TRANSCANADA
NYSE : TRP
TSX : TRP

TRANSCANADA

October 30, 2007 08:43 ET

TransCanada Announces Strong Third Quarter Results, Board Declares Dividend of $0.34 per Common Share

CALGARY, ALBERTA--(Marketwire - Oct. 30, 2007) - TransCanada Corporation (TSX:TRP)(NYSE:TRP) -

Third Quarter Highlights

(All financial figures are unaudited and in Canadian dollars unless noted otherwise)

- Net income for third quarter 2007 of $324 million ($0.60 per share) compared to $293 million ($0.60 per share) in third quarter 2006

- Comparable earnings for third quarter 2007 of $309 million ($0.57 per share), compared to $243 million ($0.50 per share) for the same period in 2006, an increase of approximately 14 per cent on a per share basis

- Funds generated from operations for third quarter 2007 of $702 million compared to $662 million for the same period in 2006, an increase of approximately six per cent

- Dividend of $0.34 per common share declared by the Board of Directors

- Significant advancement on the Keystone Oil Pipeline project and expanded scope of the Bruce A Restart and Refurbishment Project

"TransCanada's strong financial performance during the third quarter is a result of solid contributions from our existing assets, and our continued disciplined approach to growing our pipelines and energy businesses," said Hal Kvisle, president and chief executive officer. "The acquisition of ANR, and the completion of Becancour and Edson facilities in late 2006, have contributed to increased earnings and cash flow in 2007. As we move ahead on our portfolio of large scale infrastructure projects such as Keystone and the Bruce A refurbishment, we expect to continue to generate strong returns for our shareholders."

TransCanada Corporation (TransCanada) reported net income for third quarter 2007 of $324 million ($0.60 per share) compared to $293 million ($0.60 per share) for third quarter 2006.

Comparable earnings were $309 million ($0.57 per share) for third quarter 2007 compared to $243 million ($0.50 per share) in third quarter 2006. The $66 million ($0.07 per share) increase was due to higher contributions from both the Pipelines and Energy businesses. The increase in Pipelines was primarily due to additional income earned from the acquisition of ANR and higher earnings from the Canadian Mainline. The increase in the Energy business was primarily due to the impact of higher realized power prices in Alberta and the start-up of the Becancour and Edson facilities in late 2006. Comparable earnings in third quarter 2007 excluded $15 million of favourable tax reassessments and associated interest income relating to prior years, and in third quarter 2006, excluded a $50 million income tax benefit related to the resolution of certain income tax matters with taxation authorities and changes in estimates.

Net income and net income from continuing operations were $846 million ($1.60 per share) for the first nine months in 2007 compared to net income of $810 million ($1.66 per share), and net income from continuing operations of $782 million ($1.60 per share) for the same period last year.

Comparable earnings for the first nine months of 2007 were $800 million ($1.51 per share), compared to $668 million ($1.36 per share) for the same period in 2006. The $132 million ($0.15 per share) increase was primarily due to additional income earned from the acquisition of ANR, higher earnings from the Canadian Mainline, higher realized power prices in Alberta and the start-up of the Becancour and Edson facilities in late 2006. Partially offsetting these increases was a lower contribution from Bruce Power. Comparable earnings for the nine months ended September 30, 2007 excluded positive income tax adjustments of $46 million. Comparable earnings for the nine months ended September 30, 2006, excluded $83 million in favourable income tax adjustments, an $18-million bankruptcy settlement with Mirant, and a $13-million gain on the sale of TransCanada's interest in Northern Border Partners, L.P.

Net cash provided by operations in third quarter 2007 was $834 million compared to $619 million for the same period in 2006. Net cash provided by operations for the nine months ended 2007 was $2.14 billion compared to $1.58 billion for the same period in 2006. The increase in net cash provided by operations was primarily due to an increase in funds generated from operations and a decrease in operating working capital.

Funds generated from operations of $ 702 million and $1.88 billion for the three and nine months ended September 30, 2007 increased $40 million and $162 million, respectively, when compared to the same periods in 2006. These increases were mainly due to an increase in cash generated through earnings.

Notable recent developments in Pipelines, Energy and Corporate include:

Pipelines:

- TransCanada reached another major milestone on the Keystone Oil Pipeline project after receiving NEB approval to construct and operate the Canadian portion of the Keystone Oil pipeline. The approval includes converting a portion of the Canadian Mainline to crude oil service from natural gas service, and includes agreement on the toll methodology and tariff. Construction is anticipated to begin in early 2008 and Keystone is expected to be in-service in fourth quarter 2009.

- Based on strong industry support for Keystone, TransCanada has entered into contracts or conditionally awarded approximately US$3.0 billion for major materials and pipeline construction contractors and is continuing to secure land access agreements in preparation for the start of construction in the spring of 2008. The capital cost of Keystone is expected to be approximately US$5.2 billion based on the increased size and scope of the project and the executed material and service construction contracts. In November, an application with the National Energy Board (NEB) is expected to be filed for additional pumping facilities required to expand Keystone from a nominal capacity of approximately 435,000 barrels per day to 590,000 barrels per day.

- TransCanada and Northwest Natural Gas Company announced the formation of Palomar Gas Transmission. Palomar proposes to build a natural gas pipeline that would serve growing markets in Oregon, the Pacific Northwest, and the western U.S. If approved, and with sufficient shipper interest, the new pipeline is scheduled to begin service in late 2011.

- After a July 2007 approval from the Energy and Utilities Board (Alberta) to initiate negotiations with respect to the Alberta System revenue requirement, negotiations with stakeholders began in September 2007 and are ongoing. The intent is to reach a settlement for a term of up to three years beginning January 1, 2008.

- In October 2007, TransCanada's North Baja pipeline received a certificate from the U.S. Federal Energy Regulatory Commission authorizing it to expand and modify its existing system. The modification will facilitate the importation of regassified liquefied natural gas from Mexico into the California and Arizona markets.

Energy:

- TransCanada announced the expansion of the Unit 4 refurbishment on the revised Bruce A Restart project that includes installing 480 new fuel channels in Unit 4. This will extend the expected operational life of the 750 MW unit from 2017 to 2036. The expansion is estimated to be an additional $1 billion, resulting in a total investment in the restart and refurbishment program of approximately $5.25 billion. TransCanada's share is expected to be approximately $2.6 billion.

- Construction began at Halton Hills Generating Station, a 683 MW natural gas-fired power plant in Halton Hills, Ontario. The facility is anticipated to be in-service by the summer of 2010.

- Construction is progressing as planned on the Portlands Energy Centre (550 MW), a partnership with Ontario Power Generation.

- Cartier Wind received environmental approval from the Quebec Government to build its proposed $170-million Carleton wind farm on the Gaspe Peninsula of Quebec. The Carleton wind farm (109.5 MW) is the third project to be developed after Hydro-Quebec's first wind energy call for tenders in 2004. TransCanada has a 62 per cent ownership interest in Cartier Wind.

- TransCanada and the Saskatchewan Government agreed to contribute up to $26 million each for the engineering design phase of a proposed polygeneration plant. The Belle Plaine facility would use petroleum coke as feedstock to produce valuable products with very low emissions, and generate 300 MW of electricity.

Corporate:

- In October 2007, TransCanada sold US$1 billion of 30-year senior notes bearing a coupon of 6.20 per cent. Proceeds will be used to repay outstanding commercial paper and for general corporate purposes.

Teleconference - Audio and Slide Presentation

TransCanada will hold a teleconference today at 8:00 a.m. (Mountain) / 10 a.m. (Eastern) to discuss the third quarter 2007 financial results and general developments and issues concerning the company. Analysts, members of the media and other interested parties wanting to participate should phone
1-866-299-6655 or 416-641-6140 (Toronto area) at least 10 minutes prior to the start of the teleconference. No passcode is required. A live audio and slide presentation webcast of the teleconference will also be available on TransCanada's website at www.transcanada.com.

The conference will begin with a short address by members of TransCanada's executive management, followed by a question and answer period for investment analysts. A question and answer period for members of the media will immediately follow.

A replay of the teleconference will be available two hours after the conclusion of the call until midnight (Eastern) November 6, 2007. Please call 1-800-408-3053 or 416-695-5800 (Toronto area) and enter passcode 3239079#. The webcast will be archived and available for replay on www.transcanada.com.

About TransCanada

With more than 50 years experience, TransCanada is a leader in the responsible development and reliable operation of North American energy infrastructure including natural gas pipelines, power generation, gas storage facilities, and projects related to oil pipelines and LNG facilities. TransCanada's network of wholly owned pipelines extends more than 59,000 kilometres (36,500 miles), tapping into virtually all major gas supply basins in North America. TransCanada is one of the continent's largest providers of gas storage and related services with approximately 360 billion cubic feet of storage capacity. A growing independent power producer, TransCanada owns, or has interests in, approximately 7,700 megawatts of power generation in Canada and the United States. TransCanada's common shares trade on the Toronto and New York stock exchanges under the symbol TRP.

FORWARD-LOOKING INFORMATION

This news release may contain certain information that is forward looking and is subject to important risks and uncertainties. The words "anticipate", "expect", "may", "should", "estimate", "project", "outlook", "forecast" or other similar words are used to identify such forward-looking information. All forward-looking statements are based on TransCanada's beliefs and assumptions based on information available at the time such statements were made. 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, changes in environmental and other laws and regulations, competitive factors in the pipeline and energy industry sectors, construction and completion of capital projects, access to capital markets, interest and currency exchange rates, technological developments and the current economic conditions in North America. By its nature, such forward-looking information is subject to various risks and uncertainties 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 U.S. Securities and Exchange Commission. Readers are cautioned not to place undue reliance on this forward-looking information, which is given as of the date it is expressed in this news release or as otherwise stated, and TransCanada undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, except as required by law.

NON-GAAP MEASURES

TransCanada uses the measures "comparable earnings", "comparable earnings per share" and "funds generated from operations" in this news release. These measures do not have any standardized meaning prescribed by generally accepted accounting principles (GAAP) and are therefore considered to be non-GAAP measures. These measures are unlikely to be comparable to similar measures presented by other entities. These measures have been used to provide readers with additional information on TransCanada's operating performance, liquidity and its ability to generate funds to finance its operations. These measures are used by Management to increase comparability of financial results between reporting periods and to enhance its understanding of operating performance, liquidity and ability to generate funds to finance operations.

Comparable earnings is comprised of net income from continuing operations adjusted for specific items that are significant and not typical of the Company's operations. The identification of specific items is subjective and management uses judgement in determining the items to be excluded in calculating comparable earnings. Specific items may include, but are not limited to, certain income tax refunds and adjustments, gains or losses on sales of assets, legal settlements and bankruptcy settlements received from former customers. A reconciliation of comparable earnings to net income is presented in the Consolidated Results of Operation section in the Management's Discussion and Analysis accompanying this news release. Comparable earnings per share is calculated by dividing comparable earnings by the weighted average number of shares outstanding for the period.

Funds generated from operations is comprised of net cash provided by operations before changes in operating working capital. A reconciliation of funds generated from operations to net cash provided by operations is presented in the Third Quarter 2007 Financial Highlights chart in this news release.



Third Quarter 2007 Financial Highlights

(unaudited)

Three months ended Nine months ended
Operating Results September 30 September 30
(millions of dollars) 2007 2006 2007 2006
---------------------------------------------------------------------------

Revenues 2,210 1,850 6,671 5,429

Net Income
Continuing operations 324 293 846 782
Discontinued operations - - - 28
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324 293 846 810
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Comparable Earnings(1) 309 243 800 668
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Cash Flows
Funds generated from
operations(1) 702 662 1,880 1,718
Decrease/(increase) in
operating working capital 132 (43) 261 (136)
----------------------------------------------
Net cash provided by
operations 834 619 2,141 1,582
----------------------------------------------
----------------------------------------------
Capital Expenditures 364 372 1,056 1,002
Acquisitions,
Net of Cash Acquired (2) - 4,222 358
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Three months ended Nine months ended
September 30 September 30
Common Share Statistics 2007 2006 2007 2006
---------------------------------------------------------------------------

Net Income Per Share - Basic
Continuing operations $0.60 $0.60 $1.60 $1.60
Discontinued operations - - - 0.06
----------------------------------------------
$0.60 $0.60 $1.60 $1.66
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----------------------------------------------

Comparable Earnings
Per Share - Basic(1) $0.57 $0.50 $1.51 $1.36

Dividends Declared Per Share $0.34 $0.32 $1.02 $0.96

Basic Common Shares
Outstanding (millions)
Average for the period 537 488 527 488
End of period 538 488 538 488
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(1)For a further discussion on comparable earnings, funds generated from
operations and comparable earnings per share, refer to the Non-GAAP
Measures section in this News Release.


