Enbridge Inc Q4 FY2020 Earnings Call

Welcome to the Enbridge Inc. fourth quarter 2020 financial results conference call. My name is Jonathan and I will be your Operator for today’s call. At this time, all participants are in a listen-only mode. Following the presentation, we will conduct a question and answer session for the investment community. During the question and answer session, if you have a question, please press star then one on your touchtone phone. Please note that this conference is being recorded. I would now like to turn the call over to Jonathan Morgan, Vice President of Investor Relations. Jonathan, you may begin.

Thank you. Good morning and welcome to the Enbridge Inc. fourth 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, Gas Transmission and Midstream; Cynthia Hanson, Executive Vice President, Gas Distribution and Storage; and Matthew Akman, Senior Vice President, Strategy and Power. As per usual, this call is webcast and I encourage those listening on the phone to follow along with the supporting slides. We’re 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 portion of our call, we ask that you each keep to a single question and rejoin the queue if you have any follow-ups. We’ll do our best to get to each of you. As always, our Investor Relations team is available after the call for any detailed follow-up. If you are a member of the media, please direct your questions to our communications team, who will be happy to respond. Onto Slide 2, where I’ll remind that we’ll be referring to forward-looking information on today’s call, and by its nature, this information contains forecast assumptions and expectations about future outcomes which are subject to the risks and uncertainties outlined here and discussed more fully in our public disclosure filings. We’ll also be referring to non-GAAP measures summarized below. With that, I’ll turn it over to Al Monaco.

