TC Energy Corp (TRP) 2005 Q2 法說會逐字稿

Good morning, ladies and gentlemen. Welcome to the TransCanada Corporation 2005 second quarter results conference call. Please be advised this conference is being recorded.

I would now like to turn the meeting over to Mr. David Moneta, Director of Investor Relations. Please go ahead, Mr. Moneta.

Thank you. Good morning, everyone. I'd like to take the opportunity to well you today. We're please to provide the investment community, the media, and other interested parties with an opportunity to discuss our second quarter 2005 results and other general issues concerning TransCanada.

With me today are Hal Kvisle, President and Chief Executive Officer; Russ Girling, Executive Vice President and Chief Financial Officer; and Lee Hobbs, Vice President and Controller. Hal and Russ are going to start this morning with some comments on our financial results and other general issues pertaining to TransCanada. We'll then turn the call over to the conference coordinator for questions. During the question and answer period, we'll take questions from the investment community first and then open the call to the media.

Before Hal begins, I'd like to remind you that certain information in this presentation is forward-looking and is subject to important risks and uncertainties. The results or events predicted in this information may differ from actual results or events.

Factors which could cause actual results or events to differ materially from current expectations include among other things the ability of TransCanada to successfully implement its strategic initiatives and whether such strategic initiatives will yield the expected benefits; the availability and price of energy commodities; regulatory decisions; competitive factors in the pipeline and power industries; and the prevailing economic conditions in North America.

For additional information on these and other factors, see the reports filed by TransCanada with Canadian Securities Regulators and with the United States Securities and Exchange Commission. TransCanada disclaims any intention of 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.

During the second quarter of 2005, TransCanada continued to deliver solid operational performance and make further progress towards achieving our growth objectives. Over the long term, we continue to see significant opportunities to grow and create value for shareholders through both Greenfield developments and acquisitions.

TransCanada Corporation's net income for the second quarter of 2005 was $200 million, $0.41 per share. This compares with net income of 388 million or $0.80 per share for the second quarter of 2004.

Excluding the gains of 194 million recorded in the second quarter of 2004, primarily related to the power LP, and 1 million recorded in the second quarter 2005, related to TC Pipelines LP, net income for the second quarter 2005 increased $5 million compared to second quarter 2004.

TransCanada's board of directors today declared a quarterly dividend of $30.5 per share for the quarter ending September 30, 2005 on all outstanding common shares. This marks the 167th consecutive quarterly dividend paid by TransCanada and its subsidiary. The dividend is payable on October 31st, 2005 to shareholders of record at the close of business on September 30, 2005.

Russ Girling will take you through a more detailed review of our financial results. But before turning the call over to Russ, I would like to take a few moments to discuss the events of the past quarter and the progress we have made in achieving our corporate objectives.

I'll begin with updates on the regulatory front, as we've had some encouraging developments so far this year. In early April the National Energy Board approved the Canadian mainline coal settlement application for 2005 without amendment. This settlement was the result of broad industry negotiations and represents a balance of interests and compromises.

Later in April, TransCanada received the NEB's decision on the Canadian mainlines 2004 tolls and tariff application, phase 2. In that decision, the NEB approved an increase in the deemed common equity component of the Canadian mainline's capital structure from 33% to 36%, effective January 1, 2004. While this is not the 40% we had requested, it is a move in the right direction and we're pleased with the progress that is being made.

In June, the Alberta Energy and Utilities board granted approval, again without amendment, of a negotiated settlement for the Alberta system's 2005 through 2007 revenue requirement. TransCanada and its stakeholders, including producers, marketers, industrial and residential customers, and utilities, worked very hard to reach this settlement. These negotiations are highly complex and often challenging. To arrive at an agreement that TransCanada, our customers, and our regulator can support is indeed a positive outcome.

In both the western and eastern regions of our gas transmission business, we continue to work with our customers on the evolution of business models that will work for TransCanada and our customers over the longer term. In the western region our objective is to build on the success of the Alberta hub. The development of the Alberta hub has made it easier for producers to sell their gas at a transparent liquid hub and to facilitate liquids extraction within the province.

It has also served Alberta's gas consumers. There is a virtually unlimited supply of gas available for Alberta consumers at the Alberta hub.

Ultimately, our objective is to offer a seamless model to enable producers to move their gas from Alaska and the McKenzie Delta to an Alberta hub that offers greater physical liquidity than any other hub in North America. The continuing development of the Alberta hub and the evolution of competitive tolling structures on our high-volume pipelines from the Alberta hub to North American markets will maximize the value of Alberta gas to North American markets and North American consumers and sustain our gas transmission business over the longer term.

Our long haul systems, including Gas Transmission Northwest, Northern Border, Great Lakes, and the Canadian Mainline, together move two thirds of Western Canada's production to end-markets. I would note that each one of our four major long-haul pipes moves western Canadian gas to end markets than do the entire networks of any of our western Canadian competitors.

Before turning to our eastern region, I'd like to briefly comment on how please we are with the integration of the GTM system from a financial and organizational perspective. During the first six months, GTN has made a health contribution to earnings and cash flow, and we have made significant progress in bringing our two different organizations and cultures together. We have acquired an excellent pipeline and an excellent group of people at GTN and we are pleased with its initial performance.

In our eastern region, our focus is on evolving a model to meet the needs of high-volume gas customers, such as power generators and large industrial users, while at the same time ensuring stable, reliable supply for residential and small commercial customers. We're setting the stage for the introduction of new liquified natural gas supply, potentially through the projects we're currently working on, Gros Cacouna in Quebec, in partnership with Petro Canada, and Broadwater in New York, where we're partnering with Shell.

We look forward to the development of a liquid and transparent hub in the Dawn to Quebec City corridor. Such a hub would give Ontario and Quebec consumers access to multiple sources of gas, including gas from western Canada, from Dawn storage, from American hubs, and from LNG terminals in Quebec, the Maritimes, and the northeast U.S.A.

The evolution of our east and west business models speaks to our strategy to maximize the long-term value of our Canadian wholly owned gas transmission business. At the same time, we continue to pursue our strategy of growing our pipeline business in attractive regions of North America. To that end, in June we were awarded a contract to construct, own, and operate a natural gas pipeline in east-central Mexico. The 125-kilometer Tamazunchale pipeline will transport national gas under a long term 26-year contract with the Mexican Electricity Commission. . TransCanada expects to invest approximately 181 million USD in the project. The planned in-service date is December 1, 2006.

Mexico is a significant part of the broader North American gas market and one that TransCanada knows well through our experience with the Mayacan and El Bajio natural gas pipeline projects in the 1990s. We have good relationships with stake holders in Mexico and we enjoy a strong -- a strong reputation in that country. TransCanada expects the Mexican natural gas market, currently at 6 BCT per day, to grow to 9 BCF per day by the year 2013, driven in large part by new natural gas-fired power plants. We continue to assess other energy investment opportunities in that county. Rest assured that our focus remains exclusively on North America and that we will proceed in our usual prudent and disciplined manner.

Moving now to the northern end of the continent, we are encouraged at the progress that has been made in recent weeks with norther aboriginal groups, including the return to the negotiating table of the Daicho [ph] First Nations and the pledge from the federal government of approximately $500 million to help aboriginal communities deal with the socioeconomic impacts of the planning and construction of the McKenzie valley pipeline.

Many hurdles remain in bringing northern gas to market. However, we remain optimistic that sustained and growing demand for natural gas will support construction of the necessary infrastructure over the next decade. What we're less certain of is whether the many groups around the table can successfully resolve their issues to enable construction to begin. TransCanada and our McKenzie Valley project partners greatly appreciate the federal government's actions in helping to advance the McKenzie Valley pipeline. We're all working diligently but our forward momentum will be difficult to maintain unless we can get greater certainty and clarification around issues such as benefit and access agreements.

Turning to the Alaska project, it is important that the producers and the Alaska State government reach agreement on key upstream fiscal terms. TransCanada is ready to work with producers in the state on the best commercial arrangement to bring Alaska gas to the Alberta hub and from that hub to North American markets on a timely basis.

Finally in our pipeline business, we continue to development and advance the Keystone oil pipeline project. Since this project was announced earlier this year, discussions have been ongoing with potential shippers. Feedback, gathered through an expression of interest process, continues to indicate strong shipper support. We anticipate holding a binding open season process beginning this August. We see oil transmission as a logical fit with our existing business competencies and an efficient way to maximize the utilization and value of our current pipeline assets.

Turning to our power business, TransCanada closed the acquisition of the U.S. gen hydroelectric generating assets on April 1st. We're please to acquire significant hydro assets in New England. These assets are a good fit with our existing power portfolio and our power marketing operations in the northeast United States.