TRANSCANADA CORPORATION - THIRD QUARTER 2007
Quarterly Report to Shareholders


Management's Discussion and Analysis

The Management's Discussion and Analysis (MD&A) dated October 29, 2007 should be read in conjunction with the accompanying unaudited Consolidated Financial Statements of TransCanada Corporation (TransCanada or the Company) for the three and nine months ended September 30, 2007. It should also be read in conjunction with the audited Consolidated Financial Statements and notes thereto, and the MD&A contained in TransCanada's 2006 Annual Report for the year ended December 31, 2006. Additional information relating to TransCanada, including the Company's Annual Information Form and other continuous disclosure documents, is available on SEDAR at www.sedar.com under TransCanada Corporation. Amounts are stated in Canadian dollars unless otherwise indicated. Capitalized and abbreviated terms that are used but not otherwise defined herein are identified in the Glossary of Terms contained in TransCanada's 2006 Annual Report.

Forward-Looking Information

This MD&A may contain certain information that is forward looking and is subject to important risks and uncertainties. The words "anticipate", "expect", "may", "should", "estimate", "project", "outlook", "forecast" or other similar words are used to identify such forward-looking information. All forward-looking statements are based on TransCanada's beliefs and assumptions based on information available at the time such statements were made. 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, changes in environmental and other laws and regulations, competitive factors in the pipeline and energy industry sectors, construction and completion of capital projects, access to capital markets, interest and currency exchange rates, technological developments and the current economic conditions in North America. By its nature, such forward-looking information is subject to various risks and uncertainties 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 U.S. Securities and Exchange Commission (SEC). Readers are cautioned not to place undue reliance on this forward-looking information, which is given as of the date it is expressed in this MD&A or as otherwise stated, and TransCanada undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, except as required by law.

Non-GAAP Measures

The Company uses the measures "comparable earnings ", "comparable earnings per share ", "funds generated from operations" and "operating income" in this MD&A. These measures do not have any standardized meaning prescribed by generally accepted accounting principles (GAAP) and are therefore considered to be non-GAAP measures. These measures are unlikely to be comparable to similar measures presented by other entities. These measures have been used to provide readers with additional information on the Company's operating performance, liquidity and its ability to generate funds to finance its operations. These measures are used by Management to increase comparability of financial results between reporting periods and to enhance its understanding of operating performance, liquidity and ability to generate funds to finance operations.

Comparable earnings is comprised of net income from continuing operations adjusted for specific items that are significant and not typical of the Company's operations. The identification of specific items is subjective and management uses judgement in determining the items to be excluded in calculating comparable earnings. Specific items may include, but are not limited to, certain income tax refunds and adjustments, gains or losses on sales of assets, legal settlements and bankruptcy settlements received from former customers. A reconciliation of comparable earnings to net income is presented in the Consolidated Results of Operations section in this MD&A. Comparable earnings per share is calculated by dividing comparable earnings by the weighted average number of shares outstanding for the period.

Funds generated from operations is comprised of net cash provided by operations before changes in operating working capital. A reconciliation of funds generated from operations to net cash provided by operations is presented in the Liquidity and Capital Resources section in this MD&A.

Operating income is used in the Energy segment and is comprised of revenues less operating expenses as shown on the consolidated income statement. A reconciliation of operating income to net earnings is presented in the Energy section in this MD&A.



Consolidated Results of Operations

Reconciliation of Comparable Earnings to Net Income

(unaudited) Three months ended Nine months ended
(millions of dollars September 30 September 30
except per share amounts) 2007 2006 2007 2006
---------------------------------------------------------------------------

Pipelines
Comparable earnings 163 130 484 403
Specific items:
Bankruptcy settlement
with Mirant - - - 18
Gain on sale of
Northern Border
Partners, L.P interest - - - 13
----------------------------------------------
Net earnings 163 130 484 434
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Energy
Comparable earnings 156 123 352 297
Specific item:
Income tax adjustments - - 4 23
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Net earnings 156 123 356 320
----------------------------------------------

Corporate
Comparable (expenses)/
earnings (10) (10) (36) (32)
Specific item:
Income tax reassessments
and adjustments 15 50 42 60
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Net earnings 5 40 6 28
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Net Income
Continuing operations(1) 324 293 846 782
Discontinued operations - - - 28
----------------------------------------------

Net Income 324 293 846 810
----------------------------------------------
----------------------------------------------

Net Income Per Share

Continuing operations(2) $0.60 $0.60 $1.60 $1.60
Discontinued operations - - - 0.06
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Basic $0.60 $0.60 $1.60 $1.66
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----------------------------------------------
Diluted $0.60 $0.60 $1.60 $1.65
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(1)Comparable Earnings 309 243 800 668
Specific items (net of
tax, where applicable):
Income tax reassessments
and adjustments 15 50 46 83
Bankruptcy settlement
with Mirant - - - 18
Gain on sale of
Northern Border
Partners, L.P.
interest - - - 13
----------------------------------------------

Net Income from
Continuing Operations 324 293 846 782
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----------------------------------------------

(2)Comparable Earnings
Per Share $0.57 $0.50 $1.51 $1.36
Specific items
- per share
Income tax
reassessments
and adjustments 0.03 0.10 0.09 0.17
Bankruptcy
settlement with
Mirant - - - 0.04
Gain on sale of
Northern Border
Partners, L.P.
interest - - - 0.03
----------------------------------------------
Net Income Per Share from
Continuing Operations $0.60 $0.60 $1.60 $1.60
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----------------------------------------------


TransCanada's net income and net income from continuing operations (net earnings) in third quarter 2007 were $324 million or $0.60 per share compared to $293 million or $0.60 per share in third quarter 2006. The $31-million increase in net income and net earnings in third quarter 2007 compared to 2006 was primarily due to income from the acquisition of ANR in February 2007, higher realized Alberta power prices, the start-up of the Becancour and Edson facilities, and higher income recorded due to a five-year settlement on the Canadian Mainline approved by the National Energy Board (NEB) in May 2007. Third quarter 2007 net earnings included $15 million of favourable income tax reassessments and associated interest income relating to prior years, compared with an income tax benefit of $50 million recorded in third quarter 2006 relating to the resolution of certain income tax matters with taxation authorities and changes in estimates. On a per share basis, net income in third quarter 2007 remained consistent with third quarter 2006 although the Company had an increased number of shares outstanding following the Company's share issuances in 2007.

Comparable earnings for third quarter 2007 were $309 million or $0.57 per share, compared to $243 million or $0.50 per share for the same period in 2006. Comparable earnings excluded the above-mentioned $15-million and $50-million positive income tax reassessments and adjustments in third quarter 2007 and 2006, respectively.

Net income and net earnings were $846 million or $ 1.60 per share for the first nine months in 2007 compared to net income of $810 million or $1.66 per share, and net earnings of $782 million or $1.60 per share for the same period last year. The increase in net income and net earnings was due to factors discussed above as well as additional positive income tax adjustments of $ 31 million in the first six months of 2007 due to changes in Canadian federal income tax legislation, the resolution of certain income tax matters and an internal restructuring. These increases were partially offset by decreased earnings from Bruce Power. Net income and net earnings for the nine months ended September 30, 2006 included approximately $83 million in favourable income tax adjustments and benefits from the resolution of certain income tax matters, reductions in Canadian federal and provincial income tax rates and changes in estimates. In addition, net income and net earnings in 2006 included an $18-million after-tax ($29 million pre-tax) bankruptcy settlement with Mirant Corporation and certain of its subsidiaries (Mirant) and a $13 million after-tax ($23 million pre-tax) gain on the sale of TransCanada's general partner interest in Northern Border Partners, L.P. TransCanada's net income for the nine months ended September 30, 2006 also included net income from discontinued operations of $28 million or $0.06 per share, reflecting bankruptcy settlements with Mirant received in first quarter 2006 related to the Gas Marketing business divested in 2001. On a per share basis, net earnings for the first nine months in 2007 remained consistent with the same period in 2006 although the Company had an increased number of shares outstanding following the Company's share issuances in 2007.

Comparable earnings for the first nine months of 2007 were $800 million or $1.51 per share, compared to $668 million or $ 1.36 per share for the same period in 2006. Comparable earnings for the nine months ended September 30, 2007 excluded positive income tax reassessments and adjustments of $46 million. Comparable earnings for the nine months ended September 30, 2006, excluded $83 million in favourable income tax adjustments, the $18-million bankruptcy settlement with Mirant and the $13-million gain on the sale of TransCanada's interest in Northern Border Partners, L.P.

Results from each business segment for the three and nine months ended September 30, 2007 are discussed further in the Pipelines, Energy and Corporate sections of this MD&A.

Funds generated from operations of $ 702 million and $1,880 million for the three and nine months ended September 30, 2007 increased $40 million and $162 million, respectively, compared to the same periods in 2006.

Pipelines

The Pipelines business generated net earnings and comparable earnings of $163 million in third quarter 2007, an increase of $33 million compared to $130 million in third quarter 2006.

Net earnings for the nine months ended September 30, 2007 were $484 million compared to $434 million for the same period in 2006. Excluding the $18-million Mirant settlement in first quarter 2006 and the $13-million gain on the sale of TransCanada's interest in Northern Border Partner's L.P. in second quarter 2006, comparable earnings increased $81 million compared to 2006.



Pipelines Results-at-a-Glance

Three months ended Nine months ended
(unaudited) September 30 September 30
(millions of dollars) 2007 2006 2007 2006
---------------------------------------------------------------------------
Wholly Owned Pipelines
Canadian Mainline 69 59 201 179
Alberta System 32 35 97 102
ANR(1) 19 69
GTN 10 12 26 39
Foothills(2) 6 7 20 21
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136 113 413 341
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Other Pipelines
Great Lakes(3) 11 10 36 33
Iroquois 3 4 11 11
Portland 1 6 7 10
PipeLines LP(4) 8 (1) 14 3
Ventures LP 3 3 9 9
TQM 2 2 5 5
TransGas 2 3 10 8
Gas Pacifico/INNERGY - 1 2 5
Tamazunchale 2 7
Northern Development (1) (1) (3) (3)
General, administrative,
support costs and other (4) (10) (27) (19)
----------------------------------------------
27 17 71 62
----------------------------------------------
Comparable earnings 163 130 484 403
Bankruptcy settlement
with Mirant - - - 18
Gain on sale of Northern
Border Partners, L.P.
interest - - - 13
----------------------------------------------
Net Earnings 163 130 484 434
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(1)ANR's results include operations since February 22, 2007.

(2)Foothills' results reflect the combined operations of Foothills and the
BC System. Effective April 1, 2007, Foothills and BC System were
integrated.

(3)Great Lakes' results reflect TransCanada's 53.55 per cent ownership in
Great Lakes since February 22, 2007 and 50 per cent ownership prior to
that date.

(4)PipeLines LP's results include TransCanada's effective ownership of an
additional 15 per cent in Great Lakes as a result of TransCanada's 32.1
per cent interest in PipeLines LP since February 22, 2007.


Wholly Owned Pipelines

Canadian Mainline's net earnings increased $10 million and $22 million for the three and nine months ended September 30, 2007, respectively, compared to the corresponding periods in 2006. These increases reflect the impact of a five-year tolls settlement (the Settlement) with interested stakeholders effective January 1, 2007 to December 31, 2011 on the Canadian Mainline. The Settlement was approved by the NEB in May 2007 and included an increase in the deemed common equity ratio from 36 per cent to 40 per cent.

As a result of the Settlement, Canadian Mainline's net earnings for the three and nine months ended September 30, 2007 increased due to the higher deemed common equity ratio compared to the same period in the prior year. In addition, Canadian Mainline's net earnings were positively impacted by certain performance-based incentive arrangements and operations, maintenance and administrative cost savings. Partially offsetting these increases were the negative impacts of a lower rate of return on common equity (ROE) of 8.46 per cent in 2007 (8.88 per cent in 2006) and a lower average investment base.

The Alberta System's net earnings decreased $3 million and $5 million for the three and nine months ended September 30, 2007, respectively, compared to the same periods in 2006. The decreases were primarily due to a lower investment base and a lower ROE in 2007. Earnings in 2007 reflect an ROE of 8.51 per cent compared to an ROE of 8.93 per cent in 2006, both on a deemed common equity ratio of 35 per cent.

For the three and nine months ended September 30, 2007, ANR's net earnings were $19 million and $69 million, respectively, which are generally in line with the Company's expectations. TransCanada completed the acquisition of ANR on February 22, 2007 and included its net earnings from this date. ANR's revenues are primarily derived from its interstate natural gas transmission, storage, gathering and related services. Due to the seasonal nature of the business, ANR's volumes, revenues and net earnings are generally expected to be higher in the winter months.

GTN's net earnings for the three and nine months ended September 30, 2007 decreased $2 million and $13 million, respectively, from the same periods in 2006 primarily due to lower operating revenues in 2007 as a result of lower volumes contracted on a long-term firm basis and a higher provision taken in 2007 for non-payment of contract transportation revenues from a subsidiary of Calpine Corporation that filed for bankruptcy protection. Pending resolution of GTN's current rate case filing, GTN is recording its 2007 revenues at 2006 rates. As a result, GTN has been recording a provision for rate refund equal to the difference in transportation revenue based on GTN's interim 2007 rates and the rates that were in effect in 2006.



