TC Energy Corp (TRP) 2014 Q2 法說會逐字稿

Good day ladies and gentlemen. Welcome to the TransCanada Corporation 2014 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 afternoon everyone. I'd like to welcome you to TransCanada's 2014 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, President of Development; Karl Johannson, President of our Natural Gas Pipelines business; Paul Miller, President of Liquids Pipelines; Bill Taylor, President of Energy; and Glenn Menuz, our Vice President and Controller.

Russ and Don will begin today with some opening comments on our financial results and certain other Company developments. Please note that a slide presentation will accompany their remarks. A copy of the presentation is available on our website at TransCanada.com. It can be found in the Investor section, under the heading Events and Presentations.

Following our prepared remarks we will turn the call over to the conference coordinator for your questions. During the question-and-answer period, we'll take questions from the investment community first, followed by the media. In order to provide everyone with an equal opportunity to participate, we ask that you limit yourself to two questions. If you have additional questions, please reenter the queue.

Also we ask that you focus your questions on our industry, our corporate strategy, recent developments, and key elements of our financial performance. If you have detailed questions relating to some of our smaller operations or your detailed financial models, Lee and I would be pleased to discuss them with you following the call.

Before Russ begins, I'd like to remind you that our remarks today will include forward-looking statements that are subject to important risks and uncertainties. For more information on these risks and uncertainties, please see the reports filed by TransCanada with Canadian Securities Regulators and with the US Securities and Exchange Commission.

And finally also I'd 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 US GAAP, and are therefore considered to be non-GAAP measures. As a result, they may not be comparable to similar measured 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 now turn the call over to Russ.

Thanks David and good afternoon everyone and thank you very much for joining us today. We are very pleased to announce another solid quarter, with the majority of our business segments performing very well. The Q2 results reinforce our strategy of building a diversified and growing portfolio of critical energy infrastructure projects.

We're very pleased with the performance of our gas pipelines and the increased volumes that they're flowing today. This includes the Canadian Mainline, which has steadily moved over 3.3 Bcf a day so far this year. At the current time, even in the shoulder seasons right now we're moving more than 3 Bcf a day, which is two times the volumes we were moving last year.

In addition, the Keystone Pipeline continues to perform very well, including the southern leg of the system that is now operating. To date, we have now safely transported over 630 million barrels of oil to our neighbors south of the border.

Turning over to energy, fundamentals in this business continue to improve and our US power assets produced strong results in Q2. However, that was somewhat offset by weak Alberta power prices and Bruce Power maintenance outages. We are very confident both the Alberta Power business and Bruce Power are positioned for improved results as the Alberta power market fundamentals improve and Bruce operations continue to move towards steady state.

In addition, our contracted capital program continued to grow in the quarter, with an addition of the CAD1.9 billion Merrick Pipeline project, bringing our total of commercially secured projects to CAD38 billion.

TransCanada shareholders will benefit from the predictable and sustainable cash flow of earnings and dividends that these projects will deliver for years yet to come.

A couple of highlights from the Q2 financials. As I said, our three businesses performed well during the quarter. TransCanada reported net income of CAD416 million or CAD0.59 per share. Comparable earnings for the quarter were CAD332 million or CAD0.47 per share. That amount excludes a net gain of CAD99 million from the previously announced sale of Cancarp and the after-tax CAD31 million termination expense related to the restructuring of an Alberta natural gas storage contract.

Comparable EBITDA of CAD1.2 billion and funds generated from operations were CAD917 million.

Earlier today, the Board of Directors also declared the quarterly of CAD0.48 per common share for the quarter ending September 30, 2014.

In a few minutes, Don will offer more detail on our Q2 financial performance, but first I'd like to highlight some of the key developments since I spoke to you last time.

We continue with our preparations for filing our Energy East full facilities application to the National Energy Board, which we're still on track to submit in the third quarter of this year. Consultations and discussions with thousands of stakeholders along the 4,600 kilometer route of the pipeline are ongoing.

To date, we have held over 2,200 meetings and have answered hundreds of questions at over 81 open houses in communities in six provinces. These consultations will continue before and after we have filed our NEB application. These face-to-face discussions are vital to ensuring we hear people's concerns and that we address those concerns in our planning and design. To date, well over 6,000 Canadians have taken part in those open houses.

The 1.1 million barrel a day Energy East Pipeline will transport oil from Western Canada to Eastern Canadian refineries and export terminals in Quebec and New Brunswick, creating jobs, tax revenue and energy security across Canada.

Market demand for this project continues to grow. I would remind you that the CAD12 billion project is underpinned by more than 900,000 barrels per day of firm long-term contracts with a diverse set of very credit worthy shippers.

Moving over to Keystone, as you're aware, the US Department of State has delayed the decision on it [per that] Presidential permit for Keystone XL. The State Department has said it requires more time to gather input from eight federal agencies, more time to process the 2.5 million public comments from the public comment period and it needs a better understanding of the legal issues in Nebraska.

As we have said before, in our view, this delay remains unnecessary. Five exhaustive environmental reviews since 2000 and over 17,000 pages of scientific data concluded the project has minimal environmental impact and significant safety, energy security, employment and economic benefits will accrue from the project.

The need for the project remains strong, as oil production in both Canada and the United States continue to grow. Shippers remain firmly committed to seeing this pipeline completed.

In Nebraska, the State Supreme Court said that it will begin to hear oral arguments on September 5th, related to the appeal of a lower court ruling by the Attorney General of Nebraska. A decision is expected in late 2014, early 2015. As we have said before, a majority of Americans continue to support this pipeline. The project has strong bipartisan political support in Washington and in all the states along its path.

We remain confident that Keystone XL is in the national interest of the United States and that it will ultimately be approved. We anticipate that the pipeline would be operational approximately two years after we receive a Presidential permit.

Back here in Alberta, we continue to advance our CAD3.5 billion investment plans for oil infrastructure from Fort McMurray to Hardisty. Last week, the Alberta Energy regulator approved our application for the Northern Courier Pipeline Project. The CAD800 million, 90 kilometer pipeline will transport bitumen and diluent between Fort Hills, the mine location and the bitumen extraction facility and Suncor East tank farm, located north of Fort McMurray.

The pipeline is 100% subscribed under long-term contracts with the Fort Hill partners. We expect construction to begin shortly and that Northern Courier should be in service in 2017.

Moving to gas, we have filed regulatory applications for both our CAD5 billion Prince Rupert gas transmission project and the CAD4 billion Coastal gasoline project. Field work and community consultations continue to progress. Final investment decisions for both of those projects are expected in the 2014, 2015 timeframe.

Now a couple of comments on our NGTL system. We continue to experience unprecedented interest in connecting new supply to the NGTL system, as Alberta and Northeast British Columbia gas production continues to grow. CAD250 million of NGTL projects have become operational so far this year and we have another CAD3.8 billion that are either under construction or in the process of seeking NEB approval. That total includes the CAD1.7 billion North Montney project that will extend the NGTL System further into British Columbia.

