TC Energy Corporation (TRP) Q2 2021 Earnings Report, Transcript and Summary

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. [Operator Instructions] I would now like to turn the conference over to David Moneta, Vice President, Investor Relations. Please go ahead.

Thanks very much, and good afternoon, everyone. I would like to welcome you to TC Energy’s 2021 second quarter conference call. Joining me today are Francois Poirier, President and Chief Executive Officer; Don Marchand, Executive Vice President, Strategy and Corporate Development and Chief Financial Officer; Tracy Robinson, President of our Canadian Natural Gas Pipelines and 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. Francois 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 Francois 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. And 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 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 will turn the call over to Francois.

Thanks, David, and good morning, everyone. And I know, it's a busy morning with lots of companies reporting. So 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, and that despite energy market volatility, weather events, and the ongoing impacts of COVID-19. Of note, our US 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 $765 million in maintenance capital as part of our ongoing commitment to pipeline integrity. And 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 US 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. And looking forward, we expect the solid operating and financial performance of our existing assets to continue. Contributing to our performance is Colombia Gas, which recently notified the FERC that it has reached a settlement-in-principle with its customers addressing all remaining issues related to inspection for 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 are now $21 billion of secured growth projects. They're 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 their 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 US$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 fire 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 discipline growth, while being agnostic to the form of energy that will ultimately lead to a low carbon energy future. Whether its 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 mentioned before, ultimately, our goal is to sanction $5 billion to $6 billion annually to deliver on our long term growth plans, including $1.5 billion to $2 billion per year of maintenance capital across our extensive network. And 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’s modernization program, as well as the Bruce Power unit three MCR project which is under consideration to be added to our backlog by the end of this year. And through requests for information, we are identifying potential opportunities in wind, solar and energy storage projects that could generate 1000 megawatts of zero carbon energy to meet the electricity needs for a portion of our US 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 national -- our North American footprint. And 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 Defense that subject to conditions and regulatory approval allows for the development of the multibillion dollar 1000 megawatt 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. And finally, we recently announced the 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 tonnes 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% to 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, Francois. And good morning, everyone. As outlined in our results issued earlier today, net income attributable to common shares was $982 million or $1 per share in the second quarter of 2021 compared to $1.3 billion or $1.36 per share for the same period in 2022. Second quarter results included a combined $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 $13 million after-tax recovery associated with the Ontario gas fired power plants sold in 2020. The corresponding period in 2020 also included certain specific items, as outlined on the slide and discuss 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 $1 billion or $1.07 per common share compared to $863 million or $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 $2.2 billion was similar to 2020, despite strong currency translation headwinds. Canadian Gas pipelines comparable EBITDA $684 million was $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. And GTL system net income rose $16 million year-over-year, mainly due to a higher average investment base resulting from continued system expansions and reflect an ROE at 10.1% on 40% deemed common equity. Net income for the Canadian Mainline increased $14 million, largely due to higher incentive earnings. And the elimination of a 20 million after tax annual TC Energy contribution included in the previous NED 2014 decision. The US Gas pipelines comparably that US $717 million in the second quarter was higher by US $122 million compared to 2020. This was driven by a net increase in earnings from Columbia Gas following us 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 first 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 US Gas pipelines were generally higher following the cold weather events the first quarter 2021, which impacted many of the US markets we serve. Mexico gas pipelines comparable EBITDA of US$134 million rose US$4 million versus last year, primarily as a result of increased earnings on Guadalajara, following implementation of a flow reversal completed in 2020. Liquids Pipelines comparable EBITDA declined by $66 million to $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 $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 gas pipelines and parts of liquids pipelines, EBITDA was translated into Canadian dollars using an average exchange rate of $1.23 in second quarter 2021, compared to $1.39 for the same period in 2020. Well, overall, US dollar denominated comparable EBITDA increased by US$105 million. The year-over-year weakening of the currency was a considerable drag on 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 then actively managed 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. Now turning to the other income statement items on slide 11. Depreciation and amortization of $633 million was in line with second quarter 2020. Interest expense of $577 million was $16 million higher year-over-year, largely due to the net effect of lower capitalized interest due to it’s acquisition for the Keystone XL pipeline project. The change to equity accounting for 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 $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 $151 million in the second quarter, mainly due to realize gains in 2021, compared to realize losses in 2020 on derivatives used to manage our net exposure to foreign exchange rate movements on US dollar denominated income. Income tax expense included in comparable earnings was $175 million in second quarter 2021, compared to $125 million for the same period last year with the $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 were income taxes are flow through item and that's quite variable along with equity AFUDC income in U.S. natural 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 interest of $6 million decreased by $57 million relative to the same period last year, primarily as a result of the March 3rd, 2021, by units of TC PipeLines LP. And finally, preferred share dividends of $32 million were $8 million lower than second quarter 2020 mainly due to the redemption of Series 13 preferred shares on May 31st 2021. Now turning to slide 12, during the second quarter comparable funds generated from operations totaled $1.8 billion, and we invested $1.4 billion in our capital program. As noted, at the end of May, redeemed all over issued and outstanding Series 13 preferred shares using proceeds from our junior subordinated debt offering completed in March 2021. In June, we completed a free tranche offering of MTNs in Canada comprised of $750 million, a three year floating rate notes, $500 million in 10 year notes, at 2.97% and $250 million of 26 year notes at 4.33%. Also in June, the US$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 repurchase their ownership interest in KXL and issued securities and titling the government to certain project liquidation proceeds as realized. Collectively, this resulted in an after-tax net recovery of approximately $1.1 billion being recognized which was credited to directly to equity and serves to partially offset the $2.2 billion after-tax impairment charge recorded in the first quarter. Now turning to slide 13, this graphic illustrates our forecast and 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 $29.5 billion, reflecting dividends of $11 billion, capital expenditures including maintenance capital of $16 billion, $2 billion attributed to the TC PipeLines LP acquisition completed in March, and the Series 13 preferred share redemption to $500 million in May. The second column highlights expected internally generated cash flow of $21 billion, $2 billion of common shares issued pursuant to the Pipe LP buy-in 1.5 billion of MTNs issued in June, and the $500 million junior subordinated notes offering completed in March. That leaves a residual need of approximately $4.5 billion to pick it in the far right column. And we expect to fund that through a combination of incremental debt, commercial paper in Keystone XL project recoveries. The program excludes the normal course refinancing and scheduled debt maturities and is consistent with our goal of maintaining debt to EBITDA in the high-4s and FFO to debt of 15%. Now 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 dramatically aligned with both, today's needs and the world shifting energy mix, as well as being consistent with our long standing risk preferences and return requirements. This is expected to perpetuate our multi decade track record, a prudent value creation and support annual dividend growth of 5% to 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 reenter the queue. With that I'll turn it over to conference coordinator.

