Enbridge Inc

TSX:ENB

Earnings Call Transcript 2020-Q3

[Operator]

Welcome to the Enbridge Inc. Third Quarter 2020 Financial Results Conference Call. My name is Michelle, and I will be the 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.

[Jonathan Morgan, Vice President of Investor Relations]

Thank you, Michelle. Good morning and welcome to the Enbridge Inc. Third Quarter 2020 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; Bill Yardley, Executive Vice President of Gas Transmission and Midstream; Cynthia Hansen, Gas Distribution -- or Executive Vice President of Gas Distribution and Storage. As per usual, this call is webcast, and I encourage those listening on the phone to follow along with the supporting slides. A replay of the call will be available today, and a transcript will be posted to the website shortly after. We are going to try to keep the call to roughly 1 hour but will allow for additional time if necessary. In order to answer as many questions as possible during the Q&A, we ask that you keep to a single question and rejoin the queue if you have any follow-ups, and we'll do our best to get to each of you. As always, our Investor Relations team is available for any detailed follow-up questions after the call. If you are a member of the media, please direct your inquiries to our communications team. We will be happy to respond. On to Slide 2, where I'll remind you that we'll 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 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 hand it over to Al Monaco.

[Al Monaco, President, CEO & Director]

Thanks, Jonathan, and good morning. I'll depart from the usual process here today and kick things off with how we're thinking about the broader energy environment. So the fundamentals, the energy transition and the resiliency and longevity of our cash flows no matter what the pace of the transition. I'll provide a brief business update today, then Colin will take you through the financial review. And given the interest in capital allocation, he'll talk about our framework and our current thinking. I'll come back at the end and outline the new ESG targets we announced earlier. And just before we begin, a quick comment on the results. Q3 was strong. So we're on track with the 2020 guidance, and we're narrowing that down to the midpoint of our $4.50 to $4.80 DCF per share range. That outcome proves out once again the utility model we operate in the face of the worst industry downturn ever, and part of that ability to achieve the range comes from our ability to have moved quickly on reducing costs by $300 million this year, and we're now projecting $400 million for next. On to the energy outlook. Big picture, our outlook is based on 3 unassailable facts. First, global energy demand will rise in the next 2 decades driven by population growth, an increase in middle class and urbanization. Developing countries by themselves will need at least 35% more energy. And we think North America has a great opportunity to increase global market share of supply simply because we have the best resources, technology, infrastructure and environmental standards. Second, the return of economic growth will depend on affordable and reliable energy. That's always been the case over history and won't change. And third, no matter what future demand looks like or what kind of energy we're talking about, we need existing infrastructure, replacements and newbuild. It's also true, though, that we're transitioning to a lower carbon-intensive economy. You can see that in the fundamentals as well, and we all know the reasons for it. But it's clear to us that the energy transition will be gradual. Here's a snapshot of the fundamentals and how we look at the pace of transition. The recent IEA forecast shows energy demand growing and a slightly shifting supply mix. Now you've all seen a number of new forecasts come out lately, and we've shown the range of those here. And you can see there's a fairly homogenous outlook over the next couple of decades. Supply mix changes a bit. Coal declines, no surprise there. Oil and gas increases and continues to make up over half the mix while renewables moves at a fast clip from a low base. The point of this is that we're going to need all sources of supply in our view to meet demand through at least 2040 and very likely beyond. But we push ourselves on whether demand and supply mix could look markedly different if we transition faster. So on the right, we've laid out what's being done today and what's embedded in that outlook that we showed. And it assumes all announced policies to lower emissions are implemented as scheduled. Energy efficiency improves 2% annually, we spend $35 trillion on new infrastructure, roughly double, and 150 gigawatts a year of solar capacity added versus 85 per year today. EV adoption climbs to 15% of the fleet or 300 million vehicles versus 1% today. Now everybody is motivated to see this happen, but it's not going to be a cakewalk by any means. And without these actions, consumption of energy is very likely to be higher and the mix change a lot slower. Now a more radical change in consumption is possible but not by 2040 in our view. For example, we need more aggressive and globally synchronized policy and significant carbon prices, doubling of efficiency approaching the limit of 4%, increased solar capacity adds by another 65 gigawatts annually and tripling of the EV fleet to 45% by 2040. So the next slide gets to why we believe we'll need conventional energy for a very long time to come: oil demand continues to rise and stabilizes, and that's driven by accelerating growth in developing countries; increasing pet-chem demand, I think everyone understands the reasons for that; and oil retains a large share of the transport market. We're even more convinced today, though, that natural gas will dominate global energy. And some people call this the bridge, but it's going to be, in our view, an awfully long bridge. That's simply because gas is abundant, low cost, has excellent load following capability, storability, lower emissions, and it's crucial to renewables intermittency. We expect roughly 40 Tcf per year of new industrial and power gen demand. And RNG are going to be real, and we'll explain our strategy on this in a minute, but unlikely to come into play in a material way before 2040. And of course, renewables are going to continue to grow as it's clear they are competitive. So that's the macro view and why the energy transition will happen gradually in our opinion. The next few slides illustrates how we're positioned in terms of the resiliency and longevity of our cash flows in whatever transition scenario unfolds. And it begins with our low-risk business model. Most important to that is the diversity of cash flow by business line, commodity and geography, and we have over 40 sources of cash flow. The diversity you see here is the key to us powering through the pandemic that you're seeing today. Our business has strong commercial underpinning, the best customers and a solid balance sheet. And all of that has allowed us to generate steadily increasing cash flows in all cycles, commodity price downturns, the financial crisis, upstream disruptions and now COVID. We hear a lot about terminal value risk today, so let me illustrate why we're confident in the longevity of our cash flow, starting with Gas Transmission. Here, we serve 170 million people with last-mile connectivity to the U.S. Northeast, Southeast, Midwest and West Coast. These customers and the utilities that serve them aren't going anywhere anytime soon. We're also connected to global export markets through LNG, so that's a good upside for us post COVID. The yellow dots here show how crucial our gas system is to replacing coal but also in meeting future U.S. Northeast offshore renewable power balancing requirements. The business has long-term contracts, cost of service and regulatory protection. Revenues are mostly 100% reservation-based, and contracts are serially renewed for a term year after year. In fact, Bill just concluded the renewal process at 99% for TETCO and Algonquin. And so clearly, our customers believe in the longevity of our gas system and pipes generally. On to Slide 9, we look at our gas utility the same way. It's an integrated transmission, storage and distribution network serving the fifth largest population center in North America, and those customers aren't going anywhere either. You can see here on the bottom the competitive advantage that gas holds over the alternatives. It's a cost of service business as well. To put its resiliency into context, in order to replace Ontario's peak energy day needs with 100% electricity, you'd need to add 85,000 megawatts of new capacity or 3x the current level. And we don't see that happening anytime soon either. And finally on liquids. This is the quintessential demand-pull business. It's directly connected to refineries that need our feedstock. Our scale at 3 million barrels a day gives us a total advantage, and cash flows are supported by long-term contracts that push and pull volumes through the