TC Energy Corp (TRP) 2004 Q2 法說會逐字稿

Good morning, ladies and gentlemen. Welcome to the TransCanada Corporation 2004 second quarter results conference call. I will now like to turn everything over to Mr. David Moneta, Director of Investor Relations. Please go ahead, Mr. Moneta.

Thanks, very much. And good morning, everyone. I'd like to take the opportunity to welcome you this morning. We're please provide the investment community, the media, and other interested parties with an opportunity to discuss our 2004 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 second quarter results and other general issues pertaining to TransCanada. And following their opening remarks, we'll turn 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-looking and subject to important risks and uncertainties. The results of 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.

Thank you, David. Good morning, everyone. And thank you for joining us today. I'm pleased to report that TransCanada Corporation continues to deliver steady operating and financial performance.

For the second quarter of 2004, TransCanada's net income was $388 million, or 80 cents per share, compared with 202 million, or 42 cents per share for the same quarter in 2003. The increase of $186 million, or 38 cents per share, was attributable to significantly higher net earnings from the power business. This was the result of a gain from the sale of Curtis Palmer and ManChief power plant to the TransCanada Power, L.P., as well as other gains resulting from the removal of TransCanada's obligation to fund the redemption of TransCanada Power, L.P. units in 2017, as well as a reduction in our ownership interest in the L.P.

This sale is consistent with our focus on maximizing shareholder value. The Curtis Palmer and ManChief facilities are mature assets with strong power-purchase agreements that generate stable cash flows. Proceeds from the sale will allow us to finance growth opportunities in our Gas Transmission and Power businesses, and contribute to our ongoing objective of utilizing and maintaining our strong financial position.

TransCanada's Board of Directors has declared a quarterly dividend of 29 cents per share for the quarter ended September 30th, 2004 on the outstanding common shares. This marks more than 40 years of consecutive quarterly dividends paid by TransCanada and its subsidiary. The dividend is payable on October 29, 2004 to shareholders of record at the close of business September 30th, 2004.

I would like, this morning, to review some key events, and turn the call over to Russ Girling, our Chief Financial Officer, for a more detailed review of financial results. The long-term growth objectives that we've set for our two core businesses of natural gas transmission and power services, continue to be strongly supported by increasing North American demand for energy.

In 2004 TransCanada expects to invest approximately $2.9 billion in North American energy infrastructure. Approximately $2.3 billion of that amount relates to the accusation of Gas Transmission Northwest Corporation.

As you know GTN owns and operates two pipeline systems. The Gas Transmission Northwest Pipeline, previously known as Pacific Gas Transmission, or PGT, and the North Baja Pipeline System.

The acquisition of North Baja was subject to a right of first refusal in favor of a third party. That party has now agreed to waive its right of first refusal with respect to sale of North Baja to TransCanada, and accordingly, TransCanada now expects to close on the Gas Transmission Northwest Pipeline System and North Baja at the same time.

In the second quarter of 2004, NEGT's bankruptcy court approved both its Chapter 11 plan of reorganization and the sale of GTN to TransCanada. TransCanada has satisfied all its preclosing conditions under the purchase agreement and is awaiting the implementation of NEGT's Chapter 11 plan of organization, which is the only remaining material closing conditions in this transaction.

NEGT has further stated that it believes its plan will be effective no later than the late third quarter or early fourth quarter of this year. The parties expect to close the GTN transaction promptly thereafter. We anticipate the GTN transaction will be immediately accretive to both earnings and cash flow.

Turning now to Northern Development, TransCanada has engaged in renewed discussions with the Alaska North Slope producers and the State of Alaska about the Alaska portion of the Alaska Highway Pipeline Project. In June we filed an application under the Alaska Stranded Gas Development Act. In addition to reviewing this, the State of Alaska is processing our long-pending application for right-of-way lease on state lands. I would note that TransCanada already holds the right-of-way on federal lands within the State of Alaska.

The discussions on each of these applications will help advance the project. TransCanada and the state recognize the critical importance of upstring fiscal negotiations that are currently under way between the State and Alaska producers. TransCanada also continues to play a constructive role in the Mackenzie Valley Gas Project. We anticipate that regulatory applications will be filed during the third quarter of this year.

On the power side of our business, we announced this month that we have received final approval from the Quebec government to construct the 550 megawatt natural gas-fired cogeneration power plant in Becancour, Quebec. Construction activities have commenced at the site.

Once it begins operating during the third quarter of 2006, the plant will supply its entire power output to Hydro-Quebec Distribution under a 20-year power purchase agreement. The plant will also supply steam to industrial facilities located within the Becancour Industrial Park.

We are very pleased with the results from Bruce Power, both from a financial and operational perspective. Bruce Power contributed $96 million of pre-tax equity income in the first half of 2004, compared to $54 million last year. The increase reflects higher output in 2004, as a result of the restart of Units 3 and 4 which expanded Bruce Power's capacity by approximately 1500 megawatts, compared with the second quarter of last year.

A full six months of earnings in 2004, compared to the shortened period from February 14 to June 30th in 2003, which reflected our period of ownership in that year, also contributed to the year-over-year increase.

On the operational front of Bruce B Vacuum Building outage which will begin in the third quarter and we'll see all four of the Bruce B Station's Units taken off-line for approximately one month to conduct tests as mandated by the Canadian Nuclear Safety Commission. Bruce B's last Vacuum Building outage was in 1992, and this typically occurs every 12 years. Although the outage will reduce output over the last half of the year, we expect Bruce will continue to generate significant value for TransCanada shareholders in the year ahead.

In summary, we have made significant progress over the last 5 years towards achieving our goal of becoming a leading energy infrastructure company in North America, with a strong focus on gas transmission and power generation. As demand for natural gas and power grows, it is our intention to continue to connect new sources of supply to meet growing demand and to deliver long-term goals and value creation for our shareholders.

I would now like to turn the call over to Russ Girling, who will provide additional details on our second quarter financials. Russ?

Thank you, Hal. And good morning, everyone.

As Hal said we are very pleased to report anther quarter of steady operating financial performance. As reported earlier today, net income for the three month ended June 30, 2004 was $388 million, or 80 cents per share, compared with $202 million, or 42 cents per share for the same period last year.

The increase was primarily due to an after-tax gain of $15 million, or 3 cents per share resulting from the sale of the Curtis Palmer and ManChief power plants to TransCanada Power, L.P., and the recognition of $172 million or 36 cents per share of delusion and other gains resulting from the reduction of TransCanada's ownership interest in the Power, L.P., and the removal of the obligation in 2017 for TransCanada to fund Power L.P.'s obligation to redeem units not owned by TransCanada.

On a year-to-date basis, net income was $602 million or $1.24 per share, compared to $410 million or 85 cents per share last year. The increase of $192 million or 39 cents per share, was primarily due to the gains I just described as part of the quarter-over-quarter increase in net income.

I will review second quarter results for each of our segments, beginning with gas transmission. Gas transmission generated net earnings $146 millions for the three months ended June 30, 2004 compared, to $144 million for the same period last year. The $2 million increase in net earnings was primarily due to a $7 million after-tax gain on the sale of TransCanada's interest in a Millennium Pipeline Project and higher contribution from other gas transmission, which was partially offset by lower earnings from the Alberta System and Canadian Mainline.

Net earnings from the Alberta System were $39 million in the second quarter of 2004, $5 million less than the amount reported for the second quarter of last year. The decrease is due to the Alberta Energy Utilities Board's recent generic cost of capital decision, which established a rate of return of 9.6% on a deemed common equity component of 35% on the Alberta System for 2004. The Alberta System's earnings in 2003 were based on a negotiated settlement that included a fixed revenue requirement component.

