TC Energy Corp (TRP) 2006 Q2 法說會逐字稿

Good afternoon ladies and gentlemen. Welcome to the TransCanada Corporation 2006 second quarter results conference call. Please be advised that this conference is being recorded. 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, and thanks to all of you as well for participating this afternoon. We'd like to welcome you. We're pleased to provide the investment community, the media, and other interested parties with an opportunity to discuss our 2006 second quarter financial results and other general issues concerning TransCanada.

With me today are Hal Kvisle, President and Chief Executive Officer; Russ Girling, President of Pipelines; and Lee Hobbs, Vice President and Controller. Hal and Russ will start today with some comments on our financial results and other general issues pertaining to TransCanada. And following their remarks we will turn the call over to the conference coordinator for 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 additional questions, please re-enter the queue. Also, in an effort to maximize the use of everyone's time, we ask that you try and focus your questions on our industry, 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, I would be pleased to discuss them with you following the call.

Before Hal begins, I'd like to remind you that certain information in this presentation includes forward-looking statements. All forward-looking statements are based on TransCanada's beliefs and assumptions based on information available at the time the assumptions were made.

Forward-looking statements relate to, among other things, anticipated financial performance, business prospects, strategies, regulatory developments, new services, market forces, commitments and technological developments. By its nature, such forward-looking information is subject to various risks and uncertainties, including those material risks discussed in the MD&A contained in TransCanada's 2005 annual report, which could cause TransCanada's actual results and experience to differ materially from the anticipated results or other expectations expressed.

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'll now turn the call over to Hal.

Good afternoon everyone and thank you for joining us. I'm pleased to say that we've had another good quarter. TransCanada's strong operating performance during the first six months of 2006 has contributed to continued growth in net earnings and incomes generated from operations.

Earlier today we announced net earnings per second quarter 2006 of $244 million, or $0.50 per share, an increase of 44 million, or $0.09 per share. Excluding certain items relating to income taxes and asset sales in 2006, and the impact of an NEB decision in 2005, net earnings for the second quarter 2006 increased by $11 million or $0.02 per share, an increase of approximately 6%.

On a year-to-date basis, net earnings were 489 million, or $1 per share compared to 432 million, or $0.89 per share in the year previous. Excluding the items noted above, as well as gains related to a bankruptcy settlement in 2006, and the sale of TC PipeLines LP common units in 2005, net earnings for the six months ended June 30, 2006 increased by 55 million, or $0.11 per share, an increase of approximately 15%.

For both the quarter and the half year the increase in net earnings was primarily due to significantly higher net earnings from our energy businesses and lower net expenses in corporate. This increase from our energy businesses is evidence that our disciplined approach to growth and value creation is working. Our emphasis on acquiring low cost competitive power facilities and developing low risk greenfield power projects is creating real value for our shareholders.

TransCanada's pipeline business continues to deliver solid results, although net earnings declined primarily as a result of lower rates of return on common equity, and lower average investment basis on our Canadian wholly-owned pipelines.

I would note that TransCanada's Board of Directors today declared a quarterly dividend of $0.32 per share for the quarter ended September 30, 2006, on all outstanding common shares. This marks the 171st consecutive quarterly dividend paid by TransCanada and its subsidiaries. The dividend is payable on October 31, 2006 to shareholders of record at the close of business on September 29.

Before I provide an update on recent developments, I'd like to briefly speak to the recent changes in TransCanada's management structure. Effective June 1, Russ Girling was named President of Pipelines, with oversight of our natural gas and oil pipeline businesses. Alex Pourbaix was named President Energy, responsible for our power, liquefied natural gas, and natural gas storage businesses.

As you will have noted in the quarterly report, these changes have had a slight impact on the way in which we report our results. Beginning with this quarter, our reportable segments are now Pipelines and Energy, and our segmented information has been retroactively restated to reflect this change. I would emphasize these changes have had no impact on our consolidated net income.

You'll also note that Greg Lohnes has been named our new Chief Financial Officer. Greg brings strong legal, financial and line management skills to his new role, having served most recently as President and Chief Executive Officer of Great Lakes Gas Transmission in Troy, Michigan. Greg is now transitioning to the CFO role, and is locating back here to Calgary.

Effective September 1st, the new President of Great Lakes Gas Transmission will be Lee Hobbs, who most recently had served as Vice President and Controller at TransCanada. Moving into the Controller position is [Glen Monouse], who has worked with Lee Hobbs for a number of years as our Assistant Controller.

We are continuing to work through these transitions. Russ and Lee will be participating in today's conference call. In October you will hear from Greg Lohnes and Glen Monouse on our third quarter results.

With these changes, our executive team remains focused on maximizing the long-term value of our existing asset base and prudently growing our portfolio of blue chip, long life energy infrastructure assets. We today have an excellent portfolio of growth opportunities.

Significantly we have a number of projects that are now nearing completion. By the end of this year, the 550 MW Becancour cogeneration plant, the initial phase of the 740 MW Cartier Wind project, the Edson natural gas storage facility, and the Tamazunchale pipeline in Mexico are all expected to begin commercial operations.

In our Pipelines business we have a strong portfolio of growth opportunities. Of note, we continue to make good progress on the Keystone Oil Pipeline, our cost competitive proposal to transport crude oil from Alberta to key refining centers in the US Midwest.

