TC Energy Corp (TRP) 2006 Q4 法說會逐字稿

Good day, ladies and gentlemen. Welcome to the TransCanada Corporation 2006 fourth quarter results conference call. I would now like to turn the meeting over to Mr. David Moneta, Vice President of Investor Relations and Communications. Please go ahead, Mr. Moneta.

Thank you, very much. I'd like to take the opportunity to welcome everybody today. We're pleased to provide the investment community, the media and other interested parties with an opportunity to discuss our 2006 fourth quarter financial results and other general issues concerning TransCanada.

With me today are, Harold Kvisle, President and Chief Executive Offer, Greg Lohnes, Executive Vice President and Chief Financial Officer, Russ Girling, President of Pipelines, Alex Pourbaix, President of Energy, and Glenn Menuz, Vice President and Controller. Hal and Greg will begin today with some opening comments on our financial results and other general issues pertaining to TransCanada. Please note, that a slide presentation will accompany their remarks. A copy of the presentation is available on our website at TransCanada.com. It can be found in the investor section under the heading conference calls and presentations.

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

Before Hal begins, I'd like to remind you that certain information in this presentation is forward-looking and is subject to important risks and uncertainties. The results or events predicted in this information may differ from actual results or events, factors which could cause actual events to differ materially from current expectations include, among other things, the availability of TransCanada to successfully implement its strategic initiatives and whether such strategic initiatives will yield the expected benefits, the availability and price of energy commodities, regulatory decisions, competitive factors in the pipeline and power industries and the prevailing economic conditions in North America. For additional information on these and other factors, see the reports filed by TransCanada and with the Canadian Securities Regulators and with the United States Securities and Exchange Commission. TransCanada disclaims any intention or obligation to update or revise any forward-looking statements whether as a result of new information, future events, or otherwise except as required but law.

Finally, I'd also like to point out, that during this presentation we'll refer to measures such as funds generated from operations and net income from continuing operations excluding significant items. These measures do not have any standardized meaning in GAAP and are therefore considered to be non-GAAP measures. As a result, these measures may not be comparable to similar measures presented by other entities. Additional information on non-GAAP measures is available in the Company's fourth quarter news release.

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

Thank you, David. Good afternoon, everyone, and thank you, for joining us today. 2006 was another very good year for TransCanada. We continue to add to our significant portfolio of pipeline and energy assets and to see the results of our efforts reflected in increased earnings, cash flow and value for our shareholders. By continuing along the strategic growth path we embarked on 7 years ago, we have made significant progress towards our objective of being the leading North American energy infrastructure company.

As outlined in today's news release, TransCanada's net income for the year ended December 31st, 2006 was $1.079 billion or $2.21 per share. This includes net income from discontinued operations of 28 million or $0.06 per share. Our 2006 and 2005 reported results include a number of significant gains and other nonrecurring items and they are highlighted in today's news release. Excluding these items, net earnings for the year ended December 31st, 2006 increased 10% to 925 million or $1.90 per share from 839 million or $1.73 per share in 2005. Funds generated from operations grew to approximately $2.4 billion in 2006. That's an increase of 22% over 2005. We have grown annual funds generated from operations by more than $650 million over the past 24 months.

This strong underlying cash flow has enabled us to make significant capital investments in our pipeline and energy businesses. In 2006, we invested approximately $2 billion in growth initiatives.

Our performance in 2006 builds on our track record of delivering steady growth in earnings and cash flow. Over the past 7 years, TransCanada has grown net earnings excluding gains and nonrecurring items at a compound average annual growth rate of 8.4% from $1.08 in 1999 to $1.90 in 2006. Over that period, we have grown funds generated from operations at a compound average annual growth rate of 12.5% from $1 billion in 1999 to $2.4 billion in 2006. And over that period, we have invested close to $11 billion in our core businesses.

Our financial position as represented by our balance sheet has also strengthened significantly. At year end, our balance sheet capitalization included 37% common equity. This represents a significant increase from 1999 when common equity stood at 26%. Our strong 2006 financial performance has enabled our Board of Directors to increase the quarterly dividend on the Company's common shares by 6% to $0.34 per share. On an analyzed basis, this equates to $1.36 per share. This is the 7th year in a row the Board has raised the dividend.

We are also pleased to announce today that under our dividend reinvestment plan, shareholders who reinvest their dividends in additional common shares of TransCanada will receive those shares from treasury at a 2% discount to prevailing market prices. These changes will provide a direct benefit to our shareholders and help us maintain a strong financial position during a period of significant capital investment.

Finally, our track record of success has resulted in significant returns for our shareholders. In 2006,TransCanada generated a total shareholder return of approximately 15%. We have also delivered total shareholder returns in excess of 20% per annum over 3 and 5 year periods with an average annual total shareholder return of 12.5% over the past 10 years. Looking forward, we will continue to focus our energy on long-term growth and value creation. We are committed to fundamental value creation in all of our capital investment programs.

Today TransCanada is a leading continental energy infrastructure company. By virtue of our quality portfolio of assets, we are well positioned to capture opportunities for further growth. On closing of the ANR acquisition, TransCanada's network of wholly owned pipelines will extend more than 59,000 kilometers. That's 36,500 miles, taping into virtually all major gas supply basins in North America. TransCanada will become one of the continent's largest providers of gas storage and related services with approximately 360 billion cubic feet of storage capacity. We also have interests in more than 7,700 megawatts of generating capacity fueled by nuclear natural gas hydro wind and coal. In the future, we will continue to seek opportunities to invest in these businesses and pursue complementary initiatives in oil pipelines and liquefied natural gas.

In 2006, we continued to add to our portfolio of quality assets by successfully completing several projects, which will contribute to earnings and cash flow in 2007. We brought 660 megawatts of power generation into commercial production through completion of the Becancour cogeneration plant and the first phase of the Cartier Wind power project in Quebec. We also began transporting natural gas on the Tamazunchale pipeline in Mexico. We are exploring additional opportunities in the Mexican energy market as the government advances its initiative to promote the use of natural gas for regional development, particularly as a fuel for much needed power generation. In addition, we commence natural gas storage operations at our new Edson facility. TransCanada now has interest in approximately 130 billion cubic feet at natural gas storage capacity in Alberta, approximately 1/3 of the capacity in the province of Alberta.

Notably, in December we announced the acquisition of the ANR Pipeline Company and the ANR Storage Company, which we refer to together as ANR and an additional interest in Great Lakes Gas Transmission limited partnership for $3.4 billion U.S. including $457 million U.S. of assumed debt. In a separate transaction, TC Pipelines LP will acquire the remaining 46.45% interest in Great Lakes for $962 million U.S. which includes 212 million U.S. of assumed debt. TransCanada is the general partner of TC Pipelines LP and holds 13.4% of the outstanding units.

The ANR and Great Lakes acquisition represents a unique opportunity to acquire regulative pipeline and storage assets that are a strong fit with our existing North American footprint. ANR is one of the largest interstate natural gas pipeline systems in the United States providing transportation, storage, and various capacity related services to a variety of customers in both the United States and Canada. In January, we initiated the regulatory process with the U.S. Federal Trade Commission for review of the ANR transaction under the Hart-Scott-Rodino Act. We have also established a team to ensure a smooth transition once regulatory approvals are received.

