TC Energy Corp (TRP) 2005 Q1 法說會逐字稿

Good afternoon, ladies and gentlemen. Welcome to the TransCanada Corporation 2005 first quarter results conference call. I would now like to turn the meeting over to Mr. David Moneta, Director of Investor Relations. Please go ahead, Mr. Moneta.

Thank you very much, and good afternoon, everybody. I'd like to take this opportunity to welcome you this afternoon. Start out by just apologizing for the slight delay. It's been a busy morning here with our AGM and other events. But we are pleased to provide the investment community, the media, and other interested parties with an opportunity to discuss our 2005 first 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 are going to start this afternoon 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 we'll 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 and 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 strategic initiatives and whether such strategic initiatives will yield effective benefits and the availability and price of energy commodities, regulatory decisions, competitive factors in the pipeline and power industries, and the prevailing economic conditions in North America.

For additional information on these and other factors, see the reports filed by TransCanada with Canadian Securities Regulators and with the United States Securities and Exchange Commission. TransCanada disclaims any intention or obligation to update or revise any forward-looking statements whether as a result of new information, future events, or otherwise. With that I will turn the call over to Hal.

Thank you, David. Good afternoon and thank you for joining us today. Having discussed at our annual meeting this morning, TransCanada's solid earnings and cash flow performance in recent years as well as our many future growth opportunities, I'll keep my remarks on this conference call brief.

For those of you who weren't able to attend the meeting this morning or listen to the live webcast, the webcast will be archived at www.TransCanada.com. Throughout 2004 and the first quarter 2005, TransCanada has continued to deliver value for shareholders by pursuing opportunities within our two core businesses of gas transmission and power. I am pleased to report that TransCanada's portfolio of gas and power investment opportunities is now larger and of higher quality than at any time since our merger with Nova in 1998.

Our long-term growth objectives are strongly supported by increasing North American demand for energy. As one of North America's leading energy companies with recognized expertise in gas transmission and power, we are well positioned to serve growing power demand and to bring new gas supplies to market in the medium to longer term.

For the first quarter of 2005, TransCanada Corporation's net income was $232 million, or $0.48 per share. The increase of $18 million over the same quarter last year was primarily due to the one-time sale of 3.5 million common units of TC Pipeline's L P with that gain being partially offset by reduced income from our power business. Funds generated from operations for the first quarter 2005 were $407 million, compared to $415 million for the same period last year.

TransCanada's Board of Directors today declared a quarterly dividend of 30.5 cents per share for the quarter ended June 30th, 2005, on the outstanding common shares. This marks more than 41 years of consecutive quarterly dividends paid by TransCanada and its subsidiary. The dividend is payable on July 29th, 2005, to shareholders of record at the close of business on June 30th, 2005. I'll first briefly review some of the key events in the past quarter and then turn the call over to Russ Girling for a more detailed overview of our financial results.

During the first quarter, we were very pleased with the performance of the Gas Transmission Northwest and North Baja Systems, which we acquired in November 2004. GTN and North Baja contributed net income after tax of $23 million during the first quarter of 2005.

Our 2004 acquisition of GTN is an excellent example of the kind of blue-chip, large-scale acquisition that fits within our long-term plan. Beyond GTN, TransCanada continues to pursue opportunities for long-term growth in our two core regions of eastern and western North America, including northern pipelines, power generation projects, gas storage, and LNG facilities, and of course, new pipelines to serve growing gas markets in both of our core regions.

On March 25th, 2005, we announced that our wholly-owned subsidiary, Foothills Pipelines, Limited, had signed a protocol with the Kaska Nation setting out how the Kaska Nation's traditional knowledge will be integrated into the planning, construction, and operations of the Alaska Highway Pipeline Project. TransCanada has a long and recognized history of dealing constructively with First Nation, and we look forward to working closely with the Kaska Nation on the Alaska Highway Pipeline Project..

TransCanada continues to support the McKenzie Gas Project through our contribution of expertise and services to both Imperial Oil, the lead proponent, and the Aboriginal Pipeline Group. The regulatory and land access processes in the Northwest Territories are complex and unpredictable. As I've said on many occasions, Canada needs to develop more workable regulatory and land access processes in the Northwest Territories, and TransCanada looks forward to working with the McKenzie Project proponents, Northern First Nation, and the governments of Canada and the Northwest Territories to develop regulatory and land access processes that will enable this critical project to proceed.

In January 2005, we announced that we are developing a $200 million natural gas storage facility near Edson, Alberta. The facility, which will have a capacity of approximately 50 billion cubic feet, will connect directly to our Alberta system. In addition, TransCanada has secured a long-term contract for up to 40 billion cubic feet of storage capacity at an existing Alberta-based storage facility. These developments position TransCanada to become one of the largest natural gas storage providers in western Canada.

On the liquefied natural gas, or LNG front, we continue to pursue our proposals for a receiving terminal at [inaudible] Quebec with Petro Canada and for a receiving terminal in the waters of Long Island Sound near New York City with Shell. We have hosted a number of public information sessions and workshops with local Quebec communities, and we will file our environmental impact statement with the Quebec Ministry of Environment in mid-May.

We have met with a number of key stakeholders for the Long Island Sound Project, and we continue to gather feedback through open-house forums and meetings. There is clearly a critical need for reliable new sources of natural gas in eastern Canada and the northeast United States. TransCanada will continue to pursue opportunities to deliver clean and safe LNG supply to the northeast United States and Canada.

Our [inaudible] and Long Island Sound Projects are two of the very best LNG ones in North America and we look forward to working with our partners to bring both those projects to fruition. Turning now to our Canadian down transmission business, we are pleased in the first quarter we achieved greater alignment with our customers through two separate settlements related to tolls and other commercial matters on our Canadian mainline and our Alberta system. The main line settlement is for one year only. We are very pleased to have reached a three-year settlement with our Alberta System customers that will carry us through to December 2007.

We have also made announcements this year relating to our core power business. In February, Cartier Wind Energy, which is 62% owned by TransCanada, signed long-term electricity supply agreements with Hydro Quebec for 740 megawatts of wind power projects. The Cartier Wind Projects represents an investment of more than $1.1 billion and will be commissioned between 2006 and 2012. Also, in Quebec, we are very pleased that our new Bécancour plant will be commissioned in 2006. This large Gasco Generation Project is proceeding on schedule and on budget.

