Good morning, all participants. Your meeting is ready to begin. Good morning, ladies and gentlemen. Welcome to the TC Energy 2019 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 TC Energy's 2019 Q2 conference call. With me today are Russ Girling, President and Chief Executive Officer Don Marchand, Executive Vice President and Chief Financial Officer Tracy Robinson, President, Canadian Natural Gas Pipelines Stan Chapman, President, U. S. Natural Gas Pipelines Paul Miller, Executive Vice President of our Technical Center and President, Liquids Pipelines Francois Poirier, Executive Vice President, Corporate Development and Strategy and President, Power and Storage and Mexico and Glenn Menuz, Vice President and Controller.
Russ and Don will begin today with some opening comments on our financial results and certain other company developments. A copy of the slide presentation that will accompany their remarks is available on our website. It can be found in the Investors section under the heading Events and Presentations. Following their prepared remarks, we will take questions from the investment community. If you are a member of the media, please contact Jamie Harding following this call and she'd be happy to address your questions.
In order to provide everyone within the investment community with an equal opportunity to participate, we ask that you limit yourself to 2 questions. If you have additional questions, please reenter 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 would be pleased to discuss them with you following the call. Before Russ begins, I'd like to remind you that our remarks today will include forward looking statements that are subject to important risks and uncertainties.
For more information on these risks and uncertainties, please see the reports filed by TC Energy with Canadian Securities Regulators and with the U. S. Securities and Exchange Commission. And finally, during the 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. Miggy's and certain other comparable measures are considered to be non GAAP measures.
As a result, they may not be comparable to similar measures presented by other entities. These measures are used to provide you with additional information on TC Energy's operating performance, liquidity and its ability to generate funds to finance its operations. With that, I'll turn the call over to
Thanks, David, and good morning, everyone, and thank you all for joining us this morning. As highlighted in our quarterly report to shareholders, during the Q2, our $100,000,000,000 portfolio of high quality long life energy infrastructure assets continue to profit from strong supply and demand fundamentals in the core geographies, which we serve. And we continue to realize the growth expected from our industry leading capital expansion program as we place new long term contracted and rate regulated assets into service. Evidence of this can be seen in our comparable earnings of $1 per share for the 3 months ended June 30, 20 19, which is a 16% increase over the same period in 2018. Similarly, comparable funds generated from operations of approximately $1,700,000,000 were 14% higher than last year.
Today, we are advancing $32,000,000,000 of secured capital projects with approximately $7,000,000,000 of those projects expected to be completed by the end of this year. We also continue to advance over $20,000,000,000 of projects under development, including Keystone XL and the refurbishment of another 5 reactors at Bruce Power as part of the long term life extension program there. In addition, over the last few months, we've made significant progress on funding our capital programs. During the Q2, we raised $1,000,000,000 of 30 year debt at compelling rates and $238,000,000 of common equity under our dividend reinvestment program. We also advanced several portfolio management initiatives, including the partial monetization of our Northern Courier pipeline in Alberta, along with the sale of certain Columbia midstream assets in the Alkalachean region and our natural gas fired power plants in Ontario.
These initiatives combined with the sale of the Coolidge generating station, which closed in May, are expected to result in a combined proceeds of approximately $6,300,000,000 Each of these transactions will allow us to surface significant value for relatively mature assets and redeploy that cash into our $32,000,000,000 secured capital program, thereby reducing our need for external funding, including common equity. Looking forward, we expect our strong operating financial performance to continue, and therefore, 2019 comparable earnings per share are expected to be higher than the record results we produced in 2018. At the same time, our overall financial position remains solid, and we believe that we are well positioned to achieve our targeted credit metrics in 2019. Don will provide more detail on our 2nd quarter results and the funding program in just a few minutes. But before that, I'll expand on some of the recent developments, beginning with a brief review of our financial results.
Excluding certain specific items, comparable earnings were $924,000,000 or $1 per share in the 2nd quarter, an increase of $156,000,000 or $0.14 per share over the same period in 2018. That equates to a 16% increase on a share per share basis after recognizing the effect of common shares issued under our dividend reinvestment programs in 2018 2019 and our ATM programs in 2018. Comparable EBITDA increased $333,000,000 to approximately $2,300,000,000 while comparable funds generated from operations of $1,700,000,000 were $208,000,000 higher than the Q2 in 2018. Based on the strength of our financial performance, the Board of Directors declared 3rd quarter dividend of $0.75 per common share, which is equivalent to $3 per share on an annual basis. That represents an 8.7% increase over the amount declared in the Q3 of 2018, and it equates to a payout of approximately 75% of comparable earnings and 40% of funds generated from operations, leaving us with significant internally generated cash flow to continue to invest in our core businesses.
Next, a few comments on our 5 operating businesses. First, in Canadian Natural Gas, customer demand for access to our system remains strong, and we continue to work with the industry on options connect growing Western Canadian gas supply to markets across North America. Today, we are advancing an $8,800,000,000 expansion program on the NGTL system that will add approximately 3,000,000,000 cubic feet a day of incremental delivery capacity to the system by the end of 2022. We also continue to actively work with LNG Canada on our Coastal GasLink pipeline project following the positive final investment decision last October on their LNG terminal in Kitimat, British Columbia. The $6,200,000,000 project will have an initial capacity 2,100,000,000 cubic feet a day with potential expansion capacity up to 5,000,000,000 cubic feet a day.
During the Q2, construction activities continued at many locations along the pipeline route and last week, the NEB issued its decision affirming provincial jurisdiction for Coastal GasLink. Accordingly, we expect construction to carry on as planned under the permits granted by the BC Oil and Gas Commission. At the same time, we continue to advance funding plans for the project through the combination of a sale of up to 75% ownership and project financing. Both of those transactions are expected to be completed by Q4 or by the end of Q4 2019. Moving to our U.
S. Natural gas business, where demand for our services reached record levels earlier this year. As highlighted previously, our broad network has historically served approximately 25% of U. S. Daily demand.
In addition to moving those volumes on our existing systems, during the Q2, we continued to advance our $1,100,000,000 Modernization II program on the Columbia Gas System as well as another US1.1 billion dollars of other capacity additions that now include Louisiana XPress project and the Grand Cheniere XPress project. Combined, those two projects will connect nearly 2,000,000,000 cubic feet a day of gas supply to Gulf Coast LNG export markets. Louisiana XPress is a $400,000,000 U. S. Project that is expected to enter service in 2022, while Branchineer is a US200 $1,000,000 project that is expected to enter service in 2 phases over the 2021 2022 periods.
Finally, in U. S. Pipelines, we continue to advance the East Lateral Express project. The $300,000,000 project is subject to final customer FID and therefore is currently included in our projects under development. Turning to Mexico, we're advancing construction on 3 pipelines at a total cost of approximately $3,200,000,000 In June, we completed the construction commissioning activities for the Sur de Texas pipeline, which has the capacity to move up to 2,600,000,000 cubic feet a day of low cost U.
S. Natural gas supply to Mexico. We have provided notice to both the regulator and our customer that the pipeline is ready for commercial operations and are awaiting the CFE's acknowledgments of readiness prior to commencing service under the transportation service contract. Construction on the Via de Rey project is ongoing with phase in service anticipated in late 2019. Construction on the central segment of the Tula project has been delayed due to lack of progress on indigenous consultations by the Mexican government.
As a result, we expect the project to enter service at the end of 2021. Finally, in Mexico, in June, the CFE filed a request for arbitration under the Sur de Texas, Viadore and Tula contracts. We are analyzing the content of the arbitration request and preparing our responses. In our view, the contracts were properly established in accordance with all original bid and regulatory requirements and remain valid. That said, we remain open to discussions and resolving these issues.
Turning now to our liquids business, which produced very strong results again in Q2 of 2019. Keystone, which is underpinned by long haul take or pay contracts for 555,000 barrels per day, essentially ran at capacity in the 2nd quarter moving an average of about 590,000 barrels a day. On the southern portion of our system or what we call the Gulf Coast segment, capacity was increased throughout 2018, reaching 700,000 barrels a day by year end. As capacity increased, we maintained near full utilization rates in the Q1 and again in the Q2 of 2019. In addition, we continue to benefit from higher contribution from our liquids marketing activities, largely due to improved volumes and margins because of the favorable market conditions.
On the project development side, we completed the $200,000,000 White Spruce pipeline and commercial in service was achieved in early May. Finally, in liquids pipelines, during the first half of twenty nineteen, we continue to advance Keystone XL. As you know, in late March, U. S. President Trump issued a new presidential permit for the project, which supersedes the 2017 permit.
The President's actions clarify the national importance of Keystone XL and aim to bring more than 10 years of environmental review to closure. Also with respect to Keystone XL, in Nebraska, we did receive approval for a route in the state. However, as you know, that decision was challenged. The appeal was heard by the Nebraska Supreme Court in the Q4 of 2018, and we are awaiting a final decision. We continue to believe the approval of the alternate route by the Nebraska Public Service Commission was lawful.
Moving forward, we will continue to carefully and methodically obtain the regulatory and legal approvals necessary before we consider advancing this commercially secured project to construction. Turning to power and storage. As you know, we experienced equipment failure on the $1,800,000,000 Napanee project, while progressing commissioning activities on the plant in the Q1 of this year. Steps are being taken to address that situation, and we now expect the 900 Megawatt plant to be placed into service by the end of 2019. Work also continues on the Bruce Power life extension project, where we expect to invest approximately $2,200,000,000 in Bruce Power's Unit 6 MCR program, as well as the ongoing asset management program through 2023 when Unit 6 refurbishment is expected to be completed.
Bruce Power's contract price increased to approximately $78 per megawatt hour on April 1, 2019 to reflect the capital to be invested under those programs as well as normal course annual inflation adjustments. Despite the announcement earlier this week of the sale of our 3 Ontario natural gas fired power plants, we do remain committed to the ongoing multi $1,000,000,000 life extension program at Bruce Power, and we also remain committed to our broader power and storage business strategies, including future new low risk investment opportunities in the electricity sector in our core North American geographies. In summary, today we are advancing $32,000,000,000 of secured growth projects that are expected to enter service by 2023. It includes approximately $5,000,000,000 of maintenance capital, 85 percent of which is related to our regulated natural gas pipelines and therefore is expected to be added to rate base and generate a return of and on capital identical to what we realized on our expansion projects. We have invested approximately $11,000,000,000 into these programs to date, with approximately $7,000,000,000 of these projects expected to be completed by the end of 2019.
The projects expected to enter service this year include the $2,600,000,000 of the NGTL system expansions as well as the Sur de Texas natural gas pipeline in Mexico and the Naphne Gaspar power plant in Ontario. Notably, all of these projects are underpinned by cost of service regulation or long term contracts, giving us visibility to earnings and cash flow that will generate that they will generate as they enter service. Based on continued strong performance of our base businesses combined with our growth plans, we continue to expect to grow our dividend at an average annual rate of 8% to 10% through 2021. And as has always been our practice, the growth in dividends is expected to be supported by sustainable 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 demand for our services remains strong. In 2018, our $100,000,000,000 asset portfolio generated approximately $8,600,000,000 of annual EBITDA, with approximately 95 percent of that EBITDA coming from regulated businesses or long term contracted assets. Looking forward, we have 5 significant platforms for growth: Canadian, U. S.
And Mexico natural gas pipelines, liquids pipelines and our power and storage business. This is we have done since 2000. As we advance our $32,000,000,000 secured capital program, we expect to deliver growth in earnings and cash flow and dividends per share. In addition, we have more than $20,000,000,000 of projects that are in advanced stages of development, and we expect numerous other growth opportunities to emanate from our extensive critical asset footprint. We have a history of prudently funding our capital programs, and we are on track to continue to delever our balance sheet post the 2016 acquisition of Columbia and achieve our targeted credit metrics in 2019.
That concludes my prepared remarks, and I'll turn the call over to Don Marchand, who will provide more details on our second quarter results.
Don? Thanks, Russ, and good morning, everyone. As outlined in our quarterly results issued earlier today, net income attributable to common shares was $1,100,000,000 or $1.21 per share in the Q2 of 2019, compared to $785,000,000 or $0.88 per share for the same period in 2018. Excluding specific items, comparable earnings of $924,000,000 or $1 per share in Q2 2019 were $156,000,000 or $0.14 per share higher year over year. This equates to a 16% increase on a per share basis after also giving effect to common shares issued under the dividend reinvestment plan in 2018 2019 and the at the market program in 2018 in support of our growth and credit metrics.
Our positive results reflect operational strength and solid cash generation across all of our businesses, particularly in U. S. Natural gas pipelines and liquids pipelines. Turning to our business segment results on Slide 14. In the Q2, comparable EBITDA was approximately $2,300,000,000 representing a $333,000,000 or a 17% increase from 2018.
Canadian Natural Gas Pipelines' comparable EBITDA of 5 $28,000,000 was $17,000,000 lower than for the same period last year, primarily due to lower flow through taxes on the NGTL system and the Canadian Mainline as a result of accelerated tax depreciation enacted by the federal government in June 2019, partially offset by increased depreciation due to higher approved rates as well as higher incentive earnings for the Canadian Mainline. Net income for the NGTL system increased $22,000,000 compared to Q2 2018 as a result of a higher average investment base from continued system expansions and reflects a base ROE of 10.1% on 40% deemed equity as approved in our 20 eighteen-twenty 19 rate settlement. Conversely, net income for the Canadian Mainline decreased $2,000,000 due to a lower average rate base, partially offset by incentive earnings recorded in the Q2 of 2019. I would note that for Canadian Natural Gas Pipelines, changes in depreciation, financial charges and income taxes impact comparable EBITDA, but do not have a significant impact on net income as they all are almost entirely recovered in revenues on a flow through basis. U.
S. Natural Gas Pipelines' comparable EBITDA of US641 million dollars or CAD 857 million in the quarter increased by CAD 95 1,000,000 or CAD 153 million compared to the same period in 2018, mainly due to increased contributions from Columbia Gas and Columbia Gulf Growth Projects placed in service. This was partially offset by decreased earnings from Bison, which is wholly owned by TC PipeLines LP due to 2018 customer agreements to pay out their future contracted revenues and terminate their contracts. Mexico Natural Gas Pipelines' comparable EBITDA of US107 million dollars or CAD 141 million was essentially in line with Q2 2018. Liquids Pipelines comparable EBITDA rose by $169,000,000 to $582,000,000 driven by higher volumes on the Keystone pipeline system, a higher contribution from liquids marketing activities due to improved margins and volumes and a contribution from the White Spruce pipeline, which was placed into service in May 2019.
Power and storage comparable EBITDA increased by $17,000,000 year over year to $219,000,000 driven by a larger contribution from Bruce Power, primarily due to a higher realized sale price, partially offset by lower volumes caused by higher outage days. These positive results were partially offset by decreased Western and Eastern power contributions, largely due to the sale of our interest in the Cartier Wind Power Facilities in October 2018 and our Coolidge Generating Facility in May 2019, as well as decreased natural gas storage results. 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 power and storage businesses, Canadian dollar translated EBITDA was positively impacted by a stronger U. S. Dollar versus the Q2 of 2018. This was largely offset by higher translated interest expense on U.
S. Dollar denominated debt and realized hedging losses reported in comparable interest income and other. Regarding our exposure to foreign exchange rates, a sizable portion of our U. S. Dollar denominated assets are hedged with U.
S. Dollar denominated debt. We continue to actively manage the residual exposure on a rolling 1 year forward basis. Now turning to other income statement items on Slide 15. Depreciation and amortization of $621,000,000 increased $51,000,000 versus Q2 2018, largely on account of new facilities entering service across our businesses, higher composite depreciation rates approved in the mainline NEB 2018 decision and a stronger U.
S. Dollar, partially offset by the sale of power generation assets. Interest expense of $588,000,000 was $30,000,000 higher year, primarily due to higher levels of short term borrowings, long term debt issuances net of maturities and the foreign exchange impact on translation of U. S. Dollar denominated interest.
AFUDC decreased by $14,000,000 for the 3 months ended June 30, 2019, compared to the same period in 2018. A decline in U. S. Dollar denominated AFUDC was largely driven by Columbia Gas and Columbia Gulf Growth Projects being placed in service, partially offset by continued investment in our Mexico projects, while an increase in Canadian dollar denominated AFUDC was principally due to capital expenditures in our NGTL system expansion programs. Comparable interest income and other included sorry, decreased by 48 $1,000,000 in the Q2 versus 2018, primarily due to realized losses in 2019 on derivatives used to manage exposure to foreign exchange rate fluctuations on U.
S. Dollar denominated income. Income tax expense included in comparable earnings was $199,000,000 in the 2nd quarter, but compared to $146,000,000 for the same period last year, primarily on account of higher comparable earnings before income taxes and lower foreign tax rate differentials, partially offset by lower flow through income taxes in Canadian rate regulated pipelines, largely due to accelerated tax depreciation described earlier. Excluding Canadian rate regulated pipelines, where income taxes are a flow through item and thus quite variable, along with equity AFUDC income in the U. S.
And Mexico natural gas pipelines, we continue to expect our 2019 full year effective tax rate to be in the mid to high teens. Net income attributable to non controlling interests decreased by $19,000,000 for the 3 months ended June 30, 2019, mostly due to lower earnings in TC PipeLines LP, partially offset by the impact of the stronger U. S. Dollar in 2019 on their translation to Canadian dollars. And finally, preferred share dividends were largely in line with Q2 2018.
Now moving to cash flow and distributable cash flow on Slide 16. Comparable funds generated from operations approximately $1,700,000,000 in the 2nd quarter reflects an increase of $208,000,000 year over year, driven largely by higher comparable earnings as outlined, as well as the recovery of higher depreciation for both the Canadian Mainline and the NGTL system. Distributable cash flow, reflecting only non recoverable maintenance capital, was approximately $1,500,000,000 or $1.64 per share compared to $1,300,000,000 or $1.46 per share in the Q2 of 2018, resulting in a coverage ratio of 2.2x. Now turning to Slide 17. During the second quarter, we invested approximately $2,000,000,000 in our capital program and funded it through strong and growing internally generated cash flow, long term debt issuance, proceeds from asset sales and common equity from our dividend reinvestment plan.
In April, we raised $1,000,000,000 through an offering of 30 year medium term notes in the Canadian market at a fixed rate of 4.34%. Over the last few months, we have also made significant progress on the recycling of capital through portfolio management. These initiatives are expected to result in approximately $6,300,000,000 of proceeds in 2019. In May, we closed the sale of our Coolidge generating station for US448 million dollars or approximately CAD585 1,000,000. In July, we completed a partial monetization of the Northern Courier pipeline for aggregate proceeds of approximately CAD1.15 billion.
Also in July, we entered into agreements to sell certain Colombia U. S. Midstream assets for approximately US1.3 billion dollars or CAD1.7 billion dollars and our Ontario natural gas fired power plants for approximately CAD2.9 billion The Midstream sale is expected to close very soon, while the sale of the power assets is expected to be completed by the end of 2019. Finally, our dividend reinvestment plan, or DRIP, continues to provide incremental subordinated capital in support of our growth in credit metrics. In the Q2, the participation rate amongst common shareholders was approximately 34%, representing $238,000,000 of dividend reinvestment.
Year to date, the participation rate has been approximately 33%, resulting in $464,000,000 of common equity at a 2% discount. FIRP will remain in place for the 3rd quarter dividend. However, it is not a permanent element of our funding plan and will again be assessed at the time of our next dividend declaration based upon our progress towards achieving targeted metrics, placing new assets into service and closing announced asset sales. Our objective is to return to a self funding model in the near future, where our capital program is financed predominantly by internally generated cash flow and debt capacity. Now turning to Slide 18.
This graphic highlights our forecasted sources and uses of funds through 2021. Starting in the left column, the gross funding requirement over the 3 year time frame is projected to be $29,000,000,000 comprised of dividend and non controlling interest distributions of approximately $10,000,000,000 and capital expenditures of approximately $19,000,000,000 including maintenance capital. As a reminder, we are pursuing joint venture partners for the $6,200,000,000 Coastal GasLink project. For purposes of our funding program outlook, we assume we retain a 25% interest in the project, which is reflected in our capital requirements. The 2nd column highlights aggregate sources, including approximately $21,000,000,000 of internally generated cash flow, an estimated $1,000,000,000 of proceeds from our dividend reinvestment plan for the January through October 2019 dividend payments and $6,300,000,000 of proceeds from asset sales.
That leaves a remaining funding requirement of approximately $1,000,000,000 in the far right column, which is clearly modest in the context of our capital program and for which we have multiple levers available. Our funding needs could be mapped through the issuance of incremental senior debt within the constraints of our targeted credit metrics of debt to EBITDA in the high 4s and minimum FFO to debt of 15%. Additionally, we will consider issuing hybrids, maintaining these securities along with preferred shares at about 15 percent of our capital structure. Finally, I reiterate that the DRIP remains a quarter to quarter decision. In summary, our external funding needs are eminently achievable and all financing decisions will be evaluated on a per share basis.
Now turning to Slide 19. Over the 3 year period from 2019 through 2021, we also expect to refinance normal course debt maturities of approximately CAD7.2 billion equivalents, CAD1.6 billion of which has already been retired to date in 2019, and we are well positioned for the next $1,250,000,000 maturity scheduled for mid November. Normal course debt maturities are excluded from our funding outlook on the prior slide. In closing, I offer the following comments. Our positive financial and operational results in the second quarter continue to highlight our diversified low risk business strategy and reflect the strong performance of our legacy portfolio bolstered by continuing additions of high quality assets from our ongoing capital program.
Today, we are advancing a $32,000,000,000 suite of secured projects and have 5 distinct platforms for future growth in Canadian, U. S. And Mexico natural gas pipelines, liquids pipelines, power and storage. That is expected to support annual dividend growth of 8% to 10% through 2021. Success in adding to our growth portfolio in the coming years could augment or extend the company's dividend growth outlook further.
Finally, our overall financial position remains solid, supported by our strong credit ratings and a straightforward capital structure corporate structure. We remain well positioned to fund our near term capital program through resilient and growing internally generated cash flow and ready access to capital markets on compelling terms, supplemented by ongoing portfolio management. We will continue to make all funding decisions through the lens of per share metrics. 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 coordinator for questions from the investment community, we ask that you limit yourself to 2 questions. If you have additional questions, please reenter the queue.
Thank you, Mr. And the first question is from Linda Ezergailis with TD Securities. Please go ahead. Your line is open.
Thank you. I'm wondering if you could give us an update on your outlook for your liquids pipeline business post your open season for Keystone that I guess closed in July. Can you comment on how that went? And beyond just the capacity optimization that might be achieved on that front. Can you comment also on the outlook on the margin side?
Linda, it's Paul Miller here. First of all, on the open season results, we were pleased with the results. We are currently working through the various documentation, and we'll be in a position to disclose those results shortly. Timing of the increased contract flows on Keystone will likely occur starting in 2020 as we work through some of the capacity increases that we have planned for our system. Looking at the broader liquids business, we continue to be well contracted, Keystone being contracted about 94%, Market Link on the southern end of our system being contracted about 80%.
So I would anticipate relative stability. I think you'll see our contract revenue being relatively flat. Keystone will be relatively flat, both contract and spot. On the MarketLink system, on the southern end, we have been running effectively full. Maintaining that 80% contract level, we will have good stability.
But with some of the additional pipes coming into service here now and into Q3, Q4, we'll have to monitor how those market dynamics are playing out. There's a lot of noise in the market right now with line fill and speculation as to what's moving ahead, what's not. But as a general statement, I would see a general decline in the Market Link spot, again, which is about 20% of our space on Market Link. And we'll probably see additional supply coming out of the Permian. So those market dynamics are going to have to play out a little bit here before we can get any more visibility beyond On the marketing side, we'll be flat in Q3 relative to Q2.
That's our marketing affiliate. And again, Q4 and beyond, we're going to have to wait and see how the market dynamics play out with the new production and new pipes down in the U. S. Gulf Coast region.
That's very helpful context. Thanks, Paul. Maybe moving south, can someone maybe provide some context as to the next steps in Mexico? What are is there a time line that arbitration lays out in terms of the bookends in which this might be resolved? And there were some comments in your write up that you commenced discussions with some of the perceived issues on certain provisions in your contract.
Is that in parallel to the arbitration? And can you give any comment on that as well?
Linda, it's Francois Poirier speaking. I'll be happy to answer your question. Again, for context, in June, CFP filed request for arbitration under sort of Texas, the Odorayas and Tula projects seeking nullification of certain clauses regarding force majeure and requesting reimbursement of fixed capacity payments. In our view, the contracts were properly established in accordance with all original bid and regulatory requirements and remain valid and enforceable. And we will, of course, defend them as necessary through the arbitration proceedings.
On those arbitration proceedings, under the London Court of Arbitration Rules, there are time lines established for the various stages of arbitration, which we would expect would result in hearings sometime in late Q3 or Q4 of next year. And assuming that's assuming no unexpected delays, and then we would expect the decision to follow in the Q1 of 2021. But as you noted in your question in parallel, the parties have invited us to participate in negotiations to address their issues, and we have commenced discussions on these matters. So those processes are happening in parallel.
Thank you.
Thanks, Linda.
Thank you. The next question is from Robert Kwan with RBC Capital Markets. Please go ahead. Your line is open.
Great. Thank you. Maybe I'll just start by following up here on Mexico. So in the secured projects list, the footnote has been dropped around the force majeure. So are you not receiving the cash anymore from CFE?
Or are you provisioning it? Or what's going on from that perspective?
So we're entitled to receive Robert, it's Francois Portier again. We're entitled to receive force majeure payments where the claims have been recognized, and all recognized claims on Sur de Texas have been received. There are claims that have been recognized on Tula and Vila de Reyes, frankly, a de minimis or immaterial amount from our perspective in aggregate. We have not received those payments since the CFE has filed its request for arbitration, and we would expect that as within the context of our overall discussions and negotiations with them, we would look to resolve all of those questions as part of a holistic solution.
Okay. That's great. If I can finish just then with
kind of fundingasset sales. I guess the first part is part
of the description on funding. You're still holding out the potential for other asset sales. I'm just wondering outside of CGL, are you able to talk about the interest there selling outright, partial interest and then magnitude? And then the second part of the question for funding as it relates to the DRIP, Don, you mentioned quarter to quarter decision. Now what types of projects, given most of your stuff is small to medium size, what do you need to see in service to get that comfort?
And is it in terms of the funding, is that all the asset sales that you've announced to close today? Or are there other asset sales that you want to see in place before you think about turning off the DRAM?
Yes. I'll start with our additional portfolio management. The clearly, the one that's in progress right now is CGL. And we're quite encouraged by the level and the quality of the interest we've seen. And that predates the jurisdictional decision that came down.
The formal process is running. We would expect to complete that sale and bring in a JV partner late this year. As well, we're also looking at asset level funding at CGL. In terms of additional asset sales, the $500,000,000 area that we had indicated previously has effectively all been announced. We never categorically closed the door on additional asset sales.
Everything we look at is on a per share basis. So it does make sense to sell additional assets to avoid additional share count increase or if there is a valuation gap between our view and potential buyers' views on assets, we would continue to look at that. But the program that we had outlined earlier broadly, the $500,000,000 is largely complete. In terms of the DRIP decision, it is truly quarter to quarter. I mentioned a number of criteria that we'll look at here.
One is getting our credit metrics on side. We do expect as we the cadence of asset sale closings, if we get them done as described, we should be fully on side with our credit metrics in the high 4s in 2019 and FFO to debt in the 15% area. So we will again reassess this at the next dividend declaration date and just see where we are on closing these asset sales, getting additional assets into service. The key ones here, I guess, would be we'll look at Cerda Texas and where we are in Mexico. But I wouldn't say there's any specific qualitative checklist that we have to go through.
It's really how do we feel at that point in time. But we certainly made tremendous progress here. And again, it is something that we'll look at in their October Board meeting.
Great. Thank you very much.
Thanks, Robert.
Thank you. The next question is from Jeremy Tonet with JPMorgan. Please go ahead.
Hi, good morning. Just wanted to start with the East Lateral Express here. If you could expand a bit on how this project came together and kind of do you see other, I guess, demand pull projects that could come to fruition given what you're doing in the Columbia footprint there?
Jeremy, this is Stan. You can think of the East Lateral Express as a new demand center for us. If you're familiar with our system on the Columbia Gulf pipeline, you can think of it as an upside down line and this project is on the East Lake at a point called Plaquemines Parish. It's a great project for us. It's a compression only build, which is right in our wheelhouse to the tune of about 750,000 a day.
We're going to be one of 3 pipelines that are supplying the LNG facility, which in the aggregate will be around 20,000,000 tons. So I would just refer you back to some of my prior comments. LNG demand is the key growth center for the U. S. These days.
Today, we're exporting somewhere around 6 Bcf a day, which is more than twice the amount that we were exporting this time last year. And when you look at our success in the aggregates, we're going to supply somewhere around 30% of the LNG volumes come 2022 when you think in the context of almost 4 Bcf of projects under flight. And by 2022, the industry should be exporting LNG to the tune of about 10 Bcf to 12, maybe even 15 Bcf. So I think there's more success to come for us with respect to serving LNG load going forward and the East Lateral Express is just the latest addition to our project backlog list.
That's helpful context. Thanks. And just want to think about a bigger question picture here. The Power and Storage segment, you've kind of rationalized the portfolio a bit there. Just wondering if that changes your view and how you think about this segment.
Is it something you look to expand or to shrink over time? I know that there's Bruce, there's a lot of expansion potential there, but just wondering, philosophically, has anything changed?
It's Francois here. I'll answer that question. And fundamentally, our strategy hasn't changed. We're still seeking to pursue growth projects and contracted power in North America, with a focus on our core markets in Alberta and Ontario. We have several projects at various stages of development in Ontario as well as in other markets.
And as you mentioned, we remain committed to the Bruce MCR program and have committed $2,200,000,000 to the Unit 6 MCR and asset management program with potentially an additional $6,000,000,000 for future units. So strategy hasn't changed. There's a desire to continue to allocate incremental capital in this business unit for attractive projects that fit our risk preferences. Jeremy, I'd just add on to that. It's Russ.
The sale of these assets in no way is an indication of a changed strategy. With respect to power, we continue to believe that North America will need significantly more electricity infrastructure to meet the demand going forward. If you think about where those capital additions are going to take place in generation, renewables, transmission, battery storage. And there's just a whole host of things that are going to occur as a changing business. And if I look at our business position in our core geographies in Ontario, we supply about 30% of the power via Bruce Power.
It's affordable, it's reliable and it's missionless. And as Francois pointed out, there's a long capital program and growth potential there. If I think about our remaining assets in Alberta, in a conversion from coal to gas renewables and other things, again, we're well positioned to take advantage of those transitions. And as you mentioned in our core geographies, we intend to remain a significant player. But as Don mentioned, we'll always look to surface value from mature assets and redeploy that capital into our growth programs going forward.
That's helpful. That's it for me. Thanks.
Okay. Thanks, Jeremy.
Thank you. The next question is from Ben Pham with BMO.
My question maybe on a related one on the natural gas expansion. So you think about Louisiana Express, Grand Cheniere, how should we think about that in terms of your 7% to 9% unlevered return spectrum, because where it falls on that range?
Yes. You should think of both of those as right in our wheelhouse. They're compression only expansion. The financial valuation, again, think of them as 5 to 7 times EBITDA multiples squarely within that deck of the box there.
Okay. And then an early question, the Keystone 50 ks expansion, is that just simply some DRA optimization you guys are looking at that your utilization increasing? Are you guys actually looking at the nameplate moving around? And if so, is there a regulatory process you need built for that?
Hi, Ben. It's Paul here. Yes, the increase in the capacity will be largely achieved through the use of DRA and some minor bottlenecking debottlenecking on the system, but largely DRA. We will require regulatory approvals to increase that nameplate, and we will pursue those regulatory approvals.
Okay. And I know it's my second question, but the regulatory approval, that's just standard normal course. I wonder if nothing nothing notable on there?
No, that's correct. We'll require an amendment to our presidential permit and presidential amendments are not uncommon and there's always been a process to do this. And it's normal course for us to look at ways to optimize our system and this is just one of those ways.
Okay. That's great. Thanks, everybody.
You're welcome. Thanks, Pat.
Thank you. The following question is from Rob Hope with Scotiabank. Please go ahead.
Good morning, everyone. First question is on your Columbia system. We've seen some of your customers, especially on the E and P side, becoming a little bit more challenged. Can you just give an update on how volumes are ramping up versus your expectations as well as what your outlook for growth is in the Northeastern side of your system there?
Yes. I would say that our systems are in as much demand as they've ever seen right now. When you look at the Columbia Gulf system, for example, post in service of our Gulf XPress and Rain XPress projects, we're setting new peak day send out records in excess of 3 Bcf. When you look upstream to Mountain Viewer Express, we're seeing peak loads of around 2.2 Bcf a day on a 2.6 Bcf a day system. When you look at Leach Express, we're seeing peak day loads of about 1.2 Bcf a day on a 1.5 Bcf a day system.
On an average day, you can think of the upstream pipes MXP and LXP is flowing at somewhere around a 65% load factor or such. Now with respect to producers in particular, healthy producers are important to both our company and our industry. To an extent, they've been a victim of their own success in that this record production has led to lower gas prices. There's a large drive to live within their means, but to do that, they need to produce to generate the cash. Periodically, we do get inbounds for some of our producer customers seeking to restructure contracts and we'll do so when it makes sense to do that.
And in some cases, we've even proactively reached out to them because their capacity may have values to others. And being the optimist, again, I think that there's a broader feature ahead and we're going to grow our way demand out of this with respect grow our way with respect to incremental demand. Brady pointed out that on the LNG front in the U. S, we're currently exporting about 6 Bcf a day of LNG, which is twice what we were exporting this time last year. We're also seeing record loads with respect to gas fired power generation across many points on our system.
A and R, for example, earlier this month, earlier last month set both hourly and peak day send out records with respect to gas fired power generation. So again, demand for our assets is as strong as ever. And as demand continues to mature, both with respect to power generation and LNG growth, I think we'll see the producer health start to right itself. With respect to other growth opportunities on the Columbia system, we've done a really good job of adding supply to the system as evidenced by the fact that we put all these Express projects into service over the Q1 of this year. We're really turning our focus now to new demand.
And I think over the next 3 or 6 months or so, you'll see us come out with at least 1, maybe 2 new projects to add new gas fired power generation across the CECO footprint. And again, LNG growth is going to be a big part of that going forward as well. Hey, Rob. I can just add to that. So I think that the dynamics that Stan referred to are similar across all of our business today.
We've seen production increase in both gas and oil production on both sides of the border. As a result, there's a need for more capacity. That capacity pipeline transportation capacity, that transportation capacity has been difficult to build. So we're short transportation capacity wide differentials, which is putting pressure on both oil and gas producers in both countries. We're working as hard as we can to alleviate those egress situations.
But what I would tell you is that the demand for our system and the value of our capacity has grown substantially, whether that be egress out of the Western Sedimentary Basin for gas, as Paul referred to on the oil side and the movements we've been making to move additional Canadian oil across the border, but as well moving Permian oil to export markets. And as Stan said, if we can link up those producers via our systems to higher value markets like the LNG markets, that's going to help them to improve their cash flow situation. So I think the bottom line, the demand for our systems never been greater, as I've said, and the value of our transportation to our customers has never been greater. So I'd say we'll continue to try to work to expand egress wherever we can across our system, which is all of these small projects that are relatively small projects, dollars 200,000,000 to $500,000,000 projects. What I can tell you is expect to see more of that kind of activity across our whole system, whether it be gas or oil.
No matter where we are, we're looking for those kind of opportunities to demodleneck our system and offer that service to our shippers.
All right. I appreciate that fulsome answer. And then just switching over to Keystone XL, how are you thinking about that project now and the spend there for the kind of, let's call it, the remainder of the year?
Rob, it's Paul here. We continue to focus on resolving the various legal and regulatory matters in front of us. So we're actively managing resolution. And in the meantime, we're being very judicious in our spend, focusing on really the legal and regulatory with some minor work around preparation. But we're going to keep spending in check until we have a clear path to perhaps move forward on this project, but not until then.
All right. Thank you.
You're welcome.
Thanks, Rob.
Thank you. And the next question is from Robert Catellier with CIBC. Please go ahead. Your line is open.
Thank you. You've had a number of comments on the LNG demand. I wonder if you could provide a little bit more color there in light of a couple of projects in the U. S. That have received regulatory approval, but haven't had the commercial support yet.
What are you seeing on the in the market that gives you confidence the commercial support will be there in the medium term?
So this is Stan again. With respect to our projects that have not yet FID on the LNG front, expectation right now is that FID would be reached sometime next summer. So there continues to be progress made with respect to parties like Central Global, who is part of our Grand Cheniere and East Leg Express Projects signing up incremental load. The Flacoons Parish facility, as I told you, is 20,000,000 tonnes. Today, they have about 25% to 30% of that contracted for.
I think the key is going to be that demand for energy worldwide is continuing. When you look back at 2018, for example, primary energy consumption increased 2.9%, which was more than twice the historical rate and the fastest growth rate in 10 years. So from our perspective, it's more reliant on the fact that we need more energy sources of all kinds to meet worldwide demand going forward.
So you just see the low in the supply and demand and fundamentally changed? Just this balance between supply and demand is subject to vagaries of timing?
Effectively, yes. Again, as we consume more energy worldwide and we have, for the first time, perhaps, access to abundant North American energy supplies, gain access to worldwide markets, we think that the market fundamentals are very sound and that's what supports our outlook with respect to LNG growth going forward.
Okay. Thank you. And then my next question is on Bill C-sixty nine and how the passage there impacts how you approach growth specifically on NGTL, but also in other Canadian areas?
Robert, maybe I'll start with that. It's Tracy here. So we, as you know, have a significant capacity program underway in the NGTL system. We believe that all of that program will fall under our current system. So the new Bill T-sixty 9, although the bill is in place, we're working through the government is working through building out the regulations through which that bill will operate.
We are observing that as it goes by and making comments as we can on that, but it won't be until those regulations are complete that we really have a good working understanding of what the impact will be on further kind of expansions of the NGTL system or any other infrastructure really in on the Canadian regulated side.
And on larger scale projects, I mean, that's where the legislation is targeted. Is, as we've said before, anything that creates more uncertainty and more regulatory work that isn't well defined will obviously have an impact on the ability to bring those projects to fruition. And so we'll closely watch the legislation if it passes and moves on to filling in the blanks on the regulation on exactly how it's to going to work. But I think as we've said before, is directionally we think that it's going to make things more difficult.
The next question is from Andrew Kuske with Credit Suisse. Please go ahead.
Your line is open.
Thank you. Good morning. Not being patronizing about this, but it's been a pretty impressive pace of deleveraging and the asset sales that you've gone through. Now would you characterize some of the sales as being more opportunistic on your side of things and approaches that you've had and being able to monetize for good value versus TC Energy actually needing to sell some of these assets?
I'll start. It's Don here. We're certainly aware of different valuation metrics in for different asset holders. And so that's something that is that influences our thinking here. And again, as I mentioned earlier, as we look at funding our growth and getting our credit metrics to where we want them to stay comfortably in the future.
And your choice of one end of the spectrum is to issue stock and the other is sell assets. The math was fairly compelling for us to actually carry this out. So yes, so as we look at what we set out to do, we brought in $6,300,000,000 for something in the 500 dollars area of EBITDA. And without getting into the granularity, we achieved something in the high 11s in terms of a multiple on EBITDA. And we're very pleased with that, not only the outcome, but the pace in which it happened.
I think again, it highlights the Andrew, it's Russ again. The quality of the assets in our portfolio, all of the assets that we've divested ourselves up here over the last 12 or 18 months are all high quality assets, starting with our solar, wind assets to the thermal assets that we just sold, the midstream assets in Colombia, all high quality assets in our portfolio. As Don said, as we look forward in terms of our funding plan, our math was based on per share metrics and we were able to receive compelling value in the current capital markets. We've always got lots of levers to pull. That's what we've been telling the marketplace is that we feel comfortable in our funding program.
So these were, I would call them planned. We said that we probably had about $500,000,000 in EBITDA to divest that wasn't 100% core, but they're very good assets, but also that we wouldn't sell the assets unless we get compelling value for them because we had other levers to pull. So the things have worked out well for us. But I think they worked out well for the folks that have bought these assets as well. There's compelling value for both sides.
They're high quality assets and in some cases, high quality people that are going with those assets. So we're pleased with the program and it is in line with what our expectations was. We knew that we had good quality assets and the market was conducive to buying high quality assets at the current time.
I appreciate that. And then maybe just as a follow-up. Given the interest in the assets and a lot of the private equity might have been raised with a focus on infrastructure, are you still seeing a persistent public private valuation divide existing on people who are approaching you to look to buy certain assets versus the public company valuation you have?
It's Francois. Maybe I'll take a crack at that one. The answer is yes. There is, in certain circumstances, a difference between public and private market cost of capital. As part of our continuing program to rotate capital, we're very disciplined about regularly monitoring external value for our individual assets and marking that or comparing that to our hold value.
And when the external value exceeds our hold value, we pursue transactions. I think it's fair to say that there's a continued inflow of capital into infrastructure and pension funds that has created an opportunity for us to create some value and lower our own cost of capital. And it's a very viable lever we have to fund our growth program in addition to the other levers that Don has mentioned.
Okay, that's great. Thank you.
Great. Thanks, Andrew.
Thank you. The next question is from Alex Kania with Wolfe Research. Please go ahead. Thanks very much. I guess it's a follow-up question on the asset sales and the capital plan right now.
I mean, it feels like you've got ample support to hit your credit metrics. I'm just wondering how you think about it with respect to cushion on incremental capital that you might be seeing down the road. I mean, I'm thinking almost obviously about Keystone XL, but I'm just thinking about that as you look forward as well.
Yes. It's Don here. Well, step 1 was getting ourselves to a comfortable place with our metrics and modest amount of headroom. And as you can see from our funding plan, we're essentially fully funded now or very close to through 2021 for our current suite of assets. From a position of strength, we'll look at new projects, and that's that Keystone XL will be the biggest one.
That's fairly binary gono go at some point here. And so we'll continue to look at levers for that as we continue to refine cost and timing and all the commercial and regulatory aspects of that. In terms of capacity for new projects, you see us with this conveyor belt of smaller scale, mid scale stuff that continues to come in. One thing I would point out is even new projects that are landed today, given the regulatory permitting timelines, the spend is, in many cases several years out. So as you see projects being added to the portfolio now, the major spend is probably in 2020, 2021, some cases 2022.
So that's kind of the way we see the world right now. We're kind of reset ourselves here, whether from a credit perspective and then internally funding perspective, where we don't have to rely on share count growth or other levers to fund our current program in place at this point in time.
Great. And just a follow-up on
from the from the government just in terms
of the consultation timing? Or is that just to kind of be conservative to give enough time? Or do you maybe need a more global settlement with respect to just kind of curious about the CFE situation as well?
Yes, it's Francois. I'll answer that one on Tula. I think we're being conservative in our estimate. Obviously, it is the Ministry of Energy's obligation to undertake those consultations. And given the slow pace of progress to date, we decided it was wise to revise the estimate to end of year 2021.
We'll point out that both the Eastern and Western segments of Tula are complete. And once sort of Texas is flowing gas, certainly on the eastern it will be flowing gas on the eastern part of Tula and hopefully generating some IT revenue on that part of the system.
Great. Thanks very much.
Thank you. Thank
you. The next question is from Patrick Kenny with National Bank. Please go ahead.
Yes. Good morning, guys. I think it's been touched on already, but it appears gas producers in Canada have become much more responsive to daily swings in income prices and can likely accommodate a widespread curtailment even if it's just for a short duration. Wondering if we can get your thoughts on what gas curtailments would mean to your existing operations as well as the outlook for what might be next for NGTL in terms of perhaps slowing down that next wave of expansions or debottlenecking?
Patrick, it's Tracy. Yes, listen, we have an abundance of very good supply of gas in the WCSB. And the one thing that we don't have enough of is market. And so you see price move around because of that. And it's particularly acute, of course, in the summer when we have about 2 Bcf of demand that disappears here kind of locally in Alberta.
So the only permanent solution to AECO pricing, of course, is more market. And so we're working very hard with all of our customers on that. As you know, we have a big program underway that's going to provide just over 3 Bcf by 2022. We've got Coastal GasLink that will take another 2.1 out of the basin. And we've recently launched an open season with Stan's team on the next tranche capacity that will we could provide down through the Westpath down into Malin.
So we're working very hard to get those that egress in place. As to the other side of constraining supply in order to balance the system, there's been a lot of dialogue on that. We normally look at it through the lens of the market. We'll take care of that. We are at the table as with our customers and the government in particular talk about any number of options around how to provide not only that long term market access, but also some greater balance in the short term.
So we will we're working with our customers on that and with the government, we'll see where that takes us. As I said, there's any number of ideas at play.
Patrick, I guess I would just mention it for us again is don't mix up, as you point to asking your question, the potential slowdown in our expansion plans related to potential for whatever curtailment or other ideas that the folks might have for dealing with the short term situation. The long term, as Tracy said, the marketplace needs more capacity. And if anything, I would expect that, that would accelerate sort of further to my comments earlier today that the demand for our system is greater because it's difficult to build and that's what's causing these wide price differentials as production increases. So if anything, I would expect to see more increase in egress expansion for us, both in Alberta and ex Alberta. As we look at Yohu petrochemical demand, coal fired moving to gas fired demand in the province, expect to see more around that, more expansion on egress going south and east to continue to alleviate the problem long haul.
So if anything, I think that your expectation shouldn't be a slowdown in the program. But as John pointed out, as we look to programs in 2021, 2022, 2020 3, expect to see more capital required to expand the system.
All right. Thanks for that. That's great
color. Sorry, go ahead. Thanks, Patrick.
And maybe just one last question here, guys.
Yes. Go ahead.
Just going back to your comments around the focus on the per share metrics. Just wondering given the heightened focus on ESG out there right now and whether or not reducing the overall environmental footprint is now carrying a greater weight within your internal capital allocation decisions and perhaps plays a bigger factor now in the go, no go decision in Q and A.
Yes. I'll start and I'll invite my colleagues to jump in here. I wouldn't I think it's always been there. As we assess going forward on any project, we look at the build environment, what the impacts are, what the challenges to getting it done are. Certainly, the risk factors in some jurisdictions have increased.
I think things like Bill C-sixty nine have also influenced our assessment of projects. But frankly, it's always been there. And what it points to is there's probably some earlier kills, I would say, of ideas that we look at that just look very challenging given where they are and what they are.
I think just to be specific about Keystone and from an ESG perspective, ESG is a broad term. But when you look at the actual analysis of Keystone from an environmental perspective, the State Department concluded that GHG emissions will increase if you don't build the pipeline. The oil will continue to move. Building the pipeline doesn't affect global demand. It will be sourced from other locations and delivered through inferior means from a transportation perspective.
So more trains, more trucks, those kinds of things will create more GH emissions. So the actual conclusion is GH emissions increase. But as well, when we think of a broader ESG commitment, as Don said, it's always good for us there. I mean, you think about safety and reliability and making sure that communities are safe. Obviously, transporting oil by pipe is far more safe, responsible than transporting by any other means.
And then when you think about from a global security, national security perspective, those are issues that we think about as well. And you think about world turmoil, Middle East production, Venezuelan production, all of those causing challenges of heavy oil to the Gulf Coast. Obviously, Keystone is an answer to solving that supply demand problem and those products are much needed not just by United States, but on an export basis, they export them to other markets to rely upon those as well. We think about that broader spectrum. And when I think about Keystone XL, that the demand for that system has actually increased as a result of those global factors that I mentioned with respect to increased oil production both in Canada and the United States as well as declining production globally around places like Venezuela and Mexico.
So the need is greater and the most responsible and environmentally sound way of doing that is through a brand new high-tech pipeline system.
Yes, 100% agree that Keystone is ESG accretive from a global perspective. I was just curious how you thought about it from a TC Energy Corp. Standpoint. But thank you very much for those comments.
Okay. Thanks, Pat.
Thank you. The next question is from Matthew Taylor with Tudor, Pickering, Holt and Company. Please go ahead. Your line is open.
Hi, there. Thanks for taking my questions here. Just going back to Mexico. Sort of Texas and lower the rates are still pegged that in service in 2019 in the filings given that we're in August here and as already been noted here on the call negotiations are still ongoing. So is that dependent on this going to London arbitration?
Or just trying to figure out the feasibility of 2019?
Matthew, it's Francois. I'll answer that question. So with respect to Sur de Texas, as you're aware, the pipeline is mechanically complete. We notified the CFE of our readiness to provide service. However, the CFE has to confirm and declare in service.
So as to us commencing service in 2019, it will be contingent upon them making that declaration. I talked earlier about the London Court of Arbitration time lines. Those run into 20 20. So in terms of our ability to bring sort of Texas into service in 2019, it would be under the presumption that we can conclude a successful negotiation that's beneficial to both sides. On Villa de Reyes, progress does continue.
Construction is continuing. We expect to be putting the project into service in phases, with the first phase by the end of 2019 variety of different collaborating and working closely with a variety of different ministries in the Mexican government and getting good collaboration. However, I would say that the negotiations around the potential for arbitration will factor into that timing as well. Matthew, I'm on the same theme that I've talked about here this morning, when we're thinking about working our way through these issues, capital allocation, it's always based on fundamentals and where we see the fundamentals driving things. And when you think about something like the Sur de Texas pipeline, we will diligently work through our issues with CFE and the Mexican authorities.
They're our customer. But when you think about it from a macro perspective, the demand for that gas exists today. There's a large import of LNG that's taking place today to feed that demand. We're connecting those markets to the largest source of gas in the world, the most cheapest and reliable source being the U. S.
Gulf Coast. As Stan talked about this morning, producers in the U. S. Are looking for more egress capacity, more export capacity, LNG is one of those, but also Mexican demand is one of those. So you think about 2,000,000,000 cubic feet a day that can flow on that pipeline today and the benefit that, that can bring both to the producing community in the Lower 48 as well as Mexican customers.
Those numbers are substantial relative to their alternatives today. And those are the fundamentals that drive us and hopefully will be the fundamentals that drive resolution to this situation as quickly as possible. So all of those people can benefit that opportunity.
Yes, great. It's helpful context. And then one more, if I may. Tracy, just recent regulatory applications are shedding some light on shippers potentially looking for NGTL connectivity to see West Coast LNG. So obviously, early days here, but I see some evolution here perhaps within GTL moving some or redirecting some flows northwest.
Any sort of thoughts on how you see that evolution? And any thoughts maybe on size and types of projects would be helpful.
So Matthew, I think you're speaking about the NGTL connecting in to some of the West Coast pipes for LNG export. Is that right?
Yes, exactly.
Yes. So we've long held I mean, as you know, we're building Coastal GasLink, which is a contracted pipe. LNG Canada has contracted all the and their joint venture partners have contracted all of the capacity of that pipe. We believe strongly that the NGTL system offers some real benefits to those joint venture partners and when they're thinking about how to connect their supply into that pipeline and downstream into the LNG facility. And so we think that there's some potential there.
We are in discussions with all of our joint venture partners on exactly where they plan what the plans are for gas supply and how they want to connect that to the system. So we think there's some potential there. There's, as you would be aware, lots of dialogue on the West Coast around additional LNG export capacity. The first and the most relevant, of course, is an expansion of the LNG Canada facility, which would involve all the same joint venture partners. And beyond that, there's a number of other facilities under various stages of development.
So we believe the NGTL system offers some great benefits. You get access to AECO, it's a trading hub at net. It provides a lot of flexibility, and we think it will play a role as we look at volumes that move into the West Coast LNG opportunities, just like it does as you look down south into Malin or east into down the mainline into some of those other markets.
Okay. Thanks for taking my questions.
Thanks, Bhaskar.
Thank you. The next question is from Michael Lapides from Goldman Sachs. Please go ahead.
Hey, thanks guys for taking my question. Real quick one. Is there a way to back into the EBITDA of the assets sold? And by the way, congrats on the asset sales. I'm just trying to think about the impact on credit metrics and on just kind of broader EBITDA trajectory 2019 to 2020.
Yes. It's Don here. I'll reiterate my earlier answer. Dollars 6,300,000,000 of asset sales and proceeds, $500,000,000 area of EBITDA, multiple in the high 11s.
I'm sorry, didn't mean to cut you off.
No, that's it.
Now, great. So when you look out to and it
may be a little bit early,
how are you thinking about on a credit metric basis what your preferred target is? Like where do you want to be? And then kind of what's the band around that? Meaning, what's the level where you would want to start thinking again if your CapEx ramps up significantly about future asset sales? And what's the level where you would look at and say, hey, we're actually a little bit under levered here?
I'm just trying to think about the ranges around kind of leverage targets.
We look very long term. So it's not something that we can and then want to shift around on a quarter to quarter basis. It's high 4s debt to EBITDA and it's 15% FFO to debt. Those are the metrics that have been established for our credit ratings and it's our intent to maintain the highest credit ratings in our sector, in the high BBB plus category or the A- category, depending which agency is looking at that. Given the visibility of our projects, the timelines to get them regulatory approved and the like, we have a couple of years of visibility to and the ability to move stuff around.
We have a lot of levers we can pull to make sure we stay within that range. From time to time, you do get larger scale opportunities, be it an acquisition, be it a very large project such as a Coastal GasLink, potentially Keystone XL, where it can have a fairly pervasive effect on those metrics. So that's where we actually craft a plan and we actually go to the rating agencies ahead of time using their advisory services, evaluation services, get their views on what we're looking at. In many cases, they will allow you to breach those targets for some period of time to actually construct a project that is in strategy and consistent with your best preferences and then it fits their profile. So we do that from time to time.
We've just come out of that with Coastal GasLink, where from an accounting perspective, Coastal GasLink will be equity accounted for. And at the agencies, it will either be off credit or proportionate consolidated. So we have a lot of things going on in the background as we look at this stuff, and we it's our intent to supply the agencies the debt markets or the equity markets on something that we're looking at that's larger scale.
Thank you. The next question is from Jeremy Rosenfeld with Industrial Alliance. Please go ahead.
Yes, thanks. I'll be brief here. Just a couple of cleanup questions. First, going back to Mexico, and I'm trying to read between the lines, but I want to be sure that I understand in terms of holistic solutions that you referenced, Hosua. Could a sale of the assets, potentially to CFE be a holistic solution to the issue there?
And is there anything within the contract specifically that may prevent that?
So there's the contract does not contemplate any type of ownership transfer and any discussions we might have on potential solutions. Given the good momentum we have right now and out of respect for the process, I think I'll just leave it at that.
Okay, perfect. And then just another cleanup. With regard to the tax change,
the proposed tax change in Alberta,
I'm not sure if you have just the materiality of that in terms of on an annual basis, what that might mean for NGTL, guess to a small degree Canadian mainline, but NGTL specifically?
Yes, it's Don here. On a run rate basis, the flow through impact is at $70,000,000 to $80,000,000 range for the next couple of years, 2, 3 years here. And so I just and I think it's probably about half of that, that we booked in the Q2 of this year, but now $30,000,000 $35,000,000 I would just reiterate that this does reduce EBITDA, but it does not impact net income at all. We do not look for opportunities to increase our tax load or increase our interest costs on these businesses to artificially raise EBITDA for anyone who is using EBITDA as a valuation metric for Canadian regulated pipes.
Thanks, Jeremy.
Thank you. The next question is from Joe Jimmy Ngo with Morningstar. Please go ahead.
Thank you very much. Regarding the Keystone XL, can you talk about how you think about going forward with the project if you get the regulatory approvals or rulings that you need kind of in light with the potential or with the upcoming presidential election?
Hi, Joe. It's Paul here. Going forward, we Keystone XL remains very important for the producers and U. S. Refiners, particularly the latter who are looking to replace some of the declining supplies from other sources such as Venezuela.
And we have seen them contracted or take up contracts on the Keystone system. So it's a very important project for North America. We will continue to navigate the various legal and regulatory matters. At this point, it's premature to speculate on the outcome and timing of an FID construction start in our in service. We'll assess our position once we've mitigated all these various issues.
Okay, great. And would in a hypothetical situation in which you had maybe FID and you had the positive outcomes from the courts, would you consider moving forward before knowing the outcome of the next presidential
election? Again, Joe, I think what we need to do is we need to get the various matters behind us, and we'll assess our position at that point. I do want to highlight the continent wide benefit of Keystone XL and how we have our U. S. Refiners signing up for capacity.
They were anxious to get the pipe into service, and it's an important pipe for energy security.
Great. I appreciate the comments.
You're welcome. Thanks, Joe.
Thank you. Ladies and gentlemen, this I will now turn the call over to Mr. Moneta.
Thanks very much, and thanks to all of you for participating today. We very much appreciate your interest in TC Energy, and we look forward to talking to you again soon. Bye for now.
Thank you. The conference has now ended. Please disconnect your lines at this time. Thank you for your participation.