In Quebec we remain on track to bring the 550 megawatt Becancour co-gen plant, the largest Greenfield power project TransCanada has developed to date, into service in the fall of 2006. All of the output of that plant will be contracted to Hydro Quebec.

Also in Quebec, Cartier Wind Energy has begun the environmental permitting process for wind power projects that will begin in 2006. Earlier this year, Cartier Wind Energy announced the signing of long-term electricity supply contracts with HydroQuebec distribution, for 740 megawatts of wind power. TransCanada owns 62% of the assets related to Cartier Wind Power projects.

In Ontario, discussions between Bruce Power and the provincial government on the restart of units 1 and 2 are ongoing. With the recent heat wave in the East, I know our customers in Ontario are eager for updates on the potential addition of 1500 megawatts to the provincial grid through the restarts of units 1 and 2. I would note that a nuclear refurbishment project is very complicated and the project engineering, project planning, and commercial negotiations are going to take some time. TransCanada brings sophisticated engineering project management and commercial skills to the Bruce project and we will be very thorough and deliberate to ensure a satisfactory outcome for all of our stake holders.

Russ Girling will provide you with greater detail on the numbers coming out of Bruce for the second quarter. However, I would note that we expect Bruce to have a much higher operating capacity factor in the last half of the year, as much of this year's planned maintenance work has now been completed.

While growth in our natural gas transmission and power business remains a priority for TransCanada, at the same time, we are carefully managing our existing assets to ensure that we capture the maximum value from those assets for our shareholders. In June we announced the sale of TransCanada Power LP to EPCOR. This was not an easy decision. The Power LP consists of high-quality assets run by experienced, knowledgeable people. Under our sponsorship, TransCanada Power LP has grown significantly while generating strong returns for partnership unit holders, including TransCanada. However, the completion of this transaction will enable TransCanada to focus on our much larger directly owned power businesses in Canada and the United States, including our interest in Bruce Power. We expect to realize an after-tax gain of approximately $200 million at the closing of the sale of Power LP in the third quarter.

Also in June we announced the sale of TransCanada's approximately 11% interest in PT Piton Energy Company to subsidiaries of the Tokyo Electric Power Company for approximately US $103 million. Piton Energy owns two 615 megawatt coal-fired power plants in East Java, Indonesia. TransCanada acquired its interest in Piton Energy in 1996 and has retained that interest until favorable conditions for a sale and exit were available. The transaction is expected to close in the third quarter of 2005, subject to various approvals. Upon closing, TransCanada expects to realize an after-tax gain of approximately Canadian $115 million.

As I noted at the outset, TransCanada has a large and high quality portfolio of opportunities that we continue to pursue. Consistent with our strategic direction, these opportunities draw on our competitive advantages in natural gas transmission and power and are located in markets that we know well. As they are realized, these projects will strengthen our financial performance and deliver long-term value to our shareholders. Ultimately all of our efforts, whether they relate to growth, to the strategic management of our existing portfolio, or to day to day emphasis on operation excellence in everything we do, all these efforts are focused on the paramount objective of delivering superior total shareholder value.

We remain committed to implementing our corporate strategies in a disciplined and focused manner, and as a result, continuing to make progress in achieving our goals.

In closing, I'd like to recognize Kevin Benson and Lynn Draper, who have recently joined TransCanada's Board of Directors. Mr. Benson and Dr. Draper each bring a broad range of experience to the board. Mr. Benson, through his financial acumen and leadership of companies like Laidlaw International, and Dr. Draper through his extensive experience in the U.S. power industry, his strong technical expertise, backed by a doctorate in nuclear science and engineering. I would note that Dr. Drape is the former CEO of American Electric Power, one of the very largest electricity generators in the United States.

The composition of our Board reflects TransCanada's growing presence in the North American energy market and reinforces our commitment to strong corporate governance by directors who know our businesses and who bring valuable experience and incite to bare in governing our company.

I'll now turn the call over to Russ Girling who will provide additional details on our financial results. Russ?

Thank you, Hal. And good morning, everyone.

As Hal mentioned, earlier today we announced net income for the three month ended June 30, 2005, of $200 million or $0.41 per share compared to $388 million or $0.80 per share for the same period last year. Excluding gains of $1 million in 2005 related to TC Pipelines LP and $194 million in 2004 related to the TransCanada Power LP and Millenium, net income for the second quarter of 2005 increased by $5 million or 1% -- or $0.01 per share compared to the second quarter of 2004. The increase was primarily due to a higher contribution from gas transmission which was partially offset by lower contribution from power.

I'll briefly review the second quarter results for each of our segments beginning with gas transmission. Gas transmission generated net earnings of $165 million for the second quarter compared to $146 million for the same period in 2004. Excluding the gains related to the TC pipeline's LP in 2005 and Millenium in 2004, net earnings from gas transmission $164 million in the second quarter compared to $139 million last year.

The $25 million increase was primarily due to higher contributions from the Canadian mainline and Gas Transmission Northwest, which were partially offset by lower contributions from the Alberta system and other gas transmissions.

The Canadian mainline generated net income of $86 million in the second quarter, which is an increase of $20 million over the second quarter of 2004. The increase reflects the impact of the National Energy Board's April 2005 decision on phase 2 of the 2004 tolls and tariff application. The decision included an increase in the mainline's deemed common equity ratio from you 33% to 36% for 2004. The increase in deemed common equity ratio is also effective for this year under the 2005 settlement with shippers.

As a result of the decision, the Canadian mainline's net income increased by $21 million in the second quarter of 2005. The $21 million increase includes $13 million related to 2004, and $8 million related to 2005. This increase was partially offset by a lower average investment base and a lower allowed return under the NEB formula.

Gas Transmission Northwest, which was acquired on November 1, 2004, also contributed to the increase in net income from gas transmission. During the second quarter of 2005, GTN generated net earnings of $60 million and funds from operation of approximately $50 million. On a year to date basis GTN has generated net earnings of $39 million and funds from operations of approximately $100 million.

The Albert System's second quarter net earnings were $37 million which was $2 million less than the amount reported last year. The decrease was primarily due to a $185 million decline in the Alberta System's average investment base over the last 12 months as well as a lower approved rate of return in 2005.

Finally, with respect to gas transmission, TransCanada's share of net earnings from other gas transmission, excluding the gains related to the TC Pipelines LP and Millenium, was $18 million in the second quarter compared to $28 million for the same period last year. The $10 million decrease was primarily due to a lower contribution from Great Lakes and TC Pipelines LP. The contribution from Great Lakes declined by $3 million due to lower short-term revenues and higher operating and maintenance costs. The contribution from TC Pipelines LP declined by $4 million due to our reduced ownership interest.

Finally, the weaker US dollar also reduced the overall contribution from our U.S. pipeline operations by approximately $2 million.

Next I'll make some comments on power. In the second quarter the power business contributed net earnings of $42 million compared to $62 million last year, which excludes the gains related to the TransCanada power LP. The $20 million decrease was primarily due to lower contributions from Bruce Power and western operations which was partially offset by a higher contribution from our eastern operations.

Total volume sold in the second quarter were 7,323 gigawatt hours compared to 7,901 gigawatt hours in the second quarter of last year.

Eastern operations -- operating in other income in the second quarter was $39 million compared to $22 million last year. The $17 million increase was primarily due to contributions from the hydroelectric facilities acquired from USGen on April 1, 2005, and the Grandview cogeneration facility which was placed into service in January of 2005.

The hydroelectric facilities acquired from USGen have a total generating capacity of 567 megawatts. Over the last ten years, they have produced approximately 1.4 million megawatt hours of electricity on an annual basis, without output generally higher in the spring months due to seasonally higher water flows during those months.

During the second quarter these facilities generated approximately 590,000 megawatt hours of electricity, which was sold under contract to wholesale, commercial, and industrial customers, as well as into the spot market.

Overall in the second quarter of 2005, 84% of the eastern power sales volumes were sold under contract. The remaining 16% was sold into the spot market.

Partially offsetting the increased contribution from the hydroelectric facilities and Grandview, was the loss of income associated with the sale of the Curtis Palmer facility to the TransCanada Power LP in April of 2004, which resulted in $4 million reduction in operating income.

Bruce Power contributed $13 million of pre-tax equity income in the second quarter compared to $48 million last year. The $35 million decrease was primarily due to lower generation volumes and higher costs resulting from planned maintenance outages on unit 7 and unit 4 and an unplanned maintenance outage on unit 6, due to a transformer fire outside of the generating facility.

