TC Energy Corp (TRP) 2004 Q1 法說會逐字稿

Good afternoon, ladies and gentlemen. Welcome to the TransCanada Corporation 2004 first quarter results conference call.

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

Thanks very much. Good afternoon, everyone.

I would like to take this opportunity to welcome you this afternoon, including those who are joining us via the Internet. We are pleased to provide the investment community, the media and other interested parties with an opportunity to discuss our 2004 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 will begin this afternoon with some comments on our results and other general issues pertaining to TransCanada, and 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 begin, 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 that 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, and competitive factors in the pipeline and power industries, as well as 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 now turn the call over to Hal.

Thank you, David. Good afternoon, everyone and thank you for joining us today.

I touched on our 2003 and first quarter 2004 financial results, our strategy, and our outlook for the industry at TransCanada's annual meeting earlier this morning. I will therefore keep my remarks brief this afternoon.

For those of you who weren't able to attend the meeting this morning, or listen to the live web cast, the web cast will be archived on the World Wide Web at TransCanada.com. I'm pleased to report that TransCanada continues to deliver steady operating and financial performance.

Increasing North American demand for energy continues to support the long-term growth objectives we set for our core businesses, of natural gas transmission and power services. We are focused on continually improving our competitive position, within our industry, and positioning our company to deliver long-term growth and value creation. We are proud to be one of North America's leading energy companies.

For the first quarter of 2004, TransCanada Corporation's net income was $214 million, or 44 cents per share. Funds generated from operations for the first quarter 2004 were $423 million.

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

I will briefly review some of the key events over the past quarter and then I will turn the call over to Russ Girling for a more detailed review of our financial results.

In our gas transmission business, we continue to make progress through the bankruptcy court process related to our agreement to acquire Gas Transmission Northwest for $1.703 billion U.S., including U.S. dollars 500 million of assumed debt.

Gas transmission Northwest is a natural gas pipeline company that owns and operates two pipeline systems -- the GTN system formally known as Pacific Gas Transmission, or PGT, and the North Baja pipeline system. We expect to learn shortly whether there are any other formal bidders for the GTN pipeline and anticipate final bankruptcy court approval of the sale to be granted in the second quarter.

Should this transaction proceed, it would add a strategically significant connection from TransCanada’s system at the BC-Idaho border to the high demand markets of the Pacific Northwest, Nevada, and California. We expect the transaction to be accretive to both earnings and cash flow.

In northern development, TransCanada this week announced the signing of a memorandum of understanding with the state of Alaska. In that MOU, TransCanada has committed to file an application under the state Stranded Gas Development Act, and the state has agreed to resume processing of TransCanada's long pending application for a right-of-way lease for the project.

TransCanada has championed the development of an Alaska gas pipeline for more than two decades. The current strong outlook for natural gas prices provides an opportunity for Alaska Gas to become a significant supply source for North America within 10 years. We look forward to working with the state of Alaska and the Alaska north slope producers, to develop a workable and economically viable commercial arrangement for the shipment of Alaska Gas to the Alberta hub and then on to North America markets.

TransCanada will continue to lead the development of the Canadian portion of the project, and we will work with Alaska stake holders to develop the Alaska portion.

On the liquefied natural gas front we were naturally disappointed that residents of the town of Harpswell voted against leasing the former U.S. naval fuel depot site in their community for the purpose of building an LNG regasifiction facility.

TransCanada and Conoco Phillips subsequently announced that we will suspend further work in Harpswell, Maine on the Fairwinds LNG project. Despite the outcome of this vote, there remains a critical need for reliable new sources of natural gas in the northeastern United States. TransCanada remains committed to pursuing opportunities to deliver clean and safe LNG supply to the northeast United States and eastern Canada.

In Power, we announced in late March an agreement to sell the Curtis Palmer and ManChief facilities to TransCanada Power LP for $402 million U.S. This sale is consistent with our strategy of actively managing our asset portfolio to maintain TransCanada's strong financial position and strengthen our ability to pursue growth opportunities. Pending unit holder and regulatory approval, TransCanada expects to complete this transaction on or about May 5 of this year.

In regulatory matters, as indicated in my remarks earlier today, decisions by the Alberta Energy Utilities Board and the National Energy Board expected later this year will have an impact on our earnings from our Canadian regulated pipelines in the current year. Until hearings are completed and the regulators issue their decisions, we will base our earnings on interim polls.

On April 6 of 2004 we received the decision of the Federal Court of Appeals dismissing TransCanada's appeal of the National Energy Board's review and variance decision. While we're disappointed the court dismissed our appeal, the decision did provide important clarification around the role of customer and consumer interests, in the determination of our cost of capital.

Apart from the Court of Appeals decision, we remain challenged by the Canadian Regulatory Environment and its impact on our financial return. I would point out that TransCanada invested many billions of dollars during the 1990s to essentially double the capacity of our Canadian pipeline system to meet customer needs. Our financial returns were reduced fairly dramatically after we made the bulk of those investments. That is the source of our regulatory discontent.

TransCanada continues to pursue a fair return for its Canadian main line, through our 2004 tolls and tariffs application, filed in January 2004. Phase one of the two-phase public hearing to consider TransCanada's application to the NEB is expected to begin June 14 in Ottawa, Ontario, and will consider all issues raised by TransCanada's application, except for the cost of capital.

Procedures for phase two of the NEB hearing, which will address cost of capital, are expected to be announced at a later date. In early April, the Alberta Energy and Utilities Board began phase one of its hearings related to TransCanada's 2004 General Rate Application or GRA for the Alberta system.

Phase one of the GRA deals with the revenue requirement for the Alberta system, and hearings are expected to conclude in April, with a decision anticipated before the end of July. The GRA phase two hearing, dealing with rate design and service matters, is currently set for June 8.

Earlier today, I spoke about the need for new and more efficient energy infrastructure to fuel the needs of the growing North American economy. Demand for natural gas and power continues to grow. It is our intention to be positioned and ready to connect new sources of supply to meet that growing demand.

Over the past four years, TransCanada has successfully executed its strategy, and in the process, has built a reputation for disciplined strategic growth underpinned by prudent financial decision making. Developments in the first quarter underscore our commitment to long-term value creation, balanced against our objective of maintaining our strong financial position.

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

Thank you, Hal and good afternoon, everyone.

As Hal said, we are pleased to report another quarter of steady operating and financial performance. As reported earlier today, net income for the three months ended March 31, 2004, was $214 million, or 44 cents per share, compared to $208 million, or 43 cents per share for the same period last year.

