TC Energy Corporation (TRP) Q2 2022 Earnings Report, Transcript and Summary

Thank you for standing by. This is the conference operator. Welcome to the TC Energy Second Quarter 2022 Results Conference Call. [Operator Instructions] And the conference is being recorded. [Operator Instructions] I would now like to turn the conference over to Gavin Wylie, Vice President, Investor Relations. Please go ahead.

Yes. Thanks very much, and good morning, everyone. I'd like to welcome you to TC Energy's 2022 Second Quarter Conference Call. On the call, we have François Poirier, President and Chief Executive Officer; Joel Hunter, Chief Financial Officer, along with other members of our senior management team. Francois and Joel will begin today with some comments on our financial results and certain other company developments. A copy of the slide presentation that will accompany their remarks is available on our website in the Investor Relations section under Events and Presentations. Following their remarks, we'll take a few questions from the investment community. In order to provide everyone with an equal opportunity to participate, we ask that you limit yourself to 2 questions. If you are a member of the media, please contact Jaimie Harding after this call. 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 the Canadian securities regulator and with the U.S. Securities Exchange Commission. Finally, during this presentation, we may refer to certain measures such as comparable earnings, comparable earnings per common share, comparable EBITDA and comparable funds generated from operations. These and 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 Francois. François Poirier: Thank you, Gavin, and good morning, everyone, and thanks for joining us today. Despite market volatility and ongoing global events, TC Energy's value proposition remains constant, and we made important progress during this quarter. We continued to deliver strong operating and financial results from our high-quality, long-life assets, and this reflects the strength of our utility-like business model, our focus on safety and operational excellence, the value of our long-term relationships and partnerships and of course, North America's increasing demand for our essential services. In addition, we're pleased to announce that Coastal GasLink LP has achieved a significant milestone with the execution of revised agreements with LNG Canada that settles all outstanding disputes, and allows us to continue the safe and timely completion of the project. Now given Coastal GasLink will be on everyone's mind, I'll start by discussing the importance of the revised agreements before moving to a few operational highlights from the quarter. And Joel will then provide more detail around our revised funding plan and why we remain confident in our ability to deliver our 5%, ‘21 to ‘26 EBITDA compound annual growth, our 3% to 5% dividend growth rate as well as achieve our debt-to-EBITDA target of 4.75. So I'll start by saying that a lot has changed over the past 10-year life of the CGL project. We've seen additional regulatory and stakeholder requirements, scope increases, impacts from COVID, inflation, weather and other extraordinary events. So what hasn't changed is our commitment to delivering a competitive LNG solution for the Western Canadian Sedimentary Basin. The basin is globally competitive with fundamentals aligning with our strategy and the long-term value of our CGL and NGTL system assets. Our revised agreements with LNG Canada establish a better framework for project advancement and one that further strengthens our long-term partnership. Our agreements mitigate project funding and execution risk, provide a revised and expedited dispute resolution process, and it will allow us to work with LNG Canada on CGL Phase 2 if and when the project is sanctioned. More specifically, we've reduced our capital recovery risk. On the project by resolving uncertainty over specific and anticipated costs that now incorporates a new estimate of $11.2 billion. This settlement will enable an increase in our project level credit facility to $8.4 billion. And together with our equity contribution, we can step down on our balance sheet subordinated loan over time. Now I want to reaffirm that we continue to see the Coastal GasLink project as economically viable, and we anticipate mechanical in service by the end of 2023 followed by commissioning and commercial and service. Finally, these agreements create a solid foundation and a clearer path forward for the potential development of Coastal GasLink Phase 2 that if and when sanctioned, could enhance TC Energy's project returns. The success of this project is not only important for TC Energy and for LNG Canada, this is a nation-building project that contributes to global climate change goals and creates tangible social and economic benefits for numerous stakeholders. CGL will be the first direct path for Canadian natural gas to reach global LNG markets, providing additional egress for some of the most competitive and responsibly produced natural gas in the world. Importantly, our resolution allows us to continue the safe and timely execution of the project, which is now approximately 70% complete. More than $1.4 billion has been awarded in contracting and employment opportunities to indigenous and local communities and up to 6,000 people will be employed at peak construction this summer. Moving forward, this project also reflects the commitment we made to partner with indigenous communities in one of Canada's largest resource projects. This is one of the ways we continue to advance reconciliation. We have agreements with all 20 of the First Nations along the project route, and have signed historic option agreements to sell a 10% equity interest to 2 indigenous groups representing 16 of those nations. And together with LNG Canada, the project could reduce global greenhouse gas emissions by 60 million to 90 million tonnes per year by displacing coal-fired power. Now on this slide, you can see a section of pipe being