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TC Energy Corporation (TRP 0.54%)
Q3Â 2019 Earnings Call
Nov 1, 2019, 11:00 a.m. ET
Contents:
- Prepared Remarks
- Questions and Answers
- Call Participants
Prepared Remarks:
Operator
Good morning, ladies and gentlemen. Welcome to the TC Energy 2019 Third Quarter Results Conference Call. I would now like to turn the meeting over to Mr. David Moneta, Vice President, Investor Relations. Please go ahead, Mr. Moneta.
David Moneta -- Vice President, Investor Relations
Thanks very much and good morning everyone. I'd like to welcome you to TC Energy's 2019 Third Quarter Conference Call. With me today are Russ Girling, President and Chief Executive Officer; Don Marchand, Chief Financial Officer; Tracy Robinson, President, Canadian Natural Gas Pipelines; Stan Chapman, US Natural Gas Pipelines, President of that business unit; Paul Miller, President of Liquids Pipelines; Francois Poirier, Executive Vice President of Corporate Development and Strategy and President, Power & Storage and Mexico; 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 should 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 reenter the queue. Also, 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 related to some of our smaller operations, Duane and I'd be pleased to discuss them with you following the call.
Before us 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 US Securities 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, comparable funds generated from operations, and comparable distributable cash flow. These and certain other comparable measures are considered to be non-GAAP measures. As a result, they may not be comparable to similar measures presented by other entities. These measures are used to provide you with additional information on TC Energy's operating performance, liquidity and its ability to generate funds to finance its operations.
With that, I'll now turn the call over to Russ.
Russell K. Girling -- President and Chief Executive Officer
Thanks David and good morning everyone and thank you very much for joining us today. As highlighted in our quarterly report to shareholders during the third quarter, our $100 billion portfolio of high quality, long-life energy infrastructure assets continued to profit from strong supply and demand fundamentals. Those market fundamentals have resulted in demand for our services with the majority of our infrastructure now running at full capacity under either rate regulated contracts or long-term firm contracts.
The demand for access to the Continental footprint that we have has led to our industry-leading $30 billion capital expansion program, which is underpinned by contracts that are generally 20 years or longer or rate regulated constructs. We continue to realize the growth expected from this program as we placed approximately $8 billion of new long-term contracted and rate regulated assets into service during the first nine months of the year. As a result, despite significant asset sales that have accelerated the strengthening of our balance sheet, comparable earnings of $1.04 per share for the three months ended September 30, 2019, increased 4% over the same period in 2018, while comparable funds generated from operations of approximately $1.8 billion were 15% higher.
Today we are advancing $30 billion of secured projects with approximately $2.5 billion of those projects expected to be completed in the fourth quarter of this year. In addition, we're continuing on more than $20 billion of projects under development including Keystone XL and the refurbishment of another five reactors at Bruce Power as part of their long-term life extension program. We've also made significant progress in funding our capital program during the third quarter through various portfolio management activities. More specifically, we completed the partial monetization of our Northern Courier pipeline in Alberta as well as the sale of certain Columbia Midstream assets in the Appalachian region and we entered into an agreement to sell our natural gas-fired power plants in Ontario.
These initiatives, combined with the sale of our Coolidge generating station, which closed in May, are expected to result in combined proceeds of approximately $6.3 billion. Each transaction has allowed us to surface significant value for relatively mature assets and redeploy that capital into our expansion program, thereby reducing our need for external funding including common equity. As a result, commencing with our fourth quarter 2019 dividends, we have discontinued the issuance of common shares from treasury under our Dividend Reinvestment Program.
Looking forward, we expect our strong operating and financial performance to continue and therefore 2019 comparable earnings per share are expected to be higher than the record results that we produced in 2018. At the same time, our overall financial position remains solid and we are well positioned to achieve our targeted credit metrics. Don will provide more detail on third quarter results and funding programs in just a few minutes. Before that, I wanted to expand on some recent developments, beginning with a brief review of our financial results.
Excluding certain specific items, comparable earnings of $970 million or $1.04 per share in the third quarter, an increase of $68 million or $0.04 per share over the same period in 2018. That equates to a 4% increase on a per-share basis after recognizing the effect of the previously mentioned asset sales and common shares issued under the dividend reinvestment program in 2018 and 2019, and our ATM program in 2018. Comparable EBITDA increased $288 million to approximately $2.3 billion, while comparable funds generated from operations of $1.8 billion or $231 million higher than the third quarter of 2018.
On a year-to-date basis, comparable earnings were $3.11 per share, an increase of $0.29 per share or 10% over the same period in 2018. Comparable EBITDA increased 15% to approximately $7.1 billion, while comparable funds generated from operations of $5.3 billion were 14% higher than last year. Based on the strength of our financial performance, the Board of Directors declared a fourth quarter dividend of $0.75 per common share, which is equivalent to $3 per share on an annualized basis .
That represents an 8.7% increase over the amount declared in the fourth quarter of 2018 and equates to a payout of approximately 75% of comparable earnings and 40% of comparable funds generated from operations, leaving us with a significant internally generated cash flow to continue to invest in our core businesses. Next, a few comments on our five operating businesses. First in Canadian Natural Gas Pipelines, customer demand for access to our systems remains strong and we continue to work with industry on options to connect growing Western Canadian gas supply to markets across North America.
Evidence of this can be seen in our announcement earlier today that will see us invest an additional $1.2 billion in our West Path Delivery Program, which is a combined expansion of the NGTL Foothills and GTN systems. The expansion will add approximately 258 MMcf/d of capacity to the system and is underpinned by new firm service contracts with average terms of approximately 30 years. Regulatory applications for the expansion are expected to be filed in 2020. Subject to the receipt of regulatory approvals, construction is expected to commence as early in the fourth quarter of 2021, with in-service dates ranging from the fourth quarter of 2022 to the fourth quarter of 2023.
With this announcement, we are now advancing a $10 billion expansion program in NGTL that will add approximately 3.3 billion cubic feet a day of incremental delivery capacity to the system by the end of 2023. The project will be constructed concurrent with the GTN XPress project announced by TC PipeLines, LP earlier today. That $35 million GTN XPress project is an integrated reliability and expansion project on the GTN system that is expected to be fully complete in 2023 and provide the transport of additional volumes enabled by the NGTL and Foothills West Path Delivery Program.
We also continue to work on with LNG Canada on our Coastal GasLink project. The $6.6 billion project will have an initial capacity of approximately 2.1 billion cubic feet a day with potential expansion capacity up to 5 billion cubic feet a day. The estimated cost of the project has risen due to increased scope and refinement under of our construction estimates and we expect those incremental costs will be incorporated into the final tolls. Construction activities continued at many locations along the pipeline route during the third quarter, and at the same time, we continue to advance funding plans for the project through a combination of the sale of up to 75% ownership and project financing. Both of those transactions are proceeding as planned.
Moving to our US Natural Gas Pipelines, for demand for our services reached record levels during this year. As highlighted previously, our broad network has historically served approximately 25% of US demand on a daily basis. In addition to moving those volumes on our existing systems, during the quarter, we continued to advance our $1.1 billion US Modernization II program on the Columbia Gas system as well as another $1.5 billion of US of other capacity additions that now includes the GTN XPress project along with our previously announced Louisiana XPress project, the Grand Chenier XPress project and the Eastern Lateral XPress project.
Turning to Mexico, where the Sur de Texas pipeline began commercial operations in September following the execution of an amending agreement with CFE. As a result of that amendment, the contract has now been extended to 35 years, with the CFE now receiving transportation services under a levelized toll structure. All other terms and conditions of the contract remain substantially unchanged. Sur de Texas has a capacity of up to 2.6 billion cubic feet a day of low-cost clean burning -- to move the low-cost clean burning US natural gas supply into Mexico.
