Thank you for standing by. This is the conference operator. Welcome to the TC Energy Second Quarter 2021 Results Conference Call. As a reminder, all participants are in listen-only mode, and the conference is being recorded. After the presentation, there will be an opportunity to ask questions. To join the question queue, you may press star then one on your telephone keypad. Should you need assistance during the conference call, you may signal an operator by pressing star and zero. I would now like to turn the conference over to David Moneta, Vice President, Investor Relations. Please go ahead. Thanks very much, and good morning, everyone. I'd like to welcome you to TC Energy's 2021 2nd quarter conference call. Joining me today are François Poirier, President and Chief Executive Officer, Don Marchand, Executive Vice President and Chief Financial Officer, Tracy Robinson, President, Canadian Natural Gas Pipelines and President, Coastal GasLink, Stan Chapman, President, U.S. and Mexico Natural Gas Pipelines, Bevin Wirzba, Executive Vice President, Strategy and Corporate Development and President, Liquids Pipelines, Corey Hessen, President, Power and Storage, and Glenn Menuz, Vice President and Controller. François and Don will begin today with some opening 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. It can be found in the investors section under events and presentations. Following their remarks, we will take questions from the investment community. If you are a member of the media, please contact Jaimie Harding after this call. In order to provide everyone from the investment community with an equal opportunity to participate, we ask that you limit yourself to two questions. If you have additional questions, please re-enter the queue. 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'll refer to measures such as comparable earnings, comparable earnings per 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 François. Thanks, David, good morning, everyone. I know it's a busy morning with lots of companies reporting, thank you very much to all of you for joining us today. As outlined in our second quarter report to shareholders, our diversified portfolio of high-quality, long-life energy infrastructure assets continue to meet North America's growing demand for energy. Utilization levels across our network remained strong during this first half of 2021, that despite energy market volatility, weather events, and the ongoing impacts of COVID-19. Of note, our U.S. natural gas pipeline network moved an average of 26 BCF per day, an increase of 5% over the same period in 2020, while field receipts on NGTL were 12.2 BCF per day. In our power and storage business, Bruce Power continued to produce solid operating results, while our Alberta cogens benefited from increased output due to increased availability and the return to service of our MacKay River facility. Once again, this highlights the essential role our infrastructure plays in the well-being of people across the continent and the functioning of the North American economy. We take this responsibility seriously, and as always, we conducted our business in a safe and reliable manner. Safety is one of our core values and is embedded in the culture of our organization. During the first half of the year, we invested CAD 765 million in maintenance capital as part of our ongoing commitment to pipeline integrity. Our focus on operational excellence and the strong demand for our services is also reflected in our financial performance. Through the first six months of the year, comparable EBITDA, comparable earnings per share, and comparable funds generated from operations all exceeded last year's record results. This is a very good outcome considering the significant decline in the value of the U.S. dollar relative to the Canadian dollar, which negatively impacts our reported EBITDA, as well as the loss of one-time Sur de Texas fees in the first quarter of 2020 and the loss of capitalized interest during construction of KXL. Looking forward, we expect the solid operating and financial performance of our existing assets to continue. Contributing to our performance is Columbia Gas, which recently notified the FERC that it has reached a settlement in principle with its customers, addressing all remaining issues related to its Section 4 rate case. We're very pleased that we were able to reach an agreement. While more details will be available once the settlement is filed, we expect 2021 revenue on the system to be generally consistent with the estimates recorded to date. Turning to our capital program, where we remain focused on advancing our now CAD 21 billion of secured growth projects that are expected to enter service by 2025. As is our custom, they are all underpinned by cost of service regulation or long-term contracts, which gives us visibility to the earnings and cash flow they will generate. A substantial portion of this growth portfolio is linked to our irreplaceable natural gas pipeline network, which now includes the VR project on our Columbia Gas system. This $700 million project, referenced earlier today in our quarterly report, includes the installation of electric compression that will meet growing demand and reduce emissions. This is another great example of our vast network playing an important role in the transition to a lower carbon world by delivering natural gas that will be used to displace coal-fired power and provide a backstop to the intermittency of renewables. Now, a few words on Coastal GasLink. Following the macro events of the past 16 months, including the public health order that limited our project workforce at the beginning of 2021, construction activities have resumed, and we are making good progress with close to 50% of the project completed. However, as we've shared previously, costs are expected to increase, and that has resulted in a dispute with LNG Canada. While commercial discussions are ongoing and we remain committed to successfully completing the project, we are nearing a critical stage that requires resolution of the outstanding issues. Looking beyond our secured capital program, over the mid to longer term, we expect numerous other opportunities to come to fruition as the world both consumes more energy and transitions to a lower carbon energy future. We have significant additional initiatives that are aligned with our strategy, organizational capabilities, risk preferences, and return requirements in various stages of development. These include system expansions, extensions, and modernization programs across our North American natural gas pipeline footprint, electrification opportunities throughout our network, the refurbishment of another five reactors at Bruce Power, two pump storage projects in Alberta and Ontario, as well as the Alberta Carbon Grid. Now, our goal is to build on our long history of disciplined growth while being agnostic to the form of energy that will ultimately lead to a lower carbon energy future. Whether it's renewables and firming resources needed to manage their intermittency, electrifying our fleet, or other emerging technologies, our existing asset base, technical capabilities, innovative approach, and financial strength all mean that we are well-positioned to prosper irrespective of the pace or direction energy transition