We expect to fund the ANR acquisition in a manner that is consistent with the Company's current balance sheet capitalization. This is aligned with our commitment to maintain a strong financial position and transCanada pipeline's limited A-credit rating. We expect the ANR transaction to be accretive to earnings and cash flow in the first full year of ownership.

The announcement of the ANR acquisition was a strong finish to a year that saw us identify, evaluate, and advance a number of high-quality greenfield growth opportunities. In our pipeline's business, our growth initiatives include ongoing expansions of our Canadian wholly owned systems to meet customer needs as well as major new projects such as the Keystone Oil Pipeline.

In December, we filed a second application with the National Energy Board for authorization to construct new facilities for the Keystone Pipeline in Canada. We anticipate receiving the NEB's decision on our first application, which seeks approval to transfer a section of the Canadian main line to Keystone and convert that line from natural gas to crude oil transmission during the first quarter of 2007. We also continued to progress through the regulatory process in the United States. Since the beginning of the project, we have worked hard to establish strong relationships with stake holders along the proposed pipeline route and we will continue to our stake holder consultations along with engineering and pre-construction activities over the course of this year. We anticipate receiving all necessary approvals by the end of the year and the project is on schedule for a late 2009 in-service date.

Today we also announced the start of a binding open season for an expansion and extension of Keystone. The purpose of the open season is to obtain binding commitments to support the expansion of Keystone from a nominal capacity of 435,000 barrels per day to 590,000 barrels per day as well as the construction of a 468 kilometer extension of the U.S. portion of the pipeline from the Nebraska/Kansas border to the refining and terminal hub near Cushing Oklahoma. This U.S. $700 million expansion and extension project is targeted to be in service in the fourth quarter of 2010.

Over the longer term, we also remain a key player in projects to bring northern natural gas to market. On the MacKenzie gas project, imperial and the project [coventurers] expect to file an updated cost estimate and schedule with regulators later in the first quarter of 2007. The project continues to move slowly through the regulatory process.

In December, TransCanada, along with a number of other interested parties, met with newly elected Governor Palin to share our views on an Alaska highway pipeline project. We are encouraged by the Governor's early actions on this file and look forward to reviewing forthcoming legislation. It has been and continues to be our objective to play a constructive role within Alaska to enable the Alaska project to move forward on terms that Alaskans find satisfactory.

On the Canadian portion of that project, we look forward to working with the state of Alaska and the Alaska producers to develop commercial arrangements for the movement of Alaska gas, through the Yukon and through northeast B.C., taking advantage of the Northern Pipeline Act and our existing Yukon Right of Way. I would note that TransCanada's large Western Canada Gas Transmission System offers both market flexibility and significant cost savings for the movement of Alaska gas from northeast B.C. to North American markets. We are working with the state of Alaska and the Alaska producers to make those economic benefits available to the Alaska pipeline project.

Turning now to our energy sector, we remain focussed on pursuing quality opportunities in power, natural gas storage, and liquefied natural gas. The Bruce Power restart and refurbishment continues to progress as expected. To date, the partners have invested approximately $1.1 billion in the project that will ultimately see another 1500 megawatts of generating capacity returned to the Ontario Power grid. Work also continues on the second phase of the Cartier Wind project in Quebec. And we have initiated the regulatory process on the third phase of that project. We also continue to evaluate a number of potential wind projects in Quebec in response to Hydro-Quebec Distributions requests for proposals for 2,000 megawatts of wind power.

We are also proceeding with construction on the Portlands Energy Centre with our partner Ontario Power Generation and we are working to complete the environmental [perimiting] process for the Halton Hills generating station. We anticipate beginning construction on Halton Hills later this year. The Portlands Energy Centre located in downtown Toronto is expected to begin delivering electricity to the Ontario grid by the summer of 2008 with full operations beginning in 2009. Halton Hills, located outside Toronto, is expected to be operating in the second quarter of 2010. These two plants will add significant incremental generating capacity in the Ontario power market and along with our Becancour Plant will be fueled by environmentally friendly natural gas.

In the LNG business, we continue to advance our Cacouna and Broadwater projects with both projects marking significant regulatory milestones in the fourth quarter of 2006. In December, the report to the Federal Provincial Panel, studying the environmental aspects of the proposed Cacouna LNG terminal, concluded that the project is not likely to cause significant adverse environmental effects if the mitigation measures and recommendations made by the panel are implemented. The Broadwater project in New York received similar environmental encouragement in the draft environmental impact statement released by the federal environment, sorry, the Federal Energy Regulatory Commission in December.

The FERC concluded that additional natural gas supply is needed and that the Broadwater project with the adoption of the FERC and U.S. Coast Guard recommendations would result in fewer environmental impacts than any alternative considered. Public hearings were held on the draft environmental impact statement in January. And we anticipate that FERC will issue its final environmental impact statement sometime during 2007. Both LNG projects require additional regulatory approvals before construction can proceed. And we will continue to work with our partners to advance through the regulatory process during 2007.

To summarize, our accomplishments in 2006 give us confidence that TransCanada is well on its way to becoming North America's leading energy infrastructure company. Over the next 5 years, we expect to capitalize on increased demand for natural gas and power by continuing to invest in our gas transmission, gas storage, and power generation businesses. We will also continue to pursue new and complementary opportunities in oil pipelines and liquefied natural gas.

The Greenfield projects I have highlighted will see us invest more than $4 billion over the next 3 years alone, and with the ANR acquisition our total capital program over that 3-year period is expected to exceed $8 billion. The cycle of opportunity generation business development and project implementation is essential to the long-term future of our company. We will continue to analyze, develop, and expand our portfolio of attractive capital projects to ensure that TransCanada is well-positioned to create significant value for many years to come.

Finally, I've spoken at length today about our physical assets and financial strengths. Of equal if not greater significance are our people. The transCanada team is made up of some of the most skilled, knowledgeable, and expert people in the energy infrastructure industry, and it is their efforts that underpin our continued success.

In January, TransCanada was recognized as one of the global 100 most sustainable corporations in the world, in large part due to our demonstrative commitment to running our businesses safely, reliably and responsibly and with respect for all of our stake holders. Our commitment to operational excellence, financial performance, and long-term value creation will enable us to continue to deliver superior returns to our shareholders in the future.

I'd now like to turn the call over to our Chief Financial Officer, Greg Lohnes. Greg?

Thanks, Hal. Good afternoon, everyone. As Hal mentioned, earlier today we released our fourth quarter results. Net income from continuing operations, or net earnings, for the fourth quarter were $269 million or $0.55 per share compared to $350 million or $0.72 per share for the same period last year. Fourth quarter 2006 net earnings included $12 million of income tax refunds and related interests. The fourth quarter 2005 net earnings included $115 million of after tax gains related to the sale of the Company's [interest] in Paiton Energy. Excluding these items, net earnings of $0.53 per share for the fourth quarter 2006 is an increase of $0.05 per share or approximately 10% when compared to fourth quarter 2005. For the year ended December 31, 2006, TransCanada's net earnings were 1.051 billion or $2.15 per share compared to $1.209 billion or $2.49 per share for 2005.

