TC Energy Corporation (TRP) Earnings Call Transcript & Summary

Good afternoon, everyone, and thank you for joining us -- good morning, rather. Sorry about that. Today, this morning, we're extremely pleased to be joined by TC Energy's CEO, Russ Girling, for a fireside chat to talk about the TC Energy story. So with that, I just want to go right into the Q&A here, if we could.

Russ, I just wanted to see how TRP has been impacted by all the events that have transpired with the dual demand and supply shocks in crude oil sending kind of tidal waves through the energy market. Just curious if you could walk us through how TRP was impacted by these trends and what makes you guys different than other energy companies out there.

Thanks, Jeremy, and thanks for having us and putting on this conference in a virtual way. We're all adjusting, as you just pointed out, to a new way of doing business. For us, all of our businesses were deemed essential service. That includes the operations as well as the construction activities that we had underway. And then the rationale is even in this current situation, people still need energy every day. So across our whole system, our whole footprint, our assets have continued to operate at pretty high load factors, pretty close to what they've been historically. I think that's got a lot to do with our market position. We have seen some market demand dissipate as a result of the COVID crisis, and then combined with the supply disruptions that we've seen globally around the crude oil side. But as you think about each of our buckets of assets, first of all, you have Canadian gas. The markets that we serve continue to need gas, operating at load factors that are pretty close to where we were last year. We've actually seen production increases and increases in load factors on the Canadian systems. Similarly, our U.S. gas systems continue to operate at pretty high load factors, including the connections into Mexico, operating at high load factors. The one question that we've had in our portfolio that the people have asked about is on the crude oil side. We have seen global crude oil demand decline by 20-odd million barrels a day or more. How has that impacted Canada? Canada has shut in probably about 1 million barrels a day, but it's had no impact on our system. Our base Keystone, the Keystone system runs from Alberta to the Gulf Coast, that's still the single best refining market. And even during this period of time, the U.S. is still importing heavy crude from offshore. Obviously, the light oil markets have been more turbulent, but the refineries in the Gulf Coast still need to be running heavy crude. So if we can get more crude to the Gulf Coast, that's a good thing even in this market. So we haven't seen any decline in our throughput on that system. And as well, the way that we're structured is those are structured on ship-or-pay kind of arrangements, long-term contracts. And those shippers have continued to utilize those at high load factor. So across our system, we have had minimal impact with respect to our throughputs, given that it's primarily rate-regulated or contracted. We didn't expect to see a change in revenue, but we haven't seen a change in volume throughput as well. So at least this far into it, we're doing pretty well. And that is sort of by design. We would have expected to see minimal impact in revenues and cash flow. That's not to say that our upstream customers haven't. I mean, obviously, our upstream customers, both on the crude side and the gas side, have had their cash flows impacted pretty significantly. And the best thing that we can do is continue to give them the best access that we can to the best netback markets that maximizes their cash flow through this period of time. I mean keeping their volumes flowing has been critical. So as we thought about construction, for example, all of our shippers, we've checked back in and said, "Do you want us to continue on the path that we're on, the schedule that we're on in terms of expanding egress to get your product to market?" And across the board, pretty much 100% have said, yes, keep moving forward. Now we'll probably move a little bit slower with construction just because of productivity and things like that with the COVID-related protocols that we've got to put in place. As well, getting permits have slowed down a bit. The government agencies aren't as efficient as they would have been sort of pre COVID. But they're working through those as well and trying to make themselves more efficient and adapt to the current environment that we're in. So far, we expect minimal impact on throughputs, minimal impact on cash flow, minimal impact on our capital program.

That's great to hear. It seems like counterparty concerns have been topical in the marketplace, given some of the stresses, as you talked about there, with some of your producer customers. Just wondering if you could walk us through a bit as far as how conversations with WCSB producers and Appalachian producers have been going, and what kind of gives you the confidence in your outlook in those bases?

