David Moneta - Head-Investor Relations Russell K. Girling - President, Chief Executive Officer & Director Donald R. Marchand - Chief Financial Officer & Executive Vice President Paul Miller - Executive Vice President & President, Liquids Pipelines Alexander J. Pourbaix - Executive Vice President & President, Development William C.

Taylor - Executive Vice President & President, Energy Division Karl Johannson - President-Natural Gas Pipelines & Executive VP.

Paul Lechem - CIBC World Markets, Inc. Robert Catellier - GMP Securities LP Andrew Kuske - Credit Suisse (Canada) Robert Kwan - RBC Dominion Securities, Inc. Linda Ezergailis - TD Newcrest Robert Hope - Macquarie Capital Markets Canada Ltd. Matthew Allan Akman - Scotiabank Steven I. Paget - FirstEnergy Capital Corp. Ashok Dutta - Platts, Inc.

Julien Arsenault - The Canadian Press Lauren Krugel - The Canadian Press Rebecca Penty - Bloomberg LP Claudia Cattaneo - National Post, Inc..

Good day, ladies and gentlemen. Welcome to the TransCanada Corporation 2015 Second Quarter Results Conference Call. I would now like to turn the meeting over to Mr. David Moneta, Vice President of Investor Relations. Please go ahead, Mr. Moneta..

Thanks very much and good morning, everyone. I'd like to welcome you to TransCanada's 2015 second 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, Executive Vice President and President of Development; Karl Johannson, President of our Natural Gas Pipelines business; Paul Miller, President, Liquids Pipelines; Bill Taylor, President of Energy; 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, and it can be found in the Investors section under the heading, Events & 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 re-enter 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 some with you following the call. Before Russ begins, I'd like to remind you that our remarks today will include forward-looking statements that are subject to important risks and uncertainties.

For more information on these risks and uncertainties, please see the reports filed by TransCanada with Canadian securities regulators and with the U.S. Securities and Exchange Commission.

Finally, I'd also like to point out that during the presentation, we'll refer to measures such as comparable earnings, comparable earnings per share, earnings before interest, taxes, depreciation, and amortization, or EBITDA, comparable 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 our operating performance, liquidity and our ability to generate funds to finance our operations. With that, I'll turn the call over to Russ..

Thank you, David, and good morning, everyone, and thank you very much for joining us today. We're very pleased to report today's strong financial results for the second quarter of 2015. The results again reflect the resilience and diversity of our three core businesses through difficult business cycles.

As you're well aware, low commodity prices and challenging market conditions are impacting our customers, and their capital expenditure plans. And, we're working closely with our customers to understand those impacts and to adjust our projects to best meet their needs.

During the quarter, we continued to advance a number of our key components of our capital program, including construction activities on our $12 billion shorter-term project portfolio such as the Napanee power plant and Northern Courier pipeline project, Topolobampo and Mazatlan in Mexico, and several NGTL receipt and delivery expansion projects.

We advanced our $13 billion portfolio projects to support the emerging liquefied natural gas business in British Columbia, and we continued to progress our long-distance crude oil pipeline initiatives.

In addition, we continue to work on additional strategic opportunities in each of our three core businesses such as expansions of the NGTL System, the ANR system, Mexico opportunities and the refurbishment of Bruce Power.

As I said on a number of occasions, given the highly contracted nature or regulatory underpinning of these projects, once complete, they're expected to deliver steady growth in earnings, cash flow and dividends through the end of the decade and beyond. So, back to the quarterly numbers.

TransCanada reported net income of $429 million or $0.60 per share in the second quarter. Comparable earnings for the quarter were $397 million or $0.56 per share. This is a 20% increase over the $332 million or $0.47 per share reported in the second quarter of 2014. Cash flow has also continued to grow compared to the second quarter of last year.

Comparable EBITDA was $1.4 billion and funds generated from operations were $1.1 billion. Earlier today, the board of directors declared a quarterly dividend of $0.52 per common share for the quarter ending September 30, 2015.

As a result of the company's past performance, along with confidence in our future business plans, our board of directors has raised the dividend in each of the last 15 years from $0.80 in 2000 to the current rate of $2.08 per year.

Stock appreciation combined with this steady and growing dividend has resulted in a 14% average annual total shareholder return since 2000.

Looking forward, continued strong performance from our core businesses, and expansions currently underway is expected to provide the foundation to continue to grow our dividend at an annual rate of 8% to 10% through 2017, and to continue to prudently fund our industry leading $46 billion capital program.

Our CFO, Don Marchand will speak with you shortly and provide more details on the financial performance in the second quarter. But before that, I'd like to speak to you about some key developments over the quarter in advancing our capital program.

Starting with our gas pipeline business, as I've mentioned last quarter, with nearly $7 billion of new supply and demand facilities under development, we are poised to almost double the rate base of our NGTL pipeline system.

We continue to advance several of these facility expansions and plan to file additional facility applications with the NEB through the remainder of 2015. In addition, we continue to receive requests for firm receipt service that we anticipate will increase the overall capital spend on NGTL System beyond what we have previously announced.

In-service dates for the majority of those initiatives run through 2016, 2017 and 2018. The single largest NGTL project that has been approved is our $1.7 billion North Montney project.

In June, the government of Canada announced a decision to accept the National Energy Board's recommendation to approve the project, which will expand NGTL's reach into the one of the most prolific producing regions in the Western Canadian Sedimentary Basin.

It will consist of two large sections, the Aitken Creek and Kahta sections totaling just over 300 kilometers in length. This pipeline will connect Montney and other Western Canadian Sedimentary Basin supply to existing and new natural gas markets, including Pacific NorthWest LNG terminal via the Prince Rupert Gas Transmission Project.

We expect to have Aitken Creek operating in late 2016 and Kahta around 2017. Construction of the North Montney project will begin after final investment decision has been made on the proposed Pacific NorthWest LNG project and TransCanada proceeds with the construction of the Prince Rupert Gas Transmission Project.

With respect to Prince Rupert Gas Transmission, we're pleased to see significant developments over the last month. Pacific NorthWest LNG reached an important milestone with a positive final investment decision subject to two conditions; firstly, approval from the Canadian Environmental Assessment Agency; and second, the B.C.

