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Enbridge Inc
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Welcome to the Enbridge Inc. Second Quarter 2019 Financial Results Conference Call. My name is Gigi, and I will be your operator for today's call. [Operator Instructions]Please note that this conference is being recorded.I will now turn the call over to Jonathan Morgan, Vice President, Investor Relations. Jonathan, you may begin.
Thank you, Gigi. Good morning and welcome to the Enbridge Inc. Second Quarter 2019 Earnings Call. Joining me this morning are Al Monaco, President and CEO; Colin Gruending, Chief Financial Officer; Guy Jarvis, President of Liquids Pipelines; John Whelen, Chief Development Officer.As per usual, this call is webcast, and I encourage those listening on the phone to follow online with supporting slides. A replay and the podcast of the call will be available later today, and a transcript will be posted on the website shortly thereafter. In terms of Q&A, we'll 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 going to target to keeping the call to roughly 1 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. And as always, our Investor Relations team is available for more detailed follow-up questions afterwards.On Slide 2, 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 the call over to Al Monaco.
Thank you, Jonathan. Before we begin, I'll comment on the incident and fatality yesterday on our Texas Eastern Gas pipeline in Kentucky. Our hearts go out to the family and the community. Our first concern, of course, is for those impacted. So we've mobilized resources to assist and support them. Secondly, we're working with the federal agencies to investigate what happened and how the learnings can improve our approach and that of the industry in the future. Bill Yardley is on site, so we'll cover off for him on today's call.Turning to the quarter, I'll begin by highlighting the results and full year picture, followed by a business update. And as part of the liquids update, I'll speak to the recent headlines related to Line 5. Colin will then take you through the financial performance, and I'll come back at the end with a midyear progress review.Second quarter numbers were strong, driven by high utilization across the businesses. What's to note was continued high liquid throughput, especially in the Mid-Con Region and Energy Service margins. Q2 DCF per share increased 4%, which is a very good result given the share issuance related to our four sponsored vehicle roll-ups in Q4 last year.Importantly, strong first half results should allow us to come in about the middle of our $4.30 to $4.60 per share DCF guidance range, another good outcome in that we expect to fully mitigate the 2019 impact of the Line 3 delay, which was about $0.08 a share.Over to Slide 5, beginning with liquids. One of the things, as you know, we are focused on is low cost organic expansions that boost returns by enhancing revenue and minimizing our investment. Since 2015, we've added 450,000 barrels per day of capacity, which has been good for customers and illustrates the flexibility and scale of the Mainline system. This quarter, we finalized plans to add another 85,000 barrels per day, which will be ready later this year. We've also landed on an ultra-low-cost expansion of 50,000 barrels per day on express. We're in Open Season now on that one, and should be ready in Q1. In the Bakken, our partner is in Open Season that could see the Bakken system increase capacity to over 1 million barrels per day. So very good progress on low-cost, in-franchise expansions.Continuing with Liquids on Slide 6 now. This morning, as you saw, we launched our Mainline Open Season. That'll run for 60 days, followed by the NEB filing, which leaves a good amount of time ahead of the July 21 expiry of the current CTS agreement.We've outlined in the past, the key aspects of the offering and repeated them here on the slide. But here's how we got to this point. Our new contract offering responds directly to what customers are asking for. They've told us they want guaranteed access to our system, which serves the best markets in the Midwest and the U.S. Gulf Coast. They want and need the lowest transportation cost system to those markets and they want long-term total certainty. Those are the factors that drove our offering, and we've spent the last 9 months listening very carefully to customers and refining the offering. That long period of consultation led to improvements that we've incorporated in the Open Season; namely, balance access for all types of customers whether they're producers, integrateds, refiners, marketers, [ they've had ] total discounts for long-term contracts and, importantly, ensuring smaller producers have access to the system. We've got a diverse shipper group with sometimes conflicting objectives. But we believe this offering addresses differing perspectives. And the nice thing is that all potential shippers will have access to the system. So we're on our way here, and we'll await the results of the Open Season.And now onto Slide 7, and the status of Line 3. Given the recent EIS court ruling, we wanted to make sure everyone had the steps and sequencing that will go into completing the permitting process. Those are the items in the bars here on the slide. For context, the EIS was prepared by the state over a 16-month period. So it was comprehensive and thorough, to say the least. The state agencies, the administrative law judge and then the PUC, through an extensive hearing process, reviewed the EIS and agreed it was complete. But despite all that, as you know, the court upheld one appeal that now requires some added analysis at one site. The court unanimously dismissed the eight other appeals, but three of those were then appealed to the Minnesota Supreme Court. The Supreme Court will rule whether they will hear those by September 3.The PUC believes there's a strong case to deny that review, the appeals, and they've already filed against them. The next critical step is for the PUC to set the timing to recertify the EIS. Because of that, we won't be in a position to provide an expected in service date until we've evaluated the PUC's time table.What's noteworthy is that the PUC has publicly indicated they'll work expeditiously to complete the work. The permitting agencies have also committed to work in parallel with the PUC process, so that is good news.Finally, we all agree we've got to get on with it and replace the line, after all, this is a safety and reliability project. In the meantime, we'll continue to prepare it for construction.Before we move to Gas Transmission, I'll briefly comment on Line 5. We're now on Slide 8. Line 5 provides, as a reminder, 540,000 barrels per day of supply that's absolutely essential to the entire region, and 40% are refined products in Michigan alone. The line is operated safely, and our regulator and others have validated that time and time again. Despite this, we've listened to Michiganders and made a commitment to replace the [ Straits ] Crossing with a tunnel, which virtually eliminates risk to near zero.Various experts in Michigan itself agree with the tunnel. The only misalignment with the state is timing. We can't complete the tunnel in 2 years; it's simply not physically possible as the tunnel needs to be engineered, permitted and constructed, and that takes time to do right.Line 5 needs to operate during that period to avoid supply disruption through the region and increased