takes. As I've mentioned before, ultimately, our goal is to sanction CAD 5 billion-CAD 6 billion annually to deliver on our long-term growth plans, including CAD 1.5 billion-CAD 2 billion per year of maintenance capital across our extensive network. Based on the project sanction to date in 2021 and various other initiatives in late stages of development, we expect to achieve our goal this year. More specifically, in addition to the Columbia's VR Project and ongoing maintenance on our regulated businesses, we expect a continuation of Columbia Gas' modernization program, as well as the Bruce Power Unit 3 MCR project, which is under consideration to be added to our backlog by the end of this year. Through requests for information, we are identifying potential opportunities in wind, solar, and energy storage projects that could generate 1,000 MW of zero-carbon energy to meet the electricity needs for a portion of our U.S. pipeline assets. This is an important step in advancing our plans to leverage the power and storage business as a platform for sustainable future growth while lowering emissions across our North American footprint. Longer-term, the opportunity set is also encouraging. We are engaging with various stakeholders in Ontario to advance the Meaford pump storage opportunity. The project is designed to store emission-free electricity and provide backstop to the intermittency associated with the energy provided by renewables. Earlier this week, we reached an agreement with the Department of National Defence that, subject to conditions and regulatory approval, allows for the development of the multibillion-dollar 1,000 MW clean energy storage project on federal lands. Moving forward, we will continue to consult with the Saugeen Ojibway Nation and other indigenous rights holders and communities, and we will engage with local communities and other interested stakeholders to assess the potential impacts and economic benefits of the project. Finally, we recently announced a partnership with Pembina to jointly develop the Alberta Carbon Grid, a carbon transportation and sequestration system. When fully constructed, it would be capable of transporting more than 20 million tons of CO2 annually, providing Alberta-based industries with an ability to manage their emissions and contribute to a lower carbon economy. In short, I expect we will be opportunity-rich and have to allocate capital to those projects that are best aligned with our capabilities, risk preferences, and return requirements. Based on the continued strong performance of our base business and our organic growth plans, we expect to continue to grow our dividend at an average annual rate of 5%-7%. As always, the growth in dividends is expected to be supported by sustainable growth in earnings and cash flow per share and strong coverage ratios. I am confident that the future opportunity set, combined with our capabilities, will continue to deliver superior risk-adjusted total shareholder returns well into the future. I'll now turn the call over to Don, who will provide more details on our second quarter financial results. Don? Thanks, François, good morning, everyone. As outlined in our results issued earlier today, net income attributable to common shares was CAD 982 million or CAD 1 per share in the second quarter of 2021, compared to CAD 1.3 billion or CAD 1.36 per share for the same period in 2020. Second quarter results included a combined CAD 18 million of after-tax charges associated with Keystone XL preservation and other costs, along with a small net revision to the asset impairment taken in quarter one, as well as a CAD 13 million after-tax recovery associated with the Ontario gas-fired power plant sold in 2020. The corresponding period in 2020 also included certain specific items, as outlined on the slide and discussed further in our second quarter 2021 report. These specific items, as well as unrealized gains and losses from changes in risk management activities, are excluded from comparable earnings. Comparable earnings for the second quarter were CAD 1 billion or CAD 1.07 per common share, compared to CAD 863 million or CAD 0.92 per common share in 2020. Turning to our business segment results on slide 10. In the second quarter, comparable EBITDA from our five operating segments of CAD 2.2 billion was similar to 2020, despite strong currency translation headwinds. Canadian Gas Pipelines comparable EBITDA of CAD 684 million was CAD 63 million higher than second quarter 2020, primarily on account of increased rate base earnings as well as higher flow-through depreciation and income taxes on the NGTL System, Coastal GasLink development fee revenue, which commenced in mid-second quarter 2020, and a modest net increase in the Canadian Mainline. NGTL System net income rose CAD 16 million year-over-year, mainly due to a higher average investment base resulting from continued system expansions and reflects an ROE of 10.1% on 40% deemed common equity. Net income for the Canadian Mainline increased CAD 14 million, largely due to higher incentive earnings and the elimination of a CAD 20 million after-tax annual TC Energy contribution included in the previous NEB 2014 decision. The U.S. Gas Pipelines comparable EBITDA of $717 million in the second quarter was higher by $122 million compared to 2020. This was driven by a net increase in earnings from Columbia Gas following its application for higher transportation rates effective February 1, 2021, subject to refund upon completion of the rate proceeding, along with greater capitalized pipeline integrity costs in 2021 compared to 2020, partially offset by higher property taxes. Yesterday, Columbia notified FERC that it had reached a settlement in principle with its customers. While definitive terms are still being finalized, 2021 revenue is expected to be generally consistent with estimates recorded to date. In addition, earnings across our U.S. Gas Pipelines were generally higher following the cold weather events of first quarter 2021, which impacted many of the U.S. markets we serve. Mexico Gas Pipelines comparable EBITDA of $134 million rose $4 million versus last year, primarily as a result of increased earnings on Guadalajara following the implementation of a flow reversal completed in 2020. Liquids Pipelines comparable EBITDA declined by CAD 66 million- CAD 366 million in the second quarter due to lower volumes on Keystone, partially offset by increased contributions from liquids marketing activities, mainly attributable to higher margins and volumes. Power and Storage comparable EBITDA in the second quarter rose by CAD 22 million, primarily due to increased Bruce Power results, driven by higher volumes resulting from fewer outage days and a higher contract price, partially offset by increased operating expenses. Natural Gas Storage and other also contributed to the increase as a result of our November 2020 acquisition of the remaining 50% ownership interest in TC Turbines and higher realized Alberta natural gas storage spreads. For all our businesses with US dollar-denominated income, including US and Mexico Natural Gas Pipelines and parts of Liquids Pipelines, EBITDA was translated into Canadian dollars using an average exchange rate of CAD 123 in second quarter 2021, compared to CAD 139 for the same period in 2020. While overall