TC Energy Corporation (TRP) Q4 2020 Earnings Report, Transcript and Summary

Thank you for standing by. This is the conference operator. Welcome to the TC Energy 2020 Fourth Quarter Results Conference Call. [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 2020 fourth quarter conference call. Joining me today are François Poirier, President and Chief Executive Officer; Don Marchand, Executive Vice President, Strategy and Corporate Development and our Chief Financial Officer; 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, President, Power and Storage; and Glenn Menuz, Vice President and Controller. François and Don will begin today with some opening comments on our financial results and certain other company developments. A copy of the slide presentation that will accompany their remarks is available on our website. It can be found in the Investors section under the heading Events & 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 would 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 François begins, I would 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 will refer to measures such as comparable earnings, comparable earnings per share, comparable EBITDA and comparable funds generated from operations. These comparable measures are considered to be non-GAAP measures. And as a result, they may not be comparable to similar measures presented by other entities. These measures are used to provide you with 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 François. François Poirier: Thanks, David and good afternoon everyone and thanks for joining us this afternoon. While 2020 presented some of the greatest global challenges in recent history, we quietly and reliably continued to deliver the energy millions of people rely on everyday. Notably, the services we provide in Canada, the United States and Mexico were deemed essential, given the important role our infrastructure plays in the functioning of the North American economy and the well-being of people across the continent. We take that responsibility seriously. And as always, we conducted our business in a safe and reliable manner, employing thousands of workers and supporting communities wherever we operate and we delivered strong financial results for our shareholders. As you are accustomed with our risk preferences, approximately 95% of our comparable EBITDA comes from regulated and/or long-term contracted assets largely insulating us from the short-term volatility associated with the volume throughput and commodity price fluctuations. As a result, our $100 billion portfolio of high-quality long-life energy infrastructure assets produced record results again in 2020, highlighting the resiliency of our assets and our utility-like business model. At the same time, we continue to advance the capital program that will help power the North American economy for decades to come. More specifically, we placed $5.9 billion of growth projects into service in 2020 and advanced another $20 billion of secured capital projects and that’s excluding Keystone XL. In addition, we continued to progress more than $8 billion of projects under development as well as numerous other opportunities. Looking forward, we expect our solid operating and financial performance to continue with ongoing growth in EBITDA. We also expect comparable earnings from common shares in 2021 will be generally consistent with the record results we produced in 2020. Finally, we know our ongoing success will depend on our ability to balance profitability with safety, environmental and social responsibility. Society expects its energy to be delivered with care for people and our planet and we also demand this of ourselves. We have a 70-year track record of safe and reliable operations, but we recognize we can always do better. And so as a result, we are focused on continuous improvement, including potential paths to reducing our GHG emissions and understanding shifting long-term fundamentals to ensure our business remains sustainable and resilient in an ever-evolving energy landscape. Now with that as an overview, I will expand on some recent developments, beginning with a brief review of our 2020 results. Excluding certain specific items, comparable earnings reached a record $3.9 billion or $4.20 per common share in 2020 compared to $3.9 billion or $4.14 in 2019, an increase of 1.5% on a per share basis. Comparable EBITDA of $9.4 billion was similar to last year, while comparable funds generated from operations also hit a record high of $7.4 billion, which is a 4% increase over 2019. Each of these amounts reflects the solid performance of our legacy assets as well as contributions from the $5.9 billion of new assets we placed into service during the year. Based on the strength of our financial performance and our promising outlook for the future, TC Energy’s Board of Directors declared a first quarter 2021 dividend of $0.87 per common share, which is the equivalent of $3.48 per share on an annual basis. This represents a 7.4% increase over the amount declared in 2020 and is the 21st consecutive year that our Board has raised the dividend. Next, a few comments on our five operating businesses. First, in Canadian Natural Gas Pipelines, customer demand for our services remained strong in 2020. And this manifested itself in the volumes transported across our network with the NGTL system field receipts averaging 12.1 Bcf per day and Canadian Mainline deliveries averaging 4.5 Bcf per day, both amounts were similar to the volumes we transported in 2019. At the same time, we placed $3.4 billion of NGTL system growth projects into service. We invested approximately $600 million in maintenance capital on our Canadian assets, which also forms part of rate base. And we received final approval for NGTL’s 2021 expansion program. As a result today, we are advancing $6.7 billion of commercially secured projects on NGTL that will provide an incremental 3.2 Bcf a day of capacity for our customers between now and 2024. Finally, in Canadian Natural Gas Pipelines, we also continue to advance the 2.1 Bcf per day Coastal GasLink project that will connect WCSB natural gas reserves to the LNG Canada export facility in Kitimat, BC. Due to COVID-19, in late December, the BC Provincial Health Officer issued an order restricting the number of workers on industrial project sites in the Northern Health Authority Region of British Columbia. We are working with the provincial health authorities to safely resume construction activities in accordance with that order. We are also working with LNG Canada on establishing a revised project plan for Coastal GasLink. We expect that project cost will increase and the schedule will be delayed due to scope increases, permit delays and the impact of COVID-19, including the provincial health order. Coastal GasLink will continue to mitigate these impacts to the extent possible and these incremental costs will be included in final pipeline tolls, subject to certain conditions. Turning now to our U.S. Natural Gas Pipelines business, where our broad network moved record volumes, averaging approximately 25 Bcf per day in 2020, an increase of 1% over 2019 deliveries. Now during the Polar Vortex that covered most of the U.S. over the past week, we experienced unprecedented sustained demand for our pipeline capacity as we set a record for coincidental 3-day peak deliveries of over 101 Bcf from February 14 to 16, vesting our prior mark set in January of 2019 by about 2.5 Bcf per day. And I would like to extend a big shout out to our employees who have been managing trying personal circumstances yet continue to ensure that we deliver the energy people need everyday. Thank you. Over the past year, we also placed $1.9 billion of projects in service, including the completion of the modernization 2 program on our Columbia Gas Transmission System, while adding nearly $1 billion of growth projects to our backlog. Each of those projects is underpinned by long-term contracts and they are great examples of the in-corridor expansions that will allow us to meet growing demand, while also reducing our emissions. Also, in U.S. Pipelines, in late July, our Columbia Gas Transmission System filed a Section 4 rate case with FERC. The rate case is progressing as expected while we continue to pursue a collaborative process to find a mutually beneficial outcome with our customers through settlement negotiations. Finally, in U.S. Natural Gas Pipelines, in late 2020, we entered into a definitive agreement and plan of merger to acquire all of the outstanding common units of TC Pipelines LP not beneficially owned by us or our affiliates in exchange for TC Energy common shares. A vote on the plan of merger by unitholders is scheduled for February 26. The transaction is expected to close in late first quarter. Approval by the holders of the majority of outstanding common units of TCP is the remaining significant closing condition. Turning now to our Mexican Natural Gas Pipelines, where our five operating pipelines moved approximately 1.8 Bcf per day during 2020. In addition, we advanced the Villa de Reyes project, although a phased-in service of the pipeline has been delayed due to COVID-19. Subject to the timely reopening of government agencies, we now expect to complete construction during 2021. Finally, in Mexico, we completed a project to allow bidirectional flows on our Guadalajara pipeline. It’s a good example of our ongoing collaboration with the CFE on a project that provides access to either LNG imports from the Manzanillo terminus or access to low cost continental natural gas supply at the Guadalajara terminus for delivery to regional markets. Turning now to our Liquids Pipelines business, which generated solid results despite extraordinary volatility in global crude oil markets, while the volatility had a significant impact on our Marketlink and Liquids Marketing business, Keystone continued to produce strong results. The system moved an average of 555,000 barrels per day last year, underscoring its role as an important conduit between abundant North American reserves and key markets. Also in Liquids Pipelines, on January 20, the U.S. President revoked the existing Presidential permit for the Keystone XL pipeline. As a result of this disappointing decision, we suspended the advancement of the project and ceased capitalizing costs, including interest during construction, while we assess our options, along with our partners and other stakeholders. We wish to thank our customers, American and Canadian workers, our partners, the Government of Alberta and Natural Law Energy, labor organizations, industry, the Government of Canada and countless other supporters of this project over the past decade. Turning to our Power and Storage business, where Bruce Power once again produced solid results as its strong operating performance continued. Last January, work commenced on the Unit 6 major component replacement, or MCR program, when we took the unit offline. We expect to invest approximately $2.6 billion in the program with Unit 6 expected to return to service in 2023. While COVID-19 has presented some challenges, good progress is being made on the project, achieving a major milestone on October 1 with the commencement of the fuel channel and feeder replacement program. We also continue to advance work on the refurbishment of another five reactors as part of Bruce Power’s long-term life extension program. Finally, in Power, we continue to engage various stakeholders in an effort to advance a large pump storage opportunity in Ontario. The project is designed to store emission-free electricity and provide backstop to the intermittency associated with the energy provided by a renewable generation. In summary, today, we are advancing $20 billion of secured projects that are expected to enter service by 2024. All are underpinned by cost of service regulation or long-term contracts, giving us visibility to the earnings and cash flow they will generate. Approximately, $4.2 billion of these projects are expected to be completed in 2021, including $1.7 billion of maintenance and modernization initiatives tied to our regulated pipelines. Looking forward, our goal is to continue to invest $5 billion to $6 billion annually to deliver on our long-term growth plans. As you can see on this slide, our starting point is our $20 billion secured capital program. Beyond that, we expect to continue to invest $1.5 billion to $2 billion annually in maintenance and modernization programs across our extensive pipeline network, approximately 85% of which is recoverable through our regulated businesses. We are also developing a significant suite of future opportunities, including several projects that will allow us to deploy capital along our extensive pipeline corridors. And we see opportunities in renewables and the firming resources needed to manage their intermittency, electrifying our fleet as well as emerging technologies such as hydrogen. In summary, I believe we will continue to be opportunity rich. And I believe that our challenge will be to allocate capital thoughtfully to those projects that are aligned with our capabilities, our risk preferences and our return requirements, while playing a role in the evolving energy landscape. Based on the continued strong performance of our base business, combined with our organic growth plans, we expect to continue to grow our dividend at an average annual rate of 5% to 7%. And I want to make it clear that there is no assumption of M&A embedded in our growth rates nor is M&A a current area of focus for us. As always, the growth in dividend is expected to be supported by sustainable growth in earnings and cash flow per share and strong coverage ratios. In closing, I would like to leave you with the following key messages. Looking forward, I expect our assets will continue to provide an essential service to the functioning of the North American economy and demand for our services will remain strong for decades to come. We have five significant platforms for growth: our Canadian, U.S. and Mexico natural gas pipelines, our Liquids Pipelines and our Power and Storage business. As we advance our $20 billion of secured capital projects and various other organic growth opportunities, we expect to build on our long-term track record of growing earnings, cash flows and dividends per share. We will also 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. I will now turn the call over to Don who will provide more details on our financial results and outlook. Don?

