TC Energy Corp

TSX:TRP

Earnings Call Transcript 2018-Q1

[Operator]

Good day, ladies and gentlemen. Welcome to the TransCanada Corporation 2018 First Quarter Results Conference Call.I'd like to turn the meeting over to Mr. David Moneta, Vice President, Investor Relations. Please go ahead, sir.

[David Moneta, Vice President of Investor Relations]

Thanks very much, and good afternoon, everyone. I'd like to welcome you to TransCanada's 2018 First Quarter Conference Call. With me today are Russ Girling, President and Chief Executive Officer; Don Marchand, Executive Vice President and Chief Financial Officer; Karl Johannson, President of Canada and Mexico Natural Gas Pipelines and Energy; Stan Chapman, President, U.S. Natural Gas Pipelines; Paul Miller, President of our Liquids Pipelines business; and Glenn Menuz, Vice President and Controller.Russ and Don will begin today with some opening comments on our financial results and certain other company developments. A copy of the slide presentation that will accompany their remarks is available on our website at transcanada.com, can be found in the Investors section under the heading, Events. Following their prepared remarks, we will take questions from the investment community. If you are a member of the media, please contact Grady Semmens following this call, and he'd be happy to address your questions. [Operator Instructions] Before Russ begins, I'd like to remind you that our remarks today will include forward-looking statements that are subject to important risks and uncertainties. For more information on these risks and uncertainties, please see the reports filed by TransCanada with Canadian securities regulators and with U.S. Securities and Exchange Commission.And finally, I'd also like to point out that 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.With that, I'll now turn the call over to Russ.

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

Thank you, David, and good afternoon, everyone, and thanks for joining us late here on a Friday afternoon. As I highlighted previously and, again, earlier today at our Annual Meeting of Shareholders, 2017 was a very successful year for our company. In addition to delivering record financial results, we made significant progress on several other fronts that will position us for continued success. We continue to build on those accomplishments here early in 2018. Evidence of that can be seen in our record first quarter financial results, which support our Board of Directors' decision in February to increase our quarterly common dividend to $0.69 per share. That equates to $2.76 per share on an annual basis and represents a 10.4% increase over the dividend in 2017.During the quarter, we also continued to advance our $21 billion near-term capital program by placing approximately $2.7 billion of assets into service. Those included the Leach XPress project, the Cameron XPress (sic) [ Access ] project and our Columbia -- and on our Columbia system as well as a number of NGTL expansion projects. At the same time, we replenished our growth portfolio by adding another $2.5 billion of NGTL expansions to our inventory of commercially secured projects, and we also advanced over $20 billion of medium- to long-term projects, including Keystone XL, Coastal GasLink and the Bruce Power life extension program.Finally, we continue to prudently fund our capital program and strengthen our balance sheet by raising about $650 million of common equity through a dividend reinvestment and aftermarket programs. As a result, our overall financial position remains solid, and we are well positioned to fund our capital program going forward.I'll touch on each of these developments in the next few slides, beginning with a brief review of our first quarter financial results. Excluding certain items, comparable earnings were $870 million or $0.98 per share, an increase of $172 million or $0.17 per share over the first quarter despite the sale of our Northeast Power solar assets. This equates to a 21% increase on a per share basis, recognizing the effect of the common shares issued in 2017 and 2018 under our DRP and ATM programs. Comparable EBITDA increased $94 million to approximately $2.1 billion, while comparable funds generated from operations of $1.6 billion were $111 million higher than the first quarter of 2017. Each of these amounts reflects a strong performance of our legacy assets in approximately $7 billion of growth projects that were completed and placed into service over the last 12 months. Don will provide more detail on our first quarter financial results in just a few minutes.Before he does, I'd like to offer a few comments on some recent developments in each of our businesses, beginning with Natural Gas Pipelines. First, in our Canadian Natural Gas Pipelines. Over the past 3 months, we continued to advance $7.4 billion of commercially secured projects largely on the NGTL system. More specifically, we completed the NGTL 2017 expansion program, which increased the capacity of the system by approximately 500 million cubic feet a day. And here, early in April, the Sundre Crossover project entered service, adding about 228 million cubic feet a day of capacity at our Alberta/B.C. border Export Delivery Point, enhancing connectivity to the downstream markets in the Pacific Northwest and California. We also filed an application with the National Energy Board for the approval of a negotiated settlement with our customers that covers 2018 and 2019. Past settlement, amongst other things, fixes the return on equity at 10.1% on 40% deemed common equity, which is consistent with our previous agreement. Looking forward, we will continue to work with the industry as -- on options to connect growing Western Canadian supply to markets across North America. That could include the potential restoration of dormant capacity on the Canadian mainline. At the same time, we continue to actively work with LNG Canada on our Coastal GasLink project, which will provide another significant market outlet for Canadian gas.In the United States, we placed the Leach XPress and Cameron Access projects into service at a combined cost of approximately $1.9 billion. We also advanced $6.1 billion of additional projects, including Columbia's Mountaineer, WB and Gulf XPress projects. All 3 are expected to enter service by the end of 2018 at a combined investment of approximately $4.5 billion. While the total cost on these projects have increased by approximately 10% due to delays in receiving various regulatory approvals as well as increased construction costs because of unusually high demand for resources in that region and modifications to contractor work plans to maintain in-service dates, however, we continue to expect these projects to generate very attractive returns for our shareholders. Looking forward, we also expect our Columbia system to continue to generate organic growth opportunities as natural gas production in the Marcellus continues to grow. We're also looking at other opportunities across our broader U.S. Natural Gas Pipeline portfolio, including on ANR, GTN, Great Lakes, Northern Border, Iroquois and the Portland Natural Gas Transmission System. Turning to Mexico for just a moment. We're advancing construction on 3 pipelines that will bring our total investment in Mexico to about $5 billion. The Sur de Texas and Villa de Reyes lines are both expected to enter service in late 2018, while the Tula project is anticipated to be in service in 2019.Before moving to our Liquids business, I want to make a few comments on the FERC actions and their implications for TransCanada and to our MLP, TC PipeLines, LP. As you all know, on March 15, the FERC, among other things, issued a revised policy statement addressing the treatment of income taxes for ratemaking purposes for MLPs and a Notice of Proposed Rulemaking or a NOPR. On April 16, we filed a Request for Clarification and If Necessary Rehearing of the FERC Policy Statement addressing concerns over the lack of clarity around entities with non-MLP ownership structures, entities with shared ownership between MLP and a corporation as well as entities owned by the MLP that are, in turn, only partially owned by corporations.We don't anticipate that the earnings and cash flow from our directly held U.S. Natural Gas Pipelines, including ANR, Columbia Gas and Columbia Gulf, will be material impact -- materially impacted by -- if the FERC actions are enacted as proposed, as they are -- all those pipelines are held through wholly-owned taxable corporations and a significant portion of the revenues are earned on a nonrecourse rates.In contrast, U.S. Natural Gas Pipelines owned wholly or in part through TC PipeLines, LP are expected to be adversely impacted by the FERC actions if they are enacted as proposed, particularly by the policy change prohibiting the recovery of income tax allowance for pipelines held through MLPs. While approximately half of TC PipeLines' revenues are earned under nonrecourse rates, in the absence of some form of mitigation, the remaining revenues under recourse rates are expected to decline as rate adjustments occur. Individual pipelines owned by TC PipeLines do not currently have a requirement to file for new rates until 2022. However, that timing may be accelerated by the NOPR, except where moratoriums exist.As our ownership interest in TC PipeLines is approximately 25%, the impact of the FERC actions related to our MLP is not expected to be significant to our consolidated earnings or cash flow.And finally, on that front, further drop-downs of assets by TransCanada into TC PipeLines is not considered a viable funding option at this time. But as uncertain whether its competitiveness as a funding option will be restored in the future, we believe that we have financial capacity to be -- to fund our existing capital program through our predicable and growing cash flow from operations as well as several other funding alternatives. And Don will expand on those options here in just a few moments.Turning now to our Liquids business, which produced, again, strong results here early in 2018. Keystone continued to perform well and is now underpinned by long-haul take-or-pay contracts for 550,000 barrels a day. In addition, Grand Rapids and Northern Courier were both placed into service in the second half of 2017 and are now contributing EBITDA. Finally, a few comments on Keystone XL. During the first quarter, we advanced the project following the Nebraska Public Service Commission's approval of a viable route to the State of Nebraska here late in 2017. In January, we successfully secured approximately 500,000 barrels per day of firm 20-year contracts, which is consistent with the original level of contracting on Keystone XL prior to the denial of the Presidential Permit in November of 2015. Those new contracts, combined with existing contracts on the Keystone System that were put in place at the time we built the U.S. Gulf Coast section, that convert to long-haul agreements on Keystone XL means it will be nearly fully utilized by our contracted shippers after factoring in capacity that we are required by regulators to set aside for spot shippers. As a result, we expect to earn a return on total capital that is consistent with returns we earn on similar projects in our portfolio.Looking forward, we are working collaboratively with landowners to obtain the necessary easements for the approved route. At the same time, we continue to monitor and participate in the various appeals and legal proceedings brought against the regulatory bodies -- against regulatory bodies and government agencies overseeing the project, with a view of getting clarity on these matters by late 2018 or early 2019. Finally, our preparation for construction has commenced and will increase as per the permitting process advances through 2018. This can be undertaken at a relatively low cost as much of our long lead time items were previous -- were purchased previously.Turning now to our Energy business. Following the monetization of our U.S. Northeast Power business and the Ontario solar assets in 2017, the remaining 6,100 megawatts of generation in our portfolio are largely underpinned by long-term contracts with very strong counterparties. Construction of the Napanee plant continues and is expected to be placed in service in late 2018. Work also continues on the asset management program at Bruce, with major investments to extend the operating life of the facility to 2064, scheduled to begin in 2020 and continue through 2033. The $6.2 million -- $6.2 billion investment in -- [ that 2014 dollars are ] share. We'll see us spend approximately $900 million between now and the end of the decade. The remainder will be invested between 2020 and 2033.So in summary, we continue to advance our $21 billion near-term commercially secured projects largely on time and on budget. It includes approximately $19 billion of Natural Gas Pipeline expansions that are driven by growth in North America, natural gas supply in the Marcellus and Utica as well as the Western Sedimentary Basin, along with demand growth in places like Mexico. We're also developing an intra-Alberta pipeline system in Alberta that includes the recently completed Grand Rapids project and the Northern Courier projects as well as the White Spruce that we expect to be in service in 2019.And finally, we're advancing approximately $2 billion of power projects, including the 900-megawatt Napanee gas power plant in Ontario as well as the initial work required at Bruce Power as part of the multibillion dollar life extension program. These projects are all underpinned by long-term contracts or rate-regulated business models. As a result, we have a high degree of visibility to the earnings and cash flow growth that will be generated as they enter service.As you can see on this chart, comparable EBITDA grew from $5.9 billion in 2015 to $6.6 billion in 2016, to $7.4 billion in 2017. That growth is expected to continue with EBITDA of approximately $9.5 billion expected in 2020 as we largely complete our near-term capital program. That equates to a compound average annual growth rate of approximately 10% over the 5-year horizon. Also of note, 95% of our cash flow will be derived from regulated or long-term contracted assets. In addition, we're advancing over $20 billion of medium- to longer-term projects currently in the advanced stages of development. Any one of those projects could further enhance our growth profile as well as our strong competitive position. Based on our confidence in our growth plans, we expect to continue to grow the dividend at an annual average rate at the upper end of 8% to 10% through 2020 and another 8% to 10% into 2021. As we've said many times, this is supported by expected growth in earnings and cash flow and strong distributable cash flow coverage ratios.In summary, I'd leave you with the following key messages. Today, we are leading North American energy infrastructure company with a strong track record of delivering long-term shareholder value. As we advance our $21 billion portfolio of commercially secured near-term projects, we expect to deliver significant additional growth in earnings and cash flow. As a result, we expect to grow our common share dividend at the upper end of 8% to 10% on an annual basis through 2020 and foresee an additional growth of 8% to 10% through 2021. We're also progressing more than $20 billion of projects that are in the advanced stages of development, and we expect numerous other growth opportunities to emanate organically from our existing asset footprint. Success in advancing these initiatives could extend our dividend growth outlook. At the same time, we expect to maintain our strong financial position by prudently funding our capital programs.That concludes my prepared remarks, and I'll turn the call over to Don, who'll provide more details on our first quarter financial results.

