Thank you for standing by. This is the conference operator. Welcome to the TC Energy first quarter 2022 results conference call. As a reminder, all participants are in listen-only mode and the conference is being recorded. After the presentation, there will be an opportunity to ask questions. 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 Gavin Wylie, Vice President, Investor Relations. Please go ahead. Thank you very much, and good afternoon, everyone. I'd like to welcome you to TC Energy's 2022 first quarter conference call. Joining me today are François Poirier, President and Chief Executive Officer, and Joel Hunter, Chief Financial Officer, along with other members of our senior management team. François and Joel will begin today with some comments on our financial results and certain other developments within the company. Copy of the slide presentation that will accompany our remarks is available on our company's website in Investor Relations section under Events and Presentations. Following the 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 François begins, I'd like to remind you that our remarks today will include forward-looking statements that are subject to important risks and uncertainties. For more information on these risks and uncertainties, please see the reports filed by TC Energy with Canadian Securities Regulators and with the U.S. Securities and Exchange Commission. Finally, during this presentation, we will 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 turn the call over to François. Thanks, Gavin, and good afternoon, everyone, and thanks for joining us today. Before we discuss our results this quarter, and I expect we're gonna be talking about global geopolitical events here during the call, I wanna start by acknowledging the tragic humanitarian crisis happening right now, and we extend our thoughts to all of those who are experiencing such immense suffering. Now, within the context of our industry, these events have amplified the discussion around energy security and highlighted the important role our industry plays in meeting today's energy needs. While the world confronts a serious geopolitical shift, a transition to cleaner energy that also meets the world's demand is still required. North America and TC Energy will play a critical role in securing the global energy supply while also transitioning to a lower carbon future. This intersection of energy security and energy transition is not an obstacle to growth. We believe rather that it's a catalyst. We're particularly well-positioned to support exports of LNG that represents one of the most significant growth drivers in the natural gas business in North America. North American LNG exports peaked this year at 13.7 BCF a day, and we now expect that amount to grow by over 90% to 25 BCF a day by the end of the decade. Our critical energy infrastructure assets are well situated to support connecting North America's premier basins to LNG export facilities. Now, TC Energy is already a significant player, connecting approximately 25% of supply apportioned for U.S. LNG exports through our extensive pipeline networks. Going forward, we expect to compete for and win our fair share of the growth in the LNG market. We continue to evaluate new expansion potentials and execute our portfolio of sanctioned projects. For example, already this year, we have two new pipelines that directly support deliveries to LNG facilities in Louisiana. Phase two of our Grand Chenier XPress project started service in January and connects to the Calcasieu Pass LNG terminal. Our Louisiana XPress project, which is expected to be fully in service in the coming months, will deliver volumes to Sabine Pass. Now in addition, we've recently received approvals to move ahead with three more LNG-linked projects. The East Lateral XPress project on our Columbia Gulf system will support the proposed phase two Plaquemines facility in Louisiana. The Alberta XPress project will also deliver into Sabine Pass. Finally, our proposed North Baja XPress project, which supports the Costa Azul LNG facility on the west coast of Mexico. This is just the start. Our unparalleled pipeline network is critical to the delivery of LNG volumes today, and it underlines the tremendous opportunity that we have to connect supply to the growing LNG export market. Like I said off the top, the world has never needed safe, sustainable, and secure energy the way it does now. We are a company of energy problem solvers, delivering solutions to address this challenge. The demand for our services has never been stronger, and operationally, our assets performed extremely well throughout the first quarter. Despite the warmer than average winter season, we saw record sendouts on our U.S. national gas system, including Columbia Gas, PNGTS, and GTN. This contributed to daily average flows for the first quarter of 30 BCF a day, up 5% versus 2021, including an all-time daily system record of nearly 35 BCF in January. We saw similar trends in Canada. Our NGTL system in Alberta averaged winter demand was the highest on record since 2000 at 14.2 BCF a day. Our Canadian Mainline system experienced additional contracting in the quarter and is essentially sold out of long-term capacity. These tremendous performance results reinforce that our assets are ever more critical for the delivery of North American energy supply. We also progressed our secured and developing portfolio of projects, including Coastal GasLink. In March, we were proud to announce the historic signing of option agreements to sell 10% equity interest in the Coastal GasLink Pipeline Limited Partnership to indigenous communities across the project corridor. We recognize that enduring relationships with our indigenous partners include long-term economic opportunities, and this is one of the ways we can advance reconciliation. On the construction front, we continue to make headway as we approach spring breakup. Overall, the project is 63% complete with 100% of the route now cleared. In power and storage, we continue to advance projects to add renewable and lower carbon energy to the mix and reduce the carbon footprint of our own operations. For example, our Bruce Power Life Extension Program. On March seventh, the IESO verified the final cost and schedule duration estimate for Bruce Power's Unit Three MCR program. With our Unit Six MCR progressing well and expected to be in service in 2023, the Unit Three MCR represents the next step in Bruce Power's life extension program and is scheduled to begin in the first quarter of 2023 with anticipated completion in 2026. Upon completion, Unit Three will provide enough emission-less, reliable, and low-cost energy to power over 800,000 Ontario homes every year. The power and storage business, as we mentioned previously, is also supporting the company's goal to serve our own energy use with renewables, as exemplified by the RFI we kicked off last year. To date, we have finalized contracts for approximately 160 megawatts of wind and 240 MW of solar projects. We continue to evaluate the proposals received through the RFI process and expect to finalize additional contracts in 2022. New fuels will also be needed to power the energy grid of the future, and we have existing skills and assets that can pivot to develop them. For example, we're actively pursuing opportunities in the hydrogen economy, developing hydrogen hubs to serve long-haul transportation and other industrial uses. Just this week, we announced that we've identified our existing Crossfield storage site as a potential hydrogen hub location. The proposed hub would produce an estimated 60 tons of hydrogen per day with the capacity to increase to 150 tons per day in the future. Our joint development partner, Nikola, would serve as the hub's anchor customer for its long-haul fuel cell electric vehicles. We anticipate a final investment decision by the end of 2023. The Alberta Carbon Grid, our joint venture project with Pembina, is another significant opportunity to help industries and businesses decarbonize their operations and meet their sustainability goals. In March, we received notice from the government of Alberta that our proposal to build and operate a carbon storage hub and gathering lines in Alberta's industrial heartland was successful. ACG is now moving into the next stage of the province's CCUS process, entering into an evaluation agreement. Once fully constructed, the ACG aims to transport and