TC Energy Corp (TRP) 2006 Q3 法說會逐字稿

Good day ladies and gentlemen. Welcome to the TransCanada Corporation 2006 third quarter results conference call.

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

Thanks very much. I would like to take this opportunities to welcome everyone today, we are pleased to provide the investment community, the media , and other interested parties with an opportunity to discuss our 2006 third quarter financial results and other general issues concerning TransCanada.

With me today are Hal Kvisle, President and Chief Executive Officer, Greg Lohnes, Executive Vice President and Chief Financial Officer, Russ Girling, President of Pipelines, Alex Corbay President of Energy, and Glen Monouse, Vice President and Controller.

Hal and Greg will begin today with some opening comments on our financial results, and other general issues pertaining to TransCanada, please note that a slide presentation will accompany their remarks, a copy of the presentation is available on our website at transcanada.com. It can be found in the investors section under the heading conference calls and presentations. Following Hal and Greg's remarks, I'll turn the call over to the conference coordinator for questions, and Hal, Greg, Russ, and Alex and Glenn will all be available to answer your questions.

During the question and answer period, we will take questions from the investment community first, followed by the media. In order to provide everyone with an equal opportunity to participate, we ask that you limit yourself to two questions. If you have any additional questions, please re-enter the queue. Also, we ask that you focus your questions on our industry, our corporate strategy, recent developments, and the key elements of our financial performance, if you have detailed questions related to some of our smaller operations or your detailed financial models, Miles and I would be pleased to discuss them with you following the conference call.

Before Hal begins, I would like to remind you that certain information in this presentation is forward-looking and is subject to important risks and uncertainties, the results or events predicted in this information may differ from actual results or events. Factors which could cause actual results or events to differ materially from current expectations include, among other things, the ability of TransCanada to successfully implement its strategic initiatives and whether such strategic initiatives will yield the expected benefits, the availability and price of energy commodities, regulatory decisions, competitive factors in the pipeline and energy 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 U.S. 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 except as required by law. Finally, I'd just like to point out that during the presentation, we will refer to measures such as funds generated from operations, and net income from continuing operations excluding significant items. These measures do not have any standardized meaning in GAAP, and are therefore considered to be non-GAAP measures. As a result, these measures may not be comparable to similar measures presented by other entities. Additional information on non-GAAP measures is available in our third quarter report to shareholders.

With that, I'll now turn the call over to Hal.

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

TransCanada's strong financial performance during the third quarter and on a year to date basis demonstrates that our disciplined approach to growing our portfolio of high quality energy infrastructure assets is creating value for our shareholders. Net income from continuing operations for the 9 months and of September 30, 2006, was $782 million, or $1.60 per share. Our results include a number of significant non-recurring items, which are highlighted in our quarterly report to shareholders and later in this presentation.

Excluding those positive items, net earnings for the 9 months ended September 30, were $668 million, or $1.37 per share, an increase of $64 million or $0.13 per share or approximately 11% better than the same period last year. This increase is primarily due to strong earnings from our energy business as a result of our growth initiatives in power generation and natural gas storage.

Our pipelines business continues to deliver solid results, although net earnings declined. Primarily as a result of lower rates return on common equity and lower average investment basis on our Canadian wholly owned pipelines. Price generated from operations on a year to date basis were $1.7 billion, an increase of $297 million, or 21% over the same period in 2005. This very strong cash flow has allowed us to invest approximately $1 billion in our core businesses during the first 9 months of this year.

Greg Lohnes will take you through our quarterly numbers in more detail in a few moments. First, I'd like to briefly discuss recent developments. Today, TransCanada is the leading North American energy infrastructure company, with approximately $25 billion of high quality long life energy infrastructure assets. Those assets include more than 41,000 kilometers of wholly owned pipelines, generating capacity of approximately 7,000 megawatts through our interest in 15 power plants, and approximately 130 [pedadules] of natural gas storage capacity through our interests in various gas storage facilities here in Alberta.

Going forward, we see significant opportunity to add to our portfolio of assets. In 2006 alone, we expect to invest approximately $1.6 billion, bringing the total amount we've invested in our core businesses since the year 2000 to more than $10 billion. In 2006, our key projects include the 550 megawatt Bécancour cogeneration plant which was completed on time and on budget and began commercial operations late in the third quarter.

Also, the Tamazunchale pipeline, which we expect to bring into commercial operation in December. Last week, I was joined by Mexican President Vicente Fox in inaugurating that pipeline. It is our first project in Mexico since our involvement in the Mayacam and Elbahil pipelines. There is significant need in Mexico, for new energy infrastructure to support the country's growth, and regional development. And we continue to explore opportunities in both pipelines and liquified natural gas in Mexico. Also expected to begin commercial operation by the end of this year is our Edson natural gas storage facility. We have substantially completed construction and are currently working through the commissioning phase. The Edson facility is expected to have a working natural gas capacity of approximately 60 [pedadules]. Combined with our existing interest in storage facilities, TransCanada will control approximately one-third of the natural gas storage capacity here in Alberta.

Greg Lohnes will provide specifics on the contribution of natural gas storage to our earnings in the third quarter, suffice to say, gas storage is an increasingly significant component of our energy business. We expect the first phase of the Cartier Wind Energy project, the 110 megawatt Baie des Sables Wind farm to go into commercial service by the end of this year. Construction is nearing completion on schedule, and we have already begun construction on Phase II and regulatory hearings on Phase III.

TransCanada holds a 62% interest in the overall project, consisting of 740 megawatts. TransCanada is delivering on our growth objectives, in addition to those projects already under construction, we continue to pursue numerous large scale opportunities in both our pipeline and energy businesses. We are working diligently to move these opportunities forward to sustain our growth momentum over the next few years. I know that earlier that we expect to invest $1.6 billion in 2007. We anticipate investing more than $1 billion in each of the next two years and potentially significantly more as we advance key projects.

On our Keystone Oil pipe line projection, the National Energy Board began public hearings on October 23rd on our application to convert a section of the Canadian Mainline from natural gas to crude oil service. We anticipate filing our section 52 application relating to the new build portions of the pipeline in Canada with the National Energy Board later this year. In the United States, the Department of State commenced scoping meetings on environmental aspects of the proposed pipeline on October 24th. Those meetings will continue through November 16th.

