TC Energy Corp

TSX:TRP

Earnings Call Transcript 2019-Q3

[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 of 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, U.S. 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 and 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 she'd be happy to address your questions. [Operator Instructions] 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 would be pleased to discuss them with you following the call. Before Russ begins, I'd like to remind you that our remarks today will include forward-looking statements that are subject to important risks and uncertainties. For more information on these risks and uncertainties, please see the reports filed by TC Energy with Canadian securities regulators and with the U.S. Securities 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, CEO & Director]

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 continue 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 constructs 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 9 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 3 months ended September 30, 2019, increased 4% over the same period in 2018, while comparable funds generated from operations of approximately $1.8 billion or 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, work continues on more than $20 billion of projects under development, including Keystone XL and the refurbishment of another 5 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 certain -- as well as the sale of certain Columbia Midstream assets in the Appalachia 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 a 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 under -- 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 were $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% comparable earnings and 45 -- 40% of comparable funds generated from operations, leaving us with significant internally generated cash flow to continue to invest in our core businesses. Next, a few comments on our 5 operating businesses. First, in Canadian Natural Gas Pipelines, customer demand for access to our systems remained 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 million cubic feet per day 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 as the fourth quarter of 2021, with in-source 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 USD 335 million GTN XPress project is integrated -- 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 tools. Construction activities continue in 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 a sale of up to 75% ownership and project financing. Both of those transactions are proceeding as planned. Moving to our U.S. Natural Gas Pipelines, where demand for our services reached record levels during this year. As highlighted previously, our broad network has historically served approximately 25% of U.S. demand on a daily basis. In addition to moving those volumes, our existing systems -- on our existing systems, during the quarter, we continued to advance our $1.1 billion U.S. Modernization II program on the Columbia Gas system as well as another USD 1.5 billion of other capacity additions that now include the GTN XPress project, along with our previously announced Louisiana XPress project, the Grand Cheniere XPress project and the Eastern Lateral XPress project (sic) [ East 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 low-cost, clean-burning U.S. 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 2 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. Well, 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 U.S. 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 the liquids business, we continue to advance the Keystone XL pipeline project. In March, the -- U.S. President Trump issued a new Presidential Permit for the project, which superceded the 2017 permit and resulted in a dismissal of the cases related to the old permit. In August, Nebraska Supreme Court affirmed the -- their 2017 decision that approved the Keystone XL pipeline route through the State of Nebraska. A motion for recurring of that decision by the Supreme Court was denied. In addition, on October 4, the U.S. 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. Including -- included in that new SEIS is the routing 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're 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 the Portlands Energy Center 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 6 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 marketplaces. 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. And it's 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 would 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 5 significant platforms for growth: Canadian, U.S. and Mexican Natural Gas Pipelines; our Liquids Pipeline business; and Power and Storage. Just as we have done since 2000, we -- 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'll provide some more details on our third quarter results. Don?

[Donald R. Marchand, Executive VP & CFO]

