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TransCanada (NYSE:TRP)

Q3 2012 Earnings Call

October 30, 2012 11:00 am ET

Executives

David Moneta - Former Vice President of Investor Relations & Communications

Russell K. Girling - Chief Executive Officer, President and Director

Donald R. Marchand - Chief Financial Officer and Executive Vice President

Alexander J. Pourbaix - President of Energy and Oil Pipelines

Analysts

Linda Ezergailis - TD Securities Equity Research

Carl L. Kirst - BMO Capital Markets U.S.

Juan Plessis - Canaccord Genuity, Research Division

Matthew Akman - Scotiabank Global Banking and Markets, Research Division

Robert Kwan - RBC Capital Markets, LLC, Research Division

Steven I. Paget - FirstEnergy Capital Corp., Research Division

Andrew M. Kuske - Crédit Suisse AG, Research Division

Paul Lechem - CIBC World Markets Inc., Research Division

David McColl - Morningstar Inc., Research Division

Operator

Good day, ladies and gentlemen. Welcome to the TransCanada Corporation 2012 Third 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.

David Moneta

Thanks very much, and good morning, everyone. I'd like to welcome you to TransCanada's 2012 Third Quarter Conference Call. With me today are Russ Girling, President and Chief Executive Officer; Don Marchand, Executive Vice President and Chief Financial Officer; Alex Pourbaix, President of Energy and Oil Pipelines; Greg Lohnes, President, Natural Gas Pipelines; and Glenn Menuz, Vice President and Controller.

Russ and Don will begin today with some opening comments on our financial results and certain other company developments. Please note that a slide presentation will accompany their remarks. A copy of the presentation is available on our website at transcanada.com, 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. [Operator Instructions] 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 more detailed questions relating to some of our smaller operations or your detailed financial models, Terry. 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 United States Securities Exchange Commission.

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

With that, I'll now turn the call over to Russ.

Russell K. Girling

Thanks, David, and good morning, everyone, and thank you very much for joining us this morning. It's been a very busy year so far at TransCanada. And in this quarter, we continued to significantly advance our strategic priorities. And those priorities are: to maximize the long-term value of our existing businesses and ensure safe and efficient operations; to complete our capital projects safely and transition them to operations and revenue generation; to secure new, low risk growth opportunities; and four, our objective is to maintain our financial capacity and access to low-cost capital to fund our growth programs.

In the third quarter, our base businesses continued to perform well despite challenges of weak demand and soft gas and power prices in our commodity-exposed business. That performance highlights the benefit of the size and diversity of our asset portfolio, and that's something we have focused on here for a number of years.

Our safety performance remains in the top quartile, and our incident rates continue to remain well below industry averages.

So far this year, we brought on approximately $3 billion of new projects, most recently the $2.4 billion Bruce Units 1 and 2 restart, which will deliver secure cash flow for decades here to come. We remain on track to complete our approximately $10 billion of new projects between now and 2015. That includes our Gulf Coast Project and Keystone XL, the Tamazunchale extension and 9 solar projects in Ontario, as well as the ongoing expansions of our Alberta System.

Beyond 2015, since the beginning of this year, we have secured an additional $7 billion of new projects that are all underpinned by long-term contracts, including the $4 billion Coastal GasLink project, our Northern Courier and Grand Rapids oil projects and the 900 megawatt Napanee Generating Station. All of those projects are underpinned by long-term contracts and will generate stable earnings and cash flow growth for our shareholders.

So as I said, we have had -- we've been very busy so far this year, and I remain confident TransCanada is well positioned to grow earnings, cash flow and dividends as we complete that current capital program, secure new attractive opportunities and benefit from a recovery in demand and natural gas and power prices.

Taking a closer look at our third quarter results. Comparable earnings were $349 million or $0.50 per share. Comparable EBITDA was $1.1 billion and funds generated from operations were $866 million.

Today, the Board of Directors declared a quarterly dividend of $0.40 -- $0.44 per common share for the quarter ending December 31, 2012, equivalent to $1.76 per common share on an annualized basis.

Don Marchand, our CFO, will provide more details on our latest financial results in a couple minutes. But before that, I'd like to take a few moments to provide you some more detail on our capital projects.

Construction continues to move forward on multiple fronts in Texas, as we complete our Gulf Coast Project.

We're clearing brush, laying pipe, trenching and welding. Approximately 4,000 Americans are working to build this project. That doesn't include those who are manufacturing materials needed to build it or the hundreds of businesses along the route that are benefiting from construction: the hotels, the restaurants, repair shops, the grocery stores.

In recent weeks, approximately 40 out-of-state professional activists descended on Texas trying to keep these businesses from prospering and attempting to take away jobs from Americans who are building this pipeline.

TransCanada has consistently worked cooperatively with U.S. regulatory agencies and the courts to ensure that we have the legal right to proceed with the pipeline's construction. These bodies continue to confirm that we have the right and we have complied with all laws and regulations.

The benefits of this project are very clear. U.S. crude oil production has been growing significantly in states such as Oklahoma, Texas, North Dakota and Montana. And producers do not have access to enough pipeline capacity to move this production to the larger refining market at the U.S. Gulf Coast.

The Gulf Coast Project will address that constraint and allow refineries to access lower cost domestic production and avoid paying a premium to foreign oil producers.

We anticipate the pipeline being in service in late 2013. Included in the $2.3 billion cost is the $300 million for the 76 kilometer Houston lateral pipeline that will transport oil to the Houston refinery area as well.

On Keystone XL, where we continue to collaborate with the Nebraskans and the state's Department of Environmental Quality on developing an alternative route through the Sandhills. In September, we submitted a supplemental environmental report to the Nebraska Department of Environmental Quality that included preferred alternative routes for Keystone XL in the state.

The route was developed based on feedback from over 670 Nebraskans who took part in open houses this last spring. We also reviewed hundreds of comments and had direct conversations with the area landowners. Based on this feedback, we significantly modified our route. The NDEQ is expected to complete its work by the end of 2012. A preferred route would then be submitted to the governor of Nebraska and certain federal agencies for approval.

The over 3-year environmental review process for Keystone XL was completed in 2011 and was the most comprehensive process ever for cross-border pipeline.

