TC Energy Corp (TRP) 2004 Q4 法說會逐字稿

Good afternoon ladies and gentlemen. Welcome to the TransCanada Corporation 2004 Fourth Quarter Results Conference Call. I would now like to turn the meeting over Mr. David Moneta, Director of Investor Relations. Please go ahead Mr. Moneta.

Thank you. Good afternoon everyone. I'd like to take this opportunity to welcome you this afternoon. We're both pleased to provide the investment communities, the media and other interested parties, with an opportunity discuss our 2004 Financial Results and other general issues concerning TransCanada.

With me today, are Hal Kvisle, President and Chief Executive Officer, Russ Girling, Executive Vice President and Chief Financial Officer and Lee Hobbs, Vice President and Controller. Hal and Russ are going begin this afternoon with some comments on our 2004 results, and other general issues pertaining to TransCanada and then we'll turn the call over to the conference coordinator for questions.

During the question and answer period, we will answer questions from the investment community first, and then open the call to the media. Due to an unavoidable scheduling conflict, Hal will only be available until 1.00pm Mountain or 3.00pm Eastern today to answer your questions. In order to ensure that Hal is available to address as many questions as possible, I would ask that you try and direct your questions to Hal first. We will take 1 question with a follow up at a time, and rotate through the callers, so that everyone has an opportunity to ask their questions of Hal. Russ, Lee and I will remain on the line until all your other questions are answered.

Before Hal begins, I would like to remind you that certain information in this presentation is forward looking, and is subject to important risks and uncertainties. Results or events predicted in this information may differ from actual results or events. Factors which could cause results or events to differ materially from current expectations include, among other things, the ability of TransCanada to successfully implement it's 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 to reports filed by TransCanada with Canadian Security 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. With that, I'll now turn the call over to Hal.

Thank you David. Good afternoon and thanks to everyone for joining us today. I am pleased to report that it's been another good year for TransCanada. We continue to deliver on our commitment to create value for our shareholders. As you know, over the past 5 years, our increases in earnings, cash flow and dividends have helped us generate an average annual return to shareholders of 25% per year.

For the year ended December 31, 2004 TransCanada's net income was just over CAD1b or CAD2.13 per share. This compares to CAD851m or CAD1.76 last year. Excluding net income from discontinued operations and gains of CAD187m related to TransCanada Power LP, our net income from continuing operations in 2004 were CAD793m or CAD1.63 per share.

Today, recognizing the Company's positive future outlook and the importance of the dividend to our shareholders, TransCanada's Board of Directors raised the quarterly dividend on the Company's Common Shares to CAD0.305. On an annualized basis this represents a CAD0.06 or 5.2% increase. This is the fifth consecutive annual increase in the common share dividend. Over the 5 year period the dividend has increased from CAD0.80 to CAD1.22 per share. After I briefly review fourth quarter developments, I'll turn the call over to Russ Girling, who will take you through a more detailed review of our financial results.

It has been a year of steady performance for TransCanada. We delivered solid operating and financial results and we've invested approximately CAD2.6b including the assumption of debt, in our core businesses of gas transmission and power generation. Although we had a year of solid performance TransCanada did face some cHalenges, as a result of an arbitration decision affecting the cost of fuel at Ocean State Power, and disappointing decisions made last summer by the Alberta Energy and Utilities Board on Phase 1 of a general rate application, and on our generic cost of capital application. In 2005, we will continue to work with regulators, shippers and our suppliers in an attempt to arrive at satisfactory long term solutions to these issues.

In the natural gas transmissions side of our business, TransCanada completed the acquisition of Gas Transmission Northwest Corporation on November 1, 2004. Since the acquisition GTN has contributed a CAD14m to net earnings to TransCanada. GTN was an excellent strategic fit for TransCanada, expanding our pipeline system to better serve the Pacific North West and California markets. The GTN pipeline is well positioned to transport frontier supplies from the McKenzie Delta and Alaska to these markets, should Northern Gas be connected to North American markets.

We scrutinized many pipeline acquisition opportunities over the past years, and I say, without hesitation, that the GTN system is the best strategic fit and the highest quality gas pipeline available that we examined. We are very pleased that the GTN system is now part of our blue chip gas transmission portfolio.

We continue to actively pursue advancement of the Alaska Highway Pipeline project in Canada and Alaska. We have made significant investments over the past 25 years to move this project forward, including constructing and operating the pre built portion of the project south of Carolina Alberta. The pre build is a first class large diameter pipeline system, that today moves 30% of Canada's gas exports to U.S. markets.

Canada's Northern Pipeline Act or NPA provided the regulatory framework, under which the free growth section south of Carolina was constructed over the 1982 to 1998 period. The NPA remains in effect, and it is the mechanism under which the balance of the Canadian section of the Alaska pipeline will be constructed.

Other parties are suggesting that the NPA is somehow flawed or out of date. At TransCanada we don't agree with that and we're confident that the NPA will prove its worth, as the very best regulatory mechanism for the construction of the Alaska pipeline through Canada.

This is not, as some have suggested, a question of the National Energy Board versus the Northern Pipeline Agency. Our Alaska Highway Project was in fact selected over all others by a thorough NEB hearing process. The NPA was thereafter established as an extraordinarily efficient regulatory mechanism. A special purpose mechanism to expedite the approval and construction of the Alaska pipeline through Canada. That is the arrangement and that is what TransCanada intends to do. We intend to continue working with the State of Alaska, the Government of Canada, the Alaska Producers and key players in the North American gas market, to bring the Alaska Pipeline project to fruition.

TransCanada is the North America leader in large gas pipeline design, construction and operations. Our efforts have significantly advanced North American gas pipeline technology, over the last 20 years. We look forward to applying our industry leading capabilities to the Alaska Highways Pipeline project.

We are also pursuing growth in other areas, as exemplified by our announcement in the fourth quarter that we plan to build a liquidified natural gas facility in Long Island Sound with Shell U.S. Gas and Power. Also, our announcement in January 2005 that we will develop a CAD200m natural gas storage facility near Edson, Alberta.

On the power side of our business there were several positive developments during the fourth quarter. We announced that we will proceed with the purchase of Hydro Electric Generation Assets, from USGen New England. Our total generating capacity of 567MWh for a purchase price of US$505m. The acquisition is subject to regulatory approval, and subject to the pending sale of the 49MWh Bellows Falls Hydro Electric Facility to the Vermont Hydro Electric Power Authority. If Bellows Falls is sold, as planned, TransCanada purchase price would be reduced by $72m. We are pleased to have the opportunity to acquire low cost base load hydro assets in the New England area to add to our growing portfolio of power assets.

Our power portfolio also includes our new GrandView Cogeneration Plant, the 90MWh gas fired power plant in New Brunswick. The project, which began operations in January 2005, was completed on time and within budget. The GrandView project is an excellent example of how TransCanada is growing its power business by capitalizing on our expertise in fuel efficient co-generation.

In January 2005, we also announced that we have increased our interest in Cartier Wind Energy Inc. to 62% from 50%. We are working towards signing power purchase agreements with Hydro Quebec Distribution. And again on the power front, we continue to assess opportunities in Ontario. The feasibility study to examine the potential restart of Bruce Powers A Units 1 and 2 is ongoing. As well TransCanada has made submissions, under the clean energy RFP process, in Ontario which is seeking up to 2500 MWh of new generation capacity.

In addition, TransCanada together with its Bruce Power Partners, is evaluating a potential investment and the refurbishment of the 680MWh Point Lepreau nuclear generating station in New Brunswick.

To summarize, we have created 4 platforms for future organic growth in business areas, where there is substantial potential for creating long term value for our shareholders. The first 2 platforms are in power generation, where we are growing and creating value through both acquisition and development activities, in both our core regions, here in the west and in the east. The third and fourth platforms are in gas development, again focused on our western and eastern pro-regions.

In the west, we're focused on northern development on gas storage and on acquisitions like GTN. In the east, we're focused on market development, pipeline acquisitions and the development of LNG. Our strong financial position gives us the flexibility to capture valuable acquisition and development opportunities in our core regions as they arise. GTN of course being an excellent example of that.

During 2004, which was a year of very solid performance in which we faced some cHalenges, we set the stage for long term growth. In 2005, we will remain focused on executing our strategy and adding to our portfolio quality large scale infrastructure assets.

With our strong balance sheet and excellent workforce, TransCanada is well positioned within North America to seize emerging opportunities and create value over the long term. I will now turn this call over to Russ, who will provide more detailed information on our financial results, and then I'll look forward to taking your questions. Russ.

Thank you Hal. And good afternoon everyone. As Hal said, today we reported net income for the year ended December 31, 2004 of CAD1.03b or CAD2.13 per share, compared to CAD851m or CAD1.76 per share in 2003. Excluding net income from discontinued operations and gains of CAD187m recorded in 2004, related to TransCanada Power LP net income with continuing operations was CAD793m or CAD1.63 per share in 2004, compared to CAD801m or CAD1.66 per share last year.

