TC Energy Corp (TRP) 2002 Q4 法說會逐字稿

The TransCanada Pipelines fourth quarter results conference call will begin shortly. all participate.ants please stand by. Your meeting is now ready to begin. Good afternoon, ladies and gentlemen. Welcome to the TransCanada Pipelines's 2002 fourth quarter results conference call. I would now like to turn the meeting over to Mr. David Moneta, director of investor relations. Please go ahead Mr. Moneta.

Thank you. Good afternoon. I would like to take this opportunity to welcome all of you this afternoon. Including those of who you are joining us through the world wide web. We're pleased to provide the investment community, the media and other interested parties with an opportunity to discuss our 2002 fourth quarter results and other general issues concerning TransCanada. With me today are Harold Kvisle President and CEO. Russell Girling, Executive Vice-President and Chief Financial Officer And Lee Hobbs, Vice President and Controller. Hal and Russ will begin this afternoon with some comments on our results and other general issues pertaining to TransCanada. And following their opening remarks, we'll turn the call over to the conference coordinator for questions. During the question and answer period, we'll accept questions from the investment community first. Followed by questions from the media.

Before Hal begins, I'd like to remind you that certain information in this presentation is forward-look 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 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'll now turn the call over to Hal Kvisle.

Thank you, David. Good afternoon, everyone. Thank you for joining us today. I would like to take a few moments to comment on the past year and the fourth quarter. I'll then turn the call over to Russ Girling who will give you additional details on our financial results. In many ways, my remarks today will sound similar to those I made last year at this time. TransCanada's strategies for growth and value creation have not changed nor has our commitment to their diligent and disciplined execution. We remain clearly focused on our goal to be one of the most profitable, competitive, reliable natural gas transportation and power services companies in North America. We remain extremely well-positioned to move quickly on growth opportunities in both pipelines and power. And we remain committed to the prudent management and disciplined approach that has resulted in another year of consistently strong financial performance with increases in both income and cash flow.

I'm pleased to report that today, TransCanada's board of directors raised the quarterly dividend on the company's outstanding common shares to 27 cents per share. An 8% increase from the 25 cents per share paid in the previous quarter. The 157th consecutive quarterly dividend on common shares is payable on April 30, 2003, to shareholders of record at the close of business on March 31, 2003. Enhancing shareholder value is always a primary goal in determining the best use of our discretionary cash flow. We're pleased that the increases in earnings and cash flow have enabled the board to increase the dividend for the third consecutive year. It is a significant achievement and clear evidence that the focus on our two core businesses of natural gas transmission and power is working exceptionally well. As detailed in our fourth quarter report to shareholders, TransCanada's net income applicable to common shares from continuing operations for 2002 with $747 million or $1.56 per share. For the fourth quarter, 2002, net earnings were $180 million or 37 cents per share. Funds generated from continuing operations for 2002 were approximately $1.8 billion, an increase of 13% relative to 2001. Over the past year, TransCanada has used its substantial internally generated cash flow to pay dividends on its common and preferred shares, reduce long-term debt by approximately $500 million and invest more than $800 million in our core businesses. The $800 million invested was split almost evenly between pipe and power.

In our natural gas transmission business, we continued to fund maintenance capital on our wholly owned systems. We've also essentially completed the 2002 west path project which consisted of 86 kilometers of pipeline loop, one greenfield compressor station and modifications to two existing compressor stations. This project was placed in service November 1, 2002. The west path project marked the first field installation and testing of X-100 grade 690 steel line pipe. X-100 is the highest strength line pipe in use worldwide today and may be considered by TransCanada for future capital projects requiring high pressure capabilities. As we reported in the third quarter, we acquired a general partnership interest in Northern Border Partners L.P., the owner of the northern border pipeline. We consider northern border pipeline to be one of the preferred routes to move gas from northern frontier areas to markets in the future. TransCanada continues to support development of both the McKinzie Valley pipeline and an Alaska highway pipeline to meet expected demands for natural gas in the future. We are well-positioned to move northern gas through our existing systems and through the controlled growth in the future as volumes increase. In our power business, we are building the McKay River project, a 165 megawatt natural gas fired cogeneration plant that will provide electrical power and steam to petro Canada's oil sands project near Fort McMurray. We've completed construction on the Bear Creek facility, an 80 megawatt cogeneration plant near Grand Prairie, Alberta.

In November, we completed the $209 million acquisition of the Manchief power plant, a 300 megawatt facility located in Colorado. And in December, our most significant business event was the announcement of an agreement to acquire a 31.6% interest in Bruce power. Bruce power is the tenant under a lease on the Bruce nuclear power facility which continues to be owned by Ontario Power Generation. While TransCanada will have an interest in the lease on the Bruce facility, the day to day operations of the plant will continue to be run by the Bruce Power management team, the same expert team and employees who are in place today. Our direct investment in Bruce will be approximately $376 million. As part of the agreement, we will also fund a 1/3 share or $75 million of a $225 million accelerated deferred rent payment to Ontario power generation. And under the terms of the lease, Ontario Power Generation retains responsibility for spent fuel and ultimate he decommissioning liabilities.

We expect the Bruce transaction to close in mid February of 2003. As we have said previously, our investment in Bruce power is a strong fit to grow our power business. First, it is in one of our most important market regions, the province of Ontario. We have been the major gas pipeline in Ontario for more than 40 years and we have developed a significant power business in that province over the past decade. The Bruce acquisition is evidence of our commitment to the Ontario energy market. It is also consistent with our objective of building a balanced portfolio of low cost power generation assets. And it is further demonstration of our disciplined focused approach to growth and value creation. With the Manchief acquisition and the pending completion of the Bruce interest acquisition, the amount of power TransCanada will own or have interest in control, manage or be constructing will be more than 4,000 megawatts.

Turning now to the pipeline regulatory front, the national energy board approved in term, 2003 tolls on TransCanada's mainline in December of 2002. The NEB will hold a public hearing scheduled to begin on February 24, 2003, to consider TransCanada's application for approval of 2003 tolls. In September, we applied to the NEB to reconsider its decision on our 2001 and 2002 fair return application. The NEB has yet to determine whether there will be a review of that application. In Alberta, the energy and utilities board approved in term poles on TransCanada's Alberta system in December. We continue to negotiate our Alberta system 2003 revenue requirement with our Alberta customers. We plan to file an application for approval of the 2003 revenue requirement and final 2003 tolls, rates and charges with the EUB by February 28th.

In closing, I believe 2002 was the year in which TransCanada continued its disciplined, value creating growth in power, and reaffirmed its leadership position in the North American natural gas transmission business. We believe there will be significant opportunities to continue to grow both of our core businesses over the next decade. However, as we stated before, we do not measure industry leadership by sheer size. We measure it by profitability, value creation and sustainability. We're in this business for the long-term. In 2003, we will maintain our focus on our core strategies with an emphasis on well-planned, well-executed growth that creates value for our shareholders, without compromising our financial strength. I would now like to ask Russ Girling to provide with you the details of our year end and fourth quarter financial results.

Thank you, Hal and good afternoon, everyone. As Hal said, we're pleased to report another year of strong operating results. We continue to generate solid earnings, growth, by operating and developing and acquiring a large scale energy infrastructure assets. As reported earlier today, net income applicable to common shares from continuing operations for the fourth quarter of 2002 was $180 million or 37 cents per share compared to net earnings of $166 million or 35 cents per share for the same period last year. For the year end of December 31, 2002, net income applicable to common shares for continuing operations was $747 million or $1.56 per share compared to $686 million or $1.44 per share in 2001. The 9% increase in 2002 is due to higher earnings from the transmission business and reduced corporate expenses which is partially offset by low earnings from a power segment. As Hal mentioned, the board of directors increased the dividends on common shares today to 27 cents per common share for the first quarter of 2003. This increase reiterates our positive outlook for the future and delivers on our objective of enhancing shareholder value. As highlighted in our quarterly report, the company has chosen to expense stock options and the impact of the accounting change which has been recorded in the fourth quarter was a $2 million charge to net income in the 3 and 12 month ended December 31, 2002.