The EUB's decision on the Alberta System's generic general rate application could also impact 2004 earnings. Phase I of the application consists of evidence and support of the apply for rate base and the revenue requirement. The hearing to consider Phase I issues concluded on April 14 and final argument and reply arguments were filed in May 2004. A decision is expected in the third quarter of 2004.

Excluding any potential financial impact from the EUB's upcoming decision related to Phase I of the general rate application, TransCanada estimates that earnings from the Alberta System will approximate $155 million in 2004, compared to net earnings of $190 million in 2003.

Phase II of the GRA primarily deals with rate design and services. The hearing in this Phase began on June 9th, 2004 with final arguments filed in July. The EUB decision is expected in the fourth quarter of 2004.

Turning now to the Canadian Mainline, net earnings of $66 million for the three months ended June 30, 2004 were $5 million less than the amount reported for the same period last year. The decrease is mainly due to the reduction in the allowed rate of return on common equity from 9.79% in 2003 to 9.56% in 2004, and $385 million decline in the average investment base.

And finally, with respect to our gas transmission segment, TransCanada's share of net earnings from other gas transmission was $35 million for the three months ended June 30th, 2004, compared to $22 million for the same period in 2003.

The second quarter 2004 results include a $7 million gain on the sale of the Company's interest in the proposed Millennium Pipeline Project. Excluding this gain, earnings for the quarter increased by $6 million over last year, primarily due to higher earnings from Great Lakes, as a result of successful marketing, of short-term services, and higher earnings from our Ventures, L.P. as a result of expansions completed in 2003.

Next I'll move to Power. In the second quarter of 2004, the power business contributed net earnings of $249 million, compared to $63 million for the same period last year. Excluding the one-time gains resulting from the sale of Curtis Palmer and ManChief and the related transactions discussed previously, net earnings for the three months ended June 30th, 2004 were consistent with the same period last year.

Higher earnings from TransCanada's investment in Bruce Power were primarily offset by lower contributions from Eastern operations due to the sale of the Curtis Palmer and Western operations due to recognition in the second quarter of 2003 of a $31 million before-tax settlement with a former counter party.

Total volume sold in the second quarter of 2004 were 7 thousand, 9 hundred, 1 gigawatt hours, compared to 7 thousand, 14 gigawatt hours in the same period of 2003. Bruce Power contributed pre-tax equity income of $48 million in the second quarter of 2004, compared to $16 million in the second quarter last year. The increase primarily reflects higher output in 2004 as a result of the restart of Bruce A, Units 3 and 4, which have expanded Bruce Power's capacity by approximately 1500 megawatts for the second quarter of -- from the second quarter of 2003.

Overall, prices realized in the second quarter of 2004 were approximately $46 per megawatt hour, compared to an average price of $45 per megawatt in the second quarter of 2003. Approximately 55% of the output was sold into the Ontario's wholesale spot market in the second quarter of 2004, with the remainder being sold under long-term contracts.

The reduced exposure to spot market prices, Bruce Power entered into fixed price sales contracts for approximately 43% of the planned output the remainder of 2004.

On a per-unit basis, operating costs decreased to $30 per megawatt hour in the second quarter of 2004, from $40 per megawatt hour in the second quarter 2003. The decrease was primarily due to increased output in 2004, and lower costs as a result of fewer plant outages in 2004, as compared to 2003.

The Bruce Units ran at an average availability of 92% in the second quarter, compared to an average availability of 77% during the same period last year.

A planned maintenance outage on Unit 4 began on May 22nd, 2004, and the unit was returned to service July 2nd, 2004.

There's a planned maintenance outage of approximately 2 to 3 months at one of the Bruce B Units, commencing at the same time as the planned Bruce B Vacuum Building outage where all four Bruce B Units will be out of operation for approximately 1 month. Both outages are scheduled to begin in late third quarter of this year.

In our Eastern power operations, operating and other income for the three months ended June 30th, 2004 were $22 million, compared to $36 million for the same period last year. The decrease was mainly due to an $11 million reduction in the contribution from the Curtis Palmer hydroelectric facilities, as a result of the sale of that facility to the Power, L.P. on April 30th, 2004.

Operating and other income from Western operations of $35 million for the three months ended June 30th, 2004 were $25 million lower than the same period last year. The decrease was mainly due to the recognition in the second quarter of 2003 of a $31 million before-tax or $19 million after-tax settlement with a former counter party who defaulted in 2001 under power-forward contracts.

Excluding the 2003 amount, operating and other income from Western operations increased by $6 million, compared to the same period last year. The increase was primarily due to acquisition fees of $6 million pre-tax related to the sale of Curtis Palmer and ManChief, and the impact of higher net margins achieved on the overall portfolio of power in the second quarter of 2004, which was partially offset by a lower contribution from ManChief as a result of the sale of that plant to the Power, L.P. on April 30th, 2004.

The Power, L.P.'s operating and other income of $6 million were the same for three months ended June 30th, 2004 was $1 million lower than the same period last year. The decrease was due to TransCanada's reduced ownership interest in Power, L.P. in 2004, and the recognition of previously deferred gains resulting from the removal of the Power, L.P. redemption obligation. Additional earnings from the Power, L.P.'s acquisition of Curtis Palmer and ManChief partially offset those declines.

Finally, in the Corporate segment, net expenses of $7 million for the three months ended June 30th, 2004, were comparable to the $5 million reported for the same period last year.

Turning to our cash flow statement and balance sheet, funds generated from continuing operations were $390 million and $813 million for the 3 and 6 months ended June 30th, 2004, respectively, compared to $434 million and $891 million for the same periods in 2003. The decrease was primarily due to higher current income taxes.

Capital expenditures excluding acquisitions for 3 and 6 months ended June 30th, 2004 were $93 million and $194 million, respectively, and related primarily to the construction of two new power plants and the maintenance and capacity capital in the gas transmission business. As Hal mentioned, we expect total capital expenditures in 2004, including acquisitions, to be about $2.9 billion.

Of this amount, approximately $2.3 billion relates to the GTN acquisition, and includes the assumption of approximately $700 million of debt. The remainder relates to the construction of the Becancour and Grandview power plants, as well as capacity maintenance capital in the gas transmission business.

Our plan for financing this capital program is essentially in place. The majority of our remaining 2004 capital commitments will be financed using the $1 billion in cash and short-term investments on hand at June 30th, 2004, and internally generated cash flow which is expected to stay strong through the rest of 2004 and beyond. The remainder will be financed by issuing notes payable or accessing debt markets.

Over the last 4 years we have strengthened our balance sheet, so we can act on opportunities as they arise. Today, our balance sheet consists of 56% debt, net of cash, 4% preferred securities, 2% preferred shares, and 38% common equity.

To summarize, the Company's net earnings and cash flow combined with the strong balance sheet continue to provide TransCanada with the financial flexibility to make disciplined investments in its core businesses. We will continue to prudently invest our discretionary cash flow, and to make profitable investments in the natural gas transmission and power businesses.

We will continue our initiatives in the area of operational excellence with a focus on providing low-cost, reliable service to our customers. And we will continue to maintain a strong financial position, so that we can act on opportunities as they arise.

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. I will 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'll accept questions from the investment community first, followed by questions from the media. With that I'll turn it back to the conference coordinator for Q&A.

Thank you, Mr. Moneta. We will now take questions from the telephone lines.

If you have any question, please press star, 1 on the telephone keypad. If you are using a speaker phone, please lift the handset, and then press star, 1.

If at any time you wish to cancel your question, please press the pound sign.

Please press star, 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.

And the first question is from Dominique Barker from Credit Suisse First Boston. Please go ahead.

Good morning. Could you please clarify the Alaska Highway Pipeline Project? There's a growing number of energy companies to express a formal interest in building a pipeline. Is this a competitive process?

