Enbridge Inc. (ENB) Q3 2019 Earnings Report, Transcript and Summary

Welcome to the Enbridge Incorporated Third Quarter 2019 Financial Results Conference Call. My name is Sonia and I'll 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 committee. [Operator Instructions] Please note that this conference is being recorded. I will now turn the conference over to Jonathan Morgan, Vice President, Investor Relations. Jonathan, you may begin.

Thank you, Sonia. Good morning and welcome to the Enbridge, Inc. third quarter 2019 earnings call. Joining me this morning are Al Monaco, President and Chief Executive Officer; Colin Gruending, Executive Vice President and Chief Financial Officer; Guy Jarvis, Executive Vice President, Liquids Pipelines; Bill Yardley, Executive Vice President, Gas Transmission and Midstream; and Vern Yu, President and Chief Operating Officer, Liquids Pipelines. As per usual, this call is webcast and I encourage those listening on the phone to follow along with the supporting slides. A replay and podcast of the call will be available today and a transcript will be posted to the website shortly after. In terms of Q&A, we will prioritize calls from the investment community. If you are a member of the media, please direct your inquiries to our communications team, who will be happy to respond immediately. We're again going to target keeping the call to roughly one hour and may not be able to get to everybody. So please try to limit your questions to one and a follow-up as necessary. As always, our Investor Relations team is available for your detailed follow-ups afterwards. On to slide 2, where I'll remind you that we will be referring to forward-looking information on today's call. By its nature this information contains forecast assumptions and expectations about future outcomes, which are subject to the risks and uncertainties outlined here and discussed more fully in our public disclosure filings. We'll also be referring to non-GAAP measures summarized below. With that, I'll turn it over to Al Monaco.