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, an 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 U.S. 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 $907 million or $1.04 per share in third quarter 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 aftermarket program in 2018, all of which were in support of our growth and credit metrics. These positive results reflect continued progress, placing new assets into service as well as operational strength and solid cash generation across all our businesses. Turning to our business segment results on Slide 15. In the third quarter, comparable EBITDA from our 5 operating businesses was approximately $2.3 billion, representing a $288 million or 14% increase from 2018. Canadian Natural Gas Pipelines comparable EBITDA of $572 million 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 -- in 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 effect 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 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 third quarter 2019. We did not record incentive earnings in the third quarter of 2018, pending the outcome of the Canadian Mainline 2018-2020 toll review. U.S. Natural Gas Pipelines comparable EBITDA of USD 604 million or CAD 796 million in the quarter increased by USD 57 million or CAD 81 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 USD 115 million or CAD 153 million was consistent with third quarter 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 third quarter 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 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 interest 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 U.S. dollar-denominated income, including U.S. Natural Gas Pipelines, Mexico Natural Gas Pipelines and parts of our Liquids Pipelines business, Canadian dollar-translated EBITDA was positively impacted by a stronger U.S. dollar versus third quarter 2018. This was largely offset by higher translated interest expense on U.S. dollar-denominated debt and realized hedging losses reported in comparable interest income and other. Regarding our exposure to foreign exchange rates, a sizable portion of our U.S. dollar-denominated assets are hedged with U.S. dollar-denominated debt. We continue to actively manage the residual exposure on a rolling 1-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 2018 largely as a result of new facilities entering service across our businesses, higher composite depreciation rates approved in the Mainland NEB 2018 decision and a stronger U.S. 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 Bison asset impairment. Interest expense included in comparable earnings of $573 million for third quarter 2019 was consistent year-over-year. AFUDC for the 3 months ended September 30, 2019, declined by $27 million compared to the same period in 2018. A $43 million decrease in U.S. 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 third quarter 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 rate-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 U.S. 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 noncontrolling interest of $59 million for the 3 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 nonrecoverable 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 a coverage ratio of 2.4x. 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 USD 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 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 continued 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 USD 1.3 billion or CAD 1.7 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, continued to provide incremental subordinated capital in support of our growth and credit metrics in the third quarter, with a participation rate amongst common shareholders of approximately 35%, representing $247 million of dividend reinvestment. For the first 3 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 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 manner 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 4s without recourse to 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 noncontrolling 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 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 5 distinct platforms for future growth in Canadian, U.S. 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 processes. That ends my prepared remarks. I'll now turn the call back over to David for Q&A.

[David Moneta, Vice President of Investor Relations]

Thanks, Don. [Operator Instructions] With that, I'll turn it to the conference coordinator.

[Operator]

[Operator Instructions] And the first question is from Linda Ezergailis from TD Securities.

[Linda Ezergailis, Research Analyst]

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, CEO & Director]

I think I'll 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. And maybe I'll just give you a few examples. Obviously, the demand for receipt capacity on the NGTL System continues to grow, and so we expect to see more capital to be spent in that area. As demand for receipt capacity grows, so does the demand for delivery capacity on our system. As you know, our Mainline has approximately 2 billion 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 as well in Alberta as the -- 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 and delivery capacity continues to grow. As you move downstream, 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 need it, such as for example, the U.S. Northeast, moving the gas back through our systems into Canada through Québec 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 -- as we've attached more markets, they're the largest growing market for continental natural gas use offshore exports for LNG, and we've done a good 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's a demand for that capacity. So that's where we see the lion's share of our growth for the next 2, 3, 4, 5 years to come from. And I expect it to come in those kinds of increments of $500 million to $1.5 billion kind of dollar size projects. And you get a few of those a year. And all of a sudden, we're in a position where we have sufficient projects within our corridor, what we call organic growth, that meets the free cash flow that we have available to reinvest in our core businesses.

[Linda Ezergailis, Research Analyst]

And maybe just specifically on your Liquids Pipelines, are you seeing some opportunities maybe to extend and pivot to more focused on exports there? Or any other incremental expansions you see there? And maybe more broadly, as you look at Keystone XL, some good progress made on the regulatory and legal front, 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 E. Miller]

Linda, it's Paul here. I'll -- on the first question around opportunities on export, et cetera, our focus is growing and seeking opportunities around our existing footprint right from Alberta all the way down to the U.S. 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 to producers and to refiners. Specifically around the export, there is a lot of opportunities for us to connect to various export terminals in the U.S., 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 a net -- a higher netback on their volumes. In regard 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. A 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 sometime 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. In regard to the last mile risk, and I'll defer to Don in a moment on the financing side, but in regard to the last mile risk, Keystone XL remains a very important pipeline for Canadian and U.S. producers. It's a very important pipeline for U.S. refiners and a very important pipeline for Canada and the United States. U.S. Gulf Coast is the 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 declining 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 U.S. refiners.