Okay, thanks Jonathan. Good morning everybody. Colin and I are going to cover the usual agenda, including the business update, the financials, and a recap of our capital allocation priorities. Given the challenging dynamics of energy today, we’re also continuing our discussion on how we see the energy space. At the end, I’ll tie it together with what you see here on the slide, which is how Enbridge is the bridge to the energy future and the value proposition that we’re offering. Let me start with the energy landscape. As we said at Enbridge Day, we’re cautious near term but very optimistic about the long term fundamentals. We’re in the heart of the second wave here, so the timing of a full recovery is uncertain and it depends on the speed of the vaccine rollout, but a strong recovery is bound to happen. It’s also clear that the industry is fully aligned on the need to reduce emissions. We ourselves have established a net zero target and we’ve built optionality by diversifying our business and investing ahead of the curve on renewables, RNG and hydrogen, which will drive more infrastructure opportunities for us. But we also know that our economies are dependent on low cost, reliable energy - that’s always been true and always will be. Stimulus is driving the right conditions for the recovery and it’s playing out if you look at the pick-up in demand and stabilizing commodity prices. A good example is the growth we’re seeing right now in Asian economies and it’s actually bolstering U.S. Gulf Coast energy exports. The fact is that all sources of energy supply are going to be needed to meet growing energy demand, and conventional energy and new investment in conventional energy is going to be part of that. We think Western Canada is really well positioned. Producers have lower breakevens, cut emissions, and built a backlog of capital efficient, long lived supply growth. Developing Greenfield egress projects is going to be challenging, as it is today, so as new capacity is needed, the first call will be optimize, expand and modernize existing infrastructure. That means the value of pipe in the ground is set to increase. We ourselves have plenty of opportunities in the hopper to support new upstream investment and energy export growth. Capitalizing on the value uplift, though, will depend on how good you are at environmental protection and permitting and the emissions reduction solutions that you bring to the table, so companies with scale, existing connections to prime markets including exports, and world-class execution capability will thrive. Others won’t survive. The strategic location of our assets and the capabilities we’ve developed to operate in this environment means we’re best positioned to win. Spending a minute on the energy outlook, we believe gas will be critical to any energy transition scenario you want to pick and future economic growth. Its abundance means it will be economic for a long time, it’s got excellent load following capability on generation, lower emissions, and it will allow renewable generation to grow. Its fuel and density advantages are critical to industrial and manufacturing competitiveness - we’ve seen that play out globally as well. Demand was only down 4% versus 2019, and U.S. LNG exports have picked up nicely to 11 Bcf per day last month. The next slide hits home the fact that crude is also moving in the right direction. If you look at refined products, petchem demand didn’t miss a beat last year, and gasoline and diesel are climbing back. Jet fuel will take longer for obvious reasons, but it’s a smaller slice of demand. You can see the massive 20 million barrel per day COVID impact on crude in Q2, so it will take some time to get fully back to normal. Oil exports held up well last year around 3 million a day, but we remain bullish on the longer term there in particular. Part of that is economic growth in Asia, which continues to invest heavily to kick start their local economies, and all of this lines up well with our U.S. Gulf Coast strategy. We’re starting to see customer interest to support export infrastructure pop back up. Global inventories are trending down, and with current discipline coming out of OPEC and U.S. shale production, we’re seeing price stability. So what does all that mean to us? Our assets are positioned to benefit from growing energy demand, and that’s because of the strength of the markets we deliver to, including great connectivity to both gas and oil exports, the scale of the volumes we move and the competitiveness of our tolls. As you saw this past year, the commercial underpinning and diversification of the assets generates strong and predictable cash flow. When you look at these three franchise maps, the utility-like nature of what we do really comes through. These businesses are absolutely critical to North American and global economies, and they’ll be generating cash flow for a very long time. Our renewables business also fits the utility model very well. That’s how we see the big picture. Now let’s have a look at last year and how it sets us up for this year. In short, we delivered very solid results and progressed our priorities. DCF came in about the midpoint of our pre-COVID guidance range, a good outcome, and it proves out the resiliency of the portfolio. You can see our track here on the right in hitting the numbers over time and delivering constant dividend growth. On liquids, we lost 400,000 barrels per day of volume in Q2, but we mitigated a good chunk of that with cost reductions and a number of productivity enhancements. We drove about $300 million in savings and the plan is to sustain that and add another $100 million this year, and by the way, we did not avail ourselves of government programs to get there. We brought $1.6 billion of projects into service and started construction on Line 3 in Minnesota. We ramped our ESG goals on both emissions and diversity and we extended our 5% to 7% DCF per share growth outlook another year through 2023, so bottom line, in what has been the worst economic and energy downturn in decades, we grew cash flow, increased the dividend when others went the other way, and we ended the year with an even stronger balance sheet. Let me move to the business update, starting with liquids. Fourth quarter main line throughput averaged 2.65 million a day, so we’re seeing the return of volumes that we had forecast. That was driven by good WCSB response and strong pull from our heavy refinery customers. Pad 2 and U.S. Gulf Coast system utilization was up nicely and it really shows the competitiveness of our system to the key markets. In fact, heavy main line capacity has been full since July and we’ve been able to use up some available light capacity by optimizing the system to move mediums. What really shone through was the strength of the basin and our system - that has a lot to do with how critical our heavy feedstock is to our U.S. customers. Given we expect to see further decline in global heavy supply, heavies off of our full path through to the U.S. Gulf will be in big demand - you can see the highlighted path here in yellow. Next is our update on Line 3 and the capital cost refresh that we promised. The entire project underwent exhaustive review and vetting over six years. The record during that time we established is very solid. Our team worked extremely hard with Indigenous partners and we were responsive to community concerns, and that’s why we have strong local and regional support on the ground. We got the final permits in Minnesota in late November and started early work in the field. Recent state and federal court decisions once again validated those permits. You saw the stays were denied at both state and federal levels. I want to emphasize here that we are using the most thorough environmental health and safety measures possible. We made this a world-class project and the permitting agencies were focused on the same thing. The right-of-way is mostly cleared, station work is underway, and trenching and welding have started. We’ll manage through the spring environmental windows as usual, which have been accounted for in our Q4 in-service date estimate. Lots of work ahead on this one, and we’ve reiterated to our execution team that environmental protection and safety are the number one priority here, and that includes stringent COVID measures. The next slide shows our cost estimate for the entire project and now reflects our final post-permit construction plan in Minnesota. From the last estimate in 2017, capital has increased from $8.2 billion to $9.3 billion, or 13%. We actually came in very close to our budget on the vast majority of the project, so that’s great. This increase really stems mainly from our revised execution plan related to regulatory and permitting processes in Minnesota, so let me explain that. As you know, the plan changed to winter construction, which means more manpower and equipment. The days are shorter, productivity is lower, and there is seasonal transition from winter to spring, and I’d remind you as well that winter construction does come with some benefits on the environmental side. We also implemented even greater protection for wetlands, increased erosion controls, and we’re using the most conservative crossing techniques. Obviously the regulatory delays, monthly running costs and carrying costs were higher. Finally, scope changes like re-routing onto the Fond Du Lac Reservation and COVID protocols were needed, so not surprising costs have gone up, but a couple of things we want to note here. Despite this higher investment, our updated full cycle return remains attractive, and we’re seeing a stronger volume profile and lower interest rates versus the original economics, which has helped. Once Line 3 is in service, it’s going to contribute a lot of free cash flow, and this year we anticipate it will be about $200 million in Q4 with volumes and EBITDA ramping up in 2022. Onto Slide 12. Main line contracting is progressing through the regulatory process. We’re currently in what we call the evidentiary phase, which ends in April, and from there we expect a hearing and decision this year. There’s been a lot of commentary recently on main line contracting, but the bottom line is that we’re moving forward with it because it’s what our customers want, and that is dedicated capacity and toll certainty, and that’s why we have strong support. The offering reflected numerous changes, as you know, so that all shippers will be better off. We’re continuing to move our application along and we’re looking forward to the hearing, as that will help us get the facts out onto the table for everyone. On Line 5, a couple of comments on the state’s attempt to revoke the Straits easement that was granted decades ago. First of all, the fact is that the Strait segment is safe, and CIMSA has confirmed that more than once. Secondly, the line is absolutely critical to Michigan and the entire surrounding region, and in our view, attempting to cancel the easement contradicts the U.S. federal jurisdiction over safety of the line, would severely hinder both interstate commerce and North American energy flows, but most importantly it endangers the energy security of millions of people and industry in the entire region, resulting in higher consumer costs and lost jobs at the worst possible time. Let’s remember that Line 5 moves existing volumes, so shutting down this line is a very serious issue for everybody. One thing that’s been lost in all of this is that we are just as or more committed to protecting the Great Lakes than anybody. We’ve proven that by taking numerous additional actions, listening to the states’ concerns very carefully to make a safe pipeline even safer; for example, 24/7 monitoring of vessel traffic in the Straits, replacing the St. Clair crossing, shutting down the line during periods of high wave conditions, and a bunch of other measures, too many to go through today. We then committed to build a tunnel under the Straits to house a brand-new line that will reduce the risk to near zero, and that tunnel was blessed by the state government. On that front, we received initial environmental permits and we’re working on the remaining two approvals. Finally, just a quick point here on development areas for us, which is carbon capture. Just for context here, this has a lot of power in terms of reducing emissions. By 2035, there’s a potential to store 22% of GHGs, and that’s the case on both sides of the border. Transportation is a key part of any carbon solution, which fits our skill sets very well and it’s a big opportunity for us, actually. We’re going to be focused initially on Western Canada where there is strong industry in an industry solution - I’m talking pipe and facilities there. More to come on that one in the months ahead. Now let’s move to our natural gas businesses, which are a key part of the diversification I talked about earlier. In terms of gas transmission, last year was strong and this year looks better as a bunch of projects come into service in the second half. Renewals on Texas Eastern and Algonquin came in at 99%, which just shows how critical these systems are to U.S. northeast energy needs, especially on peak demand - everybody’s noticed how cold it is out there. The team did a good job of settling new rates as well with our customers, so they’re happy, which added a good chunk of EBITDA for us in the process. We completed last year’s $700 million modernization program, which is part of a recurring investment opportunity going forward that Bill talked about at Enbridge Day. We’ve got $5 billion in execution through 2023 of solid return projects that are moving along well - $3 billion of that, by the way, is slated for in service this year, so that will contribute to growing free cash flow. Onto Slide 14, the gas utility put up good numbers again and keeps on giving on growth. We added 43,000 customers last year and synergy capture in that business is on track, so we’re generating a good premium return above the allowed regulated rate. There’s another $4 billion of utility rate-based capital through 2023. Part of this is new community expansions - those are the white dots you see on the map here, and in-franchise replacement projects. On low carbon options, we’ve got six RNG projects operating and in construction, and more planned. On hydrogen, we’re piloting a 2% hydrogen blend facility and most recently Gazifère, that’s our utility in Quebec, is working on a similar pilot. By the way, the RNG and hydrogen projects are either included in rate base or have long term contracts, so they fit the business model. Finally, let’s talk renewables, specifically offshore wind. Offshore France construction is well underway now on the 480 megawatt Saint Nazare project, and we’ve kicked off now the 500 megawatt Fécamp wind farm. We expect those to be cash flowing in 2022 and 2024. Next up is the 450 megawatt Corsuelles project which should reach FID in the first half of the year. Some nice development opportunities we’re working on as well, including an expansion of our operating Rampion project in the U.K. That’s a 1.2 gig project, and another project in Dunkirk offshore France as well. An exciting area of future growth for us is floating offshore wind - Matthew covered that at Enbridge Day, and we’re actually working on a pilot project on the south coast of France, and this could actually turn into a pretty big opportunity for us going forward. As everybody knows, renewables valuations these days are frothy, to say the least, so that’s good for the value of the business but it also means that returns are being crunched down on new opportunities. It’s nice to have a backlog like we do of construction development projects, and we’re not going to stretch our investment criteria on risk or return. The next slide shows how we’re also ramping up our solar cell power program into high gear. We really like these projects because the strategy marries up renewables experience with our gas transmission and liquids franchises, and it reduces our carbon footprint. You can see we’ve got 15 to 20 projects here totaling several hundred megawatts, so roughly half a billion of investment through 2023 and more beyond that. These projects are not just on the drawing board. In October, we completed Lambertville on Texas Eastern and another one is on the go on Texas Eastern as well right now, and we’ve just started our first project for the main line in Alberta. We’ve got several in late stage development here which could FID this year. Just stepping back for a minute in terms of how we look at these from an investment perspective, you have to remember that power costs are one of the largest operating expenses we have. To the extent we can effectively deploy capital and earn a good return to reduce costs and emissions, we’re going to do that. These projects, by the way, compete for capital just like the rest of the organic growth that we have, and we’ll prioritize the best ones. That’s a good segue onto ESG. As you know, we set emissions goals last year - net zero by 2050 and a 2030 interim intensity goal of 35% reduction. We spent over a year landing on these and the levers to make sure we hit these targets, so not pie in the sky at all, and they’re linked to executive compensation. The three primary ways we’ll get there is using less carbon-intense sources to run pumps and compressors, self-powering with solar like the projects I just went through, and modernizing our assets with the latest technology. Maintaining our ESG leadership position is really important to us. I think everybody understands that. Not that we can put that on a slide, but because reducing emissions is part of our business, and it supports the lowest cost of capital. You’ll see here we’ve just added a couple more sector leading scores from S&P and Wells. Let me conclude the business update by reiterating the three-year growth outlook of 5% to 7% DCF per share CAGR through 2023. First, there’s 1% to 2% of highly visible growth from the revenue and cost lines - very little capital required on that. Embedded revenue escalators in liquids and gas are part of it; watching our overhead, which we’ve done a good job at, and importantly leveraging technology to improve productivity and optimize our operations, that has real bottom line impact, and we went through those at Enbridge Day. Another 4% to 5% will come from completing the $16 billion of secured capital that we expect will generate a couple billion of EBITDA through 2023. If we execute as planned, we’ll have $5 billion to $6 billion of annual financial capacity starting after Line 3 goes into service, so call that 2022. As we’ve been saying, we’ll be very disciplined in the way we put that capacity to work, which Colin is going to cover and recap our approach to that. Colin, over to you.