In June, we filed the first of two major regulatory applications with the National Energy Board here in Canada. In this application we are asking for NEB approval to convert a portion of the Canadian Mainline to crude oil transmission service, an innovative feature of our proposal that minimizes the environmental impact and the disruption of building new pipeline, and reduces the overall cost of materials and labor. The NEB has scheduled an oral public hearing on our application to commence on October 23, 2006.

We also continue to pursue regulatory approvals for that project in the United States, where we are conducting preliminary engineering work and consulting with stakeholders along the proposed pipeline route. We anticipate holding a binding open season on the proposed extension of the Keystone pipeline to Cushing, Oklahoma. And we expect that open season will occur later this year. That would extend Keystone pipeline from its current terminus -- or an intersection near [plat] in Nebraska down to Cushing, Oklahoma. We think that's a significant opportunity for us.

TransCanada's Keystone pipeline enjoys strong shipper support, and is the only new pipeline proposal that would ship Alberta crude oil that holds binding long-term contracts with shippers today. Pending regulatory approvals, our anticipated in-service date of late 2009 would see Keystone as the first new pipeline available to meet the increasingly critical need for increased crude oil transportation capacity from Alberta to key US Midwest markets. We remain committed to pursuing pipeline opportunities that will move northern frontier natural gas to growing North American markets.

In June we filed an application with the Alberta Energy and Utilities Board seeking approval to build natural gas transmission infrastructure in northern Alberta, which would serve to connect natural gas from the Mackenzie gas pipeline project to our existing Alberta System. The infrastructure we propose to build is dependent upon the timing of the Mackenzie project. We have participated in public hearings, and we continue to work with other project proponents to review project costs for the Mackenzie project itself.

Turning to Alaska, we are monitoring the special session of the state legislature and the status of the petroleum production tax bill currently before Alaska legislators. Progress on the gas pipeline agreement between the state and Alaska North Slope producers remains contingent on the legislative approval and enactment of the tax bill.

In July, I wrote to the governor of Alaska and reinforced TransCanada's support for the gas pipeline agreement. At the same time, I raised our concerns with specific provisions of that agreement that could lead to difficulty in Canada. Specifically, we object to provisions that specify joint state producer ownership within Canada, as well as provisions that commit the state to an NEB regulatory process in Canada.

We have asked the governor to amend the contract and either defer determination of ownership in Canada, or reflect the key elements of the commercial agreement with TransCanada in the contract prior to ratification by the Alaska Legislative Assembly.

I would note that TransCanada and its predecessors have invested several billion dollars to prebuild and pre-engineer the Alaska Highway project within Canada, and we will take all necessary actions to protect investments that were reviewed, approved and implemented pursuant to Canada's Northern Pipeline Act.

Having said that, we are pursuing commercial negotiations with the Alaska North Slope producers, which we expect will lead to a commercial win-win arrangement for the movement of Alaska gas to our Alberta hub, and from there on to North American markets. TransCanada looks forward to working with the state of Alaska and the Alaska North Slope producers to move this important project forward.

Concurrent with pursuing our growth opportunities we continue to maximize our existing assets through pipeline system expansions driven by customer needs, and in the case of our gas transmission northwest system, by working with regulators to ensure a fair return on our invested capital.

In June, the GTM system filed a rate case with the US Federal Energy Regulatory Commission requesting tariff changes, including an increase in rates for certain services. This is the GTM systems' first rate case since 1994. The rate case is driven by significant and fundamental changes to the competitive environment in which the GTM system operates.

The GTM system is an important part of the energy infrastructure in the western United States, and continues to deliver roughly one-fifth of the natural gas consumed in the Pacific Northwest and California. I would note that even with the proposed higher tariffs, GTM would continue to be a very cost-efficient route to market for Alberta gas producers.

Turning to our Energy business, we have an excellent set of growth opportunities. In the near-term, our Becancour Quebec cogeneration plant, our largest cogen plant to date, is expected to begin commercial operations this fall, delivering power under contract to Hydro-Quebec Distribution.

Also in Quebec, two of the six wind farms that make up the Cartier Wind project are now under construction, with the first of those facilities anticipated to be operational by the end of this year, and the second by the end of 2007. TransCanada owns 62% of Cartier Wind, which will deliver a total of approximately 740 MW of power under long-term contract to Hydro-Quebec Distribution.

TransCanada continues to explore further wind power opportunities in Quebec in response to Hydro-Quebec Distribution's October 2005 request for proposals for an additional 2000 MW of wind generated energy.

In Ontario, preliminary site work has begun in preparation for the construction of the Portlands Energy Center, a 550 MW high-efficiency combined cycle generating station located in downtown Toronto. With our partner, Ontario Power Generation, TransCanada is working to complete negotiations for a long-term power purchase arrangement with the Ontario Power Authority.

Also in Ontario at Bruce Power, the restart and refurbishment of the Bruce A facilities continues as expected. In July the Canadian Nuclear Safety Commission accepted the project's environmental assessment, enabling the project to move beyond the preparatory phase and onto the next stage of restart activities. Already more than 800 contract workers are on-site. That number will ramp up to an expected peak of about 1,700 workers by 2007. The first of 16 new steam generators destined for Units 1 and 2 is expected to arrive from [Babcock & Wilcox this summer.