Based on that work already completed, TransCanada expects its cross-border permit should proceed expeditiously by the Department of State and a decision made once a new route in Nebraska is determined. The state department continues to indicate it will make a decision on the Presidential Permit for Keystone XL in the first quarter of 2013. Based on a Q1 2013 approval, we expect the pipeline to become operational in late 2014 or early 2015.

Both Keystone XL and the Gulf Coast Project are vital in bringing U.S. and Canadian oil to market, supporting the goal to make energy -- make America energy self-sufficient.

Oil sands development is expected to increase by almost 3 million barrels per day over the next 15 years. In order to help ensure the infrastructure is in place to get that oil to market, we announced our Grand Rapids pipeline project yesterday. That $3 billion pipeline venture with Phoenix Energy Holdings will be operated by TransCanada and will transport crude oil and diluent between Alberta -- between Northern Alberta and Edmonton. In addition to the 50% equity commitment, Phoenix has also signed a long-term contract to ship crude and diluent on the pipeline system.

This combination of a diluent/crude oil system in Alberta is very unique and positions our company well to connect new supply from the emerging developments west of the Athabasca River.

We expect the pipeline to be operational in early 2017, with a capacity of up to 900,000 barrels per day of crude moving south and 330,000 barrels a day of diluent moving north. Grand Rapids will increase our presence in oil transportation in Northern Alberta, building on our announcement this past August of the Northern Courier Pipeline system. This $660 million project is a 90-kilometer pipeline that will transport bitumen and diluent between the Fort Hills Mine site and the Voyageur Upgrader, located north of Fort McMurray.

Northern Courier is fully subscribed under long-term contract to service the Fort Hills Mine, which is jointly owned by Suncor, Total and Teck Resources. We expect to file our initial regulatory application for the project in early 2013.

Moving a little bit further downstream to Hardisty. Detailed design work is underway for our $275 million oil terminal project that will provide new infrastructure for Western Canadian producers, as well as improved access to the Keystone Pipeline System. This past spring, we secured binding long-term contracts in excess of 500,000 barrels per day. And as a result of this strong commercial support, we expanded the proposal from 2 million barrels to 2.6 million barrels. We expect the Hardisty Terminal to be operational by late 2014.

Downstream from Alberta, exit capacity continues to be constrained. And as a result, Canadian crude oil is experiencing a significant discount to world prices. I explained earlier the advancements happening with both of our Gulf Coast Project and the Keystone XL project, which hopefully will alleviate some of that problem.

While both projects are vitally important to the development of the oil sands and to help the U.S. achieve energy security, access to broader markets will be required as production continues to grow in both Canada and the Northwest United States. In this regard, we are actively pursuing the conversion of a portion of our Canadian Mainline natural gas pipeline system to deliver Canadian and U.S. crude to Eastern Canada and American markets.

We've now determined this project is both technically and economically feasible. Discussions with potential shippers and other stakeholders are underway to determine if this is a project the market wants to see. And based on early indications, we believe that it is.

Eastern Canadian refineries import approximately 600,000 barrels per day, and much of that is higher priced imported oil from Saudi Arabia, Nigeria and Libya. We remain committed to meeting the needs of our natural gas customers, if this conversion project were to move forward. The initial -- the initiative could provide access to lower cost crude oil supplies for Eastern Canadian refiners, potentially lower gasoline prices and heating bills, support eastern refineries and the jobs they provide and allow Canadians to benefit from the oil produced in our own country.

Now moving over to gas. We're in early stages of the community consultation process for our $4 billion Coastal GasLink project. In June, our company was selected by Shell and its partners PetroChina, KOGAS, Mitsubishi to build, own and operate this large scale pipeline that will transport gas to the West Coast.

The project provides an opportunity for Canadian production to take advantage of growing export markets for liquefied natural gas in Asia.

The 700-kilometer pipeline will deliver gas from the Montney region near Dawson Creek, British Columbia to liquified natural gas export facilities that would be built in Kitimat.

This project has an initial capacity of more than 1.7 billion cubic feet per day, and we anticipate Coastal GasLink to be operational towards the end of the decade.

Currently, the main outlet for new gas production in Northeast BC is our NOVA natural gas delivery system. During the first 9 months of 2012, TransCanada continued to significantly expand this network to meet growing production.

So far this year, we have completed and placed into service 12 separate projects on the NOVA system at a total cost of approximately $680 million.

This included the completion of the $250 million Horn River Project in May 2012 that extended the Alberta System into the Horn River shale basin. The National Energy Board has approved $630 million of additional Alberta expansions, which is intended -- including the Leismer-Kettle River crossover, which is intended to provide increased capacity to growing demand in Northeast Alberta.

A further $340 million of projects are still awaiting NEB approval. TransCanada has firm commitments to transport 3.4 billion cubic feet a day from Western Canada and – or from Western Alberta and Northeast British Columbia by 2014.

The National Energy Board hearing that began on June 4 on TransCanada's application to change tolls and conditions of service for our Canadian Mainline continues. The Canadian Mainline remains a critical piece of North American natural gas infrastructure, connecting the gas fields of Western Canadian sedimentary basin to markets in Central and Eastern Canada and the United States.

Usage of the mainline has shifted away from long-haul base load shipments, but the pipeline continues to be used year-round with volumes peaking in cold winter months.

On a peak day in the winter, the mainline is needed to provide natural gas for heating homes, offices, schools across this whole country.

Final arguments will be heard and submissions presented in mid November with the National Energy Board decision, not expected before late in the first quarter of 2013.

Turning to power. We've had some very positive developments in the past couple of weeks. Firstly, Bruce Power where Unit 1, the nuclear reactor officially returned to service 8 days ago. Unit 2 is close to returning to service as well. Following the announcement on October 16, Unit 2 began sending power to the Ontario electric bid for the first time in 17 years. Both units will produce clean, reliable power for the province of Ontario until at least 2037.

100% of that power is sold under long-term contract with the Ontario Power Authority for the life of the facility. TransCanada's share of net capital cost of the refurbishment is still expected to be $2.4 billion. With the completion of the restart process, Bruce Power will be the world's largest nuclear facility, capable of generating more than 6,200 megawatts or about 25% of Ontario's power needs.

In addition, we announced that we have signed a memorandum of understanding with the Ontario Power Authority to develop, own and operate the 900 megawatt Napanee Generating Station. The facility will be located at the Ontario Power Generation's Lennox site in Eastern Ontario. We continue to work with the OPA to finalize the contract based on the terms of the MOU and we expect that work to be completed by mid December.

