TransCanada Corporation (TRP) Q4 2017 Earnings Conference Call Transcript

TransCanada Corporation (TRP 0.59%)
Q4 2017 Earnings Conference Call
Feb. 15, 2018, 4:00 p.m. ET

Contents:

• Prepared Remarks
• Questions and Answers
• Call Participants

Prepared Remarks:

Operator

Good day, Ladies and Gentlemen. Welcome to the TransCanada Corporation 2017 4th quarter results conference call. I would now like to turn the meeting over to Mr. David Moneta, Vice President, Investor Relations. Please go ahead, Mr. Moneta.

David Moneta -- Vice President, Investor Relations

Thanks very much. Good afternoon, everyone. I'd like to welcome you to TransCanada's 2017 4th quarter conference call. With me today are

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, US 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 would be happy to address your questions. In order to provide everyone from the investment community with an equal opportunity to participate, we ask that you limit yourself to two questions. If you have additional questions, please reenter the queue. 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 US Securities 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, 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.

Russell Girling -- President and Chief Executive Officer

Thanks, David. Good afternoon, everybody. Thank you very much for joining us today. It's hard to believe another year has passed but as outlined 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 $250 million US 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 US Northeast Power assets and repaid the Columbia bridge loan facilities. We continue 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 US natural gas pipeline expansions to our inventory of commercially secured projects. Earlier today, we announced another $2.4 billion expansion program on the NGTL system. In addition, we also advanced 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.

Finally, we successfully funded a $9.2 billion capital program by raising monies across the capital sector on very compelling terms. It included more than $6 billion of long-term debt and hybrid security from Canada and the United States. In addition, we did a drop-town to TC PipeLines, LP for $765 million US, 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 provision remains strong, supported by our A-grade credit ratings, and we remain well positioned to fund our capital program in the coming years. 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% 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 five 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 in natural gas pipelines 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 are also developing a regional liquids pipeline system in Alberta that includes the recently completed Grand Rapids Pipeline, and the Northern Courier Pipeline, as well as the White Spruce Pipeline.

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 multi-billion Life-Extension Program.

I remind you that all of those projects are underpinned by long-term contracts or regulated business models. 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're advancing over $20 billion in 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 expansive North American footprint.

First, in the Canadian natural gas pipeline business, over the past year we've 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 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 $700 million US. At the same time, we continued to advance an additional $7.5 billion US of projects, including the $1.6 billion Leach project, which entered service in January of this year. Having received permits for the WB, Mountaineer and Gulf Xpress projects in late '17, we expect all three to enter service by the end of 2018, at a combined investment of approximately $4 billion US.

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 US 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 four 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 to Mexico to about $5 billion US. 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 ad comments on our Canadian natural gas pipeline through-put 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 cubit feet a day. Much of that incremental gaps are eastern markets as it moved into our Canadian Mainline at Empress, where Western receipts averaged about 3.5 billion cubit feet a day in that period, up from about 2.7 billion cubit feet a day in the prior year, which is an increase of about 800 million cubit feet a day year-over-year.

The remainder of the increased supply served growing Intra-Alberta markets for power, industrial demand, including Canadian oil sands and residential heating. As we've highlighted previously, we believe Western Canada's shale plays are among the lowest cost source 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 report on the NGTL system. It will allows us to connect an incremental supply of about 620 million cubic feet a day to the system and expand NGTL's export capacity by about a 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 for construction to commence in 2019 pending regulatory approval.

When added to our expansion program, we now have contracted to build about $7.2 billion of new infrastructure on the NGTL system 32021 to move that growing production to market. Once completed, the series of expansions will provide 2.2 billion cubic feet a day of incremental delivery capacity on the system, including 550 million cubit feet a day to Intra-Alberta markets, 650 million cubic feet a day to the West Gate, where it will reconnect with our GTN system and move to Pacific Northwest and California markets, and 1 billion cubit feet a day to East Gate, where it will connect with the Canadian Mainline and have access to Midwest and Eastern Canadian and Eastern US 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 provides 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 a gain in late 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 on liquids, I'll just make a few comments on Keystone XL. During the fourth quarter, we continued to advance the project following the Nebraska Public Service Commission's approval of a viable route through the State of Nebraska, which I would 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 contract in 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 in the Keystone System, including those that were put in place at the time we built the US 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 it will take approximately two years to complete.

Now turning to our energy business, following the monetization of our US 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 generated 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 of Bruce with major investments to extend the operating life of the facility to 2064, scheduled to begin in 2020 and continue through 2033. 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 in 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%-10% range through 2020 and another 8%-10% through 2021. This is all supported by expected growth in earnings and cash flow and strong distributable cash flow coverage ratios.