I'll now review the fourth quarter results for each first segments beginning with the largest, the transmission segment. Transmission business generated net earnings of $162 million and $653 million for the 3 and 12 month ended December 31, 2002. Respectively. The Alberta system contributed net earnings of $56 million in the fourth quarter compared to $59 million last year. The decrease is primarily due to the renegotiation in the fourth quarter of 2001 for the recognition of higher incentive earnings from operating cost efficiencies related to 2001. For the year, the Alberta system contributed $214 million which is an increase of $10 million when compared to 2001. The increase is primarily due to an interest refund of $4 million relating to prior year income tax reassessment and the expiring of TransCanada's transition support costs with respect to the Alberta systems products and pricing agreement which ended in the first quarter of 2002. The Canadian Mainline contributed net earnings of $75 million in the fourth quarter compared to $70 million last year. For the year, the Canadian Mainline contributed net earnings of $307 million compared to $274 million in 2001. That increase reflects the impact of the fair return decision.

As you know, in June, we received the national energy board decision on our fair return application to determine the cost of capital to be included in the calculation of 2001 and 2002 final tolls on the Canadian Mainline. The fair return decision included an increase in deemed common equity ratio from 30 to 33% effective January 1, 2001. The NEB also decided that that return on equity as calculated based on the NEB formula continue to be appropriate for the Canadian Mainline which resulted in an approved rate of return on common equity of 9.61% for 2001 and 9.53% for 2002. Therefore, TransCanada's results for the year ended December 31, 2002, include after tax net earnings of $36 million or 8 cents per share representing the impact of the fair return decision for the two-year period from January 1, 2001 to December 31, 2002. This includes $60 million for 2001. And $20 million for 2002. Excluding the impact of the fair return decision, results for the Canadian main line for the 3 and 12-month ended December 31, 2002, are comparable to the same period last year. For 2003, the NEB formula results in a rate of return of 9.79%. However, in September, TransCanada filed a request with the NEB for review and variance of the fair return decision and in the Canadian Mainline 2003 tolls and tariff application, we requested that the final 2003 tolls reflect the review and variance decision. As Hal mentioned, the NEB has yet to determine whether there will be a review of our application.

And finally, with respect to our transmission segment, our share earnings in the fourth quarter from investments in North American pipeline ventures was $29 million, an increase of $6 million over last year. The increase is mainly due to lower northern development costs and increased contributions from Great Lakes and Cross Alta. For the year, North American pipeline ventures contributed net earnings of $126 million, $24 million more than in 2001. The increase includes TransCanada's $7 million share of a favorable ruling from the Great Lakes gas transmission related to Minnesota use tax paid in the prior year. Higher transportation margins, favorable foreign exchange rates on stronger operating results from U.S. pipeline affiliates and increased ownership interests in Iroquois and Portland, acquired in the second quarter of 2001 also contributed to the increase. And finally, net earnings related to our share of other ventures include the Cross Alta gas storage facility and the Transgas which increased by $7 million in 2002 when compared to 2001. Next, I'll talk about power.

The power business contributed net earnings of $30 million in the fourth quarter compared to $35 million last year. Total volume sold in the fourth quarter were 4,740 gigawatt hours compared to 3,633 gigawatt hours last year. For the year, power contributed net earnings of $146 million compared to $168 million last year. Total volume sold in 2002 were 19,044 compared to 14,323 in 2001. Despite the quarter over quarter and year over year decline in net earnings, we are pleased with results in light of the difficult North American power market. Also remember that in 2001, we were able to capitalize on significant market opportunities created by higher power prices and power price volatility. Our 2002 results reflect a decline in these opportunistic type transactions. However, as I've said before, our outlook for power has never been based on the belief that market conditions we experienced in 2001 would be repeated. TransCanada power L.P., contributed $9 million in operating and other income in the fourth quarter, an amount that's comparable to the $10 reported last year.

For the year, TransCanada power L.P. contributed $36 million, which is $3 million less than last year. That decrease was primarily due to an unplanned outage at the Williams Lake plant in the first half of 2002 and a reduction in TransCanada's ownership interest in the power L.P. from 41.6% to 35.6% effective October, 2001. Operating and other income from our northeastern operations decreased by $20 million and $10 million for the three and 12-month ended December 31, 2002, respectively. Compared to the same periods last year. The fourth quarter, or the decrease in fourth quarter, is primarily due to lower revenues, under the long-term power sales arrangements in 2002. And TransCanada's ability to capitalize on market opportunities that existed in the fourth quarter of 2001. The annual decrease is partially offset by the income from a full year ownership in 2002 of the Curtis Palmer hydroelectric facility which was acquired in July of 2001. Operating and other income from the western operations of $30 million in the fourth quarter of 2002 was $50 million higher compared to the same period last year. The results for 2002 include contributions from the Sundance B power purchase agreement acquired in December of 2001. Income from the commercial start-up of the Red Water and Carsland plants in January of 2002. And the November 2002 acquisition of the Manchief power plant. These were partially offset by lower contract prices on the sale of output from the Sundance A power purchase agreement.

For the year, operating and other income from western operations is $18 million lower than in 2001. The decrease is mainly due to lower contract prices on the sale of output from the Sundance A power purchase arrangement in 2002 and our ability to take advantage of market opportunities created by higher prices and power price volatility in the first half of 2001. These decreases from partially offset by contributions from the Sundance B power purchase agreement, FredWater, Carseland and the Manchief acquisition. Generally administrative and support costs of $25 million and $73 million for the three and 12 months ended December 31, 2002, respectively, were $7 million and $24 million higher than for the same periods last year. The increases are due to ongoing investment in power and include increased project development costs. As we've said, the number of opportunities that have surfaced in our core businesses have increased and we continue to evaluate them in a focused and disciplined way. At the same time, we take a conservative approach to how we account for all business development costs by expensing them as we incur them. Although the cost of this activity has a negative impact on earnings today it, will lead to profitable growth in the future.

Going forward, our objective is to grow our asset-based power business in a manner that contributes stable, long-term earnings and cash flow. We'll continue to pursue projects and manage our power portfolio in a maner that fits our desired risk profile, with a focus on low cost supply, low volatility, stable returns and longer term contracts with strong counterparties. We'll leverage our strength, extensive market knowledge, strong technical expertise, deregulation experience and risk management skills to grow our power business in the same manner that has led to its success to date. To that end, as Hal mentioned, we're progressing with the cogeneration -- with the construction of our Bear Creek and McKay River plants. In December, we've reached an agreement to acquire a 31.6% interest in Bruce Power limited partnership for approximately $376 million. In addition, we'll fund a 1/3 share or $75 a million of a $225 million accelerated deferred rental payment to OPG or Ontario Power Generation. As Hal pointed out, we expect to close the transaction in mid February. Next I'll talk about the corporate segment.

Net expenses were $12 million and $22 million for the three months ended December 31, 2002. And 2001 respectively. For the year, net expenses from $52 million to compared to $67 million in 2001. The decrease in net expenses is primarily due to lower general and administrative expenses to support discontinued operations and the positive impact of lower interest rates. These were partially offset by increased corporate financial charges resulting from the fair return decision. With respect to our discontinued operations, as described previously, TransCanada remains contingently liable pursuant to obligations under certain energy trading contracts that relate to the divested gas marketing business. As of December 31, 2002, we reviewed the provision for loss on discontinued operations including the approximately $100 million of deferred after tax gains and the remaining obligations related to the gas marketing businesses and concluded the provision and the continued deferral of the gains was appropriate. As a result, there was no earnings impact related to discontinued operations in 2002.

