Thanks very much, and good morning, everyone. I’d like to welcome you to TC Energy’s 2020 third quarter conference call.

Joining me today are Russ Girling, President and Chief Executive Officer; Don Marchand, Executive Vice President, Strategy and Corporate Development and Chief Financial Officer; François Poirier, Chief Operating Officer and President, Power and Storage; Tracy Robinson, President, Canadian Natural Gas Pipelines and Coastal GasLink; Stan Chapman, President, U.S. and Mexico Natural Gas Pipelines; Bevin Wirzba, President, Liquids Pipelines; Corey Hessen, Senior Vice President, Power and Storage; and Glenn Menuz, Vice President and Controller.

Russ 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 the heading Events and Presentations. Following their prepared remarks, we will take questions from the investment community.

If you are a member of the media, please contact Jaimie Harding following this call and she’d be happy to address your questions. 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 reenter the queue. Also, we ask that you focus your questions on our industry, our corporate strategy, recent developments and key elements of our financial performance.

If you have detailed questions relating to some of our smaller operations or your detailed financial models, Hunter and I would be pleased to discuss them with you following the call. Before Russ 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 earnings before interest, taxes, depreciation and amortization or 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. With that, I’ll now turn the call over to Russ.

Thank you, David, and good morning, everyone, and thank you all very much for joining us today. Clearly, the past seven months has been a difficult time for many families and businesses across our North American footprint.

When COVID-19 was declared a global pandemic in March of this year, the services we provide in Canada, the United States and Mexico were all deemed critical, given the important role our infrastructure plays in delivering the energy people need across this continent. This essential designation included both our daily operations and our construction projects.

We take that responsibility seriously, and I’m proud that we’ve continued to deliver the energy that millions of people rely on every day, and at the same time advanced capital projects that are vital to the powering of the North American economy for many decades to come. As always, we conducted our business in a safe and reliable manner, employing thousands of workers, fulfilling our obligations to suppliers and supporting the communities where we operate.

Despite the challenges brought by COVID-19, our operations have largely been unimpacted with few exceptions flows and utilization levels have remained in line with the historical and seasonal norms, underscoring the critical nature of our energy infrastructure assets. With approximately 95% of comparable EBITDA coming from regulated and/or long-term contracted assets, we continue to be largely insulated from the short-term volatility associated with volume throughput and commodity prices.

As a result, it’s highlighted in our third quarter report, our $100 billion portfolio of high-quality long-life energy infrastructure assets continue to produce strong financial results. And we continue to realize the growth expected from our industry-leading capital program.

Today, we are advancing $37 billion of secured capital projects. In addition, we continue to progress $11 billion of projects under development, including a refurbishment of another five reactors at Bruce Power as part of their long-term life extension program.

Earlier this year, we took significant steps to fund our 2020 capital expenditure program and maintain our strong financial position, despite the challenging capital market conditions. Specifically, we enhanced our liquidity by more than $11 billion through the issuance of long-term debt in both Canada and United States, the establishment of incremental committed credit facilities and various portfolio management activities.

When combined with our predictable and growing cash flow from operations, we continue to be well-positioned to fund our industry-leading capital program. Looking forward, we expect our solid operating and financial performance to continue.

And therefore, despite the pandemic, our outlook for full year 2020 remains essentially unchanged with comparable earnings and cash flow per share anticipated to be similar to the record results we produced in 2019. While we’re proud of our financial performance, we know our ongoing success depends on our ability to balance profitability with safety, environmental and social responsibility.

We have a 65-year track record of safe and reliable operations, but we recognize that we can always do better. As a result, we remain focused on continuous improvement and understanding shifting long-term fundamentals to ensure our business remains stable, resilient, and in an ever evolving energy landscape.

TC better informed, we recently published our 2020 report on sustainability and in ESG data sheet. Together, these reports demonstrate our ongoing focus on sustainability and transparency of reporting.

They provide a comprehensive look at TC Energy’s performance on environmental, social and governance topics that matter most to all of our stakeholders. Sustainability at TC Energy means meeting today’s energy needs while safely, reliably and economically finding responsible solutions for our energy future.

It is a continuous evolution of our principal’s approach to creating, enduring, economic and societal value, while delivering the energy people rely on today and into the future. We encourage you all to visit our website to access these reports and learn more about what we’re doing.

With that as an overview, I’ll expand on some of the recent developments beginning with a brief review of our third quarter financial results. Don will provide a more detailed review of our financial results and liquidity in just a few moments.

So excluding certain items, comparable earnings were $893 million or $0.95 per common share for the three months ended September 30 compared to $970 million or $1.04 per share in 2019. Comparable EBITDA was $2.3 billion, while comparable funds generated from operations were $1.7 billion.

For the nine months ended September 30, comparable earnings were $2.9 million billion or $3.05 per common share compared to $2.9 billion or $3.11 for the same period in 2019. Comparable EBITDA of $7 billion and comparable funds generated from operations of $5.3 billion were also similar to the amounts reported last year.

Each of these amounts reflects solid operating performance of our legacy assets, as well as contributions from $3.1 billion of new long-term contracted and rate-regulated assets placed into service in 2020 so far. This was partially offset by a low contribution from our liquids marketing business, lower equity income from Bruce Power due to the Unit 6 major component replacement program and the effect of certain assets sales that helped to fund our secured capital program.

Next I’ll make a few comments about our three core businesses. Firstly, in Natural Gas Pipelines customer demand for our services remain strong, despite the impact of COVID-19 on the broader North American economy.

This can be seen in the volumes transported across our network with the NGTL system field receipts averaging 12.1 billion cubic feet a day, Canadian Mainline Western receipts averaging 3 billion cubic feet today, our broader U.S. pipeline network moving approximately 24 billion cubic feet a day, and our Mexican pipelines moving approximately 1.8 Bcf a day through the first nine months of this year.

Each of these amounts are similar to or greater than the volumes removed over the same period last year. At the same time, we continue to advance $22 billion of capital projects associated with our Natural Gas business.

The program includes significant expansions of our NGTL system, capacity additions across our U.S. network, the Villa de Reyes project and the Tula project in Mexico, and our Coastal GasLink project in British Columbia, which will play an important role in delivering clean Canadian Natural Gas Asian markets to displace coal.

As part of this program, we’re pleased to have recently received approval from the government of Canada for our 2021 NGTL system expansion project. The approval will allow us to commence construction activities of this $2.9 billion program.

That will provide a total of $1.5 billion cubic feet a day of incremental capacity by April of 2022. Turning to our U.S.

Natural Gas Pipelines, where our expansion plans now include the incremental investment of approximately US$200 million for the Wisconsin Access project that will replace, upgrade and modernize certain facilities, while reducing emissions along portions of the ANR system. Enhanced facilities, which are expected to be placed into service in the second half of 2022, will also improve reliability being our system and allow us to serve the needs of utilities in the Midwestern United States under long-term contracts.

Like the Elwood Power and our Horsepower Replacement project announced in July, this is another great example of an in-corridor expansion that will allow us to meet the growing demand by utilizing existing facilities and our existing right-of-ways. Also in U.S.

pipelines in later July our Colombia Gas Transmission system file a Section 4 rate case with FERC, requesting an increase in its maximum transportation rates effective February 2021. It’s Colombia’s first rate case, filing in over 20 years and seeks to recover a prudently incurred operating costs as well as a fair return on and of our historical and future investments.