In addition to the items previously noted, net earnings for 2006 and 2005 included a number of significant nonrecurring gains. They are highlighted on this slide. And additional information on each is included in the fourth quarter news release. Excluding these items, net earnings for the year ended December 31, 2006 were $925 million or $1.90 per share, an increase of $86 million or $0.17 per share. This represents a 10% increase when compared to 2005. The quarter-over-quarter and year-over-year increases were primarily due to significantly higher net earnings from the Energy segment, partially offset by lower net earnings from the Pipeline segment.

I will briefly review the fourth quarter results for each of our segments, beginning with Pipelines. The Pipelines business generated net earnings of $126 million during the fourth quarter compared to $155 million for the same period in 2005. A $22 million quarter-over-quarter decline from wholly owned pipelines is primarily attributal to the lower contributions from the Canadian main line, Alberta system, and GTN. The lower contribution from the Canadian main line and the Alberta system was due to a combination of lower approved rates of return on common equity on a lower than average investment base.

The lower contribution from GTN was primarily due to lower transportation revenues, increased operating costs, and a $3 million provision with respect to nonpayment of contract transportation revenue from a subsidiary of Calpine. A $7 million decline in TransCanada's proportionate share in net earnings from other pipelines also had a negative impact on contributions from the Pipelines business. Net earnings from Tamazunchale was commenced operations in December 2006 were more than offset by the impact of higher project development and support costs associated with growing the Pipeline business in 2006.

Next, some comments on Energy. The Energy segment includes our power operations as well as our initiatives in natural gas storage and liquefied natural gas. Energy generated net earnings of $132 million in the fourth quarter, an increase of $45 million or 52% over last year, when you exclude the gains related to the sale of Paiton Energy. The increase was primarily due to higher contributions from western operations, natural gas storage, and Bruce Power. These increases were partially offset by a lower contribution from eastern operations and higher general, administrative, and support costs.

Bruce Power contributed $59 million of pretax operating income in the fourth quarter compared to $53 million last year. The $6 million increase was primarily due to an increased ownership interest in Bruce A and the positive impact of higher generation volumes, partially offset by lower overall realized prices and higher operating expenses. The Bruce units ran at a combined average availability of 89% in the fourth quarter compared to 79% average availability during the same period last year. The improvement in plant availability and our increased ownership interest in the Bruce A units increased TransCanada's share of power output from Bruce Power to 3,469 gigawatt hours in the fourth quarter, compared to 2,946 gigawatt hours last year.

During the fourth quarter, Bruce Power realized an average price of $50 per megawatt hour compared to an average price of $57 per megawatt hour in the fourth quarter of 2005. On a per unit basis, operating costs decreased to $38 per megawatt per hour in the fourth quarter from $41 megawatt hour last year. The decrease in costs per megawatt hour was primarily due to the increased output.

Looking forward, the overall plant availability percentage for 2007 is expected to be in the low 90s for the 4 Bruce B units and in the mid 70s for the 2 operating Bruce A units. Two plant outages are scheduled for our Bruce A unit 3. The first outage is expected to last one month in the second quarter. And the second outage is expected to last approximately 2 months beginning in late third quarter 2007. A one-month outage of Bruce A unit 4 is expected to commence in the first quarter of 2007. The only planned maintenance outage in 2007 for Bruce B is an approximate 2.5 month outage scheduled for unit 6 which commenced on January 20th and is expected to end in the second quarter, 2007.

Now turning to Western Operations. Western Operations operating income was $109 million in the fourth quarter compared to $33 million last year. The $76 million increase was mainly due to the acquisition of the 756 megawatt Sheerness Power purchase agreement on December 31, 2005. Improved margins, due to a higher overall realized power prices and higher market heat rates on uncontracted volumes, also contributed to the increase. Market heat rates in Alberta increased by approximately 70% in the fourth quarter as a result of an approximate 40% decrease in the average spot market natural gas prices while average spot power prices remain relatively unchanged compared to the same period in 2005.

In the fourth quarter of 2006, approximately 29% of Western Power sales were sold into the spot market compared to 9% in the fourth quarter last year. The increase in spot market sales was primarily due to the acquisition of the Sheerness PPA. Supply from Sheerness and our other plants in Alberta is managed on a portfolio basis. Depending on market conditions, we will continue to commit a portion of this supply to long-term sales arrangements with the remaining volumes subject to spot market price volatility. To reduce our exposure to future spot market prices, Western Operations have fixed price sales contracts to sell approximately 10,600 gigawatt hours for 2007.

Finally in Power, Eastern Operations operating income in the fourth quarter was $55 million compared to $68 million last year. Higher profits were earned in 2005 from increased generation volumes as a result of unusually high water flows through the hydro facilities, increased margins on natural gas purchase and sales related to the OSP gas supply contracts, and higher prices realized on power output in the spot market. [For] the quarter-over-quarter decrease was partially offset by incremental income earned in 2006 from the start-up of both the 550 megawatt Becancour cogeneration plant in September 2006 and the first of 6 wind farms at the Cartier Wind project in November 2006.

Overall in the fourth quarter, approximately 96% of Eastern Power sales were sold under contract. To reduce our exposure to future spot market prices, Eastern Operations has fixed price sales contracts to sell approximately 11,900 gigawatt hours for 2007.

Finally, in the Energy segment, natural gas storage operating income of $30 million in the fourth quarter increased $13 million compared to the same period last year. The increase is primarily due to higher earnings from CrossAlta as a result of increased capacity and higher natural gas storage spreads. Income from our contracted third party natural gas storage facility in Alberta also contributed to the increase. Commissioning of the Edson Natural Gas Storage facility in Alberta took place in the fourth quarter of 2006 and the facility was placed into service on December 31, 2006.

Turning now to Corporate. Net earnings from Corporate were $11 million compared to net expenses of $7 million in the same period last year. The $18 million increase in net earnings for the fourth quarter was primarily due to $12 million in income tax refunds and related interests and other positive income tax adjustments. Partially offsetting these increases in net earnings, were higher financial charges, including higher interest expense as a result of long-term debt issued in 2006.

Turning to the cash flow statement, funds generated from operations were $660 million in the fourth quarter, an increase of $130 million or 25% when compared to the same period in 2005. For the year, funds generated from operations were $2.378 billion compared to $1.951 billion in 2005. An increase of $427 million or 22%. The increase is primarily due to higher net income from continuing operations.

Capital expenditures in the fourth quarter were approximately $570 million and related primarily to the ongoing development of Greenfield projects such as Cartier Wind, Tamazunchale, Edson, the Bruce A restart and the Portlands Energy Centre. As well as growth and maintenance capital associated with the Canadian main line and the Alberta system. For the year, capital expenditures totaled approximately $1.6 billion. Acquisitions of $112 million in the fourth quarter and $470 million for the year are related to TC Pipelines, Tuscarora and northern border acquisitions in 2006 that appear on TransCanada's financial statement as a result of consolidated accounting.