In natural gas storage, we're nearing completion of our Edson gas storage facility, TransCanada's investments in natural gas storage, we owns 60% of CrossAlta and hold interests in another third party facility here in Alberta. Those investments continue to deliver solid results, and we see natural gas storage as a strong complement to our pipeline business.

And in liquefied natural gas we continued to make progress on our Cacouna and Broadwater projects. Public hearings on the Cacouna energy project concluded in June. Regulatory decisions are anticipated by the end of this year. And pending regulatory approvals, we remain on track to begin operations in late 2009 or early 2010. Similarly, the Broadwater LNG project in New York continues to move through the regulatory process. Pending regulatory approvals, Broadwater plans to begin operation in late 2010.

To conclude my remarks, I would reinforce TransCanada's continued commitment to the disciplined and prudent approach to growth that has, and continues, to create real value for our shareholders. We have an excellent portfolio of growth opportunities. We have a strong balance sheet, and we have the financial flexibility to support our existing and our new initiatives. I would now like to turn the call over to Russ Girling.

As Hal mentioned earlier today we released our second quarter results. In net income from continuing operations, or as we define it in the quarterly net earnings for the second quarter were $244 million, or $0.50 per share compared to $200 million, or $0.41 per share for the same period last year.

As noted in our quarterly report, second quarter 2006 net earnings included a $33 million future income tax benefit as a result of a reduction in Canadian federal and provincial corporate tax rates, and a $13 million after-tax gain related to the sale of the Company's general partner interest in Northern Border Partners LP.

Second quarter 2005 net earnings included $13 million related to National Energy Board April 2005 decision on phase 2 of the Canadian Mainline's 2004 Tolls and Tariff Application. Excluding those items, net earnings for the second quarter of 2006 increased by $0.02 per share, or approximately 6% when compared to the second quarter of 2005. For the six months ended June 30, 2006, TransCanada's net earnings were $489 million, or $1 per share, compared to $432 million, or $0.89 per share for the same period in 2005.

In addition to second quarter items previously noted, net earnings for the first half of 2006 include an $18 million after-tax bankruptcy settlement received from a former shipper on the Gas Transmission Northwest System. And net earnings for the first half of 2005 include an after-tax gain of $49 million on the sale of TC PipeLines LP common units. Excluding all of the items noted, net earnings for the six months ended June 30, 2006 increased by $0.11 per share, or approximately 15% when compared to the same period last year.

The quarter-over-quarter and year-over-year increases were primarily due to higher net earnings from the Energy segment and lower net expenses in corporate, partially offset by lower net earnings from the Pipelines segment. I will briefly now review the second quarter results for each of our segments, beginning with Pipelines.

The Pipeline business generated net earnings of $147 million during the second quarter compared to $166 million for the same period in 2005. As mentioned, this year's results include a $13 million after-tax gain on the sale of TransCanada's 17.5% general partner interest in Northern Border Partners LP, while net earnings in the second quarter of 2005 included $13 million related to 2004 as a result of a decision from the National Energy Board in April of 2005 on phase 2 of the Canadian Mainline 2004 Tolls and Tariff Application.

Excluding these amounts, net earnings for the second quarter decreased by $19 million compared to the same period last year, primarily due to lower contributions from the Canadian Mainline and the Alberta System. As we have said before, lower contributions were primarily due to a combination of lower approved rates of return on common equity and lower average investment basis for both pipelines.

I will now make some comments on our Energy business. As Hal mentioned in his opening remarks, the Energy segment includes our power operations, as well as our initiatives in natural gas storage and liquefied natural gas. Energy generated net earnings of $97 million in the quarter, more than double last year's net earnings of $41 million. A $56 million increase was due to higher operating income from each of our existing businesses, as well as a $23 million future income tax benefit resulting from a reduction in Canadian federal and provincial corporate income tax rates.

Bruce Power contributed $41 million of pre-tax income in the second quarter compared to $13 million last year. The $28 million increase from Bruce Power was primarily due to higher generation volumes, and an increased ownership interest in the Bruce A facilities, which was partially offset by lower overall realized prices.

Overall, approximately 74 reactor days of planned and unplanned maintenance outages occurred in the second quarter compared to 142 days of outages in 2005. As a result, Bruce units ran at a combined average availability of 84% in the second quarter compared to 71% availability during the same period last year. The improvement in plant availability and our increased ownership in the interest in Bruce A increased TransCanada's share of power output from Bruce Power to 3,094 Gwh in the second quarter compared to 2,306 Gwh last year.

During the second quarter, Bruce Power realized an average price of $51 per Mwh compared to an average price of $53 per Mwh in the second quarter 2005. Approximately 39% of the output was sold into Ontario's wholesale spot market, with the remainder being sold under long-term contracts. On a per unit basis, operating costs decreased to $37 per Mwh in the second quarter from $46 per Mwh last year. The decrease in cost per megawatt hour was primarily due to increase in output in the second quarter.

Going forward, income from Bruce B will be impacted by fluctuations in wholesale spot market prices for electricity, as well as overall plant availability, which in turn is impacted by scheduled and unscheduled maintenance.

