TC Energy Corp (TRP) 2004 Q3 法說會逐字稿

Good afternoon, ladies and gentlemen. Welcome to the TransCanada corporation 2004 third quarter results conference call. I would now like to turn the meeting over to Mr. David Moneta, Director of Investor Relations. Please go ahead Mr. David Moneta.

Thanks very much. Good afternoon, everyone. And I would like to take this opportunity to welcome you this afternoon, including those of you who are participating via the Internet. We're pleased to be speaking to you from Quebec City today. And we're also pleased to be able to provide the investment community, the media and other interested parties with an opportunity to discuss our 2004 third 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 afternoon with some comments on our third quarter results and other general issues pertaining to TransCanada. Following their opening remarks, we will turn the call over to the conference coordinator for questions.

During the question-and-answer period, we will accept questions from the investment community first, followed by questions from the media. Before Hal begins, I would like to remind you that certain information in this presentation is forward-looking, and is subject to important risks and uncertainties. The results or events predicted in this information may differ from actual results or events.

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

For additional information on these an 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 afternoon, everyone and thank you once again for joining us. As the challenge of meeting North America's demand for energy draws increasing attention, TransCanada took steps in the third quarter to strengthen its position as a key natural gas transporter and power generator. As detailed in our report to shareholders, TransCanada Corporation's net income in the third quarter of 2004 was $245 million, or 51 cents per share. Compared to net income of $248 million, or once again 51 cents per share, in the third quarter of 2003.

These results include net income from discontinued operations of $52 million, or 11 cents per share in the third quarter. Compared to $50 million or 10 cents per share in the same period last year. These amounts relate to the recognition of the deferred gain of $102 million associated with the disposition of TransCanada's gas marketing business in 2001.

In addition, today, TransCanada's board of directors declared a quarterly dividend of 29 cents per share for the quarter ended December 31, 2004, on all outstanding common shares. This is the 164th consecutive quarterly dividend paid by TransCanada and its subsidiary on the common shares.

I will briefly review some key events and then I will turn the call over to Russ Girling for a more detailed review of our financial results. Although most of TransCanada's strong asset-based businesses continue to perform as expected in the third quarter. Two recent regulatory decisions were disappointing, and have presented us with some challenges.

First, in the gas transmission business, the recent Alberta Energy and Utilities Board decision on phase 1 of our 2004 general rate application, disallowed approximately $24 million pre-tax of operating costs associated with the operation of our Alberta system. As a result, adjustments were made to third quarter 2004 earnings to reflect the full year-to-date impact of this decision.

TransCanada believes that these are necessary costs that it will reasonably and prudently incur for the safe, reliable and efficient operation of the Alberta system. As a result, in September, TransCanada filed with the Alberta Court of Appeal for leave to appeal the EUB's decision on the basis that the EUB made errors of law in deciding to deny the inclusion of these costs in our revenue requirement.

Subsequently at the request of TransCanada, the Alberta court of appeal adjourned that appeal from an indefinite period of time while TransCanada considers the merits of a review and variance application to the Energy and Utilities Board in respect of those 2004 costs and works towards a negotiated settlement of future years costs and tolls with our customers. On the power side of our business, at the end end of August, Ocean State Power, which is a key component of our eastern power operations, concluded its latest arbitration process with respect to its cost of fuel gas.

As in previous decisions received in 2002 and 2003, the decision substantially increased Ocean State Power's cost of gas. This most recent OSP arbitration decision, effective September 1, 2004, has established a pricing mechanism for gas that results in a gas cost in excess of the current market price in that marketplace. As a result, it impedes Ocean State Power's ability to economically and competitively produce power.

We are currently assessing the long-term impacts of this negative decision and assessing our related courses of action. Ocean State Power has also commenced a process for the next arbitration which is expected to be completed in mid 2005.

Our power operations in northeastern United States are a key component of our power business. Despite the adverse OSP decision, we remain committed to build a strong portfolio of assets in the northeastern United States, and in eastern Canada. As an example of that commitment, during the third quarter, TransCanada signed an agreement to acquire hydroelectric assets with a total generating capacity of 567 megawatts from USGen New England Inc. for $505 million U.S.

These are low cost base load facilities that would fit very well with our existing portfolio in New England. The deal requires bankruptcy court approval and certain regulatory approvals. Under the court-sanctioned process, USGen is required to seek other higher offers but TransCanada retains the right to amend its offer if that should happen.

Also during the third and fourth quarters, we have been very active in the province of Quebec. Earlier this month, Hydro-Quebec Distribution awarded six projects for a total of 739 megawatts to Cartier Wind Energy which is 50 percent owned by TransCanada. The investment in Cartier Wind Energy is a strong fit with TransCanada strategy. It allows us to diversify our fuel source and the power will be 100 percent contracted to Hydro-Quebec Distribution for 20 years once the power purchase agreements are finalized.

We expect that these wind farm facilities will be placed in service between 2006 and 2012 at an estimated capital cost of $1.2 billion. TransCanada is also constructing a 550 megawatt natural gas-fired co-generation plant in Becancour, Quebec, and a 90 megawatt natural gas co-generation power plant in St. John, New Brunswick. Both of these projects are backed by long-term power purchase agreements with very strong counter parties.

On the gas transmission side, we have signed a memorandum of understanding with Petro-Canada to develop a liquified natural gas facility called Cacouna Energy in Gros Cacouna, Quebec. We recognize the vital role local communities play in these projects and we have started to hold meetings with community members in the Gros Cacouna area.

The Cacouna Energy project, if approved, would be capable of receiving, storing, and regasifying imported LNG with an average annual send-off capacity of approximately 500 million cubic feet per day of natural gas. If the necessary approvals are received, we anticipate that the project will be completed by the end of this decade.

Moving now to the western side of the continent, TransCanada has satisfied all its pre-closing conditions for acquiring Gas Transmission Northwest Corporation from National Energy & Gas Transmission. We are awaiting implementation of that company's Chapter 11 plan of reorganization. That is the only remaining material closing condition in our transaction to acquire Gas Transmission Northwest. National Energy and Gas Transmission anticipates the plan of reorganization will become effective in the fourth quarter of this year. And we plan to close the GTN transaction very shortly thereafter.

Also in the west, the Simmons pipeline officially became part of our Alberta system on October 1. This asset, which we purchased for approximately $22 million, includes 380 kilometers of pipeline and metering facilities and 4 compressor units located in northern Alberta. The system is capable of delivering approximately 185 million cubic feet a day of natural gas to the Fort McMurray area from several connecting receipt points within the Alberta system, along with production that is connected directly to the Simmons pipeline. The Simmons pipeline will help us meet increased demand for natural gas in the Fort McMurray area and will fit very well with our existing Alberta system.

Moving now to northern development, recent U.S. federal legislation has moved the Alaska highway pipeline project another step forward. Among other provisions, the recent legislation confirmed that certificates granted to TransCanada under the Alaska Natural Gas Transportation Act are viable and valid.

We continue to work with the state of Alaska on our application filed under the Alaska strand of Gas Development Act, and on our application for our right-of-way across state lands for the pipeline project. I would note that we already hold right-of-way across federal lands within the state of Alaska. We anticipate completing the lease for the Alaska state right-of-way in the first quarter of 2005. We are also discussing with the state a commercial structure to help advance the project.

As we have indicated many times, we are prepared either to build the pipeline within the state of Alaska or to convey our right-of-way leases and other entitlements to a party that has successfully commercialized the project within Alaska. Subject only to the Alaska portion, interconnecting with TransCanada, at the Alaska Yukon border. Once those commercial agreements are in place, TransCanada will be ready to construct the Canadian portion using our existing rights and entitlements which we hold under Canada's Northern Pipeline Act.

Moving now to the Mackenzie. Imperial Oil announced earlier this month the filing of the regulatory applications for the project. This marks a significant milestone in the project definition phase of the pipeline project. Going forward, we will continue to support the project through our position established under the various project agreements and to facilitate the inter-connection of the Mackenzie Gas into our Alberta system.

In summary, while TransCanada faced some challenges in the third quarter, the initiatives I have outlined highlight our focus on adding to our portfolio of high quality energy infrastructure assets. These initiatives will strengthen our near-term financial performance, and set the stage for long-term sustainable growth that will continue to enhance shareholder value. I would now like to turn the call over to Russ Girling who will provide you with additional details on our financial results. Russ?