Thank you. We will now begin the question-and-answer session [Operator Instructions] Our first question comes from Robert Kwan of RBC Capital Markets. Please go ahead.

Good morning. My first question relates to the VR project. But more so taking a step back, you've got US$700 million for this and this is just Colombia. Have you looked at how big these types of opportunities can be across your entire system? And 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 emissions?

Hey, Robert, this is Stan. I could take a stab at that. And I would say it's really multi factors. 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, something that's important to us. And we think that we can do that, not only by installing the lesser 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? Note, it is part of our overall drive to reduce our emissions footprint, both across the country and the continent. And we have the 13 pipelines that we own or operate here in the US. And my expectation is that in any given year, on any given pipeline, we can have one or two of these projects. And that's what we're going to challenge ourselves to be successful in reducing emissions going forward.

Okay, so just so when you say one or two of these projects, you're talking about an announcement or something in that US$700 million range?

Well, again the dollar amount is going to fluctuate, depending upon the specifics of the case. But I think the expectation would be one or two projects per year over the next several years. Now, what pipeline that's on is going to be determinative of many things, including where the additional loans is 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 disputes, you just talked a little bit more, 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 claw back of the proceeds you've received?

Good morning. This is Tracy here. I'll take that one. There’s likely to be a number of questions on the deceit 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 costs and schedule. We've been in discussions for some time now. And those discussions do continue. They are confidential. We do have our equity partners involved, because they are all confidential, we're unable to share any details at this time. I can't say that they're progressing. But if we're not able to reach a resolution in the near-term, then there will be some implications to our construction. It's an important project, Coastal GasLink. We are in full execution now. We have more than 5,000 people working in the corridor. Execution is going well. We have a strong safety record. We want to continue to discuss them construction. And I -- we do remain I think very hopeful that we'll have a fair and reasonable outcome. And 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. And Don, hopefully, you're happy to get this last one out of the way. I let you off easy.

Robert, thanks. Now this is the highlight of the week again here. So thanks, Robert.

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. So 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 from a capitalization inspiration as well.

Hi, Linda. This is Corey Hessen. Couple things. Number one, we're very, very pleased that we were able to reach an agreement recently with the DND on the first step to gaining site access. But we have some technical steps that will 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. So we're really running a two pronged approach for the next coming months as we continue the development of this project. And as we go forward, we will be working collaboratively as well with our partners, local stakeholders, and Bison, who are all active participants in three 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 -- 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.