[Donald R. Marchand, Executive VP & CFO]

Thanks, Russ, and good afternoon, everyone. As outlined in our quarterly results issued earlier today, we are pleased to report that net income attributable to common shares increased by $91 million to $734 million or $0.83 per common share in the first quarter of 2018 compared to $643 million or $0.74 per share for the same period in 2017. First quarter 2017 results included a $24 million after-tax charge for integration-related costs associated with the acquisition of Columbia; a $10 million after-tax charge for costs related to the monetization of our U.S. Northeast Power generation business; and a $7 million after-tax charge related to the maintenance of Keystone XL assets, which, along with other related expenditures and interests, are now being capitalized as we advance the project. These charges were partially offset by a $7 million income tax recovery related to the realized loss in the third-party sale of Keystone XL project assets. The specific items as well as unrealized gains and losses from changes in risk management activities are excluded from comparable earnings. Comparable earnings in the first quarter rose by $172 million to $870 million or $0.98 per share compared to $698 million or $0.81 per share in 2017, a 21% increase on a per share basis. Per share amounts reflect the effect of common shares issued in 2017 and 2018 under our dividend reinvestment plan and aftermarket program.Notwithstanding the sale of our U.S. Northeast Power assets, our positive results reflect solid cash generation and strength across all our businesses, particularly Liquids Pipelines, and included benefits of lower corporate tax rates under U.S. Tax Reform.Turning to our business segment results on Slide 16. In the first quarter, comparable EBITDA from our 5 operating businesses was approximately $2.1 billion, $94 million higher year-over-year. As outlined in the quarterly report, Canadian Natural Gas Pipelines' comparable EBITDA of $494 million was $10 million higher than for the same period last year. Net income for the NGTL system increased $10 million compared to first quarter 2017 because of a higher average investment base and reflects the last approved ROE of 10.1% on 40% deemed equity. Conversely, due partially to lower -- to a lower average investment base, net income for the Canadian Mainline decreased $15 million.For the quarter, no incentive earnings have been recorded for either NGTL or the Mainline, pending NEB decisions on the NGTL 2018 and 2019 Revenue Requirement Settlement Application and the 2018 to 2020 Mainline Tolls Review. I would note that for Canadian Natural Gas Pipelines, changes in depreciation, financial charges and income taxes impact comparable EBITDA but do not have a significant 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 $804 million in the quarter increased by CAD 84 million or USD 92 million compared to the same period in 2017, mainly due to increased earnings from Columbia Gas and Columbia Gulf growth projects placed in service, additional contracts sales on ANR and Great Lakes, favorable commodity prices for Midstream and increased earnings from the amortization of the regulatory liability recognized at December 31, 2017, following U.S. Tax Reform.Mexico Natural Gas Pipelines' comparable EBITDA of 160 million increased CAD 20 million or USD 21 million compared to first quarter 2017, driven primarily by higher revenues from operations and higher equity earnings from our investment in Sur de Texas pipeline, which records AFUDC during construction, net of interest expense on an inter-affiliate loan from TransCanada. This inter-affiliate loan expense is fully offset in interest income and other in the Corporate segment.Liquids Pipelines' comparable EBITDA rose by $119 million to $431 million, driven by the addition of Grand Rapids and Northern Courier, which began operations in the second half of 2017; higher volumes on the Keystone Pipeline System; and a higher contribution from liquids marketing activities.Energy comparable EBITDA decreased by $121 million year-over-year to $184 million due to lower contributions from U.S. Power and Eastern Power, following the sale of generation assets in 2017. The continued wind down of our U.S. power marketing operations increased outage days at Bruce Power and narrower Natural Gas Storage price spreads realized by Natural Gas Storage. These reduced results were partially offset by higher realized prices on increase generation volumes from -- for Western Power and income recognized from the sale of our retail contracts in U.S. Power.For all our businesses with U.S. dollar-denominated income, including U.S. Natural Gas Pipelines, Mexico Natural Gas Pipelines and parts of our Liquids Pipelines and Energy businesses, Canadian dollar-translated EBITDA was negatively impacted versus the first quarter of 2017 by a weaker U.S. dollar. This was largely offset by lower translated interest expense on U.S. dollar-denominated debt and realize hedging gains reported in comparable interest income and other.Regarding our exposure to foreign exchange rates. Our U.S. dollar-denominated assets are predominantly hedged with U.S. dollar-denominated debt and the associated interest expense. We continue to actively manage the residual exposure on a rolling 1-year forward basis.Now turning to the other income statement items on Slide 17. Depreciation and amortization of $535 million increased $25 million versus first quarter 2017, largely because of new facilities entering service along our businesses, partially offset by the sale of power assets in 2017 and a weaker U.S. dollar. Interest expense of $527 million was $27 million higher year-over-year, following new debt issuances, net of maturities and lower capitalized interest on Liquids Pipelines projects placed in service in 2017, partially offset by the repayment of Columbia acquisition bridge facilities and the impact of a weaker U.S. dollar on translating U.S. dollar-denominated interest.AFUDC increased by $4 million for the 3 months ended March 31, 2018, compared to the same period in 2017. A decline in Canadian dollar-denominated AFUDC was principally due to the October 2017 decision not to proceed with the Energy East pipeline project, while an increase in U.S. dollar-denominated AFUDC was largely driven by additional investment in and higher rates on Columbia Gas and Columbia Gulf growth project as well as continued investment in Mexico projects.Interest income and other included in comparable earnings rose $58 million in the first quarter versus 2017, primarily due to interest income on a new inter-affiliate loan receivable from Sur de Texas plus realized hedging gains in 2018 on foreign exchange management compared to realized losses in 2017. As previously noted, the interest income on the inter-affiliate loan is offset by interest expense included in Sur de Texas equity income.Income tax expense was $173 million in first quarter 2018 compared to $244 million for the same period last year, primarily because of reduced income tax rates under U.S. Tax Reform and lower flow-through income taxes on Canadian rate-regulated pipelines. This translated into an all-in 12% effective tax rate for the 3-month period ending March 31, 2018, compared to 21% for the same period in 2017. Excluding Canadian rate-regulated pipelines where income taxes are a flow-through item and, thus, quite variable, along with equity AFUDC income in the U.S. and Mexico Natural Gas Pipelines, we continue to expect our 2018 full year effective tax rate to be approximately 17% to 18%.Net income attributable to noncontrolling interests increased by $4 million for the 3 months ended March 31, 2018, mostly due to higher earnings, partially offset by our acquisition of the remaining outstanding publicly held common units of CPPL in February 2017.And finally, preferred share dividends were comparable to first quarter 2017.Now moving