Thank you, Hal. And good afternoon, everyone. As Hal said, we reported net income for the 3 months ended September 30, 2004, of $245 million, or 51 cents per share, compared to $248 million, or 51 cents per share, for the same period last year. This includes net income from discontinued operations at $52 million or 11 cents per share in the third quarter of 2004, and $50 million or 10 cents per share in the third quarter of 2003. Both are due to the recognition of a previously deferred gain of $102 million related to the disposition of the company's gas marketing business in 2001.

Excluding those items, net income from continuing operations for the third quarter of 2004 was $193 million, or 40 cents per share. Which decreased by $5 million or 1 cent per share compared to the $198 million or 41 cents per share for the third quarter of 2003. The decrease was primarily due to lower net earnings from the gas transmission business, which were partially offset by lower net expenses in the corporate segment.

On a year-to-date basis, net income from continuing operations was $795 million, or $1.64 per share, compared to $608 million, or $1.26 per share for the comparable period in 2003. The increase of $187 million, or 38 cents per share, was due to significantly higher net earnings from our power business. In addition, lower net earnings from the gas transmission business were primarily offset by net expenses -- by lower net expenses in the corporate segment.

The increase in power net earnings of $198 million -- or $189 million are primarily due to the second quarter of 2004 gain of $15 million after tax, or 3 cents per share on the sale of the ManChief and Curtis Palmer assets to the TransCanada Power, LP and the recognition of a $172 million or 36 cent per share -- share of a dilution and other gains resulting from a reduction in TransCanada's ownership interest in the Power, LP, and the removal of the Power LP's obligation to redeem units not owned by TransCanada in 2017.

I will review the third quarter results for each of our segments beginning with the gas transmission business. The gas transmission business generated net earnings of $134 million, for the 3 months ended September 30, 2004. Compared to $160 million for the same period in 2003. The $26 million decline in net earnings was primarily due to a lower contribution from our Canadian wholly-owned pipeline system.

The Alberta pipeline system's net earnings of $31 million in the third quarter of 2004 decreased by $19 million compared to the $50 million in the same period last year. As Hal outlined, the decrease is primarily due to the year-to-date impact of the Alberta Energy and Utilities Board August, 2004 decision on phase 1 of the 2004 general rate application. The EUB decision disallowed approximately $24 million of pre-tax operating costs associated with the operation of the pipeline, and as a result, adjustments were made in the third quarter 2004 to reflect the year-to-date impact of this decision.

Of the $19 million, quarter-over-quarter decline in earnings from the Alberta system, 12 million relates to the costs that were incurred, but are not recoverable, as a result of the EUB decision. Of the $12 million, $8 million relates to the first 6 months of this year.

As Hal mentioned, in September, TransCanada filed with the Alberta court of appeal for leave to appeal the EUB's decision on the basis that the EUB made errors of law in deciding to deny the inclusion of these costs in our revenue requirement. Subsequently, at the request of TransCanada, the court of appeal adjourned the appeal for an indefinite period of time while TransCanada considers the merits of a review and bearings application to the Energy Utilities Board in respect to 2004 costs and works toward a negotiated settlement of future years tolls with its customers. The decrease in the Alberta system's net earnings can also be attributed to a lower return on capital in 2004, compared to earnings implicit in the 2003 negotiated settlement which fixed -- which included a fixed revenue component of $1.277 billion.

Earnings in 2004 reflect a return of $9.6 percent on deemed common equity of 35 percent as approved by the EUB in its generic cost of capital decision released in July of this year. This is less than the applied-for return on equity of 11 percent, on deemed common equity of 40 percent, which the company considers to be a fair return.

Turning to the main line, net earnings of $71 million for the 3 months ended September 30, 2004, were $2 million less than the amount reported for the same period last year. The decrease is primarily due to a lower rate of return on common equity of 9.56 percent in 2004, compared to 9.79 percent in 2003, and a $368 million decline in the average investment base. 2004 net earnings and interim tolls are based on a capital structure that includes a 33 percent deemed common equity component on the main line system.

We have applied for a 40 percent deemed common equity component, which will be considered at a phase 2 -- at the phase 2 of the 2004 hearing scheduled to begin on November 29. The decision is expected by the end of the first quarter of 2005.

And finally, with respect to other gas transmission, TransCanada's share of net earnings from other gas transmission was $24 million for the 3 months ended September 30, 2004. Compared to $32 million for the same period in 2003. The third quarter 2003 results included TransCanada's $11 million share of a future income tax benefit recognized by TransGas. Excluding that adjustment, net earnings for the quarter increased by $3 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 CrossAlta, as a result of favorable storage market conditions, partially offset by higher general and administrative costs.

Next, I will talk about power. In the third quarter of 2004, the power business contributed net earnings of $51 million, compared to $50 million earned in the third quarter of last year. Higher earnings from western operations were offset by lower contributions from Bruce Power and the eastern operations. Total volumes sold in the third quarter of 2004 were 7,792 gigawatt hours, compared to 7,410 gigawatt hours sold in the same period of 2003.

In western operations, operating and other income in the third quarter of 2004 was $43 million. Which was $17 million higher than the same period in 2003. That increase is mainly due to earnings from the newly constructed McKay River cogeneration plant. Fee revenue as a result of the Power LP's third quarter acquisition of hydroelectric facilities in British Columbia and higher net margins achieved on overall net portfolio management of power and gas.

Higher-than-expected quarterly contribution from the McKay River plant arose due to the recognition of revenues that were deferred in the first 6 months of 2004, pending the resolution of certain operational issues. Bruce Power contributed pre-tax equity income of $29 million in the third quarter of 2004. Which is $9 million less than the $38 million reported for the same period last year. Approximately $5 million of the decrease relates to interest, interest capitalized in 2003, related to the restart of Bruce A units 3 and 4.

From an operations perspective, Bruce once again performed very well. TransCanada's share of power output from Bruce Power for the third quarter was 2,765 gigawatt hours compared to 2,041 in the third quarter of 2003. The increase primarily reflects higher output in 2004 as a result of the restart of the Bruce A unit 3 and 4, which have expanded Bruce Power's capacity by approximately 1500 megawatts from the third quarter of 2003.

Overall prices realized in the third quarter of 2004 were approximately $45 per megawatt hour. The same as the third quarter of 2003. Approximately 55 percent of the output was sold into the Ontario wholesale spot market in the third quarter of 2004. With the remainder being sold on our long-term contracts.

Through use (ph) exposure to spot market prices, Bruce Power has entered into fixed price sale contracts for approximately 40 percent of the plant output for the remainder of 2004. On a per unit basis, the Bruce operating costs increased to $34 per megawatt hour, in the third quarter of 2004, compared to $30 per megawatt hour in the third quarter of 2003. The increase is primarily due to capacity reductions as a result of the Bruce B vacuum outage that started late September.

The Bruce units ran at an average availability of 85 percent in the third quarter 2004, compared to an average availability during the third quarter of 2003 of 94 percent. A scheduled maintenance outage on unit 6 began on September 11, 2004, and the unit is expected to return to service in December of this year.

The planned vacuum building outage inspection began -- began for the remaining Bruce B unit on September 18, 2004 and was completed ahead of schedule with unit 7 and 8 returning to service during the week of October 11, 2004. Unit 5 remained offline for additional maintenance as a result of tests performed during the inspection and it is expected to return to service by mid-November.

In our eastern operations, operating and other income for the 3 months end ended September 30, 2004 were $21 million compared to $30 million for the same period last year. The decrease was primarily due to a reduction in income from the sale of the Curtis Palmer hydroelectric facilities to the LP on April 30, 2004, the unfavorable impact of higher natural gas fuel costs at OSP and a weaker U.S. dollar in 2004 compared to 2003.

As Hal mentioned at the end of August, OSP concluded its third arbitration process with respect to its costs of fuel gas, and as in previous decisions, received in March of 2003, and December of 2002, the decision substantially increased OSP's cost of fuel effective September 1, 2004. In effect, the most recent arbitration decision established a pricing mechanism for fuel gas which results in prices in excess of market, and as a result, impedes OSP's ability to economically and competitively produce power.