Thanks, François and good afternoon everyone. As outlined in our results issued earlier today, net income attributable to common shares was $1.1 billion or $1.20 per share in the fourth quarter of 2020 compared to $1.1 billion or $1.18 per share for the same period in 2019. Fourth quarter 2020 included an income tax valuation allowance release of $18 million related to reassessment of our ability to utilize certain prior year’s U.S. tax losses, an additional $18 million income tax recovery related to state income taxes from the sale of Columbia Midstream assets in 2019 and an incremental after-tax loss of $81 million to sell remaining post-closing obligations on the sale of the Ontario natural gas-fired power plants in April 2020. Fourth quarter 2019 results also included several specific items, as outlined on the slide and discussed in the fourth quarter 2020 financial highlights release. All of these specific items as well as unrealized gains and losses from changes in risk management activities are excluded from comparable earnings, which reached $1.1 billion in fourth quarter 2020 or $1.15 per share, $110 million or $0.12 higher than last year. Turning to our business segment results on Slide 18. In the fourth quarter, comparable EBITDA from our five operating segments was approximately $2.3 billion consistent with 2019 results. Canadian Natural Gas Pipelines comparable EBITDA of $682 million was $64 million higher than the same period last year given the net effect of increased rate base earnings, flow-through depreciation and flow-through financial charges on the NGTL system as our investment program advanced and additional facilities were placed in service. Coastal GasLink development fee revenue recognized in 2020 and lower flow-through income taxes on the NGTL system and the Canadian Mainline. I would note that for 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 recovering revenues on a flow-through basis. Net income for the NGTL system increased $17 million compared to fourth quarter 2019, mainly due to a higher average investment base from continued system expansions. Net income for the Canadian Mainline decreased $2 million year-over-year. U.S. Natural Gas Pipelines comparable EBITDA of $706 million or CAD919 million in the quarter rose by $58 million or CAD64 million compared to the same period in 2019. The increase was mainly due to strong operating cost management across a number of our pipelines. Mexico Natural Gas Pipelines comparable EBITDA of $128 million or CAD166 million was consistent with results in fourth quarter 2019. Liquids Pipelines comparable EBITDA declined by $64 million to $408 million in fourth quarter 2020, primarily due to lower contributions from liquids marketing activities, largely from reduced margins. Power and Storage comparable EBITDA fell by $49 million year-over-year to $161 million, primarily due to the net effect of the removal in service of Bruce Power Unit 6 in January 2020 for its MCR program and lower Canadian power earnings, largely as a result of the sale of our Ontario natural gas-fired power plants in April 2020 partially offset by fewer planned outage dates on the remaining Bruce units and improved results from our Alberta cogeneration plants. 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 exchange rate of 1.30 in fourth quarter 2020 compared to a rate of 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 2-year forward basis with realized gains and losses on this program reflected in comparable interest income and other in the corporate segment. Now, turning to the other income statement items on Slide 19, depreciation and amortization of $652 million increased $27 million versus fourth quarter 2019, reflecting new assets placed in service and Canadian Natural Gas Pipelines, which amounts are fully recoverable in tolls on a flow-through basis partially offset by lower depreciation in Power and Storage, mainly due to a 2019 reassessment of the useful life of certain components at our Alberta cogeneration plants. Interest expense of $539 million for fourth quarter 2020 was $56 million lower year-over-year, primarily due to the net effect of higher capitalized interest related to Keystone XL, lower capitalized interest due to the completions happening in first quarter 2020 and the application of equity accounting to Coastal GasLink upon the sale of a 65% interest in the project in May 2020, lower interest rates on short-term borrowings and the foreign exchange impact from a weaker U.S. dollar on translation of the U.S. dollar-denominated interest. AFUDC decreased $22 million to $95 million for the three months ended December 31, 2020 compared to the same period in 2019, primarily due to NGTL system expansion projects placed in service and the suspension for recording AFUDC on Tula effective January 1, 2020 due to ongoing construction delays. This was partially offset by continued investment in our growth projects on Columbia Gas. Comparable interest income and other was $86 million in the fourth quarter, up from $77 million for the same period in 2019, primarily due to realized gains in 2020 compared to realized losses in 2019 on derivatives used to manage our net exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income. This was partially offset by lower interest income in 2020 related to the peso-denominated interaffiliate loan receivable from the Sur de Texas joint venture due to lower interest rates and the foreign exchange impact with the peso. 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 $134 million in fourth quarter 2020 compared to $211 million for the same period last year. The $77 million decrease was mainly on account of lower flow-through income taxes in Canadian regulated pipelines and higher foreign tax rate differentials. Comparable net income attributable to non-controlling interest of $69 million in the fourth quarter decreased by $7 million relative to the same period last year. Non-controlling interest primarily captures public unitholder ownership in TC Pipelines LP and the Government of Alberta investment in Keystone XL. And finally, preferred share dividends were comparable to fourth quarter 2019. Now, turning to Slide 20, during the fourth quarter, we invested approximately $2.2 billion in our capital program, primarily on NGTL system expansions, various U.S. Natural Gas Pipeline projects, and Keystone XL prior to suspending its advancement. Our investing activities were largely funded with comparable funds generated from operations of $2.1 billion and partner equity contributions to Keystone XL. For the full year, comparable funds generated reached a record $7.4 billion. Our balance sheet, liquidity and financial flexibility are all in their historical position of strength. We exited 2020 with debt-to-EBITDA in line with the high 4s and FFO to debt of approximately 15% that we have targeted and we are well positioned to fund our $20 billion secured capital program through our strong internally generated cash flow and debt capacity without increasing share count. As we have suspended the advancement of Keystone XL, we no longer expect to issue hybrid securities or common shares through our dividend and investment program for the purpose of funding the project. Finally, we extinguished $2 billion of 364-day committed bilateral credit facilities, which had been established in second quarter 2020 at the onset of the pandemic as they were no longer needed. Now turning to Slide 21, this graphic highlights our forecasted sources and uses of funds for 2021 through 2023, which is similar to the slide we presented at Investor Day, but updated to remove Keystone XL going forward. Starting in the left column, the total funding requirement over the next 3 years is projected to be approximately $28 billion comprised of dividends of $11 billion; capital expenditures, including maintenance capital of $15 billion; and $2 billion attributed to the pending TC Pipelines LP acquisition. The second column highlights expected internally generated cash flow of $21 billion, which leaves a residual need of approximately $7 billion in the far right column, of which approximately $2 billion is attributed to the pipe LP share for unit exchange. The remaining $5 billion will be funded through a combination of incremental debt, commercial paper and other, including capital recoveries. The program is consistent with our goal of maintaining debt to EBITDA in the high-4s range and FFO to debt of 15%. Now turning to Slide 22, next, I’d like to spend a moment on our 2021 comparable earnings outlook. Additional information is contained in our 2020 annual management’s discussion and analysis, which is being filed on SEDAR today and will be available on our website. Overall, comparable earnings per share in 2021 are expected to be generally consistent with results achieved in 2020 due to the net impact of the following. Canadian Natural Gas pipelines earnings are anticipated to be higher mainly due to continued growth in the NGTL system, higher incentive earnings in the Canadian Mainline, and increased Coastal GasLink development fee revenue due to an expected rise in project activity. U.S. Natural Gas Pipelines earnings are also expected to grow due to an increase in transportation rates on Columbia Gas, which is dependent on the outcome of the Section 4 rate case filed with FERC. In Mexico, we forecast earnings to be lower year-over-year due to fees recognized in 2020 associated with the completion of the Sur de Texas pipeline. In Liquids, earnings are anticipated to be lower than 2020 due to continued challenging market conditions impacting uncontracted volumes on the Keystone pipeline system and margins in the liquids marketing business. Comparable earnings for the Power and Storage segment are expected to decline primarily due to a lower contribution from Bruce Power as a result of greater plant outage days and higher operating costs as well as the sale of our Ontario Natural Gas fired power plants in 2020. Bruce Power availability, excluding Unit 6, was 88% in 2020 and expected to be in the mid-80% range in 2021. Other items impacting earnings include the suspension of AFUDC on Villa de Reyes effective January 1, 2021 given ongoing delays and reduced capitalized interest due to the replication of the Keystone XL Presidential permit, which occurred on January 20. With respect to income taxes, excluding Canadian regulated pipelines where income taxes are a flow-through item and can be quite variable, along with equity AFUDC income and U.S. Natural Gas Pipelines, we expect our 2021 full year effective tax rate to be in the mid to high-teens. Finally, as part of the 2021 outlook, I would note that our exposure to interest rate, foreign exchange and commodity price variability remains quite limited in our diversified portfolio, given approximately 95% of EBITDA coming from contract and regulated assets, various flow-through and sharing mechanisms as well as natural and active hedges in place. We do expect to record an impairment charge in 2021 related to the suspension of advancement of Keystone XL. And as previously noted, we have stopped recording IDC for the project effective January 20. In terms of capital spending, we expect to invest approximately $7 billion in 2021 on growth projects, maintenance capital and contributions to equity investments with the majority attributable to NGTL system expansions, U.S. Natural Gas Pipelines project, the Bruce Power Life Extension Program and normal course maintenance capital, of which approximately 85% is invested in regulated rate base or otherwise recoverable. We do not believe disruptions related to COVID-19 will be material to our overall 2021 capital program, but recognized that uncertainty exists in both the short and longer term. Lastly, turning to Slide 23, closing, I offer the following comments. Our solid financial and operational results in the fourth quarter once again highlight our diversified low risk business strategy and reflect the robust performance of both our blue chip legacy portfolio along with the incremental contribution of equally high-quality assets from our ongoing capital program. Today, we are advancing a $20 billion suite of secured projects and have five distinct platforms for future growth in Canadian, U.S. and Mexico Natural Gas Pipelines, Liquids Pipelines and Power and Storage. Our portfolio of critical energy infrastructure projects is poised to generate high-quality long life earnings and cash flow for our shareholders as well as offer further attractive and executable in-corridor opportunities. That is expected to support annual dividend growth of 5% to 7% in the future. Finally, we will continue to maintain financial strength and flexibility at all points of the economic cycle and is a proven shock absorber to unforeseen market events. That’s the end of my prepared remarks. I will now turn the call back over to David for the Q&A.