In the fourth quarter, net income from continuing operations was CAD185m or CAD0.38 per share, compared to CAD193m or CAD0.40 per share in 2003. Year-over-year and quarter-over-quarter declines are primarily due to lower earnings in the gas transmissions and power businesses, which was partially offset by lower net expenses in the corporate segment. I'll review the fourth quarter results for each of our segments, beginning with gas transmission.

The gas transmission business generated net earnings of CAD157m for 3 months ended December 31, 2004, compared to CAD160m for the same period in 2003. The CAD3m decline in net earnings was primarily due to lower contributions from the Alberta system. And Canadian mainline, which was partially offset by contribution in Gas Transmission Northwest, which was acquired in November 1, 2004.

The Alberta Systems' net earnings of CAD40m in the first quarter decreased by CAD14m compared to CAD54m in same period last year. For the year, the Alberta system contributed net earnings of CAD150m, which is a decline of CAD30m or CAD0.08 per share compared to 2003. The decreases were primarily due to the impact of the Alberta Energy and Utility Board decision in respect of Phase 1 of the 2004 general rate application, and the generic cost of capital proceeding.

In the GRA decision the EUB disallowed operating costs of approximately CAD24m pre-tax or CAD16m after tax. We believe that these are necessary costs that the company has reasonably and prudently incurred for the sake of reliable and efficient operation of the Alberta system. As a result, in September TransCanada filed with Alberta Court of Appeal for leave to appeal the EUB's decision on the basis that the EUB made errors of law, in deciding to deny the inclusion of these costs in the revenue requirement.

Subsequently, at the request of TransCanada, the Court of Appeal adjourned the Appeal, for an indefinite period of time, whilst TransCanada considers the merits of a review and variance application to the EUB in respect of 2004 costs, and works towards a negotiated settlement of future years tolls with its customers.

The decrease in the Alberta systems net earnings can also be attributed to a lower return on capital in 2004, compared to earnings implicit in the 2003 negotiated settlement, which included a fixed revenue component of CAD1.277b.

Earnings in 2004 reflect a return of 9.6% on deemed common equity, 35% as approved by EUB in its generic cost of capital decision, released in July this year. This was lastingly applied for return on equity of 11% on the deemed component -- equity component of 30%, which the Company considers to be a fair return.

Turning to the Canadian Mainline. Net earnings of CAD71m for the 3 months ended December 31, 2004 was CAD4m less than the amount reported for the same period last year. The decrease is primarily due to a lower return on common equity of 9.56% in 2004 compared to 9.79% in 2003, and a decline in the average investment base. 2004 net earnings are based on a capital structure that includes a 33% deemed common equity component. We've applied for a 40% deemed common equity component, which is being considered during Phase 2 of the 2004 Tolls Hearings. Phase 2 of the proceedings commenced in the fourth quarter of 2004 and it's currently expected to conclude sometime in February. The decision is expected in the second quarter of 2005.

Gas Transmission Northwest partially offset the lower contributions from the Canadian wholly owned pipelines in the fourth quarter. TransCanada acquired GTN on November 1, 2004 for $1.73b including approximately $528m of debt. For the period November 1, 2004 to December 31, 2004 GTN contributed CAD14m of net earnings. Total delivery volumes in GTN during the 2 month period were 181b cubic feet or approximately 3b cubic feet per day.

Finally, with respect to gas transmissions. TransCanada shared net earnings from other gas transmission was CAD25m for the 3 months ended December 31, 2004, compared to CAD23m for the same period in 2003. The increase was primarily due to higher earnings from CrossAlta as a result of favorable storage market conditions, as well as higher earnings from the Ventures LP.

Next, I'll make some comments on power. In the fourth quarter of 2004 the power business contributed net earnings of CAD31m compared to CAD44m earned in the fourth quarter of last year. The earnings decline was primarily due to lower contributions from the western and eastern operations. Total volume sold in the fourth quarter of 2004 were 7,638 GWh hours, compared to 7,161 GWh hours sold in the same period 2003. In western operations, operating other income in the fourth quarter 2004 was CAD25m which is CAD6m lower than last year. That decrease was mainly due to a reduction in income from ManChief who did the sale of that plant to the Power LP in April 2004. A series of operating costs adjustment associated with the MacKay River, that were settled in the fourth quarter and lower prices on uncontracted volumes.

In our eastern operations, operating and other income for the 3 months ended December 31, 2004 were CAD31m compared to CAD36m for the same period last year. The decrease was primarily due to a CAD13m reduction in income from the Curtis Palmer Hydro Electric Facilities, following the sale of those plants to the Power LP in April 2004, and a CAD5m reduction due to higher fuel costs at Ocean State Power.

Partially offsetting those reductions was a positive impact for restructuring transactions that closed in the fourth quarter, related to power purchase contracts between OSP and Boston Eddison. Under the terms of the transactions TransCanada assume a 23.5% share of the OSP power purchase contracts from Boston Eddison Company, effective April 1, 2004. As a result, TransCanada recognized CAD16m of pre-tax operating revenues that had been previously deferred pending the completion of the transaction. Of that total, approximately CAD10m relates to the previous 2 quarters.

As highlighted in our third quarter report, at the end of August, OSP included a third arbitration process with respect to its cost of fuel gas, and as in previous decisions, received in March 2003, and the summer of 2002, the decision substantially increased OSP's cost of fuel effective September 1, 2004. In effect, most recent arbitration decision established a pricing mechanism for fuel gas, which results in prices in excess of market prices.

The outcome of the fourth arbitration is expected by the end of the third quarter 2005. Should that fourth arbitration decision continue to support a pricing mechanism for fuel gas in excess of market prices, and if anticipated market conditions do not change substantially, management expects a negative impact of continued above market gas prices, could result in an asset impairment of the Ocean State Facility. The net carrying value of OSP at the end of 2004 was approximately $150m. [indiscernible] power operations is a core component of our power operations and has generated significant returns for our shareholders over time.

TransCanada's success in the North East, is a direct result of its assets and an efficient marketing operation. We are focused on selling power under contract, to wholesale, commercial and investor customers who are managing a portfolio of power supplies source, from both our own generation and other wholesale power purchasers. In the future, we will continue to focus on enhancing our competitive position in the U.S. North East and in Eastern Canada through a number of initiatives, which include the acquisition of the USGen Hydro assets which is expected to close in the first half of 2005.

Next, I'll talk about Bruce Power. Bruce Power contributed pre-tax equity income of CAD5m in the fourth quarter 2004, which is CAD2m less than the CAD7m reported for the same period last year. The CAD2m decrease primarily relates to higher operating costs. On a per unit basis, operating expenses increased to CAD36 per MWh hour in the fourth quarter 2004, from CAD33 per MWh hour in the fourth quarter 2003. The increase was partially due to expenses incurred by Bruce Power related to the feasibility studies on the restart of the Bruce A Units 1 and 2, which totaled CAD10m and CAD16m for the 3 in 12 month ended December 31, 2004 respectively.

In addition, total operating expenses in the fourth quarter 2004, were higher than the same period last year due to higher outages, fuel, depreciation and staff expenses in 2004, reflecting the move to a 6 unit versus a 4 unit operation. This increase in expenses combined with a lower average availability resulted in higher operating expenses on a per MWh basis in the fourth quarter 2004, compared to the same period last year. Reduced availability was primarily due to planned work on the vacuum building outage and Unit 6 as well as unplanned outage days.

Overall, the Bruce Units ran at an average availability of 72% in the fourth quarter 2004, compared to an average availability of 73% in the fourth quarter 2003. TransCanada's share of output from Bruce Power for the fourth quarter was 2,351 GWh hours compared to 1,846 GWh hours in the fourth quarter 2003. The increase primarily reflects output in 2004 as a result of the restart of the Bruce A Unit 4, in the fourth quarter of 2003, and Unit 3 in the first quarter of 2004. The restart of these 2 units has expanded Bruce Power's capability by approximately 1500 MWh.

Overall, prices realized in the fourth quarter of 2004, were approximately CAD47 per MWh hour compared to CAD45 per MWh hour in the fourth quarter of 2003. Approximately 47% of the output was sold in Ontario's wholesale spot market in the fourth quarter as approximately 30% in the fourth quarter 2003. The remainder was sold in a long term contract.

To reduce exposure to stock market prices, Bruce Power has entered into fixed price sales contracts for approximately 36% of the planned output for 2005. Average availability in 2005 is expected to be 85%, compared to 82% achieved in 2004. Total operating expenses in 2005 are also expected to increase, due to higher depreciation and amortizations on the A units, higher fuel costs and higher outage costs versus 2004.

The first of 4 planned maintenance outages for 2005 began on January 8, 2005. Unit 3 is expected to be offline for approximately 60 days.

Turning now to the Power LP. Operating and other income of CAD7m for the 3 months ended December 31, 2004, was CAD2m lower than the same period last year. The decrease was primarily due to TransCanada's reduced ownership in the Power LP in 2004, and a lump sum recognition in the second quarter, of a previously deferred gain, resulting from the removal of the Power LP's redemption obligations. These gains were previously being amortized in incomes to 2017. Additional earnings from the Power LP's acquisition of Curtis Palmer and ManChief partially offset the decline.