Earlier this month, TransCanada closed the acquisition of hydro-electric generating assets from USGen New England for $505 million. These assets have a total generating capacity of 567 megawatts. This transaction was immediately accretive and will have a positive impact on earnings and cash flow for the remainder of the year.

The town of Rockingham, which held an existing option to purchase the 49-megawatt Bellows Falls Facility from US Gen for $72 million US, has now decided to exercise that option. Bruce Power has announced that it has reached a tentative agreement with an Ontario Provincial negotiator for the potential restart of Bruce A Units 1 and 2. The tentative agreement will undergo a thorough financial review before it is brought to the Ontario cabinet for final consideration.

TransCanada also continues to pursue other energy infrastructure opportunities in a disciplined and focused manner and our Keystone Project is an excellent example. This $1.7 billion oil pipeline would transport approximately 400,000 barrels per day of heavy crude oil from Alberta to markets in Illinois. We are meeting with oil producers, refineries, and industry groups to develop shipper interests in the Keystone Project. TransCanada has more than 50 years of experience building and operating large diameter underground pipeline systems in North America. We see oil transmission as a logical fit with our existing business competencies.

What we're proposing is to convert an underutilized portion of our Canadian mainline from gas service to oil to meet the needs of Alberta's growing oil production sector. We think this is a very good project, and we continue to work with prospective shippers. During the past five years, TransCanada has successfully adhered to its long-term strategies. We have made significant strides in capturing long-term growth opportunities for value creation while at the same time delivering earnings and dividends and maintaining our strong financial position.

As we move forward, we will remain focused on operational excellence, sustained profitability, and disciplined strategic investments. I'm particularly pleased that at this time our portfolio of high-quality growth opportunities is significantly greater than ever before as illustrated by the comments that I have made this morning. I'll now turn the call over to Russ Girling, who will provide additional details on our financial results.

Thank you, Hal, and good afternoon, everyone As Hal mentioned earlier today, we announced net income for the three months ended March 31st, 2005, of $232 million, $0.48 per share, compared to $214 million, or $0.44 per share for the same period last year. The $18 million, or 4-cent per share increase was primarily due to the sale of 3.5 million common units of TC Pipeline's LP during first quarter 2005. That sale generated an after-tax gain of $48 million or 10 cents per share.

Partially offsetting that gain was reduced income from power, which included a $10 million after-tax cost associated with the restructuring of Ocean State's Powers natural gas supply contracts. Excluding those two items, net income for first quarter of 2005 was $194 million, or $0.40 per share. This compares to $202 million or $0.42 per share for the same period last year, which excludes income tax refunds and related interests of $12 million recorded in the corporate segment in the first quarter in 2004.

I will now review the first quarter results for each of our segments beginning with Gas Transmission. Gas Transmission generated net earnings of $211 million during the first quarter compared to $149 million for the same period in 2004. Excluding the gain related to the TC Pipeline's L P, net earnings from Gas Transmission were $163 million, an increase of $14 million compared to last year. The increase was primarily due to the contribution from Gas Transmission Northwest, which was partially offset by lower contributions from Alberta Systems, Great Lakes, and Iroquois.

Gas Transmission Northwest, which we acquired on November 1st, 2004, continued to perform well. During the first quarter, it contributed net earnings of $23 million and funds from operations of $52 million. Total delivery volumes on GTN during a three-month period were 215 billion cubic feet, or approximately 2.4 billion cubic feet per day -- the Alberta Systems first quarter net earnings were $37 million, which is $3 million less than the amount reported in the first quarter of last year. The decrease is primarily due to a $200 million decline in the Alberta System's average investment base as well as a lower approved rate of return in 2005.

Net income in 2005 reflects a return of 9.5% as prescribed by the Alberta Energy and Utilities Board on deemed common equity of 35%. In March, TransCanada reached a settlement with shippers and other interested parties with respect to the annual revenue requirements of the Alberta System for the years 2005, 2006, and 2007. The settlement encompasses all elements of the Alberta System revenue requirements including OM&A costs, return on equity, depreciation, and income, and municipal taxes.

In the settlement, OM&A costs are fixed at $193 million for 2005, $201 million for 2006, and $207 million for 2007; any variance between actual OM&A and those agreed to in the settlement for each year accrue to TransCanada. The majority of the other cost elements will be treated on a flow-through basis. The return on equity capital will be calculated annually during the terms of settlement using the generic UB rate of return formula on deemed common equity of 35%. TransCanada has applied for the UB for approval of the settlement and is currently waiting their decision.

Turning now to the Canadian Mainline, first quarter earnings of $53 million were $1 million lower than last year. The decrease is primarily due to lower return on common equity and a lower average investment base, which is partially offset by negative -- by a negative earnings adjustment of $2 million , which was recorded in the first quarter 2004. In March, TransCanada also filed an application with the NEB for the approval of a negotiated settlement with respect to 2005 Canadian Mainline Tolls.

This one-year settlement is essential based on the same framework I just highlighted poor the Alberta System. OM&A costs are fixed at $169.5 million with variances between actual OM&A costs in 2005, and those agreed to in the settlement accruing to TransCanada.

The ROE is set at 9.46% and the deemed common equity component of the Canandian Mainline Capital Structure in 2005 will be based on the NEB's decision on the Canadian Mainline Cost of Capital for 2004 subject to the outcome of any review applications or appeals. In early April, the NEB approved a negotiated settlement as filed. The NEB's decision on the Canadian's Mainline cost of capital for 2004 is expected this afternoon at 4:00 p.m. Calgary time.

For the first quarter, the Canadian Mainline's reported net income was based on a capital structure of 33%. Finally, with respect to our gas transmission segment, TransCanada's share of net earnings from other gas transmission, excluding the gain related to the TC Pipelines LP was $33 million for the three months ended March 31st, 2005, which compares to $37 million for the same period in 2004.

The $4 million decrease was primarily due to lower earnings from Great Lakes and Iroquois, partially offset by higher contributions from Cross-Valdez. The lower contribution from Great Lakes was due to lower short-term revenues and higher operating and maintenance costs. The contribution from Iroquois declined primarily as a result of a $2 million positive tax adjustment recorded in the first quarter of 2004.

Now I'll talk about power. Before I review the power results, I would like to highlight that in the first quarter report we've enhanced our disclosure of the company's power business -- providing additional information related to the financial results and sales volumes of our eastern and western operations. The information can be found on page 5 through 7 of our quarterly report.

