TC Energy Corp (TRP) 2017 Q3 法說會逐字稿

Good day, ladies and gentlemen. Welcome to the TransCanada Corporation 2017 Third Quarter Results Conference Call.

I would now like to turn the meeting over to Mr. David Moneta, Vice President Investor Relations. Please go ahead, Mr. Moneta.

Great. Thanks very much, and good morning, everyone. I'd like to welcome you to TransCanada's 2017 Third Quarter Conference Call. With me today are Russ Girling, President and Chief Executive Officer; Don Marchand, Executive Vice President and Chief Financial Officer; Karl Johannson, President of Canada and Mexico Natural Gas Pipelines and Energy; Stan Chapman, President, U.S. Natural Gas Pipelines; Paul Miller, President, Liquids Pipelines; and Glenn Menuz, Vice President and Controller.

Russ and Don will begin today with some opening comments on our financial results and certain other company developments. A copy of the slide presentation that will accompany their remarks is available on our website at transcanada.com. 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 Mark Cooper or Brady Siemens following this call, and they'd be happy to address your questions.

(Operator Instructions) Also, we ask that you focus your questions on our industry, our corporate strategy, recent developments and key elements of our financial performance. If you have detailed questions relating to some of our smaller operations or your detailed financial models, 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. They are used to provide you with additional information on TransCanada's operating performance, liquidity and our ability to generate funds to finance our operations.

With that, I'll now turn the call over to Russ.

Thanks, David, and good morning, everyone, and thank you very much for joining us today. As highlighted in our quarterly report to shareholders released earlier today, our portfolio of high-quality, low-risk energy infrastructure assets continues to perform very, very well. Evidence of this can be seen in our solid third quarter financial results, which continue to support our Board of Directors' decision earlier this year to increase our quarterly dividend to $0.625 per share. That equates to $2.50 per share on an annual basis and represents a 10.6% increase over the dividend we paid in 2016.

During the quarter, we also continue to advance our $24 billion near-term capital program. This portfolio of commercially secured and rate-regulated projects remains largely on time and on budget. To help fund our capital program in the third quarter, we raised $1 billion to the offering of 10- and 30-year medium-term notes on very compelling terms. In addition, in October, we recovered our development costs associated with our Prince Rupert Gas Transmission project, and we agreed to sell our Ontario Solar assets. The combined proceeds from those 2 transactions at approximately $1.1 billion will be used to fund a portion of our capital program and for general corporate purposes, thereby reducing the need for external capital, including common equity.

Finally, we continue to advance certain other strategic initiatives, such as our long-term fixed price arrangements that will enhance the predictability of our earnings and cash flow while providing our Natural Gas Pipeline customers with cost-effective service to premium markets across North America.

I'll touch on each of those developments in the next few slides, beginning with a brief review of our financial results.

Excluding certain specific items, comparable earnings for the third quarter of 2017 were $614 million or $0.70 per share compared to the $622 million or $0.78 per share for the same period last year. Comparable EBITDA was $1.7 billion while comparable funds generated from operations was $1.3 billion. As highlighted in our quarterly report, while our third quarter 2017 results are lower than the amounts reported for the same period in 2016, the declines were largely attributable to the impact of issuing 60 million common shares in the fourth quarter of 2016 and the sale of our U.S. Northeast Power generation assets in the second quarter of 2017.

Effectively, in the third quarter 2017, we enjoyed the benefit of having both the Colombia and U.S. Northeast Power assets in our portfolio funded by a low-cost bridge facility pending the subsequent permanent financing of the Colombia acquisition in the form of the November 2016 equity issue and the second quarter 2017 Power generation asset sales.

Overall, the Colombia acquisition has contributed to very strong results over the first 9 months of the year, and [this] expansion projects, which is come into service over the next 12 months, will contribute to growth in cash flow and earnings for many years to come.

As highlighted on this slide, on a year-to-date basis, comparable earnings were $2.27 per share, a 12% increase when compared to the $2.02 per share reported for the same period last year. Year-to-date comparable EBITDA was also up 15% to approximately $5.5 billion, while comparable funds generated from operations were $4.2 billion, an increase of 12% over the same period last year.

Don will provide more detail on our financial results in a few moments, but before he does, I'd like to offer a few comments on some recent developments in each of our businesses, beginning with our Natural Gas Pipelines.

First on the NGTL System. We continue to see strong demand for our services with field receipts averaging of 11.4 billion cubic feet a day in 2017, up of from 11.2 billion cubic feet a day last year. At the same time, we continue to advance NGTL's $7.1 billion capital program with approximately $2 billion -- $2.3 billion of those facilities expected to enter service by the end of 2017.

In addition, we continue to seek regulatory approvals for facilities expected to enter service in 2018 and beyond. They include the North Montney project, which will connect approximately 1.5 billion cubic feet a day of new supply under 20-year transportation contracts with producers. Recently, the NEB issued a hearing order indicating that the oral portion of that hearing will begin in mid-January with a decision to follow later in 2018.

Turning to the Canadian Mainline, where we received NEB approval for our Dawn long-term fixed-price service in September. The service, which went into effect in November 1, allows us to transport 1.5 PJs or approximately 1.4 Bcf a day from Empress in Alberta to the Dawn hub in southern Ontario under 10-year contracts at a simplified toll of $0.77 per giga-joule. This service provides our customers with toll certainty and improved market access, enabling them to compete effectively with emerging supplies of natural gas from the Marcellus and Utica basins. We also had planned to invest approximately $500 million through 2019 in the portion of the Canadian Mainline referred to as Eastern Triangle to increase our capacity from Dawn to Eastern markets, including New England via our Portland Natural Gas Transmission System.

Turning to our U.S. Natural Gas Pipelines in Colombia. As I mentioned earlier, we continue to advance our $7.9 billion capital program by placing the USD 400 million Rayne Xpress project and the USD 300 million Gibraltar project into service in early November. We also expect the USD 1.6 billion Leach Xpress project to enter service in early January of 2018.