to cash flow, a distributable cash flow on Slide 18. Comparable funds generated from operations of approximately $1.6 billion in the first quarter reflect an increase of $111 million year-over-year, driven largely by higher comparable earnings as outlined, which includes the impact of power generation asset sales in second and fourth quarter 2017. As introduced at Investor Day in November, we now provide 2 measures of comparable distributable cash flow. One includes all maintenance capital regardless of whether it's recoverable or not. The other reflects only nonrecoverable maintenance capital by excluding amounts that are ultimately reflected in totals on our Canadian and U.S. rate-regulated pipelines and on our Liquids Pipelines.Maintenance capital expenditures recoverable in future tolls of $224 million in first quarter 2018 were $87 million higher than in the same period of 2017. This represented 78% of total maintenance capital in the period. It includes $119 million related to our Canadian regulated natural gas pipelines, which was $71 million higher than first quarter 2017 and is immediately reflected in the NGTL and Mainline rate basis, positively impacting net income.Maintenance capital of $103 million in our U.S. Natural Gas Pipelines was CAD 17 million or USD 16 million higher year-over-year. Almost all of our U.S. Natural Gas Pipelines recover maintenance capital through tolls under current rate settlements. Liquids Pipelines' maintenance capital was consistent with 2017 at $3 million, while other maintenance capital of $63 million in the first quarter was $14 million higher than for the same period last year. As a result, distributable cash flow in the quarter reflecting all maintenance capital was approximately $1.2 billion or $1.38 per share, providing a coverage ratio of 2x. Distributable cash flow reflecting only nonrecoverable maintenance capital was just over $1.4 billion or $1.64 per share, resulting in a coverage ratio of 2.4x. We expect to maintain strong coverage ratios through 2020 as outlined at November's Investor Day.Now turning to Slide 19. During the first quarter, we invested approximately $2.1 billion in our capital program and successfully funded it primarily through our strong and growing internally generated cash flow, notes payable and common equity from our dividend reinvestment plan and at-the-market program. Our dividend reinvestment program or DRP continues to provide incremental subordinated capital in support of our growth in credit metrics. In the first quarter, the participation rate amongst common shareholders was approximately 38%, representing $234 million of dividend reinvestment. In June of last year, we established an at-the-market or ATM program that allows us to issue up to $1 billion in common shares from time to time over a 25-month period at our discretion at the prevailing market price when sold in Canada or the United States. The use of ATM funding will be influenced by our spend profile as well as the availability and relative cost of other funding sources. In the first quarter, 5.8 million common shares were issued under the program at an average price of $56.51 per share for gross proceeds of $329 million. An additional 1.6 million shares were issued in early April, bringing the year-to-date gross proceeds to $415 million. Accounting for shares issued under DRP and the ATM program, our earnings per share outlook for 2018 has increased compared to what was included in the 2017 annual report, primarily driven by higher volumes on the Keystone Pipeline System and contributions from Liquids marketing activities in first quarter 2018.Now turning to Slide 20. This slide highlights updates to our funding program through 2020 since our November Investor Day. Our capital requirements will continue to be financed through our predicable and increasing internally generated cash flow and a combination of other funding options, including senior debt, preferred shares, hybrid securities, asset sales and common shares issued under our DRP and ATM program, in a manner that is consistent with achieving targeted credit metrics, a 15% FFO to debt and 5x debt-to-EBITDA.Based on recent conversations with S&P, they appear to be holding to their 18% FFO to debt target introduced at the time of the Columbia acquisition in March 2016. In addition, they are now indicating a 4x debt-to-EBITDA target for the A- rating level. As such, we anticipate a rating move by them from A- negative outlook to BBB+ stable is entirely possible in the near term. While disappointed, we do not view this as material, and it does not change our funding plans going forward.I remind everyone that we are working to complete $21 billion of projects and simultaneously delevering, so some element of equity and equity equivalent capital remains necessary. We reiterate that we do not foresee a need for discrete equity to complete our near-term capital program.For 2018, our capital expenditures are now forecast to be approximately $10 billion, up from $9.2 billion previously indicated. The increase is primarily related to incremental spending this year to bring into service approximately $11 billion of projects as well as capitalize costs to further advance our medium- to longer-term projects. Over the next 3 years, our dividend and noncontrolling interest distributions of approximately $10 billion, along with capital expenditures of approximately $20 billion, result in net total requirements of about $30 billion. Approximately 65% or $20 billion will be financed by internally generated cash flow. In addition, in 2018, we expect to raise approximately $1.6 billion through our DRP and the remaining capacity under our current ATM program.As Russ mentioned, due to recent actions by the FERC, drop-downs in the TC PipeLines, LP appear no longer viable. We're previously a periodic financing lever. We have not been overly dependent on drop-downs, and this recent development is expected to have limited impact on our financial flexibility. That leaves approximately $8.5 billion to be funded in the 2018 to 2020 time frame through a combination of capital markets activity and portfolio management that achieves target credit metrics. Our plan includes $4 billion of incremental senior debt, $1 billion of hybrid securities or preferred shares and $3.5 billion from a blend of asset sales, the potential extension of the DRP beyond 2018, a new ATM program and any realized project recoveries.In summary, while our external funding needs are sizable, they remain eminently achievable in the context of multiple financing levers available and the clear accretive and credit support of use of proceeds.In closing, I offer the following comments. Our positive financial and operational results in the first quarter continue to highlight our diversified low-risk business strategy and reflect the strong performance of our legacy assets, along with continuing additions of high-quality assets from our ongoing capital program. Today, we are advancing a $21 billion suite of near-term projects and have 5 distinct platforms for future growth in the Canadian, U.S. and Mexico Natural Gas Pipelines, Liquids Pipelines and Energy. Our overall financial position remains strong. We remain well positioned to fund our near-term capital program through resilient and growing internally generated cash flow and strong access to capital markets on compelling terms. Our portfolio of critical energy infrastructure projects is poised to generate significant growth and high-quality long life earnings and cash flow for our shareholders. That is expected to support annual dividend growth at the upper end of an 8% to 10% range through 2020 and an additional 8% to 10% in 2021. Success in adding to our growth portfolio in the coming years could augment or extend the company's dividend growth outlook further.That's the end of my prepared remarks, and I'll turn the call back over to David for the Q&A.

