TC Energy Corp (TRP) 2012 Q3 法說會逐字稿

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.

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 of 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. In order to provide everyone with an equal opportunity to participate, we ask you limit yourself to two questions. If you have additional questions, please re-enter the queue. Also, we ask that you focus your questions on our industry, our corporate strategy, recent developments, and key elements of our financial performance. If you have 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 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.

Thanks, David. Good morning, everyone. 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. 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 fourth, 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, and that performance highlights the benefits 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've brought on approximately CAD3 billion of new projects, most recently the CAD2.4 billion Bruce Units 1 and 2 re-start, which will deliver secure cash flow for decades here to come.

We remain on track to complete our approximately CAD10 billion of new projects between now and 2015. That includes our Gulf Coast project and Keystone XL, the Tamazunchale extension, and nine 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 CAD7 billion of new projects that are all underpinned by long-term contracts, including the CAD4 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'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 CAD349 million or CAD0.50 per share. Comparable EBITDA was CAD1.1 billion, and funds generated from operations were CAD866 million. Today, the Board of Directors declared a quarterly dividend of CAD0.44 per common share for the quarter ending December 31, 2012, equivalent to CAD1.76 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 the materials needed to build it, or the hundreds of businesses along the route that are benefiting from construction, the hotels, the restaurants, the hair 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 take away jobs from Americans who are building this pipeline. TransCanada has consistently worked cooperatively with US 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. US 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 large refining market at the US 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 million 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 three-year environmental process for Keystone XL was completed in 2011, and was the most comprehensive process ever for a 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 US 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 CAD3 billion pipeline venture with Phoenix Energy Holdings will be operated by TransCanada, and will transport crude oil and diluent between albert -- 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 CAD660 million project is a 90-kilometer pipeline that will transfer bitumen and diluent between the Fort Hills Mine site and the Voyageur Upgrader located north of Fort McMurray. Northern Courier is fully subscribed under a 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 CAD275 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 US 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 US 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 the early stages of the community consultation process for our CAD4 billion Coastal GasLink project. In June, our Company was selected by Shell and its partners PetroChina, Kogas, and 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 would deliver gas from the Montney region near Dawson Creek, British Columbia, to liquefied natural gas export facilities would be built in Kitamat. 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 nine months of 2012, TransCanada continued to significantly expand this network to meet growing production. So far this year, we've completed and placed into service 12 separate projects on the NOVA system at a total cost of approximately CAD680 million. This included the completion of the CAD250 million Horn River project in May 2012 that extended the Alberta System into the Horn River shale basin. The National Energy Board has approved CAD630 million of additional Alberta expansions, which is intended -- including the Leimer-Kettle River crossover, which is intended to provide increased capacity to growing demand in northeast Alberta. A further CAD340 million of projects are still awaiting NEB approval. TransCanada has firm commitments to transport 3.4 billion cubic feet a day from western Canada -- 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 and 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 weeks. Firstly, Bruce Power, where Unit 1, the nuclear reactor officially returned to service eight 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 Grid 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 a long-term contract with the Ontario Power Authority for the life of the facility. TransCanada's share of net capital costs of the refurbishment is still expected to be CAD2.4 billion. With the completion of the re-start 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 we had 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 a 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 CAD10 billion projects we expect to complete by 2015, and we've secured an additional CAD7 billion worth of 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 our 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've positioned ourselves to be a leader in moving that gas to growing Asian markets.

It's these -- developments like these in all three 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 can 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?

Thanks, Russ, and good morning, everyone. I'd like to started to 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 infrastructure assets. While a persistent weak natural gas and power pricing environment, a planned life extension outage at 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 from the CAD2.4 billion Bruce re-start, and CAD800 million of Alberta System projects that have or are about to come into service in 2012. As Russ mentioned, the Company continues to advance several other long-life, highly-contracted energy infrastructure projects, and secure new investment opportunities in each of its three 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 are very well positioned to fund our current capital program, as well as pursue other growth initiatives.

Now moving on to our consolidated results. Comparable earnings in the third quarter of CAD349 million or CAD0.50 per share decreased by CAD67 million or CAD0.09 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 CAD0.05 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 CAD0.05, and the Bruce Unit 4 life extension outage decreased EPS by an additional CAD0.04. 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 CAD0.05. 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 CAD660 million in the third quarter 2012, compared to CAD698 million for the same period last year. The CAD38 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 five-year settlement that expired on December 31, 2011, and reflect the last NEB-approved return on equity of 8.08% on a 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 US 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 CAD177 million of EBITDA in the third quarter of 2012, compared to CAD156 million for the same period last year. The CAD21 million improvement was the result of an increase in revenues related to higher final fixed tolls for the Wood River and 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 CAD700 million of EBITDA in 2012. The short outage taken earlier this month is not expected to impact earnings.

