TC Energy Corp (TRP) 2003 Q2 法說會逐字稿

Good morning ladies and gentlemen, welcome to the TransCanada Second 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 very much. Good morning everyone. I would like to take this opportunity to welcome you this morning including those of you who are joining us through the worldwide web. We are pleased to provide the investment community, the media, and interested parties with an opportunity to discuss our 2003 second 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 will begin this morning with some comments on our results and other general issues pertaining to TransCanada. Following their opening remarks, we will turn the call over 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 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 it's strategic initiatives and whether such initiatives 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 it is result of new information, future events, or otherwise. With that, I will now turn the call over to Hal.

Thank you David. Good morning everyone and thank you for joining us. We are starting earlier than usual today as we are talking to you from Bruce Power in Kincardine, Ontario. I am pleased to report another quarter of strong business performance and solid financial results. The TransCanada team is highly focused on strong business performance on a quarter-to-quarter basis, and I am proud of the results that we continue to achieve. Three years ago, we embraced operational excellence as the key element of our business model and we continue to work towards ever-higher levels of operational excellence. Our solid financial results are an indicator of the success we have achieved in transforming TransCanada into an operationally excellent company.

Over the longer-term, TansCanada remains committed to real and substantial value creation for its shareholders. Over the past three years, we have made a number of moves to capture opportunities with value creation potential and I'll talk about some of those opportunities today. We have been diligent in our capital investment decision-making and disciplined in the execution of our growth initiatives. Capturing opportunities, making wise investment decisions, and executing to a high standard -- that is our approach to long-term value creation. Over an eventful second quarter, we made considerable strides to achieve growth and create value in our core businesses of natural gas transmission and power generation. We also continued to exercise the prudent financial management that has strengthened our balance sheet and given us the flexibility to pursue substantial value creating opportunities.

In the second quarter we also achieved strong financial results. TransCanada Corporation's net income for the second quarter was $202m or 42 cents per share compared to $205m or 43cents per share for the same period of 2002. For the 6 months ended June 30,2003, net income was $410m or 85cents per share. This was an increase of $18m over the $392m or 82cents per share that we delivered last year. Russ Girling will take you through the financial details, but I'd first like to take a few minutes to review some key business developments over the second quarter.

Let me start with our natural gas transmission business. In the second quarter, we announced two significant steps that further strengthened our position to bring northern gas to market. The first was the announcement in May of our agreement to purchase the remaining 50% of Foothills pipeline from Duke, including $152m of Duke's proportionate share of Foothills' corporate debt. We expect this transaction will close in the third quarter. The Foothills [arm sets] are a key element of our Western Canadian Pipeline business. The pre-build portion of the Alaska Highway pipeline project was constructed and placed in service more than 20 years ago moving Alberta Gas to U.S. markets in advance of flows from Alaska. We look forward to the day when the pre-build will actually be moving Alaska Gas to U.S. markets.

Foothills and its subsidiaries continue to hold the certificates to build the Canadian portion of the Alaska Highway pipeline. Full ownership of Foothills will enable TransCanada to play a more direct leading role in bringing the Canadian portion of this mammoth project on stream. Subsidiaries of Foothills and TransCanada also hold certificates to build the Alaska part of this project. We look forward to working with Alaska producers on that part of the project as well, but probably under different arrangements than in the past. We do expect Alaska Producers will play the lead role in the Alaska portion of the Alaska Highway Project. The second step in key development in our effort to bring northern gas to market was the announcement in June of TransCanada's involvement in the MacKenzie Valley pipeline. TransCanada, the MacKenzie Delta Producers Group, and the Aboriginal Pipeline Group reached funding and participation agreements that will enable the APG to become a full participant in the MacKenzie Gas Project.

We currently anticipate the funding that we will provide will be approximately $80m. In exchange, TransCanada gains a number of opportunities. First, the MacKenzie Valley Pipeline when built will connect to the TransCanada existing system in Northern Alberta. This will give the MacKenzie Producers direct cost effect access to the Alberta Hub and it will also benefit our existing producers in Alberta. The incremental volumes coming into our system in Northern Alberta will increase utilization rates throughout our Alberta System, and on our mainline beyond Alberta reducing tolls for all users. By enhancing the long-term viability of our Canadian pipelines, we are able to reduce the long-term business risks faced by our shareholders; as well once the decision to construct is taken TransCanada will have the option of acquiring a 5% ownership from the producer share in Mackenzie Valley Pipeline. In addition, should any of the producers choose to sell some of their equity, TransCanada would have certain first rights to acquire 50% of the divested interest with the remaining producers and the APG sharing in the other 50%.

And finally, TransCanada will have the opportunity to increase its equity ownership if should the pipeline expand beyond its original capacity. Once the APG has built itself up to a one-third ownership share TransCanada, the APG, and the other owners will each have the opportunity to take one-third interest in additional expansions.

Turning now to our power business, we announced in June in an agreement to develop the Becancour natural gas fired co-generation power project near Trois-Rivieres in Quebec. Over the past five years, TransCanada has established a strong reputation as a partner of choice in developing efficient environmentally responsible co-generation power plants. The Becancour project will be the first power facility we’ve built in Quebec, and at 550 MW, it will be the largest co-generation plant we’ve developed to-date. The Becancour project will supply its entire power output Hydro-Quebec distribution under a 20-year power purchase contract.

Given our location here at the Bruce facility at this morning, I’d like to offer some comments on our Bruce Power investment which continues to deliver strong operating performance. With the exception of a plan to maintain and salvage on one of the four Bruce B reactors, the Bruce B units have operated at 100% availability during the first half of 2003. This is the best operating performance in the plant's history. The restart of the two Bruce A units has been delayed primarily as a result of additional safety modifications, documentation, and testing necessary to meet Canadian Nuclear Safety Commission requirements. Once CNSC approval has been received on the first unit, the reactor will slowly ramp up to full power and synchronize to the Ontario power grid. The second unit will be expected to return approximately one month later.

Let me turn now to the regulatory front. There were two significant regulatory developments for TransCanada in the second quarter. In May, the Federal Court of Appeal granted TransCanada's leave to appeal to the National Energy Board's decision to dismiss TransCanada September 2002 request for a review invariance of the NEB fair return decision and I apologize for the complexity of that sentence. We are now pursuing the appeal on the two important questions of law that form the basis of our initial application. We remain concern that recent NEB decisions have prevented TransCanada from earning a fair return on our investment in the Canadian mainline. On our second regulatory development, in June the Alberta Energy and Utilities Board announced its approval of TransCanada's 2003 revenue requirement and tariff application settlements in respect of our Alberta system. These settlements resulted from a [consulted] process that included producers, industrial users, consumer groups, marketers, and export groups, and represented a balance of their interest. Having concluded that consultation process and received regulatory approval. We will now finalize 2003 rates based on these approvals and apply for a formal approval of the new rates as directed by the EUB.