Thanks, Jon, and good morning, everybody. Before we get going, I'd like to recognize Guy Jarvis, who is retiring from Enbridge after almost 20 years. Most of you have come to know Guy over that time and the tremendous contribution he has made to our company. He has delivered a lot of value and profitability in Liquids from great operating performance to system expansions to improved customer service to industry leading safety results. We're obviously going to miss Guy, but he is leaving the Liquids business in good position today. Now we wouldn't be doing our jobs if we weren't thinking ahead and succession planning as many of you know has been a hallmark at Enbridge. As part of that, Vern Yu will be stepping into Guy's shoes in the new year as Executive Vice President of Liquids Pipelines. He has been the COO at Liquids for the last while where he's worked closely with Guy. So the transition will be seamless. Many of you know Vern as well. Over his 25 years, he's put together a stellar record including in Liquids and corporate development where he's driven significant growth and been part of developing and executing our overall strategy at the company. Looking across the table he is charged up and excited about this opportunity to run Liquids. I'll start with the big picture on the quarter that on slide 4. Q3 numbers came in strong as you saw. So we should have a good result this year. We closed roughly $6 billion of the $8 billion of asset sales so the balance sheet is in very good shape. And at $4.6 times debt to EBITDA we're at the low end of our target range. We made solid progress on key priorities, namely on Liquids Mainline throughput optimizations and we remain confident in our Mainline contract offering. I'm going to spend a little bit more time on that issue today. And, of course, Bill and his team has reached a very good rate settlement on Texas Eastern. We're executing our secured copper program with some key projects coming into service shortly and re-initiation of Line 3 permitting in Minnesota after the EIS appeals, so all in a good quarter on all fronts. Let's go to slide five and the Q3 numbers. Strong operating performance and volumes drove another solid quarter. In Liquids, in particular, Mid-Continent and Gulf Coast demand for Canadian barrels continues to drive volumes through our Mainline and downstream pipes, same story on gas transmission where we ran full. And on gas distribution continues to generate solid results under the incentive tolling as well as strong utility growth. So Q3, DCF per share was up 12% which is a good result given the much higher share count from the buy-in of our core sponsored vehicles at the end of last year. Based on the strong nine-month numbers then we're confident that we will exceed the midpoint of our guidance range of $4.45 for the year and Colin will go over the results in a few minutes. So let's move to the business update beginning with Liquids on the next slide. On the Canadian leg of Line 3, we are now complete and we came in under budget, very good outcome there I think. And then not to mention good relationships built up with our First Nations and native partners. Line filling is under way and we should be fully operational by December 1 and we'll start generating cash with the partial surcharge. More broadly though, we're very pleased that we are putting in new pipe in the ground as it enhances overall safety and reliability of the system and gives us more operating flux. In Minnesota, the Supreme Court denied hearing the EIS appeals as you saw. So finalization of the EIS and permitting is moving forward. In fact, on October 1, the PUC directed the Commerce Department to complete the incremental spill modeling and submit a revised EIS by December 9. Let me outline the chronology of the remaining steps on slide 7. From here there are two concurrent tracks, on the regulatory track once the revised EIS is finalized the PUC will do public consultation and determine adequacy of the EIS followed by a process to reinstate the Certificate of Need and Route Permits. On the permitting track that's the blue blocks here state and federal agency were has been moving forward in parallel with EIS. So that's the news. We'll refile the 401 permit including amendments to our initial application to reflect the agreements that have come forward with the Pollution Control Agency since the original. Once we have those permits in hand, there was a final authorization to construct in the PUC. So that's a sequencing we expect and once we have timelines from the PUC and agencies, we'll be able to provide the next key milestones toward the start of construction. Now, on to Slide 8 and the status of WCSB Egress optimizations. On the Mainline, we expect to bring in about 100,000 barrels per day of incremental capacity by year-end. That extra 100,000 comes from capacity recovery and our optimization of receipt and delivery windows as well as leveraging Line 3 Canada. We're also moving forward with a 50,000 barrel per day expansion of the Express to serve PADD IV and that should be ready in Q1. These optimizations and expansions are exactly what we're focused on today, because they required minimal capital. They are highly executable and they generate great return. They’re also good for customers as they provide much needed low cost incremental capacity to the best markets. On that topic on to Slide 9 and an update on our downstream market access [pipes] [ph]. As you know, over the last five years, we've been executing our Gulf Coast strategy by moving increased volumes from Western Canada, the Bakken, Cushing and more recently Permian. On Seaway, we'll be launching an open season for a highly competitive expansion from Cushing to Houston. In the Bakken, the Dakota Access open season has been extended to include HFOTCO as a destination. And finally, Gray Oak will be up and running shortly, providing Permian production with the competitive outlet to local refining and exports, so again highly capital efficient expansions in new build supported by strong Gulf Coast demand. Shifting back, upstream of those pipes, as you know we're in the process of offering long-term contracts on our Liquids Mainline. We expect to be assessing our open season results at above at this point, but the CER's decision, the Canadian Energy Regulator, means the regulatory review will now precede the open season. Given there has been a lot of commentary out there on this topic, I'd like to provide our perspective on it, starting with some very important context on Slide 10. First, important to know who actually ships on our system. The Mainline has always been a demand pull system. So, the vast majority of our customers are refiners or integrated producers with downstream refining capacity. Most have been shippers for decades in large volume. That's because the Mainline is directly connected to nearly two million barrels of refining demand and supplies another one million to our downstream market access pipes and that's Flanagan, South Southern Access and Line 9. These customers depend on our system for feedstock. So they are supportive of our contract offering because they want assured access to our system at stable low cost tariffs. Western Canadian non-integrated producers are shippers of record for only about 5% capacity. And most of them prefer to sell crude to others in Alberta or they have contracts on other pipes including Trans Mountain and base Keystone. Many of the objection letters that you heard about actually represent a small fraction of our throughput and many don't ship on our system. Now having said that, we, more than anyone understand the importance of our Mainline to the basin. That's why we design our offerings to make sure all producers have an opportunity to get guaranteed access to the system, so that they can better control their barrels and maximize netbacks. But if they still prefer to access our system in some cases on a short-term basis, we set aside capacity for those customers as well. Now to Slide 11 and how our commercial model has developed which is an important factor as well on this topic. We've operated under incentive tolling, essentially decoupling from cost of service for about 25 years. Reason for that is that our customers want us to be totally aligned with them and that's what we want as well. For example, over that 25 years, we've significantly improved crude quality given the slates that we shipped down to the U.S. Midwest. We hit key service metrics and critically important provide a toll certainty that you don't get with cost of service. Over the course of CTS, we've added significant new capacity and kept costs low. Our toll has risen by about 1% annually over that period as you can see venture to say that's very unique in our industry. We've added over 700,000 barrels per day of throughput since 2011 through low cost innovative optimization and expansions that's the benefit of the entire base and we've put a lot of capital to work to ensure high reliability of the system. As we prepared for expiry of CTS coming after June 21, we spent a lot of time understanding what our customers' priorities are today. What we heard back was pretty clear in the last two years was that they want us to continue providing the lowest and most predictable tolls possible and even more low-cost optimization. But this time around they also want guaranteed access to our system through long-term contract with us. So the point of all that is that, the offering we've designed is based on what our customers are asking for and to ensure the best outcome for all types of customers, producers large and small, refiners, integrated companies and marketers. On to Slide 11 now where I'll summarize the offering that why it fits our all of those categories. Over the last 18 months, we've listened carefully to industry and we made several changes to the offering. We're offering customers a choice between traditional take-or-pay commitments and what we call a requirements option that's like an acreage dedication which still gives customers guaranteed access to the system without the balance sheet commitment that goes with take or pays. We're offering toll discounts for larger and longer-term commitments, but importantly for all shippers when throughputs are very strong, so the benefit of increasing volumes out of the basin comes back to them. The chart on this slide illustrates that the toll offering for long-term commitments is at or below the toll, we expect under the current CTS. Our offering provides shippers with toll certainty for years to come and shows how we have the competitiveness of our customers in line and it will result in the best netbacks to producers of any alternative out there as you see on that chart on the right. For smaller producers, we lowered the minimum volume to 2200 barrels per day. That's more or less a single batch per month. For those who want the status quo, we're putting aside a minimum of 325,000 barrels per day for spot capacity, plus they can use any contract capacity that's not utilized. And we further optimize the system and this is important, we'll add that new capacity to the spot pool. I want to emphasize that this offering totally levels the playing field, producers, refiners, marketers or integrated companies can all participate. And most importantly it provides shippers with toll stability over time as you can see on the chart and importantly the best netbacks out of the basin. It was exactly because of these features that we received significant long-term binding commitments to participate in the open season even before it was scheduled to conclude and that interest and more is there today and building. Moving to Slide 13 and the next steps in this process, as you know the CER determined that the regulatory approval of the offering was needed before the open season. That's the path we're on and we preparing our application and evidence. So what does that look like? Essentially it's about demonstrating public interest. Our filing is going to show that our offering is available to all shippers, its fair and responsive to customer needs, will demonstrate the support we have and how we've taken the time to design this offering to meet the needs of all customers. That support will evidence the competitiveness of our offering with competing pipelines and alternative tolling frameworks along with pricing impacts. We always expected a comprehensive review. So we think there is ample time for CER to complete the review and hold an open season prior to the expiry of CTS in 2021. The bottom line is that, we're committed to moving ahead with this offering because it's what our customers want and continuing to support. Moving now on to the Gas business update on Slide 14, this quarter Bill and his team reached a settlement with our Texas Eastern customer. Given the size and scope of Texas Eastern, this is a key milestone for the business. The rates that we agreed to strike a good balance between ensuring we get a timely and fair return on our capital while assuring we remain highly competitive to key markets for our customers. The new rate takes effect after FERC approval which we expect to be in Q2. On East Tennessee we filed a settlement agreement there which the FERC approved on October 1, small rate reduction here, but not a material impact on revenue. We've also begun discussions with the Algonquin customers and we're hoping to reach a similar settlement on that system. More broadly though, you're probably picking up that this is part of our strategy to pursue more frequent rate cases in the future. On to Slide 15 as you know Bill and the team are working on several opportunities to expand our existing LNG footprint. We're positioned well in the Gulf Coast from South Texas to Louisiana where we can play a key role in supplying existing and new export facilities. In fact we've recently signed an important MOU with NextDecade to develop the Rio Bravo Pipeline, South Texas. That line will supply our Brownsville LNG project. And importantly, the line would be proximate to our Valley Crossing system, so we're in position to provide unique value to NextDecade. This comes on the back of other LNG supply deals Stratton Ridge and the Cameron and Venice extensions more recently that we signed earlier up this year. We're pleased with the momentum here to serve growing export demand. Moving now to the Gas Utility update on slide 16. Again, good progress here on synergies from the combination of two very large utilities. And ultimately, these synergies are going to drive out a very strong return on equity over our five-year incentive-based framework, which should exceed the allowed ROE in Ontario. In September, we received an OEB decision on 2019 rates, which was in line with our projection. Finally, we secured new growth of over $400 million this year in utility and made good progress on adding new customers, again demonstrating utility's reliable growth model. I'll wrap up on slide 17 with a summary of the secured project inventory list making good headway on advancing this $19 billion of projects. Gray Oak as I mentioned is line filling with volumes ramping in early 2020. Hohe See, our German offshore wind project should be fully operational shortly. In October, we began generating electricity from the first phase and the adjacent expansion right next door will come in before the end of the year. And with the combined capacity over 600 megawatts, this represents the largest German offshore wind project and our second European project in operation and first to ramp in the UK. So with that, I'll now hand it over to Colin for the financial update.