Finally, in the corporate segment, net expenses of CAD3m for the 3 months ended December 31, 2004, compared to net expenses of CAD11m reported for the same period last year. CAD8m quarter-over-quarter decrease in corporate net expenses was primarily due to the positive impacts of income tax and foreign exchange related items.

Turning to cash the statement in our balance sheet. Funds generated from continuing operations were CAD1.674b for the year ended December 31, 2004, compared to CAD1.810b in 2003. The decrease was primarily due to higher current income tax expenses.

Capital expenditures, including the acquisitions in 2004 were approximately CAD2.6b including the assumption of debt. Approximately CAD2.1b of that is related to the acquisition of GTN. The remainder relates mainly to the construction of the [indiscernible] and GrandView power plants and as well as capacity in maintenance capital in the gas transmission business.

The majority of profit commitments were financed from the CAD1.7b in internally generated cash flow, and the proceeds of the sale of the assets to the Power LP. The remainder was financed by issuing notes payable and accessing the debt market.

Over the last 4 years, we have been consistently focused on strengthening our balance sheets so that we can act on opportunities as they arise. Today, under the equity method of accounting, our balance sheet consists of 59% debt, net of tax. 4% preferred securities, 2% preferred shares and 35% common equity.

To summarize, the Company's net earnings in cash flow combined with a strong balance sheet continued to provide TransCanada with the financial flexibility to make disciplined investments in its core businesses. We will continue to prudently reinvest our discretionary cash flow, and utilize our balance sheet strength to make profitable investments in natural gas transmission and power, when the opportunities arise to allow us to continue to create value for our shareholders. That concludes my prepared remarks and I'll now turn the call back to David.

Thanks Russ. Just before I turn it back to the conference coordinator, just a reminder, during the question and answer period, we'll answer questions from the investor community first and then open the calls to the media. As well, as I indicated at the outset, in order to ensure that Hal is able to address as many questions as possible, I would ask that you try and direct your questions to Hal first. We'll take 1 question and a follow up at a time, and rotate through the callers so that Hal -- so that everyone has an opportunity to ask their questions of Hal. Russ, Lee and I will remain on the line to answer any additional questions thereafter. But now I'll turn it back to the conference coordinator.

Thank you. We will now take questions from the telephones lines. [OPERATOR INSTRUCTIONS]. Your first questions is from Linda Ezergailis from TD Newcrest. Please go ahead.

Thanks. I'm just looking at your power segment results specifically, and I see that the overall results have been in line with guidance you provided in the Annual Report last year, that power earnings were expected to be flat year-over-year. Can you give us a sense of your expectations for how your power operations bottom line will do in 2005 versus 2004?

Well Linda we don't give that kind of an indication. We've got a lot of different things going on in our power business. We're generally optimistic about the assets that we're developing and the positions that we've got. We see power continuing to grow as a core power -- as a core part of TransCanada, but beyond that, I'm not prepared to give any specific guidance as to earnings or cash flow.

Can you give us a sense of what your views are, may be not so much on the assets, but perhaps on the operating environment that their operating in. For example, the markets in the western region are they -- do you see stock spreads improving, do you see power prices improving, what's your view in terms of outlook in the near to medium?

First said, I just observe in the west that the Alberta market place has been through a fairly significant deregulation in the last 5 years. There's a lot of things that have unfolded in a favorable way but some things, about the Alberta market has operated, then it's not been favorable to generators within that market place. We continue to make these points to the regulators and continue to work to strengthen our position in the Alberta place, but we think that's a process that's going to take some time.

In Ontario, we're encouraged that the Government of Ontario has chosen to go out under the clean power initiative and requests proposals from different parties. And we're an enthusiastic participant in that process. We see the Ontario market as 1 that will require significant investment in powergen facilities over the next 5 years.

We're quite pleased that we've developed a significant position in Ontario, we consider it a strong position and a good base from which we can grow. But beyond that, there are many elements of the commercial power markets, and/or the regulated power market in Ontario that remain unclear, and we look forward to further clarification of those from the Ontario Government and regulators. So, Linda we're happy to be in [SaltSea] Alberta and the Ontario market places, we recognize they're volatile and uncertain right now with respect to some elements of deregulation, but they're fundamentally sound markets, and ones in which we think we have competitive advantages.

In the North East U.S. markets we're quite enthused about the USGen Hydro Electric and we'd like to acquire Powergen's operations that are on the lower end of the cost curve and no better example of that than these plants that we're in the process of completing the acquisition in New England. Beyond that, Quebec progress continues well on the [Beckan Core project] and we look forward to doing more things under structured PTAs with Hydro Quebec in the Province of Quebec.

And just finally, with respect to the power market and I'll pass it on to someone else after this. Acquisitions of power plants, do you see the assets for sale as decelerating in terms of quantity and quality of what you look at, or what's your outlook on that?

No actually, we see this as fairly sporadic and unpredictable. That just about the time you start to think that all the good assets have been sold something else pops us. We have to be prepared to react fairly opportunistically the good situations as they arise, and there are very active periods and very slow periods. Linda, the power business in North America, it's so enormous and there are so many different kinds of powergen assets, for us it's a case of focusing on regions where we have -- we have a competitive advantage and trying to sort the wheat from the chaff and restrict our efforts going out there for really high quality situations. And I think USGen is a good example of that.

Great. Thanks Hal. I'll jump back in the queue.

The following question is from Matthew Akman from CIBC World Markets. Please go ahead.

Thanks. I wanted to just get your views on gas transmissions of what is happening for a couple of months. What's your outlook in terms of revenues and synergies, and in particular, what kind of timelines would you look at to achieve the full amount of synergies that you could have identified there?

Well I think Matthew there is a couple of different kinds of synergies. One is on the costs side where we are already assigned TransCanada's very deep basic of knowledge in things like pipe integrity, control of operating costs around gas turbines, any number of other areas like that. Corrosion control and prevention, metering expertise and similar areas where we are well on track to do that and that'll be a process that'll create value for us, over a 5 year period, as we implement those things. And introduce the TransCanada way of doing things, so I would add that with every acquisition we do, we also learn things from people that we acquire and that's why we've had very good discussions and very good collaboration with the GTN people that have joined TransCanada. And we welcome them to our Company.

Beyond that, we look at revenue synergies and the key thing, I think for GTN is to focus on the long term fundamental attractiveness of a pipe that connects to Western Canada supply basin, with markets in Northern California. We think that Northern California is a particularly attractive market for us, it's a relatively short distance apart, it has good markets in the Pacific North West along the way for that pipeline, and all of the fundamental and strategic reasons that compelled us to take a good look at GTN, in the first place, remain there today. So we see nothing so far that would cause us any regrets at all about having made that move. It is, as I said, the best of all the blue chip pipelines that we've looked at, and unquestionably the one that fits us, not only the TransCanada today, but as a integral part of delivery systems for northern gas in the future.

Beyond that, as to specifics around cost reductions and things like that, these are internal matters such that I'm just not prepared to discuss right now.

Okay. But just directionally, there are overlapping functions between that pipeline and your existing assets, that you would hope to address, over the relatively short term, would you not?

Yes. If you look at some of the other big pipe systems which have changed hands in North America, over the last couple of years, a lot of those involved thousands of miles of 10 inch pipe, or thousands of horsepower of old reciprocating compressors, these are not things that we bring along to the table.

The reason we're so attracted to GTN is that it's large diameter pipe is very efficient. It has the same kind of high horsepower jet engine turbine compression units that we use on our main line and our Alberta systems. It connects end to end with our BC system and right back into our [indiscernible]. It really is an integral part of the overall ship out from the Alberta Hub to markets in the western U.S. So, there are going to be an awful lot of synergies that we can take advantage of. But I would emphasize that a lot of them are going to be on the long term contracting and revenue side, as well as on the operating costs side.

Okay. Thanks, I'll get back in the queue.

Thanks Matthew.

Thank you. The following question is from Andrew Kuske from UBS. Please go ahead.

Thank you. Good afternoon. Hal, you made a comment about you're looking to increase your infrastructure portfolio and seize opportunities that create value longer term. Can you just give us a sense of what your preference is on an asset basis? Are you leaning towards pipelines as with GTN, or are you leaning towards power assets?

Andrew, when we looked at this 2 or 3 years ago, it was our expectation that there would be significantly more opportunities for us on the power side than on the pipe side, and we foresaw a migration of capital from pipeline operations towards power generation. Unexpected things happen and our views on that change from time to time. We didn't know, for example, that we would actually have the opportunity to complete the acquisition of GTN. And if we'd looked at our forecast back in 2002, it would've seemed 2004 was the year where we invested significantly more money in powergen than in pipes. In fact, the opposite turned out to be true.