Finally, in Mexico, construction of the Villa de Reyes pipeline is ongoing with phased in-service anticipated to commence in early 2020. Construction on the central segment of the Tula pipeline project continues to face delays. Tula's in-service date is estimated to be two years after the indigenous consultations are successfully concluded.
Turning to our Liquids business where I wanted to start by acknowledging that we are responding to an incident on our Keystone Pipeline System in North Dakota today. While the incident is unfortunate, when one does occur, we have world-class capabilities to respond, protect the public and the environment and restore the pipeline to service as quickly as possible.
In this instance, our leak detection systems enabled us to remotely shut down the pipeline and our crews moved to the scene immediately. Today, we are focused on cleaning up the site, determining the cause and returning the line to service. To keep you informed on the progress, we have launched a page on our website at TCEnergy.com which will provide you with updates as new information becomes available.
With respect to our financial performance, the liquids business again produced strong results in the third quarter of 2019. Keystone which is underpinned by long-haul take or pay contracts for over 90% of its capacity essentially ran full in the third quarter, moving an average of about 590,000 barrels a day. On the southern portion of the system or what we call the US Gulf Coast segment, capacity was increased through 2018 and 2019 reaching over 700,000 barrels a day by year-end. As capacity increased, we maintained near-full utilization again in the third quarter of 2019.
In addition, we continue to benefit from higher contribution from the liquids marketing activities, largely due to improved volumes and margins because of favorable market conditions. Finally in Liquids business, we continue to advance the Keystone XL Pipeline project. In March, the US President Trump issued a new Presidential permit for the project, which preceded the 2017 permit and resulted in a dismissal of the cases related to the old permit. In August, the Nebraska Supreme Court affirmed their 2017 decision that approved the Keystone XL Pipeline route through the state of Nebraska. A motion for rehearing of that decision by the Supreme Court was denied.
In addition, on October 4, the US State Department issued a Draft Supplemental Environmental Impact Statement for the project. It considers changes in the project since the 2014, Keystone XL Supplemental Environmental Impact Statement. Included in that new SEIS is the rooting of Nebraska, as well as updated information and new studies. The SEIS is expected to be issued in final form by the end of 2019.
Moving forward, we will continue to carefully and methodically obtain the regulatory and legal approvals necessary before we consider advancing this commercially secured project into construction. Turning now to power and Storage, in the first quarter, we experienced an equipment failure on the $1.8 billion Napanee project, while we were progressing commissioning activities on the plant during the first quarter. We are addressing the situation and we expect the 900-megawatt plant to be placed into service late in the first quarter of 2020.
The sale of the Napanee Facility along with Halton Hills and our interest in Portlands Energy Centre for approximately $2.9 billion is expected to close by the end of the first quarter of 2020. Work also continues on the Bruce Power life extension project where we expect to invest approximately $2.2 billion in Bruce Power's unit 6 MCR program as well as ongoing asset management programs through 2023 when the unit six refurbishment is expected to be completed.
Bruce Power's contract price increased to approximately $78 per megawatt hour on April 1, 2019, to reflect the capital to be invested under these programs as well as normal annual inflation adjustments. Despite the recently announced sales of various power generation facilities, we remain committed to Bruce Power and its refurbishment, as well as our broader Power and Storage business including future, new, low-risk investments in the electricity sector in our core North American market places.
So in summary, we are advancing a $30 billion secured growth program that is expected to enter service by 2023. We have invested approximately $9 billion into that program to date, with approximately $2.5 billion of those projects expected to be completed by the end of 2019.
Notably, all of these projects are underpinned by cost of service regulation or long-term contracts giving us visibility to earnings and cash flows that they will generate as they enter service. Based on the continued strong performance of our base business, combined with our growth plans, we expect to grow our dividend at an average annual rate of 8% to 10% through 2021. As is always been our practice, the growth in dividends is expected to be supported by sustainable growth in cash flow and earnings and strong coverage ratios.
In summary, I'd leave you with the following key messages. Today, we are a leading North American energy infrastructure company with a strong track record of delivering long-term shareholder value. Our assets provide an essential service that is critical to the functioning of North American society and our economy and the demand for our services remains very strong.
Looking forward, we have five significant platforms for growth, Canadian, US and Mexican Natural Gas Pipelines, our Liquids Pipeline business and Power and Storage. Just as we've done since 2000, as we advance our $30 billion secured capital program, we expect to deliver growth in earnings, cash flow and dividends per share.
In addition, we have more than $20 billion of projects that are in advanced stages of development, and we expect numerous other growth opportunities to emanate from our extensive critical asset footprint. Given our strong and growing internally generated cash flow, access to debt capital markets and proceeds from approximately $6.3 billion from recently announced portfolio management activities, we are very well positioned to fund our secured capital program and achieve our targeted credit metrics without the need for additional common equity.
I'll now turn the call over to Don Marchand, who will provide some more details on our third quarter results. Don?
Donald R. Marchand -- Executive Vice President and Chief Financial Officer
Thanks Russ, and good morning everyone. As outlined in our quarterly results issued earlier today, net income attributable to common shares was $739 million or $0.79 per share in the third quarter of 2019, compared to $928 million or $1.02 per share for the same period in 2018. Third quarter 2019 results included an after-tax loss of $133 million at September 30, 2019, related to the Ontario natural gas-fired power plants held for sale, and after-tax loss of $133 million related to the disposition of certain Columbia Midstream assets in August and an after-tax gain of $115 million related to the partial monetization of the Northern Courier Pipeline in July.
Third quarter 2018 results included after-tax income of $8 million related to our US northeast power marketing contracts. These specific items as well as unrealized gains and losses from changes in risk management activities are excluded from comparable earnings. Excluding these specific items, comparable earnings of $970 million or $1.04 per share in the third quarter of 2019 were $68 million or $0.04 per share higher year-over-year.
This equates to a 4% increase on a per-share basis, despite significant asset sales, as well as the dilutive effect of common shares issued under our dividend reinvestment plan in 2018 and 2019, and after market program in 2018. All of which were in support of our growth in credit metrics. These positive results reflect continued progress placing new assets into service, as well as operational strengths and solid cash generation across all of our businesses.
Turning to our business segment results on Slide 15, in the third quarter, comparable EBITDA from our five operating businesses were approximately $2.3 billion, representing a $288 million or 14% increase from 2018. Canadian Natural Gas Pipelines comparable EBITDA of $572 million, it was $50 million higher than for the same period last year, as a result of higher incentive earnings as well as increased depreciation on the Canadian Mainline resulting from higher rates approved by the NEB 2018 decision, along with increased rate base earnings and higher depreciation on the NGTL system due to additional facilities that were placed in service. These favorable variances were partially offset by lower flow through taxes on both the NGTL System and the Canadian Mainline, attributed to accelerated tax depreciation enacted by the federal government in June 2019.
I would note that for Canadian Natural Gas Pipelines, changes in depreciation, financial charges and income taxes impact comparable EBITDA, but do not have a significant impact on net income as they are almost entirely recovered in revenues on a flow-through basis. Net income for the NGTL system increased $23 million compared to third quarter of 2018, driven by a higher average investment base from continued system expansions and reflects a base ROE of 10.1% on 40% deemed equity as approved in our 2018-2019 rate settlement.
