TC Energy Corp (TRP) 2003 Q4 法說會逐字稿

Good afternoon, ladies and gentlemen. Welcome to the TransCanada Corporation 2003 fourth-quarter results conference call. I would now like to turn the meeting over to Mr. David Moneta, Director of Investor Relations.

Good afternoon, everyone. I would like to take this opportunity to welcome you this afternoon. We are pleased to provide the investment community, the media, and other interested parties with an opportunity to discuss our 2003 fourth-quarter 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 to start this afternoon with some comments on our results and other general issues pertaining to TransCanada, and following their opening remarks will turn the call over to the conference to the conference coordinator for questions. During the question-and-answer period, we will accept questions from the investment community first, followed by questions from the media.

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. The results or events predicted in this information may differ from actual results or events. Factors which could cause actual results or events to differ materially from current expectations include, among other things. the ability of TransCanada to successfully implement its strategic initiatives and whether such strategic initiatives will yield the expected benefits; the availability and price of energy commodities; regulatory decisions; competitive factors in the pipeline and power industries; and the prevailing economic conditions in North America. For additional information on these and other factors, see the reports filed by TransCanada with Canadian securities regulators and with the United States Securities and Exchange Commission. TransCanada disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise. With that, I will now turn the call over to Hal.

Thank you, David. Good afternoon, everyone, and thank you for joining us today. I am pleased to report that it has been another good year for TransCanada. Over the past four years we have built an excellent track record of solid financial and operating performance, no small feat in a business environment that has challenged the survival of many of our U.S. peers. We have delivered on our commitment to create value for our shareholders. Our compound annual return to shareholders over the past four years is almost 29 percent, 27 percent in 2003. Today, recognizing our strong financial performance and the importance of a dividend to our shareholders, TransCanada's Board of Directors raised the dividend on common shares by 7 percent to $1.16 per share. This is the fourth increase in as many years.

We have achieved our success through the prudent and disciplined execution of our strategies. Those strategies -- to grow and optimize our core businesses of natural gas transmission and power; to maintain and utilize our financial strength; to pursue operational excellence in everything we do; and to further the evolution of our regulatory business model. We have continuously evaluated those strategies to adapt TransCanada to new challenges and opportunities in our ever-changing business and competitive environment. In 2003, we made notable progress, positioning our Company to bring new sources of natural gas to market and capturing value-creating power opportunities, such as the acquisition of approximately one-third of Bruce Power and the development of additional fuel-efficient cogeneration plants.

As detailed in our report to shareholders, TransCanada Corporation's net income for the year ended December 31, 2003 was $851 million, or $1.76 per share, compared to net income of 747 million, or $1.56 per share, in 2002. These results include the third-quarter recognition of income from discontinued operations of $50 million, or 10 cents per share, equal to one-half of an approximate $100 billion after-tax gain that we had initially deferred from the disposition in 2001 of TransCanada's Gas Marketing business.

I would like to briefly review developments in the fourth quarter and then I will turn the call over to Russ Girling, who will take through a more detailed review of our financial results. Firstly, in our Gas Transmission business, we welcomed announcements late last week of filings under the Alaska Stranded Gas Development Act to develop the Alaska portion of the Alaska Highway pipeline. Two separate filings were made, one by Mid-American Energy Holdings Company and the second by the major Alaska producers, BP, Conoco, Philips and Exxon Mobil. We see these filings as progress in Alaska and for the overall pipeline project, but we note that a sound commercial structure for the project has yet to emerge. Achieving that structure will require the active participation and agreement of the state of Alaska and the U.S. Congress, as well as the affected private companies.

TransCanada, through its wholly-owned subsidiary, Foothills Pipelines Ltd., holds the certificates for both the Alaska and Canadian segments of the Alaska Highway pipeline project. We also hold significant right-of-way assets for the project in both jurisdictions, and our subsidiary, Foothills, has assembled significant legal, technical, and environmental information over the past 25-year period since Foothills and its predecessors were granted the certificates for the Alaska and Canadian portions of this project. TransCanada remains willing to build and own both portions of the Alaska Highway pipeline, but our primary focus is on the Canadian portion, where we are the natural party to build and operate a pipeline of this magnitude.

To others, the Canadian portion would be a major greenfield project. To TransCanada, it is a logical and cost-effective extension of our western Canada pipeline system, a system that already moves nearly three times the daily volume that will come from Alaska. We can do the Canadian portion as a natural addition to our existing system, and we remain committed to doing so. TransCanada will work with credible parties that wish to build and own an Alaska pipeline that connects to our system at the Yukon/Alaska border. To that end, we facilitated Mid-American's Alaska filing by providing information related to the Alaska portion of the project. We stand ready to assist both Mid-American and the Alaskan producers as they pursue the Alaska facilities required to bring Prudhoe Bay gas to market.

The development of a pipeline for Alaska gas remains strategically important to TransCanada. Equally important is the timely development of a pipeline for the transportation of Mackenzie Dells (ph) gas. To that end, we continue to assist Imperial Oil, the other Mackenzie Dells producers and explorers, and the Aboriginal Pipeline Group as they pursue development of a new gas pipeline down the Mackenzie Valley to a connection point with our western Canadian pipeline systems in northwest Alberta.

The Alaska and Mackenzie projects will bring much-needed gas supplies to the North American market, and both projects will help to sustain long-term flows and reasonable pulls through our Canadian and export pipelines. The development of northern pipelines and the integration of those projects into existing southern pipeline systems is a win-win situation for both Northern and Alberta producers. We look forward to further collaboration with all parties to bring the Mackenzie and Alaska projects to fruition.

Moving on to other parts of our system, in December we increased our ownership interest in Portland Natural Gas Transmission System and we now own 61.7 percent of Portland. As an extension of our Mainline System into the Boston regional market, the Portland System bolsters our role as an energy supplier to the U.S. Northeast. In early December, two natural gas pipeline failures occurred on TransCanada's Alberta System. Safety of the public, our employees and the environment is a top priority of TransCanada. Thanks to the quick work of our field and head office employees and the sophisticated remote-controlled systems we have in place to monitor and control our pipelines, the damaged sites were immediately isolated. There were no injuries and both sites were returned to operation within days. Deliveries of gas to local communities were not impacted as a result of either incident. Several gas producers in the immediate vicinity were shut in for up to nine days, and while we sincerely regret the interruption to their operations, we are proud of the extraordinary job our people did in repairing the damaged pipe sections and restoring service. Following preliminary investigations, we found evidence of external corrosion on these specific sections of our Alberta System. We are working diligently with our regulators to complete the investigation of these two pipeline failures.