The increase of $6 million, or 1 cent per share, was primarily due to lower net expenses in the corporate segment, as a result of income tax refunds, and that was partially offset by lower net earnings from the gas transmission business. I will review the first quarter results from each of our segments, beginning first with the gas transmission segment.

Gas transmission generated net earnings of $149 million for the first quarter, compared to $158 million last year. The lower contribution was primarily due to lower earnings from the Alberta system, and the Canadian mainline.

The Alberta system's first quarter net earnings were $40 million, $2 million less than the amount reported last year. The decrease is primarily due to a $204 million decline in the Alberta system's average investment base.

And earnings for the first quarter reflect the implicit return in the 2004 interim tolls approved by the Alberta Energy and Utilities Board in December of 2003. The interim tolls were based on the 2003 negotiated fixed revenue requirement of $1.277 billion, plus certain adjustments.

The settlement itself did not include an explicit rate of return on equity or capital structure. As such, first quarter 2004 earnings for the Alberta system approximate a return equivalent to a 10.9% return, on 32% deemed common equity, or alternatively, an 8.7% return on 40% deemed common equity.

The 32% deemed common equity is the last approved by the EUB, in the 1995 general rate application, and the 40% deemed common equity is the amount requested from the EUB in the current generic cost of capital proceeding. Earnings from the Alberta system will continue to be recorded based on the implicit return in the 2004 interim tolls, until the EUB renders its decision on the generic cost of capital proceeding.

As part of that proceeding, TransCanada has requested a return on equity of 11% on a deemed common equity component of 40%. The EUB expects to adopt a standardized approach to determining the rate of return and capital structure for all utilities under its jurisdiction and at the conclusion of the proceeding -- excuse me -- for all utilities under its jurisdiction at the conclusion of the proceeding. An EUB decision is expected in the third quarter.

EUB decisions on the Alberta system's generic rate application could also impact the 2004 earnings. Phase I of the application consists of evidence in support of the applied for rate base and revenue requirements.

The hearings to consider Phase I issues concluded on April 14 and final argument and reply argument are due by the end of May. A decision is expected in the third quarter. Phase II primarily deals with rate design and services, the hearing on this phase is scheduled to commence on June 8.

Now turning to the Canadian mainline -- first quarter net earnings of $64 million were $7 million lower than last year. The decrease is mainly due to the reduction in allowed rate of return on common equity from 9.79% in 2003 to 9.56% in 2004 and a $378 million decline in the average investment base.

The results for 2004 also include negative earnings adjustments of $2 million after tax, related to the overestimate of incentive program earnings in 2003. Foothills net earnings of $6 million in the first quarter are $2 million higher than last year, as a result of the acquisition in August, 2003, of the remaining ownership interest not previously held by TransCanada.

And finally, with respect to our gas transmission segment, TransCanada's share of net earnings from other gas transmission was $37 million in the quarter, compared to $39 million last year. The $2 million decrease was primarily due to lower earnings from CrossAlta. Higher U.S. dollar net earnings from U.S. pipelines in the first quarter of 2004 compared to the first quarter of 2003 were offset by unfavorable -- by the unfavorable impact of a weaker U.S. dollar.

Next, I will talk about Power. In the first quarter, the power business contributed net earnings of $65 million, compared to $63 million last year. Higher earnings from the Bruce Power LP and eastern operations were the primary reasons for the increase.

Partially offsetting the increase were lower earnings from the western operation and higher general, administrative and support costs. The total volume sold in the first quarter were 7,589 gigawatt hours, compared to 6,426 gigawatt hours last year.

Bruce Power contributed $48 million of pretax equity income, in the quarter compared to $38 million last year. The increase reflects TransCanada's ownership interest in Bruce Power, for the entire first quarter of 2004, compared to approximately six weeks of ownership in the first quarter of 2003.

In addition, Bruce Power's output was higher during the first quarter of 2004, as a result of the return to service of units three and four, which have increased Bruce Power's operating expense, and expanded capacity by approximately 1500 megawatts for the first quarter of 2003. Overall prices achieved during the first quarter were approximately $49 per megawatt hour, compared to an average realized price of $57 per megawatt hour in the first quarter of 2003.

Approximately 50% of the output was sold into Ontario's wholesale spot market in the quarter, with the remainder being sold under long-term contracts. To reduce exposure to spot market prices, Bruce Power has entered into fixed price sales contracts for approximately 45% of the planned output for the remainder of 2004.

On a per unit basis, operating costs increased to $31 per megawatt hour in the first quarter, up from $28 per megawatt hour in the first quarter last year, primarily due to lower availability. For the quarter, the Bruce units ran at an average availability of 80%, compared to an average availability of 100% during the six weeks TransCanada owned the facility in the first quarter of 2003.

The lower availability was due to a series of unplanned outages, including a maintenance outage at unit eight which began in the third quarter of 2003 and was extended to January 28, 2004 to repair support plates in three of the unit’s eight steam generators. In addition, although unit three began producing electricity on January 8, it was down approximately 50% of the time during the first two months of the year to perform maintenance on its heat transport system, and to repair a turbine bearing.

As a result, it was not considered commercially in service until March 1. However, during that time, Bruce Power completed additional work on unit three that had been planned for an outage later in the year, resulting in a cancellation of that planned outage later this year. A planned maintenance outage for the other Bruce A unit is scheduled for the second quarter and it’s expected to last for approximately five weeks.

In our eastern power operations, operating and other income for the first quarter was $34 million, compared to $25 million in the first quarter of 2003. The $9 million increase is mainly due to increased water flows at the Curtis Palmer hydro electric facility, higher net margin on power sales, and fees learned on the demobilization of the Coburg temporary generation facility in Ontario.

Partially offsetting the increase in earnings from Bruce Power and eastern operations, were lower earnings in the western operations. Operating and other income in western operations of $35 million was $8 million lower than the third quarter -- or than in the first quarter of 2003.

The decrease is mainly due to lower prices achieved on the sale of power in the first quarter of 2004, a lower contribution from the Manchief plant due to reduced dispatch levels and higher depreciation and lower transmission tariffs in the first quarter of 2003. The Power LP contributed $10 million, which is slightly less than the $11 million reported last year.

Before I move to the corporate segment, I will make a few comments on the sale of the Curtis Palmer and Manchief facilities to the TransCanada Power LP. On March 29, 2004, TransCanada entered into an agreement to sell these two facilities to the LP for $402.6 million U.S. TransCanada expects to recognize a gain of approximately $10 million after tax on the sale of those assets.