Finally, and in closing I had an opportunity last month to address the United States House Committee on energy and commerce on the subject of natural gas supply and demand. Obviously, it's been a topic that's significant to both of our core businesses. We are acutely interested in the long-term supply demand balance for natural gas. We move more gas over greater distances than any other pipeline company in North America, and natural gas is the fuel for about one-third of our power generation capacity. We see a pretty flat supply picture for the next five years until northern gas and offshore [LNG] come to markets. As I have said before, TransCanada is in the gas and power business for the long term, and we look forward to playing a significant role in bringing new sources of natural gas to the North American marketplace. We have made significant progress on a number of fronts during the first half of 2003, and I look forward to discussing those with you over the months ahead. I will now turn the call over Russ Girling, who will provide additional details on our financial results.

Thank you Hal, and good morning to everyone today versus usually saying good afternoon to everyone. As Hal said, we are very pleased to report another quarter of strong operating results. We continue to generate solid earnings and cash flow by focusing on natural gas transmission and our power generation businesses. As reported earlier today, net income for the three months ended, June 30 was $202m or 42 cents per share, compared to $205m or 43 cents per share for the same period last year. $3m decrease was due to lower earnings from the Transmission segment, which was partially offset by higher earnings from the Power business and lower net expenses in our Corporate segment. As you know, in the second quarter of 2002 we included an after-tax income of $25m for the period, January 1, 2001 to June 30, 2002, related to the NEB's June 2002 decision on TransCanada's Fair Return application.

Second quarter 2003 results for the Power segment include after-tax income of $19m resulting from a June 2003 settlement with a former counterparty, which defaulted in 2001 under a forward power contracts. This amount represents the value of the power forward contracts terminated at the time of default. On a year-to-date basis, net income was $410m or 85 cents per share, compared to $392m or 82 cents per share for the comparable period, last year. The increase of $18m or 3cents per share was primarily due to higher earnings from the power business and lower net expenses in the Corporate segment, which as I said, were partially offset by lower earnings from our Transmission segment. I will review the second quarter results from each of our segments beginning with Transmission.

The transmission business generated earnings of $144m for the three month ended, June 30, 2003, compared to a $174m for the same period last year. That decrease is primarily due to lower contributions from the Canadian Mainline and the Alberta System. The Canadian Mainline decreased by $21m in the second quarter of 2003, compared to the same period last year. The decrease in 2003 earnings is mainly due to the NEB's Fair Return decision of June 2002, which included an increase in deemed common equity ratio from 30-33%, effective January 1, 2001, and resulted in recognition in June 2002 of $25m net earnings for the period, January 1, 2001, to June 30, 2002. Earnings in 2003 for the Canadian Mainline reflect an increase in approved rate of return on common equity from 9.53% in 2002 to 9.79% in 2003, which was partially offset by a lower average investment base. The Alberta System's earnings decreased by $8m in the second quarter of 2003, compared to the same period last year that decrease is due to lower earnings from the one-year Alberta System revenue requirement settlement reached in February of 2003. This settlement includes a fixed revenue component of $1.277b, compared to $1.347b in 2002, as a result, the Alberta System's annual net earnings in 2003 are expected to be approximately $40m less than 2002 than net earnings -- than 2002 net earning of $214m. As we have said before, a negotiation is leading to the Alberta System settlement or significantly influenced by the NEB's decision on our Canadian mainline share return application in 2002.

And finally with respect to our transmission segment, our share of earning from investments in North American pipeline ventures in the second quarter of this year was $27m compared to $29m last year. Earnings for the second quarter was slightly lower than the same quarter last year as a result of the weaker U.S. dollar and higher operating cost accretive rates which was partially offset by higher earnings from the TransGas Occidente asset in Columbia.

Next I'll talk about power. Our power is -- the power business contributed net earnings of $63m for the three months end at June 30, 2003, compared to $40m for the same trade last year. Total volume sold in the second quarter of 2003 were 6730 gigawatt hours compared to 4953 gigawatt hours in the same quarter of 2002. Earnings from the recently acquired interest in Bruce, a settlement in the Western operations for the value of terminated contracts with a former counterparty, as I previously mentioned, and the addition of the ManChief plant in late 2002 were the primary reasons for the increase. These were partially offset by lower earnings in the quarter from our Northeastern US operations compared to the same quarter last year and higher general and administrative and support costs.

Bruce contributes $16m of equity income, just $13m after-tax in the second quarter of 2003 compared to $38m or $27m after-tax in the first quarter of 2003. Overall prices achieved at the Bruce facility during the second quarter were $45 per megawatt hour compared to $63 per megawatt hour in the last 6 weeks of the first quarter of 2003. In the first 6 months, approximately 38% of the output was sold into Ontario's wholesale spot market, with the remainder being sold under long-term contracts. Excluding the plant outage of a Bruce B unit in the second quarter, the Bruce B units have operated at 100% availability during the entire first half of 2003. As Hal mentioned, the expected restart of the two Bruce A units has been delayed, primarily as a result of additional safety modifications, documentation, and testing necessary to meet Canadian nuclear safety commission requirements. As Hal pointed out, once the CNSC approval has been received on the first unit, the unit will slowly ramp up to full power and synchronized with the Ontario power grid. A second unit is expected to return to service approximately one month later.

Cumulative restart cost Ontario Bruce to the end of June 2003 for the two Bruce A units was approximately $610m. Bruce has invested approximately $235m on the two-unit restart program for the first six months of 2003, being an average of approximately $20m per unit per month. Looking forward, equity income from Bruce will be impacted by fluctuations in stock markets prices for electricity as well as overall plant availability, which in turn is impacted by scheduled and unscheduled maintenance. To reduce its exposure to stock market prices, Bruce has entered into fixed-price sales contracts for approximately 18,000 megawatts of output for the remainder of 2003. This represents approximately 57% of the average 3140 megawatts of Bruce B capacity or approximately 38% of the total 4678 megawatts of capacity, which includes the two Bruce A reactors.

As we pointed out the last quarter, there is an approximately two-month planned maintenance outage at one of the Bruce B units commencing in the third quarter of 2003, which will affect output accordingly. The previous disclosed one-month outage of one unit at Bruce A in the fourth quarter will not occur in 2003.

Turning to our Western operations, operating and other income of $60m in the second quarter of 2003 was $33m higher compared to the same period last year. The increase was mainly due to a $31m pre-tax or $19m after-tax positive earnings impact related to a June 2003 settlement with a former counterparty. This reflects the -- this amount reflects the settlement value of the outstanding power forward contracts that were entered in Q in the normal course of business and terminated by TransCanada as a result of a default by a former counter party in 2001. The TransCanada Power L.P. contributes $7m in operating and other income in second quarter an amount which is comparable to the $8m we reported last year. Operating and other income from our North Eastern U.S. operations was $36m for the 3 months ended June 30, 2003, which was $10m lower than the same period last year. As you pointed out last quarter, the decrease is primarily due to higher costs of fuel gas at the Ocean State power plant and fuel marketing opportunities in the first half of 2003, than were available in 2002, and the unfavorable impact of the weaker U.S. dollar. General, administrative, and support cost of $22m for the 3-months ended June 30, 2003 were $8m higher than for the same period last year. The variance is due to continued increase to business activity in the power segment.

