Thank you for your patience. This is the conference operator. Welcome to the TC Energy 2020 Second Quarter Results Conference Call. Please note that all participants are in listen-only mode and the conference is being recorded. There will be a chance to ask questions after the presentation. I would now like to hand the call over to David Moneta, Vice President of Investor Relations. Please proceed.

Thanks very much, and good morning, everyone. I'd like to welcome you to TC Energy's 2020 second quarter conference call. Joining me today are Russ Girling, President and Chief Executive Officer; Don Marchand, Executive Vice President, Strategy and Corporate Development and Chief Financial Officer; Francois Poirier, Chief Operating Officer and President, Power and Storage and Mexico; Tracy Robinson, President, Canadian Natural Gas Pipelines; Stan Chapman, President, U.S. Natural Gas Pipelines; Paul Miller, President, Liquids Pipelines; Bevin Wirzba, Senior Vice President, Liquids Pipelines; and Glenn Menuz, Vice President and Controller. Russ and Don will begin today with some opening comments on our financial results and certain other company developments. A copy of the slide presentation that will accompany their remarks is available on our website. It can be found in the investors section under the heading events and presentations. Following their prepared remarks, we will take questions from the investment community. If you are a member of the media, please contact Jaimie Harding following this call and she'll be happy to address your questions. To provide everyone from the investment community with an equal opportunity to participate, we ask that you limit yourself to two questions. If you have additional questions, please re-enter the queue. We also ask that you focus your questions on our industry, our corporate strategy, recent developments, and key elements of our financial performance. If you have detailed questions relating to some of our smaller operations or detailed financial models, Hunter and I would be pleased to discuss them with you following the call. Before Russ begins, I'd like to remind you that our remarks today will include forward-looking statements that are subject to important risks and uncertainties. For more information on these risks and uncertainties, please see the reports filed by TC Energy with Canadian securities regulators and with the U.S. Securities and Exchange Commission. Finally, during this presentation, we'll refer to measures such as comparable earnings, comparable earnings per share, comparable earnings before interest, taxes, depreciation and amortization or comparable EBITDA, and comparable funds generated from operations. These and certain other comparable measures are considered to be non-GAAP measures. As a result, they may not be comparable to similar measures presented by other entities. They are used to provide you with additional information on TC Energy's operating performance, liquidity, and its ability to generate funds to finance its operations. With that, I'll turn the call over to Russ.