So, our main focus is mainly on our 2 core regions of the west, Greater Alberta I like to call it, which extends quite a way south. And also Ontario, Quebec, New York, New England and what we might do in that particular area. The reason we're focused on those 2 areas is that we really understand the market place well, we understand the drivers on both gas transmission and powergen side. In the east, we like the opportunities for LNG as well as powergen, there's not a lot of new pipeline construction evident to us in either the east or the west in the next 3 or 4 years. Beyond that, we see significant projects related to the MacKenzie Delta and Alaska and to take that gas away from the Alberta Hub to markets in the lower 48.

But, I would confess we're quite opportunistic about this, and we generally don't know about the opportunities that are going to occur in the fourth quarter of 2005, until we probably approach mid year. That seems to be the kind of lead time we have on opportunities that will come up. And, as I said before, some of the very best things we've done in the last 5 years, have been unexpected situations that arose and our key strength has been able to evaluate these things quickly, get to the right answer and put the financing in place to get the deal done.

What's your expectation if we just look at the next year or so, as far as the breakdown between what you've got already, a pretty long list of green field projects and then potential acquisitions. How would you break out your capital allocation over the next year?

I can tell you that our capital allocations for, internally generated projects, is not exactly half and half, but certainly close enough that you could describe our internal green fields as being roughly equal between power and pipe.

Beyond that, it's very difficult to say, both in terms of some of the big green field gas projects, like LNG, we don't know the timing of when those things are going to go ahead. Those are uncertain projects in the North American context. We know, for example, that we're going ahead investing in storage, and we very much like the projects that we're pursuing there. We do foresee the kind of investments that's going to occur in Quebec. We don't know what the magnitude of our investment in Ontario will be, over the next 12 to 24 months, so I think that we're positioned very well in some really interesting arenas, and things have a way of coming up. Beyond the projects that we've already got on the books, I'm quite pleased with the potential projects that are teams are looking at today. Certainly, TransCanada's very much in the deal flow, not only in our western region and our eastern region, but also looking at bigger situations throughout North America.

I'd just like to comment on the potential for additional regions for TransCanada within North America. We're very focused on getting into regions where we can establish a significant presence and be a strong competitive seller. We're not about to head off into other parts of North America doing smaller transactions. A transaction of CAD100m for example, would not establish us in a significant way in some other regions.

So, while we are willing to look at things in other parts of North America, any move we make would have to pass a very rough test of significance, asset quality and competitive advantage for TransCanada. If those things aren't there, we're not going to do it. So, just to summarize all of that, we see opportunities which are more than enough and very attractive for us in our western and eastern regions right now. And our plans for 2005 and 2006 will be to [indiscernible] in those regions.

That's great. Thank you.

Thanks.

Thank you. The following question is from Karen Taylor from BMO Nesbitt Burns. Please go ahead.

Thank you. Hi Hal. May be we could just talk about Bruce for a minute. The fourth quarter results looked a little bit weak. Cameco said on their conference call, and in their release, that the contribution for Bruce next year, on an operating income basis, but before any sort of allocations and so forth, that for TransCanada or Cameco level would be slightly lower, or generally in line with it slightly lower than where we are in '04. So can you just tell me whether or not Bruce is performing, year to date '04 and given that outlook for '05 in line with your acquisitions economics?

And then I have a follow up.

Okay Karen. I'm going to make some general comments and then I'll ask Russ to add to them. First of all, when we go back and do a look back on how Bruce has performed since we got into it a couple of years ago, we're very pleased to be part of this. Not only is it generating net income for TransCanada on the current quarter-to-quarter basis, but it provides a extraordinary platform of growth opportunities for us longer term. And, I couldn't say strongly enough, the value that has accrued to TransCanada as a result of having the platform. Not only to restart things, like the first year, the A3 and A4 but also to look at a refurbishment of A1 and A2 and then to extend through Bruce, our nuclear capabilities as situations like [McGraw] and who knows where else that may go. We don't at this stage, have any other plans but it should be obvious to everyone that TransCanada and it's partners in Bruce are building up significant capability, and are building up our comfort level with what it takes to get these different projects done in a nuclear environment.

So, all told -- all in all, certainly from a financial performance perspective, we are comfortable with where we're at. We see opportunities to implement cost reductions and performance improvements, those things are always there. And we certainly see big opportunities for further capital investment and extension projects beyond the Bruce site. Although most of our focus is on stuff that would occur at the Bruce site. Russ.

May be just before you give it back to Russ. You said a couple of things in there that are interesting. First, it's contributing earnings. For [indiscernible] you're getting cash from -- you haven't disclosed it, you're getting non cash earnings and you're reinvesting all of the operating cash flow, earnings and otherwise back into Bruce. What's the net equity investment, Russ can answer that? So the issues, you're getting any cash earnings, when do you expect to get cash?

Well Karen, I'd answer that by saying that first of all, when we went into Bruce, we went into it because we saw significant potential to grow a nuclear business around us. The fact that we're not extracting cash from Bruce is really a discretionary thing. We did not have to go ahead with the restart of A3 and A4 and we decided to do that because [indiscernible] good opportunities to reinvest cash flow. Similarly, if we look at the A1 and A2 refurbishments we see them that way.

It's interesting, some of our investments generate a lot of cash but not much earnings, and people don't like that. Others generate a lot of earnings but not much cash, and I understand people don't necessarily get attracted to that either. To answer, it's a question of what is the quality of the reinvestment opportunity and we're very happy with the financial performance of Bruce, and with the nature of reinvestment opportunities that it's been offering us thus far. On balance, I don't think the fact that we're getting earnings that do not bring cash flow should be of concern to our shareholders. I think our shareholders should appreciate the significance and the quality of the reinvestment opportunity that we're getting at Bruce and we plan to carry on with that.

Well how do we value a situation where you're netting any cash earnings and cash flow? And I guess the other question is, that you said you're building or you're extending your nuclear capabilities through Bruce to potential opportunities, I'm assuming, to restart units 1 and 2 and then Point LePreau. I sincerely hope that you're talking about the Bruce Power capabilities and unless you've acquired some nuclear expertise at TransCanada. Have you?

No, we're talking about using the Bruce organization to do that. Although I would say that TransCanada has learned a lot as we go through this. But, make no mistake, we're not about to head off with independent nuclear operations at TransCanada. We're very committed to the Bruce structure and the Bruce team.

As to the evaluation difficulties, when we look at Bruce, Karen I fully appreciate that the regular and the sophistication with which we evaluate these things internally at TransCanada, is considerable. And we put a lot of people on the evaluation of all kinds of different power situations that are not easy to evaluate.

Well I guess Hal, what I'm trying to avoid, is this situation like Ocean State, where we've gone from a situation where you had enough PB of nothing in 1998. 2000 you acquire more, you make further investments and lo and behold, the market changes and you might have to take an impairment. But you've not gleaned any cash from Bruce at any point in time in it's history, and I don't know when you plan to take cash from it.

Then how can I be assured that the investment that you're making upfront is ever going to collected?

And I guess the question I'll leave you with and then Russ can answer and I'll let someone else ask. How much of your total invested assets are you prepared to have in Bruce, including the restarts of 1 and 2 and potentially through Point LePreau. What's your target in terms of your net equity at risk?

We don't have a target Karen for net equity at risk, but I think that our investments in Bruce are driven by our appraisal of the discretionary investment opportunities that are put to us. And, thus far, we're very impressed with the quality of those investment opportunities that are put to us, and there are no investments that we've made in Bruce, thus far, that we regret. So, we're quite happy with the investment in Bruce and, it is performing, it is generating earnings and we think that's important. We also see it as a significant platform longer term.

As to your deeper question of how to evaluate some of these uncertain situations. I'm sorry I can't answer that. These are complex situations. We're comfortable with the way we evaluate them and beyond that, I think the market will come to appreciate their value over time.

Let me answer your direct question. Current equity injection into Bruce right now is about CAD640m but I guess, if I was in your shoes trying to separate what's good and what's bad, I think you have to look at it incrementally as to what we invested. We put the original CAD400m odd into the facility. From a return perspective we made about CAD100m in '03, CAD130m in earnings this year.

But [rescues] not contained any of that [indiscernible].

Just let me finish Karen. And is, with respect to the incremental decision on the cash flow. You generate cash flow substantial cash flow, we chose to reinvest that into the restart of A Units 3 and 4. 1500 MWhs new generation that cost the partnership CAD500m or about CAD300m [indiscernible]. Incrementally we thought that was a very good investment.

The first investment has returned both earnings in cash. We expect the second investment will return earnings in cash as well as we go forward. We could've from an accounting perspective, taken the cash out and made the incremental decision to restart 3 and 4. From an accounting perspective we just left the cash in but it did generate substantial cash flow, from our original investment in the first 2 years. So, we made a very good investment, it's offset we think it's going to create more opportunities for the same kinds of good cash flow and good earnings type investments going forward.

Thank you.

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

Thank you very much. I'm just trying to understand, Hal what you're going to do going forward with Ocean State. Now it looks like you've bought that from Boston Eddison just under a quarter of the power purchase arrangement. My question would be, why only a quarter? And also, you talk about potential impairment charge of US$150m associated with the Ocean State plan. Is that the maximum amount of the liability under the gas contract, or is it possible that it's higher than that?