Legislature's ratification of the project development agreement between the Province and Pacific NorthWest. On the latter condition, the B.C. Legislature ratified that agreement with Pacific NorthWest just over a week ago. Pacific NorthWest is proposing to build a liquefied natural gas facility and export facilities near Prince Rupert.

These facilities would receive gas through our 900 kilometer Prince Rupert Gas Transmission project from the Montney producing region near Fort St. John, British Columbia. PRGT with the beneficiary of further positive news recently, receiving 6 pipeline of the 11 pipeline and facilities permits from the B.C.

Oil and Gas Commission, needed to build and operate the pipeline, we anticipate a decision on the remaining permits in the third quarter of this year. We remain on target to begin construction of the Prince Rupert project following confirmation of a final investment decision from Pacific NorthWest.

The in-service date of PRGT is expected to be 2020, but we will align that with Pacific NorthWest LNG's facility timeline. On our Coastal GasLink project, we announced last month that we had signed project agreements with six B.C. First Nations.

These agreements reinforce the strong relationship TransCanada has built with First Nation communities and demonstrate their willingness to participate in the many benefits and opportunities this project will bring to their communities.

An estimated 30% of the $4.8 billion project spend will be spent locally in British Columbia, creating over 2,000 jobs during construction, and $20 million in annual property tax payments. On the permitting front, Coastal GasLink had received the majority of its permits from the B.C.

Oil and Gas Commission, 8 out of 10 are in hand and the remaining two permits we expect those to be issued in the third quarter of 2015. The 670 kilometer Coastal GasLink pipeline will run from Dawson Creek to the proposed LNG Canada liquefied natural gas export facility near Kitimat, British Columbia.

We anticipate construction starting in the latter part of 2016. Moving over to Oil and Energy East, we announced in early April that we would not build a marine terminal at Cacouna, Québec. We continue to review potential alternative export terminal options with our shippers and stakeholders.

There is a possibility that only one export terminal at a facility at St. John, New Brunswick would be built. The other existing delivery points to refineries in Montreal, Lévis, near Québec City and St. John and the export terminal in St. John are not impacted by that review.

We expect that we'll be in a position to offer further update on the project in the coming weeks. During the past nine months, the NEB has continued to review our October 2014 filing for the project. Amendments to that application are expected to be filed with the NEB in the fourth quarter of 2015.

The result of this change for project scope and further refinement of the project schedule is expected to result in an in-service date of 2020.

This project will connect directly refineries in Eastern Canada, allowing them to access cheaper Western Canadian crude oil instead of having to rely on 600,000 barrels a day of oil, Canada imports from foreign countries today.

The benefits from the multi-billion dollar project for all Canadians are quite clear, thousands of good paying jobs and millions more in annual tax revenues to fund healthcare, build the roads, schools and fund the local communities.

We expect the current announced project cost of $12 billion to increase due to adjusting the pipelines route, following feedback from communities, governments and indigenous people and higher construction costs. Moving to the Keystone Pipeline System.

We achieved a very important milestone just a couple of weeks ago when we announced the Keystone Pipeline System had safely delivered its one billionth barrel of oil of Canadian and U.S. crude oil fuel refineries in the United States. Since 2010 when we first began transporting oil, the Keystone System has contributed to the U.S.

energy security, and has generated close to $200 million in property taxes and more than 14,000 construction jobs for 11 states and provinces that it crosses. Construction continues on the Houston lateral pipeline and tank terminal, which will extend Keystone to the Houston, Texas refineries.

The terminal is expected to have an initial storage capacity of 700,000 barrels of crude oil. The pipeline and terminal are anticipated to be operational in the fourth quarter of 2015.

In addition, we announced a joint development agreement with Magellan Midstream in the spring to connect our Houston crude oil terminal to Magellan's East Houston terminal. TransCanada will own 50% of this $50 million project, which will enhance connections to the Houston market for our Keystone Pipeline customers.

We expect that pipeline to be operational in late 2016. On Keystone XL, we continue to wait for recommendations from the U.S. Department of State as to whether the project is in the national interest of the United States.

Our focus at the current time is taking part in hearings held by the South Dakota Public Utilities Commission related to our request to certify Keystone XL's existing permit authority in the state. Those hearings are expected to wrap up next week.

We continue to believe Keystone XL is in the national interest of America and meets the President's climate test and not significantly exacerbating global greenhouse gas emissions, something that the U.S. State Department has included on numerous occasions in over 17,000 pages of scientific review since 2010.

The need for the Keystone XL Pipeline remains high, as consumers continue to use more and more gasoline refined from barrels of crude oil. The American Energy Information Administration reported earlier this month, oil consumption in the U.S. is up by nearly 0.5 million barrels per day over last year.

As a result, refineries are producing more gas for U.S. motorists at near record levels.

We believe the fundamental choice for Keystone XL remains firstly, would Americans rather receive this oil that they continue to demand from Venezuela or places like Iran or would they rather use American and Canadian oil and second, is it safer and more environmentally sound to ship that oil in trucks, rail cars or barges or in a modern state-of-the-art pipeline buried 4 feet below the ground.

We continue to believe the answers to these questions as self evident. This $8 billion pipeline remains the safest, least ESG intensive and most secure way to supply the oil the United States needs, and TransCanada and it's shippers remain 100% committed to this project.

As of June 30, 2015, we had invested US$2.4 billion in the project, and we've also capitalized US$400 million of interest. Moving over to energy, in January, we began building the 900-megawatt natural gas fired Napanee power plant at Ontario Power Generation's Lennox site in the Eastern Ontario town of the Greater Napanee.

The $1 billion plant is anticipated to begin operating in late 2017 or early 2018. Power produced at this facility is fully contracted for 20 years with the independent electric system operator in Ontario.

So to conclude, our three core businesses produced another solid quarter demonstrating resiliency, while facing some very challenging market conditions. Comparable earnings and funds generated from operations increased 20% and 16% respectively compared to the same period last year.

This highlights the solid foundation from which we expect to grow a dividend at 8% to 10% through 2017, and fund our industry leading $46 billion portfolio of new, high quality energy projects.