In our power business, we began construction of the 90 MW Grandview Cogeneration facility in St. John, New Brunswick in December of 2003. As you will recall, we announced the agreement between TransCanada and Grandview Cogeneration Corporation, an affiliate of Irving Oil Ltd., to build this plant last October. The Grandview project is an excellent example of how TransCanada is growing its power business through new developments in niche markets, capitalizing on our expertise in fuel efficient cogeneration.

At the Bruce Nuclear Power Facility, Bruce A unit 4 began delivering power to the Ontario power grid in October and achieved commercial production effective November 1, 2003. Bruce A unit 3 was synchronized to the grid on January 8, 2004. Following tests similar to the unit 4 startup process, unit 3 reconnected to the grid this morning and is expected to ramp up to full power. Units 3 and 4 together will have a capacity of 1500 MW of electricity, bringing Bruce Power's total capacity to approximately 4,660 MW. While the restarts have taken longer and been more costly than we had anticipated, we are nonetheless very pleased with the performance to date of our investment in Bruce Power and its significant contribution to our results in 2003. Over the long-term, we are confident Bruce Power will prove to be an excellent investment for TransCanada.

Moving now to the regulatory front, we are in for another busy year with hearings on both our Alberta and Canadian Mainline Systems. The outcome of these regulatory proceedings could have a significant impact on results from the Alberta System and the Canadian Mainline in 2004. We were encouraged by the National Energy Board's July, 2003 decision on our Mainline tolls application, but we remain concerned with the regulators' assessment of business risk inherent in our Mainline and Alberta Systems, and the resulting low returns on equity and low deemed (ph) equity emphasis (ph) of those systems. We look forward to continuing the dialog with regulators and our customers in 2004.

What do we have planned for TransCanada in the year ahead? Firstly, we will continue to focus on strengthening our competitive advantage. We want to compete as the very best player in our chosen business in some (ph) markets. We will continue to make sure we have the right people and the right organization to execute and deliver results. We have focused our people on operational excellence and astute investment decisionmaking, and that will not change. The principles of operational excellence, low cost, reliability, superb operations and continuous improvement in everything we do, these will guide us in the year ahead.

We will build on our track record of strong operating performance and exceptional value creation. We will run our existing businesses to a high standard. We will pursue major projects and acquisition opportunities with vigor and discipline, and we will continue to capture options and opportunities to grow to set the stage for long-term growth. More specifically, we will, as I have discussed previously, pursue opportunities to bring new sources of natural gas to market. In the North, we will continue to work with stakeholders to advance both the Mackenzie Valley and Alaska Highway pipelines. And in liquefied natural gas, we will continue to evaluate and pursue initiatives that will place TransCanada in leadership roles in importing LNG.

In the Mackenzie, in Alaska and in LNG, we're looking at complex and time-consuming projects that will take years before coming to fruition. The Alaska Highway project has already been 25 years in the making, and we have been involved throughout that period. I think our long-term involvement in projects that span the continent is important to partners, customers, and government. They know they can count on TransCanada and its people. In both our gas transmission and power businesses, we will use our financial, technical, and project management strengths to pursue opportunities of scale, of quality, and of enduring value for our shareholders. In our regulated pipeline business, we will continue to work with regulators, customers, and governments to evolve our regulatory business model. We recognize that an uncertain regulatory environment is difficult for our customers as well. We are prepared to redouble our efforts to resolve issues with our customers outside the formal regulatory process, and we look forward to doing that in 2004.

In summary and closing, we have a skilled and dedicated team of people at TransCanada. Our successes over the past four years are the direct results of their efforts. I would like to conclude by recognizing the contributions of our people. They have worked hard and worked well to establish TransCanada as one of the best-positioned energy companies in North America today. Thanks to their efforts, we are ready and able to capitalize on emerging opportunities and create value over the long-term. That concludes my remarks. I will now turn the call over to Russ Girling.

Thank you, Hal, and good afternoon, everyone. As Hal said, we are pleased to deliver another year of strong financial performance. As reported earlier today, net income for the fourth quarter was $193 million, or 40 cents per share, compared to $180 million, or 37 cents per share, for the same period in 2002. The increase of $13 million, or 3 cents per share, is primarily due to higher earnings from our power business. For the year ended December 31, 2003, TransCanada's net income was $851 (ph), or $1.76 per share. As Hal mentioned, the 2003 results include net income from discontinued operations of $50 million, or 10 cents per share. Excluding this amount, net income from continuing operations was $801 million, or $1.66 per share, compared to $747 (ph) million, or $1.56 per share, in 2002. The increase of $54 million, or 10 cents per share, was primarily due to higher earnings from our power business and lower net expenses in the corporate segment, partially offset by lower earnings from the gas transmission business.

I will review the results for each of our segments, beginning with Gas Transmission. Gas Transmission generated net earnings of $160 million in the fourth quarter, compared to $162 million for the same period in 2002. For the year, Gas Transmission generated net earnings of $622 million compared to $653 million in 2002. The $31 million decline is primarily due to lower contributions from the Alberta System, the Canadian Mainline, and Great Lakes, partially offset by higher contributions from TransGas and Portland.

The Alberta System's earnings decreased by $24 million in 2003 compared to 2002 due to lower earnings from the one-year Alberta System revenue requirement settlement reached in February, 2003. The 2003 settlement included a fixed revenue component of $1.277 billion compared to $1.347 billion in 2002. The $70 million decrease in revenue was initially expected to reduce 2003 net income by $40 million relative to 2002. However, lower operating costs and lower financing costs, primarily due to a weaker U.S. dollar, partially offset the previously anticipated reduction in earnings.

The Canadian Mainline's earnings decreased by $17 million in 2003 compared to 2002, primarily due to the impact of the NEB's fair return decision in 2002. The decision included an increase in deemed common equity from 30 percent to 33 percent effective January 1, 2001, and resulted in the recognition in the second quarter of 2002 of an additional $16 million of net earnings for the year ended December 31, 2001. The impact of a $319 million decline in the Canadian Mainline's average investment base was substantially offset by an increase in the approved rate of return on common equity from 9.53 percent in 2002 to 9.79 percent in 2003. TransCanada's proportionate share of net earnings from Great Lakes decreased by $14 million in 2003 compared to 2002. The 2002 results included TransCanada's $7 million share of a favorable tax ruling for Great Lakes related to Minnesota use tax paid in prior years. Excluding the impact of the Great Lakes ruling in 2002, net earnings in 2003 declined by $7 million compared to last year, primarily due to the negative impact of a weaker U.S. dollar.