In summary, I 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 five significant platforms for growth: Canadian Gas, US 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%-10% on an annual basis through 2020 and foresee an additional growth of 8%-10% in our dividends 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 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 are well-positioned to prudently fund our capital programs. So today, trading at approximately 17 times 2018 consensus earnings and a dividend yield in the 5% range, we believe we offer 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, who will provide a few more details on our fourth quarter results and our outlook for 2018. Don, it's over to you.

Donald Marchand -- Executive Vice President and Chief Financial Officer

Thanks, Russ. Good afternoon, everyone. As highlighted in our news release issued earlier today, we have reported net income attributable to common shares in the fourth quarter of $861 million or $0.98 per share, compared to a net loss of $358 million or $0.43 per common share for 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 aftermarket programs in 2017.

Fourth quarter results included an $804 million recovery of deferred income taxes as a result of the US tax reform, a $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 US 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 a $870 million after-tax loss related to the monetization of our US 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 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 five 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 actually 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. The US natural gas pipelines' comparable EBITDA of $604 million in the quarter increased by $34 million Cdn or $45 million US, 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 US dollar, which had a negative impact on the translated Canadian dollar earnings from our US operations.

Mexico natural gas pipelines' comparable EBITDA of $161 million decreased $3 million compared to the fourth quarter 2016. In US 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 and interest income in 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 higher contribution in the liquids marketing business. Again, this was partially offset by a weaker US 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 US Northeast power generation assets in the second quarter of 2017, and a $21 billion 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 our US power marketing business, and in December announced an agreement to sell our US power retail contracts. That transaction is expected to close in the first quarter of 2018, subject to regulatory and other approvals. The remaining approximately $100 US 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 US Northeast power generation assets and a weaker US 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 US dollar in translating US dollar denominated interests, offset by new long-term debt and subordinated notes issuances, net of maturities, and the 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 in 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 US dollar denominated assets, including our interests in Mexico are predominantly hedged with US dollar denominated debt and the associated interest expense. We continue to actively manage the residual exposure on a rolling one-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-US dollar exchange rate to impact earnings by about $0.01. Going forward, it's structurally about penny for penny 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 US tax reform shortly.

Net income attributable to non-controlling interests decreased by $21 million for the three 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 three 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 US Northeast power assets, primarily due to higher comparable earnings, as outlined. As introduced at Investor Day in November, we now provide two measures of comparable distributable cash flow. One includes all maintenance capital, regardless of whether it's recoverable or not. The other reflects only non-recoverable maintenance capital by excluding amounts that are ultimately reflected in tolls on the Canadian and US-rate regulated pipelines in Keystone.

Maintenance capital expenditures recoverable in future tolls of $541 million in the 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 basis, which positively impacts net income.

Maintenance capital of $237 million in our US natural gas pipelines was $55 million or $43 million US 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 1.3 times. Distributable cash flow reflecting only non-recoverable maintenance capital was just under $1.3 billion or $1.45 per share resulting in a coverage ratio of 2.3 times. Distributable cash flow coverage ratios for the year ended December 31, 2017, were approximately 1.7 times and 2.3 times respectively. This was 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 $1.6 billion US 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 the 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 $700 million US of senior unsecured notes at a rate of 2.125%, and $550 million US 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 in credit metrics. In 2017, the full-year participation rate among common shareholders was approximately 36%, representing $791 million of dividend reinvestment. In June of last year, we established an aftermarket 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 the 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 imminently 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 discreet 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 a 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 request for both receipt and delivery firm service on the system.

US natural gas pipelines' earnings are expected to be higher in 2018 than in 2017 due to, among 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 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 constant with 2017 due to the long-term nature in the underlying revenue contracts. Sur de Texas and the 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 in the Northern Courier and Grand Rapids Pipelines and incremental long-term contracts on the Keystone system. For 2018, comparable earnings for the energy segment are expected to be lower than 2017, primarily due to the monetization of the US Northeast power generation assets in second quarter 2017 and Ontario solar assets in late 2017, the continued wind-down of our US 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 the 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 the US 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 aspects of the US tax reform that impact us are: the reduction in the federal corporate tax rate from 35%-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 expense in 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 review on collective consolidated impact is that we anticipate a modest increase in accounting earnings going forward; EBITDA guidance over our planning horizon remains in line with that 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 US, 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 five distinct platforms for future growth in Canadian, US, and Mexico natural gas pipelines, liquids pipelines and energy. Our overall financial position remains strong, supported by our A-grade credit ratings 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 from 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%-10% range through 2020 and an additional 8%-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.

David Moneta -- Vice President, Investor Relations

Thanks, Don. To those of your 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. With that, before I turn it over to the conference coordinator for questions from the investment community, we ask that you limit yourself to two questions and if you have any additional questions, please reenter the queue.