Great. Thanks, Al, and good morning everyone. I'll begin on slide 18 with year-over-year comparison of adjusted EBITDA. As I mentioned, it was another strong quarter, adjusted EBITDA is up just over 3.1 -- or at $3.1 billion and that's an increment of $150 million higher than Q3 of last year. As you can see here from the bridge visually, this was really driven by the strength in the Liquids business. Liquids Pipelines EBITDA was up $193 million and it's largely a continuation of the same trends we spoke at the last quarterly call. The Mainline system continues to run full averaging around 2.7 million barrels per day. And we also benefited from a 1% higher international joint toll that came into effect on July 1. Downstream, we continue to see strong volumes on Flanagan South and Seaway pipelines, thanks to strong demand for Canadian heavy barrels in the Gulf. Similarly, North Dakota production has contributed to higher throughput on the Bakken Pipeline System. Moving on to Gas Transmission, the chart shows our EBITDA down $94 million quarter-over-quarter, although most of this is the result of the asset sales in 2018 both the U.S. and Canadian G&P asset packages. However, in general, we continue to see strong utilization across all our Gas Transmission assets. We also had contributions from new assets like Nexus and Valley Crossing in the quarter, which were placed into service late last year. Another factor impacting lower EBITDA is the increased integrity operating expenditures, which I referenced on the last quarter's call. This will continue into Q4 and we complete our current inspection program. Gas distribution EBITDA was slightly lower for the third quarter. For the full-year, however, we continue to see higher distribution rates, growth in customer base and synergies from the amalgamation efforts in our two legacy franchises. So overall, a positive first nine months within our Utility business and in line with our expectations. Moving over to our Power business, which was up $9 million over last year. Two factors explain this, the first is slightly stronger wind resources across many of our North American wind farms and secondly the Rampion Offshore Wind farm in the U.K. was placed into service in Q4 last year, so that contribution is incremental this quarter. Energy Services, I mentioned on the call in Q2 that we had benefited from extremely profitable locked in margins over the first half of 2019. This quarter presents something much closer to a typical level, although still $17 million stronger than Q3 of last year, which was weaker than typical. Finally, Eliminations and Other increased by $29 million year-over-year thanks to favorable administrative cost recovery from our businesses and stronger foreign exchange hedge rates in 2019. Moving on to slide 19 for the DCF perspective, consolidated DCF per share for the third quarter was $1.04, a 12% increase relative to the third quarter of 2018. As you can see on this chart, most of the factors in our DCF calculation were positive quarter over quarter with a significant portion of the DCF per share growth coming from the strong EBITDA performance just mentioned. Other key drivers included lower maintenance capital due largely to our 2018 asset sales and I'll speak to maintenance capital for the full year outlook here in a second. Similarly, lower financing costs from asset sales proceeds we've used to pay down debt. And finally, stronger EBITDA performance as I discussed earlier within our joint ventures which are equity accounted for primarily Seaway and our Bakken investments. And along with new ventures placed into service like Nexus, we had higher equity distributions then we recorded in earnings. And finally, it's worth highlighting the impact of the 2018 sponsored vehicle volumes on our DCF per share calculation. It's really captured in two columns; first, the distributions to NCI were eliminated with the buy-ins, however, this is offset by the issuance of shares to execute the buy-ins. So, in summary, strong year-over-year DCF per share growth underpinned by our strong operating results. Turning now to Slide 20, and our financial outlook for the balance of 2019. As noted earlier on the call, DCF per share is expected to exceed the midpoint of our guidance range. First, we benefited from stronger liquids performance over the first three quarters. We also saw much better performance in energy services and a colder winter in the Utilities franchise in the first three quarters. But we aren't counting on more of this in Q4. In addition our original guidance included a December 2019 in-service date for Line 3. And the Line 3 delay, as a reminder, has a $0.04 per share DCF impact for every month of delay. So, we won't see that $0.08 this year And that's our largest guidance headwind. We also expect higher integrity expense in our gas transmission business in Q4, plus generally maintenance capital is seasonally higher in the fourth quarter across the enterprise and this will offset some of the strength in our operations. So, tying it all back together we expect to see full year 2019 results to be above the midpoint of our guidance range. As for 2020, we're finalizing the budget and we'll be sharing that outlook at Enbridge Day on December 10th along with our annual dividend guidance. Moving on to Slide 21, I think the message here is that our balance sheet continues to be in great shape. We've now received $6.1 billion of the $8 billion in proceeds from the 2018 non-core asset sales and we anticipate the remainder of the proceeds in the fourth quarter. As a result our credit metrics are well inside our longer-term target range with consolidated debt to EBITDA at the end of Q3 sitting at 4.6 times on a trailing 12-month basis and that should remain right around that level for the rest of this year. So, to summarize financially, we're now almost a full year into our equity self-funded growth mode. We've had strong financial performance we've made great progress on the balance sheet and our credit metrics are strong. Maybe before I turn this back to Al, I'd offer a brief comment on our capital allocation mindset. We continue to be disciplined on how we allocate shareholder capital and we have been for years and it's now part of our cultural DNA. And so we think through our capital allocation choices. First our overarching priority is to maintain financial strength. And this means protecting a robust balance sheet and living within our equity self-funded model, which we've adopted for a while now, having turned off our DRIP program last year. Next, we want to return capital to shareholders through a steadily growing and sustainable dividend, of course, while maintaining a strong payout. Currently, we returned approximately $6 billion annually or around 65% of our cash flows. And finally, we'll execute in our secured projects including Line 3 which will create significant further financial flexibility and we'll also take on new capital efficient expansions and optimizations of our system where we can earn great returns and strengthen our competitive position. Of course, we keep a close eye on risk and we compare all investment decisions against return of capital options. So, together we think this remains a shareholder value maximizing equation. I'll wrap-up here on Slide 22 with a quick reminder that we have our Investor Conference coming up on December 10th in New York and we'll be webcasting that live of course followed by an investor lunch the next day on December 11th in Toronto. This will be an exciting day for us where our leadership team can showcase our resilient business along with our enduring value proposition. We look forward to seeing you there. Al, I'll turn it back to you to wrap-up.

