David Moneta – VP, IR Russell Girling – President and CEO Donald Marchand – EVP and CFO Karl Johannson – EVP and President, Natural Gas Pipelines Glenn Menuz – VP and Controller Alexander Pourbaix – President, Energy and Oil Pipelines

Paul Lechem – CIBC World Markets Linda Ezergailis – TD Securities Juan Plessis – Canaccord Genuity Carl Kirst – BMO Capital Markets Matthew Akman – Scotiabank Andrew Kuske – Credit Suisse Robert Kwan – RBC Capital Markets Steven Paget – FirstEnergy Capital Corporation Pierre Lacroix – Desjardins Securities Inc. Edward Welsch – Bloomberg News Jeff Lewis – Financial Post

Thanks very much and good morning everyone. I’d like to welcome you to TransCanada’s 2013 third quarter conference call.

With me today are Russ Girling, President and Chief Executive Officer; Don Marchand, Executive Vice President and Chief Financial Officer; Alex Pourbaix, President of Energy and Oil Pipelines; Karl Johannson, Executive Vice President and President Natural Gas 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.

Please note that a slide presentation will accompany their remarks. A copy of the presentation is available on our website at transcanada.com, it can be found in the Investor section under the heading Events and Presentations.

Following their prepared remarks, we will turn the call over to the conference coordinator for your questions. During the question-and-answer period, we’ll take questions from the investment community first, followed by the media.

In order to provide everyone 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, Lee 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 the U.S. Securities and Exchange Commission.

Finally, I’d also like to point out that during this presentation we’ll refer to measures such as comparable earnings; comparable earnings per share; earnings before interest, taxes, depreciation and amortization or EBITDA; and funds generated from operations. These and certain other comparable measures do not have any standardized meaning under GAAP and are therefore considered to be non-GAAP measures.

As a result they may not be comparable to similar measures presented by other entities. These measures are used to provide you with additional information on TransCanada’s operating performance, liquidity and its ability to generate funds to finance its operations.

With that I’ll now turn the call over Russ.

Thank you David and good morning everyone and thank you all very much for joining us this morning. Very pleased to report we had a very strong quarter of earnings and cash flow from our diverse portfolio of critical energy infrastructure assets.

Comparable earnings in the third quarter of 2013 were 26% higher than during this – period last year. That strong performance is mainly the result of the return to an eight unit site at Bruce Power higher Alberta power prices and an increase in New York Capacity prices as well as a higher return on our Canadian Mainline.

These positive results however were somewhat offset by continued weak performance in our long haul U.S. Gas Pipeline businesses and in our U.S.

Gas Storage businesses. Our capital program continue to grow in the third quarter we announced the energy’s project we now have $30 billion commercially secured projects including the Gulf Coast project Keystone XL, the Keystone Hardisty Terminal, the Heartland Pipeline and TC Terminals project the initial phase of the Grand Rapids project, the Tamazunchale extension, and the exact acquisition of the remaining six Ontario solar projects as well as the ongoing expansion of our NGTL System.

Other large scale projects in development include the $12 billion energy project that I mentioned the Coastal GasLink and Prince Rupert Transmission projects the West Coast and Topolobampo, and Mazatlan pipeline projects in Mexico and the completion of the Grand Rapids and the Northern Courier oil projects in Northern Alberta and on the energy side the Napanee Generating Station in Eastern Ontario. All of those projects are anchored by long-term contracts or cost of service like arrangements.

As a result we expect those initiatives to generate sustained earnings in cash flow for our shareholders for many years to come. I will now give you a few highlights of our third quarter earnings before I get into some of the details on those projects.

As I said our three business segments performed well during the third quarter. TransCanada reported net income of $481 million or $0.68 per share.

Comparable earnings for the quarter were $447 million or $0.63 per share versus the $349 million or $0.50 per share we earned in Q3 of 2012 which is I said is a 26% increase on a per share basis. Comparable EBITDA was $1.3 billion and funds generated from operations were $1 billion.

The Board of Directors also declared a quarterly dividend of $0.46 per common share for the quarter ending December 31, 2013. So as I said a good quarter which reflects the strength and resilience of our diverse portfolio.

Don Marchand who will provide more details on the financial results in a moment but before we get to that I’d like to give a brief update on how our key projects are progressing. I will start with the Energy East’s project.

In August we informed stakeholders that we’d be moving forward with the 1.1 million barrel per day crude oil pipeline underpinned by firm binding contracts for over 900,000 barrels per day. Energy East project will transfer oil from Western Canada to Eastern Canada refineries but as well export terminals.

It’s an initiative that will create significant employment opportunities, tax revenue and energy security for all regions of Canada for many decades to come. With respect to Energy Security this project allows Canada to displays unstable oil from foreign suppliers.

Not everyone I’m sure is aware that Central and Eastern Canada currently import over 700,000 barrels a day of oil to meet their needs. Energy East creates the opportunity for Canada use and refine its own resources it’s something that we believe benefits Canadians across this country.

The benefits of Energy East extend beyond energy security in September outlets (Inaudible) to release an independent report from Deloitte & Touch that highlighted the economic benefits of that $12 billion project. They used the statistics Canada modeling process the report found that Energy East will generate about $35 billion in additional gross domestic product for Canada create more than 10,000 full time jobs during development and construction and 1,000 more jobs once that pipeline is operational.

Local communities in governments will see further benefits as Deloitte determine the project will generate an additional $10 billion of tax revenue for all level of governments over the life time of the project. Energy East will complement our plan Keystone XL pipeline as another tangible way of transporting growing production out of Western Canada to Eastern Canada refineries but also U.S.

refineries in the case of Energy East will also be in position that where we can attach energy supplies from Western Canada to global markets. As crude oil production grows in both Canada and United States new pipeline infrastructure is required to move that product safely and efficiently.

This is what projects like the Keystone XL pipeline and Energy East will do. We intend to file the necessary permits for the project in the first half of 2014 and moving over the U.S.

side in mid-October we recognized and thank nearly 5,000 workers in America who helped us to build the $2.3 billion Gulf Coast project. Construction on that project is now 95% complete and we’re preparing for crude oil to begin commercial service later this year.

