TC Energy Corp (TRP) 2013 Q2 法說會逐字稿

Good day, ladies and gentlemen. Welcome to the TransCanada Corporation 2013 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.

Great. Thanks very much, and good morning, everyone. I would like to welcome you to TransCanada's 2013 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 our Energy and Oil Pipelines Groups; Karl Johannson, President of the Natural Gas Pipelines Business; and Glenn Menuz, Vice President and Controller.

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

Following their prepared remarks, we will turn the call over to the conference coordinator for your questions. During the question and answer period, we'll take questions from the investment community first, followed by the media. In order to provide everyone with an equal opportunity to participate, we ask that you limit yourself to two questions. If you have additional questions, please reenter the queue. Also, we ask that you focus your questions on our industry, our corporate strategy, recent developments, and key elements of our financial performance. If you have detailed questions relating to some of our smaller operations, detailed financial models, Lee and I would be pleased to discuss them with you following the call.

Before Russ begins, I would 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, I would also like to point out that during this presentation, we'll refer to measures such as comparable earnings, comparable earnings per share, earnings before interest, taxes, depreciation, and amortization, or EBITDA, comparable EBITDA, and funds generated from operations. These and certain other comparable measures do not have any standardized meaning under GAAP and are therefore considered to be non-GAAP measures. As a result, they may not be comparable to similar measures presented by other entities. These measures are used to provide you with additional information on TransCanada's operating performance, liquidity, and its ability to generate funds to finance its operations. With that, I'll now turn the call over to Russ.

Thanks, David, and good morning, everyone. And thank you very much for joining us. We're very pleased to report this morning that all three of our core businesses generated strong results in the second quarter of 2013. We saw higher power prices in Alberta, an increase in New York capacity prices, the return of an eight-unit site at Bruce Power, and a higher Canadian Mainline allowed to return on equity. All of those things contributed to a significant increase in earnings and cash flow compared to the same period last year. In addition, we continue to advance a number of our projects and our expansive CAD26 billion capital program. Over the next three years, we expect to complete CAD13 billion of projects that are currently in the advanced stages of development. They include the Gulf Coast project, Keystone XL, the Keystone Hardisty terminal, the Heartland pipeline and TC terminals project, the initial phase of the Grand Rapids pipeline, the Tamazunchale extension, the acquisition of the remaining eight solar projects in Ontario, and the ongoing expansion of our NGTL system.

2016 to the end of the decade, a further CAD13 billion of projects are expected to become operational. Those include the Coastal GasLink and Prince Rupert gas transmission projects that would move natural gas to Canada's west coast for liquefaction and shipment to Asian markets, the Topolobampo and Mazatlan gas projects in Mexico, completion of the Grand Rapids and Northern Korea oil projects in Northern Alberta, and Napanee Generating Station in eastern Ontario. TransCanada shareholders will benefit from the predictable and sustainable earnings and cash flow resulting from these projects, as all of those projects are secured by long-term contracts.

I'll talk a little bit more about the progress on those projects in just a moment, but I would like to highlight a few of the major accomplishments in our second-quarter results. As I said, our third-quarter business segments performed well during the quarter. TransCanada reported net income of CAD365 million, or CAD0.52 per share. Comparable earnings for the quarter were CAD357 million, or CAD0.51 per share versus CAD300 million or CAD0.43 in Q2 of 2012, a 19% increase on a share basis. Comparable EBITDA was CAD1.1 billion, and funds generated from operations were CAD955 million.

The Board of Directors also declared a quarterly dividend of CAD0.46 per common share for the quarter ending September 30, 2013. Don Marchand, our CFO, will provide some more details on our financial results in a few moments. Before that, I would like to update you on the progress of our many capital projects.

I'll start with the Energy East oil project. We continue to feel very positive about this initiative and we have received significant interest from both producers and refiners. We are confident Energy East will garner the binding long-term contracts needed to move that project forward. It would be the most efficient and the safest and economic way to transport crude oil to eastern Canadian refineries, creating jobs, long-term economic benefits across the country, and displace foreign imported oil, making Canada more energy independent. This project is a new and innovative way to transport western Canadian crude oil to market, pushing out, as I said, unstable oil from foreign regimes.

It may come as a surprise to many, but eastern Canada currently imports about 700,000 barrels a day of oil each and every day from overseas. Energy East creates the opportunity for Canada to use and refine its own resources, something that we believe will benefit Canadians across this country. Energy East would complement our planned Keystone XL pipeline in a number of tangible ways, safely moving growing Canadian production not only to Canadian refineries, but also to US refineries, as well as to other global markets.

If you look at where the key refining centers are in North America, our long haul pipelines that we proposed are designed to strategically link those regions with supply. The circles on this chart represent the crude oil refining centers across North America. The size of the circle depicts the volume of crude oil refined. For example, the biggest circle is in the Gulf Coast, which is the largest refining center in North America and probably the largest refining center in the world. It currently refines about 7.5 million barrels a day.

The orange parts of those pie charts indicate where the imported oil comes from. Most of it coming from offshore. As you can see in the Gulf Coast, it imports about 4 million barrels a day. As well as you can see in North America, both Canada and the US in total import about 10 million barrels per day. Energy East and our Keystone systems have the ability to supply those refining markets with growing North American production. The Gulf Coast needs both Canadian heavy and light crude oil from the US. And Keystone will supply that need. Energy East will have the ability to supply refineries in Quebec, New Brunswick, and the Eastern United States, with light and heavy oil. Both pipelines, as I said, displacing foreign imports, ensuring North America has security supply for decades to come.

Moving to our projects under construction, or under development. Firstly, the CAD2.3 billion Gulf Coast project is nearing completion. Construction now is more than 85% complete. Since the start of that project in August 2012, we've created approximately 4,000 high-paying jobs for those who are building the pipeline. Those are pipe fitters, welders, electricians, heavy equipment operators, and many more. Demand for the project remains very clear, US crude production has been growing significantly in places such as Oklahoma, Texas, North Dakota, and Montana. Producers don't have access to sufficient pipeline capacity to move that production to the large refining markets in the US Gulf coast. The Gulf Coast project addresses that constraint, allowing US refiners to access lower cost domestic production and avoid paying premiums to foreign oil producers. This supports thousands of additional refining jobs in Texas, and the economic benefits those jobs provide to that state.

We expect the 700,000-barrel a day pipeline to be operational by the end of the year. In addition, construction of the CAD300 million Houston lateral is expected to begin in the coming months. That 76-kilometer project will transport crude oil to the Houston refineries and is expected to be complete in 2014.

Moving to Keystone XL, review of the over 1 million comments presented to the US Department of State continues, and we look forward to a final environmental impact statement being issued once that review is complete. We are now closings in on 1,800 days since the review of Keystone XL began. Our base Keystone pipeline has now safely delivered over 400 million barrels of oil to refineries in Illinois and Oklahoma since the summer of 2010. The review for that project, which is nearly an identical project to Keystone XL, took only 21 months.

Our view is now time to bring this process to conclusion to focus on the safe construction and operation and allow Americans to experience the benefits of one of the largest infrastructure projects on the books in that country right now, creating 9,000 construction jobs and many more spin-off jobs in manufacturing in other sectors. Once the FEIS is issued, the Department of State will begin the National Interest Determination period for Keystone XL, which will lead to a decision on a presidential permit. The CAD5.3 billion cost estimate that we put out there will increase, depending on the time of that permit. As of June 30, we have invested about CAD1.9 billion in the project.