We anticipate an NEB decision on the North Montney extension in the first quarter of 2015.

Continuing with the NGTL expansion, in early June we announced the Merrick Pipeline Project. It is CAD1.9 billion, 260 kilometer pipeline, would transport natural gas through the NGTL system for delivery into the proposed Pacific Trails pipeline and onward to an LNG facility in Kitimat, British Columbia. Subject to approvals and positive investment decision, we'd expect Merrick to be in operation in the first quarter of 2020.

Looking forward, we continue to work through significant requests for additional pipeline receipt and delivery capacity on the NGTL system, which I expect in the next couple of months will lead to additional firm contracts for expanded capacity and significant capital investment requirements.

Moving over to the Mainline; in May we filed a project description with the National Energy Board for our proposed Eastern Mainline project. Based on our recent open season, the project with would see us add 600 million cubic feet a day of capacity to ensure we meet the needs of existing shippers, as well as new firm service commitments contracted for the Eastern triangle segment of the Canadian Mainline.

Finally, on the gas pipeline segment, we continue to pursue opportunities in both United States and Mexico, including further expansions of the ANR system, which would connect growing natural gas supply in the Marcellus and Utica formations to North American markets and in the longer-term, an Alaska LNG export pipeline.

In oil pipelines, we continue to develop financial opportunities that will both build on our existing pipeline footprint and look for new ways to get growing crude oil production in North America to market.

In the power segment, we content to assess opportunities in our core market areas. This includes regions where we are currently seeing strong demand growth like Alberta and we're also seeking growth through things like Bruce Power, where we continue to negotiate arrangements with the Ontario Government to replace or refurbish Bruce power units 3 through 8. It is recognized by all parties that these units are critical to providing emissionless base load electricity for the people of Ontario for decades to come.

And finally, a few comments on the significant shareholder value we expect to create as we advance our CAD38 billion capital program. The scope and scale of these projects is truly unprecedented. Once they are completed, we expect our position as a leader in each of our core North American businesses to grow even further.

The portfolio includes CAD21 billion of crude oil pipeline projects, CAD15 billion of natural gas pipeline projects and CAD2 billion at power generation facilities. Each of these projects is backed by either a long-term take or bake contract that averages 20 years or more, or traditional cost of service model. As a result, the earnings and cash flow we would generate from these assets is expected to be highly predictable and sustainable for decades to come.

Though this includes the four large-scale infrastructure projects that I touched on earlier, specifically Keystone XL, Energy East, Prince Rupert and Coastal GasLink, together those projects represents CAD26 billion of the CAD38 billion growth portfolio. All of these projects are expected to come into service in the second half of this decade. Once completed, these projects will transform our company and provide growth for our shareholders well into the next decade.

In addition, we are currently in various stages of advancing CAD12 billion of that CAD38 billion program of smaller scale shorter-term projects that include CAD4 billion on the NGTL system, CAD3.5 billion of Alberta oil expansion, CAD2 billion of Mexican gas infrastructure projects and CAD1.5 billion of new energy infrastructure projects. The majority of those projects are expected to become operational between now and 2017.

As I mentioned a moment ago, we are in the process of reviewing other opportunities in all three of our core businesses that will enhance our current asset portfolio and position us better in the long-term. This activity, combined with the CAD38 billion of already commercially secured projects will almost certainly exceed our internally generated cash flow and debt capacity.

As we previously communicated, is our intention to finance these projects in a way that maximizes value for our shareholders. Specifically we have indicated that we have numerous attractive alternatives.

For example, we have indicated that it is our intention to divest 100% of our US pipeline portfolio into TC Pipeline's LP and we have been busy over the last months laying the groundwork for that to occur. Don will highlight this and some other options in his talk. And we constantly assess the market conditions and evolve them as our funding needs become more visible.

In summary, our fundamental strategy is to focus on our core businesses and it will always be on maximizing shareholder value through growing cash flow, earnings and dividends. We've had some delays in our project approvals, but the necessity of these infrastructure requirements is clear and we remain confident in all of their approvals. Today, we have an enviable, well diversified footprint of critical energy infrastructure assets that delivers stable and growing cash flows. We have CAD38 billion of high quality commercially secured projects and we are now positioned to capture more.

Due to the high quality nature of that base footprint, as well as the contracted development portfolio, we have access to many attractive value-adding financing alternatives. We remain disciplined and focused on executing our plans, growing cash flow and dividends and delivering on our commitment to grow shareholder value.

That completes my prepared remarks and I'll turn the call over to Don for further details on our quarterly results.

Thanks Russ and good afternoon everyone. Before I run through our Q2 results in detail, I'd just like to highlight a few key messages. The majority of our business segments performed well during the second quarter, which highlights the benefits of our diverse and critical energy infrastructure assets. CAD3.3 billion in new assets are now contributing to earnings and cash flow, which partially offset weak Alberta power prices and maintenance outages at Bruce Power in the quarter.

And finally, we remain well positioned to fund our CAD38 billion portfolio of commercial secured projects, with predictable and growing cash flow, a strong balance sheet and access to multiple attractive external funding sources.

Now moving to our consolidated results, shown on the next slide. Net income in the second quarter was CAD416 or CAD0.59 per share, compared to CAD365 million or CAD0.52 per share from the same period in 2013. Excluding the specific items highlighted on this slide, comparable earnings in the second quarter of CAD332 million or CAD0.47 per share were CAD25 million or CAD0.04 per share lower than the same period in 2013.

The decrease in comparable EPS was primarily due to reduced earnings from Western Power, as a result of soft operator power prices and lower equity income from Bruce Power due to higher planned and unplanned outage days at Bruce A.

This was partially offset by new contributions from the Keystone Gulf Coast extension and the Tamazunchale extension in Mexico, as well as higher realized capacity prices at US Power.

Turning to our business segment results at the EBITDA level, our Natural Gas Pipelines business generated comparable EBITDA of CAD759 million in the second quarter of 2014, compared to CAD644 million for the same period last year. Canadian gas pipelines comparable EBITDA of CAD549 million increased CAD58 million compared to 2013, driven by flow-through items from both the Canadian Mainline and NGTL, which do not have an impact on net income.

Net income from the Canadian Mainline was CAD9 million lower compared to the same period last year, as a result of a lower average investment base, as well as carrying charges owed to shippers stemming from a positive toll stabilization account balance. NGTL's net income of CAD58 million was unchanged year-over-year.

The positive impacts of our larger average investment base and higher allowed return on equity at 10.1% were offset by increased OM&A costs at risk under the terms of the current settlement, which expires at the end of 2014.

US and international gas pipeline's comparable EBITDA of CAD212 million increased CAD54 million compared to second quarter 2013, primarily as a result of the commencement of contract revenues being recognized from the Tamazunchale extension and the positive impact of the stronger US dollar.