These projects are expected to result in significant growth in earnings, cash flow and dividends through the end of the decade and beyond, and continue to deliver long-term shareholder value. I'll now turn the call back to Don for more details about our second quarter financial performance.

Don?.

Thanks, Russ, and good morning everyone. As highlighted in our release this morning, we again delivered strong results in the second quarter with net income attributable to common shares of $429 million or $0.60 per share, compared to $416 million or $0.59 per share for the same period in 2014.

Excluding a $34 million income tax expense adjustment resulting from the recent increase in the Alberta corporate income tax rate, an $8 billion after tax restructuring charge related to changes in our major projects group as well as unrealized gains from various risk management activities, comparable earnings increased $65 million in the second quarter to $397 million or $0.56 per share compared to $332 million, or $0.47 in the same period last year.

Net income in second quarter 2014 included a $99 million after-tax gain from the sale of Cancarb, a $31 million after-tax loss from the termination of our natural gas storage contract, as well as unrealized losses from various risk management activities, each of which were excluded from that period's comparable earnings.

The 20% year-over-year increase in second quarter comparable earnings was primarily due to higher contributions from the Canadian Mainline, NGTL System, Keystone, Bruce Power and Eastern Power, partially offset by lower contributions from U.S.

Power, due to timing differences on recognizing earnings, as well as lower realized power prices and PPA volumes and Western Power.

In terms of our business segment results at the EBITDA level, the Natural Gas Pipelines business generated comparable EBITDA of $807 million in the second quarter of 2015 compared to $759 million for the same period last year.

Canadian Natural Gas Pipelines' comparable EBITDA of $583 million increased $34 million compared to 2014, primarily due to incentive earnings recorded for the Canadian Mainline and the higher average investment base on NGTL, partially offset by a lower allowed ROE on the Mainline.

Canadian Mainline earnings increased $9 million in the second quarter 2015 to $67 million. The NEB approved final tolls for the 2015/2020 tolling agreement in June, allowing us to record incentive earnings in the period of $24 million for the first six months of the year.

This was partially offset by a lower allowed ROE of 10.1% versus 11.5% last year, as well as a lower investment base.

Given the strong volume throughput in contracting efforts in the first half of 2015, the Mainline is expected to earn its base ROE of 10.1% throughout the remainder of the year with incremental short-term volume movements or additional contracting providing potential upside from this level.

NGTL's net income increased by $8 million in the second quarter compared to the same period last year, primarily as a result of its growing investment base and no OM&A incentive losses realized in 2015. U.S.

and International Pipelines comparable EBITDA was up $26 million to $238 million in the second quarter 2015, primarily as a result of the positive impact of the stronger U.S. dollar. Business development costs have risen for the three and six-month periods in Natural Gas Pipelines mainly due to increased business activity.

In Liquids, the Keystone Pipeline System generated $320 million of comparable EBITDA in the second quarter, an increase of $64 million from last year. This was a result of higher uncontracted volume throughput, and the favorable impact of a stronger U.S. dollar. Turning to Energy.

Comparable EBITDA of $272 million in the second quarter represented an increase of $41 million versus the same period in 2014. Bruce Power equity income increased $42 million as a result of fewer outage days. Strong operating performance in the A units, which achieved 98% availability, was a primary factor in Bruce's strong results.

Bruce B conducted its planned 30-day vacuum building outage slightly ahead of schedule and also completed and extended planned outage on Unit 6 during the quarter. Additional schedule outage on Unit 4 at Bruce A began in mid-July and is expected to continue for approximately 90 days.

This work on Unit 4 will substantially complete the planned major maintenance events at Bruce for the remainder of the year. Eastern Power comparable EBITDA was up $21 million year-over-year due to incremental earnings in solar facilities acquired in the second half of 2014 and increased power generation from Cartier Wind.

Western Power comparable EBITDA decreased $12 million due to lower realized prices and lower purchased PPA volumes. We continue to expect Western Power earnings in 2015 to be lower in comparison to last year, as the Alberta power market is currently well supplied and demand growth has slowed with weaker economic conditions leading to lower prices.

U.S. Power comparable EBITDA of $79 million decreased $17 million in the second quarter compared to 2014, primarily due to the timing of earnings recognition on certain contracts in our power marketing business and lower realized capacity prices in the New York, partially offset by a stronger U.S.

dollar and stronger margins and sales to the wholesale customers. Now, turning to the other income statement items on slide 19, comparable interest expense of $331 million in the second quarter increased $34 million compared to the same period last year. This was primarily due to interest charges on recent U.S.

debt issues and higher foreign exchange on interest-denominated in U.S. dollars, partially offset by Canadian and U.S. debt maturities, and higher capitalized interest.

Comparable interest income and other rose $22 million compared to the second quarter of 2014, principally due to increased AFUDC related to our rate-regulated projects, including Mexican pipelines and Energy East.

Partially offsetting the increase in AFUDC were higher realized losses on derivatives used to manage our net exposure to foreign exchange rate fluctuations on U.S. dollar income, and the impact of a strengthening U.S. dollar on translating foreign currency denominated working capital balances. Our exposure to U.S.

dollar income was largely offset with U.S. dollar denominated interest expense and financial derivatives. As a result, we saw a minimal effect from the strengthening U.S. dollar in our second quarter due to our hedging activity. However, going forward, we should see future results positively impacted, should these currency levels persist.

Comparable income tax expense of a $185 million represented an increase of $23 million versus the same period last year, due to higher pre-tax earnings and changes in the proportion of income earned in higher tax jurisdictions, partially offset by lower flow-through taxes in Canadian-regulated pipelines.

Net income attributable to non-controlling interests increased $9 million compared to the same period in 2014, primarily due to the sale of our remaining 30% interest in GTN to TC PipeLines, in April, 2015, and Bison in late 2014, along with the foreign currency translation impact of U.S. dollar minority interest in the LP.

Now, moving on to cash flow and investing activities on slide 20, cash flow remained robust with funds generated from operations of approximately $1.1 billion in the quarter, representing a 16% increase year-over-year.

