TC Energy Corp (TRP) 2007 Q4 法說會逐字稿

Good day ladies and gentlemen. Welcome to the TransCanada Corporation's 2007 fourth quarter results conference call.

I would now like to turn the meeting over to Mr. David Moneta, Vice President of Investor Relations and Communication. Please go ahead, Mr. Moneta.

Thanks very much. Good afternoon, everyone. I would like to take the opportunity to welcome you today. We are pleased to provide the investment community, the media, and other interested parties, with an opportunity to discuss our 2007 fourth quarter financial results, and other general issues concerning TransCanada. With me today are Hal Kvisle, President and Chief Executive Officer, Greg Lohnes, Executive Vice President and Chief Financial Officer, Russ Girling, President of Pipelines, Alex Pourbaix, President of Energy, and our Vice President and Controller, Glenn Menuz. 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 www.transcanada.com. It can be found in the Investors section, under the heading 'Conference Calls and Presentations.' Following Hal's and Greg's remarks, we will turn the call over to the conference coordinator for your questions.

During the question-and-answer period, we will take questions from the investment community first, followed by the media. In order to provide everyone with an equal opportunity to participate, we ask that you limit yourself to two questions. If you have additional questions, please reenter the queue.

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

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

Finally I would also like to point out this during this presentation, we will refer to measures such as comparable earnings, comparable earnings per share, and funds generated from operations. These measures do not have any standardized meaning prescribed by Generally Accepted Accounting Principles, and are therefore considered to be non-GAAP measures.

As a result, these measures are unlikely to be comparable to similar measures presented by other entities. These measures have been used to provide interested parties with additional information on the Company's operating performance, liquidity, and its ability to generate funds to finance its operations.

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

Thank you, David. Good afternoon, everyone. Thank you for joining us again. I would like to take a few minutes to talk about recent developments in our business. I will then turn the call over to our Chief Executive Officer, Greg Lohnes, who will review our fourth quarter results in more detail.

TransCanada's strong financial performance for the fourth quarter and 2007 is a result of solid contributions from our existing assets, and growing earning and cash flow from newly acquired and newly developed assets. In 2007 we continued to make significant progress towards achieving 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, 2007, was C$1.223 billion, or C$2.31 per share. Comparable earnings for the year-ended December 31st increased to C$1.107 billion, or C$2.09 per share, from 925 million or C$1.90 per share in 2006. Comparable earnings grew approximately 20% in 2007, and our comparable earnings per share grew by 10%.

Funds generated from operations grew to C$2.621 billion in 2007, an increase of 10% over the prior year. This strong underlying cash flow has enabled us to make significant capital investments in our Pipeline and Energy businesses. In 2007 we invested approximately $5.9 billion in growth initiatives. That includes the U.S. $3.4 billion acquisition of ANR which closed on February 22nd of 2007.

Our strong 2007 financial performance has enabled our Board of Directors to increase the quarterly dividend on the Company's common shares by 6%, to C$0.36 per share. On an annualized basis this equates to C$1.44 per share. We are pleased to say this is the eighth year in a row the Board has raised the dividend.

In 2007 we made very significant progress to fortify our position as the premier pipeline company in North America. We closed the ANR and Great Lakes transactions, which added approximately 17,000-kilometers of pipeline to our North American gas pipeline system. Today our natural gas pipeline network extend more than 59,000-kilometers, and offers our customers unparalleled connections from traditional and emerging supply basins to growing North American markets.

The ANR acquisition also added 230 BCF of natural gas storage capacity to our portfolio. Following the acquisition we received regulatory approval to proceed with a 14 BCF natural gas storage expansion project in Michigan. This expansion capacity is fully contracted, with an expected in-service date of April 1st, 2008.

The project is in addition to a natural gas storage enhancement and expansion program that will increase Michigan capacity available for sale by a further 13 BCF. This program was also fully subscribed with injections commencing last April, 2007. We reached several significant milestones on the Keystone oil pipeline project in 2007.

A successful open season supported expansion to 595,000-barrels per day, and an extension of the pipeline to Cushing, Oklahoma. We also secured additional long term contracts to a total of 495,000-barrels per day, with an average contract duration of 18 years.

Last Tuesday we announced that ConocoPhillips acquired a 50% ownership interest in the Keystone oil pipeline. A previously signed Memorandum Of Understanding committed ConocoPhillips to ship crude oil on the pipeline, and gave ConocoPhillips the right to acquire up to 50% ownership interest. Affiliates of TransCanada will be responsible for constructing and operating the 3,450-kilometer Keystone pipeline.

On the regulatory front, progress has been made in both Canada and the United States. Early this month TransCanada received the final environmental impact statement from the U.S. Department of State, which stated that the Keystone pipeline would result in limited adverse impacts.

A decision is expected in February 2008 regarding Keystone's application for a Presidential permit, authorizing the construction and operation of the facilities at the Canada/U.S. border crossing. From both regulatory and project execution perspectives. Keystone is on-track. Receipt and stockpiling of line pipe has begun, and construction activities are scheduled to commence in February 2008.

On the gas transmission regulatory front, Canada's National Energy Board approved our five year settlement for the Canadian Mainline for the years 2007 through 2011. This settlement which we negotiated with key mainline stakeholders, reflects an increase in the deemed common equity ratio from 36% to 40%.

On the Alberta system, negotiations with stakeholders are ongoing. The intent is to reach a settlement effective January 1st, 2008. By the end of the 1st quarter of 2008 it is expected that a general rate application, or a settlement, or some combination of the two, will be filed with the Alberta Utilities Commission. The Alberta system will charge interim rates during 2008, until final rates can be determined.

In late 2007 TransCanada filed a stipulation and agreement with the U.S. Federal Energy Regulatory Commission, comprised of an uncontested settlement of all aspects of the GTN 2006 general rate case. On January 7th of this year, the FERC issued an order approving that settlement. The settlement rates are effective retroactive to January 1st, 2007.

In November 2007 a nonroutine application was filed with the Alberta Energy and Utilities Board, for the north central corridor pipeline expansion of the Alberta system. The North Central corridor project will provide capacity needed to address increasing gas supply in northwest Alberta, declining gas supply from northeast Alberta, growing intra-Alberta markets resulting largely from increased oil sands development, and reduced delivery capability in interconnecting pipelines at the Alberta/Saskatchewan border.

The estimated cost of this project is approximately $985 million, with construction expected to begin in late 2008 subject to regulatory approval. In addition to that nearly $1 billion North Central Corridor project, we expect to invest a further 925 million in the Alberta system over the next three years, on a whole host of other projects.

