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Welcome to the Enbridge Inc. Fourth Quarter 2019 Financial Results Conference Call. My name is Joelle, 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, Joelle. Good morning, and welcome to the Enbridge Inc. Fourth Quarter 2019 Earnings Call. Joining me this morning are Al Monaco, President and Chief Executive Officer; Colin Gruending, Executive Vice President and Chief Financial Officer; Vern Yu, Executive Vice President, Liquids Pipelines; and Bill Yardley, Executive Vice President, Gas Transmission and Midstream.As per usual, this call is webcast. I encourage those listening on the phone to follow along with the supporting slides. A replay and podcast of the call will be available today, and a transcript will be posted to the website shortly after. In terms of Q&A, we'll prioritize calls from the investment community. If you are a member of the media, please direct your inquiries to our communications team and we'll be happy to respond immediately. We're again going to target keeping the call to roughly 1 hour and may not be able to get to everyone. So please try to limit your questions to 1 and a follow-up as necessary. As always, our Investor Relations team is available for your detailed follow-up questions afterwards. On to Slide 2, where I'll remind you that we will be referring to forward-looking information on today's call. By its nature, this information contains forecast assumptions and expectations about future outcomes, which are subject to the risks and uncertainties outlined here and discussed more fully in our public disclosure filings. We'll also be referring to non-GAAP measures summarized below.With that, I'll turn it over to Al Monaco.
Thanks, Jonathan, and good morning, everybody. I'll start off by kicking the Q4 numbers out and then some developments since Enbridge Day, particularly line 3, then our mainline contracting application. And since there's a lot of interest in this, I'll provide a bit more of our thinking on it. As you saw as well from our announcements, we'll cover off securing longer-term growth. Colin is going to take you through the Q4 and full year results, the balance sheet and our financial outlook.So moving to Q4 highlights on Slide 3. Operationally, Q4 came in strong, capping off a record financial year, and we made great progress on our priorities. The good numbers, the proceeds from asset sales drove down our debt-to-EBITDA metric to 4.5 at year-end, the strong end of our target 4.5 to 5x range. So we're pleased with that. We delivered on highly capital-efficient optimizations and the revenue and cost capture we've been talking about, namely more throughput delivered on the mainline. We had a record December. A very good rate settlement on Texas Eastern and then synergies from combining our Ontario utilities. We put $7 billion of projects into the ground this quarter. That's not an easy feat in this environment, obviously. And we've moved our U.S. Gulf Coast strategy along by securing new projects. So all in, we've come out of our post-Spectra 3-year plan in good shape, and that's allowed us to increase our dividend again by 10% for the third year in a row.On to the financial highlights with Slide 4. EBITDA came in at $13.3 billion for the year and DCF at $9.2 billion, both exceeding our full year guidance by $300 million. That translates into DCF per share of $4.57 or at the top end of our full year guidance range. This is a great outcome, given the headwinds that we experienced. As you know, we were originally counting on line 3 to give us cash flow beginning in November of last year and that cost us $0.08 alone.Gas transmission costs were a little bit higher this year, and we issued, as you'll recall, shares to buy in 4 sponsored vehicles in Q4 2018, but we were able to offset those and more with exceptional performance in liquids through the year, good results in Gas Distribution and Storage and outperformance on Energy Services, and we had some good cost management along the way.On to Slide 5 for project execution in the queue. Gray Oak began service in Q4, that one fits very nicely into our Gulf Coast strategy, which I'll speak to a bit later. On offshore wind, Hohe See and the adjacent expansion started generating 609 megawatts of capacity, and that's a large wind farm by any measure. So with our U.K. ramping project, we're now at about 1,000 megawatts of operating offshore wind, and we've got 4 more projects in development, by the way, offshore France with attractive PPAs and we are in execution on one of those right now.Back to North America, we got line 3 Canada into service as you know, which is a big deal for us. It immediately enhanced safety and reliability of the system. It gives us good flexibility to help egress. So that's great news for our customers in terms of WCSB volumes and netbacks. And the interim surcharge gives us cash flow in 2020 before we bring the rest of the line on in the U.S.On that note, let me turn to the business update in Line 3 in Minnesota. So last week, the PUC recertified the EIS and reinstated the Certificate of Need and Route Permit. Obviously, it's good to see this process concluded because it sets the next steps in motion for the remaining permits. We had excellent community support for the project. And over the last 5 years, this project has been thoroughly vetted, and everybody has had a chance to provide their input. Well -- so that's lengthy, the process made this project better, and I think it gives people confidence that the environment is protected. The focus now is on the permitting agencies. So let me outline the big picture steps on Slide 7. So this is the graphic view that we've been using to update you, and it's divided into the 2 tracks. And at a high level, you can see a few more items have been checked off since Enbridge Day. On the PUC track now that the EIS, the Certificate of Need and Route are recertified, PUC will issue an order, followed by the petition for reconsideration period. That's the same process that occurred last time around.On the agency track, the Department of Natural Resources, the pollution control agency and the Army Corps have been working in parallel through this period where the EIS was being recertified. The PCA has now updated their schedule, as you saw, and will initiate travel review of the 401 permit next week, followed by public consultation in early March. So they're moving things along well.The additional public consultation at the Army Corps is already underway, so that's good, and the DNR continues to work on the permits. Once the state agencies and the corps complete their work, the PUC will be in a position to issue an authorization to construct. So this is where the 2 tracks come together. Now we still don't have clarity on specifically when permits will be issued, so our approach is going to be the same as before. Once we have clarity on the final permits, we'll be in position to provide an ISD estimate. But as we've said before, once we have those permits in hand and are clear to go, then construction should take between 6 to 9 months. So in light of everything, we're pleased with how this is moving along. So let's now move to the other topic, Mainline Contracting on to Slide 8. So we filed our CER application in December, and importantly, that included 13 letters of support from shippers representing about 75% of current throughput. Now this is more important than just on the face of it. These shippers have basically said in their letters that they support the offering, including the tools and they're committed to supporting this process in front of the regulator. The application itself speaks to why contracting is in the public interest, which is the CER test here, and we think the offering not just meets but exceeds that test.First, the offering maximizes producer netbacks because we provide the lowest, stable tools to the very best market. So it's positive from a WCSB economic perspective. Second, it's good for the basin because contracted capacity locks in long-term demand for Western Canadian production. That's also important to producers in the future of this basin. Through this open access, everybody will have an equal opportunity to move barrels to the best markets. And 2 examples of this process, we introduced what we call requirement's contract. So no take-or-pay commitments are needed. I think that requires clarification as well. And we reached a minimum threshold or maximum threshold of 2,000 barrels per day for small shippers. So we're basically inviting any small shippers to participate. And finally, this offering provides a commercial framework for future low-cost expansion on the main line. So the point here is that we've gone to great lengths to ensure that the offering works for everybody. And that our interests