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TC Energy Corp
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Good day, ladies and gentlemen. Welcome to the TransCanada Corporation 2017 Fourth 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.
Thanks very much, and good afternoon, everyone. I'd like to welcome you to TransCanada's 2017 Fourth Quarter Conference Call. With me today are Russ Girling, President and Chief Executive Officer; Don Marchand, Executive Vice President and Chief Financial Officer; Karl Johannson, President of Canada and Mexico Natural Gas Pipelines and Energy; Stan Chapman, President, U.S. Natural Gas Pipelines; Paul Miller, President, Liquids Pipelines; and Glenn Menuz, Vice President and Controller.Russ and Don will begin today with some opening remarks on our financial results and certain other company developments. Our comments may be a little longer this afternoon as we will also touch on our 2018 outlook.A copy of the slide presentation that will accompany their remarks is available on our website. It can be found in the Investors section. Following their prepared remarks, we will take questions from the investment community. If you are a member of the media, please contact Mark Cooper or Grady Semmens following this call, and they'd be happy to address your questions. [Operator Instructions]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 TransCanada with Canadian securities regulators and with the U.S. Securities and Exchange Commission.And finally, I'd also like to point out that 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 TransCanada's operating performance, liquidity and its ability to generate funds to finance its operations.With that, I'll turn the call over to Russ.
Thanks, David, and good afternoon, everybody, and thank you very much for joining us today. It's hard to believe another year has passed, but as outlined earlier today in our fourth quarter news release, 2017 was a very successful year for our company. In addition to delivering record financial results, we did make significant progress on a number of other fronts that will position us for continued growth and success.First of all, we completed the integration of the Columbia Pipeline Group, and we are on track to realize the USD 250 million of annual synergies that we targeted at the time of acquisition. We also acquired the Columbia Pipeline Partners for $1.2 billion, giving us 100% ownership in Columbia's core assets and again simplifying our corporate structure. We also completed the sale of our U.S. Northeast Power assets and repaid the Columbia bridge loan facilities. And we continued to advance our $23 billion near-term capital program by placing approximately $5 billion of assets into service.Also in '17, we replenished our growth portfolio by adding more than $3 billion of Canadian and U.S. Natural Gas Pipeline expansions to our inventory of commercially secured projects. And earlier today, we announced another $2.4 billion expansion program on the NGTL System. In addition, we also advanced our over $20 billion of medium to longer-term projects, including the Keystone XL pipeline, the Coastal GasLink pipeline and the Bruce Power life extension program.And finally, we successfully funded a $9.2 billion capital program by raising substantial money across the capital spectrum on very compelling terms. It included more than $6 billion long-term debt and hybrid securities in Canada and the United States. In addition, we completed a drop-down of TC PipeLines, LP for USD 765 million, and we realized another $1.1 billion through the recovery of our development costs on the PGRT pipeline and on the sale of our Ontario solar facilities. As a result of that activity, our overall financial position remains strong, supported by our A grade credit rating, and we remain well positioned to fund our capital program in the coming years.So in summary, I'm obviously, very pleased with the progress we made in 2017, and we are well positioned for continued growth and success in the future.Before providing an update on recent developments and our future outlook, I would like to briefly comment on our 2017 results. Excluding certain specific items, comparable earnings were $2.7 billion or $3.09 per share, an increase of $582 million or $0.31 per share over 2016. That equates to an 11% increase on a per share basis year-over-year.Comparable EBITDA increased $730 million to approximately $7.4 billion, while comparable funds generated from operations was $5.6 billion, which was $470 million or 9% higher than 2016. Each of these amounts represents record results for our company and reflects the successful integration of Columbia, the strong performance of our existing assets and $5 billion of growth projects that were completed and placed into service over the last year. Don will provide you a few more details on our fourth quarter results in just a few minutes.Based on the strength of our financial performance and our growth outlook, TransCanada's Board of Directors today declared a quarterly dividend of $0.69 per common share, which is equivalent to $2.76 per share on an annual basis. That represents a 10.4% increase over last year and is the 18th consecutive year that the board has raised our annual dividend.At the same time, we have maintained strong coverage ratios with our dividend representing a payout of just over 80% of comparable earnings and approximately 40% of internally generated cash flow, leaving us with the financial flexibility to continue to invest in our core businesses.Turning now to Slide 7 and our outlook for the future. As I've highlighted in the past, in 2000, we set out to become one of North America's leading energy infrastructure companies. We have largely stuck to that plan, and our strategy has generated significant shareholder value.Over the past 17 years, we've invested approximately $75 billion in high-quality, low-risk pipeline and power generation assets. Notably over that period, we have built franchises that provide us with 5 significant platforms for future growth. Today, our $86 billion high-quality portfolio of critical energy infrastructure assets includes natural gas pipelines in Canada, the United States and Mexico as well as liquids pipelines and energy assets in Canada and the United States.With over 95% of our EBITDA coming from regulated or long-term contracted assets, again, we are well positioned to produce solid results through various market cycles. Looking forward, we are advancing $23 billion of near-term commercially secured projects that will continue to expand our footprint across North America. It includes approximately $21 billion of natural gas pipeline expansions that are driven by growth in North American natural gas supply in the Marcellus/Utica as well as the Western Sedimentary Basin, along with demand growth in places like Mexico.We're also developing a regional liquids pipeline system in Alberta that include the recently completed Grand Rapids pipeline and the Northern Courier pipeline as well as the White Spruce pipeline.And finally, we are advancing $2 billion of power projects, including the 900-megawatt Napanee gas-fired plant in Ontario as well as the initial work required at Bruce Power as part of its multibillion-dollar life extension program. I'd remind you that all of those projects are underpinned by long-term contracts or rate-regulated business models. And as a result, we have a high degree of visibility to the earnings and cash flow that will be generated as they enter into service.In addition, as I've said, we are advancing over $20 billion of medium to longer-term projects currently in the advanced stages of development. Any one of those projects could further enhance our growth profile as well as our strong competitive position.Over the next few minutes, I'll expand on some of these projects and the additional organic growth opportunities that are expected to surface from our extensive North American footprint.First, in the Canadian Natural Gas Pipeline business, over the past year, we placed $2 billion of facilities into service and are advancing another $7.4 billion of commercially secured projects largely on the NGTL System. At the same time, in 2017, we enhanced the long-term future of the Canadian Mainline by connecting 1.4 billion cubic feet a day at Empress. We're contracting for 1.4 billion cubic feet a day at Empress receipt point to the Dawn hub in Southern Ontario under 10-year contracts. That new service went into effect on November 1 of 2017.In the United States, we placed the Rayne XPress, Gibraltar projects into service in November of 2017 at a combined cost of USD 700 million. At the same time, we continued to advance an additional USD 7.5 billion of projects, including the $1.6 billion Leach project, which entered service in January of this year.Having received FERC permits for the WB, Mountaineer, and Gulf XPress projects in late '17, we expect all 3 to enter service by the end of 2018 at a combined investment of approximately USD 4 billion. Looking forward, we expect our Columbia system to continue to generate organic growth opportunities as natural gas production in the Marcellus continues to grow to approximately 30 billion cubic feet a day by 2020.We also continue to look at additional opportunities across the broader U.S. natural gas pipeline portfolio, including our ANR, GTN, Great Lakes, Northern Border, Iroquois and Portland Natural Gas Transmission Systems, which are all experiencing opportunities for growth.Turning