Net income for the Canadian Mainline increased $3 million year-over-year primarily due to incentive earnings recorded in the third quarter of 2019. We did not record incentive earnings in the third quarter of 2018, pending the outcome of the Canadian Mainline 2018-2020 total review. US Natural Gas Pipelines comparable EBITDA of $604 million or CAD796 million in the quarter increased by $57 million or CAD81 million compared to the same period in 2018, mainly driven by increased contributions from Columbia Gas and Columbia Gulf growth projects placed in service.
This was partially offset by decreased earnings from Bison, as a result of 2018 customer agreements to pay out their future contracted revenues and terminate their contracts as well as the impact of the sale of certain Columbia Midstream assets in August 2019. Mexico Natural Gas Pipelines comparable EBITDA of $115 million , or CAD153 million was consistent with third quarter of 2018. As Russ noted, on September 17, 2019, following the execution of an amending agreement with CFE, the Sur de Texas pipeline entered service and we began recording equity income from operations under the now 35-year contract.
Liquids Pipelines' comparable EBITDA rose by $108 million to $575 million in the third quarter of 2019, resulting from higher volumes on the Keystone Pipeline System, a higher contribution from liquids marketing activities attributable to improved margins and volumes and income from the White Spruce pipeline, which was placed into service in May 2019, partially offset by the impact of the sale of an 85% equity interest in the Northern Courier Pipeline in July 2019.
Power and Storage comparable EBITDA increased by $45 million year-over-year to $252 million, driven by a larger contribution from Bruce Power primarily as a result of higher realized sale price sale price and higher output as a consequence of fewer outage days. These positive results were partially offset by decreased Western and Eastern Power contributions, largely due to the sale of our interests in the Cartier Wind and Coolidge generating facilities in October 2018 and May 2019 respectively, as well as lower realized margins on lower generation volumes.
For all our businesses with US dollar denominated income including US Natural Gas Pipelines, Mexico Natural Gas Pipelines, and parts of our Liquids Pipelines business, Canadian dollar translated to EBITDA was positively impacted by a stronger US dollar versus third quarter 2018. This was largely offset by higher translated interest expense on US dollar denominated debt and realized hedging losses reported in comparable interest income and other.
Regarding our exposure to foreign exchange rates, besides of a portion of our US dollar denominated assets are hedged with US dollar denominated debt. We continue to actively manage the residual exposure on a rolling one-year forward basis.
Now turning to the other income statement items, on Slide 16, depreciation and amortization of $610 million increased $46 million versus third quarter of 2018, largely as a result of new facilities entering service across our businesses, higher composite depreciation rates approved in the Mainline NEB 2018 decision and a stronger US dollar, partially offset by the previously mentioned asset dispositions cessation of depreciation on our Ontario natural gas-fired plants now held for sale and the buys and asset impairments.
Interest expense included in comparable earnings of $573 million for third quarter of 2019, was consistent year-over-year. AFUDC for the three months ended September 30, 2019, declined by $27 million compared to the same period in 2018. A $43 million decrease in US dollar denominated AFUDC was primarily due to Columbia Gas and Columbia Gulf growth projects placed in service, partially offset by continued investment in our Mexico projects while a $30 million increase in Canadian dollar denominated AFUDC was mainly driven by capital expenditures on our NGTL System expansion projects.
Comparable interest income and other of $49 million in the third quarter of 2019 was similar to the same period in 2018. Income tax expense included in comparable earnings was $260 million in the third quarter of 2019, compared to $108 million for the same period last year. As a result of higher comparable earnings, before income taxes and lower foreign tax rate differentials, partially offset by lower flow through income taxes on Canadian regulated pipelines attributed to the Canadian Federal Government accelerated tax depreciation enacted in June 2019.
Excluding Canadian rate regulated pipelines where income taxes are a flow-through item and are thus quite variable, along with equity AFUDC income in US and Mexico Natural Gas Pipelines, we expect our 2019 full-year effective tax rate to be in the mid to high teens. Net income attributable to non-controlling interests of $59 million for the three months ended September 30 2019 was unchanged from the same period in 2018. And finally preferred share dividends were also comparable to third quarter 2018.
Now moving to cash flow and distributable cash flow, on Slide 17, comparable funds generated from operations of approximately $1.8 billion in the third quarter increased $231 million or 15% year-over-year, driven largely by higher comparable earnings despite asset sales. Comparable distributable cash flow reflecting only non-recoverable maintenance capital was approximately $1.7 billion or, $1.78 per share compared to $1.4 billion or $1.56 per share in the third quarter of 2018, resulting in the coverage ratio of 2.4 times.
Now turning to Slide 18. During the third quarter, we invested approximately $2.1 billion in our capital program and successfully funded it through strong and growing internally generated cash flow, long-term debt and hybrid security issuances, common equity from our dividend reinvestment plan and significant portfolio management activities. In September, we raised $1 billion through a Canadian medium term notes offering, comprised of $700 million of 10-year notes at a fixed rate of 3% and $300 million of 30-year notes at a fixed rate of 4.18%.
Also in September, we issued $1.1 billion of 60-year junior subordinated notes at an initial fixed rate of 5.5% for the first 10 years, converting to a floating rate thereafter. Interest expense on these notes is fully tax deductible and they are generally accorded 50% equity credit in the calculation of our thee key credit metrics. Today, approximately 95% of our debt is fixed rate in nature, with an average coupon of 5.1% and an average term of 22.1 years, including the hybrid securities to final maturity.
The average term of our debt including hybrids to First Call is 13.2 years. In the third quarter, we also continue to execute on asset dispositions, completing the partial monetization of Northern Courier for aggregate gross proceeds of $1.15 billion in July and the sale of certain Columbia Midstream assets for approximately $1.3 billion, or CAD1.7 billion in August. Overall portfolio management activities have generated $3.4 billion of proceeds in 2019. This will be supplemented by the previously announced sale of our Ontario natural gas-fired power plants for an additional $2.9 billion with closing expected in the first quarter of 2020.
Our dividend reinvestment plan or DRIP continue to provide incremental subordinated capital in support of our growth and credit metrics in the third quarter with a participation rate among common shareholders of approximately 35% , representing $247 million of dividend reinvestment. For the first three quarters of 2019, the participation rate was approximately 34% resulting in $711 million of common equity at a 2% discount. Cumulatively with an additional $214 million having been reinvested as part of the fourth quarter of 2018 dividend paid in January 31, 2019, we have raised $925 million through DRIP this calendar year. Commencing with the dividends declared yesterday, we have discontinued the issuance of common shares from treasury at a discount to satisfy participation in our DRIP and will instead acquire these shares on the open market at cost. With our significant internally generated cash flow, access to debt capital markets and pending close of the sale of our Ontario gas-fired power plants, we are well positioned to prudently fund our $30 billion secured capital program in a matter that maximizes earnings and cash flow per share and is consistent with achieving targeted run rate credit metrics, including debt to EBITDA in the high fours without recourse for further share count growth.
Now turning to Slide 19, this graphic highlights our forecasted sources and uses of funds in 2019. Starting in the left column, our long-term debt maturities of $3.3 billion, dividend and non-controlling interest distributions of approximately $3.1 billion, and 2019 capital expenditures projected to be approximately $8.8 billion including maintenance capital bring our total funding requirement for 2019 to approximately $15.2 billion.
The second column highlights aggregate sources of approximately $15.2 billion, including forecast full-year internally generated cash flow of $6.9 billion and permanent funding of $7.8 billion put in place through a combination of long-term debt, hybrid securities, DRIP, and completed portfolio management. The remaining $500 million has been sourced through a mix of cash on hand and commercial paper.
As a reminder, we continue to advance funding plans for the $6.6 billion Coastal GasLink project through the sale of up to a 75% equity interest and project financing, both of which are progressing as planned. In this chart, we reflect our ownership of 100% interest pending completion of those processes.