All of the power produced will be sold under a 20-year clean energy supply contract with the Ontario Power Authority.

The Lennox power plant will act as a replacement facility for the one that was planned in the community of Oakville.

So as I said, it's been a very busy year for us so far. We continue to advance our $10 billion projects we expect to complete by 2015.

And we’ve secured an additional $7 billion for the projects, which is very positive news that provides visibility of growth well beyond 2015.

We are very pleased that Unit 1 at Bruce Power has now become operational, and this is a very significant milestone for the company, something we’ve worked on for some time. And we expect Unit 2 to follow in suit in a matter of days here.

We also are pleased with our agreement with the Ontario government to build and operate the new large, gas-fired power plant in that province.

In Alberta, TransCanada is quickly becoming a leader in the development of crude oil transportation infrastructure with the announcements of Northern Courier and Grand Rapids oil projects, along with the Hardisty Terminal initiatives. This infrastructure supports the backbone of our oil transportation system, which is the base Keystone project, the Gulf Coast Project and Keystone XL.

Construction of the Gulf Coast initiative is moving forward on schedule and rerouting of Keystone XL in Nebraska is progressing well.

In British Columbia, we continue to capture the majority of the natural gas that has been developed in Northeast British Columbia, and we position ourselves to be a leader in moving that gas to growing Asian markets.

If these -- it's developments like these in all 3 of our core businesses of oil, gas and power that advance the company in its vision of being a leading infrastructure company in North America. And we expect these developments will lead to increased earnings, cash flow and dividends in the years to come.

We continue to pursue the right opportunities, where we feel we have competitive advantage and create long-term value for our shareholders.

I'd now like to turn the call over to Don, who will provide you with additional details on our third quarter 2012 financial results. Don.

Donald R. Marchand

Thanks, Russ, and good morning, everyone. I'd like to start today by touching on the following key messages. Despite headwinds on a couple of fronts, TransCanada produced steady third quarter operating results, underpinned by good performance from our diversified portfolio of high-quality energy infrastructure assets.

While a persistent weak natural gas and power pricing environment, a plant life extension out of Bruce Power and the absence of Sundance A did impact earnings in the period, Keystone and other new assets are contributing highly predictable earnings and cash flow. This will be supplemented by earnings in the $2.4 billion Bruce restart and $800 million of Alberta System projects that have or about to come into service in 2012.

As Russ mentioned, the company continues to advance several other long life, highly contracted infrastructure projects and secure new investment opportunities in each of its 3 core businesses. These projects will further diversify the company's portfolio and contribute to sustainable earnings, cash flow and dividend growth in the future.

And last, we remain -- we're very well positioned to fund our current capital program, as well as pursue other growth initiatives.

Now moving onto our consolidated results. Comparable earnings in the third quarter of $349 million or $0.50 per share decreased by $67 million or $0.09 per share compared to the same period in 2011.

Higher income from Keystone and recently commissioned assets, as well as earnings improvements in other parts of our business, were more than offset by lower contributions from Western Power, Bruce Power and a few of our natural gas pipelines.

On a per share basis, changes in comparable earnings for third quarter 2012 compared to 2011 are summarized as follows: earnings rose $0.05 or 8.5% from improvements in Keystone and other parts of our business, including Eastern Power, Gas Storage and the Alberta System. In energy, the Sundance A force majeure caused EPS to decline by about $0.05 and the Bruce Unit 4 life extension outage decreased EPS by an additional $0.04.

In natural gas pipelines, lower revenues on ANR and Great Lakes and the absence of incentive earnings on the Canadian Mainline reduced EPS by a combined $0.05.

As you know, we are progressing through many of these items that affected earnings in the quarter. Bruce will complete the Unit 4 life extension project by the end of this year; a mainline decision is expected late first quarter 2013; and Sundance A will return next fall.

I will now briefly review the results in some detail at the EBITDA level for each business segment, starting with natural gas pipelines.

The business segment generated comparable EBITDA of $660 million in third quarter 2012 compared to $698 million for the same period last year. The $38 million net decrease resulted primarily from lower contributions from the Canadian Mainline, ANR and Great Lakes. Partially offsetting that were earnings improvements from expansions on the Alberta System, as well as from Bison and Mexican pipelines.

With respect to the Canadian Mainline, the third quarter and year-to-date results, exclude incentive earnings generated in prior years under a 5-year settlement that expired on December 31, 2011, and reflect the last NEB approved return on equity of 8.08% on deemed common equity of 40%.

Our current expectation is that we will not receive a decision from the NEB on our 2012-2013 tolls application until late first quarter 2013. And therefore, any impact on earnings will not be recorded in fiscal 2012.

In our application, we requested an after-tax weighted average cost of capital of 7%, which equates to a rate of return of 12% on a deemed common equity component of 40%.

Our lower investment base also reduced earnings for the Canadian Mainline compared to the prior year. Our U.S. natural gas pipelines were affected in third quarter 2012 by lower storage and transportation revenues from ANR, as well as capacity sold at discounted rates on Great Lakes. We expect this will continue for the remainder of this year and until such time as there is a normalizing of natural gas inventory levels and weather patterns.

Turning to Oil Pipelines. Keystone generated $177 million of EBITDA in the third quarter of 2012 compared to $156 million for the same period last year. The $21 million improvement was the result of an increase in revenues related to higher final fixed tolls for the Wood River, Patoka section of the system, which came into effect in July 2012, as well as higher contracted volumes. Keystone remains on track to generate approximately $700 million of EBITDA in 2012. The short outage taken earlier this month is not expected to impact earnings.

In energy, comparable EBITDA was $267 million in the third quarter compared to $352 million for the same period last year. The $85 million year-over-year decrease was primarily the result of plant outages at Bruce Power and Sundance A, although earnings did improve in Eastern Power and Gas Storage.

Bruce A Unit 4 commenced a life extension outage on August 2, resulting in lower generation of volumes and revenues in the third quarter. The plant outage, expected to conclude in late fourth quarter 2012, will extend the operating life of Unit 4 to at least 2021 and align it with Unit 3. In June 2012, Bruce Power returned Unit 3 to service after completing the 7-month West Shift Plus life extension outage.