Thank you, Al, and good morning everyone. I will discuss our financial results, secured capital and funding plans, performance outlook for 2021, and capital allocation to enhance shareholder value. First, let's briefly review our 2020 performance. The takeaway is that we are stronger, resilient, and growing. Our balance sheet metrics are solid, providing us with flexibility. We are where we want to be. Our counterparties and the contractual nature of our cash flows remain strong, if not improved. Our cost-reduction actions will also create a competitive advantage. Cash flows and our dividend are increasing despite challenging market conditions, so even though it's a tough year for energy, we are entering 2021 from a position of strength. Moving to our results, 2020 was strong, as mentioned, both operationally and financially. Our gas transmission, distribution utility, and renewable power assets were highly utilized, even during the pandemic. They performed in line with or better than our guidance. Liquids pipeline throughput was solid and recovered quickly, showing the strength of our markets. Our actions on costs helped mitigate most impacts. Full year adjusted EBITDA reached $13.3 billion, aligning with our guidance from December 8. Without unrecognized demand charges on unutilized capacity, we would have reached about $13.5 billion, impacting earnings by approximately $0.10 per share. We do not foresee this factor being significant in 2021 as volumes have mostly recovered. DCF per share of $4.67 is just above our midpoint guidance range, which is a solid result for any year. Now, let’s go through each segment. Liquids pipelines' full year EBITDA increased by nearly $140 million compared to last year, despite pandemic-related volume losses. This growth stems from our annual toll inflator, a $0.20 surcharge for Line 3 Canada, lower operating costs, and a stronger U.S. dollar affecting cash flows. Our regional oil sands volumes are recovering along with main line volumes, and remember that our regional business has strong commercial underpinnings. Additionally, high demand for Canadian heavy barrels driving increased volumes on our Flanagan South and Seaway pipelines was slightly offset by lower light spot volumes on Seaway's legacy system. The Grey Oak pipeline began full operations in Q1, adding continuous take-or-pay EBITDA throughout the year. Overall, this segment's results met our pre-COVID expectations. In gas transmission, full year EBITDA rose by $27 million. Our U.S. and Canada assets benefited from rate case settlements in 2020, generating an incremental $160 million of EBITDA on a full year run rate basis. It's important to point out that 2020 results included about $100 million from prior period revenues due to these settlements. The benefits from rate settlements in U.S. gas transmission were partially offset by higher integrity costs and reduced revenues from pressure restrictions tied to our integrity program, which is now mostly complete and has restored operating capacity. Expect integrity costs to remain high in 2021. Our utility EBITDA grew a bit despite warmer weather; the differences are significant when comparing 2020 with 2019. Weather-adjusted, the business added 43,000 new customers, aligning with historical trends and contributing $500 million of new capital into service along with higher distribution rates. We are also progressing well on amalgamation synergies, reflecting predictable growth in our 2021 guidance. Our renewables segment climbed $80 million over last year and met full year guidance thanks to contributions from German offshore wind farms and good wind resources in our Canadian and U.S. facilities, plus about $40 million from insurance settlements. The energy services segment, which usually contributes around 1% of consolidated EBITDA, posted a loss of just over $80 million for the quarter, and the full year was below our expectations. This aligns with our previous update in December regarding compressed location and quality differentials affecting margins. We anticipate neutral performance in 2021 for this segment, with losses in the first half and positive contributions in the second half. Lastly, eliminations contributed $40 million favorably compared to last year, attributed to better foreign exchange settlements and part of the $300 million enterprise cost reductions for 2020. Now, we will shift focus to our secured growth capital program. We have a strong $16 billion secured capital program, providing visibility to our projected 5% to 7% DCF per share growth outlook through 2023. This program diversifies across all our businesses and comes with contractual frameworks suitable for our low risk model. In 2020, we placed $1.6 billion of utility and utility-like projects into service, and for this year, we anticipate placing about $10 billion of capital into service, some of which has already occurred. This includes the Line 3 U.S. project and smaller expansions within our gas businesses, which are timely and will stimulate local economies. This execution will enhance cash flow growth in 2022 and beyond, strengthening our financial position. We ended 2020 within our debt to EBITDA target range at 4.6 times, with plenty of liquidity. This allows us to manage Line 3 expenses while staying within our 4.5 to 5 times target and still fund this on a self-equity basis. Project execution provides significant financial flexibility, as shown in the middle chart. We have updated the rating agencies on our funding plans, and they are comfortable with our outlook metrics and ratings. In line with our ESG strategy, we secured a three-year, $1 billion sustainability-linked credit facility, a first among our peers, which ties our ESG performance to our borrowing costs. Due to our early 2021 funding actions, we have canceled the $3 billion credit facility taken last March for liquidity during the onset of COVID. Looking at our outlook for 2021, we remain confident in our earlier projections from December. We are seeing strong Q4 performance continue, with main line volumes recovering as expected, and Line 3 construction in Minnesota progressing well, with an anticipated $200 million EBITDA contribution in Q4 once the U.S. portion is operational, in addition to the Canadian surcharge already earning in Q1 to Q4. In gas transmission, both T-South and Spruce Ridge expansions on the B.C. pipeline system are on track for mid-year timelines, and our utility is consistently adding customers and realizing synergies. However, energy services outlook remains challenging. Regarding macroeconomic issues, we have noticed a weakening U.S. dollar against the Canadian dollar. While we have some FX exposure to cash flows, we are largely hedged for 2021, with 90% of earnings and about two-thirds of cash flows protected, leading to a relatively stable outlook. Every $0.01 exchange rate variance equates to approximately a penny of DCF per share. A weakening U.S. dollar may lower our translated U.S. debt balances, which, combined with our hedged cash flows, could positively impact our credit metrics. If corporate tax rates rise in Canada or the U.S., we do not foresee a significant impact on our cash taxes, as we have substantial existing tax pools that will grow. On counterparty risk, the strength of our counterparties is exceptional, as evidenced during the pandemic, and their improved cost structures have left them stronger post-2020. Our ultimate credit protection lies in the strong demand for our trunk line assets. Additionally, we are well-equipped against rising inflation, as around 65% of our revenues feature embedded rate escalators linked to inflation benchmarks. In conclusion, our capital allocation strategy prioritizes balanced sheet protection, which is unwavering. We also remain dedicated to consistent dividend growth. Recognizing opportunities, we expect to allocate $3 billion to $4 billion annually toward high-confidence projects with low capital intensity, while the remaining $2 billion will be dynamically allocated to the most valuable opportunities at hand. Traditional longer-term organic growth projects will need to compete with share buybacks. Given current valuations, share buybacks are appealing. This flexible strategy ensures we maximize shareholder value while supporting our growth ambitions. Now, I’ll hand it back to Al to wrap up.