Thank you, David, and good morning, everyone. And thank you all for joining us today. Clearly, we live in unprecedented times with COVID-19 having had a significant impact on people around the world. When the World Health Organization declared a global pandemic in early March, our business continuity plans were put in place across our whole organization, allowing us to continue to effectively operate our assets and execute on all of our capital programs. All of the services we provide were deemed essential or critical in Canada, the United States, and Mexico, given the important role our infrastructure plays in delivering energy to people across this continent. This essential designation included both our daily operations and our construction projects. We take that responsibility extremely seriously. And I'm proud to say that we continue to deliver the energy that millions of people rely on every day and continue to advance all of our construction projects that are vital to powering industries and institutions for many decades yet to come. As we've always done over the past few months, we've continued to conduct our business in a safe and reliable manner while maintaining our workforce, employing thousands of construction workers, fulfilling our obligations to suppliers, and supporting the communities in which we are working. This would not have been possible without the dedication of all of our employees. And I want to acknowledge and thank them and their families for their ongoing efforts to ensure the energy that is vital to the daily lives of so many continues to be delivered seamlessly across North America. I can tell you that your efforts continue to make a big difference. Turning now to our second-quarter financial results and other recent developments across our three core businesses. Despite the challenges brought by COVID-19, our operations have largely been unimpacted. With a few exceptions, flows and utilization levels remain in line with historical seasonal norms, underscoring the critical nature of our energy infrastructure assets. With approximately 95% of the comparable EBITDA in our company coming from regulated or long-term contracted assets, we continue to be largely insulated from the short-term volatility associated with volume throughput and commodity prices. As a result, as highlighted in our second-quarter report, our $100 billion portfolio of high-quality long-life energy infrastructure assets continue to produce solid results. We continue to realize the growth expected from our industry-leading capital expansion program. Today, we are advancing $37 billion in secured capital projects. Additionally, we continue to advance $11 billion of projects under development, including the refurbishment of another five reactors of Bruce Power as part of their long-term life extension program. Over the last six months, we took significant steps to fund our 2020 capital expenditure program and maintain our strong financial position despite the challenging capital market conditions that we're experiencing. More specifically, we enhanced our liquidity by more than $11 billion through the issuance of long-term debt in both Canada and the United States at very attractive rates. This included the establishment of an incremental committed credit facility and various portfolio management activities, including the sale of three Ontario natural gas-fired power plants and a 65% interest in the Coastal GasLink project. When combined with our predictable and growing cash flow from operations, we believe that we're well-positioned to fund our capital program and meet all of our other obligations. Looking forward, we expect our solid operating and financial performance to continue, and as a result, our outlook for the full year 2020 is essentially unchanged, with comparable earnings per share still anticipated to be similar to the record results we produced in 2019. We're extremely proud of our financial performance and the significant returns that we've generated for our shareholders. We know that our ongoing success depends on our ability to balance profitability with safety, environmental, and social responsibility. We have a 65-year track record of safe and reliable operations, but we recognize that we can always do better. As a result, we remain focused on continued improvement as well as long-term fundamentals to ensure our business remains sustainable and resilient in an ever-evolving energy landscape. With that overview, I'll expand on some of our recent developments beginning with a brief review of our second-quarter financial results. Don will provide more detail on results and liquidity in just a few moments. Excluding certain specific items, comparable earnings were $863 million, or $0.92 per common share for the three months ended June 30, compared to $924 million, or about $1 per share in 2019. Comparable EBITDA of $2.2 billion and comparable funds generated from operations were about $1.5 billion. For the six months ended June 30, comparable earnings were $2 billion or $2.10 per common share, compared to $1.9 billion or $2.07 per share in the same period in 2019. Comparable EBITDA of $4.7 billion and comparable funds generated from operations at $3.6 billion were similar to the amounts that we reported last year. Each of those amounts reflects the solid performance of our legacy assets as well as contributions from $3 billion of new long-term contracted and regulated assets placed into service in the first half of 2020. This was partially offset by lower contributions from our liquids marketing business due to lower margins, as well as lower equity income from Bruce Power due to the Unit 6 NCR program we commenced at the beginning of the year and the sale of certain assets that will help fund our secure capital program for many years to come. Next, I'll make a few comments on our three core businesses. First, in our natural gas pipelines business, customer demand for our services remains extremely strong despite the COVID-19 impacts on the broader North American economy. Evidence of this can be seen in the volumes transported across our systems with the NGTL System field receipts averaging about 12.3 billion cubic feet a day, a Canadian Mainline Western receipts averaging 3.1 billion cubic feet a day, our broader U.S. pipeline network moving about 25 billion cubic feet a day, and our Mexican pipelines moving approximately 1.6 billion cubic feet a day for the first six months of this year. Each of those amounts are similar to or greater than the volumes we moved over the same period last year. At the same time, we continue to advance approximately $22 billion of capital projects associated with our natural gas business. That program includes significant expansions of our NGTL system, capacity additions on our U.S. network, important projects in Mexico, and our Coastal GasLink pipeline project in British Columbia, which will play a very important role in delivering clean Canadian natural gas to Asian markets that will displace coal. During the second quarter, the NGTL System held a capacity optimization open season to assist customers in optimizing their transportation service needs and align system expansions with customer growth requirements. The open season confirmed that all of our proposed system expansion projects will continue to be required to meet aggregate system demand, although the service base for some of those facilities has changed. As a result, certain amounts of the capital spending plan for 2020 and 2021 will be made in 2022 to 2024. The net impact of these deferrals, together with some expected increase in costs on the 2021 expansion program, will see us invest a total of about $9.9 billion, up from $9.4 billion on the '21 program. These changes have been reflected in this capital projects table in our quarterly report. Turning to our U.S. natural gas pipeline business, our expansion plans now include an incremental investment of approximately $400 million U.S. to replace, upgrade, and modernize certain facilities on a highly utilized section of the ANR pipeline system. The program, known as the Elwood Power and our horsepower replacement project, will reduce emissions along the system and is another good example of an in-corridor expansion to meet growing demands, utilizing our existing facilities and existing right-of-way. Also in the U.S. pipelines business, in the coming days our Columbia gas transmission system intends to file a Section 4 Rate Case with FERC, requesting an increase in its maximum classification rates effective February 1, 2021. It's Columbia's first rate case filing in over 20 years and will seek to recover currently incurred operating costs as well as the fair return on and above our historical and future capital investments in this extensive system that provides our customers with reliable access to low-cost natural gas. At the same time, we will continue to pursue a collaborative process to find a mutually beneficial outcome with the Columbia gas