Substantial long-term impacts of this negative decision and the related courses of action are now under review by management. OSP has commenced the process for another arbitration of its fuel gas costs which we would expect to be completed by mid-2005. As Hal mentioned, our northeast power operation is a core component of our power operation. And has generated significant returns to our shareholders over time.

TransCanada's success in the northeast is a direct result of its assets, and an efficient marketing operation. We are focused on selling power under contract to wholesale, commercial, and industrial customers, while managing a portfolio of power supply sourced from both our own and wholesale generation power purchases. In the future, we will continue to focus on enhancing our competitive position in the U.S. northeast, and eastern Canada through a number of initiatives including the proposed acquisition of the USGen hydro assets.

Turning now to the Power LP, operating and other income of $6 million for the 3 months ended September 30, 2004, was $2 million lower than the same period last year. The decrease was primarily due to TransCanada's reduced ownership interest in the Power LP in 2004, and the lump sum recognition in the second quarter of a previously deferred gain resulting from the removal of the Power LP redemption obligation. Previously deferred gains of $132 million were being amortized in income to 2017.

Additional earnings from the Power LP's acquisition of Curtis Palmer, and ManChief, partially offset those declines.

Finally, in the corporate segment, net earnings from $8 million for the 3 months ended September 30, 2004. Compared to net expenses of $12 million reported for the same period last year. The $20 million quarter-over-quarter increase in corporate net earnings was primarily due to a $12 million after-tax adjustment as a result of the release in the quarter of previously established restructuring provisions, and the recognition in the quarter of an $8 million income tax benefit related to the utilization of noncapital loss carryforwards. Excluding these amounts, net expenses of $12 million for the quarter were comparable to the previous year.

Now, turning over to the cash flow statement in our balance sheet, funds generated from continuing operations were $394 million. And 1.207 billion for the 3 month and 9 months ended September 30, 2004, respectively. Compared to $516 million and 1.407 million -- or billion for the same period in 2003. The decrease is primarily due to higher current income tax expense.

Capital expenditures, including acquisitions, for the 3 and 9 months ended September 30, 2004, were $146 million. And $354 million respectively. And related primarily to the construction of new power plants, and the maintenance and capacity capital in the gas transmission business.

Looking forward, we still expect our capital program, including acquisitions to be about $2.7 billion for this year. Of this amount, $2.1 billion relates to the GTN acquisition and includes the assumption of approximately $650 million of debt. The remainder relates to the construction of the Becancour and Grandview power plants as well as capacity and maintenance capital in the gas transmission business. Our plan for financing this capital program is essentially in place.

The majority of our remaining capital commitments will be financed with the $1.1 billion in cash and short-term investments on hand as of September 30, 2004 and internally generated cash flow which is expected to remain strong. The remainder will be financed by issuing notes payable or accessing the debt markets. Our flexibility here is underscored by the fact that during the first 9 months of 2004, we have reduced notes payable from $367 million at December 31, 2003, to zero at September 30, 2004.

As you are aware, over the last 4 years, we have consistently focused on strengthening our balance sheet so that we can act on opportunities as they arise. Today, under the equity method of accounting our balance sheet consists of 55 percent debt, net of cash, 4 percent deferred security, 2% percent deferred shares and 39 percent common equity. This gives us the financial flexibility to complete the $2.1 billion acquisition of GTN with cash and debt. We expect GTN to be immediately accretive to earnings and cash flow.

To summarize, the company's net earnings and cash flow, combined with a strong balance sheet, continue to provide TransCanada with the financial flexibility to make disciplined investments in its core businesses. We will continue to prudently reinvest our discretionary cash flow and utilize our balance sheet strength to make profitable investments in natural gas transmission, and power, as they arise to allow us to continue to create value for our shareholders.

That concludes my prepared remarks. I will now turn the call back over to David.

Thank you very much, Russ. Before I turn it back to the conference coordinator, a reminder that during the question and answer period we will accept questions from the investment community first and following that we will provide an opportunity for the media to ask questions as well. With that, I will turn the call back to the conference coordinator.

(OPERATOR INSTRUCTIONS) Karen Taylor from BMO Nesbitt Burns.

I just had a couple of really quick ones. On the eastern operation, the reduction of 9 million, can you break that down between Curtis Palmer, Ocean State and the foreign exchange change?

I need to find some information.

And while you're looking, the same for the west. The increase of the 17, can you break it into MacKay, the fee on the LP and the higher margins? And then I have a follow-up on MacKay, please.

For eastern operations, essentially the 9, a little over half of that is the Curtis Palmer. The majority of the rest is Ocean State. And a little bit on the weaker U.S. dollar. So I'm going to say it is sort of 5, 3, and 1, or something like that. On the western ops, the MacKay would be 9. The fees earned of 3 And the net margin would be 5.

Thank you. Can you just break MacKay down into what portion of the 9 was attributable to the first 2 quarters of the year?

I think, Karen, as a result of the negotiations, it is a number that we've -- a negotiation that we've agreed not to disclose, but I think what you can do is look at the amount we've earned on MacKay from the beginning of the year as what we would expect to normally earn on a go-forward basis.

It will be a levelized effect then?

Sure.

And Hal, just one quick question and I will turn it over to someone else. BP made a series of comments after the U.S. legislation was passed, and I'd just like to obtain your view on what they exactly mean by the development of a clear and efficient traditional regulatory process in Canada.

I wish I knew, Karen. It has been BP's position for some time that they would prefer to have the latitude to build the Canadian portion of the project without respecting our rights under foothills in the Northern Pipeline Act. And as we've said before, we defend our position aggressively. We believe the Northern Pipeline Act is the right way and the most efficient way to get this project done. And we've made major investments, not only in planning the northern part of the project but in pre-building the southern portion of the project.

So we find BP's comments interesting. But we do continue to discuss the best way to get the project done with them. With the other two partners, ExxonMobil and ConocoPhillips, and with the state of Alaska, and I would say that on balance, things are looking more optimistic and better at this point on the Alaska project than they have for some time.

Can I just ask a quick follow-up on the Ocean State? And it relates to the eastern operation. The contribution year-to-date from Ocean State is what? And if we've got a fuel settlement that's above market, presumably you can't run the plant. So how much is that going to affect operations, all things being equal, in the fourth quarter or prospectively in '05?

I think at the current time we're assessing what that impact will be, Karen. But it is -- we don't have -- I don't have a solid number for you. The performance in the third quarter I think we said that the earnings from OSP were down by, what, $3 million and you expect those kind of numbers over the next few months. What we're working towards now is we're looking at all of the options that we have to overturn this arbitration and is really where our focus is right now and in the short term I think you can expect sort of similar results to what you've see today.

So on an annualized basis that would be 12 million in contribution. Is that right?

Again, Karen, we haven't actually set exactly what the number is and as well, part of this is still a commercial negotiation between the parties, and we're, we're not disclosing, you know, exactly what the impacts are on us at this point in time. But I think it is safe to say that you know your conclusion is correct. That we can't economically dispatch the plant with this kind of a gas price. We believe that that is not consistent with the arbitration criteria of the contract, and we're working at every -- every possible angle to see how we can overturn that which includes both legal means and continuing the arbitration process into 2005.

Terrific. Thank you very much.

Karen, just before you go, just I wanted to qualify the 3 million that Russ referred to. That is a pre-tax operating income number.

And what would your effective tax rate then be?

I would just use sort of a U.S. standard rate of about 35 percent.

Linda Ezergailis from TD Newcrest

A few questions on Bruce Power. I'm wondering if you have had a chance to look at your 2005 maintenance schedule, and if you can give us a sense of what the outlook for that might be, including availability, and I guess any sort of split of CapEx, OpEx, run rate, going forward, with respect to both that maintenance activity as well as regular core run rate of operating expenses.

We're right in the middle of the process of doing our budget for next year, which includes maintenance schedule. With respect to availability, I would use -- continue to use what we've put out historically in terms of 2005.

We will update that to the extent that there is any material changes to what we've put out previously. But we are literally right in the middle of having that budget debate and that continues on over the next few weeks. So as a partnership, we've agreed not to disclose that information until we actually agree upon it.

Okay. And then in terms of operating expenses, those have been moving around, I guess largely because of your maintenance activity, et cetera. What sort of a run rate might we expect going forward? Assume no maintenance.

