TC Energy Corporation

Welcome to the TC Energy 3rd Quarter 2021 Results Conference Call. As a reminder, all participants are in listen-only mode and the conference is being recorded. After the presentation, there'll be an opportunity to ask questions. To join the question queue, you may press star then 1 on your telephone keypad. Should you need assistance during the conference call, you may signal an operator by pressing star and 0. I would now like to turn the conference over to David Moneta, Vice President, Investor Relations. Please go ahead.

Thanks very much. And good morning, everyone. I'd like to welcome you to TC Energy's third quarter conference call. Joining me today are Francois Poirier, President and Chief Executive Officer, Joel Hunter, Executive Vice President and Chief Financial Officer, Tracy Robinson, President, Canadian Natural Gas Pipelines and Coastal GasLink, Stan Chapman, President, US and Mexico Natural Gas Pipelines. Bevin Worspa, Executive Vice President, Strategy and Corporate Development and President of our Liquids Pipelines business. Corey Hessen, President, Power and Storage. And Glenn Meneuz, Vice President and Controller. Francois and Joel 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. Following their remarks, we will take questions from the investment community. If you are a member of the media, please contact Jamie Harding after this call. In order to provide everyone from the investment community with an opportunity to participate, we ask that you limit yourself to two questions. Before we begin, 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 Exchange Commission. Finally, during this presentation, we may refer to measures such as comparable earnings, comparable earnings per common share, comparable EBITDA, and comparable funds generated from operations. These and certain other comparable measures are considered to be non-GAAP measures. As a result, they may not be comparable to similar measures presented by other entities. These measures are used to provide you with additional information on TC Energy's operating performance, liquidity, and our ability to generate funds to finance our operations. With that, I'll turn the call over to Francois.

Thank you, David, and good morning, everyone. Thank you for joining us today. I'm told this is the busiest reporting day of the year, so we really appreciate you joining us on this very busy day. As outlined in our third quarter report, our diversified portfolio of North American energy infrastructure assets continues to perform very well. Society's unwavering demand for our services and the relentless focus our people place on operational excellence are reflected in our strong financial performance. Through the first nine months of the year, comparable earnings per share of $3.21 exceeded last year's results by 5%. while comparable funds generated from operations totaled $5.3 billion. This is a very good outcome, especially considering the significant decline in the value of the U.S. dollar relative to the Canadian dollar, which had a negative impact on our Canadian dollar reported EBITDA. Given the strong year-to-date performance, we now expect 2021 comparable earnings per share to be modestly higher than last year's record results. We continue to advance our secured program, which now totals $22 billion. This includes the US $800 million WR project announced earlier today, which will improve reliability and expand the ANR system. This project is similar in scope to the VR project we discussed in the second quarter. And WR will upgrade compressor stations to dual-drive electric horsepower, reducing our GHG emissions while ensuring natural gas backup in case of a power disruption. So manageable in corridor projects like these are the building blocks in the modernization and decarbonization of North America's energy infrastructure system, while maintaining reliability, and we expect to realize numerous similar opportunities in the future. Also of note, as part of its life extension program, Bruce Power recently launched an upgrade initiative focusing on asset optimization, innovation, and leveraging new technology. They call this Project 2030, and it has a goal of achieving a site peak output of 7,000 megawatts by the end of the decade, effectively adding the equivalent of a ninth unit at the Bruce stations. Now, this is in addition to the major component replacement program we've been investing in and talking about on Units 3 through 8. We continue to advance $22 billion of secured projects, excuse me, including $4 billion we've already added to date in 2021. When you factor in the continuation of Columbia's modernization program, as we call Mod 3, and the Bruce Power Unit 3 MCR which is expected to be sanctioned before the end of the year, as well as the Project 2030 upgrade initiative, we plan to sanction $7 billion of high-quality growth opportunities by the end of this year. Completing these projects on time and on budget will generate a weighted average after-tax IRR on these new investments, the full $7 billion of sanctioned projects, of 8.3%, which is toward the upper end of our targeted range of 7% to 9% for projects that we sanction annually. Our secured capital program continues to be underpinned by cost of service regulation and long-term contracts, giving us visibility to the earnings and cash flow these projects will generate and are consistent with our long-held risk preferences. Now, looking to next year and beyond, we expect many similar high-quality opportunities, to come to fruition as we continue to reliably deliver the energy people need while decarbonizing our asset footprint. This includes the ongoing expansion, modernization, and maintenance of our regulated natural gas pipeline network, the refurbishment of another four Bruce Power reactors, and plans to use renewable energy to electrify a portion of our pipeline network. And you'll hear more detail on that later on. The RFI process we began in the second quarter for over 1,000 megawatts of renewable capacity to electrify our own load has had an overwhelmingly positive response. Negotiations have begun and we anticipate completing the process in the first quarter of 2022. Beyond that, we're also progressing initiatives including the Ontario Pump Hydro Project, the Canyon Creek Pump Hydro Project in Alberta, carbon transportation and sequestration in partnership with Pembina, and clean energy projects with Irving Oil, and also large-scale hydrogen production hubs with Nikola Motors. As a result, we expect to sanction more than $5 billion of new projects annually over the next several years, and we hope to exceed that, with risk-adjusted returns consistent with historical levels. Our team's origination capabilities were demonstrated quite visibly during 2021, and the opportunity set that lies ahead is vast. Now, in order to judiciously fund this attractive suite of growth opportunities, maintain a strong financial position, and enhance our conservative utility-like payout ratios, we have modified our near-term dividend growth outlook. We now expect to increase our common share dividend at an average annual rate of 3% to 5%. While our previous outlook remains affordable and supported by the strong performance of our business, we believe this modest change is prudent given the generational opportunity for growth we have before us. It will allow us to fund a larger portion of our future capital programs through internally generated cash flow, moderate our leverage, and continue to deliver superior total long-term shareholder returns. As you know, we are committed to delivering these returns while growing our business sustainably. That's why I'm proud that last week we released our 2021 report on sustainability, our ESG data sheet, and our GHG emissions reduction plan. These reports outline the next step in our sustainability journey with detail on our 10 sustainability commitments that come with 32 specific measurable targets we've set to support them. This includes targets to lower our emissions intensity by 30% by 2030 and position the company to achieve net zero emissions from our operations by 2050. We also advanced our commitments in the areas of innovation, diversity, indigenous reconciliation, and safety, which for us includes mental and psychological health. I'm confident that our talented team has the technical capabilities, the innovative mindset, and the commitment required to advance our work in these areas. And I encourage you to read these documents, which can be found at tcenergy.com, to learn how we are holding ourselves accountable to protect the planet, empower people, and create shared prosperity. In summary, we are committed. We are committed to our vision of being the premier energy infrastructure company in North America, not just now, but in the future. As I've said on numerous occasions, we will achieve that by prospering irrespective of the pace or direction of energy transition. Our business decisions continue to support our goals to reliably meet society's energy needs while decarbonizing our assets. Looking forward, our $22 billion secured capital program, which we expect to grow to $25 billion by year's end, is poised to grow substantially over the years, and as always, we will fund our capital programs prudently to maintain our solid financial position. Ultimately, our goal is to continue to grow earnings, cash flow, and dividends per share, and build on our long track record of delivering superior total shareholder returns. Now I'll turn it over to Joel for some comments on our third quarter results.

