TC Energy Corporation (TRP) Q1 2022 Earnings Report, Transcript and Summary

Thank you for standing by. This is the conference operator. Welcome to the TC Energy First Quarter 2022 Results Conference Call. As a reminder, I would like to remind you, all participants are in a listen-only mode and the conference is being recorded. After the presentation, there will be an opportunity to ask questions. [Operator Instructions] I would now like to turn the conference over to Gavin Wylie, Vice President, Investor Relations. Please go ahead.

Thank you very much, and good afternoon, everyone. I'd like to welcome you to TC Energy's 2022 First Quarter Conference Call. Joining me today are François Poirier, President and Chief Executive Officer; and Joel Hunter, Chief Financial Officer, along with other members of our senior management team. François and Joel will be joined today -- or sorry, will begin today with some comments on our financial results and certain other developments within the Company. Copy of the slide presentation that will accompany our remarks is available on our company's website in the Investor Relations section under Events and Presentations. Following the remarks, we will take questions from the investment community. In order to provide everyone with an equal opportunity to participate, we ask that you limit yourself to two questions. If you're a member of the media, please contact Jaimie Harding after this call. Before François begins, I'd like to remind you that our remarks today will include forward-looking statements that are subject to important risks and uncertainties. For more information on these risks and uncertainties, please see the reports filed by TC Energy with Canadian securities regulators and with the U.S. Securities and Exchange Commission. Finally, during this presentation, we will refer to measures such as comparable earnings, comparable earnings per common share, comparable EBITDA and comparable funds generated from operations. These and other certain other comparable measures are considered to be non-GAAP measures. As a result, they may not be comparable to similar measures presented by other entities. These measures are used to provide additional information on TC Energy's operating performance, liquidity and its ability to generate funds to finance its operations. With that, I'll turn the call over to François. François Poirier: Thanks, Gavin, and good afternoon, everyone, and thanks for joining us today. Before we discuss our results this quarter, and I expect we're going to be talking about global geopolitical events here during the call, I want to start by acknowledging the tragic humanitarian crisis happening right now. And we extend our thoughts to all of those who are experiencing such immense suffering. Now within the context of our industry, these events have amplified the discussion around energy security and highlighted the important role our industry plays in meeting today's energy needs. While the world confronts a serious geopolitical shift, a transition to cleaner energy that also meets the world's demand is still required. North America and TC Energy will play a critical role in securing the global energy supply while also transitioning to a lower carbon future. This intersection of energy security and energy transition is not an obstacle to growth we believe rather that it's a catalyst. We're particularly well positioned to support exports of LNG that represents one of the most significant growth drivers in the natural gas business in North America. North American LNG exports peaked this year at 13.7 Bcf a day, and we now expect that amount to grow by over 90% to 25 Bcf a day by the end of the decade. Our critical energy infrastructure assets are well situated to support connecting North America's premier basins to LNG export facilities. Now TC Energy is already a significant player, connecting approximately 25% of supply apportioned for U.S. LNG exports through our extensive pipeline network. Going forward, we expect to compete for and win our fair share of the growth in the LNG market. We continue to evaluate new expansion potentials and execute our portfolio of sanctioned projects. For example, already this year, we have two new pipelines that directly support deliveries to LNG facilities in Louisiana. Phase 2 of our Grand Chenier XPress project started service in January and connects to the Calcasieu Pass LNG terminal. And our Louisiana XPress project, which is expected to be fully in service in the coming months, will deliver volumes to Sabine Pass. Now in addition, we've recently received approvals to move ahead with three more LNG-linked projects. The East Lateral XPress project on our Columbia Gulf system will support the proposed Phase 2 Plaquemines facility in Louisiana. The Alberta XPress project will also deliver into Sabine Pass. And finally, our proposed North Baja XPress project, which supports the Costa Azul LNG facility on the West Coast of Mexico. And this is just the start. Our unparalleled pipeline network is critical to the delivery of LNG volumes today, and it underlines the tremendous opportunity that we have to connect supply to the growing LNG export market. Like I said off the top, the world has never needed safe, sustainable and secure energy the way it does now. And we are a company of energy problem solvers, delivering solutions to address this challenge. The demand for our services has never been stronger, and operationally, our assets performed extremely well throughout the first quarter. Despite the warmer-than-average winter season, we saw record sendouts on our U.S. natural gas system, including Columbia Gas, PNGTS and GTN. This contributed to daily average flows for the first quarter of 30 Bcf a day, up 5% versus 2021, including an all-time daily system record of nearly 35 Bcf in January. And we saw similar trends in Canada. Our NGTL system in Alberta averaged winter demand was the highest on record since 2000 at 14.2 Bcf a day. Our Canadian Mainline system experienced additional contracting in the quarter and is essentially sold out of long-term capacity. These tremendous performance results reinforce that our assets are ever more critical for the delivery of North American energy supply. We also progressed our secured and developing portfolio of projects, including Coastal GasLink. In March, we were proud to announce the historic signing of option agreements to sell 10% equity interest in the Coastal GasLink pipeline limited partnership to indigenous communities across the project corridor. We recognize that enduring relationships with our indigenous partners include long-term economic opportunities, and this is one of the ways we can advance reconciliation. On the construction front, we continue to make headway as we approach spring breakup. Overall, the project is 63% complete with 100% of the route now cleared. In Power and Storage, we continue to advance projects to add renewable and lower carbon energy to the mix and reduce the carbon footprint of our own operations, for example, our Bruce Power life extension program. On March 7, the ISO verified the final cost and schedule duration estimate for Bruce Power's Unit 3 MCR program. And with our Unit 6 MCR progressing well and expected to be in service in 2023, the Unit 3 MCR represents the next step in Bruce Power's life extension program and is scheduled to begin in the first quarter of 2023 with anticipated completion in 2026. Upon completion, Unit 3 will provide enough emission-less, reliable and low-cost energy to power over 800,000 Ontario homes every year. The Power and Storage business, as we mentioned previously, is also supporting the Company's goal to serve our own energy use with renewables as exemplified by the RFI we kicked off last year. To date, we have finalized contracts for approximately 160 megawatts of wind and 240 megawatts of solar projects. We continue to evaluate the proposals received through the RFI process and expect to finalize additional contracts in 2022. New fuels will also be needed to power the energy grid of the future, and we have existing skills and assets that can pivot to develop them. For example, we're actively pursuing opportunities in the hydrogen economy, developing hydrogen hubs to serve long-haul transportation and other industrial uses. Just this week, we announced that we've identified our existing Crossfield storage site as a potential hydrogen hub location. The proposed hub would produce an estimated 60 tons of hydrogen per day with the capacity to increase to 150 tons per day in the future. Our joint development partner, Nikola, would serve as the hub's anchor customer for its long-haul fuel cell electric vehicles. We anticipate a final investment decision by the end of 2023. The Alberta Carbon Grid, our joint venture project with Pembina, is another significant opportunity to help industries and businesses decarbonize their operations and meet their sustainability goals. In March, we received notice from the government of Alberta that our proposal to build and operate a carbon storage hub and gathering lines in Alberta's industrial heartland was successful. ACG is now moving into the next stage of the provinces CCUS process, entering into an evaluation agreement. Once fully constructed, the ACG aims to transport and sequester up to 20 million tons of CO2 annually, almost 10% of Alberta's industrial emissions. It will have a vital role to play in supporting Alberta's carbon competitiveness and the development of a lower carbon economy. As I previously mentioned, achieving a balance between energy reliability and security, on the one hand, and energy transition on the other hand, is a catalyst for our growth. There are many opportunities to innovate, modernize and maintain our regulated natural gas pipeline network while reducing emissions from our business. We're also identifying and developing in-corridor capital-light projects, expanding reach and delivery points while enhancing the returns of our existing corridors. The Port Neches Link project is an excellent example of our strategy. We're increasing the interconnectivity of the Keystone system and Marketlink to enable direct access to North America's largest refinery. This vital pipeline link will provide a reliable, sustainable and stable source of domestic crude supply for decades to come. And we are focusing on sustainable energy solutions to help decarbonize the energy system. Another example of in-corridor capital-light investments is an exciting initiative that we announced earlier this week to expand our intake of renewable natural gas. We're entering into a strategic collaboration for the development of RNG transportation hubs where Green Gas USA would contract on our systems. Beyond that, we're also progressing initiatives, including pumped hydro storage in Alberta and in Ontario, clean energy projects with Irving Oil and further hydrogen production hubs with Nikola and Hyzon. As a result of our rich opportunity set, we expect to sanction approximately $5 billion of new projects in each of the next several years, including recoverable maintenance capital. And because the barriers to entry in those new areas are high, returns are expected to be consistent with historical levels while adhering to our conservative risk preferences. As I've highlighted before, you see on this slide our 2022 priorities. I'm pleased with the progress we've made towards achieving these goals in the first quarter. I look forward to providing further updates as we continue to advance towards these priorities throughout the year. We have an incredible opportunity to play a vital role in enabling a transition to cleaner energy while providing the safe, reliable and secure energy that the world needs. In summary, we have all the right ingredients to meet these energy challenges. We have a world-class base of assets in strategic locations. We have commercial, engineering and technical capabilities. We have a culture of innovation, and we have financial strength and capital discipline. Our tireless efforts to make energy more sustainable and more secure will continue to strengthen our existing business and deliver long-term results for our customers, community stakeholders, and our investors. Thank you for your attention, and I will now turn the time over to Joel for a few comments on our first quarter results.