Recently, the question of Keystone XL's contribution to global GHG emissions has been raised. In our view, the answer to that question is quite simple. Keystone XL will not result in growth in GHG emissions period. It is just a pipeline and it's 875 kilometers of pipeline in a North America market that has 180,000 miles of liquids pipelines. Keystone XL will not dictate the growth in supply, nor will it dictate the volume refined in North America. It happens to be just the safest and most efficient means to move that crude oil from supply to refiner, but that commerce will continue irrespective of the approval of Keystone pipeline.

The fact is, the US needs oil. It needs oil to start 250 million cars each morning. It also -- it needs oil so the Americans can heat their homes, fly on airplanes, and manufacture thousands of products they use every day. Simply put, for now, the US cannot live without oil.

I agree that we need to move to a less carbon-intensive energy future. And that is why TransCanada has invested over CAD5 billion in emission-free energy. Solar, hydro, in the US northeast, the largest wind farm in Maine, nuclear. We are involved in all of those areas. But the fact remains that the US consumes some 50 million barrels a day of oil, and imports 8 to 9 million barrels a day of those needs. Our opponents cannot spin this in any way that makes it look like that's going to change. The US Energy Information Administration and the International Energy Agency both forecast the United States will need to import millions of barrels a day of oil for decades to come. And again, I'm not sure how our opponents can spin that.

So it is not a case of whether Americans need oil. They will. And they do. The only relevant question is where would Americans like that oil to come from? Should it come from a friendly nation in Canada, an ally that shares American ideals and can supply lower-priced stable crude oil? Or should the oil continue to come from unstable countries like Venezuela and other countries that do not support American values? And again, I think the answer is quite clear. And that's why we remain confident Keystone XL is in the national interest of the United States and it will be approved.

Moving to the rest of our infrastructure, on the pipeline -- on the oil side, we continue to expand our oil infrastructure network in Alberta, with the announcement May 2 of the Heartland pipeline and the TC terminals project. That initiative includes a 200-kilometer oil pipeline connecting the Edmonton region to facilities in Hardisty. We will build the oil storage terminal in Heartland, which is an industrial area just north of Edmonton. Pipeline would transport up to 900,000 barrels a day and up to 1.9 million barrels of oil could be stored at the terminal. Together, these projects have a combined cost of about CAD900 million and are expected to be operational during the second half of 2015.

On May 30, we filed a permit application for the terminal and expect to file an application for the pipeline later in 2013. Earlier this spring, we filed permit applications with the provincial regulator for both our Grand Rapids and Northern Courier projects. We continue to work with the [four tails] Energy Limited partnership on the development of that project. The Grand Rapids pipeline system will be the first pipeline to connect the growing Oil Sands region west of the Athabasca River to Edmonton and will be able to carry up to 900,000 barrels a day of crude oil and 330,000 barrels a day of diluent. We expect initial deliveries to begin in 2015 and that project should be complete in 2017.

Moving now to gas. In the spring, the National Energy Board issued its decision on our application to change the business structure and terms and conditions of the Canadian Mainline. The decision significantly altered the regulatory framework that has formed the basis for billions of dollars of regulated pipeline investment over the last 60 years. On May 1, 2013, we filed an application for review and variance of that decision, asking for specific long haul toll adjustments, a surcharge methodology for the recovery of certain costs, and a change in the implementation date of the decision. On June 11, the NEB dismissed a review in variance and released its reasons for decision on July 22. The regulator did recognize that certain proposed changes by TransCanada to Canadian Mainline tariff should be considered as a separate application and proceed through an oral hearing that will begin on September 3 of this year. TransCanada is operating under that new decision environment as of July 1 and we have submitted the tariff change application and will manage that process through the oral hearing and wait for the decision on those changes.

Continuing to focus on gas, our western Canadian infrastructure network, we continue to expand the NGTL system with about CAD700 million of new facilities becoming operational so far this year. TransCanada has applied and received approval for, from the NEB for an additional CAD130 million of new facilities. To date in 2013, we've applied for an additional CAD145 million of facilities and are planning regulatory applications for further expansion into British Columbia at an estimated cost of between CAD1 billion and CAD1.5 billion to connect and transport new gas supply that will be delivered to the Prince Rupert gas transmission project and other markets served by the NGTL system. NGTL is also developing plans for its upcoming open season to provide delivery service to Vanderhoof, British Columbia on the Coastal GasLink pipeline. That open season is expected to occur in the second half of 2013.

In early January, TransCanada was selected by PETRONAS affiliate Progress Energy Canada to build, own, and operate the CAD5 billion Prince Rupert Gas transmission project. That pipeline would transport natural gas primarily from the North Montney gas producing region near Fort St John to the PETRONAS affiliate Pacific Northwest LNG's proposed export facility near Prince Rupert, British Columbia. We filed the project description with the British Columbian Environmental Assessment office and the Canadian Environmental Assessment Agency in May of 2013. First Nation's and stake holder engagement processes continue as we advance through the regulatory process.

Pacific Northwest LNG applied for a National Energy Board permit to export up to 19 million tons of LNG per year for 25 years beginning in 2019. Pacific Northwest continues to work to reach a final investment decision in late 2014. Also in June 2012, TransCanada was selected by Shell and their partners, Mitsubishi, KOGAS, and PetroChina to design, build, own, and operate a CAD4 billion Coastal GasLink pipeline project. TransCanada initiated the environmental assessment process in the fall of 2012 through filing of a project description with British Columbia Environmental Assessment office and the Canadian Environmental Assessment Agency. The project teams continue to focus on community, land owner, government, aboriginal, and First Nation's engagement as it gathers information and field data to advance the project through the regulatory process and through the preliminary design.

Turning now to power. And Bruce Power, specifically unit 4 returned to service on April 13 after work was completed to expand its operational life. That work began in August of last year and now should allow that unit, unit 4, to operate until at least 2021. With the return of unit 4 and the restart of units 1 and 2, Bruce Power is now operating as an eight-unit site for the first time in two decades and has the capability to generate 6,200-megawatts of emissions-free energy. No further maintenance outages are planned for Bruce Power for the remainder of 2013, following planned outages of two of the Bruce B units and one of the Bruce A units in the second quarter of 2013.

In addition, earlier this month, we acquired the first of nine Ontario solar power facilities from the Canadian Solar Solutions company. The combined capacity of the nine projects is 86-megawatts and the cost of that portfolio will be approximately CAD470 million. We anticipate the remaining eight projects will come into service by the end of '14. They will complement TransCanda's existing operations in Ontario, where we have become the largest independent power producer in that province. The renewable energy produced from these projects will be sold to the Ontario power authority under 20-year power purchase agreement. One-third of our power now at TransCanada is emission-free and will provide carbon-free power for the North America for decades to come.

So in conclusion, all three of our core businesses, as I said, continue to perform strong through the second quarter. Higher Alberta power prices, higher New York capacity prices, and the return to an eight-unit site at Bruce, and a higher Canadian Mainline allowed return on equity all contributed to a positive quarter. Our unprecedented portfolio of growth opportunities now includes CAD26 billion worth of commercially secured projects, which we expect to become operational between now and the end of the decade. As I said earlier, we have significant interest in our Energy East project, which would add to that existing portfolio of commercially secured projects, if we decide to move forward. As a result of the contractual nature of all of those projects, we expect them to generate predictable and sustained growth in earnings, cash flow, and dividends, growing shareholder value as we have done in the past for decades yet to come. I'll turn it over to Don Marchand, who will provide some additional details on our second-quarter financial results. Don?