Mainline. But the linchpin to the longevity of cash flow is the globally competitive refineries we serve. So let me just explain that on the next slide. The chart on the left shows the Nelson Index for global refiners. Higher in this case means they're configured to run heavy crudes that maximize margins and returns. The refineries we serve in the Gulf and the Midwest are the most complex, which, along with their scale, makes them highly competitive. So those refiners are going to be around for a long time as well no matter what scenario unfolds. What's really unique here for us, though, is shown on the right. Heavy is going to be in shorter supply as Mexico and the rest of the world decline. The only sources of heavy growth are the Middle East and Canada. That's why Canadian barrels with big growth potential and proximity to U.S. markets are ideally positioned. So these 2 realities that you see here not only support the existing Mainline cash flows but provide a great opportunity for us to grow market share. So what we've just gone through on our core assets illustrates the resiliency and longevity of our business for a long time. Now let me talk to our approach on the energy transition itself. That approach really comes down to 2 things: aligning our asset mix to long-term fundamentals and creating what we call low-cost, no-regret options that position us for the future in a way that doesn't mess with our low-risk business. Our liquids business allowed us to capture massive growth in crude infrastructure when it was there. And today, we have the best crude network in North America and, we'd argue, globally. At the same time, though, we diversified our business into gas and renewables. In '96, we had a strong view on the future of gas, so we acquired what is now Enbridge gas utility. Four years ago, we acquired Spectra, which gave us a massive transmission platform and another great gas utility alongside it. Along that road, we embedded options to adapt to changing fundamentals and capture long-term growth. We built our first onshore wind project 2 decades ago. That was a no-regret move because it came with a long-term PPA that ensured a good return. That one initial option allowed us to learn the business and, after many other projects, led to our first offshore wind project in Europe. We've applied exactly the same approach to RNG and hydrogen, which is why we're ahead of the curve on those 2. The pies then at the bottom here illustrate the gradual approach to diversification that has aligned us well with the global supply mix. And during all of this, we optimized our business by driving out costs, selling assets that didn't fit, simplifying the structure and bolstering our financial position. The next slide shows how we're set up today for the future. Our wind and solar assets are in North America and offshore Europe. We've built development, construction and operating capability, and renewables is now the fourth Enbridge platform. Today, we have 1,800 megawatts of capacity net to us, so that's sizable. And the plan is to continue to grow this business in the same way we have, which is organically at a reasonable pace. We are going to be disciplined in this part of the cycle given the frothy private and public valuations that you all see out there. And if we can't find good opportunities, we're not going to stretch our return threshold. In fact, we recently turned away a couple of opportunities that didn't make sense for us. That's fine, and we've got enough in the inventory to keep us busy for the next 5 years. Finally on this topic, we have some excellent low-cost options in play to capitalize on the longer term, similar to what we did on renewables. We'll get to these more at Enbridge Day, but here's a preview of what we're working on. RNG represents an opportunity to grow gas volumes and leverage our own utility and GTM franchises. We have 6 RNG projects operating and in construction. These are in the upgrading and injection end of the RNG value chain. And more planned, all of which are either included in rate base or have long-term contracts, so they fit the overall business. There's been a lot of talk about hydrogen and its obvious merits. The economics, in our view, for blue and green are challenged right now, but support will increase and costs are bound to come down. So another good long-term opportunity for us to capitalize on our infrastructure. We piloted North America's first power-to-gas facility, which uses an electrolyzer to convert water to hydrogen. The plant is contracted to provide grid stability for the ISO to capture off-peak renewable power. In fact, we've just received approval for Phase 2 now to blend hydrogen into the gas stream, which, of course, lowers carbon intensity, and it's used for storage and re-electrification. Related to that is a potentially large application of hydrogen, which is blending in the gas stream all across our transmission network. So excellent marriage here between new technology and our existing infrastructure. I think the takeaway here is that we're ahead of the curve on some of the good long-term opportunities where technology has already been proven out. So we're not too far out on the technology scale. And I think we're doing it in a way that aligns with the pace of transition that we see. So before I hand it to Colin, just a brief business review starting with liquids. Recall, we're cautious on volumes fully returning from COVID, and it turns out that we were right with that forecast. Our Q3 Mainline throughput, we ended up at we were -- at a point where we're forecasting at 2.55 million barrels a day, and that reflected the upstream outages at Suncor's base plant and Kearl. So that was a good outcome, actually. We also returned to heavy apportionment, and we've been full up on heavy capacity since July. That goes to the strong demand in our core markets that I mentioned earlier. On lights, as economic activity continues to ramp in Eastern Canada and the Midwest, we'll see those come back. For Q4, we see heavy capacity fully utilized, so we should be tracking to the Q4 range of 2.55 to 2.75 that we forecast last time, and that accounts for second wave impacts. And you see the Q1 range here at 2.65 to 2.75 next year. Now one thing Vern and his team have been working on is filling up some of that light capacity in the interim with medium blend. So that's a good outcome when it happens. Lastly, liquids started construction of its first self-powered solar gen facility in Southern Alberta, and we're looking to apply this to a broader scale. On Line 3, we're in the late innings here on permitting, so we've narrowed the milestones chart that we normally show to what's left to do. The PC regulatory process in Minnesota is basically done except for authorization to construct after permits are in hand. And on permitting, the PCA contested case finished up with a positive ALJ decision. That's important because it clears the way for the PCA 401 permit decision by next week's statutory deadline and the Army Corps 404 after that. The DNR and the Corps continue to work on those permits, and actually we received a couple of the DNR permits already. So no change really to construction timing at 6 to 9 months once we get all the permits. On Gas Transmission, Bill and team have been working on a comprehensive maintenance and integrity program across the system. TETCO East-bound capacity has now been restored, and South-bound should be back shortly. Rate proceedings are underway. On Alliance, East Tennessee and Maritimes, it's been a busy year on the rate side. As you can see, the team has a healthy slate of high-quality projects in construction, which are moving along well and good cash flow coming on those in the next year or 2. And finally, our first solar power installation came online at Lambertville in New Jersey, and a second is scheduled for next year. On gas utility, this is Slide '18, they put up good numbers and continue to deliver growth. I think Cynthia and her team have done a great job on synergy capture from merging the 2 utilities. In the last year, we added 40,000 customers and more to come by extending the franchise to new communities. Recently FID-ed the new $160 million project to replace 2 mines. So again, right down the middle of the utility fairway. And finally, we did break ground on Ontario's largest landfill RNG facility in Niagara Falls. By the way, the regulator just recently approved a program for customers to choose RNG supply, and that's a good signal in our view. Finally, on the renewables business, we have 3 operating projects in the U.K. and Germany. Good progress on our 4 French projects as well. Two of those, Saint Nazaire and Fécamp, are in construction and on schedule for in-service in '22 and '23. Just looking at the nacelle photo you see here, you get a feel of the scale of these projects and the equipment, which is partly the reason why offshore renewables are competitive today. We've got experienced partners in this business, and our joint venture with Canadian Pension Plan helped us optimize capital and returns. So now, over to Colin.