Western Power EBITDA was lower in third quarter 2012, primarily due to the Sundance A PPA force majeure we detailed in our last call. For the 3 months ended September 30, 2012, TransCanada recognized no earnings in Sundance A PPA compared to $48 million of EBITDA in third quarter 2011.

Going forward, until the Sundance A units are returned to service, TransCanada will not realize the generation or related revenues it would otherwise be entitled to under the PPA and move -- and will be relieved of any associated capacity payments. TransAlta has indicated it expects to return the units to service in the fall of 2013.

Now turning to the other income statement items on Slide 24. Comparable interest expense in the third quarter was $249 million compared to $242 million in the same period last year. The $7 million increase reflects incremental interest expense on new debt issues, partially offset by higher capitalized interest related to the Gulf Coast Project and Keystone XL.

In the third quarter, $74 million of interest was capitalized to assets under construction compared to $66 million for the same period in 2011. Comparable interest income and other of $22 million for third quarter 2012 improved $26 million from 2011 due to realized gains in 2012 compared to losses in 2011 on derivatives used to manage the company's net exposure to foreign exchange fluctuations on U.S. dollar income and on translation of foreign-denominated working capital balances.

In combination with U.S. dollar-denominated interest expense, this hedging program largely counterbalances the currency impact of translating U.S. dollar pipeline and energy income reported in the business segments. Comparable income taxes of $123 million in third quarter 2012 were $21 million lower, primarily due to lower pretax earnings.

Moving onto cash flow and investing activities on Slide 25. Cash flow remained solid. Funds generated from operations totaled $866 million in the third quarter and are on track to be approximately $3.5 billion in 2012.

Turning to investing activities. Capital expenditures were $694 million in the third quarter and $1.6 billion for the 9 months ended September 30, 2012, most of which related to the Keystone Pipeline System and the Alberta System.

Equity investments for the same 3- and 9-month periods were $144 million and $557 million, respectively. This represents the company's investment in equity accounted for joint ventures and mostly relates to our investment in Bruce Power, including the refurbishment and restart of Units 1 and 2, other plant maintenance activities related to the life extensions of Bruce A Units 3 and 4 and capitalized interest.

During 2012, we expect to invest approximately $3.9 billion in capital projects and equity investments, which includes expenditures on the Alberta System, the Gulf Coast Project, Keystone XL, Bruce Power, Tamazunchale extension and maintenance capital. This number includes approximately $300 million of capitalized interest.

Now looking at Slide 26. Our liquidity position and access to capital markets remain strong. At the end of the third quarter, our consolidated capital structure consisted of 43% common equity, 4% preferred shares, 2% junior subordinated notes and 51% debt net of cash. September 30, we had just under $500 million of cash on hand along with $4.3 billion of committed and undrawn revolving bank lines with our high-quality bank group.

Our 3 commercial paper programs, one in the U.S. and 2 in Canada, are well supported and provide flexible and very attractive sources of short-term funds.

And in August, we issued $1 billion of 10-year senior notes in the U.S. at an unprecedented rate of 2.5%.

We are well positioned to fund our current committed capital program through funds generated from operations, new term debt and subordinated capital as required in the form of preferred shares, hybrid securities and LP dropdowns. Going forward, we will be opportunistic in sourcing required capital, given the compelling low interest rate environment.

In closing, TransCanada's diverse, high-quality energy infrastructure assets performed well in the third quarter, and the majority of these assets continue to generate steady and predictable earnings and cash flow. Certain parts of our business were affected by low natural gas and power prices and high natural gas storage levels. We expect this trend to persist until we see a recovery in the macro natural gas environment and a normalization of weather patterns.

While these factors are expected to continue to impact volumes on certain of our U.S. pipelines, as well as power prices, our new assets are performing well, and we look forward to additional contributions from Bruce Power, moving to an 8-unit operating site, with the refurbishment and restart of Units 1 and 2, as well as having Unit 4 return from a 5-month life extension outage; Alberta System's expansion projects coming online; completion of the final phase of Cartier Wind; a decision on the mainline 2012-2013 tolls application; adding Canadian solar assets to the portfolio; and in the fall of 2013, the return to service of Sundance A.

We also continue to advance other initiatives in our $18 billion commercially secured capital program, including the construction of a U.S. $2.3 billion Gulf Coast Project and rerouting a portion of the Keystone XL pipeline in Nebraska.

I would like to reemphasize that since the beginning of this year, we have added $7-plus billion of new projects that are commercially secured and will provide highly stable and predictable earnings and cash flow in the years ahead. They include Coastal GasLink, the Napanee power generating station, the Grand Rapids and Northern Courier oil pipeline projects, the Keystone Hardisty Terminal and the Tamazunchale extension. We are well positioned to fund our capital program, along with the additional growth we continue to secure.

Finally, we expect to continue to generate significant cash flow that can be used to invest in new accretive growth opportunities, grow the dividend and further enhance our financial strength and flexibility in the years ahead.

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

David Moneta

Thanks, Don. Just a reminder, before I turn it over to the conference coordinator. We will take questions from the financial community first, followed by questions from the media.

With that, I'll turn it over to the conference coordinator.

Question-and-Answer Session

Operator

[Operator Instructions] The first question is from Linda Ezergailis with TD Securities.

Linda Ezergailis - TD Securities Equity Research

I'm wondering if you could provide us with an outlook on where you see your regional crude oil pipeline business going. Will your focus over the next year be mostly related to fully contracting the Grand Rapids system? Or may we see some other initiatives over that time period? And do you expect your activity to accelerate once you get a Presidential Permit for Keystone XL?

Alexander J. Pourbaix

Linda, it's Alex. Obviously, a big focus of the BD effort in the crude oil business over the next year is going to be to continue to add contracted volumes to our Grand Rapids project. But I think as I've said earlier, our oil business isn't just focused on Keystone and it's not just focused in Alberta on Grand Rapids. We’re, at this time, working on a number of initiatives to connect supply and demand, and we see going forward on all of those initiatives. We're not going to focus on any one to the exclusion of other opportunities.

Russell K. Girling

I think in terms of our Alberta plant, Linda, it's Russ, is then you can kind of get a picture of what we're trying to do is connect, get a supply right through the market. So if you just take a look at the map, and you could see where we have holes in the map. And you'll -- obviously, the Grand Rapids will get us down to Edmonton. But obviously, we want to get from Edmonton to Heartland and Edmonton to Hardisty to make sure that our customers downstream, our Keystone customers, and potentially Eastern Mainline customers can connect themselves right from wellhead to the refinery.