Next, I will talk about our corporate segment. Net expenses of $5m and $9m for the 3 months ended June 30, 2003 and 2002 respectively. A $4m improvement is mainly due to the positive impact of foreign exchange. Now with respect to discontinued operations in the second quarter TransCanada mitigated its exposures associated with contingent liabilities related to the divested gas marketing operations by obtaining from [inaudible] Corporation, certain remaining contracts in June and early July of 2003. TransCanada simultaneously fully hedged commodity price exposure of these contracts. TransCanada remains contingently liable for certain of the residual obligations. At June 2003, TransCanada reviewed the provision for loss on discontinued operations taking into consideration of potential impact arising from [inaudible] filing for bankruptcy protection in July 2003. As a result of this review, TransCanada has concluded that the provision was adequate and the continued deferral of the approximately $100m of deferred after tax gains related to the gas marketing business was appropriate. As a result, there was no earning impacts related to discontinued operations in the second quarter of 2003.

Now, I'll turn to our cash flow statement and to our balance sheet. For the 3 months ended June 30, 2003, funds generated from continuing operations was $434m compared to $438m for the same period last year. Funds generated from operations were $891m for the 6 months ended June 30, 2003 compared to $893m for the same period in 2002. Capital expenditures, excluding acquisitions for the 6 months ended June 30, 2003 were $183m and related primarily to 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 for the 6 month ended June 30, 2003, totaled $412m and were almost entirely comprised of the acquisition of a 31.6% interest in Bruce for $376m, which includes [post-closing] adjustments. Our balance sheet remains strong comprising of 57% term debt, 6% preferred securities, 2% preferred shares, and 35% common equity. The company's discretionary cash position also remains strong as we expect to generate substantial operating cash flow.

In June, the company successfully issued $350m US of 10-year notes bearing an interest coupon of 4%. The net proceeds are expected due finance debt maturities over the coming months. In the next 6 months, in the 6 months ended June 30, 2003, TransCanada funded debt maturity as $59m and reduced notes payable by $82m. In early July TransCanada redeemed all of its outstanding $160m U.S., 8.75% junior subordinate debentures. Also no one has our cumulative trust originated for preferred security or [Coppers]. To summarize the company continues to deliver strong earnings and cash flow, which combines with a strong balance sheet provides TransCanada with financial flexibility to make disciplined investment decision in our core businesses. As we have said previously, we will continue to make profitable investments in natural gas transmission and power, but we assure that are evaluation approach will remain disciplined and focused to ensure we continue to enhance shareholder value.

We will continue to work on establishing a new regulated business model that provides value to our customers, reduces the long-term risks of our Canadian pipelines, and allows us to earn competitive returns. We will continue to focus on operational excellence with the focus on providing low cost, reliable service to our customers. And lastly, we will continue to maintain a strong financial position and will not compromise our credit ratings. Successful execution of these strategies has and will continue to result in earnings and cash flow growth and build value for our shareholders. That concludes my prepared remarks, and I will now turn the call back to Dave Moneta.

Thanks Russ. And just 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 will provide an opportunity for the media to ask their questions as well. With that I'll turn it back to the conference coordinator.

Thank you. We will now take questions from the telephone lines. If you have a question, please press "*" "1" on your telephone keypad. If you are using a speakerphone, please lift the handset and then press "*" "1". If at any time you wish to cancel your question please press the "#" sign. Please press "*" "1" at this time if you have a question. There will be a brief pause while the participants register for questions. We thank you for your patience. Our first question is from Karen Taylor of the BMO Nesbitt Burns; please go ahead.

Thanks. I guess it’s a good thing [inaudible] at first today, because I've got questions there. Just very quickly on the contract profile for Bruce, you said it was 57% for the second half of 2003, can you please tell me what it would be for '03, '04, and '05 with an average contract price in each of those years?

No, I think right now it does decline Karen, but at this point in time, we are not disclosing the market price that we have sold out. I think for the historic ones, you can bank on them being approximately around what we originally sold for. We have entered into some new contracts over the last month or two which we wouldn’t disclose the price on, but those original contracts were in that $40 range which we talked a little before, but there is a decline in profile over '04 and '05.

In price or volume contracts?

No, just in volume. We are intent to try to keep that level, sort of, 60% of the Bruce B facility, and once we get better clarity on Bruce A and we have some operating history on it, we would likely ramp up that percentage, but at the current time it will be our plan to sort of roll into '03 -- I mean '04 with similar kind of contract profile of having that sort of 60% range.

On Bruce B?

Right.

Just to clarify the outages, so we are looking then for no outages in the second half to the extent that the Bruce A unit 4 and then followed by unit 3 comeback and one 60-day outage on one unit of Bruce B in the third quarter, is that correct?

That's correct. That's about -- I think where we were before sort of 60 days of an outage of [1 new 800] MW unit.

And that was commencing later in the third quarter Karen.

Well if it's 60 days, is it all over your third quarter or starts in the third quarter and goes into the fourth quarter?

We are still scheduling that Karen. So I mean there is a lot of activity going on at the plant with the Bruce A restart, and so that scheduling activity is sort of in the planning process right now. So, I mean that's about the specifics we can be right now.

So it starts in the third quarter but could go in the fourth?

Potentially.

Okay, the margin of tax rates for the Bruce contribution to TransCanada's earnings declined from 29% in the first quarter of 2003 to 18.75 in the second quarter; can you explain the reduction in tax rate? And then give us an indication for the second half what the rate would be and then going forward?

Yes, I was just talking with Lee here is, can we get back to you on that Karen.

Yes.

I don't have a -- on top of my head, I don't know the answer of that.

Thank you. Our next question is from Sam Kanes of Scotia Capital, please go ahead.

That counter party contract brings the question I guess is, how much in the money or out of the money are you on other contracts of that nature, and was it I guess strictly default to trigger that contract, I guess, in terms of settlements without a default with these in the money or out of money contracts be triggered by any other means I guess.

No. I think in the [inaudible] case, basically we had the -- as a result of the default, we had the right to terminate the contract, I mean, and obviously we made provisions for it and then you know worked on settling that contract over the last two years. But really we -- at this point in time, we don’t have anything else in our portfolio that looks like that.

Okay. Switching back to Bruce, your $610m CAPEX spent to date, what’s left to spend and how much comes out of British Energy's pocket versus yours?

British Energy, I’ll answer the fist question, British Energy no longer has any interest in the facility. The $610 is the total spent to date. The amount spent in 2003 is about $240-250m in that kind of range, and that’s your for the period that we’ve owned it, the bulk of that $250 has been ours. We’re spending at about a rate, as I said, above $40m a month. That number is actually probably declining, you know, or probably close to the $30-35m a month, and that sort of spend rate will continue until the units are up. I think what you can expect is that as one unit comes up, that will decline again to about half that amount, and you know that run rate will continue until the second unit is up.

100% of which is -- it will be capitalized?

100% of that is capitalized, correct.

Thanks, Russ.

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

Thanks. Staying with Bruce, can you just clarify on the original presentation? When you bought it, there were some capacities for Bruce was -- for this year was 3,210 megawatts. What is -- and then for '04 you had 3,260. What is the capacity that you are looking out on [versus P&L]?

I don’t think that our forecasts have changed much. I think what we have told you is that the capacity is -- what the total capacity is and what we think our operating rate is, certainly the performance that we have had is that we are performing above that level currently. But just looking at the output numbers right now, our output for our capacity in that forecast -- there is no real change that we have in those capacity forecasts currently. The sheet that I am looking at right now is the slide from that presentation, and we had an estimate for 2003 of 3,210 megawatts and 2004 of 3,260 megawatts and a capacity of -- factor of 88% in '03 and 79% in '04. And I think currently, those are still our forecasts.