Linda, it's David speaking. I'm not sure sort of -- there is a little bit of movement around quarter-on-quarter, but I think at times that as much has to do with the capacity factors and the amount of output. I think generally through the first quarter, I would have to check the numbers, but we have seen low $30 power per megawatt, so there will be some fluctuations depending on the maintenance program and therefore its input per megawatt hour, but I'm not sure the total operating cost on a year-to-date process. are probably fairly reflective of what one would expect.

Okay. Well, then I guess I can continue to apply that to a -- prospectively is what I'm hearing you say, kind of a year-to-date.

I think as Russ alluded to, that's consistent with sort of the guidance provided way back in December of, almost 2 years ago, in terms of ultimately the cost per megawatt hour of production.

Okay. A quick follow-up question with respect to the Alaskan pipeline. I, as well, have been reading some of the commentary and recent developments. And I just want to get an understanding of the state of Alaska's views that it might potentially be an investor in the pipeline, in lieu of gas and royalty payments.

And I'm just wondering, would that be just a U.S. portion of the pipeline? Would that also be the Canadian portion of the pipeline? And who initially proposed that if you can share that with us?

Linda, it is Hal. We have had discussions on this matter ongoing with the state for several years. It is nothing new. And it flows from the fact that the state of Alaska is the major economic beneficiary of the project going ahead, and we simply pointed out to them that there were various ways to adjust the risk/reward balance where they can retain the upside and maybe take a little bit more proactive role in the project.

Maybe it wasn't exclusively our idea but we certainly discussed with them whether or not it might make sense for them to participate in the project, either as a capital investor, or by holding some portion of the shipping commitments. The state, as you know, has about a 20 percent physical interest in the gas, and their economic interest would be larger than that, given that they don't pay operating costs. So, the discussions have progressed, have moved forward. The state has said that they would certainly consider both of those, and I think their press releases this week reaffirm that. As I said, these are not new thoughts or new ideas. This is part of the ongoing process of discussions that we've had with both the state and with the big three producers in Alaska to try to find a way forward.

The -- there are 2 major risks to the project. One is the capital costs, which as we've seen on these projects before, has run out of control many times. And I would contrast that to our own construction project in the 90s, where we did a project of comparable scope in doubling the size of the entire Canadian pipe system without cost overruns, so we're quite proud of that, and we would like to bring that capability to bear on the Alaska project. But certainly capital cost is a major issue for people.

And secondly, is the commodity price of gas, particularly at the Alberta hub, when the Alaska gas finally gets here. So we focused our efforts with the state on defining the role of TransCanada could play to help control capital cost overruns, and to try and define mechanisms that would reduce the risk and impact on the Alaska producers in the event of commodity price volatility. A lot of interesting things have been discussed. I think everybody is very engaged in it. The producers are actively looking for ways to enable the project to go ahead. And the state has become very deeply and thoroughly and competently involved in assessing different ways to make it go ahead. So long and short, we will just keep working away at it, and I'm more hopeful certainly than at any time in the past 5 years that we will achieve a break through here.

So net-net when you look at all the hurdles that are still to be achieved, how far along are you today, versus 30 years ago?

You know, we were well advanced 25 years ago, and then unfortunately, the gas price collapsed. People have blamed the demise of the project last time around on a variety of other things. But at the end of the day, 2 things happened. One, the participants experienced very high capital costs on the oil line. And 2, the gas prices in North America headed downwards.

I am of the view that the current level of gas prices may not be sustained above 7 or $8, but certainly, it would be our view that gas prices are going to be higher rather than lower in the next 15 years. And we think that bodes very well for the project. On the capital cost side, tremendous advances have been made on the technological front, in terms of higher strength steel, higher pressure pipeline, more advanced compressor stations, all these things drive down the cost of the project. On the construction side, there's 2 things driving the cost up. One is the cost of steel itself. Which is a pretty significant part of the project, and which is a large cost these days.

And the second, the cost of construction, just scarce resources of trades people and expert constructers, both affect the cost. But you know, Linda, I think that those things are better understood than at any time in the past. The commercial mechanisms that could allow the project to go ahead are much more sophisticated than at any time in the past. And I think that, we're -- we remain optimistic, certainly more optimistic than at any time in the past 25 years that we might be close to being able to proceed.

Great. That's very helpful, Hal.

Bob Hastings from Canaccord.

My -- a lot of my questions have been answered but just if I can go back to the Ocean State Power for a moment and you said are you looking at all your options but can you sort of describe what you see them being at this point?

I think there is the combination of a negotiated settlement with the shippers. And second would be continued arbitration. And the third would be a legal appeal. And those are sort of the 3 that are on our slate right now and we're pursuing all 3 actually at the current time.

But a closure of the plant is not an option?

I think if this arbitration decision sticks, I was saying commercially what are our options -- I thought your question was with respect to the gas supply. With respect to the operation, ongoing operation of the facility, it is dependent upon the outcome of the first 3 options that I mentioned.

If we end up with that -- with the belief that we have -- that we're stuck with this kind of a gas contract for the balance of the contractual life at OSP, it means that we can't run OSP in an economic fashion, and we will have to assess our options on that front. But it is premature to do that and that we need to determine, what do I do to the gas supply costs going to be for the next, I guess, through 2011 is the current term of the gas contract.

So there is no take or pay provision or something similar to it?

I'm not sure what you're referring to, Bob.

Just that you would have to take the gas or pay for it whether you ran the plant or not?

Well, the gas, we're obligated to buy the gas at the current price. So obviously there is 2 negative impacts. If it is above market, you have the impact of buying above market gas and having to resell it in the event that you shut down the facility and you have to deal with the facility itself. So it would be the combination of those 2 things which would be negatives for TransCanada. Yes, we'd have an obligation to continue to buy the gas, even at above market.

Dominique Barker , Credit Suisse First Boston.

I wanted to ask if, given yesterday, there was a recommendation that at some point (inaudible) would consider an equity investor . I was wondering if Bruce Power would consider an investment outside of Ontario and in particular in the maritime.

Yes, we certainly would, Dominique. We're very focused right now on firstly, running Bruce well. And secondly, having restarted the Bruce A units 3 and 4, we're happy to have gotten through that and we look forward to having all 6 units running at very high utilization factors at Bruce. With so many reactors, and a complex situation, as we've indicated to the market before, they're all these challenges in achieving those goals, so we're very focused on that.

Our second priority at Bruce is in negotiating an arrangement that would allow us to bring units 1 and 2 back on. We would love to see them producing into the Ontario marketplace. And we will keep working towards that.

Thirdly, there certainly are other nuclear opportunities for the Bruce team to pursue. The nuclear capability of the Bruce team is a real asset to us. And we want to maximize the value of that. But timing is everything. And we need to make sure that we don't go off pursuing distracting things if that impairs our ability to maximize value at Bruce itself. So long and short, yes, we would be interested. But, there are a lot of other priorities on the plate as well.

Okay. Thanks. And just a second question. Could you remind us of the factors that you would consider in your dividends? In increasing your dividend?

Well, I guess we know that our investors like our dividend. And factor number 1 is, can we afford to increase it, not just in the very near term, but longer term? It is a principal for us that we will adjust the dividend to a higher level only if we're very comfortable that we can sustain it at that level for the long haul. So I think that's probably the number 1 factor we consider.

Do you consider that in terms of earnings or -- in other words, payout ratio or cash?

Well, I think we see a lot of evidence in the world that -- the thinking on this is evolving. We're still pretty traditional in this but we're not one of those companies that has historically been prepared to pay a dividend that is greater than earnings. And as to where thinking in the financial markets goes in the future, I don't know but we have no plans to go in that direction right now.

Maureen Howe, RBC Capital Markets.

Thank you very much. Good morning. Just coming back to Ocean State. It seems that you are bound by a contractual arrangement. Is the gas cost to you indexed? Is that what it has led it to exceed the market price?

No, it was -- it is more of what's included in fixed and variable costs. And the disagreement between us is to what's commodity costs and what's fixed costs. And that's what's reflected in the current decision.

I guess I'm having trouble following you, Russ. Is this -- I mean is it fairly obvious that gas is a variable cost? I'm not sure with respect to what you're referring to.

I guess what we said, and again, you can't get into too much detail about it, but essentially what we're doing is at the plant gauge, paying above the market price for gas on a commodity basis would be our view and if -- with the plant with the heat rate of about 8500, and above market price gas, we won't see very much dispatch.