Yes. Maybe I'll just sort of speak to each of those buckets. A third bucket I would add is the crude oil bucket in terms of our throughput on our systems. And those shippers have been impacted as well. But maybe starting with the Western Canadian producers. The Western Canadian gas is competitive to most markets. The markets still need the gas. There will be some individual producers that are under more stress than others. And -- but the way that we're constructed is, first of all, we look at the competitiveness of the Western Canadian Sedimentary basin to market, and it remains so. And then on an individual shipper basis, does that shipper -- is that gas being produced economically. And is it positive cash flow, if you will. That doesn't speak to how much leverage that they may or may not have. We believe that we're in pretty good shape around that front. The system in Canada is rate-regulated. To the extent that there's a credit default, those costs get socialized into the overall rate base. And then in addition to that, we have long-term contracts in place for all of the new capital that we're putting in place. So it's kind of a belts and suspenders. If something occurs, which we don't think it will, because we think for the most part, they're economic. In the event that a shipper experiences insolvency, for example, the receiver steps in, wants to continue to cash flow those assets. In order to cash flow those assets, you've got to get the product to market. To get the product to market, you got to pay your transportation bills. If you don't pay your transportation bills, we're not going to ship. So our experience has been historically that even in the event of an insolvency, the receiver or whoever steps into their shoes still wants to -- don't shut in the production, that they continue to want to cash flow those -- that production. To the extent there is a default, as I said, it gets socialized in the rate basis. So similarly, so the Canadian construct, I'm very comfortable with. It's a utility-like construct, and that's where the bulk of our new capital is going right now. On the Appalachian region, similarly, when we bought Columbia, we looked pretty hard at the economics first, the underlying fundamentals. Is that gas economic long term, irrespective of who owns it or who operates it? And I'd say, for the most part, the shippers that underpin our pipe system have economic reserves. Now they may have too much leverage, which means that they might not survive, but at the same time, we believe those assets will continue to cash flow in somebody's hands for the long term. Then we look at our straw leaving is in the event of an insolvency, will they continue to use our straw to get to market. And we allow them -- first of all, our tolls are very competitive, and then we attach to the best market. So that gives whoever is operating the best netbacks. And then on top of that, we sign long-term contracts with them to be able to move the gas. And if we foresee that they are having financial difficulties, we have the ability to ask for additional security in the form of letters of credit and those kinds of things. We have the ability to ask for about $1 billion of what I'd call liquid security in the event that we see an issue. And we haven't exercised very much of that at this point in time. So it starts with fundamentals, contracts, markets and then security. And we're feeling pretty comfortable right now. And with the dislocations we talked about with crude oil coming back up again -- I mean, with crude oil coming off the Permian gas declines that we've seen, we've seen an uptick in gas prices, which, again, is bringing some life back into a lot of these folks. But sort of our game is fundamentals, and we think we're well positioned. And similarly, on the crude side, I mentioned earlier, we haven't seen any change in shipper desire to continue to move crude oil to the Gulf Coast, and those systems remain full. All of those shippers are credit-worthy. And even on our Appalachian systems, over 1/3 of our volumes are contracted by LDCs that are, again, in a different financial position than a lot of the upstream shippers right now. So what we're trying to do is work with our upstream shippers to get them the very best netbacks that we possibly can.

That makes sense. And I think just kind of building on that point, historically, looking at NGTL and the Mainline coming out there, it seems like those systems have really been able to kind of adapt and evolve over time through different kind of cycles. And so maybe it might be helpful if you just kind of remind the audience a bit as far as how that has transpired over time and how your assets have responded to different cycles, if you will.

