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Good day, ladies and gentlemen. Welcome to the TransCanada Corporation 2018 Second Quarter Results Conference Call. I would now like to turn the meeting over to Mr. David Moneta, Vice President, Investor Relations. Please go ahead, Mr. Moneta.
Thanks very much and good morning, everyone. I'd like to welcome you to TransCanada's 2018 second quarter conference call. With me today are Russ Girling, President and Chief Executive Officer; Don Marchand, Executive Vice President and Chief Financial Officer; Karl Johannson, President of our Canada and Mexico Natural Gas Pipelines and Energy; Stan Chapman, President, U.S. Natural Gas Pipelines; Paul Miller, President, Liquids Pipelines; and Glenn Menuz, Vice President and Controller. Russ and Don will begin today with some opening comments on our financial results and certain other company developments. A copy of the slide presentation that will accompany their remarks is available on our website at transcanada.com. It can be found in the Investors section under the heading Events. Following their prepared remarks, we will take questions from the investment community.If you are a member of the media, please contact Nicole Forrest following this call and she will be happy to address your questions. [Operator Instructions] Before Russ begins, I'd like to remind you that our remarks today will include forward-looking statements that are subject to important risks and uncertainties. For more information on these risks and uncertainties, please see the reports filed by TransCanada with Canadian securities regulators and with the U.S. Securities and Exchange Commission. And finally, I'd also like to point out that during this presentation, we'll refer to measures such as comparable earnings, comparable earnings per share, comparable earnings before interest, taxes, depreciation and amortization or comparable EBITDA, comparable funds generated from operations, and comparable distributable cash flow.These and certain other comparable measures are considered to be non-GAAP measures. As a result, they may not be comparable to similar measures presented by other entities. They 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.
Thank you, David. And good morning, everyone, and thank you very much for joining us today. As highlighted in our quarterly report to shareholders released earlier today, we are very pleased to announce second quarter financial results, which we expect to contribute to record financial performance in 2018. As outlined in the report, our $92 billion portfolio of high-quality energy infrastructure assets continues to profit from strong underlying market fundamentals and we are realizing the growth expected from our industry-leading near-term capital expansion program. Evidence of that can be seen in our comparable earnings per share of $0.86 and $1.83 for the 3 and 6 months ended June 30, 2018, which both support our Board of Directors' decision in February to increase our quarterly common dividend to $0.69 per share. That equates to $2.76 per share on an annual basis and represents a 10.4% increase over the dividend in 2017.During the quarter, we also advanced our $28 billion near-term capital program, which now includes approximately $5.8 billion of maintenance capital expenditures over the 2018 to 2020 period. Approximately $10 billion of those projects are expected to enter service by the end of 2018. They include several NGTL system expansions; Columbia's Mountaineer, WB and Gulf XPress projects; Sur de Texas natural gas pipeline in Mexico and the Napanee gas-fired power plant in Ontario. We also continue to advance over $20 billion of medium to longer-term projects including Keystone XL, Coastal GasLink and the Bruce Power life extension program. Finally, we have also made significant progress funding our capital program by raising approximately $6.1 billion so far this year. That includes $4.3 billion of long-term debt which was issued at very compelling rates, $1.2 billion of common equity that has been raised through a dividend reinvestment program as well as our at-the-market equity program.And as was announced earlier today, we raised $630 million from the sale of our 62% interest in the Cartier Wind facility. Collectively, that represents a very sizable component of our 2018 funding requirements. Looking forward, we expect our strong operating and financial performance to continue and therefore comparable earnings on a per share basis in the second half of 2018 are expected to be similar to the results achieved in the first half of the year. At the same time, our overall financial position remains solid and we believe that we are well positioned to fund our $28 billion near-term capital program without the need for discrete common equity. Don will provide more details on our funding programs in just a moment. But before that, I'll expand on some of the recent developments beginning with a brief review of our second quarter financial results.Excluding certain specific items, comparable earnings were $768 million or $0.86 per share, an increase of $109 million or $0.10 per share over the second quarter of 2017 despite the sale of our U.S. Northeast power generation assets and our Ontario solar assets last year. This equates to a 13% increase on a per share basis recognizing the effect of common shares issued in 2017 and 2018 under the dividend reinvestment program and ATM program. Comparable EBITDA increased $161 million to approximately $2 billion while comparable funds generated from operations of $1.5 billion was $92 million higher than the second quarter of 2017. Those amounts reflect the strong performance of our legacy assets, contributions from approximately $7 billion of growth projects that were completed and placed into service over the last 12 months and the positive impacts of U.S. tax reform.On a year-to-date basis, comparable earnings of $1.83 per share, an increase of about $0.27 or 17% compared to the first half of 2017. Comparable EBITDA increased $247 million to approximately $4.1 billion while comparable funds generated from operations of $3.1 billion were $195 million higher than the same period last year. Don will also provide more detail on our second quarter financial results in just a moment. But before he does, a few comments on our recent developments in each of our businesses beginning with Natural Gas Pipelines. Firstly, in Canadian Natural Gas Pipelines, we continue to advance $7.4 billion of commercially secured growth projects on the NGTL system. They include the $1.6 billion Montney -- North Montney project, which we received approval from the National Energy Board and the Federal government in the second quarter.The 1.5 Bcf per day project is anticipated to have the first phase in service by the fourth quarter of 2019 and the second phase is expected to follow by the second quarter of 2020. We also filed an application with the NEB for approval of our 2021 expansion project, which is underpinned by a request for new receipt and delivery capacity. The expansion includes construction of about 344 kilometers of new pipeline and 3 compressor units at an estimated capital cost of $2.3 billion. Finally, on the NGTL system, we received approval from the National Energy Board for a negotiated settlement with customers that covers the 2018 and 2019 periods. The settlement amongst other things fixes the base return on equity at 10.1% on 40% deemed common equity, which is consistent with our previous agreement.Looking forward, customer demand for access to our Canadian systems remains strong and we continue to work with industry on options to connect growing Western Canadian gas supply to markets across North America. As we have said before, that could include potential restoration of dormant capacity on the Canadian Mainline. At the same time, we continue to actively work with LNG Canada on our Coastal GasLink project, which would provide another significant market outlet for Canadian Gas. We anticipate that LNG Canada could make a final investment decision on their project in the fourth quarter of this year. Moving to our U.S. Natural Gas Pipelines. During the second quarter, we advanced $6.1 billion of expansion projects including Columbia's Mountaineer, WB and Gulf XPress projects. All 3 of those projects are expected to enter service by the end of 2018 at a combined investment of approximately USD 4.5 billion.Looking forward, we expect our Columbia system to continue to generate organic growth opportunities as natural gas production continues to grow in the Marcellus and Utica regions. We are also looking at other opportunities across the broader U.S. Natural Gas portfolio and those are slowly coming to fruition. Finally, in U.S. Pipelines, a few comments on the recent FERC actions and their implications for TransCanada. On July 18, FERC issued a final rule adopting certain revisions to the proposed FERC actions originally announced on March 15, 2018. We do not expect the earnings and cash flows from our directly held U.S. Natural Gas Pipelines including ANR, Columbia Gas and Columbia Gulf will be materially impacted as a result as they are held through wholly-owned taxable corporations and a significant portion of their revenues are earned under non-recourse rates.Further, as our ownership interest in TC PipeLines LP is 25%, the impact of the final FERC