Thanks, François. Good afternoon, everyone. As François mentioned, our assets continue to deliver strong results in the first quarter while reliably meeting the growing demand for energy. This highlights both the criticality and resiliency of our asset footprint. Comparable earnings for the first quarter were $1.1 billion or $1.12 per common share compared to $1.1 billion or $1.16 per common share in 2020. Comparable EBITDA and comparable funds generated from operations were $2.4 billion and $1.9 billion, respectively, compared to $2.5 billion and $2 billion for the same period in 2021. I won't spend a lot of time today reviewing the results we published earlier today, but I'll remind you that net income attributable to common shares was $358 million or $0.36 per share in the first quarter compared to a net loss of $1.1 billion or $1.11 per share the same period in 2021. First quarter results included a $531 million or $0.54 per share after-tax goodwill impairment charge related to Great Lakes and $193 million or $0.20 per share income tax expense for the settlement in principle related to prior year's income tax assessments in Mexico. First quarter 2021 also included certain specific items as outlined on the slide and discussed further in our first quarter 2022 report to shareholders. As mentioned a few moments ago, First quarter comparable EBITDA from our five operating units was $2.4 billion. You can find more details on the variance explanations for each business unit and our financial highlights release. So I'll just comment on a few principal changes year-over-year. Canadian Natural Gas Pipeline's comparable EBITDA decreased primarily due to lower flow-through depreciation on the Canadian Mainline. This was partially offset by increased flow-through depreciation on the NGTL system. U.S. Natural Gas Pipelines comparable EBITDA increased mainly due to higher earnings from Columbia Gas as a result of increased transportation rates effective February 1, 2021. Mexico Natural Gas Pipelines comparable EBITDA decreased primarily due to a higher deferred income tax expenses Sur de Texas as a result of a foreign exchange gain calculated for Mexico income tax purposes on the revaluation of U.S. dollar-denominated loans. Liquids Pipelines and Power and Storage comparable EBITDA declined as a result of lower contributions from liquids marketing activities, mainly due to lower margins and lower realized natural gas storage spreads, reflecting volatility seen in the quarter. As a note, we translated our U.S. dollar-denominated income in the Canadian dollars using an average exchange rate of $1.27 in the first quarter, which is similar to the same period in 2021. This included U.S. and Mexico natural gas pipelines in the majority of our liquids pipelines. And as a reminder, our U.S. dollar-denominated revenue streams are, in part, naturally hedged with U.S. dollar-denominated amounts below EBITDA and the residual exposure is actively managed on a rolling three-year forward basis. Now, I will spend a moment highlighting a few of the primary variances below EBITDA. Depreciation and amortization decreased largely due to the Northern Ontario line portion of the Canadian Mainline being fully depreciated in 2021, partially offset by higher depreciation on the NGTL system from expansion at facilities that were placed in service and in U.S. Natural Gas Pipelines, mainly due to the timing of certain adjustments related to the Columbia Gas rate case settlement. Income tax expense included in comparable earnings for the first quarter decreased compared to 2021, primarily due to lower earnings and a U.S. state tax adjustment, partially offset by lower foreign tax rate differentials and flow-through taxes. I want to take the opportunity to reiterate our outlook for 2022. We expect 2022 comparable EBITDA to be modestly higher in comparable earnings per share to be consistent with last year. In terms of capital spending, we expect to invest approximately $7 billion this year. This is up relative to our initial 2022 outlook of $6.5 billion. The increase is primarily due to higher costs for the NGTL system, reflecting inflationary pressures on labor and materials, additional regulatory conditions, weather and other factors. We continue to work on cost mitigation strategies and assess market conditions, developments in our construction projects and the impact of COVID-19 for further changes to our overall 2022 capital program. Our 2022 capital program is primarily focused on NGTL system expansions, U.S. natural gas pipeline projects, the Bruce Power life extension program and normal course maintenance capital. Turning to our funding program. This graphic illustrates our updated forecasted sources and uses of funds for 2022 through 2024. Starting in the left column, our total requirements over the three years are projected to be approximately $26 billion, reflecting capital expenditures, including maintenance capital of $15 billion and dividends of $11 billion. The second column highlights expected internally generated cash flow of $22 billion, leaving a residual need of approximately $4 billion, depicted in the far right column that we expect to fund through a combination of commercial paper, incremental debt, hybrids and Keystone XL project recoveries. Today, we are advancing our diversified $25 billion capital program, consistent with our historical risk and return preferences. Importantly, our capital program not only focuses on modernizing and growing our core business, but also in advancing projects aimed at reducing emissions and offering carbon-free or low-emission energy alternatives. These projects are underpinned by long-term contracts, our cost of service regulation, and we expect them to deliver a weighted average unlevered after-tax IRR of approximately 8%. Given our opportunity-rich position and expectation of placing $6.5 billion of assets into service this year, we are confident in our ability to deliver EBITDA growth of 5% through 2026. But remember, that growth will not be linear. And similar to today, approximately 95% of our EBITDA will continue to come from regulated and long-term contracted assets. Looking at the continued strong performance of our base business and our organic growth plans, we expect to continue to grow our common share dividend at an average annual rate of 3% to 5%. This is consistent with our conservative approach to capital allocation, historical risk-adjusted return profile and is expected to provide the capacity to fund our sizable capital program while enhancing our financial strength and flexibility. Now as always, we expect to support the growth in dividends by sustainable growth in earnings and cash flow per share and strong coverage ratios. So I'm excited when we look ahead. We have a track record of 13% average total shareholder return since 2000. We are well equipped to fund our $25 billion capital program. We have increased our common share dividend for 22 consecutive years, and we will maintain our solid financial position. When you pair our enduring business model and financial flexibility with our unmatched footprint and organizational capabilities, you'll see that we are differentiated in our potential to capitalize on the opportunity-rich environment before us. This will allow us to continue delivering superior long-term shareholder value. That's the end of my prepared remarks. I'll now turn the call back over to Gavin for the Q&A.