TransCanada's proportionate share of net earnings from TransGas increased by $60 million in 2003 compared to 2002. The increase was primarily due to higher contractual pulls (ph) and the recognition of TransCanada's $11 million share of future income tax benefits recognized by TransGas. Finally, in Gas Transmission, TransCanada's proportionate share of net earnings from Portland increased by $9 million in 2003 compared to 2002. The increase was primarily due to the impact of a rate settlement in early 2003 and TransCanada's increased ownership interest. During 2003, TransCanada increased its ownership interest in Portland from 33.3 percent to 43.4 percent on September 29th, and from 43.4 percent to 61.7 percent on December 3rd. Subsequent to the acquisition in December, Portland was fully consolidated in the Company's financial statements, with the 38.3 percent not owned reflected in noncontrolling interests.

Next I will talk about power. The power business generated net earnings of $34 million in the fourth quarter, compared to $30 million for the same period in 2002. Earnings from the February, 2003 acquisition of a 31.6 percent interest in Bruce Power and lower general, administrative, and support costs were the primary reasons for the increase. On an annual basis, the power business generated net earnings of $220 million compared to $146 million in 2002, an increase of 50 percent. Bruce Power earnings, a second-quarter settlement in 2003 in western operations, and the addition of the ManChief plant in late 2002 were the primary reasons for the increase.

In the fourth quarter, Bruce Power contributed $7 million of pre-tax equity income, compared to $38 million in the third quarter of last year -- or 2003. The $31 million decrease in pre-tax equity income reflects lower power output and higher maintenance costs compared to the third quarter due to plant maintenance outage at Bruce B Unit 8 that began on September 20th and continued through the entire fourth quarter. As a result of the extended outage, TransCanada's share of power output from the four Bruce B units in the fourth quarter was approximately 1571 Gigawatt hours, or 470 Gigawatt hours less than the 2041 Gigawatt hours reported for the third quarter.

In addition, Bruce Power incurred approximately $30 million of maintenance costs in the fourth quarter on the Bruce B Unit 8 shutdown. Repairs to Unit 8 have now been completed and approved by the Canadian Nuclear Safety Commission and it is expected that the unit will return to service in the next day or so. The contributions from Bruce A Unit 4, which was considered commercially in service on November 1, partially offset the reduced contribution from the four Bruce B Units. Overall, the four Bruce B Units and the one Bruce A Unit ran at an average availability of 73 percent in the fourth quarter, and TransCanada's share of the power output was 1846 Gigawatt hours. During the fourth quarter, 70 percent of Bruce Power's output was sold under fixed-price contracts and 30 percent was sold into Ontario's wholesale spot market. The overall average price realized in the fourth quarter was approximately $45 per megawatt hour, which is consistent with the third quarter.

Turning to the results for the year, Bruce Power contributed $99 million of pre-tax equity income, or $73 million after-tax, from February 14 to December 31. The average plant availability during TransCanada's period of ownership was 83 percent and our share of Bruce Power's output was 6,655 Gigawatt hours. During 2003, approximately 65 percent of Bruce Power's output was sold under fixed-price contracts and 35 percent was sold into Ontario's wholesale spot market. The average price realized for the year was approximately $48 per megawatt hour.

The average cost of production in 2003 was approximately $35 per megawatt hour. As Hal mentioned, on January 8, 2004, Bruce A Unit 3 was reconnected to the Ontario electricity grid. Although it has been off-line since mid-January for minor repairs, it was reconnected to the grid this morning. Similar to the Bruce A Unit 4 start-up process, after evaluating tests of the shutdown systems, Unit 3 is expected to begin to ramp up to full power. Bruce Power invested approximately $32 million on the Bruce A restart program in the fourth quarter, bringing the total to approximately $350 million in 2003, $300 million since our ownership began on February 14th. In addition, approximately $160 million was invested during this year in safety systems and power upgrade programs at Bruce B, $147 million of that spent since February 14. TransCanada has not provided any funding to Bruce Power subsequent to the acquisition of its ownership interest in February. Once the Unit 3 startup is complete, Bruce Power will have the capability of delivering 4,660 MW of a low-cost base low power to the Ontario market. TransCanada's proportionate share of the output is approximate 1500 MW.

Looking forward, equity income from Bruce Power will be impacted by fluctuations in spot market prices for electricity, as well as overall plant availability, which in turn is impacted by scheduled and unscheduled maintenance. To reduce exposure to spot market prices, Bruce Power has entered into fixed-price sales contracts for approximately 1560 MW of output for 2004.

As highlighted in our quarterly report, the average availability in 2004 for the six Bruce units is expected to be 80 percent. This estimate reflects planned maintenance outages for two Bruce B Units and two Bruce A Units, and a test of the Bruce B vacuum building, which will require all four Bruce B Units to be taken down off-line for approximately one month. The first scheduled maintenance outage in 2004 is on one of the Bruce A Units. It is expected to begin towards the end of the first quarter and to last for approximately 30 days.

Turning to our western operations, operating and other income of $160 million in 2003 was $29 million higher than last year. The increase was primarily due to a $31 million pre-tax positive earnings impact from the June 30, 2003 settlement with a former counterparty which defaulted in 2001 under power forward contracts, as well as the addition of the ManChief Power Plant in late 2002. These positive items were partially offset by lower realized prices on the sale of power in 2003 as compared to 2002. While a significant portion of our western power portfolio is contracted on a term basis, as contracts mature, we continually enter into new power sales arrangements at prices that reflect forward prices at the time the contract is signed. As a result, we are impacted by a longer-term trend in power prices. Although power prices in Alberta were stronger in 2003 when compared to 2002, they were lower than the prices realized in 2000 and 2001, when we first entered the Alberta power market in a significant way. As a result, the average price realized in western operations in 2003 was approximately 7 percent less than the prices realized in 2002.

Partially offsetting the increased contributions from Bruce Power and western operations were lower earnings from the northeast U.S. operations and higher general, administrative and support costs. Operating and other income from the northwest -- northeast Europe U.S. operations was $127 million, just $22 million lower than last year. The decrease is principally due to higher costs of fuel gas at Ocean State Power and the unfavorable impact of the weaker U.S. dollar, partially offset by incremental earnings from the growth in our northeastern U.S. retail businesses, which sell power to large commercial and industrial customers. General, administrative and support costs of $86 million in 2003 were $13 million higher than last year. The increase reflects higher support costs related to the Company's continued growth of the power business.

Next, I will talk about our corporate segment. Net expenses were $11 million and $12 million for the three months ended December 31, 2003 and 2002, respectively. On an annual basis, net expenses were $41 million, $11 million lower than last year. The decrease is primarily due to the positive impacts of a weaker U.S. dollar compared to the prior year. These positive impacts substantially offset the negative impacts reflected in the other segments of our business.