Operating Statistics

Gas
Nine months Transmission
ended Canadian Alberta Northwest
September 30 Mainline(1) System(2) ANR(3)(4) System(3) Foothills(5)
(unaudited) 2007 2006 2007 2006 2007 2007 2006 2007 2006
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Average
investment
base
($ millions) 7,323 7,450 4,236 4,293 n/a n/a n/a 824 856
Delivery
volumes (Bcf)
Total 2,359 2,209 2,994 3,033 829 600 592 1,058 1,051
Average
per day 8.6 8.1 11.0 11.1 3.8 2.2 2.2 3.9 3.9
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(1)Canadian Mainline deliveries originating at the Alberta border and in
Saskatchewan for the nine months ended September 30, 2007 were 1,655
Bcf (2006 - 1,694 Bcf); average per day was 6.1 Bcf (2006 - 6.2 Bcf).

(2)Field receipt volumes for the Alberta System for the nine months ended
September 30, 2007 were 3,064 Bcf (2006 - 3,133 Bcf); average per day
was 11.2 Bcf (2006 - 11.5 Bcf).

(3)ANR and the Gas Transmission Northwest System results are not impacted
by current average investment base as these systems operate under a
fixed rate model approved by the U.S. Federal Energy Regulatory
Commission (FERC).

(4)ANR includes results of pipeline operations since February 22, 2007.

(5)Foothills reflects the combined operations of Foothills and the BC
System. Effective April 1, 2007, Foothills and BC System were
integrated.


Other Pipelines

TransCanada's proportionate share of net earnings from Other Pipelines was $27 million for the three months ended September 30, 2007 compared to $17 million for the same period in 2006. The increase is primarily due to increased earnings from PipeLines LP and lower project development costs. PipeLines LP's earnings increased primarily due to TransCanada's increased partnership interest and PipeLines LP's acquisition of a 46.45 per cent interest in Great Lakes on February 22, 2007, as well as an adjustment recorded in third quarter 2007 related to TransCanada's increased ownership. Project development costs decreased due to the timing of costs incurred relative to the same period last year and the capitalization of project costs related to the Keystone oil pipeline extension in third quarter 2007. Net earnings also increased in third quarter 2007 due to earnings from Tamazunchale, which commenced operations in December 2006. These increases were partially offset by decreased earnings from Portland, in comparison to the prior year, due to a bankruptcy settlement received in 2006.

Net earnings for the nine months ended September 30, 2007 were $71 million compared to $62 million in the same period in 2006. Net earnings increased in 2007 primarily due to increased earnings from Tamazunchale and PipeLines LP, as discussed above, partially offset by higher project development and support costs related to growing the Pipelines business.

The Company is currently evaluating the impact of Mexico's Corporate Flat Rate Tax legislation, which passed into law on October 1, 2007. The Company anticipates that the legislation will not have a material impact on its financial statements.

As at September 30, 2007, TransCanada had advanced $135 million to the Aboriginal Pipeline Group with respect to the Mackenzie Gas Pipeline Project (MGP) and had capitalized $204 million related to the Keystone oil pipeline.

TransCanada and its co-venturers on the MGP continue to pursue the development of the project, focusing on the regulatory process and discussions with the Canadian federal government on fiscal framework. Project timing is uncertain and is conditional upon regulatory and fiscal matters. TransCanada's ability to recover its investment remains dependent on the successful outcome of the project.

Energy

Energy's net earnings of $156 million in third quarter 2007 increased $33 million compared to $123 million in third quarter 2006.

Energy's net earnings for the nine months ended September 30, 2007 of $356 million increased $36 million compared to $320 million for the same period in 2006. Excluding the $4 million of income tax adjustments in 2007 and $23 million of income tax adjustments in 2006, Energy's comparable earnings for the nine months ended September 30, 2007 increased $55 million.



Energy Results-at-a-Glance
Three months ended Nine months ended
(unaudited) September 30 September 30
(millions of dollars) 2007 2006 2007 2006
---------------------------------------------------------------------------
Bruce Power 64 72 124 176
Western Power Operations 120 84 250 188
Eastern Power Operations 52 40 189 132
Natural Gas Storage 39 24 89 63
General, administrative,
support costs and other (38) (35) (113) (100)
----------------------------------------------
Operating income 237 185 539 459
Financial charges (6) (5) (16) (17)
Interest income and other 2 2 8 5
Income taxes (77) (59) (179) (150)
----------------------------------------------
Comparable Earnings 156 123 352 297
Income tax adjustments - - 4 23
----------------------------------------------
Net earnings 156 123 356 320
----------------------------------------------
----------------------------------------------


Bruce Power

Bruce Power Results-at-a-Glance(1)
Three months ended Nine months ended
September 30 September 30
(unaudited) 2007 2006 2007 2006
---------------------------------------------------------------------------
Bruce Power (100 per cent basis)
(millions of dollars)
Revenues
Power 517 478 1,427 1,396
Other(2) 35 15 85 43
----------------------------------------------
552 493 1,512 1,439
----------------------------------------------

Operating expenses
Operations and maintenance (239) (210) (793) (656)
Fuel (23) (26) (76) (68)
Supplemental rent (43) (42) (128) (127)
Depreciation and
amortization (43) (34) (115) (99)
----------------------------------------------
(348) (312) (1,112) (950)
----------------------------------------------
Operating Income 204 181 400 489
----------------------------------------------
----------------------------------------------

TransCanada's proportionate
share 69 69 137 170
Adjustments (5) 3 (13) 6
----------------------------------------------

TransCanada's operating
income from Bruce Power 64 72 124 176
----------------------------------------------
----------------------------------------------

Bruce Power
- Other Information
Plant availability
Bruce A 79% 86% 81% 76%
Bruce B 96% 92% 88% 94%
Combined Bruce Power 90% 90% 86% 88%

Sales volumes (GWh)(3)
Bruce A - 100 per cent 2,610 2,850 7,930 7,440
Bruce B - 100 per cent 6,820 6,540 18,620 19,790
Combined Bruce Power
- 100 per cent 9,430 9,390 26,550 27,230
TransCanada's proportionate
share 3,427 3,448 9,747 9,848

Results per MWh(4)
Bruce A power revenues $60 $59 $59 $58
Bruce B power revenues $53 $48 $52 $49
Combined Bruce Power
revenues $55 $51 $54 $51
Combined Bruce
Power fuel $ 3 $ 3 $ 3 $ 2
Combined Bruce Power
operating expenses(5) $36 $32 $41 $34
Percentage of output sold
to spot market 52% 33% 45% 37%
----------------------------------------------
----------------------------------------------

(1)All information in the table includes adjustments to eliminate the
effects of inter-partnership transactions between Bruce A and Bruce B.

(2)Includes fuel cost recoveries for Bruce A of $9 million and $26 million
for the three and nine months ended September 30, 2007, respectively
($9 million and $19 million for the three and nine months ended
September 30, 2006, respectively). Includes changes in fair value of
held-for-trading derivatives of $18 million and $36 million for the
three and nine months ended September 30, 2007, respectively (nil for
each of the three and nine months ended September 30, 2006).

(3)Gigawatt hours.

(4)Megawatt hours.

(5)Net of fuel cost recoveries.


TransCanada's operating income of $64 million from its investment in Bruce Power decreased $8 million in third quarter 2007 compared to third quarter 2006 primarily due to higher post-employment benefit and other employee-related costs, higher costs associated with planned and unplanned outages (mainly at Bruce A), and lower positive purchase price amortizations related to the expiry of power sales agreements. These impacts were partially offset by higher revenues resulting primarily from higher realized prices.

TransCanada's share of Bruce Power's generation for third quarter 2007 of 3,427 GWh is consistent with third quarter 2006 generation of 3,448 GWh. Bruce Power prices achieved during third quarter 2007 (excluding other revenues) were $55 per MWh compared to $51 per MWh in third quarter 2006. Bruce Power's combined operating expenses (net of fuel cost recoveries) in third quarter 2007 increased to $ 36 per MWh from $32 per MWh in third quarter 2006 which, consistent with the nine-months results, was primarily due to higher employee-related and planned outage costs, and slightly lower output.

Approximately 25 reactor days of planned maintenance outages as well as approximately 12 reactor days of unplanned outages occurred on the six operating units in third quarter 2007. In third quarter 2006, Bruce Power experienced approximately 22 reactor days of planned maintenance outages and 20 reactor days of unplanned outages. The Bruce Power units ran at a combined average availability of 90 per cent in both third quarter 2007 and 2006.

TransCanada's operating income from its investment in Bruce Power for the nine months ended September 30, 2007 was $124 million compared to $176 million for the same period in 2006. The decrease of $52 million was primarily due to higher post-employment benefit and other employee-related costs, reduced output, higher costs associated with planned and unplanned outages, and lower positive purchase price amortizations related to the expiry of power sales agreements. Partially offsetting these decreases was the impact of higher realized prices.

The overall plant availability percentage in 2007 is expected to be in the low 90s for the four Bruce B units and in the high 70s for the two operating Bruce A units. Two planned outages were scheduled for Bruce A Unit 3 in 2007. The first planned one month outage was completed in May. A second outage that began late in third quarter 2007 is expected to last approximately one and a half months. Similarly, there were two planned outages for Bruce A Unit 4 in 2007, one completed in April and a second one completed in September. A planned two and a half month maintenance outage for Bruce B Unit 6 was completed in April.

Income from Bruce B is directly impacted by the fluctuations in wholesale spot market prices for electricity. Net earnings from both Bruce A and Bruce B units are impacted by overall plant availability, which in turn is impacted by scheduled and unscheduled maintenance. As a result of a contract with the Ontario Power Authority (OPA), all of the output from Bruce A in third quarter 2007 was sold at a fixed price of $59.69 per MWh (before recovery of fuel costs from the OPA) compared to $58.63 per MWh for third quarter 2006. Sales from the Bruce B Units 5 to 8 were subject to a floor price of $46.82 per MWh in third quarter 2007 and $45.99 per MWh in third quarter 2006. Both the Bruce A and Bruce B reference prices are adjusted annually for inflation on April 1. In first quarter 2007, the Bruce A fixed price was $58.63 per MWh (2006 - $57.37 per MWh) and the Bruce B floor price was $45.99 per MWh (2006 - $45.00 per MWh). Payments received pursuant to the Bruce B floor price mechanism are subject to a recapture payment dependent on annual spot prices over the term of the contract. Bruce B net earnings do not include any amounts received under this floor price mechanism to date. To further reduce its exposure to spot market prices, Bruce B has entered into fixed price sales contracts to sell forward approximately 2,500 GWh of output for the remainder of 2007 and 8,600 GWh for 2008.

The capital cost of Bruce A's revised four-unit, seven-year restart and refurbishment project is expected to total approximately $5.25 billion, with TransCanada's share being approximately $2.6 billion. As at September 30, 2007, Bruce A had incurred capital costs of $1.8 billion with respect to the revised restart and refurbishment project.



Western Power Operations

Western Power Operations Results-at-a-Glance
(unaudited) Three months ended Nine months ended
(millions of September 30 September 30
dollars) 2007 2006 2007 2006
---------------------------------------------------------------------------
Revenues
Power 325 311 832 807
Other(1) 22 32 71 134
----------------------------------------------
347 343 903 941
----------------------------------------------

Commodity purchases resold
Power (172) (194) (486) (534)
Other(2) (18) (27) (53) (103)
----------------------------------------------
(190) (221) (539) (637)
----------------------------------------------

Plant operating costs
and other (32) (32) (100) (100)
Depreciation (5) (6) (14) (16)
----------------------------------------------

Operating income 120 84 250 188
----------------------------------------------
----------------------------------------------

(1)Other revenue includes Cancarb Thermax and natural gas sold.

(2)Other cost of sales includes the cost of natural gas sold.



Western Power Operations Sales Volumes
Three months ended Nine months ended
(unaudited) September 30 September 30
(GWh) 2007 2006 2007 2006
---------------------------------------------------------------------------
Supply
Generation 560 599 1,683 1,622
Purchased
Sundance A & B
and Sheerness PPAs 2,860 3,283 8,990 9,520
Other purchases 362 455 1,227 1,460
----------------------------------------------
3,782 4,337 11,900 12,602
----------------------------------------------
----------------------------------------------

Sales
Contracted 2,845 3,261 9,354 9,236
Spot 937 1,076 2,546 3,366
----------------------------------------------
3,782 4,337 11,900 12,602
----------------------------------------------
----------------------------------------------


Western Power Operations' operating income of $120 million in third quarter 2007 increased $36 million compared to $84 million in third quarter 2006. This increase was primarily due to increased margins from the Alberta power purchase arrangements (PPA) resulting from higher overall realized power prices and lower PPA costs, partially offset by lower volumes. Higher prices were realized despite a three per cent decrease in average Alberta spot market prices, due to recontracting at higher prices. Western Power Operations' strategy is to reduce its exposure to lower spot market prices by contracting the majority of volumes and selling fewer volumes into the spot market.

Purchased volumes of 2,860 GWh in third quarter 2007 decreased 423 GWh compared to third quarter 2006 primarily due to a planned outage at the Sundance B facility.