I must be missing something, Russ, because the press release here says the Bruce facility is 3,140 megawatts of capacity.

Yes, I remember reading that. So it says [3,140] megawatts. I will get back to Matthew, as to why there is difference between those two numbers of about 60 megawatts of capacity there.

Okay thanks. And then just staying with Bruce; on CAPEX, again going back to the presentation from when you brought it, forecast Bruce the CAPEX for next year was 215m. That number is still making sense or is there any opportunity to reduce that given the good operating performance you have seen there?

I do, but at the current time we don't have any other estimate than the one that that we've -- that’s been out there. As I said, our focus right is on A, and the certainly the program at B are still planned. And so we don’t have any better forecast at this point in time.

Okay. Can I just ask one more question then moving to a different topic on dividend? Was this your first level of dividend increase announcement this week? And my curiosity is just whether -- would investors or should investors expect to potentially see dividend increases half of the -- what has been the regular schedule of you know -- at Q4, when you announce Q4 results? And is there any reason to think about revisiting dividend policy in that regard?

We don't actually have a dividend policy in that regard. But you know I think that what you have seen in the past is kind of a practice that we adopted. This was purely an error that occurred on the part of the Newswire service in July. There was no contemplation of a dividend increase in 27-28. It was all very unfortunate and we apologize for it. But it should not be seen as the start of mid-year dividend adjustments.

Thank you, those were all my questions.

Thanks.

Thank you. Our next question is from Winfried Fruehauf of National Bank Financial. Please go ahead.

Thank you. Regarding the settlement of your contract, what was the term of that contract, both the start date and the end date?

I don’t recall, Winfried, but it was a term contract, but I don’t recall how long the term will last.

Okay, now does TransCanada PipeLines view the $19m post-tax contribution as ordinary income pertaining to the second quarter of this year or how does it look at it?

Well, I think that -- that’s a one-time item that would have been included in income in the month -- in the timeframe that would have actually occurred have we had not terminated the contract, it's income that’s now shown up in this quarter because we came to the settlement with the counterparty. So it's not a normal course business event.

Is there any way of breaking out that portion of the settlement that at least notionally applied to 2003 compared to other years?

I would say that it wasn't a long-term contract. So we terminated it in 2001. So part of it will be through to '02 and part of it to '03, and it's not a large number when you take it in that context over that period of time.

Okay so you think a portion of that contract would have been attributable to 2003?

Yes. So I mean, with that -- at least that length of a term, I hadn't actually thought about it in the terms that you are characterizing it, Winfried. So, I know its terms and it was a contract that probably went over period of '02 and '03. So it would have been sort of ratably brought in over '02 and '03. So it would have been $19m that have been brought in over the 2-year period.

Okay. The other question I have is with respect to the capital investments in Bruce, you're capitalizing your investments right now, the incremental investments, are you also calculating something equivalent to an AFUDC?

No.

And regarding the settlement of the Nova Gas Transmission tolls for 2003, how do you access your ability right now of mitigating some of the hits that you had announced earlier in the year and repeated today?

Oh, Win, it's Hal here. We see the mitigation as really being a really long-term process of continuing our efforts to achieve a fair return, not just on the Alberta settlement, but also on the NEB regulated main line. The Alberta regulator has initiated this hearing to examine the merits of formula-based returns in Alberta and we will argue our case thoroughly in that setting.

I think, thanks for that, I was more thinking of your ability to perhaps achieve cost reductions over and above those that are under appealing your settlement.

We certainly work away at that all the time, we are quite motivated to achieve those cost reductions, firstly for the near-term impact that they on our earnings during the current one-year period of the settlement, but also to make us more competitive and sustainable over the long-term. But I would point out in this case that we are operating under a one-year settlement in Alberta, we had our fixed revenue requirements. So to the extent we can achieve cost savings. There is a sharing mechanism there and we get some benefit from that, but, you know, when you only have one year in which to work on that, it's difficult to have a meaningful impact.

I appreciate it. Last question is, in the year-to-date, how much have you been able to retain from the sharing mechanism?

Win, I don’t know. It would be a small number at this point because we are 6 months into it. The cost savings that have been achieved would be in the single-digit millions, not a large number, and there was a caller within which really no sharing occurred. So it's a small number.

Okay. Thanks very much.

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

Thank you. Just one quick question on Bruce next year, I guess there was an expectation that some of the units or all of the units would be down early next year and I'm hearing it can yet be pushed to later in the year, would you like to comment on some of the planned maintenance schedules at Bruce in 2004?

I think that the current time our schedules for 2004 are unchanged, but as a result of the changes in schedule this year; will obviously be looking at the schedules next year and you know as we have more clarity we'll update you on those schedules for next year, but at the current time we don't have an update for 2004.

Okay, my understanding was that you had applied to ship that, but I'll wait till it is official. Next question with respect to corporate cost, just wondering what a run rate might be, I see that you had a little bit higher interest in other income earnings and I'm just wondering if that's offset with some of the negative impact of foreign exchange and other business units and perhaps going forward what I might expect to see there?

I'm [inaudible] here Linda. I think you are probably right. There are offsets given the natural offsets we have on US dollar income and the expense streams, and I would say that the amount of next expenses you are seeing in the corporate for the second quarter or probably occurred on the low side of the range, what we would expect on the go-forward position.

Okay, could you perhaps provide us with some sort of sensitivity to changes in the foreign exchange rate, I guess at a corporate level.

Well, I think what you've seen Linda is that we are pretty much hedged and so any change in the corporate segment that is positive will be a negative in mostly in the North American pipeline investments and in the power of North East segment and vice versa if the dollar goes the other direction, we will see positive movement on the US investment side and negative movement on the corporate expense side. So we are pretty much hedged. So the net number would be zero in terms of an exchange rate movement.

It's an offsetting movement.

Okay good. Then that's what I had deduced. Now just with respect to an update on acquisition activity, just wondering what you are seeing in terms of asset for sale within North America and if there is any sort of change in outlook in terms of pricing?

Linda we see opportunities still on the power side and on the pipe side, but they are of course moving very slowly. For those assets that are in bankruptcy processes, we can't expect to see the resolution of old situations soon. TransCanada continues to remain very close to those situations. We continue to look at those assets. Regulated pipes are proving to be quite attractive to a number of different buyers in North America and it's certainly not easy for us to buy them at what you might regard as the bargain price. So we are very being very careful about what we invest in because for the high quality assets the market pricing is pretty competitive. On the power side we are just looking at a lot of interesting opportunities out there in Power. I don't have any specific ones I can really tell you about today, but I'd say that the pace of availability of interesting power situation is probably accelerating rather then winding down.

Just final question with respect to contracting. I believe you mentioned that year-to-date 38% of process output was contracted. Is that from February 14, or from year begin.

Yes the other way out, about 57%.

Okay.

38% when there is actually the amount that was 5 not the amount contract.

Thank you. Is that from February 14, or --

From the beginning of the year.

From beginning. Can you give us that number from February 14?

Yes, it’s the same.