Construction activity on the Tamazunchale extension has been delayed as a result of archeological findings along the route, however, the pipeline is expected to be completed by the end of September. These delays are recognized as a force majeure and provisions under the contract with the CFE allow for the collection of revenue which has been recognized in the second quarter.

Turning to liquids pipelines; the Keystone pipeline system generated CAD256 million of comparable EBITDA in the second quarter. The CAD69 million year-over-year increase, is the result of the Keystone Gulf Coast extension, which was placed into service in January, along with the favorable impact of the stronger US dollar. Liquids pipelines development expenses were CAD6 million higher, primarily due to lower capitalization of development costs.

In Energy, comparable EBITDA was CAD231 million in the second quarter, compared to CAD330 million for the same period last year. The CAD99 million decrease was the result of several factors.

Western Power comparable EBITDA declined CAD71 million as a result of lower realized prices. Despite robust Alberta power demand growth, the return of coal-fired capacity in incremental wind generation led to weaker power prices. The second quarter average pool price was CAD42 per megawatt hour compared to CAD123 in the same period last year.

In July, power prices in Alberta have been encouraging, as they've rebounded and averaged over CAD110 per megawatt.

Bruce Power's equity income decreased CAD35 million due to higher planned and unplanned outage days at Bruce A, partially offset by fewer outage days at Bruce B.

Overall availability percentages in the second half of 2014 are expected to be in the low 90s for Bruce A and high 80s range for Bruce B, as there are no further planned maintenance events scheduled at Bruce A and just one remaining at Bruce B scheduled for one of its units in the fourth quarter. As a result, we expect Bruce Power to deliver improved results the balance of the year.

US power comparable EBITDA increased CAD14 million in the second quarter compared to last year, primarily due to higher realized capacity prices in New York, higher hydro generation volumes and the favorable impact of the stronger US dollar.

Natural Gas Storage comparable EBITDA of CAD2 million was down CAD7 million compared to the same period in 2013, due to decreased proprietary and third-party storage revenues, as a result of lower realized storage spreads. This trend is expected to continue as summer/winter spreads remain challenged.

Now, turning to the other income statement items on slide 17. Comparable interest expense rose CAD45 million in the second quarter to CAD297 million, from CAD252 million in 2013. This increase was principally due to interest charges on recent US debt issues and higher foreign exchange on translating interest denominated in US dollars, partially offset by Canadian and US dollar debt maturities.

As I've highlighted in the past, exposure to US dollar income is largely offset with US dollar denominated interest expense and financial derivatives, the net effect of which is that currency movements do not have a material impact on earnings over a rolling 12-month forward period.

In the second quarter, CAD63 million of interest was capitalized to assets under construction, compared to CAD60 million for the same period in 2013. This reflects higher capitalized interest for Keystone XL, Mexican LNG and other liquids pipeline projects, offset by completion of the Gulf Coast extension of the Keystone system.

Comparable interest income and other for the second quarter increased CAD31 million compared to 2013, due to lower realized losses on derivatives used to manage our net exposure to foreign exchange fluctuations on US dollar income, the impact of currency translation fluctuations on working capital balances and AFUDC related to our rate regulated projects. This includes Energy East, which meets the requirements for rate regulated accounting under US GAAP.

Comparable income tax expense for second quarter 2014 increased CAD29 million versus the same period last year, due to higher pre-tax earnings, changes in the proportion of income earned in higher tax jurisdictions, as well as higher flow-through taxes on Canadian regulated pipelines. Excluding Canadian regulatory flow-through pipelines, the effective tax rate in 2014 is expected to be in the 27% to 28% range.

Net income attributable to non-controlling interests rose CAD8 million compared to the same period last year, due to the partial sale of GTN and Bison last July to our MLP, TC Pipelines. Preferred share dividends of CAD25 million were CAD5 million higher in second quarter 2014, as a result of the CAD450 million Series 9 issue completed in January 2014.

Now, moving on to cash flow and investing activities on slide 18. Cash flow remains solid with funds generated from operations of CAD917 million in the quarter and in excess of CAD2 billion year to date.

Capital expenditures were CAD967 million in the second quarter, driven principally by Mexican pipelines, NGTL system expansions and construction activities on the Houston lateral and tank terminal.

Equity investments of CAD40 million in the quarter reflect activity related to the Grand Rapids Pipeline and Bruce Power. Finally, the sale of Cancarb closed on April 15 and resulted in net proceeds of CAD187 million.

Now turning to slide 19, our liquidity and access to capital markets remains strong. At June 30, our consolidated capital structure consisted of 40% common equity, 5% preferred shares, 2% junior subordinated notes, and 53% debt net of cash. We had CAD565 million of cash on hand, along with CAD5 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 US, remain well-supported, and continue to provide flexible and very attractive sources of short-term funds.

As I mentioned earlier, during the second quarter, we closed the sale of Cancarb and its related power generation facility for net proceeds of CAD187 million and realized an after-tax gain of CAD99 million.

Looking forward, we remain well-positioned to finance our CAD38 billion portfolio of commercially secured projects, underpinned by predictable and growing internal cash generating cash flow from our CAD55 billion diversified asset base and new senior debt consistent with our A grade credit rating. Beyond these two funding sources, additional capital in the form of preferred shares, hybrid securities and portfolio management, including the dropdown of assets into TC Pipeline's LP, are expected to help fund our growth plans.

Over the next several years, we are committed to vending in all of our remaining US natural gas pipeline assets into TC Pipelines. These assets that remain on balance sheet are expected to generate approximately US $500 million of annual EBITDA once all of ANR's new contracts kick in by the end of 2015. TC Pipeline's strong balance sheet, investment grade credit rating and the intent to launch their new at the market equity program, positions it well for future drop downs.

Finally, as we progress through key upcoming stage gates on many of our large transformative projects, we will actively consider additional portfolio management activities, partners, project financing and reinstatement of our division reinvestment program from Treasury as an alternative to discreet common equity issuance.

In closing, the Company produced solid second quarter results despite weak power prices in Western Power and maintenance outages at Bruce Power. Year to date comparable earnings per share and funds generated from operations are up 4% and 8% respectively compared to 2013. CAD3.3 billion of new assets are now contributing to earnings in 2014, including the Keystone Gulf Coast extension, the Tamazunchale extension and various expansions on the NGTL system.

In addition, we continue to advance our CAD38 billion of commercially secured projects and are well positioned to finance this capital program. Our impressive slate of critical energy infrastructure projects is expected to generate significant growth in earnings, cash flow and dividends for our shareholders over the remainder of the decade.

That's the end of my prepared remarks. I'll now turn the call back over to David for the Q&A.

