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Enbridge Inc (ENB 0.18%)
Q2Â 2019 Earnings Call
Aug 2, 2019, 9:00 a.m. ET
Contents:
- Prepared Remarks
- Questions and Answers
- Call Participants
Prepared Remarks:
Operator
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. 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 Morgan, Vice President, Investor Relations. Jonathan, you may begin.
Jonathan Morgan -- Vice President, Investor Relations
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, 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 transcript will be posted to the website shortly thereafter.
In terms of Q&A, we will prioritize calls from the investment community. 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 going to target keeping the call to roughly one hour, and may not be able to get to everybody. So please try to limit your questions to one and a follow-up if 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 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.
With that, I'll turn the call over to Al Monaco.
Al Monaco -- President and Chief Executive Officer
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 mid-year progress review. Second quarter numbers were strong, driven by high utilization across the businesses. What stood out was continued high liquids throughput, especially in the mid-continent 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 and 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 on 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 will run for 60 days, followed by the any de-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. It told us they want guaranteed access to our system, which serves the best markets in the Midwest and the US Gulf Coast. They want and need the lowest transportation cost system to those markets, and they want long term toll 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, balanced access for all types of customers, whether they're producers, integrators [Phonetic], refiners, marketers, that had toll 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 different 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 on to 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 3rd. The PUC believes there is a strong case to deny that reviewed the appeals and they have 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 PUCs timetable.
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'd all agree, we've got to get on with it and replace the line. After all, this is a safety and reliability project. And in the meantime, we'll continue to prepare for construction. Before we move to gas transmission I'll briefly comment on Line 5 and 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% of 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 [Indecipherable] 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 two years, 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 disruptions 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 has 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 land owner 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 Fond Du Lac and the [Indecipherable] 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, progress maintenance and we've shared a lot of information about our operations with the Band. We were being attentive in our view to their concerns and 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 lighter-weight [Phonetic] communities and we will continue to work with the Band to address any concerns as they've said they are 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 US Gulf Coast from South Texas to Louisiana. We currently supply Cheniere's Sabine Pass and Cameron plants. We're making good progress on further build up.
This quarter, Stratton Ridge went into service which [Phonetic] 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 [Indecipherable] last year to serve their Calcasieu LNG facility in Louisiana. We're happy with the 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. That will 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 the white circles that you see on the map.
Finally, we're making progress on the amalgamation of the two utilities which drives 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 to 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 and [Phonetic] for the rest of our business. They line up very well and 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've 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 UK Rampion project is in service and Hohe See in Germany is progressing well for late this year. Combined, those two projects are actually one 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'd the first one of these in the queue Saint-Nazaire, with our partner EDF, this is the one on the North West Coast that you see on 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 better 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 a 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, Saint-Nazaire makes two other permitted French 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 [Phonetic] 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 will 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.
Colin Gruending -- Chief Financial Officer
Thanks, Al. And good morning everyone. This is my first quarter end 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 as 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 from Liquids Pipelines was up $37 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 a 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 along 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 US 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 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 the 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 UK 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 recall, wide crude oil differentials in the latter 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 are not expecting Energy Services result 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 the second quarter of last year. The significant increase was largely driven by the buy-in of our sponsored vehicles, which means we now retain all of the cash from those assets. The per share metrics conversely reflect the equity issued to buy these vehicles in.
In addition to that, as you can see on the right-hand portion of the slide, 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 divestitures. 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 years 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 taxes in line with our own expectations and our full year outlook for current tax remains approximately $400 million, 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 Seaway and our Bakken investments as new 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 guided 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 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 it 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 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 [Phonetic] 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 now 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 30th of 4.6 times and that's down from 4.7 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 same [Phonetic] as our investment we announced today. I confirm it will be non-recourse project debt financed and therefore our equity contribution to the project will only be $300 million, some of which has been spent already through Devx [Phonetic] 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 dip below our 4.5 to 5 times 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.
Al Monaco -- President and Chief Executive Officer
Okay. Thanks, Colin. So just to conclude here, I'll summarize the progress on the priorities that we set at the beginning of the year. Based on 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 in 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 tear-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 that the 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.
Questions and Answers:
Operator
Thank you. [Operator Instructions]
Jonathan Morgan -- Vice President, Investor Relations
Operator, are there any questions in the queue?
Operator
Yes. Our first question is going to be from Jeremy Tonet from JP Morgan. Your line is now open.