We continue to work on regulatory engineering procurement, land acquisition, and stake holder consultation activities, and we remain on track to begin construction early in 2008 and to bring the pipeline into commercial service by the fourth quarter of 2009. On our North Baha system, we received a preliminary determination from the Federal Energy Regulatory Commission approving almost all aspects of our proposal to expand the pipeline and allow for the bidirectional flow of natural gas. Environmental issues will be subject to a future order. Our proposals position TransCanada to be involved in the first major entry point for Regas find L&G on the West Coast of North America.

In the north, we are continuing our constructive dialogue with Alaska North Slope producers and we are monitoring the state election closely . We look forward to working with the new administration to realize the long held goal of bringing this much needed source of natural gas to market. On the Mackenzie gas project, we continue to work with our co ventures on the review of project costs and to monitor the continuing hearings of the joint review panel and the National Energy Board, we expect the Mackenzie gas proponents to announce the updated cost estimates later this year.

We also continued to invest in our pipelines business in response to our customers need to connect new supply in Alberta and serve markets in the eastern part of North America. We are happy to report that our highly competitive gas transmission network is capturing the majority of new gas connections in western Canada. Our customers see real value in the extent and capacity of our system and in the liquidity and transparency of our Alberta hub, the largest physical gas trading hub in North America.

Turning to energy, as I noted earlier, the first phase of the Cartier Wind project, 110 megawatt Baie des Sables Wind Farm is nearing completion on schedule. Construction continues on the second phase, the 100 meeting watt Anse à Valleau Wind farm. The first round of public hearings on the third phase at Carlton occurred during the week of October 16th. TransCanada continues to explore further opportunities to develop wind projects in Quebec, in response to Hydro-Quebec distributions request for proposals for 2000 megawatts of additional wind power. Bids on that RFP are due in the second quarter of 2007.

In September, we announced the signing of a 20 year accelerated clean energy supply contract with the Ontario Power Authority for the Portlands Energy Center. Portlands is a 550 megawatt natural gas fired power plant in downtown Toronto. Construction has begun and the facility is expected to begin operations in simple cycle mode delivering 340 megawatts to the City of Toronto beginning in June 2008 to meet peak summer demand. The plant is expected to be fully operational in combined cycle mode in the second quarter of 2009.

Portlands is a limited partnership between TransCanada and Ontario Power Generation. At Bruce Power, the restart and refurbishment program remains on track, and as we reported to you on our last conference call, delivery of major equipment, including steam generators has begun. One scheduled change I would like to highlight for you today is with respect to the refurbishment of unit 4. Bruce Power had originally scheduled unit 4 for refurbishment in 2007. Based on the results of recent inspections, it is now expected that the steam generators in unit 4 can continue to operate until the year 2010, and will then need to be replaced. The refurbishment of unit 3 is still expected to begin in late 2009.

Turning now to liquified natural gas, we continue to make progress on or Cacouna and Broadwater projects. In Quebec the joint review panel on the Cacouna Energy project was granted an extension on their report. That report is now anticipated to be submitted to ministers of environment in early November, and Cacouna Energy anticipates receiving government approvals in early 2007. The project, a partnership between TransCanada and PetraCanada remains on track to complete construction and bring the facility into service by the end of this decade.

In September, the U.S. Coast Guard released its waterways suitability report on our Broadwater energy project. The report determined that the proposed L&G facility can be operated safely and securely and has recommended a series of mitigative measures. This report is a key milestone in the ongoing regulatory review of the project, Broadwater is a partnership between TransCanada and Shell U.S. Gas and Power.

In concluding my remarks, I'd note that it is tremendously gratifying to see the tangible results of our investments as projects are completed and begin operations. In addition to the projects I've outlined today, we have numerous other pipeline and energy initiatives under development, positioning TransCanada for growth and value creation in the years ahead. Among those initiatives are our Northern Lights project to build new electric transmission lines to meet energy needs in the U.S. Northwest, power plant opportunities in Ontario, wind power opportunities in Quebec and the U.S. Northeast, expansion opportunities on our GTM system, and L&G and pipeline opportunities in Mexico.

As always, we are remain focused on prudent disciplined growth consistent with our core strategies, we continually generate and evaluate opportunities in both pipelines and energy, acting only on those that will deliver superior shareholder value. As the results we announced today demonstrate, we are doing just that.

I'd now like to turn the call over to Greg Lohnes. Greg?

Thanks, Hal.

As Hal mentioned earlier today we released our third quarter results, net income from continuing operations or net earnings for the third quarter were $293 million, or $0.60 per share, compared with $427 million, or $0.88 per share for the same period last year. As noted in our quarterly report, and highlighted on this slide, third quarter 2006 net earnings included an income tax benefit of approximately $50 million, as a result of the resolution of certain income tax matters.

Third quarter 2005 net earnings included $193 million of after tax gains, related to the sale of the Company's interest in the Power LP, excluding these items, net earnings for the third quarter 2006 were $0.50 per share, an increase of $0.02 per share, or approximately 4% when compared to the third quarter '05. For the 9 months ended September 30, 2006, TransCanada's net earnings were $782 million, or $1.60 per share, compared to $859 million, or $1.77 per share for the same period in 2005. In addition to the items previously noted, net earnings for the first 9 months of 2006 and 2005 included a number of significant non-recurring items. They are highlighted on this slide. And additional information on each is included in our quarterly report to shareholders.

Excluding these items, net earnings for the 9 months ended September 30, 2006 were $1.37 per share, an increase of $0.13 per share, or approximately 11% when compared to the same period last year. Quarter-over-quarter, and year-over-year increases were primarily due to significantly higher net earnings from the energy segment, partially offset by lower net earnings from the pipeline segment. I will briefly review the third quarter results for each of our segments beginning with pipelines.

The pipelines business generated net earnings of $130 million during the third quarter, compared to $149 million for the same period 2005. The $19 million quarter-over-quarter decline is primarily attributable to lower contributions from the Canadian Mainline and the Alberta system due to a combination of lower approved rates of return on common equity, and lower average investment basis from both pipelines. A $6 million decline in TransCanada's proportionate share of net earnings from other pipelines, also had a negative impact on contributions from the pipeline business.