Western Power Operations manages the sale of its supply volumes on a portfolio basis. A portion of its supply is held for sale in the spot market for operational reasons and the amount of supply volumes eventually sold into the spot market is dependent upon the ability to transact in forward sales markets at acceptable contract terms. This approach to portfolio management assists in minimizing costs in situations where Western Power Operations would otherwise have to purchase electricity in the open market to fulfill its contractual sales obligations. Consistent with third quarter 2006, approximately 25 per cent of power sales volumes were sold into the spot market in third quarter 2007. To reduce its exposure to spot market prices on uncontracted volumes, as at September 30, 2007, Western Power Operations had fixed-price power sales contracts to sell approximately 2,600 GWh for the remainder of 2007 and 7,600 GWh for 2008.

Western Power Operations' operating income for the nine months ended September 30, 2007 increased $62 million to $250 million compared to the same period in 2006. This increase was primarily due to higher overall realized power prices and lower PPA costs.



Eastern Power Operations

Eastern Power Operations Results-at-a-Glance(1)
(unaudited) Three months ended Nine months ended
(millions of September 30 September 30
dollars) 2007 2006 2007 2006
---------------------------------------------------------------------------
Revenue
Power 392 192 1,135 527
Other(2) 39 49 186 224
----------------------------------------------
431 241 1,321 751
----------------------------------------------

Commodity purchases resold
Power (226) (94) (586) (284)
Other(2) (38) (47) (163) (196)
----------------------------------------------
(264) (141) (749) (480)
----------------------------------------------
Plant operating costs
and other (103) (53) (347) (118)
Depreciation (12) (7) (36) (21)
----------------------------------------------

Operating income 52 40 189 132
----------------------------------------------
----------------------------------------------

(1)Includes Becancour and Baie-des-Sables effective September 17, 2006 and
November 21, 2006, respectively.

(2)Other includes natural gas.


Eastern Power Operations Sales Volumes(1)
Three months ended Nine months ended
(unaudited) September 30 September 30
(GWh) 2007 2006 2007 2006
---------------------------------------------------------------------------
Supply
Generation 1,915 1,039 5,966 2,693
Purchased 2,087 934 5,175 2,331
----------------------------------------------
4,002 1,973 11,141 5,024
----------------------------------------------
----------------------------------------------

Sales
Contracted 3,913 1,829 10,707 4,715
Spot 89 144 434 309
----------------------------------------------
4,002 1,973 11,141 5,024
----------------------------------------------
----------------------------------------------

(1)Includes Becancour and Baie-des-Sables effective September 17, 2006 and
November 21, 2006, respectively.


Eastern Power Operations' operating income of $ 52 million and $ 189 million for the three and nine months ended September 30, 2007, respectively, increased $12 million and $57 million, compared to the same periods in 2006. The increase was primarily due to incremental income earned in 2007 from the startup of the 550 MW Becancour cogeneration plant in September 2006 and payments received under the newly designed forward capacity market in New England, partially offset by decreased generation from the TC Hydro facilities resulting from reduced water flows.

Generation volumes in third quarter 2007 of 1,915 GWh increased 876 GWh compared to 1,039 GWh generated in third quarter 2006 primarily due to the placing into service of the Becancour facility, partially offset by decreased output from the TC Hydro generation assets resulting from reduced water flows.

Eastern Power Operations' power revenues of $392 million increased $ 200 million in third quarter 2007, compared to third quarter 2006, primarily due to the placing into service of the Becancour and Baie-des-Sables facilities, increased sales volumes to commercial and industrial customers, and revenue received under the newly designed forward capacity market in New England. Power commodity purchases resold of $226 million and purchased power volumes of 2,087 GWh were significantly higher in third quarter 2007, compared to third quarter 2006, primarily due to the impact of increased purchases to supply increased sales volumes to wholesale, commercial and industrial customers. Plant operating costs and other of $103 million, which includes fuel gas consumed in generation, increased in third quarter 2007 from the prior year primarily as a result of the startup of the Becancour facility.

In third quarter 2007, approximately two per cent of power sales volumes were sold into the spot market compared to approximately seven per cent in third quarter 2006. Eastern Power Operations is focused on selling the majority of its power under contract to wholesale, commercial and industrial customers, while managing a portfolio of power supplies sourced from its own generation and wholesale power purchases. To reduce its exposure to spot market prices, as at September 30, 2007, Eastern Power Operations entered into fixed price power sales contracts to sell approximately 4,000 GWh for the remainder of 2007 and 12,400 GWh for 2008, although certain contracted volumes are dependent on customer usage levels.

Power Plant Availability



Weighted Average Power Plant Availability(1)

Three months ended Nine months ended
September 30 September 30
(unaudited) 2007 2006 2007 2006
---------------------------------------------------------------------------
Bruce Power 90% 90% 86% 88%
Western Power Operations 91% 94% 93% 86%
Eastern Power Operations(2) 99% 98% 97% 97%
All plants, excluding Bruce Power 97% 97% 95% 94%
All plants 94% 93% 92% 90%
----------------------------------------------
----------------------------------------------

(1)Plant availability represents the percentage of time in the period that
the plant is available to generate power, whether actually running or not
and is reduced by planned and unplanned outages.

(2)Eastern Power Operations includes Becancour and Baie-des-Sables effective
September 17, 2006 and November 21, 2006, respectively.


Natural Gas Storage

Natural Gas Storage operating income of $39 million in third quarter 2007 increased $15 million compared to $24 million in third quarter 2006. Natural Gas Storage operating income of $89 million for the nine months ended September 30, 2007 increased $26 million compared to $63 million for the same period in 2006. These increases were primarily due to incremental income earned in 2007 from the startup of the Edson facility in December 2006.

TransCanada manages its natural gas storage assets' exposure to seasonal natural gas price spreads by hedging storage capacity with a portfolio of third party storage capacity leases and proprietary natural gas purchases and sales. Earnings from third party storage capacity leases are recognized evenly over the term of the lease. Earnings for proprietary natural gas sales, exclusive of unrealized gains or losses from changes in fair value, are recognized when the natural gas is sold which typically occurs during the winter withdrawal season.

The change in the fair value of the proprietary forward purchase and sale contracts was primarily offset by the change in the fair value of the related inventory. The net change in the fair values of the proprietary natural gas storage inventory and forward contracts included in income in third quarter 2007 was not significant.

General, Administrative and Support Costs

General, administrative and support costs of $38 million and $113 million for the three and nine months ended September 30, 2007, respectively, increased $3 million and $13 million, compared to the same periods in 2006. The increases were primarily due to higher business development costs associated with growing the Energy business.

As at September 30, 2007, TransCanada had capitalized $37 million related to the Broadwater liquefied natural gas project.

Corporate

Corporate net earnings for the three months ended September 30, 2007 were $5 million compared to $40 million for the same period in 2006. Corporate's net earnings decreased due to $15 million of favourable income tax reassessments and associated interest income in 2007 relating to prior years, compared to a $50-million income tax benefit in 2006 arising from a resolution of certain income tax matters with taxation authorities and changes in estimates. Gains on derivatives used to manage the Company's exposure to foreign exchange rate fluctuations and the impact of positive tax rate differentials were offset by higher financial charges, primarily as a result of financing the ANR and Great Lakes acquisitions. Corporate's comparable expenses were $10 million in each of third quarter 2007 and 2006, which excludes the $15-million and $50-million income tax reassessments and adjustments.

Net earnings from Corporate for the nine months ended September 30, 2007 and 2006 were $6 million and $28 million, respectively. Corporate's earnings decreased for the same reasons discussed above, as well as income tax reassessments and adjustments of $42 million and $60 million for the nine months ended September 30, 2007 and 2006, respectively. Corporate's comparable expenses were $36 million and $32 million for the nine months ended September 30, 2007 and 2006, respectively. Comparable expenses excluded the $42-million and $60-million favourable income tax reassessments and adjustments.

Liquidity and Capital Resources



Funds Generated from Operations
Three months ended Nine months ended
(unaudited) September 30 September 30
(millions of dollars) 2007 2006 2007 2006
---------------------------------------------------------------------------
Cash Flows
Funds generated from
operations(1) 702 662 1,880 1,718
Decrease/(increase) in
operating working capital 132 (43) 261 (136)
----------------------------------------------
Net cash provided by operations 834 619 2,141 1,582
----------------------------------------------
----------------------------------------------

(1)For further discussion on funds generated from operations refer to the
Non-GAAP Measures section in this MD&A.


Net cash provided by operations increased $215 million and $559 million in the three and nine months ended September 30, 2007, respectively, compared to the same periods in 2006. The increase in net cash provided by operations was primarily due to an increase in funds generated from operations and a decrease in operating working capital. Funds generated from operations were $ 702 million and $1.9 billion for the three and nine months ended September 30, 2007, respectively, compared to $662 million and $1.7 billion for the same periods in 2006. These increases were mainly due to an increase in cash generated through earnings.

TransCanada expects that its ability to generate adequate amounts of cash in the short and long term, when needed, and to maintain financial capacity and flexibility to provide for planned growth remains substantially unchanged since December 31, 2006.

Investing Activities

Acquisitions, net of cash acquired, for the nine months ended September 30, 2007 were $4.2 billion primarily due to the acquisition of ANR and the additional 3.55 per cent interest in Great Lakes for approximately US$3.4 billion, including US$491 million of assumed long-term debt. TransCanada began consolidating ANR and Great Lakes in the Pipelines segment subsequent to the acquisition date of February 22, 2007. The acquisition was financed with a combination of proceeds from an equity offering of the Company, cash on hand and funds drawn on loan facilities. Acquisitions also include PipeLines LP's acquisition of a 46.45 per cent interest in Great Lakes for approximately US$942 million, including US$209 million of assumed long-term debt. The acquisition was financed with debt facilities and a private placement offering of PipeLines LP units, which included a US$312-million investment by TransCanada.

Acquisitions for nine months ended September 30, 2006 were $358 million and related to the purchase of an additional 20 per cent general partnership interest in Northern Border Pipeline Company by PipeLines LP.

For the three and nine months ended September 30, 2007, capital expenditures totalled $ 364 million (2006 - $372 million) and $ 1.1 billion (2006 - $1.0 billion), respectively, and primarily related to the restart and refurbishment of Bruce A Units 1 and 2, the construction of new power plants in Energy and capital expenditures in Pipelines.

In the nine months ended September 30, 2006, disposition of assets, net of current income tax, generated $23 million related to the sale of TransCanada's 17.5 per cent general partner interest in Northern Border Partners, L.P.

Financing Activities

TransCanada retired $64 million and $859 million of long-term debt in the three and nine months ended September 30, 2007, respectively ($4 million and $352 million for the three and nine months ended September 30, 2006, respectively) and issued $5 million and $2.6 billion of long-term debt and junior subordinated notes for the three and nine months ended September 30, 2007, respectively (nil and $1.3 billion for the three and nine months ended September 30, 2006, respectively). TransCanada's notes payable increased $293 million and $554 million in the three and nine months ended September 30, 2007, respectively, compared to an increase of $ 4 million and a decrease of $449 million for the three and nine months ended September 30, 2006, respectively. The Company redeemed $488 million of preferred securities in third quarter 2007.

On October 5, 2007, TransCanada issued US$1.0 billion of senior unsecured notes (Notes). The Notes mature on October 15, 2037 and bear interest at a rate of 6.20 per cent. The effective interest rate at issuance was 6.30 per cent. The Notes were issued under a debt shelf prospectus in the U.S., filed in September 2007, which qualifies for issuance US$2.5 billion of debt securities, and replaced the US$1.5 billion debt shelf prospectus filed in March 2007. Prior to being replaced, the Company had issued US$1.0 billion of debt securities under the March 2007 U.S. debt shelf prospectus.

In July 2007, TransCanada redeemed, at par, all of the outstanding US$460 million 8.25 per cent preferred securities due 2047. The redemption occurred as a result of the five-year tolls settlement reached on the Canadian Mainline.

In April 2007, TransCanada issued US$1.0 billion of Junior Subordinated Notes (Junior Notes) maturing in 2067 and bearing interest of 6.35 per cent per year until May 15, 2017 at which time the interest on the Junior Notes will convert to a floating rate, reset quarterly to the three-month London Interbank Offered Rate (LIBOR) plus 221 basis points. The Junior Notes remained outstanding at September 30, 2007 and had an effective interest rate of 6.51 per cent. TransCanada has the option to defer payment of interest for one or more periods of up to ten years without giving rise to an event of default and without permitting acceleration of payment under the terms of the Junior Notes. If this were to occur, the Company would be prohibited from paying dividends during the deferral period. The Junior Notes are subordinated in right of payment to existing and future senior indebtedness and are effectively subordinated to all indebtedness and obligations of TCPL. The Junior Notes are callable at TransCanada's option at any time on or after May 15, 2017 at 100 per cent of the principal amount of the Junior Notes plus accrued and unpaid interest to the date of redemption. Upon the occurrence of certain events, the Junior Notes are callable earlier at TransCanada's option, in whole or in part, at an amount equal to the greater of 100 per cent of the principal amount of the Junior Notes plus accrued and unpaid interest to the date of redemption or at an amount determined by formula in accordance with the terms of the Junior Notes.

In April 2007, Northern Border established a US$250 million five-year bank facility. A portion of the bank facility was drawn to refinance US$150 million of senior notes that matured on May 1, 2007, with the balance available to fund Northern Border's ongoing operations.