Looking forward to 2007, in addition to our pending $2.4 billion U.S. acquisition of ANR, we expect to invest an excess of $1.5 billion Canadian and our Canadian wholly owned pipes and other Greenfield projects under development. These projects include the Bruce A restart, Cartier Wind, the Portlands Energy Centre, the Halton Hills Generating station, and Keystone.

Finally to our balance sheet. Our balance sheet remains strong. At the end of December, it consisted of 59% debt, which included our proportionate share of joint venture debt, 2% preferred securities, 2% preferred shares, and 37% common equity. As Hal stated earlier, TransCanada expects to finance the ANR acquisition in a manner that is consistent with the Company's current balance sheet capitalization. This is aligned with our intention to maintain our strong financial position and TransCanada Pipeline's limited A credit ratings. A strong balance sheet and our significant discretionary cash flow will continue to provide us with the financial flexibility to make future investments in our core businesses.

That concludes my prepared remarks, I would now like to turn the call back to David for the question and answer period.

Thanks, Greg. Before I turn the call back to the conference coordinator, just a reminder, that as part of the question and answer period, we'll accept questions from the Investment community first, followed by the media. With that, I'll turn it over to the conference coordinator.

Thank you. [OPERATOR INSTRUCTIONS] The first question from Dominique Barker Credit Suisse.

I wanted to know if on the ANR transaction if you would consider bringing in a private equity partner?

That's not part of our current plan. As you can see that we structured the transaction so that we partnered with the TC Pipeline's LP. So, there's no further need for additional partners in the transaction.

I guess from the -- at the time ANR was announced, you talked about issuing significant equity and now you're being a little bit more general and saying that you want to finance it in a manner consistent with your current balance sheet capitalization. So that's why I'm asking the question. Would you consider selling assets in order to finance the -- in order to keep your balance sheet under its current debt to Cap?

This is Greg Lohnes. We still plan to finance the transaction with significant equity and that equity would be consistent with our balance sheet current ratios.

Okay. And just one more question. So why, the question that I have, and frankly some of your investors have as well, is why there's a delay in issuing the equity from the time the transaction was announced? Is there a reason? Or is it really you're waiting for perfect market conditions? What do you expect to change between now and when the transaction -- or are you waiting for the transaction to close? Is there a risk to it closing?

There are conditions to closing. We don't consider them to be significant risks. But we continue to watch market conditions and determine what would be the most optimal time for us to issue equity.

Okay. Thank you.

Thank you. The next question is from Linda Ezergailis from TD Newcrest. Please go ahead.

Thanks. This is a question with respect to your Keystone expansion and extension announcement today. I'm wondering, what is the minimum amount you would want contracted and for what duration in order to proceed with that? And I guess a follow on question is what sort of returns would you be expecting? Would it be consistent with kind of multipipeline type returns or something else?

I think that the answer to the second question, with respect to return, we expect this project to return in that sort of neighborhood of what we achieved on most of our projects, and I think we've talked generally on capital projects that have a fair bit of underpinning and minimal earnings and cash flow volatility of the 7-9% kind of range. And --

That's [WAC] or --

On IRR, [inaudible] on return equity. It's sort of a total return capital in that kind of range. So that project would be consistent with that. With respect to minimum volumes for the Cushing open season, at this point in time, we haven't determined what that minimal threshold would be. What we're doing right now is determining whether or not the initial market interest that had been shown for the project is actually firm. And if it's firm, then we would move forward with the project. But we haven't put in place a minimum threshold at this point in time.

And what sort of lengths of contracts are you looking for?

We're looking for longer term contracts. The 5 to 20 year contracts, similar to the profile that we achieved on the original open season for the base Keystone project.

Great. Thank you.

Thank you. The next question is from Sam Kanes from Scotia Capital. Please go ahead.

Thank you. Question surrounding Alberta's Power market and Gas Storage market. I'm just curious on your views on sustainability as the margins experienced in Q4 in both of those businesses. And maybe what the budgeted spot or total production would be. You've given us, Greg, the fixed production of 10,600 gigawatt hours what is capable of being sold in the spot market, I guess, by coal or gas, do you think you can provide us that? Thank you.

Sam, it's Alex. With respect to the Alberta Power market, I think my perspective on it is we have seen a very significant run up in [spark spreads]. I think I look at the fundamentals and I would guess that over a 2-4 year period as new generation comes on, we would expect to see some moderation. But I think there is going to be relative to same strength in spark spreads and in Alberta for that period of time. And with respect to sort of percentage of spot sales, we are -- we are probably in the range of around 2/3 sold forward for the upcoming year. And that, that -- we get somewhat anxious when we get below that level, because if you get much below that level in terms of merchant megawatts, we actually potentially can run into some operational situations if we were to lose one or more plants. So that's basically where we are right now.

Thanks, Alex. And on gas storage? And what could Edson have done had it been on stream for Q4? Hypothetically the margins you're seeing now?

I -- I -- kind of rather not speculate on that. I, once again with respect to the Gas Storage market, generally in Alberta. I think we are looking forward. The sparks -- or the summer-winter spreads that are available continue to look quite attractive out sort of two or three years, and, I think, they're a bit pretty easy to take a look at those.

All right. Thank you.

Thank you. The next question is from Maureen Howe from RBC Capital Markets. Please go ahead.

Thank you very much. A couple more questions with respect to energy. With gas storage, would it be fair -- I appreciate the relevance of summer-winter spreads, but would it be fair to expect earnings from storage to proportionally increase with the capacity that's being added?

I don't know if proportionately would be an accurate statement. I think that overall we would expect, Maureen, to see continued strong contributions from storage. It was a particularly strong year, as you know, with [inaudible] last year. But we still think the fundamentals are strong. And I wouldn't expect to see a significant decrease, for example.

Okay. That's great. And then just also with respect to the Eastern Operations. The forward capacity markets and the dollar per monthly kilowatt hours that are being offered, how does that relate to something like hydro that would add, that would operate at that much lower capacity factor? Is it adjusted by a capacity factor?

Maureen, typically, because we do maintain, because our hydro facilities do have storage capability, relatively modest storage capability, my understanding is that we basically get the entire capacity payment on the full name plate of the facility.

So for ocean state and for the hydro assets, is it fair then to say take a midpoint of the range and then just multiply it out by the monthly kilowatt hours to get some estimate of what the contribution will be going forward? On an after tax basis, I guess?

Maureen, it's Glenn Menuz, you're referring to kilowatt hours -- [multiple speakers] I believe the calculations are based on kilowatt month. If you would look at kilowatt month times the posted price, that should put you in the range.

Okay. Thanks very much.

Thank you. The next question is from Matthew Akman from CIBC World Markets. Please go ahead.

Thanks, first on Bruce, Alex, I guess the question's for you. I'm trying to figure out how to model operating expenses. It looks like they jumped up a lot from Q3 to Q4, even though I know per megawatt hour they went down. What is going on there? And what is the full year kind of a good run rate? Or have the costs actually gone up?