Linda Ezergailis - TD Securities Equity Research

That's great. And just in terms of market access. Can you provide us any -- and I realize it's still very early days, but in terms of an East Coast liquids pipeline initiative and converting the mainline, can you give us a sense of updated potential timelines? And I think last quarter, you gave us some indication of potential volumes, if that's still valid. And what sort of end markets are you still targeting on that front?

Russell K. Girling

So Linda, what I would tell you, I think, a lot of the things that we said in the last call would remain valid. We're looking -- depending on demand, we're looking at a pipeline anywhere from 500,000 barrels a day to 1 million barrels a day. Because of the advantages of having 80% of the pipe in the ground already, we do not -- we can very competitively go forward with a proposal that doesn't require the upper end of that volume. We're competitive at much lower volumes. In terms of timing, we really spent the last 6 months focused on the 2 issues of technical feasibility and competitiveness. We very much satisfied ourselves that the project is technically feasible to convert gas assets to oil service and we've satisfied ourselves that at the toll, that we can offer a service that is a very competitive offering for our potential shippers. So now, we're commencing on our stakeholder efforts in the communities we're going to be in and we continue to advance our commercial deal with potential shippers. I find these things always take a little longer than everybody hopes but we're looking at something early in the new year. I would imagine we'll be in a position to consider whether to make a commercial commitment.

Linda Ezergailis - TD Securities Equity Research

That's great. And just a follow-up question with respect to your assets in the New England region in particular. I realize it's still very early but have you heard anything from the field in terms of the status of how your various power plants and other assets are doing?

Russell K. Girling

Yes, I spoke to our team early this morning and from what we've heard, it looks like all of the -- all of our power assets in that region have come through okay. Ravenswood, the storm surge peaked below our protective barrier. And so far, it's looking like the hydro assets in New England, the rainfall amounts have not been as significant as I think it originally feared. So everything so far looks like it's coming through okay.

Operator

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

Carl L. Kirst - BMO Capital Markets U.S.

Just a couple of questions. Maybe first on the impact to the main line conversion. And just, Alex, as you guys have satisfied yourselves from a competitive standpoint, can you help us out with any more refined range of cost estimates? And within that, does that envision the mainline perhaps extending as far west as being built to Edmonton, thus providing, let's say, for instance, PetroChina a full path?

Alexander J. Pourbaix

Well, as Russ said, we are very active with our BD initiatives in Alberta and we obviously see a need to connect the Heartland area to the Hardisty area. I mean, when we think about the Eastern Mainline, we're talking Hardisty East but we obviously want to provide a full path to our potential shippers on that project. So we are working very hard inside Alberta on those opportunities. In terms of cost for Eastern Mainline, that very much depends on the ultimate size of the project and the throughput of the project. But in the range, you'd be looking at a project in the range of $5 billion give or take, perhaps a little more.

Carl L. Kirst - BMO Capital Markets U.S.

Okay. And then separately, just a question on Ravenswood and I appreciate the color with the storm, thankfully. A question -- there was an indication with the FERC decision back from September that, I guess, the New York ISO is going to do a retest. Is there any timing of when that might take place?

Alexander J. Pourbaix

Yes, I think -- and I can't remember the exact date, Carl, but I -- my recollection is it's around the middle of November that the New York ISO committed to redo their testing protocol.

Carl L. Kirst - BMO Capital Markets U.S.

Okay. So really not too far in the distant future as far as knowing whether or not we might get a higher bid on those capacity prices.

Alexander J. Pourbaix

Exactly.

Operator

The next question is from Juan Plessis.

Juan Plessis - Canaccord Genuity, Research Division

With respect to Grand Rapids, I understand that Phoenix energy will be the anchor shipper, provides for a base-level return. Can you talk a little bit about the potential upside on the returns that you could get if the remaining portion of that line is contracted?

Alexander J. Pourbaix

Sure, Juan. We have targeted a range of returns for this project, kind of in line with what we've been looking at for other infrastructure projects in the oil area or the power area, kind of in the range of 8% to 10%. And obviously, towards the upper end of that range if we're successful in adding incremental volumes on top of the Phoenix volumes.

Juan Plessis - Canaccord Genuity, Research Division

Okay. That was 8% to 10% unlevered after tax IRR.

Alexander J. Pourbaix

Correct.

Juan Plessis - Canaccord Genuity, Research Division

Okay, great. And this one is probably for Don. You had $74 million of capitalized interest in the quarter. At what rate are you capitalizing your interest at?

Donald R. Marchand

It's in the high 5s.

Juan Plessis - Canaccord Genuity, Research Division

High 5s?

Donald R. Marchand

5%, 5.7%, 5.8%.

Operator

The next question is from Matthew Akman with Scotia Bank.

Matthew Akman - Scotiabank Global Banking and Markets, Research Division

Alex, I'm just wondering if you could describe a little bit physically what it takes to convert the mainline to oil.

Alexander J. Pourbaix

Sure. Right off the bat, as I said, depending on where you see the end of that pipeline, we probably have about 80% of the pipe in the ground right now. That pipe has obviously been maintained under NEB oversight. And so we have a very good understanding of the -- any issues with that pipe, the integrity of that pipe. What we would have to do right off the bat, because oil is an incompressible fluid, we have to switch from compression plants to pumping plants. So we'd have to build new pumping stations down the entire length of the pipe. And then on top of that, there would be just -- judging from our experience with the conversion of the original gas line for base Keystone, there'd be a fair amount of work done just to confirm the integrity of the pipeline. And that really -- and then whatever length of pipe we're adding in Alberta and at the end of the pipeline.

Matthew Akman - Scotiabank Global Banking and Markets, Research Division

$5 billion is a lot of cost for pumps. I mean, are you thinking about replacing large sections of the pipeline or adding to it?

Alexander J. Pourbaix

No, but there really are a lot of pump stations and just from our prior experience on base Keystone, the integrity work was quite a significant effort and I'm not talking so much about replacing, just doing the actual work. And then we also, obviously, have to buy the gas pipeline out of gas service and that will obviously add to that cost.

Russell K. Girling

That's a -- Matthew, that number is still a pretty preliminary number, I'd say, depending upon design and whatnot but those are the major components of it.

