Enbridge Inc Q3 FY2020 Earnings Call

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. At this time, all participants are in a listen-only mode. Following the presentation, we will conduct a question-and-answer session for the investment community. 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, 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; and Bill Yardley, Executive Vice President, Gas Transmission and Midstream; Cynthia Hansen, Executive Vice President, 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 on the website shortly thereafter. We are going to try to keep the call to roughly one hour, but we'll 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 who will be happy to respond. Onto slide two, where I’ll remind that we’ll 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 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. 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 began 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 in 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. Onto the energy outlook. Big picture. Our outlook is based on three unassailable facts. First, global energy demand will rise in the next two decades, driven by population growth and increase the 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, what kind of energy we're talking about, we need existing infrastructure, replacements and new build. 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. 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's 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 changed 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 4%, increased solar capacity added 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 then stabilizes, and that's driven by accelerating growth in developing countries, increasing petchem 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, of 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 through renewables intermittency. We expect roughly 40 Tcf per year of new industrial and PowerGen demand and RNG are going to be a real, then 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 illustrate 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 flows, 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 paced and contracts are serially renewed for 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 longevity of our gas system and pipes, generally. On the slide nine, 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 three times 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 main line. But the land spend 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 in 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 two 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 our business for a long time. Now, let me talk to our approach on the energy transition itself. That approach really comes down to two 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 and crude infrastructure when it was there. And today we have the best crude network in North America and lead argued globally. At the same time, though, we diversified our business into gas and renewables. In 1996, we had a strong view in 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 two 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 two. 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 our 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 five 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 six RNG projects operating and in construction. These are in the upgrading and injection of the RNG value chain and more plants, 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've 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 is 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, an 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 forecasting it to 2.55 million barrels a day, and that reflected the upstream outages at Suncor's base plant and curl, 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 in 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, a 2.65 to 2.75 next year. Now, one thing Vern and his team had been working on is filling up some of that light capacity in the interim with medium blends, so that's a good outcome when it happens. Lastly, liquid started construction of its first self-power 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 endings 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 that aren't 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 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 DNR permits already. So no change really to construction timing at six to nine 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 eastbound capacity has now been restored and southbound should be back shortly. Rate proceedings are underway on Alliance, East Tennessee, and Maritime has 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 two. And finally, our first solar power installation came online at Lambertville, New Jersey and a second is scheduled for next year. On gas utility, 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 two utilities. In the last year, we added 40,000 customers and more to come by extending the franchise to new communities. Recently FID, the new $160 million project to replace two lines, 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 three operating projects in the U.K. and Germany, good progress on our four French projects as well. Two of those, Saint Nazaire and Fécamp are in construction and on schedule for in-service in 2022 and 2023. Just looking at the new cell 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 helps us optimize capital and returns. So, now over to Colin.