In the interest of time, my comments will provide a high-level summary of our quarter over quarter performance rather than a detailed analysis of each of the individual line items. If you have specific questions on a particular line item, I would encourage you to contact David Moneta, our Director of Investor Relations. We welcome your comments on the additional information.

In the first quarter, the power business contributed net earnings of $30 million compared to $65 million last year. The decrease resulted mainly from lower operating and other income in the eastern operations and in Bruce Power. Total volume sold in the first quarter of 2005 were 7,748 gigawatt hours compared to 7,589 gigawatt hours in the same period of 2004.

Eastern operations contributed operating and other income of $5 million in the first quarter compared to $34 million in the same quarter last year. A $29 million decrease was partly due to the sale of the Curtis-Palmer Hydro-electric Facilities in the TransCanada Power LP in April 2004, which resulted in a $12 million pre-tax reduction in income.

Also contributing to the decline was a one-time $16 million pretax contract restructuring payment made by Ocean State Power to its natural gas fuel suppliers. Late in the first quarter, OSP concluded negotiations with its fuel suppliers and terminated the 20-year gas purchase contracts, which were due to expire in 2011.

Pricing under the terminated contracts had been subject to a number of arbitration proceedings since late 2001, and as highlighted in our 2004 third quarter and annual reports, the latest arbitration decision had substantially increased OSP's costs of natural gas to a price that was in excess of market prices. New contracts were entered into with the existing natural gas suppliers and agreed-upon price based on market-pricing mechanisms, which is not subject to future arbitration proceedings. The new contracts became effective in March and expire in October of 2008.

As part of these arrangements, payments of $16 million were made to the natural gas suppliers. Although this had a negative impact on the results for the quarter, we view the new gas supply arrangements as a positive debt for the future of OSP. Bruce Power contributed $30 million of pre-tax equity income in the first quarter of 2005 compared to $48 million last year.

Effective March 1st, 2004, Bruce Power moved from a five-unit operation to a six-unit operation with the commercial start-up of Unit 3. Planned maintenance outages on Unit 3 and Unit 4 in the first quarter of this year reduced the otherwise potential increases in planned output as a result of adding the sixth unit.

At the same time, Bruce Power experienced higher operating expenses including depreciation in the first quarter 2005 as a result of adding Unit 3. The decrease in Bruce power's equity income reflects this increase in operating expenses, which was partially offset by a 3% increase in total plant output and a slightly higher realized prices.

TransCanada's share of power output from Bruce Power was 2,598 gigawatt hours compared to 2,530 gigawatt hours last year. The Bruce units ran at an average availability of 81% during the first quarter compared to 80% in the same period last year.

Overall prices during the first quarter were approximately $50 per megawatt hour compared to an average realized price of $49 per megawatt hour in the first quarter of 2004. Approximately 50% of the output was sold into Ontario's wholesale spot market in the first quarter with the remainder being sold under long-term contracts.

On a per unit basis, operating costs were $38 per megawatt hour in the first quarter of 2005 -- compared to $31 per megawatt hour in the first quarter of last year. The increase is partly due to increased outage costs associated with the planned maintenance on Units 3 and 4. Also contributing to the increase is higher staff and lease costs in the first quarter 2005, which reflect the move to a six-unit site.

In addition the completion of Unit 3 re-start in early 2004 has resulted in higher depreciation and lower capitalization of labor and other in-house costs in the first quarter of this year. 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. Through reduced exposure to spot market prices, Bruce Power has entered into fixed-price sales contracts for approximately 40% of the planned output for the remainder of 2005.

Overall, plant availability in 2005 is now expected to be approximately 83 % or 2% less than we previously anticipated. This decrease is primarily due to an unplanned outage at Unit 6 as a result of a transformer fire that occurred on April 15th. Unit 6 is expected to return to service in late May; the costs to replace the damaged transformer are not expected to be significant.

Finally, in power, operating and other income from western operations was $30 million in the first quarter compared to $35 million in the first quarter last year. The decrease is primarily due to reduce margins in the first quarter of 2005, resulting from lower market heat rates on uncontracted volumes. Lower market heat rates are the result of spot market prices in Alberta that average approximately $3 per megawatt hour less and an average natural gas price that was slightly higher in the first quarter compared to 2004.

A significant portion of plant generation, a significant portion of plant generation in our western operation is sold under long-term contract to mitigate price risk. However, some output is intentionally not committed under long-term contract to assist in managing Power's overall portfolio of generation.

This approach to portfolio management assists in minimizing costs in situations where TransCanada would otherwise have to purchase power in the open market to fulfill its contractual obligations. In the first quarter of 2005, approximately 84% of the western Power sales' volumes were sold under contracts. The remaining 16% was sold into the spot market.

Next, I'll talk about the corporate segment. Net expenses were $9 million and nil for the three months ended March 31st, 2005 and 2004, respectively. The $9 million increase in net expenses is primarily due to increased interest expense on debt that was issued in 2004 and the receipt of a $12 million income tax refund and related interest in the first quarter of 2004.

Now, turning to our cash flow statements and our balance sheet. Funds generated from continuing operations were $407 million for the three months ended March 31st, 2005, compared to $415 million for the same period in 2004. Capital expenditures in the first quarter were $108 million and related primarily to the construction of the [inaudible] power plant and maintenance and capacity capital in the gas transmission business.

Our balance sheet remains strong. It consists of 58% debt, 3% preferred securities, 2% preferred shares and 37% common equity. To summarize, the company's net earnings and cash flow combined with the strong balance sheet continues 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 to make profitable investments in natural gas transmission and power.

We will continue to focus on operational excellence with a focus on providing low-cost, reliable service to our customers, and we will continue to maintain a strong financial position. Successful execution of these strategies has and will continue to deliver value for our shareholders. That concludes my prepared remarks, and I will now turn the call back over to Dave Moneta.

Thanks, Russ. Before I turn the call back over to the conference coordinator, just a reminder that as part of the question-and-answer period, we'll accept questions from the investment community first, and following that, we will open it up to the media. With that, I will turn it over to the conference coordinator.

Thank you, Mr. Moneta. We'll now take questions from the telephone lines. If you have any questions please, press star 1 on your telephone key pad. If you are using a speakerphone, please lift the handset and then press star 1.