Okay. Thanks Colin just to close off here and summarize as you see on the slide here was another strong quarter financially. Our Line 3 the Canadian side will come into service in Minnesota the regulatory process is moving forward. On the Mainline, we're committed to the contracting of the system as I went through earlier we've got strong support for the value proposition that we're offering. We secured roughly $2.5 billion of new capital year-to-date, which will help extend our growth post 2020 and our balance sheet as Colin just went through is very strong. So all in, we're pleased with the quarter and the progress that we've made on the priorities we laid out at last Enbridge Day. So with that I'll turn it over to the operator for questions.

Thank you. We will now begin the question-and-answer session. [Operator Instructions] And our first question comes from Robert Kwan of RBC Capital Markets. Your line is now open.

Great. Good morning. If I can just ask first about L3R and the construction scheduling; previously roughly speaking, I think you're looking at call it six to nine months the construction window. I'm just wondering with the delays what you’ve lined out contractor wise, and also is that a linear kind of window with respect to whenever you get the ability to construct would it be six to nine months or is it dependent on what season you actually get that notice to proceed?

Well I'll start off Robert. It's Al. The six to nine months is a good range and should be consistent depending on when we start whether winter or summer. So that's part of the reason why we're going with the six to nine month window that you refer to. So I think generally that's a good a good estimate to use for construction on the rest of it it's not a long build as you know it's roughly 300 miles. So it's doable within that time frame. Guy on contracting can you explain where we're at?

Sure. We've been very active on the contracting side for a number of reasons obviously we want to secure them. But more importantly, our contractors have been an important force behind the coalition of support that we've had in Minnesota. So they've been supporting us throughout the state and with elected officials and regulators in terms of demonstrating support for the project and how they're willing to come into these communities and build it very safely. The other element of it is in conjunction with those contractors we are looking to again provide a lot of business opportunity into the tribes in Minnesota and that effort is under way in conjunction with our contractors and there is opportunity and contracts being sublet into some of those tribal businesses already. So we're very pleased with the way that's going.

And that's great. And if I can just finish on the Mainline contracting given you can't make everybody happy I'm just wondering if you can give some thoughts on the ability to actually get a regulatory decision that maybe threads the needle or the other part we heard a lot of opposition upfront. Do you think that those who you've got support some of which may be amongst the largest shippers in the Mainline today. Do you think there'll be more vocal in their support as you get into the regulatory process?

Yeah I'll start off Robert. I think we will see more support. I think some of the supporters are people that provided initial commitments through the open season, while we were doing that certainly expected that they would be providing a local support at the hearing. Certainly, I think with the process being reversed now you're going to see that support come through at the hearing more loudly than it came through in the first part. Guy anything to add on that?

No I would agree.

Okay. That's great. Thanks so much.

Okay. Thanks Robert.

Thank you. And our next question comes from Rob Hope of Scotiabank. Your line is now open.