Now turning to slide 20. In closing, I'll offer the following comments. Our solid across-the-board financial and operational results in the third quarter highlight our diversified low-risk business strategy and reflect the strong performance of both our blue-chip legacy portfolio along with the contribution of equally high quality assets entering service from our ongoing capital program. Today, we are advancing a $30 billion suite of secured projects and have five distinct platforms for future growth in Canadian, US and Mexico Natural Gas Pipelines, Liquids Pipelines, and Power and Storage.
Our overall financial position remains strong. We are well positioned to fund our secured capital program through resilient and growing internally generated cash flow, access to debt capital markets, the sale of our Ontario gas-fired power plants, along with the Coastal GasLink joint venture and project financing process. That ends my prepared remarks.
I'll now turn the call back over to David for Q&A.
David Moneta -- Vice President, Investor Relations
Thanks, Don. Just a reminder, before I turn it over to the conference coordinator for questions from the investment community, we ask that you limit yourself to two questions. If you have additional questions, please reenter the queue. With that, I'll turn it to the conference coordinator.
Questions and Answers:
Operator
[Operator Instructions] And the first question is from Linda Ezergailis from TD Securities. Please go ahead.
Linda Ezergailis -- TD Securities -- Analyst
Thank you. I'm wondering if you could just, maybe in advance of your Investor Day, give us a bit of a sneak peek in terms of where you're spending your business development time and where your focus is on opportunities? Clearly, the West Path Delivery announcement today is a significant new project, but I'm wondering how dispersed your opportunities are geographically across your various business platforms and how might we think of kind of the cadence of spend beyond this year evolving?
Russell K. Girling -- President and Chief Executive Officer
Linda, I will maybe take a first shot at that and supplement it by our business unit heads here, but I think what you're seeing in the West Path expansion is similar to what we're seeing across the system is demand for our services continues to be strong. As you know, it's difficult to build things in the current market environment, but demand for energy continues to grow, both domestically and in things like LNG export and getting that product to market continues to grow. So we see production increases and demand for our system. So just by way of example, I guess what I would first say is that I would expect our footprint to continue to generate these kinds of $500 million to $1.5 billion expansions in lots of pockets across the system, just give you few examples, obviously the demand for receipt capacity on the NGTL system continues to grow. And so we expect to see more capital we spent in that at that area. As demand for TC capacity grows, so does the demand for delivery capacity on our system. As you know, our main line has approximately 2 billion cubic feet a day to 3 billion cubic feet a day of Brownfield capacity that could be used to deliver that gas to market. So we see a potential expansion of that. And as well in Alberta as we migrate from coal-fired generation to gas-fired generation, and then to other industrial users that have been moving to the province both things like petrochemicals, fertilizers, gas, to oil kind of conversions, again demand for our systems on delivery capacity continues to grow.
As you move downstream, you're down from that across the country. Obviously, our view is that Marcellus/Utica will continue to grow as well In the longer term, but in the shorter term, getting that gas to markets that needed such as for example, the US Northeast and moving the gas back through our systems into Canada through Quebec and into the Northeast United States, New York, New England, obviously we have a pathway that's attractive to folks. And then as you can see is our-- as we've attached more markets and the largest growing market for Continental natural gas is offshore exports for LNG and we've done a great job of capturing a big chunk of that market through our Louisiana XPress and other projects that Chenier XPress that we have announced here recently, we expect that activity to continue.
Looking to Mexico, obviously Mexican natural gas demand will continue to grow. We've completed the Sur de Texas pipeline. I'd expect to see that continue to grow. So, everywhere I guess what I'd say is everywhere across our system where we can find an ability to expand the system to provide new capacity for customers, it appears that there is a demand for that capacity. So that's where we see the lion's share of our growth for the next two, three, four, five years to come from, and I expect it to come in those kinds of increments of field $500 million to $1.5 billion kind of dollar-sized projects and you get, if you few of those a year and offset and we're in a position where we have sufficient projects within our corridor, what we call organic growth and that meets the free cash flow that we have available to reinvest in our core businesses.
Linda Ezergailis -- TD Securities -- Analyst
Thank you. And maybe just specifically on your Liquids Pipelines, are you seeing some opportunities maybe to extend and pivot to more focus on exports there or any other incremental expansions you see there and maybe more broadly as you look at Keystone XL, some good progress being made on the regulatory and legal fronts, but maybe you can also give us an update on your thoughts to approaching the financing and mitigating any sort of last mile risk, and when might all those work streams come together to be able to make an FID on that potential project?
Paul Miller -- Executive Vice-President, Technical Centre and President, Liquids Pipelines
Linda. It's Paul here. On the first question around opportunities around export et cetera, our focus is growing and seeking opportunities around our existing footprint, right from Alberta all the way down to the US Gulf Coast. And part of that effort sees us enhancing our connectivity, both at the supply side and the market side. And as we make the pipeline that much more attractive from a market access and supply access perspective, it helps us greatly with our contracting efforts. It also makes our spot capacity that much more attractive to shippers and producers and to refiners.
Specifically around the export, there was a lot of opportunities for us to connect various export terminals in the US and those export facilities is just another example on what makes the Keystone and the other pipelines that much more attractive for shippers to access because they can realize and that higher net back on their volumes. In regards to Keystone XL, we continue to go through a number of processes here most on the legal and the regulatory side. On the recent events in the last quarter, the Nebraska Supreme Court affirmed the decision by the Public Service Commission to approve the route through the state, which means we now have a fully permitted route for Keystone XL. There remains a challenge to the 2019 Presidential permit hearing occurred last month and we would anticipate a decision on that hearing later this month. The State Department issued the draft Supplemental Environmental Impact statement in October. There are various open houses occurring for that statement and we expect the final environmental impact statement to be issued here before year-end.
With the issuance of the final Environmental Impact Statement, the Bureau of Land Management and the Army Corps of Engineers will finalize their decisions. And I would anticipate we would see their decisions being issued some time in Q1. We continue to work the various legal and the regulatory aspects of Keystone XL. As far as FID, we have to get these matters behind us. [Indecipherable] and I'll defer to Don in a moment on the financing side, but in regard to the last mile, Keystone XL remains a very important pipeline for Canadian and US producers, very important pipeline for US refiners and very important pipeline for Canada and the United States. US Gulf Coast is largest refining center in the world and it's significantly configured to run heavy crudes like those produced here in Canada and those refiners are seeing decline in supplies from traditional producers and they are looking and needing diversity of supply and Keystone XL will provide those supplies for them.
And that's evidenced by the contracting of Keystone XL, which is both producers and US refiners.
Donald R. Marchand -- Executive Vice President and Chief Financial Officer
Linda, it's Don here. With respect to the funding side, the key thing here the work streams that Paul referred to as getting permitting finalized here and we will continue to work the costing and scheduling under various scenarios, and as we progress toward an FID decision point. From a funding perspective, it remains all of the above. We'll look at everything from additional portfolio management. This project will probably bring some hybrid capacity, equity in some form, whether it be DRIP ATM, but potentially joint venture partners here would be an important component of that. And then as we assess the overall risk return parameters here, if that equation is positive, we will proceed, including all the risk elements we've talked about here. Looking at it holistically, we just continue to push on all these streams right now to get to a point and if the risk return for TC Energy is appropriate, we'll move forward.
Linda Ezergailis -- TD Securities -- Analyst
Thank you. I'll jump back in the queue.
Russell K. Girling -- President and Chief Executive Officer
Thanks, Linda.
Operator
The next question is from Robert Kwan from RBC Capital Markets. Please go ahead.