to Mexico, where we've seen significant growth over the last few years. Today, we have 4 pipelines generating revenue under 25-year take-or-pay contracts with the CFE. Three additional pipelines are under construction. That will bring our total investment in Mexico to above USD 5 billion. The Villa de Reyes project and the Sur de Texas line are both expected to enter service in 2018, while the Tula project is anticipated to enter service in 2019.Before moving to our Liquids Pipeline business, I wanted to make a few additional comments on our Canadian Natural Gas Pipeline throughput increases over the last year. For the period, from November 1, 2017, to January 31, 2018, which coincides with the beginning of the new gas year, NGTL System field receipts averaged about 12.4 billion cubic feet a day, up from about 11.3 billion cubic feet a day for the same period a year ago. That's an increase in flow of about 1.1 billion cubic feet a day. Much of that incremental gas are eastern markets as it moved into our Canadian Mainline at Empress where western receipts averaged about 3.5 billion cubic feet a day in that period, up from about 2.7 billion cubic feet a day in the prior year, which is an increase of about 800 million cubic feet a day year-over-year. The remainder of the increased supply serve the growing intra-Alberta markets for power, industrial demand, including the Canadian oil sands and residential heating.As we've highlighted previously, we believe Western Canada's shale plays are among the lowest-cost sources of supply in North America, and we remain bullish on the Western Canadian Sedimentary Basin's ability to continue to grow and gain market share. Connecting that new growing production from those emerging shale plays from wellhead to market will require additional infrastructure. Evidence of that could be seen this morning when we announced that we intend to invest an additional $2.4 billion in a 2021 expansion program on the NGTL System. It will allow us to connect incremental supply of about 620 million cubic feet a day to the system and expand NGTL export capacity by about 1 billion cubic feet a day at East Gate where the system connects with the Canadian Mainline.That expansion is all underpinned by long-term agreements with shippers for an average term of approximately 29 years. We expect to file a project description with the National Energy Board by the second quarter of 2018 with construction to commence in 2019 pending regulatory approval.When added to our existing expansion program, we now have contracted to build about $7.2 billion of new infrastructure on the NGTL System through 2021 to move that growing production to market. Once completed, the series of expansions will provide 2.2 billion cubic feet a day of incremental capacity -- delivery capacity on the system, including 550 million cubic feet a day to intra-Alberta markets, 650 million cubic feet a day to the West Gate where it will connect with our GTN system and move to Pacific Northwest and California markets and 1 billion cubic feet a day to East Gate where it will connect with the Canadian Mainline and have access to Midwest and Eastern Canadian and Eastern U.S. markets.Looking forward, we continue to work with the industry on options to connect additional growing supply to markets across North America, including the potential restoration of dormant capacity on the Canadian Mainline. We also continue to actively work with LNG Canada on our Coastal GasLink project, which provide another significant market outlet for Canadian gas.Now turning to our Liquids business, which has produced very strong results in 2017. The value of our service offerings were evident again in late in 2017 as we secured incremental long-term contracts for our Keystone and Marketlink pipelines. Keystone is now underpinned by long-haul take-or-pay contracts for 550,000 barrels with an average remaining term of about 13 years. In November of 2017, we also placed the $1 billion Northern Courier pipeline into service. It's underpinned by a 25-year contract with the Fort Hills partnership.Finally, in Liquids, I'll just make a few comments on Keystone XL. During the fourth quarter, we continued to advance the project following Nebraska Public Service Commission's approval of a viable route through the State of Nebraska, which I'd remind you that we fully support. That was followed in January with the announcement that we had successfully secured approximately 500,000 barrels per day of firm 20-year commitments following an open season in late 2017. That volume is consistent with the original level of contracting on the Keystone XL system prior to the denial of the Presidential Permit. To be clear, during the open season, we sought to contract an incremental 500,000 to 550,000 barrels a day to underpin the economics of Keystone XL and provide us with a return on capital that is consistent with the returns we earn on similar projects in our portfolio.The additional contracts we secured for Keystone XL, combined with existing contracts on the Keystone system, including those that were put in place at the time we built the U.S. Gulf Coast section that convert to long-haul agreements on Keystone XL, means Keystone XL will be close to fully utilized by contracted shippers after factoring in capacity we are required by regulators to set aside for spot shippers.Looking forward, we will continue to work collaboratively with landowners to obtain the necessary easements for the approved route. In addition, our preparation for construction has commenced, and we will increase as the permitting process advances throughout 2018. As you know, much of our long lead time equipment was previously purchased and therefore, significant capital spend will not occur until we actually commence construction. Primary construction is expected to begin in 2019 and will take approximately 2 years to complete.Now turning to our Energy business. Following the monetization of our U.S. Northeast Power business and our Ontario solar assets in 2017, the remaining 6,100 megawatts of power generation assets in our portfolio are largely underpinned by long-term contracts with very strong counterparties. Those assets generate approximately $800 million of EBITDA in 2017, and that is expected to grow to more than $1 billion by 2020 as we complete the Napanee project and advance work on the Bruce Power life extension. Construction on Napanee continues and is expected to be placed into service in 2018. Work also continues on the asset management program at Bruce with major investments to extend the operating life of the facility to 2064 scheduled to begin in 2020 and continue through 2032.The $6.2 billion investment, and I'd remind you that's calculated currently in 2014 dollars, will see us spend approximately $900 million between now and the end of the decade with the remainder being invested between 2020 and 2033.So in summary, today, we are advancing $23 billion of near-term capital projects that are expected to drive significant growth. As you can see on this chart, comparable EBITDA grew from $5.9 billion in 2015 to $6.6 billion in 2016, to $7.4 billion in 2017. That growth is expected to continue with EBITDA of approximately $9.5 billion in 2020 as we largely complete our near-term capital program. That equates to a compound average annual growth rate of approximately 10%. Also of note, over 95% of our cash flows will be derived from regulated or long-term contracted assets.Based on our confidence in our growth plans, we expect to continue to grow the dividend at the average annual rate that is at the upper end of an 8% to 10% range through 2020 and another 8% to 10% through 2021. This is all supported by expected growth in earnings and cash flow and strong distributable cash flow coverage ratios.So 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. With $86 billion of high-quality assets and 7,500 talented employees, we have 5 significant platforms for growth: Canadian Gas, U.S. Gas, Mexico Gas, our Liquids business and Energy. As we advance our $23 billion of commercially secured near-term projects, we expect to deliver significant additional growth in earnings and cash flow. As a result, we expect to grow our common share dividend at the upper end of 8% to 10% on an annual basis through 2020 and foresee an additional growth of 8% to 10% in our dividend in 2021.Further, as evidenced by the fundamental long-term outlook for natural gas, crude oil and power, there are plenty of additional opportunities to continue to reinvest our strong and growing internally generated cash flow. Today, we have more than $20 billion of projects that are in the advanced stages of development, and we expect numerous other growth opportunities to emanate from our extensive asset footprint. Success in advancing these initiatives could extend our dividend growth outlook through 2021 and well beyond. At the same time, we expect to maintain our strong financial position to ensure that we're well positioned to prudently fund our capital programs. So today, trading at approximately 17x 2018 consensus earnings and a dividend yield in the 5% range, we believe we offer compelling investment -- a compelling investment proposition given the stability of our underlying businesses, our tangible outlook for significant growth and our financial strength and flexibility.That concludes my prepared remarks. I'll turn the call over to Don to provide a few more details on our fourth quarter results and our outlook for 2018. Don, over to you.