Thanks Don. Just a reminder, before I turn it over to the conference coordinator. We will take questions from the investment community first, and once we've completed that, we'll turn it over to the media. With that, I'll turn it to the conference coordinator for your questions

(Operator Instructions) Carl Kirst; BMO Capital Markets.

I certainly appreciate the comments on the MLP. Maybe I could start there. Obviously Don, there is a bit of contingent pipeline funding, XL, Petronas, what not, that could quickly build to very large 2015, 2016 CapEx years. I'm a little, I guess concerned is the wrong word, but to the extent that we look at the MLP, what do you think is the pace of the gating factor as far as how many drops you could do, how much equity you actually could pool from the MLP?

And I'm thinking about this from a timing standpoint, but is it prudent to wait until after some of these contingent pipelines get approved to know you need the funding or do you start doing it today, because of quite frankly, a more limited pace, there's only so much you can put into the retail market, so we kind of need to start building that today. How do you plan, how do you think of that?

There is an element of use of proceeds to it, clearly. We also have CAD12 billion of projects aside from the big four transformative ones. So just waiting for us to cross one of the stage gates on those projects is not necessarily a prerequisite for these drop downs, so we're not waiting for one of these large binary outcomes to go positively in our favor here.

So with that, I think a couple of drop downs a year are certainly possible and as we do drop assets into there, the size of the vehicle grows and its ability to take assets grows along with that. We're certainly subject to market conditions in the MLP space as well. We have taken steps with this at the market program here to be able to continuously feed equity into the marketplace, which allows us some flexibility in the timing and funding of these things.

I think another factor, Carl, has been us wanting to ensure that we have these assets in a position that we can maximize the value for TransCanada, offset by, as you said, the considerations around timing and market conditions.

But certainly the work we've done around ANR, for example, to extend the contract life was very important and we've been working on that for some time. As well on the cost and restructuring side of that business in order to firstly maximize EBITDA and give it long-term stability, which in our view leads to maximum proceeds down the road for (inaudible) that we can use to fund our capital program. So a lot of those things are being put in place and part of the process on timing as well.

Appreciate the color. And maybe if I could follow-up just with a question specifically on Bruce. I guess we have sort of now back-to-back quarters of fairly large unplanned outage days at Bruce A. Can you give us a little bit more color on were those perhaps associated items, is it just sort of coincidence how we had two sort of more challenged quarters back-to-back and what gives you the confidence that whatever challenges were there are now put behind us?

It's Bill, Carl. I can take that question. First off, at least one of the outages at Bruce A occurred in Q2 was really a spillover of some of the issues that occurred in Q1. That issue is largely behind Bruce at this point, is the view, so we're not expecting any further issues from that particular issue.

There's been a couple of added unplanned outages that were caused by some issues on the transmission system that really are nothing to do with Bruce's operations per se, but rather the power system being in a position where it was unable to accept Bruce's continued run due to a contingent event on the power systems. So a couple of those sorts of things occurred.

And then one added issue in the Q was the planned outage at Unit 3, which was extended to do work which will really shorten any future outage that's needed at Unit 3. It was just sort of an extension of the scope of that outage once they got into it. So we expect that to be really a positive thing for the future. So overall, as Don mentioned, we expect Bruce to come into line with their outage situation in the second half of the year.

Matthew Akman; Scotiabank.

On the MLP you guys talked about gas pipe dropdowns; I'm just wondering if you've thought about oil pipe dropdowns as well and whether there would have to be some significant change in the mandate of TCP or whether those fit strategically in your mind?

It's Don again here. Keystone would be a qualifying asset into the LP. We would not describe it as a mature asset at this point. Certainly we expect Keystone XL to come into service at some point here and then synergistically put all of this together and reap benefits from that. And we do have CAD4-plus billion of assets ahead of it in the queue.

What I would say though is if we can get all these large or many of these large transformative projects over the finish line, it is certainly a lever we could pull that we would weigh against things like common equity issuance or partners at that point in time. So, not saying yes absolutely, saying yes, it qualifies and it's something we would actively consider down the line in the circumstances at that point.

A follow-up question; Russ was mentioning some potential expansion on NGTL. I'm just wondering, I don't know if this is Russ or Carl, but if those relate to more LNG type pipeline expansions or if those are related more to intra Alberta drilling and pick up in NGL related gas drilling?

It's Karl. I could take that. I think we're talking more about the new supply and load on our system, demand on our system. So, we have had some, I'd say substantive subscriptions for new service on our pipeline. Now, what we're doing is we're going through and we're qualifying them and getting contracts and what not signed and then we'll determine what's the expansion that we need that will come out of that. So that will take us a few months to get sorted out. But yes, we've seen some growth both in the demand for gas and receipt service for new supplies coming up on NGTL.

Matthew, maybe I'd just add is we did experience an extremely cold winter across North American and Alberta was no exception and what we found on the NGTL system and our customers found on the NGTL system was to the extent that they'd use interruptible capacity historically, that interruptible capacity wasn't available on cold winter days not that demand is growing quite substantially in things like Fort McMurray, for example. And our customers have come back to us with pretty significant requests for additional delivery capacity for that current need, but as well for future growth and expansion needs.

So as Karl said, it's more related to intra Alberta growth and supply and quite frankly, demand that hasn't been addressed in some time.

Robert Kwan; RBC Capital Markets.

Just on the Mainline, I was wondering how the second quarter cash collection was versus budget and if you can just update where you are with the variance account and any thoughts on how you might like to dispose of it and when you might book it?

It's Karl. I can deal with that. We're forecasting now a positive cash balance in the TSA count of close to CAD 400 million and most of that was actually accumulated in the first quarter but a little bit was accumulated in the second quarter and there's a little bit of a forecast for the rest of the year as well.

The long-term adjustment account that we have, which really is essentially the deferrals from previous years under collections for previous years, sat at CAD350 million at the end of the year. So we have asked through our latest filing on the LDC settlement, we have asked the Board to take the surplus out of the PSA account and apply it to long-term adjustment account, so that we can essentially collect our uncollected revenues from previous years. And that has yet to be ruled on by the Board.

We would expect that that's a reasonable thing to do but we have to wait for the Board to opine on that.

Then just if I can turn to Bruce; obviously with the decline in Ontario power prices, the floor makes a lot of sense. I'm wondering though what your expectation for price is with respect to the variable lease payment and where you expect that to settle and how the lease payments might be versus previous periods?

It's Bill here. I guess the approach on that is that we do, as you point out, expect the floor to be in play again this year, although as you recall, prices in Q1 were quite strong. That has really come back more into line.

And in regards to the lease payments, I guess we don't expect there to be any positive impact on lease payments in the current year.

So just to be clear, the high prices in Q1 put you in a bit of an awkward zone where it's a bit of a headwind, I guess? (Inaudible)

Well, I think maybe Glenn would like to comment on how we treated Q1, which I think we covered the last call.