Today producers do not have access to sufficient pipeline capacity to move their production from cushion to large refining markets in the U.S. Gulf Coast.

The Gulf Coast project addresses that constraint allowing U.S. refiners to access lower cost domestic cost production and avoid paying premiums to foreign oil suppliers.

This supports additional refining jobs in Texas and the economic benefits those jobs provide to that state. As I said we expect this 700,000 barrel per day pipeline to be operational by the end of the year.

In addition construction of the $300 million Houston Lateral project is underway that 76 kilometer project will transfer crude oil to Huston refineries and it is expected to be completed in 2014. On the Keystone XL where we continue to focus on the release of the final supplemental environmental impact statement which is to be issued by department state once its review is complete.

That review has now flips the 1,800 day mark since the review begin in 2008. Our base Keystone pipeline system to-date has safely delivered about 0.5 billion barrels oil to refinery in Illinois and Oklahoma since it started operation in summer of 2010.

The review for that project which was nearly identical to Keystone XL took approximately 21 months. Once the FDIS is issued the state department is expected to begin the national Interest Determination for Keystone XL which will be to decision on the presidential permit.

As I’ve said on multiple occasions the Keystone XL decision should be based on the facts and the facts are that the U.S. consumes 50 million barrels a day of oil each and every day and imports 7 million to 8 million barrels a day from places outside of United States.

Both the U.S. energy information administration and the international energy agency predicted America will continue to import millions of barrels of oil each day through and beyond 2014.

So what we’re really talking about here is choice, a choice made all that more relevant by the recent unrest in the Middle East and the choice is the American wants their crude oils from a friendly partner in Canada or will they continue to rely on unstable regions. Based on consistent pools since 2011 the majority of Americans continue to support our project and that choice of getting their oil from Canada.

The $5.4 billion cost estimate will increase depending on the timing of permit. And as of September 30, 2013 we had invested approximately $2 billion into that project.

Now back in Canada our crude oil strategy continues to progress. Last spring we announced the Heartland pipeline and the TC Terminals project, this initiative includes a 200-kilometer crude oil pipeline, connecting the Edmonton region to facilities in Hardisty along with the oil storage terminal in the Heartland industrial area just north of Edmonton.

The pipeline will transport up to 900,000 barrels per day and up to 1.9 million barrels of crude oil could be stored at the terminal. Together, these projects have a combined cost of about $900 million, and are expected to be operational during the second half of 2015.

On May 30th, we filled a permit application for the terminal, and filed an application for the pipeline on October 24th. In addition we had some very positive news from Suncor last week with the announcement of Fort Hills oil mining project is proceeding.

It is expected to begin service it is in fact to begin producing oil as early as 2017. Our Northern Courier pipeline is expected to be completed in 2017 and will transfer crude oil from the Fort Hills mine site to Suncor’s tanks facilities north of Fort McMurray.

Moving now to natural gas. In September we reached the settlement with our natural gas distribution companies in Ontario in Québec.

The settlement will allow TransCanada to provide customers with the flexibility to source gas from various locations will ensure mainline tools are set at levels to recover the cost of providing that flexibility. The settlement allows for the extension of the Eastern portion of our system to meet the changing needs of Ontario and Québec.

We expect to file an application for approval into settlement with the National Energy Board by the end of 2013 that settlement has an implementation date of January 1, 2015. And finally with respect with the mainline as of September 30th an additional 1.3 billion cubic feet a day our firm contracts have been signed originating that efforts since the implementation of the tolls decision which took place on July 1, 2013.

Again this highlights the importance of that infrastructure to the North American marketplace. Moving to our NGTL System we continue to expand the network of pipe to gather more gas $700 million of new facilities have become operational so far in 2013 and we also have any of the approval constructing net of $300 million of facilities.

In addition in August we signed agreements with the Progress Energy for 2 Bcf a day firm natural gas contracts the one there pin a major NGTL expansion which is the North Montney pipeline extension that $1.7 billion project will connect to a delivery point which is the Prince Rupert Gas Transmission pipeline which will provide natural gas for both specific Northwest LNG export facility on the West Coast of British Columbia. Volumes on the North Montney extension will ramp up between 2016 and 2019 to a total volume of 2 Bcf a day delivery volumes on the Prince Rupert project and into 2019.

We are also in discussion with other parties that are interested in signing contracts to ship gas on the North Montney extension and we expect to file an application for that $1.7 billion project in the fourth quarter of this year. Also in August, we took an important step when we reached a settlement with our NGTL System shippers the agreement will bring the cost and rates certainly to the NGTL System through 2014 and represents an acceptable balance of interest between NGTL and its stakeholders.

The National Energy Board approved the NGTL settlement and the final 2013 rates just this past Friday. Moving to Mexico, construction of Tamazunchale extension is progressing first quarter of 2014 continues to be our targeted and service date.

The Topolobampo and Mazatlan natural gas projects continue to advance with engineering and permitting activities well underway. We still expect these two projects to be operational in 2016.

I will now make couple of comments on the energy side of our business in Alberta, Unit 1 at Sundance A return to service in September, Unit 2 became operational in October as you may recall TransAlta shutdown both of these units in 2010 but was ordered by arbitration panel in 2012 to rebuild the units. Combined Units 1 and 2 are capable of generating 560 megawatts of power.

In late September we acquired two additional solar facilities in Ontario, built by Canadian Solar Solutions, these latest acquisitions follow July announcement where we told you that we’ve acquired the first of nine solar plants that we have planned to purchase. The combined capacity of the nine projects is about 86 megawatts and will cost approximately $470 million.

We anticipate the remaining six projects will come into service by the end of 2014 they will complement TransCanada’s existing operations in Ontario. The renewable energy produced on these projects will be sold to the Ontario Power Authority under our 20 year power purchase agreement.

Today, one third of the power we provide in North America comes from carbon-free sources. TransCanada has invested over $5 billion in emission-free energy including having the largest wind farm in new England, hydro facilities in the U.S.

Northeast, our solar investments and Canada’s largest wind farm in Québec. In addition to our interest in Bruce which is now operating as I said all that units for the first time in over two decades.

So to briefly recap, our assets did perform well and we had a very strong quarter highlighted by comparable earnings being up 26% compared to the same period last year and cash flow being a record $1.1 billion, up 21% over last year. Our portfolio projects under development continues to grow.