consumer energy prices from that. To maintain [ schedule ] though, we've proceeded with a geotechnical program this year. Hopefully, we can put all the legal wrangling aside and focus on collaboration with the state to get the project done as quick as possible.In Wisconsin, there's been a recent challenge to the easement on one of the tribal lands, as you know. But first, let me give you some context here on the bigger picture. Almost 100% of the easements across our systems are perpetual or very long term. So very few need renewal that often, if at all. Where they do, we work closely with landowners well in advance of expiry, and we incorporate new commitments to address any concerns.We take all of our landowner relationships very seriously; it's what we do. And in all cases, tribal easements have been renewed successfully. For example, we just extended easements with Fon Du Lac and the Lac Courte Oreilles Bands in Minnesota and Wisconsin.In the case of Bad River, we've been engaged with the band for a number of years; in fact, we've had good discussions, progressed maintenance. We've shared a lot of information about our operations with the band. We were being attentive in our view to their concerns in discussing various aspects of the easement, so we're not sure what led to the legal action.The approach we take is to work collaboratively with all right-of-way communities and will continue to work with the band to address any concerns. And as they've said, they're open to discussions as well. This could include options like rerouting the 12-mile section. But we don't want to presume that until we get their full input.Bottom line is that we expect to reach positive outcomes on the Line 5 business issues in the near term.Turning now to gas transmission. A key focus of ours is to capitalize on LNG growth as you've heard us say before. We're in great position as our gas systems follow the U.S. Gulf Coast from South Texas to Louisiana. We currently supply Cheniere at Sabine Pass and Cameron plants, and we're making good progress on further build-out.This quarter, Stratton Ridge went into service, which flows gas to Freeport LNG. And today we've announced that we've been selected by Venture Global to serve their Plaquemines facility in Louisiana. This follows closely on the heels of global [ slackness ] last year, to serve their Calcasieu LNG facility in Louisiana.We're happy with momentum here to expand and extend our gas pipeline network by capitalizing on our competitive position.Finally on gas, it's been a busy year in terms of rate filings. We're progressing well and expect to reach settlements on Texas Eastern and Algonquin later this year. On East Tennessee, we filed a settlement agreement this quarter, and we should get a FERC order shortly.Moving on to the Gas Utility on Slide 10. This business is performing very well and growth continues on a few fronts. We're moving forward with two modernization projects, which brings year-to-date secured growth to about $400 million, including the Dawn to Parkway expansion we talked about last quarter. The Owen Sound Reinforcement and the Windsor Line Replacement will each earn solid returns under our new regulatory compact, and they'll be in service in late 2020; so full year contribution in 2021.We're also on track to add another 50,000 customers this year. And Ontario's support for community expansion means we have more runway to grow the utility. And those are the white circles that you see on the map.Finally, we're making progress on the amalgamation of the two utilities which drive synergies for us and will generate good margin over the allowed ROE.I'll now cover the positive FID we announced today on one of our offshore wind projects in France, Saint Nazaire. But before that, let me provide some context for everyone on how we see the offshore wind business. This is now on Slide 11.First of all, it's very clear that energy demand will continue to grow for decades to come. But the fact is, we're going to need all sources of energy, both conventional and renewables to meet that demand. We've got ample runway to invest in our pipeline utility businesses. But our approach has been to invest renewables where it makes sense.We've gradually and slowly developed the business over the last 15 years. Today we've got 21 renewable projects and a growing offshore presence in Europe. Last year, we monetized about half of most of our onshore projects to capitalize on the external valuations we saw and recycle cash for other uses in the business.The fundamentals of offshore wind are positive; namely, an increasing share of electricity demand that will be met by electricity, shifting consumer preferences as we know and mandated renewables targets, and significant improvements in technology and greater scale that's driven down costs.In terms of capital allocation, though, offshore renewables meet the same investment criteria [ as for ] the rest of our business. They line up very well on return, predictability of cash flow, execution and our ability to manage CapEx risk and they have room to grow.Moving on to Slide 12. European offshore wind is our focus now, driven by the strong fundamentals that you see here itemized on the chart. Importantly, we've seen a major improvement in the depth and sophistication of the supply chain in Europe, and that's part of the cost improvements that we've seen.We built a strong business by aligning with great partners, developing our own capability and bringing our execution skills around offshore and the wind generally. We've got a nice portfolio of operating and development projects. Our U.K. Rampion project is in service, and Hohe See in Germany is progressing well for late this year. Combined, those two projects are actually 1 gigawatt of capacity.We have three late-stage development projects in France. All three have just cleared permitting, and we are recently awarded another PPA. This week, we've FID-ed the first one of these in the queue, Saint Nazaire, with our partner EDF. This is the one on the northwest coast that you see in the slide. Our $1.8 billion investment comes with a mid-teen return. But what we really like about it is that PPA comes with embedded protection for wind production variances. So you've got excellent transparency to cash flow, and this is actually a very unique PPA structure.Importantly, this [ is at ] project finance, which results in minimal equity requirement by us of about $300 million equivalent. So it's easily falling within our self-funding plan. And we'd expect to be generating cash flow by late 2022.Moving forward with Saint Nazaire makes two other permitted France projects more likely to be FID-ready over the next 12 to 18 months. But that, of course, will be subject to the same investment criteria that I mentioned earlier.I'll wrap up on Slide 13, with a summary of the secured project inventory. The slide here is basically the running balance of secured capital which now sits at about $19 billion, so an increase of $2.5 B this year so far.All this growth fits squarely within our low-risk pipeline utility model and demonstrates the solid expansion and extension potential of the core assets. Importantly, this newly secured capital is provided for within our equity self-funding model, which Colin will speak to. And post-2020, we'll have a lot of free cash flow to fund new growth capital and fill in our annual $5 billion to $6 billion growth bucket.So with that, let me hand it over to Colin to provide the financial update.
