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 Q2 conference call. With me today are Russ Girling, President and Chief Executive Officer Don Marchand, Executive Vice President and Chief Financial Officer Karl Johansen, 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 Manous, 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.
In order to provide everyone from the investment community with an equal opportunity to participate, we ask that you limit yourself to 2 questions. If you have additional questions, please re enter the queue. Also, we ask that you focus your questions on our industry, our corporate strategy, recent developments and key elements of our financial performance. If you have detailed questions relating to some of our smaller operations or your detailed financial models, Duane and I'd be pleased to discuss them with you following the call. Before Russ begins, I'd like to remind you that our remarks today will include forward looking statements that are subject to important risks and uncertainties.
For more information on these risks and uncertainties, please see the reports filed by 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're very pleased to announce 2nd quarter financial results, which we expect to contribute to record financial performance in 2018. As outlined in the report, our $92,000,000,000 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 1 $0.83 for the 3 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 $28,000,000,000 near term capital program, which now includes approximately $5,800,000,000 of maintenance capital expenditures over the 2018 to 2020 period. Approximately $10,000,000,000 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, the Sur de Texas Natural Gas Pipeline in Mexico and the Napanee gas fired power plant in Ontario. We also continue to advance over $20,000,000,000 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 $100,000,000 so far this year.
That includes $4,300,000,000 of long term debt, which was issued at very compelling rates $1,200,000,000 of common equity that has been raised through our dividend reinvestment program as well as our at the market equity program. And as announced earlier today, we raised $630,000,000 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 therefore, comparable earnings on a per share basis in the second half of twenty eighteen 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 $28,000,000,000 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 Q2 financial results. Excluding certain specific items, comparable earnings of $768,000,000 or $0.86 per share, an increase of $109,000,000 or $0.10 per share over the Q2 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 2018 under the dividend reinvestment program and ATM program. Comparable EBITDA increased $161,000,000 to approximately $2,000,000,000 while comparable funds generated from operations of $1,500,000,000 was $92,000,000 higher than the Q2 of 2017. Those amounts reflect the strong performance of our legacy assets, contributions from approximately $7,000,000,000 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 $247,000,000 to approximately $4,100,000,000 while comparable funds generated from operations of $3,100,000,000 were $195,000,000 higher than the same period last year. John will also provide more detail on our Q2 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 $7,400,000,000 of commercially secured growth projects on the NGTL system.
They include the $1,600,000,000 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 Q4 of 2019, and the second phase is expected to follow by the Q2 of 2020. We also filed an application with the NEB for approval of our 2021 expansion project, which is underpinned by request for new receipt and delivery capacity. The expansion includes construction of about 3 44 kilometers of new pipeline and 3 compressor units at an estimated capital cost of $2,300,000,000 Finally, on the NGTL system, we received approval from the National Energy Board a negotiated settlement with customers that covers the 2018 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've 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 mark out outlet for Canadian Gas. We anticipate that LNG Canada could make a final investment decision on their project in the Q4 of this year. Moving to our U.
S. Natural gas pipelines. During the Q2, we advanced $6,100,000,000 of expansion projects, including Columbia's Mountaineer, WB and Gulf XProst projects. All three of those projects are expected to enter service by the end of 2018 at a combined investment of approximately US4.5 billion dollars 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're also looking at other opportunities across the broader U.
S. Natural gas portfolio, and those are slowly coming to fruition. Finally, in the 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 that 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're held through a wholly owned taxable corporation and a significant portion of their revenues are earned under nonrecourse 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 the future TC pipelines LP might be restored as a competitive funding option for TransCanada. Regardless, as we've said many times before, we believe that we have the financial capacity to fund our existing capital program through 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 US2.8 billion dollars 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 Vida Rey project and the Tula project are anticipated to be in service 2019 2020, respectively. While both projects are facing some delays, we continue to work to forward finalizing amending 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 Q2 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 twenty 17 and are now contributing to EBITDA. In addition, we continue to benefit from higher contracted and uncontracted volumes on our Market Link 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, a 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 against the Nebraska Public Service Commission's alternatives route itself. We remain confident that public interest determination of the Nebraska Public Service Commission was lawful and expected the Nebraska Supreme Court could reach a decision by late 2018 or Q1 of 2019.