Today we have $38 billion of projects at various stages of development providing visible growth for our shareholders for many years to come. In August, we official announced the largest project in TransCanada’s history, 1.1 million barrel per day crude oil pipeline Energy East which is underpinned as I said with firm binding contracts for over 900,000 barrels a day.

This will allow Canada to replace imported foreign oil with Canadian oil in its Eastern refineries and provide significant economic tax and job opportunities right across this country. As I said all of our projects that we’ve announced that underpin by long-term contracts giving us the confidence that they will generate predictable and sustained growth in earnings, cash flow and dividends, growing shareholder value for our shareholders for decades to come.

So I will turn the call over to Don, who will provide additional details on our third quarter financial results. Don?

Thanks Russ and good morning everyone. I would like to begin today by highlighting a few key messages.

First, all three business segments once again have contributed very solid results in the quarter. Second, the positive momentum that began in the second quarter continued in the third with earnings growth as a result of Bruce Power operating as a full eight unit site, the constructive power market in Alberta, capacity market in New York at a higher Canadian Mainline return on equity.

Furthermore this momentum is expected to continue with a return of Sundance A the U.S. Gulf Coast project commencing operations, the acquisition of the remaining Ontario solar projects and completion of the Tamazunchale expansion in 2014.

Third, as Russ highlighted earlier, we continue to advance the balance of our $38 billion portfolio of high quality long life energy infrastructure growth opportunities. All of these projects are underpinned by long-term contracts or cost of service business models and are expected to contribute to significant growth in earnings, cash flow and dividends over the remainder of the decade.

Finally, we continue to be well positioned to fund our current capital program. The $4.7 billion of capital that we have raised to-date in 2013 on attractive terms is a clear evidence of our ability to access bearing sources of capital in order to finance our growth plan.

Now moving to our consolidated results shown on the next slide. Comparable earnings in the third quarter of $447 million or $0.63 per share increased $98 million or $0.13 per share compared to the same period in 2012.

The 26% increase in comparable earnings per share was primarily due to positive equity income contributions from eight units of Bruce Power, higher earnings from Western Power due to lower PPA cost increased utilization of the Sundance PPA and a return to service of Sundance A Unit 1, higher capacity prices in New York, increased generation volumes at our U.S. hydro facilities at a higher allowed return on equity for the Canadian mainline which is partially offset by lower contributions from U.S.

natural gas pipelines, reduced earnings from our unregulated natural gas storage business and higher comparable income taxes due to higher pre-tax earnings. Turning to our business segment results at the EBITDA level, our natural gas pipeline’s business generating comparable EBITDA of 684 million in the third quarter 2013 compared to 660 million for the same period last year.

Canadian gas pipeline’s EBITDA of 519 million increased 42 million compared to the same period last year. The improved results were primarily due to a higher allowed return on equity of 11.5% for the Canadian Mainline and a larger NGTL system average investment base as a result of ongoing expansions.

Results for NGTL in the third quarter 2013 continue to reflect the last approved ROE of 9.7%. On November 1st, the NAB approved our 2013-2014 settlement with shippers as filed.

As a result, our fourth quarter results will include a positive $8 million retroactive after tax earnings adjustment to January 1, 2013. The adjustment reflects an increase in the allowed return on equity to 10.1% at a higher composite depreciation rate.

It does not include any adjustment related to the fixed delaminate component of the settlement. Partially offsetting growth in Canadian gas pipelines was $18 million decline in EBITDA at U.S.

natural gas pipelines. Contributions from GTN and Bison were lower due to the reduction in our ownership interest from 75% to 30% effective July 1st following their partial sale to PC Pipelines, LP.

Great Lakes realized reduced revenues due to lower rates and un-contracted capacity. While ANR experienced higher cost related to services provided by other pipelines as well as lower revenues.

Overall weakness in certain U.S. pipelines is expected to continue and we are focusing on reducing costs to minimize the impact.

Turning to oil pipelines, Keystone generated 193 million of EBITDA in the third quarter the $13 million year-over-year increase was primarily a result of higher contracted volumes. In energy, comparable EBITDA was 410 million in the third quarter compared to 267 million for the same period last year.

The $143 million increase was a result of the combination of positive factors across our Canadian and U.S. power businesses.

Western Power’s EBITDA increased 25 million in the third quarter 2013 primarily due to lower PPA costs, increased utilization of the Sundance PPA and the return to service of Unit 1 at Sundance in early September. Sundance A Unit 2 return to service in early October which will allow us to recommence realizing the associated generation and related revenues under the PPA in the fourth quarter.

Turning now to Bruce-Power. The first time in two decades Bruce Power operated as a full eight unit site for a full quarter with the return of Unit 4 from its life extension outage in April 2013.

Equity income increased to 101 million compared to the third quarter of 2012 reflecting the restart of Units 1 and 2, increased volumes from Unit 4 and the recognition of lower lease expense at Bruce B. A similar lease expense reduction was recognized in the second quarter of 2013.

No further maintenance outages are planned to Bruce for the remainder of 2013. U.S.

Power EBITDA increased 29 million in the third quarter compared to the same period last year. The increase was primarily due to higher realized capacity prices in New York and higher generation volumes at the U.S.

hydro facilities, partially offset by lower sales volumes to wholesale commercial and industrial customers and lower generation at [Inaudible]. And finally, natural gas storage results decreased $8 million in the quarter due to a lower realized storage spreads partially offset by the acquisition of the remaining 40% interest in CrossAlta in December 2012.

Now turning to the other income statement items on slide 25, comparable interest expense in the third quarter was 235 million compared to 249 million in the same period last year. The 14 million decrease was principally due to higher capitalized interest as well as Canadian and U.S.

dollar debt maturity partially offset by interest on recent debt issues and higher foreign exchange on interest related to U.S. debt.

In the third quarter $80 million of interest was capitalized to assets under construction compared to $74 million for the same period in 2012. This increase reflects higher capitalized interest for the Gulf Coast projects and Mexican projects, partially offset by lower capitalized interest related to the restart of the Bruce A units.

Comparable interest income and other decreased $6 million due to realized losses in 2013 compared to gains in 2012 on derivatives used to manage the company’s net exposure to foreign exchange fluctuations on U.S. dollar income.