Great. Thanks, Don. Just a reminder, before I turn it back 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 will turn it over to the conference coordinator.

Thank you. [Operator Instructions] Our first question comes from Robert Kwan of RBC Capital Markets. Please go ahead.

Hey, good afternoon. Recognizing you have got a lot of stakeholders, you can’t necessarily say something definitive on KXL, but it sounds like you are not expecting a path forward so the project at least one that involves any material TC Energy shareholder capital. So if that’s the case, can you just talk about how you view Liquid Pipelines in general within your overall asset mix, thinking about the lack of visibility for infrastructure-driven growth and especially what it does to your ESG profile? François Poirier: Robert, it’s François. I will get started on this and I’ll ask Bevin to provide some additional color. Our starting point is that this is irreplaceable infrastructure. It’s a very high-quality cash flow stream underpinned by long-term contracts with creditworthy counterparties. And any alternative has to compete with the growth in earnings and cash flow that this is going to generate. And it can play a role in TC Energy’s growth, irrespective of where we decide to allocate our capital going forward. We do see a tremendous amount of opportunities, and I’ll ask Bevin to speak to what we see on the liquids side, but in our Natural Gas and Power and Storage businesses, and that’s going to be high-quality, reliable cash flow that we can allocate wherever we see the best returns and how we want to manage the portfolio going forward. But Bevin, if I could ask you to comment on growth prospects within the liquids business.