Thanks, Russ, and good morning, everyone. I would like to begin today by highlighting a few key messages. First, all three of our business segments generated solid results in the quarter. Second, the positive momentum in earnings is expected to continue in the second half of 2013, with Bruce Power operating as a full eight-unit site. The return of Sundance A, construct of power markets in Alberta in the US northeast, and a higher Canadian Mainline return on equity. Third, as Russ highlighted earlier, we continue to advance our CAD26 billion portfolio of high-quality long-life energy infrastructure opportunities. All of these projects are underpinned by long-term contracts and are expected to contribute to significant growth in earnings, cash flow, and dividends over the remainder of the decade. And finally, we remain well positioned to fund our current capital program. Our track record in 2013 to date, which has seen us raise CAD3.6 billion of capital at very attractive rates, is a clear demonstration of our ability to access varying sources of capital in order to finance our growth plans.

Now, moving to our consolidated results shown on the next slide. Comparable earnings in the second quarter of CAD357 million, or CAD0.51 per share, increased by CAD57 million, or CAD0.08 per share compared to the same period in 2012. The 19% increase in comparable earnings per share was primarily due to higher power prices in Alberta, higher Bruce A volumes due to the recent restart of units 1 and 2, combined with the return of unit 3 after its life extension outage in June 2012, higher realized power prices and capacity prices in US power, and a higher allowed return on equity for the Canadian Mainline. These were partially offset by lower contributions from US natural gas pipelines, lower volumes at Bruce B, and higher interest expense and income taxes.

I'll now review the business segment results at the EBITDA level. Our natural gas pipelines business segment generated comparable EBITDA of CAD644 million in second quarter 2013, compared to CAD666 million for the same period last year. The CAD22 million decrease resulted primarily from lower contributions from A&R, Great Lakes, and TC Pipelines LP. Canadian Gas Pipeline's EBITDA increased CAD24 million compared to the same period in 2012. The improved results were due to higher NGTL system average investment base as a result of ongoing expansions, and a higher return on equity for the Canadian Mainline as a result of the NEB decision on our Canadian restructuring proposal. Recall that in its decision, the NEB approved, among other things, a return on equity of 11.5% on a deemed equity ratio of 40%, compared to the last approved return on equity of 8.08%.

US natural gas pipelines generated CAD150 million in EBITDA, a decline of CAD48 million in second quarter 2013, compared to the same period last year. Decreased revenues at Great Lakes due to lower tariff rates and uncontracted capacity, as well as lower revenues and higher costs at A&R associated with services provided by other pipelines, continued to have an impact on our results. Overall weakness in certain US pipelines due to lower revenues and higher operating costs is expected to continue in the coming quarters.

Turning to oil pipelines. Keystone generated CAD187 million of EBITDA in the second quarter. The CAD9 million of incremental EBITDA year over year was due to increased revenues as a result of higher contracted volumes and the impact of a positive adjustment to the final fixed tolls on committed pipeline capacity, which came into effect in July 2012. In energy, comparable EBITDA was CAD330 million in the second quarter compared to CAD170 million for the same period last year. The CAD160 million year over year increase was the result of a combination of positive factors across both our Canadian and US power businesses.

Western Power's EBITDA rose CAD96 million in second quarter 2013 compared to the same period last year. The significant increase was primarily due to higher realized prices, and purchase PPA volumes in Alberta, as well as the CAD30 million Sundance PPA arbitration decision charge that was recorded in the second quarter of 2012. Average Alberta spot power prices tripled in second quarter 2013 to CAD123 per megawatt hour, compared to CAD40 in the same period last year, due to plant outages from the province and increased power demand. While Western Power benefited from these higher prices, results also reflect the net impact of hedging activity.

With respect to Sundance A, TransAlba's most recent update was that it expects to return unit 1 shortly and unit 2 in the fall. Until the Sundance A units are returned to service, we will not realize the generation or related revenues we would otherwise be entitled to under the PPA, and will continue to be relieved of the associated capacity payments. Equity income from Bruce Power increased CAD28 million in the second quarter compared to the same period in 2012. For the first time in two decades, Bruce Power is operating as a full eight-unit site with the return of unit 4 from its life extension outage on April 13. The work completed on unit 4 during the prolonged outage will allow it to operate until at least 2021.

Higher equity income from Bruce A as a result of the restart of units 1 and 2, along with increased volumes in unit 3, which was under a six-month outage to extend its useful life last year, was partially offset by lower revenues and higher operating costs at Bruce B, as a result of increased planned outage days and higher lease expense. With no further maintenance outages planned for the remainder of 2013, Bruce Power is expected to generate significant earnings and cash flow in the second half of the year, now that all eight units are operational. US power EBITDA was CAD43 million higher in the second quarter compared to the same period last year. The increase was primarily due to higher realized power prices, continued firming of the New York Zone J capacity market, and higher net revenues on wholesale, industrial, and commercial power sales. And finally, natural gas storage results decreased CAD8 million in the quarter due to lower realized storage spreads, partially offset by the acquisition of the remaining 40% interest in CrossAlta in December 2012.

Now, turning to the other income statement items on Slide 27. Comparable interest expense in the second quarter was CAD252 million, compared to CAD239 million in the same period last year. The CAD13 million increase primarily reflects lower capitalized interests as a result of the restart of Bruce A units 1 and 2, partially offset by increased capitalized interest related to the Gulf Coast project. In the second quarter, CAD60 million of interest was capitalized to assets under construction compared to CAD76 million for the same period in 2012. Comparable interest income and other decreased CAD21 million year over year, primarily due to realized losses in 2013, compared to gains in 2012 on derivatives used to manage the Company's net exposure to foreign exchange fluctuations on US dollar income. In combination with US dollar denominated interest expense, this hedging program largely counterbalances the currency impact of translating US dollar pipeline and energy income reported in the business segments. Comparable income taxes for second quarter 2013 increased CAD42 million compared to the same period last year, due to higher pretax earnings, and a higher effective tax rate as a result of a change in the proportion of income earned in higher tax jurisdictions.

Moving on to cash flow and investing activities on Slide 28. Cash flow was strong in the quarter, mainly due to higher earnings in the period. Funds generated from operations totaled CAD955 million in the second quarter, an increase of CAD226 million from the same period last year. Turning to investing activities. Capital expenditures were CAD1.1 billion in the second quarter, driven primarily by the Gulf Coast project, ongoing expansion of the NGTL system, and construction of our Mexican pipeline projects. Acquisitions of CAD55 million in the quarter reflect the purchase of our first Ontario solar project, which closed in late June. The acquisition of the eight remaining projects is expected to close in 2013 and 2014, as they are satisfactorily completed and brought online.

Now, looking at Slide 29. Our liquidity and access to capital markets remains (inaudible). At the end of the second quarter, our consolidated capital structure consisted of 41% common equity, 5% preferred shares, 2% junior subordinated notes, and 52% debt net of cash. At June 30, we had CAD674 million of cash on hand, along with CAD4 billion of committed and undrawn revolving bank lines with our high quality bank group. Our three commercial paper programs, one in the US and two in Canada, are well supported and provide flexible and very attractive sources of short-term funds.

