Enbridge Inc. (ENB) Q1 2019 Earnings Report, Transcript and Summary

Welcome to the Enbridge Inc. First Quarter 2019 Financial Results Conference Call. My name is Gigi, 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. [Operator Instructions] Please note that this conference is being recorded. I will now turn the call over to Jonathan Gould, Director, Investor Relations. Jonathan, you may begin.

Great. Thank you, Gigi. Good morning, and welcome to the Enbridge Inc. first quarter 2019 earnings call. With me this morning are Al Monaco, President and CEO; John Whelen, Chief Financial Officer; Guy Jarvis, President, Liquids Pipelines; and Bill Yardley, President, Gas Transmission and Midstream. 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 later today and a transcript will be posted to the website shortly thereafter. In terms of Q&A, we will prioritize calls from the investment community only. If you’re a member of the media, please direct your inquiries to our communications team who’ll be happy to respond immediately. We’re again going to target keeping the call to roughly an hour, and may not be able to get to everybody. So please try to limit your questions to one with a follow-up as necessary. And as always, our Investor Relations team is available for your more detailed follow-ups or modeling questions afterwards. So, onto slide two, where I’ll remind you that we will be referring to forward-looking information on today’s call. Now, by its nature, this information contains forecasts, 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 the non-GAAP measures summarized below. So with that, I will now turn the call over to Al Monaco.