Questions and Answers:

Operator

Thank you. We'll now take questions from the telephone lines. If you have a question and you're using a speaker phone, please lift your handset before making your selection. If you have a question, please press *1 on your telephone keypad. If at any time you wish to cancel the question, you may press the # sign. Please press *1 at this time if you have a question. There will be a brief pause while the participants register for questions. Thank you for your patience. The first question is from Jeremy Tonet from J.P. Morgan. Please go ahead.

Jeremy Tonet -- J.P. Morgan -- Analyst

Good afternoon.

David Moneta -- Vice President, Investor Relations

Hi, Jeremy.

Jeremy Tonet -- J.P. Morgan -- Analyst

I just wanted to start off with the crude oil pipeline segment. Quite a strong result this quarter there. I was just wondering if you could help us a little bit more. What's kind of like more of a ratable number for EBITDA this quarter, there was some kind of upside with marketing and other things. So just for modeling thinking forward, what kind of a number that will repeat? And also just when will the line pressure be fully back on Keystone, and what type of a near-term impact should we expect from that?

Paul Miller -- Executive Vice-President and President

Certainly, Jeremy. It's Paul Miller here. I'll start with the pressure de-rate. We continue to work with the regulator on the event. We continue to look at the root cause of the leak we had. Ultimately, it will be the regulators' call when the pressure de-rate is lifted. So we continue to work with them. The pressure de-rate had a modest effect on our flows, nothing that impacted our Keystone financial results materially.

As far as a ratable going forward, the leak did not impact the southern part of our system, south of Cushing. 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.

Jeremy Tonet -- J.P. Morgan -- Analyst

Okay, thanks. I wanted to go to Keystone XL real quick here. I was just wondering if you could help me think through what are the next steps we should be looking for here? What are the hurdles to an FID, and also just as far as the tax reform is concerned, does KXL qualify for immediate expensing there?

Paul Miller -- Executive Vice-President and President

I'll start off with next steps. As we've indicated previously, we have commenced our construction planning. And 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 2018, 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. We look forward to negotiating with them to secure that land. In regard to the tax reform, I'll turn that over to Don.

Donald Marchand -- Executive Vice President and Chief Financial Officer

Yes, Jeremy, it's Don here. Yes, Keystone XL is a nonpublic utility by the way it looks under the Act. It should qualify for immediate expensing. To the extent we would avail ourselves of that would depend on our broader tax situation in the States and our tax shelter there. But yes, it should qualify for that.

Jeremy Tonet -- J.P. Morgan -- Analyst

That's helpful. Thank you for taking my questions.

David Moneta -- Vice President, Investor Relations

Thanks, Jeremy.

Operator

Thank you. The next question is from Robert Kwan from RBC Capital Markets. Please go ahead.

Robert Kwan -- RBC Capital Markets -- Analyst

Good afternoon. If I can just follow more broadly on tax reform, I'm just wondering if you could 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 caps, both for the EBITDA and the EBIT transition?

Donald Marchand -- Executive Vice President and Chief Financial Officer

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. US tax reform is a pretty involved piece of legislation with a lot of interconnectivity here. So maybe would be useful if I just walk through the four 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%-21%. Generally a positive thing as we apply that to our suite of US businesses but the issue here, as you know, isn't a rate-regulated business, and that's if and how much of the 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 three pieces.

Stanley Graham Chapman, III -- Executive Vice-President and President of US Natural Gas Pipelines

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 chew up of the reduced tax rates will occur in the pipelines' 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.

IGUA and several others have responded on behalf of the pipelines and noted four 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 is 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 that if changes that 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 our projects, Mountaineer and Gulf Xpress, coming online.

Donald Marchand -- Executive Vice President and Chief Financial Officer

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 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 that about $4 billion US 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. Describe this more like a teeter-totter; it's a shift between current deferred taxes and effectively smoothes out the cash flow profile. So we may pay modestly higher cash taxes up front, 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.

The third component here, limitations on the deductibility of interest. Again, the tax laws place new restrictions on the deductibility of interest going forward based on EBITDA initially and EBIT down the road. Again, there is a carve-out for public utilities. Because the bulk of our US business is rate-regulated pipes, we expect to allocate a sizable portion of our US 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 this; we're still assessing this and that said, we would see a modest impact from this. We expect that through changes in the way we finance and operate our US subsidiaries, the impact of that can be limited over time. And as our US EBITDA and taxable income grows, that becomes less of an issue. So impact again, limited initially with a view to taking steps to minimize this going forward.

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 US asset base less any givebacks 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 had 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 more of marginally lower. We would see a very low single-digit increase on cash flow as a result of this. Impact on DCF coverage is we're generally talking like 0.1s here; so again, nothing significant. So again, no impact on financial flexible and no impact on our funding plans as we would have presented to you in November.

Robert Kwan -- RBC Capital Markets -- Analyst

That's great color. If I could finish then on Mainline, just with the successful NGTL open season, especially the expansion into the East Gate. Can you just talk about the next steps 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.