Jeremy Tonet -- JP Morgan -- Analyst
Good morning.
Al Monaco -- President and Chief Executive Officer
Morning.
Jeremy Tonet -- JP Morgan -- Analyst
Just wanted to start off with the offshore business, and it seems like there is 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 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.
Al Monaco -- President and Chief Executive Officer
Great. It'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 makes some sense provided that the 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 strong [Phonetic] 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 meet the FID requirements over the next three to four years then that's our ideal and of course you're bringing on EBITDA as you go. So I would say it's a steady gradual pursuit of offshore. But certainly not rivaling the other core businesses at least within the next little while.
Jeremy Tonet -- JP Morgan -- Analyst
That's helpful, thanks. And then just turning to the US side, I was wondering if you could comment a bit more about how Gulf Coast presence is coming together with crude oil and how you see the kind of your export project moving forward, there is 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 what the amount of downtime or ability to rewrite around the cash?
Al Monaco -- President and Chief Executive Officer
Okay. Well, let me, let me start with TETCO then. I think it's probably too early to tell where we're at here. I'm not -- I don't think we can provide an estimate of when the timing will be for restart. The NTSB is currently on site of course and we are coordinating with them. I think we're probably going to know more Jeremy in the next in next few days. So we'll have to wait on that when 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 demonstrate 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 liquid 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 out 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.
Jeremy Tonet -- JP Morgan -- Analyst
That's very helpful. Thank you.
Al Monaco -- President and Chief Executive Officer
Okay.
Operator
Thank you. And our next question comes from Matt Taylor from Tudor, Pickering, Holt. Your line is now open.
Matt Taylor -- Tudor, Pickering, Holt & Co. -- Analyst
Thanks for taking my questions here. Just going to Line 5, trying to understand the timing of a potential rerouting option that you disclosed. You might be willing to do last few calls out some environmental risk obviously still under review there, but just the pace we've seen regulatory processes move forward suggest 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.
Al Monaco -- President and Chief Executive Officer
Okay, Matt, maybe we'll have Guy talk to that one.
Guy Jarvis -- Executive Vice President, Liquids Pipelines
Yes. So obviously a reroute will require regulatory approvals and will take some time. I think as we think through that, first off whether we pursue a 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 that 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.
Matt Taylor -- Tudor, Pickering, Holt & Co. -- Analyst
Great, that's helpful. And then maybe just one more from me. Another nice win there on the potential LNG 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 and 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?
Al Monaco -- President and Chief Executive Officer
Just to clarify, Matt. you were talking about the Calcasieu plant and our project to feed it?
Matt Taylor -- Tudor, Pickering, Holt & Co. -- Analyst
Yes. Precisely.
Al Monaco -- President and Chief Executive Officer
Sorry Plaquemines. Okay. Sorry. So what -- this is a very good example of how existing infrastructure can help and we've got a leg in the facilities we have that aren't very highly utilized. So ability to reverse that leg [Phonetic] 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.
Matt Taylor -- Tudor, Pickering, Holt & Co. -- Analyst
Great. That's helpful color. Thank you very much.
Al Monaco -- President and Chief Executive Officer
Okay.
Operator
Thank you. Our next question is from Linda Ezergailis from TD Securities. Your line is now open.
Linda Ezergailis -- TD Securities -- Analyst
Thank you. 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 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 your filing with the regulator later this year.
Guy Jarvis -- Executive Vice President, Liquids Pipelines
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 of things you raised, going to a contract approach would negate the need assuming success of the open season for volume off ramps. 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 tool 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.
Jonathan Morgan -- Vice President, Investor Relations
I think, Guy. There was a reference in Linda's question. I think the Line 5 around being -- it being contemplated. And the answer to that one is, yes. In the way we've looked at the new offering, we would -- would account for the cost of the tunnel, I guess.
Al Monaco -- President and Chief Executive Officer
Correct.
Linda Ezergailis -- TD Securities -- Analyst
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?
Colin Gruending -- Chief Financial Officer
Sure. Linda. So yeah, we got about 400 million of cash tax in 2019. For 2020, it's upticks a little bit about 500-ish and I think our effective tax rate for the year is approximately 20%.
Linda Ezergailis -- TD Securities -- Analyst
In 2020 or 2019?
Colin Gruending -- Chief Financial Officer
2019.