Robert Kwan -- RBC Capital Markets -- Analyst
Hey, good morning. Russ, you mentioned the ability to -- if you were able to secure a few these $500 million to say $1.5 billion type organic opportunities, that could, a, help you achieve your growth, but, b, you could fund that within your free cash flow. So I'm just wondering with the drip off now, is this really a signal that you see and have achieved a self-funding model say outside of something like Keystone XL?
Russell K. Girling -- President and Chief Executive Officer
Yeah, I think that's where we are today, Robert. Based on what we see in our portfolio coming at us over the next few years, we're comfortable that we're back to the place where we want to be, which was the self-funding model where we're not issuing common equity to fund our day-to-day business activities.
Donald R. Marchand -- Executive Vice President and Chief Financial Officer
Yeah, Robert. Again, we look at everything on a per share basis here. So, turning our share count growth right now is important and a signal to the market that we can get to that soft planning model of really balancing credit metrics, we expect to be in the high fours here and debt to EBITDA basis and 15% FFO to debt kind of range, which equates to our current credit ratings, maintaining payout ratios as we've historically done for the past couple of decades and then investing in these low-risk projects.
One thing I would note is as we do add new projects to the hopper, the permitting process is such where there is not any material spend generally for a couple of years on these things. So we do get visibility out a couple of years now as to when those dollars are going to be required, and we are comfortable here turning the drip off and managing to balance all these things going forward.
Robert Kwan -- RBC Capital Markets -- Analyst
Just to be clear, turning the drip off isn't just the -- I don't need the cash right here right now, so, I don't want to hit the share count, but say six months to nine months down the road, either it comes back on our ATM just if you all you're doing is this $500 million to $1.5 billion type stuff?
Donald R. Marchand -- Executive Vice President and Chief Financial Officer
Yes. If it's something larger transformational, we obviously reassess that, but what we see right now with our runway of projects, we think we're in that spot where we can live with an internally generated cash flow debt capacity within those credit metrics, and we still do have asset sale proceeds coming into the Ontario thermal plants in the first quarter of next year as well. The other thing we're looking at on Coastal GasLink is bringing in joint venture partners and project financing there. So when we look at this big picture wise, yeah, we are comfortable that we can balance all of these things and we can deliver on these various initiatives and we can avoid share count growth in the absence of something very large that comes along.
Russell K. Girling -- President and Chief Executive Officer
I think the key, Robert, is as Don pointed out, as you see in the West Path Delivery expansion into 2023 expansion, as we bring in new projects today, that's the kind of time frames we're looking forward to get through the regulatory process. You you'll get through permitting and then you will actually order equipment and getting to construction, you are out there 2023, 2024, 2025, and I think that's the positive of our system right now is it the existing corridors are the places where you can actually get these things done where you have your roads already built and the relationships with landowners in those kinds of things. So existing corridors, it seems to be where folks want to build these things. The unfortunate part about that is that from the time we get the request of service to the time we actually put it in this request for service till commencement of operations is now a 3 year to 4 year process which is longer than it's been historically. But that's just the fact of the length of the regulatory process as we now see in front of us. So, that's the sort of the turnaround time frame from conception to the cash flow.
Donald R. Marchand -- Executive Vice President and Chief Financial Officer
Yeah, I'll just add one more final comment here is in terms of share count growth, we'll always look at asset sales as well. You've seen us do $6.4 billion this year and sizable amounts in the past few years as well. So that's the other counterbalance here where we'll always look at portfolio management versus increasing share count, as we would have per share metrics.
Robert Kwan -- RBC Capital Markets -- Analyst
Got it. If I can just finish with the Mainline, I'm just wondering if you can outline the process as you see it unfolding for both the timeline as well as just anything you can talk about with the framework for post 2022?
Tracy Robinson -- Executive Vice-President and President Canadian Natural Gas Pipelines
Hey Robert, It's Tracy. We are continuing our dialog with customers, and I would say I'm optimistic that we will have an agreement of sorts and something to fall by late this year, early next year. We are completely aligned on -- from a principal perspective of using our mainline assets to support the basin and to reduce kind of that distance between the basin and the Eastern markets.
So the dialogs are going well. And as I said, I'd anticipate kind of later this year or earlier next year for us to come to a conclusion on that.
Robert Kwan -- RBC Capital Markets -- Analyst
Okay. And do you see that as being a bit of a bridging agreement or something bigger or something that could be more transformational than what we've seen historically?
Tracy Robinson -- Executive Vice-President and President Canadian Natural Gas Pipelines
You know we've had through this process a lot of conversations on those more transformational items. I don't think we're going to get there on this one, but we need to get this agreement done to give us that path to understand really what this Mainline is capable of, and I do see those conversations coming back as we get through this particular process.
Robert Kwan -- RBC Capital Markets -- Analyst
Great, thank you.
Russell K. Girling -- President and Chief Executive Officer
Thanks, Robert.
Operator
Thank you. The next question is from Jeremy Tonet from JPMorgan. Please go ahead.
Jeremy Tonet -- JPMorgan -- Analyst
Hi, good morning.
Russell K. Girling -- President and Chief Executive Officer
Good morning, Jeremy.
Jeremy Tonet -- JPMorgan -- Analyst
Just want to start off with a high level question as far as capital allocation process here. And in the press release, you talked about the potential for 8% to 10% distribution growth in 2021. And it seems like some in midstream overall kind of moderated that the growth that was going forward. And just wondering if you could refresh us as far as how you think about the rate of dividend growth versus other means of returning capital versus the right leverage level, how does that all come together, you know, decide that, what is the right level of dividend growth at this point?
Russell K. Girling -- President and Chief Executive Officer
I will take maybe a shot at the high level. Jeremy. I think our capital allocation philosophy has remained unchanged for 20 or so years and you [Indecipherable] to pay, first of all, you focus on the balance sheet making sure that we maintain the strongest balance sheet in our sector and that's the first sort of priority with respect to capital allocation.
Secondly, return of capital to shareholders via the dividend and historically that number has been about 40% of cash flow and approximately 80% of earnings plus or minus a bit, and taking 60% of it and reinvesting it in our core businesses to the extent that there are good opportunities on a risk-adjusted basis that we think will add shareholder value to the extent that those opportunities aren't available. Our philosophy that has been return of capital to our shareholders.
And then within there, how do we allocate capital between businesses and geographies and how compete for capital is really again unchanged as we try to high grade the projects across our system and that to the extent that we have more projects than our free cash flow. And then we look next to asset sales and then portfolio management to augment those. Most of the assets we have in our portfolio are solid good cash flowing assets, but to the extent that we see better platforms for future growth. So a good example of that is when we move to acquire Columbia and we saw the opportunity to exit the northeast power business and redeploy that capital back into a, what we saw was a longer-term growth set of assets in the Appalachian region, the Columbia Gas System sat on top of the fastest and lowest cost basin in North America, and we saw that as a good way to add shareholder value.
So that's basic philosophy of our capital allocation remains unchanged for transformational opportunities like Colombia. We are willing to access equity capital markets and our experience has been that our shareholders support us when we move on those transformational opportunities, but for the most part, our objective is to live within our means. And we've done that for most of that history of 20 years. Most recently when we went above that is when we acquired Columbia, when you think of that acquisition, it was a $13 billion acquisition, so it's CAD20 billion. And it had an $8 billion growth program included in. So you'll pick a number CAD30 billion plus our own, $10 billion or $15 billion growth program that we had. We saw that is all being very positive. We were able to lever our company up to about 6.5 times debt to EBITDA with a -- our primary focus is always around our balance sheet and a recognition from rating agencies and our commitment to them that we would bring our debt metrics back online, we committed to the levels that we have brought you today.