Looking forward, with the FERC having regained a quorum, we expect to receive FERC certificates for the WB Express, Mountaineer Xpress and Gulf Xpress projects in the fourth quarter of this year. All 3 projects are expected to be placed in service in 2018.

The capital cost for the Mountaineer XPress project has increased to approximately $2.6 billion due to increased construction estimates. However, as result of the cost-sharing mechanisms we have in place, overall project returns are not anticipated to be materially different than those previously expected.

Finally, in the U.S., we also advanced 2 new initiatives, the Buckeye XPress project and the Portland express project that we'll see us further expand our existing Colombia and Portland Natural Gas Transmission Systems to be growing natural gas demand.

Finally, in our Natural Gas Pipelines business. In Mexico, we continue to advance the Tula, Villa de Reyes and the Sur de Texas projects that will see us invest approximately $2.5 billion in those 3 projects with approximately $1.6 billion having spent to-date. Again, all 3 of those projects are underpinned by long-term contracts with CFE and are expected to be placed in service in 2018.

Turning to our Liquids business, where the Keystone pipeline continues to produce solid results in the quarter, largely due to contributions from the 545,000 barrels a day of long-term take or pay contracts as well as higher contributions from shorter-term volumes. We also placed the $900 million Grand Rapids pipeline into service in late August and the $1 billion Northern Courier project achieved commercial in service in November.

Turning to Keystone XL, where we continue to advance the project during the quarter following the receipt of the presidential permit in March of this year. Earlier this year, we also filed an application with the Nebraska Public Service Commission seeking approval for the pipeline route through the state of Nebraska. A public hearing on our application was held in August and the final written submissions were made in September of this year. The Nebraska PSC is reviewing all of the comments and a final decision is expected by the end of November.

On the commercial front, given the passage of time since the Keystone XL presidential permit application was previously denied in November 2015, we are updating our shipping contracts and anticipate core shipper group will be augmented with the introduction of new shippers. As part of the required process of updating our commercial agreements, in July we launched an open season to solicit additional binding commitments from interested parties for transportation of crude oil on both of the Keystone Pipeline System and the Keystone XL project from Hardisty, Alberta, to markets in Cushing, Oklahoma and the U.S. Gulf Coast. That open season closed on October 26, 2017, and we received a broad interest, and we are currently in a process of analyzing those results.

Overall, we anticipate the support for the project to be substantially similar to that which existed when we first applied for the Keystone pipeline permit. To be clear, production of Canadian heavy oil continues to grow, and the need for new pipeline transportation capacity remains high. TransCanada and its shippers continue to believe that the U.S. Gulf Coast is the largest and most attractive market for growing volumes of Canadian heavy oil, and we also believe the Keystone XL Pipeline is the safest, most efficient and most environmentally sound way to move crude oil from Western Canada to the U.S. Gulf Coast.

Finally, in our Liquids business. In October, we informed the National Energy Board that we will not be proceeding with the Energy East and Eastern Mainline projects after a careful review of changed circumstances. While it is very disappointing, we continue to progress a number of other medium to longer-term organic opportunities in our 3 core businesses, including the Keystone XL project, the Coastal GasLink project and the Bruce Power life extension program.

Turning now to Energy, where approximately 95% of our 6,200-megawatt portfolio of generating capacity is underpinned by long-term contracts with solid counter-parties. On the project front, we continue to advance construction of our $1 billion Napanee gas-powered generation facility in Ontario. That plant is expected to be completed in 2018 and is underpinned by a 20-year contract with the Ontario Independent Electricity System Operator. Bruce Power's $6 billion long-term refurbishment program also continues to progress with work on the asset management program advancing as planned in preparation for the first major component replacement, which is scheduled to commence in 2020.

And finally, in Energy, in October we agreed to sell our Ontario Solar assets for approximately $540 million. This sale allows us to serve as good value for our shareholders, assets that represented less than 2% of our generating capacity. As I mentioned, proceeds will be used to fund a portion of our capital program and for general corporate purposes, thereby reducing our need for external capital, including common equity.

Our remaining Energy assets, which includes approximately 6,200 megawatts of clean burning natural gas power generation as well as wind, nuclear, continue to be a core component of our overall asset base and are expected to generate approximately $1 billion of EBITDA in 2020, as we complete the Napanee and advance the Bruce Power refurbishment program.

In summary, during the third quarter, our high-quality portfolio of Energy assets continue to produce solid results. We continue to advance our $24 billion program, largely on time and on budget.

In total, we invested approximately $2.5 billion during the third quarter. This includes amounts related to the expansion of NGTL in Colombia as well as our Mexico Natural Gas pipeline projects, regional Liquids projects in Alberta, and the Napanee and Bruce Power projects, bringing the cumulative investment in this $24 billion program to approximately $10.4 billion. The remaining $13.5 billion required to complete these projects will be largely spent through the end of 2019, and we remain well positioned to fund this capital program.

Each of the projects is underpinned by long-term contracts or cost-of-service regulation giving us 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 continue to build on our track record of 17 consecutive years of dividend increases by growing the dividend at the upper end of 8% to 10% range through 2020. Our dividend growth outlook is supported by growth in earnings and cash flow emanating from the commissioning of [newer] facilities, which will allow us to maintain our strong, consistent 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 third quarter results. Don, over to you.

Thanks, Russ, and good morning, everyone. As outlined in our quarterly report to shareholders issued earlier today, we reported net income attributable to common shares in the third quarter of $612 million or $0.70 per share compared to a net loss of $135 million or $0.17 per share for the same period in 2016. Per-share amounts reflect the dilutive effect of having issued 60 million common shares in November 2016, plus additional shares through the dividend reinvestment program this year.

Third quarter results included an additional $12 million after-tax net loss on sales of U.S. Northeast Power generation assets related to closing adjustments, an after-tax charge of $30 million for integration-related costs associated with the acquisition of Colombia, and an $8 million after-tax charge related the maintenance of Keystone XL assets. We are now largely complete on integration-related charges with respect to the Colombia acquisition.

