David Moneta - IR Russell Girling - President & CEO Donald Marchand - EVP & CFO Paul Miller - President, Liquids Pipelines Karl Johannson - President, Canada and Mexico Natural Gas Pipelines and Energy Stan Chapman - President, U.S. Natural Gas Pipelines Glenn Menuz - VP & Controller.

Linda Ezergailis - TD Jeremy Tonet - JP Morgan Ben Pham - BMO Capital Markets Theodore Durbin - Goldman Sachs Robert Catellier - CIBC World Markets Robert Hope - Scotiabank Tom Abrams - Morgan Stanley Faisel Khan - Citigroup Joe Gemino - Morningstar Jeremy Tonet - J.P. Morgan.

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..

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; Donald 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 Grady Semmens following this call and they would be happy to address your questions.

In order to provide everyone from the investment community with an equal opportunity to participate, we ask that you limit yourself to two questions. If you have additional questions, please reenter the queue.

Also, we ask that you focus your questions on our industry, our corporate strategy, recent developments and key elements of our financial performance. If you have detailed questions relating to some of our smaller operations or your detailed financial models, 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 asset 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 CAD 0.625 per share, that equates to a CAD 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 continued to advance our CAD 24 billion near-term capital program. This portfolio is commercially secured and regulated projects remains largely on time and on budget.

To help fund our capital program in third quarter we raised a CAD 1 billion to the offering of 10 year and 30 year medium term notes on very compelling terms. In addition in October we recovered our development cost associated with our Prince Rupert Gas Transmission project and we agreed to sell our Ontario solar assets.

The combined proceeds from those two transactions of approximately CAD 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 and stability of our earnings and cash flow while providing our natural gas pipeline customers with cost effective service to premium markets across North America.

I will catch on each of those developments in the next few slides, beginning with the brief review of our financial results. Excluding certain specific items, comparable earnings for the third quarter of 2017 were CAD 614 million or CAD 0.70 per share compared to the CAD 622 million or CAD 0.78 per share for the same period last year.

Comparable EBITDA was CAD 1.7 billion while comparable funds generated from operations was CAD 1.3 billion. As highlighted in our quarterly report, 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. North East power generation assets in the second quarter of 2017. Effectively, in the third quarter 2016 we enjoyed the benefit of having both the Columbia and U.S.

North East power assets in our portfolio funded by a low cost bridge facility pending the subsequent permanent financing of the Columbia acquisition in the form of the November 2016 equity issue and the second quarter 2017 power generation assets sales.

Overall, the Columbia acquisition has contributed to very strong results over the first nine months of the year and these expansion projects which largely 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 CAD 2.27 per share, or 12% increase when compared to the CAD 2.02 per share reported for the same period last year.

Year-to-date, comparable EBITDA was also up 15% to approximately CAD 5.5 billion while comparable funds generated from operations were CAD 4.2 billion, an increase of 12% over the same period last year. Don will provide more details 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 from 11.2 cubic feet a day last year.

At the same time, we continue to advance NGTL's CAD 7.1 billion capital program with approximately CAD 2.3 billion of those facilities expected to enter service by the end of 2017. In addition we continue to 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 at 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 Canadian Mainline where we received NEB approval for Dawn long term fixed price service in September. The service which went into effect 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 ten year contracts at a simplified tool of 0.77 per gigajoule.

This service provides our customers with total certainty and improved market access enabling them to compete effectively with emerging supplies of natural gas from the Marcellus and Utica basins.

We also plan to invest approximately CAD 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. Turing to our U.S.

natural gas pipelines in Columbia, as I mentioned earlier we continue to advance our CAD 7.9 billion capital program by placing the $400 million U.S. rain express project and the $300 million U.S. Gibraltar project into service in early November. We also expect the $1.6 billion U.S. Leach XPress project into service in early January of 2018.

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

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

Finally in the U.S., we also advanced two new initiatives [indiscernible] XPress project and the Portland XPress project that will see us further expand our existing Colombian and Portland Natural gas transmission system to meet growing natural gas demand.

Finally, in our natural gas pipeline business in Mexico we continue to advance the Tula, Villa de Reyes, and the Sur de Texas projects that will see us invest approximately US$2.5 billion in those three projects with approximately US$1.6 billion having been spent to-date.

Again all those of three projects are underpinned by long term contracts with CFE and are expected to be placed in service in 2018.