are aligned with producers as they always have been on CTS and previous to that.So let's take a look at what is probably the most important issue here, which is how we balanced the offering that we struck. On Slide 9. When we began talking about the next rendition of CTS with customers, they told us, universally, that 3 things had to be there. Because they were frustrated with apportionment, they want guaranteed access to the mainline. They want total certainty to protect their margins and provide clarity over future upstream and downstream investments they need to make, and for us, to continue optimizing our system because it provides the lowest cost incremental capacity and widest services. And remember, we manage operating and integrity costs, foreign exchange, interest rates and capital exposure on behalf of the shippers.After 2 years of negotiation and changes to improve the offering, we landed on what is, we think, a very good balance of benefits for everybody, producers, integrated companies and refiners. So a few different perspectives on how we balance this. Refiners and integrated producers have historically shipped most of the volumes on the mainline, about 90%. So for them, contracting secures access to Western Canadian barrels that they need at stable and competitive tolls. Now on the producer end, many producers have been satisfied with selling their barrels to refiners in Alberta, but this offering can change that game. Producers can now control their destiny by getting their own guaranteed access to our system, which will optimize their netbacks because they can sell barrels to the best markets. So while many producers haven't historically been mainline shippers, this offering allows them the opportunity to control their barrels. Now for those who don't want to participate, we're reserving 325,000 barrels a day of spot. That's a lot of walk up capacity, which will increase over time with further optimizations and expansions.So let me spend a minute now on the tolls. So we're on Slide 10. And first of all, while you scan this, anyone signing up, including the requirements contracts, that's the non-take-or-pay contract, starts with a base contract total of $5.70 a barrel. Now if the system is fully utilized, going forward, then all shippers, small and large, get a $0.35 discount. So that's down to $5.35. Shippers who sign up for longer terms are eligible for another $0.10, so even the smallest shippers toll would get down to $5.25. Higher volume shippers would see an added $0.14 discount, making the lowest contract total $5.11. Now a couple of important things to take away on this. The discounts that I'm talking about here apply to all shippers, small and large, so everybody is treated fairly. And the extensive negotiation that we undertook over the last couple of years, results in a toll that's lower than what the CTS extension toll would be. So in sum, we think this offering provides a very good balance for all parts of the value chain: producers, refiners and integrateds; and it's positive for Basin netbacks. Not all that surprising that there is some debate as there are many different perspectives as there usually are in the basin here to balance, and that's why the regulator will assess it from the public interest lens.Slide 11 is the final one on this topic. It gives a brief outline. The CER just completed what they call their Issues Request Process, which helps to determine the scope of their review, and we filed our response to that last week. Next, the CER would typically lay out the scope and timing and then receive submissions by interveners and ourselves, and the timing around that will be, of course, up to them. That would be followed by a hearing and the CER's deliberations likely later this year. We fully support a very thorough proceeding that considers all of the issues based on the evidence. And once the CER makes its decision, we'll study it, and if we think it works for us, then we move forward to an open season.Switching gears now to the future and the U.S. Gulf Coast strategy on to Slide 11 (sic) [ Slide 12 ]. This chart provides context as to why the U.S. Gulf Coast is a very strategic part in North America for us. We think the Gulf will be the epicenter of how North America will prosecute its global energy advantage, which is hinged on ultra-low cost supply, feeding growing global energy demand. Gulf Coast refiners, as you know, are the most competitive in the world, and they're configured to process roughly 4.5 million barrels per day of heavy and medium sour. About 1/3 of the heavies are actually supplied by Canada, but we see that rising to 50% given the Mexican and Venezuelan declines. Blending heavies with light Permian barrels to create medium sour is also part of the value add here. And then there's low-cost light supply destined for export markets. On the natural gas side, we're excited about the Gulf Coast LNG, Mexican exports and petchem fundamentals. The focus then, overall, are more in line heavy. And growing gas exports drives good infrastructure opportunities for us.Next couple of slides shows what I mean by that, moving to Slide 13. Just a few years ago, if you looked at this map, we would have had a 0 position in the U.S. Gulf Coast. Combined with the fundamentals today are Mainline, Flanagan and Seaway pipes create an unparalleled heavy system flow path that gives us low capital intensity opportunities. With those pipes in the ground, we're now creating last-mile connectivity to refiners and export facilities on that path. The planned Houston oil terminal will provide 15 million barrels a day of storage and connections to Seaway refinery distribution network and existing docks. We're developing deepwater VLCC loading projects with enterprise, as you know, and that comes with ownership in their spot terminal. This is a great low-cost solution for customers here that we've come up with because we're leveraging combined assets and eliminating new capital.On to Slide 14. We're also very well positioned with our gas business to capitalize on exports. Texas Eastern and Valley Crossing in parallel with coastline from Louisiana through Texas, to the border with Mexico. The strategy here has been to leverage the footprint and create a set of options to capitalize on the future of LNG. We're currently connected to 3 plants and we're moving ahead with the Cameron extension to the Calcasieu Pass terminal. We've got 3 other projects in development, including 2 new committed ones that we announced today. That totals roughly $2.3 billion of new projects with opportunity to grow from there.So we'd given you a glimpse of this at Enbridge Day, but now they're secured. So on Slide 14 -- 15 for a bit of a description there. The first project will serve NextDecade's Rio Grande LNG facility at Brownsville. We reached agreement to buy Rio Bravo Pipeline development from NextDecade, as you saw, which would connect premium supply to Rio Grande through Agua Dulce, and of course, they signed a precedent agreement with us. The base investment here is $1.2 billion for the first 2 trains with good low-cost expansion potential for additional trains. Secondly, we've secured an expansion of Valley Crossing to serve the Annova LNG terminal. That capital will be about $500 million and is underpinned by a long-term take-or-pay contract. In both cases, we're using our Valley crossing footprint, so it's capital-efficient and we can manage execution risk well. The commercial underpinnings of both projects are in the middle of our pipeline utility fairway and well within our equity self-funding envelope. In fact, you can look at it as if we're filling up part of the $5 billion to $6 billion per year in organic growth capacity that we have. And both of those LNG plants are subject to final FIDs. On to Slide 16, another focus of the gas business is modernizing and upgrading the system to reflect regulatory changes, like new air emission standards. These solid organic rate-based type growth opportunities total about $800 million annually for the next while, system-wide and will recover return on capital through more frequent rate case proceedings. I'll shift now to the gas utility on Slide 17. Great progress here on capturing synergies related to the amalgamation of the Ontario utilities. That should drive a strong ROE during our 5-year incentive-based regulatory framework, and we're just in year 2 of that now. We're advancing about $400 million of system expansions, and on top of that, there's another $500 million or so of core rate base growth annually from the $40,000 to $50,000 per year in customer adds. We're happy with this business, and it should continue to generate a very solid return and good growth.So with that, I'll turn it over to Colin to speak to the financials, the balance sheet and the outlook.