sequester up to 20 million tons of CO2 annually, almost 10% of Alberta's industrial emissions. It will have a vital role to play in supporting Alberta's carbon competitiveness and the development of a lower carbon economy. As I previously mentioned, achieving a balance between energy reliability and security on the one hand, and energy transition on the other hand, is a catalyst for our growth. There are many opportunities to innovate, modernize, and maintain our regulated natural gas pipeline network while reducing emissions from our business. We're also identifying and developing in-corridor capital light projects, expanding reach and delivery points while enhancing the returns of our existing corridors. The Port Neches link project is an excellent example of our strategy. We're increasing the interconnectivity of the Keystone system and MarketLink to enable direct access to North America's largest refinery. This vital pipeline link will provide a reliable, sustainable and stable source of domestic crude supply for decades to come. We are focusing on sustainable energy solutions to help decarbonize the energy system. Another example of in corridor capital light investments is an exciting initiative that we announced earlier this week to expand our intake of renewable natural gas. We're entering into a strategic collaboration for the development of RNG transportation hubs where GreenGasUSA would contract on our systems. Beyond that, we're also progressing initiatives including pumped hydro storage in Alberta and in Ontario, clean energy projects with Irving Oil, and further hydrogen production hubs with Nikola and Hyzon. As a result of our rich opportunity set, we expect to sanction approximately CAD 5 billion of new projects in each of the next several years, including recoverable maintenance capital. Because the barriers to entry in those new areas are high, returns are expected to be consistent with historical levels while adhering to our conservative risk preferences. As I've highlighted before, you see on this slide our 2022 priorities. I'm pleased with the progress we've made towards achieving these goals in the first quarter. I look forward to providing further updates as we continue to advance towards these priorities throughout the year. We have an incredible opportunity to play a vital role in enabling a transition to cleaner energy while providing the safe, reliable, and secure energy that the world needs. In summary, we have all the right ingredients to meet these energy challenges. We have a world-class base of assets in strategic locations. We have commercial, engineering, and technical capabilities. We have a culture of innovation, and we have financial strength and capital discipline. Our tireless efforts to make energy more sustainable and more secure will continue to strengthen our existing business and deliver long-term results for our customers, community stakeholders, and our investors. Thank you for your attention, and I will now turn the time over to Joel for a few comments on our first quarter results. Thanks, François, and good afternoon, everyone. As François mentioned, our assets continued to deliver strong results in the first quarter while reliably meeting the growing demand for energy. This highlights both the criticality and resiliency of our asset footprint. Comparable earnings for the first quarter were CAD 1.1 billion or CAD 1.12 per common share, compared to CAD 1.1 billion or CAD 1.16 per common share in 2020. Comparable EBITDA and comparable funds generated from operations were CAD 2.4 billion and CAD 1.9 billion, respectively, compared to CAD 2.5 billion and CAD 2 billion for the same period in 2021. I won't spend a lot of time today reviewing the results we published earlier today, but I'll remind you that net income attributable to common shares was CAD 358 million or CAD 0.36 per share in the first quarter, compared to a net loss of CAD 1.1 billion or CAD 1.11 per share the same period in 2021. First quarter results included a CAD 531 million or CAD 0.54 per share after-tax goodwill impairment charge related to Great Lakes and a CAD 193 million or CAD 0.20 per share income tax expense for the settlement in principle related to prior years' income tax assessments in Mexico. First quarter 2021 also included certain specific items as outlined on this slide and discussed further in our first quarter 2022 report to shareholders. As mentioned a few moments ago, first quarter comparable EBITDA from our five operating units was CAD 2.4 billion. You can find more details on the variance explanations for each business unit in our financial highlights release, so I'll just comment on a few principal changes year-over-year. Canadian natural gas pipelines comparable EBITDA decreased primarily due to lower flow-through depreciation on the Canadian Mainline. This is partially offset by increased flow-through depreciation on the NGTL system. U.S. natural gas pipelines comparable EBITDA increased mainly due to higher earnings from Columbia Gas as a result of increased transportation rates effective February 1, 2021. Mexico natural gas pipelines comparable EBITDA decreased primarily due to a higher deferred income tax expense at certain taxes as a result of a foreign exchange gain calculated for Mexico income tax purposes on the revaluation of U.S. dollar-denominated loans. Liquids pipelines and power and storage comparable EBITDA declined as a result of lower contributions from liquids marketing activities, mainly due to lower margins and lower realized natural gas storage spreads reflecting volatility seen in the quarter. As a note, we translated our U.S. dollar-denominated income into Canadian dollars using an average exchange rate of 1.27 in the first quarter, which is similar to the same period in 2021. This included U.S. and Mexico natural gas pipelines and the majority of our liquids pipelines. As a reminder, our U.S. dollar-denominated revenue streams are in part naturally hedged with U.S. dollar-denominated amounts below EBITDA, and the residual exposure is actively managed on a rolling three-year forward basis. Now, I will spend a moment highlighting a few of the primary variances below EBITDA. Depreciation and amortization decreased, largely due to the Northern Ontario line portion of the Canadian Mainline being fully depreciated in 2021, partially offset by higher depreciation on the NGTL system from expansion facilities that were placed in service and in U.S. natural gas pipelines, mainly due to the timing of certain adjustments related to the Columbia Gas rate case settlement. Income tax expense included in comparable earnings for the first quarter decreased compared to 2021, primarily due to lower earnings and a U.S. state tax adjustment, partially offset by lower foreign tax rate in differentials and flow-through taxes. I want to take the opportunity to reiterate our outlook for 2022. We expect 2022 comparable EBITDA to be modestly higher and comparable earnings per share to be consistent with last year. In terms of capital spending, we expect to invest approximately CAD 7 billion this year. This is up relative to our initial 2022 outlook of CAD 6.5 billion. The increase is primarily due to higher costs for the NGTL system, reflecting inflationary pressures on labor and materials, additional regulatory conditions, weather, and other factors. We continue to work on cost mitigation strategies and assess market conditions, developments in our construction projects, and the impact of COVID-19 for further changes to our overall 2022 capital program. Our 2022 capital program is primarily focused on NGTL system expansions, U.S. natural gas pipelines projects, the Bruce Power life extension program, and normal course maintenance capital. Turning to our funding program, this graphic illustrates our updated 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 CAD 26 billion, reflecting capital expenditures, including maintenance capital of CAD 15 billion and dividends of CAD 11 billion. The second column highlights expected internally generated cash flow of CAD 22 billion, leaving a residual need of approximately CAD 4 billion, depicted in the far right column, that we expect to fund through a combination of commercial paper, incremental debt, hybrids, and Keystone XL project recoveries. Today, we are advancing our diversified CAD 25 billion capital program consistent with our historical risk and return preferences. Importantly, our capital