So through this process of growing earnings and cash flow over the last couple of years of the 8% to 10% growth that you mentioned, we've also delevered our balance sheet quite considerably. We feel that we're in a place now where we can grow within our means. But on a long-term basis, reinvesting our free cash flow into our core businesses. If we can get a return of about 8% after tax on those kind of investments, we can grow our business in a range of 5%, 6%, 7%, 8% and again looking back over our history over the last 20 years, you can see that by reinvesting our free cash flow in our businesses, we've grown earnings, cash flow and dividends per share at about that kind of rate, and the larger growth the 8% to 10% through 2021 was driven by an opportunity to reposition the company on, I guess, what I would call a higher level through that major acquisition of Columbia along with significant organic growth, and the filling up of our system, as I mentioned at the beginning of my opening remarks today. The demand for our system has never been greater and pretty much across most of our pipelines and our operating cash assets, everything's full and running at capacity. And again, those tailwinds have contributed to our growth in earnings and cash flow above those kind of historic levels in that 8% to 10% range. So we're very comfortable through 2021 and post 2021. I would expect you will go back to something more closely aligned with our historic metrics.
Donald R. Marchand -- Executive Vice President and Chief Financial Officer
Yeah. Jeremy, it's Don here. We'll give you more color and granularity at Investor Day, but the next decade, looking, shaping up a lot like the last couple of decades, and don't expect any real change in our risk preferences, our payouts, our philosophy, our keep-it-simple methodology here, I would just say that we're probably more utility-like than midstream-like in our thought process here. Earnings matter, we are not 95% payout on cash flow kind of guys here, so watch for more of the same.
Jeremy Tonet -- JPMorgan -- Analyst
That makes sense. And then maybe just building off on some of the comments there, with regards to transformational acquisition opportunities, seems like TRP has historically waited until there was stress in the market to be opportunistic there. Just wondering in the current marketplace as it is right now, do you see anything that fits your parameters as far as risk in return out there or any other comments you could share?
Donald R. Marchand -- Executive Vice President and Chief Financial Officer
I would say that the current time and we, there is some significant assets that we have it, we continue to monitor them as we always do. Nothing in that sort of fits what I'll call the risk return, kind of parameters, but there are very, very solid assets out there in the marketplace right now that we would see is very complementary to our business. And as you pointed out, our approach has always been one of, being financially disciplined. When those opportunities present themselves in a way and in an economic form, that adds value to our shareholders, then we're willing to act. And by doing that, I guess our view is that capital market support is when we want to go through those kinds of things.
Jeremy Tonet -- JPMorgan -- Analyst
Great, thanks for taking my questions.
Russell K. Girling -- President and Chief Executive Officer
Thanks, Jeremy.
Operator
Thank you. The next question is from Ben Pham from BMO. Please go ahead .
Ben Pham -- BMO Capital Markets -- Analyst
Okay, thanks, good morning. My first question maybe for Paul, I'm wondering just more of a near-term question, Q4 '19, just wondering what the direction of outlook is there on Keystone? How do you think this bill could impact the results and maybe just a comment on liquids marketing?
Paul Miller -- Executive Vice-President, Technical Centre and President, Liquids Pipelines
Hi Ben. I'll start with the impact of the spill first and then I'll speak to the liquids marketing, and I might even touch a little bit on market -- the pipe on the southern end of our system. On the spill, our teams are on-site and we have secured the site and contained the spill. At this time, we don't yet know the cause of the incident, but we will conduct a third-party assessment and learn the cause and make any necessary improvements to our integrity and maintenance programs. For now, it's little early to determine any financial impact, we will be providing updates on our website as we learn more and hope to give you a little more visibility on when we get to Investor Day.
On marketing, we had a good quarter on our marketing operations. We saw some good volume, good margins in Q3, probably up about $0.02 from Q2 and this higher result was a result of a number of factors. Marketing competes for capacity on various pipelines, those pipelines, which are offering good value because of various market differentials and they were able to secure capacity on some of these pipelines and realize on that differential. We also saw some Brent TI volatility, both at the beginning of the quarter, and toward the end of the quarter and captured some of that value and the performance I think it's just a reflection of continued evolution of our people and our programs.
I think Q4 will be softer, I think you'll see Q4 migrating back toward levels we saw in Q1 and Q2, but still $0.01 to $0.02 lower. And then going forward, 2020, I think there is still -- there's going to be some continued variability in the market differentials. I think you're going to see these differentials range trade throughout 2020 as we work through the new pipelines coming into the Permian, for example, and various line sale activities, which are occurring now, which is also having an impact on our market link operations. We had a softer quarter, but still strong volumes supported by our take-or-pay contracts. And as we've increased capacity over 2018 and 2019, we've been able to attract additional contracts to that system. attract additional contracts to that system. And so these contracts have and they will continue to provide stable cash flow. Where we saw some softness in Q3 was in our spot volume, but when I take a look at, for example, Q4 ,the net impact in this quarter of the higher contracts in the lower spot volume was under $0.02 versus Q2. And even though we will see continued variability, I think in the entire Path market, again, as these new Permian pipelines come into service and calls the line fill continue I think Q4, we'll see further softening, but will be supported by this higher level of contracts we've been able to secure over the last -- on our market link system.
Ben Pham -- BMO Capital Markets -- Analyst
Okay, thanks for that. And then on maybe one is for Don on the DRIP. I guess I'm wondering does the timing of it, how important was or is the course of in that analysis, because I guess you could have waited a month for so to get some visibility. I mean, that's 75% sale or 50 or a little bit less. I mean how should we be thinking about that?
Donald R. Marchand -- Executive Vice President and Chief Financial Officer
First, with respect to the JV process, we remain quite encouraged by the quality and the quantity of participation in that. So it's not a binary call on where that's at. What we're looking at is more bigger picture. We've got $8 billion of assets that's come into service. We've got $6.4 billion of asset sales this year. We believe our credit metrics are in line here. So it's a data point, but I wouldn't say it's the main driver of the decision to turn the DRIP off right now.
Ben Pham -- BMO Capital Markets -- Analyst
Okay, thanks. Thanks everybody.
Russell K. Girling -- President and Chief Executive Officer
Thanks, Ben.
Operator
Thank you. The next question is from Robert Catellier from CIBC Capital Markets. Please go ahead.
Robert Catellier -- CIBC Capital Markets -- Analyst
Hi, thank you. There is a lot of good commentary on your capital spending outlook. Just wanted to double check, confirm that I've heard the message, but it sounded like there is enough projects for you in the existing corridors to account for your free cash flow generation, is that correct?
Russell K. Girling -- President and Chief Executive Officer
That's what we're seeing right now. I mean, obviously it all hasn't materialized yet, but based on conversations with customers and inbound demands, it appears that we have a significant pipeline of new organic growth opportunities. It will extend this out the next number of years here.
Robert Catellier -- CIBC Capital Markets -- Analyst
Okay. And then to the extent that your capital spending includes projects that are outside the existing corridors, or maybe the regulatory process a little bit more challenging, is there an understanding in the industry that there needs to be a more balanced risk sharing mechanism, given how difficult it is to get these project approves, particularly on the regulatory side?
Russell K. Girling -- President and Chief Executive Officer
I think you've seen those kind of constructs you'll come forward on new projects. I mean, the West Coast Canadian LNG projects are a great example of the kind of constructs that are necessary to get through new corridors and to build the capacity to new markets. Those are hard work and heavy lifting and it requires your capacity of many credit-worthy and technically capable parties to actually make them happen. But those are examples of things that you can see, can come together and the kinds of constructs that are put together and make them happen.