In this expansive system, it provides customers with reliable access to low-cost natural gas. At the same time, we continue to pursue a collaborative process to find a mutually beneficial outcome with the Columbia Gas transmission customers through settlement negotiations.

Finally, in Natural Gas Pipelines, construction activities continue on the 2.1 billion cubic feet a day Coastal GasLink project that will connect abundant Western Canadian Sedimentary Basin natural gas reserves to the LNG Canada export facility from Kitimat, British Columbia. With more than 3000 workers along the right of way this summer, we have been installing pipe and advancing work on compressor and meter station facilities.

Although the project continues to review costs and schedule due to scope increases, permit delays and COVID-19 impacts. We do not expect the results to have a significant impact on our future equity contributions to the project.

Finally, we continue to work 21st nations that have executed agreements with Coastal GasLink project to provide them with an opportunity to invest in the pipeline through an option to acquire a 10% equity interest in that project. Turning to our Liquids business, which generated solid results during the first quarter or during the first nine months of 2020, despite the extraordinary volatility in global crude oil markets.

While the volatility has had a significant impact on our market link and liquids marketing businesses, Keystone has continued to produce solid results as it serves important markets in the U.S. Midwest and Gulf Coast and is underpinned by long-term take-or-pay contracts for 555,000 barrels a day with very strong counterparties.

Also in the Liquids Pipelines business, we continue to advance construction on Keystone XL during the third quarter, while managing the various legal and regulatory matters. In Canada, construction activities at our pump stations and along more than 180 kilometers of the mainline right-of-way continued to advance.

In the U.S., we continue to make progress under our revised 2020 construction plan with over 1,500 union works building 12 pump stations and completing the Canada-U.S. border crossing.

At the same time, we continue to seek authorizations from the U.S. Army Corps of Engineers for necessary permits and approvals to reconvene U.S.

Mainline pipeline construction into 2021. Keystone XL continues to be a very important project, both Canada and United States, it will create thousands of high paying union jobs and advanced energy security for both nations in an environmentally sustainable and responsible way.

In late September, we are pleased to announce the signing of a historic agreement with Natural Law Energy that will facilitate the largest indigenous equity investment of its kind in North American energy infrastructure. A final agreement, which is expected to be completed in the fourth quarter, would formalize Natural Law Energy’s participation in Keystone XL, providing with an opportunity to sharing the benefits of pipeline over the long-term as a very valued partner.

The project will require an additional investment of approximately $8 billion. It is underpinned by a 20 year take-or-pay contracts that are expected to generate US$1.3 billion of incremental EBITDA on an annual basis once placed into service in 2023.

To advance the project, we partnered with the Alberta government who will invest approximately US$1.1 billion of equity into the project and fully guarantee a US$4.2 billion project level credit facility. Once the project is completed and placed into service, we expect to acquire the government of Alberta’s equity investment and refinance the credit facility.

Moving forward, we’ll continue to carefully manage the various legal and regulatory matters as we construct the pipeline, which will have the capacity to move 830,000 barrels a day of responsibly produced energy from the Canadian oil sands to the continent’s largest refining market in the U.S. Gulf Coast.

Turning now to power, where Bruce Power continued to produce solid results through the first nine months of this year. In January, Bruce Power also commenced work on the Unit 6 major component replacement or MCR program, which took that unit offline.

We expect to invest approximately $2.4 billion into that program, as well as the ongoing asset management program through 2023, when the Unit 6 refurbished and is targeted for completion. In late March, Bruce Power declared a force majeure under its contract with the independent electric system operator because of COVID-19.

The force majeure covered the Unit 6 MCR and certain asset management work. That said, early in May, work on the Unit 6 MCR resumed with additional prevention measures in place for worker safety.

The impact of the force majeure will ultimately depend on the extent and duration of the global pandemic. On October 1, the Unit 6 MCR project achieved a major milestone with the commencement of the Fuel Channel and Feeder Replacement Program.

At the same time, operations and plant outage activities on all other units continued as expected through the third quarter. So in summary, today we are advancing $37 billion of secured growth projects that are largely expected to enter service by 2023.

We’ve invested approximately $13.5 billion into that program to date with approximately $5 billion of those projects expected to be completed by the end of 2020. Notably, they’re all underpinned by cost of service regulation or long-term contracts giving us visibility to the earnings and cash flow they will generate as they enter service.

Based on the strength of our financial performance and promising outlook for the future, earlier this year, TC Energy’s Board of Directors increased the quarterly dividend to $0.81 per common share, which is equivalent to $3.24 per common share on an annual basis. This represents an 8% increase over the amount declared in 2019 and is the 20th consecutive year that our Board of Directors has raised the dividend.

Over that same timeframe, we have maintained consistently strong coverage ratios with our dividend on average, representing a payout of approximately 80% of comparable earnings and 40% of comparable funds generated from operations, leaving us significant internally generated cash flow to invest in our core businesses. Based on the continued strong performance of our base business and the growth in earnings and cash flow, we expect to realize, as we advanced our $37 billion capital program, we expect to continue to grow our dividend at an average annual rate of 8% to 10% through 2021 and 5% to 7% thereafter.

Before I close, I’d like to offer a few words on my pending retirement. As we previously announced, our Chief Operating Officer, François Poirier will succeed me as President and Chief Executive Officer and will join the Board effective January 1, 2021.

François has been part of our ELT for five years now and has been a significant contributor to our thinking, our strategy and the execution of our plans. He’s always been committed to our values and displayed consistent integrity, vision and persistence.

I’m confident that he along with the entire executive team here at TC and our 7,500 dedicated employees they will continue to navigate the challenges and capture the growth opportunities that lie ahead with the same discipline that you’ve come to enjoy at our company over the last number of decades. Looking forward, I expect our assets will continue to provide an essential service to the functioning of the North American society and to the economy and the demand for our services will remains strong.

We have five significant platforms for growth: Canadian, U.S., Mexican and Natural Gas Pipelines, our Liquids Pipelines and Power and Storage business. As we advance our $37 billion secured capital program, we expect to build on our long track record of growing earnings, cash flow and dividends per share.

We also have $11 billion of projects in the advanced stages of development and expect numerous other in-corridor organic growth opportunities like the $200 million Wisconsin Access project that we announced today to emanate from our extensive and critical asset footprint. Looking forward, we will continue to focus on safety, sustainability, working according to our values and responding quickly to market signals and signposts to ensure we remain industry-leading and resilient as we grow shareholder value.

With that, I’ll turn it back to Don who will provide you with some more details on our third quarter financial results and our financial position.

Great. Thanks, Russ and good morning, everyone.

As outlined in our results issued earlier today, net income attributable to the common shares was $904 million or $0.96 per share in the third quarter compared to $739 million or $0.79 per share for the same period in 2019. For the nine months ended September 30, 2020 net income attributable to the common shares was $3.3 billion or $3.55 per share compared to net income of $2.9 billion or $3.09 per share in 2019.

Third quarter results included a $6 million adjustment to the after-tax gain previously recorded on the sale of a 65% equity interest in Coastal GasLink, along with an incremental $45 million after-tax loss on the disposition of the Ontario natural gas-fired power plants. Third quarter of 2019 also included certain specific items as outlined on the Slide and discussed further in our third quarter 2020 report shareholders.

These specific items, including unrealized gains and losses from changes in risk management activities are excluded from comparable earnings. Comparable earnings for the third quarter were $893 million or $0.95 per common share compared to $970 million or $1.04 per common share in 2019.