U.S. dollar-denominated comparable EBITDA increased by $105 million, the year-over-year weakening of the currency was a considerable drag on comparative 2021 Canadian dollar-reported EBITDA. That said, the corresponding impact on comparable earnings was not significant due to offsetting natural and economic hedges. As a result, our U.S. dollar-denominated revenue streams are, in part, naturally hedged by U.S. dollar-denominated amounts below comparable EBITDA within depreciation and amortization, interest expense, and other income statement line items. We actively manage the residual exposure on a rolling two-year forward basis. With realized gains and losses on this program reflected in comparable interest income and other. Turning to the other income statement items on slide 11. Depreciation and amortization of CAD 633 million was in line with second quarter 2020. Interest expense of CAD 577 million was CAD 16 million higher year-over-year, largely due to the net effect of lower capitalized interest due to its cessation for the Keystone XL Pipeline project, the change to equity accounting for our Coastal GasLink investment in second quarter 2020, long-term debt issuances net of maturities, lower interest rates on reduced levels of short-term borrowings, and the foreign exchange impact from a weaker U.S. dollar on translation of U.S. dollar-denominated interest. AFUDC decreased CAD 17 million compared to the same period in 2020, principally due to the suspension of recording it on Villa de Reyes effective January 1 of this year, partially offset by increased capital expenditures on ANR and a higher balance of NGTL System expansion projects under construction. Comparable interest income and other rose CAD 151 million in the Q2, mainly due to realized gains in 2021 compared to realized losses in 2020 on derivatives used to manage our net exposure to foreign exchange rate movements on U.S. dollar-denominated income. Income tax expense included in comparable earnings was CAD 175 million in Q2 2021, compared to CAD 125 million for the same period last year, with the CAD 50 million increase mainly due to higher flow-through income taxes on Canadian rate regulated pipelines and increased earnings, partially offset by higher foreign income tax rate differentials. Excluding Canadian rate regulated pipelines, where income taxes are a flow-through item and thus quite variable, along with equity AFUDC income in U.S. gas pipelines, we continue to expect our 2021 full-year effective tax rate to be in the mid to high teens. Comparable net income attributable to non-controlling interests of CAD 6 million decreased by CAD 57 million relative to the same period last year, primarily as a result of the March 3rd, 2021 buy-in of TC PipeLines, LP. Finally, preferred share dividends of CAD 32 million were CAD 8 million lower than 2Q 2020, mainly due to the redemption of Series 13 preferred shares on May 31st, 2021. Now turning to slide 12. During Q2, comparable funds generated from operations totaled CAD 1.8 billion, and we invested CAD 1.4 billion in our capital program. As noted, at the end of May, we redeemed all of our issued and outstanding Series 13 preferred shares using proceeds from our junior subordinated debt offering completed in March 2021. In June, we completed a three-tranche offering of MTNs in Canada, comprised of CAD 750 million of three-year floating rate notes, CAD 500 million of 10-year notes at 2.97%, and CAD 250 million of 26-year notes at 4.33%. Also in June, the U.S. $840 million outstanding on the Keystone XL project level credit facility consolidated on our balance sheet was fully repaid by the government of Alberta under the terms of their guarantee and the facility terminated. We also repurchased their ownership interest in KXL and issued securities entitling the government to certain project liquidation proceeds as realized. Collectively, this resulted in an after-tax net recovery of approximately CAD 1.1 billion being recognized, which was credited directly to equity and serves to partially offset the CAD 2.2 billion after-tax impairment charge recorded in the first quarter. Now turning to slide 13. This graphic illustrates our forecasted sources and uses of funds for 2021 through 2023. Starting in the left column, our total requirements over the three years are projected to be approximately CAD 29.5 billion, reflecting dividends of CAD 11 billion, capital expenditures including maintenance capital of CAD 16 billion, CAD 2 billion attributed to the TC PipeLines, LP acquisition completed in March, and the Series 13 preferred share redemption of CAD 500 million in May. The second column highlights expected internally generated cash flow of CAD 21 billion, CAD 2 billion of common shares issued pursuant to the TC PipeLines, LP buy-in, CAD 1.5 billion of MTNs issued in June, and the CAD 500 million junior subordinated notes offering completed in March. That leaves a residual need of approximately CAD 4.5 billion depicted in the far right column, and we expect to fund that through a combination of incremental debt, commercial paper, and Keystone XL project recoveries. The program excludes the normal course refinancing of scheduled debt maturities and is consistent with our goal of maintaining debt to EBITDA in the high 4s and FFO to debt of 15%. Turning to slide 14. In closing, our solid operational and financial results once again highlight our resilient, diversified, low-risk portfolio, the criticality of our irreplaceable infrastructure, as well as the contribution of new high-quality assets from our ongoing capital program. With our enduring business model, financial strength, organizational capabilities, and unparalleled footprint, we are poised to tap a vast opportunity set that is thematically aligned with both today's needs and the world's shifting energy mix, as well as being consistent with our longstanding risk preferences and return requirements. This is expected to perpetuate our multi-decade track record of prudent value creation and support annual dividend growth of 5%-7% into the future. That's the end of my prepared remarks. I'll now turn the call back over to David for the Q&A. Thanks, Don. 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 two questions. If you have additional questions, please re-enter the queue. With that, I'll turn it over to the conference coordinator. Thank you. We will now begin the question and answer session. To join the question queue, you may press star then one on your telephone keypad. You will hear a tone acknowledging your request. If you are using a speakerphone, please pick up your handset before pressing any keys. To withdraw your question, please press star then two. We will pause for a moment as callers join the queue. Our first question comes from Robert Kwan of RBC Capital Markets. Please go ahead. Great. Good morning. My first question relates to the VR project, more so taking a step back. You've got $700 million for this is just Columbia. Have you looked at how big these types of opportunities could be across your entire system? What was the trigger for this going forward? Was it really more so about the capacity expansion? Are you seeing from your shippers a real demand to electrify the system so they can reduce their Scope 2 emissions? Hey, Robert. This is Stan. I could take a stab