At the same time, we continue to work collaboratively with land owners 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 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 pipeline's capacity would be fully subscribed in the coming months.
The new contracts combined with the 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 point $5,000,000,000 Work also continues on the Bruce Power life extension project with more significant investments to extend the operating life of the facility to 2,064 scheduled to begin in 2020 and continue through 2,033. 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 Q4 of this year. And finally, earlier today, we announced an agreement to sell our 62% interest in the Cartier Wind project for approximately $630,000,000 That sale allows us to surface significant value for a mature asset that represented approximately 5% of our generating capacity and redeploy that capital into our $28,000,000,000 capital program, thereby reducing our need for external capital, including common equity. So in summary, we continue to advance our $28,000,000,000 near term capital program. We have invested about $10,000,000,000 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 $5,800,000,000 of maintenance capital expenditures over the 20 18 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, this real 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 the long term value creation. Turning to our outlook for growth and EBITDA. As you can see on this chart, comparable EBITDA grew from $5,900,000,000 in 2015 to $6,600,000,000 in 2016, dollars 7,400,000,000 in 2017 and as we reported here earlier today, dollars 4,100,000,000 for the first half of twenty eighteen.
That growth is expected to continue with EBITDA of approximately $9,500,000,000 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 $20,000,000,000 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 $92,000,000,000 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 $28,000,000,000 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 percent in 2021.
In addition, we have more than $20,000,000,000 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 our 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 remarks, and I'll turn it over to Don, who will provide more details on our Q2 financial results.
Thanks, Russ, and good morning, everyone. As outlined in our quarterly results issued earlier today, net income attributable to common shares was $785,000,000 or $0.88 per share in the Q2 of 2018 compared to $881,000,000 or $1.01 per share for the same period 17. Excluding specific items, comparable earnings of $768,000,000 or $0.86 per share in Q2 2018 were $109,000,000 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 U. S.
Tax reform. Turning to our business segment results on slide 16. In the Q2, comparable EBITDA from our 5 operating businesses was approximately $2,000,000,000 representing $161,000,000 increase in 2017. As outlined in the quarterly report, Canadian Natural Gas Pipelines' comparable EBITDA of $545,000,000 $18,000,000 higher than for the same period last year. Net income for the NGTL system increased $9,000,000 compared to Q2 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 percent on 40% deemed equity as approved in our 20 eighteentwenty 19 rate settlement.
Conversely, net income for the Canadian Mainline decreased $4,000,000 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. The U. S. Natural Gas Pipelines' comparable EBITDA of US546 million dollars or CAD704 million in the quarter increased by CAD136 million dollars or CAD153 million dollars 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 from Midstream and increased earnings from the amortization of the regulatory liability recognized following U.
S. Tax reform. Exco Natural Gas Pipelines' comparable EBITDA of US110 $1,000,000 or CAD142 million was in line with Q2 2017. Liquids Pipelines comparable EBITDA rose by CAD 81,000,000 to CAD 413,000,000 driven by the additions of Grand Rapids and Northern Courier, which began operations in the second half of twenty seventeen, higher volumes on the Keystone pipeline system, a 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 $85,000,000 year over year to $202,000,000 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 in Bruce Heppner's 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 the Q2 of 2017 by a weaker U. S. Dollar.
This was largely offset by lower translated interest expense and 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 $570,000,000 increased $54,000,000 versus Q2 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 $558,000,000 was 34,000,000 dollars 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 Q2 2017 and the impact of the weaker U. S.
Dollar in translated U. S. Dollar denominated interest. AFUDC decreased by $8,000,000 for the 3 months ended June 30, 2018, compared to the same period in 2017. A decline in Canadian dollars denominated AFUDC was principally due to the October 2017 decision not to proceed with the Energies pipeline project and completion of the NGTL 2017 expansion program, while an increase in U.