Similarly, our pipeline through to Mexico, those are transformational for our company, but also for Continental flow of commodities and natural gas, in particular, and the kinds of constructs that you have to put together to make those work. So we think there is still out there, but obviously the marketplace -- your question is aware of the risks and how to mitigate manage those risks as a partnership as opposed to the kind of approaches we might have had historically.
Robert Catellier -- CIBC Capital Markets -- Analyst
Okay. And then just my last question here, are you in a position to quantify the potential financial impact from the Columbia rate settlement if it's approved as envisioned?
Stanley G. Chapman -- Chairman, TC PipeLines GP, Inc. Executive Vice-President and President, U.S. Natural Gas Pipelines T
Yeah, this is Stan. The Columbia Gulf settlement is actually going to be filed today. I think it is relatively straightforward. It's a black box settlement. What you're going to see is a big nameplate increase in terms of max rates increasing by about 20%, but keep in mind, particularly on the Columbia Gulf system, virtually all of our revenues are covered by negotiated or fixed rate contracts, so you're not necessarily going to see a big revenue bump. I would just say that the settlement was very much consistent with what we thought it was going to be, two-year moratorium, 7-year comeback, very straightforward.
Robert Catellier -- CIBC Capital Markets -- Analyst
Okay, thank you.
Operator
Thank you. The next question is from --
Russell K. Girling -- President and Chief Executive Officer
Thanks, Robert.
Operator
The next question is from Praneeth Satish from Wells Fargo. Please go ahead.
Praneeth Satish -- Wells Fargo -- Analyst
Hi, good afternoon. I'm just wondering what kind of demand for gas you're seeing in the Pacific Northwest region? Is the West Path Delivery project in GTN expansion, is that servicing new demand or just kind of displacing other pipelines in the region?
Stanley G. Chapman -- Chairman, TC PipeLines GP, Inc. Executive Vice-President and President, U.S. Natural Gas Pipelines T
So this is, Stan. I can take a start at that, I think of our GTN XPress expansion as at 250,000 a day, going all the way down to Merlin and is ultimately going to serve markets off of the PG&E systems. So I think you'll see a fair amount of gas on gas competition displacing gas that otherwise we come across from the Rockies, but great opportunity for us, it's an in-corridor expansion. It's a compression expansion, we're going to take out some old inefficient compression, put in some new units. That is going to increase reliability, it is going to decrease our Greenhouse gas footprint and provide the expansion capacity that the market needs.
Tracy Robinson -- Executive Vice-President and President Canadian Natural Gas Pipelines
Praneeth, I'll just add a little bit to that. This is a combination of a pull from the market that Stan is talking about and a push from producers. And I think tellingly its 3-year contract terms on average. So it's a pretty compelling statement about the attractiveness of that market.
Praneeth Satish -- Wells Fargo -- Analyst
Got it. And then on Coastal GasLink, can you just provide more details on what caused the cost increase? And then I guess what's your confidence level that cost won't continue to creep higher?
Tracy Robinson -- Executive Vice-President and President Canadian Natural Gas Pipelines
This $400 million is a combination of two things that you heard Russ mention. One is scope. So we've got incremental meter station and a few other things. And the other is raw quantities and water crossings. There was this section, if you will recall of this pie path that we couldn't access to some restrictions until this year, until we had FID and dealt with some of those issues. And so as we've been into that terrain now, the first pass suggested that there is more rock issues than we had in our estimates. And so the adjustment reflects that as well as a greater number of water crossings across the full pipe path. So this is an estimate at this point in time and we're going to be working very hard to mitigate that, but we have now been on the pipe path in its entirety and this is our best estimate at this time.
Praneeth Satish -- Wells Fargo -- Analyst
Okay, got it. Thank you.
Russell K. Girling -- President and Chief Executive Officer
Thanks Praneeth.
Operator
The next question is from Rob Hope from Scotiabank. Please go ahead.
Robert Hope -- Scotiabank -- Analyst
Good morning, everyone. Just hoping we could build on the comments on your crude export comments earlier on. If we pivot that over to gas, would you have any interest in potentially moving past just accessing the Gulf Coast with your gas network to potentially even holding some LNG capacity?
Donald R. Marchand -- Executive Vice President and Chief Financial Officer
I think under the right construct and obviously that's a business that probably has a similar contracting profile, credit profile to our existing business and under those scenarios which certainly have that capacity, we've looked at those kinds of things in the past and we'll continue to look at them in the future. It's a matter of having the right construct and the fit with our existing systems. So certainly something we would look at.
Robert Hope -- Scotiabank -- Analyst
All right. And then just as a follow-up to that. Would you look to do it in a kind of a smaller byte size manner or something larger there?
Donald R. Marchand -- Executive Vice President and Chief Financial Officer
Again, we look for the right opportunity. We have a large platform, we work with a number of folks as well that we are delivering natural gas to. And so we have conversations with folks at all sort of ends of the spectrum of a big and small. The key for us is fit, financial stability and growth potential and those kinds of things, and like the rest of our business, those are the kind of parameters it will have to compete for capital. Obviously, as we pointed out here earlier, there is a large demand for expansion along our systems. So there is a good call on capital today and new projects have to compete for capital within the company.
Robert Hope -- Scotiabank -- Analyst
Thank you.
Russell K. Girling -- President and Chief Executive Officer
Thanks, Rob.
Operator
The next question is from Matt Taylor from Tudor Pickering Holt. Please go ahead.
Matthew Taylor -- Tudor Pickering Holt -- Analyst
Hey, thanks for taking my questions here. Just can you provide an update on conversations with customers in the Northeast as capex budgets are coming down, growth has been revised lower, just curious if there has been any rate concessions there and kind of what's your expected impact to non-contracted earnings and future growth plans there?
Donald R. Marchand -- Executive Vice President and Chief Financial Officer
So I think what you're getting at is the health of producers overall, I would just say that the big picture-wise, we really don't have any significant concerns. When you look at our top 10 producer customers, for example, they are all flowing their contracts at very high load factors, which to me says that they're getting proper value out of their capacity and they all have a very strong acreage, which means that we believe that the molecules are in the ground are going to be produced for some time to come.
Matthew Taylor -- Tudor Pickering Holt -- Analyst
And have you made any rate concessions there in the Northeast?
Donald R. Marchand -- Executive Vice President and Chief Financial Officer
No, we haven't.
Matthew Taylor -- Tudor Pickering Holt -- Analyst
And then just going back to AECO there, it looks like there's been some life breezed back into AECO, can you maybe talk through if you think this will last into the summer months and then maybe just how this impacts discussions if you're seeing any impact of discussions on adding more mainline capacity as producers are seeing better pricing?
Tracy Robinson -- Executive Vice-President and President Canadian Natural Gas Pipelines
AECO has jumped in the last months, and there's all kinds of things that impact AECO pricing. And you know the summer is normally a very difficult time for AECO because 1.5 Bcf or 2 Bcf of market disappear in the Alberta area, and there is no place for that production to go. We have had difficulty in getting into storage as our system has become completely contracted on a firm basis, has made storage access a little bit difficult.
We did have, we did reach in general agreement with industry this summer that we should, that we would agree to kind of introduce a temporary variation in how we restrict, how we prioritize services on the NGTL system during the summer months. And while we are accessing the pipe for maintenance or capital expansion purposes and that just meaning that for a temporary period of time, we would prioritize interruptible service over our firm services to create that access to storage. So we think that that's probably had some of this impact, it's is very positive. We are now finished with that and we're going into November and into the winter season. I think we're well positioned for that. And we're hopeful that the demand this winter will support our continued strength in AECO pricing.