Robert, I think it's fair to say, as Bill's saying, that we expected the weakness in the prices, coming off the strong first quarter, so you're right, it's somewhere in that zone somewhere between the threshold spot price on the lease reduction and the floor price.

But with respect to what Bill was alluding to on the first quarter, we did defer the spot excess -- the excess of the spot price over the floor price in the first quarter, because we did not think we'd be able to realize on that through the rest of the year, because the annual spot price would end up being below the floor price. And lo and behold, that's exactly what happened in the second quarter. Second quarter, average spot was below the floor and in fact, the year to date at June 30 was already below the floor. So that entire amount that was deferred in the first quarter was reversed.

And as a result, what we expect to see is as long as annual spot prices continue to be expected to be below the floor, that we would book the floor price each and every quarter of the year.

Okay and the same thing with the lease payment?

The lease payment, at this point, we haven't made any accrual for any reduction in the lease price, because at this point we don't have clarity that that would kick in.

I guess, Robert, at the end of the day, we fully expect that we'll realize the floor price at Bruce Power. And with regards to headwinds, there's no headwind that's a carryover from Q1. If there's any headwind, I guess by the end of the year, we wouldn't expect to realize a lease reduction as we have in the last year or two.

Paul Lechem; CIBC.

Since we're on Bruce, I was wondering if you have any further comments on the negotiations, the refurbishment of the remaining years? I think Russ mentioned that those are underway in his opening remarks. Is there any further color you can give in terms of timeframes or any other thoughts on that process?

Sure. It's Bill again. First off, I just would clarify that those discussions are underway between Bruce Power and the Government of Ontario and their agent, the Ontario Power Authority. And by all accounts, the discussions are going well and the owners are engaged in that process, ourselves and Borealis. The discussions are ongoing, with active effort on it.

As to timing, we can't say for sure. There are a lot of moving parts to it, but as Russ indicated, we're quite hopeful, given the interest that we and Borealis have in continuing at the site to refurbish the units and then also the government's interest in the transaction, we're hopeful that something will be able to come together that's workable for both sides.

Is there any timeframe? Given the units have a midlife, end of life by the end of the decade, is there any timeframe where you need to get this negotiation complete so you can sort of get these things refurbished in time?

Well, the schedule as to exactly which units would be refurbished in what order is certainly a point of discussion with the government and the timing and sequencing of those is something that Bruce Power is concerned about as well as the Ontario Power Authority is, relative to securing supplies for Ontario.

There isn't a hard date by which I can say to you that we have to have things buttoned up relative to that schedule, but clearly the schedule is part of it from the government's perspective and from Bruce's perspective. It is a matter of discussion in the negotiation, but it's not dispositive to an exact date as to when things have to be done.

Maybe I'll add to Bill's comments. Obviously we want to get this done as quickly as we possibly can. I believe that the Ontario government is motivated to do the same, but it is a complicated conversation and I would say in the next six, 12 months, hopefully we'll have far more visibility on the question of timing and those kinds of things. But I can tell you that all the parties at the table are motivated to get this done.

Linda Ezergailis; TD Securities.

I have a follow-up question with respect to your US MLP. I'm wondering how TransCanada Corp is thinking of what might be an appropriate range of ownership levels over time for their US MLP affiliate and would you take paper in a transaction just to kind of help with the lumpiness and timing?

It's Don here, Linda. We don't have a specific level of ownership that we're targeting at this stage. In terms of taking paper for doing more of a big bang dropdown, we have weighed that against a more conveyer belt sequential [vending] of the assets for cash and at the current time, we feel that's the better route, as it matches use of proceeds at the big TransCanada level.

I guess our concerns on taking back paper would be creating an overhang in the marketplace with that, given it would be our intention to monetize to fund our capital program at big TransCanada. So at this stage, we're in the camp of the conveyer belt approach to it.

And as a follow-up question, I don't know if this is for Bill or who, but can you give us an update on your view of the outlook of the Alberta, New York and New England power markets, both in terms of pricing and how that informs your thoughts about new assets, whether to build or buy in those markets?

That's a pretty broad question, but I would say that clearly, as indicated in the results we've been having at our US power that we're seeing some improvement in strength in both the New England region and the New York region. The New England situation is partly driven by, as you may know, improved energy spreads that are driven by some gas infrastructure challenges that are affecting peak natural gas prices in the region and that's spilling over into the energy markets and driving some of our results.

In New York, the capacity prices have been stronger. I would say that in both locations, however, it's still quite challenging to make the economics work for new investment, even with the improvement that we've seen. So we're hopeful that that will continue and that opportunities will be there.

We're well situated with our holdings in both regions to look at refurbishment type expansions at both Ravenswood and our locations in New England. So it's something that's on our radar, but we're just waiting for the economic signals to be strong enough to justify that.

In Alberta, as you know, the last quarter was dominated by quite lower prices than say a year ago this time. However, I think as evidenced more recently in the last few weeks here in July, we've seen a lot stronger demand in Alberta. I think yesterday alone, they hit a new all-time peak, is my understanding.

The fundamentals are strong in Alberta. We definitely see that on the horizon and there should be some continued strengthening in prices as that demand continues to grow.

Does that suggest that you're starting to sharpen your pencil for investments in that market?

We are always looking at the Alberta market. Again, we have a couple of projects, including the Saddlebrook project, which you may be aware of, which we have got in development and when we see the condition is right to go ahead with something like that, then we certainly would. But we don't have anything to be specific on at this moment in time.

So no corporate transactions or acquisitions in that market?

Like I said, we're always looking at opportunities and to the extent that we see something that looks interesting, then we would proceed at that point, but no.

Steven Paget; FirstEnergy.

My first question is on the Marcellus. The growth rate in the Marcellus in 2014 year to date is 3.8 Bcf per day versus 2013. This is a record growth rate, so it's growing faster than ever. How is this increasing growth rate affecting your plans? Do you in particular see making any changes to your network to be on the (inaudible) such as Eastern Mainline and (Inaudible).

I could make a comment here and if somebody else wants to jump in, they can add to it. Certainly this growth in the Marcellus is not lost on us. You're right. It is record growth and it is a very substantial volume. We have been a beneficiary of that growth. Some of the volumes that came into ANR are from the Marcellus area and certainly Marcellus and Utica, some of that volume is getting to the ANR.

Are we structuring our LDC settlement application that is in front of the NEB right now? The essence of that application is to buildout the southern constraint of the eastern triangle of our Mainline system, the Parkway to Maple area, so that our customers can get more supply from Marcellus, bring it up into Dawn and then move it through our system. So that's really the essence of the LDC settlement that we have there.

So yes, TransCanada I think is looking at Marcellus and looking at a big opportunity there for some of its assets. And I would also add too that we're starting to see more and more activity around our investment in Iroquois Pipeline system, where Marcellus is starting to move into Iroquois system. So the increased volumes has been a pretty good news story for TransCanada.

