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TransCanada Corporation (NYSE:TRP)
Q2 2019 Earnings Call
August 1, 2019, 11:00 a.m. ET

Contents:

  • Prepared Remarks
  • Questions and Answers
  • Call Participants

Prepared Remarks:

Operator

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.

David Moneta -- Vice President of Investor Relations

Thanks very much and good morning, everyone. I'd like to welcome you to TC Energy's 2019 second quarter 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, US Natural Gas Pipelines, Paul Miller, Executive Vice President of our Technical Center and President of Liquids Pipelines, Francois Poirier, Executive Vice President, Corporate Development and Strategy, and President, Power and Storage and Mexico, and Glen 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 investor section under the heading of 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 Jaime 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 two 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 related 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 would 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 US Securities and Exchange Commission.

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. These and certain other comparable measures are considered to be non-GAAP measures. As a result, they may not be comparable to similar measures presented by other entities. These measures are used to provide you with additional information on 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 Russ Girling.

Russ Girling -- President and Chief Executive Officer

Thanks, David. Thank you all for joining us this morning. As highlighted in our quarterly report to shareholders, during the second quarter, our $100 billion portfolio of high-quality long-life energy infrastructure assets continued to profit from strong supply and demand fundamentals in the core geographies in which we serve.

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 $1.00 per share for the three months ended June 30th, 2019, which is a 16% increase over the same period of 2018. Similarly, comparable funds generated from operations of approximately $1.7 billion or 14% higher than last year.

Today, we are advancing $32 billion of secured capital projects with approximately $7 billion of those projects expected to be completed by the end of this year. We also continued to advance over $20 billion projects under development, including Keystone XL and the refurbishment of another five reactors of 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 second quarter, we raised $1 billion of 30-year debt at compelling rates and $238 million of common equity under our dividend reinvestment program. We also advanced several portfolio management initiatives, including the partial monetization of our Northern Courtier Pipeline in Alberta, along with the sale of certain Columbia Midstream assets in the Appalachian region and our natural gas-fired power plants in Ontario.

These initiatives combined with a sale of the Coolidge generating station, which closed in May, are expected to results in the combined proceeds of approximately $6.3 billion. Each of these transactions will allow us to serve as significant value for relatively mature assets and redeploy that cash into our $32 billion 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 we are well-positioned to achieve our targeted credit metrics in 2019. Don will provide more detail in our second quarter results in the funding program in just a few minutes. But before that, I'll expand on some of the recent developments, beginning with brief review of our financial results.

Excluding certain specific items, comparable earnings were $924 million or $1.00 per share in the second quarter, an increase of $156 million or $0.14 per share over the same period of 2018. That equates to a 16% increase on a per share basis after recognizing the effect of common shares issued under our dividend reinvestment programs in 2018 and 2019 and our ATM programs in 2018

Comparable EBITDA increased $33 million to approximately $2.3 billion, while comparable funds generated from operations of $1.7 billion were $208 million higher than the second quarter in 2018. Based on the strength of financial performance, the board of directors declared third quarter dividend is $0.75 per common share, which is equivalent to $3.00 per share on an annual basis. That represents an 8.7% increase over the amount declared in the third quarter in 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 five 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 to connect growing Western Canadian gas supply to markets across North America. Today, we are advancing an $8.8 billion expansion program on the NGTL system that will add approximately 3 billion 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 final investment decision last October on their LNG terminal in Kitimat, British Columbia. The $6.2 billion project will have an initial capacity of approximately 2.1 billion cubic feet a day with potential expansion capacity up to 5 billion cubic feet a day.

During the second quarter, 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 the end of the fourth quarter 2019.

Moving to our US 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 US daily demand. In addition to moving those volumes on our existing systems, during the second quarter, we continued to advance our $1.1 billion modernization two program on the Columbia Gas System as well as another $1.1 billion US of other capacity additions that now include the Louisiana Xpress Project and the Grand Chenier Xpress Project.

Combined, those two projects will connect nearly 2 billion cubic feet a day of gas supplied to Gulf Coast LNG export markets. Louisiana Xpress is a $400 million US project that is expected to enter service in 2022, while Grand Chenier is a $200 million US project that is expected to enter service in two phases, over the 2021 and 2022 periods.

Finally, in US pipelines, we continue to advance the East Lateral Xpress project. The $300 million US 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 three pipelines at a total cost of approximately $3.2 billion. In June, we completed the construction and commissioning activities for the Sur de Texas pipeline, which has the capacity to move up to 2.6 billion cubic feet a day of low-cost US 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 acknowledgements of readiness prior to commencing service under the transportation service contract.

Construction on the Villa de Reyes Project is ongoing, with phased 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 complications 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, Villa de Reyes, 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 additional bid and regulatory requirements and remain valid. That said, we remain open to discussions in resolving these issues.

Turning now to our liquids business, which produced very strong results again in the second quarter of 2019 -- Keystone, which is underpinned by long-haul take or pay contracts for 550,000 barrels per day essentially ran at capacity in the second 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 first quarter and again in the second quarter of 2019.

In addition, we continued to benefit from higher contributions 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 million white spruce pipeline and commercial in service was achieved in early May.

Finally, in liquids pipelines during the first half of 2019, we continued to advance the Keystone XL. As you know, in late March, the US President Trump issued a new presidential permit for the project, which supersedes the 2017 permit. The President's actions clarified the national importance of Keystone XL and aimed to bring more than ten 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 fourth quarter of 2018 and we are awaiting a final decision. We continue to believe the approval of the alternate 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 secure project to construction.

Turning to power and storage, as you know, we experienced equipment failure on the $1.8 billion Napanee project while progressing commissioning activities on the plant in the first quarter 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 $2.2 billion 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 1st, 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 and the sale of our three Ontario natural gas-fired power plants, we do remain committed to the ongoing multi-billion 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 billion of secured growth projects that are expected to enter service by 2023. It includes approximately $5 billion of maintenance capital, 85% 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 billion into these programs to date with approximately $7 billion of these projects expected to be completed by the end of 2019.

The projects expected to enter service this year include $2.6 billion of NGTL system expansions as well as the Sur de Texas natural gas pipeline in Mexico and Napanee gas-powered 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 the demand for our services remains strong.

In 2018, our $100 billion asset portfolio generated approximately $8.6 billion of annual EBITDA with approximately 95% of that EBITDA coming from regulated businesses or long-term contracted assets. Looking forward, we have five significant platforms for growth, Canadian, US, and Mexico and natural gas pipelines, liquids pipelines, and our power and storage business.

Just as we have done since 2000, as we advanced our $32 billion secured capital program, we expect to deliver growth in earnings and cash flow and dividends per share. In addition, we have more than $20 billion of projects that are in advanced stages of development and we expect numerous other growth opportunities to emanate from our extensive critical asset footprints. We have a history of prudently funding our capital programs and we are on track to continue to de-lever 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?

Don Marchand -- Executive Vice President and Chief Financial Officer

Thanks, Russ and good morning, everyone. As outlined in our quarterly results issued earlier today, net income attributable to common shares is $1.1 billion or $1.21 per share in the second quarter of 2019 compared to $785 million or $0.88 per share for the same period in 2018. Excluding specific items, comparable earnings of $924 million or $1.00 per share in second quarter of 2019 were $156 million or $0.14 per share higher year over year.

This equates to a 16% increase on a per share basis after also getting effects of common shares issued under the dividend reinvestment plan in 2018 and 2019 and the aftermarket 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 US natural gas pipelines and liquids pipelines.

Turning to our business segment results on slide 14, in the second quarter, comparable EBITDA was approximately $2.3 billion, representing a $333 million or a 17% increase in 2018. Canadian natural gas pipelines comparable EBITDA of $528 million was $17 million lower than for the same period last year, primarily due to lower flow through taxes on the NGTL system and the Canadian main line 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 main line.

Net income for the NGTL system increased $22 million compared to second quarter 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 2018-2019 rate settlement.

Conversely, net income for the Canadian main line decreased $2 million due to a lower average rate base partially offset by incentive earnings recorded in the second quarter 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 because they are almost entirely recovered in revenues in a flow through basis.

US natural gas pipelines, comparable EBITDA of $641 million US or $857 million Canadian in the quarter, increased by $95 million US or $153 million Canadian 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 $107 million US or $141 million Canadian was essentially in line with second quarter 2018. Liquids pipelines comparable EBITDA rose by $169 million to $582 million 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 million year over year to $219 million, 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 stains. These positive results were partially offset by decreased western and eastern power contributions largely due to the sale of our interest in 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 US dollar-denominated income, including US 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 US dollar versus the second quarter of 2018. This was largely offset by higher translated interest expense on US dollar denominated debt and realized hedging losses reported in comparable interest income and other.

Regarding our exposure to foreign exchange rates, the sizable portion of our US dollar-denominated assets are hedged with US dollar-denominated debt. We continue to actively manage the residual exposure on a rolling one-year forward basis.

Now, turning to other income statement items on slide 15, depreciation and amortization of $621 million increased $51 million versus second quarter 2018, largely on account of new facilities entering service across our businesses. Prior composite depreciation rates approved in the main line NEB 2018 decision and a stronger US dollar partially offset by the sale of power generation assets.

Interest expense of $588 million was $30 million higher year over 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 US dollar-denominated interest. AFUDC decreased by $14 million for the three months ended June 30th, 2019 compared to the same period in 2018.

A declining US 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.

Profitable interest income and other decreased by $48 million in the second quarter versus 2018 primarily due to realized losses in 2019 on derivatives used to manage exposure to foreign exchange rate fluctuations on US dollar-denominated income. Income tax expense included in comparable earnings was $199 million in the second compared to $146 million 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 regulated pipelines, largely due to accelerated tax depreciation described earlier.

Excluding Canadian rate regulated pipelines where income taxes are a flow through item along with equity AFUDC income in US 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 million for the three months ended June 30th, 2019, mostly due to lower earnings in TC Pipelines LT, partially offset by the impact of the stronger US dollar in 2019 on their translation to Canadian dollars. Finally, preferred share dividends were largely in line with second quarter 2018.

Now, moving to cash flow and distributable cashflow in slide 16, comparable funds generated from operations of approximately $1.7 billion in the second quarter reflects an increase of $208 million year over year driven largely by higher comparable earnings as outlined as well as the recovery of higher depreciation for both the Canadian main line and the NGTL system.

Distributable cash flow reflecting on non-recoverable maintenance capital was approximately $1.5 billion or $1.64 per share compared to $1.3 billion or $1.46 per share in the second quarter of 2018, resulting in a coverage ratio of 2.2 times.

Now, turning to slide 17 -- during the second quarter, we invested approximately $2 billion 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 billion 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 in the recycling of capital through portfolio management. These initiatives are expected to result in approximately $6.3 billion in proceeds in 2019.

In May, we closed the sale of our Coolidge generating station for $448 million US or approximately $585 million Canadian. In July, we completed a partial monetization of the Northern Courier Pipeline for aggregate proceeds of $1.15 billion. Also in July, we entered into agreements to sell certain Columbia US midstream assets for approximately $1.3 billion US or $1.7 billion Canadian and our Ontario natural gas-fired power plants for approximately $2.9 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 DRP continues to provide incremental subordinated capital in support of our growth and credit metrics. In the second quarter, the participation rate among common shareholders was approximately 34%, representing $238 million of dividend reinvestment. Year to date, the participation rate has approximately 33%, resulting in $464 million of common equity at a 2% discount.

DRP will remain in place for the third-quarter dividend, however, it is not a permanent element of our funding plan and will again be assessed the time of our next dividend declaration based upon our progress toward achieving targeted metrics, placing new assets into service, and closing announced asset sales. Our objective is to return to self-funding model in the near future, where our capital program is financed predominately by internally generated cashflow 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 timeframe is projected to be $29 billion, comprised of dividend and non-controlling interest distributions of approximately $10 billion in capital expenditures of approximately $19 billion, including maintenance capital. As a reminder, we are pursuing joint venture partners for the $6.2 billion coastal gas link project. For purposes of our funding program outlook, we assume you retain a 25% interest in the project, which is reflected in our capital requirements.

The second column highlights aggregate sources, including approximately $21 billion of internally generated cash flow, an estimated $1 billion of proceeds from our dividend reinvestment plan for the January through October 2019 dividend payments and $6.3 billion of proceeds from asset sales. That leaves a remaining funding requirement of approximately $1 billion in the far-right column, which is clearly modest in the context of our capital program for which we have multiple levers available.

Our funding needs [inaudible] the issuance of incremental senior debt, within the constraints of our targeted credit metrics of debt to EBITDA in the high fours, and minimum FFO to debt of 15%. Additionally, we will consider issuing hybrids, maintaining these securities along with preferred shares at about 15% of our capital structure. Finally, I reiterate that the DRP 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 three-year period from 2019 through 2021, we also expect to refinance normal course debt maturities of approximately $7.2 billion Canadian equivalents, $1.6 billion of which has already been retired to date in 2019 and we are well-positioned for the next $1.25 billion US maturities scheduled for mid-November. Normal course debt maturities are excluded from our funding outlook on the prior slide.

In closing, I'd 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 billion suite of secured projects and have five distinct platforms for future growth in Canadian, US, 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 further.

Finally, our overall financial position remains solid, supported by our strong credit ratings and a straightforward corporate structure. We remained 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&A.

David Moneta -- Vice President of Investor Relations

Thanks, Don. Just a reminder before I turn it over to the conference coordinator for questions from the investment community, we ask that you limit yourself to two questions. If you have additional questions, please reenter the queue.

Questions and Answers:

Operator

Thank you, Mr. Moneta. We will now take questions from the telephone lines. If you have a question and you're using a speakerphone, please lift your handset before making your selection. If you have question, please press *1 on your telephone keypad. If any time you wish to cancel your question, please press the # sign. Please press *1 at this time if you have a question.

The first question is from Linda Ezergailis with TD Securities. Please go ahead. Your line is open.

Linda Ezergailis -- TD Securities -- Analyst

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, beyond that capacity optimization that might be achieved on that front? Can you comment on the outlook on the marketing side?

Paul Miller -- President of Liquids Pipelines

Hi, 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 documentation and will be 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 length on the southern end of our system, being contracted at about 80%. So, I would anticipate relative stability. I think you'll see our contract revenue being relatively flat. Keystone will be relatively flat for 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. As a general statement, I would see a general decline in the Marketlink spot, which is about 20% of our space on Marketlink and we'll probably see additional supply coming out of the Permian. Those market dynamics are going to have play out a little bit here before we can get any visibility beyond that.

On the marketing side, we'll be flat in Q3 relative to Q2. That's our marketing affiliate. 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 play out in the US Gulf Coast region.

Linda Ezergailis -- TD Securities -- Analyst

That's very helpful context. Thanks, Paul. Maybe moving south, can someone maybe provide some context as to the next steps in Mexico? Is there a timeline that arbitration lays out in terms of the bookends in which this might be resolved? There was some comments in your write-up that you commenced discussions on some of the perceived issues on certain provisions in your contract. Is that in parallel to the arbitration? Can you give any comment on that as well?

Francois Poirier -- Executive Vice President of Corporate Development and Strategy

Hey, Linda. It's Francois Poirier speaking. I'll be happy to answer your question. For context, in June, CFE filed request for arbitration under Sur de Texas, the Villa de Reyes, 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 with all original bid and regulatory requirements and remained valid and enforceable. We will of course defend them as necessary through the arbitration proceedings.

On those arbitration proceedings, under the London Accord of Arbitration Rules, there are timelines established for the various stages of arbitration, which we would expect would result in hearings sometime in late third quarter or fourth quarter or next year. That's assuming no unexpected delays.

Then we would expect a decision to follow in the first quarter of 2021. But as you noted in your question in parallel, the parties have invited us to participate in negotiations to address their issues. We have commenced discussions on these matters. So, those processes are happening in parallel.

Operator

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

Robert Kwan -- RBC Capital Markets -- Analyst

Thank you. Maybe I'll start by following up on Mexico. In the secured projects list, a footnote has been dropped around the force majeure. Are you not receiving the cash anymore from CFE or are you provisioning it? What's going on from that perspective?

Francois Poirier -- Executive Vice President of Corporate Development and Strategy

So, 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 Villa 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 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.

Robert Kwan -- RBC Capital Markets -- Analyst

That's great. If I can finish with funding/asset 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 of selling outright partial interest and then magnitude? Then the second part of the question -- as it relates to the DRP, Don, you mentioned quarter to quarter decision.

What types of projects, given most of your stuff is small to medium side, what do you need to see in surface to get that comfort? Is it in terms of the funding? Is that all the asset sales that you announced are closed today or are there other asset sales that you've announced are closed today or are there other asset sales that you want to see in place before you think about turning off the DRP?

Don Marchand -- Executive Vice President and Chief Financial Officer

I'll start with our additional portfolio management. Clearly the one that's in progress right now is in CGL. We're encouraged by the level and the quality of the interest we've seen in that. 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 million area that we had indicated previously has effectively all been announced. I never categorically close 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, and assets, we would continue to look at that. The program that we had outlined earlier broadly, the $500 million is largely complete.

In terms of the DRP 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 site. 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 and high fours 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 would be -- we'll look at Sur de Texas and where we are in Mexico. 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 will look in the October board meeting.

Robert Kwan -- RBC Capital Markets -- Analyst

Great. Thank you very much.

Operator

Thank you. The next question is from Jeremy Tonet with JP Morgan. Please go ahead.

Jeremy Tonet -- JP Morgan -- Analyst

Good morning. I wanted to start with the East Lateral Express here. If you could, expand a bit on how this project came together. Do you see other demand pole projects that could come to fruition given what you're doing in your Columbia footprint there?

Stan Chapman -- President of U.S. Natural Gas Pipelines

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 could think of it as an upside-down Y 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 three pipelines that are supplying the LNG facility, which in the aggregate will be around 20 million tons. I will refer you back to some of my prior comments. LNG demand is the key growth center for the US 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.

When you look at our success in the aggregate, we're going to supply somewhere around 30% of the LNG volumes come 2022 when you think of the context of almost 4 BCF of projects under flight. By 2022, the industry should be exporting LNG to the tune of about 10 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 the latest addition to our project backlog list.

Jeremy Tonet -- JP Morgan -- Analyst

That's helpful context. Thanks. I just want to think about a bigger question pictured here. The power and storage segment, you've kind of rationalized the portfolio a bit there. I'm just wondering if that changes your view and how you think about this segment. Is that something you look to expand or shrink over time. I know that there's a lot of expansion potential there, but just wondering philosophy, has anything changed?

Francois Poirier -- Executive Vice President of Corporate Development and Strategy

Hi, it's Francois here. I'll answer that question. Fundamentally, our strategy hasn't changed. We're still seeking to pursue growth projects in 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.

As you mentioned, we remain committed to the Bruce MCR program and have committed $2.2 billion to the Unit 6 MCR and asset management program with potentially an additional $6 billion 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.

Russ Girling -- President and Chief Executive Officer

Just to 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 North America will need significantly more electricity infrastructure to meet the demand going forward. You think about where those capital additions are going to take place in generation, renewables, transition, battery storage, 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. It's mission-less.

As Francois pointed out, there's a long capital program and growth potential there. I think about our remaining assets in Alberta and a conversion from coal to gas to 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.

Jeremy Tonet -- JP Morgan -- Analyst

That's helpful. That's it for me. Thanks.

Operator

The next question is from Ben Pham with BMO. Please go ahead. Your line is open.

Ben Pham -- BMO Capital Markets -- Managing Director

Thanks. My question is a related one on the natural gas expansion, Louisiana Express. How should we think about that in terms of your 7% to 9% unlevered returns? Where does it fall in that range?

Russ Girling -- President and Chief Executive Officer

You should think of both of those as right in our wheelhouse. They're compression-only expansions. On the financial valuation, think of them as 5 to 7 EBITDA multiples within that little box there.

Ben Pham -- BMO Capital Markets -- Managing Director

On an earlier question, the Keystone 50k expansion -- is that simply some DRA optimization you guys are looking at, utilization increasing or are you looking at the nameplate moving around? If so, is there a regulatory process you need to go through for that?

Paul Miller -- President of Liquids Pipelines

Hi, Ben. It's Paul here. The increase in the capacity will be largely achieved through the use of DRA and some minor debottlenecking on the system, but largely DRA. We will require regulatory approvals to increase that nameplate and we will pursue those regulatory approvals.

Ben Pham -- BMO Capital Markets -- Managing Director

I know it's my second question, but the regulatory approvals, is that a standard normal course?

Paul Miller -- President of Liquids Pipelines

That's correct. We'll require an amendment to our Presidential Permit. Presidential amendments are not uncommon and there's always been a process to do this. It's normal course officer ways for us to look at ways to optimize our system.

Operator

The following question is from Rob Hope with Scotiabank. Please go ahead.

Rob Hope -- Scotiabank -- Analyst

Good morning, everyone. The first question is on your Columbia system. We've seen some of your customers, especially on the E&P side becoming a little bit more challenged. Can you give an update on how volumes are revving up versus your expectations as well as what your outlook for growth is in the northeastern side of your system there?

Stan Chapman -- President of U.S. Natural Gas Pipelines

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 were setting new peak day send out records in excess of 3 BCF. When you look upstream to Mountaineer Xpress, 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 Xpress, 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 could think of the upstream pipes, MXP and LXP is flowing at somewhere around a 65% load vector or such. With respect to producers in particular, healthy producers are important to both our company and our industry. To the extent, they've been a victim of our own success and that this record production has led to lower gas prices. There's a large drive to live within their means, but 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. In some cases, we've even proactively reached out to them because their capacity may have values to others. Being the optimist, again, I think there's a brighter future ahead. We're going to grow our way with respect to incremental demand.

We already pointed out that on the LNG front, in the US, 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. ANR, for example, earlier this month or earlier last month set both hourly and peak day send out records with respect to gas-fired power generation. So, demand for our assets is as strong as ever and as demand continues to mature with respect to power generation, I think we'll see the producer start to write 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 expressed projects into service over the first quarter of this year. We're really turning our focus now to new demand. I think over the next three or six months or so, you'll see them come out with one, maybe two new projects to add new gas-fired power generation across the [inaudible] footprint. Again, LNG growth is going to be a big part of that going forward as well.

Russ Girling -- President and Chief Executive Officer

Hey, Rob, if I could just add to that -- I think 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 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.

What I would tell you is 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 Don 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 improve their capital situation.

The bottom line is demand for our systems has never been greater, as I've said. The value of our transportation to our customers has never been greater. As I've said, we'll continue to work to expand egress wherever we can across our system, which is all of these small projects that are relatively small projects, $200 million to $500 million projects.

What I can tell you is expect to see more of that kind of activity across our whole system, whether the gas or oil, no matter where we are, we're looking for those kinds of opportunities to debottleneck our system and offer that service to our shippers.

Rob Hope -- Scotiabank -- Analyst

Just shifting over to Keystone XL, how are you thinking about that project there and the spend there for the remainder of the year?

Paul Miller -- President of Liquids Pipelines

Hi, Rob. It's Paul here. We continue to focus on resolving the various legal and regulatory matters in front of us. We're actively managing resolution and in the meantime, we've been very judicious in our spend, focus on the legal and the regulatory with some minor work around preparation. We're going to keep spending in check until we have a clear path to move forward on this project but not until then.

Rob Hope -- Scotiabank -- Analyst

Thank you.

Operator

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

Robert Catellier -- CIBC Capital Markets -- Analyst

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 US that received regulatory approval but haven't had the commercial support yet. What are you seeing in the market that gives you confidence the commercial support will be there in the medium term?

Stan Chapman -- President of U.S. Natural Gas Pipelines

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. There continues to be progress made with respect to parties like [inaudible] Global, who is part of our East Lat Express projects, signing up incremental load. The Plaquemines Parish facility, as I told you, is 20 million tons. Today, they have about 25% to 30% 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 ten years. 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.

Robert Catellier -- CIBC Capital Markets -- Analyst

So, you just see the lull in the supply and demand and nothing fundamentally changed?

Stan Chapman -- President of U.S. Natural Gas Pipelines

Effectively, yes. 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 the market fundamentals are very sound and that's what supports our outlook with respect to LNG growth going forward.

Robert Catellier -- CIBC Capital Markets -- Analyst

Okay. My next question is on Bill C69 and how the passage impacts how you approach growth specifically on NGTL but also in other Canadian areas.

Tracy Robinson -- President of Canadian Natural Gas Pipelines

Robert, maybe I'll start with that. It's Tracy here. So, we, as you know, have a significant capacity program under way in the NGTL system. We believe that all of that program will fall under our current system. So, the new Bill C69, 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. It won't be until those regulations are complete that we really have a good working understand on what the impact will be on further expansions of the NGTL system or any other infrastructure, really on the Canadian regulated side.

Russ Girling -- President and Chief Executive Officer

Larger scale projects, that's where the legislation is targeted. As we 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. So, we'll closely watch the legislation if it passes. I think as we said before, directionally, we think that it's going to make things more difficult.

Operator

The next question is from Andrew Kuske with Credit Suisse. Please go ahead. Your line is open.

Andrew Kuske -- Credit Suisse -- Analyst

I'm not being patronizing about this, but it's been a pretty impressive pace of deleveraging and the asset sales that you've gone through. Would you characterize some of the sales as being more optimistic on your side of things and approaches that you've had being able to monetize for good value versus TC Energy actually needing to sell some of these assets?

Don Marchand -- Executive Vice President and Chief Financial Officer

I'll start, Don here. We're certainly aware of different valuation metrics for different asset holders. So, that's something that influences our thinking here. As I mentioned earlier, as I look at funding our growth in our getting our credit metrics to where we want them to stay comfortably in the future and your choice of one end of the spectrum and the other is to sell assets, the math is really compelling for us to carry this out.

So, as we look at what we set out to do, we brought in $6.3 billion for something in the $500 million area of EBITDA. Without getting into the granularity of it, we achieved something in the high 11s in terms of a multiple on EBITDA. We're very pleased with that, not only the outcome, but the pace at which it happened.

Russ Girling -- President and Chief Executive Officer

I think it highlights the quality of the assets in our portfolio. All of the assets that we divested ourselves in over the last 12-18 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 our 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 marketplaces, that we feel comfortable in our funding program. So, these were -- I would all them planned. We said we probably had about $500 million of EBITDA to divest, that it wasn't 100% core but they were 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, things have worked out well for us, but I think they've worked out well for the folks that have bought the assets as well, there's compelling value for both sides. They're either 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.

Andrew Kuske -- Credit Suisse -- Analyst

Maybe just as a follow-up, given the interest in the assets and a lot of the private equity money that you've raised with a focus on infrastructure, are you still seeing a persistent public/private valuation to provide valuation divide existing on people who are approaching you to look to buy certain assets versus the public company valuation you have?

Francois Poirier -- Executive Vice President of Corporate Development and Strategy

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 individual assets and marking that or comparing that to our hold value.

When the external value exceeds our hold value, we pursue transactions. I think it's fair to say there's a continued inflow of capital into infrastructure and pension funds that has created an opportunity for us to create value and lower our own cost of capital and it's a very viable lever we have to fund our growth programs in addition to the other levers that Don as mentioned.

Operator

Thank you. The next question is from Alex Kania with Wolfe Research. Please go ahead.

Alex Kania -- Wolfe Research -- Analyst

Thanks very much. I guess it's a follow-up question on the asset sales and the capital plan right now. It feels like you've got ample support to hit your credit metrics. I'm wondering how you think about it with respect to cushion incremental capital that you might seeing down the road? I'm thinking most obviously about Keystone XL but thinking about it as you move forward as well.

Don Marchand -- Executive Vice President and Chief Financial Officer

It's Don here. Step one was getting ourselves to a comfortable place with our metrics and modest amount of headroom. As you can see from our funding plan, we're essentially fully funded now or very close to it through 2021 for our current suite of assets. From a position of strength, we'll look at new projects and Keystone XL would be the biggest one. That's fairly binary go-no go. At some point here, 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 conveyer belt of smaller scale, midscale 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 kind of reset ourselves here where from a credit perspective and an 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.

Alex Kania -- Wolfe Research -- Analyst

Thanks. Just to follow-up on Mexico on the Tula project -- on the updated time schedule for that, do you have a sense from the government just in terms of the consultation timing or is that to be conservative to give enough time or do you need a more global settlement?

Francois Poirier -- Executive Vice President of Corporate Development and Strategy

Yeah. 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. Given the slow pace of progress to date, we decided it was wise to revise the estimate to end of year 2021. I will point out that both the Eastern and Western segments of Tula are complete and once Sur de Texas is flowing gas 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.

Alex Kania -- Wolfe Research -- Analyst

Great. Thanks very much.

Operator

The next question is from Patrick Kenney with National Bank. Please go ahead.

Patrick Kenney -- National Bank -- Analyst

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 prices and can likely accommodate a widespread curtailment, even if it's just for a short duration. I'm wondering if we can get your thoughts on what gas curtailments would mean for 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.

Tracy Robinson -- President of Canadian Natural Gas Pipelines

Hey, Patrick. It's Tracy. We have an abundance of very good supply of gas in the WCSB and one thing that we don't have enough of is market. You see price move around because of that. It's particularly key, of course, in the summer when we have about 2 BCF of demand that disappears here kind of locally in Alberta. The only permanent solution to eco pricing, of course, is more market.

So, we're working with all of our customers on that. As you know, we have a big program under way 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. We've recently launched an open season with Stan's team on the next tranche capacity that we can provide down to the west path down into [inaudible]. So, we're working very hard to get 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 will take care of that. We are at the table with our customers and the government in particular will 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. We're working with our customers on that and with the government. We'll see where that takes us. As I said, there are any number of ideas at play.

Russ Girling -- President and Chief Executive Officer

Patrick, I guess I would just mention don't mix up a potential slowdown in our expansion plans related to potential for whatever curtailment or other ideas 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 would accelerate. Further to might comments earlier today, 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.

If anything, I would expect to see more increase in egress expansion for us, both in Alberta and ex-Alberta as we look at petrochemical demand. Coal-fired is moving to gas-fired demand in the province. Expect to see more expansion on egress going south and east to continue to alleviate the problem long haul. If anything, I think your expectation shouldn't be a slowdown, but as Don pointed out, as we look to programs in 2021, 2022, 2023, expect to see more capital required to expand the system.

Patrick Kenney -- National Bank -- Analyst

Don, back to your comments around the focus on the per share metrics. I'm just wondering given the heightened focus on ESG out there right now, whether or not reducing the overall environment 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 Key XL.

Don Marchand -- Executive Vice President and Chief Financial Officer

I'll start and I'll invite my colleagues to jump in here. I think it's always been here. 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 C69 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 look very challenging given where they are and what they are.

Stan Chapman -- President of U.S. Natural Gas Pipelines

I think just to be specific about Keystone from 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 from inferior means from a transportation perspective. So, more and more trains, more trucks, those kinds of things will create more GHG emissions.

So, the actual conclusion is GHG emissions increase. But as well, when we think of a broader ESG commitment, as Don said, it's always been -- think about safety and reliability and making sure communities are safe, obviously transporting oil by pipe is far more safe, responsible than transporting by any other means.

Then when you think about from a global security, national security perspective, those are issues we think about as well. You think about world turmoil, Middle Eastern production, Venezuelan production, all of those causing challenges in heavy oil to the Gulf Coast. Obviously, Keystone is an answer to solving that supply and demand problem. Those products are needed not just by the United States but on an export basis. They export them to other markets to rely upon those as well.

When I think about Keystone XL, the demand for that system has actually increased as a result of those global factors that I mentioned with respect to increased well 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.

Operator

Thank you. the next question is from Matthew Taylor with Tudor, Pickering, Holt & Company.

Matthew Taylor -- Tudor, Pickering, Holt & Co. -- Analyst

Hi, there. Thanks for taking my questions here. Just going back to Mexico, Sur de Texas and Villa de Reyes are still pegged at in service in 2019 in the filings. Given that we're in August here and it has already been noted here on the call negotiations are still ongoing, is this dependent on this going to London Arbitration or just trying to figure out the feasibility of 2019?

Francois Poirier -- Executive Vice President of Corporate Development and Strategy

Matthew, it's Francois. I'll answer that question. 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 a declaration. I talked earlier about the London Accord of Arbitration timelines. Those run into 2020. So, in terms of our ability to bring Sur de Texas into service in 2019, it would be under the presumption that we could 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 and then phases two and three in the fist quarter of next year. I would say, however, we're 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.

Russ Girling -- President and Chief Executive Officer

Hey, Matthew, on the same theme that I've talked about here this morning, when we're thinking about working our way through these issues of capital allocation, if that was based on fundamentals and where we see the fundamentals driving things, when you think about things like the Sur de Texas pipeline, we will diligently work through our issues with the CFE and the Mexican authorities. They're a 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 taken 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 US Gulf Coast. As Stan talked about this morning, producers in the US 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 billion cubic feet a day that could flow on that pipeline today and the benefits that can bring to the producing community in the lower 48 as well as Mexican customers, those numbers are substantial relative to their alternatives today. 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 those people can benefit from that opportunity.

Matthew Taylor -- Tudor, Pickering, Holt & Co. -- Analyst

Great. Helpful context. Tracy, recent regulatory applications are shedding some light on shippers potentially looking for NGTL connectivity. So, obviously, early days here, but I see some evolution here, perhaps, of NGTL redirecting some flows northwest. Any sort of thoughts on how you see that evolution and thoughts on size and types of projects would be helpful?

Tracy Robinson -- President of Canadian Natural Gas Pipelines

So, Matthew, I think you're speaking about the NGTL connecting into some of the West Coast pipes for LNG export. Is that right?

Matthew Taylor -- Tudor, Pickering, Holt & Co. -- Analyst

Yeah, exactly.

Tracy Robinson -- President of Canadian Natural Gas Pipelines

So, we've long-held -- as you know, we're building the Coastal GasLink, which is a contracted pipe. LNG Canada has contracted and their joint venture partners have contracted all the capacity of that pipe. We believe strongly that the NGTL system offers some real benefits to those joint venture partners.

When they're thinking about how to connect their supply into that pipeline and downstream into the LNG facility. So, we think that there's some potential there. We are in discussions with all of our joint venture partners on exactly what their plans are for gas supply and how they want to connect that to the system.

So, we think there's some potential there. As you would be aware, there's 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 NIT. It provides a lot of flexibility. 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 down the main line into some of those other markets.

Operator

The next question is from Michael Lapides from Goldman Sachs. Please go ahead.

Michael Lapides -- Goldman Sachs -- Analyst

Thanks for taking my questions. Is there a way to back in to the EBITDA of the assets sold? By the way, congrats on the asset sales. I'm just trying to think about the impact of credit metrics and broader EBITDA trajectory 2019-2022.

Don Marchand -- Executive Vice President and Chief Financial Officer

It's Don here. I'll reiterate my earlier answer. $6.3 billion of asset sales of proceeds, 500 area of EBITDA, multiple in the high-elevens.

Michael Lapides -- Goldman Sachs -- Analyst

Great. When you look out 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 what's the band around that? Meaning what's the level where you would want to start thinking again of if your capex ramped 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.

Don Marchand -- Executive Vice President and Chief Financial Officer

We look very long term. It's not something that we can and want to shift around on a quarter to quarter basis. It's fours 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 higher BBB+ category or the A- category depending on 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 years of visibility and 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 they're looking at. In many cases, they will allow you to breach those targets for some period of time to actual construct a project that is in strategy and consistent with your preferences and fits their profile. We do that from time to time.

We just come out of that with Coastal GasLink, where from an accounting perspective, Coastal GasLink will be equity accounted for and have agencies that will either be off-credit or proportionally supported. We have a lot of things going on in the background as we look at this stuff. It's never our intent to surprise the agencies, the debt markets or the equity markets on something like that. We're looking at this larger scale.

Michael Lapides -- Goldman Sachs -- Analyst

Thank you. Much appreciated.

Operator

The next question is from Jeremy Rosenfield with Industrial Alliance. Please go ahead.

Jeremy Rosenfield -- Industrial Alliance -- Analyst

I'll be brief. First, going back to Mexico, 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, Francois, could a sale of the assets potentially to CFE be a holistic solution to the issue there and is there anything within the contracts specifically that may prevent that?

Francois Poirier -- Executive Vice President of Corporate Development and Strategy

So, 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.

Jeremy Rosenfield -- Industrial Alliance -- Analyst

Perfect. Just another cleanup, with regard to the tax change or 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 -- I guess to a small degree Canadian main line, but NGTL specifically.

Don Marchand -- Executive Vice President and Chief Financial Officer

Yeah. It's Don here. On a run rate basis, the flow through impact is in the $70 million to $80 million range for the next couple years, two or three years here. So, I think it's probably about half of that that we booked in the second quarter of this year, about $30 million to $35 million. 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's using EBITDA as a valuation metric for our Canadian regulated pipes.

Operator

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

Joe Gemino -- Morningstar -- Analyst

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 ruling that you need with the upcoming presidential election.

Paul Miller -- President of Liquids Pipelines

Hi, Joe. It's Paul here. Going forward, Keystone XL remains very important for the producers and US 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. 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 outcoming on the timing of an FID construction start and are in service. We'll assess our position once we've mitigated all these various issues.

Joe Gemino -- Morningstar -- Analyst

Great. In a hypothetical situation in which you had maybe FID and you had the positive outcomes, would you consider moving forward before knowing the outcome of the next presidential election?

Paul Miller -- President of Liquids Pipelines

Again, Joe, I think what we need to do is we need to get the various matters behind us. We'll assess our position at that point. I do want to highlight the continentwide benefit of Keystone XL and how we have our US refiners signing up for capacity. They are anxious to get the pipe into service. It's an important pipe for energy security.

Operator

Thank you. Ladies and gentlemen, this concludes the question and answer session. If there are any further questions, please contact TC Energy investor relations. I will not turn the call over to Mr. Moneta.

David Moneta -- Vice President of Investor Relations

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.

Operator

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

Duration: 88 minutes

Call participants:

David Moneta -- Vice President of Investor Relations

Russ Girling -- President and Chief Executive Officer

Don Marchand -- Executive Vice President and Chief Financial Officer

Paul Miller -- President of Liquids Pipelines

Francois Poirier -- Executive Vice President of Corporate Development and Strategy

Stan Chapman -- President of U.S. Natural Gas Pipelines

Tracy Robinson -- President of Canadian Natural Gas Pipelines

Linda Ezergailis -- TD Securities -- Analyst

Robert Kwan -- RBC Capital Markets -- Analyst

Jeremy Tonet -- JP Morgan -- Analyst

Ben Pham -- BMO Capital Markets -- Managing Director

Rob Hope -- Scotiabank -- Analyst

Robert Catellier -- CIBC Capital Markets -- Analyst

Andrew Kuske -- Credit Suisse -- Analyst

Alex Kania -- Wolfe Research -- Analyst

Patrick Kenney -- National Bank -- Analyst

Matthew Taylor -- Tudor, Pickering, Holt & Co. -- Analyst

Michael Lapides -- Goldman Sachs -- Analyst

Joe Gemino -- Morningstar -- Analyst

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