12 participants, thank you for standing by. The conference is ready to begin. Good day, ladies and gentlemen. Welcome to the TransCanada Corporation 2017 second quarter results conference call. I'll now turn the meeting over to Mr. David Moneta, Vice President, Investor Relations. Please go ahead, Mr. Moneta.
Thanks very much. Good morning, everyone. I'd like to welcome you to TransCanada's 2017 second 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, Executive Vice President and President, Canada and Mexico Natural Gas Pipelines and Energy, Paul Miller, Executive Vice President and President of Liquids Pipelines, and Glenn Menuz, Vice President and Controller. Stan Chapman, Executive Vice President and President of U.S. Natural Gas Pipelines, couldn't join us today, but will participate in future calls. Russ and Don will begin today with some opening comments on our financial results and certain other company developments. A copy of the slide presentation that will accompany their remarks is available on our website at transcanada.com. It can be found in the investor 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 James Miller following this call, and he would be happy to address your questions. In order to provide everyone from the investment community with an equal opportunity to participate, we ask that you limit yourself to two questions. If you have additional questions, please re-enter the queue. We ask that you focus those 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, Stuart and I would be pleased to discuss them with you following the call. Before Russ begins, I'd like to remind you that our remarks today will include forward-looking statements that are subject to important risks and uncertainties.
For more information on these risks and uncertainties, please see the reports filed by TransCanada with Canadian securities regulators and with the U.S. Securities and Exchange Commission. Finally, I'd also like to point out that during this presentation, we'll refer to measures such as comparable earnings, comparable earnings per share, earnings before interest, taxes, depreciation and amortization or 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 TransCanada's operating performance, liquidity, and its ability to generate funds to finance its operations. With that, I'll now turn the call over to Russ.
Thank you, David, good morning, everyone, and thank you very much for joining us today. As highlighted in our quarterly report to shareholders released earlier this morning, our portfolio of high-quality, low-risk energy infrastructure assets continues to perform very well. As evidence of this can be seen in our strong second quarter financial results, which continue to support our board of directors' decision earlier this year to increase our quarterly common dividend per share to CAD 0.625. That equates to CAD 2.50 per share on an annual basis and represents a 10.6% increase over the dividend in 2016. During the quarter, we also continued to advance our CAD 24 billion near-term capital program, which includes CAD 2.2 billion of additional growth opportunities announced in the past weeks in our Canadian Natural Gas Pipelines business. This portfolio of commercially secured and rate-regulated project largely remains on time and on budget.
To help fund that program, we raised about CAD 2.5 billion in the quarter, which included a US $765 million sale to our US MLP. During the quarter, we completed the sale of our U.S. Northeast power portfolio, which allowed us to fully retire the Columbia Acquisition Bridge Facility. Finally, during the quarter, we continued to advance a number of other strategic initiatives that will enhance the predictability and stability of our earnings and cash flow and position us for additional long-term dividend growth. I'll touch on each of these developments in the next few slides, but I'll start with a brief review of our financial results. Excluding certain specific items, comparable earnings for the second quarter 2017 were CAD 659 million, or CAD 0.76 per share, an increase of CAD 293 million, or CAD 0.24 per share, over the same period last year.
That equates to a 46% increase on a per share basis and reflects the strong performance across our Natural Gas Pipelines, Liquids Pipelines, and Energy businesses, including Columbia, which we acquired, as you know, July 1st, 2016. Comparable EBITDA also increased by CAD 461 million to approximately CAD 1.8 billion, while comparable funds generated from operations of CAD 1.4 billion was CAD 352 million higher than the second quarter of 2016. On a year-to-date basis, comparable earnings were CAD 1.56 per share or 28% increase when compared to the CAD 1.22 per share reported for the same period last year. Comparable EBITDA also increased to approximately CAD 3.8 billion. Comparable funds generated from operations increased to CAD 2.9 billion. Don will provide more details on our strong financial results in just a few moments.
Before he does that, I'd like to offer a few comments on some of the recent developments in each of our businesses, beginning with natural gas. First, we continue to see strong demand for our services in our Canadian Natural Gas Pipeline business, where we've recently secured CAD 2.2 billion of additional near-term growth opportunities. They include an additional CAD 2 billion of NGTL System expansions that are underpinned by customer demand for approximately 3 billion cubic feet a day of incremental firm receipt and delivery services. In addition, as you saw this morning, we announced a CAD 160 million expansion at a Canadian Mainline compressor station in Southern Ontario to primarily meet growing demand in that region. Also on the Canadian Mainline, an application was filed with the National Energy Board on April 26th for approval of the long-term fixed-price service from Empress, Alberta, to Dawn in Southern Ontario.
The NEB is reviewing our application with a decision expected to follow after oral arguments are presented in September. The new service is requested to be in service November 1 of 2017. Turning to the U.S. and Columbia, we essentially fully integrated from a system basis in April. Firstly, with respect to synergies, we remain on track to realize the majority of our targeted $250 million U.S. of synergies in 2017, with the remainder to follow in 2018. On the growth side, we continue to advance Columbia's $7.2 billion U.S. of near-term capital by advancing construction of the $1.5 billion Leach XPress project and the $400 million U.S. Rayne XPress projects. Both are expected to be in service this November. We also continue to advance the WB XPress, Mountaineer XPress, and Gulf XPress projects through the various stages of the regulatory process.
On WB XPress, we have received our final environmental impact statement and are waiting for a quarter to start construction. We received notice this morning that on Mountaineer XPress and Gulf XPress, the final environmental impact statements have also been received. All three projects are expected to be placed in service in 2018. Moving to Mexico, we continue to advance the Tula, Villa de Reyes, and the Sur de Texas projects that will see us invest a total of $2.5 billion U.S. in these three projects, with approximately $1.1 billion U.S. having been spent to date. Finally, in our Natural Gas segment, a few comments on two long-term initiatives that we've been pursuing related to the West Coast LNG market. First, with respect to Prince Rupert Gas Transmission, as you are aware, earlier this week, we were notified that Pacific Northwest LNG would not be proceeding with their proposed LNG project.
As part of our agreement, following the receipt of a termination notice, we will be reimbursed for the full costs and the carrying charges incurred to advance that project. We expect to receive that payment later in 2017. We are very pleased with the work that we did along the PGRT route, which allowed us to sign 14 project agreements with First Nations and secure key regulatory approvals and permits. We have built strong relationships, and we look forward to continuing our strong relationships with First Nations and communities in B.C. as we develop our other natural gas assets, including our North Montney Mainline project. This important project is backed by independent 20-year commercial service agreements with 11 shippers, including Progress Energy. Pending regulatory approvals, we remain ready to move that project forward.
Turning now to the Coastal GasLink project, where the ongoing delay in final investment decision for LNG Canada has triggered a restructuring provision in our project development agreement with LNG Canada. Those changes will result in the payment of certain amounts to TransCanada with respect to carrying charges and costs incurred since the inception of the project. As a result, we expect to receive approximately CAD 80 million in September, followed by quarterly payments of approximately CAD 7 million. Just to be perfectly clear, this project continues to advance, and we continue to work with LNG Canada and others towards a final investment decision. Turning to Liquids group, where Keystone continued to produce solid results in the quarter, largely due to the contributions of 545,000 barrels a day of long-term take-or-pay contracts, as well as other shorter-term volumes.
We also continue to advance the Grand Rapids Pipeline and Northern Courier Pipeline projects, which will see us invest a total of CAD 1.9 billion. Line fill has commenced on Grand Rapids Pipeline and the construction of Northern Courier Pipeline is nearing completion. To date, we have spent a total of CAD 1.8 billion on those projects, and both are expected to enter full service by the end of the year. Finally, in Liquids, we continued to advance the Keystone XL project during the second quarter, following the receipt of the presidential permit this past March. Earlier this year, we filed an application with the Nebraska Public Service Commission seeking approval for the pipeline route through the state of Nebraska. A hearing on that application is scheduled in August, and a final decision expected by the end of November 2017. On the commercial front, discussions continue with potential shippers.
Yesterday, we launched an open season to solicit additional binding commitments from interested parties for transportation of crude oil on Keystone Pipeline and Keystone XL from Hardisty, Alberta to markets in Cushing, Oklahoma and the U.S. Gulf Coast. The open season will close on September 28th, 2017. We continue to believe the U.S. Coast is the largest, most attractive market for growing volumes of Canadian heavy oil. We also believe the Keystone XL is the safest, most efficient, and most environmentally sound way to move that crude oil from Western Canada to the U.S. Gulf Coast. This project will enhance U.S. energy security, create significant employment for many U.S. citizens, as well as generate significant tax revenues. It remains a very important project for both Canada and the United States, and it is clearly in the national interest of both countries.
Turning now to Energy, where we completed the previously announced sale of our U.S. Northeast power business for approximately $3.1 billion during the second quarter. The proceeds, as I said, were used to fully retire the remainder of the Columbia acquisition bridge facilities. With those sales complete, approximately 95% of our remaining 6,200-megawatt portfolio of generating capacity is underpinned by long-term contracts with solid counterparties, further enhancing the stability and predictability of our consolidated earnings and cash flow streams. On the project front, we continue to advance the construction of the Napanee gas-fired power facility in Ontario. That plant is expected to be completed in 2018, like our other facilities, that project is underpinned by a 20-year contract with the Independent Electricity System Operator.
Bruce Power's long-term refurbishment program also continues to progress with work on asset management programs advancing in preparation for the first major component replacement, which is scheduled to commence in 2020. In summary, during the second quarter, our high-quality portfolio of energy infrastructure assets continued to produce very strong results. We continue to advance our CAD 24 billion near-term capital program, and it is largely on time and on budget. In total, we invested approximately CAD 2.3 billion on those projects during the second quarter. This includes amounts related to the expansion of the NGTL and Columbia systems, as well as our Mexican natural gas pipeline projects, regional liquids projects, which I mentioned, and the Napanee and Bruce Power projects, bringing the cumulative investment in the CAD 24 billion program to about CAD 9 billion to date.
The remaining CAD 15 billion required to complete these projects will largely be spent through the end of 2019. We remain well-positioned to fund that capital program. As we've said before, each of these projects is underpinned by long-term contracts or cost of service regulation, giving us good visibility to growth in earnings and cash flow as they enter service between now and the end of the decade. As a result, we expect to build on our track record of 17 years of dividend growth by growing the dividend at the upper end of the 8%-10% range through 2020. Our dividend growth outlook is supported by expected growth in earnings and cash flow emanating from the commissioning of the new facilities, which will allow us to maintain very strong dividend payout coverage ratios.
That concludes my prepared remarks. Now I'll turn the call over to Don for some additional comments on our second quarter results. Don?
Thanks, Russ. Good morning, everyone. As outlined in our quarterly report to shareholders issued earlier today, we reported net income attributable to common shares in the second quarter of CAD 881 million, or CAD 1.01 per share, compared to net income of CAD 365 million, or CAD 0.52 per share, for the same period in 2016. Per share amounts include the dilutive effect of issuing 161 million common shares in 2016, plus additional shares issued through the dividend reinvestment program this year. Second quarter results included a CAD 265 million after-tax net gain on the monetization of our U.S. Northeast merchant generation facilities, which was comprised of a CAD 441 million after-tax gain on the sale of TC Hydro, an incremental after-tax loss of CAD 176 million on the sale of the thermal and wind package.
It also included an after-tax charge of CAD 15 million for integration-related costs associated with the acquisition of Columbia, a CAD 4 million after-tax charge related to the maintenance of Keystone XL assets. Second quarter 2016 included a charge of CAD 113 million related to costs associated with the Columbia acquisition, which were primarily related to the dividend equivalent payments on the subscription receipts issued as part of their permanent financing of the transaction, pending their conversion to common shares, a CAD 10 million after-tax restructuring charge related to expected future losses under lease commitments, a CAD 9 million after-tax charge related to Keystone XL maintenance and liquidation costs.
Excluding these items and specific risk management activities, comparable earnings for second quarter 2017 rose by CAD 293 million to CAD 659 million, or CAD 0.76 per share, compared to CAD 366 million or CAD 0.52 per share for the same period last year, a 46% increase on a per share basis. Turning to our business segment results on slide 16. In the second quarter, comparable EBITDA from our five business segments was approximately CAD 1.8 billion, CAD 461 million higher than in the same period in 2016. The increase was largely driven by the following factors. U.S. Natural Gas Pipelines EBITDA of CAD 551 million increased by CAD 299 million, or $216 million U.S., mainly due to the acquisition of Columbia on July 1, 2016, and higher ANR transportation revenues resulting from higher rates that went into effect on August 1, 2016 as part of its rate settlement.
Mexico Natural Gas Pipelines EBITDA of CAD 145 million increased CAD 96 million, or $66 million U.S., primarily due to incremental earnings from Topolobampo and Mazatlán, which began collecting revenue in July and December 2016 respectively, and equity earnings on Sur de Texas, which records allowance for funds used during construction, or AFUDC, during its construction period. Liquids Pipelines EBITDA rose by CAD 56 million to CAD 332 million, primarily as a result of higher volumes on Keystone Pipeline and a higher contribution from liquids marketing activities. Energy EBITDA increased by CAD 56 million to CAD 287 million, the principal driver being Bruce Power's contribution increasing by CAD 112 million compared to the same period last year. Recall that in second quarter 2016, Bruce Power was impacted by a once-a-decade station containment outage that reduced plant availability to 71% in the period.
In contrast, during second quarter 2017, Bruce Power availability was 92%, resulting in a significant increase in volumes and operating revenues. The improvement at Bruce was partially offset by a lower contribution from U.S. Power. As Russ indicated, we closed the sales of our U.S. Northeast Hydro assets in mid-April and Thermal and Wind assets in early June. As a result, U.S. Power generated $32 million U.S. of EBITDA in Q2 2017, down from $82 million U.S. in the same period last year. We expect to realize the approximate $450 million U.S. cash value of the remaining U.S. Power marketing business as contracts run off and working capital is released over time. At June 30, 2017, we have realized approximately $150 million U.S. of this value, with an additional $100 million U.S. expected by the end of the year and the remainder anticipated through 2020.
These noted increases to EBITDA across U.S. and Mexico natural gas pipelines, liquids pipelines, and energy were partially offset by a CAD 34 million decrease in the Canadian natural gas pipeline segment. Net income and comparable EBITDA for our rate-regulated Canadian natural gas pipelines are generally affected by our approved ROE, our investment base, our level of deemed common equity, and incentive earnings or losses. Changes in depreciation, financial charges, and income taxes also affect 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.
As outlined in the quarterly report, net income for the NGTL System increased CAD 8 million in the second quarter compared to the same period last year, mainly due to a higher investment base and incentive earnings on O&M costs, while net income for the Canadian Mainline decreased CAD 4 million due to a lower average investment base and higher carrying charges on regulatory deferrals, partially offset by higher incentive earnings. Turning to the other income statement items on slide 17. Depreciation and amortization of CAD 516 million in the second quarter increased by CAD 72 million, largely due to the acquisition of Columbia, as well as new assets placed into service. This was partially offset by the discontinuation of depreciation expense, effective November 1, 2016, on our U.S. Northeast Power assets upon their classification as held for sale.
Interest expense of CAD 524 million increased by CAD 119 million compared to the same period in 2016, mainly due to debt assumed as part of the Columbia acquisition, along with new long-term debt issuance, partially offset by higher capitalized interest on liquids, LNG, and the Napanee projects. AFUDC was CAD 10 million higher year-over-year, primarily due to increased investment in NGTL System expansions.
Comparable interest income and other rose CAD 36 million in the second quarter compared to the same period in 2016, due to the net effect of CAD 18 million of income related to carrying charges on the Coastal GasLink project costs incurred to date that will be paid to us following a restructuring of provisions in the project agreement, the foreign exchange impact on the translation of foreign currency-denominated working capital balances, and realized losses in 2017 compared to realized gains in 2016 on derivatives used to manage our net exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income. With respect to sensitivity to foreign exchange rates, our U.S. dollar-denominated assets, including our interests in Mexico, 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 one-year forward basis.
Comparable income tax expense of CAD 198 million in the second quarter of 2017 was CAD 9 million higher than last year. The increase was mainly a result of higher pre-tax earnings in 2017 compared to 2016 and changes in the proportion of income earned between Canadian and foreign jurisdictions. Finally, preferred share dividends increased by CAD 11 million for the three months ended June 30, 2017, versus the same period in 2016, primarily due to the issuance of Series 13 and Series 15 preferred shares in April and November 2016, respectively. Moving to cash flow and distributable cash flow coverage ratios on slide 18. Comparable funds generated from operations of approximately CAD 1.4 billion in the second quarter increased by CAD 352 million compared to the same period in 2016, primarily due to the increase in comparable earnings.
For the second quarter, comparable distributable cash flow was CAD 936 million, or CAD 1.08 per common share, compared to CAD 702 million or CAD 1 per common share in 2016. Note that comparable distributable cash flow per share in 2017 included the dilutive effect of issuing 161 million common shares in 2016, as well as DRIP participation in 2017. Maintenance capital expenditures were CAD 365 million in the second quarter, CAD 96 million higher than the level of spend last year. This amount includes CAD 71 million related to our Canadian regulated natural gas pipelines, which was CAD 29 million higher than second quarter 2016 and is reflected in the NGTL and Canadian Mainline rate bases, which positively impacts net income. Maintenance capital of CAD 237 million on our U.S. natural gas pipelines was CAD 143 million or $103 million higher than in second quarter 2016.
A reminder that ANR maintenance capital is expected to be at elevated levels through the balance of 2017 and 2018 and will earn a return of and on capital per last year's rate settlement. Overall, our DCF coverage ratios of 1.7 in the second quarter and 2.0 times year to date are marginally lower than last year. Looking forward, while cash flow remains solid, we continue to expect our maintenance capital spending levels to increase over the remainder of the year. We expect our full-year 2017 distributable cash flow coverage ratio to be largely in line with or perhaps modestly better than our outlook provided on the fourth quarter conference call in February. A few words on the healthy progress we have made in financing our CAD 24 billion near-term capital program.
We believe our funding needs remain manageable and will be mapped through our predictable and growing internally generated cash flow, as well as a variety of financing levers available to us across the capital spectrum. Comparable funds generated from operations continues to grow. In the second quarter, we generated CAD 1.4 billion of comparable FGFO. We also completed incremental external financing in the quarter on compelling terms and exited the period with approximately CAD 1.5 billion of cash on hand. In May, we raised CAD 1.5 billion through an inaugural offering of 60-year junior subordinated notes in Canada, a form of security that we have had a long history with in the U.S. market. The notes have a fixed interest rate of 4.65% for the first 10 years, converting to a floating rate thereafter.
Interest expense on these notes is fully tax-deductible. They are recorded 50% equity credit in the calculation of our key credit metrics. Today, approximately 88% of our debt is fixed rate in nature, with an average coupon of 5.3% and an average term of 20 years, including the hybrid securities to final maturity. The average term of our debt, including the hybrids to first call, is 13 years. On June 1st, we completed the sale of a 49.34% interest in Iroquois and our remaining 11.81% interest in the PNGTS system to TC PipeLines, LP for a total transaction value of $765 million and received proceeds net of proportionate debt assumed of $597 million. To partially fund the transaction, in late May, TC PipeLines, LP raised $500 million through the issuance of 10-year senior unsecured notes bearing an interest rate of 3.9%.
As Russ Girling indicated, in the second quarter, we completed the sale of our U.S. Northeast merchant generation facilities for approximately U.S. $3.1 billion. Proceeds were used to fully retire the Columbia acquisition bridge facilities. Our dividend reinvestment plan also continues to provide incremental subordinated capital in support of our growth and credit metrics. In the second quarter, we saw approximately 35% of declared common dividends reinvested into common shares under the program. In June, we established an at-the-market or ATM program that allows us to issue up to U.S. $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 ATM will be used if and as necessary, shaped by our spend profile, as well as the availability and relative cost of other funding mechanisms.
We have not issued any shares through the ATM to date. Looking forward, we continue to expect to continue to access the senior debt hybrid and preferred share markets in a manner that is consistent with achieving targeted A-grade credit metrics in 2018, while maintaining a strong focus on share count and per-share metrics. In summary, while our external financing needs are sizable, they are eminently achievable in the context of multiple financing levers available and the clear, accretive, and credit supportive use of proceeds. With the dividend reinvestment plan, access to preferred share and hybrid security markets, portfolio management, including drop-downs to TC PipeLines, LP, project cost recoveries, and the select use of the ATM as appropriate, we do not foresee a need for additional discrete equity to finance our current CAD 24 billion portfolio of near-term growth projects. Turning now to slide 20.
In closing, I would offer the following comments. Our financial and operational performance in the second quarter continues to highlight our diversified low-risk business strategy. The addition of expansion projects on the NGTL System and Canadian Mainline demonstrate the organic growth opportunities that continue to emanate from a broad, strategically located asset base. Today, we are advancing a CAD 24 billion near-term capital program and have five distinct platforms for future growth in Canadian, U.S., and Mexico natural gas pipelines, liquids pipelines, and energy. Our overall financial position remains strong, supported by our A-grade credit ratings and a straightforward corporate structure. 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 suite of critical energy infrastructure projects is poised to generate significant growth in high-quality earnings and cash flow for our shareholders.
That is expected to support annual dividend growth at the upper end of an 8%-10% range through 2020. Success in adding to our growth portfolio in the coming years could augment or extend the company's dividend growth outlook through 2020 and beyond. That's the end of my prepared remarks. I'll now turn the call back over to David for Q&A.
Thanks, Don. Just a reminder before I turn it over to the conference coordinator for questions from the investment community. We do ask that you limit yourself to two questions. If you have additional questions, please re-enter the queue. With that, I'll turn it back to the conference coordinator.
Thank you, sir. If you have a question, please press star one on your telephone keypad. If you're using a speakerphone, please pick up the handset before pressing star one, and you may cancel your question by pressing the pound sign. Please press star one if you have a question. There will be a brief pause allowing you to register. Our first question is from Linda Ezergailis from TD Securities. Please go ahead.
Thank you. In your outlook discussion, in your write-up, you mentioned that your comparable earnings outlook for 2017 is expected to be higher versus previous expectations, and you cite your U.S. Northeast power business contribution the first half of the year. What other factors? Is it crude oil pipelines as well that are expected to trend stronger? How much of a factor would weather, and I'm assuming to a lesser extent, FX be as well?
Hi, Linda, it's Don. Yeah, the direction arrow's pointing up just a little higher. It's fairly broad-based in this case. We've got five months behind us since that outlook was published. We continue to see stable as-expected returns mainly out of Canadian, Mexico, U.S., Mexico pipelines. We are seeing improved revenues, cost control across liquids pipelines, U.S. pipelines. You did note the contribution from the U.S. Northeast power assets through to their date of disposition as well. Holistically, the direction now is a little bit higher than back in February. I can't really point to anything specific on that front. In terms of FX, it really doesn't have much of an impact this year. We achieved, say, an FX rate in 2016 of about 131.
I would say with our hedging programs, we'll be very close to that, probably in the 132 area for 2017. We are fully hedged out on that front. FX was, on a year-over-year basis, not a material factor on that. Again, broad-based, really just direction arrow pointed up across several business lines and revenues and costs.
Great. Thanks for the context. Just as a follow-up, with respect to your Keystone XL open season and all your latest commercial discussions, can you describe how key attributes might have changed, if at all, from some of your prior initial negotiations with your customers?
Hi, Linda. It's Paul Miller here. I don't think there's been any real key attributes around the commercial discussions. It's really been just a matter of time. When the permit was denied in late 2015, many of our shippers reviewed other options. Now that this option is again in front of them, they have come back. We continue to provide a cost-effective access to the market that they want to access, the U.S. Gulf Coast. Over the course of the last four or five months since we received the permit, it really just has been a function of refreshing the legacy contracts and getting the documentation in place.
Great. Thank you.
Thanks, Linda.
Thank you. The next question is from Robert Kwan from RBC Capital Markets. Please go ahead.
Good morning. Just wondering, a number of projects are having problems and some of them more recently building into the Northeast and also some problems popping up in the Midwest. I'm just wondering, when you look at your pipe system, can you just talk about the strategic value and the opportunities you see for the mainline as well as Columbia, given permitting existing rights of way and maybe going through some states that seem to be less of a headwind?
Yeah. Hi, Robert. It's Karl. I think your comment on going through states that are less of a headline is correct. The build-out we have right now in the U.S. is basically within our existing right of ways and through existing counties and states that we already have commercial relationships with and pipelines in. We're quite comfortable with the permitting risk on those and our permits have been coming as per expected on those particular assets. Same thing in Canada with our expansion that we announced at an existing compressor station with several compressor centers. We've been in there many times over the years. We expect the fact that we're there to make the permitting more certain than otherwise. It's not a secret our goal is to continue to develop within the right of ways.
We believe we have footprint that'll continue to be needed. Our goal is to do as much business within those right of ways or just outside of those right of ways as possible. That includes add-ons in the U.S. and continuing to interconnect and expand our systems between the U.S. and Canada. It's when you go outside of those big right of ways that you tend to have more challenging permitting activities. Right now, most of the gas activities are within the existing footprint that we have.
I guess just, Karl, are you seeing, though, with some of the headwinds that have been coming up for other initiatives, a change in just customers wanting to engage with you on your existing projects and systems?
Yeah. On assets like Portland, for example, with all the cancellations in New England of the pipelines where we're finally seeing some headwinds or some tailwinds, I mean, on getting some extra capacity out of that system. We don't have anything signed up to announce right now, but I don't think it's been a secret that we've been in that area talking to customers there. We're quite optimistic there. The proposal that we have is simple. We can expand that pipeline with just compression only, and they can access their gas through the Canadian Mainline.
If they want to bring their Marcellus and Utica gas through the Canadian Mainline, we can also facilitate that through the Columbia assets, ANR, and even through Great Lakes and St. Clair to Dawn. I think we do have a package that we can offer people that will use existing infrastructure instead of the new greenfield. The same, I would say, with Iroquois. Iroquois is a very similar situation, although I would say that we're probably less advanced on Iroquois as we are on the Portland Natural Gas System.
Okay. If I can just finish on funding. Can you just talk about the impact on the funding plan in your approach, given the money you're going to get back on PRGT as well as a bit from Coastal? Does that displace, let's say, maybe what you were planning to do on the ATM usage?
Hi, Robert, it's Don. I wouldn't say it displaces it. It's a moving equation here at any point in time. It is positive in terms of seeing probably CAD 600 million-ish coming back. That puts a dent into some of the more expensive funding that we're looking at. The amount that we'll use the ATM is still going to be shaped by the cadence of our CapEx program and business results going forward, and how much we use the LP. Back in February, we'd indicated a need for about CAD 3 billion of other, which included likes of the ATM, potential further asset sales and LP drop-downs. I would say the CAD 600 million coming back from these projects will impact that box. It is not dollar for dollar equity. It is a combination of equity debt capacity that's coming back from those items.
It would serve to suppress how much ATM we issue. That ATM target is not yet chiseled in stone here, and will depend on the factors I just outlined. I wouldn't expect the ATM to be zero. I expect we'd use some of it over the 25-month life of that. Again, it'll be a moving part depending on these other factors.
Got it. Thanks, Don. Thanks, Karl.
Thanks, Robert.
Thank you. The next question is from Ben Pham from BMO. Please go ahead.
Okay, thanks. Morning. Following on that conversation on the financing, the ATM, when you think about the financing program you put out late last year, the couple of buckets you highlighted ATM was in there. I'm just curious, has anything changed on maybe the drop-down expectation that's driving the ATM, or anything else in the prep side?
I would say that we put a healthy dent in some of these categories. We've issued CAD 3.5 billion equivalent of hybrid to date out of our target of CAD 5.5 billion-CAD 6 billion that we outlined in February over a three-year period. We've had a pretty healthy start on that front. We have closed an LP drop-down with $600 million of cash coming back to us. We've still got a healthy amount of senior debt to refinance here coming up. The DRIP program's running probably a little ahead of what we expected at the time in that 35%-40% range. When you step back and look at the context of what we're trying to do here over three years, we're building CAD 24 billion of assets, we're de-leveraging at the same time. The ATM program is there not just as a placeholder.
I mentioned we expect to use it to some extent here. It would be positives that would reduce the amount of share issuance out of that program would be further MLP drop-downs. We cannot give you any specific guidance as to when or what we might put into the MLP going forward. Watch for us to continue to move assets in there on a fairly methodical basis over time. We have a healthy inventory of that. We will continue to look at pruning the portfolio on the margin with further asset sales. Nothing fully baked at this point. We are very much focused on per-share metrics here and minimize the amount of share account growth going forward here. Those are the levers that we are looking at.
My second question is on the Columbia projects and maybe more specifically the 2018 ones and your commentary about receiving some docs on the environmental side. You got a couple other companies highlighting project delays for quorum, lack of quorum. What are your thoughts in terms of how late you can get an order there before that 2018 in service heads over to 2019, for example?
Ben, it is Karl. I guess what I will say about that is that we do view the regulatory process as moving forward. As Russ said, we did get for Mountaineer XPress and Gulf XPress, we got our EIS just today. There is not a quorum. We are encouraged that the Senate is delaying their recess, and hopefully part of the reason they are delaying the recess is to confirm some FERC commissioners. If we do not get a decision by the end of the summer, it is not by any stretch material on any of these projects. We will take a look at it. We have options virtually in every case to speed up constructions. You can put new spreads out there. There are lots of different mitigations that we have. We will cross that bridge when we get there and decide what to do if it is delayed beyond that.
I would say, in any case, I do not think it is material. We are talking days or weeks versus months or years. It certainly does not impact the status of the projects, the doability of the projects at all. We would consider this right now to be not really a material issue at this time. We certainly have lots of mitigations if, in fact, the decision does not come by the end of summer. We are still hopeful given the process we see that it will.
Okay, great. Thanks, Karl. Thanks, everybody.
Okay. Thanks, Ben.
Thank you. The next question is from Praneeth Satish from Wells Fargo. Please go ahead.
Hi, good morning. Keystone's performance this quarter was pretty strong. Just trying to figure out how much of that was due to utilizing available spot capacity versus, I guess, more long-term contracts. Any breakdown would be helpful.
Hi, Praneeth. It is Paul Miller. All of our results in Q2, the increase in results were because a majority of the increase in the uncontracted volume on the Keystone system, and within the business unit, a slight contribution from foreign exchange. We saw an increased demand for volume down to the U.S. Gulf Coast. We have today about 90% of our volume contracted, so the increment was attributable to the uncontracted volume.
Got it. Just one more question. When you look at all of the spending that you are going to be doing on NGTL over the next few years, just trying to figure out how much of those projects will bring gas down to the U.S. West Coast. I guess more specifically, I am just trying to figure out how this could impact flows and utilization of the GTN system.
It is Karl. The last open season we had, and as part of the CAD 2 billion announcement we just made on NGTL, was a section of both receipt service and delivery service that moves gas on to GTN. We have contracted on long-term about CAD 400 million a day going into GTN. That will be up and running here in about a couple of years. That should fill GTN up. We are right now looking at GTN as what else we can get through extra compression and looping, whatnot at GTN. With implementing this latest expansion of NGTL, we will actually fill up the remaining capacity of GTN. We will be having to figure out some sort of expansion on it. There is expansion capabilities on GTN. We are just not certain what that is right now, we are in the midst of doing some engineering on that.
You can certainly expect another CAD 400 million a day coming to GTN once we get this expansion complete. We will be announcing in the future what other volumes we can get to on an expansion basis.
Great. Thank you.
Thank you. The next question is from Robert Hope from Scotiabank. Please go ahead.
Yes. Thank you. Maybe just moving back on to Keystone. When we look at the open season ending in September of this year, is this timeline really set up by existing conversations that you're having with some of the larger producers? I guess second on that would be, would that be for the full Keystone XL volume that you're putting out there in an open season?
Rob, it's Paul Miller. We have had good conversations with our existing shipper group as well as new entrants as they work their way through their analysis and documentation. To date, we've achieved good support from our legacy shippers, which gives us this good base to launch the open season. The open season provides an opportunity for other known parties to bid in for capacity and for others to assess the opportunity. It is an opportunity for all parties to participate within Keystone XL. Our goal remains to achieve a significant level of long-term 20-year contracts on Keystone, this open season will give us that opportunity to see what that market support is.
All right. Thank you for that. Just as a follow-up there, does the timing with it closing late September potentially lead to an acceleration of when you could get crews out in the field? If I recall correctly, Nebraska could come later this year, you need some other permits, on Q1, I believe you said that you could get line pipe being put in the ground in Q3 of next year.
The open season closes in September, there is typically about a two-month period as you work through credit documentation, et cetera. I would not see us in a position to know our final open season results until in November. That would coincide with when we expect to receive our Nebraska decision for the route through Nebraska. Those two items remain the last two factors we're pursuing, the commercial support as well as the regulatory approval. I would see them coming together here in November. We'll make an assessment of the commercial support and the regulatory approvals at that time. In the event that we do decide to proceed with the project, we still need probably six to nine months to start doing some of the staging of the construction crews, et cetera, that would be followed by about a two-year construction period.
That's helpful. Thank you.
You're welcome.
Thanks, Rob.
Thank you. The next question is from Ted Durbin from Goldman Sachs. Please go ahead.
Thanks. It sounds like you are making good progress on the long-term fixed price service with the NEB getting the schedule and whatnot. I guess I am wondering what your thoughts are on how that is going to tie into the LDC settlement and some of the contract roll-offs that you need to deal with over the next few years as more of this Marcellus gas comes into Dawn, how that might impact, say, the ROE or the incentive structure, just what your thoughts are on combining those two.
Oh, yes. It is Karl. I guess I will start by saying that the LTFP, I think, is not only useful for TransCanada to get volumes that we thought otherwise would not flow, but is a very important product, I think, for the WCSB producers. It did price it so they can come into the Eastern Canadian markets anyway, and even beyond, and compete. It is a product that we are pursuing to get through the regulatory process and start up on November 1st. How it relates to the Mainline's kind of future with the LDC settlement and so forth, I think the settlement that we did with the LDCs, I think that is actually what guaranteed the Mainline's future.
The financial transaction we did with the LDCs to move the value, to move capital into the Eastern Triangle and separate the systems is, I think, what actually proved up the future of the Western Mainline portion. The LTFP, I think, is a great adder to that, but I don't think that the LTFP is in and of itself what's going to guarantee the future of the Mainline. I think that LDC settlement did. The LDC settlement did allow the migration of volumes from Empress to short-haul. Products like the LTFP actually fills that pipeline back up, and we are going to be aggressive and make sure that pipeline gets filled up. Even though, in my belief, the financial viability of that Mainline has been preserved through that, I'm not going to sit back idly and see markets that we traditionally serve get competed away.
We're going to be aggressive, and we're going to move volumes in there, and we're going to make sure that Western system is full. The LTFP is one of those products. We will get that through the regulatory process right now. Both us and our regulators are expecting that we'd be aggressive and move volumes down there. I think it's a good first product, but we have a lot of spare capacity in that Mainline. Quite frankly, I'd like to see more gas moving down there ultimately. Given the proliferation of the WCSB and the reserves there, I think that we've got some work ahead of us to see if we can get even more volumes down there.
Yeah, Karl, any way to quantify that? How much more beyond the one and a half that you've already contracted up you might be going after coming out of Western Canada?
Well, it's a good question. The supply base in Western Canada, when you actually take a look at the reserves, it's not an either/or situation anymore. If we can help producers get markets, the producers, I think, will produce and ship, and I think they've already shown that with the various open seasons that we have had. When you look at our long-haul system, on the Mainline right now, we have about eight Bcf a day of contracts on that system, but only about 2.7 Bcf a day is long-haul contracts from Empress. Certainly, that system, at its peak, moved about six and a half Bcf a day. Now, we don't have that capacity available today because with no contracts on it, we didn't do the maintenance. We let some compressors time out and whatnot, and reduced the pressure.
Certainly, we have that volume latent in that pipeline, which is pretty cheap to get going. It just involves maintenance, really. It just involves compression maintenance and interior work in the pipeline. There is a good opportunity to bring more WCSB gas into the Eastern Canada, Northeast U.S. if the producers are willing to compete, and I can certainly offer them a very economical solution. That is what we are working on right now. Currently, today, at 2.7 Bcf/day of contracts, I have about a Bcf that is running on either spot markets or that is running on shorter-term contracts, so I can certainly firm those contracts up today. If we go much beyond that, beyond a Bcf, 1.2 Bcf, I will have to start putting some of that maintenance into the system.
That is great. That is very helpful. Then just coming back to the question on the stronger outlook for 2017 earnings, is that something that we should think about as flowing through as well on a multi-year basis? If we look at the multi-year outlook you provided in February, how much of this, I guess, strength in 2017 will be recurring?
Hi, Ted. It is Don here. I think it just exemplifies the strength of the asset base here. Some of it is, I would say, our cost programs and our Columbia synergies coming in faster than might have been expected before. Those, we still expect them to come in around CAD 150 million of cost synergy and CAD 100 million of financing synergy. But I would expect we will hit the plateau on those faster than was initially envisioned. A lot of this is singles and doubles, and just showing how we can extract a little bit more out of the system. But fundamentally, this is a pretty predictable asset base going forward that is cost of service regulation or long-term contracts.
I wouldn't describe it as a structural shift upward, but just really strong execution at this point of the cycle and some of the cost benefits coming through quicker than was initially envisioned.
Understood. I'll leave it at that. Thank you.
Thank you. The next question is from Andrew Kuske from Credit Suisse. Please go ahead.
Thank you. Good morning. I think the question is for Karl, it's a little bit of a chicken and egg type of question, what's the bigger moderator on the pace of TransCanada's growth in your business? Is it really the pace of production coming from the producers and really their budgeting or your ability to get regulatory approval on pipes? Whether this be in the Montney or the Marcellus.
That's a good question. Not having thought about that in-depth, I would say the pace of getting regulatory permits is probably a greater moderator. These producers that, especially in the WCSB, for example, but very much the same goes for the Marcellus Utica area. These producers want the service sooner rather than later. If I can get quicker permits, if I can get [site construction] on quicker, they would take the capacity quicker. I actually think if I could do it quicker, I think they'd actually sign up for more capacity. I think it is daunting for the producer to have to sign up for capacity 3 years before they actually get it. It's not lining up anymore with the production cycle of the producer.
I would say that if we can, we're working with regulators all the time, if we can speed up that process, I think we would actually get their volumes quicker, and I think we would get more volumes.
Okay, that's helpful. A process that looks like it might speed up in a little bit is just the FERC quorum issue. Specifically, where are you being held up? What specific lines? Is it Montney or WB XPress, Gulf XPress? Are those really the three critical ones that are being held up at this stage?
Those are the three that we have going through the process right now. As I said, if I were to rank them, they're always expected to come up and come in service in 2018. We'd like to see the process conclude on all of them as quickly as we can. As I said earlier, I think it's too early to get too worried about the quorum and whatnot. Even if it goes past the summer here, we still have lots of mitigation options if we choose to speed it up. We deal with this all the time. Even in the worst case, as I said, we're dealing with days and weeks, not long-term. There's really no fundamental altering of the economics of these projects because of this quorum issue. I'd say that they're all expected to be in service in 2018.
I'd say I'm watching them all equally as to the impact of any delay on that decision.
Okay, that's great. Thank you.
Thanks, Andrew.
Thank you. The next question is from Robert Catellier from CIBC Capital Markets. Please go ahead.
Hi. I'd like to go back to Keystone XL for a minute here. What do you need to see from the Keystone XL open season to achieve your commercial milestones and get to FID, notwithstanding the regulatory process isn't finished yet? For example, if it's not entirely sold out, is there a scenario where you can proceed with a lesser amount of contracted volumes?
Robert, it's Paul Miller here. We're going to run the open season until September, and we'll assess the results at that time. Our goal remains to secure a significant level of contracts and running the open season to pursue those contracts, and at the same time, to secure our regulatory approvals. Our assessment of these factors will really drive our investment decision when we get into that November, December timeframe.
Just wanted to ask a question on the dividend growth outlook. Given you made great progress, obviously, your coverage ratios are great. Your operations are running well. Financial results are coming in strong. What are the gating factors to really extending or raising the dividend growth guidance? Maybe you could speak directly to whether the ATM is a factor in that at all, or the success on any one of the major projects.
I can give you a start, Robert, and then Don provide his comments as well. I think as you know, historically, we've been very conservative in terms of giving guidance. When we have visibility of growth in earnings and cash flow that underpin dividend growth, we provided that guidance. Our CAD 26 billion capital program that we have in place today, that's visible, and we're in the progress of executing, gives us that visibility. I think the things that augment and extend that guidance is continued performance from our base business, as you said, completion of those projects, completion of the financing plan as we've outlined it, and then adding new projects to the portfolio from the five platforms of growth that Don outlined, is that we're seeing those projects starting to come to fruition.
We announced in the quarter another CAD 2 billion plus of projects in our Canadian gas business, as Karl just outlined. I think what the constraint right now is market, not production. These producers could bring on a lot more gas if we could build the infrastructure to get it to market. We think that's a great platform. As that evolves, hopefully we can contract out more opportunities for ourselves. As I look at the U.S. gas business, again Karl outlined, we're starting to see integration between our Canadian and U.S. systems, the value of existing right of way and pipe in the ground, and interconnected between that, can we move gas out of the Marcellus to New York and New England? Yes, we're seeing opportunities to do that. That's another platform for continued growth. Mexico, we continue to look for opportunities to expand our systems there.
We said, in the power business, we'll continue to see migration from coal to other things. Certainly as we look to 2020, and we start firming up our program for Bruce refurbishment, that will mean greater clarity on capital investment on that front. Certainly, Paul has talked about oil opportunities that exist today. As those come to fruition, you'll see us adding to that CAD 24 billion program. As you heard today, becoming CAD 26 billion. That grows, we have visibility of growth in cash flow and earnings. We will look to extend and augment our dividend guidance. Don, anything?
Yeah. Again, it's visibility. You know, we take a conservative view on this. We don't statistically weight a probability set. We like to see visibility of real projects coming into service down the road that informs our decision on the dividend. Fundamentally, there's no change to payout ratios. What we're looking at is what we've always done here. We still believe earnings matter. It's old school, but you're looking at 80%-90% of earnings. That equates to around 40% of funds generated from operations and on a DCF basis, gravitating up to the [high 1.2x area] , by the end of the decade on that. We're not looking at any fundamental change there. Well, we're looking to maintain A-grade credit ratings. We think that is to the benefit of all stakeholders, the ability to act at all points in the cycle.
No fundamental change on those fronts. It is really driven by greater visibility and clarity when we see real growth coming.
Fantastic. Thank you.
Great. Thanks, Rob.
Thank you. The next question is from Nick Raza from Citi. Please go ahead.
Thank you. Most of my questions were sort of answered, but just as an add-on to Keystone XL, some clarification on that. Will the marketing entity at TransCanada also be participating in this open season?
Hi, Nick, it's Paul Miller here. We seek contracts from third parties. Our business model has us going out to the marketplace producers, refiners, to assess their market needs, assess their transportation needs, and with these long-term contracts in place from those external parties, gives us the basis that we can go forth and make an investment decision to provide that transportation opportunity or that transportation capacity. Our goal in this open season is to pursue those third-party long-term contracts.
Nick, that's true of all our businesses. As we think about marketing, having the expertise to optimize and maximize the utilization of your facilities is very important. Contractual underpinning coming from internal non-arm's length parties hasn't been our strategy in gas, power, or liquids. Our focus is on using those entities to make sure we maximize the utilization facilities, maximize the benefit for our company, but also for our shippers as well, that's the technology we've employed. We've been at this for a long time, we've figured out that is the best way to add value to both our customers and to our shareholders.
Okay. That's very helpful. I guess my next question is more for Karl. In terms of the next set of projects, assuming all your backlog gets built out on your Columbia system, essentially on the U.S. side of natural gas pipeline systems, do you sort of see more incremental projects down to the Gulf Coast, particularly on systems like ANR? If you could sort of quantify that. I know it's difficult to quantify at this point, but assuming production, a very optimistic case, what do you think is in the backlog for that pipeline system?
Yeah. Well, I'm speculating now on what the future build-outs might be, when I talk to the producers in that region, I guess it'd be fair to say that they view Dawn to be somewhat supplied, probably with the LTFP and the two proposed pipelines into it, they view that as a market that's probably well supplied. Their desire is to go into the U.S. Northeast, which is having some problems with permitting, the Gulf Coast. Yeah, I would expect looking in the future, I think we're in a great position for the U.S. Northeast, trying to work with our existing infrastructure, expand our existing infrastructure again there. I think both getting volumes into our TCO pool and in the Midwest area and the Gulf Coast would be the next two objectives.
That's on a very high level, just talking to people, those are the areas that we'll be working on within our existing footprint.
Gotcha. If I may, I'm just going to add one more. As a result of the Pacific Northwest cancellation, previously, NGTL's backlog was pushed forward despite one of the conditions was removed that Pacific Northwest LNG should be in place. Are there any other cancellation or contract issues or de-contracting issues on the existing NGTL pipeline as a result of this?
No, our build program, as presented, was all not contingent upon any of the LNG moving forward. The North Montney is the one that had the condition that you talked about. We are right now with a review and variance from the NEB, trying to lift that condition because we have, outside of Progress, who was the initial shipper on that, ostensibly to go to the West Coast with LNG. We have found 10 other shippers willing to sign very long-term contracts and wanting just to get on our base Nova system, our NGTL System. That one, we have put an application on it to have the condition lifted. We have not heard back on the process the board is going to use for that. I'm expecting it any day now. We'll see what the board says.
I guess their choice is between hearing it as a review and variance to just lift the one condition or, I guess, going into a new hearing for the project. Our belief is the project has already been through a hearing. There's already been agreement. There's nothing substantially different in the project, although it is a little shorter than it was before, but it still basically utilizes the same right-of-way, but just has more general customer support than what we had before.
Nick, on a macro level, what I'd say is the changes that have occurred in the market since we proposed those projects or the proponents proposed those projects is, obviously, the markets have become more competitive for Canadian producers. We have to be competitive in all our costs in order to compete in those international LNG markets. I think the other major thing that's occurred over that four or five-year period is proving out the prospectivity, as Karl pointed out, and the cost structure of the Western Canadian Sedimentary Basin. It appears that there's a lot more gas than anybody ever anticipated that can be recovered at everly decreasing costs. The exact opposite, I think, is actually occurring.
At least that's what we're seeing in our system, is that the value of existing transport is growing, and the desire to access existing North American markets is becoming more and more important as these folks determine that they can produce more gas. We're starting to see evidence of that, as you saw here in the quarter where we announced another three billion cubic feet a day of additional receipt and delivery contracts, as Karl pointed out. We actually expect that to continue going forward as these producers continue to prove out their resource base and have a desire to compete in North American markets. That doesn't mean that we're not going to continue to look at trying to get to the West Coast, but I think everybody realizes that's a difficult and longer-term prospect.
In the shorter run, we're focused on Pacific Northwest, California, moving gas east and south out of the Western Canadian Sedimentary Basin, and NGTL is extremely well-positioned to facilitate that movement.
That's very helpful. Thanks, guys.
Okay. Thanks, Faisel.
Thank you. This concludes the question and answer session for today. I'll now turn the meeting back over to Mr. Moneta. Please go ahead, sir.
Great. Thanks very much, thanks to all of you for participating today. We very much appreciate your interest in TransCanada, and we look forward to speaking to you again soon. Have a great day. Bye for now.
Thank you. The conference has now ended. Please disconnect your line at this time. We thank you for your participation.