David Moneta - Vice President, IR Russ Girling - President and CEO Don Marchand - EVP and Chief Financial Officer Alex Pourbaix - EVP and President, Development Karl Johannson - President, Natural Gas Pipelines Paul Miller - President, Liquids Pipelines Bill Taylor - President, Energy.

Linda Ezergailis - TD Securities Carl Kirst - BMO Capital Markets Rob Hope - Macquarie Paul Lechem - CIBC Robert Catellier - GMP Securities Robert Kwan - RBC Capital Markets Andrew Kuske - Credit Suisse Steven Paget - FirstEnergy Capital Ashok Dutta - Platts.

Good day, ladies and gentlemen. Welcome to the TransCanada Corporation 2015 First 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 afternoon everyone. I’d like to welcome you to TransCanada’s 2015 first 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, Development; Karl Johannson, President of our Natural Gas Pipelines business; Paul Miller, President of Liquids Pipelines; Bill Taylor, President of Energy; and Glenn Menuz, Vice President & 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 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 will 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 with the U.S. Securities Exchange Commission.

And finally, I would also like to point out that during this presentation, we will 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 TransCanada’s operating performance, liquidity, and its ability to generate funds to finance its operations. With that, I’ll turn the call over to Russ..

Thank you, David and good afternoon everyone. And thank you all very much for joining us late on Friday afternoon. Delivering results and positioned for a growth is the theme of our 2014 Annual Report to shareholders and the theme of our address this morning at our Annual General Meeting. And those words simply describe our strategy.

With $64 billion of high-quality assets across North America, we are situated to take advantage of unprecedented opportunities and deal with unprecedented challenges that lie ahead of us.

As we advance our industry leading $46 billion capital program of commercially secured short and long-term projects, we will enhance our competitive position in each of our three core businesses and continue to deliver significant growth in earnings, cash flow and dividends.

Focusing first on first quarter results, comparable earnings were up 10% in Q1 of 2014 to $465 million or $0.66 per share. Comparable EBITDA was also up by 10% to $1.5 billion and funds generated from operations were up 5% to $1.2 billion.

Strong performances in the quarter from each of our three core businesses contributed to that increase in comparable earnings and funds generated from operations. Strong performance from our Keystone System; Eastern Canadian Power and U.S. Power businesses helped offset lower Alberta Power prices.

This clearly demonstrates the value of a large and diversified portfolio of assets. Today, our Board of Directors declared our quarterly dividend of $0.52 per common share for the quarter ending June 30, 2015. This equates the $2.08 per share on an annualized basis.

In a moment, Don Marchand, our CFO will discuss our financial results in a bit more detail but I’d l like to now give you a brief update on our progress over the quarter on some of our major projects.

Starting with our gas pipeline business, we are now close to almost double the rate base of the NGTL System with nearly $7 billion of new supply and demand the management facilities under development. We also continued to advance several facility expansion projects in the first quarter by filing regulatory applications with the National Energy Board.

That’s a process that we’ll continue through 2015 and into 2016. We’ve also received further request for firm service that we anticipate will increase the overall capital spend on NGTL System beyond what we have previously announced. And service dates for the majority of those initiatives run through 2016, ‘17 and ‘18.

North Montney, we received some positive news just a few weeks ago from National Energy Board, recommending approval of that North Montney project that $1.7 billion natural gas pipeline would provide substantial new capacity on the NGTL System to meet the needs of the rapidly expanding Montney supply basin in Northeast British Columbia.

Besides connecting supply to existing natural gas markets, North Montney would connect a proposed -- connect with our proposed Prince Rupert Gas Transmission Project to supply gas to the proposed Pacific NorthWest LNG liquefaction facility and export facility near Prince Rupert, British Columbia.

We expect to phase North Montney into operation in 2016 and 2017. NEB approval is subject to certain conditions, including a positive final investment decision of the Pacific NorthWest LNG facility. Further on Prince Rupert, we expect decisions in the second quarter on permits from the B.C. Oil and Gas Commission.

These permits are required to build and operate that pipeline. As I said previously, we continue to work with Progress/Petronas, the project sponsors and our contractors to refine project costs in anticipation of a final investment decision later on this year.

Prince Rupert Gas Transmission is a 900 kilometer pipeline that we deliver natural gas from the Montney producing region near Fort St. John through an interconnect of the NGTL System through the proposed Pacific Northwest LNG facility near Prince Rupert, British Columbia.