Thank you, Al, and good morning, everyone. I'll begin with our enterprise quarterly highlights. Overall, it was a balanced quarter across various aspects. We observed strong utilization in all four of our businesses. Al mentioned the cost savings, which are on track. This has resulted in $1.03 DCF per share and approximately $3 billion in EBITDA for the quarter. As Al pointed out, we have made progress on several strategic priorities. Construction is progressing well on our $11 billion security growth program. Line 3 in North Dakota is now complete, and in Minnesota, we are beginning to receive initial permits. We expect the State 401 water quality permit soon. Now, let’s move on to the financial review. The nine-month results for EBITDA and DCF are roughly comparable to last year for the same period, despite the pandemic and other challenges. Similar to the first two quarters, Q3 was slightly stronger than we anticipated. Adjusted earnings have decreased compared to the previous year primarily due to a full year of depreciation expense for Line 3 in Canada, which went into service in December. Although we initially earned only a modest interim surcharge, this disproportionate expense will improve significantly once Line 3 in the U.S. is operational. Adjusted EBITDA is also largely on track, except for accounting treatments related to make-up provisions on certain contracted assets for volumes not shipped. We received contracted cash payments for these assets, which we recognize in DCF but do not include in earnings or EBITDA for revenue recognition purposes. In the third quarter, for instance, this impact was about $120 million, which would have led to EBITDA of $3.1 billion otherwise. Now, I'll discuss our segments. The Liquids Pipelines segment's EBITDA dropped year-over-year by $94 million, mainly due to a decline in Mainline volumes, which Al already discussed. Specifically, we transported about 160,000 barrels per day fewer than in Q3 last year, resulting in approximately a $50 million impact. However, this was partially offset by a higher mainline toll, including a $0.20 surcharge from the Line 3 Canada segment. The EBITDA for the Regional Oil Sands system was about $20 million lower this quarter due to disruptions from the Suncor plant fire and a separate disruption in the basin supply. The majority of these assets are backed by take-or-pay arrangements, allowing us to collect tariffs for any unused space. For the downstream segment, our well-contracted Gulf Coast and MidCon systems provide reliable cash flows, though lower light spot volumes out of the Bakken and on the Seaway legacy system slightly impacted results. In contrast, the addition of Gray Oak, with its strong contractual foundations and the recent completion of its Phase 1 expansion of 25,000 barrels per day, positively contributed this quarter. Gas Transmission EBITDA remained flat year-over-year, despite the sale of our Canadian gathering and processing assets last year and the Ozark assets earlier this year, which historically contributed about $25 million. Our Gas Transmission assets benefited from the earlier announced rate settlements on Texas Eastern/Algonquin and the BC Pipeline system, which are our three major gas systems. These settlements are expected to add an incremental $160 million to EBITDA annually. We also recognized a slightly larger quarterly share of that this quarter. Additionally, Gas Transmission is experiencing the benefits of ongoing cost-saving initiatives, although it faced some headwinds from capacity restrictions due to our integrity program, which affected about $50 million of EBITDA this quarter. This program was largely completed in October, and this business operates similarly to utilities, with most of our cash flows derived from reservation-based contracts, many calculated through a regulatory cost of service method. Gas distribution storage EBITDA increased by $60 million year-over-year, driven by customer growth, increased distribution rates, and continued synergies from combining the two utilities. This segment continues to produce steady and predictable growth and is performing well, even amid the challenges posed by the pandemic. Our power segment also experienced growth of $11 million compared to last year, primarily due to contributions from the two German offshore wind farms established recently. Our North American onshore wind and solar assets are performing well and meeting expectations, remaining largely unaffected by the pandemic. Conversely, energy services reported a loss exceeding $100 million during the quarter, an unusual outcome that reflects the severe impact of COVID on regional demand differentials and reduced volume movements. To clarify, we do not engage in speculative positions regarding commodity prices. Looking ahead at forward basis differentials, we anticipate ongoing challenging market conditions for this business into the fourth quarter, though we expect improvements compared to Q3 and a recovery in 2021. Lastly, eliminations and others showed a $48 million improvement from last year, primarily due to reduced costs. Our expected $300 million in cost savings are reported proportionately across each business segment and to some extent in maintenance capital as well. Moving on to our DCF reconciliation, distributions from our joint ventures have increased from last year, mainly due to new assets