Thanks, Francois, and good morning, everyone. As outlined in our results issued earlier today, Native income attributable to common shares was $779 million, or $0.80 per share in the third quarter, compared to $904 million, or $0.96 per share for the same period in 2020. Third quarter results include an after-tax expense of $55 million related to transition payments associated with the one-time voluntary retirement program offered to eligible employees earlier this year, and an $11 million after-tax charge associated with Keystone XL preservation and other costs. The corresponding period in 2020 also included certain specific items as outlined on the slide and discussed further in our third quarter 2021 report. These specific items as well as unrealized gains and losses from changes in risk management activities are excluded from comparable earnings. Comparable earnings for the third quarter were $972 million or $0.99 per common share compared to $893 million or $0.95 per common share in 2020. Year to date, comparable earnings per common share are up 5%, supported by the strong underlying performance of our business. Turning to our business segment results on slide 11. In the third quarter, comparable EBITDA from our five operating segments of $2.2 billion was similar to 2020, despite strong currency translation headwinds. Detailed variance explanations in each business unit can be found in our third quarter 2021 report, but I will comment on a few principal changes year over year. Canadian gas pipelines comparable EBITDA of $631 million, with $35 million lower than third quarter 2020, mainly due to decreased flow-through depreciation following the full depreciation of one section of the Canadian mainline, as well as lower flow-through financial charges, partially offset by higher incentive earnings. The cessation of depreciation does not impact net income, which increased by $12 million for the Canadian mainline. U.S. gas pipelines comparable EBITDA increased by $59 million U.S. to $706 million U.S., compared to the third quarter 2020, primarily due to an increase in earnings from Columbia Gas, following its application for higher transportation rates effective February 1, 2021, in the resulting settlement that was filed with the FERC on October 29. We anticipate FERC approval of the settlement during Q1 2022. Liquids pipelines comparable EBITDA declined by $28 million to $387 million in the third quarter, due to reduced contributions from liquids marketing activities, primarily due to lower margins. Power and storage comparable EBITDA in the third quarter fell by $19 million, primarily due to lower earnings of Bruce Power due to greater planned outage days and higher operating expenses, partially offset by higher realized power prices. For all our businesses with U.S. dollar denominated income, including U.S. and Mexico gas pipelines and parts of liquids pipelines, EBITDA was translated into Canadian dollars using an average exchange rate of $1.26 in third quarter 2021, compared to $1.33 for the same period in 2020. While overall U.S. dollar denominated comparable EBITDA increased by $53 million U.S., the year-over-year weakening of the currency was a considerable drag on comparative 2021 Canadian dollar reported EBITDA. That said, the corresponding impact on comparable earnings was not significant, as their U.S. dollar denominated revenue streams are in part naturally hedged, with the residual exposure actively managed on a rolling two-year forward basis. Now turning to slide 12. I'll speak to a few of the primary variances below EBITDA. Depreciation and amortization was $63 million lower compared to third quarter 2020, primarily due to one section of the Canadian mainline being fully depreciated. Interest expense included in comparable earnings was $37 million higher year over year, largely due to the cessation of capitalized interest for the Keystone XL pipeline project. Comparable interest income and other rose $59 million in the third quarter, mainly due to realized gains in 2021 compared to realized losses in 2020, on derivatives used to manage our net exposure to foreign exchange rate movements on U.S. dollar-denominated income. Income tax expense included in comparable earnings for the third quarter was similar to 2020. Excluding Canadian rate-regulated pipelines, where income taxes are a flow-through item and thus quite variable, along with equity AFUDC income in U.S. gas pipelines, we continue to expect our 2021 full-year normalized tax rate to be in the mid-to-high teens. Comparable net income attributable to non-controlling interests decreased by $61 million, relative to the same period last year, primarily as a result of the TC Pipelines LP buy-in completed earlier this year. Now, turning to slide 13. During the third quarter, comparable funds generated from operations totaled $1.6 billion, and we invested $1.7 billion in our capital program. In October, we issued a combined $2.25 billion U.S. of senior unsecured notes, comprised of $1.25 billion U.S. of three-year fixed-rate notes at 1%, and $1 billion U.S. of 10-year fixed rate notes at 2.5%. Now turning to slide 14. This graphic illustrates our forecasted sources and uses of funds for 2021 through 2023. Starting in the left column, our total requirements over the three years are projected to be approximately $30 billion, reflecting dividends and other of $11 billion, capital expenditures including maintenance capital of $16.5 billion, $2 billion attributed to the TC Pipeline's acquisition completed in March, and the Series 13 preferred share redemption of $500 million in May. The second column highlights expected internally generated cash flow of $21 billion, $2 billion of common shares issued pursuant to the TC Pipeline's buy-in, approximately $3 billion Canadian equivalent of senior unsecured notes issued in October, $1.5 billion of medium-term notes issued in June, and the $500 million junior subordinate notes offering completed in March. That leaves a residual need of approximately $2 billion depicted in the far right column that we expect to fund through a combination of incremental debt, commercial paper, and Keystone XL project recoveries. The program excludes normal course refinancing of scheduled debt maturities and is consistent with maintaining our strong financial position. Now turning to slide 15. In closing, our strong operational financial results continue to reflect our resilient, low-risk business strategy and demonstrate the criticality of our extensive asset footprint along with our robust growing capital program. Our enduring business model, financial strength, organizational capabilities, and unparalleled network of assets position us to capitalize on a vast opportunity set which will allow us to serve today's needs as well as the evolving energy mix of the future. Looking forward, as Francois mentioned, in order to fund our sizable capital programs during this period of growth, maintain our strong financial position, and enhance our already conservative utility-like dividend payout ratios, we have modified our near-term dividend growth outlook. We now expect to increase our common share dividend at an average annual rate of 3% to 5%, which will allow us to fund a larger portion of our future capital programs through internally generated cash flow, moderate our leverage, and continue to deliver superior long-term total shareholder returns. That's the end of my prepared remarks. I will now turn the call back over to David for the Q&A. Thanks, Joel.