Similarly on our coastal gas link project, we anticipate a decision on permits in the second quarter from the Oil and Gas Commission in British Columbia. That 670 kilometer pipeline would deliver natural gas from the Montney producing region again to LNG Canada’s proposed LNG facility near Kitimat, British Columbia.

The project is also subject to regulatory approvals and an FID is expected in early 2016. Moving to our oil pipelines on Energy East in April, we announced a decision to not build the marine terminal and associated tank terminals at Cacouna, Quebec. Potential alternative export terminal options in Quebec are being reviewed.

The existing delivery points to refineries in Montreal, Lévis which is near Quebec City and St. John and the export terminal in St. John are not impacted by this review.

This decision to move away Cacouna was a result of recommended changes in the status of the beluga whales to an endangered species and ongoing discussions we have had with communities and key stakeholders. We have listened to those conversations and our decision reflects that.

Our goal has to been strike a balance between TransCanada’s commitment to minimizing environmental impacts and the imperative to build modern infrastructure to safely transport the energy Canadian’s need and consume every day.

The National Energy Board has been advised of our decision with respect to Cacouna, amendments to the application for Energy East are expected to be filed with the NEB in the fourth quarter of 2015. The result of this change, the project scope and further refinements of the project schedule are expected to result in an in-service date of 2020.

This 1.1 million barrel per day pipeline will transport oil from western Canada, eastern Canadian refineries, creating jobs, add to revenue and energy security for all Canadians. The Keystone XL, we continue to work through the permitting process being led by the U.S. Department of State.

Our current focus is on preparing for the South Dakota Public Utility Commission hearing on TransCanada’s request to certify Keystone XL’s existing permit authority in the state.

As you’re aware, the timing of the ultimate resolution of the decision on the presidential permit for the pipeline project remains uncertain but I believe that the facts will prevail at the end of the day and we’ll eventually receive a permit and Keystone XL will be built.

Our shippers continue to be 100% supportive of the project and despite the dip in oil prices, the need to safely transport new Canadian and U.S. crude oil to marketplace remains.

Moving over to Energy, in January, we began building the 900 megawatt Napanee natural gas-fired power plant at Ontario Power Generation’s Lennox site in eastern Ontario in the town of Greater Napanee. That $1 billion plant is anticipated to begin operation in late 2017 or early 2018.

Power produced at that facility is fully contracted for 20 years with the independent electric system operator in Ontario. To conclude, despite the current low commodity price environment, I’m very pleased with the performance of our businesses and our assets in the first quarter.

Looking forward for the remainder of 2015 and beyond, you can expect us to remain focused on our four key priorities, specifically to maximize the value of our $64 billion asset base; secondly is to move our $46 billion capital program from concept to cash flow; and thirdly to continue to cultivate new opportunities to prudently reinvest our growing cash flow in the years ahead; and lastly, to maintain our financial flexibility and discipline to ensure we can continue to fund our growth in all market circumstances and conditions.

These are the priorities that guided us in our growth for about the last 15 years. And I believe continued disciplined execution of those priorities will result in growth in earnings, cash flow and dividends and growing shareholder value for many years yet to come.

I’ll now turn the call back over to Don for some more details on our financial performance in the first quarter. Don, over to you..

Good afternoon everyone. As Russ highlighted earlier, net income attributable to common shares in the first quarter was $387 million or $0.55 per share compared to $412 million or $0.58 per share for the same period in 2014.

Excluding unrealized gains and losses from changes in various risk management activities, comparable earnings in the fourth quarter of $465 million or $0.66 per share, increased $43 million or $0.06 per share compared to the same period last year.

The 10% rise in comparable EPS was primarily due to increased contributions from the Keystone System, the Tamazunchale Extension in Mexico, Eastern Canadian Power and U.S. Power partially offset by lower power prices in Western Power, weaker spreads in Natural Gas Storage and high interest expense.

In terms of our business for segment results at the EBITDA level, our natural gas pipelines business generated comparable EBITDA of $874 million in first quarter 2015 compared to $848 million for the same period last year.

Canadian gas pipelines comparable EBITDA of $522 million decreased $44 million compared to 2014, primarily due to the Canadian Mainline’s long term settlement with shippers which includes the lower embedded allowed ROE.

The 2015 to 2020 tolling agreement which took effect in January, will create long term commercial stability and certainly for the Mainline. As part of this agreement, we agreed to a base allowed ROE of 10.1% before annual $20 million contribution versus an 11.5% allowed ROE last year.