Even, you know, the newer facilities that have sort of a 7,000 type heat rate and buying market price gas in the current market environments are dispatching probably something less than 50 percent of the time. So it is our view that the arbitration criteria are such that we should be allowed, or receive a gas price that allows us to dispatch the plant, something closer to 85 percent of the time. We don't believe we have that price today and don't believe that there is -- we don't think that the factual basis upon which the arbitration decision was based is correct.

So I guess this actually does lead into the second part of my question, and that is, how much gas are you actually obligated to buy?

Well, enough to run the facility. It is about 100 million cubic feet a day.

But enough to run the facility, I guess at what utilization rate?

Well, it would be to run the facility every day, with full output of approximately 500 megawatts. So we need sufficient gas for those days.

The load factor comes into it when, you know, when you're not running that day. So basically, you need, you know, 85 percent of 100 million cubic feet a day but essentially you need 100 million cubic feet a day on the days that you run.

And do you not have to buy the gas on the days that you don't run?

We are obligated to buy the gas under the gas contract which is about 100 million cubic feet a day.

Okay. And how long does this gas contract run for?

Through 2011.

2011. Okay. Thanks very much. And turning to Bruce Power, I'm just wondering, we've heard about the province talking to Sarnia or TransAlta regarding contracting for some of that output, contract with output at this point in time. What about for the Bruce facility? And I'm just wondering, obviously the Sarnia, if they were recovering full cost, based on sort of market gas prices, that is probably a pretty attractive contract price to Sarnia, and is it possible for Bruce to get that type of price range?

Well, Maureen, we would love to get -- we think that the price that is required to justify investment in gas-fired power plants in Ontario today is pretty high-priced. And we recognize that with our own gas-fired projects that we looked at in Ontario.

And so, we believe that that kind of a price will ultimately need to be paid if the province is to attract investment in plants like that. And we have reminded the province that if they're looking at paying that for people that are not yet involved in the market, that they should be fair to the incumbents, and treat people who are expected to get a free market price. People like TransAlta should be treated the same as new investors, new entrants at this time.

Now, as to whether or not that automatically flows through that we should get the same price at Bruce, depends on the economic model that the government of Ontario settles on in the Ontario power market. An, to run Bruce on a marginal basis day-to-day or year-to-year, we would not need that price.

But when we look at the capital costs of refurbishing plants like Bruce, or adding more nuclear capacity at Bruce, the price isn't a whole lot different than what you need to justify gas-fired plants in $7 gas price environment. These are all unanswered questions at this time. And I think they're all the things that the power gen investment community is waiting on. And we're all very interested in where the government goes on this.

We've expressed our view that the government shouldn't necessarily look to the classic free market, spot market, merchant market kind of a model to make things work in Ontario. We've encouraged them to enter into longer-term arrangements with less risk so that they can achieve lower cost of capital from investors. And we think that is the right outcome in Ontario. But they're working hard on it, but we don't yet have any clear insight into how that is going to go.

With respect to Bruce -- excuse me, Bruce A and discussions regarding units 1 and 2, do those discussions or just --I guess, discussions just generally around Bruce A, did they extend to the possibility of putting new reactors on that site? Or are they strictly regarding just a restart of those units?

The detail discussions which of course are going on between the Bruce Power management and the government. We're an investor in Bruce and we're certainly an interested investor, but those discussions, Maureen, are very focused on the restart of units 1 and 2. Having said that, we all know that Bruce is an excellent site. And that further investment in a Bruce C kind of a facility could occur there -- would be a significant step forward in the overall develop of Bruce, but may well be the best alternative for additional nuclear capacity in Ontario. But, you know, there is nothing under active discussion on that front right now. We're focused on units 1 and 2.

Okay. And then one final question, if I may. And it is regarding the -- Russia's ratification of the Kyoto protocol, and what implications might there be, and I guess it 's early days, but regarding liabilities, if you will, for your PPAs and directly as a holder of a PPA, to comply with the Kyoto protocol?

Well, firstly, we do not regard Russia's ratification of Kyoto as particularly significant. The bigger issue is regardless of who ratifies Kyoto or doesn't ratify it, how in the world can we implement restrictions on CO2 emissions in an economically sensible manner, particularly when the United States is on a different timetable than we are?

And so we've consistently recommended to the government of Canada, but there needs to be consistency within the North American marketplace, as to how this happens. And we need to pursue projects that deliver fuel efficiency and fuel economy benefits, as well as reduced CO2. And as far as coal-fired power goes, the issues of NoX and SoX and mercury are, in our view, more important than the issue of CO2, so we need to make sure we can achieve our objectives on those fronts as well.

So, having said all those [inaudible] statements about CO2, as to how we move forward , if Canadian government policy is CO2 reductions have to be achieved the only logical way to get there is to allow companies that are making those investments in power gen facilities to recapture that investment in the power prices they charge into the marketplace. Any sort of a scheme that would think that they could achieve CO2 reductions without an impact on the market price of power does not make sense to us.

And specifically, in Alberta, the arrangements we have would enable us to walk away, if you will, from the obligation, to make those investments, without significant financial penalty to us. We think it would be a big mistake if the coal-fired power plants in Alberta were shut down. We don't understand how that could work or how that would work. So, this is not something, Maureen, that we spend a lot of time worrying about in the near term.

And in a lot of our longer-term, fixed contracts, Maureen, we have the same pass-through rights as Hal was alluding to, there is certain ability for the seller of the power to pass through those costs to us, to a certain extent and if they're too high and we can't pass them through to market, we have some walk away rights. We've also -- anything in terms of longer-term contracts we pass through those same provisions in those contracts to those buyers.

To the purchasers of power?

Yes.

And when you talk about the longer-term contracts you're talking about terms of how long?

I think anything sort of greater that an couple of years, we -- on the longer term, sort of 5-year plus contracts that we are able to back-to-back against that supply we try to pass through almost, identically the provisions of the power purchase arrangements with the sellers right through to the buyers. So anything sort of -- our shorter-term stuff, the 1and 2-year stuff that we're selling doesn't have those kind of provisions but I would say that, 3, 4, 5 and longer contracts do have those kind of provisions.

Okay. Thanks very much.

Maureen, it is Hal. I would just like to add to my response to that, people need to keep the magnitude of the economic impact of Kyoto in mind. That there are many coal-fired power gen facilities in North America that can operate effectively at U.S. solar power prices of 30 or 40 bucks. And to shut those down and replace them with operations that would be Kyoto-compliant, you're looking at prices in the 70 or $80 range. And so the economic impact of implementing Kyoto just on a stand-alone basis in the power gen sector is 20 or 30 or $40 a megawatt hour.

Well, I may agree with you, Hal, but our government ratified the Kyoto protocol so presumably they thought this through at the time.

Yes. And all I'm pointing out is it is going to be a long and iterative process when we recognize what the economic impacts of doing -- or complying with Kyoto faster or slower. I don't personally disagree with the objective of reducing CO2 emissions. I'm simply saying that we seem to be locked into a timetable right now, but it is hard to see how we're going to get there within that time frame.

Matthew Akman, CIBC

Thanks. First on Gas Transmission Northwest, I guess -- I don't know if this is for Hal, but what kind of assurance you can give us that this deal is going to close this year? I guess we've had a couple of delays. So maybe if you could just add some details to the comments that are in the release.

Well, we think there is a very high likelihood it is going to close this year. We were fairly confident that the bankruptcy process would come to closure, back June, July time frame. And bankruptcy processes where you've got multiple different groups of assets and multiple groups of creditors, and several different buyers of the different assets can get pretty complicated and most of the issues are -- as one group plays off its issues against all the other groups. So we have been ready to close for a long time.

It's been the other parts of National Energy and Gas Transmission that have been kind of tied up in bankruptcy issues. We know that we remain ready to close as soon as they emerge from bankruptcy. And I guess I would turn it over to Russ. Russ, I don't know if you have anything to add to that.

I think it has helped that -- I mean a lot of the issues are not inside of our control. But as there is some drop-dead dates in the contract, and certain places where -- I'd say that our rights in this regard improve and those are towards the end of November that we have certain -- certain rights to force certain things to happen. That we don't have until those -- until those ultimate drop dead dates.