Thanks, Al, and good morning, everyone. This is my first quarter in, in the CFO role, and I'm pleased to report that the financial results for the first half of the year are strong. In fact, it's more of the same diversified earnings and cash flows that you've become accustomed to from Enbridge.Slide 14 summarizes our financial performance for the quarter by segment, focusing first on adjusted EBITDA. Even after factoring in our simplification and recent asset sales, we've had a strong year so far. This is driven by strong operating performance from our core assets, incremental contributions from the $7 billion of new capital growth projects we brought into service later last year as well continued strong margins in our Energy Services segment. So overall, this translated into adjusted EBITDA for the quarter at just over $3.2 billion.I will now briefly walk through each of the businesses. Quarter-over-quarter, EBITDA for Liquids Pipelines was up $137 million, primarily due to continued strong throughput right across the liquids system. Simply put, our systems are full. Relative to last year, the Mainline benefited from both an increase to the international joint tariff and higher average quarterly throughput. Average deliveries ex Gretna for the quarter were up 25,000 barrels per day over Q2 of last year, largely due to continued optimization of the system.Downstream, we also saw strong utilization on our Mid-Continent and Market Access pipelines, Flanagan South, Spearhead and Seaway. This strong fundamental heavy crude pull from the Gulf should continue and our utilizations should continue to benefit. Also, the Bakken system continued to perform very well, benefiting from strong production growth in North Dakota.Moving down a row on the slide, second quarter adjusted EBITDA from our Gas Transmission and Midstream business was down $96 million from last year. Two factors drove the decrease. The first was the absence of earnings from the U.S. and Canadian gathering and processing assets that we sold in the back half of last year. Secondly, we're working through a comprehensive integrity program and we expect this to result in higher integrity expense through the course of 2019. I'll come back to this later.Partially offsetting this was the strong and steady performance from our core GTM assets and contributions from Valley Crossing, which you'll remember was brought into service late last year.Gas Distribution adjusted EBITDA increased by $21 million for the second quarter. This increase was largely due to higher distribution rates and growth in customer base, compounded by a colder spring in Ontario.Renewable Power Generation was down from last year. Operating performance was strong in Canada and the new Rampion U.K. facility has ramped up in line with expectations, but these were offset by weaker wind resources in the United States.Energy Services was up $26 million when compared to the second quarter of last year. As you'll recall, wide crude oil differentials in the later part of last year and early this year created opportunities to lock in profitable forward arbitrage margins and drove our exceptionally strong Q1 results. Some of those opportunities continued into Q2, although not to the same degree. Nonetheless, it drove a year-over-year growth in the second quarter segment.Looking ahead, we've seen differentials tighten. So while still positive, we're not expecting Energy Services results in the second half of the year to be comparable with the first half.Finally, turning to Eliminations and Other. EBITDA was down $20 million year-over-year, primarily due to hedge settlements on our enterprise foreign exchange hedging program related to the stronger dollar during the quarter.So overall, another strong quarter and a really strong first half across most of our businesses.I'm now moving on to Slide 15, which reconciles to DCF. Absolute DCF came in at $2.3 billion, up 24% relative to second quarter of last year. The significant increase is largely driven by the buy-in of our sponsored vehicle, which means we now retain all of the cash from those assets. The per share metrics, conversely, reflect the equity issues to buy these vehicles in.In addition to that, as you can see on the right-hand portion of the side, most of the factors were positive to DCF year-over-year, starting with strong operating performance, which I just walked through. We had lower maintenance capital expenditures compared to last year, mostly due again to the asset divestures. But we do expect our maintenance capital expenditures to ramp up in the second half of the year, similar to the prior year seasonal profile and still in line with our full year annual maintenance CapEx guidance of approximately $1.2 billion.Financing costs were lower due to the application of proceeds from last year's asset sales to debt reduction.We had lower current tax, reflecting newly enacted tax legislation during the quarter, which lowered recorded current taxes. Year-to-date, our current tax is in line with our own expectations and our full year outlook for current tax remains approximately $400 million, in line with our prior guidance.Lastly, distributions in excess of equity earnings were higher in the second quarter due to strong operating performances on assets like COA and our Bakken investments [ and ] the assets placed into service by our joint ventures, for example, NEXUS, all of which supported year-over-year higher cash distributions.Turning now to Slide 16 and our financial outlook for 2019. We had a very strong first half of the year, ahead of our own expectations. However, as I had mentioned earlier, some of this outperformance is unlikely to be repeatable in the second half of the year. We've identified some guidance variances materializing in the back half as follows. First, in our original guidance, we had contemplated a November 2019 in service date for Line 3. As discussed, we've estimated that for every month Line 3 is delayed, DCF per share is impacted by approximately $0.04. So that's $0.08 of expected