Yes, Lynda, 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 a 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. So that 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% to 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 -- if there's tax changes, investor preferences might change, et cetera?

Linda, I'll take that one. You know, 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% to 85% of earnings and 40% to 45% of cash flow per share. And, 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. So I don't see any changes in that -- 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. And, to the extent the opportunities that continues to grow as our expectation is that, it will over time, perhaps we'll consider opportunities to re-look at capital allocation, but 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 JPMorgan. Please go ahead.

Hi, good morning.

Good morning, Jeremy.

And Don, you will be missed. I hope Joel has the same good sense of humor as you did.

Thanks, Jeremy.

But 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've had -- 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. And so right now, we're working in partnership with all our customers and with industry to advance. Since our initial announcement of the carbon grid, we've been progressing our engineering and scoping work as well as filing our applications under the government of Alberta sequestration process. But I think the -- the project itself is a great example, further to Linda's question on taking -- 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. And just want 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, need for equity overall, do you feel that the stock is getting credit for kind of the 5% to 7% dividend growth that you're talking about here? Would it at any point makes 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?

Yes. Appreciate that question. Again, as I mentioned earlier, with respect to Linda's 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. So, 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. And, having said that, to the extent opportunities arise for us to invest beyond our free cash flow, we hold share count very jealously, but to the extent those opportunities occur, we would -- we consider issuing equity or perhaps retaining a greater portion of our cash flow. But 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, a 40% of cash flow, not earnings…

Pardon me.

…being paid out, so.

Thank you.

That's helpful. I'll leave it there. Thank you.

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 RFI, as you go through evaluation, move to an RFP, you give a little share, maybe any sort of qualitative thoughts there, just seems from the interest levels, is there anything that’s surprising so far?

Hi, Ben. This is Corey. 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 with a lot of requests. We had 54 individual projects, totaling 16.6 gigawatts of bid submitted for wind, which is about 27 times the request. In the solar and storage side, we had 66 individual projects, totaling about 12.4 gigawatts 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 answering definitive negotiations with the projects that best meet the criteria for our customers, our stakeholders and our shareholders and 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. Okay. Thanks for the update on that. And then on -- maybe on your liquids segments, a comment on -- your thoughts on the short-term outlook on the volumes and maybe just important, your longer term outlook relative to some of that -- maybe some of the guidance you highlighted in the past in the liquid segment.

Ben, thank you. Its Bevin here. Our pipeline ex-Hardesty down to the Gulf Coast has been at capacity leaving the supply basin in 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 in the Gulf Coast as we saw supply volumes increase out of the Permian, and really a compression in the export markets. And so we see that outlook persists 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-Hardesty and ex-Cushing into our refining markets.

Okay, great. Thanks Bevin. Thanks guys.

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 this limitations wait and see. Currently 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? And just following 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 -- in commercial discussions, and 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, but 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 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 medicine service and the timeline that aligns with the current schedule for the facility and in Kitimat. So, we're pretty focused on that and we're hopeful that we're going to get a reasonable and fair outcome here in the near-term.

Okay. Switching then to Bruce, same type of question, if you could provide a little bit of color on the return to service Bruce 3, understand that part of that's probably not in your control, you have a rough estimate of the timeline as to when that can be resolved?

Hey, Robert, it's Corey. We are in process responding to the July 26 order from the CNFC. So, we will be following the process and the procedures as laid out by the CNSC. And once we received the first bit of feedback from the CNSC regarding our response, we'll be able to provide more color, but what I would say is the plants are operating safely, reliably, effectively. Unit three is offline right now. And we are in process following the CNSC's order rather than expect a positive outcome.

Okay. Thank you.

Thanks, Rob.

Our next question comes from Rob Hope of Scotiabank. Please go ahead.

Good morning, everyone. First question on the Columbia settlements, not sure how much you can kind of talk here, but can you just maybe highlight some of the key issues that you receive some resolution as you expect? And then, can you remind us, how much of a revenue outlet do you have in bookings so far this year?

Yes, Rob, this is Stan, I tell you what I can, which is obviously you heard that we notify Burke yesterday of our plans to suspend the procedural schedule, which is the way we tell for that we have a settlement in principle with our customers. The actual detail there really can't get into until we file the settlement that will be sometime most likely in September and October. But 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 the XR expectations that the revenue and the earnings are very consistent with the estimates that we've had recorded and reported to date. But again, I can't give you a hard numbers just yet. But with respect to the modernization program, I can tell you that it is generally consistent with our prior programs, both in terms of structure and size. And yes, 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. And then secondly, given the pandemic, we had to do all of our negotiating virtually, which was a bit inefficient. So again, if you just bear with me until we get the system on file, maybe we can get some of those questions answered then. But really, I'm thankful to our customers and first staff for their contributions and making this settlement happen.