S. Dollar denominated FUDC 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 $15,000,000 in the 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 costs 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 $1,000,000 in Q2 2018 compared to $198,000,000 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 pre tax comparable earnings. Excluding Canadian rate regulated pipelines, where income taxes are a flow through item and are thus quite variable, along with equity AFUDC income in U. S. And Mexico natural gas pipelines, we expect our 2018 full year effective rate to be in the mid to high teens.
Net income attributable to non controlling interest increased by $21,000,000 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 Q2 2017. Now moving to cash flow and distributable cash flow on slide 18. Comparable funds generated from operations of approximately $1,500,000,000 in the 2nd quarter reflects an increase of $92,000,000 year over year, driven largely by higher comparable earnings as outlined and after allowing for the impact of power generation asset sales in 2nd Q4 2017. Previously, we provided 2 measures of comparable distributable cash flow, one factoring in 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 in our liquids pipelines will no longer be deducted from distributable cash flow. This represents approximately 85% of current maintenance capital spend.
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 distribution to shareholders is 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 $1,300,000,000 or $1.46 per share compared to $1,200,000,000 or $1.36 per share in the Q2 of 2017, resulting in a coverage ratio of 2.1 times. We continue to expect to maintain strong DCF coverage through 2020. Now turning to Slide 19.
During the Q2, we invested approximately $2,600,000,000 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 $2,500,000,000 of senior unsecured notes comprised of $1,000,000,000 of 10 year notes at a fixed rate of 4.25 percent, US500 $1,000,000,000 of 20 year notes at a fixed rate of 4.75 percent and US1 $1,000,000,000 of 30 year notes at a fixed rate of 4.875 percent. In early July, we raised $1,000,000,000 through a Canadian medium term notes offering comprised of $200,000,000 of 10 year notes at a fixed rate of 3.39 percent and $800,000,000 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 Q2, the participation rate amongst common shareholders was approximately 33%, representing $208,000,000 of dividend reinvestment.
Year to date, the participation rate has been approximately 36%, resulting in $442,000,000 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 $1,000,000,000 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 Q2, 8,100,000 common shares were issued under the program at an average price of $54.63 per share for gross proceeds of $443,000,000 bringing year to date gross proceeds to $772,000,000 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 $1,000,000,000 of common shares in 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 $28,000,000,000 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, as announced today, we have executed an agreement to sell our 62% interest in the Cartier power generation assets for approximately $630,000,000 The proceeds will contribute to funding our capital program. The sale is expected to close in the Q4 this year and result in an estimated gain of $130,000,000 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 5 times debt to EBITDA. Starting in the left column, our dividend and non controlling interest distributions of approximately $2,800,000,000 2018 capital expenditures projected to be $10,000,000,000 including maintenance capital and long term debt maturities of $2,900,000,000 bring our total funding requirement for 2018 to approximately $15,700,000,000 dollars The middle column highlights aggregate sources of approximately $17,500,000,000 in previously described funding year to date. This leaves an additional $2,200,000,000 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 $28,000,000,000 capital program. In summary, while our external financing needs are sizable, they remain eminently achievable in the context of multiple financing levers available in 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 Q2 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 $28,000,000,000 suite of near term projects and have 5 distinct platforms for future growth in Canadian, U. S.
And Mexico Natural Gas Pipelines, Liquids Pipelines and Energy. Our overall financial position remains strong. 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 and A.
Thanks, Don. Just a reminder before I turn it over to the conference coordinator for your questions, those questions from the investment community. We ask that you limit yourself to 2 questions. If you have additional questions, please reenter the queue.
The first question is from Linda Ezergailis from TD Securities. Please go ahead.
Thank you. With respect to the FERC recent ruling, I know there's still a lot of uncertainties. 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 rehearings or clarifications? 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 their 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 gs 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 1st or maybe Q2 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 0 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 rates 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 gs filings and we start 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 gs filings and saying that that's good enough. So each pipe has a unique set of facts and we'll deal with them on a case by case basis.