Thanks, John. Good morning, everybody. Well, we’re off to a great start this year with record operating and financial results across all of our systems. So, I’m going to start by recapping the quarter, then, provide an update on the three main businesses, Liquids Pipelines, gas transmission and gas distribution. John is going to take you through the results and the financial outlook for the year in more detail. I’ll wrap up with a summary of our priorities for the year and mention the executive changes that we announced today. Before we get to that, here is how we see our business today in the bigger picture. The steps we took in the past year made us stronger and further derisked the business. We’re focused on what we do best, building and operating low-risk pipeline utility assets. Our operating performance has been very strong and the consistency of our financial results over the recent quarters bears that out. We strengthened our balance sheet with the sale of non-core assets, giving us the financial flex that we want. And that flexibility allowed us to eliminate our DRIP last year, which moved us to a fully self-funded growth model. Lastly, we simplified our structure. And now, we have all of the core assets under the Enbridge roof. With this strengthened position and the progress on the three-year plan, we can now look to sustained discipline growth, well into the future. So, moving on to the results on slide five. It was another strong quarter across the board. The Liquids Mainline is running full, our gas transmission systems were in a very high demand and Ontario utility hit record send out. We also benefit from the very strong quarter in the Energy Services business. But given narrowing differentials, we don’t expect that to continue in Q2. EBITDA came in roughly at $3.8 billion for the quarter, up almost 11% over last year, even after factoring in recent asset sales. Distributable cash flow was $2.8 billion, up 19%; that translates to a $1.37 per share, reflecting the newly issued shares for the sponsored vehicle buy-ins in Q4. John will cover the outlook in more detail in a few minutes, but the bottom line is that we’re maintaining our 2019 financial guidance of $4.30 to $4.60 per share in DCF. Turning now to slide six and the business unit updates, beginning with liquids. Given western Canada egress constraints, we’ve been working hard to safely move as many barrels as possible to support our customers. Our mainline was full this quarter; in fact, we hit a record. Despite more barrels moving on the system, storage levels in Alberta remained stubbornly high. Given that and given Line 3 isn’t expected to be in service now until 2020, we’ll continue to focus on optimizing our system. We’ve been working with shippers on ways to add 50,000 to 100,000 barrels per day of throughput. Next on to slide seven and an update on Line 3. And just a bit of context here first. Line 3 is a critical replacement project that enhances safety and reliability of a line and also the entire system. That’s the main reason why we have overwhelming support from stakeholders, be it landowners, communities, municipalities, labor unions and critically important to us, indigenous and tribal nations. Another reason is that we’ve been very -- gone through a very rigorous regulatory and permitting review, and that’s given people confidence that we’re doing things right. In Canada, construction has gone very well and will be done by the end of the month. In Wisconsin, the pipeline has been replaced and was put into service last year. And in North Dakota, we’ve tied in the border crossing, and have all the critical permitting in place. Now, in Minnesota, the regulatory phase of the project is now complete. As you saw this past quarter, the Minnesota PUC denied the last of the petitions for reconsideration of their decisions. This reaffirmed their view that the record clearly supports the need, the route and the thorough environmental review that’s taken place over the last four years. So, we’re into the permitting phase. In March, we announced the revised permitting schedule, which pushed the in-service date to the second half of 2020, as you know. And we’re now updating our construction schedule. So, on to slide eight to look at the specifics around permitting. First, a couple of weeks ago, the Fond du Lac Band issued all the environmental permits required for work within their reservation. This is an important milestone, given the scrutiny placed on the project by the band. So, we think it’s a great outcome. At the state level the DNR and the Pollution Control Agency, that’s the PCA, published timelines that provide milestones that should lead the permits by October 28. What you see here on the slide is the timeline for the PCA’s 401 water permit, which together with the Army Corps of Engineers 404 permit is the critical path. And we expect other permits will be completed within the window that you see here. We’re working with both agencies as well as the state to monitor schedule. And our job here is to ensure we’re providing any additional information required by the agencies on a timely basis, and that’s what we did. As you can see, we’ve hit all the early milestones. The PCA is currently working on finalizing the permit drafts which will go to the other agencies by month end. At that point, additional tribal and public consultation will get underway. While we’re on that point and just stepping back for a minute here, it’s important to clarify the public consultation we’re talking about here’s is to get local input, not another form to rehash the need for the project, which was done extensively over the last few years and as well through the PUC hearings. And it resulted actually in some good changes to the project. So, as assuming we have the state permits in hand by November, we’ll then finalize the federal permitting with the Army Corps. And that’s historically taken a month or two and work is actually underway there already. So, we hope to be wrapped up with all permitting around year-end. This does mean winter construction, which actually has some benefits from an environmental perspective, but it does add complexity. The team now is working on developing a new detailed execution schedule. And at this stage, we’ve confirmed that if all the permits are in hand by year-end, we can meet the in-service date at the second half of 2020. We will continue to refine the construction schedule until we have the final permits. The delayed schedule likely means higher costs on the U.S. section, although we’re running under budget in Canada. The matter of fact is that we may exceed the overall budget for the project but the returns remain very robust, and we don’t expect any cost overruns to be material to our financial outlook. Obviously, the project is important to everybody. So, we will continue to provide information regularly. Staying with liquids, slide nine is an update on mainline contracting. The Competitive Toll Settlement or the CTS, as you know, is set to expire in June of 2021. The cost competitiveness of the mainline, the reliability and market optionality that it gives us is driving shipper interest in our priority access offering. We’ve been in discussions for several months with all shipper groups being producers whether that’s small, large and integrated, and then refiners and marketers being the other two. Our goal here is to make sure we’re addressing customer needs. So, we’re taking the time to understand those needs well, and so we can structure the right offering. We are making great progress here, and we expect to launch in open season now in mid-July. The key elements of that offering, as you might recall, will be priority access for customers with contracted volume. We’ve also tailored the terms of the offering to accommodate all of our shippers, both large and small customers. We want to make sure that this is a fair and accessible offering leading to strong open season and a good regulatory process. We’re targeting to file with NEB before the end of the year and have the agreement take effect starting July 2021. So, turning now to the gas transmission business on slide 10. One big picture change for the gas business compared to the past is that you’ll see more rate proceedings. That’s because we’ve invested a lot of capital over the years and will continue to modernize the system. So, we want to make sure that we’re recovering that capital and earning solid returns on that capital. We have several proceedings on the goal right now. We continue to progress the Texas Eastern rate case, which is our first in almost three decades where we’re working hard towards a negotiated settlement. We’re close to an agreement on East Tennessee, and we’re preparing for early rate discussions with customers on Algonquin. And we’ve now closed out all other FERC 501-G proceedings on the rest of the pipes with no material impact to revenue. Onto slide 11 and an update on gas transmission opportunities. Again, let’s put some context here. The fundamentals that drove our Spectra acquisition a couple of years ago are even stronger today, mainly increasing industrial demand, gas-fired, power-gen and new petchem facilities. The system is very well-positioned for both supply push from areas like the Permian, Marcellus, and Western Canada, and demand pull from growing markets in the Northeast, Southeast and in the Gulf Coast. I’d like to focus on one key demand pull in particular being the growth in North American LNG, and that’s where we’re focusing on mostly on the slide here. For a number of reasons, the epicenter of this growth now is in the Gulf, and we’re in the middle of that action for sure. Valley Crossing, Texas Eastern and our B.I.G. pipeline hug the Coast from South Texas all the way to Louisiana. They draw gas from multiple basins including the Permian, East Texas, and all the way up actually to the Marcellus through our bidirectional Texas Eastern system. We supply gas to Sabine LNG today, and we’re interconnected to Cameron and Freeport, which are scheduled to start up later this year. And our network is perfectly situated to be the natural gas header of system to serve multiple new projects currently under development. On the West Coast Canada, our Westcoast Connector project has an environmental permit right away into Prince Rupert, which would tie back into our existing BC pipe system to source growing Montney supply. And even on the Atlantic Coast, we’re positioned there to serve projects in the Canadian Maritimes or further south into Philly. We’re working on a number of these facilities today in all of these regions as they look to secure pipe capacity or new infrastructure to serve their plans. We’re excited about the potential here, and we’ll keep you up-to-date on those opportunities. Over to slide 12 now for some comments on the utility business. Operationally, this business continues to perform very well with record gas send out for the quarter. As of Jan 1, we brought our two Ontario utilities together under the Enbridge Gas banner. We’ve already started to generate synergies here by restructuring the organization and integrating systems and processes. With these efficiencies we expect to be able to generate a return in excess of a 100 basis points over the allowed ROE. But, this is not just the synergy story, there’s excellent opportunity here for capital investment, which I’ll summarize on slide 13. Again, the business here is driven by very strong fundamentals, the most important of which is in-franchise population growth. The Greater Toronto Area is one of the fastest growing regions in North America. We’ve been connecting nearly 50,000 customers annually, and that should continue. What’s exciting is that recently passed legislation supports expansion of 50 to 70 new communities in the coming years. It’s a great example of how natural gas can drive economic growth. And lastly, our Dawn storage and transmission system continues to provide good opportunity to support growing demand from our franchise, as well as from utilities in the U.S North East who want access to this growing hub. And you saw today, we held a successful open season on the Dawn-Parkway pipeline that underpins a $200 million expansion on the system. And we expect this project to be in service by the end of ‘21.As I said before, the utility is a real gem in our portfolio with its regulated low-risk business model, but also as you’ve heard, an attractive growth outlook. On to slide 14. This table summarizes our $16 billion secured backlog of which we expect about $3 billion to come into service later in ‘19, including the Gray Oak line. The list now includes the $0.5 billion of new projects secured in ‘19 including the Dawn-Parkway expansion I just mentioned as well as the regulated electricity transmission investment in Northern Ontario and the acquisition of the Generation Pipeline in Ohio which will connect to Nexus. These projects fit nicely within our pure play pipeline utility business model and demonstrate solid expansion and extension of the franchise. As you can see in the table, the secured projects are diversified by size, geography and business. That’s the model going forward, very manageable, relatively low-risk singles and doubles. So, with that, I’ll now hand it over to John to provide the financial update.