coming online. Maintenance capital financing costs, income taxes, and distributions to non-controlling interests are generally aligning with our annual expectations. Finally, the DCF benefits from the normal add-back of $120 million in cash received related to unused contracts. Overall, we had another solid quarter. We have had three strong quarters thus far, and as previously mentioned, we are ahead of budget for the nine months, setting us up well for the full year. Looking to the fourth quarter, we do anticipate some headwinds that may temper growth. Volumes on the Mainline are recovering as expected, but we still project that they will be down by 100,000 to 300,000 barrels per day compared to our original guidance. Additionally, energy services are expected to remain somewhat weaker in Q4, as I previously stated. We anticipate that Q4 Gas Transmission will also be affected by some catch-up expenditures and ongoing distribution reductions from DCP. On the positive side, we expect continued strength in financing costs and cash taxes. Therefore, combining these headwinds and tailwinds gives us confidence that we will remain within the DCF per share guidance range for 2020, likely near the midpoint. Ultimately, our EBITDA may fall slightly short of our $13.7 billion guidance target due to the treatment of makeup rights contracts, but this will be compensated in DCF. For 2021, we foresee steady EBITDA growth driven by several factors: a continued recovery in Mainline light crude volumes, annualized contributions from positive GTM rates settlements, ongoing customer growth and energy capture in our utility segment, and sustained cost reductions into 2021 as mentioned by Al. We expect some new assets to start service on the BC Pipeline in late 2021, along with potential contributions from Line 3. The primary challenges might include a weaker U.S. dollar that could affect our performance translation and a potential further headwind in energy services. We plan to present a detailed 2021 guidance package on December 8. Now to discuss preserving our financial strength. Our credit ratings remain among the best in the industry. DBRS and Moody's reaffirmed their ratings during the third quarter. We expect full-year leverage to stay within our target range of 4.5 to under 5 times debt to EBITDA, comfortably within triple B plus territory. Our counterparty credit performance has also remained strong despite current market conditions. Additionally, our funding plan for 2020 is complete, and we have pre-funded a portion of 2021. The final topic I'd like to discuss is capital allocation. Starting with our base business, the secured capital projects we are executing will generate significant free cash flow once fully operational. Together with the debt capacity driven by that EBITDA, we expect to have $5 billion to $6 billion available for reinvestment annually. We have consistently adhered to a disciplined organic and risk-adjusted returns-based approach, which has created substantial value for shareholders, and we intend to maintain that strategy and our low-risk business model. Our top capital allocation priority is to uphold our financial strength. We have effectively reduced our leverage through good execution, simplification, and the sale of non-core assets, and we will continue to uphold this robust position. Next, we plan to prioritize returning capital sustainably to shareholders through dividends. Our dividend is a core aspect of our investor proposition, and we aim to grow it annually, targeting the midpoint of our payout range over time. We will also focus on organic cash flow growth, placing emphasis on projects that yield the best risk-adjusted returns with high confidence. The completion of our secured growth program is our primary priority for 2021, projected to generate over $2 billion in incremental cash flows. This completion capital has compelling marginal economics. Regarding new capital deployment, we will prioritize regulated rate base expansions in our Gas Transmission and Utility businesses, as they are uniquely positioned for such opportunities. Additionally, we will maintain focus on efficient growth prospects that generate superior returns with limited capital, like our Liquids Mainline capacity optimizations in recent years. These smaller executable projects have shorter payback periods, which is advantageous. Our cash flows will also benefit from embedded growth cost reductions, total escalators, and similar factors that require no capital investment. Of our anticipated $5 billion to $6 billion annual financial capacity, we expect about two-thirds or $3 billion to $4 billion to be allocated for this initial categorization of capital, leaving us with $2 billion to $3 billion available for other deployment options. Given the current share prices, we are inclined to prioritize share purchases, and our pipeline of traditional longer-term organic growth opportunities across all businesses will compete for this capacity. We have also included relevant qualitative considerations in our evaluation. We will continue to explore smaller investments in new energy technology infrastructure to sustain our competitive edge. Lastly, we view large-scale M&A as a low priority. We believe executing our foundational plan will deliver greater value. We are committed to a disciplined allocation of shareholder capital. Back to you, Al.