Okay, thank you. I'll withdraw my question.

Thank you, our next question is from Andrew Huske(ph) of UBS; please go ahead.

Actually it's Kuske(ph), but good morning. Harry made a comment that I wouldn’t really disagree with when you see the delta gas come down, you're going to have the increased pipeline utilization and across your system and then the risk profile is going to decrease, so the system tolls should decrease to a certain extent. But there's a bit of a -- one could argue a bit of a logical disconnect that as risks declines you generally are seeking great returns, yet of risks is declining in the future, why should the regulator be wanting to give you greater returns?

Well, I appreciate your point and I agree with it, but the issue that we see today is that we don’t believe the return that we're getting today is appropriate for the risks that we're facing in our business. So we believe that there is room for both, there is room for the long-term risk to come down and also for the near-term return to go up. Now how that improved, near-term comes about, there is a little bit of variability there, it could be through a higher return on equity reflecting the continuing near-term risk or it could be thicker equity which is away in fact to mitigate risk. So, the overall internal rate of return on our pipe investments could improve in a couple of different ways.

I guess, as an extension out of that and given what debt raters have done recently really have across the sector with downgrades, which would you prefer the higher ROE or just a greater thickness?

Well, I think, we would prefer both, but--.

But if it was one or the other?

If it was one or the other provided the ROE is that a certain minimum threshold which does not necessarily have to be an awful lot higher than it is today, but I think it would have to be a bit higher than it is today. Then we'd be bias towards greater equity thickness because of the stability that brings long-term.

Okay, and then a similar question. Just in the context of receiving [inaudible] from the court. One concern that we have about -- in fact we will be getting appeal, appeal the judgment that the NEB gave one could regard it as being lacking a lot of legal logic, and therefore a appeal was really a logical step on this. A clear risk that the court just effectively turns it back to the National Energy Board just under the Principle of Juridical Reference and then you are back at ground zero, and then the concern we have in the financial community is that we are so for off the time line of getting primary decisions and knowing really what you are going to earn in advance. Now, we are really looking two years back on a perpetual basis?

I think the way we look at it -- the way we share your concerns are all of the above. With respect to downside on the historic earnings, we don’t believe there is any downside to those decisions, there is only upside. If it works out in our favor and turn back to the National Energy Board, and they see if it changed their decision, with respect to the rating agencies and to Harold's point, it's quite clear that even at the current return that we get today and the risk profile of the pipe that the returns that we are getting whether you characterize it as equity thickness or as ROE, resulting cash flow, and therefore debt covered ratios that are insufficient to maintain an A grade credit. So, I mean all those arguments are still available to us even if the you know if it were turned down at the Federal Court level, and as Harold pointed out will continued to push down that path to seek returns that ensure the long-term financial viability of our pipeline system and like you, we're discouraged by having to continually do this on a retroactive basis and we’d like to be doing it in our more current year basis but unfortunately that’s, that is the process that we are in the middle of--.

And I just one follow-up on that, what is the timing for the court to actually hear the argument and then an extension on that, when you expect to put forth your next application before the NEB?

Well, I think we are going to be faced with again filing an application for 2004 before the NEB, before we have an answer from the court. The answer from the court will hopefully come, well let me phrase it this way, in less than a year and that will then -- if we are successful trigger some kind of a rehearing at the NEB level. Just to remind you that the reason we are doing all of this is our concern over the long-term business risk and stability and rate-of-return on the mainline, and in a follow-on sense on the Alberta System, and this is a long-term issue we are trying to draw attention to. So, it should be looked at that way rather than the impact on last year's earnings or next year's earnings.

I don't disagree with that at all.

We'll keep grinding our way at it.

That's great. Thank you.

Thanks.

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

Thank you. The question has perhaps been asked previously, but I am not sure if I fully understand it, and it has to do with the downtime -- at Bruce A which was previously anticipated to be taken, I guess in Q4. Russ, is that deferred to 2004, presumably it still have to come down for maintenance.

Yes, it does, and as a result of the delay, you know, it has to run for a certain number of hours before you take it back down again and what we know as the result of the delay, but that won't happen in 2003, but it will in 2004. And, as I said, as we move forward and understand those dates better, we will update you on when that will actually occur.

Okay, thanks. With respect to the sale of the gas marketing operations to Mirant, you've talked about basically mitigating the risk and taking back these contracts. So, if I understand it correctly, and I am not sure that I do, did you essentially like repatriate a contract that was held by Mirant and then hedge it?

Yeah, what we did is essentially where we were contingently liable on certain contracts that we had sold; we repurchased those contracts and then hedged the commodity risk portion of them.

And, do you have any credit exposure to Mirant at this point?

And that we continue to still have credit exposure to Mirant, and you know, that is one of the reasons why we continue to defer recognition of the gain and not change our provisions for discontinued operations. There are still other continued liabilities we have, but we are comfortable that the provisions that we have in the deferred gain are sufficient to cover any potential exposure that we have.

Okay and then with respect to Great Lakes, there was obviously some FX deterioration there, but you also referenced higher cost at Great Lakes, was that a material contributor to the decline in the contribution or was it largely foreign exchange?

I mean, are you talking year-over-year?

Yeah, basically quarter-over-quarter, year-over-year, yes.

The year-over-year -- the biggest one in the year-over-year was the Minnesota use tax, and I think that was $7m difference between this year and last year. Quarter-over-quarter there isn't a substantial difference; there isn’t anything really material between quarter-over-quarter.

And, then the $4m -- the FX seen at the corporate level, is that a hedge that actually sits there or is that basically the revaluation of U.S. dollar debt that's held at the corporate level, which essentially is a hedge for your U.S. earnings?

It is the latter, Maureen. It is the small amount of U.S. dollar debt held at the corporate level.

And so basically it's that 4m is like a reevaluation of that.

That is correct. Yeah.

Okay and then I was just wondering with respect to your agreement with the Aboriginal Pipeline Group, I think, in house comments you mentioned that the -- basically the amount that you have agreed to is up to $80m, if is the Aboriginal Pipeline Group is successful in the finding gas to ship on the pipeline and then move to -- up to -- lets say up to a [inaudible] and [30%] position or not even up to that, but increases, you know, get some sort of material ownership. Would TransCanada be prepared to assist in or at least entertain the idea in funding the equity component that they are going to require for that investment?

Maureen, there were two issues that we've talked about all winter. One of them was the structure of this funding advance to let them get through the engineering and application phase. And, the other was if they are successful on that and there is more gas then how do they fund their longer term requirements. And, we worked really hard with them and [examined] a number of different options and some of those options had TransCanada involved and some of them didn't, and at the end of the process, they also had discussions with the producers and they got a range of options open to them; none of which at this time would contemplate TransCanada putting up that equity, but we indicated to them that we remain willing to talk in the future and we'll just see how things go, but their desire to have some assured mechanism of funding equity in the future at the end of the day does not involve TransCanada.

Okay, that's great and then and how -- earlier or in previous comments that you've made in other quarters I guess; you've talked about [LNG] as something that TransCanada might be interested in, is that something that you continue to pursue or at least are you interested in pursing?