With an eye to our longer term initiatives, TransCanada submitted an application for a license to construct the Alaska Pipeline project, under the Alaska Gasline Inducement Act, also known as AGIA. On January fourth, 2008, the state of Alaska announced that TransCanada had submitted a complete AGIA application, and would be advancing to the public comment stage. No other applicant met all of the AGIA requirements. If approved by the Administration and the Legislature, TransCanada could be granted the AGIA license later this year.

While our Pipeline business is complex, our strategy is simple. Firstly, we will use the tools that we have in place today to maximize the value of our existing pipeline asset base. Secondly, we will grow our footprint through extensions and expansions of our system, deeper into the marketplace and deeper into supply zones. We will successfully execute the capacity addition initiatives that we have underway today, and finally, we will continue to build a high quality platform of new opportunities that will benefit both TransCanada, and its customers in the years ahead.

Let me turn now to our Energy business. 2007 was another year of growth and strong financial performance in our Energy business. We remain focused on pursuing quality opportunities in power, natural gas storage, and liquefied natural gas. At the Bruce Nuclear project, we and our partners have invested approximately $1.9 million in the Bruce A Units 1 and 2 restart and refurbishment project.

In January a project milestone was reached, and a very significant milestone, when the 16th and final new steam generator was successfully installed. With the completion of this stage of the project, the authorized funding for Units 1 and 2 has been increased from 2.75 billion, to approximately 3 billion. Bruce Power is currently preparing a comprehensive estimate of the capital investment required to complete the Unit 1 and 2 restart project. This process is expected to result in a further increase in the total project cost.

Project cost increases are subject to the capital cost risk/reward sharing mechanism, under the agreement that we have with the Ontario Power Authority. At this time we continue to expect that the unlevered after tax return on total capital invested in the project, will fall within the previously announced range of 9.5 to 13.5%. An updated capital cost estimate and an updated range of unlevered after tax returns on total capital will be publicly disclosed once the comprehensive review is completed, and the revised capital costs are approved.

Also in Energy, the second phase of the Cartier Wind project, the 100-megawatt Anse aValleau wind farm was placed into service in November 2007. In addition, Cartier Wind began construction of its third phase of the project, the 109-megawatt [Carlton] wind farm. Cartier and the projects comprising Cartier are located in the Gaspe region of Quebec.

The 683-megawatt Halton Hills generating station located near Toronto, completed an environmental review, and we have now commenced preliminary construction work. Construction is progressing as expected on the 550-megawatt Portlands Energy Centre located in the heart of downtown Toronto.

On the LNG front, our Broadwater project recently achieved another major milestone as the FERC issued its final environmental impact statement. FERC reaffirmed its conclusions that Broadwater, located in Long Island Sound, New York, is an environmentally responsible way to meet the region's natural gas needs in the coming years, with fewer negative impacts than any of the practical alternatives. The New York State Department of State is expected to release a decision on the Coastal Zone Management Act in the first quarter of 2008.

Our major project initiatives in Pipelines and Energy, will result in capital commitments of approximately $10 billion. On this slide, you can see the capital cost estimates of many of the projects I have discussed, and the expected in-service dates for those projects.

In addition to the committed capital projects highlighted on the previous slides, we continue to develop a portfolio of longer term, high quality growth opportunities, in both Pipelines and Energy. At no other time in TransCanada's history have we had such a large and attractive portfolio of projects, and investment opportunities as we have before us today.

As we look ahead, we see TransCanada capitalizing on North America's increased demand for cleaner and more efficient energy. We build and operate the kind of clean and efficient infrastructure that North America needs in the years ahead.

As we meet that need, we will continue to deliver strong and sustainable financial returns to our shareholders. We will continue to maximize our financial strength, and our execution capability, to enable us to capture large scale value creating opportunities, and create value for our customers and shareholders, through superb execution of the very best of these projects. We created significant shareholder value in 2007, and we look forward to even greater accomplishments in 2008 and thereafter.

I will now turn the call over to our Chief Financial Officer Greg Lohnes.

Thanks, Hal, and 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 C$377 million, or C$0.70 per share, compared to C$269 million, or C$0.55 per share for the same period last year. Fourth quarter 2007 net earnings included C$56 million of income tax reassessments and adjustments, and a C$14 million gain on the sale of land.

Fourth quarter 2006 net earnings included $12 million of income tax reassessments and adjustments. Excluding these items net earnings of C$307 million, or C$0.57 per share for the fourth quarter 2007 is an increase of C$0.04 per share, or approximately 8% when compared to the fourth quarter 2006. For the year-ended December 31, 2007, TransCanada's net earnings were C$1.223 billion, or C$2.31 per share, compared to C$1.051 billion, or C$2.15 per share for 2006.

In addition to the items previously noted, net earnings for 2007 and 2006 included a number of specific non-recurring items. They are highlighted on this slide, and additional information on each is included in our fourth quarter news release. Excluding these items, net earnings for the year-ended December 31, 2007 were C$1.107 billion, or C$2.09 per share, an increase of C$182 million, or C$0.19 per share. This represents a 10% increase on a per share basis when compared to 2006. The year-over-year increases were due to significantly higher net earnings from both the Pipeline and Energy segments.

I will briefly review the fourth quarter results for each of our segments, beginning with Pipelines. The Pipelines business generated comparable earnings of $202 million during the fourth quarter, compared to $126 million for the same period in 2006. A C$79 million quarter-over-quarter increase from wholly-owned pipelines is the primary cause of the increase.

The higher contribution from the Canadian Mainline reflects the impact of a five-year toll settlement with stakeholders effective January 1, 2007. The settlement included an increase in the deemed common equity ratio from 36% to 40%. A higher contribution from the Alberta system was mainly due to eliminate cost savings.

TransCanada completed the acquisition of ANR on February 22nd, 2007, and included net earnings from that date. ANR's net earnings for the fourth quarter and the year were in-line with our expectations.

GTN's comparable earnings for the fourth quarter and the year, increased primarily due to the positive impact of a rate case settlement included in the fourth quarter of 2007. GTN received approval of the rate settlement from the Federal Energy Regulatory Commission in January 2008. Comparable earnings from other pipelines were $16 million in the fourth quarter 2007, which is $3 million lower than the same period last year. Increased earnings from TC Pipelines LP, were more than offset by higher project development, and support costs associated with growing the Pipelines business.

Before I move on to our Energy segment, I would like to take a moment to talk about our claims in the Calpine bankruptcy. In December 2007 Portland Natural Gas Transmissions System, which is 61.7% owned by TransCanada, and our wholly-owned subsidiary GTN, reached agreement with Calpine Corporation for allowed unsecured claims, of US$125 million and US$192.5 million respectively.