It's Hal here. I think it is, certainly, a competitive process. But there's two different parts to it.

Firstly ,TransCanada is the only company that holds certificates to build the pipeline within both Alaska and the Canadian side of the border. And we've expressed a willingness to the Alaska producers to convey our certificates, our technical information, and our right-of-way within Alaska to them if they decide to build the pipeline themselves within Alaska.

On the Canadian side of the border, we hold certificates, and we also have other historic rights under the Northern Pipeline Act, and underpinned by the treaty between Canada and the United States.

And in -- on the Canadian side of the project, we're not prepared to convey our rights to anyone else. We view that as a logical extension of our existing Canadian infrastructure. We have spent significant dollars on the pre-built portion of that project in southern Alberta, Saskatchewan, and B.C., and it would be our expectation that we'll prevail and build that part of the project within Canadian.

On the Alaska side, in addition to the producers, a variety of other parties show up from time to time. Those parties may or may not have the technical capability or experience or the financial horsepower to undertake a project like that. We encourage all of those parties to talk to the financial community, to the producers, and the State of Alaska and see whether or not they can put a project together.

TransCanada's certainly willing to step in and manage and build the Alaska part of the project as well, but at this point we see that as a logical initiative for the Alaska producers to pursue. Therein, detailed discussions with the State of Alaska at this time, and we wish them well in that.

Just a follow up. Because given those rights-of-way on federal land, how can other players be competitive?

Well, certainly any decision to proceed or not proceed within Alaska will require, we believe, the support and involvement of the North Flow producers. And because we've expressed a willingness to those North Flow producers work with them on any project that includes TransCanada building the Canadian portion, you know, we obviously think the producers can go ahead and build the Alaska part of the project on rights-of-way that we'd be pleased to could convey to them.

As to other parties, you know, I view it as opportunism at this stage, and you can judge for yourself whether or not they'll be involved.

Okay. Thank you.

Thank you, Ms. Barker. And the next question is from Linda Ezergailis from CIBC World Markets. Please go ahead.

Thank you. Good morning. Quick question -- well I guess it's a bit of a complex question with respect to your investment in Bruce Power. We've seen the first trosh (ph) of RFQs come up from the Ontario government. So we're starting to get an inkling of how they are proceeding on that front with Ontario Electricity Policy.

And I'm just wondering if you've pushed forward your cost estimates and the scope and timing of what it would take to restart the additional Bruce Units. And within the context of that, perhaps you could give us a sense of what it would take for Bruce Power to make the decision to go ahead on that? What sort of contracting or parameters or operating environment you would need or guarantees from the government.

It's a complex situation. Firstly, fundamentally it's an attractive opportunity because we believe the Ontario market will very much need the power that's available from the two Bruce Units that are not running today. So from a fundamental perspective, we think the supply and demand outlook is favorable for the restart of those two reactors. The things we would need would be clarification of the uncertainty that surrounds the power market today.

We don't know how things are going to unfold in Ontario. We are committed to Ontario. We have a multibillion dollar investment in energy infrastructure in Ontario, and we're going be a significant player there for a long time, so we very much want to be involved.

If the market unfolds correctly, if the right mechanisms are there, whether they be an effectively functioning spot market, or attractive long-term power purchase arrangements. If those fall in place, that would help. But the third item is a very important one, and that is the technical feasibility and cost control that's available to us as we undertake the restart of a project like this.

These are very large projects. There's not a particularly good track record in Canada in the last five years of bringing big projects in on time, on budget. We don't want to get caught up in a project that comes in late and significantly over budget, so it takes a lot of work to just get through the detail of what's required.

So we're interested in progress on all three of those fronts, and think that the Bruce opportunity's an excellent one, and we're very supportive of it, but the details have to be worked out.

And, can you give us a sense of what sort of preliminary costs and timing you've discussed?

No. It's a lot -- there's a lot of complex issues involved here, and we're just in the middle of very detailed, technical, and engineering, and cost estimate work. So I don't think it would be appropriate for me to comment on it at this time.

Okay. And do you have a sense when you would be able to share that information with us?

In the future.

Okay. Thanks a lot, Hal.

Thank you, Ms. Ezergailis. And the next question is from Sam Kanes from Scotia Capital. Please go ahead.

Good morning, gentlemen. Now that you have Baja back on your radar screen to close. I was wondering if you could just talk a little bit about that line and its positioning relative to some of these LNG projects that have been announced in that area, some of which have been rescinded back out. Is this the line that would carry LNG into southern California? At least, you're wanting -- you're hoping to be, I guess. Just shed some light on how that tactically fits in?

This -- first of all, we'd acknowledge that this is not an asset that fits geographically within what you'd normally regard as our core area. But it came as part of a deal. We didn't go and seek out this asset, it came as part of a deal.

And as we looked at it more deeply, we saw significant upside to it and some pretty interesting gas transportation opportunities emerging in that part of the world. If those LNG projects in Baja, California go ahead, then this pipeline would be well positioned to be both expanded and extended, and we like pipelines to have those attributes.

It's early days, though, I think, in terms of LNG importation down there. We don't know how that will work. We're pleased to have resolved the right of first refusal issues, and we look forward on closing on the acquisition and we'll do everything we possibly can to maximize the value of that bit of pipe going forward.

That's, you know, the LNG game is a long-term game in North America. It's taking time to build momentum on construction of these terminals, and so we would regard this as a -- as a patient investment that we will run it well and wait what happens as far as the LNG goes.

Okay. If I could, just one quick follow-up. Your sale of Millennium, was that a shift in strategy, i.e., that you didn't have a controlling interest, therefore why hang around with this? When was the change of views of its prospects? Or just curious as to what your thinking was? It's going to be a nice price.

Sure.

Thank you, very much.

Well, you know, Millennium's an interesting project. If you'll recall it originally started out as an end-to-end pipeline from Dawn in Ontario, under Lake Erie, through the United States and over to New York City. That's more or less was the original configuration of the project.

As it's unfolded, you know, through a very, very lengthy project development period, it's become clear that it's easier to do a shortened version of Millennium that integrates with some of the other pipelines that already in the area. Still essentially moving TransCanada gas, but now from our border crossing at Niagara, and going partly through the National Fuel Gas System, and then a much shortened version of Millennium.

As we looked at it with a minority interest in that project, I think our decision to sell out and exit really reflects our larger practice of trying to focus on projects that are significant to us, and that will make a big difference to TransCanada, and minimize the time and effort we put in to lesser projects where we have a minority interest. So, it was really just an opportunity to turn it over to people that had a bigger interest in it than we did.

We don't have any negative views on the project at all. Very clearly, New York City needs all the gas pipeline capacity it can get. This is a situation that we think the people of New York should take very seriously, and Millennium is one way to get more gas in there. There are others. As you know, we've expanded and extended the Iroquois Pipeline System, and it's a key conduit for delivering Canadian gas from the TransCanada System into New York City, and Millennium would add to that. So it -- no negative view on the project at all, simply that it wasn't important or significant to us.

Thanks, Hal.

Thank you, Mr. Kanes. And the next question is from Bob Hastings from Canaccord Capital. Please go ahead.

Yes, a couple of clarifications, if I could. You mentioned that the -- that the impact on the earnings -- or, just, sorry, on the EUB decision is in the second quarter. I wonder if there was any, sort of, retroactive impact on Q1 that came into the second quarter?

No. I think that the numbers like that, I think we both, if I remember correctly, about $40 million in the first quarter. And so -- and $39 million the second quarter.

Okay.

We're expecting, I think we said 155ish on the year pending the outcome of the Phase I of the GRA.

Okay. So, okay. Thank you. And the -- another clarification is that I think it was mentioned that the acquisition of GTN would be accretive to earnings in cash flow. And I'm just wondering if you want to, first of all, quantify that, was is that -- is that after all financing costs?