transmission customers through settlement negotiations. Finally, in the natural gas pipelines, construction activities continue on the $2.1 billion cubic feet Coastal GasLink project that will connect the abundant Western Canadian sedimentary and natural gas reserves to the LNG Canada plant to export from British Columbia. Field activity continues to increase along the route following the spring thaw, as we wrap up construction. Our focus will remain on the health and safety of our employees, our contractors, and the communities that restrict their entry to our COVID-19 protocols. Ongoing work includes the construction of roads, bridges, work accommodations, and grading. Pipe delivery also continues, with more than 50% of the required pipe supplied to the site, and the mainline mechanical construction activities planned for the balance of the summer. In May, as you know, we completed the sale of a 65% interest in the Coastal GasLink project and entered into a secured long-term project financing credit facility to fund the majority of the construction costs. This resulted in combined net proceeds of approximately $2.1 billion. Looking forward, we'll continue to work with the 21 nations that have executed agreements with the Coastal GasLink project to provide them with an opportunity to invest in the project with an option to acquire 10% interest on similar terms and conditions. Turning now to our liquids business, which also generated solid results during the first half of 2020, despite the extraordinary volatility in global crude oil markets. The volatility has had an impact on our market length and liquids marketing businesses. Keystone continues to produce solid results as it serves important markets in the U.S. Midwest and Gulf Coast, and is underpinned by long-term take-or-pay contracts with very strong counterparties. We are very pleased with yesterday's decision by President Trump's signing of a new presidential permit for the base Keystone system. The new permit will allow us to respond to market demand and fully utilize the Keystone pipeline system to safely deliver additional crude from Canada to refining centers in the U.S. Midwest and the Gulf Coast. This new presidential permit will allow us to realize the benefits from the 50,000 barrels a day open season conducted in June 2019, and we anticipate starting to increase the flows in 2021. The additional crude oil that will be delivered by the Keystone pipeline will increase the secure and reliable source of Canadian oil to meet growing demand from refineries and markets in the United States. Also in the liquids business, we continue to advance construction on Keystone XL during the second quarter while managing various legal and regulatory matters. In Canada, construction activities at our pump stations and along more than a hundred kilometers of the mainline right-of-way have continued to advance. In the U.S., we are making progress on a revised 2020 construction plan, which is focused in areas where all of our permits and approvals are in place and includes facilities and pre-construction activities. At the same time, we continue to seek authorizations from the U.S. Army Corps of Engineers for the necessary permits and approvals to reconvene U.S. mainline pipeline construction in 2021. Keystone XL continues to be a very important project for both Canada and the United States. It will create thousands of high-paying union jobs and advance energy security in both nations in an environmentally sustainable and responsible way. The project will require an additional investment of approximately $8 billion and it is underpinned by new 20-year take-or-pay contracts that are expected to generate approximately $1.3 billion U.S. of incremental EBITDA on an annual basis once the pipeline is placed in service in 2023. That’s a project we have partnered with the government of Alberta, who will invest approximately $1.1 billion U.S. equity into the project and fully guarantee a $4.2 billion U.S. project-level credit facility. Once the project is completed and placed into service, we expect to acquire the government of Alberta's equity investment and refinance the credit facility. Moving forward, we will continue to carefully manage various legal and regulatory matters as we construct this pipeline, which will have the capacity to move approximately 830,000 barrels a day of responsibly produced energy from Canadian oil sands to the continent's largest refining market, which is in the U.S. Gulf Coast. Turning now to our power and storage business, where Bruce Power continues to produce solid results through the first six months of this year. Also, after years of preparation in January, Bruce Power commenced the work on the Unit 6 major component replacements, or MCR project as we call it, when they took it offline in January. We expect to invest approximately $2.4 billion in that program, as well as ongoing asset management programs through 2023, when the Unit 6 refurbishment is targeted for completion and to come back online. Unfortunately, because of COVID-19 in late March, Bruce Power declared a force majeure under its contract with the Independent Electric System Operator. The force majeure covered the Unit 6 MCR as well as certain asset management work. With that said, I'm pleased to report that in early May, work on the Unit 6 MCR resumed with additional preventative measures in place for worker safety related to COVID-19. Progress is being made on critical path activities as Bruce works to isolate Unit 6 from the remaining units in preparation for the removal of fuel channels in late third quarter. The impact of force majeure continues to be evaluated and will ultimately depend on the extent and duration of this global pandemic. Operations and plant outage activities on all other units continued as expected in the second quarter. Finally, we completed the sale of three natural gas-fired power plants in Ontario: the Napanee plant, Halton Hills, and our 50% interest in the Portland’s Energy Centres. Net proceeds from that disposition amounted to approximately $2.8 billion that we will use to fund our industry-leading capital program. So in summary, today we are advancing $37 billion in secured growth projects that are largely expected to enter service between now and 2023. We have invested approximately $11 billion into this program to date, with approximately $5 billion of those projects expected to be completed by the end of 2020. Notably, all of these projects are underpinned by a cost of service regulation or long-term contracts, giving us visibility to the earnings and cash flow they will generate as they enter service. Based on the strength of our financial performance and the promising outlook for the future, earlier this year TC Energy's board of directors increased the quarterly dividends to $0.81 per common share, which is equivalent to $3.24 per share on an annual basis. This represents an 8% increase over the amount declared in 2019 and is the 20th consecutive year that our board has raised the dividend. Over that same timeframe, we have maintained consistently strong coverage ratios with our dividend on average representing a payout of approximately 80% of comparable earnings and 40% of comparable funds generated from operations, leaving us with significantly internally generated cash flow to reinvest in our core businesses. Based on the continued strong performance of our base businesses and the organic growth we expect to realize as we advance our $37 billion secured capital program, we expect to continue to grow our dividend at an average annual rate of 8% to 10% through 2021 and 5% to 7% thereafter. So in summary, I'll leave you with the following key points. Today we are a leading North American energy infrastructure company with a very strong track record of delivering long-term shareholder value. Our assets provide essential service to the functioning of North American society and the economy, and the demand for our services remains strong. We have five significant platforms for growth: Canadian, U.S., Mexican natural gas pipelines, liquids pipelines, and our power and storage business. As we advance our $37 billion secured capital program, we expect to build on our long track record of growing earnings, cash flow, and dividends per share. We also have $11 billion of projects in advanced stages of development and expect numerous other in-corridor organic growth opportunities, like the $400 million Elwood Power and ANR horsepower replacement projects that we announced today, to emanate from our extensive critical asset footprints. Looking forward, we will remain disciplined, continuing to our focus on safety and sustainability, working according to our values and responding quickly to market signals and signposts to ensure we remain industry-leading and resilient as we grow shareholder value. And I'll turn the call over to Don, who will provide you more details on our second-quarter results and financial position. Don, over to you.