The decrease was primarily due to the impact of a weaker U.S. dollar, higher project development and support costs, and lower net earnings from (inaudible) due to the receipt of a customer bankruptcy settlement or settlements in the third quarter of 2005. These items were partially offset by a higher contribution from Portland, primarily due to the receipt of a bankruptcy settlement in third quarter '06. Our share of the settlement was $6 million after tax.

Next, some comments on energy. The energy segment includes our power operations as well as our initiatives in natural gas storage and liquified natural gas. Energy generated net earnings of $123 million in the third quarter, an increase of $25 million over last year when you exclude the gains related to the power LP. The increase was primarily due to higher contributions from western and eastern power operations, and natural gas storage. These increases were partially offset by a lower contribution from Bruce Power, and the loss of income associated with the sale of our interest in the power LP in the third quarter '05.

Bruce Power contributed $72 million of pretax income in the third quarter, compared to $99 million last year, the $27 million decrease was primarily due to lower overall realized prices partially offset by higher generation volumes as a result of an increased ownership interest in Bruce A, and Bruce Power's overall strong operating performance. The Bruce units ran at a combined average availability of 90% in the third quarter, compared to 88% average availability during the same period last year. The improvement in plant availability and our increased ownership interest in the Bruce A units increased TransCanada's share of power output from Bruce Power to 3,448 gigawatt hours in the third quarter, compared to 2,882 gigawatt hours last year.

During the third quarter, Bruce Power realized an average price of $51.00 per megawatt hour, compared to an average price of $70.00 per megawatt hour in the third quarter of '05. On a per unit basis, operating costs decreased to $32.00 per megawatt hour in the third quarter from $35.00 per megawatt hour last year. The decrease in costs per megawatt hour is primarily due to the increased output. To reduce exposure to future spot marketplaces Bruce B has entered into fixed price sales contracts to sell forward approximately 3,300 gigawatt hours of output for the remainder of '06, and 6,700 gigawatt hours of output for 2007.

Sales that are made into the spot market by Bruce B are subject to a floor price which is adjusted annually for inflation on April 1st. As result of a contract with the Ontario Power Authority. Effective April 1, 2006, the Bruce B floor price was $45.99 per megawatt hour. Under the same contract with OPA, all of the output of Bruce A is sold at a fixed price of $58.63 per megawatt hour, which is also adjusted annually for inflation on April 1st.

Turning now to western operations. Western operations operating income was $84 million in the third quarter compared to $32 million last year. The $52 million increase was mainly due to the acquisition of the 756-megawatt Sheerness Power purchase arrangement on December 31, 2005. Improved margins due to higher overall realized power prices and higher market heat rates on uncontracted volumes of power sold also contributed to the increase.

Market heat rates in Alberta increased by approximately 140% in the third quarter as a result of the an approximate 42% increase in spot market power prices, while average spot market gas prices decreased by approximately 39% compared to the same period in 2005. In the third quarter of 2006, approximately 35% of western power sales volumes were sold into the spot market, compared to 13% in the third quarter last year. The increase in spot market sales was primarily due to the acquisition of the Sheerness PPA.

Supply from Sheerness and our other plants in Alberta is managed on a portfolio basis. Depending on market conditions, we will continue to commit a portion of this supply to long term sales arrangements with the remaining volumes subject to spot market price volatility. To reduce our exposure to future spot market prices, western operations has fixed price sales contracts to sell approximately 3,200 gigawatt hours of power for the remainder of 2006, and approximately 10,300 gigawatt hours of power for 2007.

Finally in power eastern operations operating income in the third quarter was $40 million compared to $25 million last year. The increase was primarily due to higher overall margins on higher sales volumes, an increased generation from the TC hydro facilities resulting from higher water flows. During the third quarter of 2006, the hydro northeast facility generated 312 gigawatt hours of electricity, compared to 196 gigawatt hours for the same period last year.

Overall in the third quarter, approximately 93% of eastern power sales volumes were sold under contract. To reduce our exposure to future spot market prices, eastern operations has fixed price sales contracts to sell approximately 2,500 gigawatt hours of power for the remainder of 2006, and approximately 9,600 gigawatt hours for 2007. Finally, in the energy segment, natural gas storage operating income of $24 million in the third quarter was 6 times greater than the $4 million reported for the same period last year. The increase is primarily due to the higher contributions from Cross Alta as a result of increased capacity and higher natural gas storage spreads.

Turning now to corporate, excluding the income tax benefit of approximately $50 million I mentioned earlier, corporate net expenses were $10 million, which is comparable to the $13 million reported for the same period last year. Turning to the cash flow statement, funds generated from operations were $662 million in the third quarter, an increase of $159 million when compared to the same period in 2005.

Capital expenditures in the third quarter were 372 million, and related primarily to the ongoing development of Greenfield projects such as Becancour, Cartier Wind, Tamazunchale, Edson, the Bruce A restart, and Portlands energy center, as well as growth and maintenance capital associated with the Canadian Mainline and the Alberta system. For the year, our capital program is currently expected to total approximately $1.6 billion.

Finally, our balance sheet remains very strong. At the end of September, it consisted of 58% debt, which included our proportionate share of joint venture debt, 2%preferred securities, 2% preferred shares and 38% common equity. The strength of our balance sheet and our significant discretionary cash flow provides us with the financial flexibility to make significant investments in our core businesses. Going forward, we will continue to direct our resources towards long term growth opportunities that strengthen our financial performance and create long-term value for our shareholders.

That concludes my prepared remarks, I will now turn it back over to David for the question and answer period.

Thanks, Greg. Before I turn it back to the conference coordinator, just a reminder that as part of the question and answer period, we will take questions from the investment community first, followed by the media, and as I mentioned earlier, Hal, Greg, along with Russ, Alex and Glenn are here to respond to your questions. With that, I'll turn it back to the conference coordinator.

[OPERATOR INSTRUCTIONS]

The first question is from Sam Kanes from Scotia Capital, please go ahead.