transported to the mountain top. This specialized 1.4-kilometer long cable crane can transport 16 tonnes of materials and was engineered specifically for this project. This is innovation in action. This is the first of its kind for Canada, considering the slope classification, and I'm proud of the work our team has accomplished. The execution of the CGL project clearly aligns with rising North American and global demand for affordable, reliable and low-cost energy. Now depending on which forecast you look at, global LNG demand is anticipated to grow from 50 Bcf a day to approximately 75 Bcf a day by the end of this decade, with North America playing an increasing role. This growth is largely underpinned by heightened energy security concerns and the reorientation of the energy mix in Europe, along with strong demand from growing economies in Asia. Combined European and Asian LNG demand is forecasted to increase over 40% or 20 Bcf a day by 2030. This next wave of LNG demand is creating significant opportunities that align with our strategy. TC Energy's unparalleled asset footprint will play a critical role in securing global energy supply. Our updated forecast shows North American LNG exports growing by over 90% from 13 Bcf a day to 25 Bcf a day by 2030. With a number of world-class LNG export facilities on the Gulf Coast, the U.S. is now the world's largest exporter of LNG. This represents over 1/4 of the global market and is expected to increase over the coming years. Now we are safely and reliably connecting about 25% of the volumes destined for U.S. LNG exports and are well positioned to compete for and win our fair share of this growing market. We continue to advance our portfolio of LNG projects at a steady cadence. Grand Chenier XPress went into service in January. Louisiana XPress is already delivering partial volumes and will be fully in-service by the end of this year. Construction is underway on Alberta XPress with targeted in-service by the end of '22. Additionally, North Baja Xpress is slated to come online in the spring of 2023, and we expect customer FID on the East Lateral XPress to follow later this summer with an in-service date in late 2024. Combined, these projects represent 3.3 Bcf per day of new capacity and a capital investment for TC Energy of over $1 billion. Now Canada is also ideally situated to support future LNG growth. As discussed, CGL will connect one of the most prolific and low-cost sources of natural gas supply in North America. When complete, CGL Phase 1 will facilitate over 2 Bcf a day of LNG exports off the West Coast, with the potential to expand to approximately 5 Bcf a day if and when Phase 2 is sanctioned. So with 94,000 kilometers of existing natural gas pipelines throughout the continent, TC Energy, unparalleled asset footprint is core to North America's LNG success today and of the future. And we continue to see tremendous opportunities. Now I want to shout out to our operating teams across our entire platform. They had -- they did a phenomenal job operating our system in the second quarter. Utilization remains high across our diversified portfolio of high-quality life energy infrastructure assets underpinned by increasing demand for energy. Flows on our 13 U.S. natural gas pipelines averaged 25.4 Bcf a day, up over 3% compared to the second quarter of 2021. Our NGTL system had total system deliveries averaging 12.8 Bcf a day. This is up 9% compared to the same period last year, continuing to demonstrate our ability to deliver reliable market access. At Bruce Power, execution continues to be exceptional. Planned outages were completed ahead of schedule with results further augmented by the approximately $10 a megawatt hour increase in contracted power price received in April related to the ongoing major component replacement program, asset management work and other adjustments. And on our Keystone Pipeline system, we safely reached nearly 610,000 barrels a day as we placed about 30% of the 2019 open season contracts into service. Once again, this highlights the essential role our infrastructure plays in North America. Now as we look at our 2022 priorities, I'm very pleased with the overall progress. Safety is our top value, and that is a constant. It is embedded in our culture and it is my commitment that we conduct all of our business safely and reliably. Executing on our secured capital program and increasing the returns on our existing assets are also key priorities. As I mentioned just a minute ago, we're increasing long-haul volumes on Keystone, and we're also working to increase utilizations on market link. In our Power and Energy Solutions business, we've now finalized contracts for a total of approximately 820 megawatts, that is 580 megawatts of wind and 240 megawatts of solar energy, respectively. This renewable energy will provide the required electricity for the U.S. portion of Keystone to become one of the first net-zero liquids pipelines in North America. It will also supply renewable energy solutions to industrial and then corridor demand that we've been very successful in aggregating. We continue to evaluate the proposals received through our RFI process and expect to finalize additional contracts in 2022. Now year-to-date, we’ve placed $1.6 billion of assets into service and are working towards our goal of sanctioning $5 billion of high-quality, low-risk growth opportunities each year. As Joel will discuss in more detail, we are funding our capital programs prudently to ensure we maintain our financial strength and flexibility. And we're also progressing our ESG commitments. This year, TC Energy joined the UN Global Compact, the world's largest corporate sustainability initiative and the TNFD Forum. We'll continue to identify innovative and viable energy solutions. We are energy problem solvers. And our commitment is to do so safely and sustainably while building on our long track record of delivering superior total shareholder value. Thank you very much. I'll now hand it off to Joel for a few comments on our second quarter results.