Okay Colin, thanks. I’ll come back to how we began the call here. If you go back when we established the Enbridge name years ago, it illustrated the fact that we were building energy bridges between low cost supply and the most important demand pull consuming markets. I think we’ve built strong bridges and we’re proud of providing the energy that fuels everybody’s quality of life and drives our economy, and that will be true for a long time. But today, our name also conveys something else, which is how we’re positioning Enbridge as a bridge to the energy future. It’s clear that energy systems are transitioning, just like they have over time, which is why we started diversifying our mix over two decades ago, adding more natural gas and building a renewables business from scratch. Today, we’re investing in low cost options to develop hydrogen and renewable natural gas, and as well looking at carbon capture, and we’re reducing our environmental footprint and targeting net zero emissions. As we do that, though, we’ll continue to generate predictable and reliable growth and are hyper focused on returns and protecting the low risk business model. The $16 billion of secured growth gives us that transparency that Colin mentioned to 5% to 7% DCF per share through 2023, so when you combine the growth outlook, the attractive dividend yield today, the potential for capital appreciation with how we bridge to the energy future, we think Enbridge provides a very compelling value proposition for investors and all stakeholders in any energy market. With that, we’ll turn it to Q&A, and John mentioned we would extend beyond the hour if people wish to stay. I’ll quarterback the questions, given that we’re in different locations. Operator, please proceed with the Q&A.