Just a reminder, before I turn it over to the conference coordinator for questions from the investment community, we ask that you limit yourself to two questions. If you do have some additional questions, please re-enter the queue. With that, I'll turn it back to the conference coordinator.

Thank you. We will now begin the question and answer session. To join the question queue, you may press star, then one on your telephone keypad. You will hear a tone acknowledging your request. If you are using a speakerphone, please pick up your handset before pressing any keys. To withdraw your question, please press star then 2. We will pause for a moment as callers join the queue. Our first question comes from Ben Pham of BMO. Please go ahead. Our next question comes from Robert Quan of RBC Capital Markets. Please go ahead.

Great. Good morning. If I can just start on the dividend rate change and recognizing what you've got to start somewhere, but on an absolute basis, it's not really that much dollars saved to fund things. So as you just think about the stepped up plan, can you just confirm that discrete equity has or drip ATM has no role in that? But as you step it up, what is the role of asset monetization as well? just to take advantage of private market valuation out there.

Hi, Robert. It's Joel here. So first to answer your question with respect to the need for equity or ATM, we'd say there is no need given our $22 billion capital program. Along with us announcing today, we've sanctioned $7 billion of projects this year, so far this year, and we expect to do at least $5 billion annually in the coming years. So we see no need for common equity. If there are opportunities in excess of this, we would consider equity. However, we look at everything through a per share lens, so it would have to be accretive to shareholders and add long-term value.

I think to add to that, excuse me, Robert, your question with respect to monetizing assets as an alternative, we look at all sources of equity capital, whether they are internal or external, and they have to compete with one another. And to the extent we can monetize a mature asset and rotate capital into growth, it's something you've seen us do in the past through funding the Columbia project. growth program and something we would absolutely consider and be prepared to do in the future.

Okay, so just to clarify, because Joel, your answer sounded like it was maybe just a little bit more of an absolute test of accretion, but Francois, are you trying to say, though, that you've got these different options and they're all going to get weighed against each other and the best option is how you're going to proceed?

Yes, I think the way you characterized it, Robert, is exactly that. We're going to weigh all of our options, and that's how we're going to make the choice as to how we fund our program going forward. I think where Joel was going with this is we always retain the option to issue equity, but we guard share count jealously, and to the extent we have an internal option to rotate capital, I think that will always be our preferred course of action.

Perfect. And then just, um, you know, you had the VR project last quarter, you got the WR project this quarter. Um, both are just a little under us a billion dollars. You've got lots of other systems that are full with, with compressor stations. Can you just talk about the total potential opportunity and book you've had kind of one each quarter here, what type of pace, you know, can we expect to see additional announcements?

That's a great question, Robert. I'll give that a start, and then I'll ask Stan to provide some proof points and add some color. As we talked about and published our GHG reduction plan last week, we identified five levers for us to achieve our objectives, and one of them was modernizing our existing infrastructure and assets. And I think the WR project and the VR project, which, if memory serves me, are about a billion and a half. of sanctioned projects are really good examples of that. And I think we'll see more of those going forward. So over to you, Stan, for additional color.

Thanks, Francois. Hello, Robert and team. I would start by saying this. Given the size and breadth of our assets in the U.S., I've said before that any given year, my expectation is we should be originating about a billion dollars of growth capital, and I expect that to continue for the next several years. One way we're going to look at doing that is by continuing to electrify our compression fleet, give you some data points. Today, about 5% of our compression fleet is electric driven. All things equal, that probably drives down or reduces our CO2 emissions by about 500,000 tons. Here's the opportunity set going forward, though. About 24% of our compressor fleet today is what we call older slow speed units. These units could be up to 70 years old. So as we continue to mine for other light for light compression reliability projects, like we've done with our Elwood project, Wisconsin Access, VR and WR, we're gonna look to replace this older inefficient gas compression with newer compression that may well be electric driven or this dual drive technology. The main driver for all this from a strategy standpoint may very well be linked to the retirement of cold fire generation across our footprint. And just to give you a data point, As we sit here today, there are 16 coal plants that generate about 15 gigawatts of capacity that are scheduled for retirement between now and 2030. And these coal plants sit within 15 miles of the A&R or the Columbia system. So that's exactly what we've seen happen with respect to our WR project that we announced today. Across the Midwest, we've recently seen about 1,800 megawatts of coal fire generation be retired. A majority of that is going to be replaced with renewables, but a portion of that is going to be firmed up with new gas-fired loads. And that's what the FUR project does. It expands our system to the tune of about 157,000 decatherms and gives us the ability to replace these older inefficient units with newer electric drives that not only drive down our emissions and expand our capacity for our customers, but allow us to do it in conjunction with Corey's team, who ultimately will be the provider of this green power going forward. So, again, when you look at the opportunity set, I can't tell you specifically how much of that billion dollars a year that we're going to originate in any given year is going to be electric-driven, but I would say that we're in a bit of a target-rich environment right now.