The partnership expects to fund the transaction through an offering of 8.11 million subscription receipts, which closed on April 15, 2004, and a bridge loan facility from a Canadian-chartered bank. As part of the offering, TransCanada purchased 540,000 units for an aggregate price of $20 million. Subsequent to the transaction being completed, TransCanada's ownership interest in the Power LP will be reduced to approximately 30.6% from 35.6% today.

The sale is subject to certain post-closing adjustments, regulatory approvals, and a unit holder approval. The special meeting of unit holders will be held April 29, 2004. The unit holders will be asked to approve an amendment to the partnership to remove the partnership's obligation to redeem all units not held by TransCanada in 2017.

As a result of the removal of the redemption obligation and the reduction in TransCanada's ownership upon closing, TransCanada expects to recognize a gain of approximately $165 million after tax in the second quarter. This amount primarily reflects the recognition of unamortized gains on previous Power LP transactions.

Next, I will talk about our corporate segment. Net expenses in the corporate segment were nil and $13 million for the three months ended March 31, 2004 and 2003, respectively. The $13 million decrease in net expenses is primarily due to income tax refunds received in the first quarter relating to prior years.

Turning to cash flow statement and to our balance sheet -- funds generated from operations, were $423 million for the three months ended March 31, 2004, compared to $457 million last year. The decrease was primarily due to higher current income taxes.

Capital expenditures, excluding acquisitions, for the first quarter were $101 million, and related primarily to the construction of two new power plants and the maintenance and capacity capital in the gas transmission business. Acquisitions for the three months ended March 31, 2004, were nil, compared to $409 million for the same period last year.

Our balance sheet also remains strong. It now consists of 59% debt, 4% preferred securities, 2% preferred shares and 35% common equity.

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 invest our discretionary cash flow and to make profitable investments in natural gas transmission and in power.

We will continue to work on establishing a new regulated business model that provides value to our customers, reduces our long-term risks, and allows us to earn a competitive return. We will continue to focus on operational excellence, with a focus of providing low cost, reliable service to our customers. We will continue to maintain a strong financial position and will not compromise our credit ratings. Successful execution of these strategies has and will continue to result in strong earnings and cash flow, and build value for our shareholders.

That concludes my prepared remarks and I will turn the call back to Dave.

Thanks very much, Russ. Before I turn it over to the conference coordinator, just a reminder that during the question-and-answer period, we will accept questions from the investment community first, followed by questions from the media. With that, I will turn it back to the conference coordinator.

Thank you, Mr. David Moneta. We will now take questions from the telephone lines. If you have any questions, please press star one on your telephone key pad. If you are using a speaker phone, please lift the handset and then press star one.

If any time you wish to cancel your question, please press the pound sign. Please press star one at this time if you have a question. There will be a brief pause while participants register for questions. Thank you for your patience.

The first question is from Linda Ezergailis from TD Securities. Please go ahead.

Thank you. I was wondering if perhaps you could explain to me just very quickly what is the difference in your arguments, if any, in your fair return application, versus your 2004 applications on both the mainline and the Alberta system? And specifically, I'm wondering what the basis is for a drop in requested ROE to 11% from 12.5%.

Well, it is Hal here, Linda. I will take a stab at that.

I think, you know, we recognize that ROEs do move over time as the markets move. We have disagreed in the past with the magnitude of the movement. We think the risk premium should be larger than it has been in the past. And we felt that 11% was an appropriate level to apply for.

I would acknowledge, though, that there is inter-play in our view between equity thickness and ROE. And there is a certain equity thickness at which a lower ROE is acceptable. And as our leverage gets higher, we think one of the factors that has to vary with leverage is the ROE.

That is not part of the normal regulatory thinking in Canada. The two are seen as separate and distinct and that's one of the items we disagree with.

Okay. In terms of your arguments, conceptually, for a higher ROE, have those changed in substance at all? Or in data points?

Well, no, I think that the primary argument on the ROE front is all of the things being equal, our Canadian ROEs are not competitive with what people are in, in the larger North American marketplace.

But what may have changed a little bit is our increasing focus on equity thickness -- that we do regard equity thickness, or in our case equity thinness as significant risk to the business. And we would encourage our regulators and our customers to support us, as we argue for a more stable financial structure.

That would be, Linda, one of the -- you know, the -- I guess third party or external events that has occurred over the last say 12, 18 months, from the last time we were in the regulatory hearing -- is the, you know, continuous pressure that Canadian utilities are getting from the rating agencies, directly related to, as Hal said, both coverages, and equity thickness. And those are things that we need to deal with, you know, both with respect to our balance sheet, and you can see how we've reacted to that, by having equity on our balance sheet that is in excess of the deemed equity that we are given by the regulator. And that's in direct relation to maintaining those credit ratings. And I guess it would be our hope that the regulators would recognize that we're a bit behind, in the deemed equity component.

The Company can't afford to stay at the deemed levels that the regulator has given us without putting the Company at risk. So we're hoping that those are some chance circumstances that we can bring to the table.

Okay. When you -- Hal, when were you referencing the recognition that ROEs do move over time, are you indirectly referencing the fact that ROEs have been trending down in the U.S., as well as Canada, over time?

Because that's another thing that is kind of new over the past 12 to 18 months I would say as well, in addition to the rating agencies wading into the debate.

Yeah, I think that is true. The question is, Linda, is always okay, given a certain movement in the bond yield in the long Canada bond yield, what is the appropriate movement in the return on equity. And the formula tends to move them fairly mechanistically, obviously, without a lot of reference to data points in the market.

I would observe that even in risky businesses, such as oil and gas, exploration and production, required IRRs on investment in that industry have come down significantly as broad returns in the marketplace have come down. We see that people today are looking for lower returns on everything from real estate to utilities, to oil and gas exploration. And we're not naive. We recognize that returns have come down. It is just a question of to what degree.

In our application, Linda, is that we, you know, we look at things on an IRR or at-lack basis, the -- how it splits up after financing is not really how we look at return on investment. And if you take a look at the, you know, the weighted average difference between the two filings that we made, the 12.5 on 40 reflected a return that we felt at that time was required of about 7.5%. And as Hal pointed out, as a result of declining interest rates, the costs of capital have declined, and you would see that our current ask is in the range of about 7% from an at-lack perspective.

Okay. I guess I should probably jump bark in the queue. But I appreciate those insights. Thank you.

Thank you. The next question is from Bob Hastings from Raymond James. Please go ahead.

Thank you. I just want to clarify a couple of things. The tax refunds that were referred to -- was that $10 million or $11 million?

It was actually $12 million, Bob.

Okay. I was trying to estimate the rate there. Okay.