Thanks, Joel. So just a reminder, before I turn it over to the conference coordinator for questions from the investment community, we ask that you limit yourself to just two questions, please. Thank you.

Thank you. We will now begin the question-and-answer session. [Operator Instructions] The first question comes from Linda Ezergailis with TD Securities. Please go ahead.

Very dynamic environment that we're in right now, and I'm just wondering, with all your focus on this energy transition, there is also this expectation that hydrocarbon exports out of North America will accelerate, and that was already a trend, but we'll probably see more of it. And I know you're already participating indirectly in transporting natural gas to LNG export facilities. But what are your thoughts about potentially pivoting other to support exports of liquids or NGL export facilities? And what factors would need to be in place for you to move down the value chain to actually get involved directly in exports? François Poirier: Linda, it's François. I'll get started, and I'll ask Stan to provide some proof points on what we're seeing in the LNG export market. First of all, you're quite right. The balance of -- a better balance between energy security and energy transition has brought forward additional opportunities as we -- I alluded to in my prepared remarks. We have enjoyed and benefited from the growth in LNG exports with LNG exporters as a customer. And as I mentioned, we serve about 25% of aggregate natural gas demand in that area. We've not considered recently -- in the recent past participating down the value chain as an owner of equity interest in LNG facilities. We see that as a large global market involving participants who have LNG supply from various sources, have significant scale as well as marketing -- commercial marketing and trading capabilities in that area. So our view is that there's plenty of growth opportunity for us in supplying the LNG facilities with their needed gas for their expansions. And perhaps I'll ask Stan here to provide some proof points.

Linda, this is Stan. I could address the LNG side, and then I'll kick things over to Bevin and he could address the NGL side. I do think that we're in a bit of a target-rich environment, so to speak. FERC, just over the past several weeks, approved three of our LNG export-related projects. In the aggregate, they amount to 1.4 Bcf a day, a $700 million capital investment for us, and we're going to focus on getting that capacity online as quickly and as safely as we can. Secondly, while our Columbia Gulf and AR pipelines are generally fully compressed and fully contracted for north to south flows, looping those systems to bring more Appalachian gas to the Gulf Coast is not out of the question. And just as an example, if we were to build a new line from the Columbia system all the way down to the Gulf Coast, it likely would have a transportation rate of about $2. But if you believe, as I do, that the war in Ukraine has caused a fundamental shift with respect to where our European allies source their gas from and that this incremental demand for natural gas is going to keep prices in Europe and Asia in the $13 to $20 range, which is where they currently are for 2023 and 2024, a $2 transportation rate for incremental pipeline capacity to the Gulf Coast may well clear the market. But I'd also just remind you that given our extensive 13 pipeline network that traverses 40 states, we have a footprint everywhere. If the Costa Azul facility on the West Coast has expanded from 2 million tons to 10 million tons, we can further expand our North Baja system. If the Cove Point facility on the East Coast has ever expanded, we have the ability to further expand our WB line on the Columbia Gas system as well. And with respect to the Permian, I do think that there's a likelihood that you'll see additional pipe capacity specifically built directly to the Texas Gulf Coast LNG facilities but not directly to the Louisiana Gulf Coast LNG facilities. Instead, you're likely to see pipes built out of the Permian that will interconnect with our existing infrastructure in Louisiana, where we can leverage our competitive advantage and take advantage of the last-mile connectivity. And then lastly, I would note that it's -- there are more opportunities than just Appalachia or the Permian Basin. And don't discount the ability for gas out of the Haynesville to ultimately reach some of these Gulf Coast LNG facilities where, again, we can leverage our existing footprint. So with that, I'll kick it over to Bevin to talk about the NGL side of things.

Thanks, Linda. On the liquid side, I'll first go with our oil liquid system. We have, as you know, a very strategic footprint that connects Western Canadian Sedimentary Basin down through pushing it into the Gulf Coast, and we're actively pursuing and expanding in corridor, and part of that strategy includes looking at opportunities for additional export points and access to different delivery points for our customers. To do so, we've brought on additional expertise into our marketing affiliate team that has that experience to address different Tidewater type markets. With respect to NGLs or refined products, those are still asset classes that are not in our portfolio. From time to time, we evaluate whether they would be a fit. Both the refined products and NGL businesses, though, at this point, we're not advancing any capital towards.