Third quarter 2016 included a $656 million after-tax Ravenswood goodwill impairment charge, an after-tax charge of $67 million related to cost associated with the acquisition of Colombia, recognition of $28 million of income tax recoveries resulting from a third-party sale of Keystone XL project assets, and $9 million after-tax charge related to Keystone XL maintenance and liquidation costs, and $3 million of after-tax cost related to the sale of our U.S. Northeast Power business.

All of these specific items as well as unrealized gains and losses from changes in risk management activities are excluded from comparable earnings. Comparable earnings for third quarter 2017 declined by $8 million or $0.08 per share to $614 million or $0.70 per share, largely due to the monetization of our U.S. Northeast Power generation assets in second quarter 2017 as well as the dilutive impact of share issuances last November and through our dividend reinvestment program.

As Russ indicated, the asset sales and the issuance of common shares were undertaken to help permanently fund the Colombia acquisition and retain our full ownership in the Mexico Natural Gas pipeline business, which has contributed to a 12% increase in comparable earnings per share on a year-to-date basis.

Turning to our business segment results on Slide 17. In the third quarter, comparable EBITDA from our 5 business segments was approximately $1.7 billion, $219 million lower than in the same period in 2016. The decrease was largely driven by the following factors: Canadian Natural Gas Pipelines comparable EBITDA was largely unchanged from the same period in 2016, as an increase in NGTL resulting from projects entering service was offset by a decrease from the Canadian Mainline, primarily due to depreciation on that system; 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 income and equity and incentive earnings or losses; changes in depreciation, financial charges and income taxes also affect comparable EBITDA but they 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 $11 million in the third quarter compared to the same period last year mainly due to a higher investment base and eliminated incentive earnings, partially offset by a higher carrying charges on regulatory deferrals in 2017, while net income for the Canadian mainland decreased $3 million due to a lower average investment base and lower incentive earnings.

U.S. Natural Gas Pipelines comparable EBITDA of $482 million in the quarter decreased by CAD 40 million or 9 million in U.S. dollar terms versus the same period in 2016, mainly due to the timing of funding contributions to the Colombia gas defined benefit pension plan, partially offset by increased revenue from Colombia gas growth projects and the higher ANR transportation revenues resulting from increased rates that went into effect on August 1, 2016, as part of the trade settlement. As well, a weaker U.S. dollar had a negative impact on the Canadian dollar equivalent segmented earnings from our U.S. operations.

Mexico Natural Gas Pipelines comparable EBITDA of $118 million increased $7 million compared to third quarter 2016. In U.S. dollar terms, EBITDA rose by USD 11 million primarily due to the incremental earnings from Mazatlán, which entered service, commercial service in December 2016 and equity earnings from our investment in the Sur de Texas pipeline, which records AFUDC during construction, partially offset by interest expense on an inter-affiliate loan from TransCanada to fund Sur de Texas construction. In accordance with GAAP, this interest expense in the business segment is offset by equal recognition of the income and interest income and other.

Also note that Mexico Natural Gas Pipelines comparable EBITDA was impacted by CAD 12 million impairment charge on our 46.5% equity investment in TransGas to Occidente in Colombia, which represents our last remaining non-North American based assets.

TransGas was constructed and operated under a 20-year build-own-transfer contract that was fulfilled in August 2017, at which time TransGas transferred its pipeline assets to [transport to the] Gas International SA. The impairment charge represents the write down of the remaining carrying value of the equity investment.

Liquids Pipelines' comparable EBITDA rose by $25 million to $303 million primarily as a result of higher volumes on the Keystone pipeline, a higher contribution from the Liquids marketing activities as well as initial income from the Grand Rapids pipeline, which was placed in service in late August 2017.

Energy comparable EBITDA decreased by $194 million year-over-year to $224 million, principally due to the sale of our U.S. Northeast Power generation assets in the second quarter of 2017.

Bruce Power continues to perform well with comparable EBITDA increasing $15 million from the same quarter in 2016 due to improved results from contracting activities, partially offset by lower volumes resulting from increased planned outage days.

As discussed in second quarter 2017, we are winding down our remaining U.S. Power marketing contracts and will realize their value and associated working capital over time. In the third quarter, these operations contributed comparable EBITDA of $29 million.

Now turning to the other income statement items on Slide 18. Depreciation and amortization of $506 million decreased by $21 million versus third quarter 2016 largely due to the sale of our U.S. Northeast Power generation assets, partially offset by the addition of new facilities across our segments.

Interest expense included comparable earnings of $503 million decreased by $13 million compared to the same period in 2016, mainly due to the repayment in June 2017 of the bridge facilities used to partially fund the Colombia acquisition and the impact of a weaker U.S. dollar in translating U.S. dollar-denominated interests, partially offset by new long-term debt and subordinated notes issuances.

AFUDC was $35 million higher year-over-year largely driven in Canada by investments made on the NGTL System. The increase in U.S. dollar-denominated AFUDC is primarily due to the continued investment in higher rates on Colombia projects as well as additional investments in Mexico, partially offset by the commercial in service of Topolobampo and completion of Mazatlán. With respect to the October 5, 2017, termination of Energy East and related projects, we ceased capitalizing AFUDC on the projects effective August 23, 2017, being the date of the NEB's announcement altering the terms of their assessment and expect to record an estimated $1 billion after-tax noncash charge in our fourth quarter results. As previously indicated, due to the inability to reach regulatory decision, no recovery of cost are expected from third parties.

Interest income and other included incomparable earnings rose $46 million in the third quarter compared to the same period in 2016 due to realized gains in 2017 compared to losses in 2016 on derivatives used to manage our net exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income. The interest income and foreign exchange impact related to the aforementioned [under] affiliate loan receivable from the Sur de Texas joint venture and $10 million of income recognized on the termination of the PRGT project mainly related to the recovery of carrying costs.

Regarding our 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.

Income tax expense in comparable earnings of $163 million in the third quarter 2017 decreased by $98 million compared to the same period last year mainly as a result of lower comparable pretax earnings in 2017 and changes in the proportion of income earned between Canadian and foreign jurisdictions.

And finally, preferred share dividends increased by $13 million for the 3 months ended September 30, 2017, versus the same period in 2016 due to the issuance of Series 15 preferred shares in November 2016.