In March 2007, the Company filed debt shelf prospectuses in Canada and the U.S. qualifying for issuance $1.5 billion of medium-term notes and US$1.5 billion of debt securities, respectively. At September 30, 2007, the Company had issued no medium-term notes under the Canadian prospectus and had replaced the March 2007 U.S. debt shelf prospectus with a new US$2.5 billion U.S. debt shelf prospectus, as described above.

In March 2007, ANR Pipeline Company voluntarily withdrew from the New York Stock Exchange the listing of its 9.625 per cent Debentures due 2021, 7.375 per cent Debentures due 2024, and 7.0 per cent Debentures due 2025. With the delisting, which became effective April 12, 2007, ANR Pipeline Company deregistered these securities from registration with the SEC.

In February 2007, the Company executed an agreement for a US$2.2-billion, committed, unsecured, one-year bridge loan facility with a floating interest rate based on the one-month LIBOR plus 25 basis points. The Company utilized $1.5 billion and US$700 million from this facility to partially finance the ANR and Great Lakes acquisition. At September 30, 2007, the Company had an outstanding balance of US$400 million on this facility. The undrawn balance of this facility has been cancelled and is no longer available to the Company.

In February 2007, the Company established a US$1.0-billion committed, unsecured credit facility, consisting of a US$700-million five-year term loan and a US$300-million five-year, extendible revolving facility. A floating interest rate based on the three-month LIBOR plus 22.5 basis points is charged on the balance outstanding and a facility fee of 7.5 basis points is charged on the entire facility. The Company utilized US$1.0 billion from this facility and an additional US$100 million from an existing demand line to partially finance the ANR acquisition as well as its additional investment in PipeLines LP. At September 30, 2007, the Company had an outstanding balance of US$700 million on the credit facility and had repaid the demand line.

In February 2007, PipeLines LP increased the size of its syndicated revolving credit and term loan facility in connection with its Great Lakes acquisition. The amount available under the facility increased from US$410 million to US$950 million, consisting of a US$700-million senior term loan and a US$250-million senior revolving credit facility, with US$194 million of the senior term loan amount available being terminated upon closing of the Great Lakes acquisition. At September 30, 2007, US$517 million was outstanding under this facility. A floating interest rate based on the three-month LIBOR plus 55 basis points is charged on the senior term loan and a floating interest rate based on the one-month LIBOR plus 35 basis points is charged on the senior revolving credit facility. A facility fee of 10 basis points is charged on the US$250 million senior revolving credit facility. The weighted average interest rate at September 30, 2007 was 6.16 per cent.

In January 2007, TransCanada filed a short form shelf prospectus with securities regulators in Canada and the U.S. to allow for the offering of up to $3.0 billion of common shares, preferred shares and/or subscription receipts in Canada and the U.S. until February 2009. As at September 30, 2007, the Company had issued 45,390,500 common shares at a price of $38.00 each, resulting in gross proceeds of approximately $1.725 billion under this shelf prospectus, which were used towards financing the acquisition of ANR and Great Lakes.

Under its Dividend Reinvestment and Share Purchase Plan, TransCanada issued 1.4 million and 2.7 million common shares in the three and nine months ended September 30, 2007, respectively, in lieu of making cash dividend payments of $53 million and $104 million, respectively.

Dividends

On October 29, 2007, TransCanada's Board of Directors declared a quarterly dividend of $0.34 per share for the quarter ending December 31, 2007 on the Company's outstanding common shares. It is payable on January 31, 2008 to shareholders of record at the close of business on December 31, 2007.

Directors also approved the issuance of common shares from treasury at a two per cent discount under TransCanada's Dividend Reinvestment and Share Purchase Plan for the dividend payable January 31, 2008. The Company reserves the right to alter the discount or return to purchasing shares on the open market at any time.

Changes in Accounting Policies

The Company's Accounting Policies have not changed materially from those described in TransCanada's 2006 Annual Report and First and Second Quarter 2007 Quarterly Reports to Shareholders.

Contractual Obligations

As a result of TransCanada's acquisition of ANR, Pipelines' future purchase obligations, primarily consisting of operating lease and purchase obligations, increased $225 million at September 30, 2007, compared to December 31, 2006.

The Company has entered into contracts to purchase pipe and supplies totalling approximately $2.3 billion for construction of the Keystone oil pipeline and other pipeline projects.

Other than the above-mentioned commitments and future debt and interest payments relating to debt issuances and redemptions discussed in the Financing Activities section of this MD&A, there have been no other material changes to TransCanada's contractual obligations from December 31, 2006 to September 30, 2007, including payments due for the next five years and thereafter. For further information on these contractual obligations, refer to the MD&A in TransCanada's 2006 Annual Report.

Financial Instruments and Risk Management

Energy Price, Interest Rate and Foreign Exchange Rate Risk Management

The Company enters into various contracts to mitigate its exposure to fluctuations in commodity prices, interest rates and foreign exchange rates. The contracts generally consist of the following.

- Forwards and futures contracts - contractual agreements to buy or sell a specific financial instrument or commodity at a specified price and date in the future. The Company enters into foreign exchange and commodity forwards and futures to mitigate volatility in foreign exchange rates and power and gas prices, respectively.

- Swaps - contractual agreements between two parties to exchange streams of payments over time according to specified terms. The Company enters into interest rate, cross-currency and commodity swaps to mitigate changes in interest rates, foreign exchange rates and commodity prices, respectively.

- Options - contractual agreements to convey the right, but not the obligation, for the purchaser either to buy or sell a specific amount of a financial instrument or commodity at a fixed price, either at a fixed date or at any time within a specified period. The Company enters into option agreements to mitigate changes in interest rates, foreign exchange rates and commodity prices.

- Heat rate contracts - contracts for the sale or purchase of power that are priced based on a natural gas index.

Energy Price Risk

The Company is exposed to energy price movements as part of its normal business operations, particularly in relation to the prices of electricity and natural gas. The primary risk is that market prices for commodities will move adversely between the time that purchase and/or sales prices are fixed, potentially reducing expected margins.

To manage exposure to price risk, subject to the Company's overall risk management policies and procedures, the Company commits a significant portion of its supply to medium- to long-term sales contracts while reserving an amount of unsold supply to maintain flexibility in the overall management of its asset portfolio. The types of instruments used include forwards and futures contracts, swaps, options, and heat rate contracts.

The Company continually assesses its power contracts and derivative instruments used to manage energy price risk. Contracts, with the exception of leases, have been assessed to determine whether they meet the definition of a derivative. Certain commodity purchase and sale contracts are derivatives but are not within the scope of the Canadian Institute of Chartered Accountants Handbook, Section 3855, as they were entered into and continue to be held for the purpose of receipt or delivery in accordance with the Company's expected purchase, sale or usage requirements (normal purchases and sales exception). As well, certain contracts are not within the scope of Section 3855 as they are considered to be executory contracts or meet other exemption criteria.

Natural Gas Inventory Price Risk

Effective April 1, 2007, TransCanada began valuing its proprietary natural gas storage inventory at fair value, as measured by the one-month forward price for natural gas. In order to record inventory at fair value, TransCanada has designated its natural gas storage business as a broker/trader business that purchases and sells natural gas on a back-to-back basis. The Company did not have any proprietary natural gas inventory prior to April 1, 2007.

The Company records its proprietary natural gas storage results in Revenues net of Commodity Purchases Resold. All changes in the fair value of the proprietary natural gas storage inventory are recorded in Inventories and Revenues. At September 30, 2007, $81 million of proprietary natural gas storage inventory was included in Inventories, which included $25 million related to changes in fair value of the proprietary natural gas storage inventory. Revenues included unrealized pre-tax losses related to the change in fair value of the proprietary natural gas storage inventory for the three and nine months ended September 30, 2007 of $2 million and $25 million, respectively. These losses were essentially offset by the change in fair value of the forward proprietary natural gas purchase and sale contracts.

TransCanada manages its exposure to seasonal gas price spreads in its natural gas storage business by hedging storage capacity with a portfolio of third party storage capacity leases and proprietary natural gas purchases and sales. By matching purchase and sale volumes, TransCanada locks in a margin and effectively eliminates its exposure to the price movements of natural gas.

Interest Rate Risk

The Company has fixed interest rate long-term debt, which subjects the Company to interest rate price risk, and has floating interest rate long-term debt, which subjects the Company to interest rate cash flow risk. To manage its exposure to these risks, the Company uses a combination of interest-rate swaps, forwards and options.

Investments in Foreign Operations

The Company hedges its net investment in self-sustaining foreign operations with U.S. dollar-denominated debt, cross-currency swaps, forward exchange contracts and options. At September 30, 2007, the Company had designated U.S. dollar-denominated debt with a carrying value of $3.8 billion (US$3.8 billion) and a fair value of $ 3.9 billion (US$3.9 billion) as a portion of this hedge and swaps, forwards and options with a fair value of $81 million (US$81 million) as net investment hedges.



Derivatives Hedging Net Investment in Foreign Operations

Asset/(Liability)
(millions of dollars) September 30, 2007 December 31, 2006
--------------------------------------------------------------------------
Notional or Notional or
Fair Principal Fair Principal
Value(1) Amount Value(1) Amount
-------------------------------------------

Derivative financial
Instruments in hedging
relationships
U.S. dollar cross-currency
swaps (maturing 2009 to 2014) 74 U.S. 350 58 U.S. 400
U.S. dollar forward foreign
exchange contracts (maturing
2007 ) 3 U.S. 100 (7) U.S. 390
U.S. dollar options
(maturing 2007 ) 4 U.S. 100 (6) U.S. 500

-------------------------------------------
81 U.S. 550 45 U.S. 1,290
-------------------------------------------
-------------------------------------------

(1)Fair values are equal to carrying values.


Fair Values

Fair values of financial instruments are determined by reference to quoted bid or asking price, as appropriate, in active markets. In the absence of an active market, the Company determines fair value by using valuation techniques that refer to observable market data or estimated market prices. These include comparisons with similar instruments where market observable prices exist, option pricing models and other valuation techniques commonly used by market participants. Fair values determined using valuation models require the use of assumptions concerning the amount and timing of estimated future cash flows and discount rates. In determining those assumptions, the Company looks primarily to external readily observable market input factors such as interest rate yield curves, currency rates, and price and rate volatilities as applicable.

Realized and Unrealized Gains and Losses

At September 30, 2007, there were unrealized gains from unsettled derivative financial instruments of $172 million (December 31, 2006 - $41 million) included in Other Current Assets and $129 million (December 31, 2006 - $39 million) included in Other Assets. At September 30, 2007, there were unrealized losses from unsettled derivative financial instruments of $189 million (December 31, 2006 - $144 million) included in Accounts Payable and $239 million (December 31, 2006 - $158 million) included in Deferred Amounts. For the three and nine months ended September 30, 2007, Net Income included $35 million and $50 million, respectively, of realized gains from settled derivative financial instruments. For the three and nine months ended September 30, 2007, Net Income included $5 million and $21 million, respectively, of unrealized gains from unsettled derivative financial instruments.

Risk Related to Environmental Regulations

Effective July 1, 2007, industrial facilities in Alberta emitting more than 100,000 tonnes of carbon dioxide equivalent are required to reduce their greenhouse gas (GHG) emissions intensities by 12 per cent under the Specified Gas Emitters Regulation. Emitters have until March 31, 2008 to submit third party verified reports that establish how they have met their compliance obligations. Compliance options include acquisition of Alberta-based offsets (emissions reductions from uncapped sources); installation of capital or implementation of processes that result in decreases in emissions intensities; purchase of compliance instruments from other capped entities; and contributions to the Climate Change and Emissions Management Fund. TransCanada is currently assessing its options for meeting its compliance obligations under the Alberta regulation.

TransCanada anticipates that costs associated with GHG reduction targets impacting the Alberta System will be recovered through future tolls paid by customers on the Alberta System. Recovery of GHG compliance costs related to the Company's power facilities in Alberta is ultimately dependent upon market prices for electricity. These GHG changes may have an impact on these market prices.

TransCanada continues to be engaged in policy discussions at all levels with provincial, state and federal governments. There are several processes taking place, including assessment of significant infrastructure requirements, further development of broad policy elements (for example, domestic offset systems and management of the federal technology fund) and submission of third party audited compliance reports. TransCanada is following developments in each of these processes. As provincial, state and federal government initiatives have the potential to significantly impact the energy industry, the Company continues to assess and monitor the implications to TransCanada's businesses.

Other Risks

Additional risks faced by the Company are discussed in the MD&A in TransCanada's 2006 Annual Report. TransCanada's market, financial and counterparty risks remain substantially unchanged since December 31, 2006.

Controls and Procedures

As of September 30, 2007, an evaluation was carried out under the supervision of, and with the participation of, management including the President and Chief Executive Officer and the Chief Financial Officer, of the effectiveness of TransCanada's disclosure controls and procedures as defined under the rules adopted by the SEC. Based on that evaluation, the President and Chief Executive Officer and the Chief Financial Officer concluded that the design and operation of TransCanada's disclosure controls and procedures were effective as at September 30, 2007.