That's a very helpful update on how you're thinking about things. Maybe just as a follow-up question, I'm interested to hear maybe one of your smaller initiatives that might not get a lot of airtime, but maybe could be scalable into other areas. Your urban oil decarbonization initiative. Can you paint us a picture about what beyond power generation might that involve? And would TC Energy operate the facilities in there? And what other locations might such initiatives be possible? François Poirier: Over to you, Corey.

This is Corey Hessen. I think when we think about the Irving Oil opportunity, we obviously are starting with our core businesses of the power -- the power side and being able to deliver renewable energy. Moving forward, as we talked about with many of our other opportunities, we have built a strong partnership with hydrogen opportunities across our North American footprint. And that will create for us another opportunity with Irving oil as they think about how to best use their assets and apply them going forward. So as we think about that, we think that it is a -- like all of our emerging technologies a little bit of a longer road, but it creates an opportunity for us to evaluate in a systematic fashion.

The next question comes from Robert Kwan with RBC Capital Markets. Please go ahead.

If I can start with inflation. The last call focuses on OpEx. So just I wanted to ask here about CapEx. Generally, what percentage of your CapEx plan has cost recovery either contractually or regulatory backed? And specifically just for this NGTL increase, is it all rate base where the entire cost increase earns a return on and off capital?

Yes, Robert, it's Joel here. I'll take the question. So first, it's really worth noting that when you look at all of our major projects, including Bruce Power, the MCR program there, expansion projects along our U.S. natural gas pipeline footprint along with Liquids Pipelines, those all remain on time and on budget. NGTL is unique in that it is in Western Canada. It's competing with two other major projects right now for labor, in particular. That's obviously the TMX project and CGL. So as a result, we are seeing inflationary pressures on labor and materials in addition to cost increases related to regulatory conditions, along with weather delays, COVID and, at times, slowing down the work to ensure that our workers are safe. So as a result, the costs that you're seeing are primarily related to NGTL system. We are working to meet our customer needs. It's important to keep our tools as low as possible. So we're looking ways to mitigate these costs. But as a reminder, any costs associated with the NGTL system, similar to the Canadian Mainline, those costs, you earn a full return of and on capital for those projects.

Okay. And even though you're not seeing cost pressures on all those other projects, do you -- like what percentage do you have recovery mechanisms?

For the other projects, Robert, just to clarify?

Yes. Yes.

It all depends. Maybe I'll turn it over to Stan if you had any commentary on the U.S. side and then maybe over to Corey for Bruce Power.

Robert, this is Stan. With respect to our growth projects that are underway, I would say, a vast majority -- I don't have a specific percentage for you, but the vast majority are covered contractually. We will be able to recover the capital that we're investing. It's very typical for us to have some sort of cost sharing mechanism built into our precedent agreements with our customers.

Robert, Corey Hessen. Yes, with regards to Bruce Power, Unit 6 MCR is going to be completed, I don't know, inside of 2022 or early 2023. So both materials and services have already been fixed for that MCR, and there's no -- very low risk of additional inflationary costs. Unit 3 MCR, for both materials and services, are in excess of 95% fully contracted. So we see limited risk of inflationary impacts for those units for that MCR program as well.

Got it. And I finish with Coastal GasLink, can you just talk about the nature of where you are in discussions? Like are you still negotiating over costs? Or have you now moved to more around the mechanism of how to recover that? And if you've got an update on timing, that would be great. Specifically, how much does LNG Canada's go or no-go decision on expansion matter in terms of when you're going to strike an agreement.

So Robert, this is Bevin. We're very aligned right now with our customer with LNG Canada. We're working towards resolving the dispute really quickly. But our prime focus right now is to also deliver the project safely and ahead of the delivery of the LNG facility. So as we focus to resolve the negotiation here fairly quickly, I'm optimistic that we'll reach an agreement that will put us in a position to update our shareholders on the path forward. With respect to Phase 2, it's a great opportunity, not only for LNG Canada, but also ourselves and the Western Canadian sedimentary basin as we could see the delivery out of the basin move from a 2 Bcf a day export scenario to north of 4 Bcf. So that decision, though, is clearly in the hands of our customer, LNG Canada, in terms of preparing for a final investment decision on that front.

The next question comes from Ben Pham with BMO. Please go ahead.

First question is on the LNG commentary you had. When you look at your current footprint today and how you've positioned that, you've mentioned a 25% market share as you look out to that 10-plus Bcf a day. Do you have enough visibility of the way your positioned to at least maintain that market share? Or are these projects that you may be able to lose?

Yes. Again, this is Stan. Not only do I think we're going to maintain that market share, but my expectation is we're going to grow that market share. And if you look at the 1.4 Bcf a day of projects that the FERC approved that are under construction right now, when you look at the other opportunities that we have, I could see a scenario where over the next two or three years, fit's another 2 or 3, maybe 4 Bcf a day of capacity to the LNG terminals that we're adding on our systems.

And is it reason to assume that that you can use those projects, the CapEx numbers to be to gauge the opportunity?

I'm sorry. Ben, sorry, could you clarify your question, please?

Yes, sure. Let's just -- the three projects that you've moving forward, you have CapEx numbers attached. It's $1 billion. Can we take those as examples to gauge the capital investment opportunity?

Yes, it really depends. They're not going to be a very good example if we're going to build a new pipeline from the Appalachian all the way to the Gulf Coast. But to the extent that we're going to leverage the competitive advantage we have with our existing footprint, yes, these $100 million, $200 million, $300 million, $400 million type expansion would make sense.

Okay. That's great. And my follow-up then is on the looping project, a potential project on Columbia. Do you need more LNG projects to start talking about commercial agreements? Or it just a matter of that price, the $2 price that you mentioned that's -- that's mitigating some of that?

I was using the example as an -- the $2 price as an example to show that what we think is a high cost today may not be high cost given the environment that we're in. And it fits within the overall stack when you look at transportation rates and $2 for liquefaction, $1 for regas, $2 for shipping and the like. Again, it's basically an in-the-money proposition. François Poirier: And Ben, just to supplement that a little bit because I hear where you're going with the question, as usual, we allocate capital on the strength of long-term contracts. That's the way we typically do things, ship-or-pay contracts. And in conversations with shippers in the Appalachian Basin, we are seeing willingness to consider new greenfield pipe given the robust price environment that our producers expect to remain robust for the next several years.

The next question comes from Robert Hope with Scotia Bank. Please go ahead.