Karl Johannson -- Executive Vice-President & President, Canadian and Mexico Gas Pipelines and Energy

Yes, Robert, it's Karl. We have closed the open season at the end of the month. As you've seen, we've got about 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 timeframe, so we do have a little bit of time. We have two options to provide people mainline capacity from that. One is from existing capacity sitting on the Mainline that is active right now. We are uploading large volumes on the Mainline right now, but we are anticipating some non-renewals 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 is but it isn't ready to be used. That's relatively cheap capacity to bring back. It generally just requires some maintenance, it requires some compressor work, some maintenance, and some integrity work. 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. Between that and the existing non-renewals we're expecting over the next couple of years, we should be able to take care of all the billion cubic feet a day of new delivery capacity quite easily.

Robert Kwan -- RBC Capital Markets -- Analyst

Thanks very much.

David Moneta -- Vice President, Investor Relations

Thanks, Robert.

Operator

Thank you. The next question is from Linda Ezergailis from TD Securities. Please go ahead.

Linda Ezergailis -- TD Securities -- Analyst

Thanks. 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 what are the bookends of possibilities in terms of your economics going forward?

Karl Johannson -- Executive Vice-President & President, Canadian and Mexico Gas Pipelines and Energy

Hi, Linda, it's Karl. I will start with the NGTL right now. What we have filed in NGTL really is for interim tolls. They were a reduced toll on our system but they're really intended to be in place while we sort out if there's going to be a settlement and/or if there's going to be litigation. What I can say right now is we're 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 for a little bit longer here to see if we can get a settlement. Obviously, both sides have their needs. Our producer group actually needs us to put more capital in the group, we need to be properly compensated, and proper tariffs in place for that. So I would expect coming out of there a settlement that that does not back us up in anyway, 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 six-year settlement. So if you recall, our six-year settlement had a reopen in 2018 to reestablish billing determinants. So this is kind of what I would call a limited hearing. We really just meant to reestablish the new billing determinants to take us to the end of 2020, in which case will have the larger hearing for the split between the Western System and the Eastern Triangle of the Mainline. We have filed that application and filed with what we believe they're willing to determine us a new toll should be. Again, the tolls are decreased from what we had before.

The Board has a lot of comments on that filing, and we're waiting for the Board to get back to us on process and procedure. 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 into the third quarter but it should be relatively soon.

Linda Ezergailis -- TD Securities -- Analyst

Thanks. Maybe just also very quickly on the North Montney process, and bookends and outcomes and timing?

Karl Johannson -- Executive Vice-President & President, Canadian and Mexico Gas Pipelines and Energy

Yes. Well, North Montney, the final argument from us is due next week, next Tuesday, I believe. Then the Board has made a commitment to come back to us within 12 weeks. So by the end of the second quarter I think we'll have a decision. If you recall, our ask on that particularly hearing was that we already have an approval and then that they just lift the condition, which was the PETRONAS, Pacific NorthWest LNG proceeding. We now have 10 different customers with 20-year contracts on the system, and we wanted to proceed with the LNG project proceedings. So that was our request.

Unfortunately, the hearing did get expanded 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 see through to our request, which is just to lift the one condition, or if we have to do some work on tolling conditions afterwards.

Linda Ezergailis -- TD Securities -- Analyst

Great, thank you.

David Moneta -- Vice President, Investor Relations

Thanks, Linda.

Operator

Thank you. The next question is from Ben Pham from BMO. Please go ahead.

Ben Pham -- BMO Capital Markets -- Analyst

Thanks, good afternoon. I wanted to ask about the Coastal GasLink project. Can you remind us of the permits there you've received and if it's up-to-date and if you need to go back at some point as LNG starts to get some momentum there?

Karl Johannson -- Executive Vice-President & President, Canadian and Mexico Gas Pipelines and Energy

Hi, Ben. It's Karl again. Yes, the permits are well in hand for that. With all major permits, there's always some minor local permits that you'll need as you go 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 with any expiries come our way or we're comfortable that we'll be able to renew them. I don't have on 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 we've said before, the sponsors of our program, Shell and partners on LNG Canada, 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.

Ben Pham -- BMO Capital Markets -- Analyst

Okay. Can I also ask -- the LNG story, no one's been talking about it for a long time and now it's coming back. Is there so much gas and supply in Alberta that could it could feed both the Coast LNG side of things, and also you can move that gas out east as well? Or is it going to be sort of unintended consequences if LNG export happens?

Karl Johannson -- Executive Vice-President & President, Canadian and Mexico Gas Pipelines and Energy

That's a good question. Let me say this, the reserve potential and the WCSB has gone from -- I think the last 50 years we've thought it maybe a 100 Tcf, maybe 125 Tcf, so over 1,000 Tcf right now. Quite frankly, I think it's even larger than that. 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 of markets to the West Coast of 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 through the GTN or use of the Mainline. So I'm confident that the production of reserves are there and the producing community is ready, willing, and able to produce gas to feed both of those markets or all the included markets.