To reduce exposure to spot market prices, Bruce B has entered into fixed price sales contracts to sell forward approximately 6,700 Gwh of output for the remainder of 2006, and 6,300 Gwh of output for 2007.

It is also important to remember that sales by Bruce B are subject to a floor price, which is adjusted annually for inflation on April 1, as a result of a contract with the Ontario Power Authority. Effective April 1, 2006, the Bruce B floor price was $45.99 per Mwh. Under the same contract with the OPA, all of the output from Bruce A is sold at a fixed price, which is also adjusted annually for inflation on April 1. In fact on April 1, 2006, the Bruce A fixed price was $58.63 per Mwh. In addition it's important to remember that the Bruce A price -- or Bruce A contract also recovers fuel costs from the OPA.

Overall plant availability for 2006 is still expected to be in the low 90% range for the four Bruce B units, and in the loan 80% range for the two Bruce A units. The only remaining planned maintenance outage in 2006 is for Bruce B Unit 8. It is expected to last approximately two months, and is scheduled to begin in the third quarter.

Now turning to Western operations, Western operations operating income was $46 million in the second quarter compared to $28 million last year. The increase of $18 million 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 29% as a result of an approximate 4% increase in the spot market price of power in the second quarter of 2006 compared to the same period 2005, while average spot market gas prices decreased by approximately 18%.

In the second quarter of 2006 approximately 37% of Western power sales volumes were sold into the spot market compared to 13% in the second quarter last year. The increase in spot market sales was primarily due in gains to the acquisition of the Sheerness PPA at the end of last year.

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 being subject to spot market price volatility. This approach to portfolio management assists in minimizing costs in situations where TransCanada would otherwise have to purchase power in the open market to fulfill its contractual obligations.

To reduce our exposure to future spot market prices, as of June 30th Western operations had fixed price sales contracts to sell approximately 5,900 Gwh of power for the remainder of 2006, and approximately 7,900 Gwh for 2007.

Finally in power, Eastern operations, operating income in the second quarter was $43 million compared to $39 million last year. The increase was primarily due to higher overall margins earned on the sale of power, and profits earned on natural gas purchased and resold under the OSP gas supply contract. Partially offsetting these increases was the negative impact of a weaker U.S. dollar, and an increase in the cost of generating power, primarily resulting from an increase in fuel costs associated with the increased dispatch of the OSP facility.

Overall in the second quarter, approximately 93% of Eastern power sales volumes were sold under contract. The remaining 7% was sold into the spot market. Looking forward, as of June 30, Eastern power operations had fixed price sales contracts to sell approximately 2,700 Gwh of power for the remainder of 2006, and approximately 4,400 Gwh for 2007.

Finally, in the Energy segment, natural gas storage, operating income of $17 million in the second quarter was $14 million higher compared to the same period last year. The increase was primarily due to higher contributions from CrossAlta as a result of increased capacity and higher natural gas storage spreads, and income from other contracted third party natural gas storage capacity that we have in Alberta.

Now I will turn to corporate. Net expenses in the second quarter were nil compared to $7 million for the same period last year. The $7 million decrease was primarily due to the $10 million favorable impact of future income taxes arising from a reduction in the Canadian federal and provincial corporate tax rates.

Now turning to cash flow, funds generated from operations were $539 million in the second quarter, an increase of $41 million when compared to the same period in 2005. Capital expenditures in the second quarter were $327 million, and related primarily to the ongoing development of greenfield projects, such as the Bruce A restart, Becancour, Cartier Wind, Tamazunchale and Edson, as well as growth in maintenance capital associated with the Canadian Mainline and the Alberta System. For the year our capital program is currently expected to total approximately $1.4 billion.

In conclusion, our balance sheet, as Hal mentioned, remains very strong. It now consists of 57% debt, 3% preferred securities, 2% preferred shares, and 38% common equity at the end of June. The strength of our balance sheet and our strong cash flow gives us the financial flexibility to continue to grow profitably into the future.

As we move forward, we will continue to prudently reinvest our discretionary cash flow to make profitable investments in our core businesses of power, and natural gas pipelines and other pipelines. We will continue to maintain our strong financial position. As we have said before, successful execution of these strategies will continue to deliver superior total shareholder returns for our shareholders.

That concludes our prepared remarks, and I'll turn the call back over to David for the question and answer period.

Just before I turn it back to the conference coordinator, just a reminder that as part of the question answer period we will take questions from the investment community first, followed by the media. As I mentioned earlier, we would appreciate it if you just hold it to two questions, and then re-enter the queue if you have additional questions. With that, I'll turn it over to the conference coordinator.

(OPERATOR INSTRUCTIONS). Linda Ezergailis, TD Newcrest.

Hal, I believe you mentioned that the 2006 capital budget is now $1.4 billion. I believe on the last disclosure it was $1.3 billion. Is that related to scope change, or are you seeing capital cost pressures in your projects?

We're seeing a range of different things on our major pipeline projects, which would account for about one-third of our power total capital budget. We are really not seeing a lot in the way of cost pressures. We're perhaps accessing a different contractor community, but generally those projects are coming in reasonably close to expectation.