Matthew Akman - Scotiabank Global Banking and Markets, Research Division

Sure. And my last question on this is you've determined that it's, I guess, economically feasible so you've done some sort of cost-benefit type analysis but I'm wondering whether you've included in that the substantial benefits that could accrue to gas pipeline shippers in having a more efficient gas pipeline system and a lower toll?

Russell K. Girling

I'd say the benefits that we've talked about in terms of determining whether it's feasible, what we're talking about there is can we come up with a toll that's competitive to markets; can we get marine access and potentially, access to other markets at a competitive rate. And that, we determined, is something that's pretty sound. With respect to the gas pipeline itself, there's obvious benefits to the gas pipeline system potentially, doing that. Obviously, it will impact our ability to flow gas. And we'll have to make sure that we make whatever adjustments in the system are required to meet the demands and needs of our customers. But I would say that our current thinking is there will be an overall benefit to gas customers as well but we haven't incorporated that into our – into that. When we talk about feasibility, it's primarily feasibility with respect to the crude oil market. We're just in the process right now of analyzing the impacts it will have on our gas business and preliminary indications would tell us that it will have a positive impact for our gas shippers as well.

Operator

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

Robert Kwan - RBC Capital Markets, LLC, Research Division

Just on Ravenswood. I'm just wondering if you've had a little bit more time here, what you expect the capacity price list might be if only Astoria II is excluded. And then if you've also run the calculation assuming Astoria II and Bayonne are excluded.

Russell K. Girling

Robert, I have been probably becoming sort of increasingly of the view that our perspective on forward-capacity markets is pretty sensitive commercial information for us. So I'm probably going to back away from giving you a direct response on that one. There's a lot of commentators out there, though, who have views on that and I'm sure they'd be happy to help you out.

Robert Kwan - RBC Capital Markets, LLC, Research Division

Okay. I guess, just maybe this is for Don. You've given the CapEx for 2012. I'm just wondering if you have updated numbers for 2013 and then 2014. And then just when it comes to funding, you still seem very confident in the kind of the non-equity funding sources. I'm just wondering whether there's also any contemplation, though, as you head forward here of turning the DRP from treasury, though, back on?

Donald R. Marchand

So CapEx for '13, '14, we're looking at them together is in the 9.5 to 10 range right now. Now I know about 4.5% of that is Keystone XL and the associated turnover of the Marketlink oil projects. We would expect cash flow net of dividends to be around $5 billion to cover a healthy chunk of that. And as I noted earlier, we've got Bruce 1 and 2 Gulf Coast Project coming on in 2014 and the return of Sundance A. We’ve got Solar and Tamaz coming on in that timeline as well. So we see requirements of $4.5 billion to $5 billion new capital range, plus maturities are about $1.8 billion in that timeframe. The needs are skewed to 2013 right now with the start of XL and the completion of Gulf Coast. But we'll monitor the capital program because it can shift around a bit. So we will be opportunistic going forward. In terms of subordinated capital, we're looking to the usual sources that I noted, prep shares, hybrids and LP drop downs. Probably 30% to 40% of the funding program would be comprised of that. We don't see any need for common equity, including turning the DRP on. So we believe we can complete this program and then stay on-side with credit metrics with that mix of capital. Again, the criteria on how we assess each of those various alternatives for subordinated will be driven by price equity credit relative -- size of the need and desired currency going forward. So bottom line, no need for common equity but, yes, lots of optionality there in terms of again hybrids, LP drop downs and press.

Robert Kwan - RBC Capital Markets, LLC, Research Division

That's great. And just on that $9.5 billion to $10 billion between the 2 years, is there, at least, a preliminary kind of break up between the 2 years, recognizing it can shift a little bit?

Donald R. Marchand

Probably about -- let me just have a look here. Probably about 2/3 in 2013 right now based on XL.

Russell K. Girling

Highly dependent upon XL. That's a big sort of swing item in our capital program, as you can imagine, Robert.

Operator

The next question is from Steven Paget with First Energy Capital.

Steven I. Paget - FirstEnergy Capital Corp., Research Division

At the end of June, TransCanada had 7,000 gigawatt hours contracted in 2013 on Western Power. And that number has declined to 5,700 gigawatt hours. So did you roll off first -- sell the other contracts? And does this reflect your belief that spot power prices are going to improve?

Russell K. Girling

No, there's a more simple answer for that, Stephen. In -- at Q2, the volumes sold forward still included the impact of some of those pass-through contracts that we have related to the Sundance A PPA. And those also allowed us to pass through some of the risks and benefits of the PPA onto power customers. And so the plants in force majeure, no volumes will be delivered, no revenues or costs will be accrued and so we've just corrected for that in Q3. Though those volumes were not removed in Q2, they're now out of there in Q3.

Steven I. Paget - FirstEnergy Capital Corp., Research Division

My other question is on U.S. generation. Your other purchases, 3,600 gigawatt hours in the U.S. power supply, I think, that's a record or close to it. I'm just wondering what impelled you to vastly increase your purchases.

Russell K. Girling

Just the continuing growth of our retail, commercial and industrial business, Stephen. We've expanded that business over -- it's been a profitable business for us and successful business and we're just seeing customer volumes continue to increase.

Operator

The next question is from Andrew Kuske with Crédit Suisse.

Andrew M. Kuske - Crédit Suisse AG, Research Division

I guess, my question is for Russ and also for Don and it just relates to the capital program. If you look out over the next, let's just say, 10 years. You secured $18 billion of projects. Obviously, your cash flows are going to accelerate as things like XL and a whole host of your other projects come online. How do you think about your CapEx program and really the book of business you need and really the magnitude of that book over the next 10 years? How big does that $18 billion have to be?

Russell K. Girling

I guess is what we'd like to do is be in a position where we are -- we have solid high quality capital projects that kind of match our free cash flow and our internally-generated debt capacity. That's about where we would want to be. So as you pointed out, as we bring on more projects, more cash flow, that number increases over time. But I would say that it's a number that sort of moves today from $4 billion, $5 billion up to $6 billion or $7 billion in those outer years. But that's our intent is to try to fill in those outer years with high-quality projects that match our cash flow and our debt capacity. I don’t know Don, if you want to add to that.

Donald R. Marchand

Yes. The key is quality here. We're not trying to force a number at the end of the day. And being cognizant that some of these projects are quite lumpy, too. But it's a live-within-your-means philosophy. I mean, it's substantive means as you get out into that post-2015, post-Keystone timeframe where you do have that amount of capital to deploy.