actions related to our LP is not expected to be significant to our consolidated earnings or cash flows. Finally, while the revisions to the proposed FERC actions are directionally positive, it is yet to be determined if and when in the future TC PipeLines LP might be restored as a competitive funding option for TransCanada. Regardless, as we have said many times before, we believe that we have the financial capacity to fund our existing capital program so our predictable and growing cash flow from operations and several other funding alternatives. Turning to Mexico where we are advancing construction of 3 pipelines at a total cost of about USD 2.8 billion. Offshore construction of the Sur de Texas pipeline was completed in May and continues to progress towards an anticipated in-service date of late 2018.The Villa de Reyes project and the Tula project are anticipated to be in service in 2019 and 2020 respectively. While both projects are facing some delays, we continue to work toward finalizing and making agreements for both pipelines with the CFE. In the interim, payments are being received in accordance with their respective transportation service agreements. Turning to our Liquids business, which again produced strong results in the second quarter of 2018. Keystone continues to perform well underpinned by long-haul take or pay contracts for about 550,000 barrels a day. Grand Rapids and Northern Courier were both placed into service in the second half of 2017 and are now contributing to EBITDA. In addition, we continue to benefit from higher contracted and uncontracted volumes on our market-linked project as well as higher contribution from liquids marketing largely due to favorable market conditions and that is expected to continue over the remainder of this year.Finally, few comments on Keystone XL. In June the South Dakota Supreme Court dismissed an appeal against the recertification of the project finding that the lower court lacked jurisdiction to hear the case. The decision is final as there can be no further appeals from this decision. In Nebraska, the Nebraska Supreme Court agreed to bypass the court of appeals and hear the appeal case in Nebraska -- against the Nebraska Public Service Commission's alternatives route itself. We remain confident the public interest determination of the Nebraska Public Service Commission was lawful and expect that the Nebraska Supreme Court could reach a decision by late 2018 or the first quarter of 2019. At the same time, we continue to work collaboratively with landowners in Nebraska to obtain the necessary easements for the approved route.To date, we have obtained negotiated easements for approximately 62% of the route in the state and we expect that that percentage will continue to rise in the coming months. Finally, on the regulatory front. The U.S. Department of State conducted a supplemental environmental review following the approval of the alternative route in Nebraska and they issued a draft Environmental Assessment on Monday. The assessment determined the pipeline would have no significant environmental impact. The report supports the issuance of the permits from the Bureau of Land Management for access to federal lands expected to be issued later this year. On the commercial front, in January we successfully secured 500,000 barrels a day of firm 20-year commitments, which is consistent with the original level of contracting on Keystone XL prior to the denial of the Presidential Permit in November of 2015.Potential shippers continue to expect -- express interest in the remaining capacity available on Keystone XL as well as any capacity that could be made available on the existing Keystone system. We expect those discussions will lead to additional long-term take-or-pay commitments and we would anticipate that the pipelines capacity would be fully subscribed in the coming months. The new contracts combined with existing contracts on the Keystone system that convert to long-haul agreements on Keystone XL means it will be fully subscribed by long-term contracted shippers after factoring in capacity, which we are required by regulators to set aside for spot shippers. And finally, our preparation for construction continues and will increase as the permitting process advances through the balance of 2018.Turning to our Energy business. Construction on the Napanee project continues and is expected to be placed in service in late 2018 at a cost of approximately $1.5 billion. Work also continues on the Bruce Power life extension project with more significant investments to extend the operating life of the facility to 2064 scheduled to begin in 2020 and continue through 2033. That investment will commence with the Unit 6 major component replacement project, which is expected to begin in January of 2020. Detailed project planning continues and the cost of that project is expected to be finalized in the fourth quarter of this year. And finally, earlier today we announced an agreement to sell our 62% interest in the Cartier Wind project for approximately $630 million.That sale allows us to [ source ] a significant value for a mature asset that represented approximately 5% of our generating capacity and redeploy that capital into our $28 billion capital program thereby reducing our need for external capital including common equity. So in summary, we continue to advance our $28 billion near-term capital program. We have invested about $10 billion into that program to date and it largely continues to advance on time and on budget. These projects are all underpinned by long-term contracts or rate-regulated business models. As a result, we have a high degree of visibility to the earnings and cash flow growth that will be generated as they enter service. As I mentioned earlier today, our near-term capital program now includes approximately $5.8 billion of maintenance capital expenditures over the 2018 to 2020 period.As maintenance capital has always been incorporated into our finance plans, we believe adding it into our near-term capital table will provide a more consistent view of our total capital commitments over the next few years. Approximately 85% of our maintenance capital is related to regulated natural gas pipelines and therefore is expected to be added to rate base and to generate a return on enough capital similar to what we realized on expansion projects. As a result, in conjunction with this change in presentation, we will now provide just a single measure of distributable cash flow reflecting our only non-recoverable maintenance capital. We believe this provides the most accurate depiction of cash available for reinvestment and distribution to our shareholders. Also consistent with our comments in the past, we believe comparable distributable cash flow per share is just one measure investors should consider in evaluating our financial performance.In our view, growth in earnings and cash flow on a per share basis remain the most important measures of our long-term value creation. Turning to our outlook for growth in EBITDA. As you can see on this chart, comparable EBITDA grew from $5.9 billion in 2015 to $6.6 billion in 2016, $7.4 billion in 2017 and as we reported here earlier today, $4.1 billion for the first half of 2018. That growth is expected to continue with EBITDA of approximately $9.5 billion expected in 2020 as we largely complete our near-term capital program. That equates to a compound average growth rate of approximately 10% over the 5-year time horizon. Also of note, over 97% will be derived from regulated or long-term contracted assets. In addition, we are advancing $20 billion of medium to longer-term projects currently in the advanced stages of development. Any one of these projects could further enhance our growth profile as well as our strong competitive position.Based on our confidence in our growth plans, we expect to continue to grow the dividend at an average annual rate that is at the upper end of the 8% to 10% range through 2020 and another 8% to 10% in 2021. As I said earlier, the growth in dividends is supported by expected growth in earnings and cash flow per share and strong distributable cash flow coverage ratios. In summary, I'd leave you with the following key messages. Today, we are a leading North American energy infrastructure company with a strong track record of delivering long-term shareholder value. Our assets are critical to the functioning of the North American economy and the demand for our services remains very strong. With $92 billion of high-quality assets and 7,500 talented employees, we have 5 significant platforms for continued growth; Canadian, U.S. and Mexican Natural Gas Pipelines, Liquids Pipelines and Energy.As we advance our $28 billion near-term capital program, we expect to deliver additional growth in earnings and cash flow per share. As a result, we expect to grow our common dividend at the upper end of 8% to 10% on an annual basis through 2020 and foresee an additional growth of 8% to 10% in 2021. In addition, 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 and/or other initiatives could extend our growth outlook. At the same time, we have maintained a strong financial position to ensure that we are well-positioned to prudently fund our ongoing capital programs.That concludes my prepared marks and I'll turn it over to Don, who will provide more details on our second quarter financial results.