Thank you, it relates to understanding the future earnings flow that you expect from Becancour, the Mexican pipeline, Edson storage, Cartier Wind, and perhaps even Portlands, and it's just from a point of view where we sit--I'm trying to account for these projects. Is there anything unusual or quirky, like parabolic type rates, or front end loaded rates or back end loaded rates or anything that would be unusual in the scheme of how you expect to earn on those over the next little while?

Sam, it's Hal here, I don't think there's anything quirky or parabolic or anything like that. We, of course, always during the quarter in which when we start operations usually generate less earnings than we would once everything is up and running smoothly, so there are always partial quarters at the outset, and there are always operational delays and other hurdles you need to overcome, but on the list of projects we went through, they will generally ramp up and then they'll run at a fairly predictable rate, possibly with the exception of storage, because there is some market reality in storage, the difference between the current strip and the forward price strip, sometime out, we have a number of tools available to stabilize the earnings in our storage business, but from quarter to quarter and year to year, that one would move around more than Becancour or Tamazunchale for example.

Perhaps there's a follow-up on Edson itself, specifically, that of course adds a significant amount of capacity and a long market at the moment as opposed to the opposite a while back and of course forward strip now is quite flat going forward as far as the eye can see. I'm curious as to how many you've contracted if anything on Edson, or your Cross Alta facilities on a term-up basis, or are you running basically a spot business?

Well, we don't, we doesn't run what you might call a spot speculative business, we don't store for our own account, and just sit on the gas and see where market prices go, we don't do that. We do store gas for third parties, and the revenue we derive from that is reflective of the difference, the spreads, if you will, between today and the withdrawal time.

And in the case of Edson, we would do relatively more of that business for our own account, again, with price certainty, simply because we are in the first year of operation and we need some flexibility to fine tune the facility. So there--there was a very interesting period last summer, and we were very pleased to see that the gas market gave us an opportunity to go through the first cycle on Edson in a very favorable spread environment.

Thanks, Hal.

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

Thanks a lot, I noticed business development costs are up in both major segments and you guys are strengthening the balance sheet and generating more cash, so I'm wondering if that's the business development costs signal, maybe some acquisitions on the horizon, or is that from Greenfield projects that you are working on now?

I think it's almost entirely Greenfield, Matthew, we are always looking at where we might see an acquisition opportunity. But certainly there's been no surge in spending related to any M&A activity.

In Mexico, Hal, do you see that as an M&A market or more of Greenfield development when you talk about pipelines and L & G there?

We don't see a lot of M&A opportunity in Mexico, like many markets, there's a very high quality pipeline network in Mexico, but it's owned by Pemex, and we don't see any opportunities there, and similarly on the power side, the bulk of the power generating capacity is owned by CFE, and it's not for sale.

You never know, there may be some small opportunities from time to time where private sector parties decide to exit Mexico, but we are not aware of any of that right now, so we are very focused on Greenfield activity, we are active today in the gas transmission side, and we're working to prepare ourselves for additional gas transmission opportunities that we think are going to come up in the next 12 to 24 months. We're also active on the L & G terminal front, we think that Mexico is being very astute in the way they are looking at L & G on both the east coast and west coast, and we think it's a good thing for Mexico fundamentally attractive projects, so of course we are interested in them. We've not, to date, been an active player in the Power Gen sector in Mexico, but it's something we watch and that's about all we're doing at this point.

Thanks, I'll get back in the queue.

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

Thanks, I see you've spent $806 million to date on the Bruce A restart and refurbishment project. I'm just wondering how are you tracking in terms of time line and spending outside of this unit for rescheduling?

Hi, Linda, it's Alex. We have been very, very involved at all levels on the Bruce restart, in fact, we have just come back from a substantial meeting with Bruce Management on the restart, and my perspective at this time is you are correct, we've spent about, give or take $800 million, and we are to this point, it's early days, but we perceive the plan to be on schedule and on budget, and we are from TransCanada's perspective, we are quite pleased with the progress to date, and have no significant concerns with regard to schedule or cost.

Just as a follow up question on the power business, what are you looking at in terms of potentially contracting more of your western operations Sheerness PPA output? I'm hearing that the liquidity is getting a little bit better in the forward market, so are you looking at that and maybe you can give us a sense of how much you have contracted both in your western and eastern operations beyond 2007?

Sure. I think I would agree with you. We are seeing market conditions that are more favorable in Alberta to a longer term contracting, and we are certainly taking a very hard look at that, and I think that we are seeing prices that are becoming more reflective of what we would think represents fair value in those outer years.

Right now, we are quite heavily hedged, the lion's share of our output in eastern is hedged for the next two to three years. We are, we have obviously more open megawatts in Alberta and that's particularly because of the acquisition of Sheerness, and the market conditions at the time we did that deal, and I think it's fair to say that we would be looking to cover a significant portion of that length over the next period of time.

Okay. Thank you.

Linda, it's Hal, I would like to just add one comment to that, and that's that we do as I said many times before look at the power business at both ends of the cost curve, and where we are building new build facilities that tend to be high on the cost curve, such as a gas powered plant like Becancour, we aim for long term contracts so that there is not a lot of volatility when you are sitting at that position on the cost curve.

Alex's team has got a great portfolio of assets, particularly here in the west that sit quite low on the cost curve, and we can take a little bit more price volatility and still generate predictable earnings, and so we are able to have a little more of our output at market prices rather than forward sold prices, and from time to time, we think that's a good thing to do.

Thanks.

Thank you.

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

I have a couple of questions on the power side, I guess they are for at Alex. When does Bruce B become exposed to market prices of uranium?

Right now, Bruce maintains on average about a 6 to 9 month inventory of fuel, and that obviously would have already been priced and so I think that is a--that's sort of a fair guesstimate as to when we might become exposed to uranium prices.

Do you expect the cost to be significant. I notice your fuel cost per megawatt hour is 277 this quarter, up significantly from the first quarter. And I know it's a small part right now, but do you expect it--is it something you are worrying about? Can you talk about your procurement strategy?