[David Moneta, Vice President of Investor Relations]

Okay, great. Thanks, Don. [Operator Instructions] And with that, I'll turn it back to the conference coordinator.

[Operator]

[Operator Instructions] Our first question is from Linda Ezergailis from TD Securities.

[Linda Ezergailis, Research Analyst]

I'm just wondering if you could maybe help clarify a little bit on your financing plans. How might we think of what type of assets or partial interest you might choose to sell, whether there be any sort of tax considerations or other rationale?

[Donald R. Marchand, Executive VP & CFO]

Sure, Linda. It's Don here. Yes, I'll just start out we -- I'd note that the amount of assets readily available that we consider for sale far exceeds the inventory of assets that was available for LP drop-downs, and they're significantly larger than the purple other box at the far right-hand side of our funding slide. That said, similar to what we do with the solar package last year, don't look for us to preannounce processes or dollar targets. But we'd rather quietly conduct this in the background. We just -- we continuously mark-to-market the portfolio and evaluate the whole versus sale values, and we do take cash tax incidents into consideration on that. So without identifying specific assets, that's kind of the broad perspective of what we're looking at and the magnitude that's available.

[Linda Ezergailis, Research Analyst]

Okay. And just on a slightly separate note. One of the desires by the investment communities, they seem to be a simplified corporate structure. You guys are largely there. I'm just wondering, do you need to see this U.S. MLP FERC tax situation addressed before you would consider consolidating TCP? Or how do you think about the timing and rationale for considering that?

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

Yes, I think that's correct, Linda, is it -- obviously, there is likely to be impacts on the cash flow that underlie the TC PipeLines' business. There's a fair amount of water that goes -- has to go under the bridge firstly on determining if the rules get implemented and what those rules look like, what the mitigations may or may not be at the MLP level and then seeing what that looks like at the end of the day. That's going to take some time. So it will be some time before we actually even analyze any potential strategic transactions or anything like that. At the current time, we're just focused on helping them work their way through that process with the FERC and the other issues that they're dealing with.

[Operator]

The following question is from Robert Kwan from RBC Capital Markets.

[Robert Michael Kwan, Analyst]

Just coming back to funding and looking at the box. It looks like there's -- asset sales are certainly a big part of that. I'm just wondering, do you have -- is there a sense that it's going to be a mix of those options? Or do you see something playing a bigger role such as asset sales?

[Donald R. Marchand, Executive VP & CFO]

Yes. It's Don here again. It would be a mix of the various items in there. I would say versus where we were at Investor Day, asset sales are probably a bigger proportion of that. We've lost the LP drop-down vehicle as an alternative here, and we've shrunk the hybrid box a little bit here. There's a 15% cap at S&P on the hybrids that goes more to sequencing. We can time that more as the balance sheet grows. So I would watch for more asset sales. We'll probably refile another ATM of similar size here. To the extent to which we use that will be determined by how we progress on these other items here. So it's an all-of-the-above strategy. What's meant to be highlighted here is there's no fundamental change in any of these boxes since November. We have plenty of levers available. And I'd also remind everyone that when we're looking at hybrids and drop-downs and the like, you're kind of looking at $0.50 equity credit dollars, whereas when you're issuing ATM and DRP, those are $1.00 equity dollars there. So a long winded way of saying it's an all-of-the-above strategy, Robert.