Well, thanks Al, and good morning, everyone. I’m picking up here on slide 15, which summarizes Enbridge’s consolidated financial performance for the quarter, by segment, focusing as we usually do on adjusted EBITDA. As Al noted already, we’re off to a very strong start, driven by a number of factors, including strong operating performance from our core assets, incremental contributions from the $7 billion of new capital growth projects we brought into service later in 2018, as well as the impact of colder weather [ph] operations and some exceptionally strong margins in our Energy Services segment. We also got a bit of a lift from the impact of a stronger U.S. dollar on the translation of earnings from our U.S. businesses, although this impact was muted by the impact of our enterprise-wide hedging program, which is picked up on the line labeled eliminations & other, at the bottom of the table. So, diving right into the results. Consolidated adjusted EBITDA for the quarter came in at almost $3.8 billion, about 11% higher than the first quarter of 2018. Liquids Pipelines adjusted EBITDA was up just over $100 million for the first quarter, driven by the performance of both the mainline system and downstream pipelines. The mainline benefited from both an increase to the international joint tariff and record average quarterly throughput. Average deliveries ex-Gretna for the quarter were up 90,000 barrels per day over Q1 of last year, largely due to strong supply and continued optimization of the system. We also saw higher spot volumes in our Flanagan South and Seaway pipelines as more barrels were directed to the Gulf Coast as a result of outages at certain eastern refineries. And the Bakken system continued to perform very well, benefiting from growing throughput driven by strong production growth in North Dakota. Moving down the line, first quarter adjusted EBITDA from gas transmission and midstream was actually down about 6 million from last year. But this was largely due to the absence of earnings from the U.S. and Canadian G&P assets that we sold in the second half of last year. We continue to see very strong and steady performance from our core GTM assets. And contributions from Valley Crossing and other new assets bought into service over the last year substantially offset the impact of the divestitures. Gas distribution adjusted EBITDA increased by $47 million over the first quarter of last year. The strong uptick was driven primarily by the impact of colder weather in the regions served by our utilities. We achieved record dispatch days in Ontario in both January and February, positively impacting earnings during the quarter by about $33 million or $0.02 when compared to normal weather. EBITDA was further bolstered by the impact of customer growth and increases in the distribution rates applicable under the new rate-making framework that came into effect at the beginning of the year, upon amalgamation of our utilities in Ontario. Renewable power generation was down about $16 million from Q1 of last year, largely due to weaker wind resources and lower availability at certain facilities in the U.S. This more than offset the incremental contribution from Rampion Offshore Wind project, which is now fully operational. As mentioned, Energy Services had an usually strong performance in the first quarter. Adjusted EBITDA was up $154 million when compared to the first quarter of last year. The big increase was driven primarily by wider crude oil and natural gas location differentials in the latter part of 2018, which cleared opportunities to lock in profitable arbitrage margins that we realized in the first quarter of this year. As differentials have tightened substantially over the last few months, we’re not expecting as stronger performance from Energy Services for the remaining quarters of 2019. Finally, turning to eliminations & other, the increased quarter-over-quarter was mainly due to a combination of lower centralized services costs as well as the timing of the recovery of some of these costs from the business units which is more heavily weighted to the first quarter in 2019 when compared to 2018. So, taken all together, a very strong and predictable performance from our core businesses this quarter with some additional upside from weather, FX and Energy Services. I’m now moving to slide 16, which shows how the quarter-over-quarter growth in EBITDA I just went through, translated to bottom line distributable cash flow growth. As you can see, absolute DCF came in at $2.8 billion, up close to 20% relative to the first quarter of last year. This large increase was primarily driven by the strong business performance that I just walked through. But, there are also a few items of note below the EBITDA line that impacted the quarter-over-quarter picture. Maintenance capital expenditures for the first quarter were generally consistent with Q1 of last year and in line with expectations following asset divestitures. We do expect scheduled maintenance to ramp up over the remainder of the year. Financing costs were higher as a result of the term debt and preferred shares we issued to fund capital growth projects, but this was offset to a degree by the application of the proceeds from last year’s asset sales to debt reduction. Reported current tax was up, largely as a result of the stronger earnings from our operating units. The reported increase is mostly a reflection of the impact of U.S. tax reform and of our methodology for recording taxes and the timing of normal tax planning activity. Our full-year outlook for current tax is not changed materially from the guidance we provided back in December of last year. The very big drop in distributions to NCI was expected and is of course a direct result of our buy-in of the sponsored vehicles, which resulted in the elimination of distributions to the public and significantly increased available cash at the parent Company. Moving down the line, distributions in excessive of equity earnings were higher in the first quarter 2019 than 2018 due to strong operating performance and new assets placed into service by our joint ventures, all of which support a higher payout of earnings from those entities. Looking at the bottom line on a per share basis. First quarter DCF was essentially flat year-over-year. In a nutshell, the continued strong operating and financial performance of our business and the impact of accretive projects that we brought into service over last year essentially offset the dilutive impact of shares issued late last year to fund the buy-in of our sponsored vehicles and the increase in current tax I just explained. So, turning now to slide 17 and our financial outlook for 2019. As Al alluded already, we are off to a very good start. Our core businesses performed well right in line with expectations. The outperformance was mainly driven by the very strong results from Energy Services, which we don’t expect to replicate in the last three quarters of the year, and to a lesser extent colder weather in our utility franchise areas. And while we expect continued strong operational performance in line with our budget, there are a few headwinds that will offset the strong start in Q1 over the rest of the year. This includes higher integrity expense in the gas transmission business and the timing of O&A spending in general, as we spent a little less than we planned in Q1, but expect to catch this up, over the remainder of the year. So, absent other factors, we are trending actually a bit ahead of the midpoint of our 2019 guidance range. However, our original guidance had also contemplated a November in-service date for Line 3. So, the announced will remove about two months of projected Line 3 earnings and cash flow from our 2019 outlook. We’ve estimated that a one-month delay in Line 3 impacts DCF per share by approximately $0.04, so the impact in total will be roughly $0.08. So, all of that to say we still expect to come in within our 2019 DCF per share guidance range of $4.30 to $4.60 per share, and we’re working hard to overcome the Line 3 headwind and hit the midpoint of the range. Turning now to slide 18. Over the last couple of years, we’ve made very significant progress in reducing leverage and strengthening the balance sheet. Issuance of additional hybrid equity and the sale of close to $8 billion of non-core assets in 2018 has greatly enhanced our financial flexibility, which has enabled the shift to a self-funding model and eliminated the need for additional common equity to fund anticipated growth. Consolidated debt to EBITDA for the first quarter came in at 4.7 times on a trailing 12-month basis, based on management’s calculation, right in line with our longer term targets and rating agency expectations. And we don’t expect the delay in Line 3 to have a martial impact on our leverage ratios, although the trajectory of leverage reduction over the next two years will shift out a little. In 2019, the absence of projected EBITDA in the last two months of the year will be more than offset by lower debt balances as a portion of planned spending in Minnesota is delayed from 2019 to 2020. So, credit ratios of the margin should be a little bit stronger in 2018 than we’d originally anticipated. On the other hand, credit metrics in 2020 will likely be a little bit weaker then the forecast we showed at Enbridge Day as the bulk of the remaining spending on Line 3 will now occur next year, creating a very modest drag on leverage. But to be very clear, in any scenario that we can envision, leverage will remain comfortably within our longer term debt to EBITDA target range of 4.5 to 5 times through the completion of Line 3. And with the full year’s contribution of cash flow from Line 3 in 2021, projected debt to EBITDA will fall well below our long-term targets, creating a significant additional flexibility to pursue opportunities, going forward. And with that, I’ll turn it back to Al to wrap up.