In combination with U.S. dollar denominated interest expense this hedging program largely counterbalance of the currency impact of translating U.S.

dollar pipeline and energy income reported in the business segments. Comparable income taxes for third quarter 2013 increased $49 million compared to the same period last year due to higher pretax earnings combined with changes in the proportion of income earned in higher tax jurisdictions.

Now moving on to cash flow and investing activities on slide 26, cash flow was very strong in the quarter primarily due to higher earnings in the period. It is noteworthy that funds generated from operations exceeded $1 billion in a quarter for the first time and represents a 21% increase over the same period last year.

Turning to investing activities. Capital expenditures were 992 million in the third quarter driven primarily by the Gulf Coast project, ongoing expansion of the NGTL system and construction of our Mexican pipeline projects.

Equity investments decreased to $114 million year-over-year due to lower capital spending at Bruce Power. Acquisitions of $99 million in the quarter reflect the purchase of the second and third Ontario solar projects which closed at the end of September.

The acquisition of the six remaining projects is expected in stages throughout late 2013 and 2014 as they are satisfactorily completed and brought online. Now turning to slide 27 our liquidity and access to capital markets remains solid.

At the end of the third quarter our consolidated capital structure consisted of 41% of common equity, 5% preferred shares, 2% junior subordinated notes and 52% debt net of cash. At September 30th we had $645 million cash on hand along with over $4 billion of committed and undrawn revolving bank lines with our high quality bank group.

Our commercial paper programs in the U.S. and Canada are well supported and provide flexible and very attractive sources of short term funds.

In early July we completed the sales of 45% interest in each of GTN and Bison for U.S. $1.05 billion which included a $146 million of GTN related debt through our master limited partnership TC Pipeline.

TC Pipelines successfully financed the transaction through a public offering of common units and a debt placement. Apart from maintaining our GT interest we did not participate in the equity offering and as such our ownership interest in the partnership decreased from 33.3% to 28.9%.

This asset drop down is a clear demonstration of one of the many financing options available to us as we progress our impressive growth portfolio. We also issue $2.5 billion of term debt in three offering since July at compelling rates.

Specifically in July we issued our first LIBOR-based floating rate notes raising U.S. $500 million of three year funding at an initial interest rate of 0.95%.

Also in July in Canada we placed $450 million and $300 million of medium term notes for terms of 10 and 30 years bearing interest of 3.69% and 4.55% respectively. And finally in October we issued U.S.

$1.25 billion of senior notes split evenly between 10 and 30 year maturities bearing interest of 3.75% and 5.05% respectively. Year-to-date we’ve now raised $4.75 billion on attractive terms through an array of funding products to a diverse investor base.

We also redeemed at par all of the outstanding 5.6% Series U preferred shares in October, the total face value of the outstanding shares was $200 million and they carried in aggregate $11 million in annualized dividends. We have completed our financing requirements for 2013 but we’ll be opportunistic in sourcing additional capital at what remain attractive funding levels.

Looking forward we remained well positioned to finance our capital program through funds generated from operations, new senior debts as well as subordinated capital in the form of additional preferred shares, hybrid securities and portfolio management which may include further LP dropdowns. In closing TransCanada produced another strong quarter.

Year-to-date comparable earnings per share and funds generated from operations are up 15% and 18% respectively compared to 2012. Going forward the return of Sundance A, the addition of new capital projects in late 2013 and into 2014 including the Gulf Coast project, the Tamazunchale Extension, the acquisition of the remaining Ontario solar projects and the ongoing expansions of the NGTL system along with our higher allowed NGTL system return on equity are expected to continue to positively impact future earnings.

This is expected to be partially offset by higher interest expense due to reduced capitalization as projects come into service. Finally we continue to advance the balance of our program of large scale commercially secured capital projects which now stands at $38 billion with the recent addition of Energy East.

These projects which are targeted the completion between 2015 and the end of the decade include Keystone XL, two natural gas pipelines to Canada’s West Coast, two gas pipeline projects in Mexico, several oil pipeline internal projects in Alberta and the Napanee Generating Station in Ontario. Each of these are underpinned by long term contracts with strong counter parties and we remain well positioned to fund the balance of the program.

This large capital program is expected to generate significant growth in earnings, cash flow and dividends for our shareholders over the remainder of the decade. 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 I turn it over to the conference coordinator, we will take questions from the financial community first and once we’ve completed that we’ll then turn it over to the media.

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

Thanks and with Fort Hills getting the go ahead here, obviously Northern clearly had been de-risked. I was just wondering where Grand Rapids stands with the uncertainty around the Dover project and if that has any impact on the timing and the certainty of that project?

No I don’t think so the project is anchored by long term take-or-pay commitments when the project is available for service and we think we have a pretty superior competitive position in that West Athabasca region.

But to be clear if Dover doesn’t get approved and move ahead does that mean that part of Grand Rapids doesn’t get built.

I mean we’ll wait and see. What I know is that we have a take-or-pay deal and it is not, it’s not depended on that regulatory issue.

Okay. On the Main Line you said you are going to file first half of ‘14 for the papers for Energy East.

Just wondering what that means to the mainline the gas main line tolls, does that kick off a new rate case and if so what should we expect that rate case is it a full blown hearing, you could have changed the methodology yet again what does that mean?

Well it is Karl speaking. Well it really depends I guess as we are right now we’ve just finished the settlement with some of our Eastern customers and we are going to be planning that settlement before the end of the year here and if the Board approves that settlement as we expect it well I don’t think we’ll need another gas rate case for the Energy East Project.

Now we will need from the gas, we will need a regulatory hearing on transferring the assets outs but I think the tolling of the pipeline will be fine if we get the settlement approved.

Just to be clear that we need to have an application essentially to take the gas pipeline out of gas service and put it into well services, that will have an impact on the rate base on the gas side and it’s our expectation that that impact will positively impact rates for gas consumers as Karl said one of the benefits I think of the settlement that we’ve just come to is it provides an beta framework for adding additional capital if necessary to the system to provide access to alternative supplies that our Eastern customers want to get access to. So I think it will be combined together but I suspect it’s at the end of the day it will have a positive impact on rates and costs for gas consumers.