This lower allowed return in combination with the lower investment base, primarily stemming from the positive toll stabilization account balance at the end of 2014, led to the $19 million year-over-year reduction in net income from the Mainline.

NGTL’s net income increased slightly versus first quarter 2014, as a result of growth in its investment base. So for the boarder U.S.

and international pipelines comparable EBITDA rose $79 million to $370 million in first quarter 2015, primarily as a result of higher earnings in the recently completed Tamazunchale Extension, a recovery of third party pipeline damages on ANR and the positive impact of a stronger U.S. dollar.

In liquids, the Keystone Pipeline System generated $314 million of comparable EBITDA in the first quarter, an increase of $66 million from last year. This was a result of our full quarter’s contribution from the Gulf Coast extension, higher volume throughput and the favorable impact of a stronger U.S. dollar.

Turning to Energy, comparable EBITDA was up $43 million to $388 million in the first quarter due to a combination of factors. Eastern Power comparable EBITDA rose $38 year-over-year due to sale of unused gas transportation capacity, higher contracted Bécancour earnings and the contribution from recently acquired solar facilities.

Bruce Power equity income increased $15 million as a result of fewer outage days, partially offset by higher operating expenses. Bruce is currently in the midst of its planned 30-day vacuum building outage that requires to take down all four units. Unit 6 on the B side will continue on outage beyond the BBO.

All of this work is on track and progressing well. Western Power comparable EBITDA decreased $57 million due to lower realized power prices. Lower demand, driven in part by a mild winter along with new supply and strong overall fleet performance have been contributing factors to historically low operator spot power prices.

While this offense is expected to persist in the near-term and result in lower overall earnings in 2015 for Western Power as compared to last year, we don’t see current prices as sustainable in the medium to longer term. U.S. Power comparable EBITDA of $164 million increased $70 million in the first quarter compared to last year.

The significant increase was influenced by the timing of recognizing earnings in our power marketing business and a stronger U.S. dollar partially offset by lower realized power prices in New England and New York. In our U.S.

Power business, while much of this supply is sourced at flat prices over multiple periods, customer pricing is typically shaped to the market and as such has resulted in higher realized prices in the first quarter to be offset by lower prices throughout the rest of the year.

The volatility in natural gas and power prices experienced in the winter of 2014 has caused the more pronounced impact on our 2015 contracts which in turn magnifies the normal seasonal timing differences in earnings.

The majority of these earnings -- higher earnings recorded in the first quarter of 2015 will be offset by lower earnings in the second quarter.

Natural Gas Storage comparable EBITDA declined $24 million to $3 million in the first quarter due to lower realized storage spreads and the absence of natural gas pricing volatility that occurred in the first quarter of 2014. Now, turning to the other income statement items on slide 16.

Comparable interest expense of $318 million in the first quarter increased $44 million compared to the same period last year. This was primarily due to higher interest charges on recent U.S. dollar debt issues, higher foreign exchange on interest denominated in U.S. dollars, and lower capitalized interest partially offset by Canadian and U.S.

debt maturities. Comparable interest income and other rose $21 million compared to the first quarter of 2014, primarily 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 the 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 highlighted in the past, the stronger U.S. dollar is not expected to have a material impact on earnings in 2015 but could benefit comparable results in 2016.

Comparable income tax expense for first quarter 2015 increased $23 million versus the same period last year due to higher pretax 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 $5 million compared to the same period in 2014, primarily due to the sale of our remaining 30% interest in Bison to TC Pipelines LP in late 2014 and the foreign currency translation of U.S. dollar minority interest in the LP. Now moving on to cash flow and investing activities on slide 17.

Cash flow remains strong with funds generated from operations of approximately $1.2 billion in the quarter.

Capital spending totaled $1 billion in the first quarter, driven principally by NGTL System expansions, construction activities in Northern Courier, Napanee and our two Mexican pipelines and ongoing expansion work at ANR to accommodate new contracted shale gas volumes.

Equity investments of $93 million in the quarter reflect activities related to the Grand Rapids pipeline and Bruce Power. Turning next to slide 18, our liquidity and access to capital markets remain strong.

At March 31, our consolidated capital structure consisted of 37% common equity, 5% preferred shares, 2% junior subordinated notes and 56% debt, net of cash. We have $1.8 billion of cash on hand along with $5 billion of committed and undrawn revolving bank lines available with our high quality bank group.

Our two commercial paper programs, one in Canada and one in the U.S. remain well supported and continue to provide flexible and very attractive sources of short-term funds. It’s been a busy start to the year in terms of financing activity.