Good morning everyone.

Good morning.

Maybe to start off on Line 5 we saw positive legal decision recently just want to get what you think the next steps are in terms of getting the tunnel potentially in place. And then secondly an update on the easement discussions and potential opportunities with the First Nations on the southern shores of Lake Superior?

Do you want to go Guy?

Yeah. So it's Guy. First off obviously, we're pleased with the decision from the courts around the tunnel agreements we spent a lot of time negotiating those and making sure that they represented a feasible path to build the tunnel as fast as possible. So to have them validated is an important step for us. The geotechnical work that we've been doing at the Straits, will be coming to a conclusion here shortly given, we're running out of the season. And that geotechnical work is giving us confidence that we're going to be in a position probably in the first quarter of next year to start making the necessary applications to pursue with the completion of the tunnel and that's exactly the path that we're on. In terms of Bad River we've got an offer out into the community and our ability to address more people in the community is generating a lot of constructive feedback in conversation. So we are not in a position to suggest that we have got a deal in any way shape or form just yet but certainly a lot more broad engagement.

All right. Thanks. And then as my follow-up I just want to dive further into your kind of capital allocation discussion. We're seeing some weakness in your US peers, could we see M&A trickle back into the mix? And secondly what are your thoughts on the 2020 dividend, are you still committed to the 10% growth?

Okay. Well, on the first part of that Robert, we always look at all the opportunities and what you pointed out is right. I mean, there is some changes going on in the US side and we're in a relatively good shape as Colin described. But I would say the M&A focus is not ours at the moment. We've obviously done the repositioning that we wanted to do around natural gas transmission in Bill's business and then the utility business that we added in Ontario. So the focus there was to reposition part of the asset base to more natural gas. So I think that's what we intended to do, that's what we did. So that's pretty much what we needed to do and no real further expectation of large-scale M&A at this point.

Rob, on the -- it's Colin. On the dividend, as I mentioned, we're going to communicate that dividend guidance at Enbridge Day in conjunction with our budget and strategic plan outlook rather than in isolation today. But I would highlight that we have increased the dividend consistently and substantially for the last 25 years concurrent with the return of capital mindset I referred to in my remarks.

Yeah. And just to connect another point on that Robert, I mean, as Colin alluded to, the dividend as you know has always been aligned to the multi-year look of cash flows. And given where we are overall in the business performance has been good in 2018, 2019, the asset sales are in good shape, the balance sheet is strong and we're in self-funding mode. So, overall, we think our business is positioned quite well and -- but as he said we'll be speaking to that in a few weeks.

Great. Looking forward to it. Thank you.

Thank you.

Thank you. And our next question comes from Michael Lapides of Goldman Sachs. Your line is now open.

Hey guys. Handful of questions. Thank you for taking mine. First of all, the surcharge on Line 3 in Canada, when does that go into effect the $0.20?

Closing on December 1…

Yes.

...we begin operation. So I think that's the deal, hey, Guy.

Yeah, that's correct.

So how do those -- if I'm a producer or shipper, how do those barrels get to market if Line 3 US is -- I mean are they just coming down and serving some of the Canadian refineries or just trying to think about kind of the flow of volumes off of Canada Line 3?

Well, yeah, so, obviously, the limitation to what we could do on Line 3, is that, we are not changing our operating parameters in the United States until Line 3 is approved and constructed in Minnesota. So one, you hit on the piece of the element, this does allow us to deliver incremental volumes within Canada. If you think back to Enbridge Days last year, we talked about how we had identified a delivery window in Regina, where as we delivered off into the co-op refinery, if we could find a way to get some crude into tankage there in Regina we could reinject back into the Line and move the barrels downstream. So that is one of the things that we're able to do now with the new Line 3 being in service. So I think you kind of have got the key ones already identified.

Got it. And one or two other things, just on TETCO rate case, how big of an uptick are we talking about just the EBITDA impact?

Yeah, so it's Bill, really positive outcome with the customers band it between $50 million and $70 million uptick from a revenue perspective, which translates pretty well into the EBITDA.

Okay. And then last thing and this one is kind of small piece of your pie, but just curious if you've had thoughts on it. One of the largest European wind developers Orsted just dramatically significantly revised down its guidance for wind output and even some of the costs associated with building new offshore wind. Just curious -- I think they are one of the biggest players in Europe, just curious if there's any read across to your existing or development projects, what are your desire to continue doing these type of projects?

Well, you know, given Vern has just come out of that area maybe we'll let him talk to that question for you. Vern?

Okay. Thanks, Al. Wind resource was something that we were very particular in modeling when we made these investments. And we as being conservative took definitely took a haircut in how the third-party consultants headroom modeled wind resource. So I think it's fair to say that we took 2% or 3% haircut on availability based on primarily how they view the turbines are to interact with each other and a couple of other factors. So I think from what we've seen to date on our farms, the resource is tracking to what we had modeled. And then on the actual construction costs, I think we took a different model than Orsted did. Orsted mostly got all of their wind farms where they've taken account of cost risk, the farms that we've invested to-date. We've transferred that capital cost risk to the project constructors.

And I'll just maybe add one thing that I recall Orsted talking about that was presenting challenges which is the weak effects. So where you're lining up projects next to each others said in those situations we try to be even more conservative just given the as we learn more information you always get smarter about these things but we're trying to be conservative. I think there was another part of your question that talked about what does it mean anything to us in terms of our opportunity set I think what they're doing is -- sorry what they're doing that we're focused on a pretty good inventory of three or four projects in the next little while that should carry us through for quite a while. So I think we're in good shape on the development side.

Got it. Thanks guys. Appreciate you taking my questions.