All right. Thanks, Al, and good morning, everyone. I'll start with some high-level remarks and then walk through our performance and outlook. So from a high level, when I step back from our year in its totality and consider it in the further context of the culmination of our 3-year plan since the Spectra acquisition, I'm pleased with our execution. Simultaneously, we've simplified our structure, derisked our business mix through noncore divestitures, deleveraged our balance sheet significantly and all the while accretively growing our per share financial performance. So a challenging task individually, but a good achievement all at once and a timely one relative to where the industry is at and going. So with that behind us, I'm very excited about our future.Some comments now on our 2019 performance on Slide 18. On a full year adjusted basis, EBITDA is $13.3 billion or about $420 million higher when compared to 2018. The growth came from 3 areas, thematically: first, we've optimized our base business, creating incremental pipeline capacity; and number two, filling that capacity with strong demand for fundamentals; and thirdly, as you know, incremental contributions from our new capital growth projects that we brought into service in '19 and then also later in the prior year.For the quarter, as expected, our fourth quarter EBITDA results were slightly lower than last year, primarily due to an exceptionally strong energy services reported contribution in the fourth quarter of 2018. I'd say we also have some unusual quarterly variances. So there may be some limited predictive value from some of our segment results this quarter, and I moreover guide you to our 2020 results if you're looking for patterns and run rates.Turning to liquids pipelines. Our EBITDA was relatively flat for the fourth quarter, but up significantly $424 million for the full year. And again, relative to the guidance we gave last year for this segment, we're up about $250 million versus that guidance last year at Enbridge Day. So I think a good accomplishment, and again, overcoming probably about $160 million of delayed Line 3 contribution, which was embedded in that guidance back at Enbridge Day 2018. For the full year, the mainline system ran full. And in fact, we achieved record annual throughput averaging about 2.7 million barrels per day. Our toll also benefit from our annual inflator effective July 1 as per usual. However, this incremental revenue was offset by lower effective rates on the hedges we used to convert U.S. dollar toll revenue to Canadian dollars. And I think these hedge rates are quoted in the finer points of the news release. The Gulf Coast and Mid-Con system benefited from higher volumes on the Flanagan South and Seaway pipelines due to strong demand for Canadian heavy barrels in the Gulf. We also commenced initial operations of the Gray Oak pipeline in the middle of the fourth quarter. The Bakken system also continued to perform very well, benefiting from strong production growth in North Dakota.Looking at the Liquids quarter in isolation, the relatively flat results were due to the timing of operating and maintenance expense, which was unusually heavily weighted in Q4 relative to the prior year. This should normalize going forward.Moving to gas transmission. EBITDA was flat for the fourth quarter and down $200 million for the full year, with the majority of this decrease as a result of the U.S. Acadian G&P assets that were sold in the second half of 2018. GTM saw a partial year uplift in 2019 from our annualization of new assets placed into service like NEXUS and Valley Crossing. These were placed into service late in 2018 year call.And as I've referenced in past quarters, our Gas Transmission team continued to progress a comprehensive integrity program, resulting in higher integrity, operating expenditures in the back half of 2019. Now the cost of this program should normalize downwards somewhat in 2020, as already reflected in our Enbridge Day guidance. Gas Distribution and Storage EBITDA was up $29 million for the fourth quarter and $93 million for the full year. The utility benefited from higher distribution charges as a result of the growing customer base, colder weather as well as cost synergies from the amalgamation of EGD and Union back on January 1, 2019.Our Power business was up $20 million in the fourth quarter, but down $11 million for the full year. The fourth quarter results were positively impacted by contributions from our German offshore wind investment, Hohe See, which came online, and we look forward to its full year contribution in 2020. The segment's full year results were a little lower, largely due to less favorable wind resources and availability at certain U.S. wind facilities, which again, we anticipate improved performance from in 2020.Moving on to Energy Services. As mentioned earlier in 2019, we had benefited from very attractive locked in margins, which drove our strong full year 2019 results. A small loss in the fourth quarter of 2019 was expected, given the weak market conditions for energy services, including lower basis differentials in the Gulf Coast given new pricing dynamics there. In contrast, Q4 2018 was exceptionally strong with wide basis differentials. As I've noted, we anticipate normalized results in 2020 as guided.Finally, Eliminations and Others was $14 million favorable for the full year. And I'd say the unfavorable variance in the quarter was unusually large and is again timing-related. I'd refer you here also to our 2020 guidance. Moving to Slide 19 for the DCF perspective. Absolute DCF was up 21% for the full year. And as I've referenced in the past, the sharp year-over-year increase is 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, of course, reflect the equity issued to fund the buy-ins. Full year DCF per share of $9.2 billion or $4.50 per share is up $0.15 over 2018, in line with or even a little better than our expectations and towards the top end of our 2019 guidance range. A significant portion of a DCF per share growth came from the strong EBITDA performance just mentioned. Other drivers include distributions in excess of equity earnings, which were higher throughout the year due to strong operating performance and related higher cash distributions on assets like Seaway and the Bakken as well as new joint ventures placed into service like NEXUS. Maintenance capital was slightly lower in 2019, again, due largely to our 2018 asset sales. So in summary, a strong year-over-year performance from all of our assets, which remain well utilized.Turning to Slide 20. I'd like to highlight the strength of our balance sheet. During the quarter, we closed 3 noncore asset sales. And in fact, in totality, we exceeded our original asset sales program target with over $8 billion in proceeds. As shown on the graph to the right, our