Thanks, Russ, and good morning everyone. As outlined in our results issued earlier today, net income attributable to common shares is $1.3 billion or $1.36 per share in the second quarter of 2020, compared to $1.1 billion or $1.21 per share for the same period in 2019. The six months ended June 30, 2020, net income attributable to common shares was $2.4 billion or $2.59 per share, compared to net income of $2.1 billion or $2.30 per share in 2019. Second-quarter results included a $408 million after-tax gain on the sale of a 65% interest in Coastal GasLink, along with an incremental $80 million after-tax loss in the disposition of the Ontario natural gas-fired power plants. Second quarter 2019 also included certain specific items as outlined on the slide and discussed further in our second-quarter 2020 report to shareholders. These specific items, as well as unrealized gains and losses from changes in risk management activities, are excluded from comparable earnings. Comparable earnings for the second quarter were $863 million or $0.92 per common share, compared to $924 million or $1 per common share in 2019. For the six months ended June 30, 2020, comparable earnings were $2 billion or $2.10 per share, compared to $1.9 billion or $2.07 per share in 2019. Turning to our business segment results on Slide 15. In the second quarter, comparable EBITDA from our five operating segments was $2.2 billion, a $125 million decrease compared to 2019. Canadian natural gas pipelines comparable EBITDA of $621 million was $93 million higher than the second quarter of 2019 primarily on account of increased rate-based earnings as well as flow-through depreciation and financial charges on the NGTL System from additional facilities placed in service. NGTL System net income increased $21 million, compared to the same period in 2019, as a result of a higher average investment base from continued system expansions and reflection of ROE of 10.1% on 40% deemed common equity, while net income for the Canadian mainline decreased by $3 million, largely due to lower incentive earnings. U.S. Natural gas pipelines' comparable EBITDA of $595 million U.S. or $824 million Canadian in the second quarter fell by $46 million U.S. or $33 million Canadian compared to 2019, mainly due to the sale of certain Columbia midstream assets in August 2019, as well as increased operating costs on Columbia Gas. Mexico natural gas pipelines' comparable EBITDA of $130 million U.S. or $181 million Canadian grew by $23 million U.S. or $40 million Canadian versus the second quarter of 2019, primarily due to a sort of Texas equity income resulting from the commencement of transportation services in September 2019 and lower interest expense attributable to the weakening of the Mexican peso. Liquids pipelines' comparable EBITDA declined by $150 million to $432 million in the second quarter, driven by lower uncontracted volumes on Keystone, decreased margins from liquids marketing activities, and the sale of an 85% equity interest in Northern Korea in July 2019. Power and Storage comparable EBITDA in the second quarter fell by $84 million year-over-year, primarily due to the planned removal from service of Bruce Power Unit 6 in January for its MCR program, along with lower Canadian power earnings, largely as a result of the sales of our Ontario natural gas-fired power plants in April 2020 and Coolidge in May 2019, as well as an outage at our MacKay River cogeneration facility in 2020. For all our businesses with U.S. dollar-denominated income, including U.S. natural gas pipelines, Mexico natural gas pipelines, and parts of liquids pipelines, EBITDA was translated into Canadian dollars using an exchange rate of $1.39 in the second quarter of 2020 compared to $1.34 for the same period in 2019. As a reminder, our U.S. dollar-denominated revenue streams are in part naturally hedged by interest in U.S. dollar-denominated debt. We then actively manage the residual exposure on a rolling two-year forward basis, with realized gains and losses on this program reflected in comparable interest income and other. Now turning to the other income statement items on Slide 16. Depreciation and amortization of $635 million increased by $14 million versus the second quarter of 2019, largely due to new projects in service and Canadian natural gas pipelines, which are fully recoverable and tools on a flow-through basis. Interest expense of $561 million in the quarter was $27 million lower year-over-year, primarily due to higher capitalized interest related to Keystone XL and Coastal GasLink up to its date of partial sale in May, subsequent to which CGL is now accounted for under the equity method versus previous full consolidation. The increase at Keystone XL is a result of additional capital expenditures along with the inclusion of previously impaired capital costs and the basis for calculating capitalized interest, following our decision to proceed with construction of the project. This is partially offset by new long-term debt issuances net of maturities. AFUDC decreased by $18 million compared to the same period in 2019, largely due to the NGTL System expansion projects placed in service as well as the suspension of recording AFUDC on Tula effective January 2020. Profitable interest income and other was $7 million in the second quarter and consistent with 2019. Income tax expense included in comparable earnings was $125 million in the second quarter of 2020 compared to $199 million for the same period last year. The $74 million decrease was mainly due to lower pretax earnings and a lower Alberta income tax rate. Excluding Canadian rate regulated pipelines where income taxes are a flow-through item and are therefore quite variable, along with equity AFUDC income in the U.S. and Mexico natural gas pipelines, we expect our 2020 full-year effective tax rate on comparable income to be in the mid to high teens. Comparable net income attributable to non-controlling interest of $63 million in the quarter increased by $6 million relative to the same period last year, primarily due to higher earnings at the TC pipelines LP. And finally preferred share dividends of $40 million were in the second quarter of 2019. Now turning to Slide 17. During the second quarter, comparable funds generated from operations totaled $1.5 billion, and we invested approximately $2.2 billion in our capital program, which as noted, reflects equity accounting for our remaining 35% investment in Coastal GasLink post-closing this partial equity sale. The capital market conditions in 2020 have seen periods of extreme stress and volatility. During the second quarter, we took significant actions that meaningfully enhanced our liquidity and financial position. In April, we issued $2 billion in medium-term notes and U.S. $1.25 billion of senior unsecured notes in the Canadian and U.S. capital markets respectively on compelling terms. Additionally, we arranged U.S. $2 billion of incremental committed credit facilities and closed the sale of Ontario natural gas-fired power plants for net proceeds of approximately $2.8 billion. In May, we completed the sale of a 65% equity interest in Coastal GasLink, as well as the initial draw on a newly established secured long-term project credit facility, resulting in combined proceeds of approximately $2.1 billion. Finalizing these arrangements on Coastal GasLink, along with secured government of Alberta support for Keystone XL in the form of a U.S. $1.1 billion equity contribution and U.S. $4.2 billion loan guarantee, these are the substantial portion of the funding required to advance these two large initiatives is now in place. Now turning to Slide 18. This graphic illustrates our forecast and sources and uses of funds in 2020. The left column details total funding requirements, approximately $17.5 billion comprised of long-term debt, maturities and redemptions $3.9 billion, dividends and non-controlling interest distributions for approximately $3.3 billion, and capital expenditures of approximately $10.3 billion reflecting 100% of Coastal GasLink costs up to the date of its partial sale and only equity contributions to the project thereafter. Funding sources include forecast internally generated cash flows of approximately $7 billion. Proceeds from the disposition of our Ontario natural gas-fired power plants, sale of a 65% interest in Coastal GasLink and associated project-level financing at CGO, which together generated approximately $4.9 billion. The government of Alberta's equity investment in Keystone XL of U.S. $1.1 billion and $4.1 billion comprised of long-term debt that was issued in April along with movements in balances of cash held in commercial paper outstanding. Taken together we are effectively fully funded for 2020, and along with more than $13 billion of committed credit facilities in place, we're well-positioned to navigate any prolonged period of disruption should that occur. Now turning to Slide 19. In closing, our solid financial and operational results during what has been a rather momentous first half of 2020 highlight our longstanding diversified low-risk business strategy. The criticality of our essential energy infrastructure, as well as the contribution of new high-quality assets from our ongoing capital programs. Our overall financial position remains robust. Today we are advancing a $37 billion suite of secured projects through resilience, internally generated cash flow and an array of attractive funding options. Our portfolio of critical energy infrastructure projects is poised to generate high-quality long-life earnings and cash flow for our shareholders underpinned by strong fundamentals, solid counterparties, and premium service offerings, while offering numerous distinct platforms for future attractive and executable in-corridor organic investments. That is expected to support annual dividend growth of 8% to 10% in 2021 and 5% to 7% thereafter. Finally, we will continue to maintain our historic financial strength and flexibility at all points in the economic cycle. That is the end of my prepared remarks and I'll turn the call back over to David for the Q&A.