We've had some situations, like our Edson gas storage, where costs have been higher than expected. Some part of that project involved drilling and developing of the reservoir with horizontal wells. And like the whole drilling community here in Alberta, we experienced slightly higher costs.

But I think the increase would be more than half of it due to just additional work. We've taken on some extra looping of pipelines and some extra connection of new sources of gas to our Alberta System, and those would be the bulk of it. This is not simply inflationary cost pressures.

What about on the operating side? Are you seeing high year-over-year inflationary pressures?

Well there is certainly inflation, but it depends on location. In our pipeline businesses here in Alberta, operating costs are really pretty small, and we're not seeing a significant escalation in costs. We can certainly control the costs on our pipeline systems just by the pace at which we conduct major maintenance work, and that's exactly what we're doing. Different areas in Bruce, for example, there will be just a little bit more inflation, but certainly not what you'd be seeing in the upstream sector here in Alberta.

Just in terms of my second question. Very quickly you provided us an update on the Bruce restart steam generator status. Can you give us a quick little snapshot of what's going on in turbines and electrical and the retubing?

Yet to come, I would say. Most of what we've been focused on is the steam generator work. I'm not really up to speed to give you the details on the other.

Maybe I'll follow up off line then.

That would be great, thanks.

Sam Kanes, Scotia Capital.

One on opportunities and pipelines, one on risks. The opportunity, albeit it is not very big -- I noticed Penn West announced a $750 million CO2 pipeline for tertiary oil recovery in Alberta. That is something that naturally fits with you folks -- total gasifiers and asphaltine gasifiers, Citgas has become [bold too] with $75 oil. I am just wondering how active you are in that area and is it truly a natural fit?

We are active. We're actively looking at the full range of things that are going to be required to make some of these enormous Fort McMurray projects work. CO2 is an interesting area. The movement of CO2 from various sources to various enhanced recovery projects is potentially an attractive business. Although we also acknowledge that there are many other players that are active in what would be relatively small diameter pipelines. And we don't necessarily see that we would have a natural competitive advantage there that we feel when you get into the big diameter stuff where we would be more of a dominant player.

So having said that, we are looking at it. We are staying on top of it. We do want to know what is going on in the CO2 space here in Alberta, and we will continue to do that. I would just point out one of the major problems with CO2 that is often overlooked by the proponents of these projects is the enormous compression cost in recovering CO2 from atmospheric sources. To try to capture CO2 out of the flue gas at a coal-fired power plant is extremely expensive.

Some of these other projects getting CO2 out of a gasification facility, or recovering in at Fort McMurray, may have some promise, in that the CO2 gas is available at a slightly higher pressure, maybe 100 pounds, and that make a huge difference.

On the gasification side, we continue to operate in what I would call watching brief mode. We are interested in gasification. We're always interested in anything that would make more synthetic gas available to consumers in the Fort McMurray area, because of course our interest is in moving Alberta's gas over long distances to markets in eastern North America, California, and the Midwest. And to the extent that more synthetic gas is available for industries' needs here in Alberta, that improves the long-term sustainability of our big pipe systems.

So we are interested in that. But at this point, Sam, we're not the proponent of any particular project on either the gasification or the CO2 side. I will just add to that we are also obviously interested in the crude oil pipeline opportunities that are related to Fort McMurray. And we've talked about Keystone, and I think you're well aware of what we're doing on the project, but that's an example of the third leg, I guess, of our Fort McMurray related focus.

My second question on risks. FERC came up pretty bluntly it seemed a few weeks back and told Alaska that in effect it has approved a lot of LNG terminals lately, and that they're risking being cut out entirely. I'm not sure if that was a veiled threat, or put added pressure onto this latest, I guess, special session. Could you elaborate a bit on that and your general view of LNG versus Frontier Pipelines since the last time we talked about this issue?

TransCanada's outlook for the gas market in North America firstly is driven by demand side pressure. We see continuing growth in gas consumption in the power gen sector, and all of that translates into a demand side that continues to grow. Even in the face of high prices, we don't really forecast the demand is going to contract. We think the price will rise until the available amount of gas is apportioned or allocated among all the users.

So we don't actually see any excess on the supply side -- sorry, we don't see any decline on the demand side, and that means that we have to see growth on the supply side. Our forecasts show conventional production in North America at essentially a flat line level. We think that Western Canada will probably remain stable at 17 Bcf a day plus or minus a little bit. Similarly, the lower 48 it is around 50 Bcf a day, and has been there for a long, long time.

So to meet the growth, we think there needs to be 15 Bcf a day of new gas coming into the market roughly over the next 10 years. And our forecasts would expect 1 Bcf a day out of the Mackenzie. We think the market needs and will get 4 Bcf a day from Alaska. But we also acknowledge that that's a very big project that seems to suffer a year for year delay for just about every year that goes by. And then we would see in addition to that about 10 Bcf a day of LNG coming in.

In all cases, we have an issue about where the gas enters the market, with Alaska and Mackenzie entering through the Alberta hub, and much of the LNG coming in through the U.S. Gulf Coast. For us, that means that there is significant pipeline investment required to get the gas from those locations to the end burner tip, and that's one of the drivers for us in focusing on projects in the Northeast United States and Eastern Canada.

For example, our Broadwater project in New York, which really meets the need very well by bringing a Bcf a day right into the biggest burner tip, if you will, in North America in New York City, and also provides high flexibility storage to meet short-term peaks in New York. Similarly our Quebec project brings gas into a very high net back region at the extreme eastern end of the Canadian Mainline.

So we think both are going to be required. Sam, I don't have an opinion on FERC's comment. I think FERC is genuinely concerned that the project could be delayed if Alaska doesn't move quickly here to ratify an agreement. We've seen it before that when these projects don't go ahead as planned, it can take the proponents quite a number of years to regroup and rethink and come up with a different plan. So that would be my main concern is that if we don't move forward quickly, the Alaska producers may have to pull back and think about it for a while before they try again.

Karen Taylor with BMO Capital Markets.

I have three quick questions. Could you please I guess maybe, Russ or David, tell me year-to-date what we have capitalized for Keystone, Cacouna and Broadwater, and what those those totals are in aggregate?

We'll get those for you, Karen. I just want to look up the numbers that we have in here.

My second quick question is just what the new effective tax rate would be with the reduction. So you were at 33 roughly before, where will we be now?

Roughly 33. 2006, after this is going to look something like 32.5. 2007, something like 32.1. 2008, about 30.5. 2009, at 30. 2010 at 29, the Alberta and [federated[ combined.

Perfect. I am not sure I care about them that far out, but thank you.

Well, I thought you might want them, Karen.

Just lastly, the Montreal Gazette is reporting that one of the steam hubs for the big Concord facility, the magnesium plants that are there -- is up for sale. And they're threatening to close it if a buyer can't be found. Will that in any way affect the power purchase agreement with Hydro-Quebec Distribution?

It's an interesting question. My quick answer is no it won't, but the whole project was put together on the assumption that these things would continue to operate. But we obviously plan for them with contingencies that we can't predict what third parties are going to do. I do know this kind of a hardware facility that we put together can easily be adapted to accommodate that kind of the change. But having said all of that, we expect it will continue to operate.

So because it is a cogen, and that's what's anticipated in the contract with Hydro-Quebec Distribution, if you lose your steam hoster, a significant part of the steam host community I guess, there's no change in the terms of that contract that would adversely affect you?

We're not aware of that, but we appreciate you raising the point. I will go back and ask about that, but I'm quite sure that's not the case.

Okay. Thank you.

Just on your question of capitalization, I've noted in the second quarter for Broadwater we capitalized 23 million year-to-date. On Keystone, 10 million year-to-date. And on Cacouna, we haven't capitalized anything yet.

And in total then on -- and I wasn't sure what (multiple speakers)

A total of Broadwater and Keystone would be 33 million capitalized.

In total or just year-to-date?

In total.

That's it, thank you.

That's life to date.

Okay.

Matthew Akman, CIBC World Markets.

The on oil pipelines, Enbridge announced the successful approval of their extension of southern access to Patoka, which is a market that is located right next to Wood River where Keystone is supposed to go, and how you had spoke about an open season to extend Keystone down further south to Cushing. So I'm just wondering whether you think that if the extension to Cushing doesn't get approval support that it still make sense to drop 400,000 barrels a day in Wood River, despite the fact that Enbridge is going to drop 400,000 next door in [Patoka}?

We think it does. We don't know who Enbridge is moving their crude oil for, or under what contract terms. We do know that we're moving crude oil into the Wood River region with very credible players under long-term firm contracts. So it's the contractual nature of our project that gives us comfort.

If we were to extend the pipeline down to Cushing, we would only do so on the basis that we would have -- we would be looking for contracts, and we would get contracts from additional parties that wanted to move additional crude down to Cushing. So that would involve taking the total capacity of our system above the current contracted level.

But just long and short, we think arranging contracts for long-term shipment is an important part of these projects, and that's the way we've approached it. So it really doesn't matter what someone else is bringing into Patoka, if our shippers are committed to move volumes on our system that gives us a lot of comfort.

Okay. Then shifting gears to storage, my second question is -- the storage numbers look great and obviously storage spreads have widened and you guys are bringing even more on stream, so this is looking more and more like sustainable upside here. Is that a fair way to characterize it?

Yes, we are obviously quite enthused about storage right now. I think there's two drivers to it. In the very short term, this is a remarkable year for storage, driven by the very wide summer to winter spread in gas prices. And whether or not that will continue in future years is impossible to predict.

But the second point I would make is that natural gas in future years is likely to be a much more valuable commodity than it was, say, in the 1990s. And the economic ramp, if you will, you can capture for storing a valuable commodity would tend to be more than what you could capture for storing a very low-priced commodity that's in general surplus. So we think the longer-term fundamentals, as well as the short-term opportunity, look pretty good. I also point out that we have got three very good assets in the storage business here in Alberta, and we're very comfortable with the quality of our position.

Do you have visibility at on that at least through part of 2007?

We have structured our commercial business so that a lot of it is back-to-back so that we do know what the outcomes are going to be as we head into future quarters.

Thanks a lot, those are my questions.

Maureen Howe, RBC Capital Markets.