Sure. Thank you, François. Robert, to go after the question around the liquids BU’s growth outlook, certainly, our base assets link a very strategic supply basin with the highest demand utilization in the Gulf Coast refining markets than the Midwest refining market. So a very strategic corridor that is irreplaceable. And so while we were developing the Keystone XL project, we were similarly in parallel advancing other opportunities to enhance our service offering for our customers providing different access points to delivery points and looking at – as the market fundamentals shift and supply sources change, looking at where the arbitrage is in the market and finding ways to leverage our existing assets to enhance our growth outlook. Maybe I’ll take your – you also mentioned our path forward just to address that, this is a very complex process. And while we evaluate our path forward, we have begun to immediately wind down our construction activities in both Canada and the U.S. in a safe and responsible manner. And it’s going to take some time to work with our partners and customers to determine what those exact next steps will look like, but we’ll do so consistent with our values in doing the right thing. So hopefully, that answers both your two questions.

That’s great. If I can just finish, turning to M&A and I appreciate the comments that it’s not a focus or needed to reach the 5% to 7% growth rate. But that being said, I guess, maybe this is for François, just now that you’re in the chair. Can you outline your approach or framework for, let’s call it, opportunistic M&A specifically, if you can comment on the willingness to take leverage above your target over kind of a medium-term period to execute that, how you approach the timing for EPS accretion and maybe just structurally, your interest or willingness to acquire assets or platforms of scale where you might have a non-controlling or non-operating interest? François Poirier: Well, there is lots in there to unpack, but I will do my best, Robert. With respect to asset M&A, I think as we’ve mentioned in the past, we always look for high-quality assets at distress points in the cycle, where we’re able to acquire assets that otherwise would not be available because of their quality because the existing owners are in financial distress. We typically don’t look for assets that are of lower quality and need work and deliver value from that perspective. So we do have a list of assets that we would cover over time. I would characterize them as enhancements and directly connected to our existing footprint. And to this point, we have not seen any of those assets become available, although we have had conversations with various parties. In terms of longer term M&A, our value proposition from my perspective is to deliver reasonable amount of growth in dividends with a low-risk business risk profile, underpinned by growth in underlying earnings and cash flow. So as we think about M&A, whether it’s near term, medium term or long term, the value proposition is that whatever assets we acquire have to actually meet that requirement. We don’t feel that our currency at the moment, given where we’re trading relative to our intrinsic value, lends itself to us doing anything dramatic. It’s very difficult when you’re trading at a discount to intrinsic value to generate revenue and cost synergies that close those gaps. So we don’t really think of accretion from a financial accounting standpoint, we think of accretion from an intrinsic value standpoint. And so we are inclined to be patient which is why I mentioned that we’re going to be focusing on our own operational excellence, making sure our assets are delivering the optimal amount of cash flow and performing well from that perspective and then looking to organic growth opportunities from our existing corridors and those types of business opportunities. So from a balance sheet standpoint, in order to be opportunistic, you have to be able to maintain a strong balance sheet and have some dry powder. And so any transaction that would see us taking on even temporarily a significant amount of incremental leverage above our targeted levels is not something that we’re really contemplating at this point.

And just on non-controlling and non-operating interest that has typically been a TC Energy thing, but your approach to something like that? François Poirier: Yes, thank you. Not likely. We enjoy having strategic control and operations of most, if not all of the assets that we have an ownership interest in. You can see with the transaction that we’ve initiated to buy in the LP, that’s a situation where we are the operator. We’re the general partner. We’re very familiar with the assets. And so comfortable with properly assessing risk and managing risk in a situation where you’re not necessarily the operator, it’s a different proposition. And I’m not saying we would never contemplate something like that, but it’s, as you pointed out, it’s not something that we’ve typically done, and that would not be our first approach.

Perfect. Thank you very much. François Poirier: Thanks, Robert.

Our next question comes from Ben Pham of BMO. Please go ahead.

Okay. Thanks. Good morning. Sorry, good afternoon. I was in terms of your business mix now, you got cake off to the roaster and so you look at our percentage of gas pipelines and the rest of your business, you are probably a bit more close to gas than oil now. Is there a strategic long-term focus for you to look more toward diversifying? Is this mix more maybe balancing out over time? François Poirier: I think the way we have thought about our portfolio composition, Ben, over the last number of years is that we work hard to originate opportunities to allocate capital in a manner that’s consistent with our risk preferences and that earn a reasonable rate of return, given the risk profile of the opportunity. And to some extent, the portfolio composition has emanated from the opportunities that we’ve brought forward. We do think that having more diversity going forward would be to our benefit. Our goal is to be able to prosper irrespective of how the energy mix transitions over time. So as we look at opportunities to allocate our capital going forward, we do see significant opportunity for us to invest capital in our existing fairways in our natural gas business. And as we’ve talked about, either through firming resources or building renewables to meet our own electricity consumption from our Power and Storage business, we see some really interesting growth opportunities there as well. And I think, also, as we work toward our GHG emission reduction strategies, we do see an interesting potential for us to be electrifying some of our own footprint, for example, by replacing natural gas turbines with electric motors at some of our compressor stations along our natural gas pipeline corridors. So I think you can see the migration of our capital allocation moving to a bit more diversity and perhaps more toward Power and Storage than has been the trajectory over the last few years as we’ve been monetizing some of those assets to fund our growth program along the Columbia system and in the Canada Gas system as well.

Okay. And maybe to switch to portfolio from – I know you probably lost a need for that now. You are still having in your slides as usually, you have been able to harvest from that the last couple of years, whether it’s oil pipelines or renewables. And to extent, we add more growth going forward, which seems to be the case. I mean is there – do you see any sort of corporate charge opportunities in your portfolio between lower cost of capital players and your public equity valuation? François Poirier: There could be in some circumstances. I think, from a capital allocation standpoint, our job is to maximize the spread between the return we earn on an investment and the underlying cost of capital to fund that investment. So we have the traditional public sources through debt and equity capital markets, but we also have internal equity that can generate it through monetizing individual assets. And we keep a pretty close pulse on private market valuations for assets, and it is something that we contemplate as we look to raise capital to fund our growth program. And it’s something that we would look to in the future. I can tell you that with the growth and capital program that Don walked you through just earlier in the prepared remarks, we’re confident in our ability to fund our existing program through internally generated funds and don’t expect to have the need to raise our share count in any way. So from my perspective, I would view the need to raise external capital beyond our internally generated funds as being a very good problem to have because it means that you’ve got an opportunity that’s sort of accretive to your base case. But right now, the base case does not contemplate any monetization of our existing assets.

Yes. Ben, it’s Don. I will just echo François’s comments and just – our credit metrics are in line. We’re largely self-funded at this point. Any time we have to look at issuing shares, we’ll look at selling things and everything has looked through the lens of per share metrics. But we truly are into the core assets now and with the portfolio effect of what you see on a map and hiving off arms and legs of that is a more difficult proposition, but we feel we’re in the sweet spot right now. We look at simplicity of structure. We look at the optionality embedded in these assets and also the tax consequences of monetizing anything. But at this point in time, there is no pressing need to sell anything and we’re pretty enamored with our portfolio at this stage.