credit metrics have really strengthened over the past few years and are now well inside our longer-term target. Our prime metric here is debt to EBITDA, and this, a few years ago, was as high as 6x. At the end of 2019, in contrast, it's now sitting at 4.5x on a trailing 12-month month basis. This, of course, positions us very well to equity self-fund additional future growth.Moving to Slide 21. I'd like to remind you about our capital allocation priorities. Preserving our financial strength while executing our secured growth is our #1 focus. This will support a growing return to shareholders through a dividend in the near term, which is our second priority. Once we've executed the secured capital, we'll have about $5 billion to $6 billion of annual capacity. And we're going to be very disciplined about how we allocate this capacity to maximize long-term value, and that's our third priority. Within this category, our preference is to grow organically, optimizing, extending and expanding assets. The theme here is efficiency. Size-wise, we'll be looking at singles and doubles in this category, which are more executable and deliver solid returns. We'll also consider share buybacks, too, once we're through the secured capital program and more particularly Line 3. We currently have about $11 billion in secured organic growth projects. These are well diversified geographically and by business line, and fit squarely within our low-risk business model. They will add considerable EBITDA, too, creating further financial flexibility and are all fundable within our equity self-funded model. I'd note that our projected balance sheet metrics in 2022, for example, could be even stronger than our target range given this dynamic. Even so, during this period, we will continue to evaluate opportunistic noncore asset sales as we have and recycle capital, like the MATL sale announced today, for example.So turning now to Slide 22. I'll recap 2020 and our outer year guidance. In a nutshell, I'll reiterate our messages from Enbridge Day. Our 2020 EBITDA guidance remains approximately $13.7 billion, which translates into 2020 DCF per share in the range of $4.50 to $4.80 per share. Again, the growth in 2020 is expected to be driven by a number of factors, including strong performance utilization across the board, including volume growth and system optimizations, particularly on the liquids mainline including Line 3 Canada contributions.Secondly, uplift from a full year of operating cash flows from the $9 billion of projects we brought into service in 2019 offset partially by the impact of asset sales. And within the utility, new customers, community expansions and cost synergies, and within GTM, rates uplifts from new rate agreements.As we look even further beyond, we expect our DCF per share growth in the range of 5% to 7% annually on average, again, coming from 2 sources: first, 1% to 2% from embedded opportunities in the core business, i.e., capital-light opportunities; and the second bucket, 4% to 5% from newly secured capital investment opportunities, again, all within our self-equity funded model.So thank you, Al, back to you.
Okay. Thanks, Colin. So all in, 2019 was a financially and operationally strong year. But as they say, that's in the past, the team is now focused on building for the future with a keen eye on capital allocation. And by that, I mean executing on the secured projects we have, including the U.S. portion on Line 3, optimizing the base business through embedded growth within the system. And there's plenty of that opportunity. And it means securing new projects that will extend growth well into the future as you saw with our LNG announcements. As Colin just covered well, we'll be disciplined by investing in low-capital-intensity organic projects and living within the equity self-funded model. And of course, the balance sheet and financial flexibility will continue to be the overarching priorities.So with that, we'll turn it over to the operator for questions.
[Operator Instructions] Rob Hope from Scotiabank is online with a question.
Just -- I realize that you're not providing an estimated end service date for Line 3. But based on what you've seen from the permitting agencies in terms of their proposed progress to date as well as your conversations there, just want to get a sense if everything is unfolding as you would had expected that would allow construction for the summer?
Maybe I'll just start off, then Vern, you can tag on. I would say, from everything we've seen, Rob, the agencies have been working diligently through this whole piece. And you mentioned discussions, obviously, we were engaged with them. And we have good discussions on all the work that's being done. Obviously, we are being quite responsive in terms of information that's required. And at the same time, they've got to work through their process. So -- but everything that we've seen indicates that they've been working hard and are on track. So -- I don't know, Vern, if you have anything to add on that?
Well, I think the only thing I would add, Al, is that the agencies are very mindful of making sure that their decision records are very strong. That everything is well documented so that in the future there is no ground for these things to be overturned.
All right. And then switching over to Line 5. Just want to get a sense of your thoughts on rerouting the pipeline on the southern edge of Lake Superior as well as when you could -- that would be around the Bad River Band as well as when you think you could actually start doing more fulsome tunnel construction across the straits.
Okay. Rob, I'll take those. First, with the Bad River. The tribe has indicated to us that they wanted us off of their reservation. So we've been working with that in mind, where we've now filed for our permits to reroute out of their reservation. So we filed with the Wisconsin Public Service Commission, the Wisconsin DNR and the Army Corps, and we've been actively auctioning land for about a 40-mile reroute. So we've been doing this to meet their desire of getting off the reservation as quickly as possible. And I think we're well on track for that. But we are still open to have further discussions with them if they do change their mind. Onto Line 5 tunnel. We've seen with the recent quarter claims decision that upheld the tunnel authority agreement, that effectively gives us an avenue to pursue the permits to build the tunnel. We completed the geotechnical work in the fall, and there are no surprises there. The tunnel authority is up and running now, and we expect to start engaging with them very shortly. And once we've done that, we'll be in a position to file all the necessary permits to start construction for the tunnel. So we are making all efforts to be on track to meet the earliest possible in-service date of 2024.