To date in 2015 we’ve raised over $2 billion on attractive terms in order to fund our capital program and refinance scheduled debt maturities. In January 2015, we issued U.S. $750 million of three-year senior notes in two tranches. U.S. $500 million of fixed grade notes at 1.875% and U.S.

$250 million for floating rate notes at LIBOR plus 79 basis points with the initial rate setting at 1.045%. In March, we completed a $250 million preferred share issue in Canada. The Series 11 cumulative redeemable first preferred shares carry an initial dividend rate of 3.8% which is fixed to November 2020. We also raised U.S.

$750 million of 30-year maturity senior notes in the Taiwanese market in March which bear interest of 4.6% and are redeemable at par in March 2020 and annually thereafter. Finally, on April 1, we closed the sale of our remaining 30% interest in GTN to TC Pipelines LP for U.S. $446 million comprised of U.S. $253 million of cash proceeds, U.S.

$90 million of assumed debt and U.S. $95 million of new Class B units issued to TransCanada. The transaction advances our commitment to drop down the remainder of our U.S. natural gas pipeline assets over the coming years as a means to help fund our capital program.

In closing, the company produced solid results from its diverse suite of blue chip assets in what are challenging energy market conditions. Comparable earnings per share and funds generated from operations were up 10% and 5% respectively compared to the same period in 2014.

We remain well positioned to finance the remainder of our $12 billion in small to medium size projects through various funding sources which include predictable and growing internally generated cash flow from our three core businesses, LP dropdowns and senior debt consistent with our A-grade credit rating.

In addition subordinated, capital in the form of preferred shares and hybrid securities are also expected to form part of our financing strategy. Beyond our $12 billion of shorter term projects, we continue to advance a broad portfolio of attractive growth initiatives including $34 billion of commercially secured projects.

While the timing around the $34 billion of larger scale projects remains subject to regulatory processes and customer final investment decisions, they are all underpinned by substantial long-term contractual support underscoring the need for new infrastructure to bring supply to market.

In the meantime, we are confident that our current asset footprint will allow us to capture incremental investment opportunities that will lead to sustained 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 back 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. With that I’ll turn it back to the conference coordinator for your questions..

Thank you, we’ll now take questions from the telephone lines, first from the analysts. [Operator Instructions]. The first question is from Linda Ezergailis from TD Securities. Please go ahead..

Thank you, I have a question with respect to the pent-up demand for the NGTL System expansion.

And can you maybe provide some color around the nature of that additional demand; what might be the timing and uncertainty of firming it up; what would be the potential associated capital expenditures of that and specifically how much might be dependent on LNGX where it’s going ahead?.

Yes, the demand right now is we would be looking at for in-service for 2018. I don’t have a definite number of new receipt service as being requested. We are just negotiating that with our customers right now. But we are basically undertaking our project -- the projects that we announced last year was just $2.7 billion expansion.

We’ve already filled $1.9 billion of that in front of the regulator and we are working on the rest of it as we speak and we are getting new receipt service applications right now as well. So, I can’t speak of the volume because we havn’t concluded the contracts yet..

And maybe just getting to some of your even bigger pipe, for your West Coast LNG pipelines, can you maybe talk about the bookings of possible FID, specifically for your Petronas FID, the wording is around potentially being later this year.

And I’m wondering if that might include the middle of this year or is that slipped to maybe Q4?.

I think from what we’re seeing from our customer, I’m kind of guessing that a midyear FID decision I think is probably kind of the highest probability. And that of course would be subject to, both Petronas/Progress and TransCanada receiving their remaining outstanding permits..

And on the shale side, what would be the earliest, would it be 2016 with some risk of slippage?.

I think you can -- I think probably a fair kind of estimate would be, my guess would be in the first half of next year..

Thank you. The next question is from Carl Kirst from BMO Capital Markets. Please go ahead..

Maybe just to first start on PRGT is -- as that finishes sort of the refined cost process, is that shifted at all from I guess the last amount of updated dollars?.

I think that last estimate we gave for PRGT, if I go back is probably about 2.5 years old, so it’s pretty dated. And there have been pretty significant scope increases in terms of kilometers added to the project and other scope. So, I mean I think there is going to be -- there is definitely going to be some upward pressure on that.

And that’s about as far as we can go now. The one thing I would remind everybody is the way as that our deal on both those B.C. projects works is we deliver -- and I would say all of the capital that we’re talking about, all of it has been fully shared with our customers.