Got you. Thank you very much.

Thank you. Just a follow-up question with respect to your mainline settlement, how are your discussions going with other stakeholders that are non-LBCs and what are the main elements that would change for them and what gives you the confidence that the regulator will substantially approve that settlement?

Well first of all we have just finished the legal, I guess settlement agreement with the LBCs. We have filed that.

We have finished that last week and we filed that with the OEB for a LBC hearing in the OEB. So that document’s really only been out for less than a week right now.

So we have talked to plenty of our other stakeholders on the system and I think it’s fair to say everybody was waiting until the final document was received from the regulators before they gave us any substantial feedback on that. You know the reality is that this settlement does increase some of the tolls on the system.

It does put the eastern triangle back onto cost of service and that will increase tolls on the system. So we will have some stakeholders that will not be happy with that result.

But what I can say is you know we believe we can get a substantial majority of the stakeholders that pay rates on the system upwards. The LBCs alone are probably 70% to 75% of the rates the revenue that we see in the system.

So we’ll be well in excess of that when we go to the Board with the settlement.

And Cap have they provided any feedback how will things change for the producers?

Well you know I think Cap as well has been waiting for the final document to come out and they want to take a look at the impacts on rates in some of the final terms and conditions of the documents. So although we have talked to them several times I think we’ll wait, let them resort to the document and go back and chat with them again.

Okay, thank you. Just a quick follow-up question, your business development expenses in your oil pipelines increased quite a bit year-over-year.

Are you capitalizing Energy East is that substantially Energy East or what else are you working on there?

It’s Glenn here. Energy costs are being capitalized right now.

As far as the oil BD expenses, don’t have a specific reason other than just increased activity in the segment.

Would it be more on the export side or the regional side?

Linda its Alex. You know it’s really all of the above but lately we have been pretty active domestically in Canada but also looking at opportunities in the U.S.

so it’s really just, we are seeing a lot of BD opportunities on the liquid side.

Great, thank you.

Linda, I guess just to augment Alex’s comment, once we have sort of got this backbone infrastructure in place the volume of new opportunities coming to us has increased and we are responding to those as quickly as we can. We always thought that once you have the backbone in place opportunities will come in and that certainly what we are finding is occurring with the growth in production on both sides of the border.

Great, thank you.

Thank you. Congratulations on a strong quarter.

You have contracted an additional 1.3 Bcf per day on the mainline since July 1st. What’s the total contracted volume you have now on the mainline and based on what you are seeing now what amount if any of further contracts do you expect to attract?

Well the 1.3 represented just little bit over doubling of our western receipts on the mainline so we’re right now as of November 1st we are moving up to 0.5 in that area. Are there more contracts to be had?

Yeah, I think yes but I think for the bulk of the firm load that’s on our system we now have under firm contracts so there is probably some more contracts to be had but I wouldn’t expect anything real material for the next year.

Okay, thanks for that. And Alex I wonder if you can update us on your Alberta Hedge volumes and average prices for the rest of the year and maybe into 2014.

Hey Juan. We are stepping back a bit from giving that kind of guidance.

Certain parties have indicated they have some concerns about the level of information could potentially be used in competitive manner. So we’re being a little bit more coy on that than we have in the past.

What I would sort of directionally say is we are we still have a significant merchant component but we have been able to execute a fair amount of forward sales in the Alberta business for next year.

Okay, thank you very much.

Thanks. Good morning everybody, nice quarter as well.

Maybe heading back to Energy East for second and don’t want to read too much in anything but I think previously we were thinking about an NEB filing around March. Now we’re talking first half of 2014.

I just want to make sure are there any gaiting factors that we should be I guess we should be looking at. I will stop there and ask that as the first one.

Sure Carl. It’s Alex.

I think more than anything as I think you heard us talk about in the media we were pleasantly surprised with the uptake on our open season on Energy East and that resulted with us right out of the gate upsizing the project and we’re now going to have two marine terminals. So that the slight modification in language you saw with respect to permit filing is really just the fact that that we have some more facilities we have to deal with and it is very important that we get this upfront work done correctly and that we get a lot of work done with our stakeholders before we file.

So it’s really just a recognition of the new facilities and just want to make sure we get it done right.

Okay, thank you. And then just sort of as a follow-up and I just want to make sure I am understanding this.

So when the NEB filing is made for Energy East it’s going to be all inclusive with the asset transfer from the mainline and I guess the amount of that transfer is still something that is evolving shall we say. And so when that happens is the goal to wrap that up with having both utilities and Cap on board at that time.

I just want to make sure I got a better sense of kind of how we should think about that.

Carl I will take a shot at it. It sort of crosses both the oil and the gas lines.

It’s our attempt to put forward a proposal get it in the references of all of those parties on both the oil and the gas side. I think it’s under sort of parameters that we have discussed to date and the amount of the transfer it’s our current thinking that we can provide benefits to all of those customers and we want to make sure that customers on both sides are able to get access to the capacity that they want or need and are willing to contract for.

So it will be our intent to try to pull it altogether and hopefully when we file we’ll have the support of all of those parties.

Thanks Russ, thank you guys.

Thanks very much. First on Ontario power, Alex.

Can you please give us an update on that given some of the issues around the auditor’s report on Oak Field is there any hit there or environmental issues or is that one now still kind of full steam ahead?

First of all I will talk about sort of where we are on the permitting side and then I will give you my thoughts on that AGs report but we are well advanced in our permitting process. We started our open houses, we are doing the required field studies and we imagine we should have our permit sort of mid-2014 then kind of give it a sort of 30-month probably give or take construction period just giving kind of timing for service.

With respect to the AGs report you know that’s a process that is ongoing. We gave some very limited testimony in that process and we certainly with regard to suggestions that TransCanada was able to benefit from Napanee I think the only comment I would make is that, this project when it was originally going to be the Oak Field project we actually would be in service today.

So we have a four year delay and I don’t think anybody has thought about the material implications of that four year delay. This project to us looks like materially identical kind of returns that we are expecting from Oak Field.

Okay thanks and staying with Ontario Power Bruce obviously you had a great quarter and it’s great all the units are in service. I guess the next topic is going to turn to refurbishment of BN, the province is talking about updating an energy plan in the coming months here and not building the nuclear but refurbishing existing.