Okay. Thank you, John. Before I wrap up, we’re on slide 19 here, I just wanted to touch on the executive changes that we announced today. For those of you who have followed us for a long time, you’ll know that we spend quite a considerable effort on succession planning at Enbridge. And this is part of the ongoing commitment we have to developing our people and providing new challenges and experiences. And of course, that’s good for the Company and shareholders. Most of you know, Vern Yu, who currently leads corporate development as EVP and Chief Development Officer. Vern is going to move to Liquids Pipelines as President and COO, looking after operations, engineering, asset management and pipeline control, and he’ll report to Guy Jarvis. Vern’s actually returning to Liquids after leading the commercial and BD part of the business and a member of significant strategic growth initiatives over the years. He’s held a number of roles at Enbridge over his 25-plus-years here. Replacing Vern as EVP and Chief Development Officer will be John Whelen. Of course, John is currently the EVP, Finance and CFO. Working closely with our business units, John will look after Corporate Development, Strategic Planning and Investment review along with Energy Services and our Renewable Power Generation group. Finally, taking on the EVP and CFO role and all things finance at Enbridge is Colin Gruending. Most of you know Colin from his most recent role as SVP Corporate Development and Investment Review and his 20-plus-years at Enbridge. Over that time, he’s held a series of senior finance, tax, treasury and accounting leadership roles. So, he’s very well experienced and suited for the CFO position. So, good continuity with these changes, and I’m pleased with the strengths and runway of the team. We’ll look forward to continued engagement of this leadership team with the investment community. So, finishing up then, with major priorities that we’re focused on this year. First, we’re going to be working very hard, as John mentioned, to deliver on our 2019 financial guidance. On Line 3, we’re working very closely with the states and the agencies in Minnesota on all the remaining permitting activities. We’ll be focused on securing long-term contracts as well on the main line, which will further derisk the system. Lastly, we’ve come through the largest growth phase in our history. We now want to fill the hopper back up and extend growth for years to come. And as we said before, we’ll assess all investments, though in the context of other capital allocation alternatives in order to maximize shareholder value. So, to wrap up. The actions we took in ‘18 to streamline the business, strengthen the balance sheet and refocus on our low-risk pipeline utility model, has positioned us very well. We’re off to a good start this year and we’ll keep advancing our strategic priorities over the balance of this year. So, with that, I’m going to hand it back over to the operator to open up the lines for Q&A.