Yes, we are personally not very worried as you mentioned, it does comprise a very small portion, $2.00 to $3.00 per megawatt hour of our production costs, and of that cost, only about half of that is related to the value of the raw material, so we, we obviously keep a watch on it, and when opportunities arise, we try to find ways of managing that risk and an example of that would be on our Bruce A restart deal where that fuel, that fuel price is a pass through to the OPA, so but generally, with respect to B, we watch it, we are aware of the price increases, the problems with chemicals mined, but it's not something we see as very material.

And second question, on Becancour, Norsk Hydro is out confirming that they are closing their magnesium plant, can you just confirm that your counter parties Hydro-Quebec that's contracted and there's zero impact to your earnings?

What I would say is there would be no material impact to the contribution of that asset, in the event Norsk Hydro were to shut down that facility. At the time we entered into that contract, and put in our bid to Hydro-Quebec, we were quite aware and quite conscious of the risk of losing a steam host, and we've structured that deal in a manner that we are quite comfortable there will be no material impact if we were to lose Norsk Hydro.

Thanks

Thank you. The next question is from Karen Taylor from BMO Capital Markets.

I guess this one's for Alex, you're getting a work out today. Can you talk about the maintenance schedule then for 2007 at Bruce, given the fact we are deferring the unit 4?

You are asking me to comment just on 2007 generally?

Do you have a schedule for planned maintenance, or will they be able to provide us with one?

We are right now in the process of putting together the 2007 budget, Karen, and, and we will give you all that outage data, I think we will probably do it in January, but in advance of that, I think what I could say is we are expecting slightly more outage days for Bruce A and probably slightly more for Bruce B in 2007, but we will get back to you with the formal numbers.

So when you slightly more, obviously that's with respect to the current year being 2006?

Sorry, Karen, could you just repeat that?

Sorry, just with respect to 2006, when you are talking about more outage days. That's the relevant period?

Yes, relevant to 2006. So comparable to potentially, slightly higher in terms of planned outage. It wouldn't be significant.

The overall availability, not necessarily significant, only different from what we are seeing this year, which was 90% overall. I think it would be an 80% at A.

Can I just ask a strategic question about the exposure or proportion of earnings overall that are exposed to what I'll call commodity like businesses. I appreciate Hal's comments about the higher the costs, you are on the cots curve, the higher the contract cover, and the higher the length of the durational increase. You have storage now which is a basis play, you've got volatility in the gas pipeline sector, resulting from that same basis issue, particularly on GTN and to a lesser extent through TC pipes, and now you've got relatively large unhedged position in the west.

Can you just talk about what the target overall number is for the Company in terms of what percentage of earnings you want exposed to be--to spark spreads or forward basis prices?

Karen, we have not set a target, we don't have any particular desire to explore exposed more rather than less earnings to volatility. We like low volatility earnings, and I think our shareholders do as well, but one of the realities is that we also like earnings that have some upside, and so we need to take cash flow out of businesses that are mature and stable, and don't have that kind of upside, and redeploy them into the best alternative business we can find, one that has significant earnings upside, and reasonably good stability, and we think we have those kind of businesses in both power and storage.

There will come a day when we'll see significant investment opportunities in the pipe side, and that will allow us to reinvigorate if you will the growth on that side of the Company, and that may come sooner rather than later as a result of the Keystone Oil project, and I would note, we have quite a bit of CapEx ahead of us in the Alberta system, and in certain expansions of our long delivery pipes, so the current balance that you see today is one that we are comfortable with. We think that we can see that, the split, if you will, between slightly volatile earnings and non-volatile earnings move around a bit, could go both up and down, but certainly, we do not see any scenario where we would encounter earnings volatility that would make it difficult to sustain and grow our dividend, for example. So those are the things we think about.

Thank you.

Thanks, Karen.

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

Thank you. Congratulations on the results, and particularly on reading that Alberta market, and having so much exposed to it to get those prices. One question on the Alberta market, as that tightens, at some point people are going to think about capacity additions, you've talked a lot about projects in Ontario and Quebec. When did you see--would you first of all look at things in Alberta, and secondly, when do you envision those opportunities might arise?

Bob, it'ss Alex, it is, it's interesting, I mean, Alberta is probably from a market fundamental perspective and a supply and demand perspective one of the more attractive markets in terms of where we see reserve margins going, but it's also been a market where, where to date, there have been a lot of uncertainty with regard to certain market rules, we very much see--continue to see Alberta as a market for new generation, we think a number of things need to occur, we need some stability in the market rules and we personally would certainly like to see transmission improvements in Alberta, particularly enter tie improvements with other markets, but I think you're going to see generation added in Alberta over the next five years.

Okay, one follow-up on that then is you mentioned the enter ties and there's people talking and looking at investing in expansion on the transmission side. Have you given any look on that besides Northern Lights, which I notice that you have sort of down-sized a bit as opposed to the original plan coming from the old sense.

Yes, it is interesting, I mean, we have been pursuing Northern, really, there's two opportunities, there's a Northern Lights opportunity which I would call the intra U.S. opportunity which is probably what you are referring to which is really a DC line which is going from Montana to the Southwest U.S., but I think it's fair to say that that opportunity is not mutually exclusive with expanding import/export capacity out of Alberta and we are certainly pursuing right now options that we would hope would see more export capacity coming out of Alberta.

Okay. Thank you very much.

Bob, it's Hal here. I just add to Alex's comment, we think it's a great opportunity for Alberta to fairly significantly increase electricity enter ties, and with a view to becoming a significant electricity exporter, there are many, many good cogeneration opportunities related to industrial development in Alberta, and I don't see any reason why Alberta should not be as committed to an electricity export industry as it is to gas and oil exports, these are all things Alberta can be vert good at, so we think a good big pipeline for the movement of electricity, if you will, is a key element of Alberta's strategy going forward and we of course encourage the Alberta government to think in that way.

And long that line, have you been looking at [Culdegas] or [Bichamon Cogens]?

Yes, we are looking at all of those things, we don't have anything active under development but we're certainly aware of the technologies and the opportunities and what it takes to make one of those projects succeed.

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. This is just a question on gas storage, I guess it's really a technical question, but in terms of booking the earnings from gas storage, are they booked when the gas goes in, are they booked over the term of the contract, and does the manner in which you book earnings differ when it's a fee for service as opposed to in the case of Edson where perhaps you are testing the waters there and putting some of your own gas in?