On CapEx, you've got a total CapEx of CAD5 billion for 2014, which I think in effect means you're spending about CAD3.3 billion in the second half of the year, which is more than you spent in the first half. Is this guidance still in effect and which of the projects is soaking up big portions of the capital?

It's Don here. We're still at the CAD5 billion figure. It's CapEx and equity investments, so you add in the Grand Rapids and Bruce in the first quarter there in the first half. The major projects underway right now, there's significant build going on in Mexico right now with Topolobampo and Mazatlan and GTL expansions.

We're finishing the Houston lateral as well. We're working on the LNG projects to the West Coast and some preliminary spend on Energy East. So it's spread around fairly well. We do expect a busy second half here towards that CAD5 billion number.

Andrew Kuske; Credit Suisse.

I guess my first question is for Don and it's just in relation to your capital structure. How much of a slug of preps do you think you can have with great comfort in your capital structure overall?

We look at the preps and hybrid securities as kind of a mezzanine basket here. Around the 12% area capital structure is where we believe the equity credits starts to diminish from the agencies. So we're at 7 right now, so there's a fair bit of headroom there on those two products.

Then I guess sort of somewhat related; as you go through your capital program and obviously you've got the drops that you can do to free up a lot of capacity on things, but do you see a need, if a lot of the projects start to hit all at one time, to really expand the size of your credit lines?

Potentially. We'll be cautious on that front. We're always cognizant of the risk of market disruptions. That's a safety belt for that. We generally assume we'll have capital markets access at all times. We were battle tested in 2008; we didn't actually draw our lines in the fall of 2008. But that's something, if the magnitude of the CapEx does ramp up, we'd look to do that. We're at about CAD5 billion right now and I would expect there would be significant capacity available for us from the banking community.

Then just in relation to Apache's announcement this morning of effectively exiting the LNG project that they have; to what degree do you think this is really just their specific circumstances relative to the two situations you're aligned with? And then I guess a follow-up to that is, do you have any interest in the Pacific Trail Pipeline, really a preexisting line going across BC?

First of all, we always understood and were aware that Apache was looking to sell down some of their interest in this project. Now the announcement today, I haven't had a chance to talk to them about it. I haven't been able to get ahold of them, but I noticed they used the word exit and I don't know what that exit means.

Are they selling on all their interest in the project? Are they selling down both the upstream and downstream? I just don't know. But we did know that they were looking to exit at least a piece of this project. So that suggests to me that this is nothing fundamental with the project. I know Chevron is still, from what I understand, still committed to the project and we'll see how that transition goes and who picks up that piece.

As for the Pacific Trails Pipeline, certainly as of right now, this partnership is planning on owning that pipeline, but certainly if they were to look for somebody to take that from them and develop it, we would certainly be interested in it. We'd look at it at that time.

And I'd also just add, on the project itself, nobody has asked us to slow down our spend or anything on it, so from our perspective, we're still trying to meet our deadlines for the Kitimat project on the Merrick Pipeline. So we haven't had any conversation with any of the partners to curtail or slow down any of our work on the Merrick Pipeline.

Faisel Khan; Citigroup.

I have a couple of questions on corporate strategy here, especially as you guys embark on a large capital spending program in the pipeline space and I appreciate the details on all the capital spending. I was wondering if you guys could discuss the benefits of keeping the power and pipeline assets together as a consolidated company and more specifically, if you could kind of go into what you guys the operational and commercial synergies are of keeping these assets together, especially as you embark on this large potential spending program in the pipeline space?

I can take a shot at that, Faisel. On an ongoing basis, we look at our portfolio and try to determine what's of value, what's not of value. Our power portfolio has grown consciously and very specifically along the asset footprint of our pipelines. So if you take a look at a map, you can see very clearly that where we've located our power facilities is in jurisdictions that we know and understand where we have competitive advantage.

And as a result, we've been able to build a power business in those regions which I think is quite enviable, both in terms of its contracted kind of nature but as well in terms of the merchant capacity that we have in the low-cost merchant capacity in the market, so in Alberta, for example, the coal-fired PPAs are the low-cost contributors.

And as I sort of look at the synergies between those two groups and why we've been able to grow that group in that profitable way relative to our peers in what I call the ITP space that have had to take on I think investments of lesser quality, because of not being as diversified as we've been.

But all of our customers on the pipeline side are the same customers that we have on the power side. All of the regulators in each of those jurisdictions are identical to the regulators we deal with on those sides.

The people we have operating those assets in those regions, obviously if you look at the footprints, we have a centralized operating group that operates both of those, so whether we're operating a turbine that will turn a compressor or a turbine that will turn a generator, it's the same equipment and we've got pretty significant operating economies of scale, both from a purchasing perspective, but as well from an operating perspective in being able to operate that similar equipment across the asset base.

And then from a funding standpoint, we have funded that business quite substantially through a period where we didn't have a lot of pipeline investment. A good deal of our free capital was spent in that business and we're now in a position to harvest that, if you will, our investments in power. Albeit, we're still getting those assets up and running the way we want to. But we have put in a couple of billion dollars into that asset base over the last little while and invested in several others that are now flowing cash and those cash flows will be used to fund capital in our other businesses.

But there's still some maturing left to go on in that business, as we talked about here earlier. The true value of Bruce will be realized if we can get a long-term extension in the Units 3 through 8 and that conversation is going on with the government of Ontario as well. In Alberta, we've got the expiry of our PPAs in the 2017 to 2020 horizon. Again, we want to work on ensuring the longevity of that business and maximizing the value of our position for TransCanada shareholders today.

So that's not to say that we don't look at these things in terms of separating companies at some point in time in the future, but as we look at it today, there's still a lot of value to be gained for TransCanada shareholders through the integrated management approach that we've applied, and as well from a funding perspective.

So as I said, it doesn't mean that in our portfolio there's not a group of those assets, as Don said, they could be bundled in the event that we need to access alternative financing for funding our capital program. I'd look at our contracted base of gas assets or a contracted base of solar assets that we now have under construction or wind assets; run-of-river hydro. All of those can attract low-cost to capital in the marketplace and in the event that we require additional funds, that's another lever we can pull, from a financing perspective down the road.

So we look at it as a portfolio of assets that have considerable upside potential for our shareholders and optionality in terms of their financing potential going forward. So that's currently the way we look at our power portfolio.

I'm just wondering, one last question on this topic. Do you think the volatility in the earnings, and we discussed it today on the call, is sort of a volatility in western Canadian power prices and for that matter, the outage days in Bruce? Do you think that earnings volatility around EPS and some of the recontracting issues in the future sort of clouds the value of the pipeline business and potential growth on the pipeline business?

You spent an awful lot of time talking about power when the real growth is coming from the pipes. I'm just wondering if you think there's maybe a discount in the stock or a sum of the parts discount, because of the volatility in power and because it takes up a lot of time in terms of trying to get investors to understand it?