I want to switch gears a little bit and move over to the U.S. renewable projects that you secured commitments for. Is this only for your existing Keystone capacity or would this be included in that kind of business idea of sharing it with some other parties in the earning a margin on it? And I guess, secondly, eventually, do you assume that you're going to take an ownership in these projects? And when can we see it put into the capital plan? François Poirier: Robert, it's François. I'll just start at a high level, and then I'll ask Corey to provide some detail. As we mentioned last quarter, we were very successful in aggregating incremental load in the neighboring areas to our own demand at our pump stations. And so as we're gradually contracting up the various projects, it is a combination of meeting the demand from specific pump stations as well as aggregated load in those specific areas. And so you can see a gradual contracting up of both of those as we add volume towards our overall goal of two-plus gigawatts. And Corey, over to you for a little bit more color there.

Robert. Thank you very much, François. Francios was right on point there. The way we think about it is that we are not only serving our internal load, but we are serving the load of those customers who are in corridor for our vast set of assets across North America. And so our goal, as François stated, is to approximately secure 2 gigawatts of total renewable resources. And of those 2 gigawatts, to contract 70% of those resources through our own parties and second party and third parties, and then have additional capacity available to then secure our next phase of opportunities with our own internal customers across our footprint. So we feel very solid about our progress to date, and we are continuing on the schedule that we outlined earlier, where, by the end of the year, we should have met those two goals. Robert, you also asked a follow-up question about ownership. As we've contemplated these projects, we have developed an approach to the capital stack, which would be inclusive of an opportunity for TC Energy to be an owner for those assets that make sense for our footprint and our own ownership goals and desires. And it's also inclusive of opportunity for third-party investment as well to ensure that our long-term partners have the opportunity to participate in these renewable assets across our footprint, not the least of which is our business partners who we regularly include in opportunities to co-invest as we mentioned, with our CGL project. Thank you. François Poirier: And Robert, just to add a little bit of color to help you out. We're in the middle of commercial negotiations on a number of projects. So you can expect that we'll be able to offer you a little bit more color and detail around timing once we mostly get through that. But our intention with some projects is to acquire them in late-stage development. But for the most part, I think we're looking at capital deployment at COD. And think of our equity interest being somewhere in aggregate between 25% and 50% of the equity in the overall portfolio. It may be 100% in some cases and none in others and some mix in between. But not likely additions to our capital program until we get late into 2022, as Corey said. It's going to take us most of the balance of the year to contract that up. And for commercial reasons, we'll hold on until we get near the end of those negotiations before we provide you with that detail.

And then just a clarification and a follow-up. The -- taking a look at the capital project list. In the U.S. natural gas pipelines, the other capital bucket has increased, but it's also increased in time. Is that just kind of extending the window of debottlenecking the system? Have you added new projects there? Or is that cost related?

No. That's related to an acquisition that we have. We call it our KO transmission project. We're going to spend about $80 million to acquire a line from a third party that's going to give us direct access into the Northern Kentucky and Cincinnati, Ohio markets with the opportunity to do additional bolt-on expansions in the future.

The next question comes from Jeremy Tonet with JPMorgan. Please go ahead.

I just want to touch on NewCo a little bit here. As it relates to Bruce in the potential for hydrogen, we're seeing a little bit about potential there. And just wondering, if you could dive in a little bit more in your comments, I guess, how should we think about the timeframe of this evaluation and what are kind of some of the factors in play for a decision on whether something could be done, just wondering any color that you could share at this point?

Jeremy, it's Corey. With regards to Bruce and their efforts, as you know, Bruce Power has a strong position in the province. And as part of their overall growth program, to finish the refurbishments of all of the units, along with the Project 2030 that's growing the overall capacity of the plant, that creates an opportunity for the province that as new technologies emerge and there is the need for the creation of those new technologies, Bruce Power is systematically investigating how they can apply this additional capacity that's being driven by virtue of Project 2030 and the MCR to deliver new fuel sources to the province. And so the way I think about it is they're systematically looking at a broad range of opportunities, including SMRs, hydrogen and other -- other programs that will allow them, through their Nuclear Industry Institute, to evaluate sort of in the 2030 time frame when most of these emerging technologies hope to be in a position to deliver to the province.

Got it. So I think Bruce hydrogen is pretty later-dated at this point, to sum it up? François Poirier: Yes, that's correct.

I think so. I think they've got a full plate with the MCR program and with the upgrade program at the plant. And as they look at these opportunities, it's a matter of them being experts and being able to apply rigor to the process and deliver information to the entire province.

Got it. That's helpful. And maybe just one more on nuclear, if I could. We've noticed a lot of really interesting advances on small modular reactors and technologies there. And it seems like over the next middle of this decade to the back half of this decade, some of these things could be coming into focus a bit more and maybe applied in different ways than done historically. I'm just wondering, I think, TRP, maybe in the past, have talked about the role NewCo have in the oil sands or feeding other parts of the business, power-wise. I'm just wondering if you see an opportunity for TC Energy at some point down the road to become involved with SMRs. François Poirier: Jeremy, it's François. We really do. When you think about SMRs in the context of oil sands and their needs for steam and power, it really is an excellent use case for small modular reactors. Through our affiliation with Bruce Power, we've got the technical expertise to develop and evaluate those technologies. But I think equally, as importantly, we have the commercial relationships with the oil sands producers. We have all of the surrounding and supporting infrastructure at site to provide their steam and power needs. And we understand how to dispatch energy into the energy-only market, which Alberta is. It's similar to Texas, if you're familiar with the market structure there, so very much something that we're interested in pursuing. From a time frame standpoint, however, I think it might be a little bit later than what you're alluding to, at least in our view. Just getting an operating license in its own is a very lengthy and costly process. It can take up to five years to do that. Technology still needs to be proven up. In our view, the oil sands producers would need to sort of buy in on one common technology so that they have the requisite expertise to operate and maintain a fleet for those purposes. All of that is going to take time. So we view this more as an opportunity for the 2030s than the second half of the 2020s.

Got it. Got it. Well, we'll see. Hopefully, it's a little bit earlier, but thank you for all your thoughts there.

The next question comes from Robert Catellier with CIBC Capital Markets. Please go ahead.