Thanks, Russ, and good afternoon, everyone. As highlighted in our news release issued earlier today, we reported net income attributable to common shares in the fourth quarter at $861 million or $0.98 per share compared to a net loss of $358 million or $0.43 per common share in the same period in 2016. Per share amounts reflect the dilutive effect of having issued 161 million common shares in 2016, plus additional shares through the dividend reinvestment and at-the-market programs in 2017.Fourth quarter results included an $804 million recovery of deferred income taxes as a result of the U.S. Tax Reform, $136 million after-tax gain related to the sale of our Ontario solar portfolio and a $64 million after-tax net gain related to the monetization of our U.S. Northeast Power business. These positives were partially offset by a $954 million after-tax impairment charge for Energy East and related projects as a result of our decision not to proceed with the project applications and a $9 million after-tax charge related to the maintenance and liquidation of Keystone XL assets, which costs were expensed in the quarter pending further advancement of the project.Fourth quarter 2016 included an $870 million after-tax loss related to the monetization of our U.S. Northeast Power business, a $68 million after-tax charge to settle the termination of our Alberta PPAs, an after-tax charge of $67 million for costs associated with the acquisition of Columbia, an $18 million after-tax charge related to Keystone XL assets and a $6 million after-tax charge for restructuring costs. All of these specific items as well as unrealized gains and losses from changes in risk management activities are excluded from comparable earnings.Fourth quarter comparable earnings were $719 million or $0.82 per share compared to $626 million or $0.75 per share in 2016. For the year ended December 31, 2017, comparable earnings reached a record $2.7 billion or $3.09 per share compared to $2.1 billion or $2.78 per share in 2016.Turning to our business segment results on Slide 21. In the fourth quarter, comparable EBITDA from our 5 business segments was approximately $1.9 billion, similar to 2016. I'll spend a few minutes reviewing key factors that contributed to this result.Canadian Natural Gas Pipelines comparable EBITDA of $569 million in fourth quarter 2017 was $15 million lower than for the same period last year, primarily on account of flow-through items under the cost of service regulatory model. As outlined in the quarterly report, net income for the NGTL System actual increased $6 million year-over-year due to a higher investment base, partially offset by lower OM&A incentive earnings. Net income for the Canadian Mainline decreased $4 million due to a lower average investment base and lower incentive earnings.U.S. Natural Gas Pipelines comparable EBITDA of $604 million in the quarter increased by CAD 34 million or USD 45 million versus the same period in 2016, mainly due to lower operating costs, including synergies achieved following the Columbia acquisition. This was partially offset by a weaker U.S. dollar, which had a negative impact on the translated Canadian dollar earnings from our U.S. operations.Mexico Natural Gas Pipelines comparable EBITDA of $161 million (sic) [ $116 million ] decreased $3 million compared to the fourth quarter 2016. In U.S. dollar terms, EBITDA rose by $5 million, primarily due to incremental earnings from Mazatlán, which entered commercial service in December 2016 and equity earnings from our investment in the Sur de Texas pipeline, which records AFUDC during construction, partially offset by interest expense on an inter-affiliate loan from TransCanada to fund its proportionate share of Sur de Texas construction. This interest expense in the business segment is offset by equal recognition of the income in interest income and other in the Corporate segment. Under GAAP, these are presented separately.Liquids Pipelines comparable EBITDA rose by $99 million to $401 million, primarily as a result of higher volumes on Keystone, new intra-Alberta pipelines which began operations in the second half of 2017 and a higher contribution from the liquids marketing business. Again, this was partially offset by a weaker U.S. dollar, which had a negative impact on comparable EBITDA in Canadian dollar terms.Energy comparable EBITDA decreased by $90 million year-over-year to $214 million, principally due to the sale of our U.S. Northeast Power generation assets in the second quarter of 2017 and a $21 million impairment of obsolete spare turbine equipment. Bruce Power continues to perform well with comparable EBITDA increasing $37 million from the same period in 2016 due to higher plant availability from lower planned and unplanned outage days.We continue the wind-down of our U.S. Power marketing business and in December announced an agreement to sell our U.S. Power retail contracts. That transaction is expected to close in the first quarter of 2018, subject to regulatory and other approvals. The remaining approximate USD 100 million in value to be recovered from this business is expected to be largely realized by the end of 2019.Now turning to the other income statement items on Slide 22. Depreciation and amortization of $516 million increased slightly versus fourth quarter 2016, largely due to the addition of new facilities across our segments, partially offset by the sale of our U.S. Northeast Power generation assets and a weaker U.S. dollar.Interest expense included in comparable earnings of $541 million was in line with the same period in 2016, reflecting the repayment in June 2017 of the bridge facilities used to partially fund the Columbia acquisition and the impact of a weaker U.S. dollar in translating U.S. dollar-denominated interest, offset by new long-term debt and subordinated notes issuances, net of maturities, and lower capitalized interest on Liquids Pipelines projects placed in-service in 2017.AFUDC increased by $43 million compared to the year-ago period, primarily due to continued investment in and higher rates on Columbia projects as well as ongoing growth in Mexico, partially offset by the commercial in-service of Topolobampo, the completion of Mazatlán construction and our decision not to proceed with the Energy East pipeline.Interest income and other included in comparable earnings rose $48 million in the fourth quarter versus 2016, primarily due to interest income and the foreign exchange impact on the previously noted inter-affiliate loan receivable from the Sur de Texas joint venture, with offsetting amounts reflected elsewhere in our results as well as the foreign exchange impact on the translation of foreign currency-denominated working capital balances.Regarding our exposure to foreign exchange rates. Our U.S. dollar-denominated assets, including our interest in Mexico, are predominantly hedged with U.S. dollar-denominated debt and the associated interest expense. We continue to actively manage the residual exposure on a rolling 1-year forward basis. In terms of sensitivity to currency through 2018, given our hedge position, it would take about a $0.10 move in the Canadian-U.S. dollar exchange rate to impact earnings by about $0.01. Going forward, it's structurally about $0.01 for $0.01 in the post-2018 time frame without giving effect to our active hedge program.Comparable income tax expense of $234 million in fourth quarter 2017 increased by $23 million compared to the same period last year, mainly due to the increase in comparable earnings, changes in the proportion of income earned between Canadian and foreign jurisdictions and changes in flow-through taxes in our regulatory operations. I'll speak to the broader implications of the U.S. Tax Reform shortly.Net income attributable to noncontrolling interests decreased by $21 million for the 3 months ended December 31, 2017, primarily due to the acquisition of the remaining outstanding publicly held common units of CPPL in February 2017.And finally, preferred share dividends increased by $8 million for the 3 months ended December 31, 2017, versus fourth quarter 2016 due to the issuance of Series 15 preferred shares in November 2016.Now moving to cash flow and distributable cash flow on Slide 23. Comparable funds generated from operations of approximately $1.5 billion in the fourth quarter increased by $25 million year-over-year despite the sale of our U.S. Northeast Power assets, primarily due to higher comparable earnings as outlined. As introduced at Investor Day in November, we now provide 2 measures of comparable distributable cash flow. One includes all maintenance capital, regardless of whether it's recoverable or not. The other reflects only nonrecoverable maintenance capital by excluding amounts that are ultimately reflected in tolls under Canadian and U.S. rate-regulated pipelines in Keystone.Maintenance capital expenditures recoverable in future tolls of $541 million in fourth quarter 2017 were $218 million higher than the level of spend in the same quarter of 2016. This represented 88% of total maintenance capital in the period. It includes $301 million related to our Canadian-regulated Natural Gas Pipelines, which was $168 million higher than fourth quarter 2016 and is immediately reflected in the NGTL and Canadian Mainline rate bases, which positively impacts net income.Maintenance capital of $237 million in our U.S. Natural Gas Pipelines was $55 million or USD 43 million higher year-over-year. The increase was primarily related to ANR, which earns a return of and on this capital per its 2016 rate settlement as well as on Columbia.Other maintenance capital of $75 million in the fourth quarter was $5 million higher than for the same period of 2016. As a result, distributable cash flow in the quarter reflecting all maintenance capital was $727 million or $0.83 per share, providing a coverage ratio of 1.3x. Distributable cash flow reflecting only nonrecoverable maintenance capital was just under $1.3 billion or $1.45 per share, resulting in a coverage ratio of 2.3x.Distributable cash flow coverage ratios for the year ended December 31, 2017, were approximately 1.7x and 2.3x, respectively. This is slightly above our forecast provided last February.Now turning to Slide 24. During the fourth quarter, we invested approximately $2.5 billion under our capital program, bringing the total for 2017 to $9.2 billion. As Russ mentioned, we brought $5 billion of new assets into service in 2017, followed in early January by the USD 1.6 billion Leach XPress project. This was successfully funded through our strong and growing internally generated cash flow, portfolio management and access to capital markets on compelling terms. In fourth quarter 2017, comparable funds generated from operations were $1.5 billion, bringing the total for the year to a record $5.6 billion.In October, we received $634 million from Progress Energy, representing the reimbursement of costs, including carrying charges incurred to develop the Prince Rupert Gas Transmission pipeline upon cancellation of the Pacific Northwest LNG project. In December, we closed the sale of our Ontario solar portfolio for $541 million, proceeds from which were used to fund a portion of our growth program.We also completed incremental external financing in the quarter and entered 2018 with approximately $1.1 billion of cash on hand. In November, we issued USD 700 million of senior unsecured notes at a rate of 2 1/8% and USD 550 million of senior unsecured notes at a floating rate. Both of these mature in November 2019. Today, our debt is long-duration and over 90% fixed rate with an average term of 21 years, including the hybrid securities to final maturity. The average term of our debt, including the hybrids to