These claims are expected to be settled in the first quarter 2008, when creditors are expected to receive shares in the reorganized Calpine. Calpine shares will be subject to market price moves as these new shares begin to trade in the market. Claims for NOLA gas transmission LTD and Foothills Pipelines Limited for 31.6 million and 44.4 million respectively, were fully paid in cash which was received in January 2008, and is for the benefit of the shippers.

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 C$158 million in the fourth quarter, an increase of $26 million compared to fourth quarter 2006.

Excluding C$30 million of positive income tax adjustments, and a $14 million after tax gain on the sale of land, comparable earnings were $114 million in the fourth quarter, compared to $132 million for the same period last year. Lower contributions from Bruce Power and western operations, were partially offset by higher contributions from eastern operations, and natural gas storage. The lower contribution from Bruce Power was primarily due to lower generation volumes at the Bruce A facilities, and higher operating costs related to the significant increase in planned outage days at Bruce A.

Looking forward, the overall plant availability percentage in 2008 is expected to be in the the low 90s for the four Bruce B units, and in the low 80s for the two operating Bruce A units. To further reduce this exposure to stock market prices, Bruce B has entered into fixed price sales contracts, to sell forward approximately 10,200 gigawatt hours for 2008.

A lower contribution from western power operations was primarily due to lower overall realized power prices, and lower market heat rates, on higher uncontracted volumes of power sold, partially offset by lower power purchase arrangement costs. To reduce our exposure to spot market prices on uncontracted volumes, western power operations has fixed price power sales contracts, to sell approximately 9,200 gigawatt hours for 2008.

Finally in Power, eastern power operations operating income in the fourth quarter was $66 million, an increase of $11 million compared to the same period last year. The increase was primarily due to payments received under the forward capacity market in New England, and increased earnings from higher sales volumes to commercial and industrial customers. These positive impacts to earnings were partially offset by decreased generation from the TC Hydro facilities, resulting from reduced water flows.

Overall in the fourth quarter approximately 96% of eastern power sales volumes were sold under contract. To reduce our exposure to spot market prices, eastern power operations has fixed price sales contracts, to sell approximately 8,200 gigawatt hours for 2008, although certain contracted volumes are dependent on customer usage levels.

Finally in the Energy segment, natural gas storage operating income of 57 million in the fourth quarter, increased $27 million compared to the same period last year. The increase was primarily due to incremental income earned in 2007 from the start-up of the Edson facility.

Fourth quarter 2007 natural gas storage operating income included a $15 million net unrealized gain, resulting from the changes in fair value of proprietary natural gas inventory forward purchased contracts and forward sales contracts. Natural gas storage operating income included a $10 million net unrealized gain for the full year 2007.

Turning now to Corporate, net earnings from Corporate were $17 million, compared to net earnings of $11 million in the fourth quarter 2006. The increase was primarily due to $26 million of favorable income tax adjustments arising from legislated Canadian Federal corporate income tax changes in the fourth quarter of 2007, compared to $12 million of income tax refunds and related interest in the same period in 2006.

Excluding these favorable income tax adjustments, Corporate's comparable expenses were $9 million and $1 million, in fourth quarter 2007 and 2006 respectively. The higher comparable expenses were primarily due to higher financial charges, resulting from the financing of the ANR and Great Lakes acquisitions.

Turning to the cash flow statement, funds generated from operations were $741 million in the fourth quarter, an increase of $81 million, or 12%, when compared to the same period in 2006. For the year funds generated from operations were $2.621 billion, an increase of $243 million, or 10% over 2006. The increase is primarily due to higher net income from continuing operations.

Capital expenditures of $595 million in the fourth quarter, and $1.651 billion for the year, related primarily to the ongoing development of greenfield projects such as Cartier Wind, the Bruce A restart, Portlands Energy Centre, and the Halton Hills Generating Station, as well as growth and maintenance capital associated with the Canadian Mainline, the Alberta system, and ANR. Including the ANR acquisition, we invested a total of over $5.8 billion in our core businesses in 2007.

Looking forward to 2008, we expect to invest nearly $3 billion in our wholly-owned natural gas Pipelines, and other greenfield projects, including the continued construction of Bruce A, Cartier, Portlands, and Halton Hills, and the commencement of construction of the Keystone Oil Pipeline.

Finally our balance sheet remains strong. At the end of December it consisted of 54% senior debt, which includes our proportionate share of joint venture debt, 4% junior subordinated notes, 1% preferred shares, and 41% common equity.

2007 was a particularly active year for us on the corporate finance front. In the first quarter we raised $1.725 billion in equity through a public offering. It was the largest fully funded subscription receipts transaction in Canadian history. In addition, we initiated a 2% discount on shares issued from Treasury under our dividend reinvestment program, which has been very well received by the investment community.

We also sold US$1 billion of 30-year senior notes and issued US$1 billion of junior subordinated notes, both at very competitive market rates, reflective of our strong financial position, and TransCanada's Pipelines limited A credit ratings. TransCanada has a superior growth file, with a committed portfolio of approximately $10 billion, and an attractive set of longer-term high quality growth prospects. Our track record of success has generated strong returns for our shareholders, and we fully expect to continue that track record into the future.

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

Thanks, Greg. Just a reminder before I turn the call back to the conference coordinator, we will take questions from the investment community first, and once we have completed that, we will turn it over to the media. Again, a reminder that I would ask that you limit yourself to two questions, and then get back in the queue, in order to give everybody an equal opportunity.

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

Thank you. We will now take questions from the analysts. (OPERATOR INSTRUCTIONS)

The first question is from Linda Ezergailis from TD Newcrest. Please go ahead.

Thank you. Just some questions on Bruce Power. The cost sharing mechanism goes up to 880 million of cost overruns. What proportion of that is just for Units 1 and 2?

My recollection, Linda, it is Alex, is that that amount related directly to 1 and 2.

Oh, that is 1 and 2.

No, I'm sorry, Linda. You are right. The 880 million in terms of the cost sharing mechanism relates to Units 1 through 4. The split effectively is 300 million related to Units 1 and 2, and 580 million related to Units 3 and 4.

Okay. So you are effectively at the end of that 50/50 split. So after that it will be 75/25?

Yes. The first 300 million we shared 50/50. Following that cost would be split 75/25, and obviously the recovery of costs are through the reference price.

Yes, okay. And while we are on the subject of Bruce Power, in your notes on the Bruce Power disclosure there is mention of changes in fair value of held for trading derivatives of 11 million in the quarter, and 47 million for the year. Is that all related to Bruce B, and can you elaborate a little bit on what sort of trading you are doing there?

It is Glenn Menuz. It all relates to Bruce B, and we are not actually trading there. What this is some retail contracts that Bruce has entered into, and due to the nature of how the contracts unfold, we are required to fair value these, or mark to market the contracts.