[Robert Michael Kwan, Analyst]

Got it. And actually, Don, you just mentioned on the hybrid slice getting smaller. The S&P constraint, does that matter as much then if you're going to drop down the BBB+? Or is it also the cost of the hybrids and the amount of equity credit you get?

[Donald R. Marchand, Executive VP & CFO]

Yes. It's not the cost of the hybrids. They're still -- that market's still robust, and they are very compelling. And we haven't heard definitively from S&P. It's just this is a very strong indication that we're getting there. But we'll look at it. But I think from S&P's perspective, probably best direct to them, too, as well, is this is probably being viewed more as a hard 15% limit than a soft one that you can go above and then grow your balance sheet back into. So it's a very viable, attractive product for it, probably goes more to sequencing at this point than anything. But we're -- that market's still there.

[Robert Michael Kwan, Analyst]

Okay. If I can finish on Mexico. You've got negotiations with CFE. I'm just wondering, do you have some timing as to when that may be solidified? You are getting paid. Are you getting the paid the full amount? And just where is that showing up on the statements? Is that in AFUDC? And is it actually showing up in the cash flow line as well?

[Karl R. Johannson, Executive Vice President]

Yes, Rob. This is Karl. Yes, we are finalizing our agreements on the force majeure with the CFE. But in the meantime, contract requires them to pay us, when in fact the force majeure and the delay is due to government inaction or some government problem. So yes, we are getting paid for both. Right now, we are getting paid. Our full contract dollars for both of those are [indiscernible], and they are showing up in our revenue stream, but not under cash flow. They are showing up -- I guess, we are housing the dollars under our asset accounts. Or maybe Glenn can explain where they are a little better.

[G. Glenn Menuz, VP & Controller]

Yes, Robert. This is Glenn here. As we're receiving the force majeure payment, at this point, on those 2 pipelines, we're not recording revenue right now. So those amounts are -- cash receipts are showing up on the balance sheet. Think of it as a deferred revenue, but they are showing up in our operating cash flow.

[Robert Michael Kwan, Analyst]

Okay. And the timing for CFE finalization?

[Karl R. Johannson, Executive Vice President]

Oh, for finalization of agreements? We don't have a set timeframe right now, but we're working on that as we speak and they are paying the bill. So I suspect over the next few months here, we will -- we'll come to finalize the force majeure agreements.

[Operator]

And this question is from Jeremy Tonet from JPMorgan.

[Jeremy Bryan Tonet, Senior Analyst]

Just want to turn to Mountaineer and WB XPress a bit. And since like the cost moved up a little bit there, I was just wondering if you could expand a little bit as far as the degree that could be recoverable, or what were some of the drivers there? Any additional color you could provide would be helpful.

[Stanley Graham Chapman, Executive Vice President]

Jeremy, this is Stan. We have seen some cost increases associated with our projects, primarily associated with regulatory delays, in large part due to the lack of [indiscernible] from last summer. And that has led to some higher costs associated with us having to modify our work plans and work schedules to make sure that we're maintaining our in-service dates to a large degree. We've also seen some increased exposure with respect to rock and some additional mitigation measures on our steep slopes and put back a little bit of contingency that we spent early on in the project. The Mountaineer XPress project does not have any cost-sharing left, but the WB XPress project does. At this point in time, we've executed all of our construction contracts. Construction has commenced on all 8 of the spreads, and we're largely focused on just getting these projects in service as quickly as possible and doing so without further cost overruns. With respect to impacts on returns and the like, I guess I would ask you to look at it this way. Any one project can have a cost under collection or over collection. But when you look at the entire portfolio of roughly $7 billion of largely the legacy Columbia projects, we've previously given you guidance that we would bill those somewhere at around a 5 to 7x EBITDA multiple. Even with these current cost overruns, we're still going to come in at the high end of that range, somewhere around 7 or may be just a few ticks above 7 with respect to an EBITDA multiple. And you can think of that as translating into an after-tax return in the lower double-digit range, which we think is still pretty strong.

[Jeremy Bryan Tonet, Senior Analyst]

That's very helpful. Turning to liquids. It seems like the marketing had a good quarter there. I was just wondering if you could expand a bit on the driver and kind of how sustainable, and where Keystone is right now from an operating perspective and how you see that kind of progressing as it returns to normal operations.

[Paul E. Miller, Executive Vice President]

Jeremy, it's Paul here. To your first question on the marketing. The marketing business contributed about $0.03 this quarter, and its performance largely depends on movements in the marketplace, particularly when we see high differentials. And if you look back to last August where we saw the Brent WTI spread widen out, we started to see increased contribution from the marketing business. And that lasted until probably, let's call it January into February, which gave us time to lock down some January, February business and into March. Since then, we've seen that differential narrow a bit. It's picked up a little bit again here in April. But if you wanted to sort of get an appreciation for predictability, if you wish, of the marketing business, a lot of it does revolve around some of these market spreads we see, primarily Brent, WTI, and probably to a lesser extent, the Louisiana light sweet and the WTI. As far as maybe broadly speaking, when you look in the entire liquids business, about 85% of our EBITDA is contracted under the long-term take or pay contracts. And it's really the spot component on Keystone and market length as well as the marketing entity, which is going to provide some variability around that, and it really does revolve around where those spreads are at. So going forward on the marketing business, we have seen a softening of those differentials. I would anticipate it probably would contribute about a $0.01 less here in the second quarter. And as far as Keystone is concerned, we still have a 20% D rate applied on that section of our pipeline which was affected by the leak we had late last year. And I want to emphasize that, that D rate is limited just to that affected section. So it really has not resulted in much of an impact to our throughput, and certainly does not have a material impact on our operating results. So going forward, we continue to work with the regulators to work -- lifting of that D rate, and I would love to see that D rate lifted in the next few months.

[Operator]

Next question is from Tom Abrams from Morgan Stanley.

[Thomas Edward Abrams, Executive Director]

Yes. First quick question on just Bruce power. And I see you're going to have the cost approvals in the fall. Is that a definitive, yes, we're doing that, kind of situation? Or just arguing about costs? Or is it really, technically, still need to be approved?

[Karl R. Johannson, Executive Vice President]

All right, Tom. It's Karl. Yes. So the way the agreement is written is that we are to finish our engineering and all of our pricing on Unit 6 as the particular one we're putting in on October 1. And then we are to provide a fixed price to the Ontario IESO. If that fixed price is below a certain threshold that we have in our contracts, then it is an automatic decision to move forward with the refurbishment. So if it is greater than the maximum in that contract, then we can still move forward, but the IESO would have to take it back and opine on it and give us a decision. So there is a broad understanding of how to refurbish this, and I don't think there will be much of a technical discussion that we haven't already had a discussion with the IESO. And so it would be mostly around price. And I would say that when we put that price from, which we are actually progressing very well on, I fully expect us to put the Unit 6 projects from October 1. We will receive the benefits of that -- of the capital that we are planning on investing in starting April of next year. And the capital does not start going out until the unit comes down, which is in 2020. So we get about a year of kind of a delay between when the payments for the capital starts to come in and the capital starts being spent and the unit gets taken down in 2020.

[Thomas Edward Abrams, Executive Director]

Great. And my other question is on the Coastal GasLink. With Fleur being chosen as one of the contractors, it looks like that thing's really rolling towards a positive FID, and you kind of alluded to that in your presentation as well. What could trip that up? And I particularly want to know about what's going on from a governmental permitting-type issue. And then as a follow-on to that, assuming it does go through, when do your dollars get spent?