program not only focuses on modernizing and growing our core business, but also on advancing projects aimed at reducing emissions and offering carbon-free or low-emission energy alternatives. These projects are underpinned by long-term contracts or cost of service regulation, and we expect them to deliver a weighted average unlevered after-tax IRR of approximately 8%. Given our opportunity-rich position and expectation of placing CAD 6.5 billion of assets into service this year, we are confident in our ability to deliver EBITDA growth of 5% through 2026. Remember, that growth will not be linear. Similar to today, approximately 95% of our EBITDA will continue to come from regulated and long-term contracted assets. Looking at the continued strong performance of our base business and our organic growth plans, we expect to continue to grow our common share dividend at an average annual rate of 3%-5%. This is consistent with our conservative approach to capital allocation, historical risk-adjusted return profile, and it's expected to provide the capacity to fund our sizable capital program while enhancing our financial strength and flexibility. Now, as always, we expect to support the growth in dividends by sustainable growth in earnings and cash flow per share and strong coverage ratios. I'm excited when we look ahead. We have a track record of 13% average total shareholder return since 2000. We are well equipped to fund our CAD 25 billion capital program. We have increased our common share dividend for 22 consecutive years, and we will maintain our solid financial position. When you pair our enduring business model and financial flexibility with our unmatched footprint and organizational capabilities, you'll see that we are differentiated in our potential to capitalize on the opportunity-rich environment before us. This will allow us to continue delivering superior long-term shareholder value. That's the end of my prepared remarks. I'll now turn the call back over to Gavin 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 just two questions, please. Thank you. 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. The first question comes from Linda Ezergailis with TD Securities. Please go ahead. Thank you. A very dynamic environment that we're in right now. I'm just wondering, with all your focus on this energy transition, there is also this expectation that hydrocarbon exports out of North America will accelerate, and that was already a trend, but there, you know, we'll probably see more of it. I know you're already participating indirectly in transporting natural gas to LNG export facilities. What are your thoughts about potentially pivoting harder to support exports of liquids or NGL export facilities? What factors would need to be in place for you to move down the value chain to actually get involved directly in exports? Linda, it's François. I'll get started, and I'll ask Stan to provide some proof points on what we're seeing in the LNG export market. First of all, you're quite right. A better balance between energy security and energy transition has brought forward additional opportunities, as I alluded to in my prepared remarks. We have enjoyed and benefited from the growth in LNG exports with LNG exporters as a customer. As I mentioned, we serve about 25% of aggregate natural gas demand in that area. We've not considered, in the recent past, participating down the value chain as an owner of equity interest in LNG facilities. We see that as a large global market, involving participants who have LNG supply from various sources, have significant scale as well as marketing and commercial marketing and trading capabilities in that area. Our view is that there's plenty of growth opportunity for us in supplying the LNG facilities with their needed gas for their expansions. Perhaps I'll ask Stan here to provide some proof points. Hey, Linda, this is Stan. I could address the LNG side, and then I'll kick things over to Bevin, and he could address the NGL side. I do think that we're in a bit of a target-rich environment, so to speak. FERC, just over the past several weeks, approved three of our LNG export-related projects. In the aggregate, they amount to 1.4 BCF a day, a $700 million capital investment for us, and we're gonna focus on getting that capacity online as quickly and as safely as we can. Secondly, while our Columbia Gulf and ANR pipelines are generally fully compressed and fully contracted for north to south flows, looping those systems to bring more Appalachian gas to the Gulf Coast is not out of the question. Just as an example, if we were to build a new line from the Columbia system all the way down to the Gulf Coast, it likely would have a transportation rate of about $2. If you believe, as I do, that the war in Ukraine has caused a fundamental shift with respect to where our European allies source their gas from, and that this incremental demand for natural gas is gonna keep prices in Europe and in Asia in the $13-$20 range, which is where they currently are for 2023 and 2024, a $2 transportation rate for incremental pipeline capacity to the Gulf Coast may well clear the market. I'd also just remind you that given our extensive 13-pipeline network that traverses 40 states, we have a footprint everywhere. If the Costa Azul facility on the West Coast is expanded from 2 million tons to 10 million tons, we can further expand our North Baja system. If the Cove Point facility on the East Coast is ever expanded, we have the ability to further expand our WB XPress on the Columbia Gas system as well. With respect to the Permian, I do think that there's a likelihood that you'll see additional pipe capacity specifically built directly to the Texas Gulf Coast LNG facilities, but not directly to the Louisiana Gulf Coast LNG facilities. Instead, you're likely to see pipes built out of the Permian that will interconnect with our existing infrastructure in Louisiana, where we can leverage our competitive advantage and take advantage of the last mile connectivity. Lastly, I would note that it's, there are more opportunities than just Appalachia or the Permian Basin. Don't discount the ability for gas out of the Haynesville to ultimately reach some of these Gulf Coast LNG facilities where again, we can leverage our existing footprint. With that, I'll kick it over to Bevin to talk about the NGL side of things. Yeah. Thanks, Linda. On the liquid side, I'll first go with our oil liquid system. We have, as you know, a very strategic footprint that connects Western Canadian Sedimentary Basin down through Cushing and into the Gulf Coast, and we're actively pursuing expanding in corridors. Part of that strategy includes looking at opportunities for additional export points and access to different delivery points for our customers. To do so, we've brought on additional expertise into our marketing affiliate team that has that experience to address different tidewater-type markets. With respect to NGLs or refined products, those are still asset classes that are not in our portfolio. From time to time, we evaluate whether there would be a fit. Both the refined products and NGL businesses, though at this point, we're not advancing any capital towards. Thank you. That's a very helpful update on how you're thinking about things. Maybe just as a follow-up question. I'm interested to hear maybe one of your smaller initiatives that might not get a lot of airtime, but maybe could be scalable into other areas. Your Irving Oil Decarbonization Initiative, can you paint us a picture about what, beyond power generation, might that involve? Would TC Energy operate the facilities in there? What other locations might such initiatives be possible? Over to you, Corey. Hi, this is Corey Hessen. I think when we think about the Irving Oil opportunity, we obviously are starting with our core businesses of the power, the power side and being able to deliver renewable energy. Moving forward, as we talked about with many of our other opportunities, we have built a strong partnership with hydrogen opportunities across our North American footprint, and that will create for us another opportunity with Irving Oil as they think about how to best use their assets and apply them going forward. As we think about that, we think that it is like all of our emerging technologies, a little bit of a longer road, but it creates an opportunity for us to evaluate in a systematic fashion. Thank you. The next question comes