In July, we completed the sale of the 45% interest in each of GTN and Bison, for $1.05 billion, which included CAD146 million of GTN-related debt to our master limited partnership TC Pipelines LP. TC Pipelines successfully financed the transaction through a public offering of common units and a debt placement. Aside from contributing $8 million to maintain our GP interest, we did not participate in the equity offering, and as such, our ownership interest in the partnership decreased from 33.3% to 28.9%. This asset dropped down as a clear demonstration of one of the many financing options available to us, as we continue progressing our unprecedented growth portfolio.

Also in July, we completed two additional debt offerings, raising over CAD1.25 billion in Canadian and US markets at very attractive rates. Specifically, we issued our first LIBOR-based floating rate notes, raising $500 million of three-year funding at an initial interest rate of 0.95%. In Canada, we issued CAD450 million, CAD300 million of medium-term notes for terms of 10 and 30 years, varying interest at 3.69% and 4.55% respectively. Proceeds from these offerings will be used for general corporate purposes and to reduce short-term indebtedness, which was used to fund capital program. Year to date, we've now raised CAD3.6 billion on attractive terms through an array of funding products to a diverse investor base. Looking forward, we remain well positioned to finance our capital program through funds generated from operations, new senior debt, subordinated capital in the form of additional preferred shares and hybrid securities, as well as portfolio management, which may include further LP drop-downs.

In closing, TransCanada produced another strong quarter, with comparable earnings per share 19% higher than second quarter 2012. Going forward, the restart of Bruce Power Units 1 and 2, along with completion of the unit 4 life extension outage in April, the return of Sundance A, firming of power markets in Alberta and in the US northeast, incremental Keystone revenues, and a higher Canadian Mainline return on equity are all expected to have a positive impact on earnings in 2013. This will be partially offset by lower contributions from US natural gas pipelines and higher interest expense. Furthermore, we also expect to complete a number of capital projects that will also contribute to earnings and cash flow in 2013 and 2014. They include construction of the Gulf Coast project, ongoing expansion of the NGTL system, the Tamazunchale pipeline extension, the Hardisty Terminal, and the acquisition of the fully contracted Ontario solar assets.

Finally, we continue to advance the balance of our CAD26 billion of commercially secured capital projects, which includes a number of large scale energy infrastructure investments that are targeted for completion between 2015 and the end of the decade. They include Keystone XL, two natural gas pipelines to Canada's West Coast, two gas pipeline projects in Mexico, several oil pipeline projects in Alberta, and the Napanee generating station in Ontario. Each of these initiatives is underpinned by long-term contracts with strong counter parties. As a result, we expect to generate significant growth in earnings, cash flow, and dividends, which are expected to deliver superior risk adjusted returns for our shareholders in the years ahead. 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 the call over to the conference coordinator, we will take questions from the financial community first. 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.

(Operator instructions)

First question is from Linda Ezergailis from TD Securities.

Thank you, congratulations on a strong quarter.

Thanks, Linda.

Just a quick question on Energy East, when might you expect to finalize or firm up your commercial agreements? And what would you say is the key challenge, if any, in getting to that point?

Hello, Linda, it's Alex. I don't think we really have any challenges to get to the point where we can be in a position to announce. It's just working through terms and conditions, credit, so forth. I think from our perspective, look forward to hearing something from us within the next two weeks.

Great, thank you. And then, beyond the large current project you're working on, Keystone XL, Energy East, Northern Courier, Grand Rapids, and I realize that alone keeps you busy, but are you working on any other major liquids pipelines, either regional in Canada or the US or larger, either as a new build or maybe partially repurposing a natural gas pipeline?

You know, we are, and what I would say is it's kind of all of the above. We're actually seeing some very interesting greenfield opportunities, but we always look very hard at our existing pipeline assets to see if we see opportunities for repurposing along the lines of Energy East or Keystone, and I think we're pretty optimistic we may be able to execute on some of those opportunities in the future.

Great, thanks. I'll jump back in the queue.

Okay.

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

Thanks. Good morning, everybody. Just keying off of Linda's question, Energy East, is it possible, just given where we are in the process to start giving detail as far as what we think the cost structure, the total investment cost will be and, in particular, the destination? And would this be a phased destination over time or done all at once?

Carl, it's Alex again. I think that we're, I've said this recently, we were pleasantly surprised by the commercial response to our open season and particularly with interest going all the way to the East Coast. We have provided our shippers with a number of destination options, which will be, when we announce the project, we'll be able to give a lot more guidance on that and on the capital costs.

I think the one thing I would say is we are working very closely with stakeholders in the community, so we go through to ensure that we are very thoughtful and very responsive to the concerns that various communities and regions may have. And that's one of the other reasons why we're being very careful as we go through this process.

No, understood and appreciate the color. Separate question, if I could, and Russ, this is really more of a question on the main line and the market's digestion of the new rate taking into account July 1. And one of the discussion points prior was, perhaps, don't knee-jerk on the decline in spot volumes because we're seeing increased interest in contracted volumes. I didn't know if there was any way to quantify that? To get greater long-term comfort relative to where the spot volumes are today, for instance?

Yes, I think I'll let Karl take that one.

Yes, I could take that, Carl. Yes, and I think it's a matter of public record, so I think I can share this number with you. It's on our website. We have, since the NEB decision, we have put on the books about a Bcf a day of new FT contracts, firm transportation contracts, so we have seen that. That's quite a large increase. Going into that, we had 1.1 Bcf a day coming out of the west in contracts, so it's about doubled it. So, we have seen quite a bit of new contracting on the system.

Great. That's what I needed. Thanks so much.

The next question is from Paul Lechem from CIBC.

Thank you. Good morning. Still on the main line, I wanted to try to understand a little bit what the NEB hearing, the oral hearing that's starting in September, what that is related to? What is involves? That hearing would involve?

And, furthermore, with the filing of an Energy East application, I understand that might trigger a new rate case around the main line. What would you expect that to involve as well? Thank you.

Yes, it's Karl again. Certainly. The hearing of September really came out of our review and variance with the NEB. We asked for some changes to the contracts. And we'll probably have several of these going forward, quite frankly, with the new pricing environment we're in. We have to change some of our contracts to make them less, look less like the old world of cost service and more like the new world of merchants, so we have to take things out of the contracts. In particular, in September, we're looking at the renewal options in our existing contracts. The two more important issues in September, the renewal options and the contracts that we have right now, and the diversion rates for people that, by service on us, we're looking to modify the renewal options and eliminate the diversion rights.

As for the, as for what's going to happen with the main line upon the Energy East application, the NEB did make a provision in their decision that when we were to go forward with the Energy East, or if we were to go forward with the Energy East, they would invite us back to relook at our rates and relook at how the rates are determined on the system. So, I suspect at that time, given that we would be transferring some capacity to the oil business, we would be back in front of the NEB looking for the impact of that transfer and looking for different rates.

Okay, thanks. And just one follow-up, if I may. On the, since July 1, given you were operating under the new rate toll, the new tolling structure, can you talk a little bit about your short-term and interruptible tolls? How you've been setting them? How that's being received by the market? Any thoughts in terms of modification to the any of short-term tolling that you've put in place?

Well, sure. I don't want to get into what our actual strategy is because that would, given the market we're in now, it's somewhat confidential. But I think I can talk in broad ranges. The Board has given us, for our short-term and discretionary services, they have given us a broad range of flexibility now, and they haven't really limited us in any way.

Our goals, our high level goals of offering that is to really maximize both throughput and revenue on our system. So, it's not just well throughput and it's not just well revenues. It's about both. We look at both of them, but we do look at how much volumes that we are shipping on short-term. We're looking at how much volumes that, new contracts we're getting on FT contracts as well. So it's -- we are trying to price accordingly to maximize both the revenue and throughput on the system.