Okay. That’s great. Thank you. François Poirier: Thanks, Ben.

Our next question comes from Jeremy Tonet of JPMorgan. Please go ahead.

Hi, good afternoon. A couple of high level questions here. And I was just thinking with energy transition, a larger focus in the stock market these days, I was just wondering if your thought process has evolved from investor, I guess, conversations on capital stock rotation overall, just the pace of that? And at a high level, how do you see the TRP or portfolio advancing over time? I recognize you kind of touched on that in some of the questions before, but thinking about energy transition, capital stock rotation? François Poirier: I think as you – as we discussed on our Investor Day in November, and you look at some of the tenants or fundamental beliefs that sort of drive our views on asset allocation and portfolio composition, we believe that energy demand globally will continue to grow. I think the demographics are just such that that’s going to be the case. We also believe that natural gas will continue to gain market share modestly on a percentage basis. But in absolute terms, on an energy equivalent, it will be significant growth. So we do see an opportunity for us to allocate incremental capital into our natural gas businesses. The two basins we serve, the Western Canadian sedimentary basin and the Appalachian basin are extremely competitive and resilient. And as a matter of fact, we expect that over time, they will gain market share. And so we feel like we’re serving the right basins. With respect to other parts of our portfolio, the other area of interesting growth for us will be in our Power and Storage business. And as I mentioned, we see an opportunity to electrify our own consumption. Our consumption on base Keystone is about 800 megawatts. And on the natural gas pipeline side of our system, about 10% of our compressor stations in Canada are driven by electric motors and about 5% of those in the United States. So we do see an opportunity to allocate more capital in our pipeline businesses to electrify those compressor stations. And then beyond that, once the electricity demand has been created, build the renewable generation that will be required to actually meet that consumption. So over and above that, as we think about other growth opportunities, we look at our solar and battery projects we have in development in Alberta. We just announced Siemens – in conjunction with Siemens and new waste heat technology that will generate emission-free power from waste heat at our compressor sites. That’s at a pilot installation in Alberta, but we see about 300 megawatts of potential for that across our system. So we’re very confident in our ability to meet our internal goal of finding $5 billion to $6 billion a year of opportunity to allocate our capital. And I think, as you mentioned, Jeremy, or intimated, that allocation is likely to shift more toward the theme of our investments to electrify our asset base, reduce our emissions and also reflecting the increased percentage of renewable generation and the generation mix overall.

Understood. Yes. It sure seems the events in Texas would highlight the value of natural gas there. So I understand that point. And then maybe just kind of pivoting to a separate question here, and Don have asked this before. But just curious for your thoughts on what’s the right level of payout ratio for TRP here? If you see – if your belief is that TRP is trading below intrinsic value, might it make sense to lower the payout ratio a little bit to enable more buybacks to take advantage of that situation? If you see that, I see that the 2021 growth ticked down a little bit there. So, just wondering your current thoughts on that?

Yes, thanks for the question, Jeremy. It’s – we – it’s a balancing act all the time, but we have a multi-decade model that has delivered pretty significant. TSR, over time, we think in the longer term, in terms of the capital allocation model that we have, never flavor the day, but I’d say we’re not – also not tone to what’s going on out there. The building blocks, we start looking at the base business, is anything fundamentally changed, and we’re pretty comfortable that the base business is resilient and we scenario and stress tested that at nausea. So we think the cash flow will be there as we look out a decade – coming decades here. So looking at the dividend, is it affordable and is it valued? When we look at the interest rate backdrop right now, we would think that, over time, the market will come back and appreciate the yield that is associated with our shares right now. The opportunity set to reinvest cash flow is as robust as we’ve seen it for a decade-plus here, as François alluded to. So nothing has fundamentally changed here. So we step back, and we try not to make any decisions on a short-term basis here on a major basis. But we look at our payout ratios that are largely in line on a comparable EPS basis. We have historically targeted 80% to 90%. We’re certainly well within those parameters, which equates to about 40% of cash flow. So as we guide to 5% to 7% dividend growth, we see the payout staying within those metrics going forward. You look at the share price from time to time, we look at it everyday, every hour, it can be frustrating at times, but we have seen this movie before. And if we continue to deliver on this model, we think that the valuation will ultimately reflect that. So – very long-winded way of saying, nothing has fundamentally changed in terms of base business, the opportunity set. And I’m a bit strange to figure out why 6% yield right now, when interest rates are 1% or lower, is not better reflected in the share price. But again, we’ve been through these air pockets before. And if they persist for a very long time, we’ll revisit it. But fundamentally, all the building blocks we have historically seen are in place.

Understood. Thank you for your thoughts. François Poirier: Thanks, Jeremy.

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

Good afternoon. I want to follow-up on some prior comments on the opportunities for growth in this environment. The potential loss of Keystone XL is a bit of a dent in the middle part of the decade’s growth outlook. How do you think about backfilling your growth to offset this or is that even required just given the fact that you do have about $50 million of backlog right now, which is at the lower end of your 5% to 6% per year? François Poirier: I think the way we look at it, Rob is what’s our degree of confidence in being able to build up to that 5% to 6% every year and right out of the gate, we have $1.5 billion to $2 billion a year of maintenance capital that’s required, 85% to 90% of that goes into rate base. And given the very high utilization rate on our pipelines, we’re expecting that, that level of capital spend will be required going forward. And over and above that, you look at the Bruce Power MCR program, I think as we included in some of our slides, we are approaching a decision on MCR Unit 3 in the fourth quarter of this year. I think in our MD&A, we have, from 2024 through 2031, the end of the program, in 2018 dollars, it’s about a $6 billion of capital spend. In actual dollars, let’s call that $1 billion a year. So that gets you to – pretty close to $3 billion right there. And then looking at in-corridor expansions in our U.S. and Canadian Natural Gas Pipeline businesses each of our Canadian and U.S. businesses delivered about $1 billion of new growth projects in 2020. And as we look at the next few years in each of those businesses, we think that, that is a good and reasonable run rate. So that gets you to close to five, right there and that’s before we start thinking about opportunities on the power side to invest capital in meeting our own consumption, and it’s even before looking at other things like electrifying our own load and other capital investment opportunities that come from reducing our emissions. So we actually see ourselves as opportunity rich. And if we want to live within our means, we’re actually going to have to make some choices between all of the different items I just laid out for you in terms of priorities, not only thinking about hurdle rates and risk return and the underlying commercial underpinnings, but also what we want the portfolio to look like over time.

Alright. Thanks for that. And then the follow-up was going to be on hurdle rates, so how do you think about, kind of, your hurdle rates? Does Keystone push the liquids hurdle rate up? You have a robust ROE ask in the Columbia rate filing and on the other side, our hurdle rates down on the power side. François Poirier: Stan, do you want to take that one?

Yes, yes, I will start. Looking at it holistically, we’re not going to – our hurdle rates have not really budged much over the years, and we’re not going to chase projects down below what we feel is an acceptable return. So we see some aspects of, say, the renewable space right now that what we would like to invest capital in that business, in that space, it just doesn’t meet our return hurdles. In terms of the liquid side, Bevin has outlined some of the opportunities here. There is a lot of bolt-on stuff that could be reasonably high return, low execution risk. The challenge we have is finding larger scale liquids opportunities that meet our risk preferences are they out there and how significant are they? But generally, what we pointed to is un-levered after-tax IRRs kind of in that mid to high single-digit range with variability for political risk in places like Mexico, unique nature of nuclear refurbishment and the like. But generally, the pipeline space, you end up in that 7% to 8% range. And we still see a lot of opportunity coming, certainly on the gas side and we expect that will bring some bolt-on stuff on the liquid side in that range, just maybe not the multibillion dollar stuff.