Thanks, Russ, and good morning, everyone. As outlined in our quarterly results issued earlier today, net income attributable to common shares was $785 million or $0.88 per share in the second quarter of 2018 compared to $881 million or $1.01 per share for the same period in 2017. Excluding specific items, comparable earnings of $768 million or $0.86 per share in second quarter 2018 were $109 million or $0.10 per share higher year-over-year. Notwithstanding the sale of our U.S. Northeast power generation and Ontario solar assets in 2017, this equates to a 13% increase on a per share basis after also giving effect to common shares issued under the dividend reinvestment plan and at the market program. Our positive results reflect operational strength and solid cash generation across all our businesses, particularly U.S. Natural Gas Pipelines and Liquids Pipelines and include the net benefits of the U.S. tax reform.Turning to our business segment results on Slide 16. In the second quarter, comparable EBITDA from our 5 operating businesses was approximately $2 billion representing $161 million increase in 2017. As outlined in the quarterly report, Canadian Natural Gas Pipelines comparable EBITDA of $545 million was $18 million higher than for the same period last year. Net income for the NGTL system increased $9 million compared to second quarter 2017 as a result of a higher average investment base from continued system expansions, partially offset by lower incentive earnings and reflects a base ROE of 10.1% on 40% deemed equity as approved in our 2018-2019 rate settlement. Conversely, net income for Canadian Mainline decreased $4 million primarily because no incentive earnings have been recorded in 2018 pending an NEB decision on the 2018 to 2020 Tolls Review.I would note that for Canadian Natural Gas Pipelines, changes in depreciation, financial charges and income taxes impact comparable EBITDA; but do not have a significant effect on net income as they are almost entirely recovered in revenues on a flow-through basis. U.S. Natural Gas Pipelines comparable EBITDA of USD 546 million or CAD 704 million in the quarter increased by USD 136 million or CAD 153 million compared to the same period in 2017 mainly due to increased contributions from Columbia Gas and Columbia Gulf growth projects placed in service, additional contract sales on ANR and Great Lakes, favorable commodity prices for midstream and increased earnings from the amortization of the regulatory liability recognized following U.S. tax reform. Mexico Natural Gas Pipelines comparable EBITDA of USD 110 million or CAD 142 million was in line with second quarter 2017.Liquids Pipelines comparable EBITDA rose by $81 million to $413 million driven by the additions of Grand Rapids and Northern Courier, which began operations in the second half of 2017; higher volumes on the Keystone Pipeline System; higher contribution from liquids marketing activities and lower business development costs as we have recommenced capitalization of Keystone XL expenditures. Energy comparable EBITDA decreased by $85 million year-over-year to $202 million due to lower contributions from U.S. Power and Eastern Power following the sale of generation assets in 2017, increased outage days and lower results from contracting activities at Bruce Power and narrower spreads realized by natural gas storage. These reduced results were partially offset by higher realized prices on increased generation volumes for Western Power.For all our businesses with U.S. dollar-denominated income; including U.S. Natural Gas Pipelines, Mexico Natural Gas Pipelines and parts of our Liquids Pipelines and Energy businesses; Canadian dollar translated EBITDA was negatively impacted versus the second quarter of 2017 by a weaker U.S. dollar. This was largely offset by lower translated interest expense on U.S. dollar-denominated debt and realized hedging gains reported in comparable interest income and other. Regarding our exposure to foreign exchange rates, our U.S. dollar-denominated assets are predominantly hedged with U.S. dollar-denominated debt and the associated interest expense. We continue to actively manage the residual exposure on a rolling 1-year forward basis.Now, turning to the other income statement items on Slide 17. Depreciation and amortization of $570 million increased $54 million versus second quarter 2017 largely because of new facilities entering service across our businesses and a higher depreciation rate on NGTL, partially offset by the sale of power generation assets in 2017 and a weaker U.S. dollar. Interest expense of $558 million was $34 million higher year-over-year following new debt issuances net of maturities and lower capitalized interest on Liquids Pipelines projects placed in service in 2017, partially offset by the repayment of Columbia acquisition bridge facilities in the second quarter 2017 and the impact of a weaker U.S. dollar in translating U.S. dollar-denominated interest. AFUDC decreased by $8 million for the 3 months ended June 30, 2018, compared to the same period in 2017.The decline in Canadian dollar denominated AFUDC was principally due to the October 2017 decision not to proceed with the Energy's pipeline project and completion of the NGTL 2017 expansion program. While an increase in U.S. dollar-denominated AFUDC was largely driven by additional investment in and higher rates on Columbia Gas and Columbia Gulf growth projects as well as continued investment in new Mexican pipelines. Interest income and other included in comparable earnings increased by $15 million in the second quarter versus 2017 primarily as a result of the net effect of higher interest income on an inter-affiliate loan receivable from Sur de Texas and realized hedging gains in 2018 on foreign exchange management compared to realized losses in 2017, partially offset by the foreign exchange impact on the translation of foreign currency denominated working capital balances and income related to the reimbursement of Coastal GasLink project cost recorded in 2017.The interest income on the inter-affiliate loan is fully offset by interest expense included in Sur de Texas equity income within Mexico Natural Gas Pipelines EBITDA. Income tax expense included in comparable earnings was $146 million in second quarter 2018 compared to $198 million for the same period last year primarily on account of reduced tax rates under U.S. tax reform and lower flow through income taxes on Canadian rate regulated pipelines, partially offset by higher pretax comparable earnings. Excluding Canadian rate regulated pipelines where income taxes are a flow-through item, I know that's quite variable, along with equity AFUDC income in U.S. and Mexico Natural Gas Pipelines, we expect our 2018 full year effective rate to be in the mid-to-high teens. Net income attributable to non-controlling interest increased by $21 million for the 3 months ended June 30, 2018, mostly due to higher earnings in TC PipeLines LP. And finally, preferred share dividends were comparable to second quarter 2017.Now moving to cash flow and distributable cash flow on Slide 18. Comparable funds generated from operations of approximately $1.5 billion in the second quarter reflects an increase of $92 million year-over-year driven largely by higher comparable earnings as outlined and after allowing for the impact of power generation asset sales in second and fourth quarter 2017. Previously we provided 2 measures of comparable distributable cash flow, one factoring an all maintenance capital and another including only non-recoverable maintenance capital. Starting this quarter, we will provide a single measure reflecting only non-recoverable maintenance capital. As Russ noted in his remarks, maintenance capital amounts where we have the opportunity to earn a return of and on such capital through tolls on our Canadian and U.S. rate-regulated pipelines or recover them in tolls and our Liquids Pipelines will no longer be deducted from distributable cash flow.This represents approximately 85% of current maintenance capital expend. Going forward, 3 years of all estimated maintenance capital will now be reflected in our near-term capital projects table. We believe that including only non-recoverable maintenance capital in the calculation of distributable cash flow conveys the best depiction of cash available for reinvestment or distribution to shareholders as our ability to recover rate-regulated maintenance capital expenditures through current or future tolls is effectively the same as that of growth capital. As a