And was there any change from the -- or caused in your future tax liabilities, or catch-up, because of the lower tax rate in Alberta? Or did that all get picked up by the regulatory side?

I wouldn't expect it to be material, obviously, in Alberta. Our largest part is the Alberta system. The majority would be picked up through the regulatory part on that. I’ll just add on that tax, 112 million -- there was some interest in there as well. So when you get down to the tax versus interest you will see kind of a split on segments of note for that.

But 12 million is -- would be considered sort of nonrecurring?

That's correct.

And if I could just get one last clarification, the Coburg temporary generation facility fees, can you give us a little more color on that?

Essentially, we put in place a temporary facility last year to support Ontario's need for additional power. We were paid a fixed fee for doing that. And if I recall, the number is approximately 4 to $5 million. Is that correct?

Yeah, between (multiple speakers).

Before tax.

Yeah, before tax. Between this quarter and the last quarter, the next quarter, it’d all comes in to about 4 or $5 million.

I recall you had that. But there seems to be a mobilization fee.

Well, what it was is they asked us to put that temporary facility in for a defined period of time. And we had to install it, meet certain targets, make it run properly, and then take it out at the end of the period. And we did all of that -- thereby qualifying for the fee that we got.

And that fee itself was in the $1 million kind of range.

I think it was about $1.5 million, Bob, in the quarter.

Okay. Great. Thank you very much.

Thanks, Bob.

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

Thanks very much. I'm just wondering if I could get a little greater color on the western operations? You talk about lower power prices achieved. And you also talk about lower dispatch levels at Manchief and higher depreciation, lower electricity transmission.

I mean, were these things all essentially equal? Was there one thing that was primarily responsible for the drop? And I'm also wondering in terms of the lower prices achieved, is that where contracts are rolling over and you're recontracting at a lower price?

I will deal with the first question, I think you had -- the first part, which is the relative amounts of each of these. So the part on lower price that is achieved on the overall sale was roughly $3 million. The lower electricity transmission tariffs, first quarter of 2003, was roughly another $3 million. And the Manchief one was in the range of one to two million.

Okay. And then in terms of the prices -- I mean, do you have a fair amount of spot power there? Or is that just recontracting at lower prices?

It is mostly recontracting at lower prices, Maureen. As we've seen prices trend down on longer space, we have a lag impact as we've talked about before. So it is mostly recontracted -- or our contract price is declining.

And the transmission number is a large number. Where was that primarily -- or what region was that primarily attributable to?

It is primarily attributable to our northern Ontario new -- or northern Alberta new facility, the Bear Creek and MacKay River plants which they are still sorting out transmission tariffs on. And we ended up with a lower transmission tariff than we originally were paying.

A lower trans (sic) -- I had the impression that was lower in 2003 than it is this past quarter, that --

Correct.

Okay.

You're correct.

Okay. And in the eastern operations, you referenced improved margins, due to power sales in your retail business, commercial and industrial power sales. Can you give again a little more color on that? I mean, how much of the increase was responsible or due to these retail sales?

Again, it’s Lee here, Maureen. About half of the increase of nine was related to the higher margins on the retail business.

Okay. I'm wondering, on the mainline -- we're seeing a decline in the rate base there on an annual basis of what looks to be about 4.5% a year, roughly. And is there any plan, or do you see any capital spending into the future that might contribute to a slower decline in the rate base? Or anything that might offset that? Are you in any kind of discussions for maybe a rate cap? Or just anything that would address the decline in the rate base, and therefore, the earnings that stem from that business.

Maureen, it is Hal here. There is always capital expenditure firstly to maintain the integrity of the system, and to maintain good operations. Now, we -- as you know in Alberta, there is frequently opportunity to build short bits of pipe to collect either new fields or new markets. Less of that occurs on the main line.

But for example, we had looked at investing somewhere between 50 and $100 million in the current year to add capacity at the eastern end of the main line to better serve the Quebec market -- the Montreal through to Quebec City market. And as it turned out, through some contract negotiation work, we were able to defer that -- that investment. And our policy is essentially one of deferring investments in the Canadian mainline where we can. We were quite happy to make some progress on depreciation, and that depreciation issue will undoubtedly come up again in regulatory hearings and we will continue to try to maximize cash flow out of the mainline by increasing depreciation and getting our capital out more quickly.

We are committed to making all the necessary investments to sustain it as a blue chip pipeline system. But as I've said before, we're simply unwilling to pursue major capital investments under the current NEB-regulated return. It just doesn't work for us. We find many better things for TransCanada to invest in than the current regulated return.

Okay. So really, your preference would be to reduce the capital that's actually associated with the mainline as quickly as possible?

Well, you know, it has all got to be done in a very measured way, because firstly we're not particularly motivated to get capital out of the mainline more quickly than we can redirect that capital to other value creating an earnings-building opportunities. So you know, we're not in a panic here, but I would point out that if you look forward over the next 20 or 30 years, if we accelerate capital recovery a little bit now, to ensure that there is less risk of stranded capital longer term, we think that is better for everybody. So we have a modest bias towards accelerated capital recovery out of the main line right now.

Okay. And then one final question, if I may. And it is coming back to the tax refund. You mentioned that you there were $12 million. I'm just wondering if we could have maybe an outlook for what you expect the corporate segment to look like for the balance of the year, on a quarterly basis.

So I think I will take that one, Maureen. Taking out that sort of $12 million one-time item, I don't think that the corporate segments, excluding that, on an annual basis will be all that different from last year.

Okay. So if we normalize for the $12 million on a year over year basis we would be expecting in the absence of something unforeseen pretty similar to 2003.

Pretty similar, yup.

Okay. Thank you.

Thanks, Maureen.

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

Thanks. I wanted to shift gears to Ontario and the power market here and the minister made a major speech recently on the future of power markets that could affect Bruce and other investments you make. I'm wondering if you could tell us what your interpretation of that was for the future of Bruce, and how it makes money. And then I guess just whether you saw it as positive, negative or neutral. Thanks.

Well, I think, first, Matthew, we see the Ontario government recognizing the reality of the difficult situation Ontario is in, with respect to power. And we also applaud their recognition that a willy-nilly move to wide-open merchant market is probably not a good idea in the Ontario context. And we've shared those views with them before. And we think it is the right direction that they're going.

We don't have any particular issues in the Ontario announcement that we take exception to. But we would note that there is an awful lot of detail that was not shared with us there. And I think the Ontario government is proceeding in a very methodical stepwise fashion here and they will resolve more of those issues and provide more details to the marketplace as things unfold.