Thank you very much.

Thanks, Paul

The next question is from Robert Kwan from RBC Capital Markets.

Good morning. Karl, maybe I'll just continue with the main line as the first question here. Just with the way you're aggressively pricing the IT and STFT, and what that's done for migrating some people to contracting on the FT, can you talk about what you've seen behind that in the delivery point? Are people -- did you see that increase as people are trying to use the cheaper GLGT path into Dawn, and what your expectations are as you've started to use up some of that capacity for future, or for additional FT contracts?

I guess what I can say is we've seen -- as I talked about a little earlier, I think we saw about a Bcf, a little over a Bcf a day of new contracts since the NEB decision. About 40% of that came after July 1 so we've been very busy since July 1. A lot of those contracts since July 1 have been the Empress to Emerson to Great Lakes or in that area of contracts. So, I do think we've seen some extra contracting that's destined, ultimately, for Great Lakes. The rest of the contracts really are all through our system. So there's, you know, we've seen contracting right across the board for all of our delivery points.

Just to add to that, Robert, to hear your comment on aggressively pricing, I guess that wouldn't be the way we would characterize it. Our tolling structure changed as of July 1 and what we're trying to do is understand what value people derive it for different segments and different parts of our systems over different periods of time, and make sure we price accordingly to capture the value that the people see in our pipeline. I think as we've always said, the main line has tremendous value to the North American gas infrastructure, and part of what we're doing is learning how that works and trying to price accordingly to meet customer needs.

Okay. Thanks for that. And just the second question I have, you talked about how you've used TCP and looking at it in the future as part of your financing options. I'm just wondering, though, with some of the US valuations and the bumps we've seen for the general partners, i.e., the C Corps. Just wondering if you have any thoughts on a more aggressive use of TCP from a strategic valuation perspective?

Yes, go ahead, Russ.

I was going to say maybe to start from a high level and maybe Don can jump in on this too, Robert, is obviously we've always said that the TC PipeLines is a strategic financing vehicle for us. When we have capital needs, obviously, as you look at our portfolio of CAD26 billion and growing, we have significant capital needs. So, the strategic financing position for TCP is growing inside of our Company. We are watching what others have done with respect to dropping down larger portions of their portfolio and the valuations.

I guess what we always look at is true long-term value, and to the extent that that creates value for shareholders in both TC PipeLines and for TransCanada, obviously, we would look at that. But usually not that swayed, at least to date, we haven't been swayed by what I call short-term market valuations for certain assets that aren't underpinned by fundamental economics. That said, it is obvious we have a big financing need, which is probably driving us more to using TC PipeLines in the future than we have in the past. Don?

Yes, I would agree with that. And at the end of the day, it's driven by use of proceeds and what we look for is to extract cash rather than pieces of paper from it. If you just vend assets in and create governance between the cash flows and where we need them, that's something we bear in mind. But we'll weigh it against preferred shares, hybrid securities, and the like, in terms of cost size, currency, equity credit, and the like, and you've seen us go down the path on all of these in the past and I would expect to us do the same in the future.

That's great. Thank you very much.

The next question is from Matthew Akman from Scotiabank.

Thanks. Don, question for you on financing plans. With bond yields having lifted in the last couple of months, I'm just wondering how you're thinking about your debt issuance, as there was some issuance last week? And also your hedging program on forward cost of debt?

Yes, I'll just speak broadly about what the quantum is over the next couple of years here. So, if we look between now and the end of 2015, and we'll just put Keystone XL aside for now until we have visibility on timing of that, total CapEx is in the CAD11 billion area. Roughly broken down, about CAD4 billion on oil, includes Gulf Coast and the Alberta regional pipes and terminals, but CAD4 billion in gas, which is NGTL, Mexico, and some pre-spend on the LNG projects to get them to permitting. And about CAD3 billion of other, which includes the solar acquisitions, some spend on that, beneath maintenance capital and other. So, you get about CAD11 billion. Internally generated cash will cover about CAD7 billion of that. That leaves us about CAD4 billion of new capital and about CAD3 billion in maturities. So, we would see a need of CAD7 billion, CAD7.5 billion over the next few years. Now, that will go up as we get clarity on XL, and could also go up as we start progressing NGTL spend on Prince Rupert, so from a quantum prospective, that's looking at.

Talk about some of the levers that are available, senior debt will be the first place we would look to being the cheapest form of capital within the constraints of the A credit metrics, and then as I walk through some of the other options there. We're not active hedgers of forward issuance. We're a continuous issuer in the marketplace. The cushions we have against rising interest rates are predictable in growing cash flow. We have a long-term debt portfolio. The average term of our debt is in excess of 11 years, we're over 90% fixed rate financed at this point in time.

We do have cost pass-through ability, certainly on our Canadian regulated pipes and on certain prospects such as the LNG projects, and we would expect ROEs, albeit with a lag effect, to increase in a rising interest rate environment as well. If it's accompanied by inflation, we do have CPI adjustment factors on Bruce as well. We would expect commodity prices to rise as well. So, we're not lying awake at night worrying about rising interest rates. Obviously, it has a valuation impact, but those are some of the things we look at and the quantum of needs that we have clear visibility to right now.

Okay. Great. Thanks for that. Just one more question, it relates to the main line tolls. I'm just wondering the process? We've touched on this for reestablishing tolls in the event of successful open season at Energy East. Would that process go along the same time lines as the regulatory approval process for Energy East? What time lines, roughly, would the gas pipeline retolling hearing run on?

Matthew, that's actually a good question. We've been talking a lot about that in our shop. We really have two options. We can file a revised main line application at the same time as Energy East, or we could wait until closer to the time that we take these assets out of service on Energy East.

And at this point, we haven't really determined what's -- which way we're going to go. But I guess it's not necessary to file it at the exact same time, because it is going to take a couple years to get the capacity out of service once we file our application, so we do have some flexibility there. But we haven't made a final decision on when we'll be filing that.

And Matthew, obviously the two things are tied together, that the reason for a revised inline toll application is because we're going to adjust the rate base because of the transfer to oil service. So, they are linked. And so, we are just working through what is the most efficient way to file that when the time comes. And part of that, obviously, will be dependent upon our discussions and negotiations with the shippers on both sides. And we're active in those discussions right now and we're trying to find the place that works best for both parties.

Okay. Perfect. Thanks, Russ. Thanks, guys.

Thanks, Matthew.

The next question is from Juan Plessis from Canaccord Genuity.

Thank you. You have mentioned in your MD&A that the indicative timeframe for a Keystone XL in-service date is two years after receipt of Presidential permit. And previously, you had indicated 18 to 24 months depending on the timing of the approval. Has anything changed with respect to the construction schedule, or is it just that you think you'll receive a Presidential permit at a time in the construction cycle that will require 24 months?

Juan, it's Alex. I don't think -- there really hasn't been any change in our thought on that. And, really, I think we've just used that 24 months as a bit of shorthand. I think, as you noted, we need the better part of two construction seasons, but depending on the date we get the approval, all months really aren't equal. So, we've just for simplicity's sake, we're using 24 months. But it doesn't indicate any sort of differing thought on construction timing or anything like that.

Okay. So, it's 24 months at the outside?

Yes, I think we basically, I think that's a fair way to describe it.