That's great. Thank you very much. Thanks, Robert.

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

Hi, thanks. Good morning. I wanted to also check, you've tempered your dividend growth guidance to a new range, but are you reaffirming that 5% to 7% growth in EBITDA or cash flow or more of a long-term business growth rate?

Thanks for that question, Ben. I think, you know, directionally, that's absolutely accurate. You know, what we said in our... prepared remarks is that the 5-7% dividend growth is affordable and that we considered moderating the dividend growth for really two reasons. One is to retain more cash flow to invest in our growth programs and the second is to over time grow into a slightly lower leverage targets. So by definition What's implicit in that is that earnings and cash flow are expected to grow at a rate that is above our targeted dividend growth rate of 3% to 5%.

That's what I thought. I just wanted to clarify that. You've been pretty consistent with some of your payout ratio targets, even cash flow between that 60% to 40%. Is there any change in that or maybe more wholesome update than yesterday?

I think we see value in having utility-like payout ratios, both on an earnings and cash flow basis. And again, given the fact that we see growth opportunity being very robust going forward, revolving around energy transition and lowering our emissions, we thought it was prudent for us to be retaining more cash flow. And by virtue of continuing to grow earnings and cash flow at a rate on a long-term basis above that 3% to 5% range, we expect to see our payout ratios lower over time as well from the targeted levels that you mentioned, Ben.

Okay, great. Those are my two questions. Thank you. Thanks, Ben.

Our next question comes from Jeremy Tonnet of J.P. Morgan. Please go ahead.

Hi, good morning. Just wanted to pick up with kind of some prior elements of the last question there. And just as far as the analyst day is concerned, should we be thinking about any other type of new messaging or major developments as far as how you think about TC Energy going forward with the strategy? We have, you know, new management team in the seat here. Just wondering if there's anything that you can share with us.

Jeremy, I think what you'll see from us is the same consistency that we've exhibited over the last couple of decades, which is we view our value proposition is to provide stable and steady dividend growth underpinned by growth in cash flow and earnings, to maintain a strong balance sheet and industry best payout ratios, and to continue with a set of very disciplined and conservative risk preferences. What you'll hear from us on Investor Day is more detail on the opportunity set that we see going forward. Again, energy transition provides a vast opportunity for TC Energy to prosper. The opportunity to reduce our emissions will create opportunities for us to invest capital as well. And when you combine that with the underlying growth in our existing businesses, as Stan talked about, for example, in our U.S. gas business, I'll ask Corey to provide a little bit more detail on where we are with our RFI program in here just a minute in terms of electrifying our own consumption. What you're going to hear from us is more detail around the robustness of that growth program going forward. Corey, if I could ask you to provide a bit more update on that one.

Thank you, Francois. Hi, Jeremy. Glad to have you calling in today. Appreciate you taking the time. As I mentioned in previous calls, we are systematically going through a process to to electrify our liquids assets in the U.S. And we've reached a stage now where we have exclusive negotiations for, as promised, 1,000 megawatts of renewable generation. And we expect in Q1 to be able to announce our selections and our choices and then the schedule of each one of those projects and how they're going to serve our load more specifically.

Got it. That makes sense. I didn't think TC Energy would be changing a ton, but just wanted to check. Separately, just wanted to kind of build off of, I guess, the Nikola announcement that you had made during the quarter here. Want to get any more color you're willing to share with regards to, I guess, the pace of opportunity as it relates to hydrogen going forward? And do you see these type of opportunities as far as, you know, more repurposing existing assets or building new logistics? Just any color you could share there would be helpful.

I'll start and I'll ask Corey to provide a little bit more detail with using Nikola as an example. One of the things we've learned, Jeremy, over the course of the last year is how critical our assets and infrastructure is to moving forward with energy transition. With respect to hydrogen, it's about generating, producing, storing and transporting a gaseous molecule, which is exactly what we do every day, primarily through natural gas transportation in our company. So our skill sets and our asset base really lend themselves very well to those kinds of opportunities. And you're going to see more of these type of joint development agreements that we have with Nikola with other counterparties going forward. But with respect to Nikola, perhaps, Corey, if you could sort of frame up the size of the opportunity for Jeremy.

Yeah, that'd be great. I think the way to think about it is that Nikola provides us a unique opportunity to bring our core skill sets, our core capabilities to a team as we develop investigate how hydrogen can be part of the new energy economy. And so specifically we think about it from a power and storage point of view that it matches our view of participating in agenda load match view. A normal 150 ton per day hub requires about a gigawatt of power. And so we perceive that we can participate by building and operating renewable energy assets which include storage, wind and solar to power those electrolyzers and then be able to systematically evaluate our existing infrastructure such that we can participate in the transmission side of those hydrogen molecules from point to point to service the load. But once again, I'd like to reinforce that the most important part of this is, A, we can bring our capabilities to a wider team and learn together, and, B, we can leverage our existing asset base to participate with our partners in this opportunity.

Got it. That's very helpful. Thank you. Thanks, Jeremy.

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

Thank you. I'd like to go back to the dividend growth announcement for a minute. I think you characterized it in the statements as a near-term change to the dividend growth outlook. And I wonder if there's a specific metric such as leverage that you'd need to see at a certain level, or is it really under constant evaluation? And some of the comments given this morning is it's really a long-term reduction in the leverage and the payout ratio as opposed to really a near-term change in the growth rate.