I suspect they want to provide a certain amount of high level structure, and then get feedback and proceed forward from there. We think some steps like the tight regulation of OPG is a very good step and is an essential step. If you are going to have private sector parties, like TransCanada involved in the market, we've got to understand the rules under which we compete with OPG. And for OPG to be a regulated supplier of power, rather than an entity that controls the market -- we think that is a good thing. And that makes it possible for us to be active investors there, notwithstanding the dominant position of OPG.

So I just say that there is a ton of detail yet to come on how the Ontario market is going to work. But we're not distressed in any way by the steps that they've taken so far.

Okay. And just a follow-up to that -- how are you being consulted how -- I mean are you being consulted and can you give us assurances on that, as they go step by step? Because legislation will come into play soon. And then how you are being consulted? As Bruce or as TransCanada or both? Can you give us some assurances there?

Well, we're being consulted as both. But let me phrase it a little differently. I mean they're not coming to us and asking our opinion. We're putting a lot of thought and effort into this. And we're sharing our views and our thoughts on all of this with the government of Ontario.

I would actually commend the government in the past six months for having been very open and very much inviting the opinions of the marketplace -- and seeking out the advice they can get in the market, and we applaud them for that. But TransCanada is in many ways aligned with Bruce. And we make suggestions through Bruce, that particularly relate to the Bruce facility. But TransCanada's interests in that region are much larger than that.

We're not only a power producer in our own right outside of Bruce, but we are also the predominant gas supplier to the Ontario market. And when they talk about doing different things that rely on gas, we think it is our position to make sure everybody understands what that means from a gas supply perspective. So we're -- we're encouraged by the continuing open mindedness of the government of Ontario and their willingness to listen.

We acknowledge that a good part of what we suggested to them has not been embraced right out of the chute -- that some of these things take some time to work through. And I accepted some of the recommendations we might make might not be adopted. But all told on balance we think the Ontario government is proceeding very thoughtfully here.

Okay. Thanks. I will pass it to someone else.

Thanks, Matthew.

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

Thank you. Actually, Matthew gave me a nice lead-in. Can we drill down a little bit then, as it relates to nuclear strategy. And earlier today, you described the acquisition of Bruce as a transformational event for TRAP (ph).

So, does this mean you that you would directly or indirectly participate in further lease opportunities including Point LaPleur (ph) and Pickering, if they're available. And I have a couple of follow-ups to that.

Well, you know, Karen, I think it all depends on the deal and the opportunity, and what the degree of risk is in getting into these things. You know, we've got to consider our own position on major investments at Bruce, because there are opportunities to deal with those two reactors that are shut down, and we’ll think very carefully about that and make sure that whatever we do works for TransCanada.

Beyond that, if, you know -- we have suggested to the government of Ontario that it is not inappropriate that they might want to retain ownership of the nuclear fleet within Ontario. But if it suits them, they could think about turning the operatorship and management of those facilities over to the private sector -- more or less along the model that was used at Bruce. And if they were to do more of that, we would certainly be interested.

But we won't make any commitments in advance as to what we will do, until we see the actual terms, because you know -- the way they structure it could make it more or less attractive, obviously, to TransCanada.

Can you just update, since you did mention it, the status of the assessment for Bruce A units one and two, and what the potential would be in that current assessment for new Greenfield nuclear at the Bruce site?

I guess I'm not really qualified to say much beyond all these things are possible. And you know, Bruce is a great site. And the fact that it has got a lot of infrastructure there makes it relatively easer were to do incremental things, both in terms of restarting the two shut down Bruce units and thinking about Greenfield power there. But you know, we rely on the Bruce power team to do the detailed work behind those things. And they bring proposals to us and we consider them carefully when we see them. And I would just say we're very supportive of efforts to maximize value at the Bruce site. And we will continue to review what options we have.

Just two last technical questions and then I will get back in the queue. Can you just quickly update your expectations for cash from Bruce this year? There was some conversation earlier that you could see some cash in the latter half of the year or late Q4? And then if you if you could update the status of the British Energy reps and warranties litigation.

I think on the cash front, I guess it has been our expectation that we wouldn't see cash from it this year, as we think that capital expenditures and cash generation will be roughly equal. We would hope that the 2005, as we see capital expenditures decline and revenues increase, that we may see cash flow -- positive cash flow, net to TransCanada, sometime in 2005.

Would that be -- I'm sorry, would that be unchanged given the fact that some of the maintenance originally planned for this year has now been deferred?

Yeah, I think that what will happen with those deferrals in maintenance, is actually they will just -- it will cause them all to sort of get pushed out. So it doesn't actually net increase 2005 is our current thinking right now. But as you move into the fall and do the planning for maintenance for next year, we will have a better picture of that -- you know, in probably about Q3. But the current thinking right now is that the impact of moving outages from '04 to '05 will just cause an outage to move from '05 to '06 -- sort of a domino effect.

I think your second question, if I'm correct, Karen, was related to the tax dispute, if you will, with British Energy?

And whether or not any of the technical issues in fact changed the reactor life, as they disclosed in November?

Well, I guess on the second issue, that's a matter of litigation that I guess we wouldn't want to talk about right now. That, you know, I think you're aware that we found certain damage in unit eight that we will be go whack to -- to talk to them about through this litigation. On the first issue of the tax dispute, that is ongoing with the tax authority. From TransCanada's perspective, the outcome of that -- any way it comes out, I would expect that the impact of TransCanada would be minimal and wouldn't be material. But both of those items will probably take some time to resolve.

Terrific. Thank you.

Thank you, Karen.

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

Thank you. Good afternoon.

If we could just stake take a step back and look at the regulatory saga you've been through the last few years and then the culmination with the Federal Court of Appeals decision, what was the real lesson that you have learned from that whole process? And what do you do next time, when you go back to the table?

Well, it is Hal here. I mean there's many different lessons that you learn in these things. But I think, you know, it is very difficult to change the thinking or influence the position of our customers and our regulator in any single hearing. It is an unfortunate thing, but once you enter the hearing room, it is an essentially combative situation. And strident positions get taken, and litigation proceeds from there. And you know, the one thing that we do know is that we do make more progress on many fronts in discussing these things with our customers. And we place a lot of value on being able to do that.

But at the same time, you know, we hear from our customers that they don't want to talk to us about a wide range of operational issues, unless we're prepared to put the return on equity issue behind us once and for all. And you know, we're just not prepared to do that.

So this is challenging stuff. And we just keep at it. And in the meantime, we run our pipeline business as best we can. And try to achieve the best outcome for our shareholders in the context of recognizing we have obligations to our customers, and we intend to meet those as well.