Turning to our liquid business where the Keystone pipeline continues to produce solid results in the quarter and largely due to contributions from the 545,000 barrels a day of long-term take or pay contract as well as higher contributions from shorter-term volumes.

We also placed the CAD 900 million Grand Rapids pipeline into service in late August and the CAD 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 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 final written submissions were made in September of this year.

Nebraska PSC is reviewing all the comments and a final decision is expected by the end of November.

On the commercial front given the passage of times since the Keystone XL presidential permit application was previously denied in November 2015, we are updating our shipping contract 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 the Keystone pipeline system and Keystone XL project from parts of the 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 the process of analyzing those results. Overall, we anticipate the support for the project to be substantially similar to that which existed when you 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 it's shippers continue to believe that U.S.

Gulf coast is the largest and most attractive market for growing volumes of Canadian heavy oil and we also believe that the Keystone XL pipeline is the safest, most efficient and most environmentally sound way to move that crude oil to from Western Canada to the U.S. Gulf Coast.

Finally, in our liquid business in October we informed the National Energy Board that we will not be proceeding with the energies and Easter mainline projects after a careful review of changed circumstances.

Well, this is very disappointing pointing we continue to progress a number of other medium and longer-term organic opportunities in our three core businesses including the Keystone XL project, the [indiscernible] project and the Bruce Power life extension program.

Turning now to energy where approximately 95% of our 6200 MW portfolio of generating capacity is underpinned by long-term contracts with solid counter parties. On the project fund, we continue to advance construction of CAD 1 billion Japanese Gaspar 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 CAD 6 billion long-term refreshment programs also continue to progress with work on asset management program plan 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 sale our Ontario solar assets for approximately CAD 540 million. This sale allowed us to surface 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 the capital program and for general purposes thereby reducing our need for external capital including common inequities.

Our remaining energy assets which includes approximately 6200 MW of clean burning natural gas-fired generation as well as wind, nuclear continue to be a core component of our overall asset base and are expected to generate approximately CAD 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 asset continue to produce solid results. We continue to advance a CAD 24 billion program largely on time and on budget. In total we invested approximately CAD 2.5 billion during the third quarter.

This includes amounts related to the expansion of NGTL in Columbia as well as the Mexican natural gas pipeline projects, regional liquids projects in Alberta and then Napanee and Bruce Power projects bringing the cumulative investment in this CAD 24 billion program to approximately CAD 10.4 billion.

The remaining CAD 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 a track record of 17 consecutive years of dividend increases by growing the dividend at the upper end 8% to 10% range through 2020.

Our dividend growth outlook is supported by growth in earnings and cash flow emanating from the commissioning of new US facilities which will allow us to maintain our strong, consistent dividend payout coverage ratios.

That concludes my prepared remarks and I'll turn the call over to Don for some additional comments on our third quarter results, Don?.

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 in the Canadian Mainline primarily due to depreciation on that system.

Net income and comparable EBITDA for a rate regulated Canadian Natural Gas Pipelines’ are generally affected by our approved ROE, our investment base are level with the income and equity and incentive earnings or losses.

Changes and 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 to $11 million in the third quarter compared to the same period last year mainly due to a higher investment base and eliminate incentive earnings, partially offset by higher carrying charges on regulatory deferrals in 2017 when net income for the Canadian Mainline decreased $3 million due to a lower average investment base and lower incentive earnings.

The US Natural Gas Pipelines’ comparable EBITDA of $482 million in the quarter decreased by CAD$40 million or 9 million U.S.

dollar terms versus the same period in 2016 mainly due to the timing of funding contributions to the Columbia Gas to find benefit pension plan partially offset by increased revenue from Colombia Gas growth projects and higher ANR transportation revenues resulting from increased rates that went into effect on August 1st 2016 as part of 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 were $118 million increased $7 million compared to third quarter 2016. In U.S.

dollar terms EBITDA rose by $11 million primarily due to the incremental earnings from Mazatlán which entered 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 interest expense on an intra-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 in interest income and other.

Also note that Mexico Natural Gas Pipelines’ comparable EBITDA was impacted by a Canadian $12 impairment charge on our 46.5% equity investment in TransGas de Occidente in Colombia which represents our last remaining non-North American based asset.

TransGas was constructed and operated under a 20 year build on transfer contract that was fulfilled in August 2017 at which time TransGas transferred its pipeline assets to transport to [indiscernible] the gas international SA. Impairment charge represents the write-down of the remaining caring value of the equity investments.