variance drag later this year.Second, we've also started seeing the impact of higher-than-guide integrity expense in GTM during Q2, and we expect this to ramp up throughout the remainder of the year as we execute the integrity program. We estimate that that drag is approximately $100 million for the back half of the year or $0.05 per share.Third, we expect to see higher operating and administrative spending in the second half of the year, which is just timing-related.And finally, as mentioned, we don't foresee the same market conditions that have led to the outsized Energy Services arbitrage opportunities in the second half.So overall, a really strong first half, but we expect to revert back to the middle of the range by year-end.As relates to our 2020 outlook, we're not going to be in a position to update our previous guidance until we've evaluated the Minnesota's PUC's timetable for the Line 3 process in Minnesota.I'll wrap up my section here on Slide 17, with a few comments on funding and the balance sheet. We've made significant progress on strengthening the balance sheet. Our operating and financial performance has been strong and we also sold $8 billion of non-core assets last year, which, in combination, has greatly enhanced our financial flexibility. These actions also allowed us to eliminate our DRIP program last year, so we're not in self-funded growth mode.And our credit metrics are right in line with our longer-term targets and rating agency expectations, with improved consolidated debt to EBITDA at June 30, of 4.6x. That's down from 4.7x, on a trailing 12-month basis.We forecast being comfortably within our target range for the rest of this year and next, and that's after accounting for the delay in Line 3 cash flows and factoring in our secured spend as well as new projects backfilling the inventory in coming years.Specifically on the Saint Nazaire investment we announced today, I confirm it would be nonrecourse project debt financed, and, therefore, our equity contribution to the project will only be $300 million, some of which is being spent already through DevEx, and the rest will still be a few years out at COD in late 2022.And when Line 3 does come into service, absent other actions, we could get below our 4.5x to 5x debt to EBITDA target, which will provide even more dry powder to self fund additional future growth.And with that, I'll turn it back to Al to wrap up.
Okay. Thanks, Colin. So just to conclude here, I'll summarize the progress and the priorities that we set at the beginning of the year. Based on the first half and the outlook for the second half that Colin was talking about, we can safely say we're on track to deliver on promised results, even after the Line 3 delay impact for '19. On Line 3, though, we're obviously very disappointed with the court's EAS decision, given the extensive review that I referred to earlier and the overwhelming support for the project. That said, we're moving forward to get this work done because the line does need to be replaced.We've launched an Open Season for long-term contracts on the Mainline, and expect to have this in front of the regulator by year-end. And we've secured $2.5 B of new capital year-to-date, which will help extend the growth post-2020. And again, these projects are down the middle of the fairway and we expect more to come along as well.Balance sheet-wise, we're in good shape. Debt to EBITDA stands at 4.6x as Colin said, and we expect to remain at this low end of our target through year-end.So with that, let's turn it over to the operator to start the Q&A session.
[Operator Instructions]
Operator, are there any questions in the queue?
Yes. Our first question is going to be from Jeremy Tonet from JPMorgan.
Just wanted to start off with the offshore business, and it seems like there's a bit more of a focus here as far as what capital could be deployed. Just wondering how big do you see this opportunity set? How does this opportunity compete versus other projects you have for capital? And just wondering how big could this segment get versus some of the other ones out there? Obviously, Enbridge being a large company and it takes a while to make a difference. But just kind of curious strategically looking forward, how offshore fits now.
Great. That's a good question, Jeremy. So bigger picture here, obviously, in terms of the rest of the other businesses, the current contribution from renewables is relatively small, under 5%. The way we're looking at it strategically, Jeremy, as I said, it's almost like the asset base is reflecting the overall energy mix. And as you know, renewables are still very small in the broader energy context. So we feel that having a little bit of capital in that area makes some sense, provided that their projects can hit the same returns as the rest of the business. And certainly, the ones that we're seeing out there in the European offshore wind fits as well, if not better, in some cases than the projects that we're seeing in the conventional business, let's call it.In terms of the growth capital, the way we see it here, we'd like to see it strung out in terms of the deployment over the next 2, 3, 4, 5 years. As Colin mentioned here, actual capital out on this first project is quite small. And then if we can lay in the next two projects, if they need the FID requirements over the next 3 to 4 years, then that's ideal. And of course, you're bringing on EBITDA as you go.So I'd say it's a steady, gradual pursuit of offshore, but certainly not rivaling the other core businesses, at least within the next little while.
That's helpful. And then just turning to the U.S. side, was wondering if you could comment a bit more about how the Gulf Coast presence is coming together with crude oil. And how do you see the kind of your export project moving forward? There are some other kind of developments with competitors out there. And just wondering if you could update us on that platform.And if I could sneak in with Tetco, do you know the amount of downtime or ability to reroute around the [ gas ]?