During the recent fiscal quarter, there have been no changes in TransCanada's internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, TransCanada's internal control over financial reporting. With respect to the ANR acquisition completed in 2007, the Company expects to exclude ANR from its year-end assessment of internal controls over financial reporting.

Significant Accounting Policies and Critical Accounting Estimates

Since determining the value of certain assets, liabilities, revenues and expenses is dependent upon future events, the preparation of the Company's consolidated financial statements requires the use of estimates and assumptions, which have been made using careful judgment.

TransCanada's significant accounting policies and critical accounting estimates are the use of regulatory accounting for the Company's rate-regulated operations and the policies the Company adopts to account for derivatives and depreciation and amortization expense. Effective January 1, 2007, the Company adopted the new accounting standards for financial instruments and hedges. For further information on the Company's accounting policies and estimates refer to the MD&A in TransCanada's 2006 Annual Report and First and Second Quarter 2007 Quarterly Reports to Shareholders.

Outlook

Since the disclosure in TransCanada's 2006 Annual Report, the Company's outlook is relatively unchanged except for the $46 million of income tax adjustments recorded in 2007 and the positive impact of the Settlement on the Canadian Mainline.

The recent strengthening of the Canadian dollar in relation to the U.S. dollar in 2007 is expected to have a negative foreign exchange impact on TransCanada's net earnings from its U.S. operations. However, an offsetting positive impact is expected due to the Company's continued management of this exposure with interest on U.S. dollar debt and derivative activities. For further information on outlook, refer to the MD&A in TransCanada's 2006 Annual Report.

TransCanada Corporation's issuer rating assigned by Moody's Investors Service (Moody's) is A3 with a stable outlook. TCPL's senior unsecured debt is rated A, with a stable outlook, by DBRS; A2, with a stable outlook, by Moody's; and A-, with a stable outlook, by Standard & Poor's.

Other Recent Developments

Pipelines

Keystone Oil Pipeline

On September 20, 2007, the Keystone oil pipeline project received NEB approval of its application to construct and operate the Canadian portion of the Keystone oil pipeline, including converting a portion of the Canadian Mainline to crude oil service from natural gas service. The NEB also approved the toll methodology and tariff for the Keystone oil pipeline. Keystone has also submitted applications for U.S. regulatory approvals at federal and state levels.

TransCanada also intends to file an application with the NEB in November 2007 for additional pumping facilities required to expand Keystone from a nominal capacity of approximately 435,000 barrels per day to 590,000 barrels per day. TransCanada has entered into or conditionally awarded contracts totalling approximately US$3.0 billion for major materials and pipeline construction contractors and is continuing to secure land access agreements. Based on the increased size and scope of the project and updated cost information for materials and labour, the total capital cost of Keystone has been revised to approximately US$5.2 billion. The Company expects to begin construction in the spring of 2008.

North Baja

On October 2, 2007, TransCanada's North Baja pipeline received a certificate from the FERC authorizing it to expand and modify its existing system. The modification will facilitate the importation of regassified liquefied natural gas (LNG) from Mexico into the California and Arizona markets. The project will be completed in two phases. Phase I consists of minor modifications to the existing pipeline system to allow imported gas flows from an LNG terminal currently under construction in Mexico. This phase is expected to be completed and placed in service in early 2008. Phase II is expected to proceed following a capacity expansion of the LNG terminal and will require looping of much of the existing pipeline. Phase II is not expected to be placed in service earlier than 2011.

Alberta System

On July 11, 2007, TransCanada applied to the Energy and Utilities Board (Alberta) (EUB) for approval to initiate negotiations with respect to the Alberta System revenue requirement, or components of the revenue requirement, with the intent of reaching a settlement for a term of up to three years commencing January 1, 2008. On July 31, 2007, the EUB approved this request and TransCanada began negotiations with stakeholders in September 2007, which are ongoing. Concurrently, the Company is preparing to file a 2008 General Rate Application with the EUB in fourth quarter 2007.

In July 2007, the EUB approved an application for approval to construct approximately $300 million of new facilities on the Alberta System to initially serve the growing demand for natural gas in the Fort McMurray region of Alberta.

TransCanada Coordinated Non-Binding Open Season

On October 10, 2007, TransCanada announced a Non-Binding Open Season for firm transportation services on the Canadian Mainline System. The open season, which runs to December 10, 2007, is occurring concurrently with separate non-binding open seasons that are offered by ANR, Great Lakes and Portland. These open seasons are seeking expressions of interest to transport gas between emerging North American supply sources, including the Rockies Express Pipeline, Michigan storage sites and market areas served by these pipelines.

TQM Facilities to Cacouna

In August 2007, TQM filed a preliminary information package with the NEB and the Canadian Environmental Assessment Agency with respect to construction of facilities required to connect the proposed LNG terminal at Gros Cacouna to the existing TQM system near Quebec City. TransCanada and TQM are expected to file applications with the NEB by the end of 2007 for approval to construct facilities required to connect the proposed LNG terminal to the existing TQM and Canadian Mainline infrastructure.

TQM Settlement / General Rate Application

Settlement negotiations for TQM's 2007 revenue requirement, which commenced in the summer of 2006, have not resulted in a successful resolution to date. The preparation of a General Rate Application for 2007 and 2008 is ongoing and the Company expects to file the application with the NEB in November 2007.

Palomar

Palomar, a newly formed 50/50 joint venture between TransCanada and Northwest Natural Gas Company (NW Natural), is proposing to build a pipeline from GTN's mainline in central Oregon to connect with NW Natural's pipeline southeast of Portland, Oregon. In August 2007, Palomar initiated the "pre-filing" process with the FERC. This process allows for consultation with U.S. state and federal agencies about the proposed route of the pipeline, prior to formally filing with the FERC for a Certificate of Public Convenience and Necessity, which is expected to occur in the second quarter of 2008.

Energy

Bruce Power Restart and Refurbishment

On August 29, 2007, Bruce Power and the OPA amended their existing Bruce A agreement to expand the scope of the Bruce A Restart and Refurbishment project by installing 480 new fuel channels in Unit 4. By replacing the fuel channels in Unit 4, Bruce Power will extend the expected operational life of the 750 MW unit from 2017 to 2036. Under this revised plan, Bruce Power expects to invest an additional $1 billion, resulting in a total investment in the restart and refurbishment program of approximately $5.25 billion. TransCanada's share is expected to be approximately $2.6 billion. Under the revised agreement, the OPA may elect to proceed with a three unit restart program prior to April 1, 2008 under certain conditions. Those conditions include the OPA determining that there will be insufficient transmission to accommodate all eight Bruce units by mid 2013.

Cartier Wind Project

In September 2007, Cartier Wind Energy Inc. (Cartier) received environmental approval to build its proposed $170-million Carleton wind farm on the Gaspe Peninsula of Quebec. This approval allows Cartier to begin construction once all other permits are obtained. The 109.5 MW Carleton wind farm is the third project to be developed as a result of Hydro-Quebec's first wind energy call for tenders in 2004. The Cartier projects represent an investment of more than $1.1 billion in 740 MW of electricity generation in the province of Quebec. TransCanada has a 62 per cent ownership in Cartier.

Construction continues on the 100.5 MW Anse a Valleau wind farm and remains on schedule for completion by December 2007.

Cacouna Energy

On September 26, 2007, the Cacouna Energy project announced that the planned in-service date for the regassification terminal will be delayed from 2010 to 2012. Reasons for the delay include a need to assess the potential impacts of permit conditions, to review the facility design due to escalating costs and to coordinate terminal start-up with pipeline construction and the availability of LNG supply.

Kibby Wind Power Project

In October 2007, a Land Use Regulatory Commission Hearing concluded in Maine for the Kibby Wind Power Project, a proposed wind farm along Kibby Mountain and Kibby Range in the Boundary Mountains of Maine. The Kibby Wind Power Project includes 44 wind turbines and would be capable of producing approximately 132 MW of electricity. Subject to receipt of U.S. federal and state approvals, construction of the new facilities could begin in early 2008.

Belle Plaine Polygeneration Project

On October 5, 2007, TransCanada announced that the Company and the Government of Saskatchewan will each provide up to $26 million for the engineering design of a proposed polygeneration plant near Belle Plaine, Saskatchewan. The plant, which would be owned and operated by TransCanada, would use petroleum coke as feedstock to produce hydrogen, nitrogen, steam and carbon dioxide for fertilizer production and enhanced oil recovery, and to generate approximately 300 MW of electricity. The process would combine gassification and cogeneration technologies in a large industrial complex that would produce very low emissions, including significant capture and sequestration of carbon dioxide.

Under the agreement with the Government of Saskatchewan, TransCanada is obligated to repay the $26 million provided by the Government of Saskatchewan if the project proceeds. If the project does not proceed, the loan is not repayable. The project has a targeted in-service date of 2013.

Share Information

As at September 30, 2007, TransCanada had 537,761,544 issued and outstanding common shares. In addition, there were 9,211,600 outstanding options to purchase common shares, of which 6,695,845 were exercisable as at September 30, 2007.



Selected Quarterly Consolidated Financial Data(1)
------------------------------------------------

(unaudited)
(millions of
dollars except
per share 2007 2006 2005
amounts) Third Second First Fourth Third Second First Fourth
---------------------------------------------------------------------------

Revenues 2,210 2,212 2,249 2,091 1,850 1,685 1,894 1,771
Net Income
Continuing
operations 324 257 265 269 293 244 245 350
Discontinued
operations - - - - - - 28 -
---------------------------------------------------------------------------
324 257 265 269 293 244 273 350
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Share
Statistics
Net income
per share
- Basic
Continuing
operations $ 0.60 $ 0.48 $ 0.52 $ 0.55 $ 0.60 $ 0.50 $ 0.50 $ 0.72
Discontinued
operations - - - - - - 0.06 -
---------------------------------------------------------------------------
$ 0.60 $ 0.48 $ 0.52 $ 0.55 $ 0.60 $ 0.50 $ 0.56 $ 0.72
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Net income
per share
- Diluted
Continuing
operations $ 0.60 $ 0.48 $ 0.52 $ 0.54 $ 0.60 $ 0.50 $ 0.50 $ 0.71
Discontinued
operations - - - - - - 0.06 -
---------------------------------------------------------------------------
$ 0.60 $ 0.48 $ 0.52 $ 0.54 $ 0.60 $ 0.50 $ 0.56 $ 0.71
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Dividend
declared
per common
share $ 0.34 $ 0.34 $ 0.34 $ 0.32 $ 0.32 $ 0.32 $ 0.32 $ 0.305
---------------------------------------------------------------------------
---------------------------------------------------------------------------

(1)The selected quarterly consolidated financial data has been prepared in
accordance with Canadian GAAP. Certain comparative figures have been
reclassified to conform with the current year's presentation.


Factors Impacting Quarterly Financial Information

In Pipelines, which consists primarily of the Company's investments in regulated pipelines and regulated natural gas storage facilities, annual revenues and net earnings fluctuate over the long term based on regulators' decisions and negotiated settlements with shippers. Generally, quarter-over-quarter revenues and net earnings during any particular fiscal year remain relatively stable with fluctuations resulting from adjustments being recorded due to regulatory decisions and negotiated settlements with shippers, seasonal fluctuations in short-term throughput on U.S. pipelines and items outside of the normal course of operations.

In Energy, which consists primarily of the Company's investments in electrical power generation plants and non-regulated natural gas storage facilities, quarter-over-quarter revenues and net earnings are affected by seasonal weather conditions, customer demand, market prices, planned and unplanned plant outages as well as items outside of the normal course of operations.

Significant items which impacted the last eight quarters' net earnings are as follows.

- In fourth quarter 2005, net earnings included a $115-million after-tax gain on the sale of P.T. Paiton Energy Company. In addition, Bruce A was formed and Bruce Power's results were proportionately consolidated, effective October 31, 2005.

- In first quarter 2006, net earnings included an $18-million after-tax bankruptcy claim settlement from a former shipper on the Gas Transmission Northwest System. In addition, Energy's net earnings included contributions from the December 31, 2005 acquisition of the 756 MW Sheerness PPA.

- In second quarter 2006, net earnings included $33 million of future income tax benefits ($23 million in Energy and $10 million in Corporate) as a result of reductions in Canadian federal and provincial corporate income tax rates. Pipelines' net earnings included a $13-million after-tax gain related to the sale of the Company's general partner interest in Northern Border Partners, L.P.

- In third quarter 2006, net earnings included an income tax benefit of $50 million on the resolution of certain income tax matters with taxation authorities and changes in estimates. Energy's net earnings included earnings from Becancour, which came in service September 17, 2006.

- In fourth quarter 2006, net earnings included $12 million related to income tax refunds and related interest.

- In first quarter 2007, net earnings included $15 million related to positive income tax adjustments. In addition, Pipelines' net earnings included contributions from the February 22, 2007 acquisition of ANR and additional interests in Great Lakes. Energy's net earnings included earnings from the Edson natural gas facility, which was placed in service on December 31, 2006.

- In second quarter 2007, net earnings included $16 million ($12 million in Corporate and $4 million in Energy) related to positive income tax adjustments resulting from changes in Canadian federal income tax legislation. Pipeline's net earnings increased as a result of a settlement reached on the Canadian Mainline, which was approved by the NEB in May 2007.