[Colin Kenneth Gruending, Executive VP & CFO]

Hey, thanks, Al, and good morning, everyone. I'll start on Slide 20 with our enterprise quarterly highlights. Overall, I think a pretty balanced quarter on various dimensions. Operationally, we saw solid utilization across all 4 of our businesses. Al spoke to cost savings. They're on track. This all translates to $1.03 DCF per share and about $3 billion in EBITDA during the quarter. As Al noted, we'll also -- we've advanced several strategic priorities. Construction is moving along well on our $11 billion secured growth program. On Line 3, North Dakota is now complete. And in Minnesota, we're starting to receive initial permits. The state 401 water quality permit is anticipated shortly. Let's move to Slide 21 for the financial review. Nine-month results for EBITDA and DCF are roughly in line with last year for the same period despite the pandemic and other challenges. And similar to Q1 and Q2, Q3 is a little bit stronger than we planned. Adjusted earnings are lower than the prior year, though largely owing to a full year of -- or a full charge of depreciation expense on Line 3 Canada, as you'll recall put into service in December, while we are earning only a modest interim surcharge. This disproportional expense-to-revenue relationship will improve markedly when Line 3 U.S. is completed. Adjusted EBITDA is about on track, too, except for the accounting treatment related to make-up provisions on certain contracted assets for volumes not shipped. On these assets, we received contracted cash payments that we recognize in DCF but, for revenue recognition purposes, do not get included in earnings or EBITDA. In the third quarter, for example, this impact was approximately $120 million and would have led to EBITDA of $3.1 billion otherwise. I'll now walk you through our segments on Slide 22. Liquids Pipelines segment EBITDA was down year-over-year, $94 million, mostly due to the decrease in Mainline volumes year-over-year, which Al already covered. Specifically, we transported about 160,000 barrels per day fewer than Q3 last year, which translates to approximately a $50 million impact. Offsetting some of this impact is a higher Mainline toll, including a $0.20 surcharge collected on the Line 3 Canada segment. EBITDA in the Regional Oil Sands system was about $20 million lower this quarter due to disruptions upstream from the Suncor plant fire, and separately, disruption to the basin diluent supply. As I mentioned, the majority of these assets, though, were underpinned by take-or-pay arrangements, and we collect tariffs for any unused space. Further downstream, our well-contracted Gulf Coast and Mid-Con systems generate reliable base cash flows, too, but lower light spot volumes out of the Bakken and on the Seaway legacy system drag results a little. In contrast, the addition of Gray Oak with its strong contractual underpinnings and the Phase 1 express expansion of 25,000 barrels per day placed into service earlier this year helped again this quarter. Gas Transmission EBITDA was flat year-over-year despite the sale of our Canadian gathering and processing assets at the end of last year and the Ozark assets earlier this year, which, combined, contributable about $25 million historically. Our Gas Transmission assets benefited this year from the rate settlements we announced earlier this year on Texas Eastern, Algonquin and the BC Pipeline system, our 3 big gas systems. These 3 settlements combined are expected to provide an incremental $160 million of EBITDA on an annual run rate basis, and we recognized a slightly greater quarterly pro rata share of that this quarter. Gas Transmission also is benefiting from the realization of ongoing cost savings initiatives. This was offset during the quarter somewhat by the headwind of capacity restrictions related to our integrity program, which is about $50 million of EBITDA during the quarter. This program was substantially completed in October. As a reminder, this business is very utility-like with nearly all of our cash flows coming from reservation-based contracts, many computed through a cost of service regulatory method. Gas Distribution and Storage EBITDA was up $60 million compared to last year, reflecting customer growth and increase in distribution rates and continued synergies capture from the combination of the 2 utilities. This business continues to generate quiet and ratable growth and is again performing well during a challenging operating pandemic environment. Our power business was up also from last year, $11 million. This was primarily driven by the contribution from the 2 German offshore wind farms recently put into service. Our North American onshore wind and solar assets continued to perform well and in line with expectations, also largely unaffected by pandemic effects. In contrast, Energy Services experienced a loss of just over $100 million during the quarter. This is a pretty unusual result and reflects the significant impact of COVID, demand on narrow regional basis differentials and corresponding lighter volume movements. Said simply, this business didn't cover fixed demand charges on its laddered portfolio of pipeline and storage contracts on our systems and others used to generate margin. And to be very clear, we do not take speculative positions on commodity prices. Looking ahead at forward basis differentials, we see challenging market conditions for this business continuing through the fourth quarter, although better than the third quarter and recovering in 2021. And Finally, eliminations and other was $48 million favorable to last year. The majority of this is from lower costs, and I should mention that our enabled $300 million of cost savings are expected -- are reported proportionately in each business segment and also some in maintenance capital, too. Moving to Slide 23 for our DCF reconciliation. Distributions received from our joint venture investments have increased from last year primarily due to new assets placed into service. Maintenance capital, financing costs, income taxes and distributions to noncontrolling interests are all collectively, I would say, trending in line with expectations for the year. Lastly, as mentioned earlier, DCF