Overall, approximately 138 days of planned and unplanned maintenance outages occurred in the second quarter of 2005 compared to 40 days of outages in 2004. This reduced TransCanada's share of power output from the Bruce Power to 23,006 gigawatt hours in the second quarter of 2005 compared to 2,962 gigawatt hours last year. Highly realized prices in the second quarter of 2005 partially offset the reduction in revenues from lower generation volumes and the increase in outage and operating costs.

Overall prices achieved during the second quarter were approximately $53 megawatt hour compared to an average realized price of $46 per megawatt hour in the second quarter of 2004.

Approximately 46% of the output was sold into Ontario's wholesale spot market in the second quarter, with the remainder being sold under long-term contracts. On a per unit basis, operating costs increased to $46 per megawatt hour in the second quarter of 2005 from $30 per megawatt hour in the second quarter of last year. That increase, as you are aware, is primarily due to reduced output. A significant portion of Bruce Power's operate costs are fixed and incurred whether or not the units are operating. As a result, the reduction in output will result in higher per unit operating costs.

A $24 million increase in outage costs also contributed to the increase in per unit operating costs. The increase was primarily related to planned maintenance outages, as I said, on unit 7 and unit 4, as well as the forced outage at unit 6.

Going forward, equity income from Bruce Power will be impacted by fluctuations in wholesale spot market prices for electricity, as well as overall plant availability, which in turn is impacted by scheduled and unscheduled maintenance. To reduce exposure to spot market prices, Bruce Power has entered into fixed-price sales contracts for approximately 36% of the planned output for the remainder of 2005.

Overall plant availability for the full year is still expected to be approximately 83% compared to 76% during the first six months of 2005. The increase is primarily due to fewer planned outages in this last half of 2005. Unit 7, which was taken off line on May 7th, to begin it's planned maintenance outage, is expected to return to service in early August. The only other 2005 planned maintenance outage is on unit 5. It is scheduled for the fourth quarter and is expected to last approximately 60 days.

During the first six months of 2005, Bruce Power generated cash from operations of $209 million, and capital expenditures totaled $153 million. In June 2005, Bruce Power made a $50 million cash distribution to it's partners. TransCanada's share of that distribution was $16 million. In late July, Bruce Power made another cash distribution of $35 million to its partners, and again, our share of that distribution was $11 million.

Going forward, the partners have agreed that all excess cash will be distributed on a monthly basis, and that separate cash calls will be made for major capital projects.

Finally in Power, operating and other income from western operations was $28 million in the second quarter compared to $35 million last year. The $7 million decrease is mainly due to $4 million that we earned on fee revenues in 2004 from the sale of ManChief and Curtis Palmer to the TransCanada Power LP and reduced margins in the second quarter of 2005 resulting from lower market heat rates on uncontracted volumes of power generated.

As you are aware, lower market heat rates were the result of spot market prices in Alberta that averaged approximately $9 per megawatt hour less in the second quarter of 2004 compared to the same period last year and average natural gas prices that were slightly higher than they were last year.

A significant portion of plant generation in our western operations is sold under our long term contract to mitigate price. However, some of the output is intentionally not committed under long-term contract to assist in managing Power's overall portfolio of generation. This approached portfolio management assists in minimizing costs in situations where TransCanada would otherwise have to purchase power in the open market to fulfill it's contractual obligations.

In the second quarter of 2005 approximately 87% of the western power sale's volumes were sold under long term contracts. The 13% that was remaining was sold into the spot market.

And finally, in our corporate segment, net expenses were $7 million in the second quarter of 2005, which is comparable to the same period last year.

Turning to cash flow and our balance sheet, funds generated from operations were $479 million for the three month ended June 30, 2005, an increase of $97 million when compared to the $382 million reported for the same period in 2004.

Capital expenditures and acquisitions in the second quarter were $767 million and were related primarily to the acquisition of the hydroelectric facilities from USGen, the construction of the Becancour power plant, and maintenance and capacity capital in the gas transmission business.

As you can see, our balance sheet remains strong, it consists of 59% debt, 3% preferred securities, 2% preferred shares, and 36% common equity as at June 30, 2005. During the remainder of the year we would expect the balance sheet to continue to strengthen, in part due to the sale of the Power LP and the Piton power plant in Indonesia. Upon closing these deals, we expect to generate cash proceeds of approximately $650 million and after-tax gains of approximately $315 million. As a result, it is expected that the short-term debt balances will decline and shareholder equity will increase over the remainder of the year. This will further enhance our strong financial position.

In closing, as we move forward, we will continue to prudently reinvest our discretionary cash flow and make profitable investments in our core businesses. We'll continue to focus on operational excellence, with a focus on providing low-cost, reliable service, to all of our customers. We'll continue to maintain a strong financial position. It is our belief that successful execution of these strategies will continue to deliver value for our shareholders.

That concludes my prepared remarks and I'll turn the call back to David.

Thanks, Russ. Just a reminder before I turn it back to the conference coordinator, as part of the question and answer period we'll accept questions from the investment community first and following that we'll be happy to open it up to the media. And with that, I'll turn it now back to the conference coordinator.

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

Thank you. I just have a question with respect to Bruce Power. I'm a little bit confused why the partners would choose to start distributing cash now if there's a potential for a big investment. Of course, I'm not referring to Point Lepreau, because a decision has been made on that, but -- but for restarting the two mothballed units at Bruce Power, can you give us a sense, first of all, why that decision was made, and -- and -- and why that might not be a discouraging data point given -- given the New Brunswick decision.

And did the New Brunswick power team that decided not to go ahead with Bruce Power's proposal, give any sort of reasoning? Was it purely what they felt was a cost decision? Was it a local jobs issue? Or anything like that? And -- I'm just trying to get a sense, of you know, how -- how that decision -- process might be different than what is going on in Ontario right now.

And I guess the third prong of my question would be, within the Ontario government, what is the exact process for decision making? Who is touching the documents or involved in the discussions within the government, both the bureaucrats as well as the elected officials, and I think it's taking a lot longer than all of us expected and I can appreciate the complexity, but what's causing the delays? Is it the complexity? Is it they're on summer holidays? What is going on?

Well, I'll -- I'll try to give a -- a shot at all three of those, Linda, and Hal can jump in here. On the distribution question, is -- is it's prudent for us -- up to this point in time we haven't had any distributable cash as our capital expenditures had exceeded our distributable cash or had been approximately equal to our distributable cash. We reached a point where our cash flow is in excess of our capital needs. So it's only prudent to take that cash out. When and if we come to the point where the cash is needed again in the business, Bruce Power will call for that cash, and there's a process by which it's set up for them to call that cash back into the business. But from a cash management perspective, it's only prudent to take that cash out of the business and not let it sit idle inside Bruce Power, and I think that's common amongst all of the partners.

With respect to Lepreau and the New Brunswick Power's decision to go with ACL to -- to refurbish their plant, we haven't been given any reasons, but I would surmise, based on the competitiveness of the process that our costs were probably higher than ACL's, but we haven't been given any formal reasons as to why we weren't chosen. We still believe that there's some benefits in working with them and the door is always open to continue a dialogue from an operating standpoint if they have any desires along that direction. But at the current time we haven't been given any feedback on the nature of our bid relative to ACL's bid.

And then, I guess your last question on the Ontario process, recognize this is probably taking longer than most people anticipated. We announced -- not we -- the Ontario government announced a deal in principle with the partners in March of -- of this year and from that point in time it's put in place a group of experts, being technical experts, financial experts, and legal experts, to structure a very complex deal with -- with the partners at Bruce Power, and I guess what I can tell you in terms of time is this is a very complex negotiation. There is a number of pieces that need to be managed, and I think the primary ones are related to the construction itself and the sharing of -- of construction cost risk and management of construction cost risks, being sort of front and center of those negotiations.

So I think the -- the time frame is just a reflection of the complexity and I wouldn't say would be an indication of anybody's desire or -- or lack of desire to get -- get a project done. I think that from our perspective and the perspective of the Ontario government, the power that Bruce wanted to cogenerate would be extremely beneficial to the province if it can be brought on. Both sides are motivated to see if they can make that happen and are working very diligently, as quickly as they possibly can, and so I wouldn't read anything more into it in terms of the pro decisions or the time it's taking that -- that that's an indication of any lack of interest from either side. Both sides are working very hard to come to something that will work for the partnership and for the province.

Linda, it's Hal here. If I could just add to that, I think in both the Lepreau outcome and the length of time it's taking on the Bruce 1 and 2 units, one thing you should read into that is that we are very aware of the capital cost risk and challenges of restarting and refurbishing nuclear reactors and TransCanada is being very prudent and disciplined as it moves through these.