[Donald R. Marchand, Executive VP & CFO]

Linda, it's Don here. With respect to the funding side, the key thing here are the work streams that Paul referred to as getting permitting finalized here. And we'll continue to work the costing and scheduling under various scenarios and as we progress towards 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 would 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. So 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.

[Operator]

The next question is from Robert Kwan from RBC Capital Markets.

[Robert Michael Kwan, Analyst]

Russ, you mentioned the ability to -- if you were able to secure a few of 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, CEO & Director]

Yes. 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. And I'll ask Don to comment.

[Donald R. Marchand, Executive VP & CFO]

Yes, Robert. Again, we look at everything on a per-share basis here. So turning off share count growth right now is important and a signal to the market that we can get to that self-funding model of really balancing credit metrics: We expect to be in the high 4s here on a debt-to-EBITDA basis and a 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's 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 Michael Kwan, Analyst]

Got it. But 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 6 or 9 months down the road, either it comes back on or ATM, just if all you're doing is this $500 million to $1.5 billion-type stuff? .

[Donald R. Marchand, Executive VP & CFO]

Yes. If it's something large or transformational, we'd 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 within internally generated cash flow, debt capacity within those credit metrics. And we still do have asset sale proceeds coming in from 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, yes, we are comfortable that we can balance all 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, CEO & Director]

I think is the key, Robert, is as Don pointed out, as you see in the West Path Delivery expansion, it's a 2023 expansion. As we bring in new projects today, that's the kind of time frames we're looking for to get through the regulatory process, you'll get through permitting and then you'll actually order in equipment and getting to construction, we're out there in '23, '24, '25. And I think that's the positive of our system right now, is that the existing corridors are the places where you can actually get these things done, where you have roads already built and the relationships with landowners and those kinds of things. So you just think corridors 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- to 4-year process, which is longer than it's been historically. But that's just the fact of the length of regulatory processes we now see in front of us. So that's the sort of the turnaround time frame from conception to cash flow.

[Donald R. Marchand, Executive VP & CFO]

Yes. 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, we'll always look at portfolio management versus increasing share count as we look at per-share metrics.

[Robert Michael Kwan, 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 time line as well as just anything you can talk about with the framework for post-2020 tolls.

[Tracy A. Robinson]

Robert, it's Tracy. We are continuing our dialogues 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 principle 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 dialogues are going well. And as I said, I'd anticipate kind of later this year, earlier next year for us to come to a conclusion on that.

[Robert Michael Kwan, Analyst]

Okay. And do you see that as being a bit of a bridging agreement to something bigger or something that could be more transformational than what we've seen historically?

[Tracy A. Robinson]

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.

[Operator]

The next question is from Jeremy Tonet from JPMorgan.

[Jeremy Bryan Tonet, Senior Analyst]

Just want to start off with a high-level question as far as capital allocation philosophy here. And in the press release, talked about the potential for 8% to 10% distribution growth in 2021. And it seems like some in midstream overall kind of moderated that growth outlook 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 levels. How does that all come together and decide that, what is the right level of dividend growth at this point?

[Russell K. Girling, President, CEO & Director]

I'll take maybe a shot it at the high-level, Jeremy is it -- I think our capital allocation philosophy has remained unchanged for 20-or-so years. And at its core, it's to pay -- first of all, 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, is 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 has always been return of capital to our shareholders. And then within there, how do we allocate capital between businesses and geographies and how to compete for capital is really, again, unchanged, is where we try to high-grade the projects across our system. And to the extent that we have more projects that -- than our free cash flow, then we look next to asset sales and 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 moved to acquire Columbia. We saw the opportunity to exit the Northeast Power business and redeploy that capital back into 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, lowest-cost basin in North America. And we saw that as a good way to add shareholder value. So that's -- the basic philosophy of our capital allocation remains unchanged. For transformational opportunities like Columbia, 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. And when you think of that acquisition, it was a USD 13 billion acquisition, so it's CAD 20 billion-ish, and it had an USD 8 billion growth program included in. So pick a number, CAD 30 billion, plus our own $10 billion or $15 billion growth program that we had, we saw that as all being very positive. We were able to lever our company up to about 6.5x debt-to-EBITDA with a recognition that our primary focus is always around our balance sheet and a recognition from rating agencies and a commitment to them that we would bring our debt metrics back on line. We committed to the levels that we have got to today. So through this process of growing, producing 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 at 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 assets, everything is 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 to go back to something more closely aligned with our historic metrics.