I am just wondering is there any consultation with you guys on that because obviously specially for not building new nuclear than existing refurbishment has to be a very important part of that plan.

Yeah I said I think that’s clearly the case I think they are going to come out with this new energy, long term energy plan probably I think sometime this month or certainly by the end of the year. They’ve announced that they are abandoning new build, the government has announced they are abandoning new build at Darlington.

So I think that even puts more impetus on the refurbishment of the existing reactors. I think we’ve shown with the unit one and unit two refurbishment, although we had challenges we’ve also learned a lot and even with all of those challenges those reactors are operating very well.

They are delivering power at a very competitive rate with no GHT emissions. So I mean I think there is still a lot of work to go on refurbishment discussions, but I think we are certainly at this point I think it looks like there is a great opportunity to work with the government, the OPA and stakeholders to go forward on those refurbishments.

Okay, great, thanks guys. Those are my questions.

Thank you, good morning. Spectra made some comments I think it yesterday or very recently about possibly looking to expand the Express-Platte system and obviously that would include a Presidential permit that would be necessary.

So could you just give us your thoughts on the process you’ve been through to date? Does that really set a new standard for any kind of Presidential permit application or where you get an amendment that Enbridge has or that will put a clipper?

I guess my thoughts and Russ may want to jump in on this. But I think what we’ve gone through on the Keystone XL Presidential permit process is certainly not we what would have expected prior to that application for standard type Presidential permit.

I think all that being said all of the issues that have made Keystone XL contentious with the opposition would be equally applicable to both of those projects you identified and I think it would be pretty naive to assume any future project certainly in the near future would be going through a significantly lower hurdle in terms of the Presidential permit process.

Okay that’s helpful and then if I just may ask the second question and it just relates to Mexico. If you could just give us your interest in Mexico we’ve seen some awards that have been made recently and you weren’t involved in those awards, what’s your appetite for further developments in Mexico on a longer term basis?

Oh yeah we still have we still consider Mexico to be very key and core area for us. The awards that you saw was from the Las Ramones project in Mexico.

We chose not to bid on that project. There were some parts to that project, that Ramones were making that we just weren’t comfortable with that just didn’t fit what we are doing down there.

So we chose not to bid on that particular project but we are still working diligently in the area on not only our existing projects but on other new projects that are going to be coming up.

Okay that’s very helpful thank you.

Good morning. Just with the additional FT contract you signed and many things you’ve done on STFT for the main line?

Just wondering about your cash ROE expectations are and then just second on the main line with that LDC settlement you’ve talked a lot about the Eastern triangle but just wondering if there is any impact on the long haul part of the system?

You know first we’ll start with what we’ve contracted for. So the FT that we’ve contracted for and our forecast of other discretionary sales that we are going to make till the end of the year we are going to be selling some interruptible and some STFT as well before the end of the year.

We are predicting that we will earn our revenue requirement this year which is about $1.5 billion. So we should be pretty close to that number for a full revenue recovery in 2013.

The ROE on our system is set at 11.5 on 40% that doesn’t change with the revenue that we collect but what does change is that we are going to come out here with very little deferrals if any in the TSA County that whole stabilization account. So it looks pretty good for this year and it actually looks pretty good for next year for recovery of our rate case.

And the second question, the second part of that question you had was, could you refresh my memory on your second part.

Yeah just on the LBC settlement if there is any impact on the long haul part of the system?

Oh yes what’s going to have the long haul part of the system so in essence the settlement that we’ve negotiated really have two main objectives. First it separates the Eastern Triangle part of our system out and tolls that independently from the rest of that system and it is tolled on a class of service basis.

So what that does for the LBC is that allows that allows us to make invest it allows us to roll in the vessels and allows us to get recovery so we have a line of sight of getting the recovery on those investments. It had also allowed expansion on the system.

The second part the second objective of the settlement really is to allow the LDCs to move from long-haul to short-haul. And one of the products we had with the NEB decision with the fixed tolls was that intentionally moved from long-haul to short-haul we would have a revenue deficit as well.

Now that we are totaling on a cost of service basis there’ll be no revenue deficit we collaborate with movement. So what’s going to happen with long-haul, long-haul still going to be tolled on the NEB fixed price toll but they will be paying as well the – some triangle they will be paying a slight premium to that for the transition charge.

But what we’ve done with that is the LBC’s have guaranteed 13% of their requirements to stay on long-haul until 2020. So you should see long-haul flows may be go up somewhere 50% and 20% over the six years of this settlement.

But they should remain pretty stable during that period of time.

Great, thanks Karl and just last question here probably for Alex. New York Zone J capacity prices for this month were actually spot priced cleared nicely turned back [inaudible] months.

Just wondering what you thought about that what’s your expectations are through the winter we basically doubled year-over-year?

Yeah you know I think from our perspective we’ve obviously had a reasonably nice pick up in New York capacity prices. Yeah as usual and in the New York market there is some puts and takes.

And I think a lot of the reason for that trend up was the in city required capacity moved up by both 3% I think it moved up to about 86% which have a positive I think was largely related to that positive move up. We do expect that huts and cable project to get to be coming in and getting credit for capacity here over the next little while but on the same side or on the other side of that we have the new demand curve reset process which we would think all things being equal will probably be putting an upward pressure on the capacity payments.

So you know you kind of put all of that together and I kind of look at an overall capacity payment for 2014 probably not that different from what we experienced in 2013.

Okay, that’s great, thank you.

Thank you and good morning. The contracts on the main line Karl how much of the revenue requirement is being right now through long term and how much revenue do you need from short term contracts?

I’d said right now for 2013 around the 80% is going to be collected from the FT contracts and 20 from short term. That would be a little higher next year because we have sold little bit more FT for next year so it will be maybe 80% and 85% ranges is recovered from the FT contracts.

Thank you. And just following up on Mexico, could you please comment on opportunities in Mexico what scale of new investments might be announced in the next three years overall rather than just TransCanada

It is hard for me to put the scale for Mexico’s planning because they’ve been changing their plan over the last few months. What I can say Mexico is trying to interconnect the south more thoroughly to North American grid.