Thanks very much. Just a couple pretty straightforward questions. In terms of the provision that was taken on the Portland pipeline, can you tell us what that was? And I'm just wondering, this decision that came down today for Calpine regarding their ability to sell their transmission capacity, does that perhaps improve the outlook for that throughput, or for that transmission capacity?

I will take the first part of that. So basically the provision there was for, as we noted, our Calpine subsidiary it's especially four months worth of their revenue down there. That's running about US$1 million at 100% to Portland -- per month, US$1 million per month.

US$1 million per month.

On your second question referenced to a ruling today, unfortunately it's in Board meetings up to this point in time today. So if there was a ruling allowing Calpine to release or resell its transmission and gas pipeline transportation capacity, that may give us more certainty with respect to recovery, but I suspect that the stuff that they would be selling would be related to gas pipelines that are in the money. And that would probably be our Canadian Mainline, and that's a position that we would be comfortable with anyway. So it doesn't change I guess our view on security. It's been more the ones that have been out of the money that have caused us greater concern. And I don't know that they have made any decisions on those fronts yet.

So the four-month provision, that's four months that you are owed presumably. And I guess it's possible there will be future provisions?

That is correct.

Thanks very much. This is a just clarification regarding Bruce A. Is it fair to say there's no further planned outages for 2006 at Bruce A?

Right.

Thank you, I'll get back in queue.

Andrew Kuske, UBS.

Just with respect to the Bruce, your press release states Bruce A has incurred 645 million with respect to the restart and refurbishment project. I'm just wondering how did that track to your expectations?

If I look at a presentation that you gave at the time of announcing the restart program, if I look at 2005 and '06, it looks like roughly 720 is your expectation through those two years. So at about halfway point, is that really in line with your expectations at this time? How do you see the back out of the year developing?

We're certainly not at the halfway point. We're still in relatively early days on that project. But a fair bit of money tends to get committed upfront for purchase of significant hardware items, like the steam generators that we're buying from Babcock & Wilcox.

Overall, I can't give you too much information, maybe my colleagues can, on how we said today versus where we expected to be today. But what I can say is the project generally is proceeding as planned. The overall cost estimate is within the bandwidth of what we would expect for a project like this. There's some expectation that we will be a little over budget, but there's also a number of opportunities for bringing costs in under budget. So we don't tend to focus on a precise number. We look at what the bandwidth is going to be, and we're certainly within that bandwidth.

So from both a time and a cost perspective, and also from what we've learned technically from an engineering perspective to date, the project is unfolding as it should.

So really within the first year of this project, really a five or six-year project, you feel fairly comfortable with the bandwidth that you have set around things?

Yes, we do.

And then if I may ask a different question, a bit of a broader big picture question. Just on valuations that you're seeing within the marketplace, and obviously we saw the tender announcement I guess about 1.5 months ago or 2 months ago now. What do you think that means to the sector as a whole from a valuation perspective for privatization of Kinder Morgan?

Well, we think there's obviously a significant amount of capital in the market today that finds infrastructure very attractive, and would appeared to be driving prices up. And I'm sure you would have observed the same thing more than me, Andrew.

We are gratified to see that there are investors that place a very high value on premium infrastructure. And we think we have a lot of premium infrastructure, so that should drive the market value of TransCanada up. But it remains to be seen how all that plays out in the market. I just don't know. We remain pretty comfortable with the portfolio of assets we've got, and our focus is on building value for our shareholders, and that's what we will continue to do.

That's great, thank you.

I just wanted to add one thing re the Bruce capital costs. I'm not sure exactly what slides you are looking at, but if they are ones from our presentation last October, the numbers you're seeing there are likely our share. So 50% of the anticipated cost on a year by your basis, if you will. The number quoted in our quarterly report at 645 million is the 100% number, so the 645 isn't half the total.

No, I'm aware of that (multiple speakers)

I am sure you realize there were a little bit of apples and oranges there.

No, its page 15 of the October 17th presentation where --.

And what you're seeing on that slide would be our share of the cost on a year by year basis.

You would be roughly at the halfway point of what you estimated for '05 and '06, about 320 of approximately say 720ish?

Yes, that's correct.

That's great, thank you.

We just wanted to clarify that.

Bob Hastings, Canaccord.

You've locked in some of the electrical volumes from spot to contract at the end of the second quarter. And while I know you wowuld be reluctant to tell us what the number is, would you be able to give some color as to whether the prices would be higher than what you realized in the spot market in the second quarter? And, gee, did you get any of those $1,000 prices?

I think I would tell you that prices have firmed. I would say prices are going to be probably similar to what we saw in terms of what we're locking in now. Because as we said last quarter and we have said in our release this quarter, the market hasn't firmed on a former basis as much as we would anticipate, and therefore see no reason at this time to sell a lot of volumes forward, but we have sold some.

And with respect to the current spot market and the $1,000 prices, of course we would have some volumes exposed to that. But as you know, those prices never last for too terribly long. So it's a large price on a small volume, and overall it doesn't make a large, large impact.

I was kidding about getting $1,000. OSP made some -- you sold off some of your gas there, and that accounted for some gains in the quarter. Can you give us how much of the gains that translated into?

I think it was a couple of million dollars, wasn't it?

If you actually look on the table we have in the quarterly on Eastern operations under the other categories, we made about $5 million pretax on that in the quarter.

Those are my two questions, thank you.