For the nine months ended September 30, 2020 comparable earnings were $2.9 billion or $3.05 per share compared to $2.9 billion or $3.11 per share in 2019. Turning to our business segment results on Slide 16.

In the third quarter, comparable EBITDA from our five operating segments was $2.3 billion, representing a $50 million increase – sorry, decrease compared to 2019. Canadian Natural Gas Pipelines comparable EBITDA was $94 million higher than third quarter 2019, primarily due to the net effect of increased rate-based earnings, higher flow through depreciation and financial charges and lower flow through income taxes on the NGTL System, along with the recognition of Coastal GasLink development fees.

I would note that the regulated Canadian Natural Gas Pipelines changes in depreciation financial charges and income taxes impact comparable EBITDA but do not have a significant effect on net income as they are almost entirely recovered in revenues on a flow through basis. NGTL System net income increased $21 million compared to the same period in 2019.

As a result of a higher average investment base, we continued system expansions and reflects an ROE of 10.1% on 40% deemed common equity. Net income for the Canadian Mainline decreased $3 million, largely due to lower incentive earnings.

U.S. Natural Gas Pipelines’ comparable EBITDA of US$647 million, or C$863 million in the third quarter, grows by US$43 million or C$67 million compared to 2019.

This was mainly due to lower operating costs on Columbia Gas and Columbia Gulf, and increased earnings from ANR due to the sale of natural gas from certain gas storage facilities. Mexico Natural Gas Pipelines comparable EBITDA of US$128 million or C$170 million, increased by US$13 million or C$17 million versus third quarter 2019, primarily due to higher Sur de Texas equity income resulting from the commencement of transportation services in September 2019 and lower interest expense on its peso-denominated inter-affiliate loan attributable to lower interest rates and the weakening of the Mexican peso.

Liquids Pipelines comparable EBITDA declined by $160 million to $415 million in the third quarter compared to 2019, as a result of lower uncontracted volumes on Keystone and reduced contributions from liquids marketing activities. Third quarter Power and Storage comparable EBITDA fell by $65 million year-over-year, primarily due to the planned removal from service of Bruce Power Unit 6 in January for its MCR program, along with lower Canadian power earnings, largely as a result of the sales of our Ontario natural gas-fired power plants in April.

For all our businesses with U.S. dollar-denominated income, including U.S.

Natural Gas Pipelines, Mexico Natural Gas Pipelines and parts of Liquids Pipelines, EBITDA was translated into Canadian dollars using an average exchange rate of $1.33 in third quarter 2020 compared to $1.32 for the same period in 2019. As a reminder, our U.S.

dollar-denominated revenue streams are in part naturally hedged by interest on U.S. dollar-denominated debt.

We then 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. Now turning to the other income statement items on Slide 17, depreciation and amortization of $673 million increased $63 million versus third quarter 2019, largely due to new projects placed in service in Canadian and U.S.

Natural Gas Pipelines, which amounts in Canadian Natural Gas Pipelines are fully recoverable in tolls on a flow-through basis. Interest expense of $559 million in the quarter was $14 million lower year-over-year, primarily due to the net effect of higher capitalized interest mainly related to Keystone XL, partially offset by the completion of Napanee in first quarter 2020, lower interest rates on lower levels of short-term borrowings and long-term debt issuances, net of maturities.

AFUDC decreased $29 million compared to the same period in 2019, largely due to NGTL System expansion projects placed in service in 2020. Comparable interest income and other was $32 million in the third quarter, down from $49 million for the same period in 2019, primarily on account of lower interest income on the previously noted peso-denominated inter-affiliate loan receivable from the Sur de Texas joint venture reflecting lower interest rates and the weakening of the Mexican peso in 2020.

Again, our proportionate share of the offsetting interest expense on this loan is reflected in income from equity investments in our Mexico Natural Gas Pipeline segment with no resulting impact on consolidated net income. Income tax expense included in comparable earnings was $184 million in third quarter 2020 compared to $260 million for the same period last year.

The $76 million decrease was mainly due to lower pre-tax earnings, reductions to the Alberta corporate income tax rate and decrease flow-through income taxes on Canadian rate-regulated pipelines. Excluding Canadian rate-regulated pipelines where income taxes are a flow-through item and are therefore quite variable along with equity AFUDC income in U.S.

and Mexico Natural Gas Pipelines, we expect our 2020 full year effective tax rate on comparable income to be in the mid to high-teens. Comparable net income attributable to non-controlling interest of $69 million in the third quarter increased by $10 million relative to the same period last year, primarily due to higher earnings at TC Pipelines LP.

And finally, preferred share dividends of $39 million were in line with third quarter of 2019. Now turning to Slide 18, during the third quarter comparable funds generated from operations totaled $1.7 billion, and we invested approximately $2.3 billion in our capital program.

In light of extreme market volatility earlier in 2020, we took significant steps to bolster our liquidity at that time, including the issuance of long-term debt, establishment of incremental committed credit facilities and the completion of various portfolio management and project financing activities. When combined with our strong internally generated cash flow and cash on hand, we are effectively fully funded for the year.

Furthermore, through partnership arrangements and project level credit facilities, substantial portion of the financing required to complete both Keystone XL and Coastal GasLink is also in place. Now turning to Slide 19, this graphic illustrates our forecasted sources and uses of funds in 2020.

The left column details total funding requirements of approximately $16.9 billion comprised of long-term debt maturities and redemptions of $3.9 billion, dividend and non-controlling interest to distributions of approximately $3.2 billion and capital expenditures of approximately $9.8 billion, reflecting 100% of Coastal GasLink costs up to the date of its partial sale and only equity contributions to the project thereafter. Capital expenditures, which we’re previously forecast to be $10.3 billion, are trending somewhat lower, primarily due to the delay of certain capital projects included in the 2021 NGTL System expansion.

Funding sources are shown in the second column and included forecast internally generated cash flow of approximately $7 billion, proceeds from the disposition of our Ontario natural gas-fired power plants, sale of a 65% interest in Coastal GasLink and associated project level financing, which together generated approximately $4.9 billion. The Government of Alberta’s equity investment of Keystone XL projected at US$1.1 billion and $3.8 billion comprised of long-term debt that was issued in April, along with movements and balances of cash on hand and commercial paper outstanding.

Taken together, we are effectively fully funded for 2020, and along with $13 billion of committed credit facilities in place and well-supported commercial paper programs in both Canada and the U.S., position to confidently navigate any prolonged period of disruption should that occur. Now turning to Slide 20, in closing, our solid financial and operational results highlight our longstanding diversified low-risk business strategy, the importance of our essential energy infrastructure to the North American economy, as well as the contribution of new high quality assets from our ongoing capital program.

Our overall position remains robust. Today, we are advancing a $37 billion suite of secure projects through resilient, internally generated cash flow and array of attractive funding options, which are poised to generate high-quality long-life earnings and cash flow underpinned by strong fundamentals, solid counter parties and premium service offerings.

Additionally, our business segments situated across three countries offer numerous distinct platforms to replenish our growth profile with further attractive and executable in-corridor organic investment that will be required as the world both consumes more energy and adapts to an evolving energy landscape. That is expected to support an annual dividend growth of 8% to 10% in 2021 and 5% to 7% thereafter.

Finally, we will continue to maintain our historical financial strength and flexibility at all points of the economic cycle. 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.