Yeah, Maureen, and I just like to clarify that, you know, a lot of our competitors have rolled out with a great deal of fanfare and hoopla our many different LNG ideas that they've had over the past couple of years, including some fairly exotic schemes. We've worked quite diligently and fairly thoroughly with a competent group of people for more than two years now on a number of different LNG opportunities. We started out by accessing the whole North American playing field and landing on, what we thought, were the most attractive regions of North America in which to play that business. And then from there drilling down and working with specific parties on specific opportunities and trying to advance those forward. So we have a number of well advanced, fairly detailed concepts that we’re working in and some excellent relationships with the kind of key players that, I think, you'd like to see us involved with. And we continue to work away on it, but as is our normal practice, we won't be announcing things or rolling out the fanfare until we actually have deals in place.

Are there any specific regions you are looking at?

Well, I can tell you that when you are looking at the North American continent, the price differentials from Henry Hub are an important factor when you think about where to bring LNG into the market.. And from that perspective, the Northeast U.S. and the adjacent parts of Canada are quite attractive, and the tradeoff is always between bringing the LNG into the highest value market versus the incremental cost of facilities if it's in a socially challenging area and the amount of pipe that we have to build to get up from an easier area into the market of choice. So, regionally, the Northeast U.S. and Eastern Canada and then within that try to optimize the balance between market value and pipeline cost.

Okay, that’s great. Thank you much.

Thanks, Maureen.

Thank you, our next question is from William Lacey, First Energy, please go ahead.

Hello, gentlemen. Just a couple of quick cleanup questions. Cargo came up with an announcement yesterday that [Moran] would not be paying for its June 2003 excess gas purchases and now TransCanada is the avenue for sort of the recovery of these funds, and you have a line of credit, I believe, of $141m U.S., and what is the status as far as the payment of this and what is the status of the LCs backing this up?

Well, a lot of what you’ve just sort of outlined is, it's fairly confidential information that I suspect you’ve picked up from a number of different sources given how many producers are probably involved. But as far as we know to-date, you know, the payment isn’t due till the end of today, and if the payments not made then we have certain rights to draw on certain security that we have. There really, you know, really not much to say in terms of the status of those kinds of things that showed a normal course business, you have a defaulting counterparty and liquid security to drop on, and there is a process by which you have to execute that, and if the payment is not made, ourselves along with the producers in cargo will be involved in executing that security, and you know, making good on the payment.

And you have got no concerns regarding the security behind this? On the LC side?

Again, you mean, I would say all of that is sort of confidential and certain legal type information at the current time as to whether or not we can do that. At the current time, we don't foresee any reasons why the security would be invalid.

Okay. Second thing on the [APEX] impact for the corporate level in Q2 is about $4m, can you tell me approximately what you think it was for the first quarter?

It would have been less than that, I would say. It is probably less than half of that.

Okay. So looking at sort of a more normalized EPS after taking out the power sales contract because the APEX sort of [nets that] against the other operations would be looking at normalized EPS of around 38 cents per share?

I think now I can say that if we took out the 4 cents in the power segment, it would be 38 cents and that is probably not an unreasonable number for operational result in the second quarter.

Great, thank you.

Thank you. Our next question is from John Edwards of Deutsche Bank. Please go ahead.

Yes, good morning, can you hear me.

Yes, we can John.

Okay, great. Just could you go into a little more detail, you know, on the funding on the McKenzie Delta, McKenzie gas project, the 80m that you referred to in the release. About -- over what period of time would you expect that to be spent and I assume the 80m would just be, that's the only amount you would be responsible for?

That's the only obligation that we have is to fund that. And John we would expect that to be spent over a couple of years. Whether it's intended to be funding for the period until formal applications to proceed are filed with regulatory body. And it's been something that I have been fairly public about in my comments, but we need to do everything possible to shorten and expedite that regulatory process. We are not suggesting in any way that regulatory steps be skipped or not done, but we think it's very much in the interest of the aboriginals and all the parties to the project that this get dealt with in a fairly efficient way. So if it was possible to deal with that in 2 years rather then 4 that would be great and it will allow the project to proceed more quickly and obviously we'd put up less rather than more of that $80m because a fair bit of it, just month-to-month burn rate stuff.

Okay and then any other input you can provide us on when Bruce units would go back on line or when do your regulators are going to allow you start that back up.

Nothing further than what we've disclosed.

Okay, so it important, but it is possible it could slip another month or two here.

Nothing further than what we've disclosed.

Okay, that's it from me right now, and I'll take others off line.

Thanks John.

Our next question is from Bob Hastings of Raymond James. Please go ahead.

Yes, just a may be a couple of technical small questions. The northern pipeline expenses didn’t look like there was anything there in the recorded [inaudible] development in the quarter, now that you've got an agreement, are you capitalizing expenses?

No, but we will, we will be capitalizing the $80m that Hal just finished talking about.

So you spent no money in northern development in this quarter?

It's mostly in the [inaudible].

Okay.

We're not spending a lot of money on; you know, we're not into a big dollar spending phase. That big dollar spending phase would have picked up to some extent around the start of the third quarter. It was a course right at the end of June when we finally concluded the arrangements with all parties.

Okay, but you wouldn’t -- from here on in now you have an agreement would you be looking to capitalize just [inaudible]?

No, this is the cost associated with that part of the capital project, I mean to the extent there is a -- all of our cost are going to be included there with respect to Mackenzie Valley project from an engineering construction prospective, but to the extent that we have other expenses, we'll continue to expense those on as we go.

Okay, and on the Power -- Western Power side for 2002 the numbers were restated by 5m pre-tax of 3m after-tax, what was that for?

Sorry, can you repeat that?

Yeah, Western Power operations, from where you reported last year in 2002 in the second quarter, the numbers came off by 5m pre-tax and or about 3m after tax, reported last year?

I'll have to look in to that, Bob I don't recall that number, so we'll look into that.

And is that's always memorized.

Well, Bruce I don’t have the second quarter [inaudible].

I know, I am kidding -- I am just kidding. The last question, Rush you talked about in your initial model out there that you are looking for -- you thought you've hit certain growth rates, I wonder if you would care to share sort of what the targets are for over the next couple of years?

You know, we don’t set that earning targets in the marketplace, beside if we continue to invest, as I said before we continue to invest the major drivers continue to invest our free cash flow, and if we continue to do that as wise as we have done over the last couple of years, we will continue to drive the same kind of growth rate we have experienced over the last couple of years?

Okay, and I think I've heard from Hal that the opportunities looks like they were improving [inaudible] rating?

They come and they go, but right at this particular point in time, we see lots of good and interesting opportunity on the power side, as I've said before, that's a very big business. There's a lot of things happening there. It's a little tougher on the pipe side. We are determined to be very selective on the pipe side and not buy pipes that don’t really have a good strategic fit for us. With respect to the capital spend, I mean we've always said we've got about $1b to spend on an annual basis. We are getting pretty close to that number for '03 already with Bruce and Foothills. As we look into '04, we still got capital spend on some construction projects, maintenance capital and the [inaudible] project will take us '04, '05, '06. So, we are starting to build sort of that -- the stand if you will of that $1b on good projects for -- at least for '03. We've got visibility on '04, and as Harold pointed out, there is number of other opportunities out there. So there is some visibility for you.