Yeah. Is it -- I think, you know, you can see that, you know, we have the cash on hand ready to close the transaction, you know, combination of cash on hand and incremental debt. And so we would expect that, you know, those -- that the cost of financing the transaction and the revenue will be, you know, what the revenue has been historically from that pipeline system. So we haven't quantified that, but, I think you can -- you were given the information by which you can make your best estimate of what you think that's going to be.

Yeah. I just wondered if you'd -- if in your financing costs you included the lost power income?

Exactly. I mean, that's -- that would be the, you know, the analysis is the lost power income and the cost of the incremental debt, offset by the incremental revenue generated by the GTN and Baja assets.

Okay. Great. Thank you. And the last clarification was -- the $6 million fee revenue from the sale of ManChief and Palmer, is that all one time? There's no trailers?

I'm not sure what you mean by "trailers."

There's no other fees coming in in other quarter or something?

No. That's -- that's -- that's for that transaction. We have ongoing fees in the -- in our contracts with the Power, L.P. that are related to performance. One of those is acquisitions. So to the extent we complete acquisitions, we achieve fees. So there will likely be a fee associated, for example, with the HIC transaction, if we close that. There's also fees associated with enhancements, if we were able to increase the revenues. So they're all -- you know, the contractual incentives fees that we have built into those contracts with the Power L.P.

Okay. But no changes. Okay. Thank you, very much.

Thank you.

Thank you, Mr. Hastings. Next question's from Karen Taylor from BMO Nesbitt Burns. Please go ahead.

Great. Thank you. Very quick one to start off. Do you plan to appeal the EUB's generic cost of capital decision given its very many deficiencies?

Karen, we are continuing to review that decision, and to formulate our plans going forward on it. So I think until we cross those bridges, it would be inappropriate for me to comment on it. So, I think we'll just set that aside today.

But you are reviewing it? And you haven't decided either way at this point?

Yeah. I think that's right.

Okay. Can I just ask a real quick few questions just relating to Bruce to make sure I've got my numbers in line for the rest of the year? The target availability for the second half of this year is? Or another way of asking, is you've used a number of 80% for the year, so given that the, you know, availability in the first half is about 86%, is the 80 still good for the year, and then I can do the math?

Yeah. I think that the 80's still good for the year. That's the number we're using. I think what we've -- what you've got in the third and fourth quarter is the outages that we talked about.

Beyond that, the plant should operate at, sort of, at that 90ish percentage availability. I think Unit 6 is running at 93% now. We have the availability to go to 93%. So outside of those outages, we have no other, sort of, scheduled downtime.

Okay. The realized price for the uncontracted volumes in the second quarter, can you tell me what that was? Or a percentage as a weighted HOEP?

We probably can, but it will take us a second to find it here.

Okay. Any closer to being able to provide maintenance schedule for '05? When would I expect to see that in your release? Q3 or Q4

I'm not sure whether it would be Q3 -- it won't be Q4 because we'll be into the beginning of the next year. I would hope that we have a good view of the maintenance schedule by the time we release Q3. We're going through the budgeting process, starting right now, at Bruce. And I would suspect that by the time we're into September, we should have a very good handle on what our schedule is for 2005.

Okay. So the 43% that is hedged, is that percent, you talked about planned output, in the past we've been confused by use of megawatts versus megawatt hours. When you talk about planned output, I'm assuming it's megawatt hours, is that right?

Correct. I think that the -- for looking forward is, I think the number is still about 1500 to 1600 megawatts that are sold forward for the balance of 2004 --

But it translates into 43% of megawatt hour production.

Correct. Yeah.

Okay. The contract profile going forward as a percentage of planned output in megawatt hours for 2005, how much is going forward?

I'm set correct, I think we've got a number for you. You got a number there?

It's approximately about a third of the planned output for next year. As we move into next year, the plan would be to try move that number closer to where it is this year.

So 33%, roughly, now currently, but the plan would be to take it to something in the order of 40 to 45?

Depending on forward market prices, and that sort of thing, as to whether or not we can achieve our objectives. But that's, sort of, the plan is to maintain that kind of balance between spot and firm sales until we have a little bit more history, and then I would think that our plan would be to move that up from that level once we have, you know, a better operating history of Unit 3 and 4. But, you know, rolling into that is where's the Ontario government going with respect to contracting power in total? So those factors will play into it as we move forward into 2005.

Okay.

Those are the issues that are on the table today.

Okay. And I just want to confirm, lastly, before you give the number on the uncontracted sales, that the outage on the one Unit of Bruce B that will be actually concurrent with the Vacuum. So an incremental sense, really talking 30 to 60 days.

Correct.

Okay.

So, Karen, on the -- Lee here. On the prices at Bruce, I think in our press release, in our quarterly we did disclose that the overall price was $46 a megawatt and the Ontario spot price was 47 for the same period. I don't think we're in a position to give the specific Bruce uncontracted price that we received.

Okay. Thanks, very much.

Thank you, Ms. Taylor. The next question from Matthew Akman from CIBC. Please go ahead.

Thanks. Sticking with Bruce, maybe, just, I'm asking the same question a different way, but, it looked like when you averaged the prices, the contracted price is higher than 42 where we've been before. So, can you tell us whether there's some upside you're starting to realize now in the contracted prices from when you took over the plant?

It would be small, I'm just seeing a rolling forward some of the contracts, I don't have a number for you, Matthew. Intuitively, I would think, that as we roll sales forward from those original forward sales, we're achieving higher prices in our forward sales than we did -- than were originally in place when British Energy owned the facility. So I would expect over time, as sales fall of and we're able to recontract them that we're recontracting at, you know, slightly higher values than they were originally. I don't have a number for you, though, in terms of moving average.

Okay. Then on the cost side of Bruce, costs came in pleasantly low here. And this is. I guess, the first time we've really seen the six Units all up and running without major maintenance. So, that's a nice positive surprise. I'm just wondering whether, you know, you think that's kind of a sustainable level of cost for the six Units, or where does it go from here, ex, you know, major maintenance on them?

Right. I think that the number that we're achieving now is close to what we originally put out when we bought the facility a couple years ago that would be in-between 30 and $35. We're at the low end of that. Certainly we try set out for the people at Bruce is targets to achieve lower costs, but, sort of ex-major maintenance. We're in the range of what our pro forma forecasts were in the terms of costs. It's in that, you know, low 30ish range is where we expect to run.

Okay, and then still sticking with costs, you talked about some studies going on on the restart of the last two Units. And I understand there's an extensive study going on that could be fairly expensive. So how are those costs being treated here and reported. Are they being expensed as we go or --

They will be expensed as we go. They haven't been material to date and haven't been expensed to date. It's our view they're not going to be that material.

One-third interests of those costs is going to be something less than $5 million for the year, for our share of those costs pre-tax. So, it's fairly minimal amount that we'd expect to spend. And to date we haven't actually received the bills on third-party costs. A lot of costs that we're expending right now are internal costs so they haven't been explicitly broken out and expensed to date. The magnitude of them isn't going to be material in 2004.

Okay. Thanks for that. I'll move on.

Thank you, Mr. Akman. The next question is from Maureen Howe from RBC Capital Market. Please go ahead.

Thanks, very much. A couple questions, just short ones. Why the $9 million swing in general and admin costs in wholly-owned pipeline division, and I'm wondering why is the cost positive? So I guess is recovery.

Maureen, it's Lee here. I think that if you actually look at that line, it's general administration court costs and other. The and other part that gets you here because that's where the Millennium sale gain is included.

Okay.

So if you take that out, it's fairly constant.