Our first question comes from Rob Hope at Scotiabank. What is your question, please?

Morning everyone. My question is on Line 3. Can you just give us an update on how you think construction is progressing so far, just given what looks to be favorable weather, aside from the last couple days here, and then as we look forward, what are the key gating factors in terms of construction that we should be looking for? Is it going to be the water body crossing or is it just getting the miles of pipe in the ground?

Vern, do you want to take that?

Sure. Hi Rob. I think construction’s been progressing really well. Obviously the warm weather has helped us so far, but that’s changing now. We’re welding pipe on seven spreads right now. We’ve got tents erected at each station, so we’re able to progress work through the winter. I think the things that you’ve highlighted are all the things that we’ll be looking out for as we finish construction over the balance of the year. Don’t forget we do have a short tool down period for environmental windows, so still early days but I think so far, things are going better than we had hoped for.

Thank you.

Thank you. Our next question comes from the line of Jeremy Tonet from JP Morgan. Your question, please.

Hi, good morning.

Morning.

Just wanted to pick up maybe on part of the conversation Colin had there with regards to capital allocation. It just strikes us after Line 3 completion that, that provides a lot more flexibility post-that. Just wondering how your thought process might evolve at that point, because there seems to be a lot of nice bite-sized M&A opportunities out there, like you’ve done recently. There’s also very sizeable offshore and solar opportunity, as you discussed there, yet the E&B valuation would also argue for more share buybacks. Once all this extra cash flow starts hitting, how do you guys think about these different opportunities at that point?

Okay Jeremy, well let me start out and Colin can add if I miss something here. The way we’re thinking about this, first of all, you’ve got it right - post Line 3, and as I said in my remarks, call it 2022, we’re going to have a lot of cash coming at us and very good financial capacity in total if you include where we are on the balance sheet, so we’re in good shape there. The way we’re thinking about it is really this way. We have probably, I would say, $3 billion to $4 billion a year of what we call real primary utility-like investments, so if you look at Bill’s business in transmission, Cynthia’s business in the utility and Vern’s business, and of course even power now, they all fit the utility mantra, if you will. We know how we’ll recover capital in those and over what period of time, so you can look at that and say, that’s pretty solid and that’s going to drive some very ratable growth. Now beyond that, and this is, I think, what Colin was getting to around being dynamic, because you’re right - at this valuation, buybacks certainly come to the front of the decision-making process, so depending on where we are in terms of several factors when we look at buybacks versus organic growth, we’ll pick and choose. You’ll have probably a couple billion dollars of capacity to determine what the best angle is for that deployment, and as I’m saying, I think buybacks have certainly moved up higher in the rating order. Does that help?

That’s very helpful, thanks, and just the M&A opportunities, do you see more of those, or are those very select small things?

Yes, I think we’ve been saying the smaller, sort of tuck-in things around asset deals is probably most likely for us. If we see an opportunity there that we can bolt on or extend the franchise and give us better growth in the base business, we’ll look at those. In terms of large scale M&A, I think we’ve been pretty clear that’s a low priority for us. We’ve done the repositioning we wanted to with the Spectra acquisition a few years back, but it kind of comes back to what Colin said around the low capital intensity organic growth. We’ve got plenty of that. The balance sheet is in very good shape now. We want to protect that, and the reality is, Jeremy, that there’s not that many targets that really fit our business model, so the last thing we want to do is dilute that utility low-risk business model. That’s our perspective on M&A generally.

Understood, thanks so much.

Thank you. Our next question comes from the line of Robert Catellier from CIBC Capital Markets. Your question, please.

Hey, good morning everybody, and thanks for the presentation. I’m going to ask a question related to the main line. I just wanted to know if you could comment on the additional storage assets acquired at Cushing and how those might enhance the value of the main line proposed contracting for shippers, and whether there’s any other opportunities to add, such as storage, further upstream. Then related to that, I’m curious as to how aggressive you think you could be in the U.S. Gulf Coast strategy before you have main line contracting certainty. Thank you.