Russell Girling -- President and Chief Executive Officer

TI would just add to Karl that 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 zero to 25 billion cubic feet a day in about a five-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 of going to 17 billion cubic feet a day to 19 billion, I think that's only constrained by market, as I think evidence as you saw here over the last year or two. We've eked out 2 billion cubic feet a day of delivery capacity on our system and it's chockablock forward contracts that range 20 to 30 years. If we were able to create an outlet for 2 billion, 3 billion, 4 billion, 5 billion, 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're very bullish that gas is abundant, it's cheap, and it has a long life.

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 the Karl's terms moved from 100 Tcf to 1,000, both the Appalachian Basin and Western Canada alone could supply North Americans' 100 billion cubic feet a day need for the next 100 years by themselves. So lots of gas. I guess the story from my view is still unwritten as to how that's all going on sort itself out.

Ben Pham -- BMO Capital Markets -- Analyst

That's very helpful, guys. Thank you.

David Moneta -- Vice President, Investor Relations

Thanks, Ben.

Operator

Thank you. The next question is from Robert Catellier from CIBC Capital Markets. Please go ahead.

Ben Pham -- BMO Capital Markets -- Analyst

I'd 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 new uncertainty related to that. And if you can specifically comment as to whether or not that will apply to the recently announced NGTL expansion?

Russell Girling -- President and Chief Executive Officer

I'll make sort of a macro comment. The devil is in the details, Bob, as you know. It was just announced the other da. It's open for comment in theory. Faster approval times, one-stop shopping for regulatory approval, all directionally positive but the devil is 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 following into that major projects category but maybe, Karl, you might have a view on that as well?

Karl Johannson -- Executive Vice-President & President, Canadian and Mexico Gas Pipelines and Energy

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 enacted, it would still fall under the smaller projects that really haven't changed much given what I read in the proposal so far.

Russell Girling -- President and Chief Executive Officer

This impacts traversing 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 it would be our view that it's not necessary for these projects to fall into that category.

Robert Catellier -- CIBC Capital Markets -- Analyst

Okay. That's my question. Thank you.

David Moneta -- Vice President, Investor Relations

Thanks, Rob.

Operator

Thank you. The next question is from Praneeth Satish from Wells Fargo. Please go ahead.

Praneeth Satish -- Wells Fargo -- Analyst

Hi, good afternoon. 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? How do you see the competitive dynamics in the market right now?

Stanley Graham Chapman, III -- Executive Vice-President and President of US Natural Gas Pipelines

This is Stan. Big picture-wise with respect to origination opportunities, I would throw out 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 do you expect us to compete for one 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 and to the Midwest. We're looking at adding new demand centers to the Mid-Atlantic 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 a portfolio of largely investment-grade counterparties at returns 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.

Praneeth Satish -- Wells Fargo -- Analyst

Got it, thank you.

David Moneta -- Vice President, Investor Relations

Thanks, Praneeth.

Operator

Thank you. The next question is from Andrew Kuske from Credit Suisse. Please go ahead.

Andrew Kuske -- Credit Suisse -- Analyst

Thank you. Good afternoon. I guess the question really revolves around just deploying capital into two of your major basins and really the Marcellus versus the Montney. How do you think about the deployment of capital in those two markets? 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. So how do you think about that on a risk-adjusted basis for returns relative to places where you can't get those contractual terms?

Russell Girling -- President and Chief Executive Officer

Maybe I'll get start and then Karl and Stan can jump in. I think I gave you our answer to the questions from Outlook. We believe that these two basins are the lowest cost base 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 decent returns on investment, but it appears to be something sub-$3.00 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 two markets, if you think of the North American market being around numbers of 100 billion cubic feet a day and then you'll add on to an export capacity some increased demand for power, industrial demand, you'll add of export to Mexico, people are talking about market that looks like 120, 130 or more Bcf a day.

These basins have the ability to continue to grow 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 what the term of contract. And then as we've seen, the term of contract in both places has increased. You think of how we can build up ANR, for example, the first prior to Columbia with contracts that averaged, 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 were small producers. They still may be sub-investment-grade producers but they have multibillion balance sheets today with great positions for future growth. So we tend to combine all those things together. We're actually not making a choice currently, a capital allocation decision between the basins. We think they're both strong places to invest going forward. 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 that we're 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?

Stanley Graham Chapman, III -- Executive Vice-President and President of US Natural Gas Pipelines

Yes, this is Stan. I'll just give you color commentary with respect to the Appalachian basis and our projects. If you think of the Appalachia as producing somewhere north of 25 Bcf a day, today growing to 40 Bcf by the end of the next decade. In support of that, I would note that we recently on January 1, put our Leach XPress project into service at 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. That's in an environment where if you look at the forward prices on the NYMEX, it's hard to find a lot of threes out there.

