For standing by. This is the conference operator. Welcome to the TC Energy 2020 second quarter results conference call. As a reminder, all participants are in listen-only mode and the conference is being recorded. After the presentation, there'll be an opportunity to ask questions. To join the question queue, you may press star then one on your telephone keypad. Should you need assistance during the conference call, you may signal an operator by pressing star and zero. I would now like to turn the conference over to David Moneta, Vice President, Investor Relations. Please go ahead.
Thanks very much, and good morning, everyone. I'd like to welcome you to TC Energy's 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. François 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. 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 investor section under the heading Events and Presentations. Following their prepared remarks, we will take questions from the investment community.
If you're a member of the media, please contact Jaimie Harding following this call, and she'd be happy to address your questions. In order to provide everyone from the investment community with an equal opportunity to participate, we ask that you limit yourself to two questions. If you have additional questions, please re-enter the queue. We ask that you focus your questions on our industry, our corporate strategy, recent developments, and key elements of our financial performance. If you have detailed questions relating to some of our smaller operations or your detailed financial models, Hunter and I'd 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. Good morning, everyone. 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 it 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. I'm proud to say that we've continued 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. 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 utilizations levels remain in line with historic and 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 CAD 100 billion portfolio of high-quality, long-life energy infrastructure assets continued to produce solid results. We continue to realize the growth expected from our industry-leading capital expansion program. To date, we are advancing CAD 37 billion of secured capital projects.
In addition, we continue to advance CAD 11 billion of projects under development, including the refurbishment of another five reactors at 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. More specifically, we enhanced our liquidity by more than CAD 11 billion through the issuance of long-term debt in both Canada and the U.S. at very attractive rates. 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 the 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. 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. While 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 and environment 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 continuous improvement as well as long-term fundamentals to ensure our business remains sustainable and resilient in an ever-evolving energy landscape.
With that as an overview, I'll expand on some recent developments, beginning with a brief review of our second quarter financial results. Don will provide more detail on our results and liquidity in just a few moments. Excluding certain specific items, comparable earnings were CAD 863 million, or CAD 0.92 per common share for the three months ended June 30th, compared to CAD 924 million, or about CAD 1 per share in 2019. Comparable EBITDA of CAD 2.2 billion, while comparable funds generated from operations were about CAD 1.5 billion. For the six months ended June 30th, comparable earnings were CAD 2 billion, or CAD 2.10 per common share, compared to CAD 1.9 billion or CAD 2.07 per share in the same period in 2019. Comparable EBITDA of CAD 4.7 billion and comparable funds generated from operations of CAD 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 CAD 3 billion of new long-term contracted and rate-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 MCR program that we commenced at the beginning of the year, and the sale of certain assets that will help fund our secured 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 receipts averaging about 12.3 billion cubic feet a day, the 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 to the volumes we moved over the same period last year. At the same time, we continue to advance approximately CAD 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, the Villa de Reyes and Tula 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 in-service dates for some of those facilities has moved. As a result, a certain amount 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 CAD 9.9 billion, up from CAD 9.4 billion on the 2021 program. These changes have been reflected in the secured capital projects table in our quarterly report. Turning to our U.S. natural gas pipeline business, where our expansion plans now include an incremental investment of approximately $400 million to replace, upgrade, and modernize certain facilities on the highly utilized section of the ANR Pipeline system. The program, which is known as the Elwood Power ANR Horsepower Replacement Project, will reduce emissions along the system and is another good example of an in-corridor expansion to meet growing demand utilizing our existing facilities and our existing right of ways.
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 transportation rates effective February 1st, 2021. It's Columbia's first rate case filing in over 20 years and will seek to recover our currently incurred operating costs, as well as a fair return on and of our historical and future capital investments in this expansive 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. Canadian natural gas pipelines construction activities continue on the 2.1 billion cubic feet a day Coastal GasLink project that will connect abundant Western Canadian Sedimentary Basin natural gas reserves to the LNG Canada plant to export from Kitimat, British Columbia. Field activity continues to increase along the route following the spring thaw. As we ramp up construction, our focus will remain on the health and safety of our employees, our contractors in the communities through strict adherence to our COVID-19 protocols. Ongoing work includes the construction of roads, bridges, worker accommodations, and grading. Pipe delivery also continues with more than 50% of the required pipes supplied to 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 CAD 2.1 billion. Looking forward, we'll continue to work with the First 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 a 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.