Thanks for that, Robert. I'll get started and I'll ask Joel to provide additional comments. You know, certainly we see ourselves growing cash flow and earnings at a rate that's above the 3% to 5% dividend rate. This is something we're going to constantly evaluate over time. It's a dynamic evaluation process within the company. We see, simply put, tremendous opportunity for us to allocate capital above our free cash flow, even through energy transition and emissions reductions over the next several years, and want to make sure that we're balancing appropriately, providing income growth to our shareholders and but also maintaining a very strong balance sheet because we think there will be situations where we can be opportunistic and capture opportunities that others don't to the extent we have a strong balance sheet and continue to maintain dry powder. So the idea here is to grow into... stronger metrics, and Joel, I'll throw it to you for additional comments.

Yeah, thanks, Francois, and thanks, Robert, for the question. As Francois mentioned, we will grow over time into these stronger metrics, and particularly when you look at our leverage. Over time, we want to get that down. I'd like to see us more in that four and three quarters debt to EBITDA range over time. I think it's important for us, as Francois said, to just have that additional capacity, that dry powder, if you will, further bolsters our balance sheet. So I think it's really important for us to be focused on that. But again, it'll take time and it'll depend really on the cadence of spend as to how long it will take to get there. I would note, Robert, though, if you think about the last two years, our debt to EBITDA, we ended the year at 4.9. We were very happy with that. So it's not like this is that far out of reach, but it will take some time. But that's kind of a stated target that we have is around that four and three quarters area of debt to EBITDA.

Male Speaker 1 Okay, thank you. That's a helpful color. And then my next question is on Prus Power and the upgrade there. Can you maybe provide a little bit more detail and, you know, sort of contrast it to what's going on with the MCR program? And is the higher capacity going to be achieved through operational means, or is there some capex and spend development that you can speak to? Thank you.

Corey Nielsen Hi, Robert. It's Corey. The way I would think about it is, Number one, the up rate is a three-phase project that's going to take the remainder of the decade. Bruce Power refers to it as Project 2030. Phase one is under construction right now, and we just approved phase two, which is approximately $300 million of capital. The execution is all on what we would refer to as the cold side of the plant, meaning there's no risk. to nuclear operations, so it's primarily through improvements in the non-nuclear side of the facility. Each phase has been funded and approved in a phase-by-phase process, and we expect that by 2030, the goal of 7,000 megawatts can be attained based on year-to-date progress of meeting their goals and objectives for cost and schedule for Phase I. Our next question comes from Linda Ezregelis of TD Securities.

Please go ahead.

Thank you. I don't want to spend too much time belaboring your deliberations on the dividend, but it is of high interest. So I'm just wondering how much of a factor, if any, were your conversations with the debt rating agencies in considering and converging upon an appropriate dividend growth rate? And maybe also, were there any other factors that were potentially secondary, but a consideration as well? For example, any sort of pending tax changes in any of your jurisdictions or anything like that?

Thanks, Linda. It's Joel here. I first would say that there was no discussions with the rating agencies. There's no pressure on our metrics. This was a decision that we made on our own that we found was prudent to retain more cash flow to redeploy into our business. So I just want to emphasize there's no ratings pressure whatsoever here. But we did mention to the ratings, we do have a regular update call with them. But again, this is no pressure from them whatsoever. As it relates to tax changes, I mean, it's early days in that, Linda. I mean, there's a lot of moving parts here, whether you look at tax changes in the U.S., Canada, so it's come out of the OECD. We'll have to wait until the final legislation actually comes through before we can actually make any kind of determination if there's any impact at all on our tax position. So, again, very early days on that, and we don't want to speculate, but that did not factor into your decision here on the 3% to 5% dividend, nor did the rating agencies have any pressure from them whatsoever.

Okay, I appreciate that context. And maybe moving on to the outlook for inflation, and a lot of moving parts there as well, but I'm wondering if you can just remind us what the update is on what percentage of your earnings or EBITDA might have protections in place, And when we think of the net tailwind versus headwinds, we might see next year and beyond. If you can provide any context for us, that would be very helpful.

Thanks, Linda. That's Francois. I'll take that one. As you're very well aware, we have very little exposure to commodity price risk or volumetric risk. And In terms of the rates established in our various jurisdictions, we have a settlement in Canada Gas and our mainline for five and six years, respectively. We charge negotiated rates predominantly on our systems in the U.S. on the natural gas side and our liquids business as well. So our exposure in terms of revenues to... interest rate risk is very low. The vast majority of our capital is under fixed rate from a borrowing standpoint. And so where we see some inflation pressures is on our projects and the cost of our projects going forward. It's something that we manage either through cost-sharing mechanisms with our customers to the extent that those are available, but it's something we see and, you know, take a very close eye on in terms of managing our operating and capital costs going forward. So not really any pressures in terms of allowed rates of return, in terms of revenues going forward from inflation. But again, on our O&M and our project, it's something that we watch very carefully. But we don't see that as inflation as being really a significant impact on our earnings and cash flow volatility going forward.

Thank you.

Thanks, Linda.

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

Morning, everyone. Just the first question on the Coastal Gas link. Can you update us on the path forward and how you're thinking about capital at risk regarding the kind of slip in schedule there as well as the higher capital cost?

Yeah, happy to do that. Good morning. Listen, You know, we continue on Coastal GasLink to work, you know, very closely with our customer, LNG Canada, as we advance towards completion. You know, as we work through this project, we are working very closely with them to ensure that the pipeline comes in in a timeline that's consistent with their needs on the facility. And so, you know, we are 100% aligned with LNG Canada on the importance both of the project and the need to continue to move this forward We're committed, of course, to doing that. We're more than halfway there. We've passed our 50% completion, and we've more than, I think, 5,000 people out there working right now and achieving new milestones every day. So we think this project's on track. It's going to come in in a timeline that works for our customers, and we're committed to making sure that that happens.

So there's no contemplation of any pauses like was previously discussed?

We have right now all the authorities that we need to proceed, and we are in 100% alignment with LNG Canada, the importance that construction is not disrupted. So we're out there doing it, and we don't expect a disruption in construction.