at that. I would say it's really multi-factored. There is incremental volumes and an incremental need in this particular project. At the same point in time, focusing on our emissions and reducing our emissions while we're providing additional throughput to our customers is something that's important to us. We think that we can do that not only by installing electric compression across our system, but also doing it in conjunction with Corey's team and making sure that he's providing the power and most likely green power at the end of the day. In terms of how big this could be going forward, it is part of our overall drive to reduce our emissions footprint both across the country and the continent. We have 13 pipelines that we own or operate here in the U.S. My expectation is, in any given year, on any given pipeline, we can have one or two of these projects. That's what we're going to challenge ourselves to be successful in reducing emissions going forward. Okay. Just sorry, when you say one or two of these projects, you're talking about an announcement, so something in that $700 million range? Again, the dollar amount is going to fluctuate depending upon the specifics of the case. I think the expectation would be one or two projects per year over the next several years. What pipeline that's on is going to be determinative of many things, including where the additional load's going to come from, where we have the best opportunity to add electric compression with respect to proximity to poles and wires and the like. Okay, that's great. Just on the second question here, for the Coastal GasLink dispute, can you just talk a little bit more or elaborate on the nature and the scope and maybe more importantly to you, is there anything in the sell-down agreement where there could be a clawback of the proceeds you've received? Good morning. It's Tracy here. I'll take that one. I know that there's likely to be a number of questions on the dispute status of the project and what the potential impact may be. Let me say this, we are in a disagreement with LNG Canada over the alignment of cost and schedule. We've been in discussions for some time now. Those discussions do continue. They are confidential. We do have our equity partners involved. We want to continue construction, and we do remain, I think, very hopeful that we'll have a fair and reasonable outcome. At that point in time, we'll be able to share a few more of the details that you mentioned. Okay. That's great. That's all I have. Don, hopefully you're happy to get this last one out of the way, and I let you off easy. Oh, Robert, thanks. No, this is the highlight of the week again here. Thanks, Robert. Great. Thanks. Okay. Our next question comes from Linda Ezergailis of TD Securities. Please go ahead. Thank you. Before I ask my question, I want to wish Don all the best in his retirement and a big congratulations for a very successful career. Thanks, Linda. In terms of the Ontario pump storage project, some developments recently on that front. Can you talk a little bit about the steps and timeline and what sort of commercial attributes and ownership you would be looking for, and as well as how it might be financed from a capitalization exploration as well? Hi, Linda. This is Corey Hessen. A couple things. Number one, we're very pleased that we were able to reach an agreement recently with the DND on the first step to gaining site access. We have some technical steps that we'll follow here in the coming months in order to meet their needs to ensure that the site remains operational for the DND. In parallel with that happening, we will be working with our counterparties to secure the commercial underpinnings for this particular facility. We're really running a two-pronged approach for the next coming months as we continue the development of this project. As we go forward, we'll be working collaboratively as well with our partners, local stakeholders and Dasan, who are all active participants in the process. As far as your question was concerned regarding the capital structure, it's a little early days for us to have thought through that entirely. We have to understand more clearly what the commercial underpinnings will be, and once we understand that more clearly, we'll be able to work diligently with our external partners to figure out a structure that works for everyone involved. Yeah. Linda, it's Don. I'll just supplement Corey's remarks on the financing. Again, early days, but we can see First Nation ownership here. This is the project, whether it's finance the project level or up above here would lend itself to green bond financing, and there were significant tax benefits introduced in the most recent Canadian federal budget. That will all have to be taken into account as we figure out where and how to finance this. Thank you. As a follow-on question, given all the opportunities you're facing in terms of energy transition and beyond considering your earnings and cash flow growth, which should support the 5%-7% dividend growth, I'm just wondering how other considerations might factor into the cadence of dividend growth potentially shifting over time, including if there's tax changes, investor preferences might change, et cetera? Linda, I'll take that one. Our goal, as always, as we think about our value proposition, is that we deliver a moderately growing and stable dividend underpinned by a commensurate growth in earnings and cash flow. We've targeted a payout ratio of 80%-85% of earnings and 40%-45% of cash flow per share. That in turn delivers a stable balance sheet and allows us to have the dry powder to be opportunistic to the extent any acquisitions become available. I don't see any changes in that value proposition going forward. As you perhaps intimated, and in my prepared remarks, we are seeing an acceleration in the opportunity set. You've seen the fruit of that here in our announcement with the VR Project. You can expect additional projects to be sanctioned as per my comments throughout the balance of the year. To the extent the opportunity set continues to grow as our expectation is that it will over time, perhaps we'll consider opportunities to relook at capital allocation. For the time being, it's business as usual here, and the tried and true capital allocation framework that you're accustomed to seeing from us. Thank you. Thanks, Linda. Our next question comes from Jeremy Tonet of JP Morgan. Please go ahead. Hi, good morning. Morning, Jeremy. Don, you will be missed. I hope Joel has the same good sense of humor as you did. Best of luck going forward. Thanks, Jeremy. Maybe I just wanted to start off with the Alberta Carbon Grid and wondering, it's obviously very early days here, but what you might be able to say as far as stakeholder reaction when you put out that announcement, what type of conversations you're having, what do you think is possible? Hi, Jeremy. It's Bevin here. We're very pleased with the customer engagement that we've had to date and the industry feedback. Obviously, without being able to clarify exactly what the carbon hub will look like or will evolve to, there are a lot of proponents in industry advancing their own pursuit of energy transition. Right now, we're working in partnership with all our customers and with industry to advance. Since our initial announcement