In energy, comparable EBITDA was CAD267 million in the third quarter, compared to CAD352 million for the same period last year. The CAD85 million year-over-year decrease was primarily the result of planned outages at Bruce Power and Sundance A, although earnings did improve in Eastern Power and Gas Storage. Bruce A Unit 4 commenced the life extension outage on August 2, resulting in lower generation volumes and revenues in the third quarter. The planned 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 seven-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 three months ended September 30, 2012, TransCanada recognized no earnings from the Sundance A PPA, compared to CAD48 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 that it would otherwise be entitled to under the PPA, 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 CAD249 million, compared to CAD242 million in the same period last year. The CAD7 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, CAD74 million of interest was capitalized to assets under construction, compared to CAD66 million for the same period in 2011. Comparable interest income and other of CAD22 million for third quarter 2012 improved CAD26 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 US dollar income, and on translation of foreign-denominated working capital balances. 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 of CAD123 million in the third quarter 2012 were CAD21 million lower, primarily due to lower pre-tax earnings. Moving on to cash flow and investing activities on slide 25, cash flow remains solid. Funds generated from operations totaled CAD866 million in the third quarter, and are on track to be approximately CAD3.5 billion in 2012.

Turning to investing activities, capital expenditures were CAD694 million in the third quarter and $1.6 billion for the nine months ended September 30, 2012, most of which relate to the Keystone pipeline system and the Alberta System. Equity investments for the same three- and nine-month periods were CAD144 million and CAD557 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 re-start of Units 1 & 2, other planned maintenance activities related to the life extensions of Bruce A, Units 3 and 4, and capitalized interest. During 2012, we expect to invest approximately CAD3.9 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 CAD300 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. At September 30, we had just under CAD500 million of cash on hand, along with CAD4.3 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. And in August, we issued $1 billion of 10-year senior notes in the US 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 drop-downs. 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 US 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 re-start of Units 1 and 2, as well as having Unit 4 return from a five-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 CAD18 billion commercially secured capital program, including the construction of the USCAD2.3 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 CAD7 billion-plus 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'll now turn the call back over to David for the Q&A.

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

Thank you.

(Operator Instructions)

The first question is from Linda Ezergailis with TD Securities.

Thank you. 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 might you 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?

Linda, it's Alex. Obviously, a big focus of 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 as I think 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.

I think in terms of our Alberta plan, Linda, it's Russ, is I think you can kind of get a picture of what we're trying to do, is connect -- get a supply right through to market, so 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, 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.

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 to 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?

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 six months focused on the two 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 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.

That's great, thank you. And just a follow-up question, with respect to your assets and 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?

Yes, I spoke to our team early this morning, and from what we've heard, it looks line 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 originally feared, so everything so far looks like it's coming through okay.

That's great, thank you.

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

Thanks, good morning, everybody. Just a couple of questions, maybe first on the -- back to the Mainline 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, say for instance, PetroChina a full path?

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. 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 CAD5 billion, give or take, perhaps a little more.

Okay, no, I appreciate that. And then separately just a question on Ravenswood, and appreciate the color with the storm, thankfully. A question, there was an indication with the FERC decision back from September that I guess no -- I guess the New York ISO was going to do a retest. Is there any timing of when that might take place?

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

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?

Exactly.

Great. All right, I'll jump back in queue, thank you.

Thanks.

Thank you. The next question is from Juan Plessis.

Thanks very much. 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?

Sure, Juan. We have targeted a range of returns for this project. It -- kind of in line with what we've been looking at for other infrastructure projects and the oil area or the power area and, you know, 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.

Okay, that was 8% to 10% unlevered after-tax IRR?

Correct.

Okay great, thanks. And this one is probably for Don. You had CAD74 million of capitalized interest in the quarter; at what rate are you capitalizing your interest at?

It's in the 5%s.

High 5%s?

From -- 5.7%, 5.8%.

Okay, thank you.

Thank you. The next question is from Matthew Akman with Scotiabank.

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

Sure. Right off the bat, as I said, you know, 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 would 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 would 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.

CAD5 billion is a lot of cost for pumps. I mean, are you thinking about replacing large sections of the pipeline or adding to it?