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

Thank you. We will now start the question and answer session. Our first question comes from Jeremy Tonet of JPMorgan. Please proceed.

Just want to start off with KXL and wanted to see, I guess to hit the 2023 in service as you envision it now. How do you see the kind of legal hurdles or legal challenges going at this point? Just trying to get a feeling for how much contingency is built in there? And what milestones we should be looking for to try to get a better feeling for how to progress? And I guess what types of outcomes there would have you guys kind of step away from the project on the legal challenge side.

Thanks, Jeremy. This is Bevin. With respect to the legal challenges, there are two lawsuits, the first of which is challenging the presidential permits and the balance, challenging our ability to advance construction in certain areas that have wetlands. Our schedule and plans can accommodate we're still targeting our 2023 in-service date at this point. We anticipate resolving these issues through the balance of this year and into next.

And just want to, I guess pivot if I could towards what type of appetite you guys might have for what might be thought of as kind of like greener investments, if you will. The pumped hydro storage, I'm just wondering if you might be able to update with your appetite for projects like that. And then, I guess also down the line, could hydrogen logistics fit your plans at all or any thoughts given that kind of later date at this point.

Thanks, Jeremy it's Francois. With respect to our appetite for those types of investments and the pump storage project being a great example. As we talked about our strategy for our power and storage business, we expect to be looking to invest and diversify by fuel type into other types of fuels other than our traditional natural gas-fired businesses, investing along the theme of farming resources as renewables increased as a percentage of the fuel mix. There will be a need for more storage across various systems. So, as we've mentioned, we've got the Meaford project in Ontario, that's a thousand megawatts pumped storage project that's been proposed. It's still early days on that one. We're continuing with extensive consultations with the communities. We've made significant design changes to the project to address their feedback, and FID on that project is not expected to take place until the 2023 timeframe. The next step is really to continue conducting environmental assessments once we've gained permission from the Department of National Defense to access the land on a longer-term basis. We also have another pump storage project that's under development that we've invested in, Alberta that's fully permitted, and we're expecting to make an FID on that one hopefully by the end of 2020. So, you'll see us looking to invest in a manner that's consistent with our risk preferences focusing on either investments underpinned by regulation or long-term contracts; that's never going to change for us. As we see opportunities to do that as part of on different points of the electric value chain, we're going to continue to be looking at those. As to hydrogen, it's an interesting concept. We'll continue to monitor these and other technological advancements. We are always looking for ways to optimize our asset base, and from our perspective, we've got a very strong asset base to economically and safely connect growing sources of renewable natural gas, hydrogen, or any other types of products when they do become economic; and as it relates to hydrogen, it can be blended with methane flowing through our existing pipelines and either left commingled or extracted through downstream separation process closer to the end-use source. So, I think the takeaway there is we believe that we're very well situated to take advantage of these opportunities in the coming decades, should the technologies advance.

Good morning. If I can just start with the Columbia rate cases that you given details. Specifically just around, are there some parallels that we can draw to what you did with ANR as well where included or is there a bunch of modernization capital or any capital included as part of the rate case? Are you still ready to recover that kind of as part of the new rates rather than having to wait ultimately as well? Just how far behind are you on rates with respect to earned ROE and other recoveries across?