Good morning, everyone, and thanks, Francois. As Francois mentioned, our assets continue to deliver strong results in the second quarter, while reliably and safely meeting the growing demand for energy. Comparable earnings for the second quarter were $1 billion or $1 per common share compared to $1 billion or $1.06 per common share in 2021. Comparable EBITDA and comparable funds generated from operations were $2.4 billion and $1.6 billion, respectively, compared to $2.2 billion and $1.8 billion for the same period in '21. Net income to common shares was $889 million or $0.90 per share in the second quarter 2022 compared to net income of $975 million or $1 per share for the same period in 2021. Certain specific items are outlined on the slide and discussed further in our second quarter 2022 report to shareholders. Overall, second quarter comparable EBITDA from our operating segments is up 5% year-over-year, in part driven by a stronger U.S. dollar to $2.4 billion. Mexico Natural Gas Pipelines comparable EBITDA increased primarily due to lower interest expense associated with repayment of our peso-denominated loan with the subsequent issuance of a U.S. dollar-denominated loan, which was entered into on March 15, 2022, at Sur de Texas. Liquids Pipelines comparable EBITDA decreased due to lower contracted volumes in Marketlink partially offset by higher long-haul contracted volumes on the Keystone Pipeline System as we placed approximately 30% of the 2019 open season contracts into service effective April 1, 2022. Liquids marketing achieved higher margins in the 3 months ended June 30, 2022, due to improved arbitrage opportunities compared to the same period in 2021. Natural gas storage EBITDA within the Power and Storage segment increased as a result of the active management of our natural gas positions in the second quarter 2022. By bringing sales forward from fourth quarter into second quarter, the gas storage team was able to capture favorable Alberta spreads and reduce future operating costs. It is worth noting, while we have locked in an overall gain for 2022, we expect the second quarter realized gains to be partially offset in the second half of 2022 as the corresponding purchases are recognized. Power and Storage results were also impacted by positive contributions from Bruce Power, primarily due to higher contract price that was partially offset by lower volumes resulting from greater planned outage days. For all of our businesses with U.S. dollar-denominated income, translational results in the Canadian dollars occurred at an average exchange rate of 1.28 in the second quarter of 2022 compared to 1.23 in 2021. 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 basis of up to 3 years. Interest expense increased primarily due to long-term debt and junior subordinated note issuances, net maturities, a stronger U.S. dollar and higher interest rates on increased levels of short-term borrowings. It is important to note that approximately 85% of our long-term debt has a fixed rate and an average term to maturity of 20 years. Comparable interest income and other decreased primarily due to realized losses on derivatives in the second quarter used to manage our net exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income. We continue to progress our industry-leading $20 billion secured capital program and have placed $1.6 billion of projects into service this year. This program is expected to deliver a weighted average unlevered after-tax IRR of approximately 7% to 9%, which remains in line with our targeted range. Further, our targeted $5 billion of projects sanctioned each year must adhere to our strategic capital allocation threshold. We will not compromise our value proposition. Projects must meet our risk requirements and return preferences, and decisions will be made with per share accretion as a priority. Now we remain opportunity-rich. Our capital program not only focuses on growing our business, but also on modernizing and advancing projects aimed at reducing emissions and offering low-carbon energy solutions. We reiterate our outlook for comparable 2021 through 2026 EBITDA growth of 5%. Importantly, our EBITDA outlook is largely underpinned by long-term take-or-pay contracts or cost of service regulation. Now this visibility at future cash flows continues to position us to grow our dividend per share by 3% to 5% per annum. Now turning to our funding program. As you heard, we are pleased to announce Coastal GasLink LP and LNG Canada have reached revised agreements that address and resolve all outstanding disputes over certain incurred and anticipated cost of the project. Capital costs have increased from the original cost estimates made in 2012 and the revised agreements incorporate a new cost estimate for the Coastal GasLink project of $11.2 billion. In recognition of the revised project agreements with LNG Canada and in accordance with a binding commitment subject to the execution of definitive agreements with our Coastal GasLink LP partners, we will make an equity contribution to Coastal GasLink LP of $1.9 billion, which will be paid in installments commencing in August of 2022 with no resulting change to our 35% ownership. This contribution will be included in recoverable project costs and will earn a return on and of capital. Any additional equity contributions will be initially funded through our amended 2021 interest-bearing subordinated loan agreement between TC Energy and Coastal GasLink LP. Outstanding amounts will be repaid by the Coastal GasLink partners, including us, following in-service and final cost determination. Now I want to reiterate Francois' remarks. We continue to see Coastal GasLink as economically viable and the agreements create a solid foundation and clear path forward for the potential development of Phase 2 that if and when sanctioned could enhance TC Energy's project returns. Importantly, the agreements reached reduce our project financing risk by supporting a $1.6 billion expansion of the existing project level credit facilities to a total of $8.4 billion. Our commitment under the subordinated loan agreement between TC Energy and Coastal GasLink LP will be stepped down from the current $3.8 billion over time as capacity under the project level credit facilities is increased and we make installment payments associated with our equity contribution. Now in terms of 2022 capital spending, we now expect to invest approximately $8.5 billion as a result of increased costs in the NGTL system and our equity contribution associated with Coastal GasLink of approximately $1.3 billion. The graphic illustrates our updated forecasted sources and uses of funds for 2022 through 2024, including these revisions. Now starting in the left column, our total requirements over the 3 years are projected to be approximately $29 billion reflecting capital expenditures, including maintenance capital of $18 billion and dividends of $11 billion. The second column highlights expected internally generated cash flow of $21 billion and proceeds from the USD 800 million hybrid issued in March. This leaves a residual need of approximately $7 billion depicted in the far right column that we expect to fund through a combination of commercial paper, incremental debt, hybrids, the dividend reinvestment plan, asset sales and Keystone XL project recoveries. To continue to prudently fund our capital commitments while maintaining our leverage targets, we have reinstated issuance of common shares from treasury at a 2% discount under our dividend reinvestment plan, commencing with the dividends declared on July 27, 2022. The dividend reinvestment plan is intended to be short-term funding mechanism that we anticipate will be activated for 4 quarters based on historical participation and as we bring additional projects into service. So in summary, we will always utilize the most optimal funding tools to maintain our financial strength and flexibility while delivering per share value. Given the strong year-to-date performance of our base business, we reiterate our 2022 comparable EBITDA outlook to be modestly higher and comparable earnings per share to be generally consistent with last year. We reaffirm our industry-leading capital program of $28 billion is expected to deliver 2021 through 2026 comparable EBITDA growth of 5%. And we have strong visibility to incremental growth that leaves us comfortable with our ability to meet our leverage target of 4.75. Lastly, we expect to grow our dividends by 3% to 5% on with sustainable growth in earnings and cash flow per share and strong coverage ratios. When you combine our enduring business model, unparalleled asset footprint and organizational capabilities, we are differentiated in our potential to capitalize on the opportunity-rich environment before us. Overall, solid execution will allow us to continue to deliver superior long-term shareholder value. That's the end of my prepared remarks, I will now turn the call back over to Gavin for the Q&A.