No, but there really are a lot of pump stations, and there -- 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.

Matthew, that number is still a pretty preliminary number, depending upon design and whatnot, but those are the major components of it.

Oh, sure, I appreciate that. 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?

I'd say that those numbers -- 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've determined, is something that's pretty sound. With respect to the gas pipeline itself, there's obvious benefits to the gas pipeline system potentially of 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 that are required to meet the demands and needs of our customers. But I would say that our current thinking is that there will be an overall benefit to gas customers as well, but we haven't Incorporated that into our -- 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.

Okay, thanks. Those are my questions.

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

Great, thank you. Just on Ravenswood, just wondering if you've had -- with a bit more time here, what you expect the capacity price lift might be if only Astoria II is excluded and if you've also run the calculation assuming Astoria II is excluded, and then if you've also run the calculation assuming Astoria II and Bayonne excluded?

You know, 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.

Okay.

There's a lot of commentators out there, though, who have views on that, and I'm sure they would be happy to help you.

Okay, I guess just -- maybe this is for Don. You've given the CapEx for 2012. 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 drip from Treasury, though, back on?

So CapEx for 13/14, we're looking at them together, is in the CAD9.5 billion to CAD10 billion range right now. Note about CAD4.5 billion of that is Keystone XL, and the associated terminal and market link oil projects. We would expect cash flow net of dividends to be around CAD5 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, the return of Sundance A, we've got solar and Tamaz coming on in that timeline as well. So we see requirements in the CAD4.5 billion to CAD5 billion new capital range, plus maturities are about CAD1.8 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 will -- 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 as I noted, pref 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 drip on, so we believe we can complete this program and then stay onside with CreditMetrics 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 prefs.

That's great. And just on that CAD9.5 billion to CAD10 billion between the two years, is there at least some preliminary kind of break-out between the two years, recognizing it can shift a little bit?

Probably about -- let me just have a look here. Probably about two-thirds in 2013 right now, based on XL.

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

Sure. Okay, that's great. Thank you.

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

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

No, there's a more simple answer for that, Steven. At Q2, the volumes sold forward still included the impact of some of those pass-through contracts that we had related to the Sundance A PPA, and those allowed us to pass through some of the risks and benefits of the PPA on to 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. Those volumes were not removed in Q2, they are now out of there in Q3.

Well, thank you for that. My other question is on US generation. Your other purchases of 3,600 gigawatt hours in the US power supply, I think that's a record or close to it? I'm just wondering what compelled you to vastly increase your purchases?

Just the continuing growth of our retail commercial and industrial business, Steven. It -- 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.

Thank you. Those are my questions.

Thanks, Steven.

Thank you. The next question is from Andrew Kuske with Credit Suisse.

Good morning. I guess my question's for Russ, and also for Don, and it just relates to your capital program. If you look out over the next, let's just say 10 years, you secured CAD18 billion of projects, Obviously, your cash flows are going to accelerate as things like XL and a whole host of your other projects come on line. 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 CAD18 billion have to be?

I guess is -- what we would 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 are internally-generated debt capacity; that's about where we would want to be. So as you point out, as you 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 CAD4 billion or CAD5 billion up to CAD6 billion or CAD7 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, do you want to add to that?

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. 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.

We'll look at it as always, I mean we will look at what has the best value for our shareholders. And as we've said before, 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 -- and 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 -- those are a driving force, and we'd look to spend our cash flow in a way that drives the best shareholder value.

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

I think we look at it on a project-by-project basis, as opposed to an area of concentration. What we look for is the quality of opportunity and quality of the counterparties, and in all of these situations I think you can see that we're -- we've got very, very high-quality counterparties with long-term contracts in all of our projects. I think, as I pointed out in my opening remarks, 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 provide sort of long-term stability, long-term security. There's 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 -- in the regions where we do have competitive advantage. So we focus on what we know and what we're good at, in regions where we have a solid competitive advantage.

There are regions, as you pointed out, what we call our white spaces 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. A I suspect there's a lot of others looking to get into those regions as well. One 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.

Okay, that's very helpful, thank you.

Thank you. The next question is from Paul Lechem with CIBC.

Thank you, good morning. 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 -- of gas to oil conversion would be focused on carrying light versus heavy crudes if so -- 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?

Sure, I think the obvious first market for an eastern Mainline conversion would be the eastern Canadian refineries and the US eastern seaboard refineries, and those refineries -- you know, about 600,000 or 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 moving to 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.