If anytime you wish to cancel your question, please press star 1 at this time if you have a question. There will be a brief pause as the participatants register for questions. Thanks for your patience. First question is from Linda Ezergailis from TD Newcrest. Please go ahead.

Thanks you. Before I get to my real questions, a very quick administrative question. Would it be at all possible to get historical either quarterly or annual disclosure in your power segment, kind of like what you've given us today just to help us trend prospectively? I really appreciate the heightened disclosure.

I think it will be, Linda. I'll be working with Lee here just to get the quarterly numbers together for you for Q2 through Q4 of 2004, so hopefully we'll be able to provide that to you and everybody else in the investment community in the not-too-distant future on a similar basis here.

Thanks, David. Now, with respect to the McKenzie Pipeline, just wondering how much money you've lent to the Aboriginal Pipeline Group to date in 2005 on top of the $60 million to date at the end of 2004. And also originally, I believe, the cost estimate for pre-development costs for the APG was $80 million, and then it increased to $90 million. I'm wondering if there's any further increase given that the pre-development phase might be lengthened.

Linda. [inaudible] I'll deal with the first part. As you know, there was about $60 million at the end of last year. At the end of March 2005. That number was pretty chose to seventy. I think that Hal will deal with the rest of the question.

Linda, the aggregate expenditures on the pre-development costs are driven largely by time, and this is part of our decision to curtail project spending and to really cut back on nonessential things and just hope to this expenditure activities on the regulatory process and on efforts with the federal government to come up with a land access arrangement that is a bit more workable than what we've been dealing with, so we're trying to be prudent here.

We want to continue to spend the money that will enable the project to go ahead sooner rather than later, but we're definitely pulling back on exactly that kind of expenditure. Initially, the number was $80 million, then it was $90 million, and I think it's safe to think that it's probably a little bit higher than that now.

It's not double that or anything, but it continues to inch up as the passage of time goes by, and we're not about to give a prediction because frankly we just don't know what duration it is going to take to get through this current phase; if we're able to work out workable land access arrangements with the Federal Government, then I think we'd be in a better position to decide on spending in coming periods.

Okay. Another quick question. Now you're the holder of some PPAs in Alberta, and I'm wondering if you've done any work either internally or externally with your other stakeholders to try to converge to some sort of order-of-magnitude cost estimate and scope estimate as to what it would take to comply with some of the mercury reduction and other emission standards that are going to be introduced later on this decade.

Linda, we've done a lot of work on that. We're certainly aware of the issue, and we've studied it in a significant amount of technical detail.

The interesting arrangement there is that in most of those PPAs [inaudible] are held with the operator, and they would have the right to make prudent expenditures to comply with those things and flow those prudently incurred costs through to the PPA holder, and then the PPA holder would have to decide whether or not to carry on with that PPA or if the costs were onerous to push the PPA back essentially at the end of the day on this problems.

And then, have you put any thought to maybe mitigating some of that exposure and being pre-emptive by buying any sort of emissions credits or getting involved in that sort of activity?

No, I feel quite strongly that those kinds of things are not a good bet. We don't know what the rules will be going forward; we don't know whether credits that you buy today are going to be considered valid down the road; we don't know whether regulatory legislation would allow for that sort of thing, so in general,TransCanada shies away from that.

We have purchased some credits in the CO2 world just to learn and get a little bit more of an inside perspective on how that would work, but whether it's on mercury emissions or noxious [oxs] or CO2, we don't purchase credits until the time at which we would need them.

And the last question, then I'll jump into the queue. Point Lapro. Can you give us an update on timelines or what the status is or are we just waiting for the New Brunswick government to make a decision or what's going on there?

We're waiting on that certainly, and there's discussions on-going between the Bruce team and the New Brunswick government, and it's a very difficult decision for everyone to decide what's the right course of action with respect to a reactor that needs work done on it, but on the other hand, would require huge expenditure to decommission it. So one way or another, Point Lapro needs some significant investment, and we hope that our proposal has some appeal to the government.

Great, thanks so much

Thank you, Linda.

Thank you. The following question is from Sam Kanes of Scotia Capital.

The question is to you, Russ. You recall that in the last quarter you were mentioning some form of amoritization gain that's temporary with respect to GTN. Can you refresh us what on what amount was taken in Q1 and what the issue was and was it significant?

I'll let Lee answer the question as he has the exact numbers.

I think that was probably actually me Sam that mentioned that. This relates to the acquisition of the private acquisition when you fair value all the assets and liabilities.

We fair valued the debt of GTN that,a fair portion of that was coming due June 1st, so that amortization is what we were referring to of that fair-value adjustment. There's probably $4 or 5 million in the first quarter related to that, and again, it expires June 1st that amoritization.

Okay, I'll just ask one more and get back in the queue. Operating cost on Bruce. We're all curious if anything has changed in your opinion going forward here.

Nothing. Sort of similar to what we talked about in the last quarter last year that where the costs are today is about where we would expect them to land for the balance of the year.

Thanks.

Thank you. The following question is from Winfried Fruehauf of National Bank Financial. Please go ahead.

Thank you. Is the $23 million of income contribution from [inaudible] Baja Pipeline a reasonable indication of an annualized number?

With the exception, Win, of the amount that Lee just referred to here, the amortization of the reclassification or the way we classified the debt.

And regarding Ocean State Power, could you please explain why this station operating only at partial capacity for most of this year will not impact operating income, and I assume net income significantly?

I'm not sure -- you're referring to in terms of not impacting net income. For the most part, I would say that OSP now acts as a peaking facility, and it back-stops the capacity of our marketing effort, so the amount it runs doesn't necessarily correlate to net income.

Is the way that it operates to provide a capacity back stop if it's cheaper for to us buy power in the market to fill our contractual commitments we do that, so it's load factor I guess, what I'm saying you can't really have -- there's no correlation between the load factor and the profitability of our eastern business.

To the extent you have to acquire electricity in the open market in order to serve peeking loads or so , just how do you go about dove-tailing these two activities so that you know exactly how much you have to purchase and how much you can afford to purchase? To pay yourself on your purchases.

If I understand what you're saying, basically we run a portfolio of sales, and we have a portfolio of supply, which is now augmented by the USGen acquisition, so OSP plays a role in that it gives us the capacity backstop for making those sales, so the energy comes from the production at the USGen facilities and purchases from other facilities in the portfolio, so basically just running a buy and sell book of which on the supply side we own the bulk of the energy generation, and we have capacity backstop to be able to participate in the marketplace.