Yes. The -- well, the NGTL system is the single largest gas gathering system in North America. I mean it has the capacity to move about 13 billion cubic feet a day. I think historically, there was some concern when we saw Appalachian gas come on quite rapidly. I think there was concern that Western Canada couldn't compete anymore. But what turned out was places like the Montney turned out to be every bit as robust and low-cost and long-term and competitive as Marcellus, Utica. And so as -- those 2 basins will continue to bring on new gas, what we saw is continued decline in prices, which meant that conventional gas is no longer economic to compete in the marketplace. So places like the Rockies and others, we've seen decline in conventional production and market share being taken up by the shale gas or tight gas producers. The benefit of the existing NGTL infrastructure is that it's old, it's depreciated. And if you have an economic resource behind it, similar to the Marcellus, Utica there was an economic resource behind a historic, depreciated system like the Columbia system, that makes you very competitive in the marketplace. New capacity to get to market, pick a number, something like about USD 1 an Mcf for incremental greenfield capacity to get from Marcellus Utica to a place like Dawn, a competitive sort of no point of between Canada and the U.S. To get from Western Canada -- if the resource cost is the same, to get from Western Canada to Dawn, even though it looks on a map like it's a long ways away, is probably half of that number like USD 0.50 an Mcf because you're using brownfield historic depreciated capacity to get to market. So you have 2 resources that are going to compete for the same marketplace. Western Canada competes very well, which I don't think is something that was intuitive to folks. As you look at the map and look at how far away the Western Canadian Sedimentary basin is from market, how could it compete. So similarly, we've seen Western Canadian Sedimentary basin compete for market share in the Pacific Northwest and into California, for example. We have about 1 billion cubic feet a day expansion coming out of the West. There's no new market. But as Rockies gas declines is no longer competitive, we've seen the LDCs step back into Western Canada, see the long-term reserves and wanting to buy that low-cost gas for the long term. So then they sign a contract with us to expand the pipe -- like a 20-year contract to expand the pipe. So pretty much across our systems, both in Canada and the U.S., we've seen that. Looking at our existing footprint and finding ways to utilize the existing footprint, and if you can do that, you can usually make that gas more competitive in relationship to the next greenfield expansion that's going to come about. So Western Canada has fared very well. We still have capacity left in the Mainline to fill up. We're at about 4 Bcf a day today. Historically, we've run that system at 6-plus Bcf a day. So there's still more room for, I believe, continued expansion out of Western Canada.

Maybe we could turn towards TRP's backlog, and if you could just kind of update us there with regards to the COVID-19 situation with regards to kind of the changes we've seen in the oil and gas market. Do you see any kind of shift in timing or change in need for those projects? Or any thoughts you could provide on that would be helpful.

Yes, the $30-or-so billion -- $35 billion portfolio of projects, excluding Keystone XL, is primarily gas related. There's a fairly major nuclear project, which is the refurbishment of Bruce nuclear. So maybe I'll sort of put that in that same bucket. Given the COVID situation, we've checked back in with both -- all of our contracted customers, if you will, to see whether or not they want us to continue to move forward. And I think, as I mentioned earlier, across the board, they have said, yes, continue to move forward. We -- these are still economic propositions. That said, the COVID-related protocols mean that we can have less people involved in construction at any given point in time. Construction is slower, so I would expect that the spend will be slower. We had originally planned to spend something close to $10 billion in 2020. I think we're going to be hard-pressed to spend $10 billion. I don't know if the number's $9 billion or what it is. I don't -- I think what you'll see is that number will -- that -- the spend will just get pushed further out in the future as opposed to being canceled. And then with respect to our 2021 programs, 2022 programs, where we still require permits, as I mentioned, some of the permitting processes have slowed down. Indigenous consultation, for example, by the governments and things like that, that needs to be done, we will see a slowing of those. Don't know what the impact of that is. But again, I think what it will be is, is a shifting into later years. So part of that program from '21 will be shifted to '22. The overall magnitude will still stay the same. So from a financing perspective, actually, that's easier for us to carry that burden if it's spread out over a longer period of time. But fundamentally, no change in outlook, no material change in outlook at the current time. The Bruce program we got suspended for a period of time because we weren't able to keep that many people in the work site. That's been now shifted where we found protocols that would work with the regulator to allow that program to continue. So I think we're in pretty good shape. If anything, like I said, we'll probably spend a little bit less money over '20 and '21 than we thought, and that will get pushed into '22 and '23.