Yes. Thanks, Joel. So just a reminder before I turn it over to the conference coordinator for questions from the investment community, we ask that we just limit yourself to 2 questions. Thank you.

[Operator Instructions] Our first question comes from Linda Ezergailis of TD Securities.

I'm wondering if you could just give us some more context around the Coastal GasLink updated costs. For the prospective cost, how much have you actually locked in? And have you provided for any sort of additional contingency? Or maybe you can provide some sort of confidence level in your cost estimates?

Yes. Linda, this is Bevin. So as we've mentioned, 70% of the project has already been completed. All the materials that we need to complete the project are on site. We've completed some -- 2 out of the 8 sections are completely solved and finished in terms of mechanical completion, and all our contracting strategies have already been tendered and led. So the confidence that we have in building up our new estimate is high. Inclusive of that estimate of the $11.2 billion is a contingency for what we see as the remaining potential risks in moving forward to conclusion. But we have high confidence that we'll meet our mechanical completion date by the end of 2023. So right now, we sit with a tremendous amount of confidence given that we have a settlement in place with our partners and customers with LNG Canada. And so we're well positioned to deliver on our commitments of the $11.2 billion and end of 2023 mechanical completion.

And just as a follow-on, are you in active discussions with LNG Canada about Phase 2? And what in your mind would be kind of the optimal FID timing to ensure for minimizing any sort of dismantlement and reconstruction of labor camps, et cetera, from -- presumably from a cost savings initiative. Can you provide some context around that?

Yes. So we're in active discussions with LNG Canada around Phase 2 and the feasibility, doing the appropriate front-end work to establish what the scope and scale of that project will be. The project looks very different than Phase 1. It's not a linear development. It is compression facilities. And so that changes the risk profile to our benefit. In terms of the FID timing, that is one where our customers, LNG Canada are in control of determining when they are prepared to bring a final investment decision, and we're supporting them in that evaluation right now. There's a tremendous amount of work that needs to be accomplished, but it's important to do that work today. So we have a high confidence decision in going into that FID.

And just for my second question, more broadly for your capital spend plan. You've identified $18 billion in your funding plan. Is that all up to date with any sort of inflationary pressures or appropriate contingencies? Or might we see some projects potentially embedded in that going up in cost or deferred to the extent you have some discretion around that?

Linda, it's Joel here. So we are up to date with the capital spend that you referred to. You might recall back in Q1, we did revise our cost estimates for the NGTL system expansion projects. So that's where we're really seeing, obviously, most of the cost pressure within the portfolio. We're very encouraged by what we're seeing at Bruce Power. The Unit 6 MCR program is on time and on budget. We're not seeing any inflationary pressure on our capital investment in the United States now, but it's really coming from Alberta, as you well know. It's a huge market here. We've got the CGL project going on. There's Trans Mountain going forward along with, obviously, the expansion of the NGTL. So we don't expect to see any material changes to our cost estimates going forward and what you see is most reflective of our current estimates.

Our next question comes from Ben Pham of BMO.

I wanted to go back to that gray shaded category on your funding program. I'm more specifically curious around with asset sales, how do you think that ranks in that overall gray-shaded area? And is there anything logical that stands out? And is it really appealing to sell assets in this environment when you're looking to reduce debt at the same time?