But that wouldn't be a cancellation of the acquisition? That's to actually get it done, right?

Well, that is a right that we have. As you would expect, under all contracts, as you put sunset dates in them, but as well, along with that, there is other contractual provisions that would allow us to potentially push for an accelerated close. So as Hal said, those types of things give us confidence that we will close this thing before year-end.

And from what we've been told, is it is their intent and they're working very hard to get this closed as quickly as they possibly can. And you know, every day there is another success in terms of closing out one of the outstanding items. So we're confident that they're progressing very well.

And sort of where we started this was, they were -- we're sort of months away with the feedback we're getting from them, it is next month, it is next month, we're down to, of it is next week, it is next week. So that is sort of where we're at right now, and we're seeing closure to a lot of the events, so I can't tell you for sure that this thing is going to close before year-end. But from what we see today, high probability that we're going to see close in the next short period of time.

Okay. Thanks. And then this is my last, another question, is on Ontario. We're going to see legislation come back to the house very shortly. So there is some imminent potential implications I guess, for your activities there. You talked about kind of longer-term issues on Bruce in contracting and bringing units back, but when this legislation hits the house and gets approved, what do you see in terms of any impact on Bruce short term for 2005 even? And also, regarding the RFP, the project you had previously announced downtown, with OPG, for the new gas-fired plant.

Well on the project downtown with OPG, we continue to pursue that. We think it's a very fundamentally attractive project, because it avoids the electric transmission constraints that are a problem in every major urban center in North America. And so we think it is a very good project and we remain hopeful that we will be able to proceed at that.

With respect to Bruce, you know, there are 2 parts to that. One is what will the longer-term commercial arms be for the existing Bruce units? And, will they enable us to refurbish those units or maintain them at a very high level, so that they can run longer than what their original expected lives were? We remain optimistic, we certainly know the government of Ontario understands the issues. We've done, I think a pretty thorough job of explaining both the short-term and the long-term issues at Bruce, and discussing them with them. And we believe the government is committed to maximizing the run life of all of those facilities.

As to what the exact commercial arrangement is going to be going forward, we don't yet know that. But we do believe the government understands that there is a cost to producing power, and that those costs have to be recovered in the marketplace. And if they can be recovered with greater certainty, then the required return on capital is lower, and those are the directional arguments that we've made with them, and we're very impressed, actually, with the thoroughness that the government has put into studying the problem, developing alternatives, and pursuing them. So we're not pessimistic on this, but it is a very complicated issue.

And I'm totally in agreement with all those things. I'm just wondering, do you see any specific implications of the legislation when it gets passed in this coming months here?

I'm not sure the specifics of the legislation you're talking about. Is there something specific that you are wondering about how it would impact us, Matthew?

Yes, do you see any impact in terms of the way Bruce sells power, who to whom it can sell, it market prices?

I think what we're looking for is clarity in the legislation and I guess I'm not sure, maybe Hal is, as to exactly what the wholesale market is going to look like, or how they're going to propose to manage it and operate it. As he said, there a couple of scenarios for Bruce 1 and 2 restart. One would be a fully contracted sale.

And then the question is, who is that sold to and how is that put back into the marketplace? Do they resell it in or bid it into the pool? And then there is the balance of the other 6 units that we've got on-site and the question that Maureen was asking around, how does TransAlta and their Sarnia plant fit in to the market? How do we fit into the market, and what is left for us, for a market? We don't have the answers to a lot of those structural questions.

And, so I think I can tell you for a 1-2 restart, based on the current configuration, there is no way that we would commit to build that power to sell into a wholesale market that is not defined. Even if the wholesale market is defined, we would have a difficult time just given the cost of the power as Hal outlined, I mean it is very expensive relative to what we've currently got. And therefore, we're going to need a lot more certainty with respect to revenues.

But, you know, where we're sitting today, I guess we're as curious as anybody as to what the government is going to propose, and how they are going to implement this new hybrid market model that they're talking about, and just how that is going to work. And as Hal pointed out, we've encouraged them certain directions, that we think would be workable and as we said, they're listening to those things and they're conscious of them but we really don't know at this point in time where they're going to land.

Andrew Kuske, UBS Securities.

Thank you, good afternoon. Hal, if I could just ask you a question on M&A opportunities that you see in North America. If we look at specific assets, and in fact some of the assets that you've acquired or are about to close off in the near term, the valuations on those on the EBITDA basis was fairly robust. Yet, if we start to look at corporate valuations, most corporate valuations in the U.S. is trading at discounts to your own valuation, and particularly the assets you've acquired over the last little while. Would you contemplate doing a big corporate acquisition? And if so, how large?

Well, Andrew, we certainly would contemplate doing that, but these kinds of things have to fit from a strategy and focus perspective. And so, we would not, for example, want to acquire a large corporate entity that took us into very risky merchant gas or power businesses that we're not in today. We like to acquire things in regions of North America where we have a competitive advantage in terms of market knowledge and expertise.

And those are the kinds of problems you run into when you see corporate deals. Very often, they've got scattered assets or, quite often those corporations are for sale because they've got some real thorny problems that we don't want to necessarily spend the next 5 years trying to figure out how to sort those out. We have been through that once.

So, we would be more interested in acquiring selected assets that that fit really well and we're extremely pleased with the acquisition of Gas Transmission Northwest. I've read, from time to time, that people think we paid a pretty full price for it, and we're not for a moment suggesting we got it at a bargain basement price. But, it does strike us that lesser quality pipeline systems have changed hands at higher EBIT to EBITDA multiples than the deal that we did there. And maybe we just use different numbers that other people do, I don't know. But, we're certainly very pleased with that and we're pleased with a number of the other transactions we've been able to do in the last couple of years. So yes, we would look at a corporate situation, but not without a lot of rigor. And being fully aware, eyes wide open, as to what kind of thorny issues are coming with that kind of a deal.

Well, just on that issue of the thorny issues, to what degree are you willing to stray from your core operations, being the gas transmission at this stage and then the growing power business? Would you get into distribution, for example?

Oh, not likely. I mean we're more likely to get into somewhat peripheral regulated businesses than non-core things on the nonregulated side. So I'd never say never, but, I would put a very high probability that you will see TransCanada continue to focus on gas transmission, and power generation, and particularly, that kind of power generation where we can take advantage of a lower cost of capital.

Okay. And if I just could get a quick update from your view on coalbed methane in Alberta, just on how you see that developing, how you see that starting to fill up, a bit of the pipe, or at least with gas flows starting to drop off in Alberta, how that fills a bit of the gap?

Well, you know it is interesting that coalbed methane is, maybe turning out to be a little bit bigger part of the puzzle than a lot of people thought. But, still, you know, western Canada production, 17 BCF a day, and to envision that coalbed methane would ever be more than 10 percent of that is -- would be an incredibly bullish forecast for coalbed methane.

So I don't think you're going to see coalbed methane overtaking conventional gas in any way in western Canada. But you know, it is just one form of tight gas. This are terrific opportunities for the development of deeper, tighter gas in the western portions of the basin, and up into northeast BC. Not coalbed methane but just tight fans, wells that were hopelessly uneconomic at $2 are staggeringly attractive at $6.

And the economic limits for what kinds of things you can pursue in western Canada have moved very dramatically. It is a whole different playing field out there than it was before. But Andrew, I believe that the key issue is not what is the ultimate gas resource in western Canada. That question will be answered in 200 years. And it is of no economic consequence to us today. The bigger issue is at what daily production rate will the basin yield its gas? And we've got two counter-forces at work.

One is the decline that occurs every year in western Canada, offset by the new production that can be added by the industry every year. And if production rates get too high, declines will be high, and the reserve replacement exercise won't be able to keep up, and so you will see some declines. It will bounce up and down until it stabilizes. We seem to be stable right now at 17 BCF a day where we have 3 BCF a day of annual decline and the industry seems to be able to have 3 BCF a day of new annual production so you will remain flat. The flywheel keeps running at that rate.

But, our own forecasts are probably best characterized by -- we think western Canada will produce somewhere between 15 and 20 BCF a day. And 17 seems like a pretty good middle point estimate. So that's -- those are the issues, though, that I think everybody is looking at. And I would just conclude by saying that the potential for incremental gas from conventional sources is probably in order of magnitude larger than coalbed methane.