And maybe just to touch base on Keystone XL, if you could kind of update us there with regards to latest status in nationwide Permit 12 and thoughts about building the pipe in the current political environment, if you will.

I think that the structure that we put in place from both a financing perspective as well as the contingencies that we built in for schedule and cost, I mean, we -- when we announced we're moving forward with the project, we announced that we expected an in-service date in 2023. Even with the current issues, with respect to the nationwide 12 permits, they -- we had an expectation that all of our permits would be challenged and we'd have to work our way through those legal processes before we'd could continue to advance certain portions of construction that were related to those permits. And then we would expect that to continue. So at the current time, with the current litigation that's underway, we think that our time frames that we put out there are still doable. And then with respect to the investment structure, through 2020, the bulk of the investment is being funded by government sources, the upper government being our partner as we move into '21. And if construction ramps up, there's an opportunity to draw on a debt facility that's backed up by a guarantee from the Alberta government. So financially, I think we're in a place where we can continue to move the project forward and continue to believe that under any scenario, it is in the best interest of North America, both Canada and the United States. From an energy security perspective, obviously, getting oil from a strong and friendly ally is a pretty good idea. The Gulf Coast still needs 3 million barrels a day of heavy oil. If you don't get it from Canada, you buy it from Venezuela. And as we emerge from the COVID crisis, job creation remaining at 15%. Hopefully less unemployment kind of situation. But those jobs are going to be extraordinarily important as we move forward. So if you think about it from an economic perspective, energy security perspective, even in an environmental perspective, the facts are is that the building Keystone XL, as was pointed out in the previous administrations, final environmental impact statements and this current final environmental impact statements, the GSG emissions are reduced by building this pipe as the crude would be otherwise moved by an alternative means, whether it's coming out of Canada or globally, moving it by ships or whatever. Moving it by pipeline with electric motors is by far the safest and most environmentally responsible way of moving the crude. So we continue to think that the project has merits. And again, that's shown in people willing to underpin it with 20-year contracts that are ship per pay, which haven't dissipated at all. So we'll continue to try to advance this as an option for our shareholders, and hopefully, we can get it done.

That makes sense. Over the past couple of years or so, it seems like TRP has gone through a portfolio optimization exercise. So just wondering if you could update us as far as kind of where that stands. It seems like you've gotten through where you wanted to get through at this point. But how do your financials stand versus your targets, and any thoughts on financial flexibility here.

Yes, we had a plan to sell approximately $500 million of EBITDA, cash flowing assets. They're good assets, our power assets. We had some midstream assets in our U.S. business. We largely completed that at the end of last year, raised the capital that we thought was required to bring our balance sheet in order and bring our credit metrics in line with where the rating agencies wanted us to be, which was sort of a debt-to-EBITDA ratio in the high 4s. So we exited 2019 in that kind of range. Subsequent to that, we had completed the sell-down of 65% interest in our CGL, Coastal GasLink, project as well. So I think we're in a pretty good place where our balance sheet is where we want it to be, our credit metrics are where we had targeted to be, and I think where the rating agencies are comfortable with us being. So I don't see any more on the horizon. Always looking for opportunities to optimize our portfolio. And as we move forward, we'll continue to look at that in the event that we do move forward with Keystone XL next year. We put in place a finance plan that includes hybrid securities and potentially drip equity. But obviously, we'll look at our portfolio as well. If there's a cheaper cost of capital for us to surface value from mature assets and rotate that capital back into to new and growing businesses, that's a good thing for our shareholders. So -- but right now, to your question, we're largely complete what we wanted to complete. It's -- we got to sell-down COPG in this turbulent time over the last 3 months, and we got the other sell-down of Coastal GasLink done, which I think people thought would be kind of thorny. But at the end of the day, because of the fundamental nature of those assets, obviously, we had to adjust to negotiating those agreements remotely and in a virtual format like this, but we're able to get those done. So pretty comfortable with where we are right now, Jeremy.