result, distributable cash flow in the quarter as now defined was approximately $1.3 billion or $1.46 per share compared to $1.2 billion or $1.36 per share in the second quarter of 2017 resulting in a coverage ratio of 2.1x. We continue to expect to maintain strong DCF coverage through 2020.Now turning to Slide 19. During the second quarter, we invested approximately $2.6 billion in our capital program and successfully funded it through strong and growing internally generated cash flow, long-term debt issuance and common equity from our dividend reinvestment plan and at-the-market program. In the 3 months ended June 30, 2018 we issued USD 2.5 billion of senior unsecured notes comprised of USD 1 billion of 10-year notes at a fixed rate of 4.25%, USD 500 million of 20-year notes at a fixed rate of 4.75% and USD 1 billion of 30-year notes at a fixed rate of 4.875%. In early July we raised $1 billion through a Canadian medium-term notes offering comprised of $200 million of 10-year notes at a fixed rate of 3.39% and $800 million of 30-year notes at a fixed rate of 4.182%. Our dividend reinvestment plan or DRIP continues to provide incremental subordinated capital in support of our growth and credit metrics.In the second quarter, the participation rate amongst common shareholders was approximately 33% representing $208 million of dividend reinvestment. Year-to-date the participation rate has been approximately 36% resulting in $442 million of common equity at a 2% discount. In June of last year, we established an at-the-market or ATM program that authorized 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. In the second quarter, 8.1 million common shares were issued under the program at an average price of $54.63 per share for gross proceeds of $443 million bringing year-to-date gross proceeds to $772 million. Combined with ATM activity in late 2017, this served to effectively exhaust the existing authorization.In June 2018 we replenished the ATM program capacity effective through July of 2019, which will allow us to issue up to an additional $1 billion of common shares from treasury or its U.S. dollar equivalent. Use of the ATM will continue to be influenced by our spend profile as well as the availability and relative cost of other funding sources. The program is highly flexible with a fee structure that is attractive even in comparison to DRIP. Some level of common share issuance through DRIP or ATM is viewed as a necessity now as we simultaneously prosecute a $28 billion capital program and deleverage. These should not, however, be viewed as permanent elements of our finance plan and we remain highly focused on share count and per share metrics. Going forward, we expect the recycling of capital through portfolio management to play an ongoing role in meeting our financing requirements.To that end, we -- as announced today, we have executed an agreement to sell our 62% interest in the Cartier power generation assets for approximately $630 million. The proceeds will contribute to funding our capital program. The sale is expected to close in the fourth quarter this year and result in an estimated gain of $130 million after tax. Now turning to Slide 20. This slide highlights our forecasted sources and uses of funds in 2018. Our capital requirements continue to be financed in a manner consistent with achieving targeted run rate credit metrics of a minimum 15% FFO to debt and maximum 5x debt to EBITDA. Starting in the left column, our dividend and non-controlling interest distributions of approximately $2.8 billion, 2018 capital expenditures projected to be $10 billion including maintenance capital and long-term debt maturities of $2.9 billion bring our total funding requirement for 2018 to approximately $15.7 billion.The middle column highlights aggregate sources of approximately $13.5 billion including forecast full year internally generated cash flow of about $6.4 billion and previously described funding year-to-date. This leaves an additional $2.2 billion balance of year requirement, which we expect to source through some combination of long-term debt, hybrid securities, ATM, and possibly further asset sales. As we assess this year and beyond, we iterate that we do not foresee a need for discrete equity to complete our near-term $28 billion capital program. In summary, while our external financing needs are sizable, they remain eminently achievable in the context of multiple financing levers available and the clear accretive and credit supportive use of proceeds. Now turning to Slide 21. In closing, I offer the following comments.Our solid across the board financial and operational results in the second quarter highlight our diversified low-risk business strategy and reflect the strong performance of both our blue chip legacy portfolio along with the contribution of equally high-quality assets from our ongoing capital program. Today we are advancing a $28 billion suite of near-term projects and have 5 distinct platforms for future growth; Canadian, U.S. and Mexico Natural Gas Pipelines, Liquids Pipelines and Energy. Our overall financial position remains strong. 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 supplemented further by capital recycling.Our portfolio of critical energy infrastructure projects is poised to generate significant growth in high-quality long life earnings and cash flow for our shareholders. That is expected to support annual dividend growth at the upper end of an 8% to 10% range through 2020 and an additional 8% to 10% in 2021. Success in adding to our growth portfolio in the coming years could augment or extend the company's dividend growth outlook further.That's the end of my prepared remarks. I will now turn the call back over to David for the Q&A.
Thanks, Don. [Operator Instructions] With that, I'll turn it over to the conference coordinator.
[Operator Instructions] The first question is from Linda Ezergailis from TD Securities.
With respect to the FERC recent ruling, I know there is still a lot of uncertainty. But can you give us some sense of a potential timeline to get clarity on various aspects of that? And within that, do you expect industry and TransCanada to request any further rehearing or clarification? Any context would be appreciated.
So Linda, this is Stan. I'll start and I'll just point out at the beginning that FERC's actions during July were actually directionally positive for us. They did a number of things. Most importantly while they clarified that the revised policy statement that MLPs should not receive a tax allowance still holds, they noted that pipelines are not necessarily mandated to comply with that policy now and in fact, they left the door open for pipelines on a case-by-case basis to justify a tax allowance. Procedurally the mechanism remains the same, which is pipelines are required to make these 501-G filings. The first round of filings will be made in October, the last round will be made in December. And I would expect that process is likely to continue into the first or maybe second quarter of 2019 until we get final clarity. Most importantly though, however, in the first option that you have which was to file a limited Section 4 rate case, FERC gave pipelines 2 different paths that they can go down. On one path they clarified that if you're an MLP, you can comply with the policy statement and incorporate a zero income tax allowance and in doing such, you would get to eliminate your deferred tax balance. That's significant. It's significant because eliminating the deferred tax balance actually increases rate base and helps to offset partially or maybe in some cases totally the decline you would otherwise see with the lower tax rates. The other option would be to reduce your tax rate solely to reflect the 21% FERC tax rate and then argue in the next rate case why that particular pipeline is in a unique position and should be able to continue collecting a tax allowance contrary to the commission's policy. So, a lot more work to come. I don't necessarily see us seeking any significant further clarifications. I think we have pretty good guidance right now. And I would say just bear with us as we make our first round of 501-G filings and we starting engaging with our customers and we'll probably engage with the customers here in advance of making those filings. In some cases we may be filing a limited Section 4, in other cases, we may just be filing the 501-G filings and saying that that's good enough. But each pipe has a unique set of facts and we'll deal with them on a case-by-case basis.