Regarding the carrying cost of the advances you have made to the APG, what would that be assuming say $90 million or so on an annualized basis pretax?

If you were to assume the carrying cost on that?

Yes.

I guess you could use that for incremental debt rate would be one way to look at it , which is probably in the neighborhood of 2 or 3% after tax, or you could look at, you know, an all-in average cost of debt of somewhere probably around 7, 8%, 6, 7%, something that looks like that.

Pretax.

Pretax. You could use our current capital structure to calculate the carrying cost if you want to sort of know a full debt-equity type carrying cost on an average debt cost basis.

Win, it's Hal here. The arrangement is if the project goes ahead, we're entitled to recover the full amount of advances plus the accumulated carrying cost on that. It's the bad outcome for us is if we continue to spend significant amounts of money, and at the end of the day, the project hits a brick wall and doesn't go ahead at all. That's the only scenario under which we don't get a good rate of return on that money.

That's my understanding, too, and I had been using 6% pretax. That seems to be roughly in the range. And the other question I have is with respect to the accounting treatment of the expenditures that you have made and are making towards Bécancour and Cartier Wind. Are you capitalizing everything or are you capitalizing part of it, and if you do, what part?

For Cartier Wind and Bécancour; those projects are going forward and things have been approved; all costs related to that are being capitalized.

And before you actually had signed the contracts, you presumably had expensed your expenditures on these two projects, is that correct?

That would be correct until the point we capitalized them, yes.

Now that you have firm contracts, are you then reversing the expensing you had previously practiced and capitalizing them now?

No.

So whatever you have expensed that's gone? Yes. Thanks very much.

Thanks, Win.

Thank you. The following question is from Karen Taylor of BMO Nesbitt Burns. Please go ahead.

Thank you. Can we come back to some of the incremental disclosure? I guess maybe Russ or Lee, this is for you.

You indicated for the western operations we've got fixed-price contracts in '05 and '06. Can you tell me what percentage of planned production those fixed-price contracts are, and then what the average price realized or contracted is for each region for each year? And then I have a follow-up question as well.

I'll take the first part of that. I think your question was what percentage of planned -- I don't actually have that with me, Karen.

We had decided we would actually disclose the amount of forward contracts that we had in place from a gigawatt for the remainder of '05 and '06. I actually just don't have those percentages in front of me because we have the disclosure done, so something we'll have to get back to you on that one.

So, I'll follow up with David after the call.

Yes as part of that, I'll probably to have assume Karen the sort of targeted availability of Sundance A and B Plant and some anticipated capacity factor for the Cogen plants, and then based upon that, we can work out what the percentage of planned output if you will.

Yep. That's fine. And then the prices.

Is that, can you ask the question on price again, Karen?

What's the average realized price on the forward sales for each of the two years for each of the two regions.

And again, I think on prices we haven't disclosed what the prices are.

Okay. Well, then, let me ask the follow-up question. So, we've seen a systematic decline in the operating margin from the conventional side over the last few years and you sold some plants to the L P to fund GTN and so on, but the operating performance here is not particularly strong, so can you tell me whether the planned capacities that will be coming on through the end of '05 and forecast will reverse this observed trend where we're actually realizing less margin, less revenue, and the cost of the segment continue to increase as well?

So first quarter '05, excluding Bruce, other costs and expenses were 116 million versus 81 million, $22 a megawatt hour versus 16. So where are we going to make up this performance going forward?

You're looking at the segment as a whole now, Karen, the entire power segment?

The entire power segment. My question to you is, unless, we seem to have a very small amount that's uncontracted, 5% in the eastern zone, 16% in the western zone, and yet we see a continued depreciation or reduction in operating margins for the group, so I'm just curious to know whether or not this is going to be reversed in '05 for the latter part of the year and whether the projects you plan to add will offset any reduction in price that you've got structured in these contracts.

I think the other thing is that the -- as -- we keep contracted on a prompt basis at that high level, I think in the west we said 85% or so, but as prices have declined, we have a time lag to that, so our revenues will continue to decline, so if power prices reverse over time, we will see our revenues will increase as well.

With respect to the addition of new facilities, yes that will help, I guess, reverse the decline in the eastern segment for example the addition of USGen, if you look at, as we move into the next quarter in the eastern operations, Curtis Palmer is gone, the one-time items on OSP shouldn't be there. We'll add USGen which should help prop that -- the profitability of that unit back up again. The west has been fairly stable, and I think with respect to Bruce, for example, I think we've told you where --.

I'm okay with that.

Slightly less, so on an aggregate, those are the three major pieces, and so I think you can look to some of the new additions that we've made helping out and that's mostly in the east, and it's the USGen assets that should help that out.

One question. I know that, up, you've got the Bruce A Units One and Two, I'm almost reticent to ask this question. Maybe this is more of a philosophical question for Hal.

Hal, when does the company plan to start building and establishing shareholder expectations about timelines, costs, and performance metrics on this particular endeavor and starting to lay out for shareholders just what types of risks you as a company are prepared to take and where you're looking to mitigate and lay off those risks and at what costs as well, and when is that process going to begin?

Certainly, Karen, we would never get into those kinds of discussions while we're still in negotiations with the counter party with the Ontario government.

I appreciate that.

Obviously. So, once a deal is in place, and once we understand these kinds of things, you know, in terms of the final terms that have been agreed with the government, I think it's reasonable that we would talk a little bit more about it. As to ...

I'm sorry to interrupt, but do you have a time when that is likely to occur?

We don't have any deadline or target date or specific expectation as to when we are going to conclude those negotiations. All we know is that the province of Ontario needs significant incremental quantities of power.

We have put a proposal in there. We continue to negotiate it , and we'll learn in due course, but we've learned that pushing these kinds of ropes is not productive.

Karen, maybe I can add to that, too. With respect to I guess informing shareholders of the type of investment that we would be willing to undertake; the way we look at Bruce 1 and 2 restart is no different than any other project we look at. The major items of risk we look at is revenue risk, construction costs risk, then operating costs risk. Those are your major cash flow items. And we're approaching this in exactly the same way as we approach any other investment.

We're obviously very concerned about the revenue and the volatility that exists in the Ontario market and looking for some protection or parameters around that. With respect to construction costs, analyzing in great detail what those costs are, and looking for various ways to lay off that risk to construction contractors and those kinds of things.