Okay. Well, let me start with Tetco then. I think it's probably too early to tell where we're at here. I don't think we can provide an estimate of when the timing will be for restart. The NTSB's currently on site, of course, and we're coordinating with them. I think we're probably going to know more, Jeremy, in the next few days. So we'll have to wait on that one, given the incident just occurred. So we've got some work to do, to figure that out.In terms of your Gulf Coast strategy comment, I think that what we've been able to do here is demonstrated and there'll likely be more opportunities to follow on the gas side. We're just so well positioned there in terms of our existing infrastructure, that in some ways we've become the natural go-to for bringing a supply to these LNG plants in what we call the next wave of LNG projects that are hopefully going to sanction here by the LNG developers.On the liquids side of the business, I'd say that we have a very good position there. I call it a bit of a starter kit, if you will. We've got great assets with Seaway. We're going to have Gray Oak in. So we're starting to build that, and we're looking for opportunities. And hopefully, we'll see ways to build that out in the next little while here. So that's where we are generally on the export strategy.
And our next question comes from Matt Taylor from Tudor, Pickering, Holt.
Just going to Line 5, trying to understand the timing of a potential rerouting option that you disclosed you might be willing to do. Lawsuit calls out some environmental risk, obviously still under review there. But just the pace we've seen regulatory processes move forward, suggests to me there might be something to do in the interim. So I was just curious how you're thinking about that risk and potential options moving forward there.
Okay, Matt. Maybe we'll have Guy talk to that one.
Yes. So obviously a reroute will require regulatory approvals and will take some time. I think as we think through that, whether -- first off, whether we pursue or reroute and how that shapes up will obviously be a function of our conversations with Bad River. So having that as the background, we would expect it if we're in a reroute scenario that it would be with support from the band for the reroute, which we think would help us in securing the regulatory authorizations. But you're right, it would take some time. So part of the conversation that we have been having is making sure that the operation of Line 5 across the reservation in that interim period continues to be safe as it is today.
Great. That's helpful. Then maybe just one more for me. Another nice one there on the potential NG Interconnect. Can you just help me understand? Now it's a couple in the queue there, the value proposition that allowed you to win that project in what's obviously a very competitive market there. So just kind of learnings from that project and how you're seeing the growth build out there.
Just to clarify, Matt. You were talking about the Calcasieu plant and our project to feed it?
Yes. Precisely, yes.
Sorry. Plaquemines. Okay. Sorry. Yes. So this is a very good example of how existing infrastructure can help. And we've got a leg in the facilities that we have that aren't very highly utilized. So our ability to reverse that leg and expand the existing segment that we have into that region gives us a big advantage in terms of feeding the plant with very low-cost transportation.And don't forget, part of it is the header system that we have all along the Gulf, so that from an LNG plant perspective, what you want is diversity of supply. And for sure, we're connected to all the right areas of supply. So all-in, this is the kind of thing that can drive more and more opportunity, given the position we're in with our existing assets and ability to source diversified supply into the plant.
Our next question is from Linda Ezergailis from TD Securities.
I'm wondering if you could kind of round out our understanding a little bit about the Open Season you just launched on the Mainline. Specifically, I'm wondering if you could provide some color around the attributes for risk sharing with your shippers. I know in past agreements, there were volume off-ramps, there were clauses allowing sort of unexpected costs related to legislation to flow through. And I'm assuming that the shippers will not be absorbing any sort of incremental capital expenditures on any front related to tunnels, et cetera.But can you walk us through some of those attributes? Or might we have to wait until you're filing with the regulator later this year?
Yes. Linda, it's Guy. I think we're probably not going to go too far into that. I think maybe just to address a couple things you raised. Going to a contract approach would negate the need, assuming success of the Open Season, for volume off-ramp. So we don't foresee that being a part of the puzzle. I think as you alluded to, there will be a continuation of a lot of the risks that we've been managing throughout the CTS agreement, in part because we think we've become very good at it and it goes to the certainty of the toll that Al referenced earlier.So I think the final point I would say, as with most agreements, should something dramatically unusual come out of left field, either through a regulatory requirement or some other means, we would have some degree of protection. But I think that's about as far as I want to go.
I think, Guy, there was a reference in Linda's question, I think, to Line 5, around it being contemplated. And the answer to that one is, yes. And the way we've looked at the new offering, we would account for the cost of the tunnel, I guess is...
Correct. Correct.
Okay. That's helpful. Maybe moving on to your near-term operations. Appreciate the update on cash taxes for 2019. But maybe beyond 2019, with some of the Canadian tax changes, can you give us an update on the run rate of cash taxes next year and beyond, and maybe also your effective tax rate, given what's going on in Alberta?
Sure, Linda. So yes, we got about $400 million of cash tax in 2019. For 2020, it upticks a little bit to about $500-ish million. And I think our effective tax rate for the year is approximately 20%.
In 2020, or 2019?
2019.
Okay. And does that kind of trend down a little bit over the next couple years, or would that be flat?
They're pretty similar.
Our next question is from Shneur Gershuni from UBS.
So I guess my first question is with respect to 2020. I completely understand your reluctance to give any guidance, given the MPUC hasn't given an update on the process.But has anything else changed with respect to your outlook for 2020? I mean we can make our own assumptions about Line 3 or just take it out and so forth. But are there any other moving parts that would have taken your 2020 guidance up or down, based on other announcements that you've made?
Yes. Thanks. I think generally we'll defer until Enbridge Day for 2020 guidance overall. But if you look through some of the trends, I think you can look at our base business and the strength that we reported so far this year. There are some areas that will continue around the Liquids business, certainly. And I mean, other than that, continued cost management, management of taxes, interest rates; we've talked about that.So I think, in large part, Line 3 will be the biggest delta from the guidance we provided so far, and we'll update our guidance in December.