- In third quarter 2007, net earnings included $15 million of favourable income tax reassessments and associated interest income relating to prior years.



Consolidated Income

(unaudited) Three months Nine months
(millions of dollars except per share ended ended
amounts) September 30 September 30
2007 2006 2007 2006
--------------------------------------------------------------------------

Revenues 2,210 1,850 6,671 5,429

Operating Expenses
Plant operating costs and other 739 593 2,232 1,696
Commodity purchases resold 476 382 1,579 1,224
Depreciation 298 264 888 787
-------------------------------
1,513 1,239 4,699 3,707
-------------------------------
697 611 1,972 1,722
-------------------------------
Other Expenses/(Income)
Financial charges 247 203 748 612
Financial charges of joint ventures 17 22 57 67
Income from equity investments (2) (4) (13) (28)
Interest income and other (43) (32) (111) (96)
Gain on sale of Northern Border Partners,
L.P. interest - - - (23)
-------------------------------
219 189 681 532
-------------------------------


Income from Continuing Operations before
Income Taxes and Non-Controlling Interests 478 422 1,291 1,190

Income Taxes
Current 83 31 347 278
Future 51 75 30 71
-------------------------------
134 106 377 349
-------------------------------

Non-Controlling Interests
Preferred share dividends of subsidiary 6 6 17 17
Non-controlling interest in PipeLines LP 13 11 44 32
Other 1 6 7 10
-------------------------------
20 23 68 59
-------------------------------

Net Income from Continuing Operations 324 293 846 782
Net Income from Discontinued Operations - - - 28
-------------------------------
Net Income 324 293 846 810
-------------------------------
-------------------------------

Net Income Per Share
Continuing operations $0.60 $0.60 $1.60 $1.60
Discontinued operations - - - 0.06
-------------------------------
Basic $0.60 $0.60 $1.60 $1.66
-------------------------------
-------------------------------
Diluted $0.60 $0.60 $1.60 $1.65
-------------------------------
-------------------------------
Average Shares Outstanding - Basic
(millions) 537 488 527 488
-------------------------------
-------------------------------
Average Shares Outstanding - Diluted
(millions) 540 490 530 490
-------------------------------
-------------------------------

See accompanying notes to the consolidated financial statements.



Consolidated Cash Flows

Three months Nine months
ended ended
(unaudited) September 30 September 30
(millions of dollars) 2007 2006 2007 2006
--------------------------------------------------------------------------


Cash Generated From Operations
Net income 324 293 846 810
Depreciation 298 264 888 787
Income from equity investments in excess
of distributions received (1) (1) (6) (8)
Future income taxes 51 75 30 71
Non-controlling interests 20 23 68 59
Funding of employee future benefits lower
than/(in excess of) expense 3 (2) 18 (17)
Gain on sale of Northern Border Partners,
L.P. interest, net of current income tax - - - (11)
Other 7 10 36 27
--------------------------------
702 662 1,880 1,718
Decrease/(increase) in operating working
capital 132 (43) 261 (136)
--------------------------------
Net cash provided by operations 834 619 2,141 1,582
--------------------------------

Investing Activities
Capital expenditures (364) (372) (1,056) (1,002)
Acquisitions, net of cash acquired 2 - (4,222) (358)
Disposition of assets, net of current
income taxes - - - 23
Deferred amounts and other (126) (47) (274) (63)
--------------------------------
Net cash used in investing activities (488) (419) (5,552) (1,400)
--------------------------------
Financing Activities
Dividends on common shares (183) (156) (521) (461)
Distributions paid to non-controlling
interests (23) (16) (68) (47)
Notes payable issued/(repaid), net 293 4 554 (449)
Long-term debt issued 5 - 1,456 1,250
Reduction of long-term debt (64) (4) (859) (352)
Long-term debt of joint ventures issued 12 14 122 38
Reduction of long-term debt of joint
ventures (20) (27) (139) (48)
Junior subordinated notes issued - - 1,107 -
Preferred securities redeemed (488) - (488) -
Partnership units of subsidiary issued - - 348 -
Common shares issued 53 12 1,801 25
--------------------------------
Net cash (used in)/provided by financing
activities (415) (173) 3,313 (44)
--------------------------------

Effect of Foreign Exchange Rate Changes on
Cash and Short-Term Investments (16) 1 (46) (8)
--------------------------------
(Decrease)/Increase in Cash and Short-Term
Investments (85) 28 (144) 130

Cash and Short-Term Investments
Beginning of period 340 314 399 212
--------------------------------

Cash and Short-Term Investments
End of period 255 342 255 342
--------------------------------
--------------------------------

Supplementary Cash Flow Information
Income taxes paid 93 87 305 455
Interest paid 290 195 832 629
--------------------------------
--------------------------------

See accompanying notes to the consolidated financial statements.



Consolidated Balance Sheet

(unaudited) September 30, December 31,
(millions of dollars) 2007 2006
---------------------------------------------------------------------------

ASSETS
Current Assets
Cash and short-term investments 255 399
Accounts receivable 1,008 1,004
Inventories 426 392
Other 238 297
---------------------------
1,927 2,092
Long-Term Investments 68 71
Plant, Property and Equipment 23,296 21,487
Goodwill 2,517 281
Other Assets 2,022 1,978
---------------------------
29,830 25,909
---------------------------
---------------------------

LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Notes payable 1,021 467
Accounts payable 1,708 1,500
Accrued interest 291 264
Current portion of long-term debt 706 616
Current portion of long-term debt of joint
ventures 27 142
---------------------------
3,753 2,989
Deferred Amounts 1,107 1,029
Future Income Taxes 1,250 876
Long-Term Debt 11,374 10,887
Long-Term Debt of Joint Ventures 880 1,136
Junior Subordinated Notes 983 -
Preferred Securities - 536
---------------------------
19,347 17,453
---------------------------
Non-Controlling Interests
Preferred shares of subsidiary 389 389
Non-controlling interest in PipeLines LP 540 287
Other 68 79
---------------------------
997 755
---------------------------
Shareholders' Equity
Common shares 6,595 4,794
---------------------------
Contributed surplus 276 273
---------------------------
Retained earnings 3,026 2,724
Accumulated other comprehensive loss (411) (90)
---------------------------
2,615 2,634
---------------------------
9,486 7,701
---------------------------
29,830 25,909
---------------------------
---------------------------

See accompanying notes to the consolidated financial statements.



Consolidated Comprehensive Income

Three months Nine months
ended ended
(unaudited) September 30 September 30
(millions of dollars) 2007 2006 2007 2006
---------------------------------------------------------------------------

Net income 324 293 846 810
------------------------------
Other comprehensive income/(loss), net of
tax
Change in foreign currency translation
gains and losses on investments in
foreign operations(1) (121) - (342) (30)
Change in gains and losses on hedges of
investments in foreign operations(2) 22 1 77 25
Change in gains and losses on derivative
instruments designated as cash flow
hedges(3) 41 - 4 -
Reclassification to net income of gains and
losses on derivative instruments designated
as cash flow hedges pertaining to prior
periods(4) 16 - 36 -
---------------------------------------------------------------------------
Other comprehensive (loss)/income for the
period (42) 1 (225) (5)
---------------------------------------------------------------------------
Comprehensive income for the period 282 294 621 805
---------------------------------------------------------------------------
---------------------------------------------------------------------------

(1)Net of income tax expense of $39 million and $95 million for the three
and nine months ended September 30, 2007, respectively (2006 - $nil and
$22 million expense, respectively).

(2)Net of income tax expense of $12 million and $40 million for the three
and nine months ended September 30, 2007, respectively (2006 -
$1 million expense and $13 million expense, respectively).

(3)Net of income tax expense of $13 million and $3 million for the three
and nine months ended September 30, 2007, respectively.

(4)Net of income tax expense of $14 million and $19 million for the three
and nine months ended September 30, 2007, respectively.

See accompanying notes to the consolidated financial statements.



Consolidated Shareholders' Equity

Nine months ended September 30
(unaudited)
(millions of dollars) 2007 2006
---------------------------------------------------------------------------
Common Shares
Balance at beginning of period 4,794 4,755
Proceeds from shares issued under public offering(1) 1,683 -
Shares issued under dividend reinvestment plan 104 -
Proceeds from shares issued on exercise of stock options 14 25
-------------
Balance at end of period 6,595 4,780
-------------

Contributed Surplus
Balance at beginning of period 273 272
Issuance of stock options 3 1
-------------
Balance at end of period 276 273
-------------

Retained Earnings
Balance at beginning of period 2,724 2,269
Transition adjustment resulting from adopting new financial
instruments accounting standards 4 -
Net income 846 810
Common share dividends (548) (468)
-------------
Balance at end of period 3,026 2,611
-------------

Accumulated Other Comprehensive Loss, net of income taxes
Balance at beginning of period (90) (90)
Transition adjustment resulting from adopting new financial
instruments accounting standards (96) -
Other comprehensive loss (225) (5)
-------------
Balance at end of period (411) (95)
-------------
Total Shareholders' Equity 9,486 7,569
-------------
-------------

(1)Net of underwriting commissions and future income taxes.

See accompanying notes to the consolidated financial statements.



Accumulated Other Comprehensive Loss

Currency
(unaudited) Translation Cash Flow
(millions of dollars) Adjustment Hedges Total
---------------------------------------------------------------------------
Balance at December 31, 2006 (90) - (90)
Transition adjustment resulting from
adopting new financial instruments standards - (96) (96)
Change in foreign currency translation gains
and losses on investments in foreign operations(1) (342) - (342)
Change in gains and losses on hedge of
investments in foreign operations(2) 77 - 77
Change in gains and losses on derivative
instruments designated as cash flow hedges(3) - 4 4
Reclassification to net income of gains and
losses on derivative instruments designated as
cash flow hedges pertaining to prior periods(4)(5) - 36 36
-----------------------
Balance at September 30, 2007 (355) (56) (411)
-----------------------
-----------------------

---------------------------------------------------------------------------
Balance at December 31, 2005 (90) - (90)
Change in foreign currency translation gains
and losses on investments in foreign operations(1) (30) - (30)
Change in gains and losses on hedge of
investments in foreign operations(2) 25 - 25
-----------------------
Balance at September 30, 2006 (95) - (95)
-----------------------
-----------------------

(1)Net of income tax expense of $95 million for the nine months ended
September 30, 2007 (2006 - $22 million expense).

(2)Net of income tax expense of $40 million for the nine months ended
September 30, 2007 (2006 - $13 million expense).

(3)Net of income tax expense of $3 million for the nine months ended
September 30, 2007.

(4)Net of income tax expense of $19 million for the nine months ended
September 30, 2007.

(5)During the next 12 months, the Company expects to reclassify to net
income an estimated $105 million ($71 million after tax) of net
losses reported in accumulated other comprehensive income for cash
flow hedges.

See accompanying notes to the consolidated financial statements.


Notes to Consolidated Financial Statements (Unaudited)

1. Significant Accounting Policies

The consolidated financial statements of TransCanada Corporation (TransCanada or the Company) have been prepared in accordance with Canadian generally accepted accounting principles (GAAP). The accounting policies applied are consistent with those outlined in TransCanada's annual audited consolidated financial statements for the year ended December 31, 2006, except for the changes noted below. These consolidated financial statements reflect all normal recurring adjustments that are, in the opinion of management, necessary to present fairly the financial position and results of operations for the respective periods. These consolidated financial statements do not include all disclosures required in the annual financial statements and should be read in conjunction with the 2006 audited consolidated financial statements included in TransCanada's 2006 Annual Report. Amounts are stated in Canadian dollars unless otherwise indicated. Certain comparative figures have been reclassified to conform with current period's presentation.

In Pipelines, which consists primarily of the Company's investments in regulated pipelines and regulated natural gas storage facilities, annual revenues and net earnings fluctuate over the long term based on regulators' decisions and negotiated settlements with shippers. Generally, quarter-over-quarter revenues and net earnings during any particular fiscal year remain relatively stable with fluctuations resulting from adjustments being recorded due to regulatory decisions and negotiated settlements with shippers, seasonal fluctuations in short-term throughput on U.S. pipelines and items outside of the normal course of operations.

In Energy, which consists primarily of the Company's investments in electrical power generation plants and non-regulated natural gas storage facilities, quarter-over-quarter revenues and net earnings are affected by seasonal weather conditions, customer demand, market prices, planned and unplanned plant outages as well as items outside of the normal course of operations.

Since a determination of the value of many assets, liabilities, revenues and expenses is dependent upon future events, the preparation of these consolidated financial statements requires the use of estimates and assumptions. In the opinion of Management, these consolidated financial statements have been properly prepared within reasonable limits of materiality and within the framework of the Company's significant accounting policies.

2. Changes In Accounting Policies

Changes in Second Quarter 2007

Proprietary Natural Gas Storage Inventories and Revenue Recognition

The new Canadian Institute of Chartered Accountants (CICA) Handbook accounting requirements for Section 3031 "Inventories" will become effective January 1, 2008; however, the Company chose to adopt this standard as of April 1, 2007. Adjustments to the 2007 consolidated financial statements have been made in accordance with the transitional provisions for this new standard.