[Operator Instructions] With that, I’ll turn it back to the conference coordinator.

Good morning, everyone, and congratulations Russ on your retirement and François on your new role. I wanted to start with a capital allocation question, understanding that your focus on long-term.

You’ve maintained your dividend guidance, obviously with this press release, but with the widening spreads to fill anyhow – virtually any interest rate you look at. How does that influence your capital allocation strategy and dividend growth?

Well, I mean, I can start and I’ll let François jump in. As you know, our capital allocation strategy has been consistent for approximately two decades.

It’s predicated on, firstly, focusing on our balance sheet and making sure that we maintain our financial strength and health. We’ve continuously strived to maintain the highest credit ratings in our sector.

Secondly, to ensure that we have a healthy split between return of capital to shareholders and cash retained for growing our businesses. Historically, that’s been a 60% of our free cash flow being reinvested in our core businesses and 40% being allocated to return of capital to our shareholders through a dividend.

That has worked well for us for the last two decades, where we’ve been able to reinvest 60% of our free cash flow into our core businesses, doing that at approximately an 8% return. 7% to 8% return has resulted in a growth in earnings, cash flow and dividends per share of approximately 7% over that period of time.

We’ve tried to maintain disciplined payout ratios relative to our peers. We’re focused on about 80% of our earnings being returned to our shareholders, approximately 40% of cash flow, as I said, and maintaining a strong dividend coverage ratio.

So as we move forward, the marketplace at various points in time has pointed to, you should increase or change that capital allocation model at the increased payout ratios and take on more financial leverage. And the other points in the cycle, it’s pointed us to changing it in any other direction.

We believe in consistency over the long-term. And at this point in time, as we look at our future, we don’t see any reason that we would change that capital allocation in order to chase short-term market changes.

What our job is quite frankly, Bob, always as you know, we’re focused on growth in earnings and cash flow per share and maintaining that strong discipline. And our view is if we do that over the long haul, we’ll reward our shareholders and our shareholders will reward us with an appreciation in our stock price.

Thank you for that fulsome answer. The other question I had has to do with the hydrogen economy, obviously, very early days.

But can you give us a high level view of how you see the interplay with development of a hydrogen economy over time with the long haul transmission assets?

Yes, Robert, this is François. I think it’s clearly early days yet, but we do absolutely see it as a long-term opportunity for us to deploy additional capital into our gas transportation assets.

Some of our storage fields actually would be convertible to hydrogen storage and even in our power generation business going forward as and when hydrogen becomes more cost competitive. There’s a lot of work that still needs to be done to understand what percentage of hydrogen could be safely blended into our pipelines.

With methane, obviously, we – our foremost concern is for the safety of our employees and the communities in which we operate. And so we’re going to be very careful about making that assessment.

There are many existing natural gas turbines that can already accommodate a blend, although the long-term impacts on performance, integrity, maintenance, et cetera, are things that we’re working very hard here to understand. And then of course, in the longer term, the potential for hydrogen to provide long duration storage in the power sector could be a very interesting opportunity for us, and is consistent with our theme of investing and affirming resources as we are developing our pump storage projects and our battery projects.

Yes. Everything you described there, it makes complete sense, but obviously it’s long dated.

I wonder at a high level, if you had any sense of what the – when meaningful investment can be made? What’s the timeline for that?

I know it’s a shot in the dark at this point, but what’s your best guess?

I think it’s too early to speculate on individual investment opportunities at this point, Robert.

Yes. Okay.

Thanks everyone.

Okay. Thanks, Rob.

Thank you. Good morning.

If I can continue on the capital allocation question, and you touched on payout ratios and the like. If I think more about the businesses and with some of the concerns out there about the existential risks to hydrocarbon infrastructure, does any of this cause you to think about allocating material capital to new business lines in the near-term, or accelerating a shift to greener infrastructure, particularly via transformational large scale M&A?

There’s a lot in your question, Robert. Is it – we always have one eye on our base business and one eye on the future and how quickly this energy transition is going to evolve in and what it’s going to look like.

We believe that our assets, which has sort of proven out by the resilience that you’ve seen over the pandemic, the importance of these assets for the foreseeable future. To your question, how long will that future be is the question that the people are asking.

As we think about, our assets today that the primary asset base that we have is in the Natural Gas business. They’re all rate regulated assets for the most part.

And that we think about that life cycle of assets very carefully on an annual basis, we have historically, and we’ll continue to look forward. We have the ability to manage, the capital stock turnover with both depreciation rates and with abandonment surcharges that we have in place on the pipe.

If we think that the useful life is going to be less than the anticipated useful life that we’ve got assumed in our rates today, we’ll make adjustments accordingly to recover both return and on capital. And then redeploy that capital into whatever infrastructure is going to require to service that continued energy demand.

What we know is that the energy demand isn’t going to change, it may take different forms going forward and we would look to reinvest, as we’ve done historically, you’ve seen us rotate capital in and out of different energy transportation and delivery systems based on the demand. I think what I can tell you about our experience is that we have had experience in all forms of energy delivery.

We run a river, hydro, nuclear. We’ve got large investment in a nuclear power business.

We built solar facilities, we built wind facilities and we’ve also participated in coal and natural gas. And so as things transition, we believe that we’re well positioned as François just said, things like hydrogen in order to move gaseous molecules around, don’t know what the timeframe as we just said to Rob, and how long that’s going to take, but I think we’re well-positioned to capture those investments as they occur.

So we’ll continue to monitor the pace of depreciation and other things in our system, and look to redeploy capital into whatever delivery systems are going to be required in the future. I think one of our strong competitive advantages has been we do touch a lot of customers today across the continent.

We see these changes coming probably sooner than others do and can adjust our capital accordingly. What we found is that you’re building things in existing footprints has a huge advantage.

The Bruce refurbishment, for example, I mean, that can’t be replicated outside of an existing footprint. So I think as things change, we believe that we’re well positioned to manage the transition as it occurs.

And that’s going to take some time. Some of our businesses may happen sooner rather than later, and other businesses may last a lot longer than that some people are anticipating, but I guess rest assured, we’re on top of it.

And I guess the way we’re viewing the world is as people think about deploying literally trillions of dollars of capital into this transition, we’re a company that knows how to deploy large capital amounts into large scale projects, getting them permitted and working with regulators, customers, and other stakeholders to actually bring them into a reality. So to the extent that the North America is going to invest that kind of capital, we believe that’s a great growth opportunity for us for many years yet to come.

And then just on your willingness to pursue transformational large scale M&A to either get into a new business line or really bulk up green infrastructure within the business?

I’ll take a shot and then I’ll let François join in a bit. I mean, I don’t think that our disciplines going to change as we will look for opportunities that can add shareholder value.

So at the confluence of both strategic opportunity, as you’ve seen us act on in the past, add a price that we can add and economic and shareholder value. And so we’re always on the lookout for things that make sense to us.

And at the current time, there’s nothing on our slate, but obviously, if we maintain the kinds of disciplines we have in the past around strong balance sheet, access to capital. When those opportunities arise, we believe that we will be at the best position.

And one of the reasons we – and our number one sort of priority capital allocation is being positioned with a strong financial position and balance sheet to be able to act at all points in the cycle on opportunities that can add shareholder value. Maybe François will add.

Yes. Maybe just to add to that, Russ, and thank you for the question, Robert, I think what we’ve demonstrated in the past not only from a capital discipline standpoint, but you look at the Columbia transaction, we have a competency of integrating businesses very well into our organization, and we view that as a competitive advantage.