Linda Ezergailis -- TD Securities -- Analyst
Okay. And does that kind of trend down a little bit over the next couple of years or would that be flat?
Colin Gruending -- Chief Financial Officer
Pretty similar.
Linda Ezergailis -- TD Securities -- Analyst
That's helpful, thanks. I'll jump back in the queue.
Colin Gruending -- Chief Financial Officer
Thank you.
Al Monaco -- President and Chief Executive Officer
Thanks. Linda.
Operator
Thank you. Our next question is from Shneur Gershuni from UBS. Your line is now open.
Shneur Gershuni -- UBS -- Analyst
Hi, good morning everyone. Really appreciate the color today. Can you hear me?
Al Monaco -- President and Chief Executive Officer
Hello. Yes, we can hear you. Go ahead.
Shneur Gershuni -- UBS -- Analyst
Sorry about that. Okay. 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 so forth. But are there any other moving parts that would have taken your 2020 guidance upward down based on other announcements that you've made?
Al Monaco -- President and Chief Executive Officer
Yeah, thanks. I think generally it will differ to 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 is 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 will update our guidance in December.
Shneur Gershuni -- UBS -- Analyst
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 courts 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?
Guy Jarvis -- Executive Vice President, Liquids Pipelines
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's going to, that will 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 multi-year 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 important, first of, Line 5 safe and its operating safe today and it will 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 mean line and we're not going to do that at this stage. The only message we have is that you can -- people know what the capacity is, they can determine what our tolls are, there are public and simply multiply those two numbers together is going to get you an answer that is not correct.
Shneur Gershuni -- UBS -- Analyst
So I mean without people understanding what the downside is, it's hard to -- hard for investors to actually capitalize correctly understand what the risk [balance] is. Does that 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?
Al Monaco -- President and Chief Executive Officer
I think Shneur, it's Al and we understand the question and the desire for more information here. But basically, what we're saying is there is 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 tools 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.
Shneur Gershuni -- UBS -- Analyst
Great. Really appreciate the color, guys. Thank you and have a great weekend.
Al Monaco -- President and Chief Executive Officer
Okay. Thanks Shneur.
Operator
Thank you. Our next question is from Rob Hope from Scotiabank. Your line is now open.
Rob Hope -- Scotiabank -- Analyst
Good morning. First questions on the gas transmission integrity pick up 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 of years?
Colin Gruending -- Chief Financial Officer
Hey Rob, it;s Colin. Yes, thanks. 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. So -- and we provided associated capital for that in our maintenance capital guidance for 2019.
Al Monaco -- President and Chief Executive Officer
Yeah so, just a quick add-on to what Colin said for context here Rob. So back in, I guess it was December, we undertook a 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 is already been considered within our comments around the guidance for this year.
Rob Hope -- Scotiabank -- Analyst
And is it the expectation that we can see continued higher levels of integrity in 2020 and beyond?
Al Monaco -- President and Chief Executive Officer
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.
Rob Hope -- Scotiabank -- Analyst
Okay and then just touching back on 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 you can you gain in your system to shift volumes kind of [Indecipherable] Michigan and up?
Guy Jarvis -- Executive Vice President, Liquids Pipelines
Yeah. 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 a manifest obviously in addition to our, the flexibility that we do have it will 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.
Al Monaco -- President and Chief Executive Officer
Maybe, Rob, I could just provide one bit of context here because I think Guy's previous point was right about the demand and 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. 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 a low probability.
Rob Hope -- Scotiabank -- Analyst
Thanks for the color.
Al Monaco -- President and Chief Executive Officer
Okay. Thanks, Rob.
Operator
Thank you. Our next question is from Robert Catellier from CIBC Capital Markets, your line is now open.
Robert Catellier -- CIBC Capital Markets -- Analyst
Hi, good morning. Sorry to hear about your news with Texas Eastern and good luck with dealing with the community issues on that.
Al Monaco -- President and Chief Executive Officer
Thank you.
Robert Catellier -- CIBC Capital Markets -- Analyst
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 from the state first on the legal issues?
Guy Jarvis -- Executive Vice President, Liquids Pipelines
Yes. So it's, Guy. We have our geotechnical program under way this summer that we will start dialing up some more detailed engineering around the project toward the end of the year. Assuming things progress as planned we would like to be in a position sometime in the first quarter of next year to make the necessary applications. But to your point, I think before doing that, we're 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.