All right, good to hear. And then shifting over to Alberta, the Alberta carbon grid, you know, TC's got – we'll call it high-pressure pipelines from the large emitter sources to the potential disposition for carbon areas there. So when you're taking a look at your capital plan and taking a look at how the potential CCUS opportunity comes along, how are you thinking about your assets and the path forward for this project?

Thanks, Rob. It's Bevan here. We've One great aspect of this opportunity is that it is an industry solution with both our partner Pemina and ourselves as well as potentially other parties in the Western Canadian sedimentary basin leveraging our long-life assets, re-looking at repurposing our assets to provide a more competitive solution for the industry is what we're focused on. But it's early days, Rob, where This is a multi-year effort. We're getting feedback from industry and not only the energy industry but other point source folks as well that have emissions to deal with and looking at a solution set that could really be competitive for a broader industry approach. Thank you.

Thanks, Rob. Thanks, Rob.

Our next question comes from Andrew Kuski of Credit Suisse. Please go ahead. Andrew Kuski Thank you.

Good morning. Maybe just on the growth opportunity that lies ahead, if you could delineate a little bit of it, what is in-corridor growth and potentially having higher returns versus maybe more competitive opportunities that you really foresee?

Andrew Kuski I'm happy to start, and then I'll ask Stan and Tracy to provide some proof points. I would say going forward, Andrew, that our opportunity set is going to be much more driven by in-corridor growth than not. Simply put, we find the risks in managing external processes, permitting, and the like to be much more manageable in corridor. We have very strong relationships. We're a trusted operator. Our employees work and live in the communities in which we operate. We have a strong safety record, and we have strong commercial relationships with organizations in those areas and with policymakers. So from our perspective, going forward, from us, you can see much more of what I call, using a baseball analogy, singles and doubles than swinging for the fences. You know, backfill, you know, the $8 billion we lost earlier this year with the permit revocation. We've done our job this year. We've sanctioned $7 billion, including projects that will be sanctioned before the end of the year. We've sanctioned $7 billion of projects with an unlevered IRR of 8.3%. That, to me, is strong execution on our part. And that's being done with smaller and corridor projects and projects related to energy transition and reducing our own emissions. So that's going to be the trend going forward. And I see the execution risk and the permitting risk around our capital projects going forward reducing because we're going to take that approach. So perhaps we'll start with Stan and then Tracy.

Hey, Andrew, this is Stan. Maybe I'll see if I can't paint a little picture for you for my view of growth within the U.S. natural gas business. And I guess I would start by saying the best type of growth we can achieve is one that doesn't require any capital spending. And given the current regulatory environment that we're in, where the time and complexity around building new projects is increasing, we truly believe that the value of pipe in the ground is going to continue to grow over time. And therefore, our margins on every decatherm of capacity we sell are going to increase. So whether we're focusing on cost reductions, generating new capacity with sales, or even taking advantage of artificial intelligence and machine learning like we've recently done with our autonomous pipeline project, we think that we're going to be able to grow our margins going forward. Second thing I would point out to you is our modernization program as part of our rate case that we recently settled and filed with at FERC. The Columbia rate case settlement does include a continuation of Columbia Gas's modernization program, which we refer to as Mod 3. It's a $1.2 billion investment over four years. And as with our prior proposals, every bit of capital that we put in service at the end of October of a given year starts to earn recovery effective April of the following year. So there's a relatively short period of dead capital, if you will. And I should note that if you're trying to trace back to our capital table that we included in our Q3 disclosures, the $1.2 billion modernization program is not included in that just yet, but we will update the capital table when the settlement is approved, expected around Q1 2022. But third, and perhaps really to your question and with respect to new projects, again, given the depth and breadth of our system, my expectation is we originate about a billion dollars of projects each year, and these will be largely in-corridor compression-related expansions that are permittable and constructible and will continue to have this five to seven times EBITDA multiple build, if you will. I should point out that not only are we originating about $1 billion of new growth projects a year, we're also putting into service about $1 billion of growth projects per year. This year, we're going to put in about $900 million of capital into service. Next year, we're on track to do about the same, just under $1 billion. So again, while it's difficult for me to give you a specific breakout of where the growth is going to come from, we're going to look for continued organic growth amongst the utilities, and we've had some success in that, particularly on the east coast of the U.S. The electrification opportunities like VR and WR we've already talked about. Opportunities with respect to co-retirements, again, I think are bound. LNG growth, that second or third wave is going to come, particularly as we see these $50-type LNG prices in Asia coming and record LNG sendouts to places like China. And also, I wouldn't discount an element of producer push. You know, for example, we're seeing increased capacity, increased production out of the Bakken, higher gas to oil ratios, pressure on reducing flaring. All that's going to require additional pipeline capacity. And again, we're uniquely situated to do that, I think, with our bison pipeline. All of that I would characterize as traditional growth. And on top of that, there's all of these transitional opportunities that we have around renewable natural gas, carbon capture, hydrogen, and the like. So with that, I'll pause and maybe turn it over to Tracy.

Thanks, Dan, Andrew. Thanks for the question. In Canada, as you know, we're in the middle of what is a fairly large expansion program, particularly in the NGTL system. It is positioning the NGTL system you know, within that Montney area to ensure that the basin and the gas that's up there, which is some of the most competitive North America has access to a system. And we're increasing the access that gas into market by through this program more than 30%. So you'll see that program come to an end in 2024. Beyond that, you know, we see about a billion, a billion and a half of organic-like investments as we continue to make sure that the system is positioned properly in the basin to help it succeed, and as we look at opportunities to optimize our system, we're looking at opportunities to decarbonize as we see the carbon price starting to increase, opportunities to electrify, and as we look forward, leverage our assets as we look at all of the activity around energy transition. So this is a tremendous resource base we have right now. We're starting to see the benefits of the expansion that we've done already. If you look at some pretty strong financial results, you're going to see that continue. And I think, you know, as we look forward, we're going to leverage all of that to make sure that the basin is positioned to succeed, to drive more gas down our kind of strategic asset on the main line into eastern Canada, the Midwest, on our U.S. pipes, And we'll participate fully in the growth that we're all seeing in gas.