Thank you.

Our next question comes from Linda Ezergailis of TD Securities. Please go ahead.

Thank you. Congratulations for a resilient and strong year, certainly a different year than we all expected. I’m wondering if you can help us understand, recognizing that this is another dynamic situation, the recent cold weather and polar vortex in Texas and the Southern U.S., can you talk about what sort of impact it’s having on your operations? And how might we think of any financial impact, if any, recognizing that there is force majeure clauses that we might not be available? And I guess the second part of my question is, lessons learned at some point, is it just going to be business as usual after you regroup and recover or might you rethink the value of connectivity, maybe there is some possibility of storm hardening becoming even more resilient, making those investments that customers might ask for or maybe might you rethink also the extent and pace of electrifying the pipeline network, if electric power might not be available as a backup if the solar or any other investments you make can’t provide power to your compressors?

Linda, this is Stan. I could address the first part of your question and then I’ll let my colleague to jump in at the rest. Both of our pipelines and our people performed extraordinarily well during the, I guess, what I would call the ongoing cold snap that really ripped across much of the U.S. And yet again, it shows the really valuable role that we play in providing energy to millions of individuals and businesses when it’s needed most. Yet again, we saw record throughput levels across our 13 pipeline network. François already mentioned that we had a coincidental 3-day peak between February 14 15 and 16, where we delivered over 101 Bcf of gas. On February 15, our Columbia Gulf pipeline set a new peak day delivery record spending out over 3.2 Bcf. And also on February 15, across our combined 13 owned and operated pipelines, we delivered just over 34 Bcf of gas, which was our second highest single peak day ever. So this is the most impressive accomplishment from my perspective, and it doesn’t happen by accident. And I’d like to echo François’s comment at the beginning of the call and recognize literally the thousands of employees across the U.S. from our field operations teams who were the ones that brave these late night call-outs and freezing temps to our gas control teams who optimize literally every single decatherm of capacity to ensure not only that we were meeting our customer obligations, which we did, but also creating value for the company. And lastly, our office workers and especially those in Houston, who worked most of the past week without any electricity, heat or even sometimes water in their homes. With respect to your comment around electrification and does this impact in Texas make a thing that, for a relatively minor investment, it’s likely that we would install dual drive so we’ll have the opportunity to switch back and forth between electric or gas drives that we don’t have outages in time of this. François, I believe, mentioned that we have about 240,000 horsepower of electric compression across our system today. We are going to continue to look to add additional electric where it makes sense. As a matter of fact, just a few weeks ago, we spent approved the capital project of about $100 million to expand a project into Virginia, where we’re going to basically replace some older inefficient gas compression with new electric drives, maybe even a dual drive that will help us serve incremental load, at the same time, driving down our greenhouse gas footprint. So with that, I will pause and I will just invite others to jump in, if they want to.

Yes. Stan, this is Bevin. So Linda, with respect to our Liquids Pipelines, certainly, first and foremost, want to acknowledge the teams who – and our customers who had to work through some fairly horrendous circumstances to get us to a spot where we are very safe and secure with all our assets. We needed to or within the Liquids Business unit, while the demand actually cratered in that many of the refineries that we provide deliveries to didn’t have power, couldn’t receive shipments. And so we are in the midst of a number of circumstances where both our delivery points were under force majeure. And as such, even though our assets were very operational and functioning well, we had to similarly make a force majeure event. In that, we needed to park securely those volumes that were in our pipe. We see that this will clear up fairly quickly. We don’t see it being material to our overall revenue for the year at all and nor should it impact our customers in any material way.

That’s helpful. Thank you. And I guess just 10,000-foot view, maybe a follow-up question for François or the team. Considering your geography currently, you mentioned previously that there is a benefit to diversification, certainly, asset diversification is beneficial geographic diversification is beneficial. Do you – how do you see your geographic mix potentially shifting over the next decade, given some of the political change we are seeing, given some of the policy changes we’re seeing and specifically, I am wondering if maybe there is a bit more of a tilt to Canada and what might prompt, if at all, any consideration of any investments outside of North America and what would the criteria need to be to consider that? François Poirier: Thanks for the question, Linda. It’s interesting. We do regularly, at least, annually, ask ourselves the question, is the opportunity set in our current footprint, Canada, U.S. and Mexico, sufficiently large and does it intersect with our core competencies well enough that we have an opportunity set that’s sizable enough not to cause us to want to look further appeal geographically. To this point, in the last several years, when we’ve asked ourselves that question, we’ve said that we believe there is plenty of opportunity for us in our existing footprint to grow the business in a manner that we want to. Our experience has been that where you have commercial relationships, you have political relationships with state governors or with members of parliament or members of provincial parliament, where you have relationships with the regulators with commercial organizations, it’s just much easier to manage what we all know is an increasingly demanding standard from our stakeholders in how we develop energy infrastructure. So anytime you think about going further afield, you are flying a bit blind in terms of your ability to assess how well you can manage some of those stakeholders. So for the time being, again, as we look at our opportunities, we are opportunity rich. We are very confident in our ability to originate $5 billion to $6 billion a year of opportunity in North America with the set of core competencies and capabilities where we can manage risk and earn a reasonable return. So it’s not to say that we won’t contemplate expanding further afield in the future, but those issues, particularly around having key stakeholder relationships in those new geographies is something that’s bearing more and more weight in our assessments.

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

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

Hi. Good afternoon. You’ve basically touched on most of my questions at this point. But on the capital allocation, how are you adapting the investment process to account for the uncertainty related both to the energy transition and also the pandemic, which both those seem to have an uncertain impact, especially in terms of timing? So maybe you can address that. You’ve already addressed it really from the hurdles returns point of view, but maybe you can address it from the risk transfer point of view? François Poirier: Maybe I’ll get started, and I’ll ask Don to supplement or correct me where I stray. I guess a couple of things come to mind, Robert. The first is, we do scenario analysis. We run our models to end-of-life for all of our capital investment opportunities. And we do look at various scenarios for how energy transition might occur, what the impact might be on supply and demand and prices for all of the different forms of commodities whether it’s the underlying commodity for that particular investment opportunity or competing commodities that might affect our ability to recontract and manage some of the residual risk. So running all of our investment opportunities through those scenarios does allow us to assess the resiliency of when we make investments. I’ll point out that with most of our capital being allocated into our regulated businesses, particularly on the gas side in Canada and the U.S., the regulated construct does allow us to earn a return on and of capital for when we make those investments. And so to the extent the useful life of a basin were to shorten inside of the remaining years of depreciation. We’d have the ability to apply to the regulator to accelerate depreciation and recover our capital. We don’t foresee that happening anytime in the near future, but just to point out that there is that regulatory mechanism there that’s a mitigant. The other is with respect to carbon emissions and how do we factor in, what I call, carbon competitiveness into our capital allocation model. And it’s a bit more straightforward to do, for example, in Canada, where the federal government has proposed a mechanism and an escalation for carbon taxes going forward, we can ascribe economic value to those emissions, either with respect to the emissions of the actual opportunity or to create other opportunities to actually reduce our emissions and what the economic return will be for those. I would say it’s early days for us on how to apply the concept of carbon competitiveness in our capital allocation, but it is something that we are beginning to more formally incorporate into our capital allocation going forward.