It's always a question that we ask ourselves, again, is what assets are best fit for our portfolio. And as I said, our approach to the power business is try to ensure that the power assets we bring into the portfolio are investment grade. And I guess when I think about merchant assets, merchant gas-fired assets, historically I wouldn't call it investment grade assets without a contract associated with them. So as you look through our portfolio, the percentage of what I'd call truly merchant power exposed to prices and volume interruptions are fairly minimal. All of our gas-fired power, with the exception of Ravenswood, is contracted. Ravenswood has got a capacity market, which to your point is somewhat difficult at times, but again, provides us with steady cash flow.

When I look at the other merchant assets that we've put in place, they have minimal volatility relative to what most people think about in the power business. I think run-of-river hydro, for example, in the New England region, it's the lowest cost producer. It runs every day. We're sure that we have revenue on a standalone basis. It's investment grade on a 60/40 like balance sheet. So from a balance sheet perspective it fits with ours.

I think at Bruce Power, again, contracted to an A-grade credit counterparty at a fixed and escalating price in the future, fuel cost pass-through. We do have operational risk. And given that we've just refurbished those facilities, we have had some volatility in the operation, but I would expect that to dissipate over time. I think if you look at the operations at Bruce B, I think you can see that a steady state run Bruce, running full time can generate pretty steady cash flow from a very highly credit worthy counterparty.

And sort of going back to Alberta, Alberta primarily contracted on the gas side. The lowest cost production in the provinces is coal that runs every day. It does have some price volatility associate with it. It doesn't go to a level that we can call it sort of investment grade, if you will.

So as I think about our portfolio, we tried to consciously make that portfolio as closely aligned from a balance sheet perspective as we can to the pipeline business. We haven't entered into what I call the truly merchant space that causes the rating agencies to have grade anxiety.

Now, on the edges we have a little bit of that. But if you look at where we're going with our power business over time, with things like our investment in Bruce, the Napanee facility, the solar facilities that we've got under construction right now, our percentage and then you add that to our portfolio on the pipeline side of contracted facilities; the percentage of volatile earnings or cash flow from this company declines from what I think is a very small number today, to even a small number three or four years out.

So I think that there's added value to our shareholders of that optionality and we take advantage of that optionality whenever we can. And the detrimental impacts I think aren't overwhelming.

Jennifer Hills; UBS.

It's actually Shneur Gershuni with UBS. Just wanted to ask a couple of follow-up questions on the MLP comments. Specifically, there's been talk about dropdowns to TCP, you sort of mentioned it several times over the last couple of months. I think it was at your analyst day as well too. Is it fair to read today's comments as a more firm commitment to dropping down the assets or said differently, you're a lot closer to the point where we'll see an acceleration of dropdowns as compared to your previous pace? I was wondering if you can sort of comment with respect to that?

It's Don here. Our commitment was firm at investor day and has been firm throughout here. As I mentioned earlier, there is an element of use of proceeds to this whole strategy, which does inform us on timing as to move forward with this stuff, but you can expect us to move forward here on a systemic basis over the coming several years here.

If big TransCanada has an increased need for the money as some of these projects move forward, I can see it accelerate faster. But no, there's been no change to our strategy in this regard.

So we're not closer to seeing an acceleration? I should read this no differently than I read it in November, basically?

Correct. The strategy is over time here to do that. We're certainly cognizant of the fact that it's been over a year since we did one of these, but at the same time, we'll point you to the quality of the assets that are going in. They're well known and the EBITDA that's there as well. We continue to firm up some of the target assets like ANR. In the interim period here since investor day, we've gone out and contracted up ANR for an average term of 23 years for the whole system at max rates. So there are some elements in the background here that we're just making sure these assets are tied up with a bow before we put them in.

So there's no timeline to be thinking about this, just as TransCanada needs funding, we would expect that you would basically sort of tap the markets through the dropdowns basically. Is that sort of the thought process we should employ going forward?

That's correct.

David McGough; Morningstar.

Regarding the Keystone system and the second quarter earnings for the Gulf Coast connector, I'm just trying to put in my head how much has ramped up in terms of throughput on that pipeline and where could we maybe see that going over the near-term? Because it's not at capacity yet, is it?

It's Paul here. No, it's not at capacity. We anticipate it running between 300,000 and 400,000 barrels per day during the second quarter. We're at the high end of that range now. We're probably averaging closer to 400,000. We would continue to see those volumes ramp up towards year end.

We've had some operational issues in regard to some of our injection facilities at Cushing. Those are largely behind us. So I would anticipate seeing a few more bales comes onto the system here in Q3, Q4.

Okay, so thinking a few more barrels, is maybe where we're at now a reasonable run rate with a little bit of an uptick at this point?

It is. And when you look at the run rate we have now, both on a cash basis and a volume basis, it's about CAD0.85 contracted, so I would anticipate stability in that run rate, again, with some potential for some upside, depending on market conditions.

Carl Kirst; BMO Capital Markets.

Just one quick follow-up, only because Russ, you mentioned it in the prepared comments, but casting our net much longer-term and looking at Alaska, we have had the state pass the law taking [energy] and seemingly moving forward. I guess my question is, as you sit here and you look forward today and understand we've got a two-year pre-feed process ahead of us and the like, how are you thinking about the investment size opportunity. We keep hearing these rather large 45 to 60 billion but that's of course the entire program and I guess with Alaska now, there's five different parties to consider.

But as you sort of cast your eyes forward, how large an opportunity do you think this could be, if indeed it does proceed?

I think the numbers that you're quoting are still the numbers that the project thinks about, that CAD40 billion to CAD60 billion kind of level for what I would call the pipeline and gas treatment facilities at [Gantlet], of which we have an opportunity to participate in all those facilities. It's not our intention at the current time to participate in the LNG facility itself, but that's just the upstream facility in the pipeline itself.

Our percentage, the way that it's being constructed, is aligned with what the states in kind royalty take is going to be and we don't know what that number is, but we would surmise it as probably between 15% and 25% and the way that it's structured right now is that we would take that share of the investment in both the pipeline and in the upstream facilities.

The state may take some of that. We're not sure at this time. So I think you can think of it as a TransCanada like investment in that range of 15% to 25% of the CAD45 billion to CAD60 billion and that gets you the simple math of where that would land. So it's like a CAD5 billion to CAD10 billion investment out there in the future is just kind of the way we're thinking about it.

We'll now take questions from the media. (Operator Instructions) Lauren Krugel; The Canadian Press.

I was just wondering whether you had an update on your rail bridge plans, any update you can provide there?

It's Paul Miller here. We continue to explore the opportunity to create both receipt facilities in Alberta and delivery facilities in the marketplace. On the project development side, on the engineering, the siting, we're progressing well in that regard. And then on the market development side, we're dealing with a number of parties here to anchor those facilities and it just takes time to corral a number of parties around a common project. So we continue that effort, but don't have further updates at this point.