Jeremy Tonet from JPMorgan is online with a question.
I just want to pick up on the LNG side here. It seems like some really interesting developments insofar as new projects here. And just wondering if you could give us kind of your thought process as far as the cost of these pipelines, and I guess, maybe more specifically, what cost you would incur, if any, ahead of FIDs? And how do you think about the balance of timing there? And would you have interest to go kind of further upstream there and take stakes in any of these facilities? Just any of these -- thought process here would be helpful.
I think Bill is going to address.
Sure. Jeremy, it's Bill. Yes, so really, really a good story here. I appreciate the question. We've tried to minimize any cost pre-FID for any of our activities, and so far, that's been holding pretty well. So I think you're well aware of what we've done to connect to LNG facilities with Cameron, Freeport; we go into the Sabine header today. We've got the nice project that we're working on under construction now that has FID with Venture Global and Calcasieu. And then these -- kind of these 3 that are coming down the pike here with Venture Global's Plaquemines, the Annova and Rio Grande announced today. So pretty minimal dollars upfront. We'll be watching the FIDs closely. And that's kind of the beauty of what our strategy has been, which is to simply make sure we're the ones that can connect here. And then if they go, we're in a great position. As far as timing on the pipes go. Obviously, we've got some work to do with some of them, the pre-FERC activities. The benefit of Rio Bravo is that we're buying a FERC permitted project. And that's pretty impressive. These guys have done a really nice job. So that's a benefit there. Costs, we're not seeing anything different than our -- what we typically see in our execution. I think we've got these pretty well nailed down, especially where they are. We've got a lot of experience with, for example, with Valley Crossing in South Texas. As far as interest in upstream, I think was the last part of your question -- or, not the upstream but the terminals themselves. Yes. So we have a small stake in Annova down in Brownsville. Basically, we'll watch the business model carefully there. And if that's something that fits our low-risk business model, then we'll continue with that. And not opposed to it, it's probably just not our Plan A if that makes sense.
I think Jeremy -- it's Al. Just at a high level, if you go back to the fundamentals behind the Spectra deal itself, I think this is a great example of how the footprint we were looking for is really giving us an optionality play on a number of projects. And I think Bill and the team have done a good job to set up those low-cost options. So like you said, whatever happens down there in the Gulf. And we know that the Gulf and the U.S., generally, is really well positioned for global LNG, given the supply and obviously the low cost. So we're really well situated there and very happy with these 2 projects we've lined up.
That's helpful. And maybe just continuing with natural gas here. I just wanted to touch on maybe some projects that don't get as much airplay and PennEast and then maybe as well -- as well as the Frontier project in B.C. Just wondering if you could provide updates on some of that.
Yes. So it's Bill, again, Jeremy. So PennEast is -- man, it's a struggle. We -- we've had -- a couple of points to make here. First, we've got to go to the Supreme Court if they'll take us, to hear our objection to the third circuit's decision. We -- it's something that, I don't know, breaks precedent with 70 or 80 years of the ability of projects, interstate projects, to use condemnation on state-owned land. And so that's going to be a big deal, really, for the industry and not just for PennEast. More specifically to the project on PennEast, we filed for a bifurcation, where we'll go ahead and if they'll let us build the Pennsylvania section in the first phase and then go to the second phase in New Jersey some time later. Pennsylvania will at least get the Northeast Marcellus producer's access to other pipes, like Adelphia and Columbia, and then we'll figure out what to do with the second phase, if anything, later on. With Frontier up in Western Canada, with -- basically, we're kind of on a -- in a holding pattern here. We're talking to a lot of folks to try to get a solution to the growing issue there, which will become an issue in a few years of kind of liquids in the pipe, and we ran into this in Appalachia, you may recall this, some 6 or 7 years ago. And basically, it's an opportunity for the producers to monetize some of the heavier hydrocarbons going to the system. So we really think there's a solution there, but not a lot of updates to give you right now.
Robert Kwan from RBC Capital Markets is online with a question.
I guess, the first question is around project development/M&A. And Colin, you made the comment that efficiency is kind of a key theme. So I'm just wondering, you've executed a number of projects where you've bought into later-stage developments, whether that's into a joint venture outright. Just wondering, I guess, is that a preference? And then second, as you think about just maybe larger scale acquisitions. You've become particularly adept at asset monetization. So I'm just wondering what your appetite is to acquire a business that maybe has some assets that you covet but others that you don't want? Would you be open to doing that if it meant hiving off a material part of somebody else's business?
Yes. Thanks, Robert. It's Colin. I think big picture, we're not real focused on larger scale M&A at this time. Even with the possibility of funding it with the sell-down or recycling. I think as we've talked about, our focus is really organically and more efficient projects in our corridor, in our franchise. So I guess it's theoretically possible in the industry, but it's not really something we're laser-focused on right now.
Okay. And then just the kind of buying into later-stage projects. Is that kind of almost a core strategy at this point to help derisk the development side of things?
Well, I think as I reflect on some of the projects that we've been kind of buying into, top of mind are our European wind projects, which directionally, I think you're seeing us coming in a little bit earlier on those to capture some more of the value there with strong partners. So I guess we're marrying together that. Joint-venture-wise, I think SPOT with enterprise is a good example. Perhaps not later stage, but it's mid-stage and efficient capital-wise. So those are a couple of examples where I think we're trying to team up, use our balance sheet efficiently and sound strategy.
I think maybe just going back to what Colin said about offshore wind. This is a great example, Robert, of our ability to recycle. And so we got in on those projects when they were developed they had PPAs. But now I think with a new partner coming in that we've just recently brought in, we're in a position now where we can essentially promote the project. And we obviously like that opportunity because it helps boost what was already a very strong return for us. So if we can chip away at things like that and bring in capital, minimize our own capital deployed and boost our return, that's all part of our focus on capital allocation and discipline and minimizing capital deployment.