Okay, thanks. And my second question, Karl, you didn't get the interest in the Portland's Natural Gas Transmission system open season, but you continue to look for market opportunities to develop growth. Can you talk about some of these potential market opportunities as it relates to PNGTS?

Well, I think that's fair characterization. We never got the market interest that we wanted. I think that was because there's still a lot of uncertainty over our tolls and how much capacity we're going to have for long haul, what's the price of long haul, what's the price for incremental capacity in our lines. So, there's still some uncertainty around the main line, and I personally attribute that to be the main reason that we didn't get as much interest as we wanted.

We are, as Russ said, we are in talks with all of our shippers right now to try and reduce that uncertainty, to try and determine how incremental capacity will be put into the system under this new world that we're in. And I am optimistic that we will come to some arrangement in the future. And I think we'll be able to, I think we'll be able to take out that uncertainty in the main line and we will go back with another open season at that time with PNGTS. So, I don't think it's over, our open season is on that line, by any stretch of the imagination. I think it's still a pretty useful piece of assets and I think it goes into a market that needs the capacity. So, we're just going to work on reducing some of the uncertainty over some of the main line, the main line part of that and I think we'll be back at it.

Okay, great. Thanks very much.

The next question is from Pierre Lacroix from Desjardins Capital Markets.

Yes, thank you very much. First, Russ, I just wanted to have an update on the Keystone XL. As the decision is taking more and more time and the startup is slipping towards 2016. Just wanted to have a refresh on what are the main contracts or deadlines that you have with your shippers or your customers there for your contractual arrangements, depending on the date of the startup?

I'll let Alex take that.

Sure. We do have some sunset dates in those provisions. What I can say is that we have been in close contact with all of our shippers and we do not anticipate that any of those sunset dates are going to be a problem with the project. I think basically how our shippers look at it is we are the most economic route to the Gulf Coast. We're the furthest advanced. The project is really sitting on the 5-yard line, and I think everybody is fully committed. All of our shippers behind getting this project over the line. So, we don't anticipate any significant concerns on that regard.

Okay, thanks. And further on this, the Gulf Coast project, can you remind me the return profile? I know that it's tied to volume in the meantime that Keystone XL comes in at some point. With the tightening of the differentials, do you see the initiation of the Gulf Coast project with at the lower end of the return profile range? And can you give us some kind of refresh on this side as well? Thanks.

Sure. You know, I think we're -- we've always said that the contribution from the Gulf Coast project is probably in the range to CAD200 million to CAD300 million of EBITDA, and that range probably looks like a 7% to 9% type of project. And we think that we're -- the majority of the volume moving under that pipeline is going to be under contract. There is some, there is some amount of spot. But we still think that guidance is pretty good guidance.

Okay. Thanks. And one other, maybe for Russ. What is the Company's appetite at this point to look at major, or significant comprehent strategic moves, when we saw earlier this week some of your comparables in the US doing some and some also IPO going on in the power space? Where do you stand on that front, Russ?

I think that our strategy is pretty much laid out in front of us. We have a, I think, a diversified large portfolio of energy infrastructure. All three of those businesses create new platforms for growth. That's turned into a number that looks about CAD26 billion. So, that's what our focus is on, is the execution of that CAD26 billion of opportunity. And from both a human resource perspective and capital perspective, most of our time is spent on ensuring that we have those resources to be able to execute on that plan.

If it comes to fruition, and we're fortunate that all of those projects receive sanction and move forward, they will add tremendous value for our shareholders. So, our focus isn't on other corporate transactions right now, but we do keep an eye to the market as things arise, and we'll adjust if there is, if opportunities. But I would say that's not in our core focus right now. We've got lots to do with our existing platform.

Okay. Thanks. One final for Don. You mentioned the CapEx over the next couple years outside of CAD11 billion. What is the breakdown between 2013 and 2014 in term of the CapEx plan?

Yes, it's -- just looking at it here, probably about CAD4.5 billion this year, CAD5 billion-ish this year, then CAD3 billion and CAD3 billion.

CAD3 billion 2014, CAD3 billion 2015?

Yes.

Good, thank you very much.

Thanks, Pierre.

The next question is from Paul Tan from Credit Suisse.

Hello, good morning. With regards to your Mexican assets, with the energy reforms in Mexico there's expectations that there would be a number of pipeline projects to be assigned by the government in the future. How do you see your position in Mexico and where would you like to be?

Yes, I can take that. It's Karl. I think our position in Mexico is excellent. I think we have a very good base position right now. We've got essentially three projects under construction, two in the very early stages and one in the middle of construction, and a good presence in Mexico City with all the key stake holders. So, if the reforms do pan out and some of the existing infrastructure is available, I think TransCanada will take a very serious look at it.

Thanks. And a follow-up for that one would be, would you guys be considering possible partnerships with local companies such as Innova to further increase your presence or market share in the country?

I guess I can start on that comment. We have been looking at several ways of executing these projects and new projects going forward in Mexico. And partnerships, local partnerships, I know some of our competitors even went and incorporated their own companies in Mexico, so there's various options that we can look at there if we do choose to bring in outside money into these projects. So, I wouldn't take anything off the table, but right now I think we're comfortable we can fully fund everything we have.

Our focus primarily is to get the projects secured from contractual perspective, move them through construction, remove those risks and then look at the most beneficial way to finance those for our shareholders, is bring in partners too early, obviously, would detract potentially from the shareholder value that we create. That said, in certain cases, partnerships will make sense. But I would say that our mode of operation has been secure the projects first, take away risks that we're good at mitigating, and then bring in partners and hopefully if you bring in partners, you can bring them in at a level that creates more shareholder value than to bring them in up front.

Thank you very much.

The next question is from Stephen Paget from FirstEnergy.

Thank you and good morning. My first question, what factors might potentially go into the rate case for Great Lakes being filed later this year? And what factors might create upside and downside to current EBITDA levels on Great Lakes?

Well, the Great Lakes rate case, November 1 is our filing date for that. And if we can't come to a settlement, which we're actually progressing, we think we're progressing quite well towards a settlement. So it's -- we're still in settlement negotiations and we still are talking about it. But really, the Great Lakes rate case will center around the, increasing the revenue from our shippers on our default rates. And, so, we've talked about several options on that rate case. We've talked about just increasing the rates, existing rates, and we've talked about poster stamping it.

But going in to that rate case is going to be simple. Our volumes have fallen so our rates have got to go up. This settlement, we are in FERC-mediated settlement discussions right now. And I think I'm quite optimistic that we might be able to do something there. But we do have to file by November 1 if we don't get any progress on that.

And what are the factors are driving toward progress, as you see it, or do you think you are likely to be done before November 1?

As it stands right now, I'm optimistic, but we're just a few months away from November 1 right now, and if we don't see some movement right now -- you know, it's always difficult when you have your volumes fall this much and you have to put that big of a rate increase on the remaining shippers. So, there are fairly serious conversations right now with our shippers on that. But, I think we've -- I'm quite optimistic we'll get there. But if we don't, we have the filing ready and we'll be ready to file on November 1.

Thank you, Karl. Don, just a quick follow-up, when you gave your 2013, '14, '15 CapEx split, that was ex-XL?

That's correct. And that's also excludes any significant NGTL spend related to Prince Rupert, as I think Russ mentioned in his remarks, probably a CAD1 billion to CAD1.5 billion from there may come at some point.

Thank you, Don. Those are my questions.

Thanks Stephen.

The next question is from David McColl from Morningstar.