Now I will turn to cash flow and our balance sheet. Funds generated from continuing operations in 2003 were $1.81 billion compared to $1.83 billion in 2002. Capital expenditures excluding acquisitions were $391 million in 2003 and related primarily to the Iroquois ongoing Eastchester expansion project, maintenance and capacity capital in the wholly-owned pipelines, and the ongoing construction of the MacKay River Power Plant in Alberta. Acquisitions in 2003 totaled $570 million and included the acquisition of a 31.6 percent interest in Bruce, the acquisition of the remaining interest in the Foothills Pipeline System, and the acquisition of an additional 28.4 percent interest in the Portland Pipeline System.

Including assumed debt, TransCanada invested over $1.2 billion in its pipeline and power businesses in 2003. Despite this significant level of investment in growth opportunities, our balance sheet remains very strong. At the end of 2003, our consolidated capitalization was comprised of 59 percent term debt, 4 percent preferred securities, 2 percent preferred shares, and 35 percent common equity.

In summary, over the past four years we have built an excellent track record of solid financial and operating performance. We have prudently reinvested our discretionary cash flow in our two core businesses of natural gas transmission (technical difficulty). At the same time, we have strengthened our balance sheet by repaying a significant amount of debt. Together, this has resulted in a significant increase in earnings and cash flow and has provided our Board of Directors with the ability to raise the dividend on common shares in each of the last four years.

Looking ahead, we will continue to use our discretionary cash flow to make profitable investments in our two core businesses. We will continue to focus on operational excellence, with a focus on providing low-cost, reliable service to our customers. We will continue to work with regulators, customers, and governments to evolve our regulatory business model. And lastly, we will continue to maintain a strong balance sheet, which will provide us with the ability to act on large-scale opportunities when they arise. Successful execution of our plan will continue to result in earnings and cash flow growth and build value for our shareholders over the long term. That concludes my prepared remarks. I will now turn the call back to David.

Thanks, Ross. Before I turn it back to the conference coordinator, just a reminder that we will accept questions from the investment community first, followed by questions from the media. With that, I will turn back to the conference coordinator.

Thank you. (OPERATOR INSTRUCTIONS) Matthew Akman from CIBC World Markets.

I just had a few questions about Bruce. Could you give us some indication of your contracting plans on the Bruce A units?

I think what our plan is -- I guess it's firstly we want to make sure that the units stabilize and that we get some operating performance behind us. And we will probably go through the scheduled maintenance shutdowns that we have planned for the Bruce A units to ensure that we can rely upon those units. And then on a total basis, it would be our intent to sell a higher proportion of the total megawatts available than we currently have sold.

And still on the contracting, Russ, can you give us any clue of the profile of the contract on the B units? Does anything come off this year?

I think that what we said is the total we have is about 1500 megawatts that are sold forward currently in 2004, so that would be 1500 megawatts out of the approximately 3200 megawatts that are available out of the Bruce B units.

And is the average price going up this year at all?

It is the same as we have disclosed historically.

Thanks. And when are you going to take all four units down at the same time?

We're still working on the maintenance schedule for the year, but it would be later third quarter to fourth quarter.

Okay, thanks. And still just quick stuff on Bruce. Have you issued any debt at the Bruce partnership level?

At the Bruce level, the only debt that is there right now has two components. There's $225 million of partner debt that we have put in to date. We put in that as partners at the beginning. And it has an operating facility of around $150 million, which is probably half drawn at the current time.

So when you talk about no subsidy made to the partnership from TransCanada, if you had not drawn on that, would there have been a subsidy? Or is it sort of running breakeven on a cash basis?

It is running breakeven on a cash basis.

Okay. And I guess just sticking with Bruce for one last area, would the partnership look at, do you think, expanding investments in nuclear in Ontario, specifically around Pickering (ph)?

Well, Matthew, we might. I wouldn't want to say any more than that. We're certainly interested in growing our power business in Ontario. If opportunities come up at Pickering or elsewhere, we would certainly look at them. And we have options as to whether we would do that directly as TransCanada or through Bruce. So too early to say really. We haven't encountered that opportunity yet.

Okay, thanks. I'll turn it over to someone else.

Andrew Kuske from UBS Securities.

We've seen continued erosion on the asset base of both the Alberta System and the Canadian Mainline. What do you believe is the inflection point to start to see some investment in there? What I mean by the inflection point is what level of returns do you view as being adequate to actually start seeing investment in those systems again?

It is Hal here. If I hear your question correctly, firstly, I would just say that we see rates of return on regulated pipelines coming and going in cycles. There will be periods where the returns get ground down to what we consider unacceptable levels, and that would be the situation today; and other periods where they become quite attractive. Notwithstanding those cycles, we are in this thing for the long term and it is necessary for us to continue to invest in the Mainline and the Alberta System, even though the return in the immediate near-term might not be particularly attractive relative to what we could earn, for example, in the U.S. or in the power business.

The bigger issue, I think, is when would we foresee gas supply and demand fundamentals requiring additional capacity, either long-haul capacity or new connections in Alberta. And to be honest, we don't see a lot of that here in the near-term. At this point in time, the total pipeline capacity out of Western Canada generally exceeds the productive capacity. There are periods probably such as right now today when things are very cold in the East and there's a strong pull on storage out of Western Canada, that you will see the system running at or close to capacity. But that is certainly nowhere near as common as it was five years ago. So we remain committed to these big pipeline systems for the long term, and we remain cautiously optimistic that in due course we will once again be earning a rate of return that is attractive to us.

If I could follow up with just your CAPEX profile into 2004 and really beyond. How do you see the breakdown of your CAPEX being spent on, effectively, maintenance capital, growth CAPEX, and then acquisitions? Do we see a shift away from the acquisitions you have done in the past and going into where it is more greenfield development?

That is a difficult question to answer. It is really opportunity driven. If we see excellent opportunities on the acquisition front and the time is right, I think history would tell us that those are almost always the most attractive places to put our money. If we see the acquisition market heating up and becoming what we would consider overpriced, then I think we would slow down on that front and focus more on greenfield development. Our objective really is to have a portfolio of investment opportunities that is well in excess of the roughly $1 billion a year that we try to invest, so that we can pick and choose and select from the very best of that portfolio, and hopefully hang onto the rest of the opportunities and look at investing in them in subsequent years.

So we aren't making any particular predictions on how much we will invest, but you have seen the program in the range of $1 billion a year for the last couple of years. That's a pretty comfortable program for TransCanada. As Russ mentioned, we are able to strengthen our balance sheet while investing not much money, and that is what we would like to continue to do. I will just add, though, that occasionally bigger opportunities, substantially larger than that, will come along. And we work hard on the bigger opportunities, but we are very careful not to pursue them as the pricing becomes unattractive to us. So you could see bigger investments by us if some big opportunities come our way, but those would not occur on a routine basis.