Now moving to cash flow and distributable cash flow coverage ratios on Slide 19. Comparable funds generated from operations of approximately $1.3 billion in the third quarter decreased by $125 million compared to the same period in 2016, primarily due to lower comparable EBITDA, largely as a result of the sale of our U.S. Northeast Power generation assets in second quarter 2017 and increased funding for our U.S. employee post-retirement benefit plans, partially offset by higher distributions from our equity investments and an increase in interest income and other. For the third quarter, comparable distributable cash flow was $769 million or $0.88 per common share compared to $994 million or $1.25 per common share in 2016. The year-over-year decrease was primarily driven by the decline in comparable funds generated from operations and higher maintenance capital expenditures.

Comparable distributable cash flow per common share for the 3 months ended September 30, 2017, also includes the dilutive effect of issuing 60 million common shares in November 2016 as well as through DRP participation in 2017.

Maintenance capital expenditures of $442 million in the third quarter were $100 million higher than the level of spend last year. This amount includes $181 million related to our Canadian-regulated Natural Gas Pipelines, which was $85 million higher than the third quarter 2016 and is immediately reflected in the NGTL and Canadian Mainline rate basis which positively impacts net income.

As well, maintenance capital of $217 million on our U.S. Natural Gas Pipelines was $28 million higher than in the third quarter 2016. I remind you 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.

Seasonally, maintenance capital is concentrated in lower gas flow months which tend to occur in the third quarter.

Overall, our DCF coverage ratios of 1.4 in the third quarter and 1.8 year-to-date are lower than last year but trending towards the full year outlook provided in our February business update.

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

We generated $1.3 billion of comparable funds generated from operations in the third quarter and $4.2 billion on a year-to-date basis. We also completed additional external financing in the quarter on compelling terms and exited the period with approximately $1.4 billion of cash on hand.

In September, we issued $1 billion of medium-term notes in Canada comprised of $300 million maturing in 2028 at an interest rate of 3.39% and $700 million maturing in 2047 at an interest rate of 4.33%. Today, our debt is long-duration and predominantly 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.

Our dividend reinvestment plan also continues to provide incremental subordinated capital in support of our growth in credit metrics. Approximately 35% of common share dividends declared July 28, 2017, were designated to be reinvested under the DRP. Year-to-date in 2017, the participation rate the most common shareholders has been approximately 36%, representing $594 million of common equity. 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 in the United States. The use of the ATM will be 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.

In October, we received approximately $600 million from the Progress Energy in reimbursement of costs, including carrying cost, including carrying charges incurred to develop the Prince Rupert Gas Transmission pipeline following the cancellation of the Pacific NorthWest LNG project. We're also now receiving quarterly cash payments related to carrying charges on Coastal GasLink.

The pending sale of our Ontario Solar portfolio will also contribute approximately $0.5 billion that we will use to fund a portion of our growth program. As Russ mentioned, the sale of Ontario Solar was not a reflection on the role that renewable Energy has in our strategy but instead represented in an opportunity to recycle capital on attractive terms. We expect to book an after-tax gain on the sale of these portfolio of approximately $100 million upon closing which is anticipated before year end. Looking forward, we 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 funding 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 a dividend reinvestment plan access to preferred share and hybrid security markets, portfolio management, including potential drop-downs to TC PipeLines LP, project cost recoveries and the select use of the ATM as appropriate, we do not foresee any need for additional discrete equity to finance our current $24 billion portfolio of near-term growth projects.

Turning now to Slide 21. In closing, I would offer the following comments: Our financial and operational performance in the third quarter continues to highlight the diversified low-risk business strategy. The addition of the Buckeye Xpress and Portland Xpress projects demonstrates the organic growth opportunities that continue to emanate from our 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 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 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 the Q&A.

Thanks, Don. Just a reminder before we turn it over to the investment community. (Operator Instructions) With that, I'll turn it back to the conference coordinator.

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

I have a question about the mainline. I don't know if this will be, maybe addressed at your upcoming Investor Day. But I am just curious to know if you have any preliminary thoughts on how your long-term fixed-price service is going? Is it unfolding as expected? And how might this influence in any way perhaps a resetting of tools for 2018 or post-2020 as contemplated potentially a couple of years back might be required?

Linda, it's Karl. I can address the LTFP rate now. As of November 1, it started. We have -- not all contracts started this year. Some will start next year and the year after. So we have a little less than 1.3 Bcf a day scheduled into our system for the start this year. If things went well -- I see that if you checked day over day from October 31 to November 1, we saw on incremental 700 million in our system, but the full 1.3 moved because other contracts have fallen off and had not been renewed. So I consider it to be a full incremental 1.3 on our system. I think that it went well. It has cleared a large surplus off our system, which is good for the mainline. The mainline right now today is operating full. We have capacity on that mainline of about 3.8 Bcf a day, and 3.8 Bcf a day is moving a long haul out of that system, so the Western system is full. Total contracts on the system still remain about 8 Bcf a day when you take into account all the shorter contracts and delivery contracts in Eastern triangle contracts. So the mainline is operating quite well. What impact will it have on setting of new tolls? Well, we have to go to the board for 2018 to 2020 tolls. We are right now just finishing up some discussions with our shippers to see if we can get a settlement, but we are preparing ourselves to file those tolls before the end of the year so, and any tolls that we do file will be adjudicated early next year. I think, at a very high level, I can't go into any specific details, but we have accumulated over the last few years quite a surplus in our long-term adjustment account of $1.1 billion right now sits in that account, so it is clear that as we go forward with our new rates there will be some reductions in those rates moving forward, both because of the past overall collections and because when we brought the extra revenue from the long-term fixed price we never anticipated that in our original filings back in 2015. So we will have a filing for those rates before the end of the year and then you can expect some adjustments in those rates.

This as a follow-up. If your system's running effectively full, do you see maybe the possibility of some sort of expansion, whether it be related to just adding back some of the compression over the next little while? And what might that entail?