Good morning. Thanks for taking my question. Just to move back to the Gulf Coast connector, just wondering if you can give any commentary on when the line fill might be starting there? We've kind of heard late October, early November.

You know, we're -- I think you heard Russ say we're north of 85% complete and moving quite quickly. So, I think that kind of October, November time period is probably a pretty good estimate.

All right, great. Thank you so much.

Yes.

The next question is from Lin Shen from HITE Hedge.

Okay. Thank you for taking my question. Just one question under TC PipeLine partners. If you plan to do another drop down for the MLP, what kind of asset do you think should be the ideal drop down asset for the next one?

I think what we've said in the past is that we want to put high quality assets into that portfolio. If you look at our US pipeline portfolio, I think they all kind of fit that bill, so we have recently dropped down pieces of Bison and GTN. Again, there's more of those assets left that we could sell into that portfolio, obviously Great Lakes and in our Iroquois Portland, are all good quality pipelines that we have put in. I think our focus on our MLP has been to ensure that we're putting high quality, long-life assets into the portfolio. And we do have a long list of things that would fit that.

Yes, I mean, more specifically, do you think it makes sense to drop down some accrued pipelines to make the MLP more diversified?

I don't think that our objective, as we said, is about diversifying the portfolio. Our drop-down theory of MLP are driven off financing needs and use of proceeds at the corporate TransCanada level. To the extent that down the road we see the opportunity to drop down mature oil pipeline assets, for example, into the TC PipeLines, there's no aversion to doing that. But at the current time, those assets are in what I would call the development phase and probably aren't suitable for an LP. Take Keystone XL for example, we're working through the permitting process, and then through a construction process. Those kinds of assets aren't conducive to a cash flowing vehicle like TC PipeLines LP. Down the road, we're building more options to be able to do that, but the driver really is ensuring those assets are in what I call the cash flowing phase of their life.

Okay. Thank you very much. I appreciate it.

The next question is from Carl Kirst from BMO Capital Markets.

Thanks. Appreciate the time. Just a couple quick follow-ups. One was really on ANR. And we knew it was going to be weak, but first quarter, it actually relatively hung in year-over-year, second quarter much more of a decline. And so, when we talk about it, for instance, continuing to see some weakness, basically at what point here do you see it basing out, if you will, on a year-over-year comparison?

Well, maybe I could talk a little bit about the weakness that we have seen in it. The actual transport spreads on ANR have actually hung in pretty good. It's not been a weakness of transport so to speak, of the spreads that are available. It's really been the storage now that we've seen come this last quarter. The storage spreads have been very, very weak. And their costs have increased.

Their costs, mostly, some costs on the actual integrity cost which we have to do, but most of the costs have increased to the transportation by other contracts they have on other pipelines. They use other pipelines to access their storage. So, they have -- so it has been a quarter where it was being dominated I think by the storage spreads. And storage spreads are like gas or commodity. They will get better and worse. So, I don't see anything structural there. ANR does have to have some work to do maybe on its costs and on these transportation by other arrangements that they have, and that's what we're pursuing right now, is work on those areas.

Okay. I appreciate the extra color. And then maybe, Don, just a quick follow-up and then appreciate all the budget clarity. If we were to throw XL into the mix, knock on wood here, is this something where you still think through, call it 2015, between pref LP drops, that that can be managed or are we looking at that point of perhaps evaluating a DRIP, for instance?

Well, we're -- we exhaust the hybrids, the prefs, first. And we'd look at the portfolio that could be dropped into the LP and weigh that against the cost of a DRIP. The DRIP, at some point if we're fortunate enough to get much of this portfolio moving forward into construction, a DRIP may make sense at some point because it lines up quite nicely with a spend profile on these multi-year construction projects. So, it would be on the list and certainly well ahead of a discrete equity issue by a long stretch.

Sure, absolutely All right, thanks, guys.

Thanks, Carl.

Thank you. There are no further questions from the financial community. We will now proceed to questions from the media.

(Operator Instructions)

We have a question from Kelly Cryderman from Globe and Mail.

Hello, there. I'm just wondering as you look towards the Energy East project, whether the derailment and explosion in Quebec earlier this month, whether you think that has changed anything in terms of the climate for transporting oil in that province as you look to new projects there?

Yes, I would say that obviously it's a tragic event. Tragic event for the people of Lac-Megantic and a tragic event for our country and for our industry. And we all have to step back and understand what occurred. We don't know that yet. And make sure that we implement whatever remediations are required in the transport of oil hydrocarbons.

What we know is that we need to continue to use oil to fuel our daily lives. We want to ensure the public that we can move it as safely as humanly possible. And that is the focus of our Company and what we've been focused on with all of our pipelines, including Energy East, is make sure that we are using the latest technology, the best equipment, and, again, from a response perspective, the best response capabilities available to respond to any kind of situation that we have along our pipelines.

And talking about switching to Keystone, you talked about, again, about increasing costs due to the delays. Do you have a better handle on what those increased costs are?

I think we have a pretty good handle on them. Obviously, that's a conversation between ourselves and our shippers. As you know, our shippers pick up a portion of those costs. But until we have a better understanding of when our actual construction is going to start, we have not put out a new estimate publicly. But certainly internally, we are working through that. Obviously, in terms of the kinds of things that influence that cost increase would be, you know, the cost of money. Obviously, we have almost CAD2 billion invested in this that we have the carrying costs on, the costs of maintaining pipe and equipment, and maintaining our contracts through this period.

We have thousands of tons of steel pipe sitting on the ground that needs to be maintained, and numerous pumps in warehouses, for example, that need to be maintained on an ongoing basis. So, all of those contribute to a cost increase. But, again, until we actually have a better understanding of when we can actually start construction, we're not going to issue a new number publicly.

And is there any change to the time line that, you mentioned again last week, late 2015, there's a mention just in this conference call pushing into 2016. Is that something you're preparing for at this time?

Well, I think what we're preparing for at this time is, as Alex said, is somewhere around 24 months, plus or minus a few months, depending on when we receive the permit. So, what we -- rather than me predicting where this is going to land, we're just putting out to the media and in the marketplace the facts, which are when we think we're going to get this permit, which we hope is somewhere between now and year end, and from that point it's going to take us some 24 months to construct, so that puts you in the time frames that we've been talking about.

Thank you.

The next question is from Jeff Lewis from Financial Post.

Hello. Couple follow-ups on Energy East. Are the contracts that you're looking to sign with shippers, are those binding shipment commitments? Or are you looking for financial commitments to get you through the engineering and regulatory phases of the project?

They will be binding shipping agreements. But as well, they are, as part of those shipping agreements, there will be some cost sharing of both development costs and development cost risk, if you will, and capital cost risk sharing once we're into the construction phase of the project.

Okay, and how has the ongoing uncertainty of the main line tolls and the disagreements with gas distributors in Ontario and Quebec impacted discussions with prospective oil shippers on that project?

The two haven't been related. In a lot of cases there the oil shippers are gas shippers. I think the noise that people have been hearing with respect to gas capacity versus oil capacity in the East has been raised by shippers that are being concerned about the decision about the main that the National Energy Board made on our main line, which confuses how we can service those customers and how we can add capital to the system in the future.

I think what we've tried to do is be as clear as possible in that confusion as we can, by stating that we will have capacity to meet the needs of all of our customers. What we need to do is, whether it be oil or gas, we need to understand what those needs are. Once we understand what those needs are, we can determine what kind of facilities we need to put in place and what kind of capital we need to spend. And that's an ongoing discussion that we have going on right now, with both customers.