first call, was 12.8 years.Our DRP continues to provide incremental subordinated capital in support of our growth and credit metrics. In 2017, the full year participation rate amongst common shareholders was approximately 36%, representing $791 million of dividend reinvestment.In June of last year, we established an at-the-market or ATM program that allows us to issue up to $1 billion in common shares from time to time over a 25-month period at our discretion at the prevailing market price when sold in Canada or the United States. The use of the ATM will be shaped by our spend profile as well as the availability and relative cost of other funding sources. In fourth quarter, 3.5 million common shares were issued under the program at an average price of $63.03 per share for gross proceeds of $218 million. Looking forward, we are developing high-quality projects under a $23 billion near-term capital program. These long-life infrastructure assets are supported by long-term commercial arrangements or regulated cost of service business models and once completed, are expected to generate significant growth in earnings and cash flow.These are expected to be financed through our growing internally generated cash flow and a combination of other funding options, including senior debt, preferred shares, hybrid securities, asset sales, additional drop-downs to TC PipeLines, LP and common shares issued under our DRP and ATM programs in a manner that is consistent with achieving targeted A grade credit metrics. It is in volatile market conditions that we have historically seen the value of an A grade credit rating to be a differentiating factor in terms of access to and cost of capital.In summary, while our external funding needs are sizable, they are eminently achievable in the context of multiple financing levers available and the clear, accretive and credit-supportive use of proceeds. We do not foresee a need for additional discrete equity to finance our current $23 billion portfolio of near-term growth projects.Next, I'd like to spend a moment on our 2018 comparable earnings outlook on Slide 25. Additional information is contained in our 2017 annual Management's Discussion and Analysis, which is being filed on SEDAR today and available on our website.Canadian Natural Gas Pipelines earnings in 2018 are expected to be modestly lower than 2017 due to declining Canadian Mainline investment base and lower incentive earnings, partially offset by continued growth in the NGTL System's investment base. This will occur as we continue to extend and expand connectivity to prolific supply in the northwest portion of the WCSB as well as increased northeast delivery facilities and incremental service at our major border interconnections in response to requests for both receipt and delivery firm service on the system.U.S. Natural Gas Pipelines earnings are expected to be higher in 2018 than in 2017 due to, among other factors, increased revenues following the completion of expansion projects on the Columbia Gas and Columbia Gulf systems. These projects provide our customers with increased access to new sources of supply while also improving market reach. In addition, we expect to realize the full run rate benefit of targeted Columbia acquisition synergies in 2018. ANR is positioned to continue to benefit from its combination of long-term contracts originating in the Utica and Marcellus shale plays, a broad suite of storage and transmission services to customers in the Midwest and its connectivity to Gulf Coast area production and end-use markets. We expect ANR to provide stable earnings for 2018 compared to 2017.In Mexico Natural Gas Pipelines, we expect 2018 earnings from the Topolobampo, Tamazunchale, Guadalajara and Mazatlán pipelines to remain consistent with 2017 due to the long-term nature and the underlying revenue contracts. Sur de Texas and Villa de Reyes are expected to be in-service later in the year.In Liquids, our 2018 earnings are expected to be higher than 2017, primarily as a result of full year contributions from the Northern Courier and Grand Rapids pipelines and incremental long-term contracts on the Keystone system.Our 2018 comparable earnings for the Energy segment are expected to be lower than 2017, primarily due to the monetization of the U.S. Northeast Power generation assets in second quarter 2017 and the Ontario solar assets in late 2017, the continued wind-down of our U.S. Power marketing operations and higher planned outages at Bruce Power.Planned maintenance at Bruce is expected to occur in Units 1 and 4 in the first half of 2018 and Units 3 and 8 in the second half of 2018. The average plant availability percentage in 2018 is expected to be in the high 80s range compared to 90% in 2017. These lower Energy items will be partially offset by incremental earnings from the expected completion of the Napanee power plant in Ontario and the nonrecurring $21 million turbine equipment impairment recognized in fourth quarter 2017.Comparable earnings in 2018 will also be impacted by higher interest expense as a result of financings to help fund our capital program and lower capitalized interest driven by assets placed in-service, including Grand Rapids and Northern Courier as well as the cancellation of the Prince Rupert Gas Transmission project.We also expect comparable AFUDC to be lower in 2018 compared to 2017 as a result of the Energy East project termination and assets placed in-service, partially offset by continued capital spending on Columbia and Mexico natural gas projects. Finally, I would like to reiterate that we have very limited interest rate, foreign exchange or commodity price variability inherent in our diversified portfolio.In summary, comparable earnings per share in 2018 are expected to be higher than 2017. This also takes into account the anticipated impact of U.S. Tax Reform.The Tax Cuts and Jobs Act signed into law on December 22 is a significant piece of legislation, and interpretations, guidance and clarifications will continue to surface over time. We have dedicated substantial resources over the past few months analyzing its key components and how they will apply to TransCanada going forward.Four principal areas -- aspects of the U.S. Tax Reform that impact us are: the reduction in the federal corporate tax rate from 35% to 21%, immediate expensing of qualifying capital expenditures and cessation of bonus depreciation, limitations on the deductibility of interest and introduction of a Base Erosion Anti-Abuse Tax or BEAT. I would note that there are exemptions to the immediate expensing of capital and interest limitation elements for public utilities, which will include our rate-regulated gas pipeline assets.Taken as a whole, while there are some significant changes relevant to us as well as uncertainty as to if, how and when they might impact tolls in our portfolio of FERC-regulated pipes, our view on their collective consolidated impact is that we anticipate a modest increase in accounting earnings going forward. EBITDA guidance over our planning horizon remains in line what I presented at Investor Day in November. We don't foresee any fundamental change to payout metrics. And we don't expect any material impact on our financial flexibility or funding plans.In terms of capital spending, we expect to invest approximately $9 billion in 2018 on growth projects, maintenance capital and contributions to equity investments. The majority of the anticipated 2018 capital program will be focused on U.S., Canadian and Mexico Natural Gas Pipeline growth projects and maintenance, with additional capital expenditure attributable to Napanee and the Bruce Power life extension program and maintenance.In closing, I would offer the following comments. Our financial and operational performance in the fourth quarter continues to highlight our diversified, low-risk business strategy. Today, we are advancing a $23 billion suite of high-quality, near-term projects and have 5 distinct platforms for future growth in Canadian, U.S. and Mexico Natural Gas Pipelines, Liquids Pipelines and Energy. Our overall financial position remains strong, supported by our A grade credit rating and a straightforward corporate structure. We remain well positioned to fund our near-term capital program through resilient and growing internally generated cash flow and strong access to capital markets on compelling terms. Our portfolio of critical energy infrastructure projects is poised to generate significant growth in high-quality, long-life earnings and cash flow for our shareholders. That is expected to support annual dividend growth at the upper end of an 8% to 10% range through 2020 and an additional 8% to 10% in 2021. Success in adding to our growth portfolio in the coming years could augment or extend the company's dividend growth outlook further.That's the end of my prepared remarks. I'll now turn the call back over to David for the Q&A.
Thanks, Don. And to those of you listening, we very much appreciate your patience as we got through that. Obviously, a lot to cover, including hopefully, giving you some color on our 2018 outlook. [Operator Instructions]
[Operator Instructions] The first question is from Jeremy Tonet from JPMorgan.
Just want to start off with the crude oil pipeline segment, quite a strong result this quarter there. And was just wondering if you could help us a little bit more, what's kind of like more of a ratable number for earnings? EBITDA this quarter, there was kind of some upside with marketing and other things. So just for modeling, thinking forward, what kind of a number that will be? And also just when the line pressure be fully back on Keystone and what type of a near-term impact should we expect from that?
Jeremy, it's Paul Miller here. I'll start with the pressure derate. We continue to work with the regulator on the event. We continue to look at the root cause of the leak we had. And ultimately, it will be the regulator's call when the pressure derate is lifted. So we continue to work with them. The pressure derate had a modest effect on our flows, nothing that impacted our Keystone financial results materially. As far as the ratable going forward, the leak did not impact the southern part of our systems south of Cushing. And that's where we saw high differentials in the fourth quarter, which made transportation on our Marketlink system quite attractive. So we were able to attract uncontracted volumes. Our marketing entity also participates in that marketplace, and it too realized on some good volumes in the fourth quarter. We have seen the differentials come off since then. They started off strong at the beginning of the quarter, but they have trailed off.
Okay. And I just want to go to Keystone XL real quick here. And was just wondering if you could help me think through what's the next steps we should be looking for here? What are kind of the hurdles to an FID and also just as far as the tax reform is concerned, is K XL qualified for immediate expensing there?
I'll start off with next steps. As we've indicated previously, we have commenced our construction planning. It would be our anticipation to ramp up that activity as the permitting process advances in 2018. We will commit capital to that activity. And we want to position ourselves to be able to commence construction in 2019. We do have some items that we have to attend to in '18, including securing additional land in Nebraska. With the approved route through Nebraska, it does leave us in a position of requiring additional tracts of land. So we have begun the outreach to our landowners, indigenous groups and other stakeholders. And we look forward to negotiating with them to secure that land. In regard to the tax reform, I'll turn that over to Don.