Thank you. We will now begin the question-and-answer session. [Operator Instructions] Our first question comes from Jeremy Tonet from J.P. Morgan is online with a question.

Hi. Good morning. Congratulations on the strong quarter here. I just want to see, with regards to your guidance in 2020 plus that you had provided previously, granted, there is kind of uncertainty with the Line 3 timing and that’s going to impact how that shakes out. But just wondering, if you could provide any other thoughts as far where you see that guidance now versus what you guys had said before.

Okay. Jeremy, just to clarify, we’re talking about post 2020 guidance. And, I think as you recall, at Enbridge Day, we indicated that on average post 2020 we’d expect, based on the hopper that we see going forward and the strength of the current businesses that we’d be in that 5% to 7% DCF per share outlook. And so, nothing’s really changed on that front, as you’ve heard me say, and others talk about in the businesses. There is plenty of opportunity out here into that timeframe. So, no change on that going forward.

Sorry. I was thinking more about 2020 itself at this point, if there’s any thoughts that you could provide there. Sorry about that.

Okay, yes. Thanks. So, in 2020, as you know, we had guidance out there at $5 per share in DCF. And of course, since the Line 3 delay, we know that that will shift. And we can’t get specific on 2020 guidance at this point, until we finalize the construction planning and schedule for Line 3. And of course, that depends on the permitting, which we outlined in discussion here. But, other than that, we’ve provided general guidance, I would say, and John mentioned this as well in his remarks, it’s about $0.04 per share in DCF per month. So, that’s the sensitivity that we have for the timeline around Line 3.

Okay, great. So, everything else seems intact, it’s just this is the one variable that still monitoring at this point relative to 2020?

Yes. I think that’s the right way to look at it, Jeremy. In fact, as you’ve heard us say here, the business is running well, we continue to bring new projects on. So, I think we’re still very confident in 2020.

That’s helpful. Thanks. And just second one, if I could, with regards to Line 3 here and some of the legal actions taken by other parties out there with regards to oil spill analysis or tribal cultural resource study. Just wondering if you guys are concerned that any of these actions might impact the schedule or the timing for the Line 3 project?

Not at this point. I mean, as I mentioned in my remarks, Jeremy, this has been an extremely robust process around the environmental work. In particular, it’s gone through many months’ review with many points of consultation and expertise from a number of parties. It was reviewed by the ALJ and of course, after that - after hearing itself for the PUC. So, we think this is pretty robust and will withstand any challenges. But, I don’t know, Guy, do you have anything to add on that?

No, nothing to add.

Okay.

That’s all very helpful. Thanks for taking my question.

Okay, Jeremy. Thanks.

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

I was just wondering if I could follow up on Jeremy’s question. Specifically, in your 2020 guide, can you remind us exactly what you had baked in for Line 3?

It’s John, Shneur. Line 3 in our original guidance we’d assumed would have been in service for the full year of 2020, if that’s what you’re getting at.

Yes. I was just wondering what was that actual EBITDA number.

I think, the way to look at it is, as we mentioned in the previous question. Again, the guidance we had out there that we put out at Enbridge Day for 2020 was $5 per share in DCF. And if you assume $0.04 per month contribution in DCF, I think that’s the simplest way to look at it, Shneur. Depending on when it comes in, you can use that sensitivity to calibrate your outlook for 2020. Is that helpful?

Yes. No, that’s extremely helpful. Thank you for that clarification. Just with respect to this quarter’s results, you seem to have strong results due to basis differentials. You didn’t update guidance specifically for that. Is that because you believe it’s temporary in nature and should be normalized at some point this year?

It’s John, Shneur. I think, what I did mention in my remarks was, there is a few things developing over the balance of the year, which will serve to offset the very strong performance that we had in Q1, base businesses will continue to perform well. But, some timing around O&M expenses will impact that, some higher expense on integrity and our gas transmission business will serve to offset that to a degree. So, if you look at all those puts and takes, those are sort of what’s prevailing over the course of the year. So, I’d say, solidly within that guidance range, and pretty much as I characterized it. We need to work a bit to make sure we hit the midpoint.

Final question, the VLCC project, are there any discussions at all to merge the project, let’s say with enterprise where you’ve worked together with them in the past, or are you guys going to pursue as two independent projects?

It’s Guy. At this stage of the game, we continue to purse Texas COLT as an independent project. We’re out there competing every day. Still got work to do but still confident in our own project.

Great, perfect. Thank you very much, guys, and enjoy the weekend.

Thank you. Our next question is from Rob Hope from Scotiabank. Your line is now open.