We have a pretty good understanding of what our oil customers are going to need. But given the change in nature of the contracting structure on the gas pipeline side of things and our tolling, it's going to take us some time to understand exactly what the needs of our gas customers, both now and into the future, and what we said is we're committed to meeting those needs of those customers.

Okay, and do you anticipate -- I mean, this could be -- I mean, are you anticipating a protracted sort of regulatory process as you move forward with both the main line oil application and the revised tolling structure for that service?

No, I don't believe there will be protracted regulatory timeframe. I think it's in the Canadian national interest that we get through these regulatory processes in a timely and efficient manner. That's not to say that we want to short circuit any of the review process, be it environmental or commercial, but we need to set time frames on these processes that are reasonable. We've seen new legislation introduced that will allow for those kinds of accountabilities on time frames. My view is that by working with all parties in a cooperative way, we will come to resolution, as I said, to meet the needs of all parties, and there's no reason for a protracted regulatory process.

Okay, thanks.

The next question is from Rebecca Penty from Bloomberg News.

Thanks for taking my question. I know you've addressed this question before in the past, but I hope you can address it again as people in the States keep talking about this idea that Keystone XL could be for export of refined petroleum products from the States as more refining goes on in the Gulf Coast. I'm wondering if anyone can address that question, to the ultimate purpose for Keystone XL, and whether some diesel, for example, can be exported from the oil on the line?

I guess what I would start with is we're in the oil transportation business. So, I can tell you what I know, is that we have 20-year contracts with our shippers to move crude oil from Western Canada and from the Northwest United States to refineries in the Gulf Coast. What we know is that those refiners want to refine Canadian and US oil. I think as you've heard me say before, and I said in my opening remarks, the US Gulf Coast consumes some 7 million barrels a day of oil refined, 7 million barrels a day of oil, and imports 4 million of those. With the introduction of Keystone, what will happen is we will displace approximately 800,000 barrels a day of foreign crude oil, with crude oil from Canada and from the United States. So, there's none of this oil will actually be leaving.

Now, the question of whether or not some of those refined products get exported, that commerce occurs today and it will continue to occur post-Keystone. But Keystone wouldn't have any impact on the volumes that are, of refined products, that are either imported or exported. Today, there is some diesel exports and some refined product imports in order to balance the needs of the United States, both from a product slate perspective, as well from a supply/demand perspective. Through the recession, as demand has decreased in the United States, the United States has exported more product. But I would expect that as demand returns to more normal pre-recession levels, the United States will export less. But that flexibility is built into the refineries, has nothing to do with the Keystone XL pipeline. The amount of oil, heavy oil that's refined in the Gulf Coast will stay the same, whether you build Keystone or not. This link between somehow that Keystone is going to change the nature of US exports is patently false. First of all, there will be no crude oil exported from Keystone XL shippers through to export points. We don't have any port access along the pipeline.

With respect to refined products, I mean, that's a question better directed to the refineries, as to what their plans are going forward. But what I can tell you is, incrementally, Keystone won't change that equation. It just replaces the source of crude oil. And as I've said before, it's do you want heavy oil from Canada, and light oil from the Bakken region of the United States, or do you want to import oil from Venezuela and from other OPEC nations to feed those refineries?

Thanks very much.

Thanks, Rebecca.

Chester Dawson, Wall Street Journal.

Yes, I just have a question about the pipeline projects that would potentially connect the shale gas fields with the West Coast to Canada. Obviously, that's dependent on whether these projects of the LNG refining -- or processing terminals go through. But I'm just curious, are you at all considering integration? Are you talking with other companies? I know you're involved with both PETRONAS and Shell. Is there any talk about combining those? It seems -- I think there's four planned pipelines. That doesn't seem to make a lot of sense rationally. Can you tell us about that? Also, where does that stand with the two that you're involved in, in terms of actually mapping the routes out, getting cost estimates, all that good stuff?

Lots of questions in there. The -- I think I would start with the number of projects. There are a number of projects that are proposed to move natural gas to the West Coast for the purpose of conversion to LNG and then moving to export markets. I would agree, it's not likely that all can move forward. In our view, the probability of a project moving forward is dependent on at least four things. Primarily, is it supported by the marketplace? Does it have some agreement with the market to move that LNG to it? Those are usually long-term in nature. Secondly, does it have supply? The ability to continue to drill up the properties required to meet that long-term market need? Then, thirdly, does it have the tech -- does that group have the technical wherewithal in order to build a project? Fourthly, does it have the financial capability to actually pull it off?

These are large projects, when you look at the value chain from wellhead to the re-gas facilities, we're talking about value chains that look like -- for each project at CAD20 billion or CAD25 billion, CAD30 billion value chain. So, it does lend itself to the larger players. So as we look forward as to what projects have those four key elements, we would say that the PETRONAS and Shell projects are well advanced in that regard, having supply market, technical capability and financial wherewithal. There are others that are sort of seeking to do the same. To the extent I think that there are synergies amongst supply and market and the ability to find operating synergies and scale synergies on some of these facilities, I think that there is opening for continued discussion. That wouldn't be a role that we would have in bringing those parties together.

I think that really is both at the supply end and at the liquefaction and market end. To the extent that those parties want to come together and combine their volumes, we can modify the designs of our pipelines as they have been proposed today to accommodate more volumes and more receipt points. But the way we're structured today, there's one set of delivery points to Prince Rupert and one set of delivery points to Kitimat. We're participating in one project in each of those directions. To the extent that others want to join those projects, as I said, that would be a decision that would be made by those project proponents. I think as long as there's value added in those partnerships, I think that they remain open to those kinds of conversations the best that we've been told to date.

Okay, thanks. But are you doing any work on the ground today? Or are you just waiting for them to get the crews --

No, we're very active in our review process in both of those projects. We're well underway with filing our project descriptions to the environmental assessment agencies. We've engaged in stakeholder consultation. We're busy doing our engineering and route design. Where we would hope to be is in a position to receive regulatory approval of those projects by the time that these projects reach their sanctioning point. I would expect that we will spend, as TransCanada, over the next, say, 24 months on each of those projects, somewhere in the neighborhood of CAD200 million to CAD300 million preparing for those regulatory processes and obtaining those regulatory approvals. So we're active and moving actually as fast as we possibly can towards regulatory approval.

Thank you. Just to clarify, that's CAD200 million to CAD300 million each, right for the two?

Right.

Okay. Thank you very much.

Patrick Badgley, Platts.

Just had a couple of quick follow-ups on the main line. So when you're discussing the extra Bcf per day of firm capacity since the NEB decision, can you give an idea of the length of most of those firm contracts?

Yes. We have contracts between one year and three years that have come in the door.

Okay. Then is it possible still that TCPL considering legal appeal of the NEB decision?

I didn't quite catch that. Can you say that again?

I'm sorry. Is TCPL still considering legal appeal, or appealing in the courts of the March 27 decision?

I would say at this time, we are not. I think none of our costs have been denied at this point in time. As we've said before, our objective is to try to work within the framework of the regulatory decision as it's been laid out. I think as Karl pointed out in his remarks, we have another process in September that we're going to work through, where we've requested certain tariff changes, which will allow us to transform ourselves to be able to offer the services under this new regime. From that point, we'll continue to assess our legal and regulatory strategy going forward. But at the current time, there isn't a plan on the legal front. Our strategy is to continue to try to work within this framework as it's been outlined to us.

Okay. Thank you very much.

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

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

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