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 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 dollars in the same quarter in 2016 do improve 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 in 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 the weaker U.S. dollar in translating U.S.

dollar denominated interest 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 the US dollar denominated AFUDC is primarily due to the continued investment and higher rates on Columbia projects as well as additional investment in Mexico partially offset by the commercial in service of Topolobampo and completion of Mazatlán.

With respect to the October 5th, 2017 terminations of Energy East and related projects we see as capitalizing AFUDC on the projects effective August 23rd 2017 being the date of NEB’s announcement altering the terms of their assessment and expect to record an estimated $1 billion after tax non-cash charge in our fourth quarter results.

As previously indicated due to the inability to reach a regulatory decision, no recoveries of costs are expected from third parties.

Interesting comment other included in comparable 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 in foreign exchange impact related to the aforementioned the affiliate loan receivable from the Sur de Texas joint venture and $10 million of income recognized on the terminations of the PRGT mainly related to the recovery of carrying costs. Regarding our sensitivity to foreign exchange rates, our U.S.

dollar denominated assets including our interest in Mexico are predominantly hedge 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 and comparable earnings of 163 million in 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 three months ended September 30th 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 nineteen, comparable funds generated from operations of approximately $1.3 billion in the third quarter decreased by a $125 million compared to the same period in 2016, primarily due to the lower comparable EBITDA largely as a result of the sale of our U.S.

Northeast Power Generation assets in second quarter 2017, an 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 a $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 three months ended September 30th 2017 also includes the dilutive effect of issuing 60 million common shares in November 2016 as well as through direct participation in 2017.

Maintenance capital expenditures of $442 million in the quarter were $100 million higher than the level of stand 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 main its capital of $217 million on our U.S. Natural Gas Pipelines was twenty $28 million higher than in the third quarter 2016. I reminder you that ANR maintenance capital is expected to be at elevated levels through the balance of 2017 and 2018 and will earn a return up 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 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 leavers 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 to medium term notes in Canada comprised of $200 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, as long our debt as long duration and predominantly fixed rate in nature with an average coupon of 5.3% 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 and credit metrics, approximate 35% of common share dividends declared July 2017 were designated to be reinvested under the drip, year-to-date in 2017 the participation rate amongst 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 Progress Energy in reimbursement of costs, including carrying charges incurred to develop the Prince Rupert Gas Transmission Pipeline following the cancellation of the Pacific Northwest L&G Project.

We are also now receiving quarterly cash payments related to carrying charges on coastal gas link. The pending sale of our Ontario solar portfolio will also contribute approximately half a billion dollars 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 an opportunity to recycle capital on attractive terms. We expect the book after tax gain on the sale of this portfolio at approximately $100 million dollars upon closing which is anticipated before yearend.

Looking forward, we expect a continued access to senior debt hybrid 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, in the clear, accretive and credit supportive use of proceeds.

With the dividend reinvestment plan, access to preferred share and hybrid security markets, portfolio management, including potential dropdowns 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 CAD24 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 third quarter continues to highlight the diversified low risk business strategy.

The addition of [indiscernible] expansion and Portland express projects demonstrate the organic growth opportunities that continue to emanate from our broad strategically located asset base. Today, we are advancing a CAD 24 billion near-term capital program and have five distinct platforms for future growth in Canadian, U.S.

and Mexico Natural Gas Pipelines, Liquids Pipelines and Energy. Our overall financial position remains strong supported by our A-grade credit ratings and a straightforward corporate structure.

We remain well-positioned to fund our near-term capital program through 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 in high quality earnings and cash flow for our shareholders.

That is expected to support annual dividend growth at the upper end of an 8% 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. Just a reminder before I turn it over to the conference coordinator for questions from the investment community, we ask that you limit yourself two questions and if you have any additional questions, we would ask that you please re-enter the queue. With that, I will turn it back to the conference coordinator..

Thank you. We will now take questions from the telephone line. [Operator Instructions] Thank you for your patience. Our first question is from Linda Ezergailis with TD. Please go ahead. .

Thank you.

I have a question about the main line, I don't know if this will be, maybe addressed at your upcoming Investor Day but I'm 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 how might this influence in any way perhaps a resetting of tolls for 2018 or post-2020 as contemplated potentially a couple years back might be required?.