While the volatility has had an impact on our Marketlink and liquids marketing businesses, Keystone continued 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're very pleased with yesterday's decision by President Trump to sign 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 oil 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 barrel a day open season conducted in June 2019 and would 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 continued to advance construction on Keystone XL during the second quarter while managing the various legal and regulatory matters. In Canada, construction activities at our pump stations and along more than 100 km of the mainline right of away 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. It is underpinned by new 20-year take-or-pay contracts that are expected to generate approximately $1.3 billion of incremental EBITDA on an annual basis once the pipeline is placed into service in 2023. To advance the project, we have partnered with the government of Alberta, who will invest approximately $1.1 billion of equity into the project and fully guarantee a $4.2 billion 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 continued 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 Replacement or MCR Project, as we call it, when they took it offline here in January. We expect to invest approximately CAD 2.4 billion in that program, as well as ongoing asset management program 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 Electricity System Operator. This force majeure covered the unit six MCR, as well as certain asset management work. That said, I was pleased to report that in early May, work on the unit six MCR resumed with additional prevention measures in place for worker safety related to COVID-19. Progress is being made on critical path activities as Bruce works to isolate unit six from the remaining units in preparation for the removal of the 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, in power in late April, we did complete the sale of three natural gas-fired power plants in Ontario, the Napanee plant, Halton Hills, and our 50% interest in the Portlands Energy Centre. Net proceeds from that disposition netted approximately CAD 2.8 billion that we used to fund our industry-leading capital program. In summary, today we are advancing CAD 37 billion secured growth projects that are large to expect end of service between now and 2023. We have invested approximately CAD 11 billion into this program to date, with approximately CAD 5 billion of those projects expected to be completed by the end of 2020. Notably, all of these projects are underpinned by 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 dividend to CAD 0.81 per common share, which is equivalent to CAD 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 CAD 37 billion secured capital program, we expect to continue to grow our dividend at an average annual rate of 8%-10% through 2021, and 5%-7% thereafter. 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 CAD 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 CAD 11 billion of projects in advanced stages of development and expect numerous other in-corridor organic growth opportunities, like the $400 million US Elwood Power/ANR Horsepower Replacement Project that we announced today, to emanate from our expansive critical asset footprint. Looking forward, we will remain disciplined, continuing our focus on safety, sustainability, working according to our values, and responding quickly to market signals and signposts to ensure we remain industry-leading and resilient as we grow shareholder value. I'll now turn the call over to Don, who will provide you more details on our second quarter results and our 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 was CAD 1.3 billion, or CAD 1.36 per share in the second quarter of 2020, compared to CAD 1.1 billion or CAD 1.21 per share for the same period in 2019. For the six months ended June 30th, 2020, net income attributable to common shares was CAD 2.4 billion or CAD 2.59 per share, compared to net income of CAD 2.1 billion or CAD 2.30 per share in 2019. Second quarter results included a CAD 408 million after-tax gain on the sale of a 65% interest in the Coastal GasLink, along with an incremental CAD 80 million after-tax loss on 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 CAD 863 million, or CAD 0.92 per common share, compared to CAD 924 million or CAD 1.00 per common share in 2019. For the six months ended June 30, 2020, comparable earnings were CAD 2 billion or CAD 2.10 per share, compared to CAD 1.9 billion or CAD 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 CAD 2.2 billion, a CAD 125 million decrease compared to 2019. Canadian Natural Gas Pipelines comparable EBITDA of CAD 621 million was CAD 93 million higher than second quarter 2019, primarily on account of increased rate base 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 CAD 21 million compared to the same period in 2019 as a result of a higher average investment base from continued system expansions and reflects an ROE of 10.1% on 40% deemed common equity, while net income for the Canadian Mainline decreased CAD 3 million, largely due to lower incentive earnings. U.S. natural gas pipelines comparable EBITDA of $595 million, or CAD 824 million in the second quarter, fell by $46 million, or CAD 33 million 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, or CAD 181 million, rose $23 million, or CAD 40 million versus second quarter 2019, primarily due to Sur de 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 CAD 150 million to CAD 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 Courier in July 2019.
Power and storage comparable EBITDA in the second quarter fell by CAD 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 average exchange rate of CAD 1.39 in Q2 2020, compared to CAD 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 on U.S. dollar-denominated debt.