of the Alberta Carbon Grid, we've been progressing our engineering and scoping work, as well as filing our applications under the government of Alberta's sequestration process. I think the project itself is a great example, further to Linda's question on taking our existing asset base and seeing how it can be utilized or repurposed as we pursue energy transition opportunities in the portfolio. Got it. That's helpful there. Just wanted to maybe touch on capital allocation a little bit more, talking about new opportunities kind of materializing here, and just wondering how you think about the payout ratio within the context of these new opportunities and I guess needs for equity overall. Do you feel that the stock is getting credit for kind of the 5%-7% dividend growth that you're talking about here? Would it at any point make sense to kind of ratchet down the payout ratio or that growth rate given kind of these new opportunities, as you said? Just trying to put all these things together here. Yeah. Appreciate that question. Again, as I mentioned earlier with respect to Linda Ezergailis' question, we have a tried and true capital allocation model that's been successful for many decades and allowed us to deliver a 13% annual total shareholder return over that period of time. Stability and predictability in terms of our approach to capital allocation is important. If we see an opportunity to earn an outsized return and create more value for our shareholders by retaining additional cash flow, it's something that we would give consideration to. We think the balance of 40% of our earnings going back to our shareholders in the form of a dividend and 60% being reinvested in the business is a reasonable balance. Having said that, to the extent opportunities arise for us to invest beyond our free cash flow, we hold share count very jealously. To the extent those opportunities occur, we'd consider issuing equity or perhaps retaining a greater portion of our cash flow. As I said, the model has served us well over the last couple of decades, and our expectation is that we will continue along this line. I'll just clarify, 40% of cash flow, not earnings. Oh, pardon me. being paid out. Thank you. That's helpful. I'll leave it there. Thank you. Okay. Thanks, Jeremy. Our next question comes from Ben Pham of BMO. Please go ahead. Hi. Thanks. Good morning. I had a question on the renewable energy RFIs you go through evaluation, move to an RFP. Are you able to share maybe any sort of qualitative thoughts you're seeing from the interest levels? Anything that's surprising you so far? Hi, Ben. This is Corey. I can give you some quantitative feedback, I think, which is pretty interesting and shows the level and the size of the opportunity that's available to us at TC Energy as part of the energy transition. As you know, we had sort of two components to the RFI. One was a wind component, and one is a solar plus storage component, totaling about one gigawatt of requests. We had 54 individual projects totaling 16.6 GW of bids submitted for wind, which is about 27x the request. On the solar and storage side, we had 66 individual projects totaling about 12.4 GW of bids submitted, which is about 40 times the amount of demand that we went to the market with. We are currently at a phase where we are down selecting those projects and entering definitive negotiations with the projects that best meet the criteria for our customers, our stakeholders, and our shareholders. We expect in the coming months, we will be able to announce those projects that we have chosen to move forward with. That's incredible. Not into math. Okay, thanks for the update on that. Then maybe on your liquids segment, able to comment on your thoughts on the short-term outlook on the volumes and maybe just importantly, your longer-term outlook relative to maybe some of the guidance you've highlighted in the past in the liquids segment? Ben, thank you. It's Bevin here. Our pipeline, ex- Hardisty down to the Gulf Coast, has been at capacity, leaving the supply basin here in Western Canada. As we pick up volumes in Cushing to take to the Gulf Coast or into the Midwest, we've seen a continued arb compression between the Midwest and Cushing and the Gulf Coast as we saw supply volumes increase out of the Permian, and really a compression in the export markets. We see that outlook persist here over the balance of the back half of this year and likely into early next year. We have seen producers increase supply with the run-up of commodity prices in various basins. However, our liquid segment is really driven by the arbs between ex- Hardisty and ex Cushing into our refining markets. Okay, great. Thanks, Bevin. Thanks, Corey. Okay, thanks, Ben. Our next question comes from Robert Catellier of CIBC World Markets. Please go ahead. Hi, thank you. I just wanted to follow up a little bit on Coastal GasLink. Understanding there's limitations to what you can say, but clearly an important project for the industry, and I'm curious as to when you believe you have to have this dispute resolved in order to avoid having a work suspension. Just pulling on that thought, it sounds like you're still using commercial means to resolve the dispute, but is the idea of mediation or arbitration a possibility here? Thanks, Robert. Happy to take that question. We are, as you say, in discussions and commercial discussions. Right now, we're focused on that as the mechanism to resolve the disagreement between us. There's a number of details going across the table on that. As I said before, it is the subject of some confidential dialogue with our customer. Our main focus, we're focusing really on two things. One is resolving the disagreement on cost and schedule as quickly as possible, and the other is ensuring that the pipeline is constructed in a safe and cost-effective manner and that it's in service on a timeline that aligns with the current schedule for the facility in Kitimat. We're pretty focused on that. We're hopeful that we're going to get a reasonable and fair outcome here in the near term. Switching then to Bruce. Same type of question. If you could provide a little bit of color on the return to service date for Bruce 3. Understanding that part of that's probably not in your control. Do you have a rough estimate as to the timeline as to when that can be resolved? Hi, Robert. It's Corey. We are in process responding to the July 26 order from the CNSC, so we will be following the process and the procedures as laid out by the CNSC. Once we receive the first bit of feedback from the CNSC regarding our response, we'll be able to provide more color. What I would say is the plants are operating safely, reliably, effectively. Unit 3 is offline right now, and we are in process following the CNSC's order through the letter and expect a positive outcome. Okay. Thank you. Thanks, Rob. Our next question comes from Robert Hope of Scotiabank. Please go ahead. Good morning, everyone. First question on the Columbia settlement. Not sure how much you can kind of talk here, but can you just maybe highlight some of the key issues that you received some resolution as you expected? Then can you remind us how much of a revenue uplift you have been booking so far this year? Yeah, Rob, this is Stan. I'll tell you what I can, which is, obviously you heard