That's helpful. And then maybe kind of the other side of the coin here, it seems like TRP has a history of acquiring assets countercyclically, especially very strong assets that -- crown jewels of other companies when they were in a weaker situation and were forced to divest. Just wondering, in the current environment, TRP's appetite to pursue something like that, willingness. And do you see those type of crown jewel assets possibly on the market or in a position that you could bring them into the fold opportunistically?

Lots of questions in there. Is it -- I do believe that value can be added -- significant value can be added by being able to act at particular times of dislocation, financial dislocation. So as you pointed out, we had acted in the past. One of the main reasons why we tend to focus on our credit metrics and credit ratings, trying to stay with industry-leading credit ratings and those kinds of things is to allow us to have access to capital at certain times in the cycle, where crown jewels, as you point out, might come available. And we've been able to buy ANR in the past, for example. Columbia, we were able to buy. We bought GTN out of a bankruptcy. All these things come out of these times of dislocation, where people are willing to sell really good assets at reasonable prices because the cost of capital that they're able to achieve in doing that is cheaper than some other liquidity sources of capital that they might have out there. So we continue to look for opportunities for doing that. Nothing has sort of opened up yet, but certainly, we've got our eyes on a few things that we think makes sense for us. And if we can make -- it make sense for the other party, then you've got a sort of a win-win deal. So the kinds of things we'd be looking for, as you pointed out, would be very similar to what we have in our portfolio today and -- long-term assets with good market positioning.

That's helpful, thanks. And then discuss -- looking at natural gas transmission, obviously, key backbone to the TC Energy story. Although building new pipe is incrementally more difficult by the day, it seems here. Just wondering if you could expand a bit as far as your growth strategy across natural gas pipelines. In the U.S., it seems like there's an opportunity to get more gas down to the Gulf Coast that maybe TRP can capitalize on. And then I guess the next step beyond that, looking at the LNG side of the business, thoughts on if that fits into TRP's framework. Could that be something that could make sense for you guys?

What was that -- the last question. Sorry, I lost you there.

Just as far as interest in getting into the LNG business, taking one step down the value chain there.

Yes. So maybe on the first part of the question, I would agree with you that building greenfield capacity today is very difficult, especially larger scale and traverses a large geography. And what -- we shifted our strategy to try to focus on what we could do within our footprint. The market demand continues to grow, as you point out, in the Gulf Coast, for example. LNG export has grown quite considerably. So how do you get the gas there is the competitive question. And what we found is that using our existing corridors, to expand our existing corridors is something that's doable versus -- there's something there that might appear to be a better path, a cheaper path, a more economic path to get the gas from a supply source to those new market locations. But when you look at the whole permitting regulatory process to get it there, it's almost impossible to get it done. So we've leaned in on trying to find those kinds of opportunities. So as you point out, in the Gulf Coast, our Chenier XPress project, for example, they're like $300 million or $400 million opportunity to expand our existing systems to get the gas to those that need it. And when we look at across our footprint, it's the same -- you can't get Appalachian gas to the Pacific Northwest. You can't get Appalachian gas even to New York, for example. Pennsylvania is sitting right next to New York. You think that, that would be the most direct route to get there. You can't get there. But Manhattan still needs gas, and it's a growing gas demand. So if we can bring the gas back through our Columbia systems, into our Canadian systems through Québec, through our Iroquois system and into Manhattan, that seems like a long route, and it's not intuitive for our business development. People say that's the best route to get market. But it's the only route to get to market, which is giving us expansion opportunity across our whole system. When you look at our system, in our capital program, a lot of it looks just like that is that you -- existing corridors are extremely valuable. As I think about our new connection to Mexico, Mexico's going to continue to need more gas. We're going to be able to expand that. Our new Coastal GasLink connection, it's going to be very difficult to build another greenfield line to the West Coast of Canada. Can you expand that corridor? Yes, you can. So that's how we're thinking about our system right now is existing corridors are extremely valuable. And the evidence is we're starting to see expansion opportunities across all of those corridors, people willing to sign long-term contracts to be able to get that capacity built because they know that it can actually get built. Your second question in terms of going further downstream, total willingness to go downstream for the right construct. And so a construct that would be contracted with creditworthy counterparties that gives us security of revenue. And there are situations like that out there that have been constructed, but they don't necessarily need us as a partner at the current time. I think somebody like Shell, for example, on the West Coast of Canada, they can do all of those things, they can build, construct, finance. They don't need our balance sheet. I mean what they need is they need a pipeline company that will -- that they can depend upon that will get them the gas that they need, and they'll sign a long-term contract. The ones that want us in as a partner don't have all of those, all those -- all that wherewithal, which makes us a little bit uncomfortable if we can't construct something that has that security of revenue. So totally willing to move downstream in that kind of construct, but haven't seen it yet, obviously. It's another part of the value chain that looks just like -- if we can make look just like our pipeline construct, either contracted or regulated, we'd be very comfortable there. But not willing to go merchant there either. So we'll see how that marketplace sort of sorts itself out in the coming years. And if those kind of opportunities present themselves, certainly, we would be interested in having a look.