I 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 for energy?

Hi, Rob, it's Cory. I'll take a take an opening shot at this and if Don or Francois want to comment out to them as well. But the way we're thinking about it is each individual project in each individual jurisdiction is being measured on its own merits. And so, as we think about jurisdictions, and we think about how the ISO operates in each of those jurisdictions is 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 industry leading operator. So I think that we will have a blend of both. But it's a little premature until we evaluate each individual project on its merits to sort of decide what that mix might be. But I'll feed it over to Francois or Don if they had any additional comments.

That 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, and we see an opportunity here to lower those costs. And that is in addition to or an opportunity for us to lower emissions. It is an opportunity for us to lower our variable costs for our customers. So we're very, very excited about that.

Excellent. Appreciate the color. And 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. And just sort of curious on your thought process, how does TC Energy fit into the investment theme? Across your value chain, is it across the entire value chain of your assets really from wellhead or mine case in some cases with customers, just syndicated your burner tip or do you view it in a more targeted fashion?

I'll provide some high level comments. And on the question of renewable natural gas, I'll ask Stan after my remarks to maybe provide a couple of thematic points. And 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. So 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. Now in some instances, those opportunities are many, 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 embitterment issues. And it can be safely transported across our systems. But you're exactly right. Our footprint on a broad based basis will present opportunities for us across the board.

Yes, maybe just -- this is Stan, just to tag on to that clean fuels come in many different sizes and shapes and colors, that one of them being renewable natural gas. And 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 to 4 Bcf and to double it again next year from four to eight. We're actually on track to exceed that, exceeded 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. And that we're doing this by overlaying our pipeline footprint against landfill operators, for example, with renewable natural gas, biogas is actually created. So I think that there is a significant opportunity to continue to take advantage of things like renewable natural gas, and then the end, there just really reinforces our thoughts that our future is one of natural gas and renewables and that we could work together.

That's very helpful. And then maybe just a bit of an extension of the question. But maybe a particular focus just to what’s called old style hydrocarbons. And we're aware -- we're always from budget season coming up for most of the producers. But what's the sentiment from really the clients on drilling activity and outlook? Obviously, commodity prices are elevated, but how do you think about that is probably more question for Stan and for Tracy?

I guess.

I guess, sorry.

Go ahead.

Very good. I'll go ahead and start with respect to what's going on in the US now. One thing if you're watching NYMEX prices of lately, you're seeing that there's a lot of $4 dollar in the next four or five or six months, which is something that's new, so all things equal, that's an incentive for producers to continue to drill. And 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 a responsibly sourced natural gas that's becoming more and more of a theme these days. So I think that you will 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. And 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.

And I'll follow-up on that Andrew. Same kinds of things are going on in Canada. And of course, we have the added element here of the prospect of, carbon tax, pretty significant carbon tax. And so we do see industry focused on emissions reduction, carbon tax would drive incremental kind of operating costs. And we are as well to the nature it says the -- nature of a dialogue that's pretty consistent in front of desk between us. So we have methane reduction program going on. And we're investigating the system's potential to reduce emissions through electrification. We see investments in 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, you know, 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. But the best way to mitigate that impact on carbon price is through investments that lower emissions as we go forward.

That’s helpful. Thank you.

Thanks, Andrew.

Our next question comes from Patrick Kenny of National Bank Financial. Please go ahead.

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. And of course, contracting with yourself down the main line and A&R. Just curious how meaningful this trend could be in terms of financial upside for you. And 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 overtime?

I am going to take that Patrick. So we do know is natural gas demand, is forecasted to continue to grow in the coming decades globally. And LNG rather is going to be an important component of global energy demand and transition. So North America has positioned really well to participate in that growth, whether it's, to the Gulf Coast or whether it's off the West Coast to Canada. We have a very strong portfolio of highly integrated interconnected assets across Canada, US and Mexico. So we sit on top of the WCSB in the Marcellus positions as well to participate. We can get to the Gulf Coast through the US assets. We can get to the west coast. And what the opportunity is for us is even if, we want to direct provide direct access to LNG facilities, but there's also opportunity to fill the void left by gas leaving the continent. So 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 more -- 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 Matt Taylor of Tudor, Pickering, Holt & Co. Please go ahead.