The projects that we’ve got and the projects that they’ve got so far are the start of that. I would guess that the country as a whole outside from the loss from [inaudible] projects that we talked about from Pemex but I will suggest that the country as a whole we could see a doubling of what they offered the last two years that will be easy to see.

When the timing that comes is uncertain right now, there we’re in constant discussions as you can imagine with them on their new projects but there is a bit of the process that we have there so it is very difficult for us to kind of guess when those projects will come up for bid.

Well, thank you, Karl and those are my questions.

Thanks Steven.

Thank you. Alex you mentioned you had some business development opportunities on the oil pipeline in the U.S.

could you comment a bit more about the opportunities that you’re seeing there?

It’s pretty premature for that we like to save comments when we have something material to disclose but we’re looking at opportunities around the Bakken and some opportunities around the Gulf Coast but as I said it is pretty early days for us to be talking more definitively about it.

Anything any opportunities related to conversion of natural gas in the U.S.?

I think what I would say is just generically TransCanada is always looking at maximizing the value of its assets and with this incredible gas pipeline grid that we presently operate it does lend itself to looking at oil conversion opportunities a lot of those pipes are potentially located in the attractive opportunities for that, it’s always easiest to look at BD opportunities in your own backyards so we’re taking very hard look at that right now.

Thank you.

Hi, my question is actually regarding the Gulf Coast pipeline project given the 95% of the work is done on the line when do you expect the line to start filling with oil and how long do you think that will take?

As Russ said we’re very close to completion and we would expect that we will be calling for first oil here probably as early as a few weeks.

Few weeks, okay so that’s basically pushing the line, pushing the guys down the line?

Yes, putting them in place lines for you.

Okay. And I guess as a follow what’s part of the 700,000 barrels a day you think is the contracted volumes on the pipe and in line with that what flow do you expect to see once the line is complete?

Most of these projects they take a little while to get up to full capacity. It does have a capacity of 700,000 barrels a day in ultimate capacity of 830,000 barrels a day if we have additional pump stations I would guess in 2014 we’re probably looking at something in sort of the 550,000 barrel a day range and pretty significant majority of that would be contract.

Okay. And I guess the last one that can we expect the volumes actually reaching Port Arthur by end of the year or that will be of a more early 2014 phenomenon you think.

We intend to – we should have first oil hitting Port Arthur the end of the year.

Okay. And lastly on the under committed volumes what tariff do you expect to get on those?

I don’t think we’re not disclosing that information right now.

Thank you. That’s all my questions.

Thanks.

Thank you. Appreciate the time.

One quick follow up please on the U.S. pipes and Don I think you’ve mentioned in your remarks that we expect for the challenge to be ongoing.

At the same token we’ve signed now 350 million on an ANR rates at firm rates we now have the settlement on Great Lakes. And so I guess my question is on those two developments do you see that basing out the U.S.

pipeline here 2013 to 2014, do you still see more erosion possible or is it even possible to breakout what the actual impact of those two settlement in the new ANR contracts would be?

It’s a good question, the question how we hit bottom we are starting to move up here and I guess I’ll talk what the ANR first. The Lebanon lateral contracts we got are 350 million a day I think a very, very positive development for that pipeline.

I took a look at that pipeline several times being a very diversified pipeline, with lots of market and lots of spur on it. and I think the access to Utica and Marcellus is very positive for that and we expect that to grow overtime.

We have to remember those volumes will come on the system over the next year so they are not coming in right away. So I am still forecasting a pretty difficult year next year for ANR.

The transportation spreads are thin, the storage space very low and we have some big builds for transportation levers on that pipeline. So still have we hit bottom next year, maybe I do see some good signs to it but it’s not going to turn around that quickly.

On Great Lakes you are right we did get a settlement, a 21% increase but you have to remember that 21% increase is on our default rate. We don’t have a lot of customers anymore at the default rate so there is pretty modest revenue improvement.

I think the positive part of the Great Lakes is now that we have the mainline settlement in place once we get that approved I think we’ll certainly in the market of what it costs to move gas into that system and we think that’s directionally positive. But again I think we’re in for next year another difficult year frankly because I think the transportation spreads just for the foreseeable future on the line.

I appreciate the color and just maybe on ANR you’re moving much up from the Gulf or is it primarily just regional in the Mid-West?

The most of volumes on that system now come from kind of the mid-continent shale place so it’s got a good diversified base, when that system was originally there was Gulf Coast natural and gas right now Gulf Coast is a very small percentage of the gas now in that system.

Excellent, thanks so much guys.

Thanks Carl.

Hi, this message is for Mr. Girling.

I’m just wondering if you learned anything about the timeline for Keystone XL during your recent trip to Washington.

No I think the process is as it’s been for months. We’re waiting for the final environmental impact statement to be completed and issued.

It would be our hope that, that is in the near term here and then once we receive that I believe that there is up to 90 day national interest determination period and probably between 15 and 30 days to complete the record to get to final Presidential permit and there is no update on when that FDIS would come out in my meetings in Washington last week.

But given everything that they were talking almost mid-2014 then.

Again those processes, the time frame of those processes are determined by the state department and the timeframe to get to an FDIS in my view could be relatively short. We’ve been through 15,000 pages of review and there is nothing left to review we can get to that relatively quickly and as I said the national interest determination is up to 90 days.

It doesn’t necessarily have to take that long we’re not in control of that process. So it’s sometime in between now and the end of those dates and I have given up trying to predict where and when it might fall.

Thank you.

Yes, hello, Mr. Girling, the idea that environmental activists have hijacked the process.

I mean you have used some strong language in that regard, do you have any indication as far as Keystone is concerned that given the past and the past behavior of this current administration that they will eventually green light the project given their intransigence so far.

Again for me this isn’t a political comment, the original Keystone project took about 21 months to approve, all of the same issues were raised in that process and similarly the Enbridge Clipper Project took about 27 months. We’re now sort of 60 months, greater than 60 months in this process and so my view would be that based on past history which is decades of free trade of energy between these two countries, the importance of energy trade, free trade agreements and the establishment of above 3 million barrels a day that moves across the border today of heavy oil, based on that and the US’ need for oil, my view is we will get approval.