I think we are, we are expecting for the full year in '07 a modest increase, Matthew, in per megawatt hour operating costs. So -- and I can give you some sort of an idea. I think it's probably going to be somewhere in the range of about 11% year-over-year and over half of that would be, or sort of, over half of that would be related to a few items, one would be we do have an extra outage this year as opposed to last year. Slightly increased depreciation from new CapEx, modest increase in new fuel costs, and then some modest water treatment costs. So those four items amount to over 50% of that increase. The other 50% of it however it relates to increased labor costs and that is overwhelmingly related to increased pension and post retirement benefits costs that were related to changes in actuarial assumptions that we've made.

Okay. And on the flip side, you've hedged out, it looks like maybe a quarter of the forecast production for Bruce B this year, can you talk about pricing ranges for those hedges we saw the Ontario auctions go over $70.00 a megawatt hour. So that's a starting point, I guess.

We certainly participated in those auctions. And we would have received pricing in that range, obviously for that.

And is that comparable for the other hedges you have for this year on Bruce B?

I think those prices were higher than we would have received sort of from an average sales price for the amount that is contracted for Bruce B.

Okay.

As you recall, as you know many of those contracts were legacy contracts that were entered into in prior periods.

No, no, I'm aware, but I'm just looking for pricing on the new hedges.

Yes.

Okay. And then switching gears, one last question, perhaps for Russ. On, I think Hal had mentioned something on looking at ANR integration or having set up a team, could you talk a little bit about how you planned on getting a running start at integrating this set of assets?

What we've done is we've put together a team of functional experts for sort of each piece of the Company and each one of those is responsible for dealing with their counterparts at ANR. And what they are sorting out is how to transition the business piece by piece. There's obviously a number of employees, systems, and ongoing business that needs to transition. So the plan is to make sure that we've identified every piece that needs to transition and document it and make sure there's a process to move it over. So there's a fair amount of activity going on between the two companies, currently.

Okay. That's helpful, thanks. Those are my questions.

Thank you, the next question is from Andrew Kuske from UBS. Please go ahead.

Thank you, good afternoon. Not sure if this question is for Russ or for Greg, but just on Tamazunchale, that pipeline started commercial operations in December and from the looks of it you've done 2 million in earnings on that pipeline. Can you just clarify, does that relate really to one month or operations? Or is that really throughout the quarter? And how should we look at that pipeline on a go forward basis?

Okay, give that one to Glenn Menuz here.

Sorry, Andrew, could you repeat the question?

Sure, just on Tamazunchale, the pipeline began commercial operations in December. And you've booked 2 million of earnings through the quarter. What does that 2 million relate to? Is it just one month and or is it through the entire quarter were you booking some type of earnings?

Oh, no, that was just with the start up of operations.

So that's really one month. And so if we look at that pipeline on a go forward basis analyzed you expect roughly 24 million of earnings over a course of a year?

That's not bad based on the capital that we've got invested in that pipeline. That's probably not a bad guess.

Maybe not quite that much, but close.

Okay. So then if I do the math on the returns are fairly attractive. And then to what extent, Hal, would you want to look at additional investment in Mexico? and how do you see Mexico fitting in from capital allocation plans in the future?

Well, fundamentally we see a lot of interesting opportunity in Mexico. The market is -- there's very high and growing demand for electric power. The market is relatively underserved with power generation right now compared to the rest of North America. And there's a strong preference within Mexico to use natural gas for that power generation. They're well advanced in their program of bringing in more imported LNG and we see good opportunities for TransCanada on both LNG receiving terminals and on gas pipelines to move that gas to different power gen sites. We haven't actively pursued power generation opportunities in Mexico to date but that is something we would look at over the medium term.

So the big issue always is whether or not we can earn a rate of return that sufficiently compensates us for the risks and challenges of doing projects in an area that is a little outside our normal operating theater. We've got a team of people here that are very comfortable doing business in Mexico. Tamazunchale is the only asset we have in Mexico today. But it's actually the third pipeline that we've built there. We built two others in the late 1990s and the year 2000 that we sold in our divestment program back in 2000, 2001. And I'm very impressed with the capability of people on the project side within TransCanada to bring projects in places like Mexico in on time and on budget.

So we're comfortable operating there. We're obviously pleased with the rate of return that we get on a project like Tamazunchale. And it's always the trade off between risk and reward and the nature of the particular contract that we're being asked to enter into, these are some of the things that we think about when we look at it. But I'd say we've had no bad experiences in Mexico. And we continue to look with interest at new opportunities there.

So just as a follow-up. As it relates to natural gas pipelines, if we're to look at relative risk adjusted returns in really three countries in Canada, the U.S. and Mexico as it relates to natural gas pipelines, where would you prefer to allocate your capital?

Well, I would say that the most attractive risk adjusted returns that we see would be on new build opportunities or buildout opportunities in the United States. But our experiences there have probably been the best. But that's a little unfair to Mexico because our only recent experience in Mexico's been very good. The fact that we brought the project in on time on budget and generally had a really good experience there I think would argue for Mexico. But the magnitude of opportunity is obviously not as large. So I think we would still continue to rank new build opportunities in the U.S. as number one. Acquisition opportunities are often a different story. Things are competitive. You have to bid an aggressive price. And when we look at acquisition opportunities it's always important to us to understand where we can go from there with respect to further capital investment in -- in the system or in the region.

That's great. Thank you very much.

Thank you.

Thank you. The next question is from Josh Golden from J.P. Morgan. Please, go ahead.

Good afternoon. Question for you regarding working capital. You had a pretty significant usage this quarter verses years past and all of 2-6, 2006 verses years past. Can you give me a little color on what is driving that?

I'm sorry, Josh, could you repeat the question?

Sure, I'm asking about working capital. You had a pretty decent usage this quarter and a strong usage in 2006 verses year's prior. Can I get some color on what is driving that usage in the working capital account?

There'll be, there'll be a few things going into that. Obviously, growth in our Energy business will -- we'll show an increase in working capital. As we grow the business along with the Storage business. There'll also be some factors such as inventory as we acquire gas for the Edson facilities. In addition, on a year-over-year basis, you would see a number of items such as we acquired more of northern border in Tuscarora, so you will see a proportionate consolidation of those amounts, as well as the doubling of the amount with respect to Tuscarora . And then overall, there is a timing receipts in payments that just generally happens. So all of those factors come together to explain our working capital.

Okay. Thank you.

Okay.

Thank you. The next question is from Winfried Fruehauf from W Fruehauf Consutling Limited. Please go ahead.

Thank you. In the fourth quarter 2006 and in all of 2006, how much AFUDC did you book? And what were the comparable numbers in 2005?

We'll have to check a little bit here, Winfried.

Okay.

Bear with us a moment.

Thank you.

Did you have another question, Winfried?

Yes. Regarding the Cartier Wind project, what was the capacity factor of the first phase in December? And what is the expected capacity factor on a going forward basis?