Okay. That makes sense. And then just quickly over to Line 5. I really appreciate all the color that you gave and so forth. And you sort of sounded like you had a bunch of different solutions and so forth.But is the solution in your hands right now or is it in the court's as a final say? And in the Draconian scenario, what do you expect or what would you estimate the lost EBITDA would be if the worst case scenario plays itself out?
Yes. So it's Guy. Obviously, there is a court proceeding going on. We certainly don't take the view that the issue is in the court's hands. That'll play out as it's going to play out. But we're interested in continuing to resolve this issue through the continuing collaboration that we've had with Bad River to this point. They've signaled their willingness to continue talking, and we fully expect that to happen.Going down the legal process, if that prevails as the process, we expect will be a multiyear process that really isn't going to be to the benefit of either party in this scenario.To go to your question about the Draconian side of things, we look at Line 5 and the import -- first off, Line 5 is safe and it's operating safe today and it'll be operating safe for a long time to come. The energy that it supplies is so important to that region that we are not looking at a scenario of it being shut down as being feasible at this point in time. We've never gone down in our financial reporting to the level of reporting on a specific line within the Mainline, and we're not going to do that at this stage.The only message we have is that people know what the capacity is, they can determine what our tolls are, they're public; and simply multiplying those two numbers together is going to get you answer that is not correct.
So I mean without people understanding what the downside is, it's hard for investors to actually capitalize correctly or understand what the risk downs is. By not giving that information, does that potentially increase your equity risk premium just because of the uncertainty and the risk that people make bigger assumptions on the downside?
Shneur, it's Al. We understand the question and the desire for more information here. But basically what we're saying is, there's lots of risks we manage in the business. In this case, we see it as a very low probability outcome. So when you add that to what Guy was talking about around what's publicly out there already, and I think his point around simply multiplying tolls with volume is a good one, because in the low probability event that you're referring to, certainly we'd have to do some other things to move volumes to other parts of the system.So as you said, I think that's our position today. And other than that, I think that's where we are.
Our next question is from Rob Hope from Scotiabank.
First question's on the Gas Transmission integrity pickup in the back half of the year. Just want to confirm that this would be incremental to your 2019 guidance. And just want to get a sense, just given some of the issues in BC as well as this week. Could we see higher integrity spend on gas transmission trending up over the next couple years?
Rob, it's Colin. Yes. So the amount I referred to earlier was on the expense side, and that is incremental to the 2019 guidance we provided at Enbridge day and it relates to programs we've commenced earlier this year to reevaluate the system. And we've provided associated capital for that in our maintenance capital guidance for 2019.
Yes. So just a quick add-on to what Colin said, for context here, Rob. So back in, I guess it was December, we understood our review of the gas system. And with that, we advanced some in-line inspections, we initiated some new ones, we did some engineering assessments and obviously lots of maintenance work as well. So that's what prompted the increase that you're referring to. But just to be clear, the amount that we're talking about has already been considered within our comments around the guidance for this year.
And is it the expectation that we could see continued higher levels of integrity in 2020 and beyond?
It's probably in the same order of magnitude as we have this year, maybe a touch higher. But that's our view at this point.
Okay. And then just touching back on a prior Line 5 question. In a low probability event where Line 5 is shut down for one reason or another, how much flexibility do you have in your system or how much flexibility can you gain in your system to shift volumes kind of, say out to Lake Michigan and up?
Yes. So it's Guy. Obviously, one of the benefits of our Mainline system is the flexibility that it does have. So we do see an opportunity to manage some of that situation, in the event that it manifests. Obviously, in addition to the flexibility that we do have, it'll be a function of what our shippers want to do in that scenario, in terms of what crudes they have and where they would want to try and take them.
And maybe, Rob, I could just provide one bit of context here because I think Guy's previous point was right about the demand on the market side of this equation. And it goes to the previous question around probabilities for this kind of thing happening.Michigan needs about 450,000 barrels per day of crude to meet their needs, and they only get a very small amount of it from the Detroit Refinery. That leaves a good chunk of crude that needs to be sourced from other states - Ohio, Indiana, Illinois and then in Ontario.And so if you do that scenario from the demand point of view and you take out that volume out of the system into that region, you're looking at roughly 40% to 50% shortages in Michigan itself. And let's not forget, Line 5 supplies all the volume, including Detroit. And so not having that, it's just hard to see how you compensate for that level of disruption. And so that's really the point. I think you're going to see massive increases in energy consumer costs if that low probability event were to happen. And that's partially the reason why we're saying it's low probability.
Our next question's from Robert Catellier from CIBC Capital Markets.
Sorry to hear about your news with Texas Eastern, and good luck with dealing with the community issues on that.My question was related to Line 5 as well. I'm just curious as to when you think you'll be in a position to file applications for the tunnel, if, in fact, you do that, and whether or not that's contingent on getting some agreement with the state first on the legal issues.
Yes. So it's Guy. You know we have our geotechnical program underway this summer. That will start dialing up some more detailed engineering around the project towards the end of the year. Assuming things progress as planned, we would like to be in a position some time in the first quarter of next year, to make the necessary applications.But to your point, I think before doing that, we are going to need to evaluate where we're at both in the legal perspective of discussions or where we might be at in terms of discussions with the state.