from Robert Kwan with RBC Capital Markets. Please go ahead. Good afternoon. If I can start with inflation, the last call focuses on OpEx. I wanted to ask you about CapEx. Generally, what percentage of your CapEx plan has cost recovery, either contractually or regulatory-backed, and specifically just for this NGTL increase? Is it all rate-based where the entire cost increase earns a return on and of capital? Yes, Robert. It's Joel here. I'll take the question. First, it's really worth noting that, when you look at all of our major projects, including Bruce Power, the MCR program there, expansion projects along our U.S. natural gas pipeline footprint, along with liquids pipelines, those all remain on time and on budget. NGTL is unique, in that it is, you know, in Western Canada, it's competing with two other major projects right now for labor in particular. That's obviously the TMX project and CGL. As a result, we are seeing inflationary pressures on labor and materials, in addition to cost increases related to regulatory conditions, along with weather delays, COVID, and, you know, at times, slowing down the work to ensure that our workers are safe. As a result, the costs that you're seeing are primarily related to NGTL System. We are working to meet our customers' needs. It's important to keep our tolls as low as possible, so we're looking at ways to mitigate these costs. But as a reminder, any costs associated with NGTL System, similar to the Canadian Mainline, those costs you earn a full return of and on capital for those projects. Okay. Even though you're not seeing cost pressures on all of those other projects, like, what percentage do you have recovery mechanisms? For the other projects, Robert, just to clarify? Correct. Yes. Yes. It all depends. I'll maybe turn it over to Stan if they have any commentary on the U.S. side and then maybe over to Corey for Bruce Power. Yeah, Robert, this is Stan. With respect to our growth projects that are underway, I would say a vast majority. I don't have a specific percentage for you, but a vast majority are covered. Contractually, we'll be able to recover the capital that we're investing. It's very typical for us to have some sort of cost-sharing mechanism built into our precedent agreements with our customers. Hi, Robert. It's Corey. Corey. With regards to Bruce Power, unit six MCR is going to be completed, I know, inside of 2022 or early 2023. So both materials and services have already been fixed for that MCR, and there's very low risk of additional inflationary costs. Unit three MCR for both materials and services are in excess of 95% fully contracted, so we see limited risk of inflationary impacts for that MCR program as well. Thank you. Yeah. Got it. If I finish with Coastal GasLink, can you just talk about the nature of where you are in discussions? Like, are you still negotiating over costs, or have you now moved to more around the mechanism of how to recover that? And if you've got an update on timing, that would be great. Specifically, you know, how much does LNG Canada's go or no-go decision on expansion matter, in terms of when you're gonna strike an agreement? Robert, this is Bevin. We're very aligned right now with our customer, with LNG Canada. We're working towards resolving the dispute really quickly. Our prime focus right now is to also deliver the project safely and ahead of the delivery of the LNG facility. As we focus to resolve the negotiation here fairly quickly, you know, I'm optimistic that we'll reach an agreement that will put us in a position to update our shareholders on the path forward. With respect to phase two, it's a great opportunity not only for LNG Canada, but also ourselves and the Western Canadian Sedimentary Basin, as we could see the delivery out of the basin move from 2 BCF a day export scenario to north of 4 BCF. That decision, though, is clearly in the hands of our customer, LNG Canada. In terms of preparing for a final investment decision on that front. Okay, that's great. Thank you very much. Thanks, Robert. The next question comes from Ben Pham with BMO. Please go ahead. Hi. Thanks for that. First question is on the LNG commentary you had. When you look at your current footprint today and how you've positioned it, you've mentioned a 25% market share as you look out to that 10-plus BCF a day. Like, do you have enough flexibility in the way that you're positioned to at least maintain that market share? Or, you know, are these projects that you. It's yours to lose? Again, this is Stan. Not only do I think we're going to maintain that market share, but my expectation is we're going to grow that market share. If you look at the 1.4 Bcf a day of projects that the FERC approved that are under construction right now, and then you look at the other opportunities that we have, I could see a scenario where over the next 2-3 years, it's another 2-3, maybe 4 Bcf a day of capacity to the LNG terminals that we're adding on our systems. Is there reason to assume that, Stan, that you can use those projects, the CapEx numbers to gauge the opportunity? Ben, sorry. Could you clarify your question, please? Yeah, sure. The three projects that you're moving forward, you have CapEx numbers attached. It's upward of CAD 1 billion. Can we take those as examples to gauge the capital investment opportunity? Yeah. It really depends. They're not gonna be a very good example if we're going to build a new pipeline from the Appalachian all the way to the Gulf Coast. To the extent that we're going to leverage the competitive advantage we have with our existing footprint, yes, these CAD 100 million, CAD 200 million, CAD 300 million, CAD 400 million type expansions would make sense. Okay. That's great. My follow-up then is on the looping project, the potential project on Columbia. Do you need more LNG projects to start talking about commercial agreements? Or is this just a matter of that price, the $2 price that you mentioned that's mitigating some of it? Well, I was using the $2 price as an example to show that what we think is a high cost today may not be a high cost given the environment that we're in. It fits within the overall stack when you look at transportation rates at $2 for liquefaction, $1 for regas, $2 for shipping and the like. Again, it's basically an in-the-money proposition. Ben, just to supplement that a little bit because I hear where you're going with the question. As usual, we allocate capital on the strength of long-term contracts. That's the way we typically do things, shipper pay contracts. In conversations with shippers in the Appalachian Basin, we are seeing willingness to consider new greenfield pipe, given the robust price environment that our producers expect to remain robust for the next several years. Okay. That's great. Thank you. The next question comes from Robert Hope with Scotiabank. Please go ahead. Afternoon, everyone. Want to switch gears a little bit and move over to the U.S. renewable projects that you secured commitments for. You know, is this only for your existing Keystone capacity, or would this be included in that kind of business idea of sharing it with some other parties and earning a margin on it? I guess secondly, you know, eventually, do you assume that you're going to take an ownership in these projects? When could we see it put into the capital plan? Hey, Robert, it's François. I'll just start at a high level, and I'll ask Corey to provide some detail. As we mentioned last quarter, we were very successful in aggregating incremental load in the neighboring areas to our own demand at our pump stations. As we're gradually contracting up the various projects, it is a combination of meeting the demand from specific pump stations as well as aggregated load in those specific areas. You can see a gradual contracting up of both of those as we add volume towards our overall goal of 2+ gigawatts. Corey, over to you for a little bit more color there. Hi, Robert. Thank you very much, François. François is right on point there. The way we think about it is that we are not only serving our internal load, but we are serving the load of those customers who are in corridor for our vast set of assets across North America. Our goal, as François stated, is to approximately secure 2 gigawatts of total renewable resources. Of those 2 gigawatts, to contract 70% of those resources through our own parties and second party and third parties. Then have additional capacity available to then