Russell K. Girling

Like as always, I mean, we'll look at what has the best value for our shareholders. And as we've said before, I mean, if we get out there, we're not afraid to return capital to shareholders, if that's what the best use of our capital is, if we don't have high-quality opportunities. From what we can see today, there's going to be ample opportunities for us to spend our free cash flow and beyond if -- in terms of opportunities. As Don said, our discipline is to try to stay within our means and we'll continue to employ that discipline. But if it turned out that the environment in front of us doesn't have that degree of opportunities, obviously, shareholder values are driving -- is our driving force and we'd look to spend our cash flow in a way that drives the best shareholder value.

Andrew M. Kuske - Crédit Suisse AG, Research Division

And then if I may, just related to that question. Do you feel you have too much concentration in certain market areas? In the Ontario power market, you're obviously one of the largest players in the market, XL, PG, Alberta. You're very large in the pipeline space and you’re both growing in growing in crude and clearly in natural gas. Then markets like B.C., you'd be underrepresented; players in areas like the Marcellus really nothing at this stage. So there's opportunities but do you have too much concentration in a couple of areas?

Russell K. Girling

I think we look at it on a project-by-project basis as opposed to an area of concentration. And what we look for is the quality of the opportunity and the quality of the counter parties. And in all these situations, I think you can see that we’ve got very, very high quality counter parties, with long-term contracts in all of our projects. I think, as I pointed out in my opening remarks, I mean, we'll focus on places where we have competitive advantage and we can put in place deals that are synergistic with the rest of our operation and provides sort of long-term stability, long-term security. There are certain locations where we don't have those competitive advantages today. So it’s very difficult for us to replicate the quality of projects in those regions that we have been in the regions where we do have competitive advantage. So we focus on what we know and what we're good at in the regions where we have missed all the competitive advantage. There are regions, as you pointed out, in what we call our whitespaces on our map that we continue to look at and if there are opportunities for us to enter those regions, we will definitely do that.

But right now, as we sort of look in our backyard, in our core regions in our core businesses, there just appears to be an abundance of opportunity and I suspect, there's a lot of others looking to get into those regions as well. One that we haven't talked much about today is Mexico, for example. We see ample opportunity to continue to grow in that fairway as well as they build out their gas infrastructure and continue to grow their economy as well. So we have found places outside of those couple that you mentioned, where we can use our advantages to get us what we think is a better mix of risk and return in terms of investment.

Operator

The next question is from Paul Lechem with CIBC.

Paul Lechem - CIBC World Markets Inc., Research Division

Just a couple of questions. Going back to the Mainline conversion again and I was wondering, I know it's preliminary still but your thoughts on whether the main -- the gas to oil conversion would be focused on carrying light versus heavy crudes. And if -- depending on which one is skewed more to one or the other, which target markets would you end up focusing on? You talked about East Coast refineries. Are you thinking about off -- getting it off continent to potentially further afield?

Russell K. Girling

Sure. I think the obvious first market for an Eastern Mainline conversion would be the Eastern Canadian refineries and the U.S. eastern seaboard refineries. And those refineries, about 600,000, 700,000 barrels a day of refining capacity in Canada, about 1 million barrels a day on the eastern seaboard. And those refineries are overwhelmingly configured to run light sweet barrels right now. So for that market, which is obviously a core market for the Eastern Mainline conversion, we would see that as either synthetic crudes out of Alberta or light sweet out of Bakken likely move into those markets. And then longer-term, there's obviously the potential to take heavy crudes offshore or even potentially to see some capital investment in those eastern refineries to allow them to run the heavier Alberta crudes.

Paul Lechem - CIBC World Markets Inc., Research Division

And just one final question. Just maybe a big picture thinking about pipelines crossing the border to the U.S. Is your current thinking maybe that the Keystone XL will be the last major oil pipeline crossing the border? Do you think it'll be possible to build any further pipelines going south then?

Russell K. Girling

I kind of think of it probably the other way that -- I think there's been an incredible debate on the merits of cross-border pipelines going on over the last couple of years and certainly from what we see in the U.S., Americans are -- when Americans are polled, they are very largely in favor of increased oil from Canada. They see the job benefits, they see the economic benefits and I think more than anything, they see the energy security benefits. And I kind of think that the opponents of this -- of these pipelines for a while, they had a pretty good run. They were able to scare a lot of people with a lot of allegations that I think have been proven to be false. And I think we're seeing that Americans are realizing that in fact long term this is probably the best place in the world to get their oil. So I'd like to think we kind of reached, if you will, a low watermark and hopefully, we'll see some turnaround as time goes on.

Operator

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

Carl L. Kirst - BMO Capital Markets U.S.

Actually, just a follow-up. Russ, you'd actually touched on it with respect to the future in Mexico and I know sort of more near-term, there were perhaps 4 RFPs we were waiting to hear from. I think we heard 2 last week. I didn't know if there were still 2 more additional out there and kind of what you guys thought the potential for investment in Mexico might be over the next 12, 24 months.

Russell K. Girling

Well, as you know, there is 4 out there and there is actually several other sort of future opportunities that are on the horizon as well. And we continue to participate in those and I think our prospects are very good, given our current position, our understanding of the market and our ability to construct in some of those very difficult terrain areas position us well to be a growing investor in that marketplace. So I'd say stay tuned, that we're competing hard and hopefully things will turn out well for our shareholders.

Carl L. Kirst - BMO Capital Markets U.S.

And just with respect to one question on Napanee, the latest OPA station. I didn't catch a timeframe on that. I know contracts won't be finalized here until December but is there a projected in-service of when that will be required?

Alexander J. Pourbaix

Yes, we're -- I'm trying to think of the exact -- I think it's around middle of 2017 is the time period we're looking at.

Russell K. Girling

Yes. It was, Carl, early to mid 2017.

Operator

The next question is from David McColl with Morningstar.

David McColl - Morningstar Inc., Research Division

Just kind of jumping back to the Grand Rapids pipeline and you mentioned Phoenix kind of underpinning that line. I'm just trying to reconcile the 900,000 barrel a day oil line and how it might come online? Could we see half of the capacity start up around 2017 and associated spending and then a second line come into play. I'm just wondering if you could elaborate on that a little bit for me.