Maureen, it'ss Glenn. As far as Cross Alta goes, yes, they do charge a fee for service, so as a result, revenues booked as the services are provided. As far as Edson goes, we are reporting our own gas in the ground, assuming we hedge that gas that's in there, we will record it when the gas comes out.

And that would be the same with third party business.

And that's at Edson?

That would be at Edson or at our contracted facility.

Okay, so I'm confused, because I thought for third parties, it was fee for service.

Yes, on things like Cross Alta, the services are provided, we will charge a fee and record that as revenue.

Okay, at the time the gas goes in?

Yes, and over the --

And over the term of the--

Correct me if I'm wrong, Glenn, but that is probably more of an accrual kind of basis there, Maureen, so when it's fee for service, it's probably a flatter profile, if you will, to the earnings as opposed to something for our own account where you would recognizing the revenue on deliver of the gas at the other end of the contract.

Okay, and just another question for how it's more of a strategic question, Hal, I think from time to time you have mentioned an interest in looking at, I think you call it the northern tier, but perhaps I interpret it incorrectly. I don't know as the northern part of the U.S. Of course, you now have some interest in Mexico. Let me ask you about, would you be interested in if a large natural gas pipeline such as A and R came available, would that be of interest to you at the right price?

Most of the big U.S. pipelines have three parts to them, they've got a big presence in the gathering basis, they've got the long haul segment, and then they've got a big presence in the market area. And when we look at U.S. pipes, we are primarily concerned about three things: Is it a transaction that's big enough to make it worthwhile for TransCanada to get involved. When you do enter a new area, and you need to establish a new business presence. It's got to be big enough to be worth our while, and secondly, do we bring any particular knowledge to the opportunities so that we look at some where they are very interesting, but we don't think we are particularly competitive, and we've looked for example at offshore gas gathering in the U.S. Gulf Coast, and just didn't think that that was something where we would bring significant competitive advantage to the table.

So we look at a lot of different pipelines in the U.S., and, Maureen, we don't comment on any particular opportunity because we look at so many of them, but we are certainly interested in all of North America. What we don't do though is we don't for example go to Georgia and see that there's a 50-mile pipeline that we could buy, and take that on and then try to run a very small asset as part of our North American company. We are today certainly focused on the northern tier. The Canadian Mainline from Alberta to eastern markets and down into New York and Boston is obviously a core business for us.

Our plan to assume operator shift of northern border is a really key step forward for us, and the slow path from Alberta to Chicago is important to us. Great Lakes Gas Transmission, we of course have been very involved in the operation of that, and our new Chief Financial Officer, Greg Lohnes, is just returning from having been the President of Great Lakes, and then of course, the fourth leg is GTM, and the opportunities that exist in the whole western U.S. market. We think that's a market that we are very interested in, so somehow or another, things that we look at have to fit with all of that.

Mexico is a bit of a special case. We have been involved in two different Mexican pipelines historically, and I have personally had some previous experience in the energy sector in Mexico, and we just look at it as a really unique opportunity where we think we can be a highly competitive player, where we think we know how to deliver the kind of things that the Mexican state owned enterprises are looking for, whether it's Premex or CFE, and we think increasingly Mexico is part of NAFTA and we have some comfort dealing there so just in sort of fuzzy broad terms, Maureen, that's the way we look at all this.

It sound like that would probably meet your criteria.

It all depends on the specifics of the opportunity and we scrub them down pretty carefully.

That's great. Thanks very much.

Thank you.

Thank you.

[OPERATOR INSTRUCTIONS]

The next question is from Andrew Kuske from UBS, please go ahead.

Thank you, good afternoon. This is a question for Hal. Hal, I'm just interested in your thoughts on pension fund involvement and really non-traditional players in the infrastructure world? We've seen some fairly high prices by way of multiples pay for infrastructure assets globally, and to what degree would you want a joint venture with any pension funds and have you really been approached by any pension funds on potential acquisitions?

Well, of course, we are already partnered with Omars at Bruce, and we have a good relationship with them, and I think that's worked out well for both parties. It's often difficult at the time you are actually putting in acquisitions together to simultaneously try to put a partnership together, but in the right circumstance, we would do that. I think going up to a higher level though and looking at the whole emergence of private equity in North American infrastructure, I guess there's two big opportunities for us.

One is to--three big opportunities, one is to sell very mature infrastructure to some of these private equity players and we think about that all the time. The second is to partner with them and be the expert manager, if you will, for the private equity players, and we think that we have some knowledge about the business that they might like. And then not wishing anyone bad luck, but there are some situations where private equity gets in and find themselves in business that has more challenge than they were expecting, and we might be the third buyer in a situation like that.

And I recite those three examples because we've seen all of those in the past year, and we haven't done anything major to date, other than our very good relationship with Omars and we are interested though.

On the second of those three points, on the partnering, how big a transaction would you potentially look at, and if we could just walk through. I know in the previous questions, you highlighted some characteristics you look for, but when you see a partnership really on the pipeline side more than anything else?

I don't know. Depends on the circumstance. First of all, we are not any different than a lot of major players in different industries that if the opportunity is there, to do a transaction 100% TransCanada, and have complete operating and reinvestment flexibility without having to debate with other people what we ought to do, that's kind of the way we like to do it, and so I think you are more likely to see TransCanada play these things out 100% and then maybe rationalize assets later, that's-- that's more likely the approach for us.

We would have to see something fairly large to see you get involved with a pension fund, or private equity?

Yes, and then we'd have weigh that against all the other options for financing something really large.

That's great, thank you very much.

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

Thank you. Question on L&G supplies, I'm sure Shell is protected with you, but Petro Can doesn't appear to be. Is there a high degree of comfort at this stage on L&G supplies to enter your Quebec joint venture?

I missed a bit of that.

The security of L&G supply for your terminals, just can you provide some kind of color to that? Quebec is still uncertain it appears, whereas Shell I presume would be a reliable partner with their Egyptian L&G deals and contract?

If we are successful and we certainly hope we will be, in permitting the facility, it will be the responsibility of Petro Canada to bring L&G to that facility and certainly, from my own experience with Petro Canada, they are very committed to finding supply for that facility, and hopefully, we won't have very much longer to wait to see that occur. I don't know if Hal if you had any comments on that.