Okay. I'll wrap up with ESG. 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. 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 zero 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 and low carbon infrastructure that we mentioned. On the S, we're increasing our diversity goals, including 40% gender representation, 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 four 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 with solar on both liquids and gas as you saw earlier in the examples, and we'll continue to invest in nature-based offsets. 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 any time we do make an investment, it will 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.

Thank you. We will now begin the question-and-answer session. Our first question comes from the line of Rob Hope with Scotiabank. Your line is open. Please go ahead.

Good morning, everyone.

Morning.

Appreciate all the color on the capital allocation framework. One to hone in on the potential for M&A here. We've seen some of the super majors 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 continuous assets, or you're looking for new platforms?

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 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 look at the type of asset and the business line in at least as far as asset acquisitions.

Thank you. I'll hop back in queue.

Thank you. And our next question comes from the line of Jeremy Tonet with JPMorgan. Your line is open. Please go ahead.

Hi. Good morning. I want to follow up on the previous discussion regarding capital purchases, but I don't believe there are better options than purchasing ENB shares. I see that share purchases have increased this quarter, but I have a question about the current 9% yield. Traditionally, one would expect to see dividend growth and stability, but is there real value in that at this moment? It seems to be trading at historically low levels. I'm curious why we shouldn't prioritize buybacks even more and direct capital toward reducing the share count while the price is so low.

Yeah. 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 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 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.

Got it. I'll stop there. Thank you.

Okay.

Thank you. And our next question comes from the line of Robert Kwan with RBC Capital Markets. Your line is open. Please go ahead.

Hey, good morning. I can follow on capital allocation 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 transitions.

Hey, Robert, Colin. A couple of questions there you sneak in. But I'll take them in order. So, on the dividends. So, yeah. We understand this into reality of a dividend to our investor proposition, its importance to our shareholder. 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, yeah. We're going to be pretty, I think, nimble and look at all alternatives to recycle capital and use it the best way.

Thank you so much.

Thank you.

Thank you. And our next question comes from the line of Robert Catellier with CIBC Capital Markets. Your line is open. Please go ahead.

Hi, good morning. I'd like to further the conversation you just made on your comments on hydrogen and the energy transition. So, how do you see the relative impacts of hydrogen into long haul Gas Transmission versus gas distribution assets? So, it's one of those type classes that's better positioned for growth or more risk than the other?

It's a good opportunity for Cynthia and Bill to discuss this question, so I'll let them address it. However, I'll start with a quick comment. I believe we are in a great position here. Both of those systems are large platforms with extensive long-haul pipelines, and the same applies to the gas utility business. The gas utility is very close to our customer base, which can significantly assist us in deploying various hydrogen opportunities. Additionally, as I'm sure they will mention, we are quite advanced not only with the technology but also in its practical application. We are ahead of the curve and have effective interactions with governments, which will be crucial as we will need further support and acceleration. They've done well in that regard. On the GTM side, we have a vast footprint to leverage future opportunities. It would be beneficial to get comments from Bill and Cynthia, so Bill, please go ahead.

Certainly. In terms of long haul opportunities, there are two quite promising areas to explore. The first involves a blending initiative with our current infrastructure, which will require some time for analysis. We are participating in several studies to understand its impact on the metal and the appropriate blending rates. As Al has mentioned, we have a substantial operational footprint that can facilitate this. The second opportunity lies in shorter haul projects, where we can either repurpose existing sites or develop new pipelines, leveraging our expertise in siting and construction. We are engaging in early discussions to partner with a few companies, which presents some promising prospects. That’s how I would summarize the current state of transmission.

Thanks, Bill. I would just add that as Al mentioned, we are active in the utility space in Ontario and Quebec. We have our Powder gas facility in Markham, and we're planning to blend into about 3,600 homes starting early next year with a 2% hydrogen blend. We've done the research and are currently piloting this. I see it as an opportunity, and as Bill mentioned, whether it involves blending or new assets, I think we are well positioned for both.

Okay. Thanks everybody.

Thanks, Rob.

Thank you. And our next question comes from the line of Asit Sen with Bank of America. Your line is open. Please go ahead.

Thanks. Good morning. 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? Thank you.

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 slight weaker demand on lights. We do see very strong demand for heavy, where 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 of 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, or we were effectively being able to move heavy crude on our light crude pipelines. So we see a little bit of that happening in the fourth quarter and we see that wrapping up in Q1 and Q2 of next year.

Thank you.

Thank you. Our next question comes from the line of Linda Ezergailis with TD Securities. Your line is open. Please go ahead.