So Ben, it's Joel here. When we look at our capital program and how we fund it, obviously, we're always trying to look for the optimal capital structure that really minimizes our cost capital, maximizing shareholder value and really meets our leverage targets. Obviously, we're very judicious with our share count. We want to maximize our earnings per share and cash flow per share. So when we look to the financing, it really is an all-of-above strategy. And what you see in that gray box to the extent our balance sheet permits, we do use debt. We do maximize our utilization of hybrids at 15% of our capital structure. And then we look to internal equity, which is joint venture partnering, sale of non-core assets and then obviously, external equity through the dividend reinvestment plan and if needed, discrete equity. So that's kind of the stack that we look at, but we do have a number of non-core assets in the portfolio that we could look to monetize. But again, what we're trying to achieve here is what -- maximize our shareholder value, what is the lowest cost of capital alternative for funding our capital program.

Okay. And then when you updated this funding plan, obviously, you're putting in Coastal GasLink that impact on NGTL. Are you you're thinking about some of the Mexican pipeline developments as well when you think about turning on your DRIP for at least a year?

Ben, I'll start here with regard to the DRIP. As we outlined, the DRIP is really in connection with higher spending that we're seeing on NGTL along with Coastal GasLink. We just deemed to be prudent at this point in time. Obviously, core tenant for us is to preserve our financial strength and financial flexibility, have a strong balance sheet. And therefore, we determined that turning on the DRIP for 4 quarters, and what we're trying to achieve here is about $1.25 billion of common equity based on a 35% historical participation rate at the 2% discount is appropriate to fund our capital program at this point in time.

Okay. So no comment on Mexico then?

I had no comment that I have on Mexico. I will maybe turn it to Stan.

Yes. Ben, this is Stan. I can tell you this much. We've made some very meaningful progress in the negotiations around the definitive agreements with CFE, both with respect to the settlement and the potential project, but we're not done just yet. As you know, we've been in Mexico for over 30 years. We are still very, very much committed to our strategic alliance that we have with the CFE. And I just ask that you give us a little bit more time to close out the negotiations.

So Ben, I would just offer one last comment here that, as I mentioned, you think about what's in that gray box in our funding plan right now that we have a number of levers at our disposal here that if we were to move ahead with a project in Mexico, as I mentioned, again. We are very judicious around our share count and we'll try to find the lowest cost of capital that ultimately maximize shareholder value and really meets our leverage targets. So it is a bit of an all above strategy, not only with our current capital program, but obviously, if anything goes ahead with Mexico.

Our next question comes from Robert Kwan of RBC Capital Markets.

If I can start back on Coastal GasLink and returns. Like, can you talk about how much lower the base returns are relative to the originally anticipated returns, which I think were pretty low to begin with? And then as you think about the potential Phase 2 expansion, has the cost and return framework being codified as part of your new agreement? And if there's no further liquefaction expansion, is there a mechanism in the current agreement to improve the returns on CGL? Or are you just -- and if not, you're just kind of sitting here with the low returns?

So Robert, this is Bevin. So Phase 1 clearly didn't achieve its initial return objectives. But as we indicated, coming to a settlement puts the project in the best position to move forward. And primarily, our priority was to ensure the total competitiveness to support the project and support the ongoing Phase 2 development that would subsequently follow if LNGC chooses to FID. Our returns are not linked between Phase 1 and Phase 2. The terms of our settlement are confidential. But we're confident that the return profile that would exist in Phase 2, which is well advanced in our discussions with LNG Canada as well as our settlement delivers a strong project for our shareholders.

Okay. So does Phase 2 get you back to where you originally anticipated?

Phase 2 has the same – brings -- the combination of Phase 1 and Phase 2, brings us back into a very competitive return scenario for the entire project.

Okay. If I can just finish here then on funding and specifically the DRIP. You've talked about being judicious with your share count. And so can you just talk about the decision to turn the DRIP on as the most optimal funding tool versus, say, the asset monetizations? And while you stated you'll leave it on for a year, if you have very similar current -- or the current market conditions persist, does the calculus to turn on the DRIP now mean that you see DRIP or equities being the best source of funding if you're able to add things like Mexico or other projects to the portfolio?

Yes, Robert, it's Joel here. First of all, what we're really looking at here with the additional increases that we're experiencing on NGTL and Coastal, this is over kind of a tight period of time. We're talking really 2023 where we saw our metrics being a little bit elevated based on our internal forecast. And we saw that turning on the DRIP for 4 quarters was really important for us. What we like with DRIP is that it is really shaped nicely with the capital spend profile. When we look at DRIP relative to discrete equity, it's much cheaper than a 2% discount versus an all-in discount of, say, 7% to 8% that you would see on discrete equity. And obviously, we have the ability to turn off quarterly. As we move forward here, and we see maybe further expansion of our capital program, obviously, we'll look to, again, non-core assets that we can monetize. And again, we evaluate that against other forms of capital, so as again, to maximize shareholder value and really manage our leverage. But again, I just want to reiterate that we're looking really at 2023 and to get our leverage down to where we're comfortable with. This is a quick way of getting there on a very cost-effective basis and again, really well shaped with our capital spend profile.