That makes sense. This morning in the press release, there were some improvements to your system capacity through some optimizations. I'm just wondering if you can give us an update with respect to potential Southern Lights reversal, where that stands in terms of your operational priorities.
Yes. So we've had those potential Mainline expansion options out there for some time now. At this stage of the game, I think the best way to characterize what's happened is, is our focus with our shippers has been on the Open Season and the Mainline contracting because until we see the result of that, that's going to be the greatest indicator of whether there's demand for further expansion of our system.So those options are out there. We've continued to have discussions. I think we've said historically Southern Lights is the one that would probably come last, just given the nature of what needs to be done and the commercial considerations around its current service and condensate. So it's a possibility that's out there, but it's not actively being pursued, given our focus on Open Season.
I think Guy's point is right on because, in fact, it's a bit circular, Rob, because the Open Season itself and the recontracting or contracting of the Mainline, one of the big benefits there is it provides a commercial underpinning for what'll happen in the future. And having that locked in certainly will allow us and the shipping community to have greater transparency on what we can do to expand, whether it's the one you mentioned or downstream expansions of the system, further into the Gulf, for example.
And our next question is from Praneeth Satish from Wells Fargo.
So you sold some wind assets last year. So I'm just curious, what's different about the wind farm that you're developing in France that, I guess makes you confident to keep investing capital there over the next few years?
Yes. It's Al speaking, Praneeth. I think the biggest thing here in terms of the difference, as I referred to earlier in my remarks, is that on the offshore wind business in North America, our view was that the growth opportunities there under the commercial model that we covet where we have long-term PPAs with good returns and capital risk that we can manage well, sort of waning in terms of those opportunities in North America.So at the same time we had this, obviously you know about the in-flow of private equity and capital chasing certain kinds of assets. So we basically took the opportunity to monetize half at a very good valuation, given that we thought the growth prospects were a little lower.Europe is different in that there's lots of opportunities for very good long-term PPAs. The support for those kinds of projects is very high there, and a good chunk of future generation is going to come from renewables in Europe. So it's really a trade, if you will, between focusing on a growth year part of this particular asset category. So that's the reason.
Okay. Great. And then I just wanted to touch on the potential Alliance expansion. So the last Open Season that you guys tried to do there, I don't think got the commitments that you wanted. So I guess what's changed this go-around that gives you the confidence to proceed with it?
Yes. Good question. So on Alliance, we've essentially, for the reasons you noted, sort of shifted the focus here. We think longer term there's excellent opportunity for expansion on Alliance all through the system, just given the egress challenges that are there in Western Canada. So we've essentially shifted the timing here to focus on the U.S. segment first. And as you know, the Bakken growth potential is very large and there's lots of liquids there as well. So we've essentially shifted the timing to focus on the U.S. side first. And we're seeing good opportunity there. We're in discussions now with potential shippers, and hopefully we'll have something near the end of the year.And by the way, that would include potential expansion of the Aux Sable frac facility in Chicago.
And our next question is from Ben Pham from BMO.
Had a couple follow-up questions on the Mainline Open Season. And it looks like you're adding the L3R volumes in that. And I guess I'm curious, I mean it makes a lot of sense, you want to maximize the contracts on that mid-2021.But how do you guys kind of think about managing, maximizing and contracting with timing, uncertainty of L3R and then just going through the regulatory process where you do need a certain amount of spot?
Yes. So it's Guy. I'll take a crack at that from a number of different angles. First and foremost, at this stage of the game, we still believe there's a good opportunity that Line 3's going to be replaced and in service ahead of July 2021, which is the foundational reason for moving ahead with contracting the full capacity.The start of those contracts will be upon the startup of Line 3. So if Line 3's delayed by a couple months, we'll delay the start of the contracts for a few months. So that's already built in there.I think your question -- I'm assuming your question around spot capacity is our plan to allocate 10%. That is a very consistent measure. If you look at open seasons around contracted pipelines throughout both Canada and the U.S., 10% level of spot capacity is very common, and that's why we've chosen to use that one.
Okay. All right. And then on this, if you're successful with contracting and [ the spot rate ] very good support for that, how do you think the opportunity is for you with the credit rating agencies? I mean it looks like you've been moving to this pure play utility-like model. Is this potentially credit accretive to you guys long term?
Ben, it's Colin. I think that that will be credit positive. I think the agencies view the Mainline already pretty favorably, given its competitive position. But the contracts and hopefully the tenor of the contracts should enhance the credit profile further.
And our next question is from Joe Gemino from Morningstar.
Just a couple of questions, short questions. First, regarding the potential Mainline expansion for later this year, is there a regulatory process that you need to go through to get those approvals?And turning to next year with the potential extended Line 3 delay, do you see any impact on the 10% dividend growth guidance? Thank you.
It's Guy. I'll take the first one. If you're referencing kind of the Mainline optimizations and whatnot that we've talked about, that 85,000 per day, there are no regulatory requirements associated with that.
Okay.
On the second part, Joe, so in terms of the dividend policy approach that we take, it's really based on a multiyear look at what the cash flows are going to be and how much we're going to generate out of the business. So as you know, we've set the 10% growth basically from '18 through to '20. That's what it continues to be, given our view of the underlying cash flows and the strength. And so there hasn't been a change in that view, obviously. We confirm those dividend decisions near the end of the year, in this case probably end of November.