Winfried, it was -- it was well over 40, if my recollection is correct. And that would be well in excess of what our forecast Wind would have been. I think we were targeting something in the range of 35%.

And so is there some fair amount of seasonality involved?

Yes, I think it's a fair comment that the winter months tend to be fairly -- fairly windy at the site we have up in operational. So we would probably expect that to somewhat moderate as we move out of the winter time.

And as between the second and third quarter of any given year, what are you modeling, please?

Modeling, you mean by wind farm?

Yes. First phase.

That's something that I wouldn't have available here at this time. I can -- I could check on that, but as Alex referred to the overall availability would be in that 35 range for that first wind farm.

Okay. And while your still looking, I have one more. Regarding the $23 million of future income tax reduction in 2006, what portion of the 23 million actually applied to 2006?

The 23 was only in the Energy is section. [inaudible] was another 10 million in Corporate. How much of that relates to 2006? Really it's a reflection of the recalculating of our deferred taxes for future years. So it's primarily all related by definition, it's all related to future years.

So no significant portion actually applied to 2006 [inaudible] right?

Not that 33 million, all be it as tax rates go down, obviously, our businesses benefit from it on a month to month basis.

Okay. Thank you very much.

And, Winfried, with respect to your AFUDC question, obviously with some increased capital and in the Alberta system and along the main line, that number did go up this year. Probably somewhere in the range of about $7 million for the main line in the Alberta system compared to, oh, a little less than half of that last year. A couple 2-3 million last year. And then the amounts on our U.S. pipelines would be insignificant right now.

And what about for Energy such as the restart and refurbishment of the Bruce units?

Well, with respect to that, AFUDC is only earned on our regulated pipelines.

Okay. So how do you -- how do you deal with the interest component of your capital investments for the restart or refurbishment? Is it all expensed?

No, sorry. I thought you were referring specifically to AFUDC. Yes, we do capitalize interest as a policy on our new growth and expansion projects and generally what we're doing is capitalizing the interest that we're incurring [inaudible] funds.

And that would all be reflected, essentially all reflected in the Corporate segment, which is where the debt is held.

All right.

Not in the energy segment.

Yes. Sorry, there is no capitalized interest or interest expense generally in the Energy segment.

So what was the capitalized interest that relates to the refurbishment and restart of Bruce in the fourth quarter and in 2006?

Winfried, I can try and look at that for you. I think maybe we're just delving into a level of detail that we could take offline, if you will.

Yes, that's acceptable, thanks very much.

Thank you.

Thank you, the next question is from Karen Taylor from BMO Capital Markets. Please go ahead.

Not sure what's left to ask, but I'll give it a try. The 47 or 48.7% increase ownership in Bruce A that's new threshold, when did that kick in exactly, and what's the next trigger date? Is that based on an expenditure profile?

Sorry, the 48.7 of A is what we own currently.

Right, but it was up from 46 or 47.4 at the time the deal was announced, so was that based on an expenditure earn in with the smaller participants not contributing to capital?

Generally, yes.

And so what rate will that increase? So by year end 2007 based on the planned expenditure profile, where you will be in terms of ownership at Bruce A?

Assuming the other large partner continues into it, it will not go over 50%.

It would just continue to ramp up by very small increments, Karen, over time, as Glen highlighted assuming our other major partner participates.

Right, well we would assume that.

So you get down to I guess what remains for the unions effectively. So over time it could ramp up by obviously 250 -- [to 250]%, which would be just another 2% increase over the next few years.

Right.

Karen, I --

I guess it matters from a production point of view, but we'll take it offline, I guess. Can you tell me how much of expense year-to-date on Cacouna and if it's not been expensed, should it be capitalized?

It has not been capped. Cacouna expenses -- expenditures have not been capitalized, Karen.

And what are they to date?

Again, I can get that -- I'll get back to you on that, Karen.

And the run rate for the pipeline development expenditures of about 30 million after tax. It was in line with expectations, is that a good number going forward?

I think that depends on the profile next year, Karen. And, obviously, significantly impacted by level of activity and things like regulatory approvals for Keystone and what that means in terms of rate of spend. So it could be different next year than what you saw this year.

And same question on the energy segment with the 144 million this year. It seems growing by leaps and bounds. So is that again a good run rate? Or is it going to increase by a similar percentage in '07?

Karen, it's Alex. I think that is probably a reasonable run rate. It, it might go up a little bit, but I don't see it as being material.

Okay. And just lastly, can you refresh my memory on how the claw back on the floor works at the Bruce B at the $46?

the claw back is looked at -- receipts under the claw back under the floor are -- excuse me. Receipts under the floor are received on a monthly basis. The claw back is looked at on an annual basis and a year-to-date basis. Sorry, a life to date basis. So this year there were months that the project did receive receipts, but on the whole, over the course of the year, we were not entitled to keep the receipts therefore they were all -- none of them were recorded as revenue and they were all subject to refund at the end of the year.

So you would have escrowed those amounts until year end when it was determined you can keep them?

Yes, we would have set them up as liability at year-end. They would not have been booked into our earnings.

So if we have a continuation of the power price environment that we've got here, by year end 2007, you're going to keep those, I guess, is there some point or I guess what I'm trying to get at, is there going to be a period of time where the fourth quarter result is going to be adversely affected by a claw back?

We continue to look at on a quarterly basis. And as I mentioned that claw back also looks at a life to date basis. Obviously, I without knowing exactly what the world will look like at the end of '07, I can't speak to our exact treatment, but obviously we would look backwards and we would also look forward to where we see the market going because it is [inaudible] over the life of the contract.

Okay, and just lastly on the GT and the drop in income from last year. I'm pretty sure there was a one-time item last year, but it seemed quite steep. Can you break down, you mentioned three different reasons, transportation revenues that were lower, higher costs, and then a $3 million provision. I'm assuming that's pretax for Calpine, the subsidiary of Calpine. Can you break that down a little bit more in terms of the delta there?

I'd say those are, those are the factors that generally contributed to weaker performance for the year. As we look into 2007 the largest factors, obviously going to be the outcome of our rate case that we've filed and that's obviously going to determine income. So I would say that in terms if you're looking for run rate that those factors are some of those factors are nonrecurring factors and volumes right now are moving on a system. We're charging the rates that are that we applied for. And the actual rates that we book at the end of the day, I think we're actually booking last year's rates. So this year is going to be determined in terms of what we book for earnings is going to be determined largely on the outcome of the rate case. And we, I think that's schedule right now for October. And what our hope would be is that we could settle it sometime before then.

So I just want to make sure although the rates are in effect, they were suspended. So you are notionally accruing them into some sort of defer or liability account and only recognizing last year's rates. Is that fair?

That's correct.

Okay. Thank you.

If I could, just before we continue. I would just like to remind everyone, we obviously want to provide everybody with an opportunity to participate. Again, I just ask that you limit yourself to two questions and then get back in the queue. Appreciate that.

Thank you. The next question is from Daniel Stein from Desjardins Securities. Please go ahead.