Thank you, and just one final question. Just maybe big picture, thinking about pipelines crossing the border to the US. Is your current thinking maybe that the Keystone XL will be the last major oil pipeline crossing the border? Do you think it will be possible to build any further pipelines going southbound?

You know, I kind of think of it probably the other way, that I think there has 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 US, 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 awhile 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 water mark, and hopefully we'll see some turnaround as time goes on.

Thank you.

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

Thanks. 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 four RFPs we were waiting to hear from. I think we heard two last week. I didn't know if there were still two more additional out there, and kind of what you guys thought the potential for investment in Mexico might be over the next 12 to 24 months?

Well, you know, there was four out there, and there's actually several other 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. We're competing hard, and hopefully things will turn out well for our shareholders.

Thanks, 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?

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

Yes, it was, Carl, early to mid-2017.

Great. Thanks so much, guys.

Okay.

Thank you. The next question is from David McColl with Morningstar.

Yes, good morning, guys. 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? Thank you.

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.

Okay, thank you.

Thank you. The next question is from Linda Ezergailis with TD Securities.

Thank you, this is just a follow-up to some questions that Paul had with respect to the eastern pipeline. So is kind of the obvious -- I don't want to call it low-hanging fruit, but the initial opportunity is to service the astern refineries with light crude. Would it be fair to assume that your CAD5 billion ballpark cost estimate would be just pipeline to Montreal and no further?

I'd like -- giving ballpark, you know, it's in that range. You'd add a couple hundred, a few hundred million more to get to Quebec City, for example.

Okay, and then a few billion to St. John?

(Laughing) It's early days, Linda, in terms of -- sort of that's the initial scope, I think 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 in time, so we probably would be uncomfortable to put any specifics on it.

Okay, thank you.

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

Thank you. Just given Russ's opening remarks, I just want to confirm that construction on the Gulf Coast project is proceeding as planned?

Yes, we're -- I don't have any statistics to offer up today -- Alex, but we are clearing them 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.

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.

Thank you for that. With the completion of your Quebec wind power construction next month, would you look at monetizing these high free cash flow assets?

I think we look at all opportunities in our portfolio to derive the best value for our shareholders, and that's not to indicate 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.

Well, thank you. And one final question, as we're past the hour mark. On Alaska, are the non-binding expressions of interest sufficient in total to consider proceeding, at least very preliminarily, with construction?

In Alaska?

In Alaska.

I would say the issues in Alaska remain -- the indications of interest in shipping are very positive, and we're pleased with that, but as we've said before the key issue is the key producers' negotiation with the state with respect to the fiscal terms of that production for the next few decades. And if they can come to a 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 three producers, Exxon-Mobil, BP, and ConocoPhillips have the gas. They're producing it every day, it's being reinjected, so that gas can be redirected to a 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.

Okay, thank you for all that.

Thank you. Questions will now be taken from members of the media.

(Operator Instructions)

The first question is from Nathan VanderKlippe with The Globe and Mail.

Thanks for taking my question. Just quickly on the -- sort of the longer-term potential for international 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 St. John, or could you potentially access those markets from a Montreal or a Quebec City?

Well, I think right now I guess I would say that's going to be dependent on shipper interest, but obviously as Alex pointed out the East Coast of Canada is an obvious market, the East Coast of the United States is an obvious market. And certainly Europe, some of the Asian Markets 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.

And as far as a location for marine access, do you have sufficient marine access from a Montreal or a Quebec City, or would you have to go further to access some of those larger markets?

As I said we're -- that would be sort of all confidential, in terms of conversations with potential shippers on what kind of vessel size they would like to be using, what kind of markets they want to access, and where they want terminal link capacity. So those are some of the details of negotiations 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.

Thank you very much.

Thank you. The next question is from Rebecca Penty with Bloomberg News.

Hi there, thanks for taking my question. 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 could you speak to that, that would be great.

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 to '14. Grand Rapids is a -- I think 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.

Thank you.

Thank you. The next question is from Lauren Krugel with Canadian Press.

Oh, hi, good morning. I just had a couple more questions about the aftermath of Sandy on your US power assets. Just wondering whether Ravenswood and your other generating assets in the US northeast continued to produce energy throughout the storm, or whether they were shut down preemptively to prevent damage?

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 we expected, because it was pretty windy. So no, all of the assets were -- a majority, all of the main assets continued to produce through the height of the storm.

And that was Alex Pourbaix speaking, I assume?

Yes.

Okay, great, thank you.

Okay.

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

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