Anatol Feygin, Banc of America.

Good afternoon, everyone and thanks for taking all this time with us. Can you give us a sense for the timing on the U.S. gen auction, sort of a similar perspective as you gave on the GTN closure?

What I can tell you about the time frame that we know of right now, is that there will be a qualification for bidding into the court-sanctioned auction process. And I believe that is about mid-December -- that those sort of applications are due and bids are due and from that they determine who is qualified to bid in the auction. To date, we're unaware of anybody bidding into that process or putting forward their name to bid in that process. But I think that is around the middle of the month.

To the extent there that there is a winner approved -- to the extent that there is a winner approved -- we're just searching around for the actual dates here for you. I don't have them on the tip of my tongue. But similar to the GTN process is, from that point in time, there will be an approval order hearing approving the winner of it and from that point in time, they have to move to close. And what we hope is that they -- that they would move quicker than the GTN acquisition. But I think our current view is, is we would probably be, if we do prevail as a winner, probably sometime in late in Q1, early Q2. Something like that.

And actually, the dates here that I've got, big procedure order hearing and if you remember from the GTN process, that's when they approve our contract, and our break fees and those kinds of things. I think that dates about November 3. And then qualified bidders have to qualify by December the 3rd. And they actually have the court-approved auction on December 9.

Those are the current dates that are set out by the bankruptcy court and as we found in the GTN process they can move a little bit. Their intent right now is to get this done as quickly as possible is what they're telling us, so those are the best dates that we have to work with.

Great. Thanks, Russ. And on the Cartier plan, what is -- I saw that the plan is for the power to be online between -- starting in 2006. When is that capital going to be committed? And can you just give us some sense for how that funding will be structured? Will it be 50 percent kind of equity from TransCanada, or is there going to be some level of project level debt, et cetera?

Anatol, I think is probably a little early for us to give too much detail on that. We have announced that our proposal has been accepted by Hydro-Quebec and that then starts the negotiation process around the details of a very large and complicated power and purchase agreement that will address all of these things. So, some of what you're asking us, we know, but we can't say, and some of what you're asking, we don't know. So, I hope to be able to give you a lot more information on the whole Cartier project in a couple of months once we get through that process.

No problem. Thanks. And then just one quick follow-up on GTN. I don't know how much of this you can discuss, but kind of plans for the asset going forward, both in terms of -- in terms of expansion opportunities that you see in the Northwest, and also perhaps -- is there a view to spend the asset down into TCLP down the road?

Well, we don't have a plan to spin it down into the LP at any time soon. It is a very interesting asset. In that owning 100 percent of GTN down to the California border, means that we now own 100 percent of flow path from Northwest Alberta, where an awful lot of this gas comes from, right down to the California border. GTN being the southern half of the system that we've owned the northern half of, for a long time.

And there are many different tolling arrangements, as you go from the north to the south. We pass through at least 3, and maybe 4 regulatory jurisdictions, from the Alberta regulator, the Canadian regulator, the FERC and then into CPUC territory once we hand the gas off to PG&E at the California border. And one of the things we would like to accomplish is certainly to bring more workable tolling arrangements to that whole system, more sensible end-to-end tolling structure rate from northern Alberta down to the California border. And to the extent we can, integrate that with PG&E.

So, those are the priorities. The other one, of course, is to operate the system as technically effectively and profitably as we can. Many big issues these days around pipeline integrity, and sound operations, fuel consumption, cost control, we're going to be very focused on all of that kind of stuff and I think TransCanada has a lot to bring to the table in those regards.

So now, as to your other question about expansion, we of course think that PGT, or GTN, as you may prefer to call it, is a pretty attractive flow path for Alaska gas to get to U.S. markets. But that's a long ways out there, and until we see some likelihood of gas coming down from Alaska, we would not be expecting an expansion of the main line itself, GTN, because we see there's lots of pipe capacity to take Alberta gas to market today.

But what maybe is available to us would be additional market serving pipes off of GTN to serve more local market demands along the pipeline route, and that of course depends on whether or not those market demands are there.

Thanks, and just a quick follow-up on that. The idea behind homogenizing or restructuring the tolling arrangements, is that to attract more shippers, better shippers, to just increase transparency on the system? What is the goal there, as you move through that process?

I think all of the above. You know, one of the things that we continually try to do is provide really seamless transparent service that makes the gas markets as efficient as possible. And makes it as easy as possible for our customers to take out service and to continue to hold that service.

So we are trying, of course, to do exactly the same thing by working with northern border, on the flow path to Chicago. And down our whole main line system and into the eastern region. This whole business of toll restructuring and the evolution of tolling arrangements is a big priority at TransCanada. But, it is one of those things that we work away on year after year, and I would not want to be suggesting to you that any of this is going to have a dramatic impact on the financial value of the assets in the short term.

One thing that we have mentioned in the past, with respect to expansion, though, would be the -- to the extent that there's LNG facilities in Baja, Mexico. That there may be opportunities to reverse and expand the Baja portion of the pipe that we -- that's included in the GTN acquisition and those are looking at, as I said before, those are looking a lot more promising today than they were when we initially embarked on buying this asset.

Andrew Fairbanks, Merrill Lynch.

Good afternoon Hal, gentlemen. Just a couple of quick LNG questions. First are you continuing to pursue other LNG importation possibilities beyond Quebec? And, in addition on the Quebec project, with Petro-Canada itself, are there some significant milestones we should be looking for over the next, say, 6 to 9 months to see the project moving forward?

Well, on the first question, as I've said before, our LNG strategy is very much focused on eastern Canada. And the northeastern U.S. That we understand that the U.S. Gulf Coast and the California Baja areas are good places to bring in LNG. But we don't have any particular presence or expertise in those areas. So we have chosen to focus our efforts on the northeast U.S., and eastern Canada.

As part of that, we've looked at probably a dozen potential projects in this part of the world, and we focused it down to a smaller number than that. Less than half a dozen. And the first one that came to public attention was the Fairwinds project in Maine which unfortunately did not proceed. The bad news, it didn't go ahead. The good news is that we were able to determine that fairly early on in the process and not put a lot of resources into a project that wasn't going anywhere.

Quebec is the Gros Cacouna project is very important to us. We think it has got a great location, good connections, to really good markets, and we think it will be an attractive place for Petro-Canada to bring LNG into North America. And we're optimistic that we can get it to the finish line. Beyond that, we do continue to work on a number of other projects. We prefer not to announce them until they have become certain. Or until there's some step in the process that requires us to announce them.

So I wouldn't want to tell you that there's going to be a steady string of announcements on these things, but I would want to convey that we are working hard on multiple fronts. We think the northeast U.S. is a difficult place to build LNG facilities. Just because of the population density in this part of the world. But on the other hand, it is the most attractive place to land LNG in North America, just based on locational pricing of natural gas.

With respect to the Gros Cacouna project, milestone side, I don't know that I can really answer your question accurately at this time. We're preparing to file applications and,just do all of those things that are required to bring the project to fruition. And at the same time, Petro-Canada is working on their end of it, which is bringing the LNG to the site. So, please stay tuned. But I -- I can't say there will be an important announcement on March 18 or anything. I think it is too early for us to know at this point.

Linda Ezergailis, TD Newcrest.

Very quick follow-up question with respect to Bruce power and your negotiations for restarting the 2 units there with the government. Just wondering if you could give us a sense of major milestones, and time line, and contingencies in terms of an optimistic versus a pessimistic scenario on time lines?

Well, Linda, there's two big issues here. One is what are the commercial arrangements going to be? And we're not setting the milestones -- or the time lines there. That's Ontario government policy. And that ball is really in their court.

The other one that is very much in our court is refining the cost estimates, and understanding what's the magnitude of risk on each of the major elements of risk. And just really developing a very high level of comfort that we can do a big project in Bruce that does not go sideways the way a lot of other big capital investments in the energy sector have gone in recent years. So, at this point, we're very focused on trying to do the best possible engineering, if you will. The best possible cost estimating.

And working -- we're working very hard and very diligently on understanding the risks, what drives those risks, and what we can do to mitigate them, just to try to identify what this project is going to cost within a narrower range of outcomes. So that's our main focus right now. We're happy to engage in discussions with the Ontario government whenever we can. But you know, there are a number of policy issues I think they have to deal with first.