If I could just put it a little bit differently -- there's a number of opportunities that you have on the pipeline front if northern development every actually gets going. And then with the Ontario power market, there is potentially a number of power plant development opportunities if we see the coal plants come off-line. And then if you look at those potential opportunities and then just what you see in the acquisition market currently, which do you believe would be more attractive at this time?

I think the most attractive opportunities that we see right now are probably in the power business. Maybe they are in Ontario; maybe are in one of our other core market regions like Western Canada or the Northeast U.S. But at this particular point in time, we probably see a larger number of attractive opportunities in power than in pipe. The second area that we would look to would be pipeline investments in the United States, where we have looked at a number of interesting situations and we did deal just like Portland, and we continue to invest in high-quality pipes like Iroquois in the U.S.

The third tranche of opportunities would really be incremental investment in our Canadian regulated pipes, and those are good long-term investments. It's just that the rate of return on capital employed there does not measure up to either power or the U.S. pipes.

That's great, thank you.

Winfried Fruehauf from National Bank Financial.

I have a question on the consolidated cash-flow statement, and I'm looking for an explanation for the very large shift in future income taxes for the third quarter of 2003 over the third quarter of 2002. Are we going from a plus 67 million last year or the year before to 18 million in 2003?

It's Lee Hobbs here. I will reply to that. I think you meant the fourth quarter of 2003 versus the fourth quarter of 2002.

Correct.

Yes, so there is a shift there, Winfried. And as we go through and are having higher net income from the TransCanada businesses, we are seeing a shift actually away from deferred income tax provisions to current tax provisions, so that a partial part of that is that shift that we are starting to see. We would expect if nothing else changes that that shift would continue in the future, not to the same degree that you see it in the fourth quarter.

There were also just some true-up adjustments at the end of the year, which would be reflective of the whole year that you are seeing in the negative 18.4 out of the fourth quarter. As you can see that on the full-year basis, the income tax -- future income tax addbacks are roughly the same. I guess our expectation would be that the current taxes portion will start to increase somewhat over the next year or two, in the absence of any other acquisitions or corporate moves.

What guidance would you have for a consolidated income tax rate for 2004 and 2005?

Probably just the effective rate that we would have for now as far as an income tax expense would go I would think would be fairly useful.

Okay and I have one other question on Bruce. You have sold electricity forward, and that seems like a pretty safe transaction, but by the same token, in selling it forward, you also have to incur an obligation to deliver. And in periods when Bruce is performing below expectations, you would have to find replacement electricity, correct?

That's correct.

And have you -- ?

Just a second before I say correct, that (indiscernible) is probably the main reason that we've been hesitant to sell anymore forward than we have, is that we have 1500 megawatts forward sold for 2004 right now, of a total of what we think is available of about 4600 megawatts for the year. Just given the outer schedule we have for this year, we are not comfortable going any higher than that. So the first route of managing that unit contingency and making sure that we don't have to be in the market buying power is ensuring we're not selling more than we think that will be produced on any given day.

In 2003, were there any locations, whatever, where you actually had to go out and find replacement electricity?

Not that I am aware of. We had substantially more power produced then we sold forward in any given day or any given month.

Thanks very much. That's all I have.

Linda Ezergailis from TD Newcrest.

I have a few questions. The first one is just wondering how much interest was capitalized in the quarter and the year.

Just give a second. Do you have another question, and we will look that up here.

I have a few. The Gasoducto del Pacifico investment, where will we see that impacted or consolidated in 2004, and can you give us a sense of what the earnings and cash flows might be from that asset?

The Gas Pacifico Energy you'll see in the other Gas Transmission business, probably in the other category. The amounts will not be significant. They will be very, very low digit numbers in any case.

They were less than --

Yes, they were less than a couple million in 2003, and we would expect that in 2004 -- so very, very small. The Paton (ph) investment will actually be reported in the power segment. We record that on a cost basis, so our expectation for '04 probably is very, very minimal, if any.

On your first question of capitalized interest, in total in the quarter it was about three, and for the full year, I think it was about 9 or 10.

Okay. Can you give us a sense of your outlook for the spot market as well as long-term contract prices in each of the power regions in which you operate?

No. I think that we have our own internal forecasts, but I think our preference would be for you to supply your own forecast to the volume availability that we provided.

Okay. Can you give us a sense of how much of your power margins -- and if you care to break down into prices and fuel costs, that would be appreciated as well -- how much of your non-Bruce Power operations are under long-term contract and/or are hedged.

Give us one second here. We probably have that number. Do you have another question while we look that one up?

Well, if you're asking -- do you have any sort of expectation or should I be forming my own as to when Bruce Power will start paying out dividends to the partners?

Again, that is something that we're discussing of the partnership group and it is directly related to capital investment over the next few years. So at this point in time, that is not something that we have given out formally. We don't expect any distributions in 2004 and we're working right now on what our 2005 plan looks like.

Linda, I would just add to that that as long as there are good investment opportunities within Bruce Power and the Bruce Power team is doing a good job of them, then we would not have a strong preference for receiving the cash as opposed to reinvesting it within that business.

Okay.

Just to get back to your question on forward sales. So excluding Bruce, we are at about 90 percent forward sold for '04 and about 80 percent for the two years after that.

Okay. I guess I will jump back in the queue.

Karen Taylor from BMO Nesbitt Burns.

I just have a couple of questions left. Will you be expected to contribute any capital to the 400 odd million that Bruce is looking to invest next year?

No, that is about equal to the cash flow we're expecting to generate at Bruce next year. So we're not expecting any cash injection or any cash distribution next year -- or 2004.

Okay. The availability number is 80 percent that you have given us. Does that reflect the fact that Bruce 8, of course, is down until some point later on this month, and perhaps early February, as well as the Unit 3, which came up this morning at 10?

I think that our 80 percent number is still accurate, and as I said, we're still playing around with our scheduled maintenance program, based on when these units come on and then when we will have to take them off-line again. So our current thought is that the 80 percent is still a good number.

The vacuum outages I'm assuming those would be 30 days apiece all at the same time, so it is going to be all four down for 30 days at Q3/Q4?

Actually, we're still planning that at the current time, but that is currently what we have got planned, is all four units down for 30 days.

The maintenance on two units of Bruce and two units of A, you said the one unit was going down at the end of the first quarter for 30 days. Can you give me an indication, the two Bruce B, would that also be 30 or would they be 60 apiece? And the last Bruce A Unit are those 30 or 60 day outages or longer?