benefit from the normal course add-back of $120 million of cash received on unused contracts. So overall, we had another solid quarter. On to Slide 24. We have 3 strong quarters in the bank. And as I mentioned, we're well ahead of budget for the 9 months, and that sets us up well for the full year. As we look to the fourth quarter, we're anticipating, though, a few headwinds that will temper this growth. First, volumes on the Mainline are recovering in line with our expectations, though we still anticipate volumes to be down 100,000 to 300,000 barrels per day relative to what was factored into our original guidance. Second, although it's a small part of our business, we're anticipating Energy Services will continue to be a little bit weaker in Q4, as I just mentioned. In Gas Transmission, we expected Q4 to be impacted by some catch-up spending and the ongoing reduction in distributions from DCP. Favorably, though, we expect continued strength in financing costs and cash taxes. So combined, these headwinds and tailwinds give us confidence that we'll be well within the DCF per share guidance range for 2020, in the middle of the range. Ultimately, EBITDA will be likely a little bit lower than our $13.7 billion point estimate target of guidance due to the make-up rights contract treatment I mentioned, but this will be offset in DCF. As we look out to 2021, we expect steady, continued EBITDA growth. This should be driven by the following factors: continued recovery of Mainline light crude volumes; annualized contributions of positive GTM rate settlements; continued customer growth and synergy capture in utility; cost reductions will sustain into '21 and grow, as Al mentioned; and we expect some new assets to come into service on the BC Pipeline in late 2021. As well, there's the potential for contributions from Line 3. The primary headwinds are likely a weaker U.S. dollar used to translate our performance and potentially a smaller headwind in Energy Services. Of course, we intend to provide a more fulsome 2021 guidance package on December 8. On to Slide 25. We continue to remain focused on preserving our financial strength. Our credit rating continues to be among the best in the industry. DBRS and Moody's both reaffirmed their ratings outlook during the third quarter. We expect full year leverage to be well within our target range of 4.5 to under 5x debt-to-EBITDA, which range itself is well within BBB+ territory. Our counterparty credit performance has also been strong despite current market conditions. In addition, our 2020 funding plan is complete, and we've prefunded a portion of 2021. The final topic I'd like to discuss is capital allocation on Slide 26. It's obviously topical. Starting on the left side, along with our base business, the secured capital projects we're executing on are going to generate a tremendous amount of free cash flow once fully in service. And combined with the debt capacity generated by that EBITDA, we anticipate $5 billion to $6 billion of annual financial capacity to reinvest. Now over time, we've maintained a very disciplined organic and risk-adjusted-returns-based approach that's created a lot of value for shareholders, and we aren't going to deviate from that recipe or our low-risk business model. Our first capital allocation priority, of course, is to preserve our financial strength. We've worked our leverage levels down through good execution, simplification and noncore asset sales, and we'll maintain this robust position. Second, we'll continue to prioritize sustainably returning capital to shareholders through dividends. Our dividend is central to our investor proposition, and we intend to grow the dividend annually. And we've always targeted the midpoint of our 60% to 70% payout range over time. Thirdly, we'll continue to grow cash flows organically. But in a word, we'll continue high-grading our focus on projects that deliver the best risk-adjusted returns with high confidence. I'd remind you of our capital program optimization early this year in May for an example of that. It's pretty clear that our 2021 priority is completing our secured growth program, which will generate over $2 billion of incremental cash flows. So you can see the marginal economics on that completion capital is powerful and compelling. For new capital deployment, we'll prioritize regulated rate base additions in our Gas Transmission and utility businesses, which are uniquely positioned to do so. In addition, we'll place continued emphasis across our business on efficient growth opportunities that generate outsized returns with limited capital. A good example of this is our Liquids Mainline capacity optimizations over the last few years. These in-franchise, in-corridor, smaller executable projects come with a much shorter payback period, which is great. And of course, cash flows will be further enhanced by our embedded growth, cost reductions, total escalators and the like. And of course, those require 0 capital. So of our $5 billion to $6 billion of annual financial capacity, this initial high-graded allocation of capital will ratably use up constantly about 2/3 or $3 billion to $4 billion, which is going to leave us about $2 billion to $3 billion of capacity to consider other capital deployment options. In terms of how we use that capacity, clearly, at share prices we see today, share repurchases have moved up the preference order. And our pipeline of more traditional, longer-payback, organic growth opportunities across all 4 of our businesses will need to compete with that. We've also on the slide listed various relevant qualitative considerations here, too. Of course, we'll continue to assess smaller investments in new energy technology infrastructure, as Al mentioned, like we've been doing to create optionality and sustain our competitive edge. I'm thinking about hydrogen, RNG and CNG and the like here. And finally, as we've been saying, large-scale M&A is a low priority. Simply put, we see the execution of our base plan as a superior value-add strategy, and we don't want to compromise our business model. The bottom line is that as shareholders ourselves, we remain hyper-focused on disciplined allocation of shareholder capital. Back to you, Al.