Robert Catellier -- CIBC Capital Markets -- Analyst
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 could give us an update with respect to potential Southern Lights reversal, where that stands in terms of your operational priorities?
Guy Jarvis -- Executive Vice President, Liquids Pipelines
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 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 is demand for further expansion of our systems. 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 the open season.
Al Monaco -- President and Chief Executive Officer
I think as Guy's point is right on because in fact, it's a bit [Indecipherable] because the open season itself and the recontracting -- contracting of the Mainline, one of the big benefits there is it provides a commercial underpinning for what will happen in the future and having that locked in certainly will allow us and the shipping community have greater transparency on what we can do to expand this, whether it's the one you mentioned or downstream expansions of the system further into the Gulf, for example.
Robert Catellier -- CIBC Capital Markets -- Analyst
Okay, fantastic. Thank you.
Al Monaco -- President and Chief Executive Officer
Okay, thanks.
Operator
Thank you. And our next question is from Praneeth Satish from Wells Fargo. Your line is now open.
Praneeth Satish -- Wells Fargo -- Analyst
Hi, good morning. 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?
Al Monaco -- President and Chief Executive Officer
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 covered, 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 -- about the inflow 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 and there is 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.
Praneeth Satish -- Wells Fargo -- Analyst
Okay, great. And then, I just want 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?
Al Monaco -- President and Chief Executive Officer
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 is 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 US 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 US 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.
Praneeth Satish -- Wells Fargo -- Analyst
Great, thank you.
Al Monaco -- President and Chief Executive Officer
Okay.
Operator
Thank you. And our next question is from Ben Pham from BMO. Your line is now open.
Ben Pham -- BMO -- Analyst
Okay, thanks, good morning. I had a couple of follow-up questions on the Mainline open season and it looks like you're adding L3 [Phonetic] to your 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 maximizing contracting with timing uncertainty of [Indecipherable] and just gone through the regulatory process, where you do need a certain amount that spot?
Guy Jarvis -- Executive Vice President, Liquids Pipelines
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 is a good opportunity that Line 3 is going to be replaced and in serviced 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 start up of Line 3. If so ifLine 3 is delayed by a couple of 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 am 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 US, 10% level of spot capacity is very common and that's why we've chosen to use that one.
Ben Pham -- BMO -- Analyst
Okay, all right. Thanks. And then on this if you're successful with contracting and there's probably very good support to thatm, 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?
Colin Gruending -- Chief Financial Officer
Yes. Hey, Ben it's Colin. I think that they will be credit positive. I think the agencies view that the Mainline already pretty favorably given its competitive position. But the contracts and hopefully the tenure of the contract should enhance the credit profile further.
Ben Pham -- BMO -- Analyst
All right, that's great. Thanks everybody.
Al Monaco -- President and Chief Executive Officer
Thank you, Ben.
Operator
Thank you. And our next question is from Joe Gemino from Morningstar. Your line is now open.
Joe Gemino -- Morningstar -- Analyst
Thank you. Just a couple of questions, short questions. First regarding the 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 of extending the Line 3 delay, do you see any impact on the 10% dividend growth guidance? Thank you.
Guy Jarvis -- Executive Vice President, Liquids Pipelines
So 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 barrels per day, there are no regulatory requirements associated with that.
Joe Gemino -- Morningstar -- Analyst
Okay.
Al Monaco -- President and Chief Executive Officer
On the second part, Joe. So in terms of the dividend policy approach that we take, it's really based on a multi-year 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 that's -- 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 in November.
Joe Gemino -- Morningstar -- Analyst
Great, thank you very much.
Al Monaco -- President and Chief Executive Officer
Okay, thank you.
Operator
Thank you. And our next question is from Michael Lapides from Goldman Sachs. Your line is now open.
Michael Lapides -- Goldman Sachs -- Analyst
Hey guys, just a Line 3 question, I know you're talking -- 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 hurt or do those just go back to the PUC for literally rewriting of the CN and the RP [Phonetic]?
Guy Jarvis -- Executive Vice President, Liquids Pipelines
So it's Guy, I'll take a -- 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 are not planning to deal with the Route permit. So it's the Route permit is kind of out there and not really be enacted upon any way. I think it's going to be a function of what the PUC determines they do in the process that they follow in terms of completing the EIS and and recertifying the Certificate of Need and route permits that will then determine what might or might not happen on the PL side of things.