Thank you. I look forward to continuing our discussion on the energy transition at Investor Day. In the meantime, I hope you can help us think about your energy services business going forward. Some quarters have been quite strong, like the first quarter of 2019 when you made more than $100 million. With your storage and pipeline commitments in mind, I am curious about the pace at which those expire and whether you would consider renewing or adjusting the scale of those commitments. Additionally, within that context, are you noticing any structural changes in the markets where you operate that might influence how you reevaluate your approach to capacity commitments? Specifically, with some consolidation among producers and potential economic impacts from COVID, how does that affect your energy service risk management and practices?

Hey, Lin. This is Colin. A great question. So, this is a pretty small business for us. We like it. It was quite effective at what it does. It's a very tightly controlled business for 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 is probably being zero 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.

To add to that, regarding our business philosophy, we consider the six types of commitments as a fundamental opportunity, similar to a fixed cost. We employ one of three strategies to maximize this. Contango is significant for us as we derive value from the basis, and we also benefit from blending opportunities that yield good returns. The extent to which we cover fixed costs varies based on market conditions each year. Overall, we have performed well in this aspect. Although the current market is challenging with diminishing basis, we previously benefited from contango this year. There is a short-term issue affecting profitability, but in the long run, we generally succeed in recovering and surpassing those fixed costs.

Thank you.

Thank you. And our next question comes from the line of Ben Pham with BMO. Your line is open. Please go ahead.

Okay. Thanks. Good morning. When you look at your cost of equity or your given yield and be compared to your all in cost, that it's probably too wide. It's been for some time you're benefiting from the cost of the debt side of things and your guidance. So, I guess, that's perhaps suggesting equity folks are more concerned about energy transition to risk and maybe to fixed income folks at least at this point of the cycle. My question more is, you speak to the credit rating agencies or fixed income investor is and maybe even your lenders in North America. Are you finding energy transition conversations popping up more, that's being a risk and in turn, maybe reducing debt and capital allocation might start to move up in the years ahead for you.

Thank you for that question, Ben and Colin. It's an important one. I think everyone has different perspectives on the energy transition and is assessing its pace through various lenses and values. Regarding the debt market, our observable yields are clear, and I don't see significant risks or concerns there. Everyone is discussing this topic, and we engage with agencies that also publish about it. However, the debt market seems to recognize the strength and longevity of our cash flows, so these issues don't appear to be influencing it significantly.

Okay. Thank you.

Thank you. And our next question comes from the line of Patrick Kenny with National Bank Financial. Your line is open. Please go ahead.

Yeah. Good morning. Just wanted to 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, just wondering, why not look at consolidation within the hydrocarbon infrastructure arena, given we've seen some very big synergy numbers from the ENP consolidators, and I know these opportunities might not be ESG accretive per se, right now. We 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.

Yeah. 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 liked 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 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 built up around risk and transparency 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 the target list where you've got a valuation advantage today between us and them, you find there's a big whack at GNP 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.

That's great. Thanks, Al.

Thank you. And our next question comes from the line of Andrew Kuske with Credit Suisse. Your line is open. Please go ahead.

Thanks. Good morning. Al, I think you mentioned just the competitiveness of the refineries that you serve, especially in the Gulf. 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 framing of how you think about that longevity versus just either hydrocarbon assets in North America?

I'll get Vern to comment, although he was hesitant to speak today. You raised a great question. If you remember the slide we shared about the heavy refinery outlook, particularly the global reduction in heavy and the role of oil sands, it's a significant opportunity for us. As you know, many view our Mainline contracting opportunity as attractive. The basin has effectively minimized its costs and doesn't require much new capital for development, which is quite different from oil tied to fracking investments in the U.S. The reserves have a long life, ranging from 30 to 60 years, making this a good fit for the heavy refining capacity in the Midwest and the Gulf. Your questions are very relevant and highlight a strong opportunity for us. This is tied to the transparency and sustainability of our cash flows for many years ahead. Vern, do you have anything to add?

I believe you have addressed most of it, Al. The additional point I would make is that the long-life supply is directly connected to our customers through our system, where three quarters of those refineries rely solely on the Enbridge system. Therefore, we are positioned as the natural link between a very long-life heavy supply and the most competitive refineries worldwide.

Thank you.