And what we do is just prior to FID, we gave an updated capital cost for the project and that is the target we go forward with?.

Alex, then from a timing standpoint, should we from an investment standpoint get those updated costs at FID or does that come out once for instance final permitting is gone from B.C.

or about when would we be able to see those updated numbers?.

I think you will see those numbers no later than the FID decision..

And then maybe last question if I could; I’m not sure if this is for Russ or whomever.

But just looking at Energy Eastern going to the amended profiling expected here in the fourth quarter, is there any sense at this point over what type of additional timeframe then the NEB would need to take to know to declare the application complete; I mean is this something where this is going to materially change enough that we’re kind of starting over from square one or is it just we maybe only need another six to eight weeks before the application is declared complete? Is there any way to give any more color on that?.

I think it’s important to understand that really what we’re talking about is replacing the Cacouna terminal with other terminal facilities on the project. So if you think about it from that perspective, probably 80% or 90% of the original filing would remain relevant and the NEB continues to progress that.

If you think about us filing towards the end of next year, I certainly think we -- I would hope we are not talking about much more than -- hopefully something less than six-month period for the NEB that determine the completeness of the application..

Great, appreciate the color. Thanks guys..

Sorry, Carl, just to be clear, the target is filing for the end of this year..

The end of this year. I got you..

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

Maybe just one more question about the pacific gas connector.

Just wondering of the root, what percentage of the land has now been covered with agreements with First Nations?.

We have right now executed about four. We are actively involved with the vast majority of the other First Nations. I don’t have a number for you but certainly our expectation is by the time that we get to an FID decision later this year that we will have a very significant number of those First Nation bands signed up..

Maybe switching over to Ontario, just with the potential for cap and trade there, would your existing gas plans be covered under a change of law scenario or could you get incremental costs for CO2 compliance?.

We’re waiting to understand the specific details of how Ontario will roll out their pronounced desire to head in a direction of cap and trade program for the GHT. [Ph] So, the short answer is that it really varies depending on the details of that as to how it will impact our operations.

So, it’s really speculative at this point to get into that until we see the details of what they finally put out..

The next question is from Paul Lechem from CIBC. Please go ahead. .

First on the drop down to TC Pipes to GTN dropdown. Just wondering what the rational was for taking back some of these Class B units from TC PipeLines is something hasn’t done before.

Just wondering why not cash, why the structure and what that implies for future dropdowns that you are going to use that structure again?.

These were effectively as synthetic high split that was specific to this asset dropdown. And it was designed to be beneficial to both the LP and TransCanada in the sense that it shape the cash and earnings to TransCanada to our cash requirements for CapEx.

And from the LP’s perspective, we did receive a 100% equity credit from the credit rating agencies on these units which reduced the equity it had to issue to third parties and also builds in growth into the LP year five and onwards. So it helps shape their earnings growth portfolio going forward.

So, this -- I wouldn’t consider this a template necessarily for every deal going forward. But we’ll look at it using this type of a structure on a spoke basis as we drop down other assets based on the specific situation of the LP and TransCanada at that point in time..

Also separately, just on the Alberta oil pipeline building the Grand Rapids, Northern Courier and Heartland. Just wondered if we can get an update. Has there been any change to any of those projects in terms of timeframe or anything else, given the downturn in the oil. [Ph].

There hasn’t been any change on Northern Courier; we’re still targeting 2017 in-service for about one third the way through construction; we had a good construction proceed in meeting or hitting our performance targets.

On Grand Rapids we’re moving forward with the 20-inch line first that we hope to have in service next year followed by the 36-inch later. We may see a slowing in production to fill up these pipes. At this point we’re getting strong indications from the shippers to continue..

And Heartland is still on track?.

Heartland is -- be a year late, it’s in 2017 timeframe..

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

I’d like to have your comments on the proposal on your benefits package for the First Nations; there is some comment in there about incentives from pipeline companies.

So, can you address that at all and presumably that’s what going to be recovered in your toll structure?.

We can’t comment on what others have put out in the market in terms of their payments. With respect to ours, the answer is yes.

Our contractual obligations to the First Nations will be covered in both, some of them will be covered in the capital cost and some of them will be covered in the operating cost but all of that will be paid in the tolls to our customers..

Then just on the cap and trade again, do you think if Ontario goes down road, there are any implications for the Bruce refurbishment with the thinking being obviously -- and the emission was sourced would be harder to abandon in that case and just a general update on the refurbishment discussions?.