Maureen it's Hal. I'll make some general comments first and then I'll let Russ answer the specifics. He's been involved with this for a lot longer than I have and he knows it very well. First of all, when we look at Ocean State Power, I tend to think of it as 3 different businesses. There's a gas supply that we're entitled to and that has been very valuable to us over the years, and in which we're currently struggling with some arbitration decisions that have raised the price of that gas from below market to above market, and that's been a difficult thing for us. The second thing is the power outtake or the power sales arrangement of which the [Deco] Nstar is one of them. The reason, I believe, that the percentage is 25% is that's the portion that they owned, but I'll let Russ and Lee clarify that.

So we do have a commercial business surrounding the power outtake agreements, and that is a business activity in it's own right. The third is the operation of the facility, in other words, the transformation of natural gas into electricity, which thus far, that site was designed originally to operate as a base load facility operating for a high percentage of the available days in a year, we have a number of options with respect to that plant that we have to look at going forward. I would say that the one thing that we have been successful at is the significantly reducing the costs of operating OSP. We've done a lot to drive costs out of that, but there's significant uncertainty here, particularly on the gas supply side of my 3 legged stool that I just described to you. And I'll now let Russ made some comments about Ocean State, from his perspective.

I think that's a correct characterization. As Hal said, the 23% that was owned by Deco [indiscernible] Medicine was the last power purchase contract we had, but actually there's one smaller one left, it's a very small percentage of power buyers. We actually started the negotiation of that power purchase [bio] prior to the third arbitration and we're awaiting regulatory approvals and that's why there's a regulatory approval showed up in the fourth quarter, and that's when we closed the transaction. The gas supply agreements aren't related to those power purchase agreements, so what we did with Deco is the same thing we did with Eastern Utilities in New England Electric, to basically monotize the power purchase obligations and let them out and they paid us some money to do that. And in this case, they're going to pay us money over time to be relieved of that obligation. The gas supply, your question on whether it can be greater and less than CAD150m. The CAD150m is just our book value at the end of December.

The value of the plant? Right Russ?

It's the net book value of what's left at the plant. It wasn't meant to give you an indication of where we think the impairment charge would be. The facility still has value in the market place. Outside of the gas supply contract, and so it's a combination of that value plus the value that we've lost in the gas supply contract that will determine what, if any, ultimate write down they'll be. So all we really want to do, is highlight to the market place would be the significance of the change in the gas price. The gas price that we had historically at the facility landed gas at essentially a discount to market. And now we've swung all the way to the other side and the reason for that discount from our perspective obviously, as Hal pointed out, is the facility is supposed to run base load and the way they run base load facilities is you need a supply of fuel that competitive with other market fuels.

That, through the arbitration process, has changed to a premium to gas market prices which, obviously put us in the position that we have today. So we can't run the facility essentially as a base load facility any more, and that's what causes the potential impairment. So, it wasn't really to give you an indication of where that write down will be, if there is one, it was more to give you all the parameters around it. But, just from my perspective, I wouldn't think that any impairment charge would be greater than the book value of the facility.

Well this is to clarify, if let's say, you were to sell the plant without a gas contract with no PPAs but say you sell it, and you sell it for CAD10, in other words, you give it away. Then you take US$150m impairment on the sale of the plant, you still have this negative period until 2011 on the gas contract. Can you, from an accounting perspective then, take an impairment charge on the gas contracts based on the net present value for whatever that is?

No. I don't think so.

You can't. So you have to have that negative carry going forward?

Potentially. And I guess the question is whether it's going to be negative, but I think theoretically, you're on the right track, is that we couldn't take an impairment charge on a -- an out of the money gas contract.

Okay. Thank you.

Could I -- it's Hal Kvisle here. I'd just like to interrupt for a moment. I need to depart for an important meeting. I'd like to thank everyone for coming today and I apologize for leaving soon. I'll guarantee to you that I will be available for as long as you want me, at the conference call at our next meeting, which is in just a month, I think David? So thanks everyone and again I apologize for having to leave early.

With that, conference coordinator we'll just continue on with the questions, and as I mentioned earlier, Russ, Lee and myself will be here until we get through all of the questions.

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

[indiscernible] just missing out. A question I really have for you Russ would be that, under the regulatory issues. There's still a lot of issues out there, we see a competitor Embridge pushing for the northern line, seems to have some backing from at least 1 major gas producer. Do you think the issues are somehow related that some of the ill will on some of these regulatory things and appeals, are starting to impact other businesses? And if so, what can you do to change that around?

I guess I wouldn't -- I don't [indiscernible] actually think the 2 issues are attached. The issues with respect to the north are tied to, what I would call, our views of our historic rights that are tied to the NPA, and others views that would suggest that those aren't as strong as we have. The Federal Government has come out and said that they understand what the differences are between the parties and have put in place a process to determine the validity or not of those rights, and I think that if both sides are happy to see that process move forward.

So I think if you want to call it contentious positions of the parties are related to differing views of history, and I don't think that they're related to our efforts in the regulatory forums. In both EUB and Alberta which are more tied, to what I call, current rate of return issues is, there really not a connection between the 2.

Okay. It is more than just the NEB versus the NEB because if producers were very happy and supportive then it is like you have the best project then nobody else be there with another project.

I think that you will be over-simplifying the process. Obviously their position, you know, whilst it isn't solidified yet as well, they have royalty discussions they have to carry on with the Alaskan government for right of way access issues. There is a number of very, very complex issues which our issue is only 1. I wouldn't suggest for a minute that it is just NEB versus NPA. But with respect to the Canadian side of the border, that's 1 of the major I guess critical path items for them. But they have several critical path items in Alaska yet to get over. Obviously the Alaskan government allowing us both to make applications under the Stranded Gas Act, you add to that complication obviously.

So there is a number of issues that need to be worked out between TransCanada and other parties and between other parties and the various government agencies.

The guy who was around for the first co-round back in the '70s, and seeing a lot of money spent and wasted or written off through the regulatory proceedings, I am certainly supportive of not going through that again.

1 other question on the OSP. Are they cash flow negative at this point in time?

No. I'm just looking around to make sure that I've got the correct answer. But yes, they're not cash flow negative at the current time.

Thank you very much.

Thank you. The following question is from Anatol Feygin from Banc of America Securities. Please go ahead.

Good afternoon everyone. If I could take a few minutes on the Ontario power market. One of the things that happened I guess in the fourth quarter at Bruce was that $26m was spent on a study to reactivate units 1 and 2. I was wondering if you guys could give us a little bit of color on what you see as the developments there. Presumably these studies were operational as well as market based. What do you guys see in the market going forward? How does the retirement of the coal generation that's scheduled to happen later in the spring going to affect it? And also how do you think about committing incremental, substantial incremental capital to more low cost base load nuclear and simultaneously the combined cycle of gas facilities that you guys are pursuing? Kind of if you could triangulate that for us as well.

I'll do my best. First of all just clarity on the costs that we spent on Bruce. We spent a total of I think it was -- you might have picked that up from the quarterly. But we spent $16m in total as the partnership. $10m of it was spent in the fourth quarter. So $6m was spent. Basically that money has been spent for the most part on engineering work. Not market studies. It's based on trying to determine what the feasibility of the restart of those late reactors is. Whether it can be done and what the cost of doing that will be. We've sort of capped the cost around that level. We don't expect to spend a whole bunch more in determining that.

All the other factors that you mentioned, so that covers what we can do and what it would cost us to do it. Then we have a -- we can then position that in the market place in discussions with the Ontario government.

The Ontario government has appointed a special negotiator to talk to us about the restart of A and those discussions include what are the government's intentions around the shutting of coal in 2007 or 8. What kind of market they expect to continue to have going forward. What kind of wholesale market? Can we depend upon that wholesale market? How large that wholesale market will be?

This next tranche of power won't be low cost power generation as the first tranche of power generation we had. It will be substantially higher cost. So our willingness to take risk is far less and so we will have far less dependence I guess on market prices if we were to move forward with the 1 or 2 restart.

Obviously there is market uncertainty, as you pointed out. And as well, our costs are going to be a lot higher.

So those are sort of the I guess the major points of discussion with the Ontario government. At the same time, to complete the triangulation if I can, is the government has come out with an RP if you will for clean power initiatives of which we think we have some very good projects. That fits into their supply demand forecast, the timing of the shutting down of coal, where nuclear is going to fit in in that plan. So they've got sort of a number of data points coming into them. The data points with respect to our negotiation around nuclear generation at Bruce Power. They've got information coming to them with respect to the coal plants, the cost of refurbishing the coal plants, the cost of cleaning up the coal, the cost of shutting them down, the availability of gas fired power, the availability of demand side management. And once they have all that data then we expect that they'll make some decisions.

What we're trying to do is be as constructive as we can on the fronts where we can help them. We think those are -- you know gas fired generation and at Bruce. So we're just trying to be constructive and help them along in their discussions.

But I would say no decisions have been made yet on our side and no decisions have been made yet on their side with respect to moving forward on any of those initiatives.