Yes. Good afternoon. First I'd just like to say that it's a pleasure to be covering TransCanada on this call. And on to my question. First, I would like to ask something regarding Alberta market heat rates. You've made reference in the press release to the change in market heat rates for the quarter and for the year. I was just wondering if you can actually state what the heat rate was for the year on an average basis according to your calculations?

I'm not -- we're just checking on what the average heat rate was. But it was going -- it's going to be somewhere between probably -- I'm going to say 11 and 13.

Okay. And that's for the year?

Yes. Yes. For the year 2006, probably at the high end of that range. More in that 13 range. But it's, the way we determine it is simply just taking the average full price for the year and the average gas price for the year in Alberta and divide the two and you will come out somewhere in that 13 range.

Okay. Great. And one more -- my second question is on the pipelines in particular. The Alberta system and the Canadian main line. In the presentation, you state that you expect growth or -- you state that you expect capital expenditures of about 350 million on those two pipes in aggregate for the next several years. I just wanted to confirm whether that includes a growth component of capital expenditures in there? And if so, how much?

There's a component of growth in there and it's probably about half of that number, maybe a little bit more than half of that number, which would be related to lateral connections and those kinds of things on the Alberta system for the most part. The rest is what I call maintenance and ongoing capital expenditures to keep the system running.

Okay. Very good, thank you.

Thank you. The next question is from Maureen Howe from RBC Capital Markets. Please go ahead.

Thanks, very much. Just coming back to the GTN Pipeline, the provisions for Calpine, which I think was referenced at about $3 million, does that continue forward until Calpine comes out of Chapter 11? Are you hoping for some sort of resolution of that situation?

I'd say that for now, I think that we'll continue on with that provision as long as they're not paying their bills.

Okay.

And then we would expect to settle this at some point in time with the estate. But right now that's -- I think the current accounting treatment that we'll continue to use.

And is the 3 million before tax or after tax?

I'm sorry, 3 million would generally be before tax.

Before tax. Okay. And then, Russ, I'm just wondering, this is more of a big picture question. With respect to the main line and the Alberta system. And you do reference some spending over the next few years, but we have seen pretty significant decline rates, essentially, I guess in line with the depreciation on the system. But at the current rate, I think in 20 years the main line would be zero if you didn't spend anything more and you are spending some. But does there come a point where the Company pursues a different regulatory methodology that would at least stabilize the earnings contribution from those two systems?

Obviously that's something that we talked about internally. I don't think we've quite hit that point yet. But it is something that we talked about. And I think some of the factors that play into that would obviously be things like Northern Gas, what is the probability of Alaskan Gas, those kinds of things that will play into that kind of strategic thinking over the next couple of years as we try to figure out to how to stabilize that going forward. But we recognize that's probably not the long-term answer to run the system the way it's been run off today.

So do you think this is a 5-year issue?

I can't even speculate on how long that will be, Maureen. I think that you've raised an issue that's in our minds, we don't have an answer for it yet. So I can't even speculate on the time frame of addressing the issue.

Okay. Thanks a lot.

Maureen, it's Hal, I'd just like to add to Russ's answer, that if you look at this thing over a longer term, going back 5 or 6 years ago, the big issue we were concerned about stranded asset risk and about nonproductive capital because at the time the tariff that we were charging was not the most competitive way to get gas out of western Canada. There were other routes that would yield higher net back for the producer. And we've worked fairly diligently over the last 5 years, a little bit through accelerated depreciation, part of it through negotiation with the producers on certain issues, and all of that has enabled us to reduce our tariff and once again really establish the main line as the most cost effective way to get gas to the best markets. And so having been through that difficult process, we're now in a different era where we can think about the kinds of things that you're suggesting and in the years forward, we'll do that.

And Hal, just in that regard, can you give us an idea of say the cost advantage that the TransCanada system has into [dawn]?

Well, there's two parts to that. One is -- there's really three parts. One, what does it cost you to get the gas to the other end of the pipe? Second is how much fuel are you consuming? And those tend to offset each other a little bit. But third, is what is the gas worth when you get up there? And so we are in a situation today where, depending on the weather, the market value of natural gas in Toronto, Montreal, Boston, or New York can be quite a bit higher than the market value of that gas in Chicago. And it's really the net back advantage, the sum of all of those three things that I'm talking about when I say that we've reestablished a good competitive position. I look at it all in terms of what kind of net back do you get from which market.

I see. Okay, that's great. Thank you so much.

Thank you.

Thank you. The next question is from Sam Kanes from Scotia Capitals. Please go ahead.

Alex, I'd like to stay on Alberta, just one question. Has to do with gasification, we saw [inaudible] announce major project last week, Blue Sky before, Northern Lights earlier in 2006. [Ian] appears to be offering the same gas to anybody who wants it to go bid on it and go get it. Is there some interest on your part to create power from that [sin] gas at TransCanada?

Yes, we would obviously -- we would obviously consider that. Right now the issue for us in Alberta is Alberta's a pretty tight market. We don't have a lot of transmission out of the province. We already have a pretty significant involvement in the province and as a result it may not -- new generation in Alberta might not be as near to the top of our list as it is in other jurisdictions.

Okay. Then shifting staying with Alberta. Obviously you've identified [Slave River] as a very long-term -- possibility, I guess on hydro side in Las Vegas --

Yes.

-- on the south side. Any progress on either of those two that surround Alberta?

Sorry, I missed the other one?

You had the Slave River it's a hydro project that you started to look at. And the other one, of course your transmission system between, I think [inaudible] and Las Vegas. You haven't mentioned those yet, anything of any consequence on those two so far?

I think we're in the very early stages of Slave River. It really does represent one of the most attractive large scale undeveloped hydro resources in North America. But obviously, a project of that kind of scale is just a very complex thing. And I do see that as kind of a, I think it would be fair to think of that in the 5-10 year time frame. And we're doing a lot of preliminary leg work on that and meeting with stake holders and trying to understand the opportunity. With respect to the DC transmission projects, we have been actually spending a lot of time down in the Southwest U.S. meeting with potential customers of those lines. I think what I would say is there is very clearly an economic rational for that line to be built. And it is going to be in large measure dependent on whether the market feels that they want to sign up for that. So that's the process of we're in right now is assessing support in the region and I would see that taking place over the -- over this next year.

Okay. Thank you, Al.

Yes.

Thank you. The next question is from Daniel Stein from Desjardins Securities. Please go ahead.

Yes, hi. I wanted to ask a question with regards to the capacity payments that your generation will be receiving in the U.S. Again, according to the news release by TransCanada, the forward capacity market period starts in December 2006, but the first payments would only be received by generators in June 2010. So, I just wanted to reconfirm that that would be the suppliers, which are referenced in fourth quarter, that actually means the generator, i.e. TransCanada.

No, they are not, they are not delayed for four years. They are, they're paid out regularly.

Okay. So that reference to suppliers does not mean you as the generator?

Glen, do you have that in front of you?

That was -- page 22, top line.

Sorry, let me --

Yes, what is established right now is predetermined payment for the next arguably 3 years and then after that as our disclosure shows, it does go into a more of an auction process or a bid process.