Thanks, Andrew.

Thank you. And our next question comes from the line of Alex Kania with Wolf Research. Your line is open. Please go ahead.

Great. Thanks. Good morning. I guess, just a question on the offshore wind business. Do you have a sense that maybe you'd want to get more involved than I guess the ground-up development side of things, where returns might be a little bit better and now that you've got a little bit more experience? And if I can as well, 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.

Sure. Regarding the offshore strategy, I agree with your observation. Currently, with late-stage projects, which we've leveraged to build our business, the situation is quite dynamic. Therefore, a logical step for us to expand would be to advance further up the value chain. We intend to adopt a more traditional development model, similar to what we utilize in other areas of our business, particularly in pipeline operations. This presents a solid opportunity for us to secure the necessary returns for our business. Naturally, we will need to develop and manage risks more diligently as we ascend the chain, but I believe we have the expertise required to handle those challenges. So, I think you are on the right track. As for the European impacts of hydrogen, Cynthia, would you like to provide some insights on the global perspective?

Sure. We are very active with the international kind of hydrogen market. So, we do have lots of opportunities to interact through rural 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.

I think that's correct. Given its current stage, we should focus on learning as much as possible, including from Europe. However, we have significant opportunities here at home with Gas Transmission and the Utility sector. There's a lot ahead of us right now. Generally, Europe may be a bit more advanced in this area, but we are also progressing well.

Thanks very much.

Okay.

Thank you. And our next question comes from the line of Michael Lapides with Goldman Sachs. Your line is open.

Thank you for taking my question. I'm curious about the construction progress of Trans Mountain and the permitting process for Line 3. What are your overall thoughts on production levels? Do you believe production will be able to match the significant increase in new pipeline takeaway capacity? Additionally, how might the situation change if KXL were to come online as well? I'm trying to understand the economics of production filling this new pipeline capacity and whether there is a potential risk of being overbuilt like in some other pipeline takeaway markets.

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 happened 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 week 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 will 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.

Got it. Thank you, guys. I'll stick to the one question requirement and follow-up with John offline. Much appreciated.

Thank you, Mike.

Thank you. And our next question comes from the line of Joe Gemino with Morningstar. Your line is open. Please go ahead.

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

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 the Vice President, we were able to get all of our cross-border permits.

Okay. Thank you.

Thank you.

Thank you. And our next question comes from the line of Praneeth Satish with Wells Fargo. Your line is open.

Thanks. Thanks for outlining your 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?

Thank you for the question. To clarify, while renewables are part of our overall strategy, they don't directly contribute to offsetting Scope 2 emissions. We focus on other aspects of our strategy for that purpose, such as modernizing the grid and implementing new compression technologies to reduce emissions, with the plan to recover those capital expenditures. The other components have low capital needs. Solar self-power is a small part of this, and we are also looking to secure lower emissions power as the grid transitions away from coal. So, to summarize, we do not expect to need significant capital investment to meet our emissions targets.

Got it. Thank you.

Thank you. And our next question comes from the line of Jeremy Tonet with JPMorgan. Your line is open. Please go ahead.

Hi, this is Joe, substituting for Jeremy. I wanted to expand on the ESG topic and discuss the different Scope emissions. Could you explain the significance of Scope 3 emission reductions, especially in comparison to Scope 1 and 2 emissions, considering their current size and the potential for reducing Scope 3 emissions?

First of all, we only represent 2% of the energy value chain as a starting point. We are primarily focused on our own emissions. Scope 3 emissions, which occur both upstream and downstream, including at the consumer level, are part of our considerations. We invest in renewables and other new technologies that help address these Scope 3 emissions. Our view is that these investments provide broader societal benefits since Scope 3 emissions occur at the consumer level. Therefore, we don't see Scope 3 as a key metric in relation to Scope 1 and 2. However, it's important to remember that our investments in renewables positively impact Scope 3, and we will monitor how this evolves in the near future as we begin tracking it.

Thank you. That's helpful.

Okay.

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

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.

Ladies and gentlemen, thank you for participating in today's call.