I can answer our TSP right now.

As a November 1st, it started we have, not all contracts started this year some will start next year and thereafter so we had a but little less than one 1.3 BCF a day as scheduled into our system for the start this year, if things went well I see that if you day over day from October 31st to November 1st, we saw an incremental or 700 million on our system but the full 1.3 moved because other contracts have fallen off and had not renewed.

So I consider it to be a full incremental 1.3 on our system.

I think that it is well, it is clear to a large surplus up our system which I think has been good for the mainline, the mainline right now today is operating full, we have capacity on that mainline is about 3.8 BCF a day, a 3.8 BCF a day is moving along, over that systems, 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 to other contract in eastern triangle contract so the mainline is operating quite well.

What impact it would have on, I am setting a visuals, well we have to go to the board for 2018 to 2022, we are right now just finishing up some discussions whether [indiscernible] receive if we can get a settlement but we are preparing ourselves to file those tolls before the end of the year.

So any tolls that we do file will be adjudicated early next year, I think a very high level I can't go into specific details but we have a chain might it over last three years quite a surplus in our in our long term adjustment account one point one billion dollars right now since I get out so it is clear that that as we go forward with our new Waitstill be some reductions in those rates or because of the past.

Over collections and because when we're we brought the extra few extra revenue from a lot. My expectation going into next year don't forget we’re going to reset all of our numbers, all of our billing determine as a reset and then these higher revenues will come into our set of setting mechanisms.

So it is going to be really easy during the 11.5% probably no. I suspect as we go through the hearing and we reset all of our billing determine and see that we will have a new target set for earning those discretionary revenue.

So we will be debating with our customers and potentially the regulators here coming in New Year as to what that new, with the new billing determine so we have to exceed in order and incentives will be. So I think we have had a couple of good years, I think we are aware of those incentives.

We have had a lot of values to the Mainline and this is my hope that when we come out hearing that we will have a reasonable center program back in place so that we can continue to be accepted to over perform on this system..

Got it.

If I can then maybe turn to Key XL, so one hand you are still analyzing the open season results but on the other hand you have said that you anticipate commercial support be substantially similar to the initial projects so is that fair to say based on what you are seeing in terms of the submissions that you pretty much have the volumes that you need but that obviously there is some conditions or other things that you need to work through?.

Yes Robert, 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 mean that will take us till the end of the month but we are quite encouraged by the results we have seen..

Okay but in terms of the conditions or generally none of which seem to be onerous to you?.

I believe the conditions are manageable. Yes..

Okay, that's great. Thank you..

Thanks Robert..

Thank you. Our next question is from Jeremy Tonet with JP Morgan. Please go ahead..

Good morning. Congratulations on the Key XL result as you described them there. Was just wanted turnover to the wind down of U.S.

power contracts and I was wondering if you might be able to share a bit more color with regards to the duration in ratability kind of the cash flow there or should we just kind of expect volatility in results until those expire?.

So, it's Karl.

I guess I could talk a little bit about kind of how we are winding down, what remains of the start is we still are a buff there, when I look kind of the earnings that we are expecting out of the book and all the credit that we put for those earnings and the book, we are looking about CAD 200 million I think that will come back to us probably substantially all of it 95% of it within next few years, of course, weighted to the front end as we went down that book.

We are still in discussions trying to sell what remains the book so maybe we can get a wind down little early. Today we have not concluded anything but we still are in discussion so it might come a little earlier than that if we are able to sell all of it or pieces of it on that but I would say about 95% of it we will see before qualifying..

That's helpful. Thank you and then peeping over to the financing side and listed a number of options that 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 what are the - are there other opportunities like that and if you could just help prioritize for us how you think about the different mechanisms because when I look at TCP I don't think they get a full that type of evaluation assets.

Maybe you could just help me think through how these things stack up?.

Yes it’s Don here. In terms of further assets sales it's pretty high quality portfolio that we have left here. But we are open minded in terms of further portfolio management here. The way we look at this couple of criteria whole versus market value strategic positioning and tax consequence is a big thing as well.

If we sell something and pay a big cash tax bill it makes us certainly less compelling to us.

As we look at the stack here, top to bottom senior debt within the A grade credit metrics that we are targeting here probably room for another hybrid issue in the next 12 to 18 months here of some size to branch to 14%, 15% of capital structure on the sustained basis there.