Our next question comes from Robert Catellier of CIBC Capital Markets.

First of all, congratulations on getting the Coastal GasLink deal finalized. I know that was a priority for both you and the industry, could not have been easy. I wondered if you could speak more to -- any changes to the revised agreement that mitigate risk. I think you mentioned that in the opening comments. So what specific changes can you tell us about that mitigate your risk going forward?

Well, Rob, thanks for the question, and I appreciate the acknowledgment of getting to the settlement. We -- it was a good long discussion with our customers, and we reached a really good outcome. The key mitigation components are transparency and clarity of how we resolve matters going forward. Accelerated dispute mechanisms, ensuring that we maintain proper alignment through the final delivery of the project, which gives us high confidence in transparency, not only to us, but our equity partners and also our indigenous partners that provides them clarity on the path forward as well. So the mitigations are just increased in alignment, more transparency in the process of how we deal with challenges or changes in the project going forward and just a strong alignment between ourselves and our customer, LNG Canada. François Poirier: And then I would add, it's Francois, Robert, that in the absence of a settlement, we would be carrying on our balance sheet -- a fairly sizable amount of capital. Achieving the settlement allows us to upsize the credit facility and not have to carry a substantial amount of capital for what could ultimately have been many years into the future.

Okay. And just as you pointed out, the U.S. has become the largest LNG exporter in the first half of the year. Can you provide a little bit more color on some of the ways we're going about addressing not the projects that you've listed, but projects that might be available to the industry in the future? Is it simply just a question of leveraging your existing transmission network to continue to participate? Or is there some way that you could benefit from enhancing what you already have through M&A or other asset acquisitions?

So Robert, this is Stan. I can start and tell you that our unparalleled asset footprint is what the basis is of my statements in the past around -- given the size and the breadth of these assets, we should be originating about $1 billion a year of new growth products, and LNG is right at the forefront of that. And it really is more driven by organic growth. And I look at it from this perspective, given the geopolitical events right now, Europe needs to find about 20 Bcf a day of natural gas to displace what they have historically relied on or Russian supplies. Assuming about 2/3 of that comes from the U.S., that's an increment of about 13 Bcf out of the U.S., predominantly from the Gulf Coast. Today, we transport about 25% of the LNG in the U.S. And I expect us to at least maintain, if not grow that market share going forward. So you can think of us having an opportunity set over the next 2 to 3 years, that's somewhere in the 3 to 4 Bcf a day range. I can't get into details now due to the market sensitive nature. But suffice it to say that we're well aware of these opportunities with respect to LNG growth and LNG demand, and are actively engaged with various counterparties for offerings that really leverage our competitive advantage, which is our footprint. Not only in the Gulf Coast in Louisiana, but also in other parts of the country like our North Baja system and opportunities in Costa Azul.

Our next question comes from Jeremy Tonet of JPMorgan.

Just want to look at Mexico a little bit more, if I could here. As it relates to the VdRdelay, just wondering what line of sight do you have to the completion on the time line that you said in early '23 there. Would you move forward with another Mexico project before you reach full completion on VdR? François Poirier: Jeremy, I'll start. And of course, Stan and I have been in deep conversations about these questions for some time, so I'll ask him to supplement with what we're seeing specifically on Villa de Reyes. And as I've said publicly in the past, we've been in Mexico for 30 years. We have a very positive and constructive relationship with the CFE. From the perspective of allocating incremental capital into the country, we do feel it's critical to resolve any remaining contractual disagreements ahead or simultaneous with any incremental capital decisions. So that would be the way we would think about it. And Stan, over to you.

Yes, Jeremy, this is Stan. We're -- as you know, we've already put into service or ready for service, I should say, both the north and the lateral segment for the Villa de Reyes project. And right now, we're focusing intensely on the Southern segment, which -- if we can get some issues resolved, some of the hetos would be ready for service probably sometime in early 2023.

Got it. That's helpful. And just coming back, if there is a large Mexico pipeline project approved later this year, early next year. And if that pushes CapEx over $5 billion a year in 2023 or later, how should we think about the timing of incremental portfolio rotation or equity issuance should the CapEx rise in that fashion?

So Jeremy, it's Joel here. As I mentioned earlier, like anything that we do when we evaluate capital investment, in particular, when we're over that $5 billion threshold that you've indicated, we try to find the optimal capital so that really minimizes our cost of capital. Again, thinking about being very judicious around our share count and to maximize our earnings per share and cash flow per share. So as mentioned, it really is an all-of-above strategy. Again, to the extent that we can use that, we will, to the extent that any capital project comes with a hybrid capacity, we will use that. We will then look to internal equity with partnering, sale of assets. And if need be external equity with the DRIP and discrete equity. So again, it's an all-of-the-above strategy. We make that determination at that point in time when we're making the investment decision as to what's the best path forward here as it relates to our cost to capital.

Our next question comes from Matt Taylor of Tudor, Pickering, Holt & Co.