Okay. And just one clean-up question unrelated on GTN. For the settlement that was recorded in Q4 for the full year, how much of that settlement would be related to prior periods?

I think you could probably basically take the number, and divide it over 12 months equally throughout the year. There is some seasonality to it, but basically the number is pretty ratable over the year.

And what is the number?

In the fourth quarter, Glenn, do you have that?

Yes. The adjustment in the fourth quarter was approximately 25 to $26 million after tax, compared to the revenue we had previously recorded at the 2006 rate level.

Okay. I guess it doesn't matter if it is Canadian or U.S. these days.

Not right now, no.

Okay. Thank you.

Thanks, Linda.

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

Thank you. Trying to understand eastern power operations fixed price power sales contracts 90 days ago, you had forecast or said that you had 12,400 gigawatt hours for 2008, and now you have 8,200 gigawatt hours for 2008 as of December 31st. How much of that is Becancour and how much is other?

Sam, that amount that, I don't have it right in front of me. I think it was around 8,200, something like that, that was ex-Becancour.

That is the only difference between the two numbers?

Yes.

Okay. Then switching also staying with you, Alex, this wind farm you progressed on in Maine, is that contracted, uncontracted? Have reccs been presold or not? How are you looking at developing it from a financial point of view, now that you are going to go ahead with that wind farm?

Sam, it is a fully merchant facility, but I think I would just say that there is a very active market for reccs right now in New England, and we are quite confident in our ability to enter into contracts to sell those forward.

Can you give a rough range of a recc values as you see them at the moment out there?

I guess what I would say, I would probably suggest they are very robust right now, but getting up almost to the cost of a megawatt hour of just pure power, of pure energy. So it is quite an attractive market for them right now.

Thanks, Al.

Thank you. The following question is from Bob Hastings from Canaccord. Please go ahead.

Thank you. The Keystone orders are in place for 3 billion. Would that suggest that the prices are locked in, that you have locked in about 60% of the cost?

That would be correct.

Okay, good. And how are you going to account for, how do you account for the money that is going to come in on that from your new partner? Do they have you have to pay cash up front to catch up to where your expenses are? Does that come in in this quarter? What is going on there?

Actually in that arrangement our partner Conoco has injected cash right into the partnership. So that will be used to finance our ongoing expenditures.

So there is no impact on you other than you don't have to give, you don't have to pay quite so much this year in your CapEx?

Correct.

Correct.

Okay. And on the, to be clear on the Calpine settlement for PNGTS and GTN, when you get that stock, I assume you plan to be selling it at some point into the market, and the benefit of that will be a full impact to earnings this year, cash to the shareholders, or what?

I would say it would be the assumption on selling, we will address that when we get the stock and if that's the right thing to do at the time, irrespective I think of the currency that we received the payment in, and we will book earnings at that point in time, and the earnings will be related to how we settled both of those rate cases.

The PNGTS one is still under negotiation, and the GTN one is settled, though. So that will be reflected in our income. Glenn, do you want to add to that in terms of how we book it?

No. I think that covers it all, because as Russ says we will be taking it into income upon realization.

On realization of the sale, or just realization of receiving the stock?

That is an accounting question. Glenn, it has got to be yours.

We will book something when we receive the shares, but obviously that needs to be trued up when we sell them.

Okay. Thank you very much.

Thank you. The following question is from Peter [Housel] from RBC Capital Markets. Please go ahead.

Hi. Regarding the expected increase in Bruce restart costs, could you provide any additional details on sort of the ballpark magnitude that you might expect, and maybe the reasons for the increasing costs? It is just that since like in your Investor Day, it was sort of alluded that everything was going really well, and then you were going to be at the high end of your unlevered IRR range. So I was just wondering what has changed since that time?

Sure. It is Alex. My recollection in November was really what, I think the exact message we sent was we expected the project to remain within that range. What we had seen to-date was going pretty well, but we were entering into quite a sensitive part of the work on the 1 and 2 Units, and really what we have seen since then, is it is a very complex project.

Most of the fixed cost contracts have held up very well. We are seeing some problems with the removal of the pressure tubes just in productivity, and the number of what I would call sort of low, a large number of very repetitive balance of plant-type issues, that are not sort of first of a kind, but that has caused us to just really be careful about this, and we have asked Bruce to undertake this cost review, just to make sure we have a very good handle on it.

Thank you. The next question is from Matthew Akman from Macquarie. Please go ahead.

I wanted to follow up on that question around Bruce, because I think we are getting mixed messages, that on the one hand you are comfortable you're in the range of return, but on the other hand, Bruce is preparing a comprehensive cost estimate.

So is Bruce preparing a detailed cost estimate, to nail down what you have a pretty good idea about as the range, or are they giving you information that you really don't know about right now, and that you are very uncertain on what is going to come out of it?

No. We have been intimately involved in all aspects of this. The cost review that is going on, so we have been very involved in this, and this cost review lab going on, probably since around November. So we do, we are getting data back that is leading us to be comfortable with that range. We just haven't got to the point where we are comfortable giving our absolute final view on everything.

Okay. Thanks, Alex, and I have a follow-up on that.

Sure.

Just to confirm, on the additional capital that is spent there over and above the budget, you still earn a return on that capital. It is just lower than the range for the overall project. Is that a correct way to look at it?

Yes. I mean what we have is this cost sharing mechanism for cost overruns that was referred to earlier, and so as the price increases, we continue to get capital contribution at certain levels from the OPA, but I mean we continue to get a price for power for all the megawatts that were produced. So I am not sure if that --

So I think, Matthew, it is how one addendum I could make to that, is that overall unlevered return goes down as the capital cost goes up, but in any foreseeable range of capital costs based on what we know today, we remain within that 9.5 to 13.5% range.

And the mechanism, though, to recover any additional capital is the reference price?

Yes, that is correct.

Okay. Thank you very much.

Thanks, Matthew.

Thank you. The next question is from Andrew Kuske from Credit Suisse. Please go ahead.

Thank you. Good afternoon. I think this is a question for Alex, and it just relates to western power operations, and really your contractual positions, and your strategy going into Q4. It really looked like you took a view on the market it was going to be a very robust market in the quarter, and that didn't really pan out as well as you would have liked. Just if you could give us color on what you saw in the market in Q4, and what you see in the market today in Q1, and how you are positioning the book. There is some commentary in the MD&A, but any further color would be appreciated.

Sure, sure. Over the years we really developed a strategy where we always are going to keep a relatively significant amount of our power in the west open, and that is really just to cover up the risk of operational upsets at other of our assets.