Got it. And maybe if I can finish then on something similar on the wind side, Al. How are sustainability in ESG-related topics driving your strategy? And I guess, historically, renewables was a place where you could leverage your permitting, construction and operating expertise when you got into the onshore side of things for growth. But at the end of the day, it seemed like you are still financially driven, first pulling back on onshore wind when it kind of became a cost of capital shootout, and then eventually just selling it, given the amount of value you could achieve. How should we think about renewables going forward, especially the offshore platform?
Yes. I think your observation is good around the onshore renewables. I mean obviously, I think we were probably way ahead of the game on renewables generally, and the team did a good job of building up a very good portfolio. But basically, what we saw is that the growth was going to be more limited in North America, particularly for independent renewable projects. And at the same time, as you know, we have an opportunity to monetize the assets at pretty good multiples when, frankly, the growth wasn't as strong as what we saw in the offshore side of the business. So recycling that capital into what is very growthy outlook for European offshore wind with PPAs, frankly, that are very, very strong and line up extremely well with the rest of our business.In terms of where it fits ESG-wise, I think there's some obvious benefits there. I mean if you look at all of the parts of our ESG position, I think you could fairly say that we're leading on just about every count. We tend to -- we intend to kind of keep it that way there. But the renewables really are maybe a supplement to the ESG strategy. First and foremost, they're great projects. They've got good growth in them. And most importantly, the risk reward profile lines up extremely well. So it's a part of the ESG story if you will, but certainly, very strong projects on their own. And we've got enough inventory now that we're a pretty credible player, I think, in this space going forward and with great partners in Europe.
Shneur Gershuni with UBS is online with a question.
I'm not sure if you can legally comment on this, but with respect to Mainline recontracting, there's been some intervenor arguments locally about them. I was wondering if you can talk about if there are any deficiencies in the arguments or some nuances with the Enbridge proposals that make it different and weight some of their arguments. I'm just trying to understand if there's some comments that you can sort of make about how you've changed the process, for example, thinking on the maintenance CapEx requirements risk and then it's a different ideology. Just curious what you can say?
Well, maybe I'll start, then I'll let Vern speak to it. When you really look at this at a high level, Shneur, we've got essentially a strong track record with our customers of really aligning with them. And the best evidence of that is probably the last 2 renditions over the last 20 years of CTS, where, as you pointed out, we've essentially taken on the risk of investing capital in the business; foreign exchange, interest rates, operations, we've taken all that on and essentially provided a high degree of toll certainty for the customers. When you look at this particular offering, all of that is still there, except we're providing something more, which is the 2 things that they asked us to provide, guaranteed access to the system and total stability. And when you look at this from a producer perspective, in particular, and the basin overall, having that certainty over the next 8, 10, 12 or 20 years, depending on what they sign up for, that provides a lot of certainty for their investment decision-making. I think it protects their margins. And as we said in the comments, that really, I think, solidifies their netback story, just given the low-cost hold. So I think it's unique, but it's built off of a long track record of our customers trusting us to provide excellent service. I mean, we move multiple different kinds of crude that nobody else can do, frankly, and we do it at an extremely low cost. So we think we've got a great offering here that really, as I said in my comments, tries to balance this dichotomy of issues between producers, refiners and integrated. So I'm not sure if that gets to it, but maybe, Vern, if you want to add anything now is the time.
Yes. Okay. Thanks, Al. I think one of the key things that we should point out is our customer base is very diverse. And the individual interests of all of these companies are going to vary quite dramatically. And you can see that it's extremely hard to get consensus within the basin and all the players in the basin. You can just look at the recent experience the industry has had with curtailment in Alberta, where there is some very strongly diametrically opposed views. So given that circumstance, for us to have around 75% of the volumes on the system, supportive of this commercial offering, is quite an accomplishment. We think the people who are opposed to this are doing this for a number of reasons, their own particular commercial circumstance and the timing of the offering and the free optionality that potentially Enbridge system provides to them. There are some who like contracting but just would like to see a different toll outcome. We have a few customers that want us to perfectly match their upstream and downstream contracts. And unfortunately, we can't do that in the regulatory format we have. And then finally, there are a whole bunch of smaller producers who've never really used the Enbridge system or any pipeline system, in fact, over their history. And it's been -- our challenge going forward is to continue to educate these customers on the potential benefits of this offering. So I think as we spend more time over the next year, as we go through the regulatory process, I think we will be in a good position to build stronger support as we move on.
And just one final comment. We keep saying it, but this offering has been built up over a period of 2 years. We didn't just drop a regulatory application on the table. And if you go through it objectively, you'll see that the team has done, I think, a great job of listening to particularly the smaller producers, lowering the threshold for volumes, coming in at a toll that's very cost effective and lower than it would otherwise be. And a myriad of changes in the contracts that have demonstrated that we're listening very carefully. So I guess, at this point, we'll have to see what the regulator thinks about it.
No, that makes sense and really appreciate the color on it. Maybe pivoting a little bit here. When you look at the pace of declining rig activity in the U.S. and I do recognize that you have $11 billion in capital program for 2020 and beyond. But do you see a scenario where the overall growth spending slows to a point where you basically pivot to a temporary higher level of return of capital, maybe buy it through buybacks until activity levels resume? Just kind of wondering what your thoughts on how you're thinking about it.
I think at this point, I mean, we have to be very disciplined and objective about this. So we are not going to push capital investments just to achieve a growth rate that we may have had in the past. So as you saw at Enbridge Day, we're going to be very clinical about how we deploy this capital. At this point in time, I would say, if you look at Bill's business, Vern's business, Cynthia's business and you throw on the offshore renewables, there's an ample amount of opportunity within those core franchises without having to stray too far from what we're really good at and the growth that's embedded in there. We've also got, remember probably 1% to 2% of growth that is already sort of embedded, I guess, in the growth rate from rate escalators, ramp up of volumes and some of the capital projects that we've just talked about in the gas business or customer adds and the utilities. So we've got this good pot of 1% to 2% that's fairly easily achievable, and then we'll see where it goes from there. So in the franchise, like these opportunities that we just announced today. I think we've got plenty of those. But if it gets to a point where we're running out of those and the returns don't match up to what we need them to be, then for sure, different options will come into play. And I think we've said once we get through Line 3 and executing Line 3, then certainly, all options are on the table depending on what the organic opportunities are.