that we notified FERC yesterday of our plans to suspend the procedural schedule, which is the way we tell FERC that we have a settlement in principle with our customers. The actual details I really can't get into until we file the settlement. That will be sometime, most likely in September and October or October. All issues that were addressed in the settlement or in the rate case, are addressed in the settlement, including things like rate levels, and the continuation of our modernization program. Again, I'll tell you that the settlement is in line with our expectations, that the revenue and the earnings are very consistent with the estimates that we have recorded and reported to date. Again, I can't give you hard numbers just yet. With respect to the modernization program, I can tell you that it's generally consistent with our prior programs, both in terms of structure and size. Really is a great example of the value of pipe in the ground and how it can be optimized. The settlement process took a little bit longer than we would have liked for two reasons. One, this was our first rate case in 20 years, and there were a myriad of issues that needed to be addressed. Secondly, given the pandemic, we had to do all of our negotiating virtually, which was a bit inefficient. Again, if you just bear with me until we get the settlement on file, maybe we can get some of those questions answered then. Really, I'm thankful to our customers and FERC staff for their contributions in making this settlement happen. All right. Appreciate that and look forward to some additional details in September. Okay. Pivoting over to the RFI for the renewable projects as well as how you're looking at kind of your cost of capital and kind of the attractiveness of projects. When you take a look at the vast amount of projects that came in, how much or what percentage of that could we see TC Energy invest capital into rather than just contract power energy? Hi, Rob. It's Corey. I'll take an opening shot at this, and if Don or François want to comment, I'll cede to them as well. The way we're thinking about it is each individual project, in each individual jurisdiction is being measured on its own merits. As we think about jurisdictions, and we think about how the ISO operates in each of those jurisdictions, it's going to have a bearing on our view of how we can participate in that market. That being said, we see ourselves as the long-term owner and operator of assets. We've been doing it for a very long time, and we take great pride in being an industry-leading operator. I think that we will have a blend of both. It's a little premature until we evaluate each individual project on its merits to sort of decide what that mix might be. I'll cede it over to François or Don if they have any additional comments. Perhaps the only point I'll add to that, Corey, is that obviously we have an obligation to deliver the lowest cost acquisition of power as part of our agreement with our shippers. We see an opportunity here to lower those costs. That is in addition to an opportunity for us to lower our emissions, it is an opportunity for us to lower our variable costs for our customers. We're very excited about that. Excellent. Appreciate the color. Don, all the best. It’s been fun over the years. It has, Rob. Thanks very much. Our next question comes from Andrew Kuske of Credit Suisse. Please go ahead. Thanks. Good morning. Obviously, the topic of clean fuels is a big one, and it's pretty broad-based. Just sort of curious on your thought process on how does TC Energy fit into that investment theme across your value chain. Is it across the entire value chain of your assets, really from wellhead or mine face in some cases of customers to city gate or burner tip, or do you view it in a more targeted fashion? I'll provide some high-level comments. On the question of renewable natural gas, I'll ask Stan, after my remarks, to maybe provide two thematic points. I think, Andrew, the short answer is it's across our entire asset base. What we've learned as we look at carbon capture and storage, as we look at hydrogen, as we look at renewable natural gas, a fundamental aspect of being a participant in those markets as they develop is the ability to store and transport a molecule, which is, of course, our core business. When you look at our footprint, the basins we serve, and the markets we serve, we actually see opportunities across the entire footprint for us to play a role. In some instances, those opportunities are many years away. I would say from the perspective of hydrogen, for example, we're still at the stage where we are investigating the technologies and the potential from a safety standpoint. Of course, safety is our number one value, and we want to make sure that the injection of hydrogen into our pipelines will not cause any embrittlement issues, and it can be safely transported across our systems. You're exactly right. Our footprint on a broad-based basis will present opportunities for us across the board. Yeah. This is Stan. Just to tag on to that, clean fuels come in many different sizes and shapes and colors, one of them being renewable natural gas. You may recall that we had a goal this year to double the amount of renewable natural gas we're taking into our system from 2 Bcf- 4 Bcf, and to double it again next year from 4 Bcf- 8 Bcf. We're actually on track to exceed that and exceed it in a very big way. I think by the end of 2022 or early 2023, we'll have about 30 Bcf of renewable natural gas coming into our system. We're doing this by overlaying our pipeline footprint against landfill operators, for example, where this renewable natural gas, this biogas, is actually created. I think that there is a significant opportunity to continue to take advantage of things like renewable natural gas. In the end, it just really reinforces our thoughts that our future is one of natural gas and renewables and that we can work together. That's very helpful. Maybe just a bit of an extension of the question, but maybe a particular focus just to let's call it old-style hydrocarbons. We're ways away from budget season coming up for most of the producers, but what's the sentiment from really your clients on drilling activity and outlook? Obviously, commodity prices are elevated, but how do you think about that? It's probably more a question for Stan and for Tracy. Yeah, I could start. Go ahead, Stan. Go ahead, Tracy. Okay. I'll go ahead and start. With respect to what's going on in the U.S., one thing, if you're watching NYMEX prices of lately, you're seeing that there's a lot of $4 prints of the next four, five, or six months, which is something that's new. All things equal, that's an incentive for producers to continue to drill. What we're seeing is that producers doing exactly that. Appalachian production is up to around 34 Bcf. A lot of them focusing on what they would call responsibly sourced natural gas. That's becoming more and more of a theme these days. I think that you'll continue to see production growth, particularly out of the Appalachian Basin. I think you'll see it done in a responsible way with a focus on emissions. Again, just get back to this theme. I think that we can do this in a way that natural gas and renewables can work together. I'll follow up on that, Andrew. Same kinds of