So, you know, we are pretty unlikely to go much over 75% contracted in the west, just to protect ourselves from upsets at our assets, but we certainly historically, Q4 has been a period where if we get some very poor weather in Alberta, we have often seen some very significant volatility and high prices in the power market, and it just turned out for those who are on the phone from Calgary, they will understand this, we ended up having quite a mild fourth quarter. There wasn't a lot of cold weather, not a lot of issues, and the Alberta fleet ran better than has been our historical experience. So I think that is a fair comment.

How do you see the book on a go forward basis, as far as your positioning? There are some really volatile prices month to date.

Yes. Yes. This is the kind of pricing that we often expect in Q4, and we are seeing a fair bit of it it in Q1 right now with the cold weather out west. I think it would be fair to say that we remain over the call it the one to two to three year period, very bullish on the fundamentals in Alberta, assuming normal weather, and normal consumption patterns.

We have seen a little bit, I think one of the things that probably surprised us a bit was that demand moderated to the extent it did. We were probably expecting to see a little more, we were a little more bullish on the demand side on the power, but generally overall we see demand growing. We don't see a lot of assets coming on, and we see a lot of challenges in the market in the short term. So we are pretty bullish.

Great. Thank you.

Thank you. The following question is from Karen Taylor from BMO Capital Markets. Please go ahead.

Thank you. If I could just come back to Bruce quickly, what was the the total capital expenditure I guess in aggregate, or your share, whatever way you'd like to state it, for fiscal 2007?

Do you have that number?

The spending to date is 1.9 billion on Units 1 and 2, and 0.2 billion on Units 3 and 4, and I would have to just take a look at what it was last year, Karen. I am sorry, I don't have that handy.

Okay. Just can I come back to Bruce, because I know Alex, maybe this question is for you. You and I chatted, I guess around the time that we saw the announcement on the 3, 4 agreements.

Yes.

We talked about an audit at that time. You did reiterate that at the Investor Day. The numbers that we had discussed back in September were the 2005 numbers, and I guess the question is, when are you going to disclose how big the potential increase is in total budget on the restart, and at that time are you going to talk discreetly about where those cost increases are coming from?

Yes. Karen, I think we will be in a position. Our view this process is probably going to take place over the next couple of months. So certainly in Q2 we are going to be out, we anticipate being complete, and at that time we are going to give a full discussion of where the project is, where we see it it going, and I am sure there will be some disclosure about the areas in which we are seeing the cost pressures.

Well is that also going to include then, annual capital expenditure budgets for the project going forward because I think that's been given a rather piecemeal, again not updated since 2005, with any project changes over the last two years, and a very intense price environment for CapEx?

Karen, I think maybe I misunderstand the question, but we --

Well, I guess I am just asking for some better numbers and some accountability on the project. We haven't had anything for a couple of years.

What do you mean by accountability?

Well, just where the budgets are going, where the cost overrun is going to be. We know that the price on this thing is going to come through what OPA pays you. So if it is 75/25, are we going to get some indication of how that would affect the pro forma price, based on what was announced back in October 2005, and what we would all have calculated in the model on a pro forma basis going forward?

Well, the facts are this, that we and Bruce announced a $2.75 billion project that could cost more. In the event that it costs more there's a sliding under the OPA where the power price changes and our rate of return changes and we've announced that, you know, in the best case we could end up with an unlevered return of 13.5%, and if costs ran up to the high end of the probable and possible range that we looked at, we could end up with a 9.5% unlevered return, and with normal debt leverage that would generate pretty good returns on equity anywhere in that range.

Now what we have announced today is that as a result of the first part of our comprehensive cost review, we have determined that it's highly likely that the cost is going to exceed $3 billion, so we have increased the authorized funding for the project, and this is total share, not just our share. We are about 50%.

We have increased the authorized funding from 2.75 billion to 3 billion, and as to where it goes from there, we are indicating to you and to the market, that it is likely there will be some further increase beyond 3 billion, but we have also indicated that we remain comfortable, but we are within that range that was disclosed at the outset, and that is what we know today.

Okay. I apologize, I am not asking this question very well. So your best case number would have been then what number, what you announced back in '05?

What do you mean by our best case number?

So you said just now you said in the best case you would earn the 13.5 unlevered IRR after tax.

Yes. About 13.5 unlevered after tax would line up with the 2.75 billion.

Okay. And the worst case, or the high end to use your words, which would get me down to the low end of that range, I am just trying to put some numerical parameters around high end best case, so the high end gives me a capital cost of what?

That is the information that we will share with you in 90 days, or whenever we are done with our work.

Okay. Thank you.

Sure. Can I just add that in the interim I know Glenn will get you the number in terms of the actual CapEx in 2007 in isolation.

I would also just highlight and we can get you the numbers, but the CapEx profile that we showed at November Investor Day, that highlighted capital expenditures for '08, '09 and 2010, was our view of how the remainder would be spent of that 2.75 billion. So I just wanted to highlight that the CapEx profile that you are seeing for those three years, were reflective of the best information we had available at that point in time.

And, Karen, just to update the numbers on that, as we said, we had spent 2.1 billion like to the end of this year or to the end of '07, and 1.1 billion to the end of '06. That billion dollar spending in 2007 is generally split about 900 million, to 1 and 2, and then the remainder to 3 and 4.

And that would be the 100% cost, I believe. So our share would have been 50% of that.

Correct.

Thank you very much.

Thanks, Karen.

Thank you. The following question is from Daniel Shteyn from Desjardins Securities. Please go ahead.

Yes. Good afternoon, everyone. First question here is on Mainline OM&A savings, and incentives benefits which you have booked in '07. I guess, first of all, I wanted to see if you can provide me with a quantum of what these were for the year, and also do you believe that they will be recurring under the term of your new incentive arrangement going forward?

Glenn will get you the actual number while I sort of answer the second question is, we expect to make some incentive earnings. I think we had a very good 2007. There are escalators and those kinds of things in those agreements, and there are certain opportunities that arose in 2007, which may not arise in 2008, with respect to selling Great Lakes capacity, and those kinds of things. So I would say that we expect to have some incentive earnings in 2008, but, you know, unless the circumstance arises again, I wouldn't expect to see the same level in 2008 that we did in 2007. I know Glenn, do you have the number in --

Yes. It is roughly in the range of $20 million, when adding all of different programs together, because there are a number of different programs there.

Okay and that is after tax, right?

Correct.

Okay. And the other question that I had is to come back to the Calpine settlement, now from what you indicated that roughly you expect, or you will have 300 million in U.S. in claims, and which you believe will be settled in the first quarter, I believe.

Now what will be your cost basis for the shares that you receive? Is that going to be the actual amount of the claim, and therefore there is no tax hit on getting the shares? There is no tax friction there? 300 million is what you'll get and that will drop to the bottom line?

That is a good cash question. I think if you treat it similar to cash I would think coming in. I mean it is taxable income, but there is no cost basis to the shares.