Gas prices on the forward strip or sub-$3.00 for the most part, which is good to the extent that's going to track new demand, new demand in the form of LNG exports. That's one of the key signpost that we are 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 three to five years. So continued growth out of the Marcellus. 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's going to fill up, not unlike our Leach XPress project did.

Karl Johannson -- Executive Vice-President & President, Canadian and Mexico Gas Pipelines and Energy

Maybe I'll just make a comment as well. We talked a lot about when we went and took this position in the Marcellus and why the Columbia assets were such a great fit for us. When I view the work that we've got ahead of us and the business that we've got ahead of us, I don't see it as an either/or as a capital allocation decision at all. I think we're sitting on two of the best resources in North America and I think that they're very, very complementary. And as a matter of fact, when we worked 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 have done, the WCSB markets have been impacted by Appalachian gas. When we didn't have a position in it, we lost some of our US Northeast markets. We've seen Rover, we've seen Nexus come into our Dawn market. We have seen the Bakken Associated Gas decrease the model of WCSB gas that goes down to the northern border. I guess what I would say is that we still have lots of work to do and I just don't see any issue between allocated capital between the two of them. Both of these basins are competitive and I think that if we are not working in one, that gas will still move. So I think we've got to be very mindful 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.

Andrew Kuske -- Credit Suisse -- Analyst

Maybe if I can, Karl, while you are on a roll on this topic. Do you foresee the possibility in the future of have an integrated tolling offering on Nova System and the Mainline on a long-term contracted bases to hit Dawn or even farther than Dawn?

Karl Johannson -- Executive Vice-President & President, Canadian and Mexico Gas Pipelines and Energy

Well, I don't think it's a secret that for many, many years now I've been out talking about the advantages of rolling the Mainline into NGTL. I actually did that in a hearing once. I wasn't all that successful in the hearing, but those were different days. I am out on the stump again, in the market here, talking to the producers field, giving them some of the benefits of merging these two systems and the competitive business benefits, especially to accessing and keep some of our markets down east. On the other hand, I'll end the discussion on a very high-level discussion of why I think it works pretty well.

No. 1 is, by the time we're finished our NGTL build-out, at least the phase of it, we are going to see an NGTL system probably had 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 just take a look at the law of large numbers, it really makes sense for a competitor of the WCSB to put the Mainline into NGTL and make it part of the NGTL tolling structure. It's just you get far more billing determinants in NGTL than you do 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 is 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 decrease that tolling by 30%-45% depending upon tolling methodologies that we would use to merge in the two systems. So yes, I'm going to continue talking to our producers to see if I can't convince them they should take this seriously. I do think it's the right thing to do.

Andrew Kuske -- Credit Suisse -- Analyst

I think so too.

David Moneta -- Vice President, Investor Relations

Thanks, Andrew.

Operator

Thank you. The next question is from Ted Durbin from Goldman Sachs. Please go ahead.

Ted Durbin -- Goldman Sachs -- Analyst

Thanks. 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 the producing community like you did like the 1.4 Bcf a day that you announced last year in order to attract more long-term commitments?

Karl Johannson -- Executive Vice President & President, Canadian and Mexico Gas Pipelines and Energy

Hi, this is Karl, again. Yes, we're actually looking at that right now. I think we have to be realistic about what type of product that we can offer. The last product that we offered, we had 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 at 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 non-renewals, 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 and on a longer-term basis.

So I think we are working on this right now or not only our producer 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 condition could be. So I think you will find us. We're working on 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 the product.

Ted Durbin -- Goldman Sachs -- Analyst

Got it. Okay, that's helpful. Sticking with the producer theme for pipeline tolls, if you think about West Coast LNG, one of the hang ups, of course, has been 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 it been just the developers or the buyers that would pay for that?

Karl Johannson -- Executive Vice-President & President, Canadian and Mexico Gas Pipelines and Energy

Yes, actually, there's been lots of discussion both from various groups of producers, governance, you name it, on what the NGTL System can do to use us have to help that cost. 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 will be a very long pipe in order to do that. But having said that, 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 the producers. But as of right now, I would say there is nothing concrete on the ground, just a bunch of talk about how would be nice if something like that could happen and it looks like it's a long way off.

Russell Girling -- President and Chief Executive Officer

Just to be clear for the Coastal GasLink -- Canada LNG project that the pipeline tolls haven't been an issue. Our understanding in talking to the sponsor, Shell and its partners, the issues have been in 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 and it appears it's competitive. I think that was one issue. The other one was capital availability and capital allocation within Shell. I think a couple of years ago, they announced that due to lower capital availability they couldn't proceed with several major projects at one time and, but that LNG Canada was still highly ranked within their company.

As crude prices returned, they finished other projects. We believe it's still a high priority for capital allocation within Shell. So I think those are the major drivers. It would be best 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 one based on Shell and its partners' outlook of their capital availability and end markets.

Ted Durbin -- Goldman Sachs -- Analyst

That's great. I appreciate all the color. Thank you.

David Moneta -- Vice President, Investor Relations

Thanks, Ted.

Operator

Thank you. The next question is from Tom Abrams from Morgan Stanley. Please go ahead.

Tom Abrams -- Morgan Stanley -- Analyst

Thank you and thank you for this all information. It's a lot to process. Just remaining for me was about Mexico and if it is much as Mexican gas demand is taking a lot 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?

Karl Johannson -- Executive Vice-President & President, Canadian and Mexico Gas Pipelines and Energy

Hi, Tom, it's Karl. No, we haven't -- actually, the projects are the ones that are being delayed there right now, not the access to gas and the need for gas. I would note that CFE has many power still running on fuel oil that they wish were not running on fuel oil. So our expectation is that as soon as we bring our plants into service, they will utilize us per the plan from CFE.

As per 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 their strategy. Most of the gas pipelines there right now are built for power plants. They're either in the process of being built or already built and running on fuel oil. So once these pipelines are put in service, you will see them operate at the low factor that was predicted by the CFE at the time they tendered it.

Tom Abrams -- Morgan Stanley -- Analyst

Great. That's it. Thanks a lot for all your time.

David Moneta -- Vice President, Investor Relations

 Great. Thanks, Tom.

Operator

Thank you. The next question is from Naqi Raza from Citi. Please go ahead.

Naqi Raza -- Citi -- Analyst

Thank you, 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 a very low level of contracting take-or-pay firm commitments on that line?

Paul Miller -- Executive Vice-President and President

Nick, it's Paul here. We did go to an open season late last year, and we did secure additional contracts on Keystone. It takes us up to 550,000 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 out earlier this year and termed out some of that space. 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.

Naqi Raza -- Citi -- Analyst

And other pre-Keystone XL, correct?

Paul Miller -- Executive Vice-President and President

Yes. Thank you for that. That's what I was trying to get to. The pre-XL, we do have a restriction on that space, so it's limited how much we can term up, but 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%-plus is now locked down by contract.

Naqi Raza -- Citi -- Analyst

Fair enough. 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?

Karl Johannson -- Executive Vice-President & President, Canadian and Mexico Gas Pipelines and Energy

Well, it would dependent and how the overrun was realized. Under our contracts with 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 would be the government is responsible for indigenous consultations and if those are slow or other parts of the force majeure that are the responsibility of the government to take care of. Then, we would pass those costs increase through to the CFE. We've had a couple of these before in the past, sometimes they get passed through the toll, sometimes they get settled with the financial settlement, sometimes they get settled with an incremental deal. But 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. 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 regulated rate, so to speak, in Mexico will go up and then we'll attempt to capture those cost increases.

Naqi Raza -- Citi -- Analyst

Fair enough. That's great color. Thanks, guys.

David Moneta -- Vice President, Investor Relations

Good. Thanks, Nick.

Operator

Thank you. The next question is from Matthew Taylor from Tudor Pickering. Please go ahead.

Matthew Taylor -- Tudor Pickering -- Analyst

Good afternoon, guys. Thanks for taking my question. Just a quick follow-up on Karl's earlier comments. With contracts on ANR stepping down in 2020 and 2021 room on the Great Lakes seems like there's an opportunity to get Canadian volumes down to the US Gulf Coast through a potential maybe an ANR reversal or something else. Can you just give me some thoughts on what markets you're focused on with the Mainline going forward?

Karl Johannson -- Executive Vice-President & President, Canadian and Mexico Gas Pipelines and Energy

Maybe I could say this and I can let Stan jump in, because Stan is the one working most of this. But you won't see a tariff from us that we would go up to market with, with the contiguous path without question. You've got Canadian pipelines and you've got US pipelines. But a customer is certainly, if we have the capacity or if we could build the capacity quite frankly, we will market customers and customers are free to come to us and asked us to look at different paths for them to see if we can move their product. As I've said before, we can get all the way down to the Gulf Coast, and except for the small blank spaces, we can get only in 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 US would have to kind of put together a Canadian tariff and a Great Lakes tariff, and a Mainline tariff, that sort of thing, but that certainly is possible and I know there are people have talked to us in the past. So maybe I'll pass it over to Stan and he can talk about any broader plans he has on that.

Stanley Graham Chapman, III -- Executive Vice-President and President of US Natural Gas Pipelines

I think your question is a good one. It really highlights the need for Karl's team in Canada and my team in the US to work closely together. Big picture-wise, we do have generally available capacity on the Great Lakes system, so to the extent there is another LTF2-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 a half a Bcf a day or so into the Chicago area. 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 a 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 generally available capacity on the ANR system is spoken for and spoken for a term of about 30 years.

Matthew Taylor -- Tudor Pickering -- Analyst

That's great, guys. Thanks for the color. And then just one more, moving over to North Montney. Is there any kind of a read-through from the export announcement [inaudible] [01:29:55] made in its proceedings or at least strengthening your positioning in providing more egress for shippers to clear increased receipts from the North Montney?

Karl Johannson -- Executive Vice-President & President, Canadian and Mexico Gas Pipelines and Energy

Sorry, I didn't get all that, but I assume your question was there was some concerns that we're bringing more supply on that market, and that was a big complaint of some people from the North Montney. I guess I would say this about that issue. No. 1, it's TransCanada' s role to sit there in judgment of how people are going to market their gas. The last thing I think the producers want in the market is for TransCanada to decide who brings their gas on and who doesn't. That type of supply management is just not our role and I think 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 seizes 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 between now between 2020 and 2021, we put in place a 2.2 billion cubic feet per day of new market opportunities, both down south through GTN and to the Pacific Northwest of California, out to Empress, which will ultimately go east and even internal to the NGTL System.

On top of that, we have natural decline of our system, which is running a couple billion cubic feet a year. You have to be careful when you start trying to micromanage a system like ours as to what supply comes on and which 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, but we will not get the billing determinant, 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 say 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.

Matthew Taylor -- Tudor Pickering -- Analyst

Thanks, guys. That's helpful.

David Moneta -- Vice President, Investor Relations

Thanks, Mathew.

Operator

Thank you. The next question is from Joe Gemino from MorningStar. Please go ahead.

Joe Gemino -- MorningStar -- Analyst

Hi, guys. Thanks for the time. 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 US Gulf Coast? Or is there some other type of mix that you can elaborate on?

Paul Miller -- Executive Vice-President and President

Hi, 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 onto XL. I would anticipate XL will really be a Hardisty to, let's call it Cushing and Gulf Coast pipeline. And then the existing Keystone Mainline will kind of serve that Midwest market into Illinois.

Joe Gemino -- MorningStar -- Analyst

Great. 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?

Paul Miller -- Executive Vice-President and President

Right now, you mean?

Joe Gemino -- MorningStar -- Analyst

No. when the Keystone XL is brought online and fully in service.

Paul Miller -- Executive Vice-President and President

No. When the Keystone system, including the XL project is fully built out, the XL link will be the sole transportation, if you wish, to the Gulf Coast. We'll isolate the lines. We'll effectively have a bullet line from the North to the Gulf Coast on the XL project. Then we'll have a second bullet line, again, from Hardisty into the Midwest. We would have opportunities in the future, assuming demand is there. We can underpin it with contracts to loop our Cushing extension, which is the line today which runs from Steele City down to the Gulf Coast. That would provide Gulf Coast access off the existing legacy Keystone system as well. So right after we hit in service, consider it two bullet lines -- one to the Gulf Coast, one to the Midwest, but as supply builds, as demand grows, we do have expansion looping opportunities so that we can feed the Gulf Coast from the legacy system as well.

Joe Gemino -- MorningStar -- Analyst

Great, I appreciate that.

Paul Miller -- Executive Vice-President and President

You're welcome.

David Moneta -- Vice President, Investor Relations

Thanks, Joe.

Operator

Thank you. This concludes today's question-and-answer session. I would like to turn the meeting back over to Mr. Moneta.

David Moneta -- Vice President, Investor Relations

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.

Operator

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

Duration: 96 minutes

Call participants:

David Moneta -- Vice President, Investor Relations

Russell Girling -- President and Chief Executive Officer

Donald Marchand -- Executive Vice President and Chief Financial Officer

Paul Miller -- Executive Vice-President and President

Stanley Graham Chapman, III -- Executive Vice-President and President of US Natural Gas Pipelines

Karl Johannson -- Executive Vice-President & President, Canadian and Mexico Gas Pipelines and Energy

Jeremy Tonet -- J.P. Morgan -- Analyst

Robert Kwan -- RBC Capital Markets -- Analyst

Linda Ezergailis -- TD Securities -- Analyst

Ben Pham -- BMO Capital Markets -- Analyst

Ben Pham -- BMO Capital Markets -- Analyst

Praneeth Satish -- Wells Fargo -- Analyst

Andrew Kuske -- Credit Suisse -- Analyst

Ted Durbin -- Goldman Sachs -- Analyst

Tom Abrams -- Morgan Stanley -- Analyst

Naqi Raza -- Citi -- Analyst

Matthew Taylor -- Tudor Pickering -- Analyst

Joe Gemino -- MorningStar -- Analyst

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