Okay. Great. Thanks. And on page 4 of the interim, there is a table summarizing delivery volumes. I'm wondering how the deliveries for the mainline summarized in the table of 7.4 and 7.8 differ from those in the note to the table that are 5.6 and 6 Bcf a day.

I think that the big thing to understand here is that the deliveries that you note in the note beneath is related to the long-haul. There's also a bunch of deliveries that come out the other end down in eastern Ontario that are also included in the numbers above. So that the total number includes short-term deliveries, as well as long-haul deliveries which are noted in the note below.

So the 5.6 and 6 relate to long-haul deliveries into Ontario.

I guess the way I would characterize it, Maureen, is western receipts, essentially, into the system is the 5.6 and the 6. And then as you move down stream we collect other volumes into the system which we deliver.

Okay.

So it's really trying to differentiate between what we're receiving in the west, and what we're actually delivering in the east.

Okay. So picking up volumes. I think it says in the note those are volumes that originate in Alberta and Saskatchewan?

Correct. Being the long-haul on the pipe.

They're what we call western receipts. And then in the east we're receiving volumes off of Great Lakes, Union Gas, those kinds of things that are in addition to western deliveries that move through the northern part of the mainline.

Okay. And then in the western operations for power, if we normalize for the sale of ManChief and then also the fact that there was the recovery from the third party last year, can you talk a little bit about how the western operations looked in the second quarter operationally and financially?

I'll start and then the other people may chime in, Maureen. If you look at the second quarter, I mean, last year we reported 60 of operating income. You take out the settlement with the former counter party that was 31. You're sort of down to 29ish. You add the fees on the Curtis Palmer/ManChief that Russ talked about, which is 5 or 6 million, you're down a few million on ManChief and you're up a few million on the plant, it's really not a big swing.

So, I mean, the other operations, the power purchase arrangements at Sundance, the other operations, then are pretty comparable year-over-year?

Correct.

And the same question, basically, but for the eastern operations adjusted for the sale of Curtis Palmer.

Right. So, again, just running through the numbers, last year we had 36 for eastern operations for the quarter. Again, Russ had noted that there's 11 for Curtis Palmer which brings it down to 25. There's a little bit of Forex in the difference between that and the 22 reported, but again, you're down to a million or two difference between what we're at and what was reported last year.

And is there any development at the Ocean State Plant regarding the gas contract? Is there any change in strategy there? Can you update us on that situation?

No change in strategy. We are in arbitration again and expect to see -- hopefully see a result of that arbitration sometime in the third or fourth quarter. We remain optimistic that last year's arbitration came to an incorrect conclusion and it will come to a more correct conclusion from our perspective this year. But at this point in time we haven't built any of that into our forecast.

One final question, and I'll let someone else have a chance. With respect to the MacKay River Power Plant, what exactly do you mean by integration issues. Does that basically mean that it's not working, or what does that mean?

What it means is that, trying to start up an oilfield project that's recycling dirty produced water and turning it into steam is a technically challenging thing, and both TransCanada and Petro-Canada knew that going into the project. We've achieved significant success here in recent months resolving some of those problems, but you know, Maureen, it's just the boiler-feed water has to be some of the cleanest water that you'd ever find, and produced water coming out of an oilfield operation is some of the dirtiest water. So the integration is really in cleaning that water up and making it suitable for boiler-feed water. And, you know, we anticipated that there would be difficulties there, and we're pleased that we're getting through most of them.

So it was anticipated and are you protected somehow, Hal, in terms of the contractual arrangements?

Yeah, we are.

Okay. That's great. Thanks, very much.

Thank you.

Thank you, Ms. Howe. And the next question is from David Maccarrone from Goldman Sachs. Please go ahead.

Hal, in terms of funding the GTN transaction, do you anticipate selling any of your U.S. pipeline investments to the MLP?

Not at this time, David. That's certainly an option, and something we always look at but, you know, in the grand scheme of things, we very much like our U.S. pipeline investments, and we would not sell them to the L.P. without carefully thinking it through.

Are there any conditions under which you think you would sell assets to your MLP?

Simply if it's attractive from a value perspective. You know, we view that US MLP as an attractive and essential long-term vehicle for us in the United States. We will, of course, work to sustain it as a blue chip vehicle, and from time to time when there's a good value proposition we think a transaction would make sense. But, we have no specific plans, David, at this point.

Okay. And then, maybe I missed it in the release or earlier comments, but what are the net cash proceeds from the Millennium sale?

$7 million. We were able to shelter almost 100% of that, so that the proceeds are the same as the number that we booked.

The gain is equal to the proceeds?

Yes.

Okay. So the book was zero?

Yes.

Okay. Thank you.

It expensed all of our costs.

Okay. Thanks.

Thank you, Mr. Maccarrone. And the next question is from Andrew Gusby from UBES. Please go ahead.

Thank you. Good morning. Hal, or I'm not sure which one of you would like to answer this one, but just relating to the Bruce and the outlook on that power market, can you give a sense how you're really looking at this from a return standpoint? Considering the costs -- the capital cost differential -- potential capital cost differential could be quite significant between restarting A-1 and A-2, and the rehab process there, versus the natural gas build within the Ontario market?

Andrew, I just observed that depending on the commercial arrangements around the restart of A-1/A-2, the cost of capital could vary over quite a wide range. If we embarked on that kind of a project with the expectation that we'd be selling into the spot market, you'd obviously be looking for a higher return than if the government was to put a fairly secure sales arrangement in place, either through a power purchase arrangement or some regulatory mechanism. So the actual cost of capital that we could use in appraising that investment is not yet settled.

And it all reflects, I think, the uncertainty in Ontario as to just how they're going to proceed. We think the government in Ontario's made some good progress in thinking through these issues, and they're now moving into the execution phase where they are actually going to encourage projects to go ahead.

And, you know, we continue to work with them on what the different options are for Bruce. One message we've consistently conveyed to the government in Ontario is if they can come up with lower risk ways to generated incremental power in Ontario, we will be able to bring lower cost capital to the table. And we continue to encourage them to think of ways to make power gen sector in Ontario lower risk and lower volatility rather than higher risk.

Could you guys just give us a bit of a sense of your -- the decision to allocate capital, whether Ontario, as a market does look relatively attractive here for period of time, or elsewhere. And if we're looking at other markets in North America, what would be your preference at this stage? What pockets do look very interesting right now?

Our view on these things reflects two things. One, you know, we do bring a pretty strong balance sheet to the table, and we can bring a lower cost of capital to these sorts of projects than some maybe party's that would take a more entrepreneurial approach than we would. And so we're interested in what's the forward outlook for price, but we're also interested in the volatility around that price.

And if we can identify markets where is the outlook is fairly stable or we can develop very low cost power, you know, then those would be the markets that we'd lean to. At this point in time, our favorite market for a lot of things is here in Alberta, and in the western part of the United States adjacent to Alberta. I think our acquisition PGT would reflect that, and we continue to examine power gen opportunities here in the west as well.

Ontario, we would rank very high on the list as attractive power gen development locations for us. We know that the market is structurally going to be short of power in the years ahead. There's going to be billions of dollars of energy infrastructure required there.

TransCanada's already one of the largest infrastructure investors in Ontario, and we would look forward to a long and productive relationship in that market.

The third one I'd highlight right now is Quebec. We're very pleased to see the Becancour project go ahead. We found it a good experience to deal with the government of the Province of Quebec and with Hydro-Quebec on this. The power sector in Quebec is very well understood by the government and very well understood by Hydro-Quebec. And it's good to do business there for us. So we would look forward to more opportunities in Quebec to build our power business.

Finally I'd highlight New York, New England where we have, you know, significant background in the power sector, and we will continue to be active there, both on the acquisition front and in development of new projects.