Okay. So basically 300 million is potentially a pre-tax income number?

That is correct.

That is the way I would see it.

Okay. And then would you consider this comparable earnings, or is that something you would be excluding when calculating comparables?

We will get to that in Q2 when we sort of run through the numbers. We haven't thought that deep I would say.

I would clarify that when you look at those amounts, recognize that PNGTS would be 61% our position, and that it is subject to the ongoing negotiations, with regard to the rate case around PNGTS.

So you mean the rate case could actually claw back a part of the benefit from you to the account of your shippers? Is that what you are saying?

That is the potential as we haven't sorted out all of those issues yet on PNGTS. We are in the middle of a rate negotiation for 2008 and beyond.

Okay. I see. Thanks very much.

Thank you. The next question is from Ramin Burney from National Bank Financial. Please go ahead.

Thanks. Good afternoon. How much has been capitalized for Keystone by the end of 2007?

Just one second.

Do you have another question while they are looking that up?

Actually I have got it. On a 100% basis it is about $300 million that we spent on pipe and other preconstruction costs. That is on a 100% basis.

Okay. And for my second question, we have talked about the potential for cost increases here for Bruce, and we haven't talked about timeline. Are we still expecting the restart for Bruce A1 and 2 to be done by late 2009, early 2010?

I think, you know, that is also part of the work that we are doing on the actual recasting of everything. I think under Benny's scenario we are looking at we are not anticipating a significant change in those dates.

All right. Thank you.

Thank you.

Thank you. The following question is from Steven Paget from FirstEnergy. Please go ahead.

Good afternoon, gentlemen, quick question. When Portland and Halton Hills come online in the Energy section, do you expect them to be, to increase the gross margin in the Energy group, or will they be approximately the same gross margin that you have been running with already?

I would have to look at that, Steven, for you. You mean relative to the gross margin in the eastern operations of our current portfolio?

That is correct.

I would say that generally when we look at our Energy projects, where we have a locked in 20 year PPA with a AA or AAA credit, as compared to investing in hydro, or in the coal fired, we would be looking at a slightly lower return for that kind of locked in projects. So it would be probably a little bit less than some of the more emergent parts of the business, but due to the risk profile.

But you also have to consider I think, Steven, that a lot of the costs under that kind of a commercial arrangement are not really for our account, and so it is difficult to kind of compare the margin that we get on a megawatt hour of output at Becancour or Halton Hills or Portland, with what we get at New England Hydro, or Ocean State, or even Bruce I think. You kind of got us on a way of looking at things that we don't look at those things that way.

Okay.

Maybe we should.

Okay. Thanks.

Thank you. The next question is from [Josh Golden] from JPMorgan. Please go ahead.

Hi, good afternoon. My question surrounds the balance sheet. I mean you mentioned in slide 18 that you strengthened the balance sheet to an A rating. You have done some issuance throughout the year. Given the sizable amount of capital expenditures, and the projects that you have planned, can you talk to me about the mix of financing, how much debt you would plan to issue, and more importantly, can you give me some type of credit metrics or range that you would target specifically debt to capital?

Well, generally we are first of all committed to maintaining our A credit rating. So when we do a large acquisition like ANR, we went out and issued equity to strengthen the balance sheet. So we are generally targeting a 60/40 debt to equity split, consistent with the return, the equity components on the Pipeline side, and the nature of our Energy portfolio.

With regard to the $3 billion, I think we have talked about over three years $10 billion of that 10, 1 billion was in '07, and there will be a billion that lags. So we have got the CapEx in the $8 billion range. We have got significant cash flow. We have our DRIP program running, which generates about $200 million, and we then continue to look at other opportunities, within our sort of toolbox of things that we can do around raising capital. So we feel that we are in a very strong position. We have got quite a bit of room there on that debt side with our additional cash flow.

Would you care to elaborate on what you are referring to, other tools?

I am sorry?

Would you care to elaborate? You mentioned other methods of raising capital. Is that equity? Is that hybrid? Is that debt?

We do, as you saw, we have done hybrid issues. We continue to monitor the [press] market, for example. We have the opportunity to partner on certain assets. We have currency with our LP, and we look potentially at optimizing our portfolio as we go forward. So we are always constantly monitoring our portfolio. So we have a number of different options that we can consider, as we not only look at this $8 billion worth of CapEx, but also look at potential acquisitions over that same timeframe.

But then to be clear, you definitely are committed to the A credit rating?

Yes.

Okay. Thank you.

Thanks, Josh.

Thank you. (OPERATOR INSTRUCTIONS) The following question is from Daniel Shteyn from Desjardins Securities. Please go ahead.

Yes. Thank you. I have a question with regards to ANR. So we have had 10 months worth of, or more appropriately a touch over 10 months worth of earnings from this asset, which is proving to be, I guess, an excellent asset. Now in terms of seasonality I believe that there was a mention in the MD&A that one, that winter months are more earnings heavy than other months, and I wanted to confirm that presumably the the number that we have is not really a run rate. It's for 2007 it is something a little bit more to taking the seasonality into account, and two, I wanted to ask you whether you expect that some sort of synergies to come through from this asset in '08, relative to what has been done in '07?

On the first question, I think you can expect there to be seasonality in the number I think that 2007 was a good year. We hope to continue that performance into 2008, and with respect to synergies, I wouldn't expect to see large amounts of synergies coming from these assets. They were well run by El Paso when we bought them, and we have picked up those operations. So I would say from a synergistic standpoint there isn't a lot to be had there.

Maybe, Daniel, it is how I would add that I agree with Russ' comment on cost synergies. We're constantly looking for revenue synergies. And whether there are ways to operate across from say ANR to Great Lakes, or perhaps some integrated activity with our Mainline. So there are those opportunities, but that stuff takes a bit longer to bring home.

Okay. And do you have, well, okay. That is fine.

Moving on to something else, just wanted to chat quickly about what happened with Bruce earnings, as opposed to capital costs in fourth quarter. Now there has been a fairly dramatic decrease in earnings during the fourth quarter, and that is from what I understand driven by two things actually. First there were more outages during the quarter relative to '06, and second, there is something that your adjustment that is DPA, or deposit of [TT] amortization.

I wanted to understand why is there a change in amortization of this DPA intangible, and how much do you expect it to be going forward, and two, what do you expect the OpEx profile to be going forward? Do you think that it is going to be staying at current levels, or is it going to change?

Daniel, it is Glenn here. As far as the adjustments for these forward contracts, as required when we do any acquisition accounting, we do need to fair value all of the assets and liabilities that we may acquire. At the time of getting into Bruce originally, there were a number of forward sales contracts on, that we had to put a value to, and as a result, what we do is over the course of those contracts we amortize that in.