Certainly, the system isn't fully contracted for a long period of time. As other contracts fall off, and don't get picked up, there'll be capacity that comes back on the system. So there will be opportunity for people to buy more capacity if they want to, not for a couple months here as the beginning of the winter starts. But I guess one part of the comment on that is, yes, if you take a look at our entire infrastructure coming out of the WCSB from NGTL to the mainline and the volatility and prices on NGTL, which says to me when the price is that volatile the people should have find more export markets out of the WCSB, we will be looking at potential expansions of the mainline. Right now, as you are aware, we have some latent capacity in that mainline that what we have to do is we have to finish the maintenance, we have to do compression maintenance, in-line inspections, do the digs. And we can bring that capacity back on the mainline and that is something we're looking at right now as an option for our NGTL shippers who want to find extra export capacity out of the WCSB. So short answer to your question is yes, we were are taking a look at that right now.

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

Maybe I'll just continue first with the mainline. Just given the high level of contracting that you're at for 2018, are you able to give a bit of a sense as to the ability for discretionary pricing revenues and where you might expect the achieved ROE and where the LTA might move through year-end?

We have a couple of comments on that. The discretionary pricing revenues, we never actually really got a lot of revenues from discretionary pricing. From the actual pricing of share plus services itself. Discretionary pricing acted, I think, as an incentive for our customers to buy FTE contracts and it was from the additional purchase of those FTE contracts that we were able to over perform our revenue requirement and in the last couple of years, as you are probably aware of, we earned up to 11.5%, which is the maximum amount we can earn on the mainline. My expectation going into the next year -- don't forget we're going to reset all of our numbers, all of our billing terms are reset, and then these higher revenues will come into our (inaudible) setting mechanism. So is it going to be really easy to earn that 11.5%? Probably, no. I suspect as we go through the hearing and we reset all of our billing determinants, we'll have a new target set for earnable discretionary revenues. So we'll be debating with that with our customers and potential regulator here come into the new year what that new billing determinants that we have to exceed in earn incentives will be. So I think we've had a couple of good years. I think we earned those incentives. We've added a lot of value to the mainline, and it's my hope that when we come out of the hearing, and that we'll have a reasonable incentive program back in place, so that we can continue to be incented to over-perform in the system.

Got it. If I can maybe turn to the KXL. On one hand, you're still analyzing the open season results. But on the other hand, you've said that you anticipate commercial support to be substantially similar to the initial projects. So is it fair to say, based on what you're seeing in terms of the submission that you pretty much have the volumes that you need but that obviously there are some conditions and other things that you need to work through?

Rob, it's Paul Miller here. Your comment is accurate. We do have various conditions attached to the interest that we are working through those to fully understand what they need. That will take us until the end of the month, but we're quite encouraged by the results we have seen.

Okay. But in terms of the conditions, are generally none of which seems to be onerous to you?

I believe the conditions are manageable, yes.

Our next question is from Jeremy Tonet from JPMorgan.

Congratulations on the KXL results as you described them there. Just want to turn over to the wind down of U.S. Power contracts and was wondering if you might be able to share a bit more color with regards to the duration and ratability of kind of the cash flow there or should we just kind of expect volatility in results until those expire?

It's Karl. I guess I could talk a little bit about how we are winding what remains of the U.S. Northeast. We still have a book there. When I look at the earnings, we're expecting out of the book and all the credit that we put for those earnings into the book, we're looking at about $200 million, I think, that will come back to us. Probably substantially all of it. 95% of it within the next 3 years, of course weighted to the front end as we wind down that book. We are still in discussions trying to sell what remains of that book so maybe we can get it wound down a little early. To date we have not concluded anything, but we still are in discussions, so it might come a little earlier than that if we're able to sell all of it or pieces of that. I would say about 95% of it we'll see before 2020.

That's helpful. And then pivoting over to the financing side and you listed a number of options you guys have there as far as how you approach it. It seems like with this most recent asset sale, you are able to kind of get quite a nice price tag there. So just wondering, are there other opportunities like that if you could just help prioritize for us how you think about the different mechanisms. Because if I look at the TCP, I don't think they can afford that type of evaluation of assets. Maybe if you could just help me think through how this things stack up?

Yes. It's Don here. In terms of further asset sales, it's pretty high-quality portfolio that we have left here, but we're open-minded in terms of further portfolio management here. The way we look at this couple of criteria hold versus market value, strategic positioning. And tax consequences is a big thing as well. If we sold something and pay a big tax bill, it makes it less compelling to us. As we look at the stack here, top to bottom, senior debt within the A-grade credit metrics that we're targeting here, probably room for another hybrid issue in the next 12 to 18 months here of some size to bring us to near 14%, 15% of capital structure on a sustained basis there. The DRP plan will continue running through this, and we'll use the ATM as necessary to balance off the credit metrics targets, at the same time being cognizant of growing share count here. Pipe LP is business as usual. There's been no fundamental change in how we view that vehicle. It remains a key financing alternative for us going forward. It does have to compete with our alternate capital sources, including asset sales here. So it will be fluid, depending how it ebbs and flows everything from LP market conditions to business results, capital plans and the like. But what you've seen this year is probably a preview of how we're going to do things going forward. We've done, year-to-date, about $1.5 billion of senior debt, $3.5 billion of hybrids. We did an LP drop. We have some recoveries on PRGT. We had $800 million from the DRP, and just north of $5 billion of asset sales. So long way of saying it's an all of the above a strategy here but everything is in play.

Our next question is from Ben Pham with BMO.

I want to go back to the Keystone XL and you mentioned open season taking a month to analyze the bids and Nebraska approval process around the same time frame and there are some questions about timing post that in terms of what you need to do and I just wanted to check in and end of November, is there anything left there on the XL side of things for you to make an FID decision?

Ben, it's Paul Miller here. So we still have a lot to do on both those events. We are still working through the bid conditions, and that will take some time. We anticipate the Nebraska PSC approval here by the end of the month, and it will take us some time to review the decision by the PSC. So I think we let those 2 events play out, and that will give us greater visibility into our investment, final investment decision.

[Let me just add] there is certainly an urgency on the part of our shippers to come to conclusion sooner rather than later. But as Paul said, there's still some data that we don't have in yet that will go to our decision-making, but the push is currently from our group to move sooner rather than later.