We 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. Turning to the other income statement items on slide 16. Depreciation and amortization of CAD 635 million, increased CAD 14 million versus Q2 2019, largely due to new projects placed in service in Canadian Natural Gas Pipelines, which is fully recoverable in tolls on a flow-through basis. Interest expense of CAD 561 million in the quarter was CAD 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 CAD 18 million compared to the same period in 2019, largely due to NGTL system expansion projects placed in service, as well as the suspension of recording AFUDC on Tula, effective January 2020. Comparable interest income and other was CAD 7 million in the second quarter, inconsistent with 2019. Income tax expense included in comparable earnings was CAD 125 million in Q2 2020, compared to CAD 199 million for the same period last year. The CAD 74 million decrease was mainly due to lower pre-tax 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 interests of CAD 63 million in the quarter increased by CAD 6 million relative to the same period last year, primarily due to higher earnings at TC PipeLines, LP. Finally, preferred share dividends of CAD 40 million were in line with Q2 2019. Now turning to slide 17. During the second quarter, comparable funds generated from operations totaled CAD 1.5 billion, and we invested approximately CAD 2.2 billion in our capital program, which, as noted, reflects equity accounting for our remaining 35% investment in Coastal GasLink post the closing of its partial equity sale.
While 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 CAD 2 billion in medium-term notes in the U.S., CAD 1.25 billion of senior unsecured notes in the Canadian and U.S. debt capital markets, respectively, on compelling terms. In addition, we arranged USD 2 billion of incremental committed credit facilities and closed the sale of our Ontario natural gas-fired power plants for net proceeds of approximately CAD 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 CAD 2.1 billion.
Finalizing these arrangements on Coastal GasLink, along with secured Government of Alberta support for Keystone XL in the form of a $1.1 billion U.S. equity contribution and $4.2 billion U.S. loan guarantee, means that a 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 forecasted sources and uses of funds in 2020. The left column details total funding requirements of approximately CAD 17.5 billion, comprised of long-term debt maturities and redemptions of CAD 3.9 billion, dividend and non-controlling interest distributions of approximately CAD 3.3 billion, and capital expenditures of approximately CAD 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 are shown in the second column and include forecast internally generated cash flow of approximately CAD 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 CGL, which together generated approximately CAD 4.9 billion. The government of Alberta's equity investment in Keystone XL of $1.1 billion and CAD 4.1 billion comprised of long-term debt that was issued in April, along with movements and balances of cash held in commercial paper outstanding. Taken together, we are effectively fully funded for 2020, and along with more than CAD 13 billion of committed credit facilities in place, and well-supported commercial paper programs in both Canada and the U.S., positioned to assuredly navigate any prolonged period of disruption should that occur. Turning to slide 19.
In closing, our solid financial and operational results in 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 program. Our overall financial position remains robust. Today, we are advancing a CAD 37 billion suite of secured projects through resilient 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 investment. That is expected to support annual dividend growth of 8%-10% in 2021, and 5%-7% thereafter.
Finally, we will continue to maintain our historic financial strength and flexibility at all points of the economic cycle. That's the end of my prepared remarks. I'll now 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 reenter the queue. With that, I will turn it back to the conference coordinator.
Thank you. We will now begin the question and answer session. To join the question queue, you may press star then one on your telephone keypad. You will hear a tone acknowledging your request. If you are using a speakerphone, please pick up your handset before pressing any keys. To withdraw your question, please press star then two. We will pause for a moment as callers join the queue. Our first question comes from Jeremy Tonet of JP Morgan. Please go ahead.
Hi. Good morning.
Morning, Jeremy.
Thanks. Just wanted to start off with KXL and wanted to see, 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, try to get a better feeling for how that would progress, and I guess, what type of outcomes there would have you guys 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 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.
Got it. Just want to pivot, if I could, towards what type of appetite you guys might have for what might be thought of as greener investments, if you will. The pumped hydro storage there, I was wondering if you might be able to update us on thoughts on that and appetite for projects like that, and then I guess also down the line if hydrogen logistics could fit into your plans at all or any thoughts given that's later dated at this point.
Thanks, Jeremy. It's François. With respect to our appetite for those types of investments, and the pumped storage project being a great example, as we've 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 in along the theme of firming resources as renewables increase as a percentage of the fuel mix. There'll be a need for more storage across various systems. As we've mentioned, we've got the Meaford project in Ontario. That's a 1,000-megawatt 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 with conducting environmental assessments once we've gained permission from the Department of National Defence to access the land on a longer-term basis. We also have another pumped storage project that's under development that we've invested in in Alberta that's fully permitted, and we're expecting to make an FID on that one, hopefully by the end of 2020.