Thank you. 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 pipeline. Can you comment on the duration of the additional contracts? And I'm assuming that the lower expenses would also translate into 2019 beyond. But I'm also interested in understanding whether or not those contracts are shorter term or longer term.
Yes. So on the Columbia system, a lot of the increased earnings you'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 out of the 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 Base, we do see those volumes continuing to flow for a longer duration.
That's helpful context. Thank you.
Thanks, Linda.
Thank you. The next question is from Ben Pham from BMO. Please go ahead.
Okay. Thanks. Good morning. I had a question on the Quebec wind asset sale. And it looks like Intergex is providing some more specific multiples on the sale and it's suggesting 9 to 9.5 times EBITDA.
And my question really is, how do you think about reconciling that with some recent transactions that we've seen in the low double digits and also to your own market multiple?
It's Don here, Ben. Well, each asset is unique in terms of its contractual term and like an operational characteristic. So there 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 that they will be fully cash cash tax sheltered, an important component of backfilling our funding plan here.
Ben, I could just add
to that. As you think about EBITDA multiples, it's one measure of value. Looking at trailing 12 months is one way of calculating it, looking at your EBITDA multiple on a go forward basis and then certain assumptions around what you think the market is going to look like post the contracted life of the asset. And we have different views of those kinds of things. The primary driver for us is can we surface value at a lower cost of capital than our other sources.
And we've always said that we will choose our lowest cost of capital. When we look at the implied cost of capital here that we were able to achieve in selling this asset, it's well below what our incremental sources are. So that's fits for us in terms of adding value for our shareholders is how we come to those conclusions.
All right. Great. 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 revised 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 for you.
Vince, Don here again. I would describe DCF as a data point for us, not 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 the probably the more critical points that we look at.
DCF, as I mentioned, is really just the data point.
Okay. All right. Thanks, Don. Thanks, Russ. Thanks, Ben.
Thank you. The next question is from Jeremy Tonner from JPMorgan. Please go ahead.
Good morning. Just want to start off with thanks 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 lowest 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 can kind of share your thoughts on those dynamics, that would be helpful.
Well, Jerry, maybe 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 industry natural gas pipelines and electricity business. So we are still waiting to get our first meetings with all the new appointees and whatnot. So yes, there's we still have some familiarization to do with this new administration. But to date, we're quite comfortable with what has been said and then the actions that we've seen so far. I would 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. Yes. 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 of 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. 1, the list of assets we could have dropped down to 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 chip away at that without any real pre announcements of this and look to what we've done with the solars in Cartier and continue to look at one off asset sales here for the time being.
That's helpful. Thanks. And then just picking up on TCP 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 and 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 FERC 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.
So 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 they're actually positive with the FERC actions here in July, I would say we're still kind of monitoring this and really no closer
to the decision on it. And maybe just to add to Don's comments, this is your question on whether it's an economic decision or whether other considerations be brought to the fore. Primarily for us, it is an economic consideration. I think we said that before. To the extent it makes economic sense for Trap shareholders, we would consider it.
To the extent that it doesn't, that we wouldn't likely move down that path.
That's very helpful.
Thank you for taking my question.
Thanks, Jeremy.
Thank you. The next question is from Robert Kwan from RBC Capital Markets. Please go ahead.
Good morning. 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 linked 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 linked tolling and the marketing and etcetera. So our market linked 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 Q2, we saw a 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 Q3, they dropped off again and they've been relatively flat here so far in the Q3. On the marketing side, kind of the same profile. We picked up some good value kind of midway through the Q2 and into the 3rd towards the end of the second quarter. Going forward, we're 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 length to be slightly higher in the Q3 and into 4 with market being contributing a bit more, partially offset by some reduced volume on market length.