I appreciate the three's company approach on the answering of the question. It's very helpful. But maybe my second question, if I can, is really related. Maybe it brings it back to the baseball analogy, Francois, on singles and doubles and just all the capital comments that Stan and Tracy made. Do you see yourselves in a position where you've got effectively the singles and doubles that are all in corridor that allow you to you know in certain sense run up the score and really put a lot of capital to work in a short period of time to accelerate an energy transition and just greater offers to your customers and and really benefit the overall growth story for tc itself uh very much so andrew i think you characterized it well and you know if you look at the seven billion dollars of

projects that we have sanctions or expect to sanction for the rest of the year. The majority of those projects have a component of emissions reduction or energy transition or emissionless energy built into it. So from our perspective, as we look at our responsibility and the commitments we've made around reducing our emissions, as we look at the direction policy is taking, as we look at you know, talking to our customer base about what their objectives are, more and more of our capital going forward is going to be associated with either reducing our emissions, reducing their emissions, or moving us along energy transition. And as you quite rightly pointed out, you know, a larger number of smaller projects brings less Permitting risk for us, less execution risk for us, and in many instances where we are the incumbent, we are able to attract above average returns for that capital. So all told, I think, as you pointed out very well, I think it bodes very well for us going forward in terms of our ability to achieve our targeted 7% to 9%. on newly sanctioned projects every year. And as I mentioned in my prepared remarks, we're at the upper end of that for the $7 billion we plan on having sanctioned in 2021. Okay.

Thank you very much.

Thanks, Andrew.

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

Hey, guys. Thank you for taking my question. I'm looking at your sources and uses of funds for the next couple of years. One of the items that stood out a little bit was the expected source of funds from recovery of Keystone Excel costs. Can you just remind us, A, what's the dollar amount that's assumed in that bar? B, what's the process for getting recovery of those funds and kind of the timeline for it? and see what's the backfill strategy in case that gets pushed out or delayed or doesn't get recovered. Thanks, guys.

So we'll start with Bevan with respect to the recovery, and then the backfill will go to Joel.

Yeah. Thank you, Michael. As you highlighted, we had great support from our customers to help advance the Keystone XL by supporting us with some of the capital to move that project forward. Post the revocation of the permit, we've since moved to commercial conversations with our customers that did support us. And we've made great progress on that front and we hope to resolve any outstanding balances by the first quarter of next year. With respect to the totals, those are fully disclosed in previous disclosure upwards of $800 million. But over to you, Joel.

Yes, Bevan, thanks for that, and thanks, Michael, for the question. To the extent that we couldn't recover that, the backfill would be simply through additional debt. We have capacity to do that because it isn't a large amount, Michael. It's anywhere from $500 million to $800 million, as Bevan mentioned. And perhaps I'll add a little bit to that.

The base case outcome is that we will be recovering that capital from our shippers. These are all strong, credit-worthy parties. Simply put, what we are working towards as an alternative is a bit of a win-win situation where we can create commercial opportunities that deliver even more value than the recoverable capital through commercial solutions that they need and that benefit us as well. I view the risk of not being able to recover that capital in our capital stack to be de minimis to negligible. We are simply working on trying to find commercial solutions that actually increase the value of those recoveries.

Got it. Thank you, guys. Appreciate the detailed answer.

Thanks, Michael.

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

Thanks. Good morning. I'm wondering if you could comment on the proposal here in the U.S. to impose a minimum 15% tax on corporations. If this went forward, would this have any impact on your cash taxes on the U.S. side of the business, or do you have any NOLs or credits to help offset this?

Thanks, Bernice. It's Joel here. Yeah, so if we went to a 15% tax, a minimum tax, again, as I mentioned earlier, it's still very early days to determine, you know, what's the final impact. We have to look at the legislation that ultimately will come through. We'd have to look at, you know, what's the transition period. We have to look at if there's any grandfathering, et cetera. So if there was a 15% tax, probably not a big impact to us. given that, especially on a cash tax perspective, because we do have some NOLs that we can use. So, again, for us to kind of speculate, it's just too early, just given there are a lot of moving parts. But certainly we're not seeing, we're not really concerned that we see, depending on what the legislation ultimately is, whether it's in the U.S., Mexico, Canada, OECD, as I mentioned earlier, we have to determine what the ultimate impact is for our cash versus current taxes.

Got it.

And I just wanted to go back to the IRR comment. So I know company-wide, the project backlog, like you mentioned, is going to generate an 8% IRR. But is it the case that the gas projects have higher returns in kind of the five to seven times EBITDA range, and then the energy transition projects have a lower IRR? And I guess the reason I ask is that over time, I'd imagine that the energy transition projects become a bigger and bigger piece of the backlog. So do you see risk there to the 7% to 9% target over time?

We don't see any risk to the falling outside of that band over time. As we're looking at opportunities through electrification, as we're looking at the opportunities with the carbon grid, with Nikola and other hydrogen opportunities, and even in renewables, On a weighted average basis, we're very confident that we're going to be able to fall within that 7% to 9% range. What you've seen from us over the course of the last couple of years with the predominance of our capital being spent in Canada Gas, where the prescribed rates of return based on 10.1% return on equity, on deemed equity of 40%, that falls beneath our range at roughly 6.25% with incentives. But nonetheless, we've been still able, on a weighted average basis, to fall within that 7% to 9% range. So energy transition investments include Bruce Power, include the uprate, and both the MCR and the uprate fall above the 7% to 9% range. So you should not presume that energy transition investments by default generate and attract lower returns. We're very disciplined about how we allocate capital. That 7% to 9% range is an extremely important part of our capital allocation decisions. And based on the forward pipeline of projects that we're developing, we don't expect to see us falling below that range any time in the near future.