Hey. Good morning Robert. This is Don. We are planning on filing the Columbia rate case tomorrow actually. And while there were some limited rate reviews that were done in conjunction with our prior modernization settlement, as Russ mentioned, this is going to be the first rate case on Columbia in over 20 years. So in addition to recovering our prudent incurred costs return in our historical capital investments, the filing does also propose a third phase to our modernization programs, whereby we're proposing to invest $3 billion over a seven-year period to further ensure the safety, reliability, and integrity of our assets. And to your point, we'd have the ability to recover these costs without further rate cases as we do now with our existing modernization programs. So basically all the modernization capital that we spend at the end of a given year, we would start recovering those costs starting February 1 of the following year. As you know that the rate case establishes rates for our base system customers and is not going to adjust any of the demand charges for our express projects, which were recently placed in service as they will continue to be incrementally priced and subject to fixed negotiated rates. I should point out that the rates are going to take effect on February 1 of 2021 subject to refund. So there's not going to be any impact to 2020 earnings, but the process is that once our filing is made first, we'll set a procedural schedule. That schedule will include a hearing before an administrative law judge likely sometime towards the end of next year. However, as it's very typical with rate cases in the U.S., we intend to work collaboratively with our customers, our regulators, and other stakeholders to settle this case in a satisfactory manner. In that regard, we'll likely kick off settlement discussions sometime in the fourth quarter of this year, and they will most likely continue into maybe the first quarter or second quarter of 2021.

That's helpful, just kind of all billing in over seven years that’s new and incremental with modernization capital that you're already showing in your tables is that correct?

Yes, that's correct. That would be new incremental capital. And again, that's what we're proposing. That we’re going to have to go through the profit that could change over time, but that's the proposal as it fits with our filings.

And what proportion of right now on recourse rates verses contracted rates.

Good question if memory is correct, it’s probably somewhere around 50% or so, but I should thought a little bit, David, and get you an exact number.

And then just finish with a quick funding question, just you mentioned you’re filing the ATM this quarter and that was been pre-closed specifically here for KXL, so is that still the case for, do you have any anticipation to need that for non-KXL purposes.

Hi Robert, it's Don here. We announced along with KXL, we don't have any intention to use it. It's not part of our base funding plan for Keystone XL. It's really an acknowledgment of the volatile times we're in right now and the size of the capital program. It gives us some financial flexibility as we book on KXL as another lever, but the base funding plan there's no issuance on the ATM factored into that. So I would treat it more as belts and suspenders, given the current environment and the magnitude of the capital program that we have in front of us.

Can you just elaborate on how you plan to achieve the higher capacity on Keystone, allowed in that presidential permit. Is this a DRA-only solution? Or will it be pump stations and looping? So really, I'm trying to get a sense of whether working might have to do on the permitting, and if you could also address cost and timing.

Thanks, Robert. It's Bavin. The incremental 50,000 barrels a day that we contracted through the Open Season made last year is available to the system based on using increased DRA as you suggest. No further stations or other capital is required to accommodate that increase.

Okay. And just the bigger picture here as you're looking to the 5% to 7% long-term growth rate. How much of that is contemplating from just the existing footprints? Or the state in another way, how important is it to develop another platform such as the green energy that was discussed earlier or other parts of the value chain or other jurisdictions that are less complicated in permitting compared to North American pipelines?

It's Don here. Beyond KXL and Coastal GasLink, it doesn't factor in any what we would consider mega projects. And even with those projects, we look at our 100,000 kilometers of pipe right away right now. With the opportunity to just organically come off of that. You've seen some today with Elwood, you've heard from Stan on potentially a modernization, three program. These are just examples of that singles and doubles with lower execution risk that can come off of that. I'd also point to additional five units of Bruce that need refurbishment going forward. So where we land in that 5% to 7% range will depend on the mix of projects that come out of our organic programs here, how we execute on them, and the cadence of those. I think we indicated that at Investor Day. So it's not necessarily predicated on large scale, new platforms coming into service here and building off of those. We get about three years visibility on projects. That's what it takes for landing from the commercial landing of these two, getting through the regulatory permitting process and getting shovels in the ground. So we're starting to look at stuff in a decade now. We might get rid of visibility and things like that. Francois alluded to the pump storage project that we're looking at in Ontario. These are the kind of longer tail opportunities that may be not in that KXL or CGL kind of footprint range but could meaningfully contribute to that growth going forward.

I'd like to add to Don's comments. We've consistently stated that we can reinvest about 60% of our annual free cash flow into our core businesses, expecting returns in the range of 7% to 8%. This can lead to growth rates between 5% and 7%. Currently, we are targeting around $5 billion in annual investment. Reviewing our portfolio, as Don mentioned, it is feasible for us to identify $4 billion to $5 billion in in-corridor expansion opportunities. We will continuously seek additional growth platforms. Taking this quarter into account, the Elwood project represents an investment of $500 million Canadian, and we've consistently achieved around $5 billion in capital investment over recent quarters, as Don noted. Our maintenance capital, primarily rate-regulated, amounts to a couple of billion dollars annually, providing returns on capital. Stan highlighted that U.S. modernization efforts will add to this figure. Moreover, if we complete the remaining five unit replacements, it would average an investment of $1 billion a year over the next decade. Considering the planned expansions across the system into Mexico and other regions, it’s plausible to surpass $4 billion to $5 billion annually. Therefore, we will remain in capital rationing mode, ensuring that we invest in the best projects. We've discovered that the most favorable projects are typically smaller ones, between $500 million and $1 billion, which tend to deliver higher returns with less resistance than large-scale greenfield multi-jurisdictional projects. Looking back over the last 20 years, we have reinvested $100 billion into our core businesses, achieving a 7% growth rate in earnings and cash flow per share. I anticipate this trend to persist. Our visibility for reinvesting free cash flow is likely better now than at any point in our past, largely due to the ongoing increase in energy demand. However, building new greenfield projects is challenging, hence the focus on in-corridor expansions. I can cite various examples, such as the GGN expansion, the Uruguay expansion, and the BHB expansion in the U.S. The in-corridor expansions are viable projects, and our clients are looking to us for solutions to meet their rising energy needs.

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

Thank you. I have a question for Bevin as a follow up to Robert Catellier’s question on your Keystone debottlenecking. I'm just wondering beyond the initial 50,000 barrels a day that you have already commercially underpinned. How might we think of the timing and the ramp and the commercial attributes of the remaining 120,000 barrels per day that was, I believe, also on the amended presidential permit?

Yes. Thanks, Linda. So, we've been making excellent progress. As you're aware, last year we had an incident at Annenberg, and we've been working on our pipeline integrity projects to reestablish and expand the capacity on our base systems. The new amended permit allows us to bring on and ramp up that growth of 50,000 barrels a day in the 2021 timeframe once we've established that we can safely deliver our product. So the balance, we still remain 35,000 barrels a day of spot on the system, and any incremental system and any incremental increase thereafter will determine whether or not there's market demand and capability to use that incremental capacity.

And that would require some sort of additional pumping and looping? Or what would be the scope and scale and any sort of investments required to add beyond that?

No, again, that would, the initial, as I mentioned on the 50,000, that is truly through DRA any other incremental look at optimizing the base system and may have some modest capital requirements, but we'll look at those in the future.

That's helpful. Thank you. And a follow-up question with respect to gas rate filing. I guess we'll see it filed tomorrow, but how can we think of if you were to get everything that was applied for, and what would the list be in EBITDA for the company potentially?

Linda, this is Stan, great question, but with all due respect, having not yet filed the case, I just don't want to front run the process. There are still lots of discussions that we have to have with our customers, regulators, and stakeholders, and until we do, we're really just not in a position to provide guidance on any ultimate outcome. So what I would suggest is that David and his team are in the loop, and I'm sure that they'll follow up with you as appropriate.

Thank you. I appreciate that. Are you able to share any attributes beyond the scale as a modernization? That would be a new and significant step changes in kind of the current run rate of how you're running ANR or Columbia gas.

Yes. Again, just out of respect for the process and I feel like any details, because we have not yet shared all this with our customers, so if I can just ask you to maybe hold that question, we can follow up with you and then I will see just in the future.

Thanks. Good morning. Just coming back to the ESG energy transition topic. As we look into future scenarios, just wondering how you're thinking about the financial framework, a discount rate terminal value for these green projects to attract capital. Just broadly how you’re thinking about it.

Yes. I'll start out its Don here. We were looking similar to our adjusting investments. We're not looking to deploy capital below our cost of capital; we're looking for a decent return on it, and factored into that is exactly what you've outlined. What are your cash flows during the project during the contract ranks or within rate base? It depends on the technology and the contractual structure and the regulatory structure that is behind these things. How much residual risk or how much residual value is associated with the post-contract period.

I think generally speaking, I would say that we will continue to look at fundamentals. From a fundamental perspective, is there demand for that project, and evidence of that usually is in somebody willing to pay for that under some sort of contractual or rate-regulated structure. So I would say that what we'd be seeking is projects that are within kind of what we've had as this historical risk preferences. And I would expect that our discount rates will be similar to our discount rates that we would apply to two existing projects. One of the cornerstones of sustainability is obviously financial sustainability, and the attraction of capital and that you need to have the stability of revenue to attract capital in the manner that we've attracted capital on a historic basis. So I think what you can expect from us is the same discipline, and what we know is based on growth in demand for these projects, those kinds of situations will exist. You've seen us invest in renewables in the past. We've been in hydro, we've been in wind, we've been in solar. And all those situations where we can't deal with the same sort of investment criteria that we have for all of our other assets. So that's what you can expect from us going forward. And I guess the bottom line is we do see substantial opportunity out there that's emerging in this transition. One of the biggest ones that we see right now is the intermittency issue with respect to renewable energy, either through batteries or pumped storage or some way we're going to have to sort of feel that intermittency. And then through things like our investment in Bruce Power, you'll bring on baseload power to augment these renewable energies in Ontario has been a great niche. We figured out a way to operate in Ontario that balances the system on a daily basis. And that appears to be valuable to the Ontario system operator and to Ontario residents. So the returns that we're getting there are consistent with returns that we would achieve in other parts of our business. So we see lots of promise on the horizon. And we'll just continue to be careful and disciplined as we allocate capital in that direction.

Yes, while the assets may appear different from a financial standpoint, the stream should be very familiar to our investors.

Very helpful. Appreciate the color. If I could shift to Mexico, in a post-COVID world. Could you update us your views on Mexico? Obviously the volumetrics look pretty good at $1.6 million, and EBITDA looks good. But just opportunities and risks in that marketplace.