Capital spending, which includes the projects under development totaled $1.1 billion in the second quarter, driven principally by NGTL System expansions, construction activities on Mexican pipelines, Northern Courier, and Napanee, along with ongoing expansion work at ANR to accommodate new contracted shale gas volumes.

Equity investments of approximately $100 million reflect activities related to the Grand Rapids Pipeline and Bruce Power. Turning next to slide 21, our liquidity, financial position, and access to capital markets remained strong.

At June 30, our consolidated capital structure consisted of 36% common equity, 5% preferred shares, 4% junior subordinated notes, and 55% debt net of cash.

From a liquidity perspective, we had approximately $600 million of cash on hand, $5 billion of committed and undrawn revolving bank lines available with our high-quality bank group, as well as two well-supported commercial paper programs.

Being one of a very small group of pipeline and midstream companies in North America with A grade credit, we believe our financial strength and flexibility provides us with competitive advantage, particularly during stressed market conditions, and positions us commercially as a counterparty of choice.

Access to capital markets at all points of the economic cycle is imperative to ensure we can execute on our growth plans and act when opportunities arise. In terms of financing activity, to-date in 2015, we've raised in excess of $4 billion on attractive terms in order to fund our capital program and refinance scheduled debt maturities.

Over the past several months, we closed the sale of our remaining interest in GTN to TC PipeLines LP, issued US$750 million of 60-year junior subordinated notes that will be accorded attractive equity credit from our rating agencies and pay $750 million in medium-term notes in Canada to fund the growing NGTL System rate base.

At the end of June, we also reset the rate on our Series 3 preferred shares from 4.0% to 2.15% for the next five years.

At that time, holders elected to convert 5.5 million of our 14 million outstanding Series 3 Shares into floating-rate Series 4 preferred shares, which will pay a floating quarterly dividend for the same five-year period at a yield of 90-day Canada T-bills plus a 128 basis points. The initial series for a rate setting was at 1.95% per annum.

In closing, the company produced very strong results from its diverse portfolio of critical energy infrastructure assets in what are challenging energy market conditions. Comparable earnings per share and funds generated from operations were up 20% and 16% respectively compared to the same period in 2014.

With a solid foundation in the form of high quality and diversified suite of assets and a sizable portfolio of small to medium sized growth projects under development, we remain committed to continue increase in the dividend at an annual rate of 8% to 10% through 2017.

Our strong internally generated cash flow from our three core businesses is expected to provide a significant source of funding for our capital program, in addition to underpinning a growing dividend. Given our financial strength, we remain well-positioned to finance our capital needs throughout various market conditions.

Finally, we also continue to advance a number of attractive opportunities in addition to our $46 billion of commercially-secured projects. That will lead to sustained growth and 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'll take questions from the financial community first. And once we've completed that, we'll then turn it over to the media..

Thank you. And the first question is from Paul Lechem from CIBC. Please go ahead..

Thank you. Good morning. Question on commentary in your written materials on your intra-Alberta oil pipeline is experiencing a slowing pace of growth.

I'm just wondering if you can elaborate on that, what that means in terms of in-service dates on Grand Rapids, I'm assuming Grand Rapids, Heartland and Northern Courier?.

Sure, Paul. It's Paul Miller here. I'll start with Northern Courier, we are proceeding with the construction of Northern Courier and it's proceeding well, targeting a 2017 in-service date.

On our Heartland pipeline, we continue to enjoy solid commercial support and we've elected to proceed with the project at a time when the committed volumes require transportation. We continue to contract up Heartland, but we're aligning the in-service date with Heartland when we need to move those volumes to the marketplace.

On Grand Rapids, we are proceeding with the in-service for Grand Rapids for initial volumes in 2016 and we will follow-up with the full system deliveries in 2017.

We do anticipate, however, a slowing growth of throughput and the build out of the Grand Rapids system to align with the slowing pace of growth of oil production that we've seen in Alberta..

Okay. So if I'm hearing you right that Heartland now has no fixed in-service dates is what you're saying..

That's correct. A lot of the commercial underpinning for Heartland is tied to Energy East and Keystone XL. And as we get better visibility to the in-service date of those two X Alberta pipelines, we'll look at the in-service date for Heartland or as we contract independent volumes on Heartland..

Okay. Thanks. And if I could just ask a couple of questions on PRGT. You haven't yet given us an updated cost for that, but the pipeline from when it was initially announced has increased by about 25% in additional kilometers – 20% I guess, some of that's under water.

So should we be thinking about like on an order of magnitude here, the costs have gone up at least 20% and potentially significantly more? Is that how we should be thinking about it?.

Paul, it's Alex. As Russ mentioned, we are seeing cost pressures on that largely for some of the reasons that you've identified, which is increased scope and some more complexity in the project. And we are – our plan when this project is finally sanctioned, we will give an update.

Our customer is fully apprised of where we are and we don't think it's going to be very much longer before we can give a bit of an update. But I don't think we're going to speculate at this point..

Okay. Thanks..

Thanks, Paul..

Thank you. The next question is from Robert Catellier from GMP Securities. Please go ahead..

So just some additional clarity here on the internal Alberta slowing.

So this is a question of just moving out the in-service dates and there is no deferral or make up for the impact to TransCanada?.

Robert, it's Paul Miller here. And just, if I understand your question, well, maybe just backup a bit. So on Grand Rapids, we're proceeding with the construction of Grand Rapids with the dual pipeline system. We have in place an anchor shipper who requires the dual system and we're targeting the 2017 in-service.

Beyond the anchor shipper, we would anticipate building out the system through laterals, et cetera, to attach to incremental production. That build-out and the bringing on of additional volumes beyond the anchor shipper will continue, but we believe at a slower pace than initially anticipated..

Okay.

And then, can I get an update on Bruce Power to see if there has been any advancements in bringing that to a final investment decision?.

Sure, Robert. It's Bill Taylor here. The status of discussions with – between Bruce Power management and the IESO on the potential transaction associated with the refurbishments of Units 3 through 8 are continuing. I can report that they're progressing well.

We haven't reached any definitive agreement at this point, but we are quite encouraged with the progress..

Okay. Thank you..