Yes, Jeremy, it's Don here. Yes, Keystone XL is a nonpublic utility. The way it looks under the Act, it should qualify for immediate expensing. To the extent we would avail ourselves of that, that would depend on our broader tax situation in the States and our tax shelter there. But yes, it should qualify for that.
The next question is from Robert Kwan from RBC Capital Markets.
If I can just follow-up more broadly on tax reform. Just wondering if you can talk a little bit more though about the cash flow impact with that expectations on any cross-border tax structures where you are in terms of interest deductibility cap, both for the EBITDA and the EBIT transition?
Sure, Robert. It's Don here. I'll start out, but I may turn it over to Stan here to talk a bit about his specific business here. U.S. Tax Reform is -- it's pretty involved piece of legislation with a lot of interconnectivity here. So maybe would be useful if I just walk through the 4 key component parts and how they impact us and then speak more broadly to the collective impact at the end here. So the first one is the reduction in the federal rate from 35% to 21%. Generally, a positive thing as we apply that to our suite of U.S. businesses, but the issue here is, is in a rate-regulated business. And that's if and how much of this benefit will ultimately pass through to our customers and over what time frame. So I'll let Stan maybe speak to that part then I'll circle back on the other 3 pieces.
So this is Stan. Big picture-wise, you can think of it as a situation where unless or until FERC mandates otherwise or unless there are specific provisions in a prior rate case settlement, the true-up of the reduced tax rates will occur in the pipeline's next rate case. Having said that, various industry segments have sent letters to the FERC commissioners urging them to require pipelines to reduce rates immediately. NGA and several others have responded on behalf of the pipelines and noted 4 key points. One is that FERC should respect the sanctity of rate settlements, especially in instances where there are moratoriums from rate changes in place or where rates are designed on a black-box settlement and there's no individual component of the cost of service identified. Two, that FERC has a long-standing precedent of not cherry-picking and looking at only one element of the cost of service. And then if changes are required for one component then perhaps changes in all components should be in play. Three, that legally, there's a significant hurdle that FERC needs to get over with respect to first making a finding that the pipeline rates are unjust and unreasonable. And fourth, most importantly perhaps, and along the point that Don was making, given the implementation of Order 436 back in 1985, a significant amount of competition exists within the pipeline segment, such that a significant portion of our rates are either discounted and not bearing the full tax rate or negotiated and contractually not subject to change. So by way of an example, for 2018, about 54% of our revenues fall as either discounted or negotiated rate contracts. In 2019, that will increase to 63% due to the -- our projects, Mountaineer and Gulf XPress coming online.
Yes, so I guess collectively, from an earnings perspective, positive from an EBITDA perspective. To be determined but we don't view that as significant out of the gate here and over the next couple of years. Moving to the second component here, the immediate expensing of CapEx and the cessation of bonus depreciation. As I noted, our gas pipelines don't qualify for immediate expensing of CapEx as public utilities, so it's actually possible at about USD 4 billion of in-flight Columbia growth projects would also not be grandfathered on bonus depreciation. So that effectively results in moving some tax-shelter that we otherwise would have had outward. Described this more like a teeter-totter, it's a shift between current deferred taxes and effectively smooths out the cash flow profile. So we may pay modestly higher cash taxes upfront, but we make that up in fairly short order on the back end. So we would characterize the impact of the changes to the CapEx rules on us as relatively minor to cash flow and nil to EBITDA and earnings. Third component here, limitations on the deductibility of interest. Again, the tax laws placed new restrictions on the deductibility of interest going forward based on EBITDA initially and EBIT down the road. And again, there is a carveout for public utilities. Because the bulk of our U.S. businesses rate regulated pipes, we expect the allocated sizable portion of our U.S. interest expense to those operations and as a result, we don't anticipate these limitations will have anything other than a negligible impact on us. The fourth and last one I'll touch on is the Base Erosion Anti Abuse Tax or BEAT. So effectively a minimum tax that factors in payments made to foreign affiliates. Early days on these, we're still assessing this and that said, we would see a modest impact on this -- from this. We expect that through changes in the way we finance and operate our U.S. subsidiaries, the impact of that can be limited over time. And as our U.S. EBITDA and taxable income grows, it becomes less of an issue. So impact again, limited initially with a view to taking steps to minimize this going forward. So collectively, as I mentioned in my extended opening remarks here, modest increase to accounting earnings going forward. Again, that's mainly driven by applying the lower tax rate to our U.S. asset base, less any givebacks which we -- to the customers that we don't see as being significant out of the gate here. No change to the EBITDA guidance from Investor Day where we indicated $9.5 billion out in 2020. So we would see any changes there more as a rounding error on that number. In terms of payout metrics, earnings payout modestly lower because of the increased accounting earnings. Cash flow payout, describe it as marginally lower. We would see very low double -- a very low single-digit increase on cash flow as a result of this. Impact on DCF coverages, we're generally talking like 0.1s here, so again, nothing significant. So again, no impact on financial flexibility and no impact on our funding plans as we would have presented to you in November.
That's great color. If I can just finish then on Mainline and flip to the successful NGTL open season, especially the expansion into the East Gate. Can you just talk about the next steps and on bringing back some of the mothballed capacity on the Mainline? And if there are any numbers with respect to the capital that might be required here, that would be great.
Yes, Robert, this is Karl. Yes, so we have closed the open season at the end of the month. And as you have seen, we've had about a 1 Bcf a day of new delivery capacity to the East Gate. So that new delivery capacity that we have sold is scheduled to come on about 2020, 2021 time frame, so we do have a little bit of time. We have 2 options to provide people Mainline capacity from that. One is from existing capacity that's sitting on the Mainline that is active right now. We do -- we are reporting large volumes on the Mainline right now, but we are anticipating some nonrenewals on the Mainline, so we are expecting a piece of that to come from the existing capacity that we have right now. The rest of it will come from us reactivating capacity that right now is, so to speak, dormant, the capacity that's there but isn't ready to be used. That's relatively cheap capacity to bring back. It generally just requires some maintenance that recurs, some compressor work, some maintenance and some integrity work. So that is relatively -- I don't have the number right now because I don't know the exact amount that we can bring back, but it is relatively cheap. As I said, it's maintenance. It can come back relatively quickly and we have probably in total, about 1.5 billion cubic feet a day, maybe slightly more of that capacity available in the Mainline. So we should be able to take care of -- between that and the existing nonrenewals we're expecting over the next couple of years, we should be able to take care of all the 1 billion cubic feet a day of new delivery capacity quite easily.
The next question is from Linda Ezergailis from TD Securities.
Maybe I'll stay in Canada and ask about some of your regulatory filings with the 2018 NGTL revenue requirement and then your Mainline interim toll filing for 2018 to 2020. Can you comment on the timing of when you expect those processes to be finalized? And how -- what are the bookends of possibilities in terms of your economics going forward?
Linda, it's Karl. Certainly, NGTL right now, what we have thought in NGTL really is for interim tolls, they were a reduced toll on our system but they're really intended to take -- to be in place while we sort out what the -- if there's going to be a settlement and/or if there's going to be a litigation. What I can see right now is we are still working with our shipper group for a settlement. We are optimistic that the settlement discussion is progressing, and we have no plans right at this moment to move to a filing with the regulators. So I think we're going to work with our shippers a little bit longer to see if we can get a settlement. So it will be the -- obviously, we're looking for both sides have got needs. Our producer group actually needs us to put more capital in the group and we need to be properly compensated and proper tariffs in place for that. So I would expect coming out of there, a settlement that does not back us up in any way, shape or form from the existing kind of financial metrics we have on NGTL. On the Mainline, we have filed the interim adjustments that we had in our 6-year settlement. So if you recall, our 6-year settlement had a real turn in 2018 to reestablish billing determinants. So this is kind of what I would call limited hearing. We have -- it's really just meant to reestablish the new billing determinants to take us to the end of 2020. In which case, we'll have the larger hearing from the spud between the Western system and the Eastern Triangle of the Mainline. We have filed the application and filed what we believe they're willing term this and new toll should be. Again, the tolls are increased from what we had before. We have had -- the board has a lot of comments on that filing, and we're waiting for the board to get back to us on the process and procedure. And that, they haven't done yet. We're expecting that any time now and we would expect to begin that process here in the second quarter, and maybe even end of the third quarter but it should be relatively soon.