Just add to that, Andrew, as we pointed out, we're obviously disappointed we couldn't take that -- that further. But we believe that the clarification that the federal court provided is very significant to both our negotiations and our filings at both the provincial and NEB level. The clarification being that the cost of equity can't be influenced by, you know, customer-related issues -- that the cost of equity is the cost of equity. And that when we debate what that should be, it is not clouded by issues of rate shock, it is not clouded by issues of what is fair to the customer. It is based on cost. And we think that is a very significant fact -- legal fact, that we will be able to use going forward, and a very important clarification that was necessary to us. So in terms of lessons learned, you know, we think it was very important for us to have taken the step. And, at the end of the day, we achieved a very important milestone for our future.

Is it fair to say that because we're in such a low interest rate environment at this point in time that you have really shifted your focus away from the actual returns and then really focused on the deemed equity component and the equity thickness?

I would say that our focus is always on total return. The -- you know, the current environment, somewhat limits our ability to, you know, continue down the path of arguing ROE. But obviously, you know, for us, equity thickness or ROE doesn't really matter how you achieve an overall return that is suitable to you. So we see the avenue of equity thicknesses as probably being our most logical place to make gains at the current time.

It doesn't diminish our view that ROE and equity thickness are definitely related -- leverage does matter. You know, as we pointed out before, you know, the higher your labor levers, the higher your ROE that you would expect it to be. So we haven't sort of philosophically moved away from any of our views on that front, but recognize the practicality of what we can do in the current environment.

If I may shift gears for a moment, you've been fairly active transaction-wise in the last month or so -- the last few months, actually. What are your financing expectations for, really the remainder of this year, as you might have one major disposition and then one major acquisition which is still pending?

Our current thinking right now is, we need to, you know, obviously make sure that we close this acquisition. And I think we still have some maturities due at the end of the year that we would expect to fund. But I would say, you know, at the current time, we don't have any major dispositions planned. And that we wouldn't expect to see any sort of major fund raising outside of, you know, incremental debt that we may require for the PGT, GTN acquisition, if that comes about.

So you don't anticipate any major dispositions to another affiliate vehicle?

Not at the current time.

Okay. Thank you.

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

Thank you. I'm observing your delivery volumes -- total average per day. They're down 11% on your mainline and 6% in the Alberta system year-over-year. And of course this year was a leap year for Q1 '04.

Hal, you've talked about before, saying that the basin is flat-lining now in terms of production. Bbut this is materially worse than flat-lining. Have you changed your view on what the basin can do? And what has happen to your tolls in the process, or about to?

Yeah, Sam, what -- I would again restate my view that we have a basin that is going flat-line. I can never be too precise about what level it will flat-line at. If the industry has drilled a bit too aggressively and established a high rate, the basin is not going to sustain that rate and you're going to see a little bit of pull-back from it, before annual supply additions equal annual declines and it goes into -- it stabilizes at a flat-line. So when we see a .5 BCF a day decline from year to year, that doesn't necessarily mean -- firstly that the basin really declined that much. Sometimes there is shifting of gas.

We have to be very mindful of how much consumption there is in Alberta. There is continual growth in gas demand in Alberta. And we always have to take that into account.

Secondly, because you have a .5 BCF a day movement in one year doesn't mean that it is the start of a trend, and you've begun a long decline towards zero. We are firm believers that we're in a basin that will go flat-line and stay at a relatively constant rate for many years. The question is, at what rate will that occur?

So we would not be surprised to see the basin step down by another .5 BCF a day from where it is today. We might also see the basin step up by .5 BCF a day from where it is today. It just kind of all depends on where equilibrium is reached.

So I don't see this as a particular cause for alarm right now. But rather, I would see it as evidence for our regulators that, at best, we're going to be flat-line at something like the current rate. And you know, this is very contrary to the evidence that was presented by our adversaries in the last NEB hearings, where people gave the NEB all kind was assurances that production would be rising, rather than flattening or declining.

The thing to just to add to that, Sam, is that total decrease that you mentioned on the Canadian mainline wasn't a total decrease in the basin. The deliveries, both through its California and to northern border were increased year-over-year. So it is not a total decrease. Some of it went in other directions, just due to market forces.

Okay. Just moving forward for a second, an I guess it is supportive, Hal, of your argument, looking out 20 or 30 years -- if in fact hypothetically now, a Frontier pipeline doesn't get built -- and we've had fairly quick approvals on a number of new LNG facilities, obviously -- unfortunately not yours, from a vote point of view. But certainly from FERC being active in the U.S. Gulf. Directionally, that points to obviously onshore imports of LNG and inland -- well flat-lined, I guess, production.

That, to me, -- how would you classify that argument going forward here? Because we've got a rapid change in the last six months of approvals by FERC, not just of nuke facilities but tripling or doubling of existing facilities.

Well firstly I think the pickup in approvals by FERC is good. It is not negative for us. It is positive. It indicates that the FERC is enlightened in this matter and recognizes the importance of bringing in more LNG. And the fact that they've developed some fairly expedited approval processes is good. But they have another hurdle in the U.S. and that is the coastal zone management act which the states are able to use to frustrate approvals that are given by the FERC. And the energy bill in the U.S. was going to include legislation that would -- that would limit the frustration of the Coastal Zone Management Act, and ensure that it is only used where it is supposed to be used.

So you know, things are not entirely clear sailing in the U.S. yet, as to just how these different approvals will occur. Clearly, there is a case for LNG to come in to the California coast. And there is many different ways it appears that the state of California perversely wants to frustrate that. So there is an example of where things may not go ahead as quickly.

Now as to the larger question of the impact on TransCanada -- we are strong proponents obviously of Northern Gas. And we think it is quite important that Northern Gas come on. And you know, that's more or less the top of the list priority for TransCanada right now. And part of that is of course just to keep our existing systems full.

Now if Northern Gas comes on sooner, there may be the need to add a little bit of extra capacity to market. If Northern Gas comes on later, there is almost certainly no need to add extra capacity. So we're not too stressed out about exactly when Northern Gas comes on. We just want the pace of progress to be positive and the direction to be forward.

All right. Thank you. Last quick question. The contractual mix of the GTN system that you're attempting here to close in the bankruptcy court -- our review has about a 30% fall in contracts by late '05. What has been happening there, now that you've had a few months of kind of studying it further? Has that been recontracted? What is the physical movement on that particular system? Is that falling like your mainline? Or picking up -- like Northern Border has? In terms of usage?