And then Robert, this is Stan. With respect to the FERC actions, like I said earlier, we'll be making our 501 gs 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 about it 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 book them until we get some good feedback from the Board on which way the Board is going to go. Now I will say that although it's not it hasn't taken account consensus on the Mainline. I will say that we have got our intervening evidence in on the Mainline case and it was very modest. There's really only one issue to be adjudicated.
So I'm a little bit more optimistic we will have the adjudication of our rates 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.
Yes, Robert, it's Don here. It wouldn't be a material amount regardless.
Okay. And then just finishing on funding and the Slide 20. I'm wondering how much of the $2,200,000,000 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?
Yes. In terms of the amount of senior debt, where we are in senior debt in 2018, we have 2.9 billion dollars of maturities and we've raised about $4,300,000,000 So we've got $1,400,000,000 of incremental senior debt that we've taken care of this year. In terms of that $2,200,000,000 it depends. But I'd say some in the error. Our equity equivalent requirement is probably like 50% of that, consistent with our capital structure, like 40% to 50% of that $2,200,000,000 In terms of asset sale processes, I won't comment on that.
I'll just say that don't take silences in activity and watch for down the line without any specific guidance, any specific quarter for something similar to the Solar's and the Cartier processes to repeat themselves.
That's great. Thank you.
Thanks, Robert.
Thank you. The next question is from Robert Catellier from CIBC. Please go ahead.
Hi. 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?
Hey, Robert, it's Karl. Yes, there has been a challenge to jurisdiction. We right now have our permits under the BC. This is a wholly in BC project, so we have BC permits for it. And there has been challenges that 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 NAB views this. But I will say this that we are ready to go on this project. We believe we're 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 any of the jurisdictional process, we consider that we have good and valid permits right now from the appropriate regulatory agency and we're ready to go.
And then Carl, just a comment on time line before you have, I guess, any resolution on jurisdiction?
Well, you will have to wait the there has been a filing with the NAB and we haven't heard back from the NAB 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 NMB plans to do if 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 for 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 gone 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 for the end of the year.
Okay. That's helpful color. 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.
Yes. Well, it's Karl again. I don't think 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 particular support for what Bruce Power is doing. So we're expecting we're expecting business as usual at Wiss Power.
And that includes the MCR program?
Yes. The MCR program, we still have a expectation that we will be submitting our Unit 6 refurbishment in October 1 or before then 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 number 6.
Robert, just to add, I mean, as to Karl's point, 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 emissionless energy to support the economy. But along with that is job creation in the stable emissionless electricity that 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 managed in coordination with what OPG is doing and we're doing at the same time to ensure reliability and stability of power to Ontario consumers.
As you know, Bruce prides about 30 percent and change percent of the power in Ontario. 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 emissionless energy that's good for both the economy and job creation.
That's great. Thank you.
Thank you. The next question is from Tom Abrahams from Morgan Stanley. Please go ahead.
Thanks. A lot of good questions here. 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 FID on, say, December 1, When would Coastal GasLink enter your backlog? And second, when would the actual spending occur?
Tom, it's Don here. Bruce would be there's 6 sequential decisions to 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, your question on when do we start spending, it's a 4 year build 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 Donnie might want to comment on that. Yes.
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 on 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 it the estimate that we have out there currently of $4,800,000,000 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 I think as you think about financing it, using a larger number that's probably in the neighborhood of 5% to 10%, something like that.
Okay. And then a real quick question on MarketLink. 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 costs around that capacity is really a combination of managing the kilowatts and using DRA where we have points of constraints. So the long answer is yes. Okay.
Thank you.
Thanks, Tom.
Thank you. The next question is from Andrew Koski from Credit Suisse. Please go ahead.
Thank you. Good morning. I think the question is for Karl. And it's just when you think about restoring capacity on the mainline, what are the gating items for you? Obviously, there's a volume issue, but how do you think about the gating items and just regulatory path ahead?
Hi, Andrew. It's Karl. Yes. So let me start with the regulatory path. There will be very little regulatory path ahead on restoring the capacity of mainline.
It's generally a 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 digs and do that integrity work. So there'll be a small regulatory component.
Some of the if we have to replace the facilities, for example, or something like that, there might be regulatory will come into them. But for the most part, we're having good success bringing the idle capacity back on and with very little equipment being needed. Really the gating item is and we can bring it on quite quickly in stages. It doesn't come on a very large box. We can bring it on like $100,000,000 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 that material. Otherwise, we're talking 100 of 1,000,000 versus 1,000,000,000 for new build type of deals. So the real gating item is getting commercial support and the volumes are ready to commit for it going forward.
Okay, that's helpful. And then how do you think about and maybe this is a question for really Russ or for Don on just 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 construct that we have here and the rate 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 them. In 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 we'd be compensated for in a higher return.
So on a risk adjusted basis, I think we're comfortable with the investment profile that'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 there's a few sort of iterations to it. Have you seen or talked to customers that have any changes in their behavior? Is carbon pricing effectively changing and the regime around carbon changing in Canada versus what was proposed a while ago or any direct impact to yourselves?
I guess there's no major impact. We are subjected in certain jurisdictions to carbon levies in Alberta and Quebec, for example, today. Those are incorporated into our tolls and passed on to our customers. As you can see by the demand on our systems, demand remains strong for our systems irrespective of what I would call sort of slight increases in the cost of our operation due to those increased taxes. It's still fundamentally required in those jurisdictions that we're being experiencing those levies.
Okay. Thank
you. Thanks, Andrew.
Thank you. The next question is from Rob Hope from Scotiabank. Please go ahead.
Hello. Good morning, everyone.
I just want to circle back
on to the funding plan. So Slide 20 gives us the 20 18 funding plan. I believe in Q1 you had a 2018 to 2020 outlook. Just want to get a sense if there has been any meaningful changes to the $3,500,000,000 of kind of equity equivalent over this time frame, 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 as no tectonic shift in that funding plan. There have been some tweaks. So moving left to right in terms of the uses, I would say CapEx is up probably in the neighborhood of $1,000,000,000 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 $1,000,000,000 increase there. We've also seen the LP drop its distribution by 35%, which negates part of that. So uses are up probably $1,000,000,000 In terms of what we've completed in terms of funding here, I think we had $21,500,000,000 ish as a number previously. Funds from ops remains robust. We're 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've chipped away at that. On the far right hand side, as you would have seen last quarter, I think there's about an $8,500,000,000 total need there. I would say that with the financing we've done and the sale of Cartier, we're probably down $1,000,000,000 $1,000,000,000 plus on that. The other component that is there of $3,500,000,000 is probably down marginally as we look at, I guess, the equity component of the sale of Cartier and the gain on that. So it really nothing has moved materially in that whole makeup.
In terms of the 3,000,000,000, 3,500,000,000 dollars 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, recoveries from 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.
All right. That's helpful. 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 approvals to move the project forward? And does it remain the Nebraska review that will largely be the gating factor before an FID potentially in early
2019? I think as we said before, I mean the updates we provided today on what we have 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. 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 about how we're spending our money. We're spending it cautiously by trying to maintain a schedule that allows us to build in 2019 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 before we make any big steps.
All right. That's helpful.
I don't
want to
add to that.
Thanks, Rob.
Thank you. The next question is from Dennis Coleman from Bank of America Merrill Lynch. Please go ahead.
This is Derek Walker on for Dennis. Our questions have been answered. Thank you.
Thanks, Derek.
Thank you. The next question is from Matthew Taylor from Tudor, Pickering, Holt. Please go ahead.
Hey, guys. Thanks for taking my question here. Just a question on the Northeast BC Gas System, if Coastal GasLink goes ahead. It looks like North Montney will be able to fill majority of Phase 1, but just wanted to get a sense of appetite to increase bidirectional capabilities of maybe shipping some gas Northwest Alberta? Just trying to get a sense if there is a Phase 2 other LNG projects and how you're viewing your system up there?
Hi, Matthew, it's Karl. Yes, I guess, maybe I'll just 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 Monty or not?
It really depends on who the producer is and how people stream themselves. But as Coastal GasLink interconnects with NGTL, it will be able to draw from the greater NGTL system, 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 Coastal GasLink to have direct connected from their own Northeast BC Gas supply. So some of the partners have gas supply that is proximate 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 NGTL as well, but it may end up that it's just direct connected. So it will be probably a mixture of both. The facility, the 2 chains of facility will probably bring in approximately 2 Bcf a day. So it depends on how each individual partner ramps up their proprietary production as to how much kind of incremental goes into the market for acquisition per se. You would expect us to have a normal curve on that.
I'm pretty certain most proponents are not building this facility to short of the net market. I'm expecting a lot of them to use majority of their own production. But that will probably be ramped up over time. So they'll probably use more lean on more of the market earlier than later. If they do expand the system, you can expect an expansion would be probably another 2 trains, which should 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 two trains level on the next two trains. So I'd just point that out. And there are still many other proponents of LNG that I think that's Northeast BC potential and then actually WCSB just in general and GTL, specifically in Northeast BC specifically can serve. So I have no concerns with our capability to serve any LNG facility that comes along.
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 gas leak, I understand it's a 48 inches pipe. What's the expandability of that system?
Well, I think we
could bring it probably to the 5 Bcf a day through compression. Maybe that's stretching it a little bit, but certainly we can do the first expansion, we can get over 4 Bcf a day, and I think approximately 5 with fully compressed.
Is that any looping of the pipe or?
No, that would be before new pipe goes on the ground, that'd be just compression.
Okay, thanks.
Thanks, Matthew.
Thank you. The next question is from Patrick Kenny from National Bank Financial. Please go ahead. Yes.
Hey, guys. Just on the Joliet open season, wondering if that was a one 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 a round 2 sometime soon?
Yes. It's Karl again. I wouldn't call it one and done. That offer was in response actually to producers asking for us to come 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 feedback as to why it was not fully subscribed. But you can expect us to continue to be in the market for products. Maybe that product again, but maybe there'll be different derivatives of that project. And I'm not too concerned anyways that the bottom line is we have a lot of gas now that's sitting in Empress. That's going to move down the main line.
So if they don't buy it on a term basis on a structured product, they'll be buying it kind of on our yearly tariff price. 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 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. All right.
That's great.
Thanks for that color. 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 methodology shaking out and maybe an update on timing for finalizing the tools there?
Yes, yes, I can. Well, quite frankly, we were 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 Annaveed kind of
hurried it
up a bit, so to speak, specifically with North Montney. What I can say right now is we are in discussions. We are actually far along in discussions for a new tolling method for North Bonney and then with North Bonney shippers. I can't talk details with it just yet because it's not finalized, but I can say that it's still going to have aspects of roll in. It'll be probably roll in tariff with an adder for to reflect the location of it.
And that's kind of the road we're moving down right now. And that was a road quite frankly we're moving down even before this hearing. I think the Board kind of was just giving us a message that they wanted us to do this
quicker
through their discussion with the on the North Gwani variance application. So I don't have at my fingertips what the inclusion date is going to be, but I think you can expect this fall. As soon, sooner rather than later, you will see us come out with kind of a negotiated settlement, so to speak, for a proposal for an adjustment to the rates for that area and then to be brought to the NEB.
All right, great. Thanks for the info.
Thanks, Matt.
Thank you. The next question is from Joe Gemino from Morningstar. Please go ahead.
Thank you. Can you provide any color as to any of the contract status of the Keystone XL and even the Keystone once the XL is placed into service?
Certainly, Joe. It's Paul here. I'll start with the new contracts on Keystone XL. We were able to secure about 500,000 barrels per day of 20 year commitments for Keystone XL in our open season earlier this year. Since that time, 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 onto XL. So when you combine the new contracts with those that we will transfer over with the amount of spot capacity where 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 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.