In the case of Lepreau, you'll see from the Premier's comment that they intend to hold the AECL accountable for the cost outcome of the project. I think that just reflects the cost worries that we all have when you get into these kind of projects. So on Bruce, we'll being very thorough in the way we look at our cost estimates and the contracting arrangements that we're attempting to put together and that -- that all takes time, as I said in my earlier remarks.

Is there any one particular aspect of the multiple complex pieces that you are managing that is -- is the most complex or -- or kind of the bottleneck in the process? Is it the construction risk sharing that -- that perhaps, or --

No, I don't think, Linda, that I can put my finger on any one part. Obviously it's a very large project. It's two reactors, there's timing and sequencing issues, but it's also just how much risk our contractor is prepared to take and how can we ensure that the project comes to a successful conclusion and is a positive financial outcome for TransCanada. That's our highest priority.

And it's not just Bruce and it's not just nuclear. It's something we see in the oil sands here in Alberta and on all major projects. This is a time when major project companies have to be very careful. Inflation might be 2 or 3% at the consumer level in Canada, but it's much higher at the heavy industrial project level and that's something we're paying a lot of attention to.

Can you give us any sort of bookends around the earliest -- I don't want to say the latest time that it can happen. But obviously Point Lepreau, you got a sense of when it was coming close. Is this a Q3, Q4, Q1 next year decision point? Or do you have any sense of how far along or how far away we are from a decision on that front?

No, I really can't give you much insight into that, but I would just say again that this is a big project and it's one that could be quite significant for TransCanada and we're very pleased with the effort that's being put into it by the Bruce team and the work and cooperation we're getting from our two partners in that project. So I think everybody is doing everything they can.

We respect the concerns that the government has. Obviously the government of Ontario is going to be very careful about how they proceed with these things. There have been some bad outcomes in the nuclear sector in Ontario, historically. We all want to make sure that doesn't happen again.

That's great. Thank you.

One quick question before I jump back in the queue. GTN, you mentioned you're very pleased with the progress on integration. Do you have a sense yet of the magnitude of cost synergies that you might realize there, whether it be operating related or tax related?

I don't think we have a number like that that we would share you -- share with you.

No. We don't have one yet. I think that -- we shared sort of what the costs are before. Progress is moving well and hopefully in the next little while we'll be able to share something with you. One of the reasons that we have been hesitant to do that is it's a fairly complex sharing formula inside the Company as to how those allocations work and what we actually get to put in our pocket. We haven't nailed that down yet. So once we get there, we will talk to you about that.

Great.

Linda, I would add to that, though, that if you think about it one of the real interesting upsides of our acquisition of GTN is that maybe we can offer a better gas transmission service to our customers, but today and historically if you've wanted to move gas from central Alberta to California, you've had to have capacity on NGTL in Alberta, on our BC system, which was owned by ANG, on the PGTGTM system, which was owned by National Energy Group, and then an in-state California toll.

And we don't know that we can integrate tolling into the state, but we think that we can offer a much more seamless and customer friendly service from the Alberta hub through BC and down the FERC-regulated pipeline to the California boarder and trading point at Malin. And there's some very interesting commercial synergies there that I think may be more interesting to us than just cost reductions.

So, when you say commercial synergies, that would suggest that would drive more volumes perhaps? Or you could charge more for that seamless integration?

All of those things are possible, and all of those things would be in our long-term list of objectives.

That's great. Thanks Hal.

The next question is from Dominique Barker, Credit Suisse. Please go ahead.

Just following on on GTN. Last quarter you hit a marked to market debt impact. Was there a similar impact this quarter?

Dominique, it's Lee Hobbs here. Yes, there was. That related to the fair value of the debt at the date of the acquisition and we were essentially amortizing that over til June 1, when that debt -- the $400 million was actually taken out and replaced. So in -- the differential, the first quarter there was a positive income effect of probably somewhere around $6 million, give or take, and in the second quarter, of course we only had it for a couple of months, so it was a couple million dollars less than that, but there was still a fairly healthy contribution just from the amortization of the fair value purchase prize amortization.

Okay. Because that would suggest that your earnings are actually down from last quarter. And actually if you look at the public filings on GTN, it's down versus last year's. Last year's quarter as well.

Yes.

Is there -- is that indicative of the future, or was this quarter a one-off?

Well, I think that there's two things there. I -- I think there was some -- some additional costs we had. We did have some compressor overhaul repair costs in the second quarter, which were somewhat unusual, and our revenues were down probably a million or two from the first quarter as well.

I would say that on a go-forward basis, some of those will reoccur over the quarters. I mean, GTN is different than the Canadian pipelines. There we are at risk for low M&A [ph] costs and at revenue. So there will be a volatility on a quarterly recorded basis. I wouldn't expect it to be large, but there will be some volatility.

Okay. And that repair you referred to, or some of that maintenance; how much was that?

It was a couple of million bucks.

Okay. And just one other question on Bruce. The operating costs -- of course, I know you only disclose them per megawatt hour, but it looks like they have increased maybe to -- over last quarter. Again -- and I know it's more of a fixed cost -- is that indicative -- and I understand that there's some amortization of labor cost from your unit 3 restart. So is that an indication of future operating costs?

I think that the costs were approximately what they were last year, with the exception of the additional outage costs that we mentioned. And, Lee, I think the number was, what, about $20 million in the quarter?

Yes, I think, Dominique, if you look at first quarter this year -- I'm just doing the math year. Probably would have been about, on the cash cost item, probably 265, versus 287. That was essentially due to the outage costs and the unit 6 repairs costs. Compared to last year, I think it's mostly what Russ had said previously it is, due to the higher outage costs and the higher cost of the unit 6 --

I appreciate the cash costs might be similar, but given we don't have a balance sheet or a cash flow statement on Bruce, I can only look at the actual costs that you report, and base -- my ballpark is somewhere around 335 million. First and last quarter, about 310 --

So Dominique, I'm actually looking at the schedule that we provide in any quarter. We do show cash cost versus non-cash cost, so actually looking at that -- at that level that is there. I think your larger question, though, was is the 330, give or take, a run rate?

Yes.

I would say it's a little higher because of the outage costs that we have had, as we've mentioned already.

I think as we mentioned, Dominique, there were outage costs associated with unit 7, unit 4, and then you had the transformer fire related to unit 6, so outage costs were probably a little higher in Q2 than they were in Q1, and then we've kind of highlighted what they were on a quarter -- Q2 over Q2 basis.

That's great. Thanks a lot.

Thank you.

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

Hal and Russ, this is more for you, I think. U.S. energy bill is about to be signed by George Bush, Junior, after five years. I'm wondering if you can give some general color as to how many doors open with respect to both your power and pipeline businesses from that signing?

Sam, it's Hal here. I think the energy bill -- the most significant thing in it for us is it that it does give FERC some additional power, if you will, or capability to move important infrastructure projects forward, and we think that could be most beneficial to us on some of these LNG projects. The current situation in the northeast U.S. on the power side, with very hot weather and high market prices, is serving to underscore the story we have been telling, that the U.S. needs more flexible gas supply into market regions like New York City. There are some features of the energy bill that will help expedite projects like some of our LNG things and the construction of new pipeline capacity into important markets in the U.S..

On the gas transmission side, the biggest bottlenecks in the U.S. today are closer to the burner tip. The long haul pipelines generally have spare capacity and in the producing regions, the Gulf Coast, it's relatively straightforward to get new pipe built and on stream. So we're hopeful that some of the features of the bill will help to -- to get us there.

PUCA could be -- the repeal of that could be significant. We're not sure of that. We don't know how that will work and we don't know whether it will make it easier or more difficult for us to achieve some of our objectives. But on balance I think we think that's a positive thing.

I'll say though, Sam, that there's a lot of other issue in that energy bill, everything from ethanol to different clean air related things, that we've got to spend quite a bit of time studying. Through my work as the chair of INGA [ph], I was reasonably close to a lot of the early work that went on in this, but there are inevitably a lot of trade-offs that occur in the final days of reaching a deal. Some of those I don't fully understand, at this point.

Hal, that's a great answer. If I could try one last kick at the can on the New Brunswick proposal versus your Bruce proposal; is there anything fundamentally different between those two proposals? How they went in, obviously, you'd want to make sure you know how you share cost overrun, risk, and managing cost for some timing. Fundamentally they would be the same type of offer, wouldn't it?