It's okay.

Thank you. And our next question comes from Linda Ezergailis of TD Securities. Your line is now open.

Thank you, and congratulations, Guy. Wish you all the best. With respect to the Mainline regulatory application, I'm wondering if you can help us understand, if the application evolves in any substantive way from your original open season or it sounds like it substantially the same? And I'm wondering if you're just continuing discussions this fall with the shippers or if that's paused pending the actual formal process? And kind of as a nuance for some aspects that I'm curious about how might you -- it's not clear to me how you'll treat the Line 3 replacement timing? Would you have it allocated to spot might you pro rate the contractual capacity until it's in service or might there be some other treatment? And any sort of off ramps or any other attributes that you are considering would be appreciated.

Linda, it's Guy. Thank you for your earlier comment. In terms of the application -- our approach to the application is largely unchanged. We always knew that in that proceeding. We were going to have to address the public interest requirements of the CER review. So clearly some of the issues that were raised in the preceding in front of the CER around impacts to producers and whatnot we fully expected that that we would have to address that anyway and we're going to be in good shape to do that. In relation to the customers we're always talking to the customers. One of the circumstances that we found through that process that has been run is that despite our best efforts to communicate with as many people as we can there is still some misinformation out there about what our offering is and isn't. So we're taking some steps to make sure that people are making their decisions about how to move forth with that filing on a common understanding of how the deal operates. But I think the critical factor is that we have a huge amount of support from a group of people that negotiated for 18 months with us to land on a TSA and an approach and we're committed to moving forward with that. The last part of your question around Line 3 is the way the -- first off we still believe and hope that Line 3 is going to be in service before the end of the CTS. So that it will not become an issue as it relates to the potential contracting in the Mainline, but the way our deal has been set up with shippers is that the contracting will not begin until Line 3 is in service. And if that means that there is an interim period beyond July 1, 2021 we will likely go with the continuation of the CTS tools, but they would be subject to refund any refund that might result when the contracting is implemented.

That's helpful context. Thank you. And maybe as my follow-up just further to some considerations around how you allocate capital. I hear you loud and clear no large M&A, but on the flip side I perceive kind of that your asset sales have been substantially completed and you don't need to sell assets. If you get approached for a very compelling price for any of your less core businesses or assets would you entertain any sort of asset sales and might that help maybe in closing what I perceive to be a gap in valuations in the public equity capital markets versus private money or might there be other levers you would consider to kind of close that gap whether it be through JVs with pensions et cetera.

Yeah, the short answer to that one – Linda, it's Al is yes. We're always looking at opportunities to recycle capital where it makes sense to release value. So there is a few things we have I mean we have largely eliminated the assets that don't fit the pipeline utility model which is great. But there are a few things here and there that we would act on if we got some compelling value for them. So and I think your point around closing the valuation gap is a good one. So, yes, we will recycle, we won't hesitate to do that for whatever is left in the non-core category.

Thank you.

Thank you. And our next question comes from Jeremy Tonet of JPMorgan. Your line is now open.

Hi, good morning. Just want to start with the Mainline here and it seemed that the volumes came in quite strong this quarter, and kind of exceed our expectations. And just wondering is this kind of a run rate that you guys think you can sustain, or is there anything that was happening here in the quarter, or just continuous effort to optimize capacity? And also with the Mainline, I think there was a comment that you had said before during the remarks where the Mainline could discount below current tolls, I think the long-term contracts. Just wondering I know it's kind of premature here, but your expectations for EBITDA impact in this -- with the next settlement, do you expect much of a change from where you guys are right now?

Hi, Jeremy. It's Guy. So our objective around as it comes to volumes and throughput and optimizations is to achieve exactly what you asked that we're in a position to sustainably move as much crude as we safely can. So we've got a team here that is highly focused on that day in and day out and they've been very successful. And I think it's one of the biggest accomplishments that we've got within our business units. So that is absolutely -- our plan is to continue to deliver that stuff on a sustained basis. As it comes down to the -- your question around Mainline contracting, on balance we expect that the outcome of that Mainline contracting effort is going to be pretty much similar to almost like a CTS continuation so to speak from an average toll and revenue perspective.

That's very helpful. And just one more if I could on DCP, your partner there took a write-down on DCP, so I wasn't sure if your tax basis was impacted as well here. And if that could impact I guess your future plans for DCP or is anything changed with the IDR simplification as far as ENB's view of DCP?

Yeah, hey, it's Colin. The first part of the question, the IDR transaction does not affect our underlying tax basis. And secondly, I don't want to comment on our partners' accounting practice, but they may have been carrying their investment in DCP at a different carrying value than we were having, I guess acquired interests in DCP at different points in time.

I think a broader question Jeremy. I mean, I think our position on this but maybe just to reiterate, the business itself doesn't fit perfectly with the rest of what we do at Enbridge in terms of the pipeline utility model. On the other hand, DCP has certainly migrated its commercial underpinnings to have more fixed fee and of course they have some good long-haul pipeline handset. So it's not as far off as it was perhaps in the past. So we're happy to hold the asset. And really our partners and us are focused on how can we continue to grow the business and deliver strong cash flow contributions from that business and that's where we'll have our focus.

That's very helpful. That's it from me. Thanks.

Thank you. Okay.

Thank you. And our next question comes from Robert Catellier of CIBC Capital Markets. Your line is now open.

Hi, good morning. I just had out two clarifications here one on slide 7, the Line 3 Replacement milestones. It doesn't really speak to any of the legal actions that might be possible, so appeals of the Route Permit or Certificate of Need. So to the extent you received the regulatory approvals, are you willing to proceed with construction while those appeals are pending?