A bit of a longer-dated one. In your targeted EBITDA growth of 5% through 2026, I just wanted to get a sense of how you're factoring in the rising cost of carbon. Obviously, you have plans to reduce the emission profile using whether it's renewable power on Keystone or more pump storage. What about those emissions that need to be reduced if there's not a disclosed plan in place? I guess what I'm getting at is as the government, over time, increases those costs of carbon, are you currently including some of the costs of that rising carbon as you're trying to offset it, whether it's using offsets or other projects? Or how are you triangulating to your emissions reduction targets longer term? François Poirier: Thanks for the question, Matt. We are absolutely factoring cost of offsets or mitigations, and those are incorporated in our EBITDA growth outlook. As a matter of fact, that dynamic is going to be a driver of future growth going forward because it's embedded in our strategy, is actually reducing our emissions and helping our customers reduce their emissions, which is why we continue to be opportunity rich. Emission reductions is going to be a catalyst for growth for the company. Look, in various jurisdictions, we have the ability to pass through those costs. And in others, we need to find a way to mitigate for our own account. All of those are factored into the growth estimate that we provided to the extent they are visible and been passed into law.

Excellent. And then one more, if I may. Just we've heard several times about potential opportunity in Mexico. But can you just speak more high level on Mexico. We've seen LNG projects that are you're picking up steam, some floating LNG, just a general sense of how you're viewing that market. You've been there a long time obviously, any comment with the backbone infrastructure there. Would this be good time to crystallize value? Or do you see some of those opportunities in terms of some things we've heard about previously about helping the industrial power stack transition over to gas and some of those opportunities longer term? François Poirier: I'll start at a very high level in terms of what I see as government policy and support for gas transmission, and then I'll ask Stan to provide some color around some of the things that we are seeing. I think the government in Mexico and the CFE is learning and developments over the last few years indicate that they realized gas transmission is an enabler and supporter of CFE's ambitions to lower power costs and to address social and economic disparity between different regions of the country. So in short, increasing access to natural gas around the country is a very powerful socioeconomic tool for the country, and they see partnership with the private sector in Gas Transmission as an essential tool to operationalize policy. Over to you, Stan.

Yes. Matt, this is Stan. From my perspective, again, this goes back to our asset footprint in Mexico, and we currently deliver about 15% of the gas that's transported today, along with strong demand, strong demand in the context of Mexican imports from the U.S. are going to increase from 8 Bcf to 12 Bcf over the next years. So that tells me a couple of different things. One, there's going to be the need for greater capacity into Mexico, which could be an opportunity for us to expand our Sur De Texas pipeline at some point in time, which could be done relatively efficiently with compression. We're going to focus extensively on building out our backbone system across the central part of Mexico, particularly as power loads and industrial load growth continues to materialize. And then lastly, you brought up the opportunity around LNG, particularly on the West Coast of Mexico, perhaps tied to the transition go efforts that the Mexican government is advancing. But right now, at least for the short term, our focus is on the potential project opportunity we have with the CFE in closing out those negotiations.

Our next question comes from Brian Reynolds of UBS.

Just curious as a follow-up on some of the capital allocation questions. If you could give a comment about how management is thinking about a potential suspension of dividend growth over the near term as one of the levers to support the balance sheet over the long term? François Poirier: I'll take that one, Brian. That is not in the cards. Plain and simple. We are confident in our ability to grow EBITDA at that 5% range and to have earnings per share and cash flow per share growth -- underlying growth that support a dividend growth in the 3% to 5% range, as well as lowering our leverage to the 4.75 level in that 5-year window. So we're able to balance all of those various interests. Maintain our capital discipline, maintain our priority of deleveraging as well as delivering a stable and growing return to our shareholders. So there's no plans to moderate dividend growth given the richness of the opportunities that are before us.

Great. And as a follow-up, you talked about asset sales as another lever earlier. Curious if you could provide some additional color into what those non-core assets probably look like. And then just given the resolution around Coastal GasLink, what is the interest of First Nations to join in on the project at this time during Phase 1? Or is it fair to assume that they'd like to see increased returns from CGL expansion before ultimately participating in their equity interest?

So Brian, it's Joel here. We're not going to specifically call out what assets that we're looking at. But what we can tell you is when we look across our footprint, that there are a number of assets, maybe smaller nature, but that are non-core that we could look to monetize over time if need be. But at this point in time, we're not going to call out anything that we're looking at as far as portfolio management goes.

And this is Bevin. On the First Nations, the terms of their option agreements are not affected by the settlement, and their participation in the project remains at 10% as per the original deal. So there are no changes for the indigenous option agreements, but the settlement does provide clarity and a path forward for them.

Our next question comes from Praneeth Satish of Wells Fargo.