[Al Monaco, President, CEO & Director]

Okay. I'll wrap up with ESG, Colin. Today, we're a clear leader. I think that's apparent from the proof points here and the third-party ratings. And the reason for that is that ESG has been part of how we've operated this business for a very long time. This isn't our first rodeo at ESG. We've set and met targets in the past. And the way we look at ESG is really as an enabler of our operations and our ability to execute strategy. So not a nice-to-have but a must-do, and we believe this is a differentiator. The new targets are about getting even better. And we spent about a year thinking about that and devising a plan to achieve those targets. So in the next slide, on the E, we're setting an interim emissions intensity reduction target of 35% by 2030 and net 0 by 2050. Those cover Scope 1 and 2 emissions from our business. And although the midstream business today overall in our industry accounts for about 2% of the energy value chain, we're going to be tracking performance against Scope 3 as well to reflect our investments in low-carbon infrastructure that we mentioned. On the S, we're increasing our diversity goals, including 40% gender representation and 28% ethnic and racial groups. And that extends to the G, for the Board level, to 40% on gender and 20% on ethnic and racial. And to ensure we have good alignment, we're linking these to executive compensation. The next slide briefly captures our 4 pathways. First, modernizing equipment and applying technology to tackle emissions and reduce consumption using lower-carbon sources of fuel for our pumps and compressors. Self-powering, we're solar in both liquids and gas, as you saw earlier in the examples, and we'll continue to invest in nature-based assets. Just a couple of observations about these pathways. Each of these are already underway, so we're confident on achieving the targets. And of course, this won't take a lot of capital investment just given the nature of those pathways. But anytime we do make an investment, it'll be subject to the usual investment criteria we have for any opportunity, as Colin mentioned in his list. And I think we've developed a pretty good internal framework here for optimizing the mix amongst those choices. So lastly, let me remind everybody about Enbridge Day. The team is excited about it, and we think you'll find it interesting. We'll talk about strategy and major themes that we've touched on today. Then our business leaders are teed up to speak to the big issues they're tackling. And this time around, we're going to showcase our new technology labs that we established last year. Those are essentially incubation hubs for how we optimize the business by using technology. And we'll also talk a little bit about a new entry into floating offshore wind in the future. Finally, of course, we'll talk about 2021 outlook and then beyond. So with that, we'll turn it to the operator for Q&A.

[Operator]

[Operator Instructions] Our first question comes from the line of Rob Hope with Sidoti Bank (sic) [ Scotiabank ].

[Robert Hope, Analyst]

I appreciate all the color on the capital allocation framework. I want to hone in on the potential for M&A here. We've seen some of the supermajors looking to kind of redeploy into other areas of the business, and we've seen some utilities looking to potentially spin out some assets there as well. When you take a look at what assets you want to pick up, can you kind of just outline the framework of what you're looking for? Are you looking to kind of increase ownership of existing assets? Are you looking for contiguous assets? Or are you looking for new platforms?

[Al Monaco, President, CEO & Director]

Okay. Thanks, Rob. So I think if you're looking at the incremental dollar of investment beyond what Colin just went through there, as he outlined pretty clearly, corporate M&A is unlikely to be at the top of our list, and there's a number of very good reasons for that, which we can get into, if you like. But in terms of specific assets, certainly ones where we can build out our core position or protect our core position would be great. I would say from a business line point of view, the marginal opportunity would probably go to Gas Transmission at this point in the cycle given the opportunity set we see there. Obviously, the normal investment criteria, Rob, would apply here. It's -- obviously, accretion near term is a factor, but what we look for really is growth accretion. So if something can be added to the current mix that will give us a new platform to grow from, then that's obviously something that we would favor and work into our look. So that's at a high level how we'd look at the type of asset and the business line in at least as far as asset acquisitions.

[Operator]

And our next question comes from the line of Jeremy Tonet with JPMorgan.

[Jeremy Bryan Tonet, Senior Analyst]

I want to build off, I guess, the last one there as far as using your capital to purchase stuff, but I can't see anything better to purchase than ENB shares out there. So I see how share repurchases moved up the queue there. But just kind of a question in a 9% yield right now. Traditionally, you look to grow the dividend and show that stability, but is there real value in it at this point? It just seems like it's trading at such historically depressed levels. Wondering, why not move buybacks even higher up in the priority list there and really kind of pivot capital there to knock down that share count while it's so cheap?

[Al Monaco, President, CEO & Director]

Yes. Well, I'll start it off, and then we can get Colin to comment as well. First of all, this valuation that we're seeing is not lost on us at all. We're all heavily invested here. So we're aligned with the shareholders on what you just outlined. And I think you're right. It's certainly way up the order. I think for us, Jeremy, this is really a matter of timing. And I think it's really important that, as Colin mentioned, for the next year, we're focused on executing the capital program. And that's simply because we got a ton of cash flow coming out from that, and the incremental economics of this are just so compelling. So I think for 2021, we're pretty much set. I think, as again we outlined, a lot of free cash flow coming at us after that. And I think Colin was pretty clear. Basically, the traditional, longer-term payback, organic projects are going to have to compete just as they always have with buybacks. And certainly, at this price, that's going to be a tougher threshold for them to beat. So that's how we'd look at it. I think post 2021, I think it's going to be a race, if you will, between buybacks and our traditional alternatives. But certainly, buybacks has moved up.

[Operator]

And our next question comes from the line of Robert Kwan with RBC Capital Markets.

[Robert Michael Kwan, MD & Energy Infrastructure Analyst]

If I can follow on capital allocation and optimization and just as it relates to returning capital to shareholders, namely dividends and buybacks. I guess specifically, is it fair to conclude that despite the 8% to 9% dividend yield, that you remain committed to current dividend and growing that dividend? And then for share buybacks, would you consider taking advantage of private market valuations to monetize assets on a larger-scale basis to buy back stock? Because that would also benefit your asset mix transition.

[Colin Kenneth Gruending, Executive VP & CFO]

Colin. A couple of questions there you snuck in, but I'll take them in order. So on the dividend, so -- yes, we understand the centrality of a dividend to our investor proposition, it's importance to our shareholders. So we intend to annually increase the dividend, including for 2021. And we think of that as kind of the base means of returning capital to shareholders. In terms of share buybacks, you can think of that as a supplemental method. And I think Al set up the timing on that pretty clearly. With respect to your second question on recycling capital, I think the answer to that is yes. I think we've demonstrated an acuity and willingness to do that, and we'll keep looking at that. So yes, we're going to be pretty, I think, nimble and look at all alternatives to recycle capital and use it the best way.