I just want to go back to some of your earlier comments on energy security. And if you could speak to any changes in your capital allocation strategy, you mentioned LNG, but are there other project types you're pursuing? And has there been a meaningful change in what the counterparties might be willing to accept in terms of risk transfer or anything else? And maybe you can address whether there's been an appreciable change in the permitting environment that's required to enable these energy solutions to come to market? François Poirier: Yes. Thanks, Robert. I'll get started on that, and I'll ask Stan to reflect on some of the experiences we've seen with permitting for LNG recently with the FERC. I guess, I would start, Robert, by saying that our strategy is unchanged. We were believers in the requisite balance between energy security and energy transition for many years. And if you look back to our strategy and our parameters we discussed at our Investor Day last year, in many respects, we feel that what transpired globally has confirmed the validity of our approach. We believe that all forms of energy will be required to meet the world's energy demand. And that requires an all-of-the-above strategy. So at the same time, as we're comfortable allocating approximately $20 billion of our $25 billion program to natural gas, we're also bullish on pursuing alternate sources of energy, be they renewables, hydrogen, CCUS or otherwise because we do have to achieve not only reliability and affordability, but also the lowest possible emission profile for -- in order to allow the industry to prosper. So, from that perspective, really more a validation of our view, certainly, on the LNG front, as Stan reflected, the pull in terms of increasing frequency of conversations and acceleration of conversations around new infrastructure has accelerated. I would say though that it's bifurcated in two parts. The first is governments wanting to help Ukraine and Western Europe in the near term. What can be done for the next heating season? And then there's the longer-term conversation about how do we, over the long run, reduce Western Europe's reliance on Russia for its oil and gas, which, as we all know, is it takes about five years to sanction and build energy infrastructure. On the permitting front, I'll turn it over to Stan to reflect on our recent experiences with the FERC.

Yes. Robert, you may be familiar with FERC's recent actions around its policy statement, which we believe are directionally positive, all things equal. We applaud FERC for its participation in the congressional hearings and really for listening to the various comments from industry and for ultimately reversing course and making its policy statement now into a draft document as opposed to a final rule. And the implications of that are such that now that it's a draft policy, the pending certificate applications are no longer applicable, and you've seen FERC actually come out with issue orders, which is part of the three projects that François mentioned early on. So, again, directionally positive with respect to the need for new critically needed energy infrastructure in the United States. It remains to be seen, however, what the final rule is going to look like. So we'll continue to monitor that very closely and work with the various stakeholders to make sure that our interests are properly represented. François Poirier: And perhaps I'll ask Greg to provide some commentary on the regulatory environment in Canada.

Thanks, François. Yes. Similarly, I think we're seeing a lot of positive momentum on that front, both with local communities, stakeholders, regulatory front from the energy security piece. Just reinforcing kind of the peak demand, we've been seeing inter-province export and otherwise, there's a lot of inbounds, whether it's coming in from Europe, East Coast otherwise looking for ways of getting more gas out of the WCSB. And really, when you look at the peak levels that we're seeing, it is driving that need for capacity and reliability. So we are getting a lot of support and trying to figure out ways that we can help make that regulatory process more efficient as we try to add more capacity.

Okay. And just -- I was a little bit curious on Coastal GasLink and why you felt it was necessary to increase the loan commitment there -- portend to potentially higher -- even higher CapEx than what you were thinking previously?

Yes, Robert, it's Joel here. Very similar to what we said before with that subordinated loan facility. It's just to make sure there's sufficiency of funding for the project. We do have a credit facility in place for CGL for $6.6 billion. And in order to make sure that we have all the funds in place, we just had to increase the subordinated loan by $500 million this quarter. Our expectation going forward, though, would be to increase the credit facility, that $6.6 billion that I mentioned higher. And by doing that, that would lower the subordinated loan by the same amount. So again, we view this facility as being temporary, but we did increase it just to make sure that we have the appropriate funds to fund the project.

The next question comes from Brian Reynolds with UBS. Please go ahead.

Maybe to start off, talk about the Marketlink open season. Just kind of curious if you can give a little bit more color around it and super interest that you're seeing so far? And just maybe talk about future demand for capacity from Cushing to Houston and Port Arthur demand markets, given the domestic and export market clearly demands more Canadian and U.S. barrels?

Yes, sure. Thanks. Glad you asked with the open season. So to start -- this is Richard Prior, by the way. This open season is an example of our new strategy of finding ways to increase utilization where we have latent capacity on the system. So, this is through in core or capital light, and in this case zero capital opportunities. So we launched an open season on Marketlink on April 8. It closes in mid-May, and it's going to enable Cushing crude to reach the domestic markets and in the Port Arthur and Houston areas. Before we launch the open season, we worked extensively with our customers, which gives us a strong understanding of where the market is. I'm quite pleased with the customer response that we've had. And based on the feedback, I'm confident that we'll be successful and we'll see an increase in committed contracts on the Marketlink system. You asked about other demand on MarketLink and there's a number of things that we're doing with that asset to make sure that we increase volumes and we work to fill up that light capacity and manage that I mentioned. We're actively managing our spot tool. And as a result of that, we've seen additional spot tool movements. We've taken a different strategy around our Houston tank terminal position, and we're starting to see more barrels going to the Houston marketplace. We're starting to see an uptick in diversions from Patoka, Cushing flowing all the way to the Gulf Coast. And that's a lot based on refinery pull for increased heavies. And we're doing things like we're adding the Port Neches link that François mentioned in his opening comments where we're going to extend the Keystone system down to Motiva's facility. That's the largest North American refinery. And things like that, we're confident are going to increase the pull down our system all the way to the Gulf Coast. And I think the future is very bright for that part of the system.

Great, I appreciate the color. And then maybe as a follow-up to the subordinated loan capacity question increase. While I understand there's no update on the potential total cost for Costa GasLink at this time, could you perhaps just let us know what the project spend has been to date for Coastal GasLink to help us gauge potential future CapEx needs with the project roughly 65% complete at this time? François Poirier: Yes, it's François, Brian. We have contractual agreements with our customer not to disclose what they view as market-sensitive information. You can expect a generally linear relationship between the fact that we're 63% complete and the aggregation of the project financing and the subordinated loans. And we'll -- once we reach hopefully, an amicable solution with our customer, we'll be able to provide additional details. And as Bevin mentioned, we expect that to happen here in the near future.

The next question comes from Michael Lapides with Goldman Sachs. Please go ahead.

I have one nuanced one for first quarter earnings or first quarter comparable EBITDA. If I look at the Canadian Gas Pipeline segment and down year-over-year around $40 million. But I assume the bulk of that is just the roll-off of the mainline -- the net earnings neutral impact on the depreciation for the Canadian Mainline. And I thought that was around $40 million a quarter or so. And if so, that would imply EBITDA year-over-year was flat there quite pretty good volume growth. I just want to make sure I understand what -- kind of why flat, why not up a bit year-over-year at that segment?

Yes, Michael. It is Greg Grant here from Canada Gas. And I think you got that right from the EBITDA front. Certainly, that is partially mainline. But I think you also have to remember and consider there's tax depreciation that moves quarter-to-quarter, and we have some offsetting effects to that. I think net income is a much better measure for our business. And I think as you would see and as you model the increased capacity and capital that we continue to put in the ground, you will see the net income continue to follow that and correlate quite closely to that.