Okay. Thank you and the last question that is if it's becoming tougher to find good pipeline projects as competitive or at good prices given the competition from LPs and income trusts, when your get your settlements with NEB whatever they might be, would you consider taking portions of your mainline out?

The focus right now -- first of all let me say that everything that we do on the mainline is a very long-term process. Every bit of progress that we make seems to take several years rather than just a couple of months. And our key focus on the mainline today is to make it as competitive and stable as we can over the long-term. And part of what we are focusing on right now is different tolling structures and maybe some segmentation of the mainline from a tolling perspective to give, for example, Eastern customers more effective short haul service if that’s what they really want. So we are entirely focused on that. There is no consideration being given to selling off part of the mainline or anything like that until we have the business model side of it figured out, and that's well down on the road.

Okay, thank you very much.

Thanks.

Thank you. Our next question is from Andrew Fairbanks of Merrill Lynch, please go ahead.

Good afternoon guys, just two quick ones. You mentioned the U.S. dollar impact in some of the operating segments, if the corporate is 4m and there is a rough offset there, am I right to think there is basically a couple of million dollars in transmission and power that is offsetting there? Could you just quantify those amounts?

That's roughly where -- as Russ said, these are basically offsetting movements between the various segments.

Oh that's great, thanks. And then as you look at volumes out of the western basin on the natural gas side, you mentioned that you know you are looking for flatter volumes for North America until you get some of larger projects on. Can you give us a shorter timeframe snapshot of what your view is towards what volumes are doing there? Are they rising in the last couple of months through the system and what are your expectations for the year?

And sorry, that’s natural gas volumes.

Natural gas volumes.

Yeah, I’ll comment on how we see Western Canada unfolding right now. I just note that at a Western Canada production rate of nearly 17 Bcf a day, the annual decline is around 3.5 Bcf a day every year. So our friends, the producers worked feverishly to add new production to offset decline, and they’ve done a very good job for many years of offsetting that 3.5 Bcf of a day, and we expect they will continue to do that in the future. And then if they manage to generate 4 Bcf a day rather than 3.5 of new production, we see a net increase of 0.5 Bcf a day. But it's very much on the margin and after the gargantuan task of simply offsetting decline, that’s a long winded way of saying that right now in Western Canada, we see pretty flat production year-over-year. We are not seeing any major increases. We do know that there is a bunch of very exciting, deeper place in the Foothills that people are pursing, and there is a lot of activity in Northeast BC, but there is not a steady string of lady-fern type discoveries that would add you know 0.5-1 Bcf a day per discovery. It is very bread and butter stuff in the west, and I think it is quite similar. Only evidence we are seeing in the U.S. Gulf Coast would indicate that both onshore and offshore in the Gulf of Mexico region, things are pretty flat and not necessarily generating the kind of increases that people had speculated before. And again industry is very active and investing a lot of money, but they are faced with very significant annual decline rates. The only area that we would be hopeful for maybe a 20-30% increase would be in U.S. Rockies. But we are not experts in that region and we wouldn't want to be quoted as having a production forecast. Though all I would say is that the people I know that are actively drilling and developing in the Rockies complained significantly about the very slow land access problems in that part of world.

And that's great and given that outlook, is there anything that you would do in how you run your business to accommodate that outlook? In the past people have been -- industry as whole has been hopeful but there would be little more production growth certainly in Western Canada. Are there things that you looking and doing differently going forward that would optimize the system more towards that outlook?

Yes a couple, I mean, first of all when we bring a Bcf a day in from the MacKenzie Valley if we're successful in helping the producers get that project to completion that will be quite important because that's one Bcf a day relative to 11-12 Bcf a day that we move through our Alberta System but more importantly since all other pipelines leaving Alberta are full, it ends up on the mainline and it amounts to something like a 25% increase in throughput on the northern Ontario section of our mainline. So, it is the margin that incremental volume coming in from the north is quite important at the further downstream ends of our Canadian pipe. So that is one thing we are doing. The other is as you would have observed, we have worked quite hard with the Canadian regulator, the National Energy Board to raise the seriousness of this issue, and I would note that the NEB's own forecast of exportable gas out of Alberta have become quite a bit more conservative, and while they do their own independent work, we think that our focus on that issue may have played a part in that. So we will continue to work that front as well. What that would mean, we hope with the National Energy Board is that as they become comfortable with a lower exportable forecast out of Alberta, we might be able to convince them to increase the depreciation rate and reduce the long-term capital risk on the mainline and that's certainly a very important focus for us.

That looks great. Thanks, Harold.

Thank you.

Thank you. Our next question is a further question from Karen Taylor of BMO Nesbitt Burns. Please go ahead.

Sorry, I just had a couple of real quick cleanups. How much of the 8m of the higher G&A cost in the power segment was a result of the activities at Bruce?

I would say that not much. We would have included those costs into the cost of Bruce once we had a real project. So, I would say that those are normal cost that you can expect to see incurred on a go-forward basis.

So it's the run rate of that orders [inaudible]--?

Yes.

Just real quick. On the quarter was Bruce self funding in terms of all of its capital requirements and so forth or did -- do you advance any money to them on that?

At this time we haven’t had to advance any money to Bruce.

Okay. How much corporate debt is left at the [critical] level? In '03 -- Q2 of '03 versus Q1 of '03?

Can we get back to you on that.

[Turn your back John now on] Karen. So you're referring just corporate debt, you mean outside of the [holion] sites?

Just the stuff that's non-allocated?

Okay, I'll get back to you on that one and you--.

And you're also going to get back to me on the tax rates for Bruce, so just, and then two other real quick questions. The net use of cash and discontinued ops was about 88m, can you just explain to me what that was for? Is that an ongoing thing or do you get it back later in the year?

No, the bulk of it if I remember correctly, and Lee jump in here is that a good chunk of it was the settlement with the counter party in that sort of $40m-rish pretax number, the balance was what Lee?

That’s right Karen, basically the net was 40, you got 30 [own] power side and something over 70 on the discontinued ops side of settling out things on gas marketing side.

So I am sorry, this 30 was net cash outflow?

No, no. Sorry, the 30m on the power side, we had a 40m net outflow. So that’s give us 70m plus on gas marketing side.

Okay, and then just very lastly, what's the notional value of the contract that were reacquired from [Merit]?

We can't disclose that because the contract -- the confidentiality around the contract. As you can see, I mean there is no impact on our gas flow statement. So, we assume that it wasn’t -- wasn’t very large

Would you reacquire them at [NPEB's] contract -- current time or would it have been notionally back to the booking date or how would have that have work?

Basically we acquired them I am not sure if I understand you question we acquired them sort of you know, at a mark-to-market value.

Right, so if they were mark-to-market and you didn’t pay a lot for them that means, they are not necessarily in or out of their money to any greatest degree at this point?

Is that -- basically we brought that you know two sides of a book, which netted to a very small number and at that particular estimated time there wasn't a large difference you know, a net difference to extent that there was commodity risk associated with it, which we changed that, you know, the next day, and we hedged that simultaneously so that we weren't exposed to any additional commodity risk beyond the time you know that we actually had executed the contracts.

So just to go back, can you give us any indication at all on how big the book is in aggregate?

No.

Okay, thank you.

Thanks Karen.