Russell K. Girling

Obviously, we've underpinned that line with significant volumes from Phoenix. I would expect their volumes will ramp up over time as we would also expect volumes of other shippers that we’d potentially be adding to the pipeline but -- and we're also -- there are a lot of producers in that area that have indicated they have interest and need for transportation. So we're going to be working really hard over the next couple of years to accommodate their requests.

Operator

The next question is from Linda Ezergailis with TD Securities.

Linda Ezergailis - TD Securities Equity Research

This is just a follow up to some questions that Paul had with respect to the Eastern pipeline. So as the kind of obvious -- I don't want to call it low-hanging fruit, but the initial opportunity is to service the eastern refinery with light crude. Would it be fair to assume that your $5 billion ballpark cost estimate would be just a pipeline to Montréal and no further?

Russell K. Girling

I'd like to give a ballpark, it's in that range. You'd add a couple of hundred, few hundred million more to get to Québec City, for example.

Linda Ezergailis - TD Securities Equity Research

Okay. And then a few billion to Saint John?

Donald R. Marchand

I think it's early days in terms of that -- sort of that’s the initial scope and you've got a picture and you add the costs on those other sort of new build parts of the system are very preliminary at this point to actually -- we'd probably be uncomfortable to kind of put any specifics on it.

Operator

The next question is from Steven Paget with FirstEnergy Capital.

Steven I. Paget - FirstEnergy Capital Corp., Research Division

Just given Russell's opening remarks, I just want to confirm that construction on the Gulf Coast Project is proceeding as planned.

Russell K. Girling

Yes. We're -- I don't have any statistics to offer up today, Alex. But we're clearing it right away, we're welding and we're backfilling. So the project is sort of up, it's moving up to sort of full swing construction as we speak.

Alexander J. Pourbaix

No, I'd have nothing else to add. As Russ mentioned, we obviously have had a relatively small number of very active protesters, but they have been unable to materially impact our productivity.

Steven I. Paget - FirstEnergy Capital Corp., Research Division

With the completion of your core back wind power construction next month, would you look at monetizing these high-free cash flow assets?

Russell K. Girling

I think we look at all opportunities in our portfolio to arrive at the best value for our shareholders and that's not to indicate that there's anything imminent with respect to that particular asset but obviously we look at our portfolio on a continuous basis and if there's value to our shareholders in doing that, it's something we'd look at.

Steven I. Paget - FirstEnergy Capital Corp., Research Division

And one final question. On Alaska, are the nonbinding expressions of interest sufficient in total to consider proceeding at least very preliminarily with construction?

Russell K. Girling

In Alaska?

Steven I. Paget - FirstEnergy Capital Corp., Research Division

In Alaska.

Alexander J. Pourbaix

I would say that the issues in Alaska remain -- the indications of interest in shipping are very positive and we're pleased with that. But I think as we've said before, the key issue is -- the key producer’s negotiation with the state with respect to the fiscal terms of that production for the next few decades and if they can come to conclusion on the sharing of the value of this resource, I believe it's highly likely that the project would move forward but that's the key determinant in moving forward as opposed to shipping interest. Obviously, the big 3 producers ExxonMobil, BP and ConocoPhillips have the gas. They're producing it every day. It's being reinjected. That gas can be redirected to market if they can make the project economic and key to making that project economic is understanding what the royalty terms are going to be. So that conversation, we understand, is ongoing between the state and the producers and we continue to hope for some breakthrough there.

Operator

Questions will now be taken from the members of the media. [Operator Instructions] The first question is from Nathan VanderKlippe from The Globe and Mail.

Nathan VanderKlippe

Just quickly on the sort of the longer-term potential for internal shipments off your mainline conversion. What markets might make sense to access from that part of the continent and would you have to build all the way through to Saint John or could you potentially access these markets from A, Montréal or Québec City?

Russell K. Girling

Well, I think right now, I guess, I would say is that's going to be dependent upon shipper interest. But obviously, as Alex pointed out, the East Coast of Canada, I mean, the East Coast of Canada is an obvious market, East Coast of the United States is an obvious market. Certainly, Europe and some of the Asia market that can be accessed economically from those kind of shipping points. But again, those would be dependent upon whether or not those customers, if you will, have an interest in buying Canadian crude.

Nathan VanderKlippe

And as far as allocation from marine access, I mean, do you have sufficient marine access from a Montréal or Québec City or would you have to go further just to access some of those larger markets?

Russell K. Girling

As I've said, we're -- that would be sort of all confidential in terms of conversations with potential shippers on what kind of vessel size they’d be likely using, what kind of market they want to access and where they want term link capacity. So those are some of the details of negotiations that -- and discussions that need to go on between ourselves and those shippers right now. So I'd say we're again too early to share details like that.

Operator

The next question is from Rebecca Penty from Bloomberg News.

Rebecca Penty

I just have a question about the Grand Rapids project with Phoenix. How does TransCanada plan to fund that? Is there any kind of bond issuance that could come? Is it going to be funded through cash? If you could speak to that, that would be great.

Donald R. Marchand

It's Don Marchand here. It would be funded on the balance sheet with the mix of all of our other projects. I did just walk through the finance plan a few minutes ago, which indicated how we intend to fund things for 2013, '14. Grand Rapids is a -- the bulk of the spend is in '15 and '16. So I would expect much of that funding would come from internal cash flow as we do have a lot of projects coming on stream between now and then.

Operator

The next question is from Lauren Krugel with Canadian Press.

Lauren Krugel

I just had a couple of more questions about the aftermath of Sandy on your U.S. power assets. Just wondering whether Ravenswood and your other generating assets in the U.S. Northeast continued to produce energy throughout the storm? Or whether they were shut down preemptively to prevent damage?

Alexander J. Pourbaix

In fact, the vast majority of our assets in New York and New England continued to operate through the storm. Ravenswood, all of our large units were operating. The hydro dams were generating power and even our Kibby wind farm in Maine actually produced more power than expected because it was pretty windy. So all of the assets were -- majority -- all of the main assets continued to produce through the height of the storm.

Lauren Krugel

Okay. And that was Alex Pourbaix speaking, I assume?

Alexander J. Pourbaix

Yes.

Operator

There are no further questions registered on the telephone lines. I'd like to turn the meeting back over to Mr. Moneta.

David Moneta

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

Operator

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

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