John Spears; Toronto Star.

I just have two quick questions about Bruce Power. In Mr. Girling's remarks, he mentioned about the Units 3 to 8, he said replace or refurbish and I'm just wondering if you were contemplating new build reactors at Bruce at all?

Well maybe I can defer to Russ on that. This is Bill. But I would just say that the nature of the discussions between Bruce and the government, although I think at one point in time there was some discussion about further expansions at Bruce, there's nothing on the table in that regard. This is purely regarding the refurbishment of units 3 through 8 at the present time.

I was just looking at my notes, John. It did have those words, replacement. I think what we were referring to there in the speaking notes was there's replacements of certain parts and pieces, which are part of a refurbishment. No plans at this time for a newbuild facility of any kind.

I just wondered; every so often we hear that TransCanada or Bruce is interested in operating the Darlington or Pickering stations. What interest do you have and what conversations are you having with the government about that, if any?

I can maybe try to take that. Obviously, that's something that's bantered around on a continuous basis. That's not the current focus, is my understanding of the current negotiation is a bipartite negotiation between Bruce Power and the OPG and the government on Bruce's units.

But obviously it has to be coordinated with their similar bipartite conversations with OPG, because we have to schedule the sequence of taking these reactors down with how Darlington's refurbishment program is planned at the same time.

And I'm not aware at the current time that there's any sort of discussion around having a single operator. My understanding is that they're coordinated discussions, but they are bipartite discussions, not a tripartite discussion at the current time. I hear those comments as well, but we wouldn't be the source of them and not something that we're pursuing at the current time that I'm aware of.

Geoff Lee, Pipeline News.

I have a question about Energy East. You're going to build a lateral to take oil from Cromer, Manitoba to [Lucien], Saskatchewan; will you be taking oil from Anaridge tanks in Cromer or from Tundra Energy tanks in Cromer?

It's Paul here. We are looking at a number of different -- both routing options and receipt point options in that total Saskatchewan Manitoba marketplace. We have solicited interest from perspective shippers to understand what their market needs are and what their receipt point requirements are. So at this point we have surveyed various locations and we have had conversations with numerous parties, who have existing facilities.

Part of TransCanada's approach to pipeline development is to site our own terminal facilities at all the receipt and delivery points. So all of those are in play. It really is going to be a function of what is the market requirement and then we'll scope the facilities accordingly.

Elsie Ross; Daily Oil Bulletin.

How close are you actually to getting ready to file that Energy East application? Could it be in August or are you looking at later than that?

It's Alex Pourbaix just talking. Our plan is, we've announced that we're going to file that in the third quarter, so you can expect to see that filing come in really in just a few weeks, most likely.

In Ontario, what sense are you getting from those public consultations? I've heard in some places that people are saying there's no percentage for that province for the pipeline to go through it. What sense are you getting in those [communities] out there?

As you probably heard Russ talk about in his prepared remarks, we have held on this project something in the range of 80 different public meetings, we've met with over 6,000 stakeholders. I would tell you that our experience has been very much so that most of the people who attend these events and the people who get engaged in learning about this project are very interested in it and recognize that there are very very significant benefits for all of the provinces that the project goes through.

If you look at Ontario alone, if you look at the benefits of the construction activities, because so much of the project in terms of its total length is located in Ontario, those construction benefits and the GDP benefits to the province are massive. And that's just the direct benefits.

So I think when we go along the route and we talk about this project, the message I'm getting very strongly is most people recognize that there are very significant benefits to this project and very significant benefits to Canada to be able to market its production inside the country as opposed to importing oil to our domestic refineries.

I'll say that clearly, along those routes in Ontario, for example, we've been partners in those communities for literally decades. We're refurbishing a pipe that's been there. Our employees know those communities. Those communities know our employees. We've been a very strong corporate citizen, a strong contributor to the fabric of those communities over a long period of time. They recognize the property taxes and things like that that we pay today. But probably more importantly is our investment in other ways in those communities.

So, as we have the conversation about really just changing the product that's in the pipeline, they want to understand what are the potential risks and what are our mitigation strategies and that's been the nature of the conversation, as Alex said. I would say that those have gone extraordinarily well. They know us and they know that when we talk about pipeline safety, mitigation and response, they know that we've been serious about it and they've seen firsthand how we handle those kind of situations in their communities, as I said, over the last number of decades.

Iris Kuo; Argus Media.

First of all, could you give a little bit more detail on what the injection issues were with the Gulf Coast pipeline, I think you said, in the second quarter and how that's been addressed? In addition to any color on heavy throughputs on the pipeline?

It's Paul here. I missed the second half of your question. Any color on what?

Heavy crude throughputs on the line.

Oh, I see. The operability issues were really more just having all the facilities finished being constructed and commissioned, so we've had the terminal in place probably the beginning of the year here and we have just been finalizing all the various interconnects, which allow for the efficient operation of the terminal. So those interconnects, which provide the liquidity to the hub, have now largely been constructed and we'll move them into operations once we conclude commissioning.

In regard to the heavy/light split, we don't provide that information. I can tell you that we do have the ability to take both heavy and light bales from the Cushing marketplace down to the US Gulf Coast and that's just a function of market demand.

And then just a quick question on Cushing market link, if you don't mind giving perhaps a little bit more, I mean explain. I was confused on whether this -- is this project sort of the interconnect that you just mentioned or if it's storage or pipelines or once the project is completed, what kind of impact you would expect to see on throughputs or operations on your crude systems?

The Cushing market link is the terminal and injections facilities and related interconnects in the Cushing marketplace and it uses facilities that form part of the Keystone Pipeline system. That portion of the Keystone Pipeline system from Cushing to the US Gulf Coast, as built today, has a capacity of 700,000 barrels per day, but we have been ramping up capacity since we put this in service in early January. And today we're probably flowing about 400,000 barrels per day. We're targeting to increase those volumes throughout the year, and again, how quickly we ramp up is really going to be a function of market demand.

As far as terminal facilities, today we have just probably under 1 million barrels of capacity, mostly for operational purposes, but there is a storage component of this Cushing market link, so to the extent that folks want to contract storage with us, we'll provide the tankage services as well.

Rebecca Penty; Bloomberg News.

I just had a point of clarification. Russ, earlier on the call you were talking about Keystone XL and the cart process in Nebraska and you mentioned that you expect a decision in late 2014 or early 2015. And I just wanted to clarify, were you referring to a State Department decision or a ruling from whatever court it is in Nebraska?

It was with respect to the Supreme Court ruling in Nebraska. I'm hopeful that we'll see a decision before then, but based on historic precedent in terms of Supreme Court decisions and kind of the timeframe we would expect to get from September or a hearing to a decision sometime later in the year or early next year.

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

Thanks very much and thanks to all of you for participating this afternoon. We 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 thank you for your participation.