Turning to the cash flow statement and our balance sheet, funds generated from continuing operations for the fourth quarter were $467 million, which is an increase of $106 million compared to last year. On a year to date basis, funds generated from continuing operations from approximately $1.8 billion, an increase of $203 million or approximately 13% over last year. Capital expenditures excluding acquisitions for the year ended December 31, 2002, were $599 million. And related primarily to maintenance and capacity capital in the transmission business and the construction of two new power plants. Acquisitions for the year totaled $228 million and included the acquisition of the Manchief power plant and the general partner interests in the Northern Border Partners L.P.. Now, turning to our balance sheet.

Our balance sheet continues to improve. The company retired $486 million of term debt and reduced notes payable to $46 million in 2002. Today, our balance sheet is stronger than it has been in over 15 years. It consists of 57% term debt, 6% preferred securities, 2% preferred shares and 35% common equity. The company's discretionary cash position remains strong as we expect to generate substantial operating cash flow and aside from ongoing maintenance requirements and the pending Bruce Power transaction, we have limited capital commitments going forward. During the fourth quarter, we also established a new $1.5 billion syndicated credit facility, replacing exists lines set to expire in mid 2003. And we filed universal shelf prospectus with the Canadian and U.S. securities regulators in the amount of $2 billion Canadian and $1 billion U.S. respectively. To summarize, the company's earnings, cash flow, combined with a strong balance sheet provides TransCanada with the flexibility to maintain -- to make disciplined investments in its core businesses. As we have said previously, we continue to make profitable investments in natural gas transmission and power. But be assured the valuation approach will remain disciplined and focused to ensure we continue to enhance shareholder value. We'll continue to work on establishing a new regulated business model that will provide value to our customers, reduces the long-term risks of our Canadian long-haul pipelines, and allows us to earn a fair and competitive return. We'll continue to focus on operation excellence with a focus on providing low cost, reliable service to all of our customers and we'll continue to maintain a strong financial position and we'll not compromise our credit ratings. Successful execution of these strategies will result in continued earnings and cash flow growth in years ahead. And build value for our shareholders. That concludes my remarks. I'll now turn the call back to David.

Thanks, Russ. Before I turn it back to the conference coordinator, just a reminder that during the question and answer period, we will accept questions from the investment community first. And following that, we would be happy to accept questions from the media as well. With that, I'll turn it back to the conference coordinator.

Thank you very much Mr. Moneta. Thank you Mr. Girling. We'll now pull questions from the analyst community. If you're from the analyst community and you have a question, please press 1 on your touch tone telephone if you're using a speakerphone, please lift the handset then press one. If you wish to cancel, please press the number sign. Please press one at this time if you have a question. Our first question will come from Mr. Matthew Akman from Credit Suisse First Boston. Please go ahead, sir.

Thanks. Couple of questions on the power segment. Wanted to ask whether there's any contract price improvements for the Sundance A and B, PPAs going forward in 2003.

For the most part, the power is sold forward. There is some contingent power we don't sell. We don't sell at 100% of it. Just for operating reasons. To ensure that we don't get caught offside so there will be some marginal improvement in that and that power prices have been strong for the first 25 days of January. That has dissipated somewhat but like I said, the volumes we have exposed to that aren't very large.

What about the contract of prices, Russ? Would those have improved? I mean anticipating maybe some plant outages and some of the other power producers in Alberta. Would that have factored into your contract prices?

No. Essentially most of the power was sold under sort of long-term agreements two years ago. So, we would still be living with those prices. There is some that's recontracted on an ongoing basis but there's no material change in the prices.

Then, staying with power. On Bear Creek, is there any capacity open for sale into the Alberta market?

Yes, there is some.

Be small?

Yeah, it's not large.

Ok. Staying with power, where is Manchief recorded? The quarter? Is that in western operations?

Yes.

Ok. Just moving on from power for a second. On the balance sheet, presumably you've had some times to talk to the rating agencies now since the Bruce acquisition announcement. Just wondering if you would give us an update on where that stands. What kind of debt targets they would be looking for and whether those are in line with your current levels or maybe just give us an update on that.

Actually, we haven't had the opportunity yet to visit with rating agencies on that issue. We do have meetings scheduled in the upcoming weeks. And I think that our understanding hasn't changed from that point in time from a credit standpoint. All of our credit statistics continue to improve whether you're talking about debt service coverage ratio, debt/equity ratio, funds to total debt, any of the ratios that are commonly talked about. They're all on a very -- on an improving trend in both the regulated and nonregulated businesses. So, we're set to have discussions with them, as to where that might go. I think subsequent to our last conference call, DBRS has reaffirmed our rating with a stable trend and Moody's hasn't commented to date and we're comfortable at this point in time that they have no issue, at least at this point in time. It is with S & P and we'll have that conversation in the upcoming weeks.

Last area I just wanted -- quick question on the Alberta system. You said that you would file for rates by the end of February. I'm just wondering what the significance of that date is in your mind. Is that sort of the line in the sand, you said, if we don't have a negotiated deal by that point, we file or are you hoping to file a negotiated settlement at that point?

Matthew, we hope to have as many parties on side with us in that as we can. That is the date that was set out by the UB that we need to make the filing by that date regardless of how much support we have. But we're working hard. We've worked hard in December and January and we'll continue that process through February to get hopefully the majority of our shippers on side with the deal that we negotiated with the big customers.

You're still optimistic you can get a negotiated deal.

Yes, we are, although there's always elements to it that the EUB will need to review and rule upon. It is just unclear at this point whether we're going to have to file a very substantive application or a relatively minor filing.

Ok.

I think you know, the outcome of the fair return decision in June of last year, obviously doesn't make that process of negotiation as easy as potentially it's been in the past. It is a very difficult process to get everybody on side with the direction we want to go.

Ok. Thanks. I'll stop there.

Thanks, Matthew.

Thank you very much, Mr. Akman. Our next question will come from Sam Kanes from Scotia capital. Please go ahead.

Thank you. With respect to Bruce nuclear, there has been some fairly aggressive chatter, I guess, from management of Bruce nuclear, respantions without being specific. Now that ownership has been settled or somewhat settled. Obviously the issue in New Brunswick comes up point la pro, the government's been fishing for support partnership there. That reactor and obviously British energy is still trying to sell their 50% of AmoryGEN. I'm wondering what you think about the comments and where you stand on that with respect to more appetite with nuclear down the road.

Sam, we're very focused at this point in time on closing the Bruce nuclear deal, on making that facility operate to the highest possible standard to bringing the two Bruce A reactors back on stream. And really working through all of the complexities of the Ontario power market and what's going on there. We're not paying much attention to opportunities in the nuclear field elsewhere. We think we have a very high quality output at Bruce and we're very focused on making that operate well and that would be TransCanada's priority for the next couple of years, I would expect.

I think that that would be shared by the consortium and to the extent that some of Duncan Hawthorne's comments were taken I think out of context in some of the reports that we've seen, he responded to a question of whether or not the consortium would consider that and I think his actual response in the notes that we've seen were yes, it will consider all kinds of things in the future but right now, he's got a pretty big job ahead of him to meet the targets that the consortium has set forward at the forum. At the Bruce facility and he's very much focused on that and I think what we can tell you is from the consortium perspective is that there's no focus on pursuing other opportunities at this point in time.