[Donald R. Marchand, Executive VP & CFO]

Yes. Jeremy, it's Don here. We'll give you more color and granularity at Investor Day. But the next decade is 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're not 95% payout on cash flow kind of guys here. So watch for more of the same.

[Jeremy Bryan Tonet, Senior Analyst]

That makes sense. And then maybe just building off 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 in -- as far as risk and return out there? Or any other comments you could share? .

[Russell K. Girling, President, CEO & Director]

I would say that at the current time -- and we, there's some significant assets that we covet. We continue to monitor them as we always do. Nothing in -- that sort of fits what I would 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 as 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 markets support us when we want to go do those kinds of things.

[Operator]

The next question is from Ben Pham from BMO.

[Benjamin Pham, Analyst]

Okay. My first question, maybe for Paul. Wondering -- just more of a near-term question, Q4 '19, just wondering what the directional outlook is there on Keystone. How do you think the spill could impact the results? And maybe just a comment on liquids marketing.

[Paul E. Miller]

Okay, 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 Marketlink, 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 a 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 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 a couple cents 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 towards the end of the quarter, and captured some of that value. And the performance, I think, is 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 towards levels we saw in Q1 and Q2, but still $0.01 to $0.02 lower. And then going forward, 2020, I think there's still -- there's going to be some continued variability in the market differentials. I think you're going to see these differentials range trade around 2020 as we look through the new pipelines coming into the Permian, for example; and various line-fill activities which are occurring now, which is also having an impact on our Marketlink 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 to 2019, we've been able to 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 and the lower spot volume was under $0.02 versus Q2. And even though we'll see continued variability, I think, in the entire Pad 3 market, again, as these new Permian pipelines come into service and, cause the line fill continue, I think Q4 will see further softening but will be supported by this higher level of contracts we've been able to secure over the last -- on our Marketlink system.

[Benjamin Pham, Analyst]

Okay. And then on -- maybe a second one for Don on the DRIP. I guess I'm wondering just the timing of it. How important was -- or is the Coastal sale is in that analysis? Because I guess you could have waited a month or so to get some visibility. I think that's 75% sale or 50% or a little bit less. I mean how -- like how should we be thinking about that? .

[Donald R. Marchand, Executive VP & CFO]

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 whether and where that's at. What we're looking at is more bigger-picture. It's -- we've got $8 billion of assets that have 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.

[Operator]

The next question is from Robert Catellier from CIBC Capital Markets.

[Robert Catellier]

There was a lot of good commentary on your capital spending outlook. I just wanted to double check, confirm that I've heard the message. But it sounded like there's enough projects for you in the existing corridors to account for your free cash flow generation. Is that correct?

[Russell K. Girling, President, CEO & Director]

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 demand, it appears that we have a significant pipeline of new organic growth opportunities that will extend this out the next number of years here.

[Robert Catellier]

Okay. And then to the extent that your capital spending includes projects that are outside the existing corridors or maybe the regulatory process is 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, CEO & Director]

I think you've seen those kind of constructs 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 capacity to new markets. It's -- those are hard work and heavy lifting, and it requires capacity of many sort of creditworthy 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 to make them happen. Similarly, on 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 they're still out there. But obviously, the marketplace, to your question, is aware of the risks and how to mitigate and manage those risks as a partnership as opposed to the kind of approaches we might have had historically.