So to the extent, an opportunity presents itself, we have the ability to evaluate and integrate those types of opportunities and the willingness to do so. Those types of situations present themselves rarely over a management team’s career.

And so we can’t rely on that approach for us to build critical mass and the portfolio composition that we want to see over time. We do actually through our opportunities to develop organically different projects.

We do see an opportunity even without M&A to actually build some scale in our Power and Storage business as the economy looks to continue to electrify. Not only with respect to Bruce, as Russ mentioned, another example is our two pumped storage project that are under development.

We have our own electric load that we’re starting to think about how to electrify that. And so there’ll be a number of other opportunities aside from transformational M&A that will allow us to grow that business.

And if an opportunity does present itself to do something more substantial, as I said, we’ve got the skills and the willingness to consider it.

Got it. Thanks.

So if I can just finish with Columbia, is there any update or anything you can give on potential timing as you get into the negotiations? And just in terms of the magnitude, I know you haven’t wanted to talk how to given the negotiations, but is it fair to say that you could have just waited one year to get out of the moratorium, the fact that you’re filing early, you see at least the potential for a material financial impacts of the company?

Hey, Robert, this is Stan. Yes, with respect to the rate case and the timeline, our attention is still to settle this case with our customers.

For top sheets, which basically out there, initial position on the case, are likely to be released sometime in mid-December. So once those are released, we’ll begin meaningful negotiations with work staff, our customers, and other interested parties.

And those discussions are likely to extend into a Q2 of 2021. In the unfortunate event that the settlement negotiations do not prove fruitful, we’ve had meetings with an administrative law judge, and he has assigned the case that includes a procedural schedule that would have a final ruling in the case sometime in Q4 of 2021.

So either way, the case will be resolved sometime next year. With respect to guidance, yes, you’re correct that I really can’t share anything with you at this point in time.

And I guess you’re also correct to the extent that we would not be filing a case to the extent there was not a meaningful way.

Thank you so much.

Okay. Thanks, Robert.

Thank you. Before I ask my questions, I want to add my congratulations to both Russ and François, on the exciting announcements.

And wish you all the best, Russ, in your retirement.

Thank you.

With – I’d just add further to Robert’s question about your Columbia rate case and settlement. I’m just wondering how any potential tax increases in the U.S.

might be incorporated into not just Columbia gas rates, but prospectively across your pipeline network in the U.S.?

Yes. Linda, this is Stan.

I can address that. All things equal.

We will have the ability to file rate cases to increase our federal income tax allowance that are embedded in our rates. We obviously have a case ongoing right now in the Columbia system.

And our expectation would be that any settlement would include some sort of mechanism for us to recover that should have higher file rates be implemented. We also are planning on filing a rate case next summer on the ANR system.

So we will address any increased federal income tax rates there as well. Columbia and ANR together represent about two-thirds of our revenue stream across all of the U.S.

assets. And in addition, we have our rate cases filed – planned to be filed on GTN and Great Lakes also in 2022.

So we’ll have a mechanism in place to address those in relatively short order. And also keep in mind, particularly on the Columbia system, about 52% of our revenues are under fixed negotiated rates, which still have the higher federal income tax allowance embedded in them from prior to the 2018 tax reductions.

Thank you. That’s helpful context.

Moving on to your financing plans, and I guess maybe this is a blended question with respect to your exciting announcement recently on the Natural Law Energy MOU signing. I’m just wondering how this might influence your financing plans going forward.

How meaningful could this First Nations investment be? What might be the scale of additional MOUs with additional parties?

And just wondering what the timing might be on – bringing on additional partners that haven’t already joined the project?

Good morning, Linda, it’s Don. I’ll start and then I’ll turn it over to Bevin, with respect to the Natural Law MOU.

Our funding plans for KXL are really haven’t fundamentally changed. About two-thirds of the funding will come from Government of Alberta equity injections and the guaranteed debt facility that will be in place there.

And our proportionate share of the remaining funding will be from DRIP and hybrid issuance as we’d outlined previously, probably about US$1.5 billion of hybrids and US$1.2 billion of DRIP when we turn that on. To the extent we have third-party investments would probably reduce those amounts somewhat, but depends on the extent of that investment.

The Natural Law deal is still being finalized here, but I’ll let Bevin speak to where that’s at.

Sure. Thanks, Don, and thanks Linda for the question.

TC, as you know, is a long history of working with indigenous nations, but we’re really proud to have partnered with in a historic way, Natural Law Energy, who represents five First Nations in Alberta and Saskatchewan. And we’re working closely with other nations in Canada and the tribal nations in the U.S.

to similarly bring them in as partners. We’re operating on their traditional territories, and we share a set of core values about the environment and sustainable development.

So we’re working hard on those agreements right now. We can anticipate getting those done here, hopefully in the fourth quarter.

And once they’re finalized, we’ll be able to make the level of investment public and the structure of those transactions. In addition, I guess, outside of those equity investments, we expect to create $500 million of benefits to the indigenous nations directly through jobs on the KXL project and with indigenous suppliers.

So all in all, pretty exciting to move forward with them being part of our project.

Thanks for the additional context. Maybe just a follow-up question on the renewable power opportunity, and I’m wondering what the current load is across TC Energy’s network of compressors and pumps?

And what factors might you consider beyond direct economics and cost savings on converting those to run on solar or wind versus not?

I think the load on the base system is several hundred megawatts. And would be when you factor in both the base system and Keystone XL, over 1,000 megawatts between the two to the extent we were able to enter into some PPAs to consume renewable energy.

It would it would make us one of the top 10 corporate purchasers of renewable energy in the world. So there’s substantial scale there.

As we think about opportunities to going forward to reduce our greenhouse gas emissions, there is also an opportunity for us to electrify some of our compression on our Natural Gas system. I can tell you that there was several hundred thousands of horsepower of energy that’s consumed for moving gas along the system.

And there’ll be an opportunity there over the – we expect as the capital stock turns over and turbines reached the end of their useful lives for us to be considering other alternatives. We are starting to factor carbon emissions into our capital allocation decisions.

I could certainly attest that in many jurisdictions the cost of renewable power is very competitive with other sources as to the cost of carbon emissions, we don’t have clarity in every jurisdiction as to what the plan or the program is going to be. So it’s difficult for us to actually quantify those impacts.

But when you factor in current competitiveness, you factor in reliability concerns that there will be opportunity for us to be developing some renewable projects to meet our own load. We’re very confident over the next several years, Linda.

And I think maybe just I’d add to that, Linda. You had asked what the criteria are, what we’re looking for, obviously the milestones of moving from – the policy initiatives that have been announced moving to legislative frameworks, which then move into regulative frameworks.

I mean, obviously we’re always concerned about return of and on capital and capital recovery over the life of the assets. And our view would be, if actually we’re going to implement these policy initiatives and have the manifest themselves into legislation regulation.

I think those are some of the signals we’re looking for, how are regulators going to be using carbon pricing in their cost benefit analysis. And then when we put forward our least cost alternatives, they’re sinked up with where the regulators are going to be.

So these are the kinds of changes that are going to occur. And I think, as I said earlier, we’re pretty excited about it.

There’s some uncertainty with respect to it, but this is the direction the marketplace is going. And as we see capital stock turnover over the next 10, 20, 30, 40 years there’s going to be tremendous opportunity for a company like ours to continue to participate in that and deploy capital into infrastructure that’s going to reduce emissions over the long-term.

