth program. As Al has already mentioned, on a per share basis, DCF for the Q3 came in at $0.93 up about 13% when compared to the Q3 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 punch line. 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 1st 9 months of the year as well as better than expected arbitrage opportunities in our Energy Services businesses. Looking ahead to the Q4, we expect to continue to see strong operating results from our 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. While the scope of the remediation plan is still being finalized, we don't expect a material financial impact in the Q4 related to the BC pipeline incident and believe that we will 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 Q2. 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 and starting with Spectra Energy Partners or SEP, where ongoing EBITDA in the Q3 of 2018 increased by $7,000,000 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 of SEP's year over year EBITDA growth reflects an 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 $0.77625 per share, an increase of $0.015 per share over the distribution paid in Q2, consistent with our previously communicated guidance. This distribution will be paid on November 2019 November 29, pardon me, to all unitholders of record on November 21. As Al mentioned earlier, we'd expect this to be the final distribution as the SEP rollout transaction is now targeted to close in mid December. Moving along to Enbridge Energy Partners or EAP on Slide 17. Q3 EBITDA and DCF for EAP were both slightly lower than 2017. The decrease was mostly attributable to lower revenue on 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 EAP's revenues 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 driven by growing production in that region. EAP 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 EAP buy in as we expect, this would also be the final quarterly distribution to be paid by EAP. Finally, turning to Slide 18 and highlights for E and F and the Fund Group. The Fund continued its strong performance with 3rd quarter DCF up $228,000,000 over the Q3 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 throughput higher throughput, a higher benchmark toll and higher effective exchange rates 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, E and F declared a monthly dividend of $0.183 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 E and F buy in to be held on November 6. Assuming the transaction is approved, E and F shareholders who continue to hold their Enbridge Inc. Shares 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 Days a little less than a year ago. With the closing of Part 1 of our sale of the Western Canadian gathering and processing assets, we have now received over $5,700,000,000 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 the proceeds from asset sales scheduled to come in the first half of twenty nineteen, 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 4.5 times 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 in self 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 5 times. But we also recognize that in challenging market conditions, it's important that we operate with a certain level of additional flexibility and cushion. There will be more on this at 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 a trailing 12 month consolidated debt to EBITDA metric of 4.7x this quarter, so we're 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 consolidated 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 beyond. Those projections from last year will be updated 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 good progress on the balance sheet, which positions us very well from a financial perspective heading into the end of the year. 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 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 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 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 sponsor vehicle buying 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 strong our new strategic plan, our business unit leads will talk about the drivers of growth going forward, and we'll 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 and A. Thank you. And we will now begin the question and answer 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 improvements that could be made there or any other thoughts? I know you guys have done some work there. And just when you go further downstream, all this crudes hitting Upper Pad 2 here. And just wondering where you think it goes at that point. I mean, I think a Capline reversal will make a lot of sense to bring that down to the Gulf. But maybe the refiners in the 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. Yes. So, Jeremy, first on 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 being 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 2, II, into our downstream pipelines, Line 9, Southern Access Extension Plant against 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 there's there is a potential Capline reversal if that 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 will see some new capacity coming on, I think, other parts of North America as well. So I think looking out 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 we'll be in much better shape and I think we've got to be patient through the next year or 2 here. I guess on that point real quick, Southern Lights 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, from when 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. So 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? Yes. Robert, it's Guy. We are 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 timeline, 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 Alan 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 than 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 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 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, will 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 can 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 and 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 in 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've 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 and in service date of the second half of twenty nineteen 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, might you miss some construction windows? Or are you going to give us an update, I guess, at 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 ex heme 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 guys 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 'nineteen 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 that's 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. Yes, great. Thanks for taking my call this morning. I guess, there's been a lot of good questions asked. On Line 3, are there 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, 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? The only thing I would add, Al, is there is a rehearing process within the Minnesota Public Utilities Commission. But we're very confident that 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 execute the use of 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 happens. 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 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 would win wise 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, sort of probably done a lot of work scenario analysis. And so when you look at that cash flow out flow, inflow next couple of years, I mean there's obviously the benefit on a 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 still at $5,000,000,000 to $6,000,000,000 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 described 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 the kind of balance sheet capacity we'd have. We'll spend more time on that probably as the guide bill and our other business unit leaders roll 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 $5,000,000,000 or so for 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 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'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. 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 comfortably below 5 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? Yes, that's right, Robert. Okay, perfect. If I can maybe just finish here then with the main line, 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 Midyear 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 2,600,000 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 operational additional operational tankage build up, 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. 1st, when it comes to the mainline contracting, obviously, we've demonstrated over the years, there's all 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 Q4 of last year, our record throughput levels were, I think, close to 2,750,000 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, we 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 to 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. Great. Thanks. I also want to ask a couple of questions about Line 3, a 3 part one. But as you complete it, is there a possibility that you, A, complete the section that's south and 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 2 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 another pipe besides Platte? Yes. So to get to again, I'll take these 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 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 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 so 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 that, the market access element of that as well, but they're underway and we're working on it. We just don't have a solution right now. Maybe committed to lights. The other question I have is a financial one and you 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 nontax bull horizon, at least out another 2 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. Yes. 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 E and F roll up, that will 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. 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 Finance. 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 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. All right. 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? Yes. 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 that 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 sneak 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 uncontracted and open for the smaller producers that might not be able to sign 10 year plus contracts? Yes. 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 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 and spot capacity. And so we don't see any regulatory impediments to moving that direction if that's what we agree to with our shippers. Great. Thanks guys. Thanks Al. Okay. Thank you. Our next question comes from Joe Gemino with Morningstar. Hi, guys. Quick question following up on the mainline. I know some talked about a lot regarding potential conversion to long term contracts. How do you think about those producers who may have committed to pipeline expansion such as Keystone XL and Trans Mountain expansion that have committed capacity to those pipelines, but not admit, but are 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'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 and 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 as 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's 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. Great. I appreciate that. Thank you. Okay. Thank you. And our last question comes from Dave Winans with Prudential. Hey, guys. Just looking at the allegation of 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 with the parent, you're going to fold in that debt as well? Just wondering what the outcome there will be. Yes. It's John speaking here. We'll make some of those decisions in connection with the closing of those transactions and probably more to come at Enbridge Day. I think you can be assured that we 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 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 and 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 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.