I guess I would say that the Ontario government’s move on the cap and trade and defining how they are going to approach GHG is quite consistent with the previously stated support for I emission free or GHG emission free sources of power and their commitment to the Bruce site and the commitment to engage with Bruce Power in discussions about the continued refurbishment, I can report that those discussions are still ongoing and we are working alongside Bruce Power and with our partner to try to bring those discussions to a successful close.

.

Well, recognizing it’s still ongoing, is there any material progress that’s there that they have been tied up, trying to figure out what they are going to do on cap and trade first and at this point maybe more substantive discussion can take place?.

I guess I would say that the cap and trade initiatives in Ontario are not really impacting our discussions. We’re pursuing those with good due-diligence and working, as I said alongside our partners to try to move that along as just as quickly as we can..

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

Recognizing we’re only four months into the year, but we do have the winter volume season behind us.

Just wondering if there is any comments on Mainline performance?.

Mainline performance this winter was good. We had another good cold winter at least, so chipped some pretty good volumes. To just give you an idea right now. Our front long-haul volumes, is just a little under 3 Bcf a day, about 2.7 Bcf a day. We’ve got a little over 7 Bcf a day of toll from contracts on the system.

So we’re still gathering about in the mid 90%ish of our revenue coming off from toll. So the Mainline had another good winter season..

And just is there any context or anything you can give in terms of where you are versus the budgeted revenue requirement..

We had to do a compliance filling here at the end of March and that was a filing to set our final tolls as of January 1st and the board hasn’t ruled on that. So, it’s hard for me to comment on where we’re going to be vis-à-vis our revenue requirement because I don’t know what part is going to set for final tolls.

But I will say that we had a good quarter if it is filed as we expected. I do expect some incentive revenue to coming from income statement. We will be -- the processor for adjudicating the compliance filing looks like it will take most of this quarter, so we’ll get a decision either late this quarter or on our final tolls or maybe early next quarter.

but it’s hard for me to tell you definitely because the board hasn’t approved our final tolls yet..

Then just the other question, if you’ve got some commentary about being more positive on the Alberta Power market longer term.

I’m just wondering given your portfolio’s relatively short duration, how you are thinking about positioning or taking advantage of that view in the market and as well if you can comment on how you think the environmental regulations on carbon may or may not be unfolding and how that might change, how you think about the Alberto Power market?.

I guess our optimism longer term is really driven by the -- repeating the comment that Don made earlier that really these prices are not sustainable from the perspective that as you understand, I’m sure there is a fleet turnover need that is underway, which I guess those to your comment or your question I should say regarding where apparently ultimately be going with the GHG.

There is obviously some -- going to be some changes in that regard which are currently being considered by government. And we’re engaged as our all other stakeholders in some consultation that is happening in that regard with government. And it’s really aimed at turning over the fleet away from cold which is a long term goal I guess.

And so these prices do need to improve in order to have that happen. And our company is well-positioned I think to -- with our business, both in renewables and in gas-fired generation to participate in that once the pricing signals show us that those can be reasonable investments..

So, you want to see the price signals before or instead of you think you’re going to get there and you want to be out in front of them?.

We’re going to be cautious I guess I would say on that and ensure that we can see the runway to some continued prosperity in that before we make those investments..

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

I guess the question spans multiple business groups but probably starts with Karl.

Just in relation to the North Montney line, as you start to expand into that basin, what other opportunities do you see beyond natural gas pipes? Are you seeing other opportunities to be involved in say the G&P space and dedicated liquid lines?.

So, let me just start little bit about what we view. So number one, of course gas pipelines meeting with the business right now. The North Montney is a prolific part of that shale play and it’s something that we’re working diligently on try and get a bigger -- more infrastructure in that area.

What else we see in that area, I suspect as LNG goes forward, we will see more NGL infrastructure. Every LNG project has its different heat content of its gas. And I don’t if we could say right now where they are going to keep disturbing plans and the processing plans for managing the heat content of the gas.

But I suspect there will be some opportunity in that region too for maybe stripping plans or some sort of NGL infrastructure as well. So certainly, we keep looking at that. We’ll see as FIDs get a move forward and as we see the plans for the company, we’d expect some NGL infrastructure as well in that region..

So, just on that, it seems like there is a bit of multiplier that could happen on you current capital expectations just in the Montney region alone, given the richness of the gas there..

Well certainly, if they transportation of liquids, we would welcome the opportunity to work with them on that as well. So yes, you could say there might some upside to our business out there, if we can convince our partners to go with us for that type of infrastructure as well..