It’s Don here. I’ll just maybe speak to COVID. And really, is there any other event risk that might be visited upon us either from permitting or execution on any large project, we’re – we do restrict the amount of capital we expose at the early stages of any project. And we look to – toward mindful risk sharing with other stakeholders to box in risks that we don’t necessarily have the ability to control or of a magnitude potentially that is overly impactful to us. So that’s really the way you’ve seen us change our approach here, particularly in the large-scale projects on the KXL, the Coastal GasLinks and the like is. So it’s not COVID specific. It is a standing event so we can’t foresee or control, just try to limit how much capital we have exposed or how much of a grind it could be to our returns.

Yes. Thank you. That’s the answer I was looking for. Thanks.

Our next question comes from Michael Lapides of Goldman Sachs. Please go ahead.

Hi, guys. Thanks for taking my question and appreciate you for taking the amount of time on this fourth quarter call. I actually have two. One is Coastal GasLink, can you remind us what is the lag in cash flow? So like the CapEx is going to go up on Coastal GasLink, do the tolls go up each year reflective of what the CapEx level? So if CapEx, in a given year and the forecast is up $500 mill or a bill, will a toll in that year go up as well to reflect that change in that year’s CapEx? Is there a lag in cash flow, and so it has an impact on kind of credit metrics, debt, etcetera?

Maybe I will start with that one, Michael and then Don may have some comments on it as well. So of course, we – as we spend on Coastal GasLink, if CapEx goes up and in all cases, we attempt to mitigate any impact on CapEx as we encounter issues, that capital flows into tools add-in service. And all of the CapEx flows into tools at the same time. So the toll recovery begins as soon as we are adding service. So – but we do – from the perspective of operating cash, we do achieve AFUDC on this as we progress and we have case AFUDC from the joint venture partners as we go. I hope that answers the question. Don may have some comments to add to that.

Sure. So the way Coastal GasLink is structured, it is an equity investment from our perspective on our financial statements. There is significant project financing in place at the project level that will be shaped to the ultimate size of the project so the significant leverage there that does not hit our balance sheet. It’s supplemented by, as Tracy mentioned, cash carry costs from the shippers over the course of the project and equity contributions from ourselves plus KKR and AIMCo, our partners and hopefully, ultimately, First Nations. So the impact on TC Energy is – of the cost increase there is relatively insignificant on our balance sheet and on our credit metrics. As we noted in our disclosure, we don’t expect the cost increase or the schedule delay to have any significant impact on the equity contributions we ultimately make to the project. So meaningful at the project level, but in terms of the consolidated impact on the company, we don’t see this being material.

Got it. And then one just kind of coming back to capital allocation a little bit. If CapEx stays in the $4.5 billion to $5 billion a year range, FFO to debt will continue to improve over time, even if dividend growth is up 6% or so. In year 3 and year 4, that implies your – you kind of naturally deleveraging. So unless there is some other headwinds or some other use of cash on the cash flow statement, do you think you’re positioning yourself where if there is not incremental growth projects like the hydro project or something else, where that by year 3 or 4, you’re likely buying back stock?

It’s Don here again. I’m not sure if we’re buying back stock, but we do have financial capacity that grows over time. So it’s beyond just the cash, the 40% or 60% of cash flow that we come in the year tends to reinvest each year. Your debt capacity, as you pointed out, within your credit metrics of debt-to-EBITDA in the high 4s and FFO in the 15% area does give you the ability to grow that investment base without tripping any of your credit metrics over time, whether it’s share buyback or additional investment in similar kind of initiatives that we have going forward remains to be seen.

Got it. Thank you, Don. Much appreciated.

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

Good morning, everybody. I know you’re looking to establish your emission reduction targets at some point this year. I was just curious how far away you still might be from setting those targets and maybe some initial thoughts around pledging that zero or setting absolute versus intensity targets by, say, 2030? And I guess, just how you’re thinking internally about aligning those emission targets with broader government policies out there and your overall 5% to 7% growth objectives? François Poirier: Patrick, it’s François. Thanks for the question. We did mention at our Investor Day that our intention – well, first of all, we did establish some policy initiatives in our sustainability and climate change report here in 2020, indicating that we believe we do have a responsibility as a responsible owner and operator of infrastructure to reduce our emissions to every extent possible. We, as a company, decided to take the additional time to come back with a more granular answer not only with respect to what interim targets might be and ultimately what our 2050 type time frame targets would be but also the strategies that we would be employing to get there. We think it’s important to have a credible plan, one that not only we can communicate to you all and others in the financial community, but our other stakeholders, indigenous communities, governments, policymakers, etcetera. So I would say you can expect us to be providing some clarity on that in the second half of the year. Our sustainability climate change report was published in October in 2020. We might be ready to publish our conclusions then our findings a bit earlier than that, but it would be no later than that type of time frame. We think it’s an important document to get out to our stakeholders as early as possible. Given our culture and our propensity to be disciplined and under promise and over deliver, I won’t provide any hints as to where we think we might land. The good news is that from our perspective, the technology exists today in order for us to make significant reductions in our emissions because a good percentage, I would say, the vast majority of our emissions come from burning gas at our compressor stations on our pipeline systems and simply by replacing those with electric motors, you reduce your Scope 1 emissions immediately. Scope 2 emissions matter, of course. And so if you’re replacing a gas turbine at a compressor station with electricity generated from gas power generation would currently be the case in Alberta. It doesn’t make a whole lot of sense to do that. So we think it’s going to take some time for us to achieve those targets based on – particularly around Scope 2 emissions, how the underlying generation mix evolves over time. Also, as I think Linda alluded in an earlier question, you have to consider reliability and a lot of our compressor stations are in very remote areas where there are no transmission lines and so from a reliability and a safety and a redundancy standpoint, it’s not going to be applicable everywhere. But so I think we’ll be able to get part of the way there, at least with a pretty well-defined set of strategies. The other important thing is how quickly this takes place we think it’s very important to have a vibrant and healthy energy system with all participants in the energy value chain, having financial help. And so the natural opportunity for us to rotate capital to lower emitting technologies is when a piece of equipment reaches the end of its useful life. To the extent you’re replacing it earlier than that, someone has to absorb that cost and we’re very cognizant of not creating significant rate shock for our customers. So we think this is a strategy that’s going to be pretty straightforward, but it will take some time to execute, if you want to minimize rate shock, and we’ll see what policymakers provide in terms of incentives for us to accelerate the rotation of that capital stock. And there is not a ton of clarity from policymakers yet on what those mechanisms might look like. And I think those would affect our ability to reduce our emissions more quickly than would otherwise be the case through natural attrition.

That’s great. Appreciate the comments there, François. And also, just with respect to balancing the strategic plan to achieve your ESG goals with your financial growth goals as well, just looking at your power portfolio, clearly, it’s been a strong first couple of months of the year for the Alberta power market. I’m sure the main focus right now is beefing up your renewables footprint. So just wanted to get your thoughts on how you view the relative attractiveness of allocating more capital toward the Alberta market to capture more of an immediate impact financially versus building out some of your larger scale contracted renewables over time, which, again, might fit well with achieving your ESG goals? François Poirier: Yes. Perhaps I’ll get started and then I’ll ask Corey to provide further comment. Just at a high level, our strategy in our power business is we want to invest in more fuel diversification. So we like our co-gen business in Alberta. It’s been doing well and operating extremely well under severe cold temperatures over the last few weeks. So we’ve been very pleased with the operating and financial performance of those. We do want to have more of a balance in terms of fuel diversity. Again, our goal is to be prosperous, as a company, irrespective of the pace and direction of energy transition over time so that speaks to having more diversity in our fuel mix. But having said that, perhaps I’ll ask Corey to add some commentary on how he’s thinking about the Alberta marketplace.