Thanks for that clarification. One more and I'll let you go. The issue comes up on CANDU reactors with heavy water absorbing hydrogen into metallurgy which causes this preliminary breakdown of the Pickering units vis-a-vis having problems that led to tubing that massive cost mid '80s. How does Bruce fit in with respect to that issue as metallurgy changed enough that it isn't an issue? That's a lumpy kind of maintenance, CAPEX every ten years. Maybe it's not. How did you view that in your calculations?

Sam, we hired some very qualified and expert nuclear technical people in advance of getting involved in the Bruce thing. And the issue you raise is one of you know literally hundreds of significant issues that they worked through. And satisfied themselves that the circumstances at Bruce were ones that we could be comfortable with. The particular issue about retubing and about tube degradation, things like that, we received fairly high level of comfort that the particular problem that's occurred at Pickering is not one that we face in the near term at Bruce. Longer term, all of these issues have to be monitored very closely. But we did get substantial comfort from people who know the facilities very, very well that we're not facing any undue risk of that kind of stuff in the near term.

Thanks, Hal.

Thanks.

Thank you very much, Mr. Kanes. Our next question is from miss Karen Taylor from BMO Nesbitt Burns. Please go ahead, ma'am.

Just if we could return to the power segment, please. My favorite questions will come back so hopefully you have your little sheet there like last time. You gave us the gigawatt hours sales. Can you it tell me what the gigawatt hours available were for the year as well as the fourth quarter?

I'm looking around the room and nobody has that, Karen in terms of available gigawatt hours. It is not a number that we record.

Ok. Then what was the average plant availability as a percentage of MCR. Do you have that?

They're all very high. The average plant availability, I don't think would be a number that we calculate either a weight average availability. For the most part, our plants average in excess of 90% or 95%. Some of them approaching like 97%, 98%. But I don't have an average number for you. But they all run at a high availability given even our gas-fired plants, are dispatched on a continuous basis.

How about I guess part of the root of the question -- let me finish with the statistics then we'll get to Ocean State and northeast. In actual percentage terms, if you wouldn't mind, over the '03 to '05 period, what percent of your energy sales are sold forward.

One second here. I think -- do you know what the number is, Lee? Total sales, 97% in '03. '04, 80%. In '05, 73%.

And can you describe or give me some indication about either the average price for megawatt hour or some description of a margin on a per megawatt hour?

No.

And would it be reasonable to assume that either the availability is going to be consistent excluding the Bruce over that period of time, so in terms of what you got in your portfolio right now, the average availability would be similar to what we saw in fiscal '02?

Yes.

With respect to Ocean State, and you marked -- you remarked in the press release, the lack of opportunities to opportunistically trade around your assets. The deterioration of natural gas spark spreads in the U.S. northeast since the beginning of the fourth quarter '02 is quite marked and it continues to be quite negative for high heat rate facilities into January of '03. Is that the primary reason for the decline in contribution for the northeast power section?

I don't know a way that would be primary or not. That would be one of the contributing factors. There is other opportunistic things that we took advantage of, but that would be one of the factors included, Karen.

One of the major ones? I'm trying to get a grip on here is the volatility from this facility and what's the base going forward.

I think I would characterize it as one of several factors in our northeast operation.

So, if I were to look at the contribution from this power segment, going forward, we saw a relatively similar third quarter performance where on year over year basis, it was down and it is down on a quarter of a quarter basis again. Where is a run rate given if 2001 is [INAUDIBLE]. Am I to look at the third and fourth quarters and assume that based on the collection of assets that's a normal run rate?

That's a $30 millionish sort of range. In that kind of range is what we expect.

Karen, it's Lee, as well, the Curtis/Palmer facility in there. Depending on the water flows, that will also move the number around.

Ok. Is it subject to other than what I would anticipate, the seasonality to be or do the contracts in place in that facility smooth that?

This Curtis/Palmer you're talking about?

Ocean State. And the rest of the operation, whatever you've got in there.

It should be fairly flat. It depends on the seasonality of opportunistic things that come along. Normally, they come along in the peak periods of either summer heating season or winter season. That's when we expect to see the anomalies.

So, if we're working with a market that peaks in the first quarter, also should have fairly strong results in the fourth quarter, because temperatures drop, and then we have a seasonal peak for space cooling in August or July/August. That really leaves the second quarter then to be the weakest for that segment, is that the case?

I guess again, we'll wait and see what happens. We would expect it to be fairly flat and as events occur, I can't predict what's going to occur or when the weather is going to occur and when it will impact market prices for gas and power so we don't forecast anomalous events.

Ok. Maybe this is a question for Hal. We sort of addressed it or at least talked about it very briefly on the Bruce conference call but it's appearing again in this press release. There was a lot of conversation about stable, low risk growth, measured acquisition but yet we do see power investments must be either supported by strong stable and predictable cash flows or be at low cost end of the dispatch curve. Why should we not be interpreting this as an increase in the tolerance for risk?

Well, Karen, I think the kind of risky situation that we're trying to avoid is one that we see many of our competitors get into where they build or buy power plants that are very much at the margin. And when gas prices, fuel gas prices go up or power prices fall, the cash flow margin out of those facilities can disappear almost entirely and you end up with not only, no earnings but also no cash flow and there are a lot of plants like that in North America today that we look at. So, the way to control that extreme kind of volatility is if we're dealing with a high operating costs asset. We will seek to have long-term fixed contracts around that. If we have something that would be very low cost, like Bruce or like the Alberta Sundance PPAs, we're willing to take a little more volatility around that because you have protection of both earnings and cash flow fundamentally driven by the very low cost of production. So, no matter where the marketplace moves, we still have positive margins both earnings and cash. I don't know whether it is fair to characterize it as the company willing to take on a greater risk. I mean, every one of our businesses has got different risks. Some are very short term. Some are much longer term, but we feel very comfortable with the long-term value of everything that we're getting into, and we certainly do regard earnings volatility as one of the limitations within which we have to live.

I think further evidence of that is the numbers I read you a couple of minutes ago with respect to what we have contracted. From a corporate philosophy standpoint. You can see that the bulk of our power is sold forward. Even though, for example, in Alberta, we're sitting at the very low end of the dispatch curve. We still seek to manage that volatility in a prudent way. And as you know, as we pointed out when we announced the Bruce deal, 60% of that, the current power from Bruce, is sold forward under long-term agreements and there is good reason why we don't go above that in terms of unit contingencies in contract. So, our approach continues to be even though we're at the low end of the dispatch curve, that just says you've got a -- a very economic long-term facility. How you manage the risk around that is discretionary in the company's choice has been to manage that on a rolling forward contracting basis.

So, what is the average term to maturity then, if I could express it this way, in the residual of the power contract starting to '03 going out to whenever and what average percentage of sales does that in terms of availability, does that represent.

For which facility?

All of them in aggregate as a portfolio.

Again -- I think I moved out four years for you, Karen. It declines like in off the sheet I can give you 2006. That's 70% and so what I can tell you is that that's a fairly high percentage going out four years. We continue to roll the prompt year to something in around that 90% to 100% kind of level.

Ok. On PNGTS, if you can remind me what the equity is on that line.

Someone just has to remind us. Do you have another question, Karen?

The gross assets were about $490 million U.S. Is that what you're working at from a rate base point of view?

Karen, could you repeat that question?

The gross assets in service FIRC approved -- I gotta look at the date here. Earlier was about $490 million. Is that the approved rate base on a forward basis?

Can you ask one more time? Lee was pulling up the numbers here.

Deemed equity is 30%, Karen.