The drip plan will continue running through this and then will use the ATM as necessary to balance off the credit metric targets, at the same time being cognizant of growing share count here. Pipe LP’s business is usual. There has been no fundamental change in how we view that vehicle. That 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 ebbs and flows of everything from LP market conditions to business results, capital plans and alike, but what you have seen this year is probably a preview of how we are going to do things going forward we have done year-to-date about 1.5 billion of senior debt, 3.5 billion of hybrids.

We did the hybrids we did an LP drop. We have some recoveries on peer GT, we had 800 million from the drip and just north of CAD 5 billion of asset sales, so long way to way of saying it’s all the above strategy here but everything is in play..

That's all helpful. Thank you very much..

Thanks Jeremy..

Thank you. Our next question is from Ben Pham from BMO Capital Markets (Canada). Please go ahead..

Thanks.

I wanted to go back to the Keystone XL and you mentioned have been season taken a month to analyze the debt and Nebraska approval process around the same time frame and there are some questions about timing post that what you need to do and I just wanted to check in and end of November is there anything left there on that sale side of things for either making up a decision?.

Ben, it's Paul Miller here. So we still have a lot of work to do on both of 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 left those two events play out and that will give us greater visibility into our investment, final investment decision..

Let me just add Ben. There is certainly urgency on the part of our shippers to come to conclusion sooner or rather than later but as Paul said, there is still some data that we don't have in yet that they will go into decision making but they are the pushes currently from our shipper group to move sooner rather than later..

And then my follow up on that you mentioned some of the conditions imposed by shippers you think is 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 without the structure of the contract or the poll 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 where the shippers bid into. So there is no movement or 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 lot of mechanical logistical but all are very unique teach shipper..

Okay. I think that's helpful. Thank you..

Thanks Ben..

Thank you. Our next question is from [indiscernible] with Credit Suisse. Please go ahead..

Hi, good morning.

Regarding the sales 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?.

Well this is Karl. Maybe I will speak to that. We still have actually pretty high quality power portfolio within TransCanada. So I see the sale of solar as an opportunity to recycle some capital which doesn't mean we are not going to recycle capital elsewhere.

We have done it both with our natural gas pipeline, through the LP and we have done it through selling parts to the prior 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 going into the billion plus dollar plant.

The structure right now is happening, so I would say that we look at our Canadian power business as a key and core aspect of our business going forward. It doesn't mean to say that we won’t recycle some other assets in its overtime but I do believe it’s a still pretty high quality business that we intend to hold on to and to grow overtime..

Just to augment Karl’s response the power business remains a very important part of your portfolio. And what we still appear in the last two months is 2% of our portfolio.

76 MW wasn't a large component of other portfolio, we retained 6200 MW of operating assets with the addition of Napanee here coming into 2018 that business will still be generating a billion dollars of EBITDA for us.

Looking forward we believe that billions of dollars of new investment is required in the energy business where they have the power business going forward to both convert the system from a higher carbon intensity to lower carbon intensity for a more natural gas, more renewable and in our case potentially more molecular in places like Ontario but as well with transmission, distribution as system needs to be built to accommodate those news resources and to replace an aging infrastructure system.

So we literally see billions of dollars of opportunities ahead. And those opportunities will compete for capital in the future from our growing cash flow from our asset base.

So it remains important to us, remain in the business as Karl said, as we have done with all of our businesses we will look to surface value where possible recycle that capital to higher returns if possible.

The wins of which we look at all of things is through a per share return basis for our shareholders and that’s the way that we will continue to move forward and it’s always component of our portfolio for 20 plus years and will continue to be for the future..

Great. Thank you very much..

Thanks Paul..

Thank you. Our next question is from Theodore Durbin of Goldman Sachs & Co. LLC. Please go ahead..

Thanks.

Just on Keystone, so we recently had announcement that the owners of cap-line are playing too reverse that in a few years and I wonder if that's 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, cap line reversal is near the marketplace there, looking for non-binding interest rate access as a different market 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 were up year-over-year but actually if I can tick down a little bit for second quarter we would have thought you would have maybe taken advantage of some of the widening in WTI brand to move more market, like maybe you can just talk about the dynamics there and the ability to drive more revenue on market link given that widening spread?.

Sure. So we saw the spread widening here really into October more than September and so we saw reduced activity particularly on marketing business in the third quarter. And slightly reduced flows on market link 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 market length. We have launched an open season on market length with the higher differentials parties have approached us with the goal to maybe terming out some space on market length.