And my follow-up on that, you mentioned some of the conditions imposed by shippers you think could be manageable. Are you able to share those conditions? Are they mainly driven by external events that shippers have to manage? Or is it more negotiation with how the structure of the contracts or the tolls is being discussed at the moment?

Yes. The way the open season works is we provide the contract and the terms and conditions of the contract to the marketplace, and that's what the ship is bid in to. So there's no movement of negotiations around that. It's just unique situations for different shippers that they have to navigate and work with us to help navigate that, so it really is a lot of it mechanical, logistical but all very unique to each shipper.

Our next question is from (inaudible) Crédit Suisse.

Regarding the sale of your Canadian solar asset, how do you think about sort of the positioning of the Canadian business, Power business, relative to other opportunities in your portfolio?

[Paul], this is Karl. Maybe I'll speak to that. We still have actually a pretty high-quality power portfolio within TransCanada. So you know I see the sale of the solar us an opportunity to recycle some capital, which doesn't mean that we are not going to recycle capital elsewhere. We've done both with our Natural Gas Pipelines through the LP and we've done it through selling parts of the Power business. But certainly, we have a big long-term commitment to the Bruce Power to refurbish that with our partners. And we have a very large plant, $11 billion-plus plant under construction right now at Napanee. So I would say that we look at our Canadian Power business as key and a core asset to our business going forward doesn't mean to say we won't recycle some other assets over time but I do believe it is a still pretty high-quality business that we intend to hold on to and to grow over time.

Just to augment Carl's response the power business remains a very important part of our portfolio. And what we sold here in the last 2 months is 2% of our portfolio, 76 megawatts, it wasn't a large component of our portfolio. We retained 6200 megawatts of operating assets with the addition of Napanee hear coming into 2018. That business will still be generating $1 billion of EBITDA for us. Looking forward, we believe that billions of dollars of new investment is required in the Energy business or the Power business going forward to both convert the system from a higher carbon intensity to a lower carbon intensity. That means more natural gas, more renewables and in our case, potentially more nuclear in places like Ontario. But as well with transmission, distribution as the system needs to be built out to accommodate those new resources and to replace an aging infrastructure system. So we literally see billions of dollars of opportunities ahead and those opportunities will compete for our capital in the future from our growing cash flow from our asset base. So it remains important to us, remain in the business because Karl said, as we've done with all our businesses, we will look to surface value where possible and recycle that capital to higher returns if possible. The lens with which we look at all things is through a per share return basis for our shareholders and that's the way we will continue to move forward. It's been a solid component of our portfolio for 20-plus years and will continue to be for the future.

Our next question is from Ted Durbin from Goldman Sachs.

Just on Keystone XL, we recently had an announcement that the owners of CAPP line are planning to reverse that in a few years. I wonder if that's just changed the nature of the conversation around the competition and the ability to get heavy crude down to the Gulf Coast.

Ted, it's Paul Miller here. It has not. CAPP Line reversal is near the marketplace. They're looking for nonbinding interest, it accesses a different markets. So it really hasn't had any impact on our activities around Keystone XL or any of our operating activities.

Okay. and then if I can just on the quarter itself, if we look at the Liquids results, you're up year-over-year but actually looks like tick down a little bit versus the second quarter. We would have thought you would have maybe taken advantage of some of the widening in WTI Brent to move more market length. Can you talk about the dynamics there and your ability to drive more revenue on market link given that the widening spread?

Sure. So we saw the spread widening here really into October more than September. And so we saw reduced activity on particularly on marketing business in the third quarter. And slightly reduced flows on MarketLink relative to the second quarter. In the fourth quarter, however, we have seen market activity pick up considerably, and we see flows probably in the 500,000-barrel per day range on MarketLink. We have launched an open season on MarketLink with the higher differentials. Parties have approached us with a goal to maybe term it out some space on market link. So we've launched that open season, I think it runs for about a month and I would anticipate seeing higher activity in Q4.

Our next question is from Robert Catellier with CIBC Capital Markets.

I wanted you to address the AKO price situation for a minute. As you know, there's been periods of very low AKO prices in recent months. So in your opinion, what does the industry have to do to mitigate this risk over time? And in your answer, can you please address the various stakeholder groups, including infrastructure companies, shippers as well as regulators?