So it's a bit of an update on where we're at today, the process and how it will unfold will be largely dictated by the process that the PUC determine they'll follow.
Michael Lapides -- Goldman Sachs -- Analyst
Meaning the PUC could make adjustments to ERP [Phonetic] and the CN and that would either have to get reviewed and approved by and voted on by the PUC again and that would sideline or make the appeal irrelevant or would that just get folded into the current appellate [Phonetic] case?
Al Monaco -- President and Chief Executive Officer
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 reopened all of the proceedings around the Certificate of Need and the Route permit.
Michael Lapides -- Goldman Sachs -- Analyst
Got it. So then those appellate cases would just pick back up again once the EIS issue is done?
Guy Jarvis -- Executive Vice President, Liquids Pipelines
Correct. That's our, our assumption.
Al Monaco -- President and Chief Executive Officer
If that's what happens, we're -- you're pursuing that. But, yes.
Michael Lapides -- Goldman Sachs -- Analyst
Okay and then just a question on US 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?
Al Monaco -- President and Chief Executive Officer
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've got a balance that with the fact that it's still a competitive world out there and we are 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 of 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 are in place for longer terms. So I guess we don't expect that it's going to change our competitive position.
Michael Lapides -- Goldman Sachs -- Analyst
Okay. Like for one of the pipes you've got a settlement already filed at the FERC. Can you just give us a sense of the 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?
Al Monaco -- President and Chief Executive Officer
Yeah, I think you're talking about East Tennessee, which is I believe it was 3% . So it's [Indecipherable] in terms of the impact on revenue to us, and also on that when will likely be moving to filing a full rate case in the coming years.
Michael Lapides -- Goldman Sachs -- Analyst
Got it. Thank you, guys. Much appreciated.
Al Monaco -- President and Chief Executive Officer
Hey, Mike. Thanks.
Operator
Thank you . And our next question is from Patrick Kenny from National Bank. Your line is now open.
Patrick Kenny -- National Bank -- Analyst
Yeah, good morning. Just maybe back to the Mainline open season here, I'm wondering if you can comment on how some of these other recent egress developments may be impacting shipper demand, a few smaller open seasons out there including your own offering additional capacity out of Western Canada, there a cap line reversal debottlenecking the Midwest? Again, just wanted to get your thoughts as to whether or net-net, these other open seasons are having a positive or negative effect on demand for long-term commitments on the Mainline?
Guy Jarvis -- Executive Vice President, Liquids Pipelines
Yeah. 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 in the [Phonetic] 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 to be successful.
Al Monaco -- President and Chief Executive Officer
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, let's call it pure upstream producer and 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 contract and get surety not only provide assurity [Phonetic] 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 assurity 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.
Patrick Kenny -- National Bank -- Analyst
And given that appetite for US certainty, is it safe to say that the contracted tools coming out of the open season might land at least equal to the current CTS tool or should we expecting a little bit of a down tick here, just given the discounts being offered for term and volume?
Al Monaco -- President and Chief Executive Officer
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 have said is that actually, that you can assume the exit toll is 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 you assumption is too far off.
Patrick Kenny -- National Bank -- Analyst
Okay, that's great, thanks a lot Al.
Al Monaco -- President and Chief Executive Officer
Okay.
Operator
Thank you, this concludes the question-and-answer session. I will now turn the call over to Jonathan Morgan for final remarks.
Jonathan Morgan -- Vice President, Investor Relations
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.
Operator
[Operator Closing Remarks]
Duration: 78 minutes
Call participants:
Jonathan Morgan -- Vice President, Investor Relations
Al Monaco -- President and Chief Executive Officer
Colin Gruending -- Chief Financial Officer
Guy Jarvis -- Executive Vice President, Liquids Pipelines
Jeremy Tonet -- JP Morgan -- Analyst
Matt Taylor -- Tudor, Pickering, Holt & Co. -- Analyst
Linda Ezergailis -- TD Securities -- Analyst
Shneur Gershuni -- UBS -- Analyst
Rob Hope -- Scotiabank -- Analyst
Robert Catellier -- CIBC Capital Markets -- Analyst
Praneeth Satish -- Wells Fargo -- Analyst
Ben Pham -- BMO -- Analyst
Joe Gemino -- Morningstar -- Analyst
Michael Lapides -- Goldman Sachs -- Analyst
Patrick Kenny -- National Bank -- Analyst