Got it. Okay. And then how are you all -- I noticed in the financing slide like when you showed the two bars, and Joel, you spent a good amount of time walking through that. When I look at the fourth quarter slide, that same slide, so the 2022 to 2024 financing, I don't know if you mentioned use of hybrids in the fourth quarter slide, but I think it did today. Are you guys thinking you have a need for convertible securities in the next couple of years? And do you think it's a sizable portion of that kind of that funding bar? Or is it just kind of tiny and rounding error relative to your enterprise value?

No, Michael, it's something that we always look at. When you look at subordinated capital, it always comprises roughly 15% of our capital structure. So as the balance sheet grows, obviously, the subordinated capital portion of the capital structure grows with it. So, as we see -- as we look out over the next couple of years, certainly, we're seeing additional hybrid capacity as a result of the growth in the balance sheet. So yes, we didn't include it in the fourth quarter, but we thought it was important just to highlight that for investors this quarter that certainly as we move forward here, in order to keep our leverage metrics in line and moving down, along with improving our earnings and cash flow per share, that THE hybrids will make up an important component of it, again, capped at the 15% of the capital structure.

Got it. Okay. I'll follow up with Gavin and team offline. Much appreciated.

The next question comes from Praneeth Satish with Wells Fargo. Please go ahead.

In the Bakken, I know there's been some production outages due to the severe winter weather, but if you adjust for weather, gas production growth has been very strong. I guess what's been the shipper feedback so far on your Bison Express project? And just hypothetically, if the project doesn't get constructed, do you think there's a possibility at some point in the next few years where you just stop accepting more Bakken gas on Northern Border?

Puneet, this is Stan. As you noted and I alluded to in our call -- last call, we did launch an open season for some Bakken export capacity up to around 430,000 a day. The open season doesn't close for another week or so. And as is typical, we tend to receive all of our bids at the last minute of the last day. So unfortunately, I don't have anything that I could share with you that would not be commercially sensitive at this point in time. With respect to your other question, we're receiving about 2 Bcf a day of gas out of the Bakken right now, 70% of the supply that comes into the Northern Border system. So there's another 30% of that capacity that is going to compete for space against the Canadian supplies that come in from the north. So a little gas-on-gas competition perhaps that goes on. Once that gets filled up, then the pipe is essentially full, and that's just another signal for a pipe expansion down the road.

Got it. And then just staying in the U.S., the Haynesville production has started to pick up in the last few months. And there's a few companies now looking at building egress out of the region. So I'm just wondering, is this something that you're evaluating as well? Do you have any opportunities on ANR or CGT to potentially increase capacity down to the Gulf Coast?

Yes. It is something that we're looking at. And I'll go back to my remarks in the beginning with respect to Haynesville production out of the basin is not that different from the Permian. The growth opportunities are not that different from the Permian. The distance from the basin to the LNG export terminals in Louisiana is not that different from the Permian. So, there's a lot of overlap there. Whether it's a greenfield or brownfield expansion, we do have the opportunity to interconnect with our existing lines on the Columbia and the Columbia and A&R systems, I should say. So yes, that's something that is very much at the top of our minds.

The next question comes from Matthew Weekes with IA Capital Markets. Please go ahead.

Just looking at the quarter here, and it looks like there were some impacts to EBITDA a little bit from sort of commodity-related factors talking about natural gas storage, liquids marketing and then some talk of some timing on earnings in the liquids related to risk management activities. I'm just wondering, keeping in mind that a lot of these factors are out of your control and subject to the volatile environment we're in, if you have any visibility on how these factors will sort of play going forward on results as the year progresses and if you have any visibility for maybe some of these factors normalizing or moderating going forward. François Poirier: Thanks, Matthew. It's François. I'll get started, and I'll ask Richard or Bevin to provide some proof points. We do undertake commercial marketing and trading activities. And sometimes there's a bit of a mismatch between the financial and the physical. And so if we're caught in between the two at the end of the quarter, you might see the cost impact of one and not see the revenue impact of the other until the next month, which is in the next quarter. So maybe Richard, you can provide a bit of an example of that. And then -- that -- provide some color as to what you see happening for the rest of the year from our business.

Yes, absolutely. So you look at the first quarter between the pandemic and the war in Ukraine, we've seen tremendous volatility in the crude markets right the way through. And there's really a couple of things going on that impact our margin business and not necessarily specific to commodity prices on the one end and then the other, as François mentioned, has to do with the risk mitigation. So first of all, the transportation differentials remained quite tight. So despite the fact that we saw a steep increase in flat crude prices, the differentials between the different trading hubs, which is what sets the margins for our marketing entity and that would really be between Hardisty and the Gulf Coast and Cushing on the Gulf Coast, they stayed very tight. And so that sets a tight margin. In addition to that, we saw steep backwardation throughout the first quarter. And that further exacerbates the type differentials, as with the Keystone system due to the transit times, you receive a barrel onto the system and then you deliver a barrel off of the system in the following month. And so we saw the calendar spreads as wide as $4 at points in the first quarter. So that put further compression on margins. Then we've got our risk mitigation strategy around the commodities. And so we deploy disciplined financial risk mitigation measures to minimize our commodity exposure. But on a short-term basis, we have this timing aspect between when we purchase the crude, place the financial hedge and then sell the crude in the following month. And so what we're expecting is that the timing will catch up likely over the next quarter. And so I think what we saw in Q1 is an anomaly, and we would expect our future business to be more consistent throughout the rest of the year as we've seen in previous quarters from the marketing entity. One thing I just want to mention as well, though because I do think it's important to note is that the majority of our liquids business is committed long-term contracts, and the demand for our pipeline throughput continued to be consistent and predictable. We've been flowing in excess of 600,000 barrels a day now for the last two quarters. And I'm not seeing anything that's suggesting that, that's going to decrease. And we're seeing that across the whole system, our Keystone system and our Gulf Coast system. And then I already discussed some other things that we're doing to try to increase that on the southern part of our system, where we have some latent capacity.

Matthew, it's Joel here. What Richard just pointed out is why we are confident in reaffirming our outlook for the year, where our EPS to be generally in line with last year and our EBITDA to be modestly higher than 2021.

Okay. I really appreciate the detail and the commentary on that.

Thanks, Matthew.

The next question comes from Andrew Kuske with Credit Suisse. Please go ahead.

I guess the question is going to be for Stan and for Greg. And we've spent a lot of time over the years talking about producer health. Obviously, it's fairly robust right now. But do you see opportunities across the portfolio for an acceleration of volumes in certain submarkets or certain basins that you serve, and maybe that comes from outright drilling activity accelerating or just some of the DUCs, no pun intended, but they're all lined up at this point in time. What does that mean from an upside to returns?