Linda Ezergailis from TD Securities is online with a question.
I'm wondering if you could give us a sense from a capital perspective, what the outlook is for the next year. In terms of your backlog of opportunities, I appreciate that there's a lot, but I'm wondering if, for example, with some of the decline in activity on the producer side in the U.S., there might be a little bit of a lull maybe on the pipeline side. And are you seeing more perhaps than in Canada or offshore to kind of get to deploying your $5 billion to $6 billion of free cash flows this year and next year? I guess, I'm looking at your $11 billion secured capital bucket and I see about a 2-year backlog. So I'm just trying to figure out the cadence of securing new projects for the next half year, a year?
Maybe I'll just start, and then Colin will chime in. I think the way to think about this, Linda, at least for the 3-year plan that we have out there through 2022. So what we have embedded in the business in terms of those items I mentioned earlier around tolls and volume ramps and some of the other things that we talked about and the $11 billion that is secured through 2022. So I think we're good to go on this 3-year plan as far as achieving the growth that we had talked about in the 5% to 7% range. I think what we're doing now is tacking on opportunities like the ones we announced that start to contribute beyond that 2022 period. And we're working on a number of other opportunities that will help fill that in, including some of the offshore ones that you mentioned. So I think that's how to bifurcate it. It's out through 2022, I think the $11 billion gets us there. And then beyond that, it's more organic growth to be secured. How's that?
Yes -- no, it's a great answer. I think you asked what do a 2020 growth CapEx was -- we disclosed that at Enbridge Day, it's $5.5 billion of growth CapEx to satisfy and execute on the first of the 3 years to get this $11 billion on the ground. And as Al said, as we consider new projects, we're really looking to see that the spend years, if you like, on those newer secured projects fit with this CapEx profile and that our balance sheet can accommodate it handily.
Yes. I guess, I was asking more in terms of securing new projects, so that it kind of backfills 2 and 3 years out. Maybe I can just follow-up with your existing operations. And maybe this is a question for Bill. I'm wondering what sort of discussions you're having with your producer, customers in the U.S. Northeast? Are they asking for any sort of toll relief, any sort of blend and extend? How are you seeing your volumes, even on your secured capacity trending?
Well, so in my business, Linda, to say we're a long haul, long line, FERC-regulated, fully contracted pipeline system. And I would say, number one, no, we're not in any discussions with blend and extend or any type of discounting. I think one reason for that and maybe this shouldn't be hard to get, but these contracts are pretty much in the money, meaning, we get out of -- for example, when you get out of Appalachia as a producer and you hold one of the contracts that they hold on us, they're getting to places like New York City or all the reversals we did. They're getting to the Gulf Coast, right? So those are -- and they're pretty inexpensive rates, relatively speaking. So, so far, I think they're very heavily utilized and they are very valuable contracts for them. So no, we just -- we haven't had those. We don't have G&P, right? We're just the long-haul reservation-based pay us and we'll get you somewhere good kind of pipeline system.
Michael Lapides from Goldman Sachs is online with a question.
Just a question about what's assumed in guidance around the mainline toll going forward, kind of the guidance growth rate, not the 2020 guidance. Just curious, do you -- should we assume the $5.70 per barrel? Or should we assume one of the kind of discount rates or some kind of weighted average when thinking about kind of the average toll that you'll collect on the Mainline starting mid-'21 and beyond?
Yes. What we use for our financial projections is kind of a weighted average toll. So assuming that there's contracted tolls in and around what we've shown in the presentation today and that the spot toll would make up the difference.
Meaning, the weighted average would somewhere be between the $5.10 and $5.30 a barrel range? And can you remind us what that spot toll would be?
The spot toll would be close to the CTS exit toll.
Got it. So close to the $5.70?
Yes.
Okay. I appreciate it, guys. One last question. You all made the announcement today about Rio Bravo and previously had made announcements around Annova. Just curious, given how weak global LNG prices were before the beginning of this year and then the massive dip down that's occurred in the last month or so, especially in the Asia-U.S. and Asia-Canada spread. How are you thinking about the likelihood of those projects actually going FID in the near future and those pipelines actually getting built?
Yes. So it's Bill. Certainly, the global prices brought about by a number of factors are causing some short-term issues. But these are facilities that are in that next round of FIDs. So these are entities that are looking for off-take contracts and supply agreements over the course of the next year or so, but not to be in service until 2023, '24, '25. And that's kind of where that inflection point is. As you get into -- some folks think '21, others '22, you get to a point where you get a better -- a sort of a rebalancing and a need for global LNG. And I don't know, I haven't seen anything that says that LNG globally or the demand for LNG globally isn't going to be pretty strong over the course of the next couple of decades. So these folks are -- yes, they're beating the bushes, but we have a lot of faith. We obviously got a really good insight into their activities over the course of our negotiations for the pipes. And I'm not going to count any of them out, but that's our -- right now, we hold optionality if they do FID, and we have a pretty good view that they're in good position.
I think competitively, though, if I'm right, Bill, from a cost -- supply cost perspective, given where those 2 projects are and how competitive they are proximity-wise to markets and so forth. I think we feel pretty good that if projects go, these are likely to be them. So that's a good spot to be in, and Bill and his team have captured these. Now we'll see what happens from there.
Ben Pham from BMO is online with a question.
Okay. On the Annova/Rio Bravo project, where do those projects sit in your -- those 4 buckets of build multiples? Is Annova 3 to 5x and Rio Bravo a little bit higher than that because you're getting a little bit late on the project?