Thank you. The next question is from Andrew Kuske from Credit Suisse. Please go ahead..

Thank you. Good morning. I guess the question just relates to a bit of the capital flexibility that you've got, and how are you thinking about just your balance sheet right now, and just a bit of the interest rate dynamics across the board where you've got an environment in the U.S.

with rising rates in Canada, more compression? And then obviously, what also falls into the mix is a little bit of what we've seen in the MLP market in the U.S.

where that's really come back in pretty dramatically where you've seen about a 20% decline and a lot of the names?.

In terms of the balance sheet strength, it really doesn't vary at any point of the cycle here. It's a solid A grade credit and allows us to act on whatever might arise. In terms of interest rate exposure here, we're predominantly fixed rate finance. So in terms of horizon, U.S. rate environment shouldn't have any significant impact on us.

In general, we have about – average turnover of about 16 years and we're over 90% fixed rate funded, and a rising interest rate environment as well. We have a significant cost pass-through ability on several of our projects and assets. So, the things we can control in the interest rate front we think we're in pretty good shape there.

We'll see what the FX dynamic here as you can do see rate diversions between Canada and the United States. Just from an FX perspective, for every $0.10 move in the currency – yeah, every $0.10 move in the currency, it's about $0.10 impact on earnings. We do hedge on a rolling one-year forward basis here.

So, not seeing much impact from this fairly sizable shift in the currency over the past 12 months coming through yet, but we should start seeing that come through in future quarters and years here. In terms of the overall environment looking at assets and the like, we're being who we are. We see pretty much everything that transacts in North America.

So we're as always interested observers. If anything comes loose that they might be of interest and fits our criteria, but really no change at this point of the cycle from any other point of cycle other than we will see what if anything does arise..

That's helpful. And then maybe just a follow-up. You know moving away from just the interest rate movements themselves, maybe just on spreads.

Are you seeing less movement with the A credits like yourself versus the BBB and BB kind of credits that are in the marketplace right now?.

Yeah. It's pretty broad spectrum of credits out there, but generally it's when you do see stressed market conditions where the A diverges from the lower rate of credits more dramatically, that's the environment we appear to be headed into.

So the benefits of the A are probably more pronounced in these choppy market conditions than when things are robust across the complex..

Okay. That's very helpful. Thank you..

Thanks, Andrew..

Thank you. The next question is from Robert Kwan from RBC Capital Markets. Please go ahead..

Good morning.

If I can just start with Keystone, just wondering if you're part of the better results as well? Are you seeing a trend to any shippers bypassing Steele City and sending more crude into the Gulf Coast?.

Rob, it's Paul Miller here. The Gulf Coast market has seen increased activity on Keystone or Keystone seeing increased activity on to the Gulf Coast, largely sourced at Cushing. The Cushing market from Hardisty based barrels continues to be the market of choice, it seems. We saw the spreads pretty strong here between Hardisty and Cushing.

In the first quarter, they collapsed into the first part of the second quarter, but they seem to have rebounded a bit here. So we're seeing good flows into the Cushing market and then from the Cushing market down to the Gulf Coast..

Okay.

And so, there is though a financial benefit to you just with the way you're picking up volumes on the southern part of the system?.

There is. We're flowing about, little, about 450,000 barrels per day on the southern part of the system. That's up from about 400,000 barrels a day late last year and into the first quarter. On Keystone, we've seen our flows increase into about the 550,000 barrel per day range and that's been fairly sustained over the course of 2015..

Okay. If I can just look at around more capital allocation in the dividend, and you got two upside options here one around the value of all the projects you've got and then also around doing something on the dividend. I recognize you don't want to do anything to jeopardize the value of the projects by painting yourself into a corner on funding.

I guess though when you look at the delays in Alberta and look at how NRG's has been pushed back and Keystone XL has been pushed back, it kind of feels like if that's to come together regardless, it's just going to be a size that you can't finance at your cash flows.

So, is there an ability to move the payout ratio up a little bit just to get that dividend growth that you have at 8% to 10% to something north of 10% to be a little more competitive with your North American peers?.

Yeah, it's Don here. The capital program is still in that $6 billion range for the next couple of years here as well. So, it's not entirely hinged on the large projects. There is quite a sizable portfolio of the small to midsize stuff that we continue to finance. So, we expect to add to that portfolio here over time.

So, it's a balancing act in terms of prudency and we recognize fully the value that our shareholders place on the dividend and the growth in that dividend. We think earnings do matter. So, that is a metric that factors into it.

But yeah, this 8% to 10% range is our comfort level right now based on what we have in front of us and with the A grade credit and the like and we continue to revisit that as we see our portfolio develop with twists and turns here..

I'd just add to that, Robert. This is Russ. I mean as we've said before, the 8% to 10% is predicated on our projects that we've got underway. If you get us into that range of, into the higher range, there would be greater confidence around the future of those capital projects.

So as we see greater visibility, those actually coming to fruition whether that be our West Coast LNG projects or the long haul oil projects, or even some of the other projects that we're working on in our portfolio right now that are substantial.

If we see direct line of sight to that long-term earnings and cash flow growth, we don't have a major issue with increasing our payout ratio in the short run. But as we said, in order to kind of to get above that 8% to 10% level, we want to have some greater visibility around those longer term projects and certainly that's what we're working on..

Yeah, we're not going to hold back dividend growth to store up capital for these large projects and the magnitude of them aside, they are all heavily or fully contracted for decades. So, we're pretty comfortable in the financability of those projects.

We view it as a high-grade problem if we did have to get out in the marketplace and finance them, but that's the dynamic we're looking at right now. We're not going to hold back dividend growth and we may augment it if we have greater clarity on earnings and cash flow growth going forward..

Okay. So, any step up in dividend growth really is tied to larger projects.

Is there anything else that you might be considering that could develop that would cause you to want to move the payout ratio up?.

Well, I think as we said, I mean is that the long-term projects are one with greater visibility of growth in our base business. As we've said, there is several organic projects on our horizon, greater visibility of build-out to the NGTL System, the ANR System bringing Marcellus gas moving south and the expansions of those kinds of systems.