At this point, I believe most of those contracts have rolled off. So as a result, what you saw last year was an amortization of that positive value, and now we just have very little, if any, of that amortization left. As far as the cost structure goes, I will throw that over to Alex.

Yes. Daniel, I think that the kind of costs that you are seeing coming out of Bruce in 2007, we expect that to remain fairly stable over 2008, not a lot of difference.

Okay. So just to clarify, this 18 million earnings drag that we saw in 2007, you expect that to go to more or less go away going forward, and that when we talk about cost structure, we are actually talking cost structure on a per megawatt hour basis, which is $41?

Yes. That is exactly what I am talking about.

Very good. So that is a roger on both the points.

Sorry. On the second point which is the cost per megawatt hour, and I don't have the budget in front of me, or the outage days in front of me, but I mean you were correct. The decrease in earnings was primarily due to increased outage days, and I can't recall maybe, Glenn, I don't know if you recall offhand what our outage days '08 versus '07 are.

As far as '08 versus '07 on or planned outage days, they will be slightly lower in 2008.

Is that for Bruce A or Bruce B?

I was referring to a combined basis. It is a little bit lower for Bruce A, both flat for Bruce B year-over-year. So on a combined basis we are going to be a little less on the [flat] outage days.

But in any case, you are still consistent with your guidance on the capacity factors. When you say availability factor, you actually mean capacity factor, right?

Correct.

Okay. That is fine. Thanks very much, I appreciate your answers.

Thank you.

Thank you. The following question is from Steven Paget from FirstEnergy. Please go ahead.

Good afternoon. As we are into the second hour of this call, just a quick question on ANR. After almost a year, the comment was made when it was initially purchased, that ANR had a significant market serving component versus something the Canadian Mainline, which is a long haul that delivers gas to others. Could you comment on the ANR market service that you are seeing in particularly Wisconsin, Michigan, Illinois?

I am not sure exactly what you are referring to. It does have a large market serving component and it is mainly grounded in this 230 to 240, of storage capacity that we have in the market, where we can combine that service with transportation service, and offer a bundled service to meet that, the uneven load factor of our customers actual burn, a lot of these will buy those kind of services from us.

What we found is, as Hal mentioned, in terms of offering new services across our system, whereby we can take gas into ANR, and store it in the Michigan area, and then move it out on the Great Lakes system, or even out to the Canadian Mainline, is something that is attractive to our customers, and we are just getting to those kinds of if you want to call them synergies now, between the systems, whereby we can use that market serving component to survey larger market regions, than just the sort of that Michigan/Wisconsin kind of area.

Steven, it is Hal. There is one other broad difference between ANR and our Canadian pipes that is generally true of all the U.S. pipes and our Canadian pipes. Under the Canadian regulated model, they aim to regulate our net income to a fixed number.

Right.

And if there is increased volume or reduced operating cost, the benefit of that generally flows through to the shipper, whereas under the U.S. model, if we can reduce operating costs, or significantly increase through-put volumes, or come up with some innovative service offerings, such as the one that Russ described where we package storage, transport, and maybe transport on other pipes, you know, we have the opportunity to profit from that, and that of course, is one of the things that we find interesting and relatively attractive about the significant investments that we have made in the U.S.

So what you would be doing is storing gas for a power generator, and then selling it to them?

Yes.

For example?

That would be a good example.

Great. Thanks.

Thank you. If I could, conference coordinator, if we could just switch to any questions from the media just in order to give them an opportunity to ask questions, to the extent there are any further questions from the investment community, we will certainly circle back and try to answer those as well.

Thank you. We will now take questions from the media. (OPERATOR INSTRUCTIONS) The first question is from David Ebner from The Globe. Please go ahead.

Hello. I was wondering in the portfolio of options the company has, how highly building a nuclear power plant in Alberta ranks, and what a potential timeline might be?

Well, David, it is Hal. A nuclear power plant in Alberta would rank quite highly, in terms of interesting opportunities, but it wouldn't rank particularly high in terms of probability of going ahead in the next five years. When we look at all the different capital opportunities available to us, many of which were identified in the slides related to this call, you won't see an Alberta nuclear plant there. So it would be more than five years out, and as such, I would say there are a lot of things ranking ahead of it, in terms of what we will do to create shareholder value.

What sort of work do you do? Obviously they are long term projects. What sort of work do you do on a potential plant in the next five years, in the next two years, in the next year?

I think one of the key issues, Alex may want to add to this, but, you know, we also look at something like Slade River Hydro, and we don't get into detailed engineering or foundation design, or anything like that. It is more around what kind of commercial structure would apply to it, and there is an awful lot of discussion with parties like the Alberta government, and others, as to what kind of commercial structure could be put in place, that would actually allow is to go ahead with one of these very long term projects.

Dave, I would point out that a big issue in Alberta is that the power market is so small, relatively few players, and not much size and not much liquidity. So we have identified as a priority that the Alberta power market needs to be connected to other more liquid North American power markets, before some of this stuff can go ahead. If we can't make those connections to more liquid markets like the Pacific Northwest, then we are stuck trying to figure out some sort of long term contracting model, and you know, that takes quite a while to figure that out.

In terms of that kind of long transmission period, the new premier in Saskatchewan is interested in that, do you see that as a more realistic option, maybe build in Saskatchewan with a long transmission line?

Well, the trouble is Saskatchewan is not a market for Power, and it is a government controlled and in many ways politically controlled market, and so just integrating Alberta with Saskatchewan, or for that matter, B.C. on the other side, we end up being the ham in a not very pleasant sandwich sometimes. So we are much more interested connecting into U.S. markets, like the Pacific Northwest, where genuine market forces prevail, and we can make investments comfortable that the market will dictate the return.

Okay. And last one, if I can have a fourth here, on the MacKenzie Pipeline, do you see a resolution in the next couple weeks or next couple months, or does it extend further and further?

We don't know. We would be hopeful that we can make some progress here in the next few months, to the point of knowing whether or not we should persist with the project. We think we have come up with some ideas that are pretty good.

We know the timeline for the regulatory process is about another 12 to 15 months, for them to complete everything that the National Energy Board and the Joint Review Panel has to do. So we believe that we need to resolve the commercial issues over that period, but we would sure be interested in seeing some sort of a breakthrough in the next six months.

Okay. And I will squeeze one more in. In terms of 8 billion dollars budgets for the pipeline budget itself, the Mainline, do you think that is a realistic price?

You mean for the main MacKenzie line?

Yes, that's right, the the 1,200-kilometer main line.

Yes, we think it is reasonable but we never know for sure. A big issue is how much more delay do we experience, and if you experience another three years' delay, and that happens to be during a very inflationary period, that will have a dramatic impact on the costs, but it is the kind of project that we know how to execute, and we are reasonably optimistic that we could do it within that 8 billion amount.