Good morning, everyone. I just wanted to take a look at the Canadian Mainline. Can you update us on your thoughts to potentially add any optimizations there? Has that changed? As well as, if a Canadian portion is constructed by mid-year this year, any potential chance that you could come to in the quarter to shippers to put it in service?

Yes. So, it’s Guy. On the first question, we continue to look at those optimization opportunities all the time. With the delay in Line 3, it has us looking at some different things. So, we’re still confident in what we have been seeing since back at Enbridge Days in terms of the potential for 50,000 to 100,000 barrels a day. As it relates to Line 3 in Canada, we certainly don’t have the commercial underpinning today that would allow us to put Line 3 Canada into service. But, it’s certainly something that if our shippers were interested in, we’d be willing to have that conversation.

All right. Thank you. I’ll hop back in the queue.

Thank you. Our next question is from Robert Kwan from RBC Capital Markets. Your line is now open.

Good morning. Kind of coming back to the main line and with the contract in proposal, I’m just wondering you can update what you’re hearing from customers on that, what are the pushbacks as you think about some of your small producers and even some of the large producer commentary? Is there also a push to get you to negotiate in parallel something in lines of CTS extension?

Robert, it’s Guy. So, I think that the key points in terms of the way the nature of discussions or what I’ve outlined, our shippers are interested in priority access; they’re interested in toll certainty; they’re interested in the market optionality that our system provides. And that’s really the driver behind the approach. We’re responding to those shipper interests. We have a very diverse shipper group. It is very unlikely at any point in time that we’ll ever receive 100% consensus on just about anything that we would do. But, we are going to great lengths in terms of the way our offering is being developed to accommodate as many of the issues and concerns and opportunities that our shippers are putting in front of us. In particular, on the small producer side, producers can contract for as little as 6,000 barrels a day. The offering that is designed for producers is very customer-friendly, to use a term, in terms of their ability to access capacity. And we also know that there are people out there offering small producers who are as small as 500 barrels a day, the opportunity to participate in this program with firm capacity and downstream pricing access through these -- this aggregation of these volumes. So, we actually see the opportunity for small producers coming out of this program to get some things that they currently don’t have access to.

I think other than that, Robert, just two things. We’re -- I think, as Guy’s comments imply, we’re doing everything we can to make sure this process is fair but accommodating to all groups of customers, and we’ve got different streams of work here and teams working with each of the groups that’s been identified. So, our job is to make sure that we have an offering here that works for everybody. And hopefully that will allow us to move smoothly through the process. You mentioned also discussions around extension of CTS. I think that the response to our offering and our response to what customers desire here from us is pointing to recontracting the line and moving in that direction as opposed to extension of the current commercial deal.

Got it. If I can just clarify something on that answer, Guy. You mentioned optionality. Is the anticipation here to have back-to-back or a concurrent, open season refining in South Seaway extension or some sort of other flow path options such as one in the eastern Gulf Coast?

At this point in time, the direction that we’re proceeding will be around existing capacities only. Depending on the outcome of that process, we will then begin evaluating whether there’s some other steps we need to take.

Okay, got it. If I can just finish, Al you mentioned additional rate proceedings on the gas pipeline side. So, just to clarify, for Texas Eastern you talk about revenue enhancement, I assume that’s a positive. I’m just wondering, as you look at Algonquin, is that similar, or is it something where you’re trying to get out in front and stay ahead of the Section 5 proceeding?

Yes. So, basically, really all of our rate base is going up, Robert, over time. It’s been a while, as you know, since we filed rate cases on all these systems. And yes, you’d expect revenue enhancement on all these. What the question is just timing. With Texas Eastern, we’d expect to hopefully settle something by late summer, early fall. If not, we’d go into litigated rate case. Algonquin is probably a little bit later than that, and East Tennessee perhaps even beyond that, but all probably within the next year.

Thank you. Our next question is from Joe Gemino from Morningstar. Your line is now open.

Great. Thanks for taking my call and congrats on the great quarter. How do you think about the priority access with -- on the mainline with potential good news coming from the Trans Mountain expansion in the next month or so?

Yes. It’s Guy. We don’t see a lot of impact in terms of those types of decisions that may or may not come in, in the near term around competing pipelines. Our customers are after priority access on the system and the market access opportunities that we offer. And we don’t, for example, see customers sitting in front of us and saying well, I’ll do X on your system if that pipeline is delayed and something less than X if it’s going ahead on a particular time. There’s people that are focused on shipping on our system seem to be making those decisions independent to what might go on, on competing pipeline.

I think one of the key things too just to add on what Guy is saying, you really have to look at the fundamentals of where our infrastructure is connected to. So, if you look at the markets that we serve, we’re directly connected to huge capacity in the U.S. Midwest and then now, into the Gulf Coast. So, I think this is more about the fundamentals of the markets we get to and the fact that we get there at the lowest possible cost. And so, the optionality, the low cost, the ability to have flexibility in this priority access offering or offerings that are very attractive to our customers regardless of what’s happening with other options.

Great. I appreciate the response. Thank you.

Thank you. Our next question is from Praneeth Satish from Wells Fargo. Your line is now open.

Hi. Good morning. Can you talk about your willingness to be a partner on the Capline project, either as a shipper or part owner? And I guess tied to that, do you need to wait for the open season on the Mainline to conclude before making decision on Capline?