And our next question's from Michael Lapides from Goldman Sachs.
Just a Line 3 question. I know you've talked a lot today about the EIS process. But what happens now with the appeals for both the Certificate of Need and the route permit? Do those appeals actually get heard? Or do those just go back to the PUC for literally rewriting of the CN and the RP?
So it's Guy. I'll take a crack at that. So right now, the appeals of the Certificate of Need have been stayed by the courts. And the route permit appeals have always kind of been positioned that until the appeals of the Certificate of Need are dealt with, they're not planning to deal with the route permit. So the route permit is kind of out there and not really being acted upon anyway. I think it's going to be a function of what the PUC determines they do and the process that they follow in terms of completing the EIS and recertifying the certificate of need and route permits that will then determine what might or might not happen on the appeal side of things.So it's a bit of an update on where we're at today. The process and how it'll unfold will be largely dictated by the process that the PUC determines they'll follow.
Meaning the PUC could make adjustments to the RP and the CN, and that would either have to get reviewed and approved and voted on by the PUC again. And that would sideline or make the appeal irrelevant? Or would that just get folded in to the current appellate case?
Our expectation is that given the narrow nature of the one issue that has been raised on appeal around the EIS, that there will not be a need to kind of reopen all of the proceedings around the Certificate of Need and the route permit.
Got it. So then those appellate cases would just pick back up again once the EIS issue is done?
Correct, that's our assumption.
If that's what happens -- you're presuming that, but, yes.
Okay. And then just a question on the U.S. Gas Transmission business. How material, do you think the rate changes at the three pipes that are in kind of rate reviews right now? So for Algonquin, Texas Eastern, East Tennessee. How material of a change when we think about 2020, and beyond?
Well, that's a good question, Mike. So I mean, that's obviously part of what we're doing here in the settlement discussions is making sure that -- while we want to catch up, for example, on Texas Eastern, for the number of years that we haven't been updating our rates, I think we got to balance that with the fact that it's still a competitive world out there, and we're taking that into account - let's put it that way - while we go through settlement discussions.So I don't want to comment on what rates could be. And remember, half the rates here are -- it's only half the rates that are subject to this process; the other half are negotiated, and, of course, they wouldn't be affected because they're in place for longer terms.So I guess we don't expect that it's going to change our competitive position.
Okay. But like for one of the pipes, you've got a settlement already filed at the FERC. Can you just give us, since it's a public document, just a little bit of kind of direction of, does it imply an increase, a decrease, to the revenue requirement at that pipe?
Yes. I think you're talking about East Tennessee, which I believe it was 3%. So it's de minimis in terms of the impact on revenue to us. And also on that one, we'll likely be moving to filing a full rate case in the coming years.
And our next question from Patrick Kenny from National Bank.
Just maybe back to the Mainline Open Season here. Wondering if you can comment on how come of these other recent egress developments may be impacting shipper demand, a few smaller open seasons out there, including your owns, offering additional capacity out of Western Canada. There's the cap line reversal debottlenecking in the Midwest.Again, just wanted to get your thoughts as to whether or not, net-net, these other open seasons are having a positive or negative effect on demand for long-term commitments on the Mainline.
Yes. So it's Guy. I'll take a crack at that. I think as we think through that, it really boils down to what do producers want to do with their barrels? These other actions on other pipelines really aren't having an impact on kind of our traditional downstream refining market in terms of their desire to continue to utilize our system. We went through the exercise of negotiating where we've landed on the Open Season and in the approach, and the producers made it very clear to us that they wanted to have a level playing field in terms of their ability to participate in the Open Season versus refiners, and we've given them that.So there is a signal from them that they want to ship on our system. But I think until we get into the results of the Open Season, we can't speculate on their views of going on Enbridge versus other alternatives.Express is a bit of a different animal, in that we've begun to see some refinery creep in that Rocky Mountain region. So it's about egress, obviously, but it's also about some growing demands in that area. So we think that one's got a good chance of being successful.
Just bigger picture here, though. If you think about some of these smaller open seasons, certainly they're not going to move the dial to what has become the broader issue as a Western Canadian, what's called a pure upstream producer, in that the whole game for the future is going to be certainty of egress. And that's why the Open Season for us and their ability to contact and get surety not only provides surety for volume that they have, but in the bigger picture their growth and the optimization and capitalization of their total upstream resource potential is really driven by that, a surety to access. And so that's why we think the offering that we're putting out provides not just near-term benefits for access, but I think it really helps the overall picture in the basin long term.
And given that appetite for U.S. certainty, is it safe to say that the contracted tolls coming out of the Open Season might land at least equal to the current CTS total? Or should we expect maybe a little bit of a down-tick here, just given the discounts being offered for term and volume?
Well, we're not going to get into that because that's not public information at this point. I think what we said, though, in the past is basically what you've said, essentially that you can assume the exit toll is at about the same rate. There'll be escalator in the toll in the agreement, just like there is today under the existing CTS. But I don't think your assumption's too far off.
This concludes the question-and-answer session. I will now turn the call over to Jonathan Morgan for final remarks.
Great. Thank you, Gigi. Thank you, everyone, for your time and interest in Enbridge today. As always, our IR team is available to take additional follow-ups. And have a great day. Thank you.
Thank you, ladies and gentlemen. This concludes today's conference. Thank you for participating. You may now disconnect.