So at a high level, you're looking at asset sales and DRIP to help fund the current CapEx backlog, and you're still juggling some larger projects like Mexico pipeline, pump hydro, among others. I guess my question is not on funding, but is there any thought to try and seek a higher return on the future projects that you do FID, I guess, higher than the 7% to 9% corporate return basically to kind of match the fact that your cost of funding -- your cost of incremental funding might be starting to creep higher. François Poirier: Because we're opportunity rich, we have lots of options before us. One of the critical capabilities that we bring as a company is capital discipline and the opportunity to high-grade to the highest returning projects. You didn't mention risk in your question, but I'm going to. That risk return relationship is very important. Our historic risk preferences are unchanged, and we're confident in our ability to bring projects forward with a low-risk profile underpinned either by long-term contracts or regulation that deliver that 7% to 9% unlevered after-tax IRR. To the extent we're looking at incremental capital beyond our $5 billion run rate that's affordable with free cash flow, you have to look at the marginal cost of capital to fund those. And our job as a management is to maximize the spread between earned return and that -- in that case, the marginal cost of capital, which may include asset sales or equity, which is at the highest cost end of that stack. And our calculus is that there must be a reasonable spread between the earned return and that cost of capital to make that capital allocation decision. But again, risk and managing to a conservative risk profile and not changing our value proposition is always top of mind for us.

And just switch -- sorry, did you want to continue? François Poirier: No.

Okay. Just switching gears. Just curious if there's an update on the potential Bison project in the Bakken. I think you launched an open season. Just curious how that's progressing. I know there's been some weather-related disruptions in the Bakken. So I'm not sure if that's impact to anything.

Yes. This is Stan. And again, go back to our best-in-class footprint and this opportunity-rich environment that we have here. These supply push projects are just another opportunity for growth for us. We did have a nonbinding open season that closed in May. We were very pleased with the results of that open season. And suffice it to say that we're going to take the second half of this year to turn those negotiations into precedent agreements and look forward to sharing more with you in coming weeks and months.

Our next question comes from Matthew Weekes of iA Capital Markets.

I just wanted to quickly ask if you had any update on the open season that you talked about last quarter for Marketlink and looking to increase volumes there a little bit? And what the outlook might be sort of going forward here?

Matthew, thank you. This is Bevin. We ran 2 open seasons in the past quarter, certainly Marketlink, but also for our Port Neches lateral, both were successful in completing that, getting contracts in place. Our strategy is to -- as the contracts have been rolling off on Marketlink was to reestablish both short- and long-term contract profiles, cognizant of the volatility that's in the market right now and some of the headwinds that we're facing at least currently in the short term. But our mid- to long-term outlook is at the Marketlink asset will return to perform going from a headwind situation to kind of tailwinds. And so with the Port Neches link open season that couples with project, which is coming in under budget and ahead of schedule with enhancing deliveries into Motiva refinery, which is the largest refinery in North America. So providing increased delivery points to our customers has been a key component of our strategy. So both of those open seasons were very successful.

Our next question is a follow-up from Rob Hope at Scotiabank.

Just want to circle back on the Mexican project. So when you take a look at the relatively full CapEx backlog you have relative to the -- what we'll classify as attractive risk-adjusted returns, how do you think about adding a partner there, which will lessen some upside but make the project easier to finance if it is to move forward, similar to what's happening at Sur de Texas. François Poirier: Rob, it's Francois. Thanks for the question. It is in the context of our views on how much Mexico EBITDA we want in the consolidated portfolio, we think of 10%-ish contribution to consolidated EBITDA from Mexico as an appropriate near- to medium-term target for the company. And it's just prudent portfolio management and sharing diversification, et cetera. So certainly, to the extent we see attractive opportunities to earn a premium return, to the extent bringing in a potential partner for a portion of that helps us prosecute and make the value of the entire franchise more valuable, we'll certainly consider that. And so the short answer is potential for selling a minority interest down the road is something that we would be open to, but it's, again, more within the context of prudent portfolio management and proper diversification.

All right. I appreciate that. And then just as we take a look at 2023, any flex in the capital plan just to help state by this, we'll call it, tightness on the balance sheet. Could we see you less willing to invest money in some of the renewable projects towards the end of the year? Or could we see some deferred capital from '23 into '24, if possible? François Poirier: I think there's somewhat limited opportunity for us to defer capital as you can well imagine, it sometimes takes 2 or 3 years from the time we sanction a project to receiving regulatory approvals and permits. We've made commitments to contractors. We've ordered long lead equipment. And so deferring spend can be a bit challenging. Our view is if a project is accretive to value, we can be creative around rotating capital. We can be creative around bringing in partners to be able to deliver long-term value for our shareholders. And more likely that you would see us doing that rather than deferring near-term capital projects.

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 back over to François Poirier. Please go ahead, Mr. Poirier. François Poirier: Thank you very much. Appreciate everyone's time and attention today. I just want to remind everybody, capital discipline, discipline around our risk profile and deleveraging our key priorities for our company. We are opportunity rich. Energy transition is going to continue to be a catalyst for growth. Our incumbency through our unparalleled asset footprint is going to continue to bring us a very healthy flow of opportunities. And we have high-quality franchises that will bring that forward. So -- we're well positioned to prosper regardless of the pace and direction of energy transition, and we will always balance growth, risk and maintaining balance sheet strength. Thanks very much for your attention today.

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