It’s Guy. So, a number of questions. I don’t think at this stage of the game we’re contemplating being a shipper on Capline. As we’ve said all along, we’re very interested in looking at that opportunity for Canadian crude when the Capline owners get around to considering that mark fulsomely. The current plan they have in place is clearly targeted at light barrels and less so heavy barrels. And when the time comes that they want to pursue that, we’re happy to engage.

Just, again just a bit of expansion on what he’s saying. Fundamentally, it does make a lot of sense. I mean, obviously, we already connect to the Western Gulf, and that’s a big plus for us. But, if you look at the fundamentals of Canadian heavy, there’s a good market for heavy barrels in the Eastern Gulf. And the opportunity that we bring too to this kind of thing is through some kind of joint tool all the way down into that region, so I think it makes a lot of sense. We’ll just have to wait and see what happens on various fronts between now and getting those heavy barrels ready to go.

Thank you. Our next question is from Dennis Coleman from Bank of America. Your line is now open.

Great, thanks. I guess, if we can explore the LNG initiatives a little bit more, I know this has been talked about quite a lot, and you spent time on it in your prepared remarks. But, just trying to think about the scale of what the opportunity is here. And as we start to see some of these facilities approve by the FERC, is it just in the pipeline side of things? Is there a situation where you would get into the liquefaction piece of it?

Hey, Dennis, it’s Bill Yardley. So, yes, first, our primary interest would be in pipelines for some of the facilities, it’s what we’re good at. Generally, we’re really well positioned to serve what are the Gulf, Western Canada, and a chance anything happens on the Atlantic side. We’ve got really good infrastructure there and building upon that’d be great. Scale really depends on, which facility you’re talking about. These could be -- they range from a small $100 million, $200 million laterals to multibillion dollar lines, particularly on the West Coast Canada or South Texas. So, I think that’s probably the answer to scale of pipeline opportunities and our focus. When it comes to liquefaction, we’d certainly explore it and be interesting to look at, but it’s not our primary focus at this point.

Okay, thanks for that. I guess, my second question is a little bit about leverage or maybe more broadly capital allocation. You’ve been pretty clear about leverage and your targets, and that it will sort of tick up a little bit next year. But then, you talk about being well below your range in 2021 and beyond. And that obviously raises the question of do you move to a lower leverage target? Do you hold that target and use the funds obviously for reinvestment but potentially share repurchases or things like that? How do you think about the capital allocation with regard to leverage in the 2021 and beyond?

Maybe I’ll start off, Dennis. So, if you look at what we’ve talked about just a few minutes ago around the outlook in terms of our DCF growth, I mean, you could actually get there through organic investment, which is our base case or you can get there by other means around buybacks and other options that are there. So, I think we’re going to be pretty diligent about assessing all the options. The reason it’s the base case in organic investment right now is that we think we have a pretty good hopper out there that can generate good projects. And what I mean by that is projects that are right in the core business, either expansion or expansion of the current franchises in all three of the main businesses, and then, of course, the power business as well, on the side is -- are all good opportunities. So that’s the base case. And in terms of the leverage component, maybe John can add on this. I mean, you’re right. In 2021, the leverage number would move down below the range, which to me is a pretty good option. And from there, it makes the capital allocation choice, I guess, flexible from our point of view. We can use some of that capacity, or if we don’t see those opportunities, then we’re looking at potentially buybacks or other uses of the capital. So, that’s the general outlook on leverage and how we allocate capital.

Yes. Nothing further. I think that’s exactly right. It’s all about flexibility.

Okay, great. Thank you.

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

Hi. Thank you. Just a follow-up to some of the CTS questions you’ve been fielding. You addressed Robert Kwan’s questions about how you accommodate smaller producers versus larger. But, what about -- is there anything that needs to be done to balance the interest of producer shippers versus non-producer to ensure reasonably smooth outcome on the regulatory proceeding?

It’s Guy. Yes. The way that plays out is that we’re going to have to have an open season process that provides for open access per the rules of the National Energy Board. So, it’s not really a situation that Enbridge can have an overwhelming influence on. It needs to be a fair and open process and that’s what we’re planning to run.

Okay. Thanks for that. And then, just a follow-up. You’ve touched on the 5% to 7% DCF per share growth beyond 2020. Wondering what outcome on the CTS in terms of pricings and volume certainty is baked into that 5% to 7% growth number?

Well, I’m not sure we’re going to get into the granularity of that beyond 2020 for sure at this point, Robert. I think, generally, speaking, you could assume an extension of what we’re seeing today in terms of the revenue from the main line. I think that’s a good overall assessment you could use for what it contributes. But, I think that’s about all the detail we can provide now.

Yes. That’s helpful. Thank you.

Thank you. Our next question comes from Matthew Taylor from Tudor Pickering Holt & Co. Your line is now open.

Hey, thanks for taking my questions here. Just can you clarify the timing on downstream expansions? I know, as mentioned to some other questions on Flanagan South and Seaway. Are these commercial discussions ongoing or are you waiting until after the mainline settlement application is approved or even Line 3 construction is started? Just trying to understand the drivers there?

So, it’s Guy. Obviously, we’re talking to people about things like that all the time. The plan we’re on right now is, it doesn’t really make any sense for us to be spending any detailed time on things like that until we have a better sense for how the open season process and contracting will play out on the existing capacity that we have. So, how the current process plays out and what we learn about that in terms of demands for our systems, will dictate the next steps that we might take on Flanagan South or Seaway or any of those other downstream pipes.