Yes, there's a few unique things at Point Lepreau. First of all, it's a single-reaction operation versus a potentially 8 reactor operation at Bruce. And one of the things we felt we were bringing to the table was the ability to incorporate a single-unit operation and make it part of a nine-unit operation, which obviously has benefits from an engineering and administrative support perspective. So we, perhaps, felt that those benefits were greater than the government of New Brunswick did.

The other thing is anytime you are starting up another construction site in complex technical work like this, it brings additional risk, and we wanted to make sure we were covered for that. So we think it's a more controllable environment, and one in which we can achieve greater success, operating within the 8-unit Bruce site and we think the Bruce team is particularly well equipped to operate on their own site. They have got a lot of experience there.

So I would say we're relatively more comfortable and -- and just more keen to proceed with projects on the Bruce site than we would be at -- at some off-site, like Lepreau.

I think another thing I would just add to what Hal said is that the major difference between the two is in New Brunswick there was two options with respect to the start of the nuclear reactor. [Inaudible]. At Bruce there is only one option, so to the extent that the government believes that nuclear power should be a part of their energy mix going forward and they want the 1-2 power as part of that mix, there's only one option for them to take as opposed to the New Brunswick case, where they had two options to pick from to restart that nuclear reactor.

I may beg to differ a little, because Pickering is just starting up No. 1 and they've got No. 2 and 3 hanging over you, I guess, indirectly.

Oh, I agree -- [inaudible] our units 1 and 2 on our site.

That's the only option of your site of course.

Sam, I would just add one more thing here, in that we think this decision to go ahead at Lepreau is a positive one. AECL has got some challenges, and the CANDU technology, a good technology, needs a bit of a kick start right now, and we think that AECL undertaking this work at Lepreau is certainly a whole lot better than the alternative of seeing Lepreau shut down. So we're very supportive from that perspective.

Thanks for your thoughts.

Thank you. The next question is from Bob Hastings, Canaccord Capital. Please go ahead.

Yes, if I could maybe get a couple of clarifications. At Point Lepreau, I believe you are expensing everything so there's no charge coming in in the third quarter of any magnitude.

No.

And the corporate tax refunds referred to and positive tax adjustments in the second quarter, can you give us a little bit -- can you tell us the exact numbers for that?

The total, Bob, was probably somewhere around 5 or $6 million and it was pieces here and there, 1s and $2 million making up that number. There was nothing really big in there.

Okay, so that's all in the second quarter? Not the half, but the second quarter, the 5 or 6 million?

That was just in the second quarter.

All right. And was there anything in the second quarter last year?

There was, but it was a much smaller number.

Okay. And one last clarification on Bruce in terms of the 83% that you referred to as expected utilization rate. Is that the average for the year or is that at 83% for the remainder of the year?

That's the average for the whole year.

That's the average for the whole year, Bob.

I thought that would have been the case. But -- okay. That was it, thank you.

Thanks, Bob.

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

Thank you very much. Hal, I'm wondering, with respect to the McKenzie Valley pipeline, we have seen a couple of really positive moves. What would it take at this point in time for the co-ventures to proceed with the technical work on the project?

Maureen, the -- the number one challenge I think we face is nailing down benefit and access agreements. In other words, agreements that give us right-of-way to build the pipeline. And I think the co-ventures are at the point where we need firm binding agreements that give us clear rights to proceed. It's not going to be satisfactory to just have discussions underway or to be making progress. These things actually have to be put in place. We're at the point in the project where letting those discussions continue on forever is -- you know, we have hit a stall here. And that was the reason a few months ago that we made the announcement that we were downing tools on the technical work and that we would not be resuming that until the benefit and access issue was resolved.

So we think that the efforts by the federal government have been very positive, and we appreciate the willingness to work hard on this issue that's been demonstrated by the northern aboriginal groups, we really do appreciate that, and we're hopeful that over the next weeks and months we can get that in place so t hat we can get back to work on the project itself.

You mentioned that the process is stalled, Hal. I mean, is there progress being made on obtaining these firm and binding agreements?

Yes, I -- I'd say there is Maureen, progress being made. The -- the situation 6 months ago was that the various northern groups were demanding certain financial compensation in -- in return for giving their consent to the benefit and access agreements, and as we've said in the press before, we didn't feel that what they were asking for was the responsibility of the project and we went to Ottowa and we asked Ottowa to please get involved in this and Ottowa I think has responded very favorably.

So it's now a question of bringing all these parties together and reaching agreement, firstly through discussion and then transforming it into an executable document that can be signed off in a hard way, and allow us to proceed to the next step.

And so is the time frame, Hal, then, weeks and maybe months? Is that the type of time frame that you think will resolve this issue?

Yes, I think that's -- that's the right way to characterize it, Maureen. And whether it's weeks or months is difficult for me to say. You know, there's a lot of issues here. Fortunately, there are many precedents. There's much precedent for the value of right-of-way for pipeline projects. And we've argued that those precedents are significant and there seems to be increasing acceptance that they are.

And moving on to the regulatory agenda, I'm wondering if you can tell me what your thoughts are for the mainline for 2006 and maybe forward from that. Are you looking at any innovative filings or changes in the regulatory methodology?

I think the most interesting opportunity probably lies within our eastern region, and when I say that, what I really mean, Maureen, is southern Ontario and the St. Laurence region of Quebec. And whether or not we can ultimately migrate to a more market- facing tolling structure in that part of the world, and by market-facing, I mean one that would be similar to what you see in the market regions of the U.S. This under -- under FERC regulation.

This is not something that is going to happen overnight. It will depend on the development of things like what I might call the Ontario/Quebec hub or the St. Laurence hub, similar to what we have already got in place here in Alberta, and greater liquidity. I think that our concerns over stand of asset risk and depreciation rate within southern Ontario and Quebec are not significant. Much -- you know, depreciation and strand of asset issues are primarily focused on the northern Ontario part.

Right.

So we think it's important to keep the prairie section of the main line on the northern Ontario section under a pretty predictable regulatory framework, not a lot of changes from where they are today, but we would look forward to figuring out whether there are commercial arrangements in southern Ontario that could offer some up-side to TransCanada and greater flexibility to our customers. So if I was to try to give you a glimpse of things that we are going to be working on, I'm think -- I'm not predicting we'll implement that but I am indicating that that is a priority that we will be working on.

Okay. Just a couple of more, I suppose, straightforward issues. I guess this is probably a question for Russ. Is there a financial impact from the OSP outage this quarter? I don't know if it's dispatching a lot. Does that have any impact on the bottom line?

I think your characterization is accurate. It's not being dispatched much -- actually, with higher prices, with the one units on here as we speak, but the outage hasn't impacted the financial results materially at all.

Okay. And then I'm just wondering about -- it looks like Cameco has restructured an agreement at Bruce and that will result in somewhat higher costs of uranium for the facility. Is that going to have a material impact on the costs going forward?

I wouldn't say material, but it will have an impact on our costs going forward.

Okay. I think my other questions are pretty much things I can deal with Dave offline on. So thanks very much.

Thanks, Maureen.

The next question from Matthew Akman, CIBC World Markets. Please go ahead.

Thanks. Hal, you talked about the Keystone project, and yesterday I guess Enbridge talked about expanding their system into a similar region. Do you see those projects as competing head-on? Or do you think that you could actually bring on 800,000 barrels a day of new capacity into that region?

I don't -- I don't really see them completing head-on, but they're clearly competitive proposals. They are competing with each other over the longer term. When I say I don't see them competing head-on, much of this is a timing issue. Which project proceeds first and will 800,000 barrels a day of new production come to pass.

Clearly there are more than enough proposals to develop new syncrude-type production in western Canada, whether it's bitumen or synthetic crude to achieve an 800,000 barrel a day increase. I think the total projects that have been put on the table today would exceed that.

But it's an interesting interplay between which projects to the west coast will proceed and what will be the timing and magnitude of expansions to the existing Enbridge and Terasen systems, and are there particular shippers that will see particular value in our Keystone project. I think that's the key point when you are looking at Keystone, does it offer unique attributes that would be of interest to particular parties, and I would point out that parties that are both producers in western Canada and have refining interests or access to refining capacity in Wood River would be more likely to find value in the Keystone project than maybe in some of the other projects.

So all of those things are issues. We fully appreciate that Enbridge has some economically attractive expansibility by incremental expansion of their existing systems, and Terasen has some of that as well. So we know that there are good projects out there, but we do think that Keystone has some unique attributes.

So, an open season process though, you talked about this summer, I guess, and I guess shippers could be facing several open seasons. Isn't one likely outcome that everyone just gets a piece of this and no one maybe gets enough to go forward with the full amount of capacity that's required? And I guess if that happens, what would you see as a next step? Or how do you see this playing out.