Yes. Great question. If you read Gas Daily today, this Stan, by the way, you'll see that Antero was talking about the value of their transportation capacity and how critical it is to their success in getting additional gas down to the Gulf Coast. That's just a reinforcement of exactly what we do. Producers are still living within their means and staying within their balance sheets, at least for the moment. They're not chasing the higher prices, which I think is the right thing to do. But going forward, there are clear signals. And I think that you're likely to see drilling activity increase, and we're seeing that in the Bakken. We're seeing it in the Permian. We're seeing it a little bit in the Appalachian Basin. And as that happens, there's going to be a need for more egress capacity, and that's what we do. When I think about things like the Appalachian Basin, for example, we have the ability to further compress up our Buckeye XPress project, which we put in service about a year ago. That could bring a couple of hundred thousand day of capacity online into Teco pool in very short order. So absolutely, we are bullish. We're glad to see that the producer's health is back to where it should be, and we're glad to see if they recognize the value that our transportation capacity brings.

And then maybe from Greg.

Yes. Sorry, I'll add. Thank you. Yes, I think what we're seeing is just going back to the unparalleled footprint that we do have here on the WCSB and the competitiveness of the gas. So we are seeing a lot of strength in the basin. We are operating at near capacity, and we are seeing the Q growth from the regulated side of our business. We fully expect that to continue to help support some of the guidance that we provided back in November on Investor Day, that $1 billion to $2 billion a year going forward. As we see supply migration, we see absolute growth on the expansion side. From a pure producer perspective, I agree with Stan. You still are seeing very disciplined capital being put in. But that said, we do expect upwards of a 20% increase in capital here from the producer community in the basin. So we should continue to maintain those flows and continue to see growth over the next couple of years, especially as we see CGL and LNGC coming on.

That's helpful. And then, I guess, maybe an extension of this or building upon the question is where do you have some operational leverage where increased volumes effectively are going to drop down the bottom line and then that enhances EBITDA and earnings. And then the extension of that, and Stan, you mentioned a bit of this is just the looping and compression and then the capital opportunities. Just how do you think about that ordering in your business? François Poirier: Andrew, it's François. I'll get started and then I'll ask Richard and Stan to provide some proof points. One of the things we talked about on our Investor Day was improving the return on invested capital on our existing assets, firstly, through cost efficiency and small revenue enhancement initiatives around machine learning. But we talked about Filadereas and we talked about Marketlink as two examples of where the capital is largely in the ground, in the case of Filadereas, and it's entirely in the ground in the case of Marketlink. And our job now is to commercially fill -- increase the throughput and fill those pipes because that's infinite return on incremental cash flow because of the cash flow is already in the ground. So, those are two great examples of where we've got some good operating leverage. And I know maybe I'll ask you, Richard, again to comment on Marketlink and our strategies. And then maybe, Stan, you can provide an update on the other areas.

Yes. So just regarding the Gulf Coast part of our system. So we look at the Gulf Coast pipeline and it's used for either flowing a long-haul barrel all the way from Alberta down toward delivery points in the Gulf Coast, or it originates barrels and in Cushing to our Marketlink lease that delivers domestic barrels into the Gulf Coast. And we're -- that is a significant and key part of our liquids strategy is to focus on low capital or capital-light options that we can create more pull through that southern part of the system. Things that we're doing, are typically looking at and are looking at right now to increase that pull is a lot of it is increasing the receipt point so that we can find extra barrels to bring into the system and also looking for additional delivery points so that we can get accrued to more markets. Something that I didn't mention that were earlier that we're anticipating seeing some additional pull forward example of is we've recently entered into a joint tariff with another pipeline. And so we're going to be able to pull a barrel all the way from Cushing through into the Louisiana marketplace as well. And that's currently a market that isn't necessarily touched by our system, but I think we could see adding incremental volume. The other place where I should leave it and mention as well is just our long-haul Keystone system. We continue to work on optimizing the performance of that pipeline. We did put an open season in the marketplace back in 2019 where we put 50,000 barrels of capacity. We still have not delivered on that capacity. And at some point in the future, I am confident just through the work that we're doing with our engineering team, our field operations and our commercial teams, that we will be able to realize on that capacity at some point in the future.

And Andrew, this is Stan. Just to follow up on [indiscernible] real quick. That is now mechanically complete for both the North and Lateral segment. So I know we're glad to have that behind us, and we expect to have the southern portion complete here later this year. And with respect to your general question around optimization, I guess a couple of things I would point out is, given some of the headwinds we have with respect to the ability to build new critically needed energy infrastructure, the value of pipe in the ground is increasing and increasing exponentially. And one of the things we're going to do is we're going to test the elasticity of the market, and we're likely to see less discounts offered on our existing capacity, less discounts, all things equal, is going to lead to higher revenues. And then the other thing I would leave you with is innovation. We're doing some really neat things in the innovation space around machine learning. We have a tool that we refer to as our autonomous pipeline, which helps us use artificial intelligence machine learning and the like to make sure that we're maximizing the value out of the pipe at any given day. And so far, that's beginning to pay dividends for us as well.

Ladies and gentlemen, this concludes the question-and-answer session. If there are any further questions, please contact Investor Relations at TC Energy. I will now turn the call over to François Poirier. Please go ahead, Mr. Poirier. François Poirier: Thanks very much. I appreciate everyone's time and attention mid to late afternoon on a Friday. Thank you very much for your attendance. Look, our key messages are we continue to be opportunity rich beyond our $25 billion existing program, when you look at LNG export growth, when you look at our RFI program to electrify our own power consumption, you look at pumped hydro storage, you look at hydrogen, you look at CCUS, you look at recoverable maintenance capital, we're very confident in our ability to deploy $5 billion a year in a responsible manner, consistent with our historical risk and return preferences. One of the key things we're learning here is that incumbency is extremely valuable, not only with respect to our existing gas and liquids businesses, but as we contemplate hydrogen production and CO2 transport sequestration, having assets in the ground, regulatory relationships, rights of way, et cetera, is all becoming increasingly valuable. And then the third thing I want to mention is capital discipline is very important. We are going to deleverage at the same time as we grow our business. We talked about long-term debt-to-EBITDA multiple targets of 4.75. Our expectation continues to be that we will achieve that within our five-year planning horizon. So we're bullish on the opportunity set, and we're also bullish on our ability to maintain strong balance sheet so that we can be opportunistic for opportunities in the future. So thanks very much for your time today, everyone.

This concludes today's conference call. You may disconnect your lines. Thank you for participating, and have a pleasant day.