Hi, thank you, François. I think that we would approach the Alberta marketplace and the entire power platform the way we approach the rest of our business. We are looking for long-term contracted relationships that meet our hurdle rates for our assets. And I think we will be going to stick to our knitting and really stay focused on that being our core business. I think we want to avoid merchant exposure and avoid adding that to our portfolio. And I think, as François said, in his comment, firming assets such as pump hydro, long-term contracted assets, such as renewables, both in the province and in the Lower 48 provide opportunities as well as serving our existing load.

Okay. That’s great. Thank you very much.

Our next question comes from Andrew Kuske of Credit Suisse. Please go ahead.

Thank you. Good afternoon. Probably a question for Bevin to start, and it’s really just on some of the legacy asset positioning you have at Hardisty around base Keystone and then what you have already built really for what was the KXL project and really in relation to pipeline connectivity and then the terminal positioning you have in Hardisty?

Thanks, Andrew. Certainly, Hardisty is the origination point for the Keystone system. And it is strategically connected and the interconnects that are with other parties terminaling assets become more strategic with how you manage those assets. So we’ve been generating a longer term plan for those assets that originally was based primarily off of the Keystone XL project, but there still is very strategic use for our investments in Hardisty. And attention to that is that the assets that have already been constructed or put in surface, we were – our project teams are actively looking for ways to utilize that equipment. It is strategically positioned again, and that’s been in our core corridor and as such, we would look to find ways to recover value on those assets.

Okay. That’s very helpful. And then maybe also just a reference to your legacy business being in the power business where you’ve been for many years, especially with renewables exposure and then waste heat pump 20-some-odd years ago, you started there. Can you give us just some color and context, and there is probably a question more for François, just on your internal capabilities for scaling the renewables business or just associated power efforts with your in-corridor assets if you chose to go that route?

Yes, excellent question. And I’ll point out that at various points in time over the last 20 years, well, we either currently or have operated nuclear wind, solar, natural gas, we dispatched coal, some geothermal as well, I believe, run-of-river hydro. And for the most part, those people are still about our organization. One of the reasons for bringing Corey on board with 20 years plus of experience in the electric utility sector and developing in generation business for a couple of our competitors over those two decades was to reconsolidate and reform our team and build back our origination capabilities around those types of opportunities. So we can prosecute what we see as the opportunity set going forward. And Corey, I’ll invite you to add any comment you want to make there.

Yes, thank you very much. I think that’s an excellent point. I think we are, as François said, we are – have been – we are opportunity-rich with choices for investing, and we are equally as opportunity-rich with our personnel and our team members that have a long history in this sector. So we have a high level of confidence that we can execute systematically and effectively and within our risk profile for this sector. And I think, as you would have heard from many folks on this call, we are very focused on staying in corridor with what we do best. And so we’ll manage those projects safely and effectively and really use the expertise that we have gained over the last 20 years plus in this sector.

That’s great. Thank you.

Our next question comes from Praneeth Satish of Wells Fargo. Please go ahead.

Thanks. I have two quick questions. First, on KXL, if you decided not to proceed with the project, can the steel that was ordered to be reused for future projects are sold? And if so, is there any way to quantify those savings? François Poirier: Bevin, do you want to grab that one?

Yes, absolutely. Sorry, I had myself on mute. Certainly, our project team, Praneeth, is evaluating what we can do with all of our equipment and its uses, the value of steel, in some cases has increased. And certainly, there is a market for some of our spare materials, if that – if we evolve to that point here. So our team is looking at the best strategy to wind down and work closely with our partners to do so, and we’ll provide further updates once those plans are in place.

Okay, GOT it. And then it looks like you’re still in settlement negotiations on Columbia Gas, but the rates became effective on February 1. So, I am just wondering how this will be accounted for? I guess, specifically, will your EBITDA in Q1 reflect the higher proposed rate on Columbia Gas?

So Praneet, this is Stan. I could start and Don, you could supplement as necessary. But yes, so we did put the motion rates into effect on February 1, and we will continue to collect those until a settlement is finalized. At that point in time, we’ll basically go back and restate our revenues back to February 1. So you can kind of think of each month, we’ll be reserving the difference between what our filed rates are and what are expected or final settlement rate is. And I hope to have more clarity on the whole rate case process for you in the May conversation. But I would just say at this point in time that things are progressing as expected. We’ve had two settlement conferences so far. A third one scheduled for next week. And again, I’m just going to ask for your patience and letting the process play out a little further.

Yes. It’s Don here. Yes, the progress on the process will inform us as to what kind of an estimate we make in terms of recognition in the quarter. It will all get smooth out over time as a settlement is either reached or we end up going through litigation and get the outcome of that. But it will be a point in time estimate.

Got it. Thank you.

Our next question comes from Harry Mateer of Barclays. Please go ahead.

Hi, good afternoon. Two for me. The first just on hybrid security, so I appreciate the comment earlier that with KXL out of the budget, no longer intention to issue those for funding. I guess I’m just wondering if we can expand that, given you seem content with your leverage metric trajectory, is the plan for any debt financing really just to be straight senior unsecured or might hybrid still play a role in sort of your base case in the next couple of years?

Yes. It’s Don here. We have a limitation of 15% of our capital structure being in preferred shares and hybrid securities. We’re bumping up against that right now. So in the absence of balance sheet growth, I wouldn’t expect any change upward in that. So that – what you see on the slide in terms of debt financing is generally senior debt.

Okay. And then second question, more just financial policy, but away from hitting a specific credit ratings target. Have you spent any time thinking about whether just with the energy transition, which, I think, carries some inherent uncertainty, does that alone warrant bringing leverage down further than your current target just to naturally embed a dramatic cushion for the company?

We’re in continuous dialogue with the rating agencies to get a sense of where their heads are at. We’re pretty satisfied with the strength of the portfolio right now. As you look at the left-hand side of the balance sheet, it’s really never been stronger. It’s long-term annuity streams, crown jewel assets and portfolios. So from our perspective, it’s very utility-like in that sense. If the rating agencies start attributing more risk to that portfolio, as François mentioned earlier, we have mechanisms such as accelerating depreciation to address that. So because there is uncertainty out there, it doesn’t – at this point, doesn’t make us move to reduce leverage. We’re quite comfortable with where our metrics are at and just the stability of our cash flow here. So if the goalposts do start changing, we’ll have to assess that and see where to from there. But at this point, we’re quite comfortable and the rating agencies seem quite comfortable as well with the business risk and how it’s funded – and how it’s financed.

Okay. Thank you for that.

Ladies and gentlemen, this concludes the question-and-answer session. If there are any further questions, please contact TC Energy Investor Relations. I will now turn the call over to Mr. Moneta. Please go ahead.

Thank you, and thanks to all of you for participating today. We very much appreciate your ongoing interest in TC Energy, and we look forward to talking to you again soon. In the meantime, we wish you and your families’ good health. Thank you, and goodbye. François Poirier: Thank you.

This concludes today’s conference call. You may disconnect your lines. Thanks for participating and have a pleasant day.