[Karl R. Johannson, Executive Vice President]

So let me just start with what could trip it up. I really do not -- I'm not comfortable talking about kind of LNG Canadas or Shells and their partners, kind of the parts of their project that may be tripped up or not. So it's very difficult for me to sit here and talk about those contingencies. We are the pipeline supplier to Coastal. I agree with your assessment. And then we've said this before, the -- it is looking very, very positive for this project. It looks like LNG Canada has received some of the concessions they are looking forward from the BC government, and it looks like they've got their contractors in place now. And certainly, as the -- from the pipeline supplier, we are in the process right now of keeping up with them, and we will be putting the rest of our arrangements together and waiting for a fall FID, or an FID before the end of year that they have promised us. So I would just -- I guess, I'd just leave that by saying that I really can't opine on what other issues that LNG Canada is working on.

[Thomas Edward Abrams, Executive Director]

Okay. And then assuming it goes through, when would you be spending money on it?

[Karl R. Johannson, Executive Vice President]

Well, the capital -- so it's probably about a 4-year build cycle. There won't be much capital going out this year. We'll start next year. But the bulk of the capital will be '20, '21 and '22.

[Donald R. Marchand, Executive VP & CFO]

It's Don here, Tom. From a funding perspective on Coastal, I'd just like to add that as Karl mentioned, it's spread out over like a 4-year build cycle. We will look at joint venture partners and we will look at project financing for this specific project, which could shrink the TransCanada cash contribution quite substantially. So this is something that we've been looking at in the background for quite some time, and that is on the table as something that we might consider here.

[Operator]

The next question is from Ben Pham from BMO.

[Benjamin Pham, Analyst]

On the S&P, as you -- just the potential action change there. I was wondering if you can provide us your thoughts on the recent Moody's rating change? And if your funding program solidifies what they're looking for? And maybe your overall thoughts on the A rating and your previously long-term commitment to the A rating?

[Donald R. Marchand, Executive VP & CFO]

Yes. We were surprised by Moody's actions. It didn't have much warning in it. As they noted in their report in mid-March, they actually retroactively changed their methodology on their treatment of AFUDC and EBITDA from assets that were sold. They had outlined they wanted to see us between a 5 and 5.5x debt to EBITDA in 2017. Using their unrevised methodology, we came in at 5.3x. So I thought we're in compliance with what they were looking for. But with the retroactive changes, they moved that to 5.7x. So with that, they said we were offside, so short of having a DeLorean to go back in time to change our financing strategy, we drive forward here. That said, our finance plan does have us onside their 5x target as we exit 2018 here. So that was the state there. In terms of how we go -- how we look at this going forward. We'd like to remain on A-rated entity, but we're looking for a reasonable balance here between equity and debt interests. We will not chase moving goal posts at any cost. So what we will strive for going forward is to achieve credit metrics of a maximum 5x debt-to-EBITDA and a minimum 15% FFO to debt as our target ratios. And again, we should be onside with those as we exit 2018 as we bring $11 billion of projects into service this year. When we look collectively at 4 rating agencies, each with their distinct methodologies, expectations, factor weightings and the like, we think this is the appropriate place to be based on our business position, our simple corporate structure and considering our access to and cost of capital. So we're not going to chase moving goal posts, but we will target 5x 15%.

[Operator]

The next question is from Robert Catellier from CIBC.

[Robert Catellier]

You've answered most of my questions. I just wondered if you could provide some context around the $9.5 billion EBITDA target in 2020 in light of the perhaps higher level of asset sales you might be contemplating. So I presume the $9.5 billion in 2020 included your funding plan. But as it changed to more asset sales perhaps, is there a sensitivity you can provide us around that, sort of an upper-lower bound?

[Donald R. Marchand, Executive VP & CFO]

Yes, it's Don here. Without having specifically identified assets and when that might be executed, I would say the $9.5 billion figure won't change materially, and that includes contemplative financing and as well as the impacts of FERC actions and tax reform. So the $9.5 billion figure is, in our view, still a good figure. If it moves off that we're talking about a rounding error at this point.

[Robert Catellier]

Okay. That's helpful. And then just on TCP, given it's not material to your results necessarily, but obviously, they have some things to work through there. Is there any sort of thinking about equity injections into that vehicle to help them through this period of uncertainty.

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

Robert, no, that's not our plan. It's time [indiscernible] really has to work through its issues, both from a cash flow perspective, distribution perspective, debt covenant perspective. And no cash injections are contemplated from the parent.

[Operator]

The next question is from Rob Hope from Scotiabank.

[Robert Hope, Analyst]

Looking at the mainline in the NGTL system, no incentive earnings were recorded during Q1. Given the timeline on the toll review for the mainline, is it safe to assume that we won't really see any incentive earnings booked in 2018 and a catch up thereafter? And I guess, secondly, kind of give a ballpark gauge of how much you would've been able to generate in incentive earnings in Q1.

[Karl R. Johannson, Executive Vice President]

Yes, Rob, it's Karl. So I on the NGTL for example, we had the settlement in front of the NEB rate now. The question or the period where people can make comments on it has closed, and we're just waiting for the NEB's decision on the settlement. If the NEB accepts a settlement, which I don't see why they wouldn't, that will be before the end of the year. So you'll see the incentives on NGTL coming through our income statement at that time. On the mainline, yes, you have a good point. It looks like the actual hearing won't take place late this fall, which means there's a potential for a decision not to come before the end of the year. I think our policy is, right now, that we generally do not book that until we have a defined decision. We will relook at that policy in the fall. If the hearing doesn't -- it looks like it's very supportive of the assessor program, stuff like that, we might try and put something in on accrual basis before the end of the year. But our general policy is not to do it until the end of fall. Just to give you an idea on the mainline. For every 1% ROE, it's about $15 million. So we have been averaging the last couple of years 11.5% ROE. Right now, we're booking it at 9.2%. I think the -- so I think that to expect 11.5% ROE with incentives at this year and next year is a little aggressive given we had to rebase our -- we had to rebase kind of our revenue stream. So and I would certainly expect that we'd make some incentives just when we get to 11.5%. It's probably unlikely at least the first year of the new term.

[Robert Hope, Analyst]

All right. That is helpful. And then just a clarifying question on Mountaineer cost increase. There was a commentary that you've gone through the cap for that 50-50 cost sharing. Was that for all the incremental costs that was announced today? Or did you blow through it part of the way through?

[Karl R. Johannson, Executive Vice President]

No. It was for all the incremental costs.

[Operator]

The following question is from on Andrew Kuske from Crédit Suisse.

[Andrew M. Kuske]

I think the question is for Paul, and it really relates to Keystone and the fact you've been pressure restricted now for, I guess, about 5 months. To what degree, when you go back to normal pressure, do you think you can push more volume through the line just with using DRA and just other initiatives?

[Paul E. Miller, Executive Vice President]

Yes, Andrew, it's Paul. We're always looking to optimize our system, and our team did a great job when this gate rate was applied to a portion of our system. Once it's lifted, I think we'll take a look at how we can further enhance our system. But I wouldn't look to see us move significant additional volumes through. It really did have a minor impact on our throughput, and so consequently, I don't anticipate us seeing a tremendous increase in our throughput once it's lifted based on some of the changes we've made already.

[Andrew M. Kuske]

Okay, appreciate that. And then just shifting gears. A question really for Karl. Just on Mexico. How do you think about just the demand growth within the country? And then comparing that to the pipelines, really seeking to push more gas into Mexico. And just a balancing act. Because obviously, it's a little bit of a chicken and egg problem that exists.

[Karl R. Johannson, Executive Vice President]

Yes. Most of the new pipelines are really designed to take incremental -- or to convert power plants from -- running on fuel oil and our new power plants that they're building. So it's designed to fuel that right now. I do -- when I take a look at Mexico, I can't help but be optimistic about the gas position there. A lot of the industry, because gas has been so unreliable in the past, really don't use gas. So companies like TransCanada, for example, and some of our competitors, we're now setting up marketing to get the incremental sales to convert industrials off of fuel oil and propane, for example, onto natural gas. I think there's going to be a couple of phases that we're going to see in Mexico going forward. Number one is everybody's taking a pause now and finishing the construction of not only the pipelines, but the power plants that are anchoring those pipelines. I think after the pause you're going to see a big marketing effort as we move into the industrials in the country and start converting them to natural gas. And I still think there's some more CFE and electrical-based pipeline construction to be done in the country. The CFE isn't finished the grid that they want to build, but they are taking a pause right now. A lot of their pipelines are running late because of various indigenous issues or archaeological issues or whatnot, so it's taking a pause. But I don't think that pause means it's the end. I think there'll be more additions to the screen coming later.

[Operator]

The next question is from Ted Durbin from Goldman Sachs.

[Theodore J. Durbin, Vice President]

Just back to the FERC issue, and I realize you say it's not material. But I wonder if there's any way you can quantify the downside to your earnings as you flow through the lower income tax allowance on the 501-G form if you sort of think about pipelines where you might be over earning on your cost of service rates? Any way to put the number on what that might be? Is it, I don't know, $100 million or $500 million? Just kind of any way to give us a sense of what that might look like based on that filing that's required?

[Stanley Graham Chapman, Executive Vice President]

Yes. So Ted, this is Stan. A couple things. One, I would not put a whole lot of fate in the 501-G schedule in and of themselves, and that they're just a starting point based upon historical data. Two, the impact is, like we see for 2019, much less than any number you've just thrown out. Keep in mind that with respect to our wholly-owned pipeline, Columbia has already largely complied with this obligation to reduce its rates for the tax change under its modernization settlement. ANR has a rate moratorium in effect through August of '19. We don't expect there to be any material differences, and its results gets compared to prior periods. Northern Border and Great Lakes just came out of rate reviews that the commission approved back in January. So any true-up associated with just the tax component there is going to be relatively small. Most of the balance of our pipes are owned wholly or in part by the LP, and we only own 25% of the LP. And then again, just to remind you that anything that's going to happen here is going to happen prospectively and likely no earlier than some time in 2019. And at that point in time, roughly 63% of our revenues are covered by even negotiated rates or discounted rate contracts. So again the impact is going to be relatively small.

[Theodore J. Durbin, Vice President]

That's great. That's helpful. And then just coming back again to Keystone XL. As you think about you're getting closer, it sounds like, to a final route, any update you can provide us on the capital cost there. You've been carrying this $8 billion number for a long time. I realize you have a lot of long lead times items already, but steal costs have kind of been moving around on you. Just kind of get a sense on how that's shaping up for you.

[Paul E. Miller, Executive Vice President]

Ted, it's Paul here. And you're right. We do have a lot of the long lead items, the material, the pipe, pumps, the motors. Part of our construction planning here during 2018 while we move through the various legal and regulatory proceedings is to position ourselves to -- for construction in 2019. And part of that is doing some value engineering, other engineering and other construction planning. Where we sit today, the $8 billion number is still a good number, but we'll continue to look at that as we move through the engineering here through the balance of 2018.

[Operator]

The next question is from Dennis Coleman from Bank of America Merrill Lynch.

[Dennis Paul Coleman]

Just another quick one on KXL if you would. You talked about the supreme -- Nebraska Supreme Court taking up the case and sort of that seems like good news in terms of getting to the final arbiter as you say. And given the timeframe that you put out, I wonder, are there any points along the way or other scheduling points that you might share with us that we can watch for in terms of hearings or other, like I said, key dates?

[Paul E. Miller, Executive Vice President]

Sure, Dennis. This is Paul here. The Supreme Court has taken up the Nebraska approval challenge. If I recall correctly, the various are oral arguments and submissions are due here in May. And then the Supreme Court will recess over the summer, and I would anticipate that they come back probably after Labor Day to hear oral arguments. And at that point, the decision will be theirs. But we anticipate that they would reach a decision here before the end of the year.

[Operator]

The next question is from Nick Raza from Citi.

[Naqi Syed Raza, Senior Associate of Oil and Gas]

Most of my questions have been answered. But just following back on TCP. Previously, you had mentioned that there have been offsets, including higher spending in terms of just integrity management for some of the systems like GTN that have had significantly higher utilization over the past, say, 2 or 3 years. Are -- could you just talk about some of the options available as offsets, or if they aren't available anymore, such as integrity spending on some of the pipelines owned by TCP?

[G. Glenn Menuz, VP & Controller]

Sorry, Nick. Maybe if you could -- maybe just rephrase the question. Are you wondering sort of from a cash flow perspective then? Or like are you looking at operating cash flow?

[Naqi Syed Raza, Senior Associate of Oil and Gas]

Sure, absolutely. In terms of just rate reductions, there's a thought that you could spend a little bit more on the systems and keep the rates where they are or increase rate base that would be an offset. Are there anything -- or is there anything that we should be looking at for TCP particularly or Great Lakes Northern Border in terms of an offset?

[Stanley Graham Chapman, Executive Vice President]

Yes, I would say that each pipeline is kind of unique in and of its own way. There may be some instances where the lower tax allowance could be offset by other elements at our overall cost of service. In other cases, you may have situations where the pipeline is earning a very attractive return. We'll just going to have to reduce rates going forward. So it's going to be a bit of a mixed bag going forward.

[Karl R. Johannson, Executive Vice President]

Yes, it's Karl. I'll just maybe say a couple of comments. The LP board meeting and conference calls coming up early next week. There'll probably be a little bit more detailed in what the strategic alternatives are and what their options are. But I would say when we go under rate cases, when you go discuss your rate adjustments, you're not only taking the fact of the tax rate, you're taking the fact any other class that you maybe haven't been collecting on. And you also will get into the discussion on what corporate form is the entity going to be in the future. So there's obviously the option to turn the LP into C corp. So I think that you're best to wait until the conference call of the LP, and then they can talk a little bit more directly as to what options that they are assessing that are unfavorable right now.

[Naqi Syed Raza, Senior Associate of Oil and Gas]

Okay. And then I guess, my second question is really regarding the open season on market link. If you could provide us any update or color on that, that would be great.

[Paul E. Miller, Executive Vice President]

Sure, Nick. It's Paul here. Are you alluding to the one we just launched here, I guess, last week?

[Naqi Syed Raza, Senior Associate of Oil and Gas]

Yes.

[Paul E. Miller, Executive Vice President]

Yes, so we're offering kind of a short-term service between one to three months. We do think that there's additional desire for contracted capacity on market link. We've offered up 1 to 3 months' terms. It's a bit of a bid process where we've established the floor and the ceilings are effectively a recourse rate. So I think it runs for about a month. And it's a bit of an ever-greening type program, so we launched it, we announced it here. Depending on the take-up, we can lock down those contracts. If it's not at a rate that we're satisfied, we don't have to accept any of those contracts. And it's the type of ever greening type open season that when we see differentials move up and we want to lock down some of this revenue, we can go back into the market fairly quickly.

[Operator]

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

[Matthew Taylor, Associate of Midstream Research]

Just over to North Montney. Can you give me a sense of timing on that? Is April 2019 still achievable? Or just where do we stand on that?

[Karl R. Johannson, Executive Vice President]

Oh, for the decision? Yes, we're expecting any time in the next couple of weeks. So it's -- we haven't heard that it's going to be materially delayed or anything. So yes, we're -- it's, hopefully -- I don't [indiscernible] in April now provided. But I'm kind of expecting it in the next couple of weeks, maybe the middle of May.

[Matthew Taylor, Associate of Midstream Research]

And then construction, still April 2019? Are you still targeting that?

[Karl R. Johannson, Executive Vice President]

Yes. I would have to take a look at it and just see if there's anything materially happening to our schedule. But that's kind of where we are right now, give or take. We don't need -- we do have parts of it we can work on in the summer. It's not up in the -- it's not fully in the [indiscernible] so we can't work on the summer. We're kind of sitting there. But subject to sitting back, once we get the permit and doing a full evaluation of the timing.

[Matthew Taylor, Associate of Midstream Research]

Okay, that's great. And then just one more if I may. It looks like recontracting has been pretty strong in mainline through 2018 sticking around 3 Bs a day. How do you see that playing out the rest of the year? And in order to expand the system, will you need to backstop a majority of that capacity with contracts before expanding?

[Karl R. Johannson, Executive Vice President]

Yes. So yes, I agree with you. The contracting has been very robust. We're very pleased. Just on the entire system, just when I talk about the firm contracts on there, right now, I have about 3.5 Bcf a day of long haul, and I have almost 9 -- let's say, 8.7 Bcf a day, of total contracts on the mainline, including the Eastern Triangle and all the short hauls. So we've got a very, very robust billing determinants in that line right now. Specifically, on the long haul, my expectation, given the surplus of gas coming out of NGTL and the need for egress out of NGTL, my expectation is we're going to be able to sell more products going through the mainline. The mainline is, I think, the cheapest incremental capacity coming out of the WCSB right now. So we're going to continue putting packages together that will allow -- that will bring more volumes off the engine tail and off the mainline. To give you an example, right now, we've had 2 open seasons over the last half dozen months. We've got about 1.3 billion cubic feet a day of new delivery capacity to Empress coming out of NGTL which I intend on putting some products through the mainline on right now to take that away. And then I can either get some more capacity, get some more capacity on the mainline. Bringing more capacity on, our maximum right now is just below 4 Bcf a day. To bring more capacity on, which we think is about 1 billion Bs to 1.5 billion of extra capacity, it's not all that expensive, and it's not all that time-consuming. It's basically maintenance. So as we get new contracts, I think we can bring it up in a reasonable cost and a reasonable timetable if people are willing to -- if people need it and they want to cite some contracts for it.

[Matthew Taylor, Associate of Midstream Research]

Paul, just to clarify, would those Empress -- the extra 1.3, did that backstop the existing capacity? Or could you use that capacity then to expand the system?

[Karl R. Johannson, Executive Vice President]

Well, yes on both things. Really, I wouldn't call it an expansion. The capacity is already there. We just had to put some maintenance into it to get it active again. So a little bit of that capacity will be used actually to take care of the existing 1.3. But the existing 1.3, there's probably enough capacity on the system if you assume kind of normal non-renewals of capacity, there's probably enough capacity to manage most of it. Although some of it may come out of like that kind of the latent capacity that's there. So the rest, again, I'd just be cautious, it's probably not an expansion. I think it's just -- we're just doing the maintenance and getting more capacity out of it. So we'll use a little bit for the 1.3 that we have there, and then we'll go find some new products to develop and bring some extra gas over and above the 1.3 to utilize the rest.

[Operator]

The next question is from Linda Ezergailis from TD Securities.

[Linda Ezergailis, Research Analyst]

Just a follow-up question on your financing possibilities in the future. Very helpful to get a reminder of how you're thinking of potentially financing Coastal GasLink. I'm wondering if Keystone XL goes to positive FID, how might you think of the incremental financing required for that, realizing that, that spend probably ramps up as some of your Columbia projects have already been completed.

[Donald R. Marchand, Executive VP & CFO]

Yes, Linda, it's Don. It does dovetail nicely into $11 billion-plus of assets being completed this year. Much of that $20 billion build program behind us and seeing the cash flow from that, especially factoring in that much of the long lead time items are in-house already. So it's a 2019-2020 concentration right now. We are looking at it and at this point in time in the event that we do hit the go button at the end of this year or early '19, whenever we get to that final decision point. And it will be all of the above. Everything from -- everything you see in the boxes right now. It does bring balance sheet growth, which brings hybrid capacity. We would -- again, we've identified quite a few assets we would consider selling as we compare it to other cost of capital. We could look at it extending the ATM and the DRP programs and the like. So we will put a package of financing together, and we'll engage all 4 of our rating agencies in advance as we did with Columbia under the rating advisory or rating assessment services to get a sense as to how it's viewed and what the impact would that be. So again, another all of the above strategy here. And we are looking at it, but still early days at this point as we refine the cost estimates as well.

[Operator]

The next question is from Jeremy Tonet from JPMorgan.

[Jeremy Bryan Tonet, Senior Analyst]

Just a quick follow-up. Just wanted to explore a thought. Maybe I'm off in left field here. But as far as kind of funding for TRP, if I look at TCP, there's no resolution with the FERC. Would it make -- or no positive resolution. Would it make sense for TRP to take out TCP in an equity-type of deal with TRP shares for TCP units? TRP gets negative offering. Or would it make sense just for TCP to kind of go its own way and internally delever itself, or any thoughts on those topics?

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

I think as I said earlier, TCP has got a lot of issues it's got to source itself out first. And I think your first comment was in the absence of clarity at the FERC. I think the first thing that we need is clarity at the FERC. What is the impact of these policies? What are the mitigation actions that are -- that can be taken place at that level? What is the remaining cash flows? What are the other sort of pluses and minuses before any thoughts or discussions can take place on the other storage strategic alternatives. So I would say that's well down the future for us. It's something that we don't have on our radar screen at this point in time.

[Operator]

There are no further questions registered. I'll turn the meeting back over to Mr. Moneta.

[David Moneta, Vice President of Investor Relations]

Thanks very much, and thanks to all of you for participating this afternoon, late on a Friday afternoon. We very much appreciate your interest in the company, 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, and we thank you for your participation.