Long time since I refreshed these assumptions in my model. The gross assets in service subject to the FERCs approval in their decision was $492 million.

Sounds about right.

Is that -- does that constitute then the effective rate base for rate making purposes going forward?

I believe that's correct but we'll get back if that's not right.

The fourth quarter contribution from PNGTS. Does that include anything that was retro active in quarters in 2002?

Portland may have to do a small rate rebate, but it's very small.

And I'm assuming the accrual rate is in the 12.3% range, correct?

Sounds about right. Maybe higher maybe but not much.

Just last, there was a nice increase in operating cash flow. Is this sustainable in '03 and perhaps if you could just explain where the variance came from in '02.

Do you mean corporately or from Portland?

Nope, generally corporately, sir. The $1.8 billion.

That's in around the level we've been talking about, probably slightly higher than the $1775 I've talked about in the past. The higher cash flow is obviously due to higher earnings, and some that is repeatable. The things that aren't repeatable like the one-time items in the fair return decision, those kinds of things. That impact the one-time events but I think on a sustainable basis, what we've talked about is cash flow in that $1.75 kind of range.

Very lastly, the hearing to consider the 2003 tolls begins on February 24th. Is the decision predicated on a rehearing of the fair return? In other words, does NEB actually have to hear the fair return appeal or agree to hear it and then actually render a decision prior to being able to issue the 2003 rate decision, or can they proceed separately?

Karen, there are two scenarios here. One is that the NEB may decide to hear, fairly shortly that they're simply not going to entertain our review and variance application in which case that whole thing is a dead file.

Right.

And for 2003, they then need to determine what the ROE and equity thickness and other factors like that will be. Our application is that whatever they decide out of the review and variance, we are proposing that that would be the basis for setting our equity thickness for '03. So, it is a little bit vague right now because we don't know what they will decide in terms of the fair return. We're not anticipating any kind of a full-blown hearing around the review and variance of the fair return. It is really an application to have the NEB reconsider the evidence. And that's what the review is, and then if they see fit, vary the decision. That's the way we see it, but so we don't expect one big hearing coming in front of the other but at this point, we have got no insight as to what the decision will be on review and variance.

My question really was are they going to proceed with potentially the 9.79 ROE and 33% equity thickness in determining the '03 rates and whatever it is they happen to decide, even if they hear it or reconsider it, they can then subsequently adjust rates?

Karen, it is Lee here. The cost of capital is not actually included in the 2003 rate application that we've made. We've left that up to the final decision on the review and variance.

Ok. Thank you.

thank you very much, Miss Taylor. Our next question will come from Mr. Andrew Kuske from UBS Warburg.

If we accept step back a little bit and take a look at the dividend, last year, you had nearly a 12% increase. This year, fairly impressive at 8%. Are we to infer with the shelf prospectuses and the cutting back of the dividend increase that you're in growth mode at this point in time?

I wouldn't interpret that at all. I think what we've said is that if we continue to grow earnings on a sustainable and predictable basis, the board will have the opportunity to increase dividend. I think we look at the dividend, not in the context of growth but in terms of our long-term ability to pay the dividend on a sustainable basis. And I would think for us, a 12% increase on an annual basis is probably not sustainable given our risk profile. We thought that at this point in time, 8% was a more prudent and sustainable number. It had nothing to do with growth mode and you shouldn't interpret it as such as the dividend is an important part of our commitment to our shareholders, and our commitment is to continue to grow earnings and grow dividends.

Ok, if we turn our attention to the Bruce, will you be providing monthly output statements for the Bruce? Some generators around the world do provide monthly output statements and considering a bit of the sensitivity, in fact, just the leverage that exists with that type of facility, will you be providing that kind of statement?

Not sure what you mean by leverage but I think that it -- to the extent there's regulatory reasons for providing output reports, we'll comply with those. I don't know what those are right now but current time, I don't think we have any plans outside of that to be providing the market with monthly output reports.

Ok. And then if we take a look at that after tax, the $100 million after tax, the deferred gain on the disposal of the natural gas, marketing cash unit, what conditions do we really need to see for you to realize that gain?

I think the -- one of the impacts we've had on the current year in terms of continuing to defer it is the absolute level of prices has increased. As we said basically, what we have to wait for is for time and over time, the contracts roll off. But at the same time, there is still price volatility in the marketplace and prices of natural gas have increased substantially. At the same time, we've had roll-off. So, our net position hasn't changed. Materially, but we would expect that over time, the bulk of the -- the exposure will roll off. I think the number this year is -- we had a substantial reduction in the volume. Which was as I said offset by the price by the end of June this year, I think we see another reduction and a substantial reduction in the gain by June. If power prices -- if gas prices stay the same, we would see our -- our exposure reducing and our ability to reconsider booking that to where it would be more positive.

So potentially third quarter if all of the conditions remain true that you just mentioned, we could see you realize this.

Again, I don't want to predict what prices are going to be or what our books are going to look like and as to whether or not it would be third quarter, fourth quarter. If things go well, we would expect to see a change in that position. Either -- towards year end.

Then if I may just one final question. Just on the Bruce. And contracting rates on the Bruce. You're about 40% or 50% open on that facility. I'm assuming you want to get up to roughly 75%, fully contracted. Now, what kind of contractual rates are you going to be seeing or are you projecting going forward.

Again, we're not predicting power prices. What we laid out was what -- what the volumes are that we expect to be producing from Bruce. But certainly not the prices. You can apply your own judgment, I think, to the Ontario market as to what you think power prices are going to be.

Ok. That's great. Thank you.

Thanks, Andrew.

Thank you very much Mr. Kuske. Our next question will come from Ms. Maureen Howe from RBC capital markets. Please go ahead, ma'am.

Thank you, good afternoon. I want to start with the general administrative and support costs within the power segment. Very significant increase both for the quarter and for the year. You do make reference in the description to the cost of project development and that they reflect the continuing investment in the power business, but this is a really substantial increase, and is there opportunity there to bring that down or is this something that's going to continue into the future?

I'll make one comment then maybe pass it on to Lee. I think what we did is we handled the Bruce expenses in a conservative way. We haven't closed Bruce yet and the year it closed, we would have normally capitalized those if we had closed Bruce within the year. We chose not to do that because the deal didn't close during the year. So, there is that element of the sort of what I call an anomalous event where your costs do escalate once you get into a transaction that you're going to close versus sort of ongoing expenses of chasing things. Maybe I'll let Lee fill in the rest of the blanks.

I think that's a fair comment. And I think given that that occurred in the fourth quarter, the major wrap-up of the costs, it is a fair comment to say that the 25 is probably a little higher than we would normally think the quarterly numbers would be. The average for the year and that line item is about $18 million. So, to go forward, it is somewhere north of 18 and south of the 25 we reported. Very much dependent upon the level of it particular business activity we do in a particular quarter.

Ok. That's great. Thanks. Talking and keeping along the powerlines, talking about power plant capital spending, I know that your partner in Sundance has talked about putting material capital spending requirements to meet future -- I guess it is environmental regulations if I understand that correctly. Can you talk about that, and also, perhaps with respect to Sundance A as well?

I think that there is a comment -- commitment that we pay for the capital costs but if they're unreasonable, then we have the ability to -- I don't remember the exact numbers but we have the ability to turn the facilities back to the government. So, issues like Kyoto, greenhouse gases, those kinds of things and the costs associated with the potentially cleaning them up, if you want to call it that, are things we've talked about but in sort of the worst-case scenario, we can turn the facilities back. But we -- I'm not aware of any capital expenditure profile or proposition by the operators of those facilities at this point in time that would make them uneconomic.