As we see our base business continue to grow as well, that gives us greater confidence. I think as Don said, earnings do matter to us, but it's sort of visibility of the growth in that and that the payout ratio in the short run isn't major sort of factor. It's where we think things are going over the long term.

So there's obviously those shorter-term organic projects, greater efficiencies that we can gain in our base businesses. Along with those greater visibility, future opportunities will be the things that drive our dividend decisions over the coming quarters and years..

That's great. Thank you very much..

Thanks, Robert..

Thank you. The next question is from Linda Ezergailis from TD Securities. Please go ahead..

Thank you. I'm wondering on your NGTL project, what is the scale of possibility in terms of further requests? And I'm assuming it somewhat constrained by your ability to develop in that region.

So can you talk about if this is more of an backend loaded this decade or if there's some potential in some ways to accelerate some of your expansions there?.

For the NGTL – so it's Karl, Linda. Right now, as you know, we're undergoing about a $2.7 billion of expansion of that system. We have regulatory applications in for about $2 billion of that, and we're working on the rest right now. We're seeing a very little slowdown in that expansion. Our customers are asking that we proceed on it.

And we – although, we may see some of it extend into 2018, we're expecting the vast majority of it to be completed in 2017. Aside from that, we have close the queue recently. On NGTL, we have more receipt service requests from transportation on NGTL right now in front of us.

We're just going through the system design for that request and we will hopefully in the next couple of months be able to determine what type of expansion that will be.

Probably, it won't be as big as a $2.7 billion expansion that we're undertaking right now, but there is a reasonable amount of receipt service requests in front of us right now for – that people are asking for us. So, we will have some expansion coming over 2018 and beyond..

Thank you.

And just a follow-up, Karl, your – some of the pressure restrictions you're seeing right now, do you see that being on schedule to get resolved with the NEB?.

Yeah, we're expecting the NEB issues – the derisks from the NEB we expect, so we're still kind of expecting kind of September, maybe late September to have them all lifted. The pressure restrictions you're seeing right now is clearly on the Western side of our system. Kind of Western Alberta and Northeast B.C.

are both from our integrity work, both are normal to the integrity work. And the integrity work we requested from the NEB and our regular maintenance process right now, as this part of our system is extremely firm. And we have been setting interruptible transportation quite significantly over the last few months.

And hopefully by the end of Q3, we will have most of the maintenance integrity done, and we'll have some more interruptible transportation for our customers. But really the most of the tests that we have done have been the interruptible transmission. We have seen some firm service cuts, but they have generally been isolated in short duration.

But we do hope by the end of the Q3 that we'll have reestablished that interruptible capacity for our customers back again..

Great. Thank you. And just as a follow-up on your Alberta power hedging philosophies and approach, I realize there is some competitive dynamics and sensitivity.

But can you comment on how much you've been dispatching your PPA contracts? And to the extent that that has maybe come down in expectations as well for the next year or two, is there, I guess, a bias towards less to no contracting to ensure you're not long power during these lower price times, or can you comment on how you're approaching the Alberta fleet?.

Yeah. You're correct, Linda, that we don't typically like to discuss the approach we're taking to the Alberta market in any detail for competitive reasons.

But I can tell you that we approach it cautiously as it relates to – you saw some of the activity in late May and into June that impacted the quarter as it related to some outages in the Alberta market.

So we approach our program pretty carefully, as it relates to ensuring that we're well positioned to not only capitalize on those kinds of opportunities, but also to ensure that we don't find ourselves on the wrong side of events like that.

So, I mean, in terms of going forward, I think that the market, as Don mentioned in his opening remarks is, at present pretty well supplied. We're seeing some reductions in overall demands with the general economic climate in Alberta at the moment.

And so we're cautiously optimistic that there may still be some opportunities in the latter half of the year. Our prices have obviously been quite well other than the adjustments that occurred in June due to some outages. So, I mean, that's about all I guess I cans say on that..

Okay. Thank you..

Thank you..

Thanks, Linda..

The next question is from Rob Hope from Macquarie. Please go ahead..

Thank you and good morning, everyone..

Good morning, Rob..

Most of my questions have been answered, but maybe just a few clarifications.

On the Grand Rapids, can you maybe comment on how much anchor volumes you have on the system and what's an expected ramp in returns would be on that?.

Hi, Rob, it's Paul Miller here. We haven't released the anchor volume commitments. The Grand Rapids has the capability of moving 900,000 barrels per day of blend Southbound and then dealing with Northbound. The anchor ship in itself provides us with threshold volumes to proceed and with a suitable return.

We'll probably start the capacity of Grand Rapids out of the gate at a lower amount in that 500,000 to 600,000 barrel range and then add power as we go. But we haven't disclosed the shippers commitment and it's inappropriate for us to do so, but is enough to proceed with the project and then attract additional barrels as the production grows..

All right. Thanks for that. And then maybe just shifting East. I just noticed that the Eastern Mainline in-service date shifted to 2019 from 2017 in your disclosure versus Q1. Is that just to run it up in terms with the energy oil project or rather....

Yes..

Yeah. Rob, it's Karl. That's just where we're just lying it up with the Energy East project..

All right. Good to hear. Thank you..

Thank you. The next question is from Matthew Akman from Scotiabank. Please go ahead..

Thanks. Good morning..

Good morning, Matt..

Couple of questions just around the triggers for construction on Pac NorthWest LNG, and obviously the permitting is going very well at the potential level. And on the other hand, some of the First Nations' stuff is little more choppy.

So I'm just wondering, let's say, we get an FID, would TransCanada begin construction on the pipeline even if there – even if some of the First Nations legal challenges persist?.

Hey, Matthew, it's Alex. I think we've always said with this project, I mean, we seek to reach agreements with all of the affected First Nations.

And I think if you've seen our disclosure over the last couple of months, you've seen that we've been making a significant amount of progress in signing project agreements with a number of the bans on both of the projects.

From our perspective, we believe that – we will, by the time this project is ultimately sanctioned, reach agreement with a vast majority of affected First Nations. And it has never been a criteria for us that we reach – that we get a 100% of those. That's obviously what we strive for.

But we think we're well on the way of getting a significant pace of support for this project to proceed..