Maybe just also very quickly on the North Montney process in bookends and outcomes and timing.
Yes, well, the North Montney, the final argument from us is due next week, next Tuesday, I believe. And then the board has communicated to come back to us in 12 weeks. So by the end of the second quarter, I think we'll have a decision. If you recall, we are asked on that particular hearing was that they just lift the -- we already have an approval and they've just lifted the condition, which was the Petronas Pacific Northwest LNG proceeding. We now have several, 10 different customers with 20-year contracts on this system, and we want to proceed without the LNG project proceedings. So yes, that was our request. Unfortunately, the hearing did get expand a little bit into toll design issues and we will be wrapping up with our final argument, and we will await their decision as to if they will work, if they will see through to our request, which is just to lift one condition or if we'll have to do some more work on tolling conditions afterwards.
The next question is from Ben Pham from BMO.
I wanted to ask about the Coastal GasLink project, and can you remind us the permits there you've received and if it's up-to-date and if you need to go back at some point if your balance sheet starts to get some momentum there?
Well, hi, Ben, it's Karl again. Yes, the permits are well in hand for that. All major permits are, there's always some minor local permits that you'll need as you into construction. So all major permits are in hand for the Coastal GasLink. Yes, on some of the permits, there will be an expiry date, but we have either dealt any expiries that'll come our way or we're comfortable that we're going to renew them. I don't have on my hand, exactly what those are but it's just not unusual for some permits to have some sort of expiries, but we're in pretty good shape. The permits that we do have are valid and ready to be used. As I said, the -- as we said before, the sponsors of our program will be Shell and partners on LNG Canada. They have said that they will take an FID one way or the other by the end of this year, so we're looking forward to have conversations with them on what that will be.
Okay. And can I also ask, the LNG stories, no one's been talking about for a long time and now, it's coming back. Can I -- is there is so much gas supply in Alberta that could feed both the Coast LNG side of things and also, you can move that gas out East as well? Or is it -- is there going to be sort of some sort of unintended consequences if LNG export happens?
Yes, that's a good question. Let me say this, the reserve potential in the WCSB has gone from -- well, I think the last 50 years, we've thought of it between maybe 100 Tcf, maybe 125 Tcf, to over 1,000 Tcf right now. And quite frankly, I think it's even larger that and people have just stopped really counting. It's so prolific with the new technology. So I'm of the firm belief that you can do both, the expansion of the markets that we're working on, both south and east and the expansion markets to the West Coast, the LNG. And as a matter of fact, I think the producing community agrees with me. The producing community is very anxious to see LNG off the West Coast and they're very anxious to participate in the markets where we can find markets with them either going south to the GTN or East into the Mainline. So I'm confident that the production of reserves are there and the producing community is well and able to produce gas to feed both of those markets or all the included markets.
And then I would just add to Karl, I would agree with him. I believe that the Western sedimentary basin for all intents and purposes, is only constrained by market access. I think our best example would be the Marcellus Utica. We saw that go from 0 to 25 billion cubic feet a day in about a 5-year period. I mean, it's astonishing what new technology will do on top of 1,000 Tcf of recoverable reserve. So as we thought about the Western sedimentary basin sort of conventionally here for the last few years going to 17 billion cubic feet a day to 19 billion, I think that's only constrained by market. I think evidence, as you saw here over the last year or 2, we've eked out 2 billion cubic feet a day of delivery capacity on our system and it chocked a block full with contracts that range 20 to 30 years. If we were able to create an outlet for 2, 3, 4, 5, 8 billion cubic feet a day, there's probably a handful of producers that could supply 25% or 30% of that on their own. So we believe we're very bullish that gas is abundant, it's cheap and it has a long life. And our job is to figure out how we can create market access for it. So I don't see any unintended consequence. I think it's a positive. The basin can feed all markets for -- I hate using terms like this but beyond 100 years. If you think of Karl's terms of it moved from 100 Tcf to 1,000 Tcf. Both the Appalachian basin and Western Canada alone could supply North America's 100 billion cubic feet a day need for the next 100 years by themselves. So lots of gas and I guess, the story from my view is still unwritten as to how that's all going to sort itself out.
The next question is from Robert Catellier from CIBC Capital Markets.
Just like a quick update on your thoughts with respect to the new project approval process. In particular, how you might put development dollars at risk, given that there's few uncertainty related to that. And if you can specifically comment as to whether or not that will apply to the recently announced NGTL expansion.
I'll make sort of the macro comment, I guess. The devil's in the details, Rob. As you know which was announced the other day, it's open for comments or theories, faster approval times, one-stop shopping for regulatory approval, all directionally positive but the devil's always in the details as to whether or not the process can actually deliver on those kind of promises. So we'll participate in that process, and we'll see. I wouldn't view projects like NGTL falling into that major projects category. But maybe, Karl, you might have a view on that as well?
Well, my expectation is it would not. We have announced a $2.4 billion expansion of the system, but you have to understand, that is an accumulation of many different looping projects and compression projects that each one alone will be for a fairly small size. So I would expect that this would be a series of smaller projects that even if this new regulatory regime is inactive, it will still fall under the smaller projects that would be -- they really haven't changed much, given what I read in the proposal so far.
That impacts, as we're traversing in existing geography, you're revamping existing facilities, it doesn't feel like that's the intent but we'll participate in the process they've asked for comments in regard to what projects should fall in here and certainly, would be our view that it's not necessary for these projects to fall into that category.
The next question is from Praneeth Satish from Wells Fargo.
Just one quick question for me. At your Analyst Day, you talked about building a potential Permian gas pipeline. Are there any updates on that front? And I guess, just how do you see the competitive dynamics in the market right now?
Yes, so this is Stan. Big picture wise with respect to origination opportunities that were throughout this, our team is working on about $1.5 billion worth of origination projects going forward. Some of these are longer puts than others but I do expect us to compete for and win more than our fair share going forward. The details to your question are somewhat commercially sensitive right now, so I can't get into them. But I will tell you this, we are leveraging our existing pipeline network by working closely with Karl and his team in Canada to provide outlets for Western Canadian producers to the Northwest into the Midwest. We're looking at adding new demand centers to the MidAtlantic off of the Columbia gas pipeline. And to your question in particular, we are looking to fill in some of the white spaces, particularly in Texas. We want to be very thoughtful about what we do going forward. We want to remain true to our risk preferences. We are very quietly trying to see if we can put together a project that has long-term contracts with the portfolio of largely investment-grade counterparties at every turns that work for us. So I would ask that you bear with us for a little bit and we will definitely update you as further details mature over the next several months.
The next question is from Andrew Kuske from Crédit Suisse.
I guess, the question really revolves around just deploying capital into 2 of your major basins and really, the Marcellus versus the Montney. And how do you think about the deployment of capital in those 2 markets? And one thing that just jumps out of your release this morning is the contractual terms that you've got for the capacity of 28.6 years. And so, how do you think about that on a risk-adjusted basis on a -- for returns relative to places where you can't get those contractual terms?
I'll maybe start and then Karl and Stan can jump in. But I think I gave you our answer to the question, sort of outlook is, but we believe that these 2 basins are the lowest cost basins in North America. We're seeing them both continue to grow as others decline. We don't know yet how low the price can go and then still recover full cycle these returns on investment. But it appears to be something sub-$3 and maybe lower as they continue to prove out and get better and better at what they do. I guess our view is that those 2 markets, if you think of the North American market being round numbers of 100 billion cubic feet a day and then you add on some export capacity, some increased demand for power and industrial demand, add a bit export to Mexico, people will talk about market that looks like 120, 130 or more Bcf a day. These basins have the ability to continue to grow and that -- and then you throw on top of that, a 5 billion cubic feet a day of decline every year from traditional sources. There's ample room for them to both continue to grow. When we're making our capital investment, first and foremost is the fundamentals. We think fundamentally, that's a strong investment to move from the lowest-cost basin to market, is going to be fundamentally sound no matter who owns it, no matter the term of contract. And then as we've seen, the term of contract in both places has increased. You think of how we build up ANR, for example, first, prior to Columbia with contracts that average, if I remember correctly, somewhere in the 23 or 24-year range; GTN in that same sort of 20-plus year range; Columbia in that sort of same long-term range. The creditworthiness of these counterparties is improving. What we saw with small producers, they still may be sub-investment-grade producers but they have multibillion dollar balance sheets today, with creative positions for future growth. So we tend to combine all those things together as if we're actually not making a choice currently on capital allocation decisions between the basins. We think they're both strong places to invest going forward. And as Stan said, we're very careful about how we contract and what our paper looks like. But I don't see it as a choice, I think they're both strong fundamentally. The folks we are working with are getting stronger and as I look at our position going forward, there's going to be ample new opportunities to add to that. I don't know if you guys want to add to that, Stan or Karl?