things are going on in Canada. Of course, we have the added element here of the prospect of carbon tax, pretty significant carbon tax. We do see industry focused on emissions reduction. Carbon tax would drive incremental operating costs. We are as well. It's the nature of a dialogue that's pretty consistent in front of desks between us. We have methane reduction program going on, and we're investigating the system's potential to reduce emissions through electrification, waste heat investments, and those types of things. It is important to note that they're focusing on it, we're focusing on it. This energy transition provides meaningful opportunities for investment in our system as we go forward, whether it's through reduction of emissions or the transition to new energies. We are focused on doing that in a manner that preserves the competitiveness of, in our case, the WCSB in the continental market and ultimately into the LNG markets. The best way to mitigate that impact on carbon price is through investments that lower emissions as we go forward. That's very helpful. Thank you. Thanks, Andrew. Our next question comes from Patrick Kenny of National Bank Financial. Please go ahead. Hey, good morning, everybody. I just wanted to touch on this recent trend of Canadian gas producers looking to secure long-term market access to the Gulf Coast and international pricing. Of course, contracting with yourselves down the Canadian Mainline and ANR. Just curious how meaningful this trend could be in terms of financial upside for you. Then I guess on the flip side, how you might be thinking about mitigating any impact on your eastern Mainline system from perhaps less Alberta gas flowing into Ontario over time. Happy to take that, Patrick. What we do know is natural gas demand is forecasted to continue to grow in the coming decades globally, and LNG is going to be an important component of global energy demand and transition. North America is positioned really well to participate in that growth, whether it's through the Gulf Coast or whether it's off the west coast of Canada. We have a very strong portfolio of highly integrated, interconnected assets across Canada, U.S., and Mexico. We sit on top of the WCSB, and the Marcellus positions us well to participate. We can get to the Gulf Coast through the U.S. assets. We can get to the West Coast. What the opportunity is for us is even if we want to provide direct access to LNG facilities, but there's also opportunity to fill the void left by gas leaving the continent. We are looking to provide as much access as we can to any global market as we go forward. I would say the opportunity to go down south to the U.S. right now with available capacity, the opportunity to do more is somewhat limited, but we'll continue to work with our customers, both Stan and I, to take advantage of whatever capacity and whatever market opportunity we see. Okay. That's great. Thank you very much. Thanks, Pat. Our next question comes from Matthew Taylor of Tudor, Pickering, Holt & Co. Please go ahead. Thanks for taking my question here. I wanted to start first on your focus on the U.S. for renewable development. Can you explain what needs to change in Canada on the regulatory side for you to start focusing on electrification of compressor stations, of looking at renewable opportunities tied into NGTL or the Mainline, which I believe you said you're really just focused on the U.S. right now? Perhaps I'll start, and then Corey can provide additional comment. With respect to electrification of compression within our Canada gas system, our obligation with the prescribed rate of return, is to deliver the least cost alternative. Currently, that least cost alternative, in most instances, is to build gas turbines to deliver the service. As the carbon tax potentially escalates over time, we would be reassessing what technology meets the standard of least cost alternative. We do believe that that inflection point is somewhere around CAD 50 or CAD 60 a ton, where there would be a clear economic advantage to designing an increased amount of compressor stations with electric motors. We also have to factor in reliability. We also have to factor in proximity to poles and wires to supply the power to electric motors at compressor stations. Of course, to the extent there are other regulatory accommodations, to perhaps even include some of the generation into rate base, that would also, I think, help accelerate that development. Those are the two things that I see on that question, Matt, and Corey, is there anything else you want to add to that? Matt, the only thing I would add is that you got to pick a place to start, and in the U.S., we have really a significant opportunity with the current financial models in place. We are taking the lessons we're learning about the process in the U.S., and then we'll actively apply those lessons learned to our opportunity set in Canada. That's great. Thank you. Maybe one follow-up for you, François. You mentioned that it's tied to the least cost alternative. I'm just curious on your thoughts whether or not educating government here or even lobbying if Canada is serious about meeting our carbon emission objectives, if in fact that is the right way to be looking at this. We can make the argument carbon taxes could still be viewed very politically. Perhaps, maybe not just looking at the least cost alternative is the right way to be looking at this longer term. We are in conversation either directly or through industry associations, with regulators to the extent it's appropriate, of course, outside of specific project conversations, as well as various levels of government. I can tell you from my perspective, the policy landscape is evolving very rapidly and these are very complex questions that take some time to implement in a thoughtful manner. All participants, whether they are our customers or ourselves, the regulators and governments, all have the same objective in mind, which is to deliver energy reliably and responsibly, minimize our emissions and do it in an affordable fashion at the lowest possible cost. It will simply take some time because of the velocity of policy change for that to be implemented in a practical manner. That's great. Thanks for that. That's it for me. Thanks, Matt. Our next question comes from Becca Followill of U.S. Capital Advisors. Please go ahead. Morning, guys. Just following up on that issue of reliability and electric compression for gas pipelines. Most battery storage is about four hours. How do you handle the reliability issue on gas pipelines in putting in electric compression? Hey, Becca. Yeah. Yeah. I can take that, François. Actually, what we're doing with the VR project, for example, is putting in a dual drive that is both gas and electric driven. For example, when you have electric power to the station, the electric motor will spin. If you have a loss of electric power, then the gas unit will kick in, and effectively there's a clutch that will then drive the electric motor. You have 100% reliability with respect to these dual drives that we're putting in. It's not just an electric unit. Does that make sense? Gotcha. That makes sense. Yeah. That's what most people are doing. Just the read, it was like, oh, maybe that's not good for a pipeline. Just to clarify, this is independent