Okay. Thank you.

Thanks, Dave.

Thank you. The next question is from Ian McKinnon from Bloomberg. Please go ahead.

Hi, this is a question for Alex. Have you guys hired an outside consultant for the cost of Bruce?

Sorry. I didn't get the question.

Have you guys hired an outside consultant to analyze the cost and cost creep at Bruce, or is it all being done internally?

No. We are quite comfortable between our Project Manager, Bruce staff, and TransCanada's staff, that we are quite competent to assess this.

Okay. On a going forward basis for the total project cost, you know, like previously was 5.2 million or 25 million, now it is going to be 5.5, what other issues are going to be pushing up costs because you know the productivity should be behind you, since all the tubes are removed. Are you expecting the same sorts of problems with Units 3 and 4?

You know, our experience on this project has generally been that there has been a number of first-of-a-kind activities that were really required to do this refurbishment and restart of the 1 and 2 Units, and I think our experience has been that typically when we first start these first-of-a-kind activities, productivity often lags, and a great example of that is removal and replacement of the steam generators.

You know, we had significant challenges on removing the eight, and replacing the eight steam generators on Unit 2, and by the time we got to Unit 1, the productivity was just miles ahead and, in fact, caught up and in fact, surpassed our expectations for the entire program.

So I mean I do expect as we move on to 3 and 4 we are going to see productivity improvements, as the various activities become more and more hard-wired. I think with respect to 3 and 4, one of the other things that is interesting is you will recall that when we first acquired Bruce, one of the first projects that we inherited was the restart of the 3 and 4 Units, that were laid up at the time that we acquired the project, and as part of that less comprehensive work, that was done probably in around 2003, 2004, almost all of the balance of plant activities that are giving us problems on 1 and 2, were actually taken care of in that original 3 and 4. So we do not expect on the 3 and 4 to have remotely the level of balance of plant activity that we are having on 1 and 2.

And specifically are you having any shortage of workers, or skilled trades pinching costs?

Well, you know, that has actually been I think one of the positives of the project. We are right now at approximately 2,200 contractors on site, which I believe makes Bruce largest energy infrastructure project in North America at this time, to this point we have actually had very good luck with with our trades. We haven't had a lot of shortages.

Okay. Thank you kindly.

Thank you. The following question is from Elsie Ross, Daily Oil Bulletin. Please go ahead.

Hi. Just one question. Do you anticipate any further cost increases on Keystone, or is this pretty well that 5.2 pretty well the final cost you expect?

I would say that we are as mentioned, we have locked in about $3 billion worth of the costs on a $5.2 billion estimate, and the balance is just an estimate, and I think there is a number of times today we are in a very intensely competitive CapEx kind of environment. That said, we have learned a lot over the last two years through this environment, and we are pretty comfortable with that estimate, but I would say that, you know, we are not locked into 5.2 at this point in time by any means.

Okay. Thank you.

Thank you. The next question is from John Harding from The National Post, please go ahead.

Just a quick question on MacKenzie. I wondered what an impact, any change within the partnership structure, what impact would that have on the regulatory process? Would there be any?

I don't think so, John. It's how -- we are very much in this project together with Imperial. Shell, ConocoPhillips and Exxon Mobil. We think that any changes in the actual makeup of the partnership, or the way the producers interact with the original pipeline group, which we are currently funding can all be worked out. It is not really material to the regulatory process.

Thank you.

Thanks.

Thank you. (OPERATOR INSTRUCTIONS) The next question is from [Shawn Coulter] from Calgary Herald. Please go ahead.

Hi. In terms of MacKenzie, has there been any more thought of maybe taking over the project from the producers group, as some people were talking about a few weeks ago?

I am sorry, Shawn. Could you repeat that? We had difficulty hearing the beginning of your question.

Well, in terms of MacKenzie, has there been any more thought to taking the lead from the producers group?

Well, as I have said many times, we are not focused on the issue of taking over the lead in the project. We are working very closely with with the producers and with the government of Canada, trying to resolve some issues so that we can break the the logjam, and move ahead with the project.

I have said before that TransCanada is willing to contribute in whatever way we can. I would note that the amount of construction, the tonnage of pipe, the miles of pipe that we are installing on the Keystone pipeline project, is about twice as big as the MacKenzie. So this is the kind of project that we do.

This is what our company does, and we have extended the offer that we would be prepared to do that on the MacKenzie project, but those are not issues that are important to any of us right now. The most important thing to the aboriginal Pipeline group, to the producers in TransCanada, and I believe to the government of Canada, is to figure out an economic model that allows the project to go ahead, and to do that we are really focused on risk reduction, and cost management, and once we get through those, we will figure out how we're going to implement.

Thank you.

Thank you.

Thank you. (OPERATOR INSTRUCTIONS) The next question is from Karen Taylor from BMO Capital Markets. Please go ahead.

Thank you. It is okay. I don't need to ask it.

Thanks, Karen.

You are welcome. Thank you.

The following question is from Sam Kanes from Scotia Capital. Please go ahead.

Then I will ask one, what the heck. Churchill River, you guys were selected in a joint venture about 18 months ago to a reccs call for a project with respect to Churchill River. Wills been some activity in respect to you getting connected to Newfoundland Labrador to study how to deliver that power. Where do you stand, Alex, with respect to that particular project, or is that dormant?

That was actually a call for proposals, preliminary proposals, to express interest in actually designing and constructing and operating the actual hydro facility, and at the time we put it in, we see that as a great opportunity, but we weren't going to go very much further with it, unless it was quite clear that we were getting the support of the various provincial governments and the utilities in the area, and I think it is fair to say at this time Newfoundland, as you noted, they have announced that they are working on the opportunity. So we are not doing any more work on it. We are just monitoring it and yes, we would love to be involved, but we want to make sure there is a role for us, before we put any more effort into it.

Okay. Lastly, small question, Becancour, used the word similar economics, but not identical to operating. So there must be some small differential you are picking up if you were running Becancour. Is that correct?

No. Our economics are very close, but I think it would be, here is a simple way to put it. The economics from my perspective are identical. We get the benefit of not having the wear and tear on our machines, and not having to worry about any type of catastrophic incident, or any other kind of incident that could affect operations. So we get the exact same margin out of the project, had we with run as if by not running.

Okay. I appreciate that, Alex. Thank you.

No problem.

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

Thanks very much. We thank all of you, both within the investment community and the media, for participating this afternoon, and your interest in TransCanada, and we look forward to talking to all of you soon. Thanks. Bye now.

Thank you. The conference has now ended. You may now disconnect your lines at this time, and we thank you for your participation.