Yes. That's exactly right. And so I didn't I understand the question. So for four years, the capacity payments are fixed and escalating over the four years. At the end of that, there will be this auction or RFP process wherein generators will be given the opportunity to bid their acquired capacity payment and then it depending on the need in the market, it will be determined who's successful in that auction at what price.

Perfect. Great. That clarifies things. And my second question here is with regards to the ANR acquisition. Again, TransCanada stated that you expect the acquisition to be accretive in the first full year of ownership. Now, I wanted to ask whether this comment can be applied to 2007. I know this is not going to be the first full year of ownership, but do you expect that acquisition to be accretive in 2007, as well, or not?

I think that depends on when the acquisition closes. At this point in time, we don't know when that would occur. So depending on when throughout the year it would occur, that would determine that. I would say generally speaking our view is that it's likely to be accretive, but not as accretive as it would be in the first 12 months of full operation.

Okay. And you're saying that you're not sure when the closure would take place. Are you -- does that mean that you're just not sure when it would take place during first quarter 2007? Which was I think previous guidance or could it be, could it slip a little bit?

It can slip a little bit as Greg mentioned up front. One of the major conditions precedent is an HSR approval, inaudible] approval, and our expectation is that would happen sometime in the first quarter. But it may go longer than that.

Okay. Very good, thank you.

Thank you.

Thank you. We will now take questions from the media. [OPERATOR INSTRUCTIONS] The first question is from David Ebner from Globe and Mail Newspaper. Please go ahead.

Hi, question for Hal. I was wondering, your team did a lot of talking on the conference call. Maybe it's sideways question, but I was wondering how long your tenure might be continuing on at TransCanada if you're moving on to maybe grooming a successor?

Dave, I must be getting old, everybody keeps asking me that. We have a very strong team of people at TransCanada, and on a number of specific questions that are asked by the investment community, it's clearly appropriate that Russ and Alex and Greg Lohnes answer those questions, so I'm happy to defer to them. I have no plans to be doing anything other than what I'm doing right now. And when the question is one that I feel I can give a good answer to, I try to do that.

Okay. Sounds good. And then a couple specific questions. What was the capacity down to Cushing be?

The capacity at Cushing would be the full 600,000 barrels a day. Actually, Cushing gets probably somewhere in the neighborhood of 150,000 barrels a day. The capacity sort of long haul with the size of a pipe to be able to move that kind of volume. But probably to move that volume beyond to the Gulf coast. There's some size in questions that we have right now as to how much horsepower we put behind it. Sort of thinking in that 100,000 barrel range, initially.

We have a potential for 600 all the way to the Gulf Coast then?

Correct.

And I guess, where is the -- obviously, the Cushing link has been spoken about before. How, where is the Gulf Coast thing from Cushing in terms of idea gustation?

I think that it's still a ways away. It's not part of our current thinking, is, I suspect that's something that they would probably in a position to talk about depending upon the success of a Cushing open season.

Two more. One quick and one maybe a bit longer. This one, how significant is moving ahead with the Cushing link presuming it might be successful?

Well, I think that the base Keystone pipeline of 435,000 barrels a day from our perspective is still let go, assuming that we get the section 74 approval to transfer line one from gas service to crude oil service. And we still have 340,000 barrels a day of underpinning contracts for that initial build. And so that's still our game plan. The Cushing would be just in addition to that. Even if the Cushing season -- Cushing open season isn't a success, we would still move forward with the base project. And just one clarification here is the 600,000 barrel a day. Just a clarification, is the way that the pipeline is configured is it can deliver 600,000 barrels a day to either Cushing or Wood River is the way it'll be sized. It won't be -- just for clarity, it's coming out of Alberta, it won't be greater than 600 ,000 barrels a day leaving Alberta.

Roughly speaking 400 to Wood River and 200 to Cushing or some variant there --

That's currently the thinking, but there is ability to move back and forth. We'll have the -- the sizing the pipe will be sized so that we can move those barrels back and forth between those two markets to sort of a maximum of about 600 to each market.

Okay. And then on the equity issuance, I might have missed any specific figures, but above $1 billion, do you have a ballpark there?

We have not, Dave, disclosed a number around that. We have a number of different financing options. We have said that it will be a significant equity issuance and we'd just like to leave it at that for now.

Could I just add one comment on the Keystone project. As to how much volume ultimately goes to Wood River or to Cushing or down to the Gulf Coast very much depends on the market demand from shippers out of Alberta. And that's really what we're responding to. We have had very strong interests from the shipping community out of Alberta for getting more of our Keystone production down to the Cushing hub and from there down to the Gulf Coast. And so given that there's that demand among the producing and shipping community here in Alberta, we keep coming up with new alternatives, some new elements of the project that would satisfy that demand. Longer term, we see Keystone as an expandable system beyond the initial pipeline. And so there are a variety of ways that we could take it to where it would be more than 6 00,000 barrels a day. But those are all long-term options and long-term alternatives that we're just looking at. I just wanted to add that on the Keystone. It's not any any way limited to the 590 or 600,000 barrels a day, that's just the initial design capacity of the first line.

Sounds good, thank you.

Thanks, Dave.

Thank you. The next question is from Rich Kern from Bloomberg News. Please go ahead.

Hi, Hal, Rich Kern here. In terms of the pipeline that are proposed by yourselves and others, are you at all concerned that over capacity becomes an issue? There are a lot of projects on the board and being proposed.

When you're in the business of building and operating long life infrastructure, overcapacity is always a worry. And that applies to us whether we're looking at power gen projects or gas pipelines or crude oil. So we proceed very cautiously on that and, of course, one way we go about dealing with that is to make sure we've got underpinning contracts for a significant part of the volume for an extended period of time. We have those kind of arrangements contractually in place to underpin the Keystone pipe. And we count on that. When we're building big power plants, whether it's Cushing, Wind, Becancour [inaudible] Hills or Portlands, they've all got long long-term underpinning contracts and those are really important things to us. Very seldom do you see TransCanada go into these things with a naked risk, if you will, on the longer term.

If I may, one follow-up, if you had to sort of -- of your areas that you're concentrating on power pipelines and so on, is there one you favor over the other in terms of opportunity? Or opportunities, I guess?

I think we're very happy that we've got 3 major businesses being our Power Gen business, our Canadian Pipes, and U.S. Pipes. And we have a number of related businesses things like Gas Storage and LNG. And what I always favor is the opportunity within that suite that delivers the best sustainable rate of return on a risk adjusted basis so that sometimes the project with a 7% return is more attractive than a project with an 11% return if it's got very low long life risk. So there are a number of things we consider, but mostly we want to focus on businesses that are opportunities that are in businesses where we have expertise and some competitive advantage and where we are comfortable that we can manage the risk. And then all things being equal, we naturally go for the higher return.

Thanks very much.

Thank you.

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

Great. Thanks very much. And I would just like to thank everyone for participating today. We appreciate your interest in TransCanada and we look forward to speaking to you soon. Bye for now.

Thank you, the conference is now ended. Please disconnect your lines at this time. Thanks for your participation, and have a nice day.