Okay. So just in terms of the next year, I would imagine that the discussions, as you said, are contingent upon the government resolving its policies, which in my mind would take up to the middle of next year, so we might start looking more closely at this in a year from now?

You know, it could happen quite a bit more quickly than that, if the government really decided that they wanted to put a lot of energy and attention on that particular opportunity, as opposed to others. And as I said before, we've had many good discussions with the government, and we don't have anything -- I'm certainly not intending to be critical of the way they're going about this. This is very complicated stuff.

And on the one hand, they're under time pressure to bring new capacity on stream, or to refurbish existing capacity so that it stays on stream. On the other hand, we would be the last people to suggest that they move quickly and rationally and make a mistake on this. We think it is important that it be well thought out.

Great. Appreciate the context.

Once again, the financial analysts may press star, 1 at this time for any questions or comments. Sam Kanes from Scotia Capital.

Questions for you Russ, on clarity with respect to the 24 million denied by the EUB. The way you stated it, sounded like this recurring operating earnings, first of all, is that -- if it is or isn't, then can you mitigate any of this in 2005, if this has now gone into radio silence.

I'm not sure what you mean by radio silence --

Well it has gone indefinite, it has got to be readdressed of course at some point.

Yes. For 2004, these were disallowed costs. We are, as we said, for the most part incurring these costs. As you might have read in the decision, the costs related to our incentive compensation, some of the costs, for example, on charitable donations were disallowed as as well. Those are costs that we might be able to deal with more in 2005 and we made some of those commitments as well.

But certainly compensation costs we can't, you know, turn our compensation systems on a dime. And change the way we pay our people. As we said, as we have to pay our people competitively. We believe that the total package that we pay our employees is competitive, and therefore, those costs are prudently incurred. And we will put those forward in a 2005 rate application for the Alberta system.

Of note, is the recent decision in phase 1 of the main line, where they have disallowed a portion of those incentive costs for example in 2003, they approved 100 percent of those costs in 2004. That gives us some confidence that we're not, I guess we're not looking at this incorrectly. That they said that these are prudently incurred costs and that we need to pay our employees to ensure the safe and reliable operation of our system. Those will be the kind of cases that we put forward in 2005.

And as well, for us, the 2004 issue isn't over yet. As we mentioned, we have an appeal to the Alberta court. Which has been set aside for the current time. What we consider the merits of a review and variance application. And one of the things that that caused us to go that route on review and variance is the changed circumstances, and one of those would be in the intervening period we did have the national energy board decision approving those similar costs for 2004 for the main line.

And as well, we said we will continue on discussions with our shippers, and a subtlety in the filing was the cap shippers we had come to settlement with them on these costs and they had withdrawn their evidence on the costs. The EUB, even upon that -- that withdrawal their evidence, saw it necessary to disallow the costs. So, it is not over until it is over but that is sort of where we sit, is that there is a risk that these are disallowed. If they are, for a long period of time, obviously we're going to to have to address the way that we pay people. And ensure that we can mitigate these costs as much as possible. But that would be sort of a second tier strategy.

Our first tier strategy is to determine what is a prudently incurred cost and what is recoverable. And once we know that, then we can substantially change our system. But it wouldn't be fruitful to change our compensation system just to potentially have that disallowed as well. So we really want to understand the principles behind that, the decision.

Okay. Thank you, Russ for that. Back into Ocean States for a minute. You generally guided indirectly or obliquely that we should be expecting probably 3 million a quarter of shortfall from Ocean States, because of above market pricing relative to I presume, the forward strip of gas which is at record highs. Has that ever happened before at Ocean States, that you would be above market? And conversely, would you have been at below market at times based on however the contract is structured for the same type of say 3 million a quarter to the upside years past?

Well, the actual numbers, I won't comment on. But historically, we have a gas contract that would have been below market, as you would expect, to run a gas-fired facility in that region, base load, at an 85 percent load factor, you would need a gas supply that would be below market. And that's the way it ran for the first 10 years of the 20-year contract.

Then as a result of the changes in the marketplace, and deregulation, changed some of the indexes upon which the original gas contract was based. And that led to the subsequent arbitrations. As we've been trying to replace the indexes, if you will, which would set that gas price, our view is that there has been -- been mistakes in how the arbitrators have take an look at what just happened historically and how this facility was supposed to run.

So we did have a gas contract that was below market, and now we have a gas contract that is above market. And as I said earlier, is it -- you would not build a gas-fired facility to -- you could not build a gas-fired facility to run base load back in 1991, without a discounted gas contract. And you certainly can't do it today in light of the increased inefficiency and and higher gas prices relative to other fuels.

Then Russ, the below market, can you quantify it, the first 10 years of how much below market that gas was or that remains confidential?

It is part of the negotiation and it does fluctuate but it it was based off of other fuels in the marketplace which fluctuate, and what we received was a price for our fuel commodity that would allow this facility to be dispatched, and depending on the price of other fuels, the price of gas would move around.

So it would move around with say day forward market just to make sure were you dispatched?

Basically it was on a -- if I remember correctly, it was done on a monthly lag basis.

This concludes the financial analyst question session. We will now take questions from the media. David Ebner, Globe & Mail

Hi, on LNG Rebasca (ph), your guys are in Quebec City, are having a quite a few more problems than maybe your project might. I'm wondering if that project doesn't go ahead does that bode well -- does that bode better for your project?

No, it is Hal here, not necessarily. We don't consider the 2 projects to be competitive. The way we look at the market, the whole northeast U.S., eastern Canadian market, is bigger than 10 BCF a day. And, additional supply is needed into that marketplace. And, whether there is half a BCF a day or a 1 BCF or 2 BCF a day coming in through facilities located in the province of Quebec, these things are all possible.

Perhaps there is nothing coming in through Quebec but it is a very large market. These are relatively small bite-sized increments to the supply. And, we think that the projects are pretty much independent. I've seen some of the press articles from the Rabasca (ph) project that they don't think they're independent. And we don't actually share that view.

We think that if the fundamentals of the market make sense, whether it is 0.5 BCF a day or 2 BCF a day, it could all go ahead. Now, the other point I would make, though, is that the province of Quebec stands to be a significant beneficiary economically of LNG coming in through the Saint Lawrence.

Firstly, the construction expenditures and operating costs necessary to run these facilities. But more importantly, if you're at the upper end of the gas value chain, you're going to enjoy more competitive gas prices than people that are further down the chain. And I think this is a major benefit to Quebec that is not always recognized. But if Quebec is at the inlet end of the gas system, rather than at the far end of it, Quebec will enjoy lower gas prices than the -- than they otherwise would. So, we think that -- we would not be here arguing against the other project. We like our project. We have worked on this one for a long time. We think we've got an excellent partner. And we think it fits very well into the marketplace. So that's our focus.

Okay. I know you were saying you don't want to preannounce anything, but you said there's a few more ideas on the drawing board. Could we expect something perhaps this year? Or something by the end of next year?

You know, I just don't know at this point. We don't announce things until there's a clear reason to do so. Even until we've got all the pieces put together, or we need to make a public filing, or something like that. So, if one of these other projects gets to the point where it is all ready to go or where we need to make a public regulatory filing, you will see us announce it then.

But, you know, LNG development is a multi-year game. And projects that we may have started work on 2 or 3 years ago still have not seen the light of day. So I wouldn't want to give you any signal that you should anticipate something in the near term.

Okay. And then finally, on wind, I was wondering after the Cartier success, how aggressively you want to push ahead on wind power. Ontario has requests out right now.

Again, it all depends on what the contractual terms are. Hydro-Quebec is a very good company to do business with. They're large. They're financially capable. Their credit rating is excellent. And when we sign a long-term contract with Hydro-Quebec, we're pretty comfortable what the outcome is going to be. And as a result, we can bid quite aggressively.

If those kind of terms are available in Ontario and if there are locations that we can access that have good strong winds, then we would be enthusiastic about pursuing them. But, I don't know the answer to any of those questions right now.

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

Thank you, conference coordinator, and just in closing I would like to thank everybody for their participation this afternoon. We welcome your interest in TransCanada. And we look forward to speaking to you again real soon. Bye for now.

Thank you, Mr. David Moneta. The conference has now ended. Please disconnect your line at this time. And we thank you for your participation. And have a great day.