Yes.

Can you just please confirm, Alex, that any risk related to any legal challenges or tolling issues on North Montney on the project are the risk of PETRONAS and not TransCanada?.

Sorry. On the North Montney....

First, on the Pac NorthWest LNG, if there is any risk related to legal challenges following construction commencement, whose responsibility is that, TransCanada or PETRONAS?.

Well, it's Karl, I can talk about the North Montney and that's an NGTL project. So we would be – that would be the risk of building that infrastructure would be part of the NGTL infrastructure. So, I guess, if we had any delay or whatnot, that would be between NGTL and our customers there..

With respect to PRGT, I mean, the way that it's constructed, Matthew, is that we're building this on behalf of our customer. And for the most part, all of the risks pass through to that customer. It's a hypothetical question that you're asking that's got a myriad of potential outcomes, which I wouldn't want to speculate at this point in time.

As Alex said, our intent is to get as many First Nations agreements as we can and we believe that our agreements will protect our shareholders, but, I mean I don't think I can share with you much more than that at this point in time..

Okay. Thanks, guys. Those are my questions..

Thanks, Matthew..

Thank you. The next question is from Steven Paget from FirstEnergy Capital. Please go ahead..

Well, thank you and good morning.

Karl, could you please update us on progress at Clearwater and what we can expect in the remainder of the third quarter at that station?.

For the – you mean the outage that we have there?.

Units 1 and 5, yes..

Yeah. So we're making good progress. We are expecting it to be a reestablishment from service here before the end of the third quarter. So that's what all I can say right now. It's quite a recent issue that we've had, but we are working on getting it back up..

Thank you. Second question. The Magellan announcement looks like it gives some optionality to the Houston delivery and the Keystone XL.

Is there an opportunity to add similar connectivity to the Port Arthur or is that pretty much got all the connectivity it needs?.

Hi, Steven, it's Paul Miller here. So you're accurate on the Magellan opportunity.

We're excited about being able to team up with Magellan and allow us to essentially access the 2 million barrels per day plus refining capacity in the Houston, Texas City marketplace, and that's a business model we like where we can team up with folks downstream of us to encourage flows on the Keystone System.

So we'll continue to look for similar opportunities in all the markets we serve, including the Port Arthur marketplace and I do think there is opportunities in Port Arthur..

Opportunities there. Thank you. Final question, if I may.

Are we looking at any further dropdowns to TC PipeLines, LP in the remainder of the year?.

It's Don here. Yeah, I can't give you a specific timing, but we're still on a path to bend the rest of our U.S. gas pipes into that vehicle on a systematic basis. So there has been no change to our thinking..

Well, thank you. Those are my questions..

Thanks, Steven..

Thank you. We'll now take questions from the media. And the first question is from Ashok Dutta from Platts. Please go ahead. Mr. Dutta, your line is open..

Hi. Good morning. Two very quick questions, if I may, please.

When or at what stage will you take a call on the single export terminal at Energy East?.

Hi, Ashok. It's Alex Pourbaix. As Russ said in his prepared remarks, we are well advanced in the process of determining the ultimate configuration for Energy East. We stated that our plan is to file an amendment with the National Energy Board prior to the end of the year.

I think we're still on that path and we are relatively close to making that decision..

Okay.

And the second question, in that case, in case there is only one terminal, how would refineries in Québec be served?.

Even in the event that we were to proceed without our marine terminal in Québec, all options that we are considering would continue to have the pipeline direct connected to the Québec refineries. So under any scenario, Energy East will be able to serve the overwhelming need of those refineries in Québec..

Okay, lovely. Thanks..

You're welcome..

Thank you. The next question is from Julien Arsenault from The Press Canadian. Please go ahead..

Hi, and thanks for taking my questions.

Regarding the possibility of another terminal in Québec, how's been the evaluation process right now? Has it been more difficult that you thought and have you had discussions with some towns regarding this possibility?.

Thanks for the question, Julien. Once again, Alex Pourbaix here. We have undergone a really comprehensive review of all of our options, and those go from looking at alternative sites along the St. Lawrence within Québec to, as we mentioned, potentially just going with one marine terminal into Brunswick.

In all of those cases, we have engaged with stakeholders and we'll make an informed decision based on all of those discussions and the information we gathered from that..

Okay. And second question, I wanted to get your thoughts, TransCanada. For the last month-and-a-half, the tone of the Prime Minister of Québec seems to have changed regarding Energy East. He now says that the financial impact are not sufficient enough in Québec for the government to give us approval to the project.

What do you make of that change of tone from the last month-and-a-half?.

I'm not sure there's been a significant change in tone. I think from the very early days, both the Québec government and the Ontario government, have indicated that their conditions for support include looking at the economic benefits of the project to their respective provinces.

I think something that is often lost in this discussion is whether or not you talk about a marine terminal, there is already an extraordinary economic benefit for those provinces.

I think my recollection is that just through the construction period and operation period in Québec alone, we and our consultants are estimating GDP impact in excess of $6 billion. We're going to employ 4,000 people alone full-time equivalent through the development and construction stage.

But on top of that, we really do take seriously that these projects have to provide long-term benefits in the provinces in which they're situated.

You might have seen several months ago, we announced in Peterborough with GE, that as a result of Energy's proceeding, GE has been able to make a commitment to move their large industrial motor production, global center of excellence to Peterborough. That's totally based on the Energy East project proceeding.

And I would just suggest that everybody should stay tuned, because over the next several months as we give more clarity on Energy East on the scope and the alignment of the project, we also intend to roll out a lot more positive information about the benefits of this project to the provinces.

We're not at all concerned at the end of the day that this project will pass that criteria of providing economic benefit for the provinces..

Okay. Thanks. Was that Mr. Pourbaix or who answered my question, not sure of the voice..

Yeah, it was Alex Pourbaix..

Okay. Thanks..

Thank you..

Thank you. The next question is from Lauren Krugel from The Canadian Press. Please go ahead..

Good morning. I'm just looking at the capital program chart and the figures for the cost estimates and how much has been spent. And I see about $700 million on for Energy East.