investment. This is not investment that you would put in rate base. Under the current compact in all of our jurisdictions, these investments in terms of renewables would be in our unregulated affiliate, our Power and Storage business that Corey runs, and enter into arm's length commercial arrangements with the regulated affiliates. Gotcha. Thank you. Then on the Alberta Carbon Grid, just is that dependent, and was that dependent at all on the Pembina Inter Pipeline merger? Were some of the pipelines from Inter Pipeline being used in that? How does the termination of that deal impact the project? Yeah, Becca, thanks for the question. This is Bevin Wirzba. Us as partners with Pembina, we remain focused in developing this world-scale carbon transportation system. Both of us as partners have an extensive network of pipelines that can rely on the project. It’s not just specific pipelines, but it’s corridors and interconnections. We believe that we can leverage both of our asset bases as well as work with other industry partners, to fulfill the development of the full grid. The Inter Pipeline merger breaking apart has no impact on the project. At this time, no, it wouldn't. We're still in very early stages of pulling together all the pieces of the lines that would contribute. If in the outcome that Brookfield is successful with the Inter Pipeline acquisition, we'll definitely look to work with them as well to see if they can also be part of this industry solution. Great. Thank you. Thanks, Becca. Our next question comes from Michael Lapides of Goldman Sachs. Please go ahead. Hey, guys. Thank you for taking my question. Real quick, buried in the release was the detail about unit 3 on Bruce and the hydrogen pressure levels. I know you mentioned that you didn't think it was material to your cash flows. Just curious, what are you seeing technically right now that gives you that conviction? I'm just thinking about the history of North America over the last 10 or 15 years when some of the other plants, some on the U.S. side of the border had pretty major issues that actually started with what people thought were pretty minor things when they were undergoing outages. I'd love to know just, what at this early stage gives you that insight to think it's not something more serious at unit 3. Hi, Michael. It's Corey. I don't want to speak for the executive management team at Bruce Power about technical issues, but what I can say is that the issue was identified and that we are following a systematic process as identified by the CNSC on how to manage this effectively. We have done a fair amount of R&D at the site and amongst all the CANDU operators to resolve the issue. Until the CNSC process is complete, I don't want to comment on exactly what the technical resolution is. I'm really not qualified, and I don't think anybody on our team is really qualified in a way that's meaningful to answer that question. Got it. Okay. You're confident at this point that it's something that's just isolated to unit 3 and it doesn't impact any of the other units there? What I would say is that the unit 3 design is a bit different than the other units. The impact on unit 3 is different than what it would be on those other units. Got it. Thanks. Thank you. Much appreciated, guys. Okay. Thanks, Michael. Our next question comes from Alex Kania of Wolfe Research. Please go ahead. Great. Thanks. I just have one question. I know, I guess the theme from a lot of the new investment opportunities are into energy transition, and kind of de-carbonization and just trying to make the product cleaner. Just thinking about your history with respect to portfolio management, are there any assets or whatnot that are in the existing portfolio today that you feel could be sold or divested to maybe improve the overall footprint as you think about that long-term transitional strategy? Also help fund the rest of the investments? Hi, Alex. It's Don here. I think you've seen us recycle capital here over the past several years, and I think we're showing a willingness and an adeptness at that. Whenever we start looking at our growth versus our internal capacity, we look to minimize share account growth, and we look for the cheapest source of funding for the new projects here. We will continue to scour the portfolio and look for asset sale opportunities to fund anything beyond our internal capacity, which is probably in the CAD 5 billion-CAD 6 billion a year range. That said, we're into the pretty good stuff now. We have to be cognizant of tax consequences, the optionality embedded in our assets, and the network value that Tracy Robinson alluded to and Stan Chapman has alluded to earlier, where we've got a dozen and a half pipelines across the system, and taking a piece out or certain components of it actually detracts from the overall network value there. Something we'll look at, but there is nothing jumping out of any magnitude right now where we think it's a candidate for that. Anytime we're looking at investing beyond internal capacity, it's something we'll evaluate. Great. Thanks. Best of luck. Thank you. Thanks, Alex. 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. Thank you. In summary, during the first half of 2021, our commitment to operational excellence and the strong demand for our services translated into record financial results. As we advance our CAD 21 billion secured capital program and numerous other organic growth opportunities, we expect to build on our long track record of growing earnings, cash flow, and dividends per share. With an irreplaceable asset footprint, extensive technical expertise, substantial internally generated cash, and a solid balance sheet, we are well-positioned to prosper irrespective of the pace or direction energy transition takes. Looking forward, we'll continue to focus on safety, sustainability, working according to our values, and responding quickly to market signals and signposts. Before closing, I would like to acknowledge that this is Don's last quarterly conference call. He's stepping down as CFO on July 31st and will retire on November 1st after 27 years with the company. As a longstanding and deeply respected member of our senior management team, Don has played a significant role in our strategic direction, our growth, our financial strength, and our ability to have fun while we're doing it. Thank you, Don, on behalf of the entire executive team and on behalf of our board of directors. On August 1st, Joel Hunter will be assuming the role of Executive Vice President and CFO. Joel has been with TC Energy for 24 years, working closely with Don and making a significant contribution to the company's success in raising capital, executing on key initiatives, and navigating major market events and industry shifts. I am confident he will maintain the disciplined approach to our financial strength, risk preferences, and capital allocation decisions as we continue to execute on our vision to be North America's premier energy infrastructure company now and in the future. That concludes my remarks, and thanks very much for joining us today. We really appreciate your ongoing interest and support and look forward to speaking again with you soon. This concludes today's conference call. You may disconnect your lines. Thank you for participating, and have a pleasant day.