Similarly, on the operating cost side of things is our understanding what those operating costs are and how we're going to contain those and mitigate those. So our approach on this project is identical to the way TransCanada approaches other projects, and that's I guess what we would hope that shareholders would expect from us is that we would bring that same prudent disciplined investment process to Bruce Power and that is the process we've been using.

One very last quick question since we'll come back to how you look at investments. Do we expect any cash at all from Bruce this year or is that post 2006 event from the existing six reactors?

I think that this year -- with the Unit Six fire. I'm not sure about getting cash this year. I'd say after the restart of 2006, you could probably expect some net cash generation. As I said before, we are for generating the cash, but we are re-deploying the cash back into enhancements and upgrades at the facility today. And in the current model, it would be sort of 2006 or some in 2005 depending on how the year turns out in prices. With the One-Two restart , that forecast may change.

Thank you.

Thank you, Karen.

The following question is from Gabriel Hammond of Alerian Capital. Please go ahead.

Good afternoon. Could you tell us, do you consider your GP interest in [inaudible] a strategic focus, and if so, what your plans are in the future to maximize the value of that GP interest?

Can you ask that question again? This is with respect to our GP interest in the TC pipelines L P?

Exactly.

I would say that Hal will probably jump in as well -- it 's a very strategic investment for us. Our northern border is a very important corridor. It's connected to our pipeline system in Canada. We deliver 100% of the volume into the north end that system at Manche.

An with respect to the sale of the units during the quarter is the financial investment that we had in the 30% unit didn't enhance our ability to maintain the interest in Northern Border Pipeline, so it was really capital that we could release is the units we sold for the most part were units that were subordinated at the time of the IPO, and that subordination expired in August of last year, and then there was a six-month wait period that we had to wait, which got us to about February , so at that point in time, our us holding the investment was of no longer any value to other unit holders because the subordination was gone.

Return on capital on those units was lower than a hurdle rate, and we have other places such as GTN to redeploy that capital back into, so that was the reason for selling the units, not that there was any change in our strategic intent with respect to Northern Border.

I'd just add to what Russ said, maintaining our significant influence over the way the is operated is extremely important to TransCanada, and it would be unthinkable to me that we would give up our position in that. I'd also point out that Tuscaroura, although a smaller aspect in that MLP, is much more significant to us today than it was before we acquired GTN. Now that we own the GTN connection, we have greater interest in what we might do to create value around the Tuscarora asset.

Let me come from maybe a little bit of a different angle. We've seen large energy companies such as Sunoca or Valero double the value of their MLP units in the last two years and presumably perhaps quadrupled or quintupled the value of the actual GP stakes they own. Kinder Morgan has obviously done quite well.

You mentioned Tuscarora, which is probably the single significant acquisition or investment that has been made at the TC LP level in the last five years. I'm just trying to get a better perspective for why it seems you are not been more focused on using the power of the structure and the access to the capital in that way as some of these other energy companies.

A lot of it depends on the prices being paid in the market for different assets and our determination that TC Pipe L P is going to be absolutely blue chip and is going to hold only pipes that make strategic sense and that fit well with our overall footprint. We're no more inclined to go all over the place and buy assets willy-nilly in TC Pipe LP than we are within TransCanada. We try to manage our holdings in that LP with the same degree of rigor that we would apply to a direct investment by TransCanada.

Frankly, there's a lot of assets that have been traded hands and have been put into MLPs that we would not be interested in. We admire people who manage to double the value of these different interests, but I would point out that TC Pipe LP trades at a very low cash on cash yield. It's considered to be one of the blue chip entities in the sector, and that's exactly the way we would want it.

Thank you.

Thank you. The following question is from Matthew Akman from CIBC World Market. Please go ahead.

Russ, question for you on Ocean State. Wonder if you could try as simply as possible to explain the economics of the power plant going forward now that you've renegotiated the contract.

Simply that's probably a hard thing to do, but I'll do my best, Matthew. It basically fits in the portfolio, as I said, we have a number of energy sales and in order to make energy sales in that marketplace, you have to have a certain amount of capacity backstop as well as we go forward, and we start to see that the overbuild dissipates, and the value of capacity gains start to rise in that market there's been some structural changes proposed in that marketplace to ensure that as the supply demand, the oversupply balances itself out, that there will be a market price signal for capacity in the marketplace again, so it really has two roles in that portfolio.

The first is as a capacity back stop for energy sales. Secondly, you know, its value as capacity going forward. As we said before we have about $150 million of capital still on the books on that asset, and we would expect to make a decent return on that asset from those revenue sources that I mentioned. So we don't actually attribute revenues directly to OSP on either an energy or capacity basis. It's part of our portfolio, so you have all the revenues.

In our new disclosure, the way we've tried to break that out is we've shown what you the sales are on firm basis, sales are on a spot basis, so you can see sort of what the portfolio of sales are and then the portfolio of supply that's used to fill that market. So that's sort of where OSP is. It is historically it was a large part of the portfolio, I would say on a go-forward base given the introduction of the USGen asset it's going to be a smaller and smaller portion of the portfolio, but we do hope to make a decent return on the capital that we have deployed, or we'll do something else with the asset.

Is the plant uneconomic right now from a heat-rate perspective in that market?

I would say, again, if you looked at it on straight energy, it probably doesn't run enough, but it has capacity value. So, it does generate sufficient revenues on both capacity and energy basis to give us a decent return on investment.

So let me ask another way. You've finished this deal on it at the end of Q1, so putting aside the unusual items in Q1, looking forward, will there be an improvement do you think starting Q2 of this year in the earnings contribution from that asset? Putting aside the one-time items.

I think, as I said, if you add that asset to the whole portfolio and the introduction of USGen as of April 1, you will see an improvement in that -- in the eastern segment going forward.

Okay. Let me just shift gears quickly to a different topic, which is back to GTN. I know that there's been -- it was disclosed there was a restructuring program that was implemented in February, so that was in Q1. I'm just wondering whether there were any restructuring costs or charges taken on GTN in Q1.

The last part of that question again?

Were there any restructuring charges taken at GTN in Q1 of this year?

Not significant. I think -- the thing to remember here, Matthew, on the TransCanada level on the acquisition, we would have made certain assumptions with regard to cost of transition. There were some costs that may show up on the GTN books in first quarter that you will see in the 10-Q, but those will not end up in a consolidated books. From TransCanada perspective, they are very minimal.