Thank you. I’ll jump back in the queue.

Thanks, Linda.

Good morning. Maybe just starting off on energy transition hit a bunch here, but maybe just kind of rounding it out a bit.

You talked about the compressors there, and it seems like a pretty sizable opportunity. Just wondering if you’re able to share kind of what ballpark CapEx could be as far as renewables generating the electricity for compressors there.

That’d be helpful. I mean, it seems like more than a few billion here.

And generally speaking, along with pumped hydro, do you see other opportunities to kind of participate in energy transition fuel types?

Thanks for the question, Jeremy. And literally like – the entirety of our compressor fleet would be literally thousands – upon thousands of megawatts.

Obviously only a subset of those would be actionable in the near-term. And over time, as we factor in things like reliability access to backup supply from – and access to the transmission grid where gas supply for backup generation might be available, as Russ said, we do need and this is one of the signposts we’re looking for is for legislation and regulation to catch up the policy.

Obviously, the policy trends are tending in that direction, but until the regulatory construct allows us to factor in all of those issues into our equipment decisions, we’re going to continue to adhere to our conservative risk preferences. As to other parts of the value chain, we might be interested in looking at and investing in, obviously you see our pump storage projects in Alberta and Ontario, particularly the one in Ontario is at significant scale.

We’re looking for other opportunities for pump storage. We think it’s a technology that’s proven on a global scale about 98% of electricity storage comes from pumped hydros, so we’re looking for other opportunities there.

And we talked about hydrogen already to the extent there are other opportunities for us around renewables and battery storage. We are developing some projects here in Alberta, and we’ll be continuing to look at projects, as I said before, along the theme of firming resources, because we believe that the generation mix continues to trend towards renewables, firming resources will be increasingly important to ensure the reliability of the grid.

And as well we want to make sure that we have investments as diversified – well-diversified as possible in terms of different fuel types in generation. To the extent opportunities present themselves for us to develop transmission assets, it’s long linear infrastructure that’s regulated.

It’s definitely a core competency of ours. And we will consider those as well.

Jeremy, I can provide some context. Your question is, is this bigger than a breadbox, yes, it is.

But going back to my earlier comments around, what it takes for this company to continue to grow at 5% to 7% on an annual basis going forward 60% of our free cash flow is in that capacity is in the neighborhood of about $5 billion. So can we find $5 billion of investments going forward beyond our current capital program to sustain the growth rate of the company?

And all the things that François just said, I mean, if governments are measuring this in terms of trillions of dollars, you’ll get our system, the capital stock turnover, as you’ve mentioned, you can measure that in multi-billions of dollars. And what we need to grow the company on an ongoing basis is about $5 billion.

We think we’re extremely well positioned to capture $5 billion of growth on an annual basis. If you just looked at the kinds of things that we’re actually doing today, $1 billion dollars a year of Bruce Power for the next 10 years, just refurbishing those reactors to meet that emissionless desire down the road much less, some of the other things that we’re talking about.

So that’s what gives us the confidence in the statements we’ve made with respect to future growth. This is a trend that is going to continue.

People are going to deploy capital and desire to deploy capital into making the energy delivery systems across North America, more efficient and more environmentally friendly. And we have one of the largest and best position footprints across North America to actually make that occur.

So we’re very confident and comfortable that opportunities will continue. And that from a recovery of capital – return on capital, given the nature of our regulated businesses and our contracts and the fundamental position of our assets in the marketplace that we’ll get return of and on our capital, we’ve got deployed today.

And as that capital’s returned to us, we’ll be able to deploy it back into these other things that we are talking about.

Great. That’s a helpful detail.

Thank you for that. And then, historical you’ve talked about picking up high quality assets during periods of stress.

It seems like we have distress in spades these days. And I was just wondering if you could update us here given what’s happened in the markets before you talked about quality assets not being cheap enough last year, it seems like maybe quality assets could be cheaper this year.

And you talked about electric transmission, possibly being of interest for you. But I was even thinking kind of like on the U.S.

LDC side, given the precipitous decline, the PEs there, maybe that presents the map there is much easier than points in the past. So just wondering any thoughts that you could provide on those topics?

I think as we think Jeremy about M&A as we always have, we look to acquire high quality assets at distressed points in the cycle, as opposed to distressed assets that require improvement. This has been a successful formula for us underpinned by patience and a strong balance sheet.

So part of that is you need to have a willing counterparty. And I think as we’ve assessed the opportunities, we’ve sent out some feelers.

And if I were on the other side of that inquiry, I would be looking at my own internal and external cash requirements, the implied cost of capital in the different sources of capital that I could raise to fund my own growth. And I would compare that to the implied cost of capital that any potential acquirer is offering in the form of the purchase price.

So we don’t think enough time has transpired yet. That would be our observations for any counterparty to be willing to consider partying with in a very volatile environment – a high quality asset.

But we’re patience and if those opportunities present themselves, we’ll be ready.

Jeremy, it’s Don here. We are on the beneficial position of having $37 billion in our secured program and a proven ability to replenish that.

So we’re not reliant on M&A to grow, but again, it’s – for François answer, we’ll be patient – we’re looking for the same high quality stuff that comprises our portfolio today. We’re not looking to move up the risk spectrum.

We’re not looking at GNP assets and the like. And in many cases, the crown jewels that we would want are not sitting in distressed entities right now.

But given who we are, we see most of what transacts in North America or might transact and will act if and when it makes sense.

Got it. That’s helpful.

Thank you.

Thanks, Jeremy.

Good morning, everyone and congratulations Russ and François as well. Just another question on capital allocation, if the next U.S.

administration sidelines, Keystone XL, have you looked at your crude oil business with a potential lack of growth there? Could you look to recycle that capital on some of those initiatives that you’ve mentioned earlier?

I guess, I mean, it start with the fundamentals, we will always look to deploy capital in the way that that’s sort of add shareholder value. But, what we know is that, the U.S.

Gulf Coast refining complex is that the largest and most sophisticated in the world. Every indication that we have today is – even in a two degrees policy environment that the world’s still going to need 60 or 70 million barrels a day of oil, the U.S.

will still continue to refine oil. And the Gulf Coast complex is still very resilient in that scenario.

The options for heavy oil, quite frankly, are limited, there the Middle East, Venezuela and Canada. And so as we look at our – the Keystone corridor as it exists today is an extremely valuable corridor.

I think that’s being borne out, even in an environment where we’ve seen huge demand destruction in the short run as a result of COVID, that corridor still gets utilized at a very, very high rate. And we expect that to continue as you look at the third largest crude oil reserve in the world being in Canada, connected to the world’s largest and most sophisticated refining complex.

That seems to be something that that has longevity and stability to it. How it gets value going forward obviously is a question that will be on our minds.

But from a business standpoint the biggest issue the industry has today is lack of egress. That’s why the Keystone XL is important.

That’s why TMX and other things are important to the industry today. And we expect that to continue going forward.

So those are still the fundamentals. I think you’ve heard from Don, François and what we’ve done historically, we look hard and long at fundamentals, and then we look at who’s willing to support those fundamentals with long-term contracts.

And right now, I would say, if we had any more capacity available on base Keystone, we would be able to sell that capacity for 20 year terms to credit worthy counterparties.

All right. Thank you for that.