If I may, just as a follow-up, we’re seeing progress has really accelerated drilling activity on the year-over-year basis.

What should we really take away from that as we run into potential FID decision in June or July?.

I think what I would say is until they make their FID decision, I guess there is always the ability for the project to go both ways.

But I think by their actions up in the resource base and by the effort that they’re going into with us and their other stakeholders, I think you certainly -- we look at it and view it as -- all of that as being positive..

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

You had a strong EBITDA out of U.S Power. And it looks like it was driven by purchasing power for resale.

Can we expect this purchase resale to continue?.

First quarter was indeed impacted, as Don mentioned in his opening remarks, by some -- not only growth in volume in our direct sales business in the Northeast but also driven by the dramatic delta in price that we’ve seen in Q1 ‘15 versus what we would have seen in same quarter last year.

The anticipated higher winter prices on the fuel side in New England were driving our retail prices higher and that’s what really drove that.

As Don mentioned, we do expect in the second quarter to see essentially the opposite effect because we’ve -- while we do have a very strong positive margin expectations from our overall business, there is this timing element where we really saw high revenue in the first quarter which will be declining in the latter quarters, in particular in Q2..

I’m not sure who will take this next question.

But what was the contribution of the spot capacity sales to Keystone’s EBITDA results? And the second part is, could TransCanada buy oil for its own account, ship on the spot capacity market and then resell out at the other end of Keystone?.

Would you mind repeating the first question?.

What was the EBITDA contribution of spot capacity sales to Keystone?.

In the first quarter?.

Yes..

The contribution of that $68 million increase quarter over quarter, about half of that was attributable to increased volume over Q1 last year and of that sort of let’s call it mid $30 million range, about half of that was attributable to spot and the other half is attributable to the full quarter contribution from the Gulf Coast Extension.

In regard to the second half of the question, we don’t get into the buying and selling of crude for our pipelines. We’re seeing good demand on Keystone now; we saw the strong contango market going into [indiscernible] which contributed to this increased spots on Keystone. So at this point, the market has taken up all that demand.

All of that capacity, sorry..

Thank you. The next question is from Carl Kirst from BMO Capital Markets. Please go ahead..

Just a couple of clean up questions if I could and the first just sort of looking at eastern Canada because the EBITDA came out a little bit higher than we were expecting as well, even with the Bécancour core reset.

And I noticed there was some sale in the numbers of unused gas transportation and was just curious how much that was and perhaps maybe said another way, is there anything seasonally in that Eastern Canada number in the first quarter that will see perhaps a roll back on as we get to second quarter?.

The transportation question is transportation that we’ve taken out in advance of the Napanee project which as Russ highlighted in his remarks is under construction.

So that capacity which we will be holding for use at Napanee down the road, it has some winter value and so we were able to take some earnings in as it results from the resell of that capacity; you won’t see that in Q2 or Q3 but you may see a little of it in Q4 then..

Can you give us sort of a zip code of that number was as far as what we should see coming out of the second quarter?.

About $0.2 on an EPS basis..

And then last question, maybe for Karl; it’s just really a question on the North Montney Extension. I guess I didn’t quite understand some of the commentary around the potential toll structure.

It seems like we may be going from molding to perhaps negotiated rates on the future and I just wanted to better understand what was going on there?.

The decision came down from the North Montney. And really I guess as a very high level, the board came back until they we’re satisfied with cost causation principles on the current volume methodology that we have.

They have tried to distinguish between expansions on our system and extensions on our system, which extension being leaving the boundaries or existing system, and expansion being within existing boundaries.

What they have done is they have approved the projects, which is good and they have invited us to come back later after a transition period, they’ve called after the project is started up. And they invited us to come back with one of two options.

We could either come back with a new methodology that would conceivably include roll in that more close reliance to the cost causation principles.

And that’s quite frankly the path we will probably take to deal with our customers and we will come up with the new tolling methodology for NGTL that will better incorporate cost causation principles for these extension projects or alternatively they invited us to come back with the standalone tolling which should be what you just talked about some sort of a standalone for the project, maybe even negotiated tolling with the customer.

But I would expect and we’re coupe years away from actually doing anything with board on this but that was expected NGTL and our shipper, we prefer to come back with the new tolling methodology that would include rolling and more closely aligned with what the board’s looking for on cost causation..