I can't be specific about those. I think you can back into the 80 percent numbers from the numbers that we have given you. We're still working on what has to be done on those units when we take them down, so those schedules are still being worked on. We have not definitively said how long those outages are going to be yet.

There was a question earlier, I think Matthew asked it, about Pickering. There has been a lot of noise in the press, and perhaps people are talking wishfully about Units 1 and 2, and is there any serious effort going on right now to take a look at restarting 1 and 2?

Karen, we're not involved in Pickering. We're not experts in it and we really would not have any knowledge other than what you have with respect to Pickering.

With respect to units 1 to 2, we continue to discuss with the Ontario government -- they have obviously asked us what if anything it would take to bring those units online -- and we continue to work on understanding what that would look like. Obviously, we would need some contractual arrangements and that sort of thing with them to make that work. So it is an ongoing discussion with them. There is obviously about 1500 megawatts of laid-up power there on our site, and they are questioning what it would take to bring it on. So that dialogue is ongoing.

And then with respect to our interest in operating other facilities, obviously we have a big job of just getting our current investments online and working the way that we want it to work. And certainly if the Ontario government wants to talk about other things, we are open to talk about it, but our focus is primarily today on the Bruce facility itself.

As the results of some comment -- I believe Duncan Hawthorne made the comment about potentially setting new reactors on the Bruce site. Is that something that you're also discussing the government?

I'd say we're not discussing that with the government. Those are all internal ideas that are generated as a result of what it would take to bring those units on. One alternative obviously is to remove the contaminated facilities and put new facilities on-site. There is a certain cost associated with that that makes it feasible or not feasible. We have not done any of the detailed work that would say that is feasible, but that is in the range of options that be available to us to bring 1 and 2 on. So I think that's what Duncan is referring to in his public statements, is we will look at all of those opportunities as time goes by.

Hal, if I could back up, you said something about TransCanada pursuing potential nuclear opportunities outside of the Bruce Power. This is a two-part question for you. One, does that mean that there's a potential interest in sharing the financial $900 million cost of refurbishing Point LePros (ph)? And secondly, have you hired a nuclear staff internally to TransCanada to help you make these decisions?

I guess I would probably say something like no to both. Karen, we're interested in nuclear power as a potential solution to the supply/demand situation in Ontario. We are very interested in being a significant investor in the power business in Ontario. We think that there is interesting opportunities perhaps in small new reactors on the Bruce site, but these are all very long-term things that we are looking at. We're certainly interested in Camden (ph) technology and the possible ways that that could be applied, not just in Ontario but elsewhere as well. So it would be incorrect, I think, to conclude that TransCanada is on the leading edge of any sort of nuclear revitalization in Canada today, but we're certainly interested. It is going to take a large financial commitment and it is going to take some degree of familiarity with nuclear power, and we are capable of contributing on both those fronts.

I'm just going to leave it with this, but you started with a no and you have come back to a yes. So is that the way that I'm going to interpret this, is that it is something that you'd consider, it is on the plate and we will just see?

If you are asking the question are we actively pursuing projects or business plans to do something like Point LePros or restart Pickering or build new reactors at Bruce, I would say the answer is no. We don't have active projects underway on any of those things. But as longer-term opportunities for TransCanada, maybe in much longer time frames, just as we look at Alaska Highway pipelines, we're certainly prepared to do our homework and understand what those opportunities might be and what the role for TransCanada would be in them. But that is much different than having made a decision or commitment to be involved in that area.

I think my question is it could change to a yes, is what you are saying. That was my last question.

I really don't know. These are long-term things. I think we have (ph) a lot of work ahead of us before we did anything like that.

Thank you.

Fred Goppert from Goppert Financial.

I was having a question regarding any plans for redeeming or refinancing your preferred stock. Hello?

I'm just trying to understand what we have said publicly about that is that we do have some preferred securities that can be redeemed at this point in time. The bulk of that is in our regulated capital structure, and at the current time we don't have regulatory approval to redeem those shares. So it will be something that we will potentially discuss over the next year, but certainly it is not something that we have approval to do today.

Thank you.

Sam Kanes from Scotia Capital.

With respect to maybe a shorter term project in Ontario, namely the (indiscernible) with Ontario power generation, has work ground to halt on that one or is that still ongoing, given all the changes at OPG and the liberal government?

Sam, it's Hal. We are continuing to work on that. There are a number of uncertainties. The Ontario government is needing to consider all of its option and decide what it wants to do. The project is not dead within TransCanada. We're still keen to proceed with it, and we just need to figure out how to do it.

Moving to a broader question or observation, I guess, or your opinion, California's trying to re-regulate their power market right now. There's an infamous bill called the Edison Bill. It's not quite clear how this is going to work. The liberals are also reviewing this amongst many other things. Is there a generic resistance, perhaps, if on the liberal government decides (ph) should it re-regulate, provided they give fair returns as however they are defined, and obviously lower the risk-reward of incremental expenditures, with multiyear contracts but with lower returns? Is there some kind of matrix where you would have an indifference point as to how this market turns, left or right?

At TransCanada, we're quite happy to work in regulated environments. And I would point out the Becancour Project in Quebec where we're entering into a long-term VPA (ph) -- very little volatility to that. And you are right, that when you enter into those kinds of things and you have a really high-quality counterparty, the rate of return you can expect will be less than in a volatile merchant situation. But our bias, if anything, would be towards the regulated environment. If we're not in a regulated environment, we're very focused on low-cost operations, sitting on the low end of the cost curve. The one part of the matrix that we don't like at all is the highly volatile high-cost operation, where it really doesn't suit our balance sheet or our risk tolerance at all.

But as to whether it is regulated, as in the Quebec situation, or quite deregulated, as we have here in Alberta, we are comfortable in either model. It is nice to know what the ground rules are going to be, though.

It doesn't appear -- as Hal said, we can operate in either environment and under the right contractual arrangements, we can work with either. But certainly the signals that we are getting from Ontario currently are not that they want to retract deregulation. I think they want to make some potential changes to the way that the market is going to operate, but certainly there appears to be a commitment to some form of wholesale market in Ontario. So that is just the signal we're getting today, but like you said, they are still working towards what they want the model to look like, and we are prepared to work with them in almost any form or fashion they want to work.

Last one for me, MidAmerican, your support of MidAmerican, is there an ongoing commitment for farm-in or joint venture or vision you have with MidAmerican for the Alaska portion of the pipeline? I.e., what is behind your support?