secure our next phase of opportunities with our own internal customers across our footprint. We feel very solid about our progress to date, and we are continuing on the schedule that we outlined earlier, whereby the end of the year, we should have met those two goals. Robert, you also asked a follow-up question about ownership. As we've contemplated these projects, we have developed an approach to the capital stack, which would be inclusive of an opportunity for TC Energy to be an owner for those assets that make sense for our footprint and our own ownership goals and desires. It's also inclusive of opportunity for third-party, investment as well to ensure that our long-term partners, have the opportunity to participate in these, renewable assets across our footprint, not the least of which is our indigenous partners who we regularly include in opportunities to co-invest, as we mentioned, with our CGL project. Thank you. Robert, just to add a little bit of color to help you out, you know, we're in the middle of commercial negotiations on a number of projects, so you can expect that we'll be able to offer you a little bit more color and detail around timing once we mostly get through that. You know, our intention with some projects is to acquire them in late-stage development. For the most part, I think we're looking at capital deployment at COD. Think of our equity interest being somewhere, you know, in aggregate between 25% and 50% of the equity in the overall portfolio. It may be 100% in some cases and none in others, and some mix in between. You know, not likely additions to our capital program until we get late into 2022. As Corey said, it's gonna take us most of the balance of the year to contract that up. For commercial reasons, you know, we'll hold on until we get near the end of those negotiations before we provide you with that detail. Thank you. Just a clarification or follow-up. Taking a look at the capital project list, you know, in the U.S. natural gas pipelines, the other capital bucket has increased, but it's also increased in time. Is that just kind of extending the window of debottlenecking the system? Have you added new projects there, or is that cost increase? No. That's related to an acquisition that we have. We call it our KO Transmission Project. We're gonna spend about $80 million to acquire a line from a third party that's gonna give us direct access into the Northern Kentucky and Cincinnati, Ohio, markets with the opportunity to do additional bolt-on expansions in the future. Excellent. Thank you. Thanks, Robert. The next question comes from Jeremy Tonet with JP Morgan. Please go ahead. Hi, good afternoon. Hi, Jeremy. Hi. I just want to touch on nuclear a little bit here as it relates to Bruce and the potential for hydrogen. We are seeing a little bit about potential there. Just wondering, you know, if you could dive in a little bit more in your comments. I guess, how should we think about, you know, the timeframe of this evaluation, and what are kind of some of the factors in play for a decision on whether something will be done? Just wondering any color that you could share at this point. Hi, Jeremy Tonet. It's Corey Hessen. With regards to Bruce Power and their efforts, as you know, Bruce Power has a strong position in the province. As part of their overall growth program to finish the refurbishments of all of the units, along with the Project 2030 that's growing the overall capacity of the plant, that creates an opportunity for the province that as new technologies emerge and there is the need for the creation of those new technologies, Bruce Power is systematically investigating how they can apply this additional capacity that's being driven by virtue of Project 2030 and the MCR to deliver new fuel sources to the province. The way I think about it is they're systematically looking at a broad range of opportunities, including SMRs, hydrogen, and other programs that will allow them, through their nuclear industry institute, to evaluate sort of in the 2030 time frame when most of these emerging technologies hope to be in a position to deliver to the province. Got it. Anything Bruce Power hydrogen is pretty way dated at this point, to sum it up? Yes, that's correct. I think so. I think they've got a full plate with the MCR program and with the uprate program at the plant. As they look at these opportunities, it's a matter of them being experts and being able to apply rigor to the process and deliver information to the entire province. Got it. That's helpful. Maybe just one more on nuclear, if I could. We've noticed a lot of really interesting advances on small modular reactors and technologies there, and it seems like over the next, you know, middle of this decade to the back half of this decade, some of these things could be coming into into focus a bit more, and maybe applied in different ways than done historically. Just wondering, I think TRP maybe in the past have talked about the role nuclear could have in the oil sands or feeding other parts of the business power-wise. Just wondering if you see any opportunity for TC Energy at some point down the road to become involved with SMRs. Jeremy, it's François. We really do. When you think about SMRs in the context of oil sands and their needs for steam and power, it really is an excellent use case for small modular reactors. Through our affiliation with Bruce Power, we've got the technical expertise to develop and evaluate those technologies. But I think equally as importantly, we have the commercial relationships with the oil sands producers. We have all of the surrounding and supporting infrastructure at site to provide their steam and power needs. We understand how to dispatch energy into the energy-only market, which, you know, which Alberta is. It's, you know, similar to Texas, if you're familiar with the market structure there. Very much something that we're interested in pursuing. From a timeframe standpoint, however, I think it might be a little bit later than what you're alluding to, at least in our view. You know, just getting an operating license in and of itself is a very lengthy and costly process. It can take up to 5 years to do that. Technology still needs to be proven up. In our view, the oil sands producers, you know, would need to sort of buy in on one common technology so that they have the requisite expertise to operate and maintain a fleet for those purposes. All of that is gonna take time. We view this more as an opportunity for the 2030s than the second half of the 2020s. Got it. Well, we'll see. Hopefully, it's a little bit earlier, but thank you for all your thoughts there. Thank you, Jeremy. The next question comes from Robert Catellier with CIBC Capital Markets. Please go ahead. Hi. Thank you. I just wanna go back to some of your earlier comments on energy security and if you could speak to any changes in your capital allocation strategy. You mentioned LNG, but are there other project types you're pursuing? Has there been a meaningful change in what the counterparties might be willing to accept in terms of risk transfer or anything else? Maybe you can address whether there's been an appreciable change in the permitting environment that's required to enable these energy solutions to come to market. Yeah. Thanks, Robert. I'll get started on that, and I'll ask Stan to reflect on some of the experiences we've seen with permitting for LNG recently with the FERC. I guess I would start, Robert, by saying that our strategy is unchanged. We were believers in the requisite balance between energy security and energy transition, you know, for many years. If you look back to our strategy and our parameters we discussed at our Investor Day last year, in many respects, we feel that what's transpired globally has confirmed the validity of our approach. We believe that all forms of energy will be required to meet the world's energy demand, and that requires an all-of-the-above strategy. At the same time as we're comfortable allocating approximately CAD 20 billion of our CAD 25 billion program to natural gas, we're also bullish on pursuing alternate sources of energy, be they renewables, hydrogen, CCUS or otherwise, because we do have to achieve not only reliability and affordability, but also the lowest possible emission profile in order to allow the industry to prosper. From that perspective, really more a validation of our view. Certainly on the LNG front, as Stan reflected, the pull