I think what you've described is one bad scenario that could unfold, where all shippers contribute just a little bit of production to a whole bunch of different of projects, thereby frustrating all of those projects. Clearly, a project like Keystone has a certain threshold that it needs. We can't throw the pipe in the ground and run it at 25% of capacity, and we'll certainly be very careful not to do that.

So, I would just say, Matthew, it is going to be interesting to see how this plays out and how much value different shippers put on access to different markets and I think one thing to focus on is whether various shippers have some particular source of value creation by going to particular markets. At this time, ours is the best project for moving significant volumes of crude oil in an express line concept right through to the Wood River/ Patoka area, and that's the value proposition that we're focused on.

Okay. If I could just follow up quickly on one area, which is eastern hydro assets, Russ. You talked about selling some of that output on contract. We have seen really high prices out there. Can you give us any more details on how much is contracted for what terms, or whether you are going to see more spot-type pricing in the coming quarter. And forward.

I think what you will see is -- you can see that our eastern portfolio in our quarterly report, how much of our sales are contracted. I would expect that that portfolio is going to stay pretty much the same as it is. So over the long run we have exposure to the trend upward or downward in spot market prices, but at any given point in time, we don't have a lot exposed to the monthly or prompt spot market. You can see the amounts in there that we have exposed and I would say that that would probably continue.

Okay. Thanks.

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

Thank you. Just a few questions and then I'm come back to [inaudible]. Did Bruce have to borrow to fund both the June and and July distributions?

No. Bruce has a $150 million operating line that it operates its business with. That's to meet sort of working capital needs, and any -- you know, any potential requirements that it has between what I would call cash calls and cash distributions, but at this point in time, none of that operating line has been used for funding of distributions.

When Caneco has got some disclosure in their release relating to the capital structure of Bruce Power, and it looks like there's a bunch of debt. Is that your debt, or -- what is that?

There's a $225 million loan from the partners --

Yes.

-- to Bruce Power. That -- its only debt with the exception of what I call the operating line, which probably runs somewhere between 0 and $75 million at any given point in time.

Okay. The numbers that they have are significantly higher than that, so I'm going follow up with you offline.

Just -- I'm just looking over at Lee, if he's got anything for you on that.

Karen, the only thing I can think of is there a capital lease that for accounting purposes is accounted for as a capital lease, that shows up in debt. That would be my only item, and it is fairly [inaudible].

Right. I just want to make sure that's what it is, but I'll give you a call back.

It is definitely the sizable portion of what you would call debt.

I'm not calling it debt. They are and they don't explain it in notes. So I just want to make sure I know what I'm looking at.

All right. We'll [inaudible] offline.

Okay. You had mentioned for Bob that the income tax refunds in Q2 are 5 to 6 million, but you also said there was an offset in Q1, '05. Can you tell me how big that was?

In Q1 '05 it was probably about the same amount. Q2 '04 was a very small number.

Okay. Just -- I'm worried about whether or not there's -- so, for Q1 '05 there was a negative tax adjustment of 5 to 6 million?

No. They were both positive.

They were both positive. And how big was it in '05? Q1?

Q1 '05, again, same kind of number.

And will these be recurring in the last half of the year?

We're -- at this point things like refunds and adjustments, Karen, we can't forecast that they would be coming in -- so -- they will come when they come.

So we have had -- sorry -- between 10 and 12 million pre-tax or after tax?

Well, it's taxed so --

After tax? Of one-time adjustments and refunds in the first half of this year.

Approximately.

Approximately, yes.

Okay. The -- is it fair to assume that we've greatly curtailed in the western power division the spot sales such that when I look forward -- and you talk about 5100 of gigawatt hours being sold, it's safe for me to assume that I'm going to get the same sort of spot fixed contract mix like I've had in the first half of this year?

Yes.

And I know I always ask the question and I never get an answer but maybe one time I'll get lucky and you'll answer it. Can you please tell me the term of your forward sales contracts and the average price so we can determine how exposed to the trend we are rather than the spot or prompt market.

No, I think that's competitive information which we wouldn't want to share, you know, commercially sensitive. That kind of information, as we've said before.

Okay. And I guess just a last question relating to the USGen assets and the Irving facility, the 17 million of operating income is pre-tax?

Can you say that again?

The two facilities in the eastern power that increased performance by 17 million: is that pre-tax?

That is pre-tax, yes.

So what portion of it, broadly, arises from the USGen and is that a reasonable run rate, given that Q2 is typically spring run-off and probably is slightly higher than what you would get in Q1 and Q3.

I would say, Karen, that Q2 historically has had a much higher water flow, Q3.

Yes.

So I would say, no, I clearly wouldn't expect this to be a run rate. It will go with the water flows in the USGen asset. The summer months are historically much lower than the spring months.

I --

I'm sorry?

40% of production is in --

35 to 40% historically is in second quarter and more like 15 %, maybe 20 percent in third quarter. So, significantly lower.

Those are based on --

That's fine. I'm just looking for history and pattern so I know what the run rate is.

But sort of looking at it on about a 10-year average, Karen.

That's fine. Can you just give me an indication strategically, how we're going to address ever-weakening performance in the western power segment?

I guess we'd -- one is to await further rebalancing of supply and demand in the western power segment, that's the big picture -- you know, we have had some significant additions to capacity, and some dysfunction in the market that has led to prices and spark spreads being lower than we would have thought.

Uh-huh.

But you know, people aren't building.

Well we have heard from others who have been responsible for constructing new coal-fired generation that would continue to build this stuff without the benefit of capacity contracts or other types of long term sales arrangements, so the surplus as it exists in Alberta that's currently trapped, based on the transmission studies we have seen, the willingness to build new coal-generation; can you just describe for me when you expect this captive market to begin to be dissipated? I know that you have subscribed for capacity on the Alberta Montana line. Is that thing actually going to get constructed in line with the in-service state's we've seen? Or is this something we're just sort of crossing our fingers for?

First of all, Karen, we can't give you much in the way of predictions on a quarter to quarter or even a year to year basis, but clearly we have laid out the strategy to other interests in Alberta and particularly to the Alberta government that Alberta should aspire to be an electricity exporter in the same way that it's a gas and power exporter.

Uh-huh.

And that whole fundamental approach to the market gets a pretty good hearing in Edmonton and the government likes that. And one of the reasons why being a significant power exporter is a good idea is that it gives you a very robust reserve margin.

Uh-huh.

When -- when things get tight within Alberta you can just fall back on exports.

So that's our view of the longer term. We've proposed projects like Northern Lights, which would very significantly connect the Alberta power supply and demand market to the US western region markets.

Uh-huh.

And we think the long term future in this area is north/south. We find it a bit difficult to contemplate some of these grandiose east/west Canadian projects. We think proper integration will occur more in a north/south way.

And can I just ask one other quick question on Bruce. How much of a factor is the timing in terms of the government's assessment with the fact that its own fuel mix and the anticipated role of nuclear power past 2020 is certainly and currently up for discussion as part of the Ontario Power Authority's fuel supply mix exercise, that it has to determine and report to the government by year-end 2005. Is that determination by the OPA and the fact that the government does not yet have a policy statement regarding the role of nuclear power in this market post 2020 in any way a factor in taking -- in delaying or making take longer this Bruce process?

Well, you know, we're always interested in the periodic pronouncements from government on the long term.

Uh-huh.

But, you know, Karen I think that from our perspective it's pretty clear that nuclear is going to be a significant part of the Ontario power supply mix, long term. We think that will probably increase rather than decrease.

Uh-huh.

And we would be guided more by our fundamental outlook on these things than by any particular policy statement from time to time. Because they do change. So I would say no, that's not a big factor in what we're wrestling with right now.

Okay. Thanks.

Thank you.

Thank you. The next question is from Winfried Fruehauf, National Bank Financial. Please go ahead.

Thank you. Karen asked about the contribution of USGen in the second quarter. I'm not sure if that number was a pre or a post tax number. So I'll just ask you. What was the post tax contribution of USGen to the second quarter eastern operations income?

We don't -- don't break out sort of specific facility contributions, if you will, in the eastern portfolio. We do sell -- the supply is a portfolio and the market is a portfolio. What I can tell you is that the -- the contribution from USGen was a good chunk of it. I think if you took the volume, I think you can figure out the volume that we have generated at USGen and multiply it by what you think the average spot price, would give you a proxy of what the contribution is. But we don't actually break it out.

Okay. What is the status of your Broadwater LNG project?