I just would add, certainly on the first part of your question with Shell, they not only have Egypt, they have a whole portfolio of opportunities, and when we looked for a partner on the New York project, we deliberately sought out what we thought was the premiere L&G player, globally, and that was Shell. They are able to do that.

Interestingly, at the grand opening of our Tamazunchale Pipeline in Mexico last week, that pipeline was purpose built to deliver gas from the Shell Altimira regas facility to CFE power plant in land, and it was notable that, a very large L&G tanker was offloading Shell global L&G as we were there, so they're a very big incredible player in that business.

In the case of Petro Canada, we chose to partner up with Petro Canada on the Cacouna project because the bring a strong Canadian element to it, but also we are confident of the work that Petro Canada is doing not just in one area, obviously they've talked about Russia, and getting L&G through the St. Petersburg project that they have jointly committed to Gazprom , but also, a number of other opposites that they have.

And one of the interesting things that's evolving in L&G is that it's traded, that you may have a physical supply arrangement with one supplier from one location but the actual cargos that show up at your sight come from somewhere else. So all of those things are possible. We are working well with Petro Canada, and they are working well with Gazprom. There has been some news, I guess, recently around Gazprom in their Stockman Field that was the offshore liquefaction project that was going to come over the top in Norway and to market, but that's not the project that Petro Canada was working on so theirs continues to be in good shape, and by all accounts, continues to be moving forward.

Thank you. As a follow up, kind of broad and strategic and long term I guess, there were some colorful estimates made by the Department of Natural Resources on sharply declining gas exports out of Canada to the U.S. We're about halfway through the alliance--15 year contract terms and conditions. Can you just kind of give your reaction to that particular report and what happens once Alliance does go into perhaps a spot market business against your various pipelines from Canada.

I'll comment first generally Sam, and then ask Russ to talk a little bit about some of the specific things that we are doing on the pipe side to deal with that. Obviously, gas consumption in western Canada is going to increase. We don't really have a scenario where gas consumption in western Canada goes down.

The increase ranges from relatively modest in a sort of business as usual scenario, normal economic growth would cause consumption to go up here in the west, and gas fired power generation is going to cause consumption to go up, and that ranges all the way through to a pretty high case which would probably be higher than what the National Energy Board sees, and that would be if a lot of natural gas continues to be used in [Bichamon] upgrading and other Fort McMurray activities, and so, but directionally, the middle of that would see gas consumption in western Canada increasing fairly significantly.

From a geological point of view, we have fair bit of capability here to asses the trend and where things are going in western Canada, and having broken the western Canada supply basin down into very analyzable bits, if you will, our team would be of the view that a very high rate of drilling is going to be required to bring on the 3 to 3 .5 bcf a day of new gas that's required every year just to offset natural decline. It's an extraordinary level of activity today, everybody is focussed on Fort McMurray, but the amount of money being spent out in other rural areas of Alberta bringing natural gas and conventional oil on stream is many times as much as the amount money that's being spent at Fort McMurray and we think that's significant.

Despite the expenditure of that enormous amount of capital, and I'm talking about north of $25 billion a year, we are not seeing any increase in gas production out of the west, so it's kind of like a very big flywheel that we think has reached maximum sustainable rate, and there's good evidence for that theory, the lower 48 in the U.S. reached its peak rate in 1981, and has been more or less flat line ever since, so these things can go on a long time and western Canada is the kind of basin that we think will sustain for a long time, given that it's made up of many, many thousands of very small pools.

We think Northern Gas coming on is going to be an important part of the mix, but of course that's out there. Our ability to compete with Alliance is pretty strong. We operate the bigger pipeline into Chicago and it's more depreciated and has operating and fuel cost advantages over an expanded Alliance, so we think we are good into that market. The Canadian Mainline has been depreciated significantly, and you'll note that our toll for moving gas on the main line peaked out at about $1.25 to move from Alberta to Ontario, and that's now down into the low $0.90.

So we've got a competitive flow path into Ontario. Similarly, GTM is the biggest volume, most competitive pipeline into the PAC Northwest, and down into the California. So I think we are pretty competitive on all three fronts. It will be interesting to see what the load factor on Alliance would be today if they didn't have firm service contracts. I think northern borders a pretty competitive way to go. Beyond that we have projects like Keystone and Russ maybe you could comment a little on that.

I think that's one of our responses to the competitive market environment, Sam, is the potential taking out of that line one out of service, and reducing the capacity out of the western sedimentary basin, so I'm sort of on the demand side. We're working on those fronts to bring supply and demand of pipeline capacity closer in line, and then up stream, working very hard as Hal mentioned earlier with producers in McKenzie and Alaska, and BC to try to bring new supplies into the marketplace, to fill these pipelines in the long haul, so a number of initiatives which we think are very positive for the Company and can lead to significant capital investment down the road.

Thanks.

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

Hi, I have a question on Bruce Power. The average realized price at Bruce B was 4,760. But the average spot price in Ontario was lower than that, it was around $46.00. I'm just wondering how Bruce B can realize an average price that is higher than the spot, given that it's base load, and given that a floor price is guaranteed of 45?

Sorry, the guaranteed floor price is on--with respect to Bruce B, your question about how we can achieve that price is, call it legacy contracts that we've already entered into at higher prices.

Okay, so that would imply that you've got contracts with counter parties higher than 47?

Yes.

Okay, and another question on GTN, this may be for Russ, I apologize, I wasn't on the Q1 conference call, I was just reading through transcripts recently and you talked about how GTN is in competition with Transwestern and Curran River. I don't understand how GTN competes with those two pipelines given that GTN seems to go into northern California.

I'm not sure what the context of the transcripts are, I would agree with you that GTN competes mostly for Northern California. Those pipes come into Souther California. There is some capacity to move north, but it's not substantial, so I would agree with your comment.

But there is, Dominique, a certain amount of price interchangeability between the north and south because a PG&E system has capacity to move gas in both directions. We do find that when the price in California goes down as a result of additional Curran River volumes coming in, it tends to go down in the northern part of the state as well as the south, and in those circumstances, western Canadian producers find our main line to the Ontario market a much better choice. The gas can tend to move around from one to the other, but there are limits to that, and on balance over a 365 day period, GTM does pretty good getting its share of the California market.