And then just pivoting over to the NGTL System. Can you add a little bit of color on how much capital you think will be deferred from 2021 to 2022?

And how the delays and the approvals have kind of altered construction schedules there?

Sure, Rob. NGTL is of course a critical asset for the WCSB.

WCSB is positioned really well. And the volumes have been strong even through this COVID period, very prolific and very competitive.

So the infrastructure that we put in place to facilitate access to market is critical. We did go out to market it was an open season earlier this year, just to check on whether all of the capacity that we had planned was still needed.

The result of that was that indeed it is, although a portion of it moved around a little bit from a timing perspective, either a delay of a season or a year. And so we’ve accommodated that.

And as a result, you’ve seen our capital program changed a little bit from a timing perspective. If you – the one other thing that’s happened of course is, we had the delay in the approval of the 2021 program.

We had got – we received finally the GSE approval just recently here. And that has a number of increased or enhanced conditions in it.

So the move like in, the delay of that program has altered the shape of our capital program as well. So I think we’ve laid out the movement of the program in our disclosure, but we’ve come off 2021 by just over $1 billion and then add that back on in 2022 and 2023, but net the capacity that we’re providing to the basin remains the same.

All right. I appreciate that.

Thank you.

Thanks, Rob.

Hi. Thanks.

Good morning. On François comments around incorporating carbon emissions or transition and capital allocation, is this a new thing you’re doing posts the DSG since just when this started?

then, and really, as you look forward on projects, like you’ve just announced on ANR pump hydro store, are you effectively including a theoretical and no snow carbon taxes in your IRR analysis?

Thanks for the question Ben. I think, at this point – so the front part of your question was is this new for us?

I think it’s emerged to the forefront of our analysis over the ensuing couple of years. We’re thinking long and hard about our own greenhouse gas emission reduction strategies.

I think there’ll be more to report on that here coming up in 2021. We clearly are focusing from a qualitative standpoint on the impact of emissions to our objectives as a corporation and in our objectives in our business units.

We do run various scenarios of potential economic costs whether they’re carbon taxes or regulation that’s existing or proposed as we think about capital allocation going forward. But until we have clarity from a legislation and a regulatory standpoint, it’s difficult for us to actually pin down what the economic impacts might be.

And it’s one of the signposts, as we’ve been talking about that we’re looking for going forward to incorporate economic impacts of emissions into our capital allocation.

As you think about carbon pricing going forward, there’s uncertainty with respect to what it’s going to look like. Similarly, as we thought about deploying 30 and 40 year capital, we look to understand commodity prices, for example, but we don’t make our capital allocation decisions based on a forward market view of commodity prices.

And we wouldn’t make our capital allocation decisions based on a forward view of carbon pricing, because there’s just too much uncertainty to try to finance it with a long-term assets. What we look for is – what do those fundamentals tell us, and then, can we incorporate that capital investment either into a rate base, which give this confirmation that that we’ll get recovery of an on capital or through a long-term contracted structure similar to the Coastal GasLink project for example, where we look to get return of on capital in the primary term of that 25 year contract.

We’re not betting on the future of what we – what our view of commodity prices or in this case, carbon pricing is going to be. What is the investment community say about that?

What do counterparties say about that? And are they willing to provide the security that we need to bring the financing to a large scale project.

That’s how we make capital allocation decisions. So it has been incorporated in our thinking in the past.

But again, as we put forward, for example, projects in the past that may have reduced emissions, but ended up with a larger cost. When we think about putting those in front of our regulator, we’ve always put those in front of our regulator, what they approve and don’t approve is based on what their criteria are for approval in low cost, relative to other whether those be societal or other benefits or costs in the trade-off of making a regulatory decision.

As you know, they’re not always made just on pure economics. It’s a considered weighing of economics, but as well as other impacts on environment in communities.

And then they come to a conclusion on whether it’s in the national interest or public interest or not. So that’s how we think about it is, these – carbon has been a conversation we’ve been having for many years and we’ll continue to be.

And they’ll get incorporated as required into our decision-making, as people place their capital investment in allocation decisions based on those things going forward.

Okay, great. Thanks for that.

And on the pump hydro or battery storage, where do you think that fits on your target return, that 7% to 9% range, is it more in Bruce Power sort of return? Is it more an NGTL sort of return?

So we have not yet had the conversation about commercial underpinnings. The two goalposts are rate-based type treatment and the other goalpost would be a Bruce type structure.

Each of those has an allocation of risk between the counterparty and ourselves, and we would expect that the returns would be commensurate with the allocation of risk. So think of the range as somewhere between the Bruce return and the NGTL type return.

And it’s the allocation of risk between the two parties that would determine where we land, but we have not yet had that conversation.

I think in all cases you can expect that it’s in that lower risk end of the spectrum within that range, is that we have field risk preferences that have allowed us to operate in that range for some time, expect that to continue. But don’t expect this to take on, as I said, any sort of forward commodity risk or things like that that are incorporated into our thinking.

Okay, great. Well, I’ll leave that firmly, and François, congratulations again.

Russ, all the best in retirement, I’m sure you’re not going to miss these earnings calls and thanks for taking our tough question to over the years. Really appreciate it.

Appreciate it. Thanks.

Thanks, Ben.

Thanks. And I’ll let go my congrats to both Russ and François as well.

Just looking at the Columbia rate case, the requested ROE of 16%, at least on the surface, it looks a little bit higher than some of the other recent pipeline rate cases. Is there some specific circumstances here that wanted to hire ROE for Columbia?

Yes, I think when you look at just our risk preferences, risk factors overall, we are sparely within what FERC is mandating in their new policy with respect to setting ROE with respect to that 50% DCF, 50% Cap (M). So our take is a 65% equity thickness with a 16% return on equity maybe at the high end.

But it’s justifiable given the environment that we’re operating in today.

Okay, got it. And sorry, go ahead.

I would just say, clearly in the environment that we’re in from a cost of equity standpoint, which is what the ROE is, is your cost of equity capital clearly in the environment that we’re in. The risk that has been perceived to be injected into the industry, I don’t think you can argue the cost of equity capital has declined.

And certainly that goes into our consideration of an ROE we ask.

And then I’m just curious, what is the advantage of doing a pumped hydro project for Ontario versus building out additional battery storage that you have expertise in both or at least investments in both. Is one more cost effective than others, I guess what’s the puts and takes?

So certainly, there’s a – at the scale, we’re contemplating here, the Meaford project is a 1,000 megawatts. It’s eight hours in duration.

From a reliability standpoint, there is no battery alternative that can deliver that kind of scale and duration. So yes, there is a cost advantage for pump storage at that length of duration.

But also it’s a reliability question.

Thank you.

Good morning, everybody. Just back on KXL, you guys have done a good job with the Alberta government taking the project as far as you can, up until this point.

Can you just confirm that all the border-crossing infrastructure required is essentially in place and what legal recourse you might have? Assuming the presidential permit is in fact retracted after the election, and also maybe if you might look to re-file your previous NAFTA claim as well?

Okay. Thank you, Patrick.

We have completed the 1.2 mile international border-crossing. We completed that earlier this year.

But we’ve taken the past year to basically listen to all the stakeholders and have made great progress in creating a new vision for the project. We have signed for labor agreements with leading North American trade unions, established a green energy fund for those unions partnered with the five First Nations as equity partners as we’ve already discussed.

So we’ve taken and we’ll continue to take a pretty progressive step in demonstrating how we’ll develop the infrastructure responsibly and sustainably. And we believe that by positioning the project this way, it aligns with the expectations of either administration going forward.