in terms of increasing frequency of conversations and acceleration of conversations around new infrastructure has accelerated. I would say, though, that it's bifurcated in two parts. The first is governments wanting to help Ukraine and Western Europe in the near term, what can be done for the next heating season? Then there's the longer-term conversation about how do we, over the long run, reduce Western Europe's reliance, you know, on Russia for its oil and gas, which as we all know, it takes about five years to sanction and build, you know, energy infrastructure. On the permitting front, I'll turn it over to Stan to reflect on our recent experiences with the FERC. Yeah. Robert, you may be familiar with FERC's recent actions around its policy statement, which we believe are directionally positive, all things equal. We applaud FERC for its participation in the congressional hearings and really for listening to the various comments from industry and for ultimately reversing course and making its policy statement now into a draft document as opposed to a final rule. The implications of that are such that now that it's a draft policy, the pending certificate applications are no longer applicable. You've seen FERC actually come out and issue orders, which is part of the three projects that François mentioned early on. Again, directionally positive with respect to the need for new critically needed energy infrastructure in the United States. It remains to be seen, however, what the final rule is gonna look like. We'll continue to monitor that very closely and work with various stakeholders to make sure that our interests are properly represented. Perhaps I'll ask Greg to provide some commentary on the regulatory environment in Canada. Good. Thanks, François. Yes. Similarly, I think we're seeing a lot of positive momentum on that front, both with local community stakeholders, regulatory front, from the energy security piece, just reinforcing. Kind of the peak demand we've been seeing inter-province export and otherwise, there's a lot of inbounds, whether it's coming in from Europe, East Coast, and otherwise looking for ways of getting more gas out of the WCSB. Really, when you look at the peak levels that we're seeing, it is driving that need for capacity and reliability. We are getting a lot of support and trying to figure out ways that we can help make that regulatory process more efficient as we try to add more capacity. Okay. Thank you for that, very fulsome answer. I was a little bit curious on Coastal GasLink, why you felt it was necessary to increase the loan commitment there. Does it point to potentially higher, even higher CapEx than what you were thinking previously? Yeah, Robert, it's Joel here. Very similar to what we said before with that subordinated loan facility. It's just to make sure there's sufficiency of funding for the project. We do have a credit facility in place for CGL for $6.6 billion. In order to make sure that we have all the funds in place, we just had to increase the subordinated loan by $500 million this quarter. Our expectation going forward, though, would be to increase the credit facility, that $6.6 billion that I mentioned, higher. By doing that would lower the subordinated loan by the same amount. Again, we view this facility as being temporary, but we did increase it just to make sure that we have the appropriate funds to fund the project. Okay, great. Thank you. The next question comes from Brian Reynolds with UBS. Please go ahead. Hi, good afternoon, everyone. Maybe to start off, talk about the Marketlink open season. Just kind of curious if you can give a little bit more color around it and different interests that you're seeing so far, and just maybe talk about future demand for capacity from Cushing to Houston and Port Arthur demand markets, given, you know, the domestic and export market, you know, clearly demands more Canadian and U.S. barrels. Thanks. Yeah, sure. Thanks. Glad you asked. With the open season, you know, to start, this is Richard Prior, by the way. This open season, it's an example of our new strategy of finding ways to increase utilization where we have latent capacity on the system. This is through in-quarter or capital light, and in this case, zero capital opportunities. We launched an open season on Marketlink on April 8. It closes in mid-May, and it's gonna enable, you know, Cushing crude to reach the domestic markets in the Port Arthur and Houston areas. Before we launched the open season, we worked extensively with our customers, which gave us a strong understanding of where the market is. I'm quite pleased with the customer response that we've had, and based on the feedback, I'm confident that we'll be successful and we'll see an increase in committed contracts on the MarketLink system. You know, you asked about other demand on MarketLink, and there's a number of things that we're doing with that asset to make sure that we increase volumes and we work to fill up that light capacity I mentioned. You know, we're actively managing our spot tool, and as a result of that, we've seen additional spot tool movements. We've taken a different strategy around our Houston tank terminal position, and we're starting to see more barrels go into the Houston marketplace. We're starting to see an uptick in diversions from Patoka and Cushing flowing all the way to the Gulf Coast. That's a lot based on refinery pull for increased heavies. We're doing things like we're adding the Port Neches link that François mentioned in his opening comments, where we're gonna extend the Keystone system down to Motiva's facility. That's the largest North American refinery. I think the future is very bright for that part of the system. Great. Appreciate the color. Then maybe as a follow-up to the subordinated loan capacity question increase. While I understand there's no update on the potential total cost for Coastal GasLink at this time, could you perhaps just let us know what the project spend has been to date for Coastal GasLink to help us gauge potential future CapEx needs with the project roughly 65% complete at this time? Thanks. Yeah. It's François, Brian. You know, we have contractual agreements with our customer not to disclose what they view as market-sensitive information. You can expect a generally linear relationship between the fact that we're 63% complete and the aggregation of the project financing and the subordinated loans. You know, we'll. Once we reach, hopefully, an amicable solution with our customer, we'll be able to provide additional details. As Bevin mentioned, we expect that to happen here in the near future. Fair enough. Thought I'd ask. Have a great weekend, everyone. Thank you, Brian. Same to you. The next question comes from Michael Lapides with Goldman Sachs. Please go ahead. Hey, guys. Thank you for taking my question. I have one nuanced one for first quarter earnings or first quarter comparable EBITDA. If I look at the Canadian gas pipeline segment and down year-over-year around CAD 20 million, but I assume the bulk of that is just the roll-off of the net earnings neutral impact on the depreciation for the Canadian Mainline. I thought that was around CAD 40 million a quarter or so. If so, that would imply EBITDA year-over-year was flat there despite pretty good volume growth. I just wanna make sure I understand what, you know, kind of why flat, why not up a bit year-over-year at that segment? Yeah. Hi, Michael. It's Greg Grant here from Canadian Natural Gas Pipelines. I think you got that right from the EBITDA front. Certainly that is partially mainline. I think you also have to remember and consider there's tax depreciation that moves quarter to quarter, and we have some offsetting effects to that. I think net income is a much better measure for our business. I think as you would see and as you model the increased capacity and capital that we continue to put in the ground, you will see the net income continue to follow that and correlate quite closely to that. Got it. Okay. How are y'all? I noticed in the financing slide, like, when you showed the two bars, and Joel, you spent a good amount of time walking through that. When I look at the fourth quarter slide, that same slide, so the 2022 to 2024 financing, I don't know if you mentioned use of hybrids in the fourth quarter slide, but I think you did today. Are you guys? Yeah. Do you think you have a need for convertible securities in the next couple of years? Do