Ben, it's Colin. Maybe Bill can supplement that. I think you're generally right. I think these -- both of them fit pretty squarely in our traditional build multiple range of 6x to 9x. Annova is a little more efficient.
Yes, yes, that's right. We've negotiated these. From a financial standpoint they're right down the fairway with our -- with projects we've done in the past.
Okay. And I know there's some questions on the $5 billion to $6 billion and securing that post-2022 and your B team is working hard on that. And just looking at your slides, it seems though -- and you're pretty like Enbridge gas, gas transmission, offshore wind, and it seems like there's an ongoing sustainable $1 billion or $2 billion or so that you're seeing in the long term. But when you put a product, like Annova, in there 3 to 5x, USD 0.5 billion Capex, isn't that like spending or putting like $1.5 billion in that $5 billion to $6 billion. Which would have assumed a higher multiple, Bill? Is that the right way to think about it?
Yes. I think, generally, you're right. I mean, not all capital spend is treated equally, right? Indeed, some of the capital-efficient projects, punch above their weight, so to speak, in terms of EBITDA contribution. So that's the most important metric, is the EBITDA contribution coming from them and they're kind of a unit of efficiency.
Okay. And that's $5 billion to $6 billion, that's still that just like 8 to 9x because that's a very theoretical high-level assumption you guys are using?
Yes, yes. Yes, I think that's right. This is actually a very good question, Ben, because we've kind of talked around here around the organic opportunities in the $5 billion to $6 billion. But I like to think of it as if you look at the 4 businesses now, you're probably looking at between $1 billion or $2 billion for each of them per year to fill that $5 billion to $6 billion. And you pointed one out there that is pretty much locked in with the Gas Distribution business, around $1 billion. Certainly, Bill's opportunity set is certainly in that category, at least Vern's, and then we've got, as we said earlier, the offshore wind. So it doesn't take long when you look at the 4 franchises to get to those kinds of numbers in -- just with organic growth. But obviously, these things don't happen naturally every year. I mean there's probably bumpiness to this, and that's just part of organic-based growth. So I think we feel pretty good about the $5 billion to $6 billion and getting there within the core franchises.
Praneeth Satish of Wells Fargo is online with a question.
Just what kind of interest are you seeing from shippers to expand Seaway? It seems like there's a lot of capacity now out of Cushing. So just wondering what the competitive advantages of the project.
Okay. It's Vern here. So we've seen some pretty good interest on the Seaway open season. It's probably one of the lowest tolls for light crude from Cushing to the Gulf Coast. But having said all that, the shippers have come back to us and said they want more flexibility as far as different crude types that could be moved. And then we have the advantage of being the really the primary conduit of heavy crude into the Gulf Coast. So we're going back and amending our TSAs to allow for these different crude types, allowing shippers to bring heavy crude to the open season. So we're pretty -- feeling pretty good that with those changes that we'll have a good path to move forward.
And then can you just give us an update on Bakken gas takeaway? And just whether there's been any progress on an alliance expansion? Is this something you can tackle in maybe a phased approach?
Yes. So it's Bill. Yes, we're still plugging away in the Bakken. I think -- we're hoping to have something this year, for sure, as a small project out of there and perhaps take it in phases.
Robert Catellier from CIBC Capital Markets is online with a question.
You touched on this a little bit through your answer to other questions, but I just want to dig down on the Mainline a bit. I don't want to be dismissive of tolls because I know they're important to everyone. But other than tolls, is there a common refrain you're hearing from shippers that are not immediately supportive of the Mainline contract offering? And is there anything you can do operationally, such as enhanced connectivity, storage or anything like that to help ameliorate the situation?
It's Vern. Those are -- that's a great question because, from a producer perspective, tolls are obviously important, but having the ability to compete month in and month out with the refineries is also a very important thing for them. So we are in the background working on additional downstream points for those producers, potentially tankage at Flannigan, potentially longer term more access to Patoka, more access downstream of Flanagan to Cushing in the Gulf Coast, which will ultimately make this more attractive to the producing community. So there are many of these little tweaks that aren't involved with the Mainline but involved with downstream assets that will potentially make this more attractive to producers as we move forward.
Okay. So I guess, that's just going to run in parallel, but not -- it's not supposedly part of the -- certainly not part of the hearing, but I guess, it runs in parallel, yes.
Yes, it's not part of the hearing, but it is a way for us, in parallel, to build more support with the producing community for what we're trying to accomplish here.
Okay. And then just on the very low interest rate environment, I'm wondering if there's any opportunity, further opportunity, to take advantage of that in a way that benefits shareholders, or for example, more asset sales or ways to bring in partners into existing projects to monetize? I know you're kind of at the low end of your leverage rate currently. But are you seeking to take advantage of the low rate environment?
Robert, Colin. Yes, interesting question. I think we're all observing these low interest rates, generationally low rates. I guess, at a first principal's basis, we're -- we tend to derisk interest rate risk. So we're -- obviously, our debt portfolio is significantly termed out and our floating rate exposure would be sub-10% by design. However, within that bucket, we are being as creative as we can be. And we're hustling for every basis point, trying to capture it. We're likely to see some tailwind from this theme on our Canadian rate reset, preferred shares, for example, those are rolling at lower rates than expected and a variety of other things like that, that will contribute smaller contributions to our outlook. You mentioned in a bigger picture, lower interest rates provide a tailwind for a strong on PE bid, which I think will support continued asset recycling, again, on the margin. So those are maybe a couple of barbell examples of how we can participate in this by design.
In fact, that's what -- if you look at the recent asset sale on MATL, that's exactly what happened. It got to a point where we got bids, and we decided to capitalize on it for exactly the reason you're pointing out. There was very strong interest at good valuations.
We have reached our time limit and are not able to take any further questions at this time. I will now turn the call over to Jonathan Morgan for final remarks.
Thank you, Joelle. As always, our IR team is available to take any additional follow-ups you may have. And thank you to everyone for your time and interest in Enbridge, and have a great day.
Thank you, ladies and gentlemen. We appreciate your participation. This concludes today's conference. You may now disconnect.