TC Energy Corp

TSX:TRP

Earnings Call Transcript 2019-Q2

[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 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 Jaimie Harding following this call, and she would 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 re-enter the queue. Also, we ask that you focus your questions on our industry, our corporate strategy, recent developments and key elements of our financial performance. If you have detailed questions relating to some of our smaller operations or your detailed financial models, Duane and I'd be pleased to discuss them with you following the call.Before Russ begins, I'd like to remind you that our remarks today will include forward-looking statements that are subject to important risks and uncertainties. For more information on these risks and uncertainties, please see the reports filed by TC Energy with Canadian securities regulators and with the U.S. Securities 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. 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.

[Russell K. Girling, President, CEO & Director]

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 second quarter, $100 billion portfolio of high quality, long-life energy infrastructure assets continued 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 placed 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, 2019, which is a 16% increase over the same period in 2018. Similarly, comparable funds generated from operations of approximately $1.7 billion were 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 continue to advance over $20 billion 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 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 Courier 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 the sale of the Coolidge generating station which closed in May, are expected to result in combined proceeds of approximately $6.3 billion. Each of these transactions will allow us to surface 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 and 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 second 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 million or $1 per share in the second quarter, an increase of $156 million or $0.14 per share over the same period in 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 $333 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 our financial kind of performance, the Board of Directors declared third 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 third quarter 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 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 positive 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 B.C. Oil and Gas Commission. At the same time, we continue to advance funding plans for the project through the combination of the sale of up to 75% ownership and project financing. Both of those transactions are expected to be completed by the fourth quarter or by the end of the fourth quarter of 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 second quarter, we continued to advance our $1.1 billion Modernization II program on the Columbia Gas system as well as another USD 1.1 billion of other capacity additions that now include Louisiana XPress project and Grand Chenier XPress project. Combined, those 2 projects will connect nearly 2 billion cubic feet a day of gas supply to Gulf Coast LNG export markets. Louisiana XPress is a [ USD 400 million ] project. It is expected to enter service in 2022, while Grand Chenier is a [ USD 200 million ] project that is expected to enter service in 2 phases over the 2021 and 2022 periods.Finally, in U.S. 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 3 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 a capacity to move up to 2.6 billion 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 acknowledgment 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 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, Villa de Reyes and Tula contracts. We are analyzing the content of the arbitration requests and we're preparing our responses. In our view, the contracts are properly established in accordance with all original bid and regulatory requirements and remain valid. That said, we remain open to discussions and to 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 555,000 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 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 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 Keystone XL. As you know, in late March, the 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 fourth quarter of 2018 and we are awaiting a final decision. We continue to believe the approval of the alternative 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 $1.8 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 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 multibillion-dollar 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 off and on capital identical to what we realize on our extension 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 the $2.6 billion of the NGTL system expansions as well as the Sur de Texas natural gas pipeline in Mexico and the Napanee gas-fired power plants 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 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 remain 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 5 significant platforms for growth: Canadian, U.S. and Mexico Natural Gas Pipelines, Liquids Pipelines and our Power and Storage business. Just as we have done since 2000, as we advance 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 footprint. 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?

[Donald R. Marchand, Executive VP & CFO]