Okay. Because ultimately where I was trying to kind of better understand was if we’re seeing additional demand coming on the NGTL System; was this issue of rolled into negotiated basically shifting the competitive structure a little bit to open the door to others to come in but doesn’t sound like that’s giving you pause..

No, it’s not giving me pause. I’m quite convinced our shippers want to continue with rolling, our shippers want this volume, the volume is coming from NGE projects as the production from that they wanted on NGTL. It contributes to the breadth and depth of the market and of the pricing mechanisms on NGTLs.

And I’m pretty certain that’s the route that we’re going to go and until told otherwise, I’m pretty certain that that’s the route that we’re going to go..

Thank you. This concludes the portion of the Q&A for analysts. We’ll now take questions from the media. [Operator Instructions]. The next question is from Ashok Dutta from Platts. Please go ahead..

I had two sets of questions. The first one is about the Prince Rupert Gas Transmission.

How do you think you would be able to overcome this cost overrun issue?.

I’m not sure what are you referring to when you say cost overrun?.

Last month at the CAT [ph] conference, the guy from Progress said that this project is facing a 40% cost overrun because of the necessity of re-routing or going through offshore areas the last 150 kilometer and that would result in 40% cost overrun. So, I’m just wondering how will that be overcome..

First off, as I said earlier in my comments, we’ve announced there has been some upward pressure on that estimate; it was pretty dated estimate. And in fact we have added a lot of kilometer to the project. And we do have a marine component to the project.

All that being said, I think our customer at the end of the day will consider that in the context of the overall economics of their liquefaction project. And I think as I said, if you look at their actions over the past year or two, they certainly seem to be a company that consider this to be a compelling opportunity.

And at the end of the day, the capital or the tolls associated with the capital on the pipeline portion of this project, although important really are relatively modest portion of their overall cost of delivering gas, liquefying and getting to their customers..

And what’s the latest with the Upland Pipeline, has the regulatory application been filed as yet and who has it been filed to?.

The regulatory application was filed earlier this week and it’s field with the U.S State Department. And we will follow up with a filing for the Canadian side with the National Energy Board later on this year..

The next question is from [indiscernible] from Bloomberg. Please go ahead..

My question is, I heard your guidance that shipper interested still strong for Keystone XL even with oil prices where they are.

My question is whether the lower oil price environment which some see continuing for couple years, is that any impact on any liquid pipeline project yet or if you see it as possible in the near-term and what that would be?.

I’ll start and maybe turn it over to Paul.

I think on those long haul pipelines where you started your question around Keystone XL and things like energies, those are projects that are tied to peoples long-term views of what the productions going to be and what the pricing is going to be out in 2020 through 2050 and from, what we see today production has grown quite considerably since we announced, both Keystone and even energy but from time we applied for Keystone our production is up in Canada, probably about 1 million barrels a day and we’re probably up 3 million barrels day in the U.S.

Pipeline capacity hasn’t kept with that current increase in production. So, we’re kind of behind already in terms of building long haul infrastructure to move oil to market. And as a result, you’ve seen oil by rail move up quite considerably, almost from a zero to like 1.5 million barrels a day.

So the pent up demand still for long haul infrastructure and that’s where Keystone XL sits. The demand is still there and that’s our shippers remain 100% supportive.

If I look upstream, currently there is a lot of projects that are still under construction and moving forward which means that production in Canada will continue to increase over 2015, 2016, 2017 and likely into 2018 which means they need new infrastructure up.

Maybe I’ll turn it to Paul for some specifics if you have any?.

Thanks, I think you covered it fairly well..

Can I ask you a quick follow-up, which would be I think that the maybe Grand Rapids and Northern Courier had been pushed at some point on the timing. Was this all related to that or was it just project which is the closer?[Ph].

On Northern Courier, we’ve aligned the construction of Northern Courier to coincide with the customer’s requirement for the pipe based on the anticipated production date. And that’s where we landed on the 2017. Grand Rapids was building in two phases starting with the smaller pipe first and going down some initial volumes in 2016.

We pushed that out here; we’re initially targeting this year but there is a delay in getting on permits on the Alberta regulator. As I said earlier we’ve got direction from the shipper to machines. We do anticipate that we will be slowing in production and attracting volumes on to Grand Rapids.

But the need of Grand Rapids remains as it is when we first sanctioned the project..

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

Thanks very much and thanks to all of you for participating this afternoon. We recognize it’s been a long day with our Annual Meeting earlier today and our conference call this afternoon. Once again very much appreciate your interest in TransCanada and we look forward to speaking to you again soon. Bye for now..

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