You'll see us l ooking 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 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're always looking for ways to optimize our asset base. From our perspective, we've got a very strong asset base to economically and safely connect growing sources of renewable natural gas or hydrogen or any other types of products when they do become economic. As it relates to hydrogen, it can be blended with methane flowing through our existing pipelines and either left co-mingled or extracted through downstream separation process closer to the end use source.
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.
That's very helpful. Thank you for that.
Okay. Thanks, Jeremy.
Our next question comes from Robert Kwan of RBC Capital Markets. Please go ahead.
Good morning. If I can just start with the Columbia rate case and just to get some extra details. Specifically, just around, are there some parallels that we can draw to what you did with ANR as well, where you included or put differently, is there a bunch of modernization capital or any capital included as part of the rate case? An ability to recover that 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 the other recoveries of costs?
Hey, good morning, Robert. This is Stan. We are planning on filing our Columbia rate case tomorrow, actually. While there were some limited rate reviews that were done in conjunction with our prior modernization settlements, as Russ mentioned, this is going to be the first rate case on Columbia in over 20 years. In addition to recovering our prudently incurred costs, a fair return on our historical capital investment, the filing does also propose a third phase to our modernization program, whereby we're proposing to invest CAD 3 billion over a seven-year period to further ensure the safety, the reliability, and the integrity of our assets. To your point, we'd have the ability to recover these costs without further rate cases as we do now with our existing modernization program.
Basically all the modernization capital that we spend at the end of a given year, we would start recovering those costs starting February 1st of the following year. I should note that the rate case establishes rates for our base system customers and is not going to adjust any of the demand charges for our XPress projects, which were recently placed in service, as they will continue to be incrementally priced and subject to fixed negotiated rates. I also should point out that the rates are going to take effect on February 1st of 2021, subject to refund. There's not going to be any impact to 2020 earnings. The process is such that once our filing is made, FERC will 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 is 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 mutually satisfactory manner. In that regard, we likely will kick off settlement discussions sometime in the fourth quarter of this year, and they would most likely continue into maybe first quarter, second quarter into 2021.
That's helpful. Stan, just to kind of follow up, that CAD 3 billion over seven years, that's new and incremental to the modernization capital that you're already showing in your tables. Is that correct?
Yeah, that's correct. That would be new incremental capital. Again, that's what we're proposing. We're going to have to go through the process. That could change over time, but that's the proposal as it sits with our filing.
What proportion of Columbia right now is on recourse rates versus contracted rates?
Good question. If memory is correct, it's probably somewhere around 50% or so, but I should follow up with Dave and get you an exact number.
Okay, fair enough. If I can just finish with a quick funding question. Just you mentioned that you're going to be filing the ATM this quarter, and that had been previously specifically earmarked for KXL. Is that completely still the case, or do you have any anticipation to need it for non-KXL purposes?
Yeah. Hi, Robert. It's Don here. We announced it 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 embark on KXL as another lever. The base funding plan, there's no issuance under the ATM factored into that. 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. Thanks, Robert.
Our next question comes from Robert Catellier of CIBC Capital Markets. Please go ahead.
Hi. Good morning. 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? Really, I'm trying to get a sense of what other work you might have to do on the permitting, and if you could also address cost and timing.
Thanks, Robert. It's Bevin. The incremental 50,000 barrels a day that we contracted through the open season mid last year is available to the system, based on using increased DRA, as you suggest. No further pump stations or other capital is required to accommodate that increase.
Okay. Just the bigger picture here, as you're looking to the 5%-7% long-term growth rate, how much of that is contemplated from just the existing footprint? Stated 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?
Yeah. It's Don here. Beyond KXL and Coastal GasLink, it doesn't factor in any what we would consider mega projects. Even with those projects, we look at our 100,000 kilometer of pipe right-of-way right now with the opportunities that just organically come off of that. You've seen some today with Elwood. You've heard from Stan on potentially a Modernization 3 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 at Bruce that need refurbishment going forward. Where we land in that 5%-7% range will depend on the mix of projects that comes out of our organic programs here, how we execute on them, and the cadence of those. I think we indicated that at Investor Day.
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 the commercial landing of these to getting through the regulatory permitting process and getting shovels in the ground. We're starting to look at stuff mid-decade now. We might get greater visibility on things like that. François 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.
