TC Energy Corporation

Thank you for standing by. This is the conference operator. Welcome to the TC Energy fourth quarter 2021 results conference call. As a reminder, I would like to remind you 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 one on your telephone keypad. Should you need assistance during the conference call, You may signal an operator by pressing star and zero. I would now like to turn the conference over to David Mineta, Vice President, Investor Relations. Please go ahead.

Thanks very much, and good afternoon, everyone. I'd like to welcome you to TC Energy's 2021 Fourth Quarter Conference Call. Joining me today are Francois Poirier, President and Chief Executive Officer, Joel Hunter, Executive Vice President and Chief Financial Officer, Stan Chapman, President, U.S. and Mexico Natural Gas Pipelines. Bevan Worspa, Executive Vice President, Strategy and Corporate Development. And Group Executive, Canadian Natural Gas and Liquids Pipelines. Greg Grant, President, Canadian Natural Gas Pipelines. Richard Pryor, President, Liquids Pipelines. Corey Hessen, President of our Power Storage and Origination. And Glenn Manouse, Vice President and Controller. Francois and Joel will begin today with some 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 in the investor section under events and presentations. Following their remarks, we will take questions from the investment community. In order to provide everyone with an equal opportunity to participate, we ask that you limit yourself to two questions. If you're a member of the media, please contact Jamie Harding after this call. Before Francois begins, I'd like to remind you that our remarks today will include forward-looking statements that are subject to important risks and uncertainties. For more information on these risks and uncertainties, please see the reports filed by TC Energy with Canadian securities regulators and with the U.S. Securities Exchange Commission. And 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 additional information on TC Energy's operating performance, liquidity, and its ability to generate funds to finance its operations. With that, I'll now turn the call over to Francois.