Hi Rob, it’s Vern. I believe the recently acquired storage assets have significantly benefited the entire system by providing us with increased flexibility. A major advantage is that these tanks are already integrated into our existing network, allowing us to immediately realize cost and commercial efficiencies. Looking further, there are numerous opportunities for additional tanks upstream. We've been collaborating with the industry to create a larger hub in Flanagan and other key points along our main line system. Given the disruptions in demand and supply over the past year, having more physical assets is advantageous for our customers, and we are observing a strong interest, particularly in the U.S. Gulf Coast. Due to the decrease in foreign heavy crude production entering the Gulf, there's a heightened demand for Canadian heavies. As more heavy crude arrives, it's essential to have the capacity to blend crudes and meet the specific requirements of refineries in the Gulf Coast, as well as the flexibility to move crude offshore. This positioning strengthens producers' negotiating power with refiners regarding month-to-month sales. We are witnessing significant interest in our Enbridge Houston oil terminal, renewed interest in our joint venture with Enterprise for the spot export terminal, and we anticipate strong pipeline demand increases from the U.S. Midwest to the Gulf Coast in the coming months. The fundamentals are aligning well for us to grow our assets with relatively low capital investment, providing greater options for our customers.

And Vern, there’s nothing about the main line contracting process that would make you hesitate to make further investments in the U.S. Gulf Coast strategy?

Our main line contracting proposal in front of the CER really dovetails nicely into being able to provide international joint tariffs all the way from Canada to the Gulf Coast for potentially incremental volumes on our system and growth on the Flanagan South and Seaway and Spearhead pipelines. That is going to be critical for all of our customers to see that you can see a joint tariff all the way down the line.

Okay, thanks very much.

Thank you. Our next question comes from the line of Robert Kwan from RBC Capital Markets. Your question please.

Good morning. Maybe I’ll stick with the main line here. I’m just wondering if you’ve got some additional thoughts on top of what you said earlier in the call, and specifically if you see the fate of Keystone XL factoring into the CER’s decision-making process - I guess that’s the first, the second being if you’ve had any discussions with shippers on a contingency basis on the fallback to either negotiated tolls or even a cost of service tolling framework in light of the new L3R costs, which presumably would drive rate base and tolls higher, and then the third being again if you’re in that negotiated or cost of service framework, what’s the cost of capital you might be seeking, given there’s been clear market signals that the cost of capital for oil pipelines has moved materially higher.

Robert, I’ll see if I can answer all those. Our path forward is really that we’re going to continue with our main line contracting regulatory process with the CER. We’ve seen intervenors file evidence and we now have been able to ask questions about that evidence that they’ve filed, and we will have an opportunity here to respond. If we back up and just remember that over 75% of the volumes that move on the main line today are supported with main line contracting, it provides certainty of capacity, it reduces the amount of apportionment on the system, we get certainty of tolls, and it allows us probably most importantly to grow the system over time because there’s a mechanism available for us, as I mentioned earlier, to provide joint tolls all the way to the different markets. That’s job one, is to continue on in that process, and we think we’ve filed a very strong regulatory case for that. I think you are right that there’s been some good precedents, particularly in the U.S. for allowed rates of return on oil pipelines to be higher than what people think they have been in the past. We will be filing U.S. tolling on our Lakehead system over this year, which will demonstrate that we’re currently significantly under-earning on that portion of the pipeline system. The higher L3R costs would go into those filings, but I should remind everyone that for Line 3, it is an attractive toll surcharge on every barrel that flows on the system, so I think we have some really strong regulatory precedents particularly in the U.S. that supports that the toll that we’re looking for in main line contracting is just and reasonable. Hopefully that answers your questions, Robert?

That’s great, thank you.

Thank you. Our next question comes from the line of Shneur Gershuni from UBS. Your question please.

Hi, good morning everyone. I’m wondering if we can focus on Slide 26, the capital allocation slide. Just thinking about capital allocation beyond ’21, it sounds like in the answer to one of the former questions and as outlined on the slide, that you’re sort of expecting $2 billion of the $6 billion to be towards buybacks, balance sheet, strategic investments. I wanted to focus on the $3 billion to $4 billion of long term growth against your target of 2050 and the whole energy transition trend. At the same time, I understand you want to be a reliable transporter of traditional energy and that does require continued investment. Should we expect the $3 billion to $4 billion to be primarily focused towards renewable and energy bridge transition-oriented investments? Do you have different return profiles given the longer terminal value versus traditional legacy investments? Can you walk us through the lens that you’re looking at that, and are you finding opportunities that will allow you to hit your target of a 5% to 7% return profile?

Okay Shneur, it’s Al here. I think the way the lens comes out on this is in that $3 billion to $4 billion, let’s call it utility-like category. We believe that in any scenario that we see from the fundamental perspective on supply and demand and the need for energy, just given the length of transition that’s required for moving energy systems along, utility investments, whether it’s our gas utility in Ontario or Bill’s transmission business, is going to come with very strong commercial underpinning, whether it’s strictly regulatory or contractual that gives us a high degree of confidence around return on and of capital. I would put renewables in the same category, though, as I mentioned in my remarks, because they really come with the same kind of contractual underpinning. I would say out of the utility category, whether it’s gas utility or gas transmission, and the renewables category, it will be a question of what’s the best opportunity to ensure that we’re going to generate the best risk-adjusted return. You might favor renewables depending on the situation, particularly if it’s offshore Europe where we have good opportunities to grow there, but generally speaking we think we can accommodate what we need to from an infrastructure point of view for our customers with that $3 billion to $4 billion in both the utility and renewable category.

Al, can I add one point in there?

Yes, go ahead.

Within that $3 billion to $4 billion, for example in Bill’s business, he’s got maybe $700 million a year of modernization capital. That is consistent with transition. Those expenditures are basically reducing emissions, which I think is consistent with some of our other goals, and we’re going to have it in rate base, so I think it’s an example of how these objectives are consistent.