And so the recourse and the plan certainly there are approaches we can take, but we’re taking a more proactive approach and positioning the project to continue advancing it.

Okay. Thanks for those comments.

Lots of discussion already on the energy transition, just curious if we can get your updated thoughts around LNG infrastructure and whether or not there’s accelerated push towards clean energy on a global basis, increases or decreases your willingness to invest capital towards extending your gas network into LNG assets relative to say, this time last year,

Thanks for that question, Patrick. It’s François.

First of all, the benefits of LNG are clear to the extent the purchasers of LNG are replacing coal fire generation with natural gas fired. There’s obviously a greenhouse gas reduction component to that that we think is meaningful.

As Russ talked about and I will be talking about going forward, our risk preferences and our capital allocation model going forward will not change. What might evolve over time is where we allocate our capital based on where the opportunities are.

And so to the extent we have an opportunity to invest capital in either regulated assets or in the case of LNG, more likely underpinned by long-term contracts with credit worthy counterparties. We’re very open to that type of investment.

And so if an opportunity presented itself in the future along that part of the value chain, we would certainly evaluate it.

And with respect to those opportunities on the hydrogen front, can you just confirm if Bruce Power might be a candidate for generating green hydrogen? Or is there something within the refurbishment agreement that legally prohibits you from integrating hydrogen with Bruce?

On the latter question, I don’t have that level of detail. So we’ll have to follow up with you.

But clearly, nuclear power is a terrific asset class to participate in the production of green hydrogen through electrolysis. And as we look for opportunities beyond the refurbishment of the units at Bruce as part of our long-term strategic planning and opportunity set for Bruce the production of green hydrogen is very much something that we’re going to be contemplating.

Okay. Thanks for those comments and congratulations François and to you Russ on your retirement.

Thanks for taking my question. And I’ll echo the retirement, succession, congratulations announcements.

A couple of easy questions for you, can you remind us if the cost of building Coastal GasLink rises, who embeds that incremental cost, who bears that to the project owners, including you, or does that simply raise the tariff that gets charged to shell and the other LNG owners?

Michael, it’s Tracy. So the agreement that we have with LNG Canada would contemplate that any differences between the estimated cost and the actual cost of building the pipeline would be rolled into the tolls with respect to certain circumstances, right?

So as we go forward, we’re in constant dialogue with LNG Canada about that. But essentially that’s how it works.

Got it. And then on the U.S.

Gas Pipeline side, can you just I’m trying to think about what the dollar millions revenue requirement has it is, trying to think about the Columbia Gas rate case, the Section 4 that’s underway. What is the revenue increase requests that you guys have asked for in that case?

Yes, Michael, I don’t have the exact number off the top of my head in terms of what the filed revenue increase was but we could circle back with David and get you that.

Okay. And do you see yourselves as significantly under earning at either Columbia Gas or ANR, or is this more about getting the modernization trackers set up on an annualized basis?

So you can kind of upgrade the compression on both systems?

Clearly, the modernization program is a big part of the filing and what we proposed is a seven-year $3 billion program, but also if you look back over time, our maintenance capital spend for example, has outpaced our depreciation expense to the tune of about $1 billion on a cumulative basis. So when we talked to you that our maintenance capital is recoverable in rate cases, this is a rate case to recover that historical investment that we made in the system.

Got it. Thank you much appreciated.

Thanks. Good morning.

In general, you savored a pretty simple approach to corporate structure over the years, and then maybe for obvious reasons you’ve engaged in partnership structures with KXL and CGL, but would you look to maybe enhance value and extract capital out of certain assets with a partnership approach and then take the proceeds you could get, whether allocate them to accelerate energy transition or share buybacks. Could you give us some color on, do you think about that possibility and that kind of approach?

Thanks for the question, Andrew, it’s François. As we’ve done in the past with CGL and with Northern Courier and others.

To the extent and our equity – and we have a need to raise either internal or external equity. We look for opportunities to find that equity at the lowest possible cost.

We’re obviously always mindful about share count, as we think about our capital raising efforts. So if there’s an arbitrage opportunity between the private markets and the public markets and we have the ability to avail ourselves of that it’s something that we will consider going forward.

So I wouldn’t suggest that at the current time, there are any specific initiatives to do that on any of our assets, but it’s a tool in our toolbox. And one that we’ve now built the mousetrap with CGL, and it could possibly be a mousetrap we could use again, in other circumstances, should the opportunities to redeploy that capital look attractive and avail themselves to us.

Yes, it’s Don, here. It’s always a balancing act as well, because we do value a simple structure.

And when it’s hard to get stuff done, owning a 100% of it has great benefit to us. And as always, we look into things like tax consequences, structural subordination from a fixed income perspective as we look at these things, but François comment that we always look at per share metrics when we’re looking at increasing share count.

Okay. That’s very helpful color.

And then maybe just an extension, when you think about just cost of capital and we’ve seen alternative capital providers of the longer term view, come into some pipeline situations in particular in the Middle East recently in the last few years. What do you think that speaks to cost of capital in North America?

Yes. Tough to say, if there’s a direct read through on that.

There is a lot of private money looking at exactly the kind of assets we look at and the kinds of assets we actually have in-house here. From a debt capital perspective, I would say our debt cost of capital is actually gone down.

It’s really on the equity side. And so it depends how much leverage these guys are able to use, but it’s the exact same annuity revenue streams that we’re looking at here.

In terms of geographic location, I’m not sure exactly the extent of the correlation between the Middle East and something and say middle of America that we would again, try to read through on that front.

Okay. Thank you very much.

Thanks. Just maybe two questions.

The first one is just on the TC Pipelines transaction, if you could talk to us a little bit about how the timeline of that would work out. And are there any – and I’m thinking about structurally here, if there’s any synergies or any kind of strategic kind of elements that might work a little bit better with it integrated into the broader system?

More, more strongly, I guess. And the second question is just on Columbia.

It’s been a few months since we’ve had Atlantic coast pipeline get canceled, and we’ve heard that, discussions with those shippers looking elsewhere. Are there any opportunities or how has that evolved for the Columbia system?

It’s Don here, I’ll start with the pipe LP question. We do have an active proposal in front of the LP, so we are limited in what we can say here.

I would just say that these are core assets that we operate in and before we consolidate into our existing financial statements, simplification of structure for us as important here as well. We think what we’ve offered here is compelling and mutually beneficial to both the TC Energy shareholder and the LP TC shareholder and the LP unit holder, be some modest amount of operational synergies in the light.

But again, it’s already fully consolidated into our operations and financials and given just the relative size of the LP versus TC any impact would be fairly small here.

Yes. And then, this is Stan, with respect to your second question.

You’re correct that while Dominion’s ACP project may have gone away, the demand for gas in the region has not. And we do have a couple of what I would say, small scale expansion opportunity, particularly in the Virginia that would cover a portion of ACP load.

Originating them is likely to take in the first quarter of next year. So we don’t have anything definitive to share with you.

Other than, this is a great opportunity for us to actually look at instilling electric compression or additional electric compression across our system as part of this project. So stay with us and we’ll give you an update Q1 next year.

Great, thanks. Congrats Russ and François as well.

Take care.

Okay. Thanks, and thanks to all of you for participating today.

We very much appreciate your interest in TC Energy, and we look forward to talking to you again soon. Have a great day.