Ok. So, if I understand it correctly, there is some environmental rates to be met with respect to particulates which would include adding scrubbers and that type of thing, as well as, being on the hook for any changes in regulations that come out of the, adopting the Kyoto protocol?

Yeah, those are costs that are passed through in the cost service to the buyers under the PPAs. But like I said, we haven't been informed of any escalation in our expectation of what the costs will be. When we originally did our economics, we did build in costs for those things. Capital additions in the future. And we haven't seen anything from the operators that's unexpected at this point in time.

Oh, ok. With respect to the McKenzie Valley pipeline development, I guess this is probably a question for Hal, the announcement, or I guess, the stories that have been in the press in the last couple of days are regarding the over-the-top route. Can you provide us any insight on how that might impact the McKenzie valley, and also any developments as you see them with respect to addressing the northern party concerns regarding the $70 million?

I'll make a couple of comments, Maureen. First, we don't think anything related to over-the-top is likely to be going ahead. But the people who are actually making the decision on the Alaska project are probably leaning in other directions and doing projects that are more pragmatic and practical than attempting an over-the- top. It is just too much risk given all of the other risks of the project, and we just think it's highly unlikely. We've done a lot of work on this, so we're not just speculating. Secondly, with respect to the McKenzie Valley, both projects, both Alaska and the McKenzie Valley are of sufficient volume that you can reach a pretty economic, economy of scale even with just the BCFA coming out of the McKenzie Delta. There is no substantial cost advantage in the integrating the two projects into a single pipeline. Among other things, a single pipe to serve both projects would be a pipe that's bigger than anything that's ever been built, and we don't think this is the circumstance to try something that radically new and different. So, we would see even if there was an over-the-top pipeline coming out of Alaska, that the McKenzie Valley would still be served by an independent pipe. Among other things, they're on very different time lines. We see the McKenzie Valley as a very do-able, relatively near term project. 1200 kilometers of medium diameter pipe is not a particularly difficult undertaking, and we think that can go ahead fairly quickly here. So, we don't see a whole lot of likelihood of an over-the-top line anytime. And even if an over-the-top line was to go ahead, it would probably be much after the McKenzie Valley gas was to come on.

Well, let's say that -- and I'm sure it is, it is absolutely true and accurate. But if the over-the-top group makes an agreement with northern parties promising 100% ownership interest and that the agreement and the support of northern parties is a requirement to get the McKenzie Valley route built, does it not -- regardless of how rational it might be, create problems?

I think it is -- it is an issue, certainly. It would be a whole lot easier if there weren't proponents of an over-the-top route working up and down the McKenzie Valley making outlandish proposals to the local residents. It would be much easier if they weren't doing that, but at the end of the day, rational and do-able projects will prevail. In our view. And so we think that McKenzie Valley is just so enormously more do-able than an over-the-top pipeline that at the end of the day, that would be the one that goes ahead. Related to, that I would point out that everybody -- sometimes forgets that the big producers who hold all of the gas actually make the decision at the end of the day as to how this is going to happen. And I'm not aware that the producers at this time are enthused about being involved in any over-the-top pipeline or any pipeline that's 100% debt-financed or any of that kind of stuff.

Total agreement. Just while they make the decisions, they also require the support, right, of the residents and the local owners of the land.

Yes. I agree they do. And those are difficult issues to work through when you have all of these other bizarre proposals being floated around.

Just going on to Bruce, one of the questions that I think often comes from a company like TransAlta investing and operating entity like Bruce is the concern that well, why would a company take a 31.6% interest in another company and not have control and not really have any strategic input. It looks like they're just the providers of capital they might as well be a bank, and listening to your thoughts to Sam's question about well, we're not really particularly paying any attention to these acquisitions, we've got our own things to focus on, not withstanding the fact there has been $376 million invested in this project. How do you respond to that sort of concern on the part of your investors?

Well, first, Maureen, let me clarify what I said. It was that we at TransCanada and as Russ added, are partners in Bruce as well, are not particularly concerned or interested in all of these other widespread nuclear opportunities like Amerongen or Point La Pro or other things. We've got our own business to focus on and our own business in that sector is Bruce. We're very focused on Bruce and we're very involved in that and we're going to be very knowledgeable about Bruce as things unfold there. And we're going to be spending a lot of time being on top of what's going on. The key point though about operatorship at Bruce is that one of the challenges we don't face is putting together a team of people that can take over and operate that facility. That team of people and they came with the facility and in our assessment, they're very good at what they do. So, we're deeply interested in Bruce and we're certainly very involved in all of the commercial activity around Bruce. We're comfortable that we've got a technical team there that will do a very good job of taking care of the nuclear and other equipment issues, but I didn't -- I'm sorry if I was interpreted to say that we're relatively unengaged in Bruce. We're very focused on it. We're just not conducting the technical work of the operations day-to-day.

So, if I understand you correctly, when you said you're not really paying much attention or not interested in the other nuclear opportunities, you were actually speaking for the management at Bruce.

No, I'm -- I was stating the position that I can really state which is the position of TransCanada. The Bruce team may be interested in kicking tires on other things. We don't mind if they float different ideas past us from time to time. But we would say to them, as I'm saying to you, right now, that job number one is to really get Bruce to run at the very highest possible level of efficiency and reliability, and the big challenge for all of us is just completing this Bruce A restart. We're well along in that. We think the regulatory process and the technical work are both going very well. And we're optimistic and quite pleased with what lies ahead of us on Bruce A and he's where we think the team will be focusing all of their attention for the rest of this year certainly.

And just to add to that, Maureen, we have had discussions with our consortium partners both Borealis and Camco and we have discussed those longer term opportunities, but as Hal pointed out, the focus of the group is on a Bruce A restart and regulatory and technical issues associated with that. The various capital programs that are in place at Bruce B. Technical employee programs that are underway. There is a large, large workload for those -- that team there, and we've challenged them to get those things done. So those other things are out there, but certainly not the focus of the partnership at this point in time. I would say with respect to a mode of operating businesses, this is something that we've done historically -- we don't sort of differentiate this from the way that we would operate Iroquois pipeline which we do with a number of partners so we're not day to day operating it. There is a management team in place. But we do take an active interest in regulatory issues, marketing issues. Capital addition issues, expansion. Those kinds of things. We do it on AirQual, for example, Great Lakes, northern border, Tuscarora. This is a mode of business in this industry of joint ventures and partnerships to operate significant infrastructure assets. It is very much in line with the way we've operated in the past. That's the approach we've taken to the partnership and to the consortium.

Ok. And just one final question. For 2002, growth on a normalized basis, and I suppose this will be subject to one's normalizing adjustment, but growth under normalized basis was pretty modest year over year. Any comment on what we might be looking at for 2003?

And Maureen, you're talking about growth in --

Earnings per share.

Yeah. I just offer the comment that you know, TransCanada is in very capital intensive long-term businesses. And growth is not the be-all and the end all. Sustainability, stability, good financial performance and results, we think these are things that marketplace has a high value on. We certainly have ambitions to grow but from time to time, we may shed assets and we just don't think that earnings growth rate is really the key measure for how well a company like TransCanada's doing. We think there is a bunch of others as well. Stability of earnings is probably job number one for us. And then keeping things and making sure everything is sustainable over the very long-term would also be a priority. So, those two in addition to growing our earnings and cash flow, those are the priorities we're focused on.

Ok. Thank you very much.

Thank you.

Thank you very much, Ms. Howe. Our next question will come from Mr. Peter Case from CIBC World Markets. Please go ahead, sir.

Two questions if I may. First of all, Russ, on your cash flow statement, Q4 investment of $103 million in deferred amounts. Any idea what that represents?

Lee, go ahead.