That makes perfect sense, and appreciate the expanded color on that. Maybe for a follow-up question, just wanted to focus on Line 3 for a second here. When you established your balance sheet and capex targets for ’21 at investor day, did you already have a sense of the material step-up in Line 3 capex, or were the only open questions really related to the fact that it was going to be winter construction and COVID-related costs totaling about half a billion? Just trying to understand what was known at the time and what’s changed. Did I understand your answer to the prior question, I think it was to Robert, that it could actually be recoverable in rates over time?

Shneur, it’s Colin. Yes, at Enbridge Day, we had a good sense of the cost estimate was moving up, and I think we signaled that, and we’ve, the last couple of months, refined and finalized those plans, working through a few moving parts yet, as we received the final permit conditions just days before our analyst day. We had a bit of a placeholder, I think, in our thinking and we’ve refined it since. We’ve been sharing those funding plans with the rating agencies along the way, and they’ve been kept up to speed.

I can answer the second part.

Sure.

Line 3 is a toll surcharge for 10 years. After that, all the capital will go back into rate base.

Okay, so to clarify, the rating agencies knew exactly where we’re at, so there shouldn’t be any surprises there, and then in 10 years you should be able to start recovering this?

Yes, on the rate base for sure, but I would point out we’re making a very attractive return on the project, even with this capital cost overrun on the first 10 years.

Back to the first part, just to confirm, Colin and his team obviously are very intertwined with the rating agencies, and we keep them up to date, I’m going to say almost monthly on whatever’s going on in the business, so good connection there.

That makes perfect sense. I just wanted to make sure that everything was buttoned up, and it sounds like it is. Perfect, thank you very much guys, and have a great long weekend.

Okay, thanks Shneur.

Thank you. Our next question comes from the line of Patrick Kenny from National Bank Financial. Your question please.

Good morning guys. Just on the carbon pipeline and storage opportunity, it looks like it has good potential on both sides of the border over the long term, but are you expecting any funding support from the various governments anytime soon on these initiatives, either at the provincial, state or federal levels? I know it’s early days, but perhaps you can comment on how meaningful this opportunity could be in terms of accelerating some of your emission reduction targets, either reaching the 35% reduction goal well before 2030 or perhaps you keep the 2030 target but you’re able to exceed that 35% by a certain amount?

Yes, let me start, Patrick. I think it's early to assess the situation, but we can see that there is significant momentum around carbon capture from various levels of government, whether provincial, federal, or state. From a policy perspective, we have been advocating for support similar to the U.S. 45Q system, especially considering the current costs of carbon capture. If Canada adopted a similar approach, it would be very beneficial. Overall, the feedback from governments has been quite encouraging regarding this matter. I believe we have a good chance of surpassing the 35% reduction target. Although it’s still early to judge, we established our targets through a dynamic process that allowed us to optimize the pathways I mentioned. We will aggressively push these initiatives forward, so we hope to exceed our goals. I think this is a solid starting point, and we have several strategies to help us achieve it. Vern, would you like to add anything about carbon capture?

Yes, I think carbon capture is not going to be material for us to meet our emissions targets. It’s really about helping our customers reduce their carbon footprints, so I think there’s a big opportunity to provide a network of carbon pipelines in highly industrialized areas, such as the oil sands, where we can then capture a significant amount of carbon and move it by pipeline to a series of storage areas. I think as Al mentioned, carbon incentives such as Q45 would be very instrumental in making that happen, and we do have a little bit of funding right now from some of the provincial and federal governments to just kick off work on how we could create a model that would work for both our customers, ourselves, and potential downstream users of carbon as we move forward.

That’s great, thank you very much.

Thank you. Our next question comes from the line of Andrew Kuske from Credit Suisse. Your question please.

Thank you, good morning. Obviously you’ve got a lot going on in the liquids business with a clear focus on L3R contracting on main line, and then Line 5. But when you get through all of that, how do you think about Southern Lights on just a longer term basis as the contracts start to roll off on that asset?

Well, I think what we talked about, Andrew, at Enbridge Day was once we’re through our near term initiatives, there is a possibility of growing our network fairly substantially through a series of things, and Southern Lights is one of those things. From my perspective, the biggest factor for Southern Lights is what is happening with condensate in Alberta, will there be enough condensate coming from some of the non-conventional oil and gas plays in Alberta to replace that condensate coming up from Southern Lights. That will be a key focus for our customers probably over the next year or two on determining what is the best way to supply the oil sands with condensate, and if they feel comfortable with that Indigenous condensate production, I’m pretty sure they will put their minds to the reversal of Southern Lights.

And if I may, just a follow-up in how do you think about the connectivity into things like cap line?

I think there’s lots of options at Flanagan to move crude to various markets. Cap line is an option. We do have quite a bit of expandability that’s available on Flanagan South as well, and the southern access extension, obviously, could be expanded as well. I think we have some good optionality and we’ll probably be focused on our own projects first.

Great, thank you.

Thank you. Our next question comes from the line of Praneeth Satish from Wells Fargo. Your question please.

Thanks. Just on Line 3, I see the surcharge is $0.895 per barrel. Will this surcharge be flat or change over the 10-year period; for example, are there any inflation escalators on it? Then when Line 3 does go back into rate base after 10 years, would you expect that rate to hold flat or move higher or lower? Thanks.

Currently, the toll surcharge remains unchanged over the 10-year period, a decision made several years ago. Once it returns to the rate base, the Canadian segment will be included in the Canadian main line, while the U.S. segment will be part of the Lakehead rate base. However, if we proceed with our contracted offering for main line contracting, the entire Line 3 would be included in that. Our existing filing contains an inflator, so its outcome will rely on our success at the CER and how that capital is adjusted over the next decade. After this 10-year period, we will consider the regulatory mechanisms in place to ensure an appropriate return on capital at that time.