I'm just wondering at this stage in the process what that figure would have been spent on given that it is so early on?.

Well, I think the first thing you have to look at is first of all, this is a 4,500 kilometer project. It has 75 pump stations. This project has very, very significant scale and scope.

And where the regulatory process has gone in order to make a regulatory filing, a very significant amount of field work, environmental studies, technical studies, engineering reports needs to be prepared along with preliminary engineering. All of this is required just to inform the application.

On top of that, there is a real significant obligation, and something that TransCanada would do in any event, but to work with stakeholders in the regions. And to give you an idea, we have held in excess – I think it's somewhere in the range of 120 open houses.

We've worked with the better part of 8,000 or 9,000 individuals in terms of our stakeholder outreach. The last I saw, we have already held 1,600 meetings with affected First Nations along the route. And as you can imagine, all of that work has costs associated with that.

The one thing I would say is that at where we are right now in terms of costs for the project, there is very little incremental costs required to get us to the regulatory hearing stage. So, a lot of that number that you saw is, we don't expect that number to get significantly larger prior to the hearing.

The other issue that I should also mention is, in order to make the application, we also have to satisfy our regulator that the pipe, the existing gas pipe that we are proposing will be converted to oil usage.

We have to do a significant amount of integrity work on those pipes and that work has been done once again to inform our application and give comfort to the regulator..

Okay. Thanks for the clarity on that. And that sounded like Alex answering the question..

Yes. Sorry, Alex again..

Okay. Great. Thanks so much..

Okay..

Thank you. The next question is from Rebecca Penty from Bloomberg News. Please go ahead..

Thanks for taking my question. It's about Keystone XL. As you guys are well aware, there has been lots out recently regarding the potential for Obama to reject Keystone XL in August when the Senate leaves.

I'm just wondering in terms of the possibility of a NAFTA challenge and an investor state dispute settlement, as it's called, I'm wondering, how TransCanada is looking at the potential of that and any kind of remedy that the company would have in the event that Obama doesn't relent?.

I think as we've said before, Rebecca, I mean TransCanada will employ whatever means necessary to protect its shareholders, and its shareholder value, but that's not our focus at the current time.

As I said, our focus is on the regulatory proceedings as you know in South Dakota, and working through those issues, working through the outstanding Supreme Court issues in Nebraska and getting ourselves in a position so that we can construct this facility upon a positive decision by the Department of State.

With respect to rumors and things like that, we've been at this for seven years now and there have been lots of rumors about lots of different things. And we continue to just sort of focus on the things that we're good at, which is trying to get a safe and reliable pipeline built.

I don't want to speculate on what happened sort of post or any kind of scenarios or outcomes. At this point in time, it's not our focus..

Would you comment at all on how you see that, like whether it could be successful, any kind of NAFTA challenge?.

As I said, it's not at this point in time, that's not a focus that we have. No decisions have been made, so it'd be premature to speculate on anything like that..

Thank you..

Thank you. The next question is from Claudia Cattaneo from the National Post. Please go ahead..

Hi. Thanks for taking my question. Actually, I'd just like to follow up on the last one. I know that your focus is not on what other options you might have on Keystone XL.

But if it does get rejected, would you just re-file a new application under a new administration? And would a re-filing basically involve, like can you use some of the work that you've already done or it would have to be a complete re-filing of an application for Keystone XL?.

Claudia, as I said, no decision has been made, so difficult to speculate on that. I guess what I can tell you is that the demand for the project is greater than it was when we made the application. I think as you've heard me say before, production is up in Canada. We're moving more barrels by rail, production is up in the U.S. coming out of the Bakken.

They're moving that production by rail. Demand is up in the U.S. So the need for the pipeline remains. All of our shippers remain 100% supportive even through the decline in commodity price here that we've seen. We've gone back to all of our shippers.

As I said, we continually work with them on all of our projects to understand what changes in commodity prices will have on their future needs. They've reiterated their need for Keystone Pipeline and their commitment to their contracts. So, it'd be our intent to continue to press to build that pipeline because the demand doesn't change.

So, obviously that would be our intent under any scenario is to continue to press for the approval of building this pipeline. What that would require in the event that you outlined, we can't speculate on what that is, because we don't what that looks like at the current time.

But, certainly, we don't see there is any rationale at the current time for a negative decision. As I said in my prepared remarks, the greenhouse gas emissions question has been answered several times by the Department of State in its environmental review.

The question of safety has been answered and at the current time, we see no rationale for anything but a positive decision. So that's when we continue to press and provide information to the Department of State that help them augment the current record and drive towards making a positive decision..

If I may, just a follow-up. You highlighted in a recent letter to the State Department the fact that Alberta has implemented more stringent climate change regulations.

Have you heard any response at all about that?.

No, we haven't. We filed that information as we do on a continuous basis with the Department of State any material updates.

And given the greenhouse gas emissions question has gathered so much attention, we wanted to ensure that the record was as full as possible and have indicated; a) that the decision or the conclusion had already been come to that the pipeline won't have an impact on greenhouse gas emissions.

The ETA had indicated on several occasions that Canada could be doing more, so we updated the Department of State with, as you pointed out, the most recent changes in Alberta emission regulations, which increased the stringency on a per barrel basis in terms of reduction emission targets and increased the penalties if you will.

If emissions are above those levels, that's a significant incentive for the industry to continue to reduce greenhouse gas emissions, they continue that. At the same time, we updated the Department of State on Canada's commitment to greenhouse gas reductions.

They had made certain statements with respect to their position, going into Paris, the 30% reduction by 2030, their 2050 reduction targets and the 2100 reduction targets as well. So, in terms of the greenhouse gas emissions questions, what our intent there was, was to ensure that the record was up-to-date as much as possible.

And I guess, again to indicate that the Canadian production continues to be a leader and Canadian jurisdictions continue to be a leader in greenhouse gas emissions reduction standards relative to either producing countries or around the world..

Thank you..

Thank you. There are no further questions registered at this time. I'd like to turn the meeting back over to Mr. Moneta..

Thanks very much, and thanks to all of you for participating this morning. We very much appreciate your interest in TransCanada, and we look forward to talking to you again soon. Bye for now..

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