you think it's a sizable portion of that, kind of that funding bar, or is it just kind of tiny and rounding error relative to your enterprise value? No, Michael, it's something that we always look at. When you look at subordinated capital, it always comprises roughly 15% of our capital structure. As the balance sheet grows, obviously the subordinated capital portion of the capital structure grows with it. As we see, you know, as we look out over the next couple of years, certainly we're seeing additional hybrid capacity as a result of the growth in the balance sheet. Yeah, we didn't include it in fourth quarter, but we thought it was important just to highlight that for investors this quarter that certainly as we move forward here in order to keep our leverage metrics in line and moving down along with you know improving our earnings and cash flow per share that hybrids will make up a you know an important component of it again capped at the 15% of the capital structure. Got it. Okay. Thank you, guys. I'll follow up with Gavin and team offline. Much appreciated. Thanks, Michael. The next question comes from Praneeth Satish with Wells Fargo. Please go ahead. Thanks. Good afternoon. In the Bakken, I know there's been some production outages due to the severe winter weather, but if you adjust for weather, gas production growth has been very strong. I guess what's been the shipper feedback so far on your Bison XPress project? And just hypothetically, if the project doesn't get constructed, do you think there's a possibility at some point in the next few years where you just stop accepting more Bakken gas on Northern Border? Praneeth, this is Stan. As you noted, and I alluded to in our call, last call, we did launch an open season for some Bakken export capacity up to around 430,000 a day. The open season doesn't close for another week or so, and as is typical, we tend to receive all of our bids at the last minute of the last day. Unfortunately, I don't have anything that I could share with you that would not be commercially sensitive at this point in time. With respect to your other question, you know, we're receiving about 2 BCF a day of gas out of the Bakken right now, 70% of the supply that comes into the Northern Border system. There's another 30% of that capacity that is gonna compete for space against the Canadian supplies that come in from the north. There'll be a little gas on gas competition perhaps that goes on. Once that gets filled up, you know, then the pipe is essentially full, and that's just another signal for a pipe expansion down the road. Got it. I guess just staying in the U.S., the Haynesville production has started to pick up in the last few months, and there's a few companies now looking at building egress out of the region. I'm just wondering, is this something that you're evaluating as well? Do you have any opportunities on ANR or CGT to potentially increase capacity down to the Gulf Coast? Yeah. It is something that we're looking at, and I'll go back to my remarks from the beginning with respect to Haynesville. Production out of the basin is not that different from the Permian. The growth opportunities are not that different from the Permian. The distance from the basin to the LNG export terminals in Louisiana is not that different from the Permian. There's a lot of overlap there. Whether it's a greenfield or brownfield expansion, we do have the opportunity to interconnect with our existing lines on the Columbia and the Columbia Gulf on the Columbia and ANR systems, I should say. Yes, that's something that is very much at the top of our minds. Got it. Thank you. The next question comes from Matthew Weekes with iA Capital Markets. Please go ahead. Good afternoon. Thanks for taking my question. Just looking at the quarter here, and it looks like there were some impacts to EBITDA a little bit from sort of commodity-related factors, talking about natural gas storage, liquids marketing, and then some talk of some timing on earnings in the liquids related to risk management activities. I'm just wondering, keeping in mind that a lot of these factors are out of your control and subject to the volatile environment we're in, if you have any visibility on how these factors will sort of play going forward on results as the year progresses, and if you have any visibility for maybe some of these factors normalizing or moderating going forward. Thanks, Matthew. It's François. I'll get started, and then I'll ask Richard or Bevin to provide some proof points. You know, we undertake commercial marketing and trading activities, and sometimes there's a bit of a mismatch between the financial and the physical. If we're caught in between the two at the end of a quarter, you might see the cost impact of one and not see the revenue impact of the other until the next month, which is in the next quarter. Maybe Richard, you can provide a bit of an example of that, and then that, you know, provide some color as to what you see happening for the rest of the year from our business. Yeah. Absolutely. You know, you look at the first quarter, and you know, between the pandemic and the war in Ukraine, we've seen tremendous volatility in the crude markets, you know, right the way through. There's really a couple of things going on that impact our margin business. Not necessarily specific to commodity prices on the one, and then the other, as François mentioned, has to do with our risk mitigation. First of all, the transportation differentials remained quite tight. Despite the fact that we saw a steep increase in light crude prices, the differentials between the different trading hubs, which is what sets the margins for our marketing entity, and that would really be between Hardisty and the Gulf Coast and Cushing on the Gulf Coast, they stayed very tight. That sets a tight margin. In addition to that, we saw steep backwardation throughout the first quarter, and that further exacerbates the tight differentials as with the Keystone system, due to the transit times, you receive a barrel onto the system, and then you deliver a barrel off of the system in the following month. We saw you know calendar spreads as wide as $4 at points in the first quarter. That put you know further compression on margins. We've got our risk mitigation strategy around the commodities. We deploy disciplined financial risk mitigation measures to minimize our commodity exposure. On a short-term basis, we have this timing aspect between when we purchase the crude, place the financial hedge, and then sell the crude in the following month. What we're expecting is that the timing will catch up likely over the next quarter. I think what we saw in Q1 is an anomaly, and we would expect our future business to be more consistent throughout the rest of the year, as we've seen in previous quarters from the marketing entity. One thing I just wanna mention as well, though, is 'cause I do think it's important to note, is that the majority of our liquids business is committed long-term contracts, and the demand for our pipeline throughput continued to be consistent and predictable. We've been flowing in excess of 600,000 barrels a day now for the last two quarters, and I’m not seeing anything that's suggesting that that's going to decrease. We're seeing that across the whole system, our Keystone system and our Gulf Coast system. I already discussed some other things that we're doing to try to increase that on the southern part of our system, where we have some latent capacity. Matthew, it's Joel here. What Richard just pointed out is why, you know, we are confident in reaffirming our outlook for the year, where our EPS to be generally in line with last year and our EBITDA to be modestly higher than 2021. Okay. Thank you. I really appreciate the detail and the commentary on that. I'll turn the call back. Thanks. Thanks, Matthew. The next question comes from Andrew Kuske with Credit Suisse. Please go ahead. Thanks. Good afternoon. I guess the question is gonna be for Stan and for Greg. We've spent a lot of time over the years talking about producer health. Obviously, it's fairly robust right now. Do you see opportunities across the portfolio for an acceleration of volumes in certain submarkets or certain basins that you serve? And maybe that comes from outright, you know, drilling activity accelerating or just some of the DUCs, no pun intended, but they're all lined up at this point in time. What does that mean from an upside