Yes, this is Stan. I'll just give you some color commentary with respect to the Appalachian basis and our projects. Think of Appalachia as producing somewhere north of 25 Bcf a day today, growing to 40 Bcf by the end of the next decade. And in support of that, I would note that we recently, on January 1, put our Leach Xpress project into service, 1.5 Bcf a day of capacity, which today, is flowing at just over 1.4 Bcf a day. So it just goes to show that there's plenty of production out there to fill up expansion projects going forward. And that's in an environment where if you look at the forward prices on the NYMEX, it's hard to find a lot of 3s out there. Gas prices on the forward strip are sub-$3 for the most part, which is good to the extent that, that's going to track new demand in the form of LNG exports. That's one of the key signposts that we're going to continue to watch going forward, is the growth in LNG exports, which we believe could get up to that 6, 8, 10 Bcf a day over the next 3 to 5 years. So continued growth out of the Marcellus. Now we're going to put somewhere around $4.3 billion of new capital investment in service later this year, which is going to be close to up to 4 Bcf a day capacity, and I have every expectation that, that's going to fill up, not unlike our Leach Xpress project did.
Maybe I'll just make a comment as well. We've talked a lot about when we ramped up this position in the Marcellus and why the Columbia assets were such a great fit for us. And when I viewed the work that we got ahead of us and the business that we got ahead of us, I don't see it as an either/or or as a capital allocation decision at all. I think both that -- we're sitting on 2 of the best resources in North America and I think they're very, very complementary. And as a matter of fact, when we weren't together, I always considered our lack of position in the Marcellus and Utica to be a big competitive disadvantage for us. So when you take a look at what we've done, our markets have been impacted by -- the WCSB markets have been impacted by Appalachian gas. When we didn't have a position in it, we've lost some of our U.S. Northeast markets. We've seen Rover and we've seen Nexus come into our Dawn market. We've seen the Bakken associated gas decrease the amount of WCSB gas that goes down the northern border. So yes, I guess what I would say is that we have still lots of work to do and I just don't see any issue between allocated capital between the 2 of them. Both of these basins are competitive and I think that if we're not working in one, that gas will still move, so I think we've got to be very mindful of that. Just because we choose not to move the gas doesn't mean it won't move and it won't move in the markets that compete with us. So I think we're quite eager to make sure we maintain our market share in both areas.
And maybe if I can, Karl, while you're on a roll on this topic. Do you foresee the possibility in the future of having an integrated tolling offering on Nova's system and the Mainline on a long-term contracted basis to hit Dawn or even farther than Dawn?
I don't think it's a secret that I've been -- for many, many years now, I've been out talking about the advantages of rolling the Mainline into NGTL. And I actually did that in a hearing once, I didn't -- it wasn't all that successful in the hearing. But those were different days and I have been -- I am out on the stump again in the market here, talking to the producers, giving them some of the benefits of merging these 2 systems and the competitive business benefits, especially to accessing and keep some of our markets down east. On the other hand, I'll just -- I'll end the discussion just on a very high-level discussion of why I think it works pretty well. Number one is, by the time we've finished our NGTL buildout, at least this phase of it, we're going to see an NGTL system that's probably got about $12 billion of capital in it. By the time we finish in 2020, our LDC settlement, we're going to see Western System on the Mainline, it's going to have about $1.3 billion in it. So when you just take a look at the law of large numbers, it really makes sense for competitors of WCSB to put the Mainline into NGTL and make it part of the NGTL tolling structure. It's just you just get far more building determinants in NGTL than it does in the Mainline to keep the tariffs where you want them to. My preliminary numbers suggest we can move the actual ongoing day-to-day tolls, and this all depends upon tolling design, but this is just indicative. We can decrease the toll to get out to the Eastern market, either North Bay, which would be the Dawn equivalent, I would think. We can increase or decrease that tolling by 30% to 45%, depending upon tolling methodologies that we would use to merge in the 2 systems. So yes, I'm going to continue talking to our producers to see if I can convince them that they should take this seriously, and I do think it's the right thing to do.
The next question is from Ted Durbin from Goldman Sachs.
So I'd love to stay on this topic and actually ask around the next wave of volumes on the Mainline. Would you be willing to do discounted tariffs to sort of producing community like you did with the 1.4 Bcf a day that you announced last year in order to attract more long-term commitments?
Yes, this is Karl again. Yes, we were actually looking at that right now. Now, I think we really have to be realistic about what type of product that we can offer. The last product that we offered, we had a huge supply overhang, we were clearing a very large surplus, and that we were very successful in clearing that and making sure that the remaining capacity is viewed as some value for the rest of the industry, which I think we're very successful at. This next tranche, what we want to do is we want to sell some of the capacity that we believe is going to come up through nonrenewals, and we want to -- if we can, we want to bring some of this dormant capacity out of dormancy, so to speak, and get it ready for back in service since we really want a longer-term basis. So I think we are working on this right now, the -- or not only in our producing community but actually, some of the markets out of the end of the pipeline are asking us what we can do and what the terms and conditions would be. So I think you will find us -- we're working on it as I speak. I do not have a product right now to put in front of our customers, but we are working on it as I speak. And I do believe we'll be able to put a long-term fixed price product in front of them. But I would just caution you, it may not look exactly the same as the last one we did and the price certainly won't be the same, but we are working on a product.
Got it. And then sticking with the producers saying for pipeline tolls, if you think about West Coast LNG, one of the hang-ups, of course, is on the cost of the pipe. Is there any discussion around having the producing community maybe wear a portion of that cost of the transportation that has been just the developers or the buyers that would pay for that?
Yes, actually, there's been lots of discussion both from various groups, producers, governments, you name it, on what the NGTL System can do to use us, have to help that cost. We haven't seen anything, nobody has actually come to us with any type of real plan, so to speak, to roll it into the NGTL system or anything like that at this time. As far as we're concerned, given our experience from the regulator, that would be a very long pipe in order to do that. But having said that, this is a -- I do view this as essentially a producer pipeline system. And if the producers are willing to pay for this or a piece of this to be rolled in, I'm always open to discussion and open to collaborating with producers. But as of right now, I would say there is nothing concrete on the ground, just a bunch of talk about how it would be nice if we did -- if something like that could happen and it looks like it's a long way off.
Just to be clear, for the Coastal GasLink Canada LNG project, the pipeline tolls haven't been an issue. Our understanding in talking to the sponsor, Shell and its partners, the issues have been market and market window. They believe another market window is on the horizon at '21, '22. We look at the combined sort of cost from our math. It appears that it's competitive, I think. So that was 1 issue, the other one was capital availability and capital allocation within Shell. And I think a couple of years ago, they announced that due to lower capital availability, they weren't just -- they couldn't proceed with several major projects at one time but that LNG Canada was still highly ranked within their company. As crude prices return, they finished other projects. We believe that it's a still high priority for capital allocation within Shell. So I think those are the major drivers and sort of we're not getting any -- what would or back to sharpen our pencils certainly around our costs for building the pipeline, but that won't be a major driver, I think, of that FID decision. It will be, I think, one based on Shell and its partners' outlook of their capital availability and markets.
The next question is from Tom Abrams from Morgan Stanley.
Just remaining for me was about Mexico and if it is much as Mexican gas demand is taking a lot to kind of queue up, if there's any chance that your projects there would be delayed or if payment from CFE would be different than what you had originally thought.
Hi, Tom, it's Karl. No, we haven't. Actually, the projects are the ones that are being delayed there right now and not access to gas and the need for gas. I would note that CFE has many power plants still running on fuel that they wish were not running on fuel. So our expectation is as that soon as we bring our plant into service, they will be utilized out for the plan from CFE. As per kind of our financial arrangements, these are take or pay contracts. The CFE is a great credit and we don't see any issues, even if the plan was slower than what they had hoped for. But right now, I'm quite comfortable with the strategy. Most of the gas pipelines there right now are built for our plans that are either in the process of being built or already built and running on fuel oil. So there will be -- once these pipelines are put in service, you will see them operate at a reasonable -- at the low factor that was predicted by the CFE at the time they're done with it.