And then just as a follow-up to your U.S. Natural Gas Pipelines operationally. Your consolidated outlook for the company has improved versus prior disclosure and one of the factors was improved earnings from your additional contract sales and lower expenses in your U.S. Natural Gas Pipelines. Can you comment on the duration of the additional contract? And I'm assuming that the lower expenses would also translate into 2019 and beyond, but I'm also interested in understanding whether or not those contracts are shorter term or longer term.
So on the Columbia system, a lot of the increased earnings we're seeing is due to the new growth projects that are placed in service and obviously, those are long-term contracts that are going to be with us for a very long time. On the ANR and the Great Lakes system, we've been very successful in doing short-term year-to-year sales to capture those basis differentials, whether it's basis differentials coming out of the Permian and trying to find a way to get that gas to Chicago or whether it's basis differentials added at WCSB that's trying to migrate into the U.S. While the contractual terms are basically quarter-to-quarter, month-to-month, year-to-year particularly with respect to the Western Canadian Sedimentary Basin, we do see those volumes continuing to flow for a longer duration.
The next question is from Ben Pham from BMO.
Had a question on the Quebecois asset sale. And I look [indiscernible] is providing some more specific multiples on the sale and they're suggesting 9x to 9.5x EBITDA. And my question really is how do you guys think about reconciling that with some recent transactions that we've seen low double-digits and also to your own market multiple?
It's Don here Ben. Each asset is unique in terms of its contractual term and like and operational characteristics. So, it may not necessarily be apples to apples in the case of every single project, you need to drill down into that. I would just characterize it as saying we are very pleased with the number and the proceeds and they will be fully cash tax-sheltered, an important component of backfilling our funding plan here.
Maybe, Ben, I could just add to that. As you think about EBITDA multiples, it's just one measure of value and looking at your trailing 12 months is one way of calculating it or looking at your EBITDA multiple on a go-forward basis and then you have certain assumptions around what you think the market's going to look like post the contracted life of the asset. Everybody has different views of those kinds of things. The primary driver for us is can we service value at a lower cost to capital than our other sources and we've always said that we will use our lowest cost to capital when we look at the implied cost to capital here that we were able to achieve in selling this asset. It's well below what our incremental sources are. So, that fits for us in terms of adding value for our shareholders. This is how we come to those conclusions.
Alright. And then on the distributable cash flow revision, can you remind me when you're setting your dividend expectations on the growth going forward, it was always on this revise distributable cash flow. Is that correct? And I know you guys looked at EPS as well, but I wanted to check in and clarify that.
Ben, it's Don here again. I would describe DCF as a data point for us, really nothing more than that. Historically going back a couple of decades, our dividend is largely based on payout ratios driven by EPS and cash flow. So generally 80% to 90% of accounting earnings, which equates to about 40% area of cash flow. Those are probably the more critical points that we look at. DCF, as I mentioned, is really just a data point.
The next question is from Jeremy Tonet from JPMorgan.
Just wanted to start off with Mexico here and just wanted to see what updated thoughts you had on the geography post the elections here if anything has changed on that front as far as your appetite to expand there. And then I guess as well with regards to funding options, clearly, you look to the lower source of capital when looking to fund. But just wondering if this geography, these assets as far as could be sold, they were thought to be sold in the past. How that stacks up versus the ATM? If you could kind of share your thoughts on those dynamics, that will be helpful.
Well, Jeremy, it's Karl. Maybe I'll start by just talking about the overall environment in Mexico. There has been a new President elected. To date the President I think has said all the right things, particularly with our Energy and Natural Gas Pipelines and Electricity business. So, we are still waiting to get our first meetings with all the new appointees and whatnot. So we still have some familiarization to deal with this new administration, but to date, we're quite comfortable with what has been said and the actions that we've seen so far. I'll point out that what we're doing is fundamentally important for the economy of Mexico and we would expect that the natural gas business would continue to progress and grow as it has been in the past. So we will -- it's early days right now, but what we've seen so far doesn't concern us at all and it has demonstrated to us that it's more or less business as usual in our segment of the market. And for the funding discussion, maybe I'll turn it over to Don here.
Jeremy, it's Don. As we look at share count growth, we will look to portfolio management as a way of slowing that or removing it to the extent we can when we look at the comparative cost to capital there. Things we do factor in are strategic positioning, growth prospects of the assets, cash taxes and the like. So, not every asset is equal in that sense. I would say that, as I noted in my remarks, portfolio management will continue to play an important role here in the funding plan. I won't laundry list for you everything that we would conceivably look at selling. All I would say is that when we look at our suite of contracted assets across the entire portfolio, it really does dwarf 2 things. One, the list of assets we could have dropped down into the LP, which at this point is no -- is not -- still not considered a viable funding vehicle or the other box in our funding program. So, I just watch for us to continue to chip away at that without any real pre-announcements of this and then look to what we've done with the solars and Cartier and continue to look at one-off asset sales here for the time being.
And then just picking up on PCP there. If it's deemed to not be a viable funding vehicle anymore, just when do you think you might have the information sufficient to make that determination and if you reach that determination, what actions do you think you might take at that point? You realize don't want to get ahead of ourselves here, but would you look to kind of consolidate the entity in if it no longer serves the purpose you intended or this is strictly an economics decision and that's how TRP will address the situation?
It's Don here again. I think the news that came out here a couple of weeks ago is actually directionally positive for the LP. That said, it remains a work in progress to figure out, get some clarity on what it's really worth at the end of the day here as we work through -- Stan outlined all the various processes related to different filings and the like. I would say at this time, it remains a non-viable funding vehicle. It's unclear if and when in the future that might be restored since that's not definitive. In terms of potential buy-in, I would describe it as a possibility down the road. But until again we get clarity what ultimately it's worth, that's sometime down the road. But I'd also say it's neither a certainty nor a necessity for us to buy it in. So while directionally positive for the FERC actions here in July, I would say we are still kind of monitoring this and really no closer to a decision on it.
And maybe just to add to Don's comments is your question on whether it's an economic decision or are there other considerations to be brought to the floor. Primarily for us, it is an economic consideration, I think we've said that before. To the extent it makes economic sense for TRAP shareholders, we would consider it. To the extent that it doesn't, we wouldn't likely move down that path.
The next question is from Robert Kwan from RBC Capital Markets.
If I can come back just to the EPS outlook that you gave for the second half of the year and you touched on some of the factors in terms of whether they're ongoing. I was wondering if you can provide some color as well on things like market link tolls, walk up rates, marketing outlook. And as well just as related to what's going on at the FERC given you don't expect anything retroactive or anything immediate, how that might play into the outlook in future years?