Perfect. Thank you.

Our next question comes from Matt Taylor of Tudor Pickering Holten Co. Please go ahead.

Yeah, thanks for taking my question here. Not only one for me. As LNG producers are looking to offer net zero carbon cargoes, are you guys seeing any opportunities to partner there to reduce emissions of where that gas is being transported from and And if there's any conversations there about preference for some of these LNG producers on where they source their gas from by basin or customers, that might give you guys a competitive advantage.

Hey, Matt, this is Stan. Maybe I'll take that last part of your question first with respect to is there a preference in LNG customers to source green gas, if you will? And the answer is no, we really haven't seen that. As a matter of fact, it's been a bit of a mixed bag amongst producers whether or not they're interested in putting forth a product such as that. Overall, no. I think our part of the value chain is to build out the capacity to feed the LNG terminals, and we're quite comfortable doing that going forward, again, particularly in light of the unprecedented demand that we're seeing for LNG right now and this winter, where cargoes have traded for over $55 the past couple weeks, record deliveries to China last month and the like. So I think we generally like where we are in the value chain, all things evil. Okay.

Dan, if you could, maybe on the topic of RNG, provide some additional color on some of the initiatives that you've got going.

Yeah, I could. I appreciate that, Francois. I think I mentioned to you earlier that we were on track to double the amount of RNG that we were taking into our system this year, and we're probably going to exceed that by 50%, and perhaps get up to about 20 to 30 BCF of RNG into the system by the end of 2022. What we're trying to do is work with some of the larger landfill providers, for example, look at where their landfills are relative to our pipeline infrastructure, studying the value chain to determine the value propositions along the digester component, the conditioning component, the transportation component. And also, we have kind of a unique ability to interact at the intersection of molecules and electrons to an extent in the context of Corey's team could come in and provide a role in this as well. And it could be as simple as buying the gas, buying the renewable gas from the renewable producer, or perhaps entering into an asset management agreement as well. So a lot of exciting stuff, I think, yet to come on the renewable gas front. We're really bullish on that opportunity.

Great. Thanks for taking my questions.

Okay. Thanks, Matt.

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

Thank you. Good morning, everybody. Just to follow up on Coastal GasLink and more on the cost side, I just want to make sure I've got this right in the sense that the worst case of financial exposure for yourselves and your LP partners at this point, assuming no incremental project financing for whatever reason, would be that $3.3 billion with your net exposure just being north of a billion. That would also assume that your LP partners don't have any recourse on you guys as project manager. So, not sure how much you can share at this point with respect to, A, firming up that incremental project financing, or B, any legal protection you might have as project manager from the other LP partners potentially making a claim as well.

Hey, Patrick. I'm going to let Joel address the temporary financing component that you mentioned, but First, let me address just a few important points. As you know, this project is critical to both the industry, to the country, to LNG Canada, and we're working very closely with LNG Canada as we advance towards completion. We can, of course, discuss the details of any discussions on cost and schedule and the issues between us because they're confidential. But what I can say is is that we're very hopeful that ultimately we're going to reach an agreement between us on those issues. And that, of course, you know, will lead to the resolution of some of the temporary financing as well. We are continuing to work on the pipe, more than 50% done. Lots of people out in the field progressing that, very aligned with LNG Canada on the importance of ensuring that that's not disrupted. And with that note, I will pass it over to Joel.

Thanks, Tracy. So yes, Patrick, you saw us disclose that there is a commitment up to $3.3 billion that would be temporary if necessary for us to lend into the project. I think it's important to note, though, if that were required, that we would earn a return on that investment, if you will, that would be temporary. We fully expect that over time that CGL will be able to increase its project credit facility. and the likelihood of this up to $3.3 billion wouldn't be required, but if so, again, we'd be viewed as temporary and we'd earn a return on it.

Okay, great. That's very helpful. Thank you. And then maybe as a follow-up, as you think about, say, the pumped hydro opportunity, obviously a very different project in the context of design and construction challenges, but still quite similar as it relates to capital intensity and you know, long lead execution risk. So just curious how this CGL experience might be influencing your strategy around mitigating and diversifying your risk during the build out just in order to maximize your risk adjusted returns.

Hi Patrick, it's Corey. Thanks for the question. I think that your question really amplifies what it means to be a part of TC Energy and the fact that we have a diversified business and we every day create opportunities to have learnings from other parts of our business. And so what we would learn and apply and what we have learned and applied to this process is number one, understanding how our partners want to operate and because on the Meaford project, the Ontario pumped storage project, we will have partners that include local constituents, it will include the Saugeen Ojibwe Nation, and it will include potentially other investors. And so we will definitely be thinking about how we include them early on in the process to make sure we're aligned on our contracting strategy and execution strategy. And secondarily, we are very focused on making sure that we have the right contracting strategy with our actual construction partners, our OEM partners, and our supply chain, so that as we move along in this process, we all are very clear on the roles and responsibilities. And I think I would just sort of close with the fact that the Pumped Hydro Project is is also an excellent opportunity for us to leverage what we have in a partnership with Bruce Power and all of their excellent work that they have done and to be able to help and guide us through this process as well, just because we both serve the same jurisdiction, the same customers, the same province, and so that's really a competitive advantage for us for this particular project.

Great. Appreciate the color. I'll leave it there.

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

Thank you very much. In closing, our disciplined approach, as always, emphasizes financial strength and adherence to our conservative risk preferences. That's a critical part of our value proposition. Secondly, as you've seen with our results year to date and the upward revision in our outlook, our high-quality long-life assets continue to produce strong operating and financial results. And thirdly, as we think about our strong performance this year in terms of sanctioning $7 billion of projects with an 8.3% after-tax unlevered IRR, and we think about our growth prospects going forward, energy transition will provide vast opportunities for TC Energy to prosper, as I said in our strategy, to prosper irrespective of the pace or direction of energy transition. Thanks very much for your time today.

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