Okay. Thanks. I'll move on.

Thanks, Matthew.

Thank you.The following question is from Andrew Kuske of UBS.

Thank you. Good afternoon. Hal, if you could give us some context on your view on the Ontero power market, in particular, your Portland proposal, the recent RFP results that were announced by the government and then just your ongoing negotiations with the government on the Bruce, any color you can provide on that specific point.

Andrew, I have to be a little bit careful here because under the Portland's proposals we're required to not say very much about them until they're finally awarded or not awarded by the government, and so need needless to say, that our Portland proposal has not yet been dealt with by the government, and we remain hopeful that one way or another we'll be able to reach an agreement there.

I just would note that in the Ontario marketplace there is no location that needs incremental power gen capacity more than the urban hub of downtown Toronto. That is a particularly difficulty place to get incremental power to and the Portland project not only generates power right in the center of that urban marketplace, but it is also provides both support and other things back into the rest of the power coming into the city. So we think it's a highly desirable project.

We're a little bit frustrated that some of our opponents have tried to characterize it as a highly inefficient, undesirable combined cycle plant as compared to a much more desirable cogeneration project. The fact of the matter is that the design of Portlands is very efficient and whether the secondary cycle is cogen with some heat user downtown or whether we use it in a secondary cycle of a combined cycle plant, there's not very much difference between the two, so we think those objections that have been raised to it will be better understood by people here over next month, and we would expect that that opposition would go away. There will always be opposition to projects like Portland from people who just don't want projects like that to be built by anyone anywhere, and we need to deal with that.

But we've had many good discussions, you know, Andrew, we've been at this project for years and years. This isn't something we just cooked up here in the last couple of years, and it's always been a series of trade-offs that are needed to make that project go ahead, and that's what we're faced with right now. So, we are absolutely convinced that Portlands is a project that would be very beneficial to the power markets in Ontario.

We understand that the Ontario government is chosen to select some projects in Sarnia rather than ones in downtown Toronto. And so be it. We'll continue to work with them and answer any questions they may have and hope in that due course this project, which is very beneficial, will be able to go ahead.

So you don't see the see the selection of the project in Sarnia really precluding the Portland project?

Not at all. They solve two very different problems. The Sarnia Projects do not solve power gen problems -- or power supply problems in the urban area of Toronto. It's my understanding that the transmission capacity from the Sarnia area towards Ontario is inadequate to handle both these new gas-fired plants and the existing Lampton Coal Plants. So I don't think that you can see those Sarnia plants as being built to solve any problems in Toronto.

And you feel relatively competitive versus the projects that have been proposed in [Miscesaga] and [Grandville].

Well, particularly when you consider the added urban supply benefit of the Portlands Project. There's no question that Portlands is a more expensive project than if you were building that same amount of capacity at North Bay or something like that. Trying to do a project of that magnitude in an urban area is always going to be more expensive, but according to our analysis, the economic benefits of building that complex project in the middle of the urban area far outweigh the incremental costs, so we think the value is superior.

If I may shift questions -- shift gears on one question regarding [inaudible] -- what do you see as the appropriate rate of return on that proposed crude line?

Well, it should be in a rate of return that's attractive to an investor in that kind of pipeline.

Why? I can appreciate that, but I ask that question in the context of if you look at crude returns for certain pipeline players that have been 14 to 15% return on equity, your natural gas returns have been 9.5 in really the current year, do you see a collapsing of that delta?

Well, I think what we would see is for that kind of an oil pipeline, it would it certainly be a higher return on equity probably on thicker equity than what you typically run across on our Canadian gas pipelines, but the interesting issue there, Andrew, is that it much depends on the length of contractual term that we get out of shippers, and that we certainly be looking for a higher rate of return and a less risky capital structure if we were shipping primarily on short -term contracts than if we were able to get long-term commitments.

But that is historically a month-to-month nomination business.

Well it is and it isn't. On some pipelines, I'd say I'd acknowledge that on the majority of crude oil pipelines in North America it is a month-to-month nomination business underpinned largely by the fact that the oil producers and the oil refiners have no other way of getting their crude oil from oil field to refinery. But there are pipelines that are underpinned by longer term contracts, and those would generally attract a lower cost of capital.

So all this remains to be seen. I'm not really able to give you much guidance as to where we're going to come out on that yet. We're still going through the process, and we will still be going through the process of nominations and open seasons and discussions with potential shippers for much of the rest of this year.

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

Thank you. The following question is from Dominique Barker of Credit Suisse First Boston. Please go ahead.

Good afternoon. There was an increase in the mainline utilization, I think 82% from 76% last quarter. I just wanted to get your views on, you know, to what would you attribute that increased utilization and also saw there was an increased utilization on the Alberta system.

There's a little bit of extra gas in western Canada. We don't think it's meaningful enough to declare that a new rising trend has kicked off, but it's good to see a little bit of extra gas. Certainly, not only has there been record drilling in Alberta for two or three years now, but in more recent quarters, we've seen accelerated connection activity, more wells, and plants being connected to the system.

But I would -- I think the numbers would show you that most of the increased flow on the mainline is due to reduced flow on other pipelines. It's not a net increase in production out of western Canada.

Is that because it's more competitive?

Mostly it's because at different times of the year, and in different circumstances, people need more or less gas in southern Ontario, Quebec, New York, and New England. We will see, for example, the winter, when it's very cold in January that we'll have very high flows through northern Ontario because that's the most effective, most economical way to get volumes of gas to Toronto and Montreal, and then that will cause reduced flow rate on Great Lakes, then in other times of the year that will flip around.

Okay. So I guess bottom line is that is that reversal in trend sustainable, or are you saying it was a one-off due to some demand in eastern Canada?

No, I think you've seen that from month-to-month and quarter-to-quarter occur several times over the last three or four years, and we regard these as shorter-term market effects rather than any change in the trend. But I'd say that one thing we're very happy about, Dominique, is that the collapse in floor rates on the mainline that look to be a trend has proven not to be quite such a trend, and we're actually very comforted to see that there is some bouncing up and down. We were quite worried back in year 2000 that we were facing a period of sustained reductions year-over-year. That, in fact, has not happened.

Thank you very much.

Thank you. Once again, analysts may press star 1 for any questions or comments. The following question is from Maureen Howe of RBC Capital Markets. Please go ahead.