Really nothing has changed in that the U.S. needs crude oil in excess of its own production and Canada produces oil in excess of its own consumption, and the marriage of those two things makes sense historically and makes sense today and it makes sense for many decades in the future.

So I don’t actually see how that has changed and those are the fundamentals which will I hope drive the decision for the Keystone Project.

And yet, you have an administration that in spite of everything that you’ve said and the rationale that you’ve given to green light this project it hasn’t happened to this point, so the question is do you have any hope whatsoever that this administration will come to the same sort of view that you have had regarding Keystone and eventually green light this project?

Yeah, I’ve got every confidence that we will get there and we have, the State Department has issued four environmental impact statements. In all four of those they have come to the conclusions that are outlined that a, that the project is necessary, that it has limited environmental impact on the resources and property along the route, and that it will have no material impact on GHG emissions.

So we’ve seen the administration comes to those conclusions four times already, and I will expect that the fifth time when they issue the final environmental impact statement, it will come to the same conclusions because there is no way to come to any other conclusions except for those conclusions. The pipeline does not increase consumption and therefore does not increase GHG emissions, and it has met every other criteria.

So I fully expect that the administration will continue to process the data that they have accumulated and the comments, the million and a half comments that they’ve accumulated in the last commentary they will get to that process, they will issue an FEIS and my belief is that that will pave the way to a positive Presidential decision.

My last question, it has to do with the ongoing diplomatic efforts on the part of Canada to try and get this project green lighted, have those efforts have had any impact in your view.

I believe that the supportive Canadian government with respect to a major industry that is a major driver of the Canadian economy is extremely important, some of the questions that have been raised with respect to energy trade between the two countries and the questions that you raised have or has any of that changed, I think it is important for the Canadian government to voice its view that it is importance of the production of energy in Canada to the economy is substantial and they have a desire to develop those resources and they will develop them responsibly. But I think, they want to make it clear that they make no mistake that those resources will get developed and they will move to market.

The preferred market is the US market but they will also develop other markets along the wayside. I believe that those positions that the Canadian government has taken with respect to U.S.

and export markets are critical and continue to be important both for the projects like Keystone and other projects that have been proposed by other proponents and our projects which include, you know the Energy’s project.

Thank you.

Thanks, I have a question, a couple of questions on the main line. I was just wondering now that you have got this additional 1.3 BCF a day on pipeline, is this enough basically, in a nutshell, to make it sustainable over the long term, I believe it is still, underutilized running at less than half capacity.

So I was just wondering if you could sort of provide some guidance on that. Also I’m wondering the change in the short term tolls that happened between, July and September caused the big move in the natural gas market in Western Canada prices really dipped.

I was wondering what was the thinking when you decided to reverse some of those changes in September, you changed the structure, was that in reaction to what was happening in the market, or had you already achieved what you intended. Those are my questions.

Your first question with respect to sustainability of the mainline, I think what we’ve always said is that the mainline is a critical piece of North American Gas Infrastructure the question was how it was going to be tolled as opposed to how it was going to be utilized. There is no question that with the advent of the production in a traditional market zone like Marcellus Gas, it has had impact on our long haul volumes.

That said, there is still a requirement for base load volumes to move through that system and it’s incredibly important during peaking times in those eastern markets. So we’ve seen our volumes reach 4 or 5, 6 BCF a day in those peak periods across the [inaudible] and at the same time, those eastern end of the system is full every day.

So the system is needed and will be needed for many decades to come. The settlements that we put in place really, just speak to who paid for the system and how those costs will be allocated over time.

With respect to our tolling changes on July 1st we implemented the National Energy Board’s neutral instruction that they had put in place for us. As a result we moved our discretionary pricing to meet the market demands.

I don’t believe that our tolling alone has the ability to move basis differentials across this country but certainly we move to a place where we are trying to encourage our customers to use the system and to pay for the system in a way that met their long term needs. And what we determined in the process is that the long term needs are best met for those group of customers that sign long term contracts by signing with us for a term period so that they had certainty and at the same time we had certainty of revenue.

Okay, thanks a lot for that. And so I was just wondering Karl’s comment that I believe that he doesn’t expect any more long term contracts, beyond the 2.5, that’s all that has been reached, I mean why is that, is that the maximum that you think you can get in long term contracts or...?

Well, you know, I think that I am expecting some extra-long term contracts but I don’t think we will see another 1.3 BCF come on the system. There’s still is some opportunity to market it, but we will look for pipeline after this with the more seasonal volumes which is coming, people are going to long term, the shorter term, the short term form of the interruptible service.

So there is two, there is two basic types of services as people do buy on the pipeline, they’ll buy the FP the Firm Pull service for the base needs, for their needs for their firm commitments and then they will buy the interruptible, or short term needs for their non-firm requirements so to speak. So we will still be marketing, we will still bringing volumes on that systems, but, as I said I don’t believe we will bring in another 1.3 BCF into the system but we will bring in more FP into the system as time goes on.

Okay, thanks a lot.

Hi, thanks for taking my question. Regarding the North Montney Project, with the discussions that you are been having with parties interested in using that besides Progress Energy, would that involve upsizing the project beyond what’s been proposed.

And then I have a follow up question.

I guess the answer to that question is maybe we haven’t really concluded those discussions yet but the North Montney area of our system is there is many different producers in that area and many other LNG actually producers that have LNG aspirations in that area. So it is difficult to say right now how successful we will be with talking to the other producers but they are other customers looking to get on to that system and they come with material volumes, yes just we might have to upside for other systems.

And secondly, just as a follow on, what are your thoughts around or have there been any discussions around perhaps consolidating some of the infrastructure that’s planned into the coast, say gas line and transition line?

I think that’s up to the deployments of those projects TransCanada I think offers a very beneficial service in that we can attach all of those projects to the liquidity of the NGTL systems and that’s very attractive to them. In terms of combining projects downstream, all of these different proponents have different time frames for both production and when they want to have their product available to market.

That obviously makes it a little more complicated to bring these projects together. We are not aware of any projects that are sort of being talked about being brought together but there is some obvious logic that you could see and bring some of these projects together, they could align themselves on timing and other issues.

Okay, thanks.

Thanks very much, and thanks to all of you for participating today. We very much appreciate your interest in TransCanada and we look forward to talk to you again.

Bye for now.