We made a number of efforts over the past five years to get things going on the Alaska part of the project. The situation there is that a number of American pipeline companies were involved in Alaska Northwest when it was proposing the Alaska side of that project. And those companies all withdrew in the early 1990s and TransCanada and Foothills picked up their interests, such that TransCanada and Foothills ended up as the 100 percent owners of the rights in Alaska. We made an attempt a couple of years ago to try to reconstitute that partnership, and some of the parties were just unable to do it for different reasons. And then the major meltdown in the U.S. pipelines sector occurred and even those that were enthused pretty much had to pull back.

TransCanada is really very focused on the Canadian side of this project. That is the natural part for us to do and it is the part that we really want to do. As I said in my comments, we are willing to be involved as a builder or an investor on the Alaska side, but we don't necessarily want to take it entirely on our own. We thought it looked quite interesting when the producers were proceeding with their plans to build the Alaska part. There have been a number of twists and turns in that road, and we thought it was very interesting when MidAmerican came to the table. And when they asked us if we would be prepared to provide information and help them out in a couple of other ways, we indicated that, yes, we would do that in the interest of collaborating in an end-to-end project.

So no, there is no agreement or other formal arrangement that would see us either as a nonowner or as an owner on the Alaska side. We continue to have all of our rights and certificates, right-of-way, technical information, everything else related to the Alaska side. If a competent party comes along and wishes to build the Alaska portion of the project, that is fine by us. The Canadian side is a pretty big part of that project and we're quite happy to focus on that.

Okay, thanks, Hal.

Maureen Howe from RBC Capital Markets.

Thanks very much. Continuing on the Alaska pipeline, Hal, I'm just wondering, in light of the development of LNG that we're seeing in North America and the lower cost -- delivered cost, the commodity, what do you think you need from the government -- both the federal government and potentially the Alaska government -- to make the economics of this project work?

Well, first of all, Maureen, it is a difficult question to answer because that is really something that the producers, the net back owners of the wellhead in Alaska have to wrestle with. We were quite enthused about the package that was in the energy bill. The federal government loan guarantees very much helped with the debt financing of the project. The enabling legislation was going to very much speed the regulatory process through Alaska. We don't need that in Canada. We've got a good arrangement through the northern pipeline act in Canada. And the wellhead tax credit was going to dampen the volatility around the prices in Alaska at the wellhead at the end of a very long fixed-cost system. That was a very good and complete package, and I believe that if that package had been passed, the Alaska producers would've been able to go ahead and underwrite the whole project in the form of either direct capital investment on their part or long-term shipping commitments on a pipeline sponsor project.

So the key challenge at this point is whose credit is going to stand behind the project, who is going to take the capital cost overrun risk and who is going to take the wellhead price volatility risk. Those are the big issues I think that we are all working on. And historically in North America, it was always the end users, the local distribution companies that stepped up for twenty-year contracts and underpinned the building of all of the major U.S. pipe infrastructure and also the TransCanada system itself was underpinned by end-user contracts. Since FERC 636 and other deregulations, those kind of things have been increasingly difficult to put into place, and most people over the past couple of years have been thinking that it will be the Alaska producers that have to step up and underpin the credit to get the pipeline built.

I think the emergence of MidAmerican and some of the thinking that is going on indicates that people are also looking at whether there is a market pull option rather than a producer push that could get this pipeline built. It's too early to say. But I think I have kind of tried to cover for you, Maureen, what the major considerations are as we try to put the whole deal together.

Let's say you had loan guarantees from the federal government. Do you think that Alaska gas delivered into, say, Chicago, is competitive with LNG into the same market? Or competes, let me put it that way.

Yes, our economics look fairly similar for both. The total cost end-to-end from Prudhoe Bay to the Chicago or New York market is about the same as the cost of bringing LNG from an offshore source to, say, land in the northeast U.S.

And that cost is --?

Let me say it's something around $2 in either case, $2 U.S.

Without a return to the producers? That is the infrastructure cost?

That's right. And so you have -- and that might -- well, maybe we should think about $2.50 U.S. for that, because you have financing charges during construction, a lot of things like that. And then the question is what kind of a net back is demanded at the wellhead, and whether it is the producers in Alaska or the government of Trinidad or (indiscernible) or any of these other major LNG exporting places, some people think they'll take 50 cents. Other people think they're going to demand $2. So what you need at the wellhead is quite variable.

Where LNG has a big advantage is that you can build up a large supply of LNG one bite at a time, and you can do a whole series of half-a-Bcf-a-day or one-Bcf-a-day projects, and each project requires a lot less capital then an end-to-end Alaska pipeline. So I think that is where -- it's the magnitude of the commitment as well as the volatility and the risk that causes some people to favor LNG, and we're quite keen to pursue LNG as well.

That's great. Thanks. If I could just go on and ask a bit about the cash flow and the CAPEX. You mentioned that you were comfortable with the $1 billion in CAPEX, unless, say, a significant acquisition opportunity or project comes along. I'm just wondering for 2004, it is hard actually -- and maybe I'm missing something -- I'm not sure that I actually see that level of CAPEX. You have Becancour and you have Grandview. And so in the absence of other projects like that, what would you do with the cash flow? Would you look at repurchasing shares? Is that something you think about?

Acquisitions, large or small, are always of interest to us. And, Maureen, I would say that something like the Portland acquisition, which we think was very attractive to us, we did not have that identified at the start of the year and I doubt that you did either. We did not know that was going to come along. And so there are always those kind of things that seem to come up during the course of the year. I would ask Russ maybe if he wants to comment in addition to what I am saying, but buying back shares is not something that we see as a high probability. It is certainly an option. If nothing else came available and it made sense to do that, well, we would do that.

But the other option that I personally favor is just building our debt capacity. It never hurts to pay down debt a little bit and strengthen the war chest and be ready for a bigger opportunity that does come along.

Okay. And I guess this might be for Russ, I'm not sure, but the Ocean State Power gas contracts and the outlook for 2004. Do you think that the gas cost -- I guess you're probably in discussions now -- should we be looking for further pressure on gas costs in 2004 or should we be looking at something similar to 2003?

(indiscernible) look at something similar to 2003. We are about to enter arbitration again on those gas costs. We would hope that there is no further downside to us. We think that we got a fairly unfavorable ruling last time, so we would hope that, if anything, there would be some upside to that for us. But again, it is a third party controlled process, so we can't definitively say where we're going to land. But right now we are forecasting a number that looks similar to the 2003 cost number.

Okay. And finally, just in terms of the Ontario situation, you did talk about an interest in contracting and you talked about being careful with Bruce because of the reliability issue at least through 2004. I guess my question is, is there any interest in Ontario, given the somewhat uncertain environment, on the part of the end users in signing contracts at this point in time?

It is not as great as it has been in the past, as you would expect. So I would say that that market has retracted somewhat, because the market as well as the supply is watching the government to see what they're going to do. Certainly, there is the export market that has a little bit more liquidity in it, and you get a little more term (ph) out of it. But certainly that market is not as liquid as it was a couple of years ago, and we would hope that that would come back as the government starts to unveil its position and policy with respect to the market.