Essentially, the change that we had in most of our regulatory deferral accounts [INAUDIBLE] at the end of any given year, Peter?

Then the other question, Hal, can you give us a bit of an update on your view of the U.S. acquisition landscape of how things may have changed in the last quarter with respect to, willingness of sellers to negotiate, or bankers to take less than 100 cents on the dollar?

Sure. Peter, I think it is an evolving situation and it is not evolving particularly rapidly. These are big quagmires that a lot of our U.S. friends find themselves in. It will take them a while to work their way through it. One of the challenges we see in the U.S., people look at the different levers they can pull to work their way out of a financial mess. And they think about selling assets and they invite people to come in and take a look at the asset. And at the end of the process, they conclude that they wouldn't be any better off having sold that asset and paid down debt. But really they've got much more fundamental problems than that, and they're not going to work their way out of it by selling assets. In some cases, the sale of assets will work. We've managed to do some smaller transactions but you know, one of the things you're dealing with in the pipe business is a fairly concentrated industry sector. There aren't 20 or 30 or 40 players in the pipeline infrastructure business the way there might be in the oil and gas producing sector, for example, and as a result, you know, it takes a long time to get some of these big issues sorted out. We have worked hard on a number of different situations in the U.S. We're being very careful not to pay too much for things. We don't think this is -- a good time, except in the case of a very, very strategic asset to pay up. And as a result, we've missed out on a couple of deals, but we're not unhappy that we did miss out. We continued to have our powder dry and we're very familiar with a large number of situations unfolding in the U.S. I think 2003 will be a year in which some significant transactions do occur whether or not TransCanada's involved in those will depend on how highly we view the assets and how intense the competition is. One observation I would make is that the opportunities in power generally come in smaller bite-size pieces. There are a lot more of them. Many more players in the power generation market. Much greater diversity of opportunity available to us. And we just generally do find that it's easier to do power deals that meet our financial return requirements than pipe, where there's much more concentrated, sweet of assets and fewer come into market.

Great. Thanks very much.

Thanks, Peter.

thank you very much Mr. Case. Our next question will come from Mr. Bob Hastings from Raymond James. Please go ahead, sir.

Thanks. Just a couple of quick ones. In Ontario, for the nuclear, what percentage of the output did you say is merchant for 2003?

For 2003, looking at an estimate of -- in the presentation that we made a couple of weeks ago, when we announced the deal, I think the on here is 46%, Bob. That would include our estimate of what we think Bruce A is going to be.

Ok. That's what I had. I thought you said another number earlier.

I used 60. That's of Bruce B currently. As we move into '03 in terms of availability, it is 46%. But you know, we're being probably overly cautious in 2003 because Bruce A isn't up and running yet and we don't know exactly when it's going to happen and what the difficulties will be. So, that percentage would be lower than I would expect to see it on an ongoing basis once we get comfort with Bruce A.

Just to be clear, Bob, that 46% is the amount under the PPA. Under PPAs.

Right. Ok. And you didn't want to make any comments on your sensitivities earnings to electric prices in the Ontario market and what's going on in the market now?

No, I think again, we ran our economics for the Bruce transaction at sort of the $43 cap level. Provided -- hopefully enough information with respect to output. And people want to, they can slide in all kinds of different prices but at this point in time, again, we're not going to predict what prices are going to do in Ontario.

Ok. Then the last question was on the environmental cost that was talked about earlier. Do you have the option of having the plant upgraded or buying credits or is that -- is that the decision made by the operator?

I'm not sure what you're referring to in terms of buying credits.

In terms of pollution credit offsets if the market develops, you might be able to buy those as opposed to spending money on the plant.

Is this for Bruce?

No, I'm talking about Alberta.

Ok. Bob, that would be an item that we would sit down with TransAlta operator and with the representatives of the Alberta government to talk through that and figure out the best way.

Obviously, everybody wants to do it in the least cost way that is the least painful for everyone and some people still would be of the view that maybe we can figure out how not to do it at all. And there's I think some reality in that as well. So, it is a complex issue. Our main fallback position is we do have the right to put the asset -- or the PPA entitlement back to the province of Alberta if it becomes unusually onerous or painful and that's a number of years out, you know. We're not facing any sort of immediate CO 2 restrictions or problems in the next seven or eight years.

Ok, thank you very much.

Thanks, Bob.

thank you very much, Mr. Hastings. Once again, if you are from the analyst community and you have a question, please press 1 at this time. Our next question will come from Zahir Khan from Baker and Associates.

Hello, gentlemen. Well-done job in the year. I just want to touch base on the [INAUDIBLE] basically current protection measurements, which has certainly improved, given that there have been debt reduction of about $426 million, as you mentioned as well as, the $486 million and increases in subsequent shareholder's equity. Now, given these numbers, and are you basically on side with the rating densities criteria for maintaining the rating in the A category?

This would be with respect to --

Your debt to capital numbers. And other things definitely have improved with lowering expenses and obviously finances have been reduced as well.

Yes, we're getting closer to being in the -- the issue is that we have in front of us is what S & P refers to as their global grid. For utilities and pipeline companies and traditionally, or historically, we haven't been an A grade credit in those grids and they've given us, Canadians, for the most part, the benefit of the doubt. Because of the unique Canadian regulatory environment relative to other places in North America and other places in the world. So, we're still outside of those but by that, we have improved to a considerable extent such that we're creeping up to those categories now. And I think part of S & P's -- the discussion we'll have with S & P is how they're going to work the global grid, given that in each jurisdiction, there is unique circumstances that will cause them to have to go outside of that grid. Or else they're not going to be able to give -- what I would call it, a fair and accurate rating for the unique characteristics of an individual company or an individual country or location. So, that will be part of our ongoing discussion with them but I think if your question was, are we do we meet the global standards, we're not there yet.

But I mean what will be the debt to capital number at the end of this year -- I mean last year?

At the end of the year, we had I think it's 57% debt and 35% equity, if I remember correctly.

So the balance will be --

There's 2% preferred shares and the balance being preferred securities.

Ok. Now, is it any move basically with respect to like a [INAUDIBLE] separation of debt, debt, I mean there's always some concern that the level -- the hard core debt. Are you going to clarify that basically for the rating, as well as, for the investing public, you know? Are you intending to maintain basically a [INAUDIBLE] the issue or basically, you know, going forward.

We've -- we had a number of discussions with bondholders last year with respect to amending our -- of some our bond covenants. One of the alternatives to making the bond amendments was a hold type structure. We continue to discuss that. There is other positive attributes of a hold structure with respect to flexibility in organizing your affairs. There is negatives as well and we continue to discuss all of those. So, I would say that yeah, we do we would do it in a prudent way that allowed us to maintain A grade credit. Such that we would be in a position where we could issue debt at the lowest possible cost. It will be a consideration if we were to go that route. But that's just one of the alternatives that's currently in discussion.

Given after Bruce, obviously there is some debt accumulation there as well. I mean you're not -- I should say joint venture debt or something like that would have creeped up as well. Is this rating -- not going to include that kind of debt in your calculation? I mean --

We're totally up-front with them as to how much joint venture debt. In Bruce in particular, there's no joint venture debt. There is no debt in Bruce today. The only thing that existed in Bruce was that $225 million deferred lease payment that we've talked about which we're paying out as part of the transaction. So, there is no project debt at the Bruce level.

Ok. Great. Thank you so much.

Thank you.

Thank you very much. We will now pull questions from the media community. If You're from the media community and you have a question at this time, please press one on your touch tone telephone. Our first question will come from Jillian Livingston from the Canadian Press. Please go ahead, ma'am.

Hi. How are you doing this afternoon.

Good, thanks.