Thanks very much. With respect to the Ocean State, the new gas purchase contract on that facility, or associated with the facility, it extends -- says it expires in October 2008. Is it for 75 million cubic feet a day as well ?

It's actually for a full hundred-- We settled with both gas producers. There's two gas suppliers, and we settled them both for 100 million cubic feet a day.

And it says that it's at an agreed -upon price based upon market. Is it market or is it --.

It's market index.

Okay. And then also just with respect to Cross Alta; there was a good earnings contribution there associated with storage. Is that something that is sustainable? Is it something that's going to be extremely variable going forward? Can you give us a little flavor or insight into the drivers of those numbers?

Maureen, this is Hal here. It's very much driven by winter-summer spreads, or any season-to-season spread when there's a very large spread in prices between summer and winter evident in the forward markets, people will be obviously motivated to put gas into storage, and the profitability of Cross Alta is very much a function of just how wide those spreads are.

So it tends to be a bit bumpy. We don't see a trend quarter-over-quarter, year-over-year that we can use to predict that this thing is going to get a lot better or get a lot worse; we do think that Cross Alta is a very good asset. We've had a pretty good experience in terms of earnings with Cross Alta over the past five years, and we're pleased to see that 2005 looks like it's starting off as a good storage year; obviously, that's important to us as we have taken out that additional lease on capacity here in Alberta, and we're going ahead with the development of Edson.

We think the storage business is quite an interesting business in Alberta as long as there's spare capacity from Alberta in the pipelines to consuming markets. If there's no spare capacity, then the Alberta storage game tends to get disconnected from the continent, and it's no -- it's not rewarding under that scenario.

And I realize, so okay, its function, the profitability is a function of the winter-summer spread, so this might be a bit of a difficult question, but would you say that a contribution during the quarter to TransCanada $5 million, is that the upside, or could we expect higher earnings in certain quarters?

I think we've seen before it. Close to that. But does it move around. Certainly, Maureen, I would say that for Cross Alta that's a pretty good outcome.

That's a strong quarter.

That's a good quarter. What's interesting is whether we can expand that kind of profitability by increasing our storage-volume capacity. We hope we can, but we may not be exactly proportional to that. I think that's a pretty good result.

Okay. With respect to the GTN, I know you've addressed this a couple of times, but I just want to clarify. For this next quarter, would we expect to see GTN book two-thirds of the amortization?

Probably closer to a half, Maureen.

More like a half? Okay. And then just finally with respect to costs, capitalized costs associated with the McKenzie Valley Pipeline, can you tell us where the company stands on that?

We're essential capitalizing them now. We have an agreement with the Aboriginal Pipeline Group. And as long as we think there's a solid expectation that the project is going to go ahead, we continue to do that.

Well I guess I'm referring not to the costs that we were previously referred in terms of capital extended to the APG, but more with respect to your own development costs, or did those numbers actually include that?

No, they don't, but they're not significant. We don't have a working interest directly in the projects right now.

They just get -- our internal costs just get expensed.

They're just getting expensed.

And they're very minor.

Maureen, I would point out that we have contributed significant TransCanada horsepower to the project in terms of people that are [inaudible] to the project, and we get paid by the project.

And I think the difference between the APG cost as Hal pointed out earlier in the call, the contractual agreement is that we will recover those costs in addition to the carrying costs as part of the rate base of the investment once -- if and when it goes forward. So that's the reason for capitalizing those costs.

Right. That's great. Thank you very much for those answers.

Thanks, Maureen.

Thank you. The following question is from Brian Purdy of First Energy Capital. Please go ahead.

Hi, guys. I just wanted to ask a question about mainline volumes longer term. I believe in the AGM presentation today you indicated that you were fairly comfortable with volume from the western Canadian sedementary basin, even post-2010, and that it would support your mainline volumes absent any Alaskan or McKenzie gas, but your presentation on Alaska a few weeks ago you seemed a bit more concerned about declines post-2010. So, I was wondering if I get a clarification there.

Sure, I think if you go back and listen to the transcript from this morning that's not exactly what I said. If it comes across that way, it's not what I meant to say.

What I was saying was that we're quite comfortable post-2010 because it's our view that the North American market is absolutely going to need the gas from the McKenzie and from Alaska, and therefore, we're quite comfortable that we will be able to sustain the mainline long-term and, you know, in the follow-up press conference, I was asked a similar question, and I mentioned that we can keep a very close eye on these things, and if we start to get the sense that the northern projects are moving very slowly and that the consumption of gas in Alberta is growing at the Tar Sands or elsewhere and that western Canada production is flat, then we have the ability through the National Energy Board mechanism to accelerate depreciation, aka capital recovery, on the mainline, and those are the things we have to stay right on top of to make sure that we managed any stranded capital risk that might exist there.

Now, I'd go back to my opening position, which is that we think post -2010 there's a very high likelihood that the McKenzie and Alaska projects are going to go ahead, and they don't need to go ahead in 2010 or in 2012 or in 2014 to make it work for the main line. In fact, if they go ahead a little bit later, it actually makes it easier for us to integrate those volumes into our existing system because there will be a little bit more spare capacity. Having said that, it's very much in our economic best interest to have them go ahead sooner rather than later.

Okay. So even if the volumes come in 2015 or 2020, that sounds like that's fine. The only negative scenario would be if that LNG terminal perhaps went in up north and bypassed Alberta?

We think it the's a very negative scenario for Canada generally if the -- if the Americans...Alaskans were to convert all of their north slope gas to LNG and move it to world markets through Valdez. That would be a very unfortunate day for Canada because we would lose all the economic benefits of a $15-billion project that's being underpinned by the Alaskans.

So, we very much don't want to see that, but I would also -- this shouldn't be painted too much as a battle to the daft between LNG and an Alaskan Highway Pipeline. There are also scenarios where you could do both, and that may well end up being something in the future that has appeal to Alaska producers if they sent a base volume of [4 bcdF] down the highway pipeline and some incremental volume went to LNG that would give them more market options, and I don't know that might be attractive to them.

Okay great, thanks very much.

This concludes the financial analyst question session. We'll now take questions from the media. Please press star 1at this time if you have a question. There are no further questions registered at this time. I would now like to turn the meeting back over to Mr. Moneta.

Thanks very much and I'd like to thank everybody out there for participating this afternoon. It's getting to be late on a Friday afternoon in the east, and we appreciate your interest in TransCanada. We'll talk to you soon. Bye for now.

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