Two things need to be finalized, Win. One is the whole commercial arrangement between us and Shell regarding the processing of LNG through that facility. And that's moving along well, and we'll nail that down soon I think.

The second is the application to FERC for a permit to construct. What we have found is that most of the state regulatory processes and local processes rely on FERC filings and FERC information before they can be processed. We wish there was an easier way to do it. We wish the fundamental questions of whether or not the facility is acceptable to the local community could be addressed in a more straightforward way, and we wish we didn't have to spend 10s of millions of dollars on FERC filings in order to address other questions. It's a very similar situation to what we're going through in the McKenzie Valley, where the regulatory process does not always work in a cost effective way.

But, so be it. That's what it is and that's the state we're at. We have prepared most of the FERC filing materials and we look forward to proceeding with that in the next 6 months.

Is there anything in the recent weeks or months that might have improved, perhaps, the outlook for an approval for that facility?

One of the topics that we emphasize as we speak to local interests in the state of New York and the city of New York and on Long Island is how this sort of an LNG facility would significantly dampen the volatility of gas prices in New York. As you would recognize, New York is at the end of a long pipeline system with my constraints and more constraints as you get closer to New York City. So to the extent you can bring gas in -- right into the heart of the market rather than bringing it into the Gulf coast and flowing up that long pipe system, you will reduce the volatility of gas prices in the New York market, and there's all kinds of market data that supports that contention.

So this is a key theme, Win, of what we're emphasizing to people right now, and I think the current tight situation on the power gen side just serves to underscore why more gas delivered right into the heart of the market and more gas-fired power gen would result in significant economic benefits for the people of that region.

With respect to Keystone, what are the implications to Keystone's prospects of proceeding, if no new pipeline capacity were constructed to the west coast or if the proposed capacity is constructed?

Well I think clearly if -- if there are several hundred thousand barrels a day delivered out of the Alberta supply basin to markets on the west coast, that would diminish the attractiveness of Keystone. Clearly, the more crude oil is backed up within Alberta, the more motivated people are going to be to underpin projects like Keystone.

So even though I -- I don't believe projects like Enbridge's Gateway project, if it was to proceed it wouldn't necessarily preclude Keystone, but obviously if several hundred thousand barrels a day are heading west, then that reduces the need for a project like Keystone.

Okay. And the support -- shipper [ph]support that has been mentioned: does that shipper support come from producers and refiners?

Yes, from both.

Approximately what percentage, in terms of numbers of companies supporting Keystone?

I think we'll be able to give you a better insight into that after a successful open season. At this point these are negotiating items, and I -- I don't think our potential customers would want us to disclose that.

Okay. I have two more cleanup questions. One is, with respect to the NAB decision on capital structure, the $8 million of increase in net income for the first half of this year, how does it break down between the second and first quarters?

It would -- it would be flat. We essentially would take that straight through, win for the year. So it's essentially half and half.

Okay. And the tax refunds that have been mentioned, do any of them pertain to a period other than the second quarter 2005, and if so, what is that period? Or portion.

Win, they would have related to periods prior to 2005. It just happens that we received the refunds in 2005 and we only record these amounts as income when we know we have the cash on hand. So clearly, the refund occurred in the second quarter. They would have related to multiple prior periods.

And do they relate to gas transmission and electricity or only one of them?

I'd say probably related to both.

Probably related to both. I'm just thinking back. Again, there were multiple -- I would say probably related to both. Clearly they -- they are items which come in by -- by legal entity which sort of crosses boundaries between gas transmission and power sometimes. So I would say it's both.

Okay. Thanks. And the last one is the contribution to income of North Baja pipeline in the second quarter -- in the first quarter.

North Baja, of the 16 it's going to be a very small number. I don't have it right in front of me. But it would be -- it would be very low single digits, I would think.

May I talk to David about it?

You may, yes. I just don't have that one in front of me, Win, sorry.

Thanks very much.

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

Thank you, good morning. Hal, I was wondering if you could give us a bit of a clarification of your strategy. There's the recent foray into Mexico, and when you first joined several years, first if was really a focus on the northern tier, the northern tier really expanded out into North America when you did ManChief, GTN, among other things. So if you could just give us a bit of clarification as to the direction the Company is headed and what the Company will look like or potentially look like 5 years from now.

Sure. If I go back to the year 2000 when we really made some very significant moves to redirect the Company's asset portfolio, the real commitment that we made at the time was that we were going to be a North American focused company and that we were going to pull back from Tanzania and Indonesia and Argentina and a lot of other places around the world. We have done that and as we went through the divestment program in the year 2000 one set of assets that gave us some heartburn were the Mexican ones, because on the one hand we had been very successful at establishing our presence in Mexico and bringing a couple of projects in on time and, in the case of Mayacan, under budget. It had been a very successful experience.

So what -- in the debate that occurred in the year 2000, we said, you know, under what conditions should we keep the Mexican assets, and under what conditions should we sell them, and we decided that since our other international divestments had gone quite well at that point that we would require a really good financial outcome before we would decide to sell the Mexican assets.

And Andrew, that's exactly what came to pass. We ran into a few highly motivated buyers for the Mexican assets, and at the end we we are able to conclude a deal to sell those to Gaz de France, which resulted in a really good financial outcome for TransCanada. So it was kind of with regret that we pulled back from Mexico at that time, and I guess there have been some developments in the last couple of years that have made us think that we wish we hadn't sold those, even though we did get a very good price for them.

There's a couple of things going on in Mexico. One is that the demand for power gen and the growth in power gen capacity in Mexico is really significant. If you look at electric power consumption per capita in Mexico, it's really quite small compared to North America. I wish I had the precise numbers, but you can -- you can see it in the statistics.

And so we see significant growth in power generation in Mexico over the next 10 years. And when you look around at to options that are available to them, like much of North America, natural gas is the only source of power generation that can be brought on stream in a reasonable period of time.

Now, Mexico, enjoys some advantages that for example a place like Chicago would not, in that it's close to tide water on both sides of Mexico and the importation of LNG into Mexico is a fairly attractive proposition. And it's interesting, the Thomason Charley pipeline that we are building will in large part be used to move LNG from the Shell Alta Mira facility into the power gen markets closer to Mexico City. So we think that's a fundamentally attractive pipeline, long term. But it's just a toe in the water for us in Mexico.

We're also focused on the opportunity to import LNG into the west coast of Mexico, and we're not talking about Ensenada or somewhere on the Baja peninsula. We think that global LNG coming into the west coast of Mexico, probably further south and flowing directly to large clusters of power plants, which is the way CFE, the Mexican electric utility likes to do it, makes a lot of sense. And the opportunities for us there would be both in the construction and ownership of the LNG facility and in some cases more importantly the building of the pipelines that connect those facilities into the load centers within Mexico.

So we see significant long term upside. I have no projects like that to announce for you today, but we have a very good team of people working on this and we're coming at it from both the LNG and the pipeline perspectives and obviously, there could be a scenario where Mexico would offer power generation opportunities for TransCanada, as well.

So that's the background to this relatively modest investment that we have now announced.

So I appreciate what you went through with the December plan five years ago, but if we look at your efforts in Mexico at this point in time, you're really looking primarily at pipeline assets at this stage, potentially into re-gas [ph] and then, if possible, maybe into power gen.

I think that's a good characterization.

Okay. That's great. Thanks very much.

Thanks, Andrew.

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

Good afternoon, guys. I realize it's late, but Hal, I was wondering if you could just give us a brief update on your Alaska gas effort. Is there anything new to add there on timing or your view of probability [ph] milestones, et cetera.

Andrew, as I have been saying over the last 6 to 12 months, the really critical step in the process is the negotiation between the North Slope producers and the state of Alaska, over a whole variety of royalty and other fiscal issues. Every producer will of course want greater certainty as to what those burdens are going to be in the future, and there are a number of other complex issues.

Now, what we're talking about is gas that is produced in conjunction with oil and currently reinjected in the ground and as that gas gets processed through existing facilities and delivered down a new gas pipeline, there's a whole host of complicated physical issues that need to be worked out between the state of Alaska and the producers. And we have done everything we can to support those discussions between those two parties. We continue to talk to the state of Alaska. We continue to provide advice and assistance to them on matters related to the pipeline. We continue to talk to the three Alaska producers and propose concepts to them and other things that we think might be helpful to this overall project. But I just emphasize again that until the really significant issues around fiscal terms at the wellhead can be resolved between producers and the state, there's not much point speculating about when a pipeline will be built.

I can tell you -- and this is common knowledge, that the producers in the state are engaged in very active discussions. There's a lot of effort going into it on both sides and we obviously wish them well in those discussions and once that phase is concluded, we would look forward to engaging more directly with the state and the producers to highlight for them the very significant value that our existing infrastructure can add to their overall project.