So we have launched that open season I think it runs for about a month and I would anticipate seeing higher activity in Q4..

Okay. That's helpful. Thank you..

You are welcome..

Thank you. Our next question is from Robert Catellier with CIBC World Markets, Inc. please go ahead..

Hi, good morning. I wanted you to address the echo price situation for minute.

As you know there has been periods of very low echo prices in recent months, so in your option what is the industry have to do to mitigate this risk overtime and then your answer can be please address the various stakeholders groups including infrastructure companies, shippers as well as regulators?.

Yes Robert it's Karl. So maybe that's very repeat question so I will try to answer them in a reasonable amount of time here. And let me start by talking about kind of, in my view kind of dynamics that are going on here and how infrastructure relates those that dynamics.

I think it's important to recognize that NGTL and TransCanada, NGTL specifically and TransCanada generally are partners with the producers in the WCSB. We have in NGTL, we have already 1.5 billion invested, net invested into asset with we have 7.1 billion dollar structuring program right now.

And in that structuring program this November, for this November 1, we put 30 odd, 30 different projects in the service to both create new, receipt capacity on NGTL and to create more delivery capacity on NGTL.

What we wanted to be, just to be plain spoken here what we are saying on this system right now and this is the net system echo whatever you want to call it, is we see more supply staying in net or echo than we see market. And that is causing supply and supply competition for the sales and that is causing extreme amount of volatility.

Now I know lot of people are out there complaining about kind of maintenance cuts or cuts for installing the capacity or use of cutting IT before FT but I think when you actually step back for a second you take a look at it, it all comes down to there is no local supply than multiple demand.

And this is causing some gas competition which is causing extreme volatility as people are fighting for those internal markets. What you will find right now with this is that you will level to or moderate someone with the cold weather and let's try the new gas here.

We see our industrial load in our system is average or over 6 pcf per week and you probably seen if you take a look at the daily price which I haven't looked at for a day now but if you look at the daily price it’s probably stabilized and good measure because there is more demand on our systems take up these statement gigajoules.

But the fact is you will say it's fundamentally more gas fighting for a limited market and this is what's causing us volatility, now begin off look - let me take couple of -- just couple of comments about kind of what people are feeling about customer operating practice and then I will 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 more noticeable because 85% of our gas is concentrated in one area versus that's kind of the Northwest [indiscernible] so what happens when we do maintenance there is no t -- the system isn't robust as it used to be with the - when gas is distributed through our entire system. And they are seeing.

One thing I will say with our maintenance and our integrity work is that we are - the cuts generally are pretty small and it depends on where you are at the system and they are getting better. We are seeing about one third less cuts this year than we saw last year for example.

What are the big issues that we have had is if you recall over the last couple of years watching as this transformational it’s just in the place we first of all we had people they are upset, they were cutting so much IT so they bought FT and now they are upset we are cutting more IT in order to let FT flow.

I can tell you the methodology that we are using when we do the cuts is that we are trying to respect and we have 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 have been asked for by our shippers to follow and that's is something that we are trying to do as best as we can to follow the fact that affectivity of the FT contract.

That has caused some brief for people who believe that some IT should have - and it has caused some extra people depending upon 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 if somebody buys an FT contract we have to make sure that all IT that can be cut is cut before that FT contract get cuts to make way for maintenance.

But I would just reiterate again that our maintenance cuts, the system every time you have those 30 projects in and 13 projects next year end those maintenance cuts gets less and less and people notice some less and less.

So what is the solution to this? Well, I’ve talked about this before and I’ve talked about it with our shippers and quite frankly a lot of our shippers follow this through their own marketing efforts.

But the solution is not only own FT receipt contracts for receipts contracts gets the gas lock but to own FT for - which is contracts to get your gas out of the system and to export markets.

The FTB recall, FT delivery contracts there are customers that are all knows be completely isolated from volatility, as a matter of fact the volatility might worked there in their favorite but they are now in Dawn or they are in California or they are in Chicago or are they in the Mid West or New England and New York to get upon where they bought the transportation contracts too.

Those are the people that have not be armed - that have not felt this volatility or manage the benefit because they have owned capacity to get their surplus gas schedules out of the WCSB where the price depressed lower and into higher value market.