Sure, it's Francois. So I think we take a long-term perspective on Mexico. We think that the growth and introduction of low-cost natural gas from the U.S. Gulf Coast into the Mexican economy is a strong strategic imperative for the country. It'll be a strong driver of macroeconomic growth going forward and is consistent with the Mexican government and the CFCs ambitions with respect to power generation and its own market share ambitions. The way they're going to achieve those targets is through increased supply of natural gas into the country. So, our assets in Mexico are positioned there. Again, once again, long-term contracts of 20 years or longer, U.S. dollar-denominated with a creditworthy counterparty are consistent with our risk preferences. We're comfortable with our investments in the country. And to the extent that there's opportunity, and we do see some opportunity for us to increase conductivity. We've built the backbone now. And we're completing work on the backbone of the infrastructure in Mexico. There'll be an opportunity for us to increase asset utilization through connecting with additional power plants with additional industrial load via petrochemical or otherwise. And so in the medium term, that's what I think you'll see from us in terms of incremental capital investment. Those tend to be along the corridor, lower risk and reasonable returns. And to the extent there are opportunities to expand or extend that backbone into other markets as the economy grows, we'll be ready to do so.

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

Good morning everyone. Just one from me. Good to see the $400 million U.S. expansion on ANR. Just want to get a sense of how discussions are going for similar and further kind of singles and doubles of your pipeline expansion project? Are we seeing a shift away from what we'll call a supply push projections is a focus now more on the demand pool.

Yeah. Hey, Rob. This is Stan. I could answer that. As I noted on some of our prior calls, just given the size and extent of our footprint, I expect us to originate anywhere between $0.5 billion to $1 billion in new book projects each year. With the announcement of the Elwood project today, we're not only on track to meet that in 2020, but we're clearly trending towards the high side. So going forward, I do see a little bit of a shift from the supply push to demand pool. For example, from a macro perspective, gas-fired power generation is expected to grow by 3 Bcf a day between now and 2023 and about 7 Bcf a day between now and 2030, and I have every expectation that we'll compete for and win our fair share of that. As a matter of fact, we're currently pursuing a couple of other gas-fired power generation projects right now on the ANR and Columbia System, one of which is very similar to the Elwood project, and I think we'll have at least one of them closed out by year-end. We still remain well-positioned to capture growth in the LNG export markets as we await the opening of economies due to the pandemic. And then lastly, I would just point out that while it's unfortunate that Dominion is no longer pursuing its APP project, I should note that there's still a need to get incremental gas supply down to those markets in the Southeast. We have a little bit more hallmark yet to do. But that very well may be in a position to serve at least a portion of that load through appraise and modifications to our existing infrastructure. And to do so perhaps without any builds through the Appalachian trail or national parks, there is still much more work to do there. So, stay tuned. Maybe the one thing that's left there on the supply side, at least in the short-term is that Bakken Express project. The impact of COVID-19 on oil prices definitely had us hit the pause button on that. But I do remain optimistic that we're ultimately going to get that project done too, although our origination timeline for doing so and service states are likely going to be pushed back a bit. So, as we can see, there are still many, many growth opportunities left that we're pursuing and we're going to continue to focus on constructible, permittable in-corridor expansions that are primarily compression-related.

Rob, let me add a little bit to that. This is Tracy. I'll add some on the Canadian gas-type system. As you know, we're in the middle of a quite a large program right now, and that program is both supply and demand-driven. But I think as we see forward and come through that, the WCSB is the depletion rate on our system, about 2 Bcf a day per year. So we will look to reconnect that amount of gas each year to just keep our supply going. And of course, we're connecting that in the Montney region on an increasing basis, 80% of our supply now comes from that area. But we also see opportunities for rifle shot connections within the Alberta system from an industrial perspective, and we look to use that remaining capacity on the mainline strategically to make sure that the WCSB volumes are getting into the continental North American markets effectively and competitively. We will always look, we think the WCSB gas is very economic and competitive, and we think it should, when the LNG markets arise themselves, it should then take its place in those markets as well. That's a longer-term basis, but we're looking for all of that. So we have, we see past the current program that we have in place right now, which goes to 2023 to 2024. We do see a continued expansion organically of our existing right-of-way.

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

Good morning. Just one question from me, can you maybe provide more details on the capacity optimization open season on NGTL? And I guess specifically how your customers are thinking about growth in the current environment. And then maybe in the context of that, how much capacity in total was deferred relative to your prior outlook?

Happy to do that. As you are aware, we've got a very large now almost $10 billion expansion program underway on NGTL. And we believe all that, of course, is based on contracted demand. We believe strongly in the fundamentals, WCSB prices have been stable this summer. They're strong if you look up the curve. It's a very competitive basin, but we did want given all of the announcements early in the year around changes to capital investments on the producer side, we want to check in and see how much that capacity was needed. So the open season gave an opportunity for those who had contracted on the expansion to advanced contracts, to defer contracts, and to turn that contract under certain circumstances. What we learned through that is that all of that capacity is still required. Some of it is required in different timeframes. We will see some advancing; some contracts will advance. We're seeing some capacity be deferred by a season or up to a year. We're just putting together the new capital program that will reflect that; but the good news in this and the strong in we expected it was that our customers want this capacity and see the same fundamentals we do.

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

Thanks very much to all of you for participating this morning. We recognize it's a busy time, so we appreciate your interest in TC Energy. We very much look forward to talking to you again soon. Thanks and have a great day.

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