Bob, It's Paul here. I'll start on the market link tolling and the marketing, et cetera. So our market link tolls, we have a range of tolls for contractual tolling. They range from around $2 to $2.50. Our spot walk-up rate, if I recall, is probably in the $3.25 range, but we'll cycle back and correct if I'm wrong in that regard. As far as outlook goes, in the second quarter, we saw softening of the market a little bit for those walk-up tolls in the early part of the quarter. As far as the volumes towards the end of the quarter, they picked up and then going into third quarter, they dropped off again and they've been relatively flat here so far in the third quarter. On the marketing side, kind of the same profile. We picked up some good value kind of midway through the second quarter and into the third -- towards the end of the second quarter. Going forward, we are able to capture some of that value and I would expect to see the marketing results to be probably upwards of $0.02 higher in Q3, might be able to hold that into Q4. So taken together, I would anticipate our results for marketing and market link to be slightly higher in the third quarter and into 4 with marketing contributing a bit more partially offset by some reduced volume on market link.
And then Robert, this is Stan. With respect to the FERC actions, like I said earlier, we'll be making our 501-G filings in October, November and December for the respective pipelines as required. And in terms of the impact on TRAP, I guess I'll just leave you with this. Last time we told you that it was basically immaterial to TRAP. The FERC actions here are directionally helpful so just think of that as being even more immaterial to TRAP at the end of the day.
Okay. And actually just in your second half outlook, does that include the booking of Mainline incentives?
No, actually. As it stands right now, we are not looking at incentives. We probably won't look at them until we get some good feedback from the board on which way the board's going to go now. I will say that although it's not -- it hasn't taken account incentives of the Mainline. I will say that we have got our intervening evidence in on the -- on the Mainline case and it was very modest. There was -- there is really only one issue to be adjudicated. So, I'm a little bit more optimistic we will have the adjudication of our rigs done before the end of the year than I was before. But no, we haven't included the Mainline incentives in the forward-looking view.
Robert, it's Don here. It wouldn't be a material amount regardless.
And then just finishing on funding and the Slide 20, I'm wondering how much of the $2.2 billion is senior debt versus the other alternatives. And when it comes to asset monetizations, Don, you talked about possibly further asset sales this year. Are there any active processes ongoing right now?
In terms of the amount of senior debt, where we are in senior debt in 2018, we have $2.9 billion of maturities and we've raised about $4.3 billion. So, we've got $1.4 billion of incremental senior debt that we've taken care of this year. In terms of that $2.2 billion it depends, but I'd say some in the area -- equity equivalent requirements probably like 50% of that consistent with our capital structure, 40% to 50% of that $2.2 billion. In terms of asset sale processes, I won't comment on that. I'd just say that don't take silences in activity and watch for down the line without any specific guidance to any specific quarter for something similar to the solars and the Cartier processes to repeat themselves.
The next question is from Robert Catellier from CIBC.
I'd like to discuss Coastal GasLink and has there been a recent challenge on the permits for that project? And if so, do you expect it to have to go -- undergo an NEB review and what's your appetite for that and any impact on the timeline?
This is Karl. Yes, it has been a challenge to jurisdiction. We right now have our permits under the BC and this is a wholly NBC project so we have BC permits for it and there has been a challenge that it should be under NEB jurisdiction. I'm not going to talk about our strategy going into this, but as you can imagine, we will be involved and we will be waiting on how the NEB views this. But I will say this that we're ready to go on this project. We believe we are working -- we believe and we are working on valid permits from the appropriate regulatory agency. So although we will be obviously an interested party in NEB jurisdictional process, we consider that we have good and valid permits right now from the proper regulatory agency and we're ready to go.
Maybe Karl, just a comment on timeline before you have I guess any resolution on jurisdiction?
Well, the -- you will have to wait. There has been a filing with the NEB and we haven't heard back from the NEB at all on this filing. So, I wouldn't -- I'm sure we'll hear back in the next 30 to 60 days on what the NEB plans to do anything with this particular filing. But as I said, I don't think that -- right now as it stands, we believe we have valid permits so we will -- the main thing we're waiting for right now is an FID by LNG Canada and again we expect that before the end of the year. So, we'll probably get much more information on the validity of the jurisdiction case before then in any event. But as I said right now, we will -- we consider we have proper permits. I will also add that change in jurisdictions and whatnot between NEB and provincial has been done before. It's -- generally, in my experience, it has not been that disruptive. So even if something does happen, we have -- we have done jurisdictional changes before and we have -- it hasn't delayed or upended any type of projects we've done. So we'll follow this through to its natural conclusion. But as I said, we're -- the main thing we're waiting for is the FID that we expect before the end of the year.
Maybe I'll follow up with you offline for the details. Just on with the change in Ontario government, I'm wondering if there's any serious change to your operating outlook and in particular if you can comment on the Bruce refurbishment program.
Robert, it's Karl again. I don't think there -- the short answer is there is no change to our operating outlook. We produce -- especially at Bruce, we produce power at very reasonable rates. The Bruce nuclear business itself is very important to not only the local economy around Bruce, but it's important for the entire nuclear industry in Ontario. And I would add that all parties in Ontario just outside of the election itself -- all parties in Ontario have expressed support for the nuclear energy and in particular support for what Bruce Power is doing. So, we're expecting business as usual at Bruce Power.
And that includes the MCR program.
Yes. The MCR program, we still have a expectation that we and -- that we will be submitting our Unit 6 refurbishment on October 1 or before that by October 1 and getting a decision from the government before January. So, we're still on track to do that. We have everything we have, we're progressing well and we will expect to be in there before or at October 1 in our submission for our Unit #6.
Robert, just to add I mean to Karl's point is that all parties have been -- in Ontario have been supportive of the nuclear refurbishment program from a whole bunch of different perspectives. The primary one being low-cost emission-less energy to support the economy, but along with that is job creation and stable emission-less electricity that will transcend a number of decades here. So, all parties have been supportive of that plan. And as you know, it's already underway at Darlington and this is a program that is managing coordination with what OPG is doing and we're doing it at the same time to ensure reliability and stability of power to Ontario consumers. As you know, Bruce provides about 30% and change of the power in Ontario and it will for a long time yet to come. So as we've had these discussions over the past several months, as I said, all parties are supportive of low-cost emission-less energy that's good for both the economy and job creation.
The next question is from Tom Abrams from Morgan Stanley.
I just had one on backlog, I'm thinking of backlog as an indicator. So when the Bruce Power thing is formally approved, does that enter backlog in stages every year or is it all -- the whole 10 years' project comes in at once? How is that going to work? Then I also wanted to ask about Coastal GasLink, if that was FID -- I'm sorry, the LNG facility was FIDed on say December 1, when would Coastal GasLink enter your backlog? And secondly, I guess when would the actual spending occur?
Tom, it's Don here. Bruce would be -- there's 6 sequential decisions be made, one for each reactor that needs to be refurbed. So, they will enter the near-term secured growth projects on that basis. So if Unit 6 does go ahead, the cost of that would move to the near term, but only the cost for that one. With respect to Coastal GasLink, if we do get an FID by the end of the year, the entire cost of that project would move to the near-term project backlog. So, it is based on when we have clarity on any outstanding processes or approvals that are required.
In terms of spending on Coastal GasLink, to your question when do we start spending, it's a 4-year bill process. A large amount of the spending probably wouldn't occur till probably closer to 2020 and we're at the current time working through our financing options. Maybe, Don, you might want to comment on that?