to returns? Yeah, great question. If you read Gas Daily today, this is Stan, by the way, you'll see that Antero was talking about the value of their transportation capacity and how critical it is to their success in getting additional gas down to the Gulf Coast. That's just a reinforcement of exactly what we do. Producers are still living within their means and staying within their balance sheets, at least for the moment. They're not chasing the higher prices, which I think is the right thing to do. But going forward, there are clear signals, and I think that you're likely to see drilling activity increase. You know, we're seeing that in the Bakken. We're seeing it in the Permian. We're seeing it a little bit in the Appalachians too. As that happens, there's gonna be a need for more egress capacity, and that's what we do. When I think about things like the Appalachian Basin, for example, we have the ability to further compress up our Buckeye XPress project, which we put in service about a year ago. That could bring 200,000 a day of capacity online into TECO Pool in very short order. Absolutely, we are bullish. We are glad to see that the producers' health is back to where it should be, and we're glad to see that they recognize the value that our transportation capacity brings. Maybe just from Greg too. Yeah, sorry. I'll add to that, Andrew. Thank you. It you know, I think what we're seeing is just going back to the unparalleled footprint that we do have here, you know, on the WCSB and the competitiveness of the gas. We are seeing a lot of strength in the basin. We are operating at, you know, near capacity, and we are seeing the queue grow from the regulated side of our business. We fully expect that to continue to help support some of the guidance that we provided back in November on Investor Day of that CAD 1 billion-CAD 2 billion a year going forward as we see supply migration, we see absolute growth on the expansion side. From a pure producer perspective, I agree with Stan. You know, you still are seeing very disciplined capital being put in. That said, we do expect upwards of a 20% increase in capital here, from the producer community in the basin. Should continue to maintain those flows and continue to see growth over the next couple of years, especially as we see CGL and LNGC coming on. That's helpful. Then I guess maybe an extension of this or building upon the question is, where do you have some operational leverage where increased volumes effectively are gonna drop down to bottom line, and then that enhances EBITDA earnings? Then the extension of that, and Stan, you mentioned a bit of this, is just the looping and compression and then the capital opportunities. Just how do you think about that going forward in your business? Andrew, it's François. I'll get started, and then I'll ask Richard and Stan to provide some proof points. One of the things we talked about on our Investor Day was improving the return on invested capital on our existing assets. Firstly, through you know, cost efficiency and some small you know, revenue enhancement initiatives around machine learning. We talked about Villa de Reyes, and we talked about Marketlink as two examples of where the capital is largely in the ground in the case of Villa de Reyes, and it's entirely in the ground in the case of Marketlink. Our job now is to commercially increase the throughput and fill those pipes because that's infinite return on incremental cash flow because the cash flow is already in the ground. You know, those are two great examples of where we've got some good operating leverage. I know, maybe I'll ask you, Richard, again to comment on Marketlink and our strategies, and then maybe, Stan, you can provide an update on Villa de Reyes. Just, you know, regarding the Gulf Coast part of our system. We look at the Gulf Coast pipeline, and it's used for either flowing along the whole barrel all the way from Alberta down to our delivery points in the Gulf Coast, or it originates barrels in Cushing through our MarketLink lease that delivers domestic barrels into the Gulf Coast. We're. You know, that is a significant and key part of our liquids strategy is to focus on, you know, low capital or capital-light options that we can create more pull through that southern part of the system. You know, things that we're doing typically looking at when we are looking at right now to increase that pull is, you know, a lot of it is increasing the receipt points so that we can find extra barrels to bring into the system and also looking for additional delivery points so that we can get our crude to more markets. Something that I didn't mention that we're earlier that we're anticipating, you know, seeing some additional pull, for example, is we've recently entered into a joint tariff with another pipeline, and so we're gonna be able to pull a barrel all the way from Cushing through into the Louisiana marketplace as well. That's currently a market that isn't necessarily touched by our system, but I think we could see, you know, adding incremental volume. The other place where I should leave it at and mention as well, though, is just our long-haul Keystone system. We did put an open season in the marketplace back in 2019, where we put 50,000 barrels of capacity. We still have not delivered on that capacity. at some point in the future, I am confident just through the work that we're doing with our engineering team, our field operations, and our commercial teams, that we will be able to realize on that capacity at some point in the future. Andrew, this is Stan. Just to follow up on Villa de Reyes real quick, that is now mechanically complete for both the north and lateral segments. I know we're glad to have that behind us, and we expect to have the southern portion complete here later this year. With respect to your general question around optimization, I guess a couple of things I would point out is, given some of the headwinds we have with respect to the ability to build new critically needed energy infrastructure, the value of pipe in the ground is increasing exponentially. One of the things we're gonna do is we're gonna test the elasticity of the market, and we're likely to see less discounts offered on our existing capacity. Less discounts, all things equal, is gonna lead to higher revenues. The other thing I would leave you with is innovation. We're doing some really neat things in the innovation space around machine learning. We have a tool that we refer to as our autonomous pipeline, which helps us use artificial intelligence, machine learning and the like to make sure that we're maximizing the value out of the pipe on any given day. So far, that's beginning to pay dividends for us as well. That's great. Thank you very much. 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 François Poirier. Please go ahead, Mr. Poirier. Thanks very much. Appreciate everyone's time and attention, mid to late afternoon on a Friday. Thank you very much for your attendance. Look, our key messages are we continue to be opportunity-rich. Beyond our $25 billion existing program, when you look at LNG export growth, when you look at our RFI program to electrify our own power consumption, you look at pumped hydro storage, you look at hydrogen, you look at CCUS, you look at recoverable maintenance capital, we're very confident in our ability to deploy $5 billion a year in a responsible manner, consistent with our historical risk and return preferences. One of the key things we're learning here is that incumbency is extremely valuable, not only with respect to our existing gas and liquids businesses, but as we contemplate hydrogen production and CO2 transport and sequestration, having assets in the ground, regulatory relationships, rights of way, et cetera, is all becoming increasingly valuable. The third thing I wanna mention is capital discipline is very important. We are going to deleverage at the same time as we grow our business. We talked about a long-term debt-to-EBITDA multiple target of 4.75. Our expectation continues to be that we will achieve that within our five-year planning horizon. We're bullish on the opportunity set, and we're also bullish on our ability to maintain strong balance sheets so that we can be opportunistic for opportunities in the future. Thanks very much for your time today, everyone. This concludes today's conference call. You may disconnect your lines. Thank you for participating and have a pleasant day.