[Robert Catellier]

Okay. And then my -- 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 Graham Chapman]

Yes. This is Stan. The Columbia Gulf settlement is actually going to be filed today. Think of it as 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: 2-year moratorium, 7-year comeback, very straightforward.

[Operator]

Your next question is from Praneeth Satish from Wells Fargo.

[Praneeth Satish, Senior Equity Analyst]

I'm just wondering what kind of demand for gas you're seeing in the Pacific Northwest region. Is the West Path delivery project and GTN expansion, is that servicing new demand or just kind of displacing other pipelines in the region?

[Stanley Graham Chapman]

So this is Stan. I could take a start at that. Think of our GTN Express expansion as a 250,000 a day, going all the way down to Malin and is ultimately going to serve markets off of the PG&E system. So I think you'll see a fair amount of gas-on-gas competition, displacing gas that otherwise would 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's going to decrease our greenhouse gas footprint and provide the expansion capacity that the market needs.

[Tracy A. Robinson]

Praneeth, I'll just add a little bit to that. This is a combination of a pull from the market that Stan's talking about and the push from producers. And I think tellingly, it's 30-year contract terms on average. So it's a pretty compelling statement about the attractiveness of that market.

[Praneeth Satish, Senior Equity 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 costs won't continue to creep higher?

[Tracy A. Robinson]

This $400 million is a combination of 2 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 rock quantities and water crossings. So there was a section, if you will recall, of this pipe path that we couldn't access due 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 path has suggested that there's more rock issues than we had in our estimates. And so this adjustment reflects that as well as a greater number of water crossings across the full pipe path. So this is an estimate at that 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.

[Operator]

The next question is from Rob Hope from Scotiabank.

[Robert Hope, Analyst]

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?

[Russell K. Girling, President, CEO & Director]

I think under the right construct. Obviously, that's a business that probably has a similar contracting profile, credit profile to our existing business. And under those scenarios, we'd 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 just a matter of having the right construct and the fit with our existing systems. So certainly something we'd look at.

[Robert Hope, Analyst]

All right. And then just as a follow-up to that, would you like to do it in a kind of a smaller, bite-sized manner or something larger there?

[Russell K. Girling, President, CEO & Director]

Again, we look for the right opportunity. We have a large platform, but we are -- we work with a number of folks as well that we're delivering natural gas to. And so we have conversations with folks at all sort of ends of the spectrum of big and small. The key for us is fit, financial stability, growth potential and those kinds of things. And like the rest of our business, those would be the kind of parameters. It'll have to compete for capital. Obviously as we pointed out here earlier, there's a large demand for expansion along our systems. So there's a good call on capital today, and new projects have to compete for capital within the company.

[Operator]

Your next question is from Matt Taylor from Tudor, Pickering, Holt.

[Matthew Taylor, Director of Midstream Research]

Just can you provide an update on conversations with customers in the Northeast? As CapEx budgets are coming down, growth is being 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 VP & CFO]

So I think if what you're getting at is the health of producers overall, I would just say that, big picture-wise, we really don't have any significant concerns. When you look at our top 10 producer customers, for example, they're 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 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, Director of Midstream Research]

And have you made any rate concessions there in the Northeast?

[Russell K. Girling, President, CEO & Director]

No. No, we haven't.

[Matthew Taylor, Director of Midstream Research]

And then just going back to AECO there. It looks like there's been some life breathed 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 to discussions on adding more Mainline capacity as producers are seeing better pricing.