Without a doubt, we are seeing increased demand for the mainline. In fact, there is some capacity on the Mainline right now because the bottleneck is the NGTL capacity to get on to the Mainline until 2021 when we're finished with that expansion, but post 2021, most of the available capacity on the mainline is now being contracted. And so we are working with our customers on an expansion potentially if the main line in the future to facilitate even a greater access for the basins volumes into the eastern markets. But that will be a dialog we will have over the course of the next year or so.
Russell K. Girling -- President and Chief Executive Officer
And Matt, just to add on to that is that we will work very hard in all of our basins to optimize our systems to be able to move as much gas as we can. And in doing that, hopefully improving the economics of our upstream producers. Our focus has been longer term, and if you can take a look of what we're doing longer term, we believe in the long-term economics of the basin. The gas in the Western Sedimentary Basin and Appalachia, we believe is the low-cost gas, which will compete extremely well in the marketplace over the long haul. With all the expansions we have under way on NGTL right now, we're increasing the delivery capacity by about 3.5 billion cubic feet a day over the time frame that Tracy mentioned. And that's going south and it's going East and it's going West and we'll continue to look at that on top of that with the coastal gasoline project, we're going to add another 2 billion cubic feet a day delivery capacity, so 5 billion cubic feet a day or so of delivery capacity coming out of the basin.
And it's underpinned by more of the market fundamentals in the long term that liquids rich gas coming out of the major plays in Western Canada will compete well. And as we pointed out, as Stan pointed out, if you think about things like Pacific Northwest in California, there isn't that much new incremental demand, but obviously Canadian gas is competing for market share. And with 30-year contracts, it appears that there is great confidence that the basin will continue to grow into that 3.5 billion cubic feet a day of capacity that we made available. And if we can make available anymore, I think Canadian gas will compete very well into all of those marketplaces.
Matthew Taylor -- Tudor Pickering Holt -- Analyst
Just to clarify, Tracy, when you say Mainline contract, did you need to add more or invest more NGTL dollars to add more mainline capacity or do you already have enough NGTL egress to get them?
Tracy Robinson -- Executive Vice-President and President Canadian Natural Gas Pipelines
Once we finish, as you know, Matt, we have a considerable expansion program under way on the NGTL system and a big chunk of that comes into service in 2021, which should give us enough access of NGTL into the Mainline to think about how we get more volumes down that system.
Matthew Taylor -- Tudor Pickering Holt -- Analyst
Great, that's helpful. Thank you.
Russell K. Girling -- President and Chief Executive Officer
Thanks Matt.
Operator
Thank you. The next question is from Shneur Gershuni from UBS, please go ahead.
Unidentified Participant
Good morning, this is [Indecipherable] calling in for Shneur Gershuni. How confident is management with the progress on Keystone XL FID now versus the last earnings call and how goes with the recent development? And the US administration changes, do you feel there are protections in place?
Paul Miller -- Executive Vice-President, Technical Centre and President, Liquids Pipelines
Hi, it's Paul Miller here. We progressed Keystone XL over the last quarter. When you look back, going into Q3, there was uncertainty around the route in Nebraska, there was uncertainty around the issuance for example of the Draft Supplemental Environmental Impact Statement. Since then the Nebraska Supreme Court has affirmed the Public Service Commission's approval of the well. So we are fully approved in the state and all the jurisdictions in which the pipeline will be cited.
We have received the draft environmental impact statement, the review of that environmental impact statement is under way and we anticipate getting it finalized here by year-end and then we would look to see the Bureau of Land Management and the Army Corps issue their decisions in Q1. Ultimately our comfort level is going to revolve around getting these various legal and regulatory proceedings behind us before we commit to move forward on FID.
I'm sorry. And then the second part of your -- I think was in regard to last mile, we had some change in administration and our focus is managing the legal, the regulatory and project management activities. Keystone XL remains a very important pipeline for the industry and a very important pipeline for Canada and the United States. It is fully contracted by both Canadian and US interest, and as a result, I think that the merits of the pipeline are well established and well understood and we will continue to focus on the legal, the regulatory and the project management activities.
Russell K. Girling -- President and Chief Executive Officer
Thanks.
Operator
Thank you. The next question is from Patrick Kenny from National Bank Financial. Please go ahead.
Patrick Kenny -- National Bank Financial -- Analyst
Hey, good morning. Just with the NGTL expansion, was curious to get your thoughts on dealing with the new CER relative to the NEB, if we should be expecting any material change in the regulatory process?
Tracy Robinson -- Executive Vice-President and President Canadian Natural Gas Pipelines
The West Path expansion, Patrick, is one that will fall under the new CR process. Our current -- all of the rest of the NGTL expansion that we have under way will follow as you know, under the old kind of NEB rules and processes. So we've been working around what you expect on this and we're optimistic in fact. So this falls underneath the level of an expansion that would trigger the Impact Assessment agency review and it is an expansion of two separate assets. So we believe that we are optimistic that this process should run generally in line with the timeline that we would have seen under the former NEB rules and procedures.
Having said that, it's new to us. We are working through it, it's new to all of our stakeholders who are also working through it. So we will have to see how this goes.
Patrick Kenny -- National Bank Financial -- Analyst
Okay, great. Appreciate that. And then just on the Alberta power market here, was interested to see you guys sign an agreement for renewable power. I was just curious maybe a little bit of background on that and then also just your overall view with respect to your remaining Alberta power assets and the market in general?
Francois Poirier -- Executive Vice-President, Corporate Development and Strategy, and President, Power & Storage and Mex
Patrick, it's Francois. I'll be happy to take that question. That transaction obviously was very modest size, but complementary to our existing trading business. It was an opportunity to acquire attractively priced energy and remarket it. And really capital-light way for us to invest in the solar resource in Alberta. We like the Alberta market, we supported the reaffirmation of the energy-only market. We believe in the fundamental merits of all of our Cogencis facilities in Alberta and we would look at for opportunities to invest more capital along similar constructive, the opportunity presents itself.
Patrick Kenny -- National Bank Financial -- Analyst
Got it. Thanks everybody.
Russell K. Girling -- President and Chief Executive Officer
Thanks, Pat.
Operator
Thank you. 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 back over to Mr. Moneta. Please go ahead.
David Moneta -- Vice President, Investor Relations
Okay, thanks very much. We very much appreciate your interest in TC Energy, and we look forward to speaking to you again soon. Bye for now.
Operator
[Operator Closing Remarks]
Duration: 81 minutes
Call participants:
David Moneta -- Vice President, Investor Relations
Russell K. Girling -- President and Chief Executive Officer
Donald R. Marchand -- Executive Vice President and Chief Financial Officer
Paul Miller -- Executive Vice-President, Technical Centre and President, Liquids Pipelines
Tracy Robinson -- Executive Vice-President and President Canadian Natural Gas Pipelines
Stanley G. Chapman -- Chairman, TC PipeLines GP, Inc. Executive Vice-President and President, U.S. Natural Gas Pipelines T
Francois Poirier -- Executive Vice-President, Corporate Development and Strategy, and President, Power & Storage and Mex
Linda Ezergailis -- TD Securities -- Analyst
Robert Kwan -- RBC Capital Markets -- Analyst
Jeremy Tonet -- JPMorgan -- Analyst
Ben Pham -- BMO Capital Markets -- Analyst
Robert Catellier -- CIBC Capital Markets -- Analyst
Praneeth Satish -- Wells Fargo -- Analyst
Robert Hope -- Scotiabank -- Analyst
Matthew Taylor -- Tudor Pickering Holt -- Analyst
Unidentified Participant
Patrick Kenny -- National Bank Financial -- Analyst