Yes, Robert, it's Karl. So maybe that's a very big question so I'll try to answer it in a reasonable amount time here. Let me start by talking about TransCanada, in my view kind of the dynamics that are going on here and how our infrastructure relates to those dynamics. I think it's important to recognize that your NGTL and TransCanada NGTL specifically and TransCanada generally are partners with the producers in the WCSB. We have NGTL, we have about $8.5 billion invested into this asset. We have a $7.1 billion construction program right now and in that construction program, this November for this November 1, we put 30-odd -- 30 different projects into service to both create new receipt capacity on NGTL and to create more delivery capacity on NGTL. What we, just to be plain spoken here, what do we are seeing on the system right now and this is the [NGT] system, AKO or whatever you want to call it, is we see more supply staying in [NGT per] AKO than we see market, and that is causing supply and supply competition for the sales and that's causing extreme amount of volatility. Now I know a lot of people are out there complaining about our maintenance cuts, our cuts for installing new capacity, our use of cutting ITV for FT. But I think, when you actually step back for a second and you take a look at it, it all comes down that there is more local supply than local demand, and this is causing gas-on-gas competition, which is causing us extreme volatility as people are fighting for those internal markets. What you will find right now with this is that that volatility will moderate somewhat with the cold weather then with the start a new gas year. We see our industrial load in our system has averaged over 6 Bcf all week, and you've probably seen, if you take a look at the daily price, which I looked at for a day now, but if you look at the daily price it's probably stabilized and in good measure, because there is more demand in our system to take out this extra giga-joules. But the fact is it's fundamentally more gas fighting for a limited market. It's what's causing us volatility. Let me take a couple of comments about kind of what people are feeling about some of our operating practices, and then I'll talk about what I think the solution is. First of all, maintenance on the system. Maintenance is not new for the NGTL System. What people are seeing right now is that it's more noticeable, because 85% of our gas is concentrated in the one area versus and that's kind of the Northwest Alberta, Northeast BC System up by Montney and Duvernay. So what happens, when we do the maintenance, there's not a -- the system is not as robust as it used to be when gas was distributed throughout our entire system, and they are seeing it. One thing I will say with our maintenance and our integrity work, is the cuts generally are pretty small, and they're episodic. Depends where you are on the system. And they're getting better. We're seeing about 1/3 less cuts this year than we saw last year, for example. One of the big issues that we have had, if you recall over the last couple of years watching as this transformation of our systems took place, we -- first of all, we had people -- they were upset that we're cutting so much IT so they bought FT, and now they're upset we're cutting more IT in order to let FT flow. I could tell you the methodology that we're using when we do, do cuts is that we're trying to respect, and we've been asked by our producers, our shippers, to respect that FT cuts come last. Any IT that can be cut before FT is being cut, and that is a model that we've been asked for by our shippers to follow, and that is something that we're trying to do as best as we can to follow the fact that the sanctity of the FT contract. That has caused some grief for people who believe that some IT should have some ability to flow and it's caused some angst for people depending on what type of IT we cut. For example, if we cut delivery market IT, it can create even more competition for the market. But we do have to respect the fact that when somebody buys an FT contract, we have to make sure that all IT that can't be cut is cut before that FT contract gets cut to make way for maintenance. But I would just reiterate again that our maintenance cuts, the system, every time I put those 30 projects in and the 30 new projects next year in, those gets less and less, and people notice them less and less. So what is the solution to this? I have talked about this before, and I've talked about it with our shippers. And quite frankly, a lot of our shippers have followed this through their own marketing efforts. But the solution is to not only own FT receipt contracts, firm receipt contracts to get your gas on, but to own FT firm transmission contracts to get your gas out of the system into export markets. The FTD, we call it. FT delivery contracts. There are customers that have owned those and be completely isolated from any volatility as far as a matter of fact the volatility might work in their favor. But they are now in Dawn or they are in California or in Chicago or in the Midwest or New England or New York, depending upon where they bought the transportation contracts, too. Those are the people that have not been harmed, that have not felt this volatility or have managed to benefit from it, because they have owned capacity to get their surplus gas kilojoules out of the WCSB, where the price is depressed and lower and into higher-value markets. So if I can have advice for any customers, it's to take a look at moving your gas out of the market. We are working very hard to get more capacity out. The LTFP was one step in that. We will find more capacity on the mainline where Stan and his group in the U.S. are right now looking for more capacity on GTM to get to California and so forth. As for your contract, what is the infrastructure companies and regulators? I do think that the solution to this, the price volatility, is to build more takeaway capacity. The regulators will have a role in that, and that we've got to be able to build that capacity before too much economic damage occurs, so to speak, with volatile operators. Obviously, the regulators will have a role, as us, and other infrastructure companies come along to find solutions to it. But because I do believe the answer is to transport your gas right to market now and not sit around on an oversupplied market that is currently met. So I hope that answered your question.

Thank you for that very fulsome answer. I do have one more question for Don. You've articulated very clearly your financing strategy for existing projects with the current slate. If you are successful with Keystone XL is there 1 or 2 items in the immediate slate that's more attractive to fund that project?

A couple of comments. Should KXL proceed, we do have much of the long lead time items in inventory already, so that's just one thing to bear in mind here. Much of this deal is already in-house here. By the time we would marshal up and get construction going here, the bulk of the spend on KXL would be in the 2019-2020 time frame, which actually dovetails quite nicely with much of our $24 billion near-term program being completed, and those assets starting to cash flow. So probably this is probably more of a 2019-2020 financing story, with that asterisk that cash flow would be ramping considerably in that time frame.

Our next question is from Rob Hope with Scotiabank.

Just keeping on the Keystone XL theme. Just want to get the sense of what volume [treatments] you were targeting and then whether or not the return on the project would be, including existing capital or would it just be on new capital there?

Rob, it's Paul Miller here. When we had launched Keystone XL previously, we had contracts of about 500,000 barrels per day, and we'd be looking to target something similar, and these would be long-term 20-year contracts. And consistent with all of our large projects, we look to underpin Keystone XL with these 20-year contracts, and we'd look target appropriate returns on our total capital.

That's helpful. Excellent. And then just finally, getting back onto the NGTL System. You have announced projects year-to-date, but we still do need some capital to connect in some coal to gas conversions as well, some other expansion. Just want to get a sense of behind the scenes what do you think a run rate level of investment at the NGTL would be for the next couple of years?

That's a good question. So let me answer it this way. We need 2 investments to happen on the NGTL. Number one is we still have a queue of customers lining to get on the system for receipt services. And that queue is sitting at -- that's been a long time since I'd look at it, so I'll just talk kind of an approximate here. But it is approximately 1 billion cubic feet a day of gas sitting in the queue right now, waiting for us to come and propose the pipelines. I also am mindful of the conversation that I just had with Robert on kind of what is the solution to the oversupply in that system. And we are looking right now, and we will probably be holding some sort of open season or some sort of expression of interest for the delivery capacity to go along with that, such that we can not only bring on 1 billion cubic feet of new receipt, but tie in some of our delivery service. Delivery service on the NGTL, to get to the East Gate, for example, it is about 4.8 billion cubic feet a day. When you take a look at the math right now, it is fully utilized. We are between going into the mainline, which is right now at the 3.8 and going down to [Montney] on the northern border, which is about 1.3. We are fully utilized. As a matter of fact, we're using storage to make up the difference on that. So we need to do both. So now what does that come down to for a dollar amount. But I hate to come out and give the number a dollar, because it really depends on what where it is and what we're doing. I could be orders of magnitude [out]. But maybe what I will just say is that we have queue of Bcf a day of new receipts on it. And I would argue that we are here and then actually won't even argue I can tell you we are here looking to find Bcf to 2 Bcf a day of more delivery capacity, more capacity downstream on say GTN and or the mainline. So I'll give you the volume numbers that we're kind of looking at and then we can talk about capital as I get contractual support for it, and we get better engineering on what that looks like.