So that if I can have the base for any of our customers is to take a look and moving your gas out of the market. We are working very hard to get market capacity, the LTFP was one step in that. We will apply more capacity on the mainline where Stan and his group in the U.S.

are right now looking at more capacity on GTN to get the California and so forth. As we contract on what does the infrastructure companies and regulators, I do think that the solution to this with the price volatility is to build more tickly capacity.

The regulators will have a role in that and that we got to be able to build that capacity before too much economic damage occurs so to speak with volatile places. So obviously the regulators will have a role as us and other infrastructure companies come along to find solutions to it.

And but because I do believe the answer is to transport your gas out right to market Allen, not sitting around and over supply market that is currently mix. So I hope that answered your question..

Yes. Thank you for that very fulsome answer. I do have one more question for Don.

You have articulated very clearly your financing strategy for existing projects the current slate, if you’re successful with Keystone XL is there one or two items in the immediate slate of financing options that's more attractive to the fund that project?.

Couple of comments should kiosk, I’ll 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 -- is already in house here.

By the time we would marshal up and get construction going here, the bulk of the spend on cash would be in 2019-2020 timeframe which actually dovetails quite nicely with much of our CAD 24 billion near term program being completed and those assets starting to cash flow.

So this is probably more of a 2019-2020 financing story with that aster is that cash flow would be ramping considerably in that timeframe..

Okay. Thank you..

Thanks Russ..

Thank you. Our next question is from Robert Hope with Scotiabank. Please go ahead..

Yes. Good morning.

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

Hey 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 would be looking to target something similar and this would be long term 20 years contract.

And consistent with all of our large project we looked underpinned Keystone XL with this 20 year contracts and we look to target, hope it returns on our total capital..

Alright. That is helpful. Excellent and then just finally getting back on to the NGTL system, you have announced projects year-to-date but we still do need some capital to connect and pull the gas conversions as well from other expansions.

Just want to get a sense of behind the scenes or what do you think a run rate level investment at the NGTL would be for the next couple of years?.

You know that's a good question. Now let me answer it this way. We need two investments to happen on the NGTL. Number one is we still have the queue of customers wanting to get on the system for receipt services and that queue is sitting at and it's been lot of times I’ve looked at it, so I will just stop kind of approximately here.

But this is approximately billing gas is sitting. They are sitting in the queue right now waiting for us to come and propose buybacks. I also am mindful of that conversation that I have just had with Robert on kind of what is the solution to the oversupply and the net system.

And then we are looking right now and we will probably be holding some sort of open season or some sort of special interest for the delivery capacity to go along with that. So we can not only bring on billing cubic feet of new receipt but tie in some delivery service.

So delivery service on the NGTL to get to the use case for example 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 now 3.8 and going down much on northern border which is about 1.3, we are fully utilized as a matter of fact we are using stories to make up the difference on that. So we need to do both.

So what is that come down to for dollar amount, I hate to come out and give the numbers in dollar because it really depends where it is and what we are doing.

I could be orders of magnitudes maybe I will just say is that we have bcf a day receipts on it and I would argue that we are here actually I will not argue I can tell you argue looking to find a bcf a day more delivering capacity and more capacity downstream say on GTN and or the mainline.

So I will give you the volume numbers that kind of look in at that and then we can we will talk about capital as I get contractual forward in, I get better engineering or what that looks like..

That's helpful. Thank you..

Thanks Rob..

Thank you. Our next question is from Tom Abrams with Morgan Stanley. Please go ahead..

Thank you and thank you for your patience hanging there with us today. I want to look at slide 17, you call some principal variances for the different segments. Just wanted to ask a couple questions on those. First is in pipelines.

How the size of the Columbia gas pension plan item and if that's always going to be third quarter item or if it's something that you trued up and particularly this year to minimize charges in the future?.

Yes. It's Glenn here. Normally we would just expect pension costs as everybody does. In the case of permit they have unique aspect of their last rate that says it will only expense engine cost as refunded and this is our normal funding for the year. We just didn't have any funding last year as part of the - as it was transitioning.

So it's one time thing that you are seeing and we will continue with normal finding going forward on this..

Yes. Order magnitude probably a penny and penny and a half this quarter..

Okay.

And question on B is on the entry, pipeline Grand Rapids entry service what was magnitude of that and I am assuming since this was mid august based at least more than maybe at least doubles I the fourth quarter only the ramp behind that?.