[Operator]

And our next question comes from the line of Robert Catellier with CIBC Capital Markets.

[Robert Catellier]

I'd like to further the conversation you addressed, Al, with your comments on hydrogen and the energy transition. So how do you see the relative impacts of hydrogen to long-haul gas transmission and -- versus gas distribution assets? So is one of those asset classes better positioned for growth or more at risk than the other?

[Al Monaco, President, CEO & Director]

Well, actually, this is a good opportunity for Cynthia and Bill to battle it out, so I'm going to let them answer this question. But maybe just a quick comment from me first. The way I look at it, we are in an excellent position here. If you think about both of those systems, very large platforms, massive long-haul pipelines. And the same really holds for the gas utility business. The gas utility, of course, is, let's call it, very close to the customer base here, which could help us a lot with respect to deploying the various elements of hydrogen opportunities. And the other thing is, as Cynthia will tell you I'm sure, we're pretty much advanced on this, not just with the technology itself but how it's actually being applied. As I said, we're pretty much ahead of the curve. And not to mention good interaction with governments. And that's going to be really important, I think, because it's pretty clear that we're going to need more support and acceleration. So I think they've done a good job on that one. And on the GTM side, just again a massive footprint to which to apply future opportunities here. So it might be good, though, just to get Bill and Cynthia's comment. Bill, why don't you go first?

[William Turner Yardley]

Sure. So on the long-haul side, I'd say 2 fairly exciting opportunities. First is a blending game with our current infrastructure. And that's going to take some time to study. We're involved in a couple of different studies as to how it impacts the metallurgy, what the right percentages to blend. But as Al points out, massive footprint with which to operate and make something work there. The second, though, is some of the shorter-haul opportunities both with existing site to totally repurpose or a new pipe and bringing our expertise in siting and construction to that. And we're looking to partner with a couple of folks. Early discussions but nice opportunities there. That's -- I think that's how I'd sum up transmission at this point.

[Cynthia Lynn Hansen]

Thanks, Bill. I would just add, it's Cynthia, Robert, that as Al had mentioned, we are active in the space, in the utility space in Ontario and Quebec. So we do have our power-to-gas facility in Markham, and we're looking at blending into about 3,600 homes starting early next year, 2% hydrogen blend. So we've done the research. We're at a point where we're piloting this. And so I would say we're looking at this as an opportunity. And as Bill mentioned, whether that's going to be blending or it's going to be some new assets, I think we're well positioned for both.

[Operator]

And our next question comes from the line of Asit Sen with Bank of America.

[Asit Kumar Sen, Research Analyst]

I just wanted to follow up on your comments on Mainline volume recovery. Good guidance. Just on light volume, how do you see the lights evolving in 2021? And did I hear 100,000 to 300,000 barrels a day lower volume in Q4? Does that factor in a second wave? And any thoughts on heavy in 2021 relative to Mexico?

[Dai-Chung Yu]

Okay. It's Vern here. So overall, we're seeing across North America gasoline demand down 5% to 10% and diesel demand down about 5% and jet fuel down about 50%. So that's translating into primarily slighter weaker demand on lights. We do see very strong demand for heavy. We're significantly apportioned this month, and we've been apportioned since July. So overall, we're not really forecasting much increase in light demand until probably early to the middle part of next year when we see more recovery in the economy post COVID. We do see our volumes going up, and really that comes from what Al talked about earlier, about blending opportunities that we have where we were effectively being able to move heavy crude on our light crude pipeline. So that's the medium blends where we effectively put more diluent into heavy crudes. So we see a little bit of that happening in the fourth quarter, and we see that ramping up in Q1 and Q2 of next year.

[Operator]

And our next question comes from the line of Linda Ezergailis with TD Securities.

[Linda Ezergailis, Research Analyst]

I look forward to a continued discussion on all of the energy transition at Investor Day. But in the meantime, I'm hoping you can help us think about your Energy Services business going forward and recognizing that some quarters can be quite strong, including the first quarter of 2019 when you made more than $100 million. But looking at the, I guess, laddering of your storage and pipeline commitments, I'm wondering at what pace those expire and whether you would consider renewing those or maybe adjusting your -- the magnitude of those commitments that you make. And I'm also wondering within that context if you're seeing any sort of structural changes in the markets in which you operate, which might also inform how you revisit your approach to committing to capacity. And specifically, with some of the consolidation on the producer side and maybe some economic fallout of COVID, how that informs your energy service risk management and practices.

[Colin Kenneth Gruending, Executive VP & CFO]

It's Colin. A great question. So this is a pretty small business for us. We like it. It's quite effective at what it does. It's a very tightly controlled business from a risk management perspective. And as you mentioned, it's transport and storage contract based. There's no trading. So I think we forecast this business to earn about $100 million in 2020. And the range on that performance historically has probably been $0 to $300 million. It's a pretty tight range. It's generally a positive range. It's a capital-light business generally, and so we like it. We have a ladder of contracts here. So they renew and get extended, and the team does a pretty thoughtful job of trying to be in the right places using their experience. So there isn't really anything structural, I'd say, long term different here. I think the impact that we're experiencing in third quarter is very COVID specific, and we expect the business to return to its historic patterns in 2021 and beyond.

[Al Monaco, President, CEO & Director]

And maybe just a quick add-on to that just on the whole philosophy of the business, which I think gets to your question as well, Linda. In a way, we look at the fixed nature of the commitments as kind of a base level of opportunity that, again, is like a fixed cost but then we apply basically 1 of 3 strategies. So contango is a big one. We get value from the basis. And of course, there's blending opportunities as well where we make some good returns. So it kind of depends on what's happening in the market in any particular year as to how much of the fixed cost you're covering. Generally, we've done pretty well on them. I think in this environment, when the basis is getting crushed -- I think we did well on contango earlier in the year, but I think it's one of those things where you've got an interim issue here that's just affecting the profitability. But longer term, overall we do pretty well on recovering and exceeding those fixed costs.