Yeah, it's Guy. We've done that a number of times before with projects of this nature. And I think our expectation is that once again that if we have an authorization to construct on the Public Utilities Commission, we're going to start construction and there may be appeals that are running concurrent to that, but we plan to move ahead.

Right…

Right. Couple of things just to add -- sorry it's not changed, maybe just a couple of things to add, you'll notice on one of the blocks there, there is a time allowed for petitions for reconsideration by the PUC. So we blocked that end, but after let me see if I can add this up about 48 months now of regulatory review and having the PUC come down on Certificate of Need and Route clear -- the multitude of work that's been done, I think we really be as Guy said in good shape to proceed on those strengths.

Sure. I understand. And then just one more quick one on page 12 on the CTS contract framework that first chart in the middle that timeline seems to have 2024 plus, I think as I understood the intention was to have a much longer contracting timeline. So, how are we going interpret that 2024 plus?

I think that this is just to illustrate, how the toll stays very steady. And that's frankly one of the biggest attributes of this. I think, the contract offering includes either, take-or-pays or the other form of contract for up to eight to 20 years. I think, is the number Guy?

Correct.

All right, okay, understood.

Just ourselves…

Yeah. Congratulations Guy on the retirement.

Thank you.

Thank you. And our next question comes from Shneur Gershuni of UBS. Your line is now open.

Hi. Good morning, everyone. Most of my questions have been asked and answered. But I'm going to try them a little differently, I guess. With respect to the comments about returns and so forth, do really appreciate the comments at the end of your prepared remarks. But I was wondering, how we should be thinking about CapEx going through this period where the E&Ps are talking down production growth, rig counts have kind of fallen over 20%. How do you think about the next set of FIDs? And how we think about CapEx for 2020 and 2021? Are you only going to focus on projects with a very high return hurdles like a four times EBITDA multiple. Just wondering like how you're responding to the current environment. And should we be thinking that CapEx will be on the lighter end of your typical $5 billion to $6 billion range. And will the projects be mostly the ones that are, kind of in the low EBITDA multiple return hurdles?

Hey Shneur, it's Colin. Yeah. So we'll talk more about this on December 10th. But I guess as a teaser, I think, we agree directionally with what you're talking about. Well I think we use the words capital efficient a number of times in our prepared remarks today, which is purposeful and I think highlights our mindset on this. So for us, a lot of our businesses are Utility-like. And I think we're going to target more of our investments in franchise, so to speak, so, asset renewals, optimizations like we've talked about so, that are executable, high confidence, and enhance our competitive position, even defensively. So, we think we think of that as checking a lot of the boxes in our Utility pipeline mindset. So yeah, I think, I would agree with your overall assessment.

Maybe just a quick point to add on to what Colin said. It's a good observation about how things may be changing over that again in certain basins, particularly in the US and has been the case in Canada, already. For us other than being efficient with capital the commercial underpinning of these things is critical to us. So in other words, we're not as naturally inclined to take volume risk. And maybe go out on allege that in terms of what future production might look like, that is drilling dependent. So we're really focused on areas within franchise as Colin said, but also areas that give us the right commercial underpinning where we're looking at strong predictable cash flows, over a longer term. So that's another governor if you will, on the capital allocation process for us.

I really appreciate the color. Maybe as a follow-up question just going back to the CER and I'm sure we've beaten this one a little too much. But I really appreciated your views and they clearly appear to be grounded in precedent. But I was wondering if we can talk about the risks a little bit here, because given the decision a few weeks ago by the CER that already wasn't in precedent. So I'm kind of wondering if the CER cares about what you've negotiated with the shippers and what the shippers have told you or are they going to pursue their own independent study kind of as you go forward. Just trying to understand how that in the risks to the processing your expectations are?

Yeah. So it's Guy here. I'll take a crack at that. One of the things that I think we want to caution people about the CER decision that was made was the CER has not seen our offering. They have not seen our application. And they have not seen our evidence. So the decision that they did make was on a pretty narrow view of concerns to being raised by people who think they need to be opposed to it. We -- our view is that the CER's job is to listen to everybody in the process. They are going to have to listen to our evidence, and our experts. They're going to have to listen to people who might be taken countering views. The CER has staff who will be advising the commissioners on viewpoints to come out of it. But I think that, again at the end of the day, the driving -- the guiding light if you want to call it, that is the public interest. And that's why we have always been focused in terms of how this is going to play out? How we conducted ourselves to this stage, in being able to demonstrate that what we're planning to do is in the public interest? And we're confident that our filing is going to demonstrate that.

And just to tag on to what Guy just said -- if you go back to the slide that refers to the public interest 13, I think. What we outlined there, there's four things that determine that. Open access which will be clearly able to demonstrate, just in reasonable source and if you think about the chart where we're saying those have been just reasonable for a long time based on commitments provided by the shippers over CTS period. And now if you look at where the future tolls are looking to be, I think that's a check mark being responsive to the customer needs is a big part of public interest and demonstrating that it will be good from the basin's perspective from a pricing perspective. So those are the things that we have to demonstrate and we'll be putting forward in the application but as you point out that I'm sure there'll be different views on all of that.

All right, perfect. Really appreciate the color. Guy, congrats in retirement. And have a great weekend to everyone else.

Thank you.

Thank you. And our next question comes from Ben Pham of BMO. Your line is now open.

Okay. Thanks. Good morning. I wanted to go back to L3R in Slide 7, the sequencing of the milestones and I guess you've dealt with these timelines before and it seems quite visible from your perspective. And my question is in terms of in-service dates are you not updating that right now because you think second half 2020 is still achievable or you need to see that today Line move a little bit more to the right?