Thanks Russ. I guess shorter term the question I have is without the monies being spent on feasibility studies, presumably that has been concluded and now you're in this kind of commercial negotiation period. And with the stack losing some coal generation, the dispatch curve pushes us into coal, gas and oil fired power which presumably would push up the market prices and would be a net positive for Bruce. And yet you guys seem comfortable with saying that '05 is going to mirror '04 performance.

We haven't said anything yet with respect to our expectations. I think that the market place has heard Camaco's views that it will be flat to less.

But I think a good chunk of that view is based on their view of future power prices, which we said we don't provide to the market place. Our view of power prices is likely to differ from Camacos.

Okay. Right. Thanks for your time Russ.

Thank you. The following question is from Andrew Fairbanks from Merrill Lynch. Please go ahead.

Thanks. Good afternoon Russ. I'm just curious. In the past you provided some of your outlooks on overall gas production and transportation in the Western Basin. I wondered if you just had an update for us on that outlook. Do you see it as something that's relatively flat or gradually declining in the Basin until we do get Alaska and Mackenzie Delta gas? Or is your view that there is enough organic filling going on in piped gas that leaves a little bit of a bounce over the next year or 2?

Then further to that, just curious, also your latest views on organic reinvestment opportunities in that system. Do you see enough oil fanned development and the need for some natural gas spurs to have a meaningful impact on the infrastructure there? Or is that just all basically going to be rounding here?

I'll start with your first 1, answer to that. I don't think we're expecting any sort of bounce out of the Alaskan Sedimentary Basin. I think our view would be flat to potentially declining a few years out. And I don't see that changing until the advent of Northern Gas and I guess our hope would be is that that gas connects to our system some time in the future.

With respect to organic growth, obviously on the mainline system I would say that there is almost nothing. In Alberta there will be statistical sort of high ends that we have every year. But that won't amount to anything large either. You know $100 to $150m is about all I would say we could expect at the high end on those over the next few years.

So organic growth for our wholly Canadian pipeline systems I would say it would be very minimal in the next few years.

I guess just as a follow up to it, do you have a sense, or sort of gut instinct on what the potential might be for some additional power gen projects as the orders [indiscernible]?

I think there is potential obviously. There is a huge thermal requirement and so we're looking at that. With the price of natural gas at $6 [indiscernible] capacity for meeting that thermal energy. $2 or $3, that might make more sense. There is a lot of coal in the province. That may make more sense as an alternative to generating that steam requirement.

There is -- there will be a large thermal requirement. I'm just not sure if gas is the best candidate when gas prices are so high.

That's great. Thanks.

Thank you. The following question is from Charles Matthews from Financial and Investment Corporation. Please go ahead.

Good morning. With regard to the Northern Pipeline Act and the quarrel with Enbridge over whether it should be a regional project or not, what is the projection on the Canadian Cabinet's decision on this matter? And if it was adverse, would you vigorously contest their decision in the Courts as far as a negative decision would be? Thank you.

Well I think that first of all we don't have a dispute with Enbridge. We have differing views in the market place. We've operated under the NPA for several years and continue to think that we can continue to operate under that in the future.

I guess I wouldn't want to provide any speculation as to where the Federal Government will land. Nor would I speculate on what our reaction over that will be. We will have to see where they land and what that outcome is and then we'll assess our options at that point in time.

A further question. With regard to Alaska, it appears that quite a number of years ago Yukon Pacific, a subsidiary of CSX spent 10 or 15 years getting licenses and permits to go from Prudhoe Bay to Valdez. But lacks any kind of an agreement with the owners of the energy up at the North Slope. Now the State of Alaska is very much concerned about keeping some of the gas within the State of Alaska for its own industry and expansion. Do you have any conversations with the State of Alaska on helping them with spurge from Delta Junction to Valdez or on to the Anchorage grid?

I think that the -- I'm not familiar with the first group you're referring to, or what they spent or what they've done.

With respect to indigenous requirements for gas, I think the Alaskan government has made their position on it that they would like some of that gas to stay in Alaska and have asked to structure a project that would allow for those kinds of uptakes. And we would design a project in accordance with what their requirements and needs were.

Just a last question. I notice you're getting into the LNG regasification business or applications. Would you be in any position to help the State of Alaska if they sought to bring LNG production in the city of Valdez?

It's not something that I'm aware of that we've discussed with them. Certainly we have those kind of capabilities. But it is not something that we have discussed actively with them at all.

Thank you.

Thank you. The following question is from Winifred Fruehauf from National Bank Financial. Please go ahead.

Thank you. With respect to TGM and North Baja Pipelines, what was the contribution in the fourth quarter 2004 from the latter? From North Baja Pipeline.

I think the numbers would be negligible. Do you know what the number was?

Yes, probably Winifred I'm going to say it's a $1m rounded from North Baja.

Okay. And in terms of run rates, is there any guidance you care to offer for 2004 for the remaining quarters for both TGM and NBP?

In terms of run rate for the--

Contributions. Yes, the contributions to earnings.

I would say that we're probably -- what you've seen is probably what you'll get. They're going to be pretty close to where we are right now.

That's because of the fixed price arrangements?

I'm not sure what you mean by fixed price arrangements.

Well the fixed tolls I should say.

Yes, in terms of throughput and revenue collection if you will, we don't expect that it's going to be very much different than it has been in the fourth quarter.

Just 1 thing to add to that Winifred. I think that with some of the amortization of our purchase price discrepancy, we're probably on a run rate basis, the $14m that we showed for the 2 months is probably $1m or $2m higher than we would actually expect going forward for the full 2005.

That's somewhat a little bit less than that for the run rate for 2005. But that's the standpoint.

That's because of the amortization of the purchase price discrepancy?

Yes.

That's only in North Baja Pipeline?

That's actually on both.

On both?

Yes.

What is actually the purchase price discrepancy on each of them?

So on the TGM system?

Yes.

It's about $530m and that will be amortized over the life of the related PP&E. And on the North Baja system, we recorded some goodwill of about $14m, which obviously is not amortized.

We also had, because they have a substantial amount of gas coming due, it's a fair value adjustment on the gas which will actually create a little bit of income. A little bit of earnings in the first half of 2005. So that's why I'm saying on a run rate basis you're probably a little less than the $14m that you have for the first 2 months because that amortization runs out. It [indiscernible] but the water runs out in June 2005.

What do you expect the final book value of your investment in North Baja including the $14m of goodwill?

I'm going to get back on that 1 because the number I have has both GTN and North Baja together in the analysis that I have. We will get back to you on that number.

Yes, fair enough. Thank you so much. That's all I have.

Thanks Winifred.

Thank you. The following question is from Sam Kane from Scotia Capital. Please go ahead.

Just for further clarity on your study on Bruce A1 and 2. Is there any more spending to occur in Q1 '05 above and beyond the $10m?

And secondly, is the Point Lepereau study that's underway now, was that also embedded in the $10m?

I don't expect there will be any material amount spent in 2005 on the 1, 2 restart unless we come to some resolution or conclusion with the Ontario government.

And with respect to Point Lepereau, those costs are not included and there could be some expenses of cash to Point Lepereau in 2005. We haven't commenced the significant due diligence and that would be supposed as having some sort of MOU arrangement with them, which we don't have yet. So we wouldn't spend large dollars until we have some commitment.

Okay. Getting back to OST. $16m pre-tax, that was all embedded in Q4. Is there any lingering effect into '05 of that particular restructuring transaction? That's [clean investment]?

No, that was just effective April 1, 2004 if I remember correctly.

Sure. And just for the year 2004?

Correct. We do not expect to see that further bump going into '05.

Okay. Seasonality. I guess Ocean State is going to become more seasonal. Can you help us with how much it did run in Q4 in terms of utilization and capacity?

I don't have that number and I guess with respect to making predictions on seasonality, I wouldn't want to sort of make any predictions until we get through the next arbitration as to how often that facility is going to run.

Okay. Then how much did it run in Q4?

I don't have that number.

Okay. Shifting to another 1. You did mention the amount the MacKay River had those slow performance start up offering cost adjustments. What was the significance?

Yes. You might have hit the nail on the head there.

What's that? Okay. Lastly, a broader question. Given the nature of your US investment [regime], I'm a little surprised to see that you're indicating $300m, 5.1% issue at January. I presume that's all your debt incrementally geared for the next foreseeable future should be US dollar related, shouldn't it?

That last issue is for the most part for the Alberta system. Essentially what we do is we look at -- we do look at our US investments as well as our US GAAP position and try to keep it relatively in balance. But what we mostly look for is where we can get the best rates and to the extent that the US is offering better rates, for example, which we've done historically. Then we'll swap back into Canada. It's where we can get the best deal in the market place for the most part.

Okay. Thanks a lot.

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

Thank you. With respect to the review and variance request by cap on the main line phase 1 decision, what would be the impact on earnings if they were to be successful in that?

I don't have that number Linda. But it's a number that we can get for you. I think it is at least a number in their application. But it was with respect to the similar kinds of costs that were disallowed in Alberta. So I'm guessing it would be a similar kind of number. But I'll get either Lee or I or Dave will get back to you on that.