Beyond that as we look around North America, there are many opportunities, as some that are fundamentally attractive to us, but also to a lot of other people, and therefore, the competition is very high. There are fairly extreme Contrarian opportunities in places like California, but I don't think you should expect to see us there soon. And we look at all of these areas, both in terms of the outlook for the price, the likely volatility around that price, and the opportunity to be a significant and competitive player in the market.

One thing I believe in very strongly is competitive advantage. And if we go into other markets that are dominated by big players where competition's intense, the Southeast United States might be that kind of a market, for example, I don't think you'd see us going there, because we don't see what competitive edge we can bring to that kind of situation.

Okay. That's great. If I may ask just one follow-up, it's in return to Becancour. When you received approval for that project, if you could just give us a bit of commentary just on the approval for that project versus the rejection of Sur Wa (ph) and just the logic behind that in your view.

Well, you know, I think that there were significant reasons given by the various regulatory and government agencies in Quebec around those two projects. I would just observe that Quebec needed the incremental power, they needed it fairly quickly, and Becancour at the margin, was a better way to do it from both a cost-efficiency point of view and environmental impact point of view. And the superiority of Becancour is driven by the cogen nature of it, as opposed to the combined cycle.

And I don't mean in my comments to be in any way critical of Sur Wa, we think it's a good project, and one that may in due course go ahead but we just observed that Becancour's the better project because a better heat rate, better fuel efficiency, and lower emissions of all kinds than Sur Wa did.

Okay. That's great. Thank you, very much.

Thank you.

Thank you, Mr Gusby. And the next question is from Winfried Fruehauf of National Bank. Please go ahead.

Thank you. My question relates to page 5 of the second quarter report. And it is on income taxes, and I'd like to obtain explanation as to why there was such a drastic change in the income -- the implied income tax rate between the second quarter of last year and the last quarter? And also why there was a downward change in the 6 months which is not as noticeable as for the second quarter .

Just to be sure that I understand your numbers, Winfried. It's Lee here. You're looking at the 3 month ended June 30th for '03 and '04?

Yes.

And as a 30 versus the 22?

Yes.

Is that correct?

Yes.

So I think that in the second quarter of 2004, where the rate is somewhat lower, obviously, than it would be for the second quarter 2003, there was a small adjustment in there for a couple million dollars, but because the numbers are small, it changes the rate quite a bit by having a very small number change. And there was a couple million dollars of recovery, if you like, in the second quarter of 2004. But it certainly was not something that would be sustained and probably wasn't big enough to actually get into, but it is a couple million dollars, yes.

Okay. And what would be your guidance for all of 2004 and for 2005 for the electricity sector?

I wouldn't expect it to vary significantly from the year-to-date numbers that you have for this year and last year.

I think on a year-to-date basis, Winfried, the effective rate is in the 31 to 32% range both years, so pretty consistent.

Okay. Thanks, very much.

Thank you.

Thank you, Mr. Fruehauf . And the next question's from Linda Ezergailis from TD New Press. Please go ahead.

Thank you. Just have a quick cleanup question on GTN. Now that you've had a little bit more time to look at the transaction, I'm wondering if a decision has been made as to how you will be allocating the purchase price discrepancies. What proportion will be going to good will versus assets?

We haven't made that decision yet. Part of it will be related to how we allocate the price between the PGT asset and the Baja asset. Let me tell you that our current thinking is that good will be a very small number if there's number at all.

Okay. And when will you be able to communicate decision that to us? When the transaction closes?

Yeah. I think when the transaction closes we'll communicate how we're going to allocate the purchase price and the good will.

That's great. Thank you.

Thank you, Ms. Ezergailis. And the next question from Sam Kanes from Scotia Capital. Please go ahead.

Just on GTN, you've also had some time to watch, perhaps, a few contracts mature and rollover on using that system. I know there's a large contract coming in late next year, I think it's PG&E . Is there anything that's shown you any difference of any kind as to of, I guess, the existing of the 26 cent toll? Why would that would be any different, or if it would just be rolling the same? Can you give us a bit of guidance there?

Well, my -- it's Hal here. My observation would be that on most of our pipelines we look to the fundamentals of supply and demand than gas flow rather than relying on contract. The new world is that people, logically, don't want to enter into long-term contracts if they don't have to.

Now, PG&E would be a special case where it, you know, they are such a significant shipper and user of capacity on that system, that, you know, I think you could expect that they probably would want to secure that for their own interests rather than just ship on short-term.

But, you know, what we really looked at when we evaluated PGT was the attractive net back of producers in Alberta generally receive from sales into the California market, and the attractiveness of California as a gas market, and one where we don't see that we face a lot of competition from nongas sources. Certainly there are other pipelines that is deliver gas into California, and depending on the availability of LNG from Baja, Rockies gas coming in through Kern River, I think you can see southern California being a very well-supplied market.

We continue to believe that Northern California is among the very best and most logical markets for Alberta gas and, you know, that's where we get our comfort on volumes that we think will flow through that pipe in the future.

If I may, one last one, Hal, it's very broad. Continentally, it's kind of a slow motion, it seems, movement forward, in frontier gas pipeline prospect projects versus, well, LNG prospect projects, you are very close to both of those camps having worked in both. Could you, kind of, give a general view of -- has there been acceleration, kind of, of setbacks? Or how was the last 6 to 12 months look to you where you sit based on progress in both those camps in this continent?

You know, I was reading in the paper recently about a piece of music that they're playing in Europe that will take 600 years or 900 years, or whatever, to finish the performance. You know, when you talk about slow-moving, and glacial pace, I think that would also reflect what we're seeing here, both on northern pipe development and LNG.

It's a very interesting situation, to me, in that supply and demand would tell us we need these kind of big projects as quickly as possible. And yet the way in which they unfold is slow motion as you describe.

I don't know, Sam, whether there's anything that's likely to happen to trigger an acceleration in the pace of activity or not. I would observer that, you know, we keep at it, we keep trying to position the projects to move as quickly through the commercial and regulatory processes as we can.

But the NIMB factor, the not in my backyard feeling, that effects most of the communities in which these projects would be located, specifically on the LNG side, you know. It's a big issue and we understand why people feel that way. and it's a difficult thing for the policy makers to balance the longer-term energy needs of North America and the United States, in particular, versus the local concerns of people who would do everything they can to slow the projects down.

So, my observation would be it's going to take longer rather than shorter. Commodity prices are probably going to be higher rather than lower, and supply demands challenges are going to continue for the foreseeable future.

Thanks, Hal.

Thanks.

Thank you, Mr. Kanes. And the next question from Karen Taylor from BMO Nesbitt Burns. Please go ahead.

Thanks. I just two really quick questions. Have you got external consultants at the corporate level working in tandem with the Bruce Power people as they go through the resessment to restart 1 and 2?

We're doing our own work on that, Karen. There's a variety of consultants that we would look at using for this sort of thing.

We do believe in tapping into the very best technical nuclear consultants, and TransCanada has very much benefited from the people that helped us understand that. It's not a question of coming up with an alternative plan to what Bruce would generate but it's more case of really, you know, making sure we're a valuable and capable partner and able to contribute to that.

In terms of the financial analysis, we will use consulting expertise on that as well. Just understand and make sure that we're making the right decision.

Well, that's what I'm trying to get to. So, do you have one that's working for you now as you go through the process, and isn't to do something different, it's that's what you're being -- critically evaluate what you're shown by the operators at Bruce?

We do have consultants working for us now, yes.

And just if I can come back to both the western and eastern power groups, can you describe or quantify for me, please, how much of the remaining plant production for '04 in both east and west is subject to contracts. I'm assuming that would be 95% plus in each group and what the present contract position is forward sales for '05, both east and west?

Is that the last question, Karen?

Yes.

Okay.

You want more?

No, if you had another one, I'd ask you --

No, I'm done. I promise.