Hi Tom it's Paul Miller here. Grand Rapids contributed about half a penny in Q3 and I would anticipate probably a penny and half in Q4..

Great. And then question two is the amount in the air and Leach XPress cost increases $700 million between the two of them is pretty big. I know you have got back in the future but it 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 the opportunity to opine on that. Cost estimates for Mountaineer particularly had been revised due to increased construction costs mainly tied to the high demand for resources in the region in 2018.

So it just as an example across the Appalachian region across all the projects that are being built, this is 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 increase cost as we lock in our costs with our contractor.

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 pre-defined cap which will minimize the impact to our project returns overall. So we have incorporated.

We have lessons learned from our Leach XPress project which we have been constructing for this past summer and are comfortable that the CAD 600 million represents a large part that all of the cost increases with respect to the Mountaineer express project..

Great. I appreciate it guys. Thanks a lot..

Thanks Tom..

Thank you. Our next question is from Faisel Khan with Citigroup. Please go ahead..

Thank you. Thanks for taking my question here. I just wanted to figure out how you guys are seeking about your revenue requirement, hinder your cares how they might change U.S.

pipelines under a lower corporate tax rate and if you could remind also sort of what happened with the revenue requirement in Canada for some of the regulated pipes ten years ago when the corporate tax rate came down.

Just help us understand how things could change or may not change at all?.

Faisel, this is Stan, I will start another jump into the extent necessary. With respect to rate cases, we do not have any immediate rate case obligations. The first two would be Columbia and ANR in 19 and 20.

So absent one, the tax plan being finalized is currently yes, and then absent FERC requiring pipeline to come in, in some sort of a special proceeding to address rate reductions those tax changes would just be incorporated into the future rate cases..

It's Don here. On the Canadian side income taxes are full 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 effectively immediately..

Okay.

Got you and then just on current rate cases on the GLGT rate case is there a time when you have to go in for your next rate case and then stuck on the northern border side and if you can talk about the settlement that thing offered there?.

Yes. With respect to great lakes there is a five year comeback provision however, there is not a more [indiscernible] I’m founding in rate cases sooner should we need to do so.

In the aggregate that great lakes represent the about 27% rate reduction but that will largely be offset by increased revenues associated with the long term fixed price field as well as removal of the revenue sharing cap. So net:net on great Lake, so we don't see material changes in cash flows. The Northern Border right case is not yet public.

We are actually drafting that right now. The rate reduction there is much more smaller. You can think of that in terms of a upper single-digit rate reduction but again, given some other parts to settlement we do not see material impact to cash flows of revenues in that proceeding either..

Great, thanks for the time guys. I appreciate it..

Thanks Faisel..

Thank you. Our next question is from Joe Gemino with Morningstar. Please go ahead..

Great. Thank you.

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 will start and Mike is going 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 recurring phenomena there. But effectively there is two major trends here.

One maintenance capital has been trending upward as the gas system gets tighter and tighter and more money is required for the liability.

And the second trend this is actually positive for us because maintenance capital has always been the case in Canada but increasingly so in the United States is recoverable, it's to factor a growth capital that we will earn a return on and on.

So I will give a little more granularity on Investor Day in terms of that but those are the two major trends right now..

Great, thank you..

Thanks very much, Joe..

Thank you. Our next question is a follow up question from Jeremy Tonet with J.P. Morgan. Please go ahead..

Thanks. Just want to be real quick here and you guys were quite successful in scooping on Columbia what appear to be just the right time in the U.S. market. It sees that MLP market is quite a level of distress for some players out there.

So just wondering if you can 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 of migrate their balance sheet towards metrics more similar to yours? Thanks..

I think Jeremy as we’ve always said, I mean, we’re a chalk a block full right now with things to do and places to allocate our capital. That said there are certain aspects and positions in the marketplace that we covered and we continue to watch them and if there is an opportunity to act we will do that.

As Don mentioned we’ve several levers and the reasons for maintaining our strong financial position and natural flexibility is to be able to act when opportunities do arrive.

But usually what we’re hunting is the crown jewels of these portfolios and that there usually the last thing to be sold out of those, so I sort of round about to answer your question is, we’re always interested, we’ve the capacity to act, but it’s very rare that these opportunities arise. But if they do we will be prepared to act upon them..

Sounds good..

Thanks Jeremy..

Thank you. There are no further questions registered. At this time I would like to turn the meeting back over to you 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..