It's Guy. You can paint a plausible scenario that would potentially allow us to be in service in 2020. We will be ready. Yes the PUC and the agencies are able to move forth on that schedule. But at this stage of the game we certainly don't have enough line of sight to the timeline that these various steps are going to take. And until we get further through some of those milestones, we really won't be in a position to give narrow down when we think we can come into service.

So the approach Ben really I think is we need some further clarification on timing. I think we'll -- we know there is a December 9 date out there for the EIS to be finalized. I think as we get through that and we get more timing guidance from the PUC and the agencies that we can go from there if you will. It's just very hard to put an in-service date estimate without further clarity and we think that's the prudent thing to do in this situation.

Okay. Makes a lot of sense. And my next question maybe for Colin and I'm just curious directly on how you think about the dividend payout next few years when you look at your total return proposition. I mean historically it's been 10% growth, 2% to 3% yield so kind of double -- low double-digit total return. So are you at a point now where your cash flows are more stable you're contracting the Mainline that it's going to be more of the total return as you say and you can pay a little bit more than you have in the past?

Hey, Ben. I think I mentioned our current payout around 65% of cash flows and we think that's sustainable and prudent target. And I think we'll remain in and around that proportion going forward. You're certainly right, the utility pipeline model affords high payout and returning capital as I mentioned is important to us. So I don't think there is any change Ben, if you're looking for a vector here that proportion has served us well in the past and we see it as part of our value proposition going forward.

Okay Thanks. Well I just wanted to check and just given that I've seen a huge derisking of your cash flows in your balance sheet. Thanks for that.

Thank you.

Thank you. And our next question comes from Patrick Kenny of National Bank Financial. Your line is now open.

Hey, good morning and congratulations to both Guy and Vern. Appreciate the updated DCF per share guidance for 2019. But as we think about 2020 and I guess this might be another teaser ahead of Investor Day, but at a high level maybe you can just walk us through some of the headwinds and the tailwinds that you're seeing at this point for 2020 relative to 2019. Obviously, Mainline optimization Express and Seaway would be positives for the Liquids segment but just wondering about some of the other moving parts into next year?

Sure I can appreciate the community's interest in sharpening 2020 estimates. So I'll stop short of providing you that guidance. But maybe I can give you yeah, I can say a few big rocks to help formulate a preliminary view here. So I think to start high level 2020 should be at least as strong as 2019. And I'll give you three detractors year-over-year and three growth drivers. On the minus side I think we'll see moderating energy services contributions 2019 was fairly strong. We'll probably also see normal weather, at least will budget for normal weather in contrast to colder weather in 2019. And thirdly, we'll have the absence of asset sales closed in 2019. On the growth driver side, I think you've identified a few of them already. In the Liquids segment, we're going to see the Line 3 Canada surcharge, which is effective December 1 as you mentioned. We'll see mainline volume optimization as we've talked about to the top end of 100,000 barrels per day range. We'll see -- it's still in this bucket, the tariff and flatter and the Express capacity. And putting a similar quantum, we'll see contributions from some of the assets that we've put into service recently. The German wind farm, our investment in Gray Oak, Atlantic Bridge and other investments annualized. And thirdly, on the positive side, we should see contributions from Bill's Gas Transmission business, including rate case settlements when they become effective. So, some headwinds, but certainly some opportunities as well.

And I think just to add maybe one point as a clarification. I don't think at this point we're anticipating any Line 3 contributions from the U.S. side. So, I think last year obviously at Enbridge Day, we had assumed that for 2020, but that's not the case now. So that's sort of just as a background.

Okay. That's great. Much appreciated. And then, I might have missed it, but was there an update on the commercial contracting front for Texas Colt or the timing on when you expect to have that project fully committed?

Yeah. Pat, there isn't really much of an update right now. If you recall, our myriad application has been stopped. We had to design and make part of our application vapor recovery unit, which wasn't part of the initial scope. So that work is under way. I think we're hoping to get that back and submitted and the clock started as early as the first quarter of next year. Obviously, lots of conversations continuing with lots of customers, trying to drum-up the underpinning commercial support, and while there is a lot of conversations, we don't have anything to report just now, but we're certainly confident in the positioning of that asset vis-à-vis a range of upstream crudes that can get there.

All right. That's great, guys. I'll leave it there. Thanks.

All right, thanks Patrick.

Thank you.

Thank you. And our next question comes from Joe Gemino of Morningstar. Your line is now open.

Great, thank you. Congrats on the quarter. And just one quick question about Alberta's new potential easement of the curtailment if producers can move to market by rail, have you thought about any impact that may have on mainline values in the next year?

Yeah. We've been watching mainline volumes vis-à-vis curtailment since before curtailment was announced. We've been actively engaged on a very frequent basis with the province and keeping them up to speed on our plans to be able to offer more capacity. So that they can consider that additional egress as they contemplate how they're going to manage curtailment on an ongoing basis. The addition of rail is something that is causing us to look at this even more closely. So we continue to be highly engaged. I think while we all have to watch it very closely. I can tell you that whether it's the producers or whether it's people we speak to within the government. If there’s pipeline capacity available, that's where they all want the barrels to move first and we fully expect that that's going to happen.

Great, that's helpful. I appreciate the insights.

Thank you. And this concludes the question-and-answer session. I will now turn the call over to Jonathan Morgan for final remarks.

Thank you, Sonia. As always, our IR team is available to take any additional follow-ups you may have. And thank you everyone for your time and interest in Enbridge, and have a great day.

Thank you, ladies and gentlemen. This concludes today’s conference. Thank you for participating. You may now disconnect.