Effective April 1, 2007, TransCanada began valuing its proprietary natural gas storage inventory at fair value, as measured by the one-month forward price for natural gas. In order to record inventory at fair value, TransCanada has designated its natural gas storage business as a broker/trader business that purchases and sells natural gas on a back-to-back basis. The Company did not have any proprietary natural gas inventory prior to April 1, 2007.

The Company records its proprietary natural gas storage results in Revenues net of Commodity Purchases Resold. All changes in the fair value of the proprietary natural gas storage inventory are recorded in Inventories and Revenues. At September 30, 2007, $81 million of proprietary natural gas storage inventory was included in Inventories, which included $25 million related to changes in fair value of the proprietary natural gas storage inventory. Revenues included unrealized pre-tax losses related to the change in fair value of the proprietary natural gas storage inventory for the three and nine months ended September 30, 2007 of $2 million and $25 million, respectively. These losses were essentially offset by the change in fair value of forward proprietary natural gas purchase and sale contracts.

Changes in First Quarter 2007

Effective January 1, 2007, the Company adopted the CICA Handbook accounting requirements for Section 1506 "Accounting Changes", Section 1530 "Comprehensive Income", Section 3251 "Equity", Section 3855 "Financial Instruments - Recognition and Measurement", Section 3861 "Financial Instruments - Disclosure and Presentation", and Section 3865 "Hedges". Adjustments to the consolidated financial statements for the first nine months in 2007 have been made in accordance with the transitional provisions for these new standards.

Comprehensive Income and Equity

The Company's financial statements include statements of Consolidated Comprehensive Income and Accumulated Other Comprehensive Loss. In addition, as required by Section 3251, the Company now presents separately in its Consolidated Shareholders' Equity the changes for each of its components of Shareholders' Equity, including Accumulated Other Comprehensive Loss.

Financial Instruments

All financial instruments are included on the balance sheet initially at fair value. All derivatives, other than those that meet the normal purchases and sales exceptions or are not within the scope of GAAP, are also carried on the balance sheet at fair value. In general, financial assets are classified as held for trading, held to maturity, loans and receivables, or available for sale. In general, financial liabilities are classified as held for trading or other financial liabilities. Subsequent measurement and financial statement classification of changes in fair value are determined by classification of the instruments.

Held-for-trading financial assets and liabilities consist of swaps, options, forwards and futures and are entered into with the intention of generating a profit. A financial asset or liability that does not meet this criteria may be designated as held for trading. TransCanada has not designated any financial assets or liabilities as held for trading. These financial instruments are initially accounted for at their fair value and changes to fair value are included in Revenues. Held-to-maturity financial assets are accounted for at their amortized cost using the effective interest method. The Company did not have any of these financial instruments at September 30, 2007. Loans and receivables include primarily trade accounts receivable and non-interest-bearing third party loans receivable and are accounted for at their amortized cost using the effective interest method. The available-for-sale classification includes non-derivative financial assets that are designated as available for sale or are not included in the other three classifications. These instruments are initially accounted for at their fair value and changes to fair value are recorded through Other Comprehensive Income. Income earned from these assets is included in Interest Income and Other.

Other financial liabilities not classified as held for trading are accounted for at their amortized cost, using the effective interest method. Interest expense is included in Financial Charges and Financial Charges of Joint Ventures. As part of the accounting for the Company's regulated operations, gains or losses from the changes in the fair value of financial instruments within the regulated operations are included in regulatory assets or regulatory liabilities.

Derivatives embedded in other financial instruments or contracts (the host instrument) are recorded as separate derivatives and are measured at fair value if the economic characteristics of the embedded derivative are not closely related to the host instrument, the terms of the embedded derivative are the same as those of a stand-alone derivative and the total contract is not held for trading or accounted for at fair value. Changes in fair value of the embedded derivative are included in Revenues. The Company used January 1, 2003 as the transition date for embedded derivatives.

Transaction costs are incremental costs that are directly attributable to the acquisition, issue or disposal of a financial instrument. Effective January 1, 2007, the Company began offsetting long-term debt transaction costs against the associated debt and began amortizing these costs using the effective interest method. Previously, these costs were amortized on a straight-line basis over the life of the debt. There was no material effect on the Company's financial statements as a result of this change in policy. In third quarter and the first nine months of 2007, the charge to Net Income for the amortization of transaction costs using the effective interest method was immaterial.

Hedges

Section 3865 specifies the circumstances under which hedge accounting is permissible, how hedge accounting may be performed and where the impacts should be recorded. The standard introduces three specific types of hedging relationships: fair value hedges, cash flow hedges and hedges of a net investment in self-sustaining foreign operations.

As part of its asset and liability management, the Company uses derivatives for hedging positions to reduce its exposure to credit and market risk. The Company designates certain derivatives as hedges and prepares documentation at the inception of the hedging contract. The Company performs an assessment at inception and during the term of the contract to determine if the derivative used as a hedge is effective in offsetting the risks in the values or cash flows of the hedged financial instrument. All derivatives are initially recorded at fair value and adjusted to fair value at each reporting date.

Fair value hedges primarily consist of interest rate swaps used to mitigate the effect of changes in the fair value of fixed-rate long-term financial instruments due to movements in market interest rates. Changes in the value of fair value hedges and the corresponding underlying transactions are recorded in Financial Charges and Interest Income and Other, for hedges of interest rates and foreign exchange rates, respectively. Any gains or losses arising from ineffectiveness are recognized immediately in income in the same financial category as the underlying transaction.

The Company uses cash flow hedges for its anticipated transactions to reduce exposure to fluctuations in interest rates, foreign exchange rates and changes in commodity prices. The effective portion of changes in the value of cash flow hedges is recognized in Other Comprehensive Income. Ineffective portions and amounts excluded from effectiveness testing of hedges are included in income in the same financial category as the underlying transaction. Gains or losses from cash flow hedges that have been included in Accumulated Other Comprehensive Loss are included in Net Income when the underlying transaction has occurred or becomes probable of not occurring. The maximum length of time the Company is hedging its exposure to variability in future cash flows is six years.

The Company hedges its foreign currency exposure of investments in self-sustaining foreign operations with certain cross-currency swaps, forward exchange contracts and options. These financial instruments are adjusted to fair value and the effective portion of gains or losses associated with these adjustments are included in Other Comprehensive Income. In addition, the Company hedges its net investment with U.S. dollar-denominated debt, which is valued at period-end foreign exchange rates. Gains or losses arising from ineffective portions of the hedge are included in income. Gains or losses from these hedges that have been included in Accumulated Other Comprehensive Loss are reclassified to Net Income in the event the Company settles or otherwise reduces its investment.

Net Effect of Accounting Policy Changes

The net effect to the Company's financial statements at January 1, 2007 resulting from the above-mentioned changes in accounting policies is as follows.



Increases/(decreases)
(unaudited)
(millions of dollars)
---------------------------------------------

Other current assets (127)
Other assets (203)
Accounts payable (29)
Deferred amounts (75)
Future income taxes (42)
Long-term debt (85)
Long-term debt of joint ventures (7)
Accumulated other comprehensive loss (186)
Foreign exchange adjustment 90
Retained earnings 4


Future Accounting Changes

Section 1535 Capital Disclosures

Effective for interim and annual financial statements for fiscal years beginning on or after October 1, 2007, the new CICA Handbook Section 1535 "Capital Disclosures" requires the disclosure of qualitative and quantitative information about the Company's objectives, policies and processes for managing capital.

Section 3862 Financial Instruments - Disclosures and Section 3863 - Financial Instruments - Presentation

Effective for interim and annual financial statements for fiscal years beginning on or after October 1, 2007, the new CICA Handbook Sections 3862 and 3863 will replace Section 3861 to prescribe the requirements for presentation and disclosure of financial instruments.



3. Segmented Information


Three months ended
September 30
(unaudited - Pipelines Energy Corporate Total
millions of ------------------------------------------------------
dollars) 2007 2006 2007 2006 2007 2006 2007 2006
----------------------------------------------------------------------
Revenues 1,148 1,010 1,062 840 - - 2,210 1,850
Plant operating
costs and other (422) (351) (315) (240) (2) (2) (739) (593)
Commodity
purchases
resold (6) - (470) (382) - - (476) (382)
Depreciation (258) (231) (40) (33) - - (298) (264)
------------------------------------------------------
462 428 237 185 (2) (2) 697 611
Financial
Charges and
non-controlling
interests (205) (197) - - (62) (29) (267) (226)
Financial
charges of
joint ventures (11) (17) (6) (5) - - (17) (22)
Income from
equity
investments 2 4 - - - - 2 4
Interest income
and other 14 25 2 2 27 5 43 32
Gain on sale of
Northern Border
Partners, L.P.
interest - - - - - - - -
Income taxes (99) (113) (77) (59) 42 66 (134) (106)
------------------------------------------------------
Income from
Continuing
Operations 163 130 156 123 5 40 324 293
-----------------------------------------
Income from
Discontinued
Operations - -
-------------
Net Income 324 293
-------------
-------------


Nine months ended
September 30
(unaudited - Pipelines Energy Corporate Total
millions of ---------------------------------------------------------
dollars) 2007 2006 2007 2006 2007 2006 2007 2006
-----------------------------------------------------------------------
Revenues 3,500 2,956 3,171 2,473 - - 6,671 5,429
Plant
operating
costs and
other (1,222) (994) (1,005) (695) (5) (7) (2,232) (1,696)
Commodity
purchases
resold (71) - (1,508) (1,224) - - (1,579) (1,224)
Depreciation (769) (692) (119) (95) - - (888) (787)
---------------------------------------------------------
1,438 1,270 539 459 (5) (7) 1,972 1,722
Financial
charges
and non-
controlling
interests (628) (573) 1 - (189) (98) (816) (671)
Financial
charges
of joint
ventures (40) (50) (17) (17) - - (57) (67)
Income from
equity
investments 13 28 - - - - 13 28
Interest
income
and other 32 59 8 5 71 32 111 96
Gain on sale
of Northern
Border
Partners,
L.P.
interest - 23 - - - - - 23
Income taxes (331) (323) (175) (127) 129 101 (377) (349)
---------------------------------------------------------
Income from
Continuing
Operations 484 434 356 320 6 28 846 782
--------------------------------------------
Income from
Discontinued
Operations - 28
------------
Net Income 846 810
------------
------------

Total Assets September December
(unaudited - millions of dollars) 30, 2007 31, 2006
-----------------------------------------------------------------------
Pipelines 22,101 18,320
Energy 6,761 6,500
Corporate 968 1,089
-------------------------------
29,830 25,909
-------------------------------
-------------------------------


4. Acquisitions and Dispositions

ANR and Great Lakes

In February 2007, TransCanada acquired 100 per cent of American Natural Resources Company and ANR Storage Company (together ANR) and an additional 3.55 per cent interest in Great Lakes from El Paso Corporation for approximately US$3.4 billion, subject to certain post-closing adjustments, including US$491 million of assumed long-term debt. The acquisition was accounted for using the purchase method of accounting. TransCanada began consolidating ANR and Great Lakes in the Pipelines segment subsequent to the acquisition date. The preliminary allocation of the purchase price at September 30, 2007 was as follows.



Purchase Price Allocation
(unaudited)
(millions of US dollars) ANR Great Lakes Total
-------------------------------------------------------------
Current assets 251 4 255
Plant, property and equipment 1,874 35 1,909
Other non-current assets 83 - 83
Goodwill 1,776 35 1,811
Current liabilities (177) (3) (180)
Long-term debt (475) (16) (491)
Other non-current liabilities (447) (22) (469)
---------------------------
2,885 33 2,918
---------------------------
---------------------------


A preliminary allocation of the purchase price has been made using fair values of the net assets at the date of acquisition. As ANR's and Great Lakes' tolls are subject to rate regulation based on historical costs, the regulated net assets, other than gas held for sale, were determined to have a fair value equal to their rate-regulated values.

Goodwill will be evaluated on an annual basis for impairment. Factors that contributed to goodwill included the opportunity to expand in the U.S. market and gaining a stronger competitive position in the North American gas transmission business. The goodwill recognized on this transaction is not amortizable for tax purposes.

PipeLines LP Acquisition of Great Lakes

In February 2007, PipeLines LP acquired a 46.45 per cent interest in Great Lakes from El Paso Corporation for approximately US$942 million, subject to certain post-closing adjustments, including US$209 million of assumed long-term debt. The acquisition was accounted for using the purchase method of accounting. TransCanada began consolidating Great Lakes in the Pipelines segment subsequent to the acquisition date. The preliminary allocation of the purchase price at September 30, 2007 was as follows.



Purchase Price Allocation
(unaudited)
(millions of US dollars)
-----------------------------------
Current assets 42
Plant, property and equipment 465
Other non-current assets 1
Goodwill 457
Current liabilities (23)
Long-term debt (209)
------
733
------
------


A preliminary allocation of the purchase price has been made using fair values of the net assets at the date of acquisition. As Great Lakes' tolls are subject to rate regulation based on historical costs, the regulated net assets were determined to have a fair value equal to their rate-regulated values.

Goodwill will be evaluated on an annual basis for impairment. Factors that contributed to goodwill included the opