TC Energy Corp (TRP) 2017 Q2 法說會逐字稿

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, and 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 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 James Miller following this call, and he would be happy to address your questions.

(Operator Instructions)

Also, 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 Exchange Commission.

And 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, and 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 evidenced, this can be seen in our strong second quarter financial results, which continued to support our Board of Directors' decision earlier this year to increase our quarterly common dividend per share to $0.625. That equates to $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 $24 billion near-term capital program, which includes $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 $2.5 billion in the quarter, which included USD 765 million sale to our U.S. 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. And 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 of 2017 were $659 million or $0.76 per share, an increase of $293 million or $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 1, 2016. Comparable EBITDA also increased by $461 million to approximately $1.8 billion, while comparable funds generated from operations of $1.4 billion was $352 million higher than the second quarter of 2016. On a year-to-date basis, comparable earnings were $1.56 per share or $0.28 -- or 28% increase when compared to $1.22 per share reported for the same period last year. Comparable EBITDA also increased to approximately $3.8 billion,

Comparable funds generated from operations increased to $2.9 billion. Don will provide more details on our strong financial results in just a few moments. But 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 $2.2 billion of additional near-term growth opportunities. They include an additional $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 $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 26 for approval of the long-term fixed price service from Empress, Alberta, to Dawn in Southern Ontario. NEB is reviewing our application with a decision expected to follow after oral arguments are presented in September. The new service is requested to begin service November 1, 2017.

Turning to the U.S. and Columbia, which we essentially fully integrated from a system basis in April. Firstly, with respect to synergies, we remain on track to raise -- realize the majority of our targeted USD 250 million of synergies in 2017 with the remainder to follow in 2018. On the growth side, we continue to advance Columbia's USD 7.2 billion of near-term capital by advancing construction of the USD 1.5 billion Leach XPress project and the USD 400 million 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 due to various stages of the regulatory process.

On WB XPress, we have received our final environmental impact statement and are waiting for a court order to start construction. And we received notice this morning that on Mountaineer and Gulf, the final Environmental Impact Statements have also been received. All 3 projects are expected to be placed in service in 2018.

Moving to Mexico. We continue to advance the Tula-Villa de Reyes and Sur de Texas projects that will see us invest a total of USD 2.5 billion in these 3 projects with approximately USD 1.1 billion having been spent to date.

Finally, in our natural gas segment, a few comments on 2 long-term initiatives that we have 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 would be -- we will be reimbursed for the full cost and the carrying charges incurred to advance that project, and 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 secured key regulatory approvals and permits. We have built strong relationships, and we look forward to continuing our strong relationships with First Nations in communities in DC, 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 for the 11 shippers, including Progress Energy. And 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 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 $80 million in September, followed by quarterly payments of approximately $7 million. But 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 and Northern Courier pipeline projects, which will see us invest a total of $1.9 billion. Line fill has commenced on Grand Rapids, and the construction of Northern Courier is nearing completion. To-date, we have spent a total of $1.8 billion on those projects and both are expected to enter full service by the end of the year.

Finally, in Liquids, we continue 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 is expected by the end of November 2017.

On the commercial front, discussions continue with potential shippers. And yesterday, we launched an open season to solicit additional binding commitments from interested parties for transportation of crude oil in Keystone Pipeline and Keystone XL for parties in the Alberta to markets in Cushing, Oklahoma and the U.S. Gulf Coast. The open season will close on September 28, 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 the U.S. Energy security, create significant employment for many U.S. citizens as well as generate significant cash 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 USD 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 megawatts 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. And like our other facilities, that project is underpinned by a 20-year contract with the Ontario Independent Electric 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.

So in summary, during the second quarter, our high-quality portfolio of energy infrastructure assets continue to produce very strong results. We continue to advance our $24 billion near-term capital program, and it is largely on time and on budget. In total, we invested approximately $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 Mexico Natural Gas Pipeline projects; regional Liquids projects, which I mentioned; and the Napanee and Bruce Power projects, bringing the cumulative investment in the $24 billion program to about $9 billion to date. The remaining $15 billion required to complete these projects will largely be spent through the end of 2019, and 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% to 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. And 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 $881 million or $1.01 per share compared to net income of $365 million or $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 $265 million after-tax net gain on the monetization of our U.S. Northeast merchant generation facilities, which was comprised of a $441 million after-tax gain on the sale of TC Hydro and an incremental after-tax loss of $176 million on the sale of the thermal and wind package. It also included an after-tax charge of $15 million for integration-related costs associated with the acquisition of Columbia and a $4 million after-tax charge related to the maintenance of Keystone XL assets.

Second quarter 2016 included a charge of $113 million related to cost 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 $10 million after-tax restructuring charge related to expected future losses under lease commitments and a $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 $293 million to $659 million or $0.76 per share compared to $366 million or $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 5 business segments was approximately $1.8 billion, $461 million higher than in the same period in 2016. The increase was largely driven by the following factors: U.S. Natural Gas Pipeline's EBITDA of $551 million increased by CAD 299 million or USD 216 million, 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 $145 million increased CAD 96 million or USD 66 million, 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 $56 million to $332 million, primarily as a result of higher volumes on Keystone pipeline and a higher contribution from Liquids marketing activities. Energy EBITDA increased by $56 million to $287 million, the principal driver being Bruce Power's contribution increasing by $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 of 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 USD 32 million of EBITDA in second quarter 2017, down from USD 82 million in the same period last year. We expect to realize the approximate USD 450 million 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 USD 150 million of this value, with an additional USD 100 million 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 $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 improved ROE, our investment base, our level of the income and 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 $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 $4 million due to our lower average investment base and higher carrying charges on regulatory deferrals, partially offset by higher incentive earnings.

Now turning to the other income statement items on Slide 17. Depreciation and amortization of $516 million in the second quarter increased by $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 $524 million increased by $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 issuances, partially offset by higher capitalized interest on Liquids, LNG and the Napanee projects.

AFUDC was $10 million higher year-over-year primarily due to increased investment in NGTL System expansions. Comparable interest income and other rose $36 million in the second quarter compared to the same period in 2016, due to the net effect of $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 1-year forward basis. Comparable income tax expense of $198 million in the second quarter of 2017 was $9 million higher than last year. The increase was mainly a result of higher pretax earnings in 2017 compared to 2016 and changes in the proportion of income earned between Canadian and foreign jurisdictions. And finally, preferred share dividends increased by $11 million for the 3 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.

Now moving to cash flow and distributable cash flow coverage ratios on Slide 18. Comparable funds generated from operations of approximately $1.4 billion in the second quarter increased by $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 $936 million or $1.08 per common share compared to $702 million or $1 per common share in 2016. Again, 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 $365 million in the second quarter, $96 million higher than the level of spend last year. This amount includes $71 million related to our Canadian regulated Natural Gas Pipelines, which was $29 million higher than second quarter 2016 and is reflected in the NGTL and Canadian Mainline rate basis, which positively impacts net income. As well, maintenance capital of $237 million on our U.S. Natural Gas Pipelines was CAD 143 million or USD 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 2.0x 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. As a result, 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.

Finally, a few words on the healthy progress we have made in financing our $24 billion near-term capital program. We believe our funding needs remain manageable and will be mapped through our predicable and growing internally generated cash flow as well as a variety of financing levers available to us across the capital spectrum.

As I mentioned, comparable funds generated from operations continues to grow. In the second quarter, we generated $1.4 billion of comparable FGFO. We also completed incremental external financing in the quarter on compelling terms and exited the period with approximately $1.5 billion of cash on hand.

In May, we raised $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, and they are accorded 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 1, we completed the sale of a 49.34% interest in Iroquois and the remaining 11.81% interest in the PNGTS System to TC PipeLines LP for a total transaction value of USD 765 million and received proceeds net of proportionate debt assumed of USD 597 million. To partially fund the transaction, in late May, TC PipeLines LP raised USD 500 million to the issuance of 10-year senior unsecured notes, bearing an interest rate of 3.9%. As Russ indicated, in the second quarter, we completed the sale of our U.S. Northeast merchant generation facilities for approximately USD 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 in credit metrics. In the second quarter, we saw approximately 35% 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 $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 to 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.

So in summary, while our external financing needs are sizable, they are eminently achievable in the context of multiple financing levers available and the clearer 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 $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 $24 billion near-term capital program and have 5 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 resilience 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 and high-quality 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. 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. (Operator Instructions)

With that, I'll turn it back to the conference coordinator.

(Operator Instructions) Our first question is from Linda Ezergailis from TD Securities.

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 in the first half of the year. What other factors -- is it crude oil pipelines as well that are expected to trend stronger? And how much of a factor would weather, and I'm assuming to a lesser extent, FX be as well?

Linda, it's Don. Yes, it's more of a -- the direction arrow is pointing just a little higher, and it's fairly broad based in this case. While we've got 5 months behind us since that outlook was published and we continue to see stable, as expected, returns mainly at the Canadian, Mexico U.S. and Mexico pipelines, but we are seeing improved revenues, cost control across Liquids Pipelines, U.S. pipelines. You did note the contribution of the U.S. Northeast Power assets through to their data disposition as well. So holistically, the direction is a little bit higher than back in February, and 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 million. I would say with our hedging programs, we'll be very close to that, probably in the $132 million area for 2017, and we are fully hedged out on that front. So FX was, on a year-over-year basis, not a material factor on that. So again, broad based. Really, just direction arrow pointed up across several business lines and revenues and costs.

Great. 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?

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 we viewed 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. And so the -- over the course of the last 4 or 5 months since we've received the permit, it really just has been a function of refreshing the legacy contracts and getting the documentation in place.

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

Just wondering, a number of projects are having problems in some of the more recent way of building into the Northeast and also some problems popping up in the Midwest. So I was just wondering when you look at your pipe system, can you just talk about 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?

Yes, Robert, this is Karl. Yes. I think you've -- your comment on going through states with less of a headline is correct. The buildup 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. So we've been quite -- we're quite comfortable with permitting risk on those. And we -- our pretty much headwind is coming as per expected on those particular assets. Same thing in Canada, with our expansion that we announced that an existing compressor station with several compressors in. So we've been in there many times over the years, so we expect the fact that we are 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 will continue to be needed and our goal is to do as much business within those right-of-ways or just outside of the right-of-ways as possible. And that includes add-ons in the U.S. and interconnecting expander systems between the U.S. and Canada. So it's when you go outside of those big right-of-ways that you tend to have more challenging permitting activities, but right now, we're -- most of the gas activities are within the existing footprint that we have.

And I guess just, Karl, are you seeing that with some of the headwinds that have been coming up for other initiatives, customers -- a change in just customers wanting to engage with you on your distinct projects and systems?

Yes. On assets like Portland, for example, with all the cancellations in New England at the pipelines, where we're finally seeing some headwinds or some fill-ins, I mean, on getting some extra capacity out of that system. We don't have anything signed up to announce right now, but we don't think it's been a secret that we've been in that area talking to the customers there. So we are 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. And if they want to bring their Marcellus and Utica gas through the Canadian Mainline, we can also facilitate that through the Columbia assets and/or through Great Lakes and St Claire(inaudible). So I think we do have a package that we can offer people that we use existing infrastructure instead of the new greenfield. And the same I would say with Iroquois. Iroquois is a very similar situation, although I would say that we're probably less advanced in 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 planning and your approach, given the money you are 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?

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 $600 million-ish coming back that puts a dent into some of the more expensive funding we are looking at. The amount that we'll use the ATM is still going to be shaped by the, I guess, 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 $3 billion of other, which included likes of the ATM, potential further asset sales and LP drop-downs. I would say the $600 million coming back in 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. But -- so it would serve to suppress how much ATM we issue, but that ATM target is not yet chiseled in stone here, and it will depend on the factors we just outlined. So I wouldn't expect the ATM to be 0. I expect we would use some of it over the 25 months of life of that. But again, it'll be a moving part depending on these other factors.

The next question is from Ben Pham from BMO.

I'm wondering -- just following on that conversation on the financing and the ATM, and when you think about the financing program you put out late last year, there are a couple of buckets you highlighted. ATM was in there, but I'm just curious, has anything changed on maybe the drop-down expectation that's driving the ATM? Or anything else in the pref 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 state out of our target of $5.5 billion to $6 billion that we outlined in February over a 3-year period. So that -- we've had a pretty healthy start on that front. We have closed an LP drop-down with USD 600 million of cash coming back to us. And we still got a healthy amount of senior debt to refinance hear coming up. The DRIP program is running probably a little ahead of what we expected at the time in that 35% to 40% range. But when you step back and look at the context of what we are trying to do hear over 3 years, we are building $24 billion of assets and we are deleveraging at the same time. So the ATM program is there, not just as a placeholder. Again, I mentioned we expect to use it to some extent here. It would be positive that would reduce the amount of share issuance out of that program, would be further LP drop-downs. We can't give you any specific guidance as to when or what we might put into the LP 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'll continue to look at pruning the portfolio on the margin with further asset sales. Again, nothing fully baked at this point, but we are very much focused on per-share metrics here and minimize the amount of share count growth going forward here, and those are the levers that we are looking at.

Okay. And my second question is on the Columbia projects, and then maybe more specifically the '18 ones and your commentary about leaving some docks in the environmental side. You talked about the company's highlighting project delays of FERC quorum or lack of quorum. And what are your thoughts in terms of how late you can get a order there before at '18 in service that's over to '19, for example?

Ben, it's Karl. So I guess what I'll 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, but we are encouraged that the senate is delaying the recess, and hopefully, part of the reason they're delaying the recess is to confirm some of the commissioners. If we don't get a decision by the end of the summer, it's not by any stretch material on any of these projects. So we will take a look at it. We have options, virtually in every case, to speed up construction. You can put new spreads out there. There's lots of mitigations that we have. And we will cross that bridge when we get there and decide what to do if it is delayed beyond that. But I would say, in any case, I don't think it's material. We're talking days or weeks versus months or years, and it certainly doesn't impact the status of the projects, the doability of the projects at all. So we would consider this right now to be not really a material issue at this time, and we certainly have lots of mitigations if, in fact, the decision doesn't come by the end of summer, but we are still hopeful given the process we see that it will.

The next question is from Praneeth Satish from Wells Fargo.

So Keystone's performance this quarter was pretty strong. Just trying to figure out how much of that was utilizing available stock capacity versus, I guess, more long-term contracts? Any breakdown would be helpful.

Praneeth, it's Paul Miller. Our results in Q2 were -- the increase in results were because of 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. And then just one more question. When you look at all of the spending that you're 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? And I guess more specifically, I'm just trying to figure out how this could impact flows and utilization of the GTN System?

It's Karl. Yes, so the last open season we had as part of the $2 billion announcement we just made on NGTL was a section of both receipt service and delivery service that moves gas on the GTN. Now we have contracted on long term about 400 million a day going into GTN. That will be up and running here in 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 without (inaudible) at GTN. So we will, with this next -- with implementing this latest -- this phase expansion of NGTL, we will actually fill up the remaining capacity of GTN. So we won't be having to figure out some sort of expansion on it. There is expansion capabilities on GTN. We're just not certain what that is right now, so we're in the midst of some engineering on that. But you can certainly expect another 400 million a day coming to (inaudible) of GTN once we get this to expansion complete and then we will be announcing in the future what else -- what other volumes we can get through on an expansion basis.

The next question is from Robert Hope from Scotiabank.

Maybe just moving back onto Keystone. When we look at the open season ending in September of this year, is this time line really set up by existing conversations that you're having with some of the larger producers? And then I guess second on that would be, would that be for the full Keystone XL volume that you're putting out there in that 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. And to-date, we've achieved good support from our legacy shippers, which gives us this good base to launch the open season. But the open season provides an opportunity for other nonparties to bid in for capacity and for others to assess the opportunity. So 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 in this open season. It will give us that opportunity to see what that market support is.

All right. And then just as a follow-up there, does the timing with their closing late September potentially lead to an acceleration of when you go get crews out in the field? If I recall correctly, Nebraska could come later this year, then you need some other permits. And then on Q1, I believe you said that you could get line piping put in the ground in Q3 of next year.

The open season closes in September, and there is typically about a 2-month period as you work through credit documentation, et cetera. So I would not see us in a position to know our final open season results until -- in November. And that would coincide with when we expect to receive our Nebraska decision for the route to Nebraska. And those 2 items remain the last 2 factors we're pursuing, the commercial support as well as the regulatory approval. So 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 6 to 9 months to start doing some of the staging of the construction crews, et cetera, and that would be followed by about a 2-year construction period.

The next question is from Ted Durbin from Goldman Sachs.

It sounds like you're making good progress on the long-term fixed price service with the NEB, given the schedule and whatnot. I guess I'm wondering what your thoughts are and how that is going to tie into the LDC settlement, some of the contract rolloffs that you need to deal with over the next few years as more of the -- this Marcellus gas comes into Dawn? How that might impact the ROE or the incentive structure, just kind of what your thoughts are on the -- combining those 2?

Yes. It's Karl. I guess I'll start by saying that the LTFP's is not only useful for TransCanada, it gets volumes that we thought otherwise would not flow. But it's a very important product, I think, for the WCSB producers. It does -- they did price it to -- so they can come in from the Eastern Canadian markets and beyond and compete. So it is a product that we are pursuing to get to the regulatory process and start up on November 1. How it relates to the Mainline's kind of future with the LDC settlement and so forth, I think this settlement that we did with the LDCs, I think that's actually what guaranteed the Mainline's future. The financial transaction we did it with the LDCs to move the value -- to move capital with Eastern Triangle on separates systems is I think what actually proved up the future of the Western Mainline portion. The LTFP, I think, is 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. So 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. So even though, in my belief, the financial viability of that Mainline has been preserved to that, I'm not going to sit back idly and see markets that we traditionally serve get competed away. We are going to be aggressive. We're going to move volumes in there, and we are 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. But both us and our regulators are expecting that it would be aggressive to move volumes down there. So I think it's a good first product. We have a lot of spare capacity in that Mainline. And quite frankly, I'd like to see it -- I'd like to see more gas moving down there ultimately. So we are wanting to be -- 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.

Karl, any way to quantify that? How much more beyond the 1.5 PJ/d that you've already contracted of you might be going after, coming out of Western Canada?

Well, it's good question. The supply base in Western Canada -- when you actually take a look at the reserves, it's not an even -- it's not a 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 various open seasons that we have had. So when you look at there, when you look at our long-haul system -- on the Mainline right now, we have about 8 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 6 Bcf, 6.5 Bcf a day. Now we don't have that capacity available today, because there's -- with no contracts on it. We didn't do the maintenance. We let some compressors time out and whatnot and reduced the pressure. But certainly, we have that volume [lated] in that pipeline, which is pretty cheap to get going. It just involves maintenance, really, just involves compression maintenance and integrity work in the pipeline. So there's a good opportunity to bring more WCSB gas into the Eastern Canada and Northeast U.S. If the producers are willing to compete, then I can certainly offer them a very economical solution. So there's -- what we are working on right now. Currently, today, I probably have on extra 2.7 Bcf a day contracts. I have about an extra 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. And if we go much beyond that, beyond 1 Bcf, 1.2 Bcf, I will have to strike some of that maintenance into the system.

Okay. That's great. That is very helpful. And 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 multiyear basis? If we look at the multiyear outlook you provided in February, how much of this, I guess, strength in 2017 will be recurring?

Ted, it's Don here. I think it's 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. So those we still accept -- expect them to come in around $150 million of cost synergy and $100 million to financing synergy. But I assess we -- 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 the long-term contracts. So I wouldn't describe it as a structural shift upward, but just really, really strong execution at this point of the cycle and some of the cost benefits coming through quicker than was initially envisioned.

The next question is from Andrew Kuske from Crédit Suisse.

I think the question is for Karl, and it's a little bit of a chicken and egg type of question. But 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?

Well, that's a good question. I would -- not having thought about that in advance. I would say the pace of getting regulatory permits is probably a greater moderator. These producers that -- especially in the WCSB, for example, they're very much same that goes for the Marcellus-Utica area. These producers want to serve us sooner rather than later. And if I can get quicker permits, if I can get siting instructions quicker, they would take the capacity quicker. And 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 just that it's not -- it's not lining up anymore with the production cycle of the producers. So I would say that if we can -- we're working with regulators all the time, and if we can speed up that process, I think we would actually get them launch quicker, and I think we would get more volumes.

Okay. That's helpful. And then maybe a process that looks like it might speed up in a little bit, it is just the FERC quorum issue. Maybe just specifically, where are you being held up with specific lines? Is it Mountaineer, WB XPress, Gulf Xpress? Are those really the 3 critical ones that are being held up at this stage?

Well, those are the 3 that we have going through the process right now. And 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. But as I said earlier, I think it's too early to get too worried about the quorum and whatnot. Even if it goes past this summer here, we still have lots of mitigation options if we choose to speed it up. We deal with this all the time. And again, even on the worst case, as I said, we are dealing with days and weeks, not long term. There's going to be no fundamental altering of the economics of these projects because of this quorum issue. But it is -- I've got to say that they are all expected to be in service in 2018. So let's say, I'm equally -- I'm watching them all equally as to the impact -- of an April date on that decision(inaudible) of an equally on that decision.

The next question is from Robert Catellier from CIBC Capital Markets (sic) [CIBC World Markets].

I'd like to go back to Keystone XL for a minute here. So 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 will result -- 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. So our assessment of these factors will really drive our investment decision when we get into that November-December time frame.

Okay. Just wanted to ask you a question on the dividend growth outlook. Given you've made great progress, obviously -- your coverage ratios are great, your operations are running well, financial results are coming in strong, so what are the gating factors to really extending or raising the dividend growth guidance? And maybe you could speak directly to the -- whether the ATM is a factor in that at all or the success in any one of the major projects?

I can give you a start, Robert, and then Don perhaps can add his comments as well. But I think as you know, I mean, historically, we've been very conservative in terms of giving guidance. When we have visibility of growth in earnings and cash flow that underpinned dividend growth, we have provided that guidance. And so our $26 billion capital program that we have in place today that's visible, and we're in the progress of executing -- it gives us that visibility. So 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 5 platforms of growth that Don outlined because we were seeing those projects started to come to fruition. We announced in the quarter another $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 out a lot more gas if we could build the infrastructure to get it to market. So we think that's a great platform. So 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 the interconnected between that. Can we move gas out of the Marcellus to New York and New England? Yes, we are seeing opportunities to do that. So 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. But 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. And certainly, Paul has talked about oil opportunities that exist today. So as those come to fruition, you'll see us adding to that $24 billion program, as we see here today, becoming $26 billion. As that grows, we have visibility of growth in cash flow and earnings. We will look to extend and augment our dividend guidance. Now Don, do you have anything?

Yes, I'll just -- again, it's visibility. As you know, we take a conservative view on this. We don't statistically weigh the 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 are looking at 80% to 90% of earnings. That equates to around 40% of funds generated from operations and with -- on a DCF basis, gravitating up to the high-1s, 2 area by the end of the decade on that. So we're not looking at any fundamental change there. As well, we're looking to maintain A grade credit ratings. We think that is to the benefit of all stakeholders, the ability of that at all points of the cycle. So no fundamental change on those fronts. It is really driven by greater visibility and clarity when we see real growth coming.

The next question from Nick Raza from Citi.

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?

Nick, it's Paul Miller here. We see 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 those contracts, 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. So our goal, in this open season, is to pursue those third-party long-term contracts.

And 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. But contractual underpinning coming from internal non-arm's-length parties isn't in our strategy in gas, power or liquids. Our focus is on using those entities to make sure we maximize the utilization of facilities, maximize the benefit for our company but also for our shippers as well. And that's the technology we've employed. We've been at this for a long time, and we figured out that is the best way to add value to both our customers and to our shareholders.

That's very helpful. And then 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 and 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? And if you could sort of quantify that, I know it's difficult to quantify it at this point, but assuming production as a very optimistic case, what do you think is in the backlog for that pipeline system?

Frankly, I don't know what the future builds those might be. But when I talk to the producers in that region, I guess it would be fair to say that they view Dawn to be somewhat supplied. And probably with the LTFP and the 2 proposed pipelines, they view that as a market that's probably well supplied. And their desire is to go into the U.S. Northeast, which is having some problems implementing the Gulf Coast. So yes, I would expect, looking in the future, we're going to -- 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. And I think both are getting volumes into our TCO Pool in the Midwest area, and the Gulf Coast would be the next 2 objectives. So 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.

Got you. And if I may, I'm just going to add one more. As a result of the Pacific Northwest cancellation, was there-- I know previously NGTL's backlog was pushed forward despite -- one of the conditions was removed that can Pacific NorthWest LNG should be in place. But are there any other -- or contract issues or decontracting issues on the existing NGL pipe -- NGTL pipeline us 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 condition that you talked about. We are right now with a reviewing variance from the NEB trying to lift that condition, because we have -- outside of progress, there was the initial shipper on that. Extensively, the goal to the west coast LNG. We have found 10 other shippers willing to sign very long-term contracts and wanting just to get on our base IEnova system, our NGTL System. So that one we have put an application on it to have that condition lifted. We have not heard back on the process the board is going to use for that. I am expecting it any day now, but we'll see what the board says. I guess their choice is between hearing it as a review on variance to just sort the one condition or I guess going into a new hearing for the project. But our belief is the project is already been through a hearing that's already been agreed. 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 rate and weighing and -- but just has more general customer support than what we had before.

And Nick, on a macro level, let's say, 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. But I think the other major thing that's occurred over that 4- or 5-year period is proving up the prospectively, as Karl pointed out and the cost structure of the Western Sedimentary Basin. It appears that there's a lot more gas than anybody ever anticipated that can be recovered at everly decreasing cost. So 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 America markets is becoming more and more important as these folks determine that they can produce more gas. So we're starting to see evidence of that. As you saw here in the quarter, where we announced another 3 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 America markets. That doesn't mean that we are 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. And in the shorter run, we are focused on Pacific Northwest, California, moving gas east and south out of our Western Sedimentary Basin. And NGTL is extremely well positioned to facilitate that movement.

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, and 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 lines at this time. We thank you for your participation.