Maureen Howe, RBC Capital Markets.

I actually wanted to come back to the $1,000. I was wondering if you could just perhaps give us some insight on how you manage the situation when you're in the position, as I guess you were on Monday, and the units Sheerness was down. And Sundance, one of your units Sundance was down, or I believe it was your unit. And prices are going up to incredible levels and you're receiving I believe under the terms of PPA the 30 day average price. To the extent that you're hedged, are you getting pretty squeezed on those situations?

We certainly can get pretty squeezed, and we have to move pretty quickly to stabilize our position. Sometimes though we have obligations that are contingent on our ability to supply them. I would say this, we did not suffer a significant crisis here at TransCanada during the events of this week.

And I just give you that as some evidence that we're party careful about making sure we can manage anything that the market might throw at us.

And we have kept our portfolio long enough to be able to manage those kinds of situations. As we mentioned before, that's the reason for keeping a lot of the length that we do keep in our portfolio. And as well, it depends on what the reason for the outage is as to whether or not it's our responsibility or not.

Under the terms of when you contract, Russ, do you try and pass that through? Is that correct then?

Even under the terms of the power purchase agreements, depending on the reasons for the outage, as to who has responsibility for the delta between market prices and the value of the output. And so those things help us manage as well. But in the case of some of those obviously we have to have a portfolio that allows us to manage those situations. I would say overall through that process, or through that situation, we probably have a positive outcome rather than a negative outcome through that period of time.

That's great. And just in terms of the Sheerness one specifically, in this situation, we believe it was a transmission issue. So in that type of a situation under the terms of the power purchase arrangement then does your compensation change? In other words do you receive spot as opposed -- well, I'm not sure, I guess I'm asking the question. But do you receive spot as opposed to the 30 day average, or --?

We can talk a little bit more about this in the future. It's a matter of some contentiousness, I guess I could say right now. And I just want to be very careful that we don't do anything that would jeopardize our position in how this is all resolved.

But I guess the short answer is thhat in this particular situation you feel you came out of it pretty well, and may be ahead of the game?

Yes, in this one.

That's great, thanks so much.

We don't necessarily feel we came out as forehead as we should of.

Okay.

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

Before we do terminate, though, I would just offer that if there are any questions from the media, we're now happy to accept those.

(OPERATOR INSTRUCTIONS). [Dave Edmond] with the Globe Newspaper.

Regarding Alaska, I was wondering how urgent the situation might be in terms of ownership of the Canadian portion in regards to a letter you sent earlier this month?

It's not urgent. What we think is most urgent is that the state and the producers conclude their arrangements within the state. We simply noted to them that their agreement had specified, if you will, that the state and the producers would develop and own the project through Canada in a particular way. And we just were making the observation that it was premature for them to say that. But we have a commercial negotiation with them underway, and that really ought to run its course, and that's how we ought to get this thing resolved. So the urgency is all within Alaska. We stand ready here in Canada to work with them to get the gas down to the Alberta hub once they resolve their issues in Alaska.

And then on Mackenzie, obviously Imperial in the performance of reviewing the situation in regards to the economics of everything, if the producers were in theory to kind of step back from the project, would TransCanada be interested in building the Mackenzie volume and then signing on shippers?

Well, certainly we would, and we always have been. But I want to point out that no Mackenzie project will go ahead if the producers aren't willing to commit quite a bit of money to develop the gas fields and to build the processing infrastructure, and most notably enter into long-term contracts to ship the gas through somebody's pipeline.

And those contracts may be really long-term, or not too long. But no matter how you look at it, you have to get an agreement from the producers that they're going to produce and that they're going to ship the gas through the pipeline. So at the end of the day, you really need a positive decision by Imperial Oil, By Shell and by ConocoPhilips that they want to go ahead with the project.

And if they think that the pipeline is going to be extremely expensive whether they build it or whether we build it, such that they're net back at the well head is inadequate, then they won't go ahead. So we think it's really important that we all pull together as best we can and try to make the current project move forward. It's our best hope in the near term, and we need to really focus on that.

Great, thank you.

[Scott Ackin] with Reuters.

[Avativy] has signaled that it's no longer dedicated to owning its hydroelectric or its generating assets, and wants to spin them off into an income trust. Is the something you would be interested in? Could these be in good hands if you owned them?

I don't want to comment specifically on theirs, because frankly, Scott, I don't know that much about them. But I would say generally hydro assets, river hydro assets, are very interesting to TransCanada. We've made significant investments, as you have seen in the last couple of years, in Hydro assets. They are low on the cost curve, very high-quality output, so we do like them.

But of course it all depends, what market do they sell their power to? If they would be assets that involve the resale of power to a pulp mill or something, we would want to be very careful that the pulp mill is going to be there to buy the power end of the contract. So a complex situation, but the simplest answer is, yes, we very much like hydro assets.

There are no further questions registered at this time.

Thanks, conference coordinator. I will just reiterate, if there are any additional questions, we're happy to taken now from the investment community or the media.

(OPERATOR INSTRUCTIONS). There are no questions registered at this time.

Thanks to those of you who have participated this afternoon. We very much appreciate your interest in TransCanada, and we look forward to talking to you again very soon. Goodbye for now.

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