Our next question is from Thomas Abrams with Morgan Stanley.

I want to look at Slide 17, you call out some principal variance for the different segments just want to ask a couple kind of questions of those. First is in pipelines. How the size of the Colombia gas pension plan item and if that's always going to be a third quarter item or if it's something that you trued up in particular this year to minimize charges in the future?

It's Glenn here. Normally, we would just expense pension costs as everybody does. In the case of Colombia, they have a unique aspect of their [lot to prove] per FERC rate that says they will only expense pension cost as they're funded. And this is our normal funding for the year. We just didn't have any funding in it last year as part of the -- as it was transitioning in. So it's a onetime thing that you're seeing and will continue with normal funding going forward on this.

Yes, the order of magnitude is probably $0.01, $0.015 this quarter.

And question 1B is on the entry and liquids pipeline of the Grand Rapids entering service. What was the magnitude of that? And I am assuming, since it was mid-August, at least more than, at least doubles in the fourth quarter, what would be the ramp beyond that?

It's Paul Miller here. Grand Rapids contributed about $0.005 in Q3, and I would anticipate probably $0.015 in Q4.

Great. And then question 2 is the Mountaineer and Leach Xpress cost increases. $700 million between the 2 of them is pretty big. I know you'll get it back in the future but it's just a lot of capital. What happened there? Can you elaborate? And why are you confident that that's not going to continue to happen?

Yes, this is Stan. Thanks for opportunity to opine on that. Cost estimates for Mountaineer in particular have been revised due to increased construction costs, mainly tied to the high demand for resources in the region in 2018. So just as an example, across the Appalachian region, across all the projects that are being built, there's going to be over 100 pipelines spread, which is an all-time peak high for the region. And that demand for resources is what's driving the increased cost as we lock in our cost with our contractors. I should point out, however, that we do have a cost-sharing mechanism with our customers whereby 50% of the cost are shared equally between us and the customers up to a predefined cap, which will minimize the impact to our positive returns overall. So we've incorporated the lessons learned from our Leach Xpress project, which we've been constructing for this past summer and are comfortable that the $600 million represents a large part, if not all, of the cost increases with respect to the Mountaineer XPress project.

Our next question is from Faisel Khan with Citigroup.

Just wanted to figure out how you guys are thinking about your revenue requirements and/or your tariffs, how they might change in your U.S. pipelines under a lower corporate tax rate. And if you could just remind us also sort of what happened with the revenue requirement in Canada for some of your related pipes for that 10 years ago when the corporate tax rate came down, just to help us understand how things could change or may not change at all.

This is Stan. I'll start and others can jump in to the extent necessary. With respect to rate cases, we do not have any immediate rate case obligations. The first 2 would be Colombia and ANR in '19 and '20. So absent the FERC -- absent, one, the tax plan being finalized as currently is, and then two, absent FERC requiring pipelines to come in in some sort of the special proceeding to address rate reductions, those tax changes will just be incorporated into future rate cases.

It's Don here. On the Canadian side, income taxes are flowed through on a cash basis, and that's always been the case, so any interest rates -- sorry, any tax rate increases or decreases would be reflected in rates effective immediately.

Okay, got you. Just on current rate cases on the GLG rate case, is there a time when you have to go in for your next rate case done also in the northern border side can you talk about the settlement that's being offered there?

With respect to Great Lakes, there is 5-year comeback provision. However, there is not a moratorium on filing a rate case sooner should we need to do so. In the aggregate, Great Lakes represents about a 27% rate reduction, but that will largely be offset by increased revenues associated with the long-term fixed price deal as well as removal of the revenue sharing tax. So net-net on Great Lakes, we don't see material change in cash flows. The northern border rate case is not yet public. We're actually drafting that right now. The rate reduction there is much more smaller. You could think of that in terms of a upper single-digit rate reduction. But again, given some other parts of the settlement, we do not see material impacts to cash flows and revenues in that preceding year.

Our next question is from Joe Gemino with Morningstar.

Looking at maintenance capital for the quarter, can you explain why it went up from the previous quarter? And is this kind of the run rate to look at going forward?

It's Don here. I'll start and my colleagues may want to jump in as well. There is a seasonality aspect to maintenance capital. As I mentioned in my remarks, it is concentrated particularly in the U.S. in months where gas flows are lower. So that will be a recurring phenomenon there. Effectively, there's 2 major trends here. One, maintenance capital has been trending upward as the gas system gets tighter and tighter, and more money is required for reliability. The second trend, this is actually positive for us because maintenance capital, as has always been the case in Canada but increasingly so in the United States, is recoverable. It's de facto growth capital that we will earn a return on. And so yes, I'll give a little more granularity on Investor Day in terms of that, but those are the 2 major trends right now.

Our next question is from Jeremy Tonet from JPMorgan.

Just want to be real quick here. You guys were quite successful in scooping up Colombia at what appeared to be just the right time in U.S. market, and it seems like the MLP market is quite the level of distress for some players out there. So just wondering if you could provide any high-level thoughts as far as opportunities to further expand your position in the U.S. given the need of some players there to kind the migrate their balance sheet towards metrics more similar to yours?

We're chockablock full right now with things to do and places to allocate our capital. That said, there are certain assets and positions in the marketplace that we covet, and we continue to watch them, and if there's an opportunity to act, we'll do that. As Don mentioned, we have several levers. One of the reasons for maintaining our strong financial position and financial flexibility is to be able to act when opportunities do arise. But usually what we're hunting is the crown jewels of these portfolios, and they're usually the last things to be sold out of those portfolios. So I sort of roundabout, but the answer to your question is we're always interested. We have the capacity to act. But it's very rare that these opportunities arise. But if they do, we'll be prepared to act upon them.

There are no further questions registered at this time. I would like to turn the meeting over back to, Mr. Moneta.

Thanks very much and thanks to all of you for participating this morning. We very much appreciate your interest in TransCanada. We look forward to seeing many of you again later in the month as part of our Investor Day. Again, thanks very much and have a great day. Bye for now.

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