Maybe I just add to Don's comments. I think what we've always said is if we can reinvest our free cash flow, the 60% that's generated on an annual basis into our core businesses and get a return in that sort of 7%-8% range, we can generate that kind of 5%-7% growth rate. Pick a number, that number happens to be about CAD 5 billion on an annual basis that we're looking for right now. As we look at the portfolio, as Don said, it's not a big stretch for us to say that we can find CAD 4 billion-CAD 5 billion of in-corridor expansion. We'll always look for other platforms for growth. As we think about our platform, you just think about this quarter, where we brought on the Elwood Project, for example, CAD 500 million, in a sense.
We've done that sort of quarter on quarter here over the last while. Getting to CAD 5 billion of capital investment in our corridors doesn't seem to be a stretch. As Don said, our maintenance capital, which is for the most part, rate regulated, is a couple billion CAD a year that we get return of and on capital on. As Stan pointed out, his modernization programs going forward will be over and above that. You add to that these in-corridor expansions that we're talking about. Bruce Power on an annual basis, if we do complete the balance of the five more unit replacements, on average, that's CAD 1 billion a year over the next decade or so. You think about the expansions that we've talked about across the system into Mexico and other places.
You quickly add up to numbers that can exceed CAD 4 billion-CAD 5 billion a year. We'll be, I think, continuing to be in capital rationing mode and making sure that we allocate capital to very best projects. What we found is that the very best projects are the smaller ones, CAD 500 million-CAD 1 billion. They generally give us higher returns, and we don't have the same resistance as we do to large-scale multi-jurisdictional projects that are greenfield. I guess from my perspective, over the last 20 years or so, you can see that we've reinvested CAD 100 billion into our core businesses and generated that sort of 7% growth rate in earnings and cash flow per share. I'd expect that to continue looking forward.
I'd say our visibility of opportunities to reinvest our free cash flow are probably greater now than at any time in our history, and it's primarily related to continued increase in demand for energy. A difficult environment to build new greenfield things in, which has pointed us back to these in-corridor expansions. I can go through numerous ones, the GTN expansion, our Iroquois expansion, our BXP expansion in the U.S., attaching to LNG facilities, is that the in-corridor expansions are things that can get done, and our customers know that, and they're looking at us for solutions to continue to meet their growing energy demands.
Okay. Thank you for those comments.
Thanks, Rob.
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 per day that you've 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. We've been making excellent progress. As you're aware, last year we had an incident at Edinburg, and we've been working on our pipeline integrity projects to reestablish and expand the capacity on our base system. 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. The balance, we still remain 35,000 barrels a day of spot on the system, and any incremental increase thereafter will determine whether or not there's market demand and capability to use that incremental capacity.
That would require some sort of additional pumping and looping, or what would be the scope and scale of any sort of investments required to add beyond that?
No. The initial, as I mentioned on the 50,000, that is purely through DRA. Any other incremental, we'll just look at optimizing the base system. It may have some modest capital requirements, but we'll look at those in the future.
That's helpful. Thank you. A follow-up question with respect to the Columbia 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, what would the lift be in EBITDA for the company, potentially?
Yeah. Linda, this is Stan. Fair question, but with all due respect, having not yet filed the case, I don't want to front-run the process. There's still lots of discussions that we have to have with our customers, regulators, and stakeholders. Until we do, we're really just not in a position to provide guidance on any ultimate outcome. What I would suggest is that David and his IR 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 of the modernization that would be new and significant step changes in kind of the current run rate of how you're running ANR, or sorry, Columbia Gas?
Yes. Again, just out of respect for the process, I'd rather not go into any details because we have not yet shared all this with our customers. If I could just ask you to maybe hold that question, and we could follow up with you in the not-too-distant future.
Will do. Thanks so much, Stan.
Okay.
Thanks, Linda.
Our next question comes from Asit Sen of Bank of America. Please go ahead.
Thanks. Good morning. Just coming back to the ESG energy transition topic. As you look into the future scenarios, just wondering how you're thinking about the financial framework, discount rate, terminal value, for these green projects to attract capital. Just broadly, how are you thinking about it?
Yeah, I'll start out. It's Don here. We would look at them similar to our existing 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's your cash flows during the project, during the contract length, 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'll continue to look at fundamentals. From a fundamental perspective, is there demand for that project? Evidence of that usually is in somebody willing to pay for that under some sort of contractual or rate-regulated structure. I would say that what we'd be seeking is projects that are within kind of what we've had as historical risk preferences, and I would expect that our discount rates will be therefore similar to our discount rates that we would apply to existing projects. One of the cornerstones of sustainability is obviously financial sustainability and attraction of capital, and that you need to have stability of revenue to attract capital in the manner that we've attracted capital on a historic basis. I think what you can expect from us is the same discipline and rigor.