Thanks, Russ, and good morning, everyone. As outlined in our quarterly results issued earlier today, net income attributable to common shares was $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 per share in second quarter 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 giving effect to 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 strengths 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 second quarter, comparable EBITDA was approximately $2.3 billion, representing a $333 million or a 17% increase from 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 in 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 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 Mainline 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 as they are almost entirely recovered in revenues on a flow-through basis.U.S. Natural Gas Pipelines comparable EBITDA of USD 641 million or CAD 857 million in the quarter increased by USD 95 million 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 USD 107 million or CAD 141 million 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 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 second quarter 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 million increased $51 million versus second quarter 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 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 U.S. dollar denominated interest.AFUDC decreased by $14 million for the 3 months ended June 30, 2019, compared to the same period in 2018. The 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 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 U.S. dollar denominated income.Income tax expense included in comparable earnings was $199 million in the second quarter 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 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 are thus quite variable, along with equity AFUDC income in 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 noncontrolling interests decreased by $19 million 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 second quarter 2018.Now moving to cash flow and distributable cash flow on 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 Mainline and the NGTL system. Distributable cash flow, reflecting only 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 2.2x.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 of proceeds in 2019.In May, we closed the sale of our Coolidge generating station for USD 448 million or approximately CAD 585 million. In July, we completed a partial monetization of the Northern Courier Pipeline for aggregate proceeds of approximately $1.15 billion. Also in July, we entered into agreements to sell certain Columbia U.S. Midstream assets for approximately USD 1.3 billion or CAD 1.7 billion 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 DRIP, continues to provide incremental subordinated capital in support of our growth in credit metrics. In the second quarter, the participation rate amongst common shareholders was approximately 34%, representing $238 million of dividend reinvestment. Year-to-date, the participation rate has been approximately 33%, resulting in $464 million of common equity at a 2% discount.DRIP 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 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 billion, comprised of dividend and non-controlling interest distributions of approximately $10 billion and capital expenditures of approximately $19 billion, including maintenance capital. As a reminder, we are pursuing joint venture partners for the $6.2 billion 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 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 the remaining funding requirement of approximately $1 billion 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% of our capital structure. Finally, I reiterate that the DRIP remains a quarter-to-quarter decision.In summary, our external funding needs are imminently 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 $7.2 billion Canadian equivalent, $1.6 billion of which has already been retired to date in 2019 and we are well-positioned for the next $1.25 billion U.S. maturities scheduled for mid-November. Normal course debt maturities are excluded from our funding outlook on the prior slide.In closing, I'll 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 5 distinct platforms for future growth in Canadian, U.S. and Mexico Natural Gas Pipelines, Liquids Pipelines and 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 programs 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. [Operator Instructions]

[Operator]

[Operator Instructions] And the first question is from Linda Ezergailis with TD Securities.

[Linda Ezergailis, Research Analyst]

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 marketing side?

[Paul E. Miller]

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 market link system, on the southern end we have been running effectively full. Maintaining at 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 sale 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 linked 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 that. On the marketing side, we'll be flat in Q3 relative to Q2. That's on 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.

[Linda Ezergailis, Research Analyst]

That's very helpful context. 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 may go in terms of the bookends in which this might be resolved? And there were some comments in your write-up that you've 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?

[Francois Lionel Poirier, Executive VP]

Linda, it's Francois Poirier speaking. I'll be happy to answer your question. Again, for context, in June CFE filed request for arbitration under Sur de Texas, 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 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 third quarter or the fourth quarter of next year. That's assuming no unexpected delays. And 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 and we have commenced discussions on these matters. So those processes are happening in parallel.

[Operator]

The next question is from Robert Kwan with RBC Capital Markets.

[Robert Michael Kwan, Analyst]

Maybe I'll just start by following up you 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? So what's going on from that perspective?

[Francois Lionel Poirier, Executive VP]

So we are entitled to receive -- Robert, it's Francois Poirier 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 onto Villa de Reyes at 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 has, 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 Michael Kwan, Analyst]

That's great. If I can finish just then with kind of funding/asset sales. I guess the first part is part of the description on funding is 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 out right, partial interests 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 decisions. Now what types of projects, given most or your stuff are small to medium size, what do you need to see [ and surface ] to get that comfort? And 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 you in place before you think about turning off the DRIP?

[Donald R. Marchand, Executive VP & CFO]

Yes. I'll start with our additional portfolio management. 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 million area that we had indicated previously has effectively all been announced, but never categorically closed the door on additional asset sales. Everything we look at is on a per share basis, so if 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 assets we would continue to look at that. But the program that we had outlined earlier broadly, the $500 million, 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 onside. We do expect as we -- the cadence of asset sale closings if we get them done as described, we should be fully onside 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 Sur de 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've certainly made tremendous progress here. And again, it is something we'll look at our October Board meeting.

[Operator]

The next question is from Jeremy Tonet with JPMorgan.

[Jeremy Bryan Tonet, Senior Analyst]

Just wanted to start with the East Lateral XPress here. If you could expand a bit on how this project came together, say, and kind of do you see other I guess demand pool projects that could come to fruition, given what you're doing in your Columbia footprint there?

[Stanley Graham Chapman]

Jeremy, this is Stan. You can think of the East Lateral XPress 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 Y and this project is on the east leg 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 million tonnes. 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 are 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 aggregate, we're going to supply somewhere around 30% of the LNG volumes come 2022. When you think of it in the context, almost 4 Bcf of projects under flight. And by 2022 industry should be exporting LNG to the tune of about 10 to 12 Bcf, maybe even 15 Bcf. So I think there is more success to come for us with respect to serving LNG load going forward, and the East Lateral XPress is just the latest addition to our project backlog list.

[Jeremy Bryan Tonet, Senior Analyst]

That's helpful context. And just wanted 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 this something you look to expand or to shrink over time? I know that there is Bruce -- there is a lot of expansion potential there. But just wondering philosophically has anything changed?

[Francois Lionel Poirier, Executive VP]

Hi. It's Francois here. I'll answer that question. And 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. And 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 a future unit. So strategy hasn't changed. There is a desire to continue to allocate incremental capital in this business unit for attractive projects that fit our risk preferences.

[Russell K. Girling, President, CEO & Director]

Jeremy, I'd just add on to that. It's Russ. The sale of these assets in no way 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, I mean, there is just a whole host of things that are going to occur. It's 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 emission-less. As Francois pointed out, there is a long capital program and growth potential there. I think about your -- our remaining assets in Alberta, in a conversion from coal to gas to renewables and other things. Again, we're well-positioned to take advantage of those transitions. And as we 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.

[Operator]

The next question is from Ben Pham with BMO.

[Benjamin Pham, Analyst]

My question, maybe a related one on the natural gas expansion. So Louisiana XPress, Grand Chenier. How should we think about that in terms of your 7% to 9% unlevered returns [ fashioned ] -- where it falls on that range?

[Donald R. Marchand, Executive VP & CFO]

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

[Benjamin Pham, Analyst]

Okay. And then on an earlier question, the Keystone [ 50K ] expansion. Is that just simply some DRA optimization you guys are looking at? Are you -- it's utilization increasing? Are you guys actually looking at the nameplate moving around? And if so, is there a regulatory process you need to go through for that?

[Paul E. Miller]

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.

[Benjamin Pham, Analyst]

Okay. And -- I know it's my second question, but the regulatory approval, that's a standard normal course? Like nothing notable in there?

[Paul E. Miller]

That's correct. It will require an amendment to our Presidential permit, and Presidential permits -- amendments are not uncommon, and there has always been a process to do this. It's normal course for us to look at ways to optimize our system, and this is just one of those ways.

[Operator]

The following question is from Rob Hope with Scotiabank.

[Robert Hope, Analyst]

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 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?

[Stanley Graham Chapman]

Yes. I would say that our systems are in as much demand as they have ever seen. Right now, when you look at the Columbia Gulf system, for example, post in-service of our Gulf XPress and Rayne 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, NXP and LXP is flowing at somewhere around a 65% load factor as 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 is 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. In some cases, we even proactively reached out to them because their capacity may have value to others. And being the optimist, again, I think that there is a brighter future ahead, and we're going to grow our way demand out of this with respect -- grow our way with respect through incremental demand. Already 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&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 help us 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 XPress projects into service over the first quarter 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 AECO footprint and again LNG growth is going to be a big part of that going forward as well.

[Russell K. Girling, President, CEO & Director]

Hey, Rob, I'd just add to that. As we think back, 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 is a need for more capacity. That capacity, pipeline transportation capacity, that transportation capacity has been difficult to build. So we're short in transportation capacity, wide differentials which is putting pressure on both the oil and gas producers in both countries. 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 the export market, 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 improve their capital situation. So I think the bottom line, the demand for our system has never been greater as I've said, and the value of our transportation to our customers has never been greater. And so 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 -- or 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 it be gas or oil, no matter where we are, we're looking for those kind of opportunities to debottleneck our system and offer that service to our shippers.

[Robert Hope, Analyst]

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?

[Paul E. Miller]

Hi 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 the regulatory with some minor work around preparation. But we're going to keep spending in check until we have a clearer path to perhaps move forward on this project, but not until then.

[Operator]

The next question is from Robert Catellier with CIBC.

[Robert Catellier]

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 in the market that gives you confidence the commercial support will be there in the medium term?

[Stanley Graham Chapman]

Yes. So this is Stan again. With respect to our projects that have not yet FID-ed 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 Venture Global who is part of our Grand Chenier and East Lat XPress projects, signing up incremental load. The [ Plaquemines Parish ] facility that I told you is 20 million 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 reliance on the fact that we need more energy sources of all kinds to meet worldwide demand going forward.

[Robert Catellier]

So you just see the low in the supply and demand and nothing fundamentally changed? Just the balance between the supply and demand, just subject to vagaries of timing?

[Stanley Graham Chapman]

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.

[Robert Catellier]

And my next question is on Bill C-69 and how the pass just there impacts how you approach growth specifically on NGTL but also in other Canadian areas?

[Tracy A. Robinson]

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 C-69, although the bill is in place, we are 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 on the Canadian regulated side.

[Russell K. Girling, President, CEO & Director]

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 doesn't -- 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 and exactly how it's going to work. But I think, as we've 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.

[Andrew M. Kuske]

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 opportunistic 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?

[Donald R. Marchand, Executive VP & CFO]

I'll start. It's Don here. We're certainly aware of different valuation metrics for different asset holders. So that's something 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 to sell assets. The math was really compelling for us to actually carry this out. So yes, so as we look at what we set out to do, we brought in $6.3 billion for something in the $500 million area of EBITDA and without getting into the granularity of it, 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.

[Russell K. Girling, President, CEO & Director]

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 -- 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 Columbia, all high quality assets in our portfolio. I mean as Don said, as we look forward in terms of 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 market places that we feel comfortable in our funding program. So these were, I would call them planned. We said that we probably had about $500 million of EBITDA to divest. It wasn't 100% core, but they are very good assets. But also, we wouldn't sell the assets unless we could 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 these assets as well. It'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.

[Andrew M. Kuske]

I appreciate that. And then maybe just as a follow-up, given the interest in the assets and a lot of the private equity managers in a race 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?

[Francois Lionel Poirier, Executive VP]

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 whole value. And when the external value exceeds our whole value, we pursue transactions. I think it's fair to say that there is 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.

[Operator]

The next question is from Alex Kania with Wolfe Research.

[Alexis Stephen Kania, Utilities Senior Vice President]

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 new incremental capital that you might be seeing down the road. I mean I'm thinking about most obviously about Keystone XL, but I'm just thinking about that as you look forward as well.

[Donald R. Marchand, Executive VP & CFO]

Yes. It's Don here. Our 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, are very close to it through 2021 for our current suite of assets. From a position of strength, we will look at new projects, and Keystone XL will be the biggest one. That's fairly binary go, no-go at some point here, and so we will 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 his 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 time lines, 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, in some cases, 2022. So that's kind of the way we see the world right now. We're kind of resetting ourselves here from a credit perspective and then certainly 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.

[Alexis Stephen Kania, Utilities Senior Vice President]

And just to follow up on Mexico, on the Tula project, just on the updated time schedule for that. Is that -- do you have a sense from the government just in terms of the consultation timing? Or is that just kind of conservative to give enough time? Or do you maybe need a more global settlement with respect to it? Just kind of curious what the CFE situation as well.

[Francois Lionel Poirier, Executive VP]

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. I will 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.

[Operator]

The next question is from Patrick Kenny with National Bank.

[Patrick Kenny, Managing Director]

I think it's been touched on already, but it appears gas producers in Canada have become much more responsive to daily swings in AECO 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.

[Tracy A. Robinson]

Patrick, it's Tracy. Yes. Listen, 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 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 Bcf out of the basin, and we've recently launched an open season with Stan's team on the next tranche capacity that we could provide down through the west path down into [ Moulin ]. So we're working very hard to get that egress in place. As to the other side of constraining supply in order to balance of system, there has been a lot of dialog 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 particularly to 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 is any number of ideas at play.

[Russell K. Girling, President, CEO & Director]

That, Patrick, I guess, I would just mention -- it's Russ again, is don't mix up, as in your question, a potential slowdown in our expansion plans related to potential for whatever curtailment or other ideas that folks might have for dealing with a short-term situation. The long term is, as Tracy said, the marketplace needs more capacity. And if anything, I would expect that, that would accelerate. So to -- further to my 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. 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 [ new ] 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 Don pointed out, as we look to programs in 2021, 2022, 2023, expect to see more capital required to expand the system.

[Patrick Kenny, Managing Director]

And maybe just one last question to you, guys.

[Russell K. Girling, President, CEO & Director]

Yes, go ahead.

[Patrick Kenny, Managing Director]

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. You think so?

[Donald R. Marchand, Executive VP & CFO]

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-69 have also influenced our assessment of projects. But frankly, it's always been there. And what it points to is there is 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.

[Russell K. Girling, President, CEO & Director]

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 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 for us there. I mean you think about safety and reliability and making sure the 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 your 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 the United States, but on an export basis, they export it to other markets who rely upon those as well. We think about that broader spectrum -- and 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 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.

[Patrick Kenny, Managing Director]

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.

[Operator]

The next question is from Matthew Taylor with Tudor, Pickering, Holt & Co.

[Matthew Taylor, Analyst of Midstream Research]

Just coming 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 as already been noted here on the call, negotiations are still ongoing. So is that dependent on this going to London arbitration? I'm just trying to figure out the feasibility of 2019.

[Francois Lionel Poirier, Executive VP]

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 2020. So in terms of our ability to bring Sur de 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 and then phases 2 and 3 in the first quarter of next year. I would say, however, that -- 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.

[Paul E. Miller]

Matthew, I mean, on the same theme that I've talked about here this morning, when we are 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 the CFE and the Mexican authorities. They are our customer. But when you think about it from a macro perspective, the demand for that gas exists today. There is 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 if you think about 2 billion cubic feet a day that can flow on that pipeline today and the benefits 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 a resolution to this situation as quickly as possible so all of those people can benefit from that opportunity.

[Matthew Taylor, Analyst of Midstream Research]

That'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 feed West Coast LNG. So obviously early days here. But I see some evolution here perhaps with NGTL moving some -- are redirecting some flows northwest. Any sort of thoughts on how you see that evolution and any thoughts on again size and types of projects would be helpful.

[Tracy A. Robinson]

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, Analyst of Midstream Research]

Yes, exactly.

[Tracy A. Robinson]

Yes. So, 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 -- and their joint venture partners have contracted all of the capacity of the 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 is some potential there. We are in discussions with all of our joint venture partners on exactly where they planned -- what their plans are for gas supply and how they want to connect that to the system. So we think there is some potential there. There is, as you would be aware, lots of dialog 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 is 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. There's a trading hub at [ NIT ]. 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 or Moulin or east into -- down the Mainline into some of those other markets.

[Operator]

The next question is from Michael Lapides from Goldman Sachs.

[Michael Jay Lapides, Vice President]

Guys, real quick one. Is there a way to back into the EBITDA, 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.

[Donald R. Marchand, Executive VP & CFO]

Yes. It's Don here. I'll reiterate my earlier answer. $6.3 billion of asset sales of proceeds [ $500 million ] area of EBITDA multiple in the high 11s. And we…

[Michael Jay Lapides, Vice President]

Got it. Sorry. Didn't mean to cut you off there.

[Donald R. Marchand, Executive VP & CFO]

No. No, that's it.

[Michael Jay Lapides, Vice President]

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 ramped up significantly above future asset sales and what's the level where you would look at it and say, hey, we're actually a little bit under-levered here? I'm just trying to think about the ranges around kind of leveraged targets.

[Donald R. Marchand, Executive VP & CFO]

We look very long term. So it's not something that we can and 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+ category or the A- category depending which agency is looking at that. Given the visibility of our projects, the time lines to get them regulatorily approved and the like, we have a couple of years of visibility 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 the 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 bridge those targets for some period of time to actually construct a project that is in strategy consistent with your best practices and 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 while proportionately supported. So we have a lot of things going on in the background as we look at this stuff and we never tend to surprise the agencies, the debt markets or the equity markets on something that we're looking at this larger scale.

[Operator]

The next question is from Jeremy Rosenfield with Industrial Alliance.

[Jeremy Rosenfield, Equity Research Analyst]

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, Francois, 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?

[Francois Lionel Poirier, Executive VP]

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, Equity Research Analyst]

And then 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 Mainline, but NGTL specifically.

[Donald R. Marchand, Executive VP & CFO]

Yes. It's Don here. On a run rate basis, the flow-through impact is at a $70 million to $80 million 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 we booked in the second quarter of this year, about $30 million, $35 million. I would just reiterate that this does reduce the 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 our Canadian regulated pipes.

[Operator]

The next question is from Joe Gemino with Morningstar.

[Joseph J. Gemino, Equity Analyst]

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 kind of in light with the potential -- or with the upcoming Presidential election?

[Paul E. Miller]

Hi, Joe. It's Paul here. Going forward, 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 and/or in-service. We'll assess our position once we've mitigated all these various issues.

[Joseph J. Gemino, Equity Analyst]

And would -- in a hypothetical situation in which you had maybe FID, you had the positive outcomes from the courts, would you consider moving forward before knowing the outcome of the next Presidential election?

[Paul E. Miller]

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.

[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 now 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.