We think an extension of TransCanada's existing system to the Alaska Yukon border makes a lot of sense. We think this is gas that can be integrated into our existing systems to the benefit of both western Canada shippers and Alaska shippers and we think that some sharing of the benefit -- of the economic benefit of that integration makes sense. Now, working that all out is not something we can achieve overnight, but our current emphasis is to really make sure the Alaska producers and the state of Alaska, which is a very large economic stakeholder, that they do understand and appreciate the benefits that we can bring to this project.

I would point out that there's one other area that is really quite significant and that's our technical and project management expertise in all of this and it's easy for people to blow their own horn on these issues, I appreciate that, but the only pipeline project that is of a larger scale than the proposed Alaska project in the history of North America was the expansion of our system in the 1990s. And the advances across the technical front, whether it be high-strength steel pipe of welding technology or construction techniques, and the environmental factors and a whole lot of operational issues, we think we have some very hands-on experience that is valuable to a project of this size. So we, of course, look forward to making sure they understand that as well.

Absolutely. Great. Thanks, Hal.

Thank you.

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

Thanks. Quick question on our LNG initiatives. You mention in your second quarter report that to date you have capitalized 8 million of cost related to Broadwater. Can you give us a similar number for growth, Cacouna, or are you just expensing everything here?

We're just expensing those as we go right now, Linda. They are not particularly significant.

Okay. And what portion of the 8 million was in 2005 versus 2004?

I believe it was all in 2005.

I can double check that. I think the majority. I know it was 3 million at March so there was about 5 million in the quarter so I would expect the vast majority was this year.

We'll check on it, Linda, but I think it was 2005.

So -- should we expect that sort of run rate to continue until you activity enter into the construction phase, or is that -- is there now a higher level of -- I would imagine it would increase, perhaps.

Well, Linda, there will be a relatively hi period here of expenditures as we complete the drawings and designs and other things that are required for the FERC application. Then I think you could see a flow down in expending while that application is processed and then of course if we receive approvals and actually get into the physical project, obviously then it would ramp up again.

So rough ballpark order of magnitude numbers, is it fair to say that the cost prior to approval could be in the range of 20 to $30 million for an LNG project of this sort?

I don't think that's unreasonable. To be honest I don't have accurate numbers at my fingertips, and if I did I'd have to think twice about giving them out, for competitive reasons. But you are clearly in any ballpark there, Linda.

That's great. Thank you.

Thank you. [OPERATOR INSTRUCTIONS] The next question is from Maureen Howe, RBC Capital Markets. Please go ahead.

It's a follow-up question on GTN that I have, and I know a couple of other people have asked similar questions, but I'm just wondering, in terms of the second quarter results you mentioned that there was about 2 million due to the overhaul of the compressor and a million in lower revenues. Would the lower revenues, is that a seasonal issue or is there something else happening on the revenue side?

I don't think there's anything else happening specifically, Maureen, on that side that I would say, going forward. It is somewhat volatile and it flows through to the bottom line. A million or two here and there will move in the quarters.

Market differentials.

Okay. And I'm just also wondering if -- in the second quarter, the fees associated with refinancing, the $400 million debt, if they were significant at all?

At the consolidated level we wouldn't have included those --

Okay.

-- Maureen, they would have been taken into account when we did the acquisition.

Okay. And so again, you know, quite a drop. I guess the $3 million -- those are pre-tax numbers, is that right? I'm sorry, 2 million from the compressor and 1 million in revenue.

After tax. Those are after tax.

Oh, those are after tax?

Yes.

Okay. That's great. Thanks.

Thank you Maureen.

Thank you. The next question is from Winfried Fruehauf, National Bank Financial. Please go ahead.

Thank you. With respect to Bruce Power, what is the total cash investment from the inception in late 2003 or so, to June 2005, disregarding the distributions you just received.

Sorry, Winfried. Cash put into Power?

Yes.

I'm sorry, nothing has been put into Bruce Power since our initial investment. So the only movement of cash since day one would have been these recent distributions received from them.

Okay. So in other words, cash flow has enabled you to finance any incremental cash contributions that were required since you first made the initial investment.

They have all been self financing within Bruce power.

Thanks very much.

Thank you.

Thank you. This concludes the financial analyst question session. We will now take questions from the media. [OPERATOR INSTRUCTIONS] The first question is from James Stevenson, Canadian Press. Please go ahead.

Hi, guys. I know it's dragging on, so I'll be quick. I just have a few clarifications on the Keystone again. First of all, if you could give me, Hal, some idea on the timing that you are hoping to proceed with this project. Second of all, what sort of threshold you'll need to go forward? And second of all, some more detail on these binding open season agreements that you are going to try and sign this fall.

So James, on timing, as -- as I have said before, this is a project that we've been fleshing out, if you will, over the past two and a half years. This is not something new that came up in the last 6 months, and obviously market supply and demand forces are going to be a big part of when we actually proceed.

We decided 6 months or so ago that it was appropriate to start communicating more openly about the Keystone project and get the concepts out there, and start discussing options with people.

Some of the options were related to rooting. The diameter of the extension from Winnipeg down through the US. The amount of horsepower versus pipe that was put into the project. Whether it would move exclusively heavy oil or perhaps exclusively synthetic crude or batches of them and whether there would be any breakout storage, or would it be a tight line right through to the end of the system.

I mention all of those topics just to give you an indication of the things we continue to discuss with shippers other than just the toll structure and the term of commitment.

We -- there's two parts to this project for TransCanada. One is the investment in the crude oil pipeline, which we expect would move somewhere between 300,000 and 590,000 barrels a day, it's in that range, depending on the amount of horsepower and the diameter, and secondly, the appropriate reuse of a piece of the Canadian main line gas system that runs from Empress on the Alberta boarder over to Winnipeg, and that's a pipe that we no longer think is needed for gas transmission service. But there are people in the gas business in western Canada who would like that pipe to remain there just because it does give some flexibility and optionality, so that discussion has to unfold.

We're planning to go out in the -- in the open season here within the next 4 weeks, and that's the schedule right now. Some things could delay that. And then depending on the response we get back in the open season, we will decide to go the next step. One of the key issues is going to be either resolving the reuse of the gas pipeline with our gas shippers in advance of a hearing or having some discussion of those issues in a hearing.

So we're not encouraging people to start forecasting any net income or other things from the Keystone project. This is a long-term undertaking. It's quite common in the world of TransCanada that we work on these things that come to fruition five or more years later.

You mentioned earlier about the timing aspect and obviously yesterday Enbridge said they are aiming for early '09. Then, are we to infer that there's no way that Keystone could make -- could sort of get before that?

Well we -- we don't know and trying to debate whether we can be earlier in '09 than they can be isn't productive, I don't think, at this point. I think the key thing is that the producers and the refiners will underpin the projects that create the most value for them. And we believe Keystone is a very good value proposition and if the market supports that, we'll build it, and if the market doesn't support it, we won't.

And I wasn't quite sure on your earlier answer regarding west coast pipelines. Were you saying that if one does in fact finally go ahead that that's going to negatively affect adding more sort of lines in the sort of Keystone east direction?

Yes, we don't think it serves the producing sectors' best interest to overbuild a lot of pipe that people are paying unnecessarily high tolls on and we're not about to build large pipeline projects like this on spec and just hope that the oil shows up, so that if more oil is committed to a pipeline to Prince Rupert or a Terrison [ph] expansion to Vancouver, that obviously reduces the amount of oil that's available for new pipes the the Midwest U.S. and that will of course effect the prospects for Keystone.

But I would underscore that the forecasts that exist today, the reasonable forecasts that are out there, are for such significant increases in Fort McMurray and Cold Lake oil production, that we think there's a good chance for a number of these projects to go ahead.

It's just a matter of timing?

Yes. Yes.

Okay. Thanks, Hal.

Thanks, James.

Thank you. The next question is from John Harding, National Post. Please go ahead.

Just one quick question about Keystone. Have you ever mentioned a cost -- potential cost of that project?

I -- we certainly have in discussions with potential shippers.

Yes, we have and I think it was included even in our original news release, I believe it was in the range of U.S. 1.7 to 1.8 billion.

Okay. Thanks.

Thank you. Once again, please press star 1 if you have a question. There are no further questions registered. I would like to turn the meeting back over to Mr. Moneta.

Thanks very much and just in closing, again, I would like to thank you for taking the time this morning and being with us here to discuss our second quarter results and issues. We look forward to talking to you again soon. Bye for now.

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