Okay, that's great. Those are my questions, thank you.

Andrew Fairbanks from Merrill Lynch.

Just a couple of quick questions on your outlook for the Western Basin natural gas. As you think about your long-term forecast for the Basin, what is your latest thinking on production increases or declines out of the area? Then I was also curious if you had any leading-edge data on perhaps how volumes looked at December or even if you had some January data that would be intriguing. You mentioned that you are getting a reasonable amount of pull currently with the cold weather (indiscernible).

I will take a stab at that. Firstly, all basins like Western Canada that consist of thousands of pools, none of which are (indiscernible), all those basins will at some point in their life go flat-line. And the question is just at what rate will they go flat-line? If you have overaccelerated development, you'll see a little bit of a tapering off and then they will flatten out. If you have been fairly cautious in development, you'll see them just peak and then go flat-line. And a basin like Western Canada should be expected to go flat-line for quite a while.

And the best indications we have seen here lately are that we're pretty much into that flat-line phase. There has been very aggressive drilling in the last couple of years, with high prices, and we're not seeing any significant uptick. We had a brief uptick when Ladyfern came on and it went through its brief period of glory and then declined, and since then the basin has pretty much been level. During December and January, we have seen no evidence of any dramatic changes. But you know, during a period like January that we're in right now, intense cold weather, the producers have a number of production problems that can cause production to fall off by, say, 5 percent. And so whether the general flatness in production is masking what is maybe a little bit of an increase, we really don't know.

Longer-term, our outlook would not be a lot different from the Natural Gas Council study -- or sorry, the National Petroleum Council study in the U,S. We think that was quite a thorough and good piece of work. TransCanada's own forecasts for Western Canada and North America in total might be a little bit different from the National Petroleum Council study, but not a lot. And that is the best and most confident piece of work I'd seen in a long time on the outlook for gas in North America.

Thanks, Hal.

Matthew Akman from CIBC World Markets.

Just quickly wanted to circle back, Hal, to something you had said in your introductory remarks about possibly negotiating tolls with shippers in 2004. I might have misheard or something, but I'm just wondering what you had in mind when you said that.

It is not just negotiating tolls. We look at a whole range of issues that exist between us and the shippers, the producers, primarily here in Western Canada. And it is very difficult for us to negotiate return on equity or any of the financial parameters because it's essentially a win-lose situation. If we get a higher ROE, it takes money out of their pockets and I think we all recognize that it is very difficult to negotiate those things. But there are other things like incentive agreements to drive lower operating and maintenance costs and whether we can negotiate something like that. We are currently in discussions around new long-term business models, both here in western Canada and in eastern Canada, Ontario and Quebec particularly, and it's those kinds of issues. How do we sustain flows through the systems so that we keep people's tolls at a reasonable level? How do we make it possible for people to ship gas without necessarily entering into long-term contracts? Those are more the kinds of issues that will bear fruit, I think, in discussions with the producers and other shippers.

Okay, thanks for clarifying that.

(OPERATOR INSTRUCTIONS) Linda Ezergailis TD Newcrest.

Just another quick questions with respect to debt. Can you give me a sense of what the debt levels were in your various business units, for example, corporate, power and transmission?

We don't allocate debt to our other segments. We allocate debt to our regulated businesses but not to our nonregulated businesses. And when I say regulated, I'm speaking to the Canadian wholly-owned regulated businesses. I can tell you what those are, is that where we're currently sitting, I think, is on the Mainline 33 as deemed, and on the Alberta System I think it's 4 --.

Why you go through that, Linda. You can just use the regulated capital structures for the Canadian Mainline, Foothills, and BC, and then I think Russ or Lee has got something there re the nonregulated.

Yes, you back into a number that looks like 40 percent, if I'm looking at this correctly.

Approximately 40 percent debt and 60 percent equity.

I'm sorry, the 40 percent is referring to?

The nonregulated business. Once you take consolidated and back out the wholly-owned Canadian pipes, what you are left with is a capital structure that is made up of approximately 40 percent debt, 60 percent equity.

Okay, I guess I can -- is there a place that I can find all the (indiscernible) for Portland and all that kind of stuff? Maybe I can take it off-line with David.

Yes, I can take that up with you in terms of the finer points of that calculation.

Okay, I appreciate that. Thank you.

John Edwards from Deutsche Bank.

You may have said this already; I probably missed it. What is your capital spending plans for 2004?

We don't actually have a defined capital spending plan for 2004, John, but if you look at the past few years, you'll see numbers hovering around that $1 billion level. And we tend to think in those terms, that we will probably spend about the same in the next year as we did in the last. But I would add to that that we are always looking at significant new initiatives that -- at this time last year, we did not realize we would have an opportunity to invest in the Aboriginal Pipeline Group in the Mackenzie Valley. We were not aware of the Portland deal and different things like that. But I would say statistics would tell us, based on the past few years, it will be generally in that range of $1 billion.

And I would just add, Hal, because I know there's been a lot of questions in the call about that, is that every year we enter it, we maintain a large inventory of projects that we're pursuing, both development and acquisition, at any given point in time. This year is no different than the past in terms of our inventory of potential projects that we have. Of the $1 billion that we have -- or slightly greater than $1 billion that we would have to spend from internally generated cash, probably about 5 to 600 million of that is (indiscernible) to maintenance capital projects like Becancour and the Grandview project. So there is a significant chunk that is already spoken for, and I would say that our inventory of opportunities is probably far greater than the cash that we're going to have available from internally generated funds, as it is every year.

So with respect to questions around buying share backs and that sort of thing, is what are you going to do with the cash, we are pretty confident that we will find opportunities this year as we have the last four or five years to spend that capital. As I said, we have more opportunities than we have cash.

Okay. And I don't know if I heard it right. You said the Bruce Power -- the planned capital spending there did you say was 400 million overall, and so your share would be about one-third of that?

That is correct and that will be funded from cash flow from Bruce Power. That is not included in the one billion we are referring to. That is free cash at the TransCanada level.

And what is the current reserve margins in the Ontario power market? (multiple speakers)

I don't have an answer.

We're not sure that there is any some days. I think there are frequent occasions where there's power being brought in from adjacent jurisdictions. But sorry, John, can't answer it any more precisely than that.

Great, thanks a lot.

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

Just before we close, conference coordinator, maybe just you want to polls to see whether or not there are any questions from the media.

There are no questions at this time.

Okay, that will bring it to an end then. We thank you very much for your time and look forward speaking to you again soon. Thanks.