Okay. I appreciate it. I guess just further to your mention of the Alberta decision, what was the reason -- I mean I guess part of the reason you dropped your appeal of that aspect of the disallowance was that you were hopeful you could get some sort of negotiated settlement for 2005. But how similar are the arguments for and against, including those long-term compensation costs etc. in Alberta versus the mainline level?

Let me just clarify. We didn't drop our appeal. What we did is we suspended the appeal because you only have a certain timeframe to make the appeal. So we made the appeal. But the avenues available to us still in Alberta are to apply for a review and variance from the EUB, which doesn't have a timeframe on it.

Okay.

That would be probably our first step before we appeal it, would be we would request review and variance. And secondarily, we are trying to negotiate a settlement for 2004 and years beyond with the shippers on the Alberta system. So that appeal will sort of stay in advance until such time as we come to conclusion on those other avenues.

With respect to the argument, they're identical in both situations. There, for the most part, are long-term compensation costs which we would argue are prudently incurred. They're benchmarks against competitive market alternatives and against our peers. And I guess what that dispute is, the characterization of them. Most of them are long-term incentive costs which include essentially share units which most companies include in their compensation. And the dispute has been whether or not compensation in the form of shares of any sort is in the interest of shippers given that the only way that those pay off is if the shareholders win. And I think there is a belief that that's detrimental to shippers. The National Energy Board saw through that argument and said that it's competitive compensation prudently incurred and competitive to the extent that there is conflict that those conflicts can be dealt with -- between shareholders and shippers can be dealt with through codes of conduct. Alberta ruled in an opposite fashion saying that those costs couldn't be incurred because they weren't in the interest of shippers.

As I said, our belief is that they're prudently incurred and are required in order to attract the people that we need to attract to operate the system in a safe and reliable way. So we just -- similar tacks. 280 degree opposite decisions.

Okay. Just further to I believe it was Win's question with respect to the purchase price discrepancy on TGM and Baja. Is the $530m, is that Canadian or US dollars?

That's US dollars.

Okay US dollars. Because you allocated $40m to goodwill, does that mean on Baja there was no allocation? There was no premium to the book value allocated to PP&E?

Yes, so let me just make sure. North Baja had the goodwill that we allocated. The $40m. I believe there was a very small allocation to PP&E, but it was not significant.

Okay and then we saw on your Bruce Power acquisition that you amortized some out-of-the-money contracts. Are there any other amortizations at TGM that we should be aware of similar to what happened at Bruce?

So I think the 2 issues will be what is the amortization of the $530m.

Okay.

That was allocated to PP&E and as I said, there was some fair value adjustments to the long-term debt. The majority of that does run off through the first half of 2005. There is a very small lingering impact after that.

Okay.

So I think those are the only 2 that I would be aware of. And goodwill of course which is not amortized, which we will adjust every year.

Okay. So no out-of-the-money contract?

No.

Okay. I'm sorry, I seem to have missed the fair value adjustment amount on the debt?

It was about $28m. About $23m of that will actually flow through income and probably about half of that flows through from November 1 to the end of June. The remainder runs out over a very long period of time.

So the $23m is roughly all in 2005 any of that--?

No. You will see probably about half of that between November 1 and the end of June. So you've already seen a little bit of it. And the other half of that will actually stretch out over probably 5 or 6 years. A very small amount going forward.

So then the November/December amount would have been kind of straight line over the period out until June '05?

Yes. About half of it, yes.

Okay. And then final question. At your corporate level prospectively, can you give us a sense of run rate or at least effective tax rate? Should we expect to see continued benefits associated with foreign exchange and income tax benefits?

Well I think clearly on the foreign exchange 1, I mean that's really a question of where the rates go. So I mean I'm not in a position right now to forecast obviously what that will look like for 2005.

On the income tax adjustment, those really are things that have come up as we go through the year based on where we get to with various tax agencies etc. So that 1 again is really hard to forecast.

Excluding those items, I would think that going back actually to '03 and looking at the corporate segment, is probably a fair picture of what I would expect and what you saw in '04.

Bottom line?

Bottom line.

Okay and then maybe can you elaborate a little bit on what was the nature of the income tax benefit in the fourth quarter?

It was actually or 4 or 5 very small items that probably not worth characterizing. These are realities in the full year. The amounts really related to refund as we noticed in Q1 I believe it was, as well as utilization of certain non-capital loss carry forwards in Q3. The amounts in Q4 individually were very, very small, would have the same kind of major.

Alright. Thank you.

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

Quickly, I've a question on Bruce I guess for Russ. The guidance for 2005 operating rates was down I guess a few hundred basis points or something relative to the guidance when you guys bought the plant. I'm just wondering whether you still have confidence that these plants can get up to more like the 90% capacity factors that were originally projected?

Yes, we're still on track for that and that's 1 of the places where the capital is being spent today is to allow us to get up to those kind of rates. So I think we're still confident that that's still our target.

The 87% versus 85% is really balancing around of maintenance.

How soon could you see the units getting to that level?

Probably not something we've provided the market place at the current time. Something as we get more confidence as to when that's going occur, we will certainly do that. At this point in time I don't want to make any predictions.

Thanks.

Thank you. The following question is from Karen Taylor from BMO Nesbitt Burns. Please go ahead.

Just a follow up quickly on the Ocean State $16m. That really is the net present value, the benefit of that contract to you amortized over the period from April 1 to December 31?

No. Essentially Karen, As Russ had mentioned, we're going to be receiving payments from Boston Edison over time. Essentially what happened is in 2004 the amount of those payments at a run rate is higher than it is going into 2005 and forward. So really it's just [indiscernible].

I misunderstood your answer for [standards]. The $16m then is not all attributable to the fourth quarter and a [final] reallocation?

It's related to the three quarters beginning April 1.

Yes and $5m then roughly a quarter for how long?

Because of the decrease in the payment time of that negotiated deal with Boston Edison, I would say the end of '04 is about the end of where you will see the additional $5m.

The payments then actually go down from there.

So I'm sorry, you just backtracked again. So are we expecting any contribution then from this contract or payments of the contract in '05?

We are expecting payments but you will not see the same sort of 1 time incremental earnings that you saw in '04.

Right. But you will get something?

Yes.

And how long will that something continue?

The 4 payments that I understand Karen will actually be realized all the way. So I believe it is September of 2011.

On a declining basis.

On a declining basis.

On a declining basis it is about how much per annum?

Right now it is my preference at the current time is given that all of these are factors in the arbitration, or at least they've been made factors. We don't necessarily agree that they should be factors. But all of this sort of what I call commercial information has been brought into that discussion and prefer not to talk about it until we're through that process.

Can you just -- because the performances from both the West and East are weak. I know from speaking to David about Ocean State previously that you're also going to be working at changing reporting '04 hopefully. So maybe we could just take a look at the Western. How much of a deviation resulted from the operating cost adjustment at MacKay and how much of a deviation is seen from the lower [sea] rates? Lower slight sea rates in the market?

Well Karen I'll try and answer that and Hal can add if he wants. So in the news release we refer to the $6m difference in fourth quarter versus fourth quarter last year. That $6m is sort of evenly spread between the ManChief sale, the MacKay River adjustment and the lower price, lower margin.

So about $2m each Karen.

Okay. That amount is today. Your portfolio percentage of the contract in Western Canada, you don't like to talk about this stuff. But the returns in these segments keep going down. So can you tell me how much is subject to a long-term forward PPA for '05? And how much was that in '04?

I have the '05 number Karen. It's just over 80%.

I'm sorry, 80% forward sales?

Correct. For the West.

Okay.

I don't know that I actually have in front of me the '04. We'll have to get that for you.

I'll get the '04 number for you Karen.

Okay. And make sure I've got everything. The $39m again for cumulative reduction in corporate expenses, is that evenly distributed between the tax and the foreign exchange?

This 1 is not evenly distributed. Just 1 second Karen, just let me grab a piece of paper here. So of the $39m, approximately let me say half of that almost is related to the income tax differentials. The foreign exchange is somewhere around $7m after tax. I think we said in the third quarter, the business restructuring provisions was $12m after tax.

Yes. Sure. Thank you very much.

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

Russ, the $16m I guess $10m relates to previous quarters. But that's a before tax charge. What sort of effective rate would you put on that?

Yes, about 35% Maureen. I believe the after tax number was equivalent of about $10m.

Okay. And also just to confirm the ROEs on the system. The mainline and the Alberta system. I have the mainline over earning by about 50 basis points - 10.06. Is that your belief?

Yes. I believe that's pretty close Maureen.

And then--

It's not the exact word that I would use is over earning. But--

Yes I agree to the 10.06. The calculation.

Okay. On the mainline, TransCanada has backed away it looks like from the formula. But it is continuing to look for 40% common equity component. Is that correct?

That's correct. It's not that we've backed away from the formula. Is the only way to cap the formulae if you will in the current proceeding through a review and variance application. And we didn't think that was going to be fruitful. So the only way I guess to get at total return on capital was to make an application on the equity thickness.

Okay.