What we know is that 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. In all those situations, we came to it with the same sort of investment criteria that we have for all of our other assets. That's what you can expect from us going forward. 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 pump storage or some way, we're going to have to sort of fill that intermittency. Then through things like our investment in Bruce Power.
You'll bring on base load power to augment the renewable energy in Ontario has been a great mix, and we figured out a way to operate in Ontario that balances the system on a daily basis. That appears to be valuable to the Ontario system operator and to Ontario residents. The returns that we're getting there are consistent with the returns that we would achieve in other parts of our business. 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.
Yeah. Physically, the assets may look different, but financially the stream should look very familiar to our investors.
Very helpful. Appreciate the color. If I could shift to Mexico. In a post-COVID-19 world, could you update us on your views on Mexico? Obviously, the volumetrics look pretty good at 1.6 billion, and EBITDA does look good. Just opportunities and risk in that market, please.
Sure. It's François. 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. It's consistent with the Mexican government and the CFE's 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. Our asset position there, once again, long-term contracts, 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 there's opportunity, and we do see some opportunity for us to increase connectivity.
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, be it petrochemical or otherwise. 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. 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.
Thank you.
Okay. Thanks, Asit.
Our next question comes from Rob Hope of Scotiabank. Please go ahead.
Morning, everyone. Just one from me. Good to see the $400 million US 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. Have we seen a shift away from, we'll call it supply-push projects, and is the focus now more on the demand-pull ones?
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 a half a billion to a billion CAD of new growth 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. Going forward, I do see a little bit of a shift from the supply push to demand pull. For example, from a macro perspective, gas-fired power gen is expected to grow by three BCF a day between now and 2023 and about seven 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 gen 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 market as we await the opening of economies due to the pandemic. Lastly, I would just point out that while it's unfortunate that Dominion is no longer pursuing its ACP 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 homework yet to do, but very well may be in a position to serve at least a portion of that load through upgrades and modifications to our existing infrastructure.
To do so, perhaps without any builds through the Appalachian Trail or the national parks or forests. A little bit more work to do there, so stay tuned. Maybe the one thing that's left on the supply side, at least in the short term, is the Bakken XPress project. The impact of COVID-19 on oil prices definitely had us hit the pause button on that. I do remain optimistic that we're ultimately going to get that project done too, although our origination timeline for doing such and in-service dates are likely going to be pushed back a bit. Again, as you can see, there's still 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 pipe system. As you know, we're in the middle of quite a large program right now, that program is both supply and demand driven. I think as we see forward and come through that, the WCSB has a depletion rate on our system of about two BCF a day per year. We will look to reconnect that amount of gas each year to just keep our supply going. Of course, we're connecting that in the Montney region on an increasing basis. 80% of our supply now comes from that area.
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, the 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 right themselves, it should take a place in those markets as well. That's a longer-term basis. We're looking for all of that. We see past the current program that we have in place right now, which goes to 2023, 2024. We do see continued expansion organically of our existing right of way.
I appreciate all the color. Thank you.
Okay. Thanks, Rob.
Once again, if you have a question, please press star, then one. Our next question comes from Praneeth Satish of Wells Fargo. Please go ahead.
Thanks. Good morning. Just one question for me. Can you maybe provide any more details on the capacity optimization open season on NGTL? I guess specifically how your customers are thinking about growth in the current environment. Maybe in the context of that, how much capacity in total was deferred relative to your prior outlook?
I'd be happy to do that. As you are aware, we've got a very large, almost CAD 10 billion expansion program underway on NGTL. We believe all that, of course, is based on contracted demand. We believe strongly in the fundamentals of the WCSB. Prices have been stable this summer. They're strong if you look out the curve. It's a very competitive basin. We did want, given all of the announcements early in the year around changes to capital investments on the producer side, we wanted just to check in and see how much that capacity was needed. The open season gave an opportunity for those who had contracted on the expansion to advance contracts, to defer contracts, or to turn back contracts under certain circumstances. With that all netted out, what we learned through that is that all of that capacity is still required.
Some of it is required in different time frames. We will see some bits advancing. Some contracts will advance. We're seeing some capacity be deferred by a season or up to a year, and we're just putting together the new capital program that will reflect that. The good news in this, and the strong, we expected it, was that our customers want this capacity, and they see the same fundamentals in this basin that we do.
Great. Thank you.
Thanks, Praneeth.
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.
Great. Thanks very much, and 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, and 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.