That’s great. Thanks and then one more clean-up question here. Can you provide some more color on NGL infrastructure opportunities you noted in the slides, including Aux Sable, does that dovetail with an Alliance expansion?

It could. Yes, it could dovetail nicely if we do an Alliance expansion that it obviously require more processing at the Aux Sable facility. And then of course, in Western Canada we’ve got some liquids in trains and the gas stream on north [ph] which could potentially result in some NGL opportunities there too.

Great. Thanks for taking my questions.

Thank you. Our next question comes from Ben Pham from BMO Capital Markets. Your line is now open.

Okay, thanks. Good morning. And this question is probably for Bill and it’s on some of the comments around LNG Westcoast Connector. And I’m curious if your, how are you guys, if any positioning is this project going forward, when you compare it to how Spectra was looking at in terms of partnerships, capacity? And if you could just share just difference to your Investor Day of this project, do you think that the probability of that has increased or not?

Probably about the same, Ben. It’s I don’t want to say early days, mid days, right? So, we’ve been talking to a number of potential shippers, the scale of the project, maybe a bit different than what we were looking at in the Spectra days. But not a whole lot has changed from Investor Days. Yes, and I know, that’s not a lot of detail, but I’ll leave it there.

Okay. And maybe the T-South pipeline, maybe just a quick commercial update on? I know last year, it’s put some a little bit here, but just really in line with in-service, but anything you can share on that project?

Yes. I think, we are -- we saw a little bit of -- we see a little bit of pressure on in-service on that project. I believe we had 2020 originally, and we may be pushing out to 2021 with some of the, any de-activity that was announced, not too long ago. So overall, commercially looks fine, but perhaps delayed six months or so.

Okay, all right. Thanks a lot, Bill.

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

Good morning, guys. I’m just wondering if we could start with an update on Line 5, and your discussions with the Governor with respect to the title and when we might see a resolution there.

So, it’s Guy. Not really going to get too far into that. We continue to operate Line 5. We believe it’s safe today and it’s going to be safe for many years to come. The tunnel option in our view is an opportunity to make already safe pipeline even safer going forward, which is why we’re so interested in it. And other than to say, acknowledge, as the Governor said that we’re talking, we’re not going to go into any more of those details today.

Fair enough. And then, just to circle back on the mainline open season here, and the contract term, I know you’re looking for up to 20 years with some of the larger customers. Would there be a minimum term for the smaller producers, Guy, or does equal access, allow for shorter term say annual maintenance?

I think we don’t want to get into what this entire commercial offering is until it’s fully baked. All I will say about the opportunity for the small producer and the nature of the contract that is being offered is that the -- there is a minimum terms, but there is flexibility within the offering that should not put them in a position that is untenable.

And we’ll have spot capacity reserves as well.

Sounds good. And then, just lastly, can you remind us if reversing the Southern Lights will be part of the conversation with shippers this summer, or is that completely separate from the priority access offering we shouldn’t expect new agreements on Southern Lights for at least a couple of years?

So, it is completely separate. And again, it goes back to my earlier comments that until we see how the contracting plays out on the mainline with the existing capacity, we’re actually not that focused on any options to increase capacity at this time.

Okay. Sounds good. Thanks for that, Guy.

Thank you. Our next question is from Andrew Kuske from Credit Suisse. Your line is now open.

Thank you. Good morning. If you manage to get the mainline in a contractual framework and you grow all interests, [ph] if you have these longer term contracts, if it derisks the line, you can offer lower tolls. But is there a financial consequence if you could actually put more debt on the line to enhance returns for Enbridge?

Yes. It’s John, Andrew. Overall, our system, taken in the whole, is very low risk system, the agencies technology that in their evaluation of credit. And I think that in this circumstance, at the margin clearly, there is a little less overall business risk. I don’t think that leads us necessarily to fairly to lever the business up anymore than it would have otherwise. And if you think of that range that we’ve adopted, I think we’re all within that target range, if you will, in terms of sensitivity.

Okay. That’s helpful. And then, if I may, just a follow-up, and probably more for Guy. If you look at the quarter and the volumes you had on the system, on the mainline system, did you effectively see lower heavy volumes through the pipe than you saw greater amount of blending and higher lighter value products that have a higher value to them?

No. I don’t think we really saw that playing out. The issues that played out for us in the first quarter, first off, we had no planned maintenance in the quarter. So, we have gotten very particular about planning our maintenance in conjunction with planned refinery turnarounds and what not. So, we had -- the availability of capacity was high. We saw strong performance out of both the heavies and the lights from a supply side of thing. And the only nuance, and John referenced it a little bit, was the cold weather did impact the performance of some of the pad 2 refineries which then saw barrels redirected down Flanagan South as opposed into the Eastern part of pad 2. So, that was all a positive outcome from us, but nothing of the nature that you’re talking about in terms of the crude slate.

Thank you. This concludes today’s question-and-answer session. I will now turn the call over to Jonathan Gould for final remarks.

Thank you, Gigi. That was a good discussion on the call today. And as always, our IR team will be available to take any additional follow-ups you may have. So, thank you to 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.