It is very seasonal and dependent on prices, as we've seen the gas flows, I guess split from the Canadian mainline to the PGT system. The PGT system is higher than it's been. With respect to the contract you are referring to -- the 30% -- it expires at the end of 2005. It would be our view that that would be recontracted. For the most part, that's for the -- you know, the major utility in northern California. Given that we don't own it yet, and a lot of us -- the things are still sort of subject to discussion, I wouldn't want to comment further. But we're comfortable that the gas will be needed, long-haul, in northern California and that the pipeline will run relatively full.

Okay. Thank you, Russ.

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

Thank you. Just further along the flow of gas in North America -- I'm wondering if at this stage and point in the Alaska Pipeline proposal, if you're further along today than you were 20 years ago?

Yes. Yes, I think there is some feedback on the line. Could somebody turn their -- could somebody turn their phone down? Okay. It is Hal here, Linda.

I think we're a lot further along than we were 20 years ago, simply because supply/demand fundamentals in North America have moved to a different place. There is simply no outlook for anyone adding 5 or 10 BCF a day of supply to the North American market from basins in either Canada or the U.S., Other than through northern development.

No one is predicting that western Canada gas is going to double in production, as it did from 1980 to today. And nobody is really predicting substantial increases in deliverability out of the U.S. Gulf Coast onshore/offshore region.

So when you look around today, it is unlikely that you're going to see the sort of response to deregulation that occurred in the '80s and really caused a dramatic increase in gas production, including that doubling out of western Canada that I referred to. So from a fundamental perspective, there is much stronger demand for natural gas today than there was, particularly in the power gen sector. Residential commercial demand has grown. The only sector that's pulled back is the low-value industrial sector which is consuming a lot less gas today than it was in 1981.

Much of that industrial sector has in fact migrated offshore already, an unfortunately, it looks like another tranche of it will probably migrate offshore in the coming years. But you take all of that and you recognize the outlook for gas demand on the power gen side, we think the fundamentals for Alaska are a lot better.

Technically, TransCanada's ability to build a cost-effective pipe and build it at a predictable cost and make sure it runs very efficiently -- we are much more able to do that today than we were 25 years ago. We have migrated to much higher strength pipe. We have much more advanced remote control systems. The gas turbines and compression equipment we use is an order of magnitude better than it was in 1980. So, I would just say yes, we're in a lot better position than we were then.

I can appreciate that the fundamentals are much more supportive. I'm wondering if it’s a process, in terms of the approvals, negotiations, et cetera -- is further along today, and if you are able to lever significantly off of your work from before -- or where you are at in the administration side of things?

Well, a lot of things are unchanged from where they were before. Most of the environmental realities are essentially the same as they were. The rivers we have to cross -- the mountain ranges, the terrain -- all of that was studied in detail in the '80s and most of that work is usable today.

We do need to update our regulatory filings. And we need to comply with the regulatory regulation -- or sorry, the environmental regulations of 2005, are going to be different than they were in 1981. But you know, we're prepared to do all of that. And the data we've got is useful in that.

So you know, I think a lot of that stuff is in hand and useful. We do hold the right-of-way through the state of Alaska, on federal land. And the agreement of this week enables us to commence the process of securing the Alaska right-of-way on state land. So between the two of those, we're in pretty good shape there.

I think the Northern Pipeline Act in Canada, in particular, is a very useful mechanism to get this thing done in Canada. I think that it will do a lot to expedite construction through the Yukon and northeast BC. And there are many days when we wish we had the Northern Pipeline Act to expedite things in the Mackenzie Valley. But of course we don't.

Okay. What sort of risks in terms of any slippage in timing of mega projects and pipelines and the oil sands -- how does that impact timing of the Mackenzie pipeline, and potentially the Alaska pipeline project?

Well, first, I would discourage any connection between the Mackenzie and the oil sands. I read in the paper all the time that people are connecting the two, and I understand now the Sierra Club has connected the two. We don't see that.

That is one BCF a day of gas coming into a western Canada basin than deals in 16.5 BCF a day. And that one BCF a day will get accommodated into the larger western market, just as easily as the one BCF from Lady Fern did a couple of years ago. So there is not a direct linkage between the two. And if the Mackenzie gas does not come on stream, it simply means that more Alberta gas will flow to Fort McMurray than would otherwise be the case.

From a labor perspective, what sort of an overlap is there between oil pipeline projects, oil sands mega projects, and natural gas pipeline mega projects?

And I'm sorry, I acknowledge that from that perspective, there is a connection. That there is a very tight capability right now, in terms of managing mega projects in western Canada. Now pipelining is a little bit different. It is essentially a linear repetitive activity. And once you get things down to a steady rhythm, you can proceed with it a little differently than a complex integrated three dimensional project like a thin crude expansion.

So there are different kinds of people, different kinds of machinery and equipment. There is certainly the pipeline capacity in western Canada -- the contractor capacity to build a Mackenzie line. And we have not regarded a 30-inch line down the Mackenzie Valley -- 1220 kilometers -- as being significantly different than a routine annual program that TransCanada was doing during the mid 1990s, as we doubled our existing system.

So you know, that's quite a doable project. And we think on the Mackenzie project, there is relatively little impact from a tight contractor market, driven by Fort McMurray or anything else.

Alaska is a bit of a different story. Coming up with the amount of pipe for the Alaska project will strain the pipe-making capacity in Canada, and to some extent globally. The steel demands are extraordinary. It is unnerving right now to see where steel prices are going, driven by Chinese demand. But you know, that's what is happening.

We would very much like to see the Mackenzie project go first, so that we would help the pipeline contractors build up their construction capacity. And we think the Mackenzie project would help them do that.

So there is no way of avoiding the issue. The Alaska project is an enormous project that will strain the resources of every party that is involved. But we have built a lot of big inch long hole pipe and we think we know what the key things are and what we need to do to manage that project.

Thank you. I appreciate that context. One very quick last question.

Can you give us an update on the status of -- and potentially the results of your arbitration at Ocean State Power?

At this point in time, we don't have an update for you. It is just an ongoing process. And nothing hasn really changed, since the last time we updated you.

Okay and any sort of time-line for resolution that we can look towards or -- ?

No, an arbitration has the potential of taking a fairly long period of time. And as you probably know from the past, the parties don't necessarily agree on everything, including choosing arbitrators and those kinds of things, which can take long periods of time.

Great. Thank you. That concludes my questions.

Thank you, Linda.

Thank you. The next question is from Dominique Barker from CSFB. Please go ahead.

Hi. Just a simple accounting question. What are you capitalizing in other assets? I think it went up by $300 million?