The next question is from Nick Raza from Citi.
Just a couple of quick questions. In terms of just contracting on Marketlink, when you went out with your open season on Keystone, you also included Marketlink but are we to assume that until Keystone XL doesn't come online, Marketlink is essentially -- I mean, there's a very low level of contracting of take or pay from commitments on that line?
Nick, it's Paul here. We did go to an open season late last year and we did secure additional contracts on Keystone, takes us up to 555,000 barrels per day, which means Keystone is about in excess of 90% contracted. When you look at Marketlink, we do have space required for Keystone XL. We went up, went out earlier this year and termed out some of that space. And when you look at it from a contracted perspective, probably about 80% of our capacity is locked down under contracts that we put in place here, just over the last couple of months.
All right. And those are pre-Keystone XL, correct?
Yes, thank you for that. That’s what I was trying to get to. They're pre-XL, we have restriction on that space so it's limited how much we can term up, but we termed -- fair to say, we termed up what we could. We managed to term up about 80% of the capacity. So when you look at the total EBITDA for the Liquids Pipelines, about 85%, 85%-plus is now locked down by contract.
Fair enough. And just turning really quick to Karl's comments on Mexico. In terms of any CapEx overruns, are we to assume that those are essentially passed on to the shippers or are those something that TransCanada would serve there?
Well, it would depend on how the overrun was realized on. Under our contracts with the CFE, if we have a cost associated with a force majeure event, that would be deemed to be the government's, the government being the reason of the force majeure event. Examples of those will be the government is responsible for indigenous consultations and if those are slow, or other parts of the force majeure that are responsibility of the government to take care of. Then we would pass those cost increase through to the CFE. We've had a couple of these before in the past. So sometimes, they get passed through the toll, sometimes they get settled with a financial settlement and sometimes, they get settled with an incremental deal. But force majeure events that are -- the force majeure and the cost increases are a result of government action are generally passed through to the CFE to the government of Mexico. Any cost increases that happened outside of those conditions would be the responsibility of TransCanada, and we would add those costs to our rate base because we do actually -- we will have third-party volumes on there and we can't collect those cost increases from other volumes that move on the system. So our regulator rates, so to speak, in Mexico will go up and then let them take and capture those cost increases.
The next question is from Matthew Taylor from Tudor, Pickering.
Just a quick follow-up on Karl's earlier comments. With contracts on ANR stepping down in 2020 and 2021, the room on the Great Lakes seems like there's an opportunity to get Canadian volumes down to the U.S. Gulf Coast through a potential, call it, maybe an ANR reversal or something else. Can you just give me some thoughts on what actual markets you're focused on with the Mainline going forward?
Well, maybe I could this and I can let Stan jump in because Stan is the one working most of this. But we -- you won't see a tariff from us that we would go out to market with, with the contiguous path where [indiscernible]. Of course, we've got Canadian pipelines and we've got U.S. pipelines but a customer is -- certainly, if we have the capacity or if we could build the capacity quite frankly, customers are -- and we will market to customers and customers are free to come to us and ask us to look at different paths for them to see if we can move their product. As I've said before, we can get always on the Gulf Coast and except for some small blank spaces, we can get -- with Mexico City, theoretically, if people want. So people are free to come talk to us. I know we will be marketing to people but it won't be a simple, contiguous tariff. The U.S. would have to kind of put together Canadian tariff and a Great Lakes tariff and an ANR tariff, that sort of thing. But that certainly is possible and I know we have -- people have talked to us in the past and maybe I'll pass it over to Stan and he can talk about any broader plans he has on that.
I think your question is a good one and really highlights the need for Karl's team in Canada and my team in the U.S. to work closely together. Big picture-wise, we do have a general available capacity on the Great Lakes system. So to the extent there is another LTFP type deal, we would welcome the opportunity to fill that system up. We also have the ability to expand the ANR system fairly economically to the tune of about 0.5 Bcf a day or so into the Chicago area. And above and beyond that, with respect to incremental capacity down to the Gulf Coast on ANR Southeast Mainline, to a large extent, that would be a build. We do have small pocket of capacity availability that we're looking to potentially place with one counterparty. But do note that as part of the Marcellus buildout, the ANR did enter into a significant amount of contracts as part of its rate case. Half of which goes south to the Gulf Coast already. So a big chunk of the historical or general available capacity on the ANR system is spoken for and spoken for, for a term of about 30 years.
Yes, that’s great, guys. And then just one more, moving over to North Montney. Is there any kind of readthrough from the export announcement that may influence proceedings or at least strengthen your positioning in providing more egress for shippers to clear the increased receipts from the North Montney?
Well, so -- I'm sorry, I didn't get all that but I assume your question was there was some concerns that we're bringing more supply on than market, and that was a big complaint of some people from the North Montney. And I guess I would say this about that issue. Number one, it's not TransCanada's role to sit there in judgment of what people -- how people are going to market their gas. So the last thing I think the producers want in the market is for TransCanada to decide who brings the gas on and who doesn't. That type of supply management is just -- it's not our role. I think the -- nobody wants anybody to play that role. So from TransCanada's position, we want to provide everybody an opportunity to compete. We are providing egress out of the market. One of the issues that we do have is the way the system works is supply comes on, supply sees us an opportunity, the price differentials get wide and there's an opportunity to buy export capacity to get to market and then they buy export capacity. So it's kind of a linear path here and that's exactly what we've seen. As Russ said in his opening remarks, we have put in place right now, between now and 2020 -- 2021, we've put in place a 2.2 billion cubic feet per day of new market opportunities, both in down south to GTN and to Pacific Northwest California, out into Empress which ultimately go East, and even internal to NGTL System, so -- and on top of that, we have natural decline of our system, which is running a couple billion cubic feet a year. So I don't think -- you have to be careful when you start trying to micromanage a system like ours as to what supply comes on and what supply does not come on. That supply, if we do not bring it on North Montney, I will say it will produce and it will compete with everybody else on our system anyways. It just will not produce in our system and we will not get the billing determinants, so our customers will have to pay higher tolls. And that's the unfortunate result if the board does choose to go with the people that we should not bring that gas on. So I guess, you can tell I have very strong feelings about this but limiting supply is not an answer. Actually, I would argue that what the system needs right now is more transportation capacity, not less.
The next question is from Joe Gemino from Morningstar.
When you think about the Keystone and Keystone XL when it's fully ramped up, how do you think about capacity and where will it go? Will all of the legacy capacity go to the Midwest and all the XL go to the U.S. Gulf Coast? Or is there some other type of mix that you can elaborate on?
Joe, it's Paul here. Once we bring XL into service, we will move contracts that flow in XL today that convert to XL contracts over on to XL. And I would anticipate XL will really be our Hardisty to, let's call it, Cushing in Gulf Coast pipeline. And then the existing Keystone Mainline will kind of serve that Midwest market into Illinois.
Great. And is there any opportunity for the existing Keystone pipeline now to go down to the Gulf Coast or do you think it's fully going to be in the Midwest and Illinois?
Right now, you mean?
No, when the Keystone XL is brought online and fully in service.
No, when the Keystone system, including the XL project, is fully built out, the XL Lake will be the sole transportation, if you wish, to the Gulf Coast. And we'll isolate the lines. We'll effectively have a bullet line from the North to the Gulf Coast on the XL project, and then we'll have a second bullet line, again, from Hardisty into the Midwest. We would have opportunities in the future, assuming demand's there. And we can underpin it with contracts to loop our Cushing extension, which is the line today which runs from Cushing down to the Gulf Coast -- oh, I'm sorry, from Steele City down to Gulf Coast. And that would provide Gulf Coast access off the existing legacy Keystone system as well. So right after we hit in service, consider it 2 bullet lines. One to the Gulf Coast, one to the Midwest. But as supply builds, as demand grows, we do have expansion in looping opportunities so that we can feed the Gulf Coast from the legacy system as well.
Thank you. This concludes today's question-and-answer session. I would like to turn the meeting back over to Mr. Moneta.
Okay. Thanks very much, and thanks to all of you for participating today. We very much appreciate your participation during what we know is a very busy time for you. We look forward to talking to you again in the not-too-distant future. Bye for now.
Thank you. The conference has now ended. Please disconnect your lines at this time, and thank you for your participation.