Thank you and we have a further question from Matthew Akman of CIBC World Markets, please go ahead.

Yes I think I -- you just answered it. You have got 31m contract settlement number, I wanted to just follow that in cash and it sounds like it was a cash inflow item this --in Q2?

It was a cash inflow item for the power segments, but on the discontinued side there was an out flow offsetting it.

Yes I understood.

Yes.

But it itself was a cash inflow on this -- in the quarter.

That is correct.

Thank you.

Thank you. We have a further question from John Edwards of Deutsche Bank. Please go ahead.

Yes, and just what I forgot to ask you was on the Canadian Mainline, you went-- I mean to adjust for the $16m, you know, backing up $16m of earnings that were recognized this period instead of in '01 -- you'll be down to 76 but the earnings still came down to 71 despite the fact you have a higher deemed equity ratio a higher return, and higher volumes and so I was wondering if you could that [inaudible].

I think John that, when you refer -- you are looking at quarter-over-quarter; that's 71 versus to 92?

Yes, I know you are back out the 16, so it'll be 76.

And just to point out for you, the 16 would relate to '01, but there was also approximately another 5m which would relate to the first quarter of '02. So to get a proper quarter-over-quarter analysis you should back out more like 21m.

Okay.

Okay and then you would have a, you know, pretty comparable number. And so then I think you could include that the thicker equity kind of offset the depreciating rate base.

Okay. So it's the higher depreciation that was the offset to the thicker equity higher return in volume?

Correct.

Okay and then I think you may have talked about this, I probably missed it, can you talk about again in the power segment why the G&A support cost were higher?

We just continue to grow that business, and it costs more money to run a larger business on a go forward basis.

I think may be just to add to that, John, just to Russell's remarks, I think while it is higher quarter-over-quarter, on a year-to-date basis that run rate of 20 or 21m has been there for a few quarters now. So, it's not out of out of a norm relative if you went to Q1 '03 and possibly even Q4 '02.

It's fairly close in the last three quarters.

Okay.

You have a further question Mr. Edwards.

Just you probably -- I think this may -- perhaps this question has already been declined to answer. I guess you can't talk about then that what Mainline credit exposure is, you have already said that other things are confidential. I don't know if you can answer that one either.

I think the best way to answer that is, is that, you know we've reviewed it and you know the provisions that we have in the deferred gain are sufficient to cover any exposure that we have. So from an income standpoint I wouldn't expect in the worst case scenario to have any impact on our financial statements.

Okay, great thanks a lot.

Thank you we have a further question from Linda Ezergailis of TD Newcrest. Please go ahead.

Thanks this is just a further to Bob's question about potentially putting some portions on the Mainline into income trust, just wondering, if there is any other assets in your current portfolio other than the Mainline that you looked at potentially moving and then further to that for your existing LP both in pipeline and power, are you looking at making any third party acquisitions into those, well maybe not directly, either indirectly or directly at this point?

Linda, we were not actively working on putting any other specific TransCanada asset into either the existing LPs or new LPs right at this time. There is always interesting situations that they become more mature and the risks are been taken out of them that they maybe worse more to an LP unit holder than they are to us. And we look at those all the time and there has been quite a good track record from TransCanada historically of having put different power plants into the power LP and of course creating the US pipeline in first place. As far as external assets go, we look at those all the time, and when we look at them, if they are a nice stable, highly predictable comfortable kind of an asset that isn't going to need a lot of capital investment, but for whatever reason we think they make a good part, a good offset within the TransCanada portfolio. We could very well buy them through the vehicle of the LP, either in the power or the pipe side. But as I say, we are looking at those things all the time and I don't have any specific pending deals I could really tell you about today.

Alright thank you.

Thanks.

Thank you. Once again if you have a question, please press "*" "1."

I think -- conference coordinator if I may just interject, just in the interest of time. If we could, also like to give the opportunity to the media to ask questions. So if there are any questions from the media we'll take those.

Certainly. We will now take questions from the media. If you have a question, please press "*" "1" on your telephone keypad. If you are using a speakerphone, please lift the handset and then press "*" "1." Our first question is from David Todd of Power Canada (ph.). Please go ahead.

Yes good afternoon gentlemen. Regarding Bruce power has the recent decision by the Ontario government to include nuclear, to extend some nuclear, the tax relief that's been promised in terms of [green] energy renewables. Does that effect your strategy at all or any decision making or regarding the other out of service units of per say the one and two units and the economic viability of that?

It would certainly help the economic viability of a restart of the unit one and two. It doesn’t impact any of the decisions, my understanding is that it doesn't impact any other decisions that we made to date with respect to units three and four, but from our prospective it’s a very positive development with respect to units one and two and potentially other things we might do at Bruce B, or Bruce A down the road. So I guess we are very encouraged by the developments today in that regard and hopefully there is an opportunity to utilize them.

And this is the subject that has been taken up yet with your partners and the [inaudible]?

I am not sure what you mean subject has been taken up.

Well, this has been a matter of discussion with other investors in Bruce Power?

Certainly, Bruce [inaudible], Bruce Management is very involved in discussions leading up to this and we are involved in with the government consultation on what it might mean for us. The partners were all aware of that and encouraged Bruce management team to continue down that path. So they are all very aware of the implications.

And finally, just quickly is it -- it is entirely clear yet in terms of the policy shift that Ontario government has announced what the rules of the game are going to be in relation to a development like this, if it were to proceed?

No. I am not sure if I totally understand your question.

Well, state -- at least in the public statements that the government has made and the ministry has made, it hasn’t been made entirely clear of what all the regulatory aspects would be around this and the -- where the precise rules of the game are? There was the announcement. I am just wondering if there have been any follow-ups since the date that the ministry made the announcement?

No, not that I am aware of, you know, the details -- our understanding is that the details are yet to be worked out.

Great, thank you.

You have any further question Mr. Todd?

No, I don’t, that is it. Thanks very much.

Thanks.

Thank you. Our next question is from John Spears of Toronto Star. Please go ahead.

Hello. I just have a question about the cost of the Bruce A restart. In the first quarter, you have talked about the cost going from 450m and a 20% increase, which would take it to 540, now it is 610; I'm just wondering what's driving these -- that's up 35% or so in six months; I'm just wondering what's driving that substantial cost increase and is there any further update on the timing?

It is timing that's driving the cost and they are just costs of people on-site that are working on the restart. Our burn rate was about $40m a month for the first six months of the year or about $20m per reactors. We'd expect that run rate to come down a little bit as probably closer to 30-35m on a go forward basis. And once we get one unit up, that will probably drop in half and go away once we have both units up and running. So, it is totally time-dependent as to what, you know, the ultimate cost is going to be because it is just people on-site. We don't have -- I think we've disclosed as best we can what the situation is with respect to timing of the restart. We are [right in] through a number of issues right now, and we are confident and optimistic that we've found most of the problems and working our way towards commissioning.

Thanks. And sorry who is that speaking?

It's Russ Girling.

Russ?

Russ Girling.

Girling. Okay thanks.

Thank you and this time there are no further questions registered. I would like to turn the meeting back over to you Mr. Moneta

Thanks very much conference coordinator. We appreciate once again everybody's participation this morning. Look forward to talking to you again soon. Thanks. Bye for now.