Yeah, so the majority of that increase -- if you look, actually, in the financial statements, there is a couple of accounting changes that related to the new section handbook -- the 1100 -- and also the new regulations for accounting guidelines on hedging transactions, and basically those two increases that we note in the tables -- in the financial statements, end up increasing both the assets and liabilities on the books, such that we have set up regulatory assets to offset certain liabilities we've had to set up -- as well as on the hedging side, we've put on fair value of certain derivatives that we had. But they are hedges, so the offseting side went into other assets. And if you actually look in that note, there is a fairly good explanation that will explain just about all of that increase.

And so, were you expensing all of the -- this Fairwinds stuff?

Yes.

Okay. That's great. Thanks.

Thank you.

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

One really quick question. The 80% capacity factor on Bruce, when we work through the production numbers for the remainder of the year, it seems a little bit low. Can you just elaborate that it is in fact 80 even? And is there any padding in there for unplanned outages?

I wouldn't say it is padding. But we are doing the same calculations as are you right now and perhaps in Bruce, the number that we're still using is 80%. But it could it be 81 or 82? That's possible. But right now, our forecasts still include 80%.

And in terms of the last conference call, we talked about 45% of 4600 megawatts being contracted. Is that the same as 50% of the output under contract which is what we saw in the first quarter? And should we see using the 45% of production sold forward for the remainder of '04?

It think the number is -- we will just get the number here for you. But I think it is about 1500 megawatts -- we’ll give you the megawatt number, that is actually sold forward here. We’ve got it.

But, does that equate to 50% of output?

I would have to back calculate the number.

Okay I will follow-up separately, thanks.

We will -- I will get the actual number of megawatts for you, Karen.

Terrific, thank you.

Thanks, Karen.

Thank you. This concludes the financial analyst question session. We will now take questions from the media. Please press star one at this time if you have a question.

The first question is from Gordon Jaremko from Edmonton Journal. Please go ahead.

I guess probably a question for Mr. Kvisle. A question arising from the way you’ve worded statements on the arrangements that you're looking after in Alaska. It says that once you've got your right-of-way lease, TransCanada would then convey that lease to the corporation or partnership that will undertake construction -- could be owned in part by TransCanada. Can you elaborate on whether you're trying to put together some sort of consortium -- and who you think would be in it? And what would TransCanada's role be in it?

Sure. Gordon, we have consistently said for three years now that we're determined to lead the Canadian portion of this project, and essentially build it as an extension of our existing Canadian system, including our foothills systems, in Alberta.

We've always said on the Alaska side of the border that we're prepared to play whatever role is most valuable to the other parties in getting the project done. Our main area of focus is on the Canadian side.

It was thought at one point that the producers would simply build and lead the project on the Alaska side. And that is one impulse. You could still see that -- that it would be a producer built and owned project on the Alaska side.

At the other extreme, it could be that the producers don't do that, and no other pipeline companies step forward. And people look to TransCanada to build and own 100% of it, right from one end to the other. And if that is the way it goes, we will be prepared to figure out a way to do that. But more likely, it is something in between. And one stage would be to see significant involvement by the Alaska native corporations, who certainly are financially capable of participating. And they would, I presume, look to us or some other pipeline company, to bring the technology and expertise to bear.

Second tranche could be the inclusion of another pipeline company. Or there could be a joint project between TransCanada, the native corporations and the producers. The sky is wide open on this one. I would say, as to how it gets done in Alaska. And I would just repeat our consistent message, which is that TransCanada stands ready to do whatever it takes to help everybody get this part of the project done within Alaska.

Supplementary to that, inside Canada, are you saying that TransCanada and only TransCanada should own the Canadian portion?

We're not saying that. But we would want to see good logic and a good reason why there would be involvement of other parties in Canada. We think we are the logical party and it is a logical extension of our existing Alberta system.

This is a volume of gas that integrates into our Alberta system very well. And we've learned over the years that if you have a long linear pipe, where the little different chunks of it are broken up and owned by different people, that makes tolling and contracting and customer service a whole lot more difficult than if one company just owns it and runs it from one end to the other.

But you know, we're open-minded on that. If there is a good reason to include someone else as a co-owner on the Canadian side -- well, we would look at that. But at this point in time, we continue to pursue the Canadian project as a TransCanada project.

Now I would add that there are some Aboriginal groups in the Yukon and northern BC that have expressed some interest in participating in the project. And I think in the Mackenzie Valley, we have demonstrated our credentials, as a party that is willing and capable of working with the Aboriginal entities to make a project happen. And we would bring a similar attitude toward Aboriginal participation in the Yukon and northeast BC. But we can't really engage and progress those discussions a long ways, until other bigger pieces of the project have fallen into place.

Okay. Last question -- do you estimate how much the entire project would cost currently?

Well, you know, that's a loaded question, because every time I quote a number, some other party comes out and points out that I have flip-flopped and changed the number, or that it is inconsistent with some previous quote. But let me put it to you this way -- that the piece within Alaska -- many people have quoted numbers around $6 billion U.S. to do that. It could be a little lower. It could be a little higher. And when you're talking about a project that is 10 years out, and through the most difficult circumstances on earth, you know, it could be plus or minus 50%.

But if you use that number, 6 billion is roughly the cost to get from Prudhoe Bay to the Yukon/Alaska border. And about the same -- maybe a little bit less -- but about the same to get from that point to central Alberta. And where is central Alberta? Where is the end point of the pipeline? That's a big question. And people spend an awful lot of time debating that. And I'm not particularly fussed about that.

If we have a lot of capacity in Alberta, it could connect into our Alberta system up Northwest of Grand Prairie. If Alberta is producing relatively more, rather than less, maybe that connection point is all the way down at Caroline, where the existing foothills line separates, with one leg going east and one leg going south.

So it is somewhere in there. And that’s -- and beyond that, Gordon, I don't think it is really productive to spend a lot of time talking about how much it is going to cost to move the gas from central Alberta to end markets. Because in one case, it will all move through our existing pipeline system. We will be able -- we and Alliance and West Coast, and other pipes taken together between us will be able to move it. And I don't think there is any scenario that we can see where a four or five BCF a day pipeline through to Chicago is going to be necessary. We -- I would be highly confident that at least half the Alaska gas will go through our existing system, and reasonably confident that three-quarters of it will go through. And perhaps even all of it will go through. So I don't think we should speculate on the southern end. We will solve that problem when we get to it.

Thank you.

Thanks, Gordon.

Thank you. Once again, if you are from the media community, please press star one at this time if you have a question.

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

Thanks very much. I would just like to thank everybody for participating today and showing an interest in TransCanada. We look forward to talking to you again soon. Bye for now.

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