Yes. Thanks for taking my questions 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 n 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 comments. With respect to electrification of compression within our Canada gas system, our obligation with a prescribed rate of return is to deliver the least cost alternative. Currently, that least cost alternative, in most instances, is to deliver -- or 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. And we do believe that inflection point is somewhere around $50 or $60 a tonne, 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. And, 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. So those are the two things that I see on that question. Nat [ph] and Corey, is there anything else you want to add to that?

Yes. 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. And so, 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, Francois, 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 about this -- looking at this, I mean. We can make the argument, carbon taxes could still be viewed very politically. So perhaps, maybe not just looking at the least cost alternatives is the right way to be looking at this longer term?

So 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 sometime 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 and minimize our emissions. And do it at in an affordable fashion at the lowest possible cost. But it will simply take sometime, 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 US Capital Advisors. Please go ahead.

Good morning guys. Just following up on, that issue of reliability and electric compression for gas pipelines. So, most battery storage is about four hours. And so how do you handle the reliability issue on gas pipeline and putting in electric compression?

Hey Francois here.

Yes. Go ahead.

I will take that Francois. Actually what we are doing with the VR project, for example, is putting in a dual drive that is both Gas and Electric driven. So 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 there's a clutch that will then drive the electric motor. So you have 100% reliability with respect to these dual drives that we're putting in. It's not just an electric unit. Is that makes sense?

Yes. That makes sense? Yes, that's what we're doing. I just the way is this, to me, that was like, oh, maybe that's not good for a pipeline. And then, 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 affiliates that are our Power and Storage business that Corey runs. And, you know, enter into arm's length commercial arrangements with the regulated affiliates.

Okay. Thank you. And then, on off the carbon grid, just is that dependent and was that dependent at all on temporary in a pipeline merger with some of the pipelines being used in that? And how does that the determination of impact upon that?

Yes, Becca thanks for the question. This is Bevin. Our assets partners with Pembina, we remain focused in developing this world scale carbon transportation system. And both of us as partners have an extensive network of pipelines that can rely on the project. And it's not just specific pipelines, but its corridors and interconnections. And so, we believe that we can leverage our, our both of our asset bases, as well as work with other industry partners to fulfill the development of the full grid.

So the inter pipeline, merger breaking part has no impact on the project.

At this time, no. They wouldn't, we're still in very early stages of pulling together all the pieces of the lines that would contribute. And in a -- in the outcome that Brookfield is successful with the interpipe acquisition, you know, we'll definitely look to work with them as well to see if they can also be part of this industry solution.

Right. 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, compared in the release was the detail about unit 3 on Bruce and the hydrogen pressure levels. And I know you mentioned that you didn't think it was materials for 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 plans -- some in the on the US 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, you know, kind of 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. And we have done a fair amount of R&D at the site and amongst all the can do operators to resolve the issue. And so until the CNSC process is complete, I don't want to comment and 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. And but you're competent 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. And so the impact on unit 3 is different than what it would be on those other units.

Got it? Thanks. Thank you. much appreciate it, guys.

Thanks, Michael.

Our next question comes from Alex Kania of Wolfe Research. Please go ahead.

Thanks. I just had one question. I guess the theme of a lot of the new investment opportunities are into energy transition and Tennessee rehabilitation and just trying to make the product cleaner. But it's just, you know, thinking about your history with respect to portfolio management. Are there any new assets or whatnot that are in the existing portfolio today that you feel like, could be sold or divested to maybe improve the overall kind of footprint, if you kind of think about that long term transitional strategy? It'll 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 shown a willingness and an adeptness of that. Whenever we started looking at our growth versus our internal capacity, we look to minimize share count growth. And we look for the cheapest source of funding to -- for the new projects here. So 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 $5 to $6 billion a year range. That's said, we're into the pretty good stuff now. We have to be cognizant and this has consequences. The optionality embedded in our assets and the network value that Tracy alluded to and Stan has alluded to earlier, where we've got a dozen and a half pipelines across the system and taking a piece out or the certain components actually detracts from the overall network value there. So, something we'll look at, but there is nothing jumping out of any magnitude right now were we think it's a candidate for that. But anytime we're looking at an investing beyond internal capacity, it's something we will evaluate.

Great. Thanks. Best 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 Francois Poirier. Please go ahead. Mr. Poirier.

Thank you. So 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 $21 billion secure 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 will continue to focus on safety, sustainability, working according to our values and responding quickly to market signals and signposts. Now, before closing, I would like to acknowledge that this is Don's last quarterly conference call. He is stepping down as CFO on July 31, and will retire on November 1 after 27 years with the company. As a long standing 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 1, 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'm confident he will maintain a 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.