Okay, so the reason the pricing in Northern California would be similar to Southern California is related to flows?

I think as Hal mentioned they are connected, the aligned 300 which is a PG&E line, so you can move some gas, but it is limited, so it helps if prices move down in Southern California, as much as gas is possible, will be trapped north which will have an impact on (inaudible) pricing, which is essentially the pricing point for GTN gas moving into Northern California. So the overall prices in California do impact Northern California. But I would agree with your statement that the flows are limited, but obviously there are flows and that influences pricing.

Thank you.

Thank you. The next question is from Karen Taylor from BMO Capital Markets. Please go ahead.

I have just a very quick question on the natural gas storage, the 24 million of operating margin in the quarter, can you break that down between your own activities at Edson if there was any contribution from those and then fee for service from third parties?

No, Karen, I don't think we do break that down. Obviously, we are a competitive storage player here, and I think that's the best we can do for you.

So when the question was asked earlier about the nature of booking the revenues for that particular business, there was some uncertainty as to whether or not or some reflected in the answer as to whether or not you do hedge the gas for an equity gas position going into Edson. Do you absolutely always hedge that so it's doing a simultaneous buy sell?

I wonder if Dave Mineta or Glenn Monouse could get back to you on that. We think we know the answer, but we want to be absolutely precise on that, and it depends, there's four or five different circumstances, and it can be different in each one.

Okay.

Thank you. The next question is from Josh Golden from JP Morgan. Please go ahead.

Sorry, it's Alex, I just wanted to jump in on that. Karen, for your question with respect to when we put our own gas into the facility, yes, our practice to date, 100% of all purchases of gas that we have made to go into the facility, we have executed at the exact moment a sale, gas that we are putting in is always--is bought and sold at the same time, we are not at this point at all holding speculative open gas positions in the facility.

Sorry, go ahead.

Hello, good afternoon. You really talked briefly about making acquisitions potentially. My question really relates to credit ratings, you are still in negative outlook with an A minus rating at Standard and Poors. Would you be willing to sacrifice that for acquisition and then given your appetite for acquisitions, can you talk to me about financing alternatives, potentially to stay A rated?

This is Greg Lohnes, we are dedicated to the A rating. The negative outlook from S&P has primarily been a attributed to some large construction exposure. We don't really think that is, deserved, but we continue to talk about that. We continue to do a really good job of bringing in projects on time and on budget so we think we have a good track record for large capital projects.

Going forward, when we do look at capital spend, whether it's Greenfield or acquisition, we look at our entire portfolio of assets, and we determine how best to keep our metrics in line with the rating agencies, we have ongoing discussions with them in that regard, and then we take such steps as we think are appropriate, in order to manage our large capital spend program and the profile we see going forward consistent with the credit rating.

I hear that being said but for the proper acquisition though would you be willing to sacrifice the A rating and move into a high triple B rating?

No, we're not, and we don't think we have to do that. We have very strong financing capability, just as a general point, Josh, we are--we would prefer to run the Company with less debt rather than more debt, and we continue to work with our Canadian regulators to move our equity thickness up.

We think from a regulated perspective here in Canada, we are currently required to operate with equity that's thinner than it should be, and so we continue to do that. All of these things directionally will strengthen our credit rating, and as we contemplate any kind of an acquisition, one of the pre-conditions, we have to have a way to finance that will not cause the downgrade.

Okay. Thank you gentlemen, that answered my question.

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

Thank you very much. Just if I could get clarification on the time line regarding the regulatory process for Keystone, you mentioned that-- I believe you mentioned you are intending to file an application with the NEB at the end of the year?

Before the end of the year, the full facility's application, Maureen, we filed for the transfer of the gas pipeline to oil pipeline back, I think it was October 23rd, the hearing started. We filed that back in July, I believe.

So I guess I'm just wondering if you anticipate a decision on the application to transfer before you file the full facilities application.

No, that will be concurrent, I would expect the progress of the hearing to date on the, we'll call it second 74 application which is the transfer application. I'd expect that to come to conclusion maybe the middle of November and then we are looking sort of 90 days from there for decision making so January, February, March of next year. We would expect to file the section 52 application which is the facilities application as you mentioned sometime before the end of the year, so I don't think that we will have a decision on the 74 before we file the 52.

So with the 90 days, then if we just took that and if you were finished in the mid-November, we would maybe be looking for mid-February?

Yes, I think that whenever that hearing ends you can use 90 days as sort of a proxy of when we think we'll get that decision. And I guess because you haven't filed yet, there wouldn't be a hearing at this point scheduled of course for the--what do you call it, section 52? Right, we'll probably take a gain from the time we filed that, and I think you can look at it to gain probably some 90 days to the beginning of a hearing process.

And then another 90 dates from of the end of the hearing to a decision?

Yes, so you're looking at something that looks like probably 7 months, something like that from the time you file to the time you get a decision.

Okay, thanks.

Thank you. There are no further questions from the investment community.

I would now like to turn the meeting back over to Mr. Moneta.

Thanks, just before we close, we would be more than happy to accept any questions from the media, so to the extent that the media has questions, please feel free to queue up at this point in time.

[OPERATOR INSTRUCTIONS] The first question is from Elsie Ross from Daily Oil Bulletin.

Hi, just a fast question about--you mentioned the expansion, potential expansion of GTN. What do you see along those lines?

I think that couple of things that we are looking at is that the region is basically getting greater access with the Pacific Northwest market, we're always looking to attach our pipes to the market growth and capture as much of that market growth as we can. So I would say in the near term, GTN's expansion would be centered around attaching to Pacific northwest residential industrial commercial loads through the LDCs which we can probably direct connect, but through the LDC there and their increasing loads.

So, Elsie, at this time, it's mostly connecting new markets within the Pacific Northwest market region, it's not expanding the long haul capacity out of Alberta.

Good. Thank you very much.

Thank you. 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 just in closing, I would like to thank everybody for participating today, we appreciate your interest in TransCanada and we look forward to speaking to you again very soon. Bye for now.

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