That was the only thing available to us in 2004.

Okay. So that is still outstanding for 2004 and will carry over until 2005?

Correct. We expect a decision I hope sort of by the end of Q2. We expect the current Hearing will wrap up. This is actually wrapping up this week and then sort of 90 days after that we would expect a decision for cost of capital for 2004.

Okay and then if I'm doing the math correctly, for the Alberta system and presumably because of the disallowance, the earned ROE was 9.28% approximately?

Yes, that's correct. That's correct Maureen. I would agree with that.

And just, I hate to come back to this Ocean State situation. But I guess I've never really fully appreciated what exactly is going to arbitration here with respect to the gas contract? Is it interpretation of the wording in the contract? Is it interpretation of an index? Can you go into that?

I'll do my best. Basically it is interpretation of the arbitration provisions in the contract which were put in place at a time when there was different indices in place. And sort of since deregulation those indices have gone away and the way that the facility operates in the market place, the whole mismatch the way things were dispatched 10 or 15 years ago has changed. So a lot of those market changes weren't calculated in the contract and I guess the dispute would probably be around is how those changes impact the pricing arbitration provisions going forward.

Okay. So the indices have disappeared. Presumably the parties are looking at different indices and the interpretation of the wording in the absence of what was written into the original contract?

Yes. It is obviously the parties have different views. We have our view that it is perfectly clear and the other party it is perfectly clear from their perspective. So I think that the fundamentals for us is that this facility was built to run base load and at the gas fired plant in this market place. In order for that to happen it needs a certain gas price. So we think that that's fairly fundamental and that's the reason we believe that we need to go back and arbitrate this again. Because some minor changes in the calculation caused the gas price to swing from premium to discount. So what we intend to do is to try to change those minor adjustments I guess if you want to call it that.

Okay and just to clarify what was said previously and I think this is right. That with the restructuring of the Boston Edison agreement there are no power purchases -- sales associated with the plant?

There is a very small 1. I think it is for something less than 5%.

Okay and just again for clarification - this is my last 1. The purchase price discrepancy is about $28m. $23m flows through. Half of it will be amortized until the end of June of 2005.

Correct.

So okay and evenly. It's a straight line. It's a straight line calculation?

Correct.

Okay. Thanks very much.

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

Just a follow up to Win's question on GTN and certainly looking out for the year. In terms of -- you talked a lot about the earnings. Cash flow, is it just the depreciation and the amortization and if so, what does that total to get the cash flow number?

From GTN Bob? Just for this?

Yes, just for GTN.

Okay. Yes I will have to get back to you on that.

Okay, no problem. Thanks.

Thank you. The following question is from Winifred Fruehauf from National Bank Financial. Please go ahead.

Thank you. My question relates to page 11 of your release and the terms on your definition of availability. Are you defining availability as being synonymous with capacity factor? Or is availability meant in the sense of the plants having been available for 72% of the time?

I'll start that 1. Actually we do define plant availability on page 12 from the way we're looking at it. It's in the table on page 12 under weighted average time availability. Footnote 1 actually is our definition.

So is that different then from capacity factor?

No, nothing. No it's not Winifred.

It's not. Okay. The portion of the Bruce output that you have locked in under contract, I take it the average price of these contracts exceeds the $47 that we saw in the -- in 2004?

No, it doesn't.

It doesn't.

No, the installment per day would be less than that. That was part of the rationale for some of those adjustments on consolidation with regards to out-of-the-money contracts at the time we got into Bruce. So no, those contracts are not at rates above $47.

Another question. Can you tell us what they are on average?

I think no. I think if you go back though to December '02, I think we were looking at prices at that time, or I had indicated that I think we gave an average sort of rate that was in the $42, $43 range was my recollection. Now that's not to say that was a specific number for each of the years going forward. But that was sort of what we had indicated at the time.

Yes. That's my recollection to but I just wanted to be sure that is indeed correct.

Yes.

So you're really then sort of at the mercy of the Ontario wholesale spot price?

I wouldn't say at the mercy. But the bulk of our output will be sold until such time as we have yes some operating history with units 3 and 4 and some clarity on how the market is going to sort itself out. And what we may or may not include in a long-term PTA with the Ontario government. Whether that includes just the A1 and 2 restart units. Or A3 and 4, or the balance of the Bruce B. All of those things are currently subject to discussion.

What is the average remaining term of your fixed price contract? What's the remaining term?

I don't recall. But I think that it probably goes out another 2, 3 years would be my guess. If it's different than that Winifred, we'll give you a call. But I think it's sort of that kind of timeframe. It's not long, long-term.

Okay. Then I have 1 other question. Can your foresee a situation where OPA would contract say for units 1 and 2 if you bring them back at a price that is different from the original Bruce units that you leased plus the additional units that you have brought on line? And if so, does that create problems for you?

As I said all of those are the subject of current discussion. Obviously bringing on 1,500 new megawatts of power into the market place and if the balance of the 4,500 megawatts is still subject to market, that could have a detrimental impact on our 4,500 megawatts. It's something we're very concerned about.

Right.

So we want some clarity on how that's all going to work. How the market place is going to work and what of the balance of the 4,500 we may contract. So I would say you've highlighted what our same concerns are and those are concerns that we've brought to the Ontario government.

Okay. Thanks very much.

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

Very brief. GTN, the debt associated with GTN that you've acquired, the $14m that I assume is subtracting the interest cost of bad debt against your $14m number?

Yes.

Okay. Thanks.

Thank you. This concludes the financial analyst question session. We will now take questions from the media. [OPERATOR INSTRUCTIONS]. The first question is from David Sim from CBC News Business. Please go ahead.

I have a feeling this was a held question but I'll ask it anyway. Would you like to, or would you be entitled to take a shot at building an All Alaska route?

Can you say that again?

Would you be entitled -- Would TransAlta have an interest in, or be able to take a shot at building the All Alaska route, the L&G route?

If you're asking whether we have the -- first of all we're TransCanada.

Sorry, TransCanada.

That's okay. Do we have the capacity? And I would say yes we have the capacity to build the line from Puerto Bay to Alberta.

No to the South Coast of Alaska. For the L&G transshipment.

I'm not sure what your question is. We haven't, as I said, we haven't have had any discussions in that regard.

So it's not something that you would look at? I mean as deposed as I understand it, but I'm not sure it is something you could play in.

It is not currently part of our focus.

Alright. Thank you.

Thank you. The next question is from Claudia Cattaneo from National Post. Please go ahead.

Hi. I just wanted to ask a couple more questions on this NTA debate. First of all you said that there is some kind of a process underway in Ottawa to look at the merits of the 2 systems. That is the NGA system versus the NEB system. I just wondered if you could expand on what that process is all about?

Secondly, when do you expect a decision from Ottawa? I guess I would like to find out also whether you're proposing to build this entire line. I mean I thought it was a $20b line. Can you handle it on your own?

Claudia it is Robert Dann, the Vice President of Government Relations at TransCanada. I'll respond to your Ottawa question. Russ can answer the portion on the entire line.

You had seen the interventions from some other parties with respect to the potential validity of the NTA. Our position as stated by Hal is it is valid. It has been valid. We have expanded the system 5 times under the NTA, the most recently being in 1998. We are very confident that it is going to provide the regulatory certainties that the producers are looking for.

If you look at the firmness of the assessment that was initially done and the associated benefits that accrued to Canada, that very unique outcome was actually moved the government of Canada to enshrine this within an Act of Parliament. So our discussions with Ottawa to this point have simply been you have relied on it. We have relied on it and what the market place is looking for is the certainty and we've asked them to make comments so that the market does understand there is a mechanism in place.

Okay. When do you expect a decision?

Well at the moment we've been talking, as you know, as Hal commented both in Ottawa and the Minister [Effert] has, when he was last in Calgary, indicated that it is his preference. And I don't particularly understand the macerations of the Federal Cabinet and the Prime Minister's office, but we would expect it will be clarified this year.

Okay. Thank you. What about with respect to building this whole line? Is that what you are proposing?

That is not what we're proposing. What we said is that we are -- what we would like to do is build the pipeline from the Canada/US border to Alberta under the NTA as was originally envisioned 25 years ago.

With respect to the Alaska portion of the pipeline, we have certain rights and certificates in Alaska as well. And what we've said is we are willing to share those with anyone who wants to collaborate with us to build that section of the pipeline. To the extent that we've said that we don't need involvement in that section of project if we're confident that it will get build from Puerto Bay to the Alaska/Yukon border. What we've said is we will just help facilitate that.

But to the extent that the Alaskan government wants us to build that portion of the line, we're totally willing to step up to the table and we do have the capacity to do that.

Certainly our intent is to work as collaboratively as we can with the government, the aboriginal groups and most importantly, the producers who own the gas in Alaska.

Okay. 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.

Thank you very much. Just like to thank everybody for the participation this afternoon. We appreciate your interest in TransCanada and we look forward to speaking to you again in the near future. Thanks and bye for now.

Thank you. The conference is now ended. Please disconnect your lines at this time. We thank you for your participation and have a great day.