[Operator]

And our next question comes from the line of Ben Pham with BMO.

[Benjamin Pham, Analyst]

When you look at your cost deck or your dividend yield and you compare it to your all-in cost of debt, it's probably the widest it's been for some time. You're benefiting from the cost of the debt side of things in your guidance. So I guess that's perhaps suggesting equity folks are more concerned about energy transition risk than maybe the fixed income folks, at least at this point in the cycle. My question more is you speak to your -- the credit rating agencies, your fixed income investors and maybe even your lenders in North America. Are you finding energy transition conversations popping up more as being a risk and, in turn, maybe reducing debt and our cap allocation might start to move up in the years ahead for you?

[Colin Kenneth Gruending, Executive VP & CFO]

Colin. Yes, thanks for that question. It's a good one. And I think everyone who's watching energy transition have different views on it and is measuring its pace with different views and values. I think the debt market, you don't -- I mean, I think our observable yields on our debt are pretty transparent. And you don't really see that risk or concern in the debt market, I would say. But I think everyone's having conversations about it. We speak with the agencies about this topic, and they publish on the topic generally. But I think the debt market sees the durability of our cash flow as being quite strong and quite long. So it doesn't seem to be appearing in the debt market.

[Operator]

And our next question comes from the line of Patrick Kenny with National Bank Financial.

[Patrick Kenny, Managing Director]

Just wanted to come back to your comment, Al, on corporate M&A being off the table while, at the same time, you acknowledged public valuations of hydrocarbon assets are clearly under pressure today, which I presume presents a few buy-low opportunities for your strong balance sheet, especially if we look back a couple of years from now and global energy demand does come back strong after the pandemic. So I was just wondering, why not look at consolidation within the hydrocarbon infrastructure arena given we've seen some very big synergy numbers from the E&P consolidators? And I know these opportunities might not be ESG-accretive per se right now and will definitely go against the grain. But if you're not looking to monetize your oil and gas infrastructure and make a bigger, more meaningful switch into clean energy, why not look at executing some generational opportunities to capture financial accretion and really drive that payout ratio down to well below your 60% to 70% target?

[Al Monaco, President, CEO & Director]

Yes. Okay, Patrick. That's, again, excellent question. Let me put it this way. First of all, as you've seen in the upstream side of things, definitely a shift in focus from growth to returns, and with that, free cash flow and less capital. And a source for the upstream industry is clearly synergy capture, which I think is your point. And we like that idea. In fact, if you go back to the Spectra transaction, we more than paid for the low-premium deal by capturing a lot of synergies. So we get that. And I accept the fact that, that's a big opportunity. We monitor this really closely. We're pretty happy with the repositioning that we've done already with the Spectra deal. So the focus right now, as Colin alluded to, is on low-capital-intensity growth. And we've got the balance sheet in shape. As you said, you don't want to mess with that. And we're in an equity self-funding mode here, so we're cautious to use our currency certainly at this valuation. But the broader reality is here that few targets, when you go through the entire list, really fit us well. And the last thing we want to do is mess with the value proposition that we've built up around risk and transparency of cash flow. So I guess in a nutshell, it's not just about near-term accretion and synergy capture for us. We just don't want to dilute the utility business model that we've had. And in many, many cases, in a target list where you've got a valuation advantage today between us and them, you find there's a big swack of G&P usually and other sort of commodity-sensitive businesses. So I think it kind of comes down to that one. I do accept that the synergy capture would be attractive, but that's how we look at the broader picture.

[Operator]

And our next question comes from the line of Andrew Kuske with Crédit Suisse.

[Andrew M. Kuske]

Al, I think you mentioned just the competitiveness of the refineries that you serve, especially in the Gulf. But I don't think you mentioned anything about the longevity of the assets that you serve up in the oil sands. If you could just maybe give us a framing of how you think about that longevity versus just other hydrocarbon assets in North America.

[Al Monaco, President, CEO & Director]

Andrew, I'll get Vern to comment. And he didn't really want to go on today, but I think you're asking a great question. And if you think back to the slide that we showed about the heavy refinery outlook and, in particular, the reduction in heavy globally and where the oil sands plays there as the role it will play, I think it's just a great opportunity for us. And of course, as you know, and this is why I think many people see our Mainline contracting opportunity as attractive, you've got a basin there that has really brought its costs down and doesn't need a lot of new capital to develop. It's very much unlike tight oil and fracking-related investments that happen south of the border. So you got long-live reserves, anywhere from 30, 40, 50, 60 years. And I think that's entirely suitable and a good opportunity to marry up that outlook with the great heavy refining capacity in the Midwest and the Gulf. So I think your question is just spot-on and a very good opportunity for us. And it goes back to the transparency and longevity of our own cash flows here for many years to come. Vern, you got anything to add on that?

[Dai-Chung Yu]

Oh, yes, I think you've covered most of it, Al. The only other point I would make is that those -- the supply, which is long lived, is directly tied to our customers through our system where 3/4 of those refineries are sole-sourced from the Enbridge system. So we're at the natural conduit between very long-lived heavy supply and the most competitive refineries in -- globally.

[Operator]

And our next question comes from the line of Alex Kania with Wolfe Research.

[Alexis Stephen Kania, Senior Vice President]

I guess just a question on the offshore wind business. Do you have a sense that maybe you'd want to get more involved in, I guess, the ground-up development side of things where returns might be a little bit better now that you've got a little bit more experience? And then if I can as well, does this kind of being focused a little bit more in Europe give you maybe a little bit kind of better sense of kind of how the hydrogen strategy is evolving over there as well?