That's really helpful. And maybe if I could sneak one last one in under the wire here, just want to go south of the border into Mexico. If you could update us on Tula-Villa de Reyes pipes, how those stand, and I guess, appetite for -- to do further business in Mexico.

So we really like Mexico, maybe start there, is long-term fundamentals. You've got 150 million people growing middle class. They're using more energy. And we would expect that longer term, the rest of Mexico looks more like the rest of North America than less like the rest of North America. And it's going to be bumpy ride some days along that road, but it's fundamentally a good place to be from an energy standpoint. Natural gas, obviously, can supply power plants with lower emissions than using fuel oil or other things. So there's an environmental benefit. And electricity is going to fuel the economy in terms of industrial developments. So there's a natural kind of relationship between the United States and Mexico. The United States has the cheapest available natural gas on earth. It's cheaper than PEMEX drilling for it. And if you can make a sort of a hardwire connection -- which I think the cornerstone of our strategy there has been around the subsea pipeline in sort of Texas line going into the heartland of Mexico. So it connects into these other pipes that you mentioned, the Villa de Reyes and Tula lines, which will then take it -- there's power plants actually built behind both of those pipes already. We'd expect Villa de Reyes to enter service sometimes towards the end of this year. We're slowly constructing it as we move forward. Tula, we've got some consultation issues with indigenous groups in about the middle section of the pipe. We believe that we can still utilize the eastern and western sections of the pipe. We -- it's the government's responsibility to deal with those issues in the middle. But the pipe itself has tremendous value, still. So we might be able to utilize those sections earlier -- the eastern and western sections earlier because, as I said, there's power plants that are behind them that are running on fuel oil today. They're built and Mexico wants to move forward. Today, Mexico represents about $5 billion or so of our overall $100 billion portfolio, about 5%. I don't see that number doubling or anything like that in the near term. We built the backbone in. The backbone, as I mentioned earlier, has expandability. We're moving about 2 billion cubic feet a day through Sur de Texas today. We think that, that number can expand. Our other pipes can expand along that footprint. So I think that's what you'd expect from -- to see from us is that I don't see large-scale new projects coming about anytime soon. They're going to try to utilize -- fully utilize what they have currently. They've got to fill that up, and that's where we're going to be for the next few years. So I would say that what we expect is smaller expansions to occur, and then down the road, we'll see what happens. But I don't ever see Mexico being 20%, 30% of our portfolio. Today, it's 5%. Could it get to 10%? I think that's a long shot. But in the interim, I think it's a pretty good business for us.

Well, thank you very much. I think we have to stop there. But Russ, thank you very much again for joining us. Looking forward to you coming back next year. Thank you.

Likewise, Jeremy. Thanks to you and JPMorgan for setting this up. It's a great opportunity for us as well.