That's good. I was just wondering, there's been a lot of talk both in your news release and today during this conference call about acquisitional opportunities out there for you. Just wondering if you might sum it up a little bit for me in sort of what areas you would be more interested in. I know you made it very clear that you're not about to go willy-nilly and buy whatever is out there. If you could clarify what areas you might look at, whether or not power you see that for the next opportunity for this upcoming year and following years and what opportunities you see in the pipeline area, too.

Sure. On the power front, I would point out that we have done significant acquisitions in power in each of the last three years. It is not a new thing for us. We continue to look at a lot of different power opportunities in both the United States and Canada. And when we find good ones, we go after them quite enthusiastically. As for my ability to predict what we'll be able to do in 2003, I just don't know at this stage. All I can say is we'll continue to be on top of power opportunities as they come up. Throughout Canada and in the United States. And we'll look closely at quality ones. I've described earlier in the call what kinds of criteria we look at as far as risk management and long-term stability and upside and Jillian, we'll it continue to do that, with respect to power in 2003. On the pipe side, it as I said a little more difficult in that the number of parties that own pipelines in the U.S. is quite small. And whether or not different pipe situations are going to come up for sale really depends on where these different companies are at in their various restructuring and financial workout processes. But obviously we would be more interested in large substantial pipelines with high quality earnings and cash flow. We're not particularly interested in junk collection. We're not buying a lot of small diameter short-distance pipes or gathering and processing businesses or anything like that. We're very much focused on the large diameter long haul, or very focused market region pipelines that fit well with the assets that we've got today. So, you know, there is a lot out there but I would say deals are more dealable and more likely to occur on the power side just because they come in smaller pieces and there are many more vendors of power plants than there are pipelines.

Right. Is there any certain types of power that you would prefer to look at or any particular areas that you would -- within Canada or the U.S., working more in Ontario or more along any particular side of the U.S. that is -- you know, appeals more to you or looks better as an investment opportunity because of what you already hold?

Well, I would refer you to something like Manchief which was an asset that we were very comfortable. It uses natural gas. It uses gas turbines and we consider ourselves experts in the gas turbine operating business. It has got very long-term contracts. Stable. Not a lot of volatility. That's all the kind of stuff we're looking for. In many cases, acquiring coal plants would be attractive because they're low cost, substantial long-term operations. But they do come with air quality and Kyoto risks and we're very mindful of that and careful not to get offside on those fronts. You shouldn't expect the TransCanada will be a major accumulator of nuclear facilities. Bruce is the largest single powerGEN facility in North America and one of the most attractive low-cost high-margin facilities we've seen anywhere. It is also a uniquely Ontario situation that we knew and understood very well. So, all things considered, we felt that taking a 1/3 interest in Bruce was a good thing for TransCanada to do, and a good solution to some problems that the Ontario market was facing. And we found as we did in Alberta, that participating in those market workout situations can sometimes be a very good thing for us as well. I can't be much more definitive than that. We're kicking tires on all fronts. Hydroelectric facilities, if those come available, we're always interested in looking at those, but they tend to be very few and far between.

So, nuclear but you basically see that Bruce is the acquisition you've made and that it is going to be a while working on that one that you won't aim toward those types of facilities.

Yeah. I mean we're not going to prohibit ourselves from looking at anything but I just would not wait in anticipation that TransCanada's going to do another deal like that. Bruce was a very unique situation. We're very happy with it. We think it will work out well. And we think that, that's going to be our focus in nuclear power for a number of years here.

Do you have any targets for any kind of acquisitions that you see in 2003?

Just good financial returns. That would be one.

But do you see -- I'm wondering how you could classify TransCanada? Are you sort of an active acquirer at this point?

We don't set out financial targets. This kind of relates to Maureen Howe's question from earlier. We're not particularly focused on acquiring a certain number of assets in order to meet some earnings growth target. We're very opportunistic and value conscious in these things. We'll look at assets as they come available. If the acquisition can be structured in a way that mitigates risk and is attractive to TransCanada, and we can get the asset at an attractive price, ideally in a downturn, well, that sounds like a good deal to us and we would go after that, but we don't set out a target that we're going to invest so many hundred million dollars a year regardless of what market conditions are.

Right. In the last little while with what we've seen in sort of different electricity and power markets in the United States, in particular, is it sort of in a state of flux there as you might see that, that's where some opportunities may come from because of some instability in different areas?

Yeah, I think flux might be a charitable word. Some parts of the U.S. power market are in chaos. And California is a good example. We're not interested at all in acquiring power-gen plants in California, but California does affect the power market in all of the western United States and there could very well be interesting collateral opportunities outside of California that come from that. We think the other parts of the United States that are in various phases of deregulation offer interesting opportunities. I would simply add that it's all very complicated. As we look at a place like New England that we know very well, there are many complexities to that market and very much depends on the circumstance and on the particular plant as to whether we would be interested. In fact, I would say the characteristic of an individual plant are even more important than the market region in which it is located.

Thanks very much.

Ok, thank you.

Thank you very much. Once again, if you are from the media community and do have a question, please press one at this time. Our next question will come from Mr. Tony Seskus from the Financial Post. Please go ahead, sir.

Hi, gentlemen.

Hi.

Just had a question. I wonder if you could speak about what your role is exactly in the McKenzie Valley pipeline. It is understood you're having talks with the APG. I was hoping for clarification on that front.

TransCanada is -- of course, Canada's leading gas pipeline company. And we have worked in the McKenzie Valley front for about 30 years looking at different ways of getting that gas to market. Over the past three years, we've been in frequent discussions with the producers in the McKenzie Valley about what kind of a role we might be able to play in helping them bring that project on. And we essentially continue to do that. We continue to talk to the producers about what we can do to help out and we're particularly interested in making sure the gas connects to our Alberta system and moves through Alberta and on to continental markets through our main line and other systems. And beyond that, I wouldn't really want to speculate or comment on any of the speculation that comes up in the press from time to time. This has been going on for a long time. We've been at this project for about 30 years. And we continue to work diligently with the producers and beyond that, Tony, I really wouldn't want to say anything more than that at this time.

Ok. You have mentioned that -- you said the Arctic Gas over-the-top proposal, it was bizarre. I'm just wondering -- they publicly, they're saying they have a viable project. I'm wonder what do you think their motivation is if it's not?

They have no money. They're not planning to put any of their own money in. They're trying to -- planning to finance it with 100% debt. They have no gas. The producers are not interested in shipping their gas to market through that kind of a project. And from our perspective, they have no technology. This is not an established pipeline company that's proposing all of this. I put that all together and I think it is bizarre, and we don't regard that as a credible way to get northern gas to market. When you're at the high risk stage of building frontier infrastructure like northern pipelines, you need more equity, not less. You need people that are willing to put up real money and take real risks to get that kind of facility built along stream. And the Arctic Gas consortium isn't bringing any of that to the table. So, that's sort of the way we see it.

So, what do you think the motivation is then in locking up these -- or trying to lock up land deals as this most recent one on Friday?

We don't know.

Ok. Are you concerned they're just trying to lock up deals and someone might have to pay them to go away or what?

What we're always concerned that aboriginal groups and other people that are landowners in these areas might get misled into being part of a project that isn't actually going anywhere, and we would really prefer that that kind of stuff not happen, but we're not doing it and we're not involved with it and we're not supporting that project in any way.

Ok. Thank you very much.

Ok.

thank you very much. At this time, Mr. Monetta, there are no further questions registered. I would like to turn the meeting back over to you, sir.

Thank you very much. Thanks, everyone for your participation this afternoon. We look forward to talking to you again in the not-too-distant future. Bye, for now.

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