[Al Monaco, President, CEO & Director]

Okay. On the first part, I'll take it, on the offshore strategy, let's call it. I think you're spot-on, actually. What we're seeing today with late-stage projects, which, frankly, we've used to kind of build up the business, is it's very frothy, as I said in my remarks. So I think the natural thing for us to do to build out the business from here given we now have great capability on operating, commercial and development is start to move up the value chain. And so call it more traditional development model that we use elsewhere in the business on the pipe side. So yes, I would say that's an opportunity for us and likely a good way for us, frankly, to make sure that we're getting the returns we need out of the business. Of course, you have to develop -- you have to manage the risks more carefully when you're further up the chain. But as I said, I think we've got the skills now where we can manage those well. So I think you're heading in the right direction. On European effects of hydrogen, I don't know, Cynthia, if you want to comment on that on the global front.

[Cynthia Lynn Hansen]

Sure. Thanks, Al. So we are very active with the international kind of hydrogen market. So we do have lots of opportunities to interact through world hydrogen councils and other activities. So it's something that we're interested in and we've had an opportunity to monitor, and we'll continue to look for opportunities for us to see how the technology is developing.

[Al Monaco, President, CEO & Director]

Yes. I think that's right. Certainly, from where it is in its life cycle, I think us learning as much as we can, and that includes Europe, is the way to go. But I'd say we have so much right in our backyard here with the Gas Transmission side and then, of course, the utility. We've got a lot of -- a lot in front of us right now. Generally, Europe is probably a little bit ahead on this, but I think, as I said, we're up the curve as well.

[Operator]

And our next question comes from the line of Michael Lapides with Goldman Sachs.

[Michael Jay Lapides, Vice President]

Just curious, and this may be a Vern question or someone else on the team. We're seeing Trans Mountain start to make a little more construction progress. And obviously, you guys are making some progress in the permitting process for Line 3. Just curious about your macro views of production levels and whether you think production will kind of grow into this potential significant amount of new pipeline takeaway capacity. And that's even not including what would happen if even KXL came online as well. So just trying to get your views on kind of the economics of production filling all this new pipeline capacity. Or is there potential for Canada to be overbuilt like some of the other pipeline takeaway markets are?

[Dai-Chung Yu]

Okay. Well, I think if you go back to pre pandemic in the first quarter of this year, the basin was obviously significantly pipeline short, where we were moving a significant amount of crude by rail and we had a lot of curtailment happen on the oil sands side of things. So ballpark, we're 500,000 or 600,000 barrels a day short capacity as we started this year. Obviously, our customers have dialed back with the weak crude prices, but we expect those facilities to come back online as demand grows and we see more pipeline egress. So our expectation is when Line 3 goes into service, that we will fill up immediately. We have in our plans that TMX will get completed and we'll also fill up very rapidly as well. So if you look at all of the sources of data for where supply is going to go, we still see robust supply growth in Western Canada. In fact, if you look at the most recent IEA report, it talks about supply growing by 1 million barrels a day between now and 2040 in Western Canada.

[Operator]

And our next question comes from the line of Joe Gemino with Morningstar.

[Joseph J. Gemino, Senior Equity Analyst]

With the positive momentum surrounding Joe Biden potentially becoming the next president in the U.S., do you have any concerns about the progress of Line 3? Do you think with this green deal, he may potentially do what he can to try to stop the replacement?

[Dai-Chung Yu]

At this point, we have all of our federal permits with the exception of the Army Corps 404 permit, which is well underway and near the final stages of being issued. So once we get the Minnesota Pollution Control Agency 401 permit, our expectation is to get the Army Corps 404 permit relatively quickly. And we should remind you that under the prior administration, where Mr. Biden was a Vice President, we were able to get all of our cross-border permits.

[Operator]

And our next question comes from the line of Praneeth Satish with Wells Fargo.

[Praneeth Satish, Senior Equity Analyst]

Thanks for outlining our emissions targets. I'm just wondering from a high level, to meet these targets, would you need to increase the amount of CapEx you're spending on renewables? Or would you kind of get there naturally based on the current amount you're spending on renewables?

[Al Monaco, President, CEO & Director]

Okay. Well, good question. First of all, renewables really doesn't come into this picture. Although it's certainly part of our strategy, it doesn't go to, let's call it, offset Scope 1 and Scope 2 emissions. We do that by the other elements of the strategy. So as I said, modernizing the grid, for example, new compression, where we reduce emissions. And in those cases, the plan is to recover that capital as we spend it. The other elements are very low capital intensity. Solar self-power is an item but very small. And of course, procuring lower-emissions power from a transitioning grid overall, for example, given that coal is coming off, that's part of how we're going to achieve the targets. So hopefully, that helps. Bottom line is, as I said, we don't anticipate capital-intense effort here in terms of achieving the targets.

[Operator]

And our next question comes from the line of Jeremy Tonet with JPMorgan.

[Joseph Robert Martoglio, Research Analyst]

This is Joe on for Jeremy. Just wanted to build on the ESG side and different scope emissions. Could you talk about -- I think kind of some of the Scope 3 emission reductions are a bit later dated. Could you talk about how significant that could be compared to kind of Scope 1 and 2 emissions both in terms of what the size is now and how Scope 3 emissions can be reduced?

[Al Monaco, President, CEO & Director]

Well, okay. First of all, given that we, as I said in my remarks, only represent 2% of the energy value chain as a starting point, we're, first of all, focused on our own emissions. Scope 3 emissions are obviously upstream and downstream of us, including at the consumer level. So the way we look at it, we do invest in renewables and other new technologies. So really, those investments are going against, if you will, the Scope 3 emissions. So the way we look at it is those investments serve the broader societal benefit because obviously, Scope 3 are emissions that occur at the consumer level. So again, we really don't see that as a key metric as far as Scope 1 and 2. But it's always good to keep in mind that the renewables investments we make actually go to Scope 3. And we'll see how that develops here in the next little while as we start tracking that.

[Operator]

Thank you. This concludes the question-and-answer session, and I will turn the call back over to Jonathan Morgan for his final remarks.

[Jonathan Morgan, Vice President of Investor Relations]

Thank you. And thank you for joining us this morning. As always, we appreciate your ongoing interest in Enbridge. Our Investor Relations team is available to address any additional questions you may have. And once again, thank you and have a great day.

[Operator]

Ladies and gentlemen, thank you for participating in today's conference. This does conclude the program, and you may now disconnect. Everyone, have a great day.