Except for the remainder of '04, Karen, you're right. I mean, we're at that 90% level. Actually the '05 numbers and '06 numbers just, sort of, decline a little bit from there down to, sort of, the 80% in '06.

For east or west?

This would be total.

Can you give it to me?

Including Bruce.

Including Bruce. Excluding Bruce and by group, can you give me the numbers?

Excluding Bruce. I don't have it broken up that way.

But the average is up high. They both got to be close.

They both got to be pretty close.

I'll look at further breakdown of that, Karen. I'll get you the numbers Lee quoted, obviously include Bruce, but I think it makes sense for them combined. I'll see what I can get for you here individually.

I'm sorry. Just to clarify, so the 90 to 80% includes Bruce.

Excludes Bruce.

Excludes Bruce. And you're break them up afterwards.

We don't have that breakdown right here.

Thank you. That's it.

Thanks, Karen.

Thank you, Ms. Taylor. The next question is from Matthew Akman from CIBC. Please go ahead.

Just a clean-up question. On Portland pipeline, the earnings haven't shown any growth there this year despite the improved ROE that the regulators have allowed in Europe and your increased ownership interest there. I'm just wondering whether, or when we could expect a positive change to kick in there. Thanks.

It's Lee here. I think the reality in Portland is if you look over the last few years, they consistently have lower summer months income than winter months, just given their contract and toll portfolio. So in the winter months, you will see increases compared to summer months, and that's historically been the case as well.

And the other thing I'd just maybe point out Matthew, I don't have the number at my fingerprints, but as I recall, early last year, there may have been a catch-up adjustment related to, I think, depreciation. So on the surface the year-over-year numbers are -- from a run rate or a normalized perspective would be better than what they appear on that page.

Just add to that, Matthew, I mean, last year, if you actually look at the results of the report for Portland, in the summer months of Q2 and Q3, we also did not report income for both those months. Again, it's just the contract portfolio.

Okay. Thanks. That's all I have.

Thank you, Mr. Akman. The next question is from Andrew Fairbanks from Merrill Lynch. Please go ahead.

Hey. Good morning, guys. You touched on LNG and Arctic Gas. I was curious, would contemplate going back to Harpswell, Maine if asked. And second question would be would you care to hazard a guess on the latest thinking on the timing of the MacKenzie Valley Pipeline?

On the first question, Andrew, on going back to Harpswell. You know, it's interesting. We have, in fact, been out. There have been people in the community who have implored us, if you will, to rethink what we might do there, and we've indicated to people that we will not going to try to build LNG projects where the local communities doesn't want us. And Harpswell was the unique situation in that we needed to lease the land in question from the town. It was not free-hold land we owned. And so there was an extra level of discussion required with the towns folk there.

They did have their vote on it. They made it clear that they did not want the project there, and we're not going to force the issue. You know, 3, 5, 10, years down the road, Harpswell may be a very logical place for and LNG terminal, and perhaps someone will develop it sometime in the future. And, perhaps, it would be us, but we would have no plans at all to be pursuing the LNG project any further at Harpswell at this time.

I would say that we have evaluated in a fair bit of detail half a dozen different LNG sites in the eastern U.S. and the maritimes region of Canada. And Harpswell was certainly a good one among the group of 6 that we looked at, but there are several others. And our whole focus in LNG has been to pursue it as a market play, looking at markets where a superior price could be achieved for the producer of the gas.

We're not looking at the commodity play that you would find if it was built in the Gulf Coast, where it's much easier to build the terminals, but the price you get is the Henry Hub minus the cost to get there. So we continue to be focused on pursuing LNG projects in the region that we know in the region that we have a competitive advantage. And if it comes to pass we'll be keen to invest in them.

Regarding the MacKenzie Valley, it's a bit frustrating, I think, to all of the parties that are pursuing that project, that it's not moving ahead more quickly. The market demand for the gas is certainly there. I think Imperial Oil, ConocoPhilips, and Shell are doing everything possible to move that project ahead quickly, and there are plans to submit regulatory filings here in the fairly new future. But, you know, there remain a lot of issues with the local, indigenous people that need to be dealt with up there, and we look forward to some breakthroughs and success on that front.

If things go as planned, we would hope to have that project flowing gas before the end of this decade. And we very much hope that comes to pass, because we would not like to see the MacKenzie Project go into the -- on to the back burner for another 25 years. That would not be a good outcome.

Excellent. Thanks, Hal.

Thank you, Mr. Fairbanks. And the next question is from Winfried Fruehauf from National Bank. Please go ahead.

Thank you. Question is on other gas transmission, page 3 of the report. And the first question relates to Great Lakes. And I'm wondering whether some fairly unique, if not one-time opportunity existed in the second quarter to make this short-term transportation arrangement, or you say repeatability in your opinion.

I think, as always, Winfried, we take advantage of opportunities as they arise. Great Lakes is well positioned based on where your market differentials were over the last quarter. We're seeing that continue into the next quarter as well.

Our view is that, you know, Great Lakes has the expertise and the capacity to take advantage of opportunities as they arise. As you know, In this business volatility is a constant. If you're good at it, you can take advantage of that.

So, I don't know what sort of a run rate, kind of, number is you might be seeking, but I guess this is their job, this is what they do is to try to take advantage of the opportunities and to add to their income by taking advantage of it. And then, as I said we, you know, we haven't seen those opportunities dissipate as we move into the third quarter here, they are continuing.

Thanks. And I have a similar question on both TC pipelines and Ventures as to -- are those unique conditions in their repeatability? What were these unique conditions.

I guess the Ventures one was mostly related to expanding of those pipelines systems. So that's going to be continuing as well. And similarly on the TC Pipelines, we've got an expansion on the Tuscarora System which has resulted in increased income at that level, which we get a proportionate share of. So, for the most part, both of those are related to expansions that we would expect to continue on a go-forward basis.

Pretty well at the same annualized level that we have seen so far in 2004?

It's Lee here. Yeah. Give or take, Winfried, that's probably fair.

Okay. That's all. Thanks, very much.

Thank you.

Thank you, Mr. Fruehauf. And the next question is from Maureen Howe from RBC Capital Market. Please go ahead.

Thanks, very much. Hal, you probably get tired of the questions, so I apologize in advance. But, you've talked about the MacKenzie Delta Project. I'm just wondering if you can update us on the timeline of that project. You mentioned a regulatory filing in the third quarter.

I'm wondering if there's been any progress in the negotiations with the Deh Cho and just really how the timetable unfolds over the period between now and the end of the decade?

I wasn't sure, Maureen, whether you were going to say the period between now and the end of the year, or now and the end of the decade. And let me just affirm that I don't mind questions at all. We think these are valuable sessions, and we enjoy doing them.

We are making progress not only with Deh Cho but the Sahtu, the Gwichin, and the Inuvialuit as well. This project is very important to the aboriginal peoples at the northern end of the pipe. And as a result, the Inuvialuit, and the Gwichin have been the most involved in helping move this project forward.

The Deh Cho situation is a difficult one for all of us because the real issue is that the federal government has not reached land claim settlement agreements or other agreements with the Deh Cho. And as a result, there's a lot of uncertainty there. We would be hopeful that an arrangement could be worked out that would allow us to build a pipeline to get the right-of-way we need, and to proceed with all of that on a different timetable than that which the federal government and the Deh Cho are on with respect to land claims. So, you know, that's a big "if."

And similarly, although to a lesser extent, in the Sahtu region around Norman Wells. You know, it's -- I continue to be frustrated that the time required to build a very sophisticated and technically complicated pipeline is a small fraction of the time taken to get through, what I can only describe as ponderous regulatory and approval processes. And you've seen a lot in the press from different parties lately on the need for Canada and the United States to address this issue.