Thank you.

Thank you. Our next question comes from the line of Harry Mateer from Barclays. Your question please.

Hi, good morning. First one, just on the 2021 financing plan, do you guys anticipate issuing any hybrids or, given your plan to be in your target leverage and you don’t really need any equity credit, would those just be viewed as high cost debt and you’re more likely to go straight senior bonds?

Hey, it’s Colin. The latter - just straight up, vanilla financing. We’ve used hybrids in the past. We don’t have that in our base plan. It’s always an option, of course if we do need some more equity credit, but at this point we don’t see the need for it, so I think pretty straight up, conventional program there issued through various members of our family in Canada, the U.S., and across the maturity term.

Okay, thanks. Then a little bit more broadly, I guess this is circling back to capital allocation, where I know there have been a number of questions this morning, but what I want to focus in on is just the leverage target. You guys have been very consistent now for a couple years, about 4.5 to 5 times. You still expect to be within that. I guess the question is what gives you comfort that continues to be the right number, and why shouldn’t it perhaps be lower, because rating agencies can do and change those thresholds, sometimes quickly, so I’m wondering just why it might not be prudent to pull that leverage number down and just accommodate a less certain energy outlook, or put differently, why not shrink both the equity and debt sides of the capital structure?

Yes, it’s Colin - great question, and it’s something we’re mindful of. As Al mentioned, we’re fluently and frequently in front of all of the agencies and keep our ear to the ground on this. Our sense is that the goalposts aren’t moving in the midstream space in the near term. I think certainly there will be more differentiation within the space, but we’re confidently at the higher quality end of that spectrum. We map very strongly to triple-B plus credit metrics, and we’re trending right now in the bottom end of our range, which I think is consistent with the general spirit of your question. We’re going to allocate capital dynamically and in a very disciplined way, I think with an eye on all of these dashboard metrics, and preserving strength, as I said, is our first priority. I think in spirit, we’re directionally aligned here, but at the same time pretty confident in where we’re at.

Okay, thank you.

Thank you. Our next question comes from the line of Alex Kania from Wolfe Research. Your question please.

Hi there. One question, maybe it’s more on the hydrogen side of things, but it feels like Europe is really involved with things, and thinking about offshore wind integration, is that at all on your radar or is that something that might be too early to look at right now?

I don’t know, Cynthia or Bill? I can comment too, but why don’t you start off?

Sure Al, thanks. It’s Cynthia. Alex, I think we are looking at all opportunities in hydrogen. As you said, it’s early days, and currently we’re looking at those low cost options and where we can gain our expertise and knowledge, but I know Matthew can also touch on this from the offshore perspective, there may be opportunities as that continues to build out. We have of course our existing infrastructure now in Markham and we’re starting to blend, as Al mentioned, in Markham, so we do have some expertise that we’ll be able to build on.

Yes, it's probably too early to be specific about offshore wind, but overall, we are confident in our position because we have developed a substantial renewables business, and we are at the forefront of the hydrogen sector. We believe this focus is a natural fit for us, particularly in green hydrogen, which represents the best return on investment. Our ability to engage in both areas boosts our confidence, although it will take time to fully realize this potential, and we will approach the process carefully.

Great, thank you.

Thank you. Our final question comes from the line of Asit Sen from Bank of America. Your question please.

Thanks, good morning. This week, we saw a privatization transaction in the Canadian midstream space. Al, just wanted to get your perspective into whether we see more such deals in North America, and probably some of the topics, if you could hit on access to capital, cost of capital, and pressure on public companies in this new energy transition regime.

Okay. Well, what we’re seeing so far, whether you look at the midstream or the upstream part of things, one thing’s for sure - downturns always spawn consolidation, so I think what you’re seeing here is exactly the right response from industry that you’d expect here, so people are shifting to focus on returns, scaling up the business, capital preservation, cost efficiency. From our own perspective when we watch that upstream, we think it’s really positive for the business and makes the industry stronger in terms of its ability to sustain itself, but also grow the business. For us, we’d probably get some credit benefits at the margin, so I think this is all very good. You mentioned the privatization transaction that’s in the market here recently. The good news about that is we’re starting to see how this is surfacing value, which we’ve been talking about. I mentioned it in my remarks that the value of existing pipe in the ground is going to go up, so I think this foray, if you want to call it that, although we’re not involved with it is certainly good for illustrating the value that’s going to be surfaced in this business. Hopefully that will come about in a broader sense, I guess, and it gets the ball rolling. As to the challenges to our business generally from if you’re a public company, I would agree with you - it’s certainly more difficult as a public company, but on the other hand, I think as what we’ve shown in the last several years, is we’ve certainly adapted to the way you have to operate and the way you have to permit projects. This is clearly all about how strongly we engage with communities, the expertise of our people on the ground and through the regulatory application process, so it’s kind of what I was referring to earlier - it’s our job to manage this in public companies, but I think the skill set we’re developing here is going to set us apart. It’s a broad response to your question, but that’s actually how we look at it.

Appreciate it, Al. Thank you.

Okay, thanks Asit.

Thank you. This does conclude the question and answer session of today’s program. I’d like to hand the program back to Jonathan Morgan for any further remarks.

Great, thank you. Thank you for taking the time to join us this morning. As always, we appreciate your interest in Enbridge. Our Investor Relations team is available after the call to address any additional questions you may have. Once again, thanks and have a great day.

Thank you ladies and gentlemen for your participation in today’s conference. This does conclude the program. You may now disconnect. Good day.