[Tracy A. Robinson]

Yes, AECO has jumped in the last months. And it is all kinds of things that impact AECO pricing. And the summer is normally a very difficult time for AECO because 1.5 or 2 Bcf of market disappear in the Alberta area, and there's no place for that production to go. We -- it has had difficulty in getting into storage as our system has become completely contracted on a firm basis, which has made storage access a little bit difficult. We did have -- we did reach a general agreement with industry this summer that we should -- that we would agree to -- kind of introduce a temporary variation in how we restrict -- or 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 very positive. We are now finished 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 continued strength in AECO pricing. Without a doubt, we are seeing increased demand for the Mainline. In fact, there's some capacity on the Mainline right now because the bottleneck is the NGTL capacity to get onto the Mainline until 2021 when we're finished that expansion. But post 2021, most of the available capacity in the Mainline has been contracted. And so we are working with our customers on an expansion potentially of the Mainline in the future to facilitate even a greater access for the basin's volumes into the eastern markets. But that will be a dialogue we'll have over the course of the next year or so.

[Russell K. Girling, President, CEO & Director]

Matt, just to add onto 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 the longer term. And if you can take a look at what we're doing longer term. We believe in the long-term economics of the basin, that 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 underway in -- 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 GasLink project, we're going to add another 2 billion cubic feet a day of delivery capacity. So 5 billion cubic feet a day or so of delivery capacity coming out of the basin. And it's underpinned by the -- more of the market fundamentals in the long term, that this liquids-rich gas coming out of the major plays in Western Canada will compete well. And as we pointed out, as Stan pointed out, as you think about things like Pacific Northwest and 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's great confidence that the basin will continue to grow into that 3.5 billion cubic feet a day of capacity that we've made available. And if we can make available any more, I think Canadian gas will compete very well into all of those marketplaces.

[Matthew Taylor, Director of Midstream Research]

Just to clarify, Tracy, when you say Mainline is fully contracted, do 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 the inputs?

[Tracy A. Robinson]

Once we finish -- as you know, Matt, we have a considerable expansion program underway on the NGTL system. And a big chunk of that comes into service in 2021, which should give us enough access off NGTL into the Mainline to think about how we get more volumes down that system.

[Operator]

The next question is from Shneur Gershuni from UBS.

[Unknown Analyst]

This is [ Agasha ] calling in for Shneur Gershuni. How confident is management with the progress on Keystone XL FID now versus last earnings call in August with the recent development? And if the U.S. administration changes, do you feel there are protections in place?

[Paul E. Miller]

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 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 route. So we are fully approved in the state and all the jurisdictions in which the pipeline will be sited. We have received the draft environmental impact statement. The review of that environmental impact statement is underway, and we anticipate getting it finalized here by year-end. And then we'll look to see the Bureau of Land Management and the Army Corp. 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 an FID. Oh, I'm sorry. And then the second part of U.S., I think it was in regard to last-mile with 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 U.S. interests. And as a result, I think 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.

[Operator]

The next question is from Patrick Kenny from National Bank Financial.

[Patrick Kenny, Managing Director]

Just with the NGTL expansion. I was curious to get your thoughts on dealing with the new CER relative to the NBE, if we should be expecting any material change in the regulatory process.

[Tracy A. Robinson]

This -- the West Path expansion, Patrick, is one that will fall under the new CER process. Our current -- all of the rest of the NGTL expansion that we have underway will follow, as you know, under the old kind of NEB rules and processes. So we've been working around what to 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 2 separate assets. So we believe that -- we're optimistic that this process should run generally in line with the time line that we would have seen under the former NEB rules and procedures. Having said that, it's new to us. We're 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, Managing Director]

Okay. Great. I appreciate that. And then just on the Alberta power market here, was interested to see you guys sign an offtake 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 Lionel Poirier, Executive VP]

Patrick, it's Francois, I'll be happy to take that question. That transaction obviously was very modest-sized, but complementary to our existing trading business. It was an opportunity to acquire attractively priced energy and remarket it; and really, a capital-light way for us to invest in a 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 co-gen facilities in Alberta, and would look for opportunities to invest more capital along a similar construct if the opportunity presented itself.

[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 of 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]

Thank you. The conference has now ended. Please disconnect your lines at this time, and thank you for your participation.