Countless projects, we know what the outcome is going to be, we know the project's going to go ahead. Just just don't know if it's going to be this decade or the next decade. And somehow or another, the proponents of these projects and the regulators and other government agencies that govern them, have got to address this question and move ahead more quickly, because the alternative is more blackouts, more shortages, more high prices for gas, and so we would very much encourage all parties to think seriously about this and what can be done. And I'm not saying anything new here. This is the conclusion that came out of the Inga study that released over the last week about the need for new infrastructure in North America. And what the real time delays are.

We can have that MacKenzie Valley Pipeline built in 18 months from the day that we get the green light. The big issue is how long is it take to get the green light, and we're being frank with regulators and very frank governments about how long this is taking, because we think they need to understand, and they need to do their part in making these projects move ahead more quickly.

I don't mean to be critical of them, but I mean to be very frank about what's needed if we're get something to happen here. We continue to say 2009, because we're kind of expecting, you know 3 or 4 years of regulatory stuff.

People talk about getting the regulatory process completed within two years. We would hope that's the case. But, you know, we've now spent several years just trying to approach the door to get into the regulatory process, so, you know, it's hard to predict how long the process will take when we've spent several years trying to commence it.

Hal, then has the issue been more regulatory than it has dealing with the northern parties?

Well, no, I think it's a vacuum at the federal policy level. You know, we can build pipelines anywhere in Canada through the right-of-way access mechanisms that is exist in Canadian law. But those processes really aren't, in practical terms, available to us in the McKenzie valley.

It's easier to build pipelines across privately owned land in southern Ontario than it is across federally owned land in the MacKenzie Valley. And this is an issue that the government's going to have to deal with. And that project is not going to go ahead until we can clarify some of those things.

Okay. Thanks, very much.

Thanks, Maureen.

Thank you, Ms. Howe. And the next question is from Dominique Barker from Credit Suisse First Boston. Please go ahead.

Hi. Russ, given the book value of GTN's about $700 million, Canadian, how can the good will be 0?

Say that again?

Well, the book value of GTN, you had mentioned to someone else's question that you expected good will to be zero?

Yeah.

But you're paying an excess of book value. So, how's -- I'm wondering -- like -- how are you -- how does that work?

Like I said. First question I'll let Lee answer, here. But the $700 million book value for GTN, are you talking about the equity value?

Yeah.

So that's the equity of GTN and Baja combined?

Yes.

Okay. What we would do, I mean, we will, to the extent there is access purchase price over and above that, we will amortize that over the normal depreciation, I believe.

So, just from an accounting perspective, Dominique, basically what happens when you buy these off is that you have to look at the what the depreciated replacement cost is of those assets today. And so, therefore, the underlying book value may or may not be relevant from and accounting perspective as to where you end up.. And, of course, if you look at the value, the depreciated replacement cost today of that assets, it would become much more closer to the value that we're paying. So the underlying book value is not particularly relevant, especially with pipes that are older.

Oh, okay. I have a second question. It's more general. GMI Co. has been quoted as saying that the reason that they want to build Havasquez (ph) is to have an alternative supply to TransCanada mainline? Does the NEB have any ability to intervene on there given that there's excess capacity on the mainline?

You know, the interesting issue, I don't necessarily disagree with Gaz metro on this because it's not an issue of capacity on the mainline, so much as it is gas flows out of western Canada, and whether the molecules are there coming out of Alberta, And whether or not they get attracted to markets in Ontario and Quebec, or do they firstly get attracted to markets in Alberta, California, and the Chicago-Midwest area?

So, you know, we firstly would recognize that North America is structurely short of gas, and that is those parts of North America that are the furtherest end of the pipeline are the most exposed. And in this particular case, on our system that's Quebec, and it is New York and New England, so those are the areas we would see as being most logical for LNG to come in.

We don't particularly like the way GMI characterized it, as being an alternative TransCanada. I don't think there's any issue between us and GMI, to cause them to want supplier of transport service other than TransCanada, perhaps other than what some of their shareholders might want.

But, we think we'll continue to provide reliable service to Quebec as long as the gas is available in Alberta, and the importation of LNG would help to balance that market.

Okay. Thanks for that insight.

Okay.

Thank you, Ms. Barker. And we would now take questions from the media. The first question is from Gordon Jerinsgo from Edmonton Journal. Please go ahead.

Yes, sir. It's a further question to the MacKenzie Valley Project. Wondering if you could clarify how you would separate the land claim process from the pipeline process. Sort of explain what is the real sticking point there, and what has to be changed?

Well, Gordon, it's certainly is not up to us to separate them. You know, under the NEB application process, we have certain retirements that we have to meet, both for the NEB and for the large number of environmental review boards that exist up and down that right-of-way.

It's truly amazing, the regulatory structure that's been created in the Northwest Territories with land and water review boards that are more than a few that have to be satisfied on this. But all that, we think we can handle it in a relatively straight-forward way.

It'll take a long time, and the process is overly ponderous, and we would encourage all the regulators to continue the collaborative efforts that have been led, primarily, by the NEB, to simplify things. And we commend the NEB for the efforts they've made thus far.

On the land claim side, there's no really role for us, and there's nothing we can do. This is a matter that the federal government needs to address with the Deh Cho. And the federal government also needs to address some other residual issues in the other aboriginal regions as well.

So we can do nothing other than encourage the federal government to treat this problem seriously, and, you know, there were sporadic periods of serious attention to this issue during the last government, but nothing was brought to closure, and we would just encourage them to do that.

In light of what you're saying about needing to separate the land claim process from the regulatory process in order to get the pipeline through, is that, sort of, implying that until and unless that line claim is settled with the Deh Cho, that the project is just not going anywhere?

We don't know that. The federal government would have a wide range of mechanisms available to it to enable the project to go ahead. But I'm simply saying, Gordon, that this isn't an issue that we can settle.

Okay. Is it the fact that the issue's there, though, that is the principal hang-up for the project.

Hang-ups for the projects come out of the woodwork as the process moves ahead. And, you know, I just can't begin to imagine what might -- what the next set of hurdles might be.

Okay.

You know, this is was a very good project 25 years ago, and then it was market prices that effectively that put it on the back burner. People have pointed to the Berger inquiry and all of those things, as reasons why the project didn't go ahead. In my opinion that's not actually correct.

The real reason it didn't go ahead was the market changed and there were ample supplies of gas . And the market could change again, here. And, you know, we just don't know what the market for natural gas in North America 7 or 8 years out might be. In the event that the Alaska has gone first and the LNG project have gone ahead by the dozen, you know, it might make a different market situation for MacKenzie Gas. We think that would be an unfortunate outcome, but people shouldn't necessarily assume that the voracious market appetite will be there. I think we should go ahead with this project while it's attractive to do so.

Does it help you have now got 3 out of the 5 native nations along the route as formal shareholders in the Aboriginal Pipeline Group, and you only have the Deh Cho left?

There's really significant financial value for the APG members in the construction of this pipeline. The way in which we're prepared to proceed, and the producers are prepared to proceed is very attractive financially for the APG members, and we would hope that they would be motivated by that to encourage the rest of the aboriginal peoples along the route to try to move the project ahead more quickly. But, you know, as to whether or not they will do that, that's their decision.

Okay. Thank you. Thanks, Gordon.

Thank you, Mr. Jerinsgo. And once again, please press star, 1 at this time if you have a question or comment.

And there are no further questions registered. I would now turn everything back over to Mr. Moneta.

Great. Thanks, very much. Just like to thank everyone for participation this morning. We appreciate your interest in TransCanada and we look forward to talking to you again in the not-to-distant future. Bye, for now.

Thank you, Mr. Moneta. The conference has now ended.

Please disconnect your line at this time. We thank you for your participation, and have a nice day.