Thanks, David. And good afternoon, everyone, and thanks for joining us today. As highlighted earlier today in our fourth quarter news release, I'm pleased to report that 2021 was another very successful year for TC Energy. Our $100 billion portfolio of high-quality, long-life energy infrastructure assets continued to produce strong operating and financial results. During the year, we placed $4.1 billion of assets into service, and we sanctioned approximately $7 billion of new projects. We also progressed numerous long-term energy transition growth initiatives in renewables, hydrogen, and CCUS that will position us for future success regardless of the pace or direction of energy transition. We continued our focus on expanding our organizational capabilities in key areas like power and storage, innovation and stakeholder relations and finally we released our 2021 report on sustainability which includes targets for all 10 of our sustainability commitments notably we set ambitious scope 1 and scope 2 ghg reduction targets our goal is to reduce our emission intensity 30 by 2030 and to position the company to achieve net zero emissions from our operations by 2050. So, operationally, the demand for our services remains strong, and our assets performed extremely well. This was evidenced by the volumes transported across our network. For example, our NGTL system in Alberta reached a decade-level high for average export flows and set an all-time record on intrabasin delivery of 8.1 BCF on January 5th of 2022. A similar story in the U.S., where we saw increased flows across most of our natural gas pipeline assets in 2021. The robust volumes continued into early 2022, and we set an all-time send-out record on January 20th of 34.9 BCF across our U.S. network, and that represents approximately one quarter of total U.S. daily supply. Same in our liquids pipelines, where our Keystone system achieved record throughput of 602,000 barrels per day in 2021, up 6% from 2020. And in power and storage, the Bruce Power Facility delivered 86% plant availability And we also had 98.9% peak availability on our cogeneration assets through the 2021 weather extremes. So what does that mean? It means our strong operating performance translated into strong financial results. Excluding certain specific items, comparable earnings reached a record $4.2 billion in or $4.27 per common share in 2021, compared to $3.9 billion or $4.20 a year earlier. Comparable EBITDA of $9.4 billion and comparable funds generated from operations of $7.4 billion were both similar to last year's results. However, we achieved these record results despite the impact of a weaker U.S. dollar, which impacted comparable EBITDA by approximately $400 million. These results reflect the strong performance of our legacy assets as well as contributions from the approximately $4 billion of new assets we placed into service in 2021. Looking forward, we are advancing a $24 billion capital program. This includes approximately $7 billion of new high-quality growth opportunities that we sanctioned in 2021, including the Columbia Modernization III program and the Bruce Power Unit 3 MCR program. Importantly, the entire $24 billion program is consistent with our historical risk and return preferences. It's underpinned by long-term contracts or cost-of-service regulation and expected to deliver a weighted average unlevered after-tax IRR of approximately 8% on the entirety of the portfolio. Looking beyond our current capital program, the opportunity set that lies ahead of us is vast. Our substantial origination capabilities position us to capture many similar high-quality opportunities as we continue to deliver the energy people need while decarbonizing our own assets footprint. This includes the ongoing in-corridor expansion, modernization, and maintenance of our regulated natural gas pipeline network. It also includes the Bruce Power Life Extension Program and the Project 2030 Upgrade Initiative at Bruce to achieve peak site output of 7,000 megawatts. As we've mentioned previously, we're evaluating proposals in response to our RFI for renewables to electrify the US portion of our base Keystone system. The response has been overwhelmingly positive and we expect to finalize contracts in the first half of 2022. Now associated with the RFI, we have identified a meaningful origination opportunity to sell carbon-free energy products and services to the industrial and oil and gas sectors for aggregation of load that's proximate to our own in corridor demand, thereby enhancing our return on this renewable activity. We're also progressing initiatives for two pumped storage projects. We expect to make a final investment decision this year on the Canyon Creek project in Alberta, which has a capital cost of approximately $300 million. And we continue to progress the development of the Ontario Pump Storage Project with an estimated $4 billion investment that would provide 1,000 megawatts of flexible, clean energy to Ontario's electricity system. Beyond that, we are working on numerous opportunities, including carbon transportation and sequestration with Pembina, clean energy projects with Irving Oil, and large-scale hydrogen production hubs with Nikola and Hyzon. As a result, we are well positioned to sanction more than $5 billion of new projects in each of the next several years with risk-adjusted return profiles consistent with historical levels. Looking forward, our $24 billion secured capital program gives us line of sight to an average annual growth rate in EBITDA of 5% through 2026. This outlook reflects our current portfolio of high-quality, long-life assets and secured projects expected to enter into service in that period of time. Having said that, we continue to see the potential for incremental growth to the extent we're able to originate and place into service additional in-corridor projects, secure capital light opportunities, and realize further cost savings. So 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 2022 dividend of 90 cents per common share, which is equivalent to $3.60 per share on an annual basis. This represents a 3.4% increase over the amount declared in 2021 and is the 22nd consecutive year that our board has raised the dividend. Based on the confidence we have in our future outlook, we expect to continue to grow the dividend at an average annual rate of 3% to 5% per annum. Now, finally, as I highlighted at our investor day in December, our vision is to be the premier energy infrastructure company in North America now and in the future. To help us realize our vision, we've set the following priorities for 2022, which we will report against throughout the year. First, safety is our number one value. We take our responsibility to safely deliver the energy people need every day very seriously. Next, our goal is to continually increase the return on invested capital. We'll achieve this by optimizing our existing operations through cost savings as well as innovative products and services that enhance our revenues. We also expect to place approximately six and a half billion dollars of assets into service in 2022. And our goal is also to sanction an additional five plus billion dollars of high quality growth opportunities. As always, we will fund our capital program prudently to ensure we maintain our financial strength and flexibility. And finally, we will progress our sustainability targets including GHG emission intensity reductions. We will also continue to enhance our organizational capabilities necessary to prosper irrespective of the pace and direction energy transition takes. Before I turn the call over to Joel, I'd like to mention a few recent management changes. Bevan Wurzba's role has expanded to Executive Vice President, Strategy and Corporate Development, and Group Executive, Canadian Natural Gas and Liquids Pipelines. Reporting to Bevan will be Greg Grant, President of Canadian Natural Gas Pipelines, and Richard Pryor, President of Liquids Pipelines. This follows the news that Tracy Robinson has been appointed President and Chief Executive Officer of Canadian National Railway. I'd like to thank Tracy for her contribution over the years and wish her well in her new role. While we will miss Tracy, this seamless transition highlights the strength of our succession planning efforts and the depth of our organization. Each of these individuals were identified in our leadership succession planning process over the last many years. I'm confident that Bevan, Greg, and Richard, along with the rest of our leadership team, have the experience and the skills necessary to achieve our goals. Now I'll turn the call over to Joel who will provide more detail on our fourth quarter financial results and outlook.

Thanks Francois and good afternoon everyone. As Francois mentioned, our assets continue to perform very well. Our strong operational and financial results continue to reflect our diversified, low-risk business strategy and demonstrate the criticality of our unparalleled asset footprint. As outlined in our results issued earlier today, net income attributable to common shares was $1.1 billion, or $1.14 per share, in the fourth quarter, compared to $1.1 billion, or $1.20 per share, for the same period in 2020. Fourth quarter 2021 results, as well as the corresponding period in 2020, included certain specific items which are discussed further in our fourth quarter 2021 financial highlights release. These specific items are excluded from comparable earnings. Comparable earnings for the fourth quarter were $1 billion or $1.6 per common share compared to $1.1 billion or $1.15 per common share in 2020. In the fourth quarter, comparable EBITDA from our five operating segments of $2.4 billion was 3% higher compared to $2.3 billion earned during the same period in 2020 despite currency translation headwinds. Detailed variance explanations for each business unit can be found in our financial highlights release, so I'll just comment on a few principal changes year over year. U.S. gas pipelines comparable EBITDA increased compared to fourth quarter 2020, primarily due to higher earnings from Columbia Gas as a result of increased transportation rates effective February 1st, 2021. Liquids pipelines comparable EBITDA declined mainly due to lower volumes on the U.S. Gulf Coast section of the Keystone Pipeline system. For our businesses with U.S. dollar denominated income, including U.S. and Mexico gas pipelines and parts of liquid pipelines, EBITDA was translated into Canadian dollars using an average exchange rate of 126 in fourth quarter 2021 compared to 130 for the same period in 2020. Therefore, while our overall U.S. dollar denominated comparable EBITDA increased in the fourth quarter, the year-over-year weakening of the U.S. dollar was a considerable drag on comparative 2021 Canadian dollar reported EBITDA. Now, that said, the corresponding impact on comparable earnings was not significant, as our U.S. dollar-denominated revenue streams are, in part, naturally hedged, with the residual exposure actively managed on a rolling three-year forward basis. I will now speak to a few of the primary variances below EBITDA. Interest expense included in comparable earnings was higher year over year, largely due to the cessation of capitalized interest for the Keystone XL pipeline project and long-term debt issuances, partially offset by the foreign exchange impact from a weaker U.S. dollar on translation of U.S. dollar denominated interest. Income tax expense included in comparable earnings for fourth quarter increased compared to 2020, primarily due to higher flow through income taxes on Canadian rate-regulated pipelines. During the fourth quarter, comparable funds generated from operations were $2.1 billion, bringing the total to $7.4 billion for the year. As we exited 2021, our liquidity position remained strong. We continue to have access to capital markets on compelling terms and remain focused on bolstering our financial position over time. Looking forward, this graphic illustrates our forecasted sources and uses of funds for 2022 through 2024. Starting in the left column, our total requirements over the three years are projected to be approximately $25.5 billion, reflecting capital expenditures including maintenance capital of $14.5 billion and dividends of $11 billion. The second column highlights expected internally generated cash flow of $22.5 billion, leaving a residual need of approximately $3 billion depicted in the two far right columns that we expect to fund through a combination of cash on hand commercial paper, incremental debt, hybrids, and Keystone XL project recoveries. Turning now to our outlook for 2022. Additional information is contained in our 2021 annual management discussion and analysis. Overall, we expect 2022 comparable EBITDA to be modestly higher than 2021. Canadian natural gas pipelines EBITDA is anticipated to be higher mainly due to the continued growth in the NGTL system, partially offset by the reduction of flow-through depreciation on the Canadian mainline, as one segment was fully depreciated in 2021. As a reminder, we believe earnings are a more appropriate measure than EBITDA when assessing financial performance for a Canadian gas business. U.S. natural gas pipelines EBITDA is expected to be consistent, primarily due to an anticipated increase in transportation rates on ANR subject to the outcome of the Section 4 rate case filed with the FERC, as well as expansion projects on ANR and Columbia Gulf. These positive developments are expected to be partially offset by higher operational costs and property taxes. In Mexico, we expect EBITDA to be higher year over year due to increased contributions from the Villa de Reyes pipeline expected to be phased into service throughout the year. In liquids, EBITDA is anticipated to be lower due to continued challenging market conditions impacting volumes on the U.S. Gulf Coast section of the Keystone Pipeline system and decreased margins in the liquids marketing business. Comparable EBITDA for the power and storage segment is expected to be generally consistent with 2021. We anticipate Bruce Power equity income will be similar in 2022 as the impact of its contract price increase for the Unit 3 MCR program is expected to be offset by greater non-MCR planned outage days and operating costs. Bruce Power Availability, excluding Unit 6, which continues its MCR program, is expected to be in the low 80% range in 2022. Other items impacting earnings include a lower average foreign exchange hedge rate on our 2022 U.S. dollar-denominated comparable earnings, along with higher anticipated interest expense on long-term debt issuances, net maturities. In 2022, our forecasted U.S. dollar income is largely hedged at 126 compared to 135 in 2021. Excluding Canadian rate-regulated pipelines, where income taxes are a flow-through item and thus quite variable, along with equity AFEDC income in U.S. gas pipelines, we expect our 2022 full-year normalized tax rate to be in the mid to high teens. Our exposure to interest rates and commodity price variability remains quite limited in And our diversified portfolio, given approximately 95% of our EBITDA, comes from contracted and regulated assets, which include various flow-through and sharing mechanisms. As a result, we expect our 2022 comparable earnings per share to be consistent with our record results in 2021. Now, in terms of capital spending, we expect to invest approximately $6.5 billion in 2022 on growth projects, maintenance capital, and contributions to equity investments with a majority earmarked for NGTL system expansions, U.S. natural gas pipelines projects, the Bruce Power Life Extension Program, and normal course maintenance capital. Despite a few headwinds, which include the impact of a weaker U.S. dollar, we remain confident in our ability to deliver EBITDA growth of 5% through 2026, though our growth will not be linear. Our outlook is underpinned by our $24 billion secured capital program is expected to produce unlevered after-tax returns of approximately 8%. We also have numerous other levers to build on that growth rate in each of our business units. Similar to today, approximately 95% of our EBITDA will continue to come from regulated and long-term contracted assets. So in closing, our strong operational and financial results continue to reflect our diversified low-risk business strategy and demonstrate the criticality of our unparalleled asset footprint. Our enduring business model, financial flexibility, organizational capabilities and extensive portfolio of assets position us to capitalize on a vast opportunity set which will continue to allow us to serve today's needs in the evolving energy mix of the future. Now looking forward, we're well equipped to fund our current capital program with a combination of internally generated cash flow and debt capacity which will allow us to maintain our solid financial position and flexibility. Our expected growth in EBITDA of 5% or more will provide us with the ability to enhance our already conservative payout ratios, 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. 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 two. We will pause for a moment as callers join the queue. Our first question comes from Ben Pham of BMO. Please go ahead.

Okay, thanks. Good morning. Good afternoon. A couple questions on the power business. You mentioned with the RFI and the renewable procurement, and you add in some additional origination. I'm wondering, how does that result in higher returns and impact on your EBITDA? Is that only under the assumption that TRAPS invests as equity alongside these power companies?

Thanks, Ben. It's Francois. I'll kick this off, and I'll ask Corey to provide a little bit of additional detail. By virtue of our ability to aggregate load in the area of our pump stations on the base Keystone system, number one, we can create economies of scale from being able to deliver power at a lower cost for everyone's benefit. Secondly, we're able, as TC Energy, without having necessarily ownership in the assets, as the PPA counterparty, partial off different amounts of load to the different counterparties on the purchasing side. So we might be the counterparty on a 100 megawatt wind farm and find three different counterparties that each want, let's say, 25 megawatts for their own purposes. and we're the intermediary that stands in between. So without allocating any long-term capital but utilizing working capital, we can create some margin for ourselves to enhance our returns in addition to meeting our own demand. We will, in some instances, have the option to acquire equity in the facilities themselves at COD. We won't be taking any construction risk. and we'll consider those on a case-by-case basis as those types of investments will have to compete for capital with other parts of our business. Corey, I'll throw it over to you for some additional detail and proof points on the scale of what we've seen in terms of aggregation.

Hi, Ben. It's Corey here. Thanks for the question. Just two points to make real briefly. Number one, One of the most expensive parts of the process of development for renewable assets, as you know, is to find and contract with customers. And because we have those customers already in corridor, we're able to reduce our costs pretty dramatically as we think about reaching those customers and closing out transaction opportunities for us and also helping our customers on their decarbonization journey. The second, you know, proof point that I sort of lay out to you there is because we are in this sector, in the industrial sector, many of our customers already have longstanding relationships with us. So we understand the T's and C's and some of the other unique parts of their business that's going to make the transactions move a little bit more smoothly. And just as a proof point, you know, right now we have approximately 1.3 gigawatts of offtake secured in LOI stage, and we are now in definitive negotiations with those counterparties, in addition to the internal load that we've already worked on.

Okay, I got it. So, at some extent, it's similar to some of the contracts in Alberta that we've been seeing you engage in. Is that correct? Yes. Okay. And then my follow-up, is there anything you need to do on the power marketing side in terms of expanding it or can you run everything out of Alberta?

Hey, Ben, it's Corey again. We currently and have historically done our power marketing out of both Alberta and Houston to service our our Canadian and U.S. customers. Those should be plenty sufficient for our continued operations moving forward and continuing to service the load that we have internally with our existing customers.

Okay, great. That's very helpful. Thank you.

Thanks, Ben.

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

Thank you. I'm just wondering if you could help me understand the status of any white space in your business, an update on where it is in your pipeline network, and how might any sort of increasing costs on the operating side kind of offset from a margin perspective how much lift we might see in the next couple of years as that white space fills up?

Thanks, Linda. Joel, to take the inflation part of that question first, and then I'll come back around to white spaces.

So thanks, Linda, for the question. With regard to inflation, because we get asked this a lot, you know, the key takeaway is that the impact of inflation remains quite limited. And that's a result of, you know, 95% of our EBITDA is underpinned, obviously, by, you know, contracted and regulated assets. And this obviously includes various, you know, flow through and cost sharing mechanisms. So what we see is that about 20% of our operating costs would be subject to inflation in the near term. And so a key sensitivity to use is for every 100 basis point change in the inflation rate. It results in approximately less than $10 million pre-tax impact to our bottom line.

And as to the second part of your question, Linda, so what you hear from Joel is that we have very little exposure to inflation in terms of our operating costs. In terms of white spaces, I think if you look at our natural gas pipeline footprint, for example, we have plenty of in-corridor growth that will be derived from our leading position in the WCSB and the Appalachian Basins. We don't see a great imperative for us to be looking to serve other basins. Those are the two basins, for example, through COVID and some of the demand destruction that occurred that performed very well throughout that period of time. So we're very confident in those basins' ability to deliver. On the power side, I think you'll see us growing our contractual position and our long-term capital investments in the U.S. We have a terrific footprint and opportunity to electrify our own consumption on the gas pipeline side. The regulatory construct in the U.S. is more conducive to us investing in electrifying our own compressor stations in the U.S. in the near term. That may change in Canada as well, but for the time being, I think we'll be focusing our capital investment in power and storage with respect to renewables in the U.S., and that's to complement the roughly billion dollars a year we're going to spend at Bruce Power.

Thank you. And just as a quick follow-up on your Ontario pump storage opportunity, have there been any recent discussions with anyone or any activity on that front? Or might there be a bit of a pause this year given the pending provincial and municipal elections that we'll be seeing in Ontario?

Hi, Linda. It's Corey again. We are in process in the province. We are working on a number of major fronts. We have begun discussions with the ISO in accordance with phase two of their phased assessment process, and we are working with the DND with continued site assessment work in Meaford. And then finally, we are working with our other indigenous stakeholders and partners such as the San to finalize our partnership going forward on this project.

Our next question comes from Robert Kwan of RBC Capital Markets. Please go ahead.

Good afternoon. I can just ask about your capital allocation around the balance sheet and leverage. And you talked about your balance sheet as being a strategic enabler for either large projects or acquisitions. And I'm just wondering, how do you envision getting there as you think about the likelihood, at least that you're putting forward, of bringing in $5-plus billion of new projects a year in terms of getting to that position where you can use that balance sheet opportunistically? Is it either or, or do you see other levers you can pull to get to whatever that target might be?

Thank you, Robert. It's Francois here. Our plan is to, as you see the sources and uses over the next several years, we'll be keeping our total debt relatively steady and using internally generated cash to fund both the dividend and our capital program. So in essence, you'll see us growing into the targeted long-term leverage of 4.75 debt to EBITDA. Looking at the materials we presented at our investor day, and ascribing an average 5% EBITDA growth over that period of time, we'd get well below 4.75 by the end of that five-year period. But we did also say that we expect to be able to sanction additional project as we go. I cannot tell you that there's a specific number at which we'll say, okay, we've got dry powder, and when an opportunity comes along, we'll be able to act on it. I tell you that, generally speaking... retaining more free cash to invest in, whether it's M&A, or I would argue it's really important to be agile and nimble around energy transition as we compete to help our customers lower their own emissions. Having a strong balance sheet and an ability to respond quickly to their needs is really important. It's not just with respect to M&A. It's also in terms of developing projects around energy transition. And so, you know, again, I think it's just a directional preference. And, you know, as I said, we do expect to be adding projects over the next few years. And we sort of see $5 billion as a reasonable run rate for us to be able to live within our means going forward.

That's great. If I can finish with a topic related to the reselling of power and that being looking like an asset light strategy. Just wondering, is that a specific strategy to this business? Or when you pair it with your 2022 priority of improving the return on invested capital, is this a strategy that you might consider more broadly? whether that's something like monetizing portions of your existing assets but remaining the operator and, say, taking back management and other fees.

Yeah, I think that's a great observation, Robert. When it comes to the decisions we'll make in the future around investing equity in some of the renewable projects that we're sanctioning, those projects are going to have to compete with other uses of capital within our capital stack. So looking to aggregate and parcel out and gen to load match, load for third parties, is a way for us to improve our returns and take a little bit of an asset-light approach. If you look at what we're doing in Mexico, if you look at what we're doing with our liquids business, we've got capital in the ground. You know, in VDR, you know, achieving completion this year with the southern portion of our Keystone system from Cushing down to the Gulf Coast, the capital has already been deployed and our job now is actually to increase the utilization through commercial means and, you know, marketing means as well. So if we're able to do that, we are going to be able to improve the return on invested capital on the existing capital that's been invested. And that's a theme that we're going to be focusing on over the next couple of years to help us across all of the different metrics, improve our leverage, retain more cash, and invest in energy transition.

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

Yes, I'd like for you to walk me through the strategy in pricing the next phase of the Bruce MCR. On the one hand, you've highlighted the COVID-19 impact on cost and schedule contingency for Unit 6, but you're also seeking recovery for the force majeure provisions. What level of certainty do you have for recovery of those costs that gives you the confidence in the final cost and schedule estimate you submitted for Unit 3 and same thing for the preliminary cost submitted for Unit 4?

Hi, Robert. It's Corey. You know, as we think about Bruce Power, you know, I think about it as definitely being, you know, the poster child for our high-quality long-life assets. And so when we go through the process of the MCRs, We use a very systematic approach to determining each one of those factors. We work closely with all of our stakeholders, including the ISO, to make sure that we are adequately evaluating each phase of the MCRs and making sure that we are inclusive of all reasonable outcomes and costs that will be part of that. I feel like our relationship with the ISO and the stakeholders is quite good. And we have included each component of the risks that were presented as a function of COVID as part of that going forward. That being said, the folks at Bruce Power have done a great job of being able to plan well in advance. This isn't a process that just kicked off last year in December. It's actually a process that takes many years. And most of the work that went into this has been a long time coming. I feel like we're in the right spot, we'll be in the right spot for the next years to come, and we have a really strong relationship with the ISO to ensure that the citizens of Ontario receive the most fairly priced carbon-free electrons available to them.

Corey, if you might also help Robert with the status of Unit 6, where we are with respect to cost and schedule, and the status of the force majeure applications that we made at the beginning of COVID.

Yeah, thanks, Francois. First, we are on schedule and on budget for Unit 6. We expect that to come in on schedule in 2023 as per plan. And with regards to the force majeure submittals, those are being tabulated and we keep very close records of all of the impacts, and then we submit those to the ISO in accordance with the terms and conditions of the ABIPRIA. So there'll be more to come on that in the coming months as we sort of exit this phase of the project, but right now I would reinforce we are on schedule and on budget for Unit 6.

Okay, that's helpful that answers it. And just maybe a quick one on the finance side for Joel. I just want to understand the status of the ATM, which I believe that program has expired, and whether or not you have any plans to renew it.

Thanks, Robert. Yeah, we have no plans to renew it. We put the ATM in place originally for Keystone XL, and we just left it there. We have not used it, but it will expire, and we have no intentions to replace it.

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

Hi, this is Stephen McGee, stepping in for Jeremy. Really only one question for me, guys. Early last month, we took a closer look at the Bakken, and we found that with increasing gores and reduced flaring, NBPL is running near full nameplate capacity, at least on a e-content perspective. And seeing as how ethane rejection and extraction dynamics play a larger role on egress, just kind of wanted to get your thoughts on the MBPL pipeline, basin egress, and just general views on the basin. So thank you.

Stephen, this is Stan. I could address that. And you kind of hit some of the high points already. Bakken production is now pushing close to three DCF a day, which is what it was prior to the pandemic. And if you look at the mix between Bakken volumes versus Canadian volumes coming into the northern border system, it's about that 72% Bakken weighted, which is the highest ratio it's been in the past three, four, five years or so. We have seen an increase in processing and ethane extraction capacity in the region, which is not unexpected given the fact that ethane prices are somewhere in the 40 cent a gallon right now range. So given all that, given the fact that production is up, layering is down, We're actually very bullish on the need for there to be additional takeaway capacity out of the Bakken, probably to the tune of about a half a BCF a day, give or take. And, again, we've been actively engaged with the Bakken producers. We think our bison pipeline is uniquely situated for a takeaway solution. And don't be surprised if you see something coming out along those lines later this spring with respect to an open season.

Got it. Appreciate it. Thank you, guys. Thanks, David.

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

Afternoon, everyone. I want to circle back on the renewable power energy transition business. Where do you see DC Energy's optimal place to enter the development process there? Do you think it is the expectation that moving forward you'll want to focus on that asset light like you're doing in the in the middle part of the U.S., or could we see more of a historical development focus similar to what you're doing in Ontario and Alberta?

Male Speaker 1 Hey, Rob, it's Corey. I think that the answer to your question is yes. I think we would take an all of the above strategy, really more focused on the jurisdiction that the opportunity presents and the customers that we are trying to serve. So you see us with an early stage development with some of our renewable assets, specifically Canyon Creek or Meeper Pump Storage in Ontario because of a number of different reasons, not the least of which is our assets in that particular jurisdiction. In the United States, I would think about it through the following lens, and that is the market has a great number of organizations that are very good at early stage development, and it would be difficult for TC Energy to replicate that those development skills. But what we can do and where we can bring our expertise to bear is in contracting TCCs and then connecting the load with our customers and both internal and long-term customers of our other businesses and so i think it's going to be a variety of a variety of different uh choices there but we do believe that we will own assets or portions of assets over time and there will be assets we will take the asset light approach as it meets our needs in that jurisdiction all right appreciate it color and then as a follow-up and maybe a little early just given where we are in the year

If the annual goal is to sanction $5 billion worth of projects, as we look out to 2022, what buckets or business lines are you seeing the greatest opportunities in? How much do you have high visibility that you'll be able to get into the secured bucket in 2022?

Rob, it's Francois. I'll take that one. Recall that we have $1.5 billion to $2 billion annually of maintenance capital on which we can earn a return on and of capital. because we're investing in our regulated businesses. And so I think you can expect that to continue. We've got good visibility on that occurring every year, really, throughout the balance of the decade. And then it's well diversified across our various jurisdictions. I think you can expect a billion dollars plus of new projects in our gas franchises combined between Canada and the U.S., simply around electrification of our own assets, reducing our own emissions, and meeting natural gas demand growth. I think one of the things I talked about in my prepared remarks is that the evidence and the facts indicate that demand for natural gas in North America continues to grow. And we've benefited from that. And then in our power business, we've talked about the RFI process and the fact that we're aggregating incremental load and we're going to do some gen-to-load matching. And the opportunities for Canyon Creek, we'll be looking at sanctioning that $300 million project this year, as well as a number of other smaller projects. in different parts of the company. So it's spread around a little bit, which is good. We feel comfortable about the fact that we're not heavily reliant on any of our businesses to actually deliver that $5 billion per year. Having said that, we have a couple of large, sizable opportunities out there for us to sanction, potentially a phase two of CGL, the Ontario Pump Storage Project, $4 billion. And then, of course, our efforts in Mexico, working in partnership with the CFE to potentially sanction additional infrastructure. So, you know, we've got lots of small in-corridor opportunities across our entire footprint that when you add them together, that $5 billion is pretty visible, and then some larger opportunities on top of that.

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

Thanks. Good afternoon. On the ANR rate case, it looks like the requested ROE is 16%, if I'm seeing it correctly. Just wondering how much of that is based on the regulatory environment and the increase in perceived risk, I guess. What are the factors behind that number? I think it's a bit higher than normal.

Yeah, Praneesh, this is Stan. Actually, when we look at our Our proxy group, it's in the upper third range, so it's in that higher tier, but that does reflect the fact that all things equal, amongst our proxy group, ANR has a little bit more exposure to producers and, therefore, commodity prices and probably has a little bit more exposure to gas-on-gas competition with respect to deliveries of volumes into the mid-continent area. So not an outlier by any stretch, but it is in that upper third tier of our proxy group.

And then in terms of the bridge loan that's being provided to Coastal GasLink, can you comment on the timeframe for when that would be repaid? And I guess I'm just wondering why you elected to provide funding yourself versus using additional bank debt. And then maybe also if you could give us an update on the status of Coastal GasLink, that would be good.

So, Praneeth, I'll start with that. It's Joel here, then I'll turn it over to Bevan. As we mentioned before, the $3.3 billion bridge loan is just the, you know, proved that there's sufficiently of funding for the project as we've highlighted back in Q3. We view it as being temporary to the extent that we can actually get an increase in guarantees so that we can then subsequently increase the credit facility that we have at CGL at this point in time. So once again, we view it as being temporary, the $3.3 billion. And as we've highlighted, we do earn a market return if we do lend funds into CGL. At year end, it was $238 million, I believe, outstanding on that $3.3 billion facility. So it will be in place until we get an increase in the credit facility, and then whatever is needed to bridge the funding, if you will, to the project completion will be determined.

Praneeth, this is Bevan. We're making great progress in the field on the right-of-way. At the beginning of the year, we're nearly at 60%. complete in the field. What is really clear to us is that the fundamentals that underpin the need for Coastal Gas Link and the LNG Canada LNG facility have, the needs for those projects have never been more robust. And so we've been working very closely with our customers, LNG Sea Canada and also with our equity partners to position the project for a safe execution and be ahead of the LNG facility. So discussions are ongoing and we're making great progress, so happy with the direction that the project's taking.

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

Yeah, hey guys. Thank you for taking my questions. Just curious, on Coastal GasLink, should we think about the potential cost increase as being a significant or material number or is it it was the disclosure you're giving of hey there's going to be cost but it's not going to be in the billions of dollars range and if it is a pretty sizable number call it i don't know anything north of a billion how does that impact the return you guys would earn on the project michael this is bevin again um you know the

Our shared objective with our customers is to deliver the pipeline safely and get it ahead of the LMG plant that's being constructed right now. The most complex parts of the project in terms of the civil works are behind us. We're advancing very carefully with our contracting plans. So the balance of the project, we see very strong line of sight to being able to be executed in a manner that mitigates the risks that are ahead. I'm not saying that those risks don't exist, but we have plans in place to ensure that we can deliver the project for our customers.

Got it. And what's the process? The annual report disclosure in your press release today kind of talked about how there was kind of an ongoing negotiation or dispute over, I think it was cost and timeline. I don't remember off the top of my head. What's the formal process for that getting resolved? Is it just a negotiation? Is it arbitration or some other methodology?

Yeah, we're in very constructive dialogue with LNGC right now, and that is just a process of commercial discussions with our customers to ensure that we maintain that alignment going forward on the project.

Got it. Thank you, guys. Much appreciated. Thanks, Michael.

Our next question comes from Brian Reynolds of UBS. Please go ahead.

Hi, good evening, everyone. Maybe to follow up on Coastal GasLink, it appears that, you know, the project continues to progress. And TransCanada talks, you know, previously about partnering further with the First Nations. First part of my question is, is TransCanada still interested in divesting some of the equity ownership? And two, you know, what would the First Nations, you know, like to see before, you know, committing to become an equity partner? Thanks.

Yeah, thanks, Brian. This is Bevan again. You know, we've had unprecedented support from the Indigenous communities along the route, and our team is doing a real good job progressing construction, as I just mentioned in response to the previous question. And we've got 20 agreements successfully implemented with the nations along the right-of-way, and we're still moving forward and progressing our... our negotiations around bringing in Indigenous communities in an equity participation mode. The reason for that is we share the same values as our Indigenous partners and we believe working alongside them in an equity participation role is the right thing to do for the project.

Great, thanks. And maybe just to follow up on capital allocation and some balance sheet I talked about previously. The slide that you guys provided kind of implies, you know, a couple billion, you know, need in debt issuances over the coming years through 2025. Just kind of curious, you know, post 2025, should we see a free cash loan inflection after dividends? And then maybe just on the KXL recoveries, could you provide, is there currently a reserve on the balance sheet as a contingent asset, or just kind of curious if you could provide a quantifiable range of, you know, potential expected outcomes? Thanks.

We'll get Glenn to start on the second of those questions, and then Francois will take the first part of that. Go ahead, Glenn.

Thanks, Brian. Yeah, as far as the contractual recoveries on KXL, they are sitting on our balance sheet as an asset, as a receivable. And we will realize those under the terms.

And with respect to inflection points, I think at the moment our view of our desired steady state for our balance sheet metrics is a debt to EBITDA of 4.75. And it's also important for us to be living within our means. And so we think of that as a run rate of capital expenditures of $5 billion a year after servicing our dividends from our free cash. We'll have a very stable long-term debt sum if we proceed on that basis. And you'll see us sort of grow into that leverage over time. To the extent we are comfortable in the future with that steady state and opportunities present themselves for us to return capital to our shareholders. We'll weigh those against opportunities to invest additional capital. I can tell you right now we are very bullish on the opportunity set that's in front of us. As we've said before, we believe we can maintain our risk preferences and our historical rates of return, even in allocating capital to energy transition. And if we're able to do that, we think we are creating value for our shareholders and would be very comfortable allocating that capital at that point in time.

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

Thank you very much. I want to say thanks to everyone for your attention today. We're working feverishly to try and tighten up our prepared remarks and shorten our calls going forward, so we appreciate all of the good feedback we've gotten. In closing, a couple of things, and then I'm going to pass it over to Joel for just a quick minute. Firstly, we will continue our disciplined approach around capital allocation. and adhere to our risk preferences. We see no reason for us to be relaxing our risk preferences to be able to allocate our $5 billion a year of free cash flow. And secondly, as I said, the opportunity set is substantial and we are really well positioned. The more we speak to our customers about how to help them reduce their emissions, the more opportunity we see for ourselves to play a role in energy transition. Joel, over to you for a few closing remarks.

Sure. Thanks, Francois. So last fall, David Mineta informed us of his plan to retire at the end of March of this year. David has been with the company for over 38 years, beginning in our Toronto office and has been in investor relations for the past 26 years. So, David, based on my math, this means that you've participated in over 100 quarterly calls, including today, during your wonderful career here. And I can't count the number of meetings with investors well into the thousands throughout your career. You know, David's unwavering professionalism, dedication, and reputation, not only here at TC Energy, but obviously in the investment community, is just unparalleled. So on behalf of current and past management, David, I want to say thank you for a wonderful career, and we wish you all the best in your well-deserved retirement. Well done. That's great. Thanks, Joel.

Much appreciated.

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