In terms of the financing of Coastal GasLink, what we would be looking at for this specific project would be introducing joint venture partners and also project financing this given the nature of the cash flows and the risks contained in that project. So what would happen there is we would essentially take -- assuming like a 70% project financing debt component. We could shrink the equity contribution to about 30% and then split that in half or even less, which would comprise our equity contribution of that. So, the [ intent ] of Coastal GasLink would be to pursue that and shrink the total cost to a fairly manageable number in terms of our actual equity contribution over that 4-year timeframe.
Maybe the last thing I would add to that is, is that the estimate that we have out there currently at $4.8 billion as we said before, that's an old estimate. And if we do achieve FID in the fall, we will revise that estimate and directionally it will be a larger number than that. So as you think about financing it, using a larger number that's probably in the neighborhood of 5% to 10%, something like that.
And then real quick question on market link. If your marketing activities are using DRAs to capture some additional volumes?
Tom, it's Paul here. We -- on market link, we have capacity of about 660,000 barrels per day and the way we optimize our power and our cost around that capacity is really a combination of managing the kilowatts and using DRA where we have points of constraint. So, the long answer is yes.
The next question is from Andrew Kuske from Credit Suisse.
I think the question is for Karl. I know it's just -- when you think about restoring capacity on the Mainline, what are the gating items for you, obviously there is a volume issue, but how do you think about the gating items and just regulatory path ahead?
This Karl. Starting with regulatory path, there will be a very little regulatory path ahead on [indiscernible] especially Mainline, it's generally maintenance issue. So it is -- most of the capacity can be restored by either refurbishing compression or by in-line inspections or digs or integrity of the pipeline. These are things -- rather than doing integrity pipeline inspections, we would reduce pressure for example and these are how we would manage capacity down during times when there's less volumes. And the way to get them back is just to do those things and do that integrity work. So there will be a small regulatory component. Some of the -- if we have to replace some facilities for example or something like that, there might be a regulatory component to them, but for the most part, we're having good success bringing the idled capacity back on and with very little new equipment being needed. Really the gating item is -- and we could bring it on quickly in stages, it doesn't come on a very large large blocks, we can bring on like a [ 100 million ] at a time as we do -- as we progress this maintenance work. So the real gating item I think is getting the customer support for spending the extra maintenance dollars, and I would point out that the maintenance is not -- it is not that material dollars wise. We're talking hundreds of millions versus billions for new-build type of deal. So the real gating item is getting financial support and then the volumes are ready to commit for it going forward.
And then how do you think about, and maybe this is a question for really Russ or for Don, on the relative returns on capital employed Canada versus the U.S. and natural gas pipelines?
I think as we've always said, the range of our returns on pipelines is in that 7% to 9% kind of range, lower in Canada as a result of the cost structure we have here and the regulated model and -- in the U.S. it's slightly higher than that and the combination of the 2 is where we come up with a sort of 7% to 8% kind of average return for those kind of businesses.
Yes, it's Don here. And it is reflective of the modestly different risk profiles of -- Canada here, obviously, it's flow-through of income taxes, no counterparty risk, no volumetric risk. There's a bit more of that in the U.S., which will be compensated for in a higher return. So on a risk-adjusted basis, I think we're comfortable with the investment profile, what's there on both sides of the border.
And then one final question if I may. And I know it's a bit fluid, but is there any impact to your business and just the changes that have happened in carbon recently in Canada?
Not sure what you're referring to specifically, Andrew.
I guess, as a few sort of iterations to it. Have you seen or talked to customers that have any changes in their behavior because carbon price isn't effectively changing and the regime around carbon changing in Canada versus what was proposed a while ago, or any direct impact yourselves?
I guess there is no major impact that we are subjected in certain jurisdictions to carbon levies in Alberta and Quebec for example, today. Those are incorporated into our tools and then passed on to our customers. As you can see by the demand on our systems, the demand remained strong for our systems, irrespective of what I would call also are slight increases in the cost of our operation due to those increased taxes. We still fundamentally are required in those jurisdictions that were being -- experiencing those levies.
The next question is from Rob Hope from Scotiabank.
I just want to circle back on to the funding plans, so Slide 20 gives us 2018 funding plan. I believe in Q1 you had 2018 to 2020 outlook. Just want to get a sense if there has been any meaningful changes to the $3.5 billion of kind of equity equivalent over this timeframe, I guess after we adjust for the Cartier sale or if there's been any additional thinking there?
Yes, it's Don here, Rob. I'd say, I'd characterize it as no tectonic shift in that funding plan. There have been some tweaks. So moving lefts or right in terms of the uses, I would say CapEx is up probably in the neighborhood of $1 billion as we look at some new projects we've introduced this past while some additional expenses on projects like Napanee. We do have new methane regs here in Alberta. So probably a $1 billion increase there. We've also seen the LP drop its distribution by 35%, which negates part of that. So uses are up, probably 1 billion. In terms of what we've completed, in terms of funding here, I think we had [ $21.5 billion-ish ] as a number previously. Funds from ops remains robust, we are not seeing a whole lot of movement there, maybe directionally, a little bit better. And then with all the funding in terms of term debt and asset sales, we have chipped away at that. On the far right-hand side, as you would have seen last quarter, there's about $8.5 billion total need there. I would say that with the financing we've done and the sale of Cartier, we're probably down $1 billion and $1 billion plus on that. The other component that is there, $3.5 billion is probably down marginally. As we look at, I guess, the equity component of the sale of Cartier and the gain on that. So if really nothing is moved materially in the whole makeup, in terms of the $3 billion, $3.5 billion of other that's there, I wouldn't say it's dollar for dollar equity equivalent. What's categorized in there is potentially portfolio management, future ATM, recovery of some projects, future drip, that's to be determined. So long-winded way of saying no fundamental shift in any of those categories, but just some of the moving parts that we're thinking about here.
Moving over to Keystone XL, Russ, I believe in your comments, you did mention that pre-construction activities are accelerating through 2018. Just want to get a sense of, are you looking for specific approval to move the project forward and does it remain in Nebraska review, that will largely be the gating factor before an FID potentially in early '19?
I think as we've said before, I mean the updates we've provided today on what we've called the major items, the approvals in Nebraska, along with the right of ways and the issuance of BLM and Army Corps permits are on our watch list, as well, we're looking at other legal proceedings that have been initiated, the one in Montana, for example, monitoring the outcomes of those along with the ongoing work that we're doing on the commercial front. As we said, we're pretty much done there, but there's a lot of activity still yet to be done. We would hope that all of that would sort of culminate in sufficient information to allow us to make a decision later in the year, early into next year. But we don't control, as you know, the timing of those processes. So we're being very cautious and careful -- careful about how we're spending our money. We're spending it cautiously but trying to maintain a schedule that allows us to build in 2019 and 2020, but, we'll make decisions on a monthly basis as we go. As you know, we've been at this for almost a decade and we're just methodically going through each of these pieces and making sure that we dot our i's and cross our t's before making any big steps.
The next question is from Dennis Coleman from Bank of America Merrill Lynch. Please go ahead.
This Derek Walker on for Dennis. Our questions have been answered.
The next question is from Matthew Taylor from Tudor, Pickering, Holt.
Question on the Northeast BC gas system as Coastal gasoline goes ahead. It looks like North Montney will be able to fill majority of Phase I, but just wanted to get a sense of appetite to increase bi-directional capabilities of maybe shipping some gas of Northwest Alberta. Just trying to get a sense if there's a Phase II other LNG projects and how you're viewing your system up there?
Mathew, this is Karl. I guess you may also start with Coastal GasLink. We do expect it to be -- to ultimately be, have some interconnection with NGTL. And I would expect some NGTL volumes go through. Are they specifically designated in North Montney or not, it really depends on who the producer is and how the people stream themselves. But as Coastal GasLink interconnects within NGTL it will be able to draw from the greater NGTL, so which I think is a big benefit for these LNG projects to be able to get into the overall NGTL system. I would put out that there are some expectations on a Coastal GasLink that we have direct connected from their own Northeast BC gas supply. Some of the partners have gas supply that is approximate to the pipeline. So I would expect that we would see some direct connect. Obviously, we're working closely with them to see if we can do a deal, to get that on NGTLs well, but that may [indiscernible] connected. So we probably have a mixture of both. The facility, the 2 trains of facility probably -- will probably bring in approximately 2 Bcf a day. So it will -- it depends on how each individual partner ramps up their proprietary reduction as to how much kind of incremental goes into the market for acquisition, per se. Here you would expect kind of a normal curve on that. I'm pretty certain most proponents are not building this facility to shorter the net market. I'm expecting a lot of them to use a majority of their own production. But that'll probably be ramped up over time, so they will probably use more, lean on more of the market earlier than later. If they do expand the system, you could expect an expansion would be probably another 2 trains, which will be another 2 Bcf a day plus or minus. So it gives you an idea, they have not made an FID, even on the first 2 trains, maybe on the next 2 trains. So I would just point that out. And there are still many other proponents of LNG that I think that have some Northeast BC potential and they are actually WCSB in general, NGTL, specifically in -- and Northeast BC specifically can serve. So, I have no concerns with their capability to serve any LNG facility that comes along. So we have a very big robust system. As a matter of fact, I would expect most LNG facilities would be looking to NGTL, because of the robustness of that system as a source of gas.
And then just on that Coastal GasLink, I understand that's a 48-inch pipe, what's the extendability of that, of that system?
I think we could bring it probably to the 5 Bcf a day through compression. Maybe that's stretching a little bit, but certainly, we can do -- the first expansion, we can get over 4 Bcf a day and I think approximately 5 Bcf a day with fully compressed.
Is there any looping of the pipe or?
No that would be before new pipe [indiscernible] just compression.
The next question is from Patrick Kenny from National Bank Financial. Please go ahead.
Just on the [ July ] open season, wondering if that was a won and done type of offer to shippers, or if you'll be going back to the drawing board, so to speak and try to launch around [indiscernible] sometime soon?
Yes, it is Karl again. I wouldn't call it won and done. That offer was in response actually to producers asking for us to come to -- to bring more products to them. And I personally think it was a great product. To this day, I'll be honest, I haven't received any reasonable feedbacks to why it was not fully subscribed. But you can expect us to continue to be in the market for production. Maybe that product again, but maybe will probably different derivatives of that project. And I'm not too concerned anyways. The bottom line is we have a lot of gas, now that's sitting at [indiscernible] that's going to move down the Mainline. So if they don't buy it on a term basis or a structured product, they'll be buying it kind of on our yearly or yearly tariff products. So I'm sure the gas is coming, so I'm not concerned that we're not going to move the gas. But we are -- we're still in the market looking for feedback for new products for people and we're not afraid to come back with a new product if we believe that it will be subscribed.
And then just maybe back on North Montney. I'm not sure how much you can comment on any feedback that's coming from shippers so far on the new tolling mechanism there. But, perhaps you can just provide a bit more color on how you see the new methodologies shaking out and maybe an update on timing for finalizing the tolls there?
Yes, I can. Well, quite frankly, we are in discussions with all of our shippers in that area, not just in North Montney, for a long time on kind of new tolling methodologies for the Northeast BC part of our system. So these discussions haven't been new, I guess the decision that we got from the NEB are -- hurried it up a bit, so it speaks specifically to North Montney. But what I can't say right now is, we are in discussions, we are actually up for long end discussions for new tolling method for North Montney and then with North Montney shippers. I can't talk details with them just yet, so I can just stop finalized, but I can't say that it's still going to have aspects of roll-in. It will be probably roll-in tariff with a matter for -- to reflect the location of it. And that's kind of the road we're moving down right now. And that was road, quite frankly we're moving down in before this hearing. I think the Board kind of was just given us a message that they wanted us to do this quicker, through their discussion with -- on the North Montney variance application. So I don't have at my fingertips what the -- what the conclusion date is going to be, but I think you can expect this fall. Soon, sooner rather than later, you will see us come out with a -- with kind of a negotiated settlement, so to speak for a proposal for an adjustment to the rates for that area and to be brought to the NEB.
The next question is from Joe Gemino from Morningstar.
Can you provide any color as to any of the contract status of the Keystone XL and even the Keystone, once XL is placed into service?
So, hi, Joe, it's Paul here. I'll start with new contracts on Keystone XL. We were able to secure about 500,000 barrels per day of 20-year commitments for Keystone XL open season earlier this year. Since that time our interest in the pipeline remains strong. We continue to talk to producers and other interested parties and I would anticipate that, that level of commitment would increase. When we bring Keystone XL into service, we will move probably about 200,000 barrels per day of contracts over from the existing ship -- existing pipeline on to XL. So when you combine the new contracts with those that we will transfer over with the amount of spot capacity we were required to set aside for walk-up shippers, we will effectively be fully contracted on Keystone XL. That does provide capacity on the existing Keystone system and we would look to contract that capacity up as well, serving markets in that upper Midwest region.
Have you seen any interest in contracts on that existing -- around the legacy system for the upper Midwest region?
We have, we are in discussions with various parties all the time across our network. And to the extent that they have a transportation requirement, and we have a good solution for them, we'll certainly engage them in that conversation and ultimately secure long-term contracts from them. So, those conversations continue, some of the opportunities may be in the upper Midwest, some of them may be in markets further downstream through interconnecting pipes, but we're covering most of the marketplace looking for opportunities to backfill the capacity on the legacy system.
Ladies and gentlemen, the call has now concluded. If there are any further questions, please contact TransCanada Investor Relations. I will now turn the call over to Mr. Moneta. Please go ahead, Mr. Moneta.
Thanks very much and thanks to all of you for participating today. We very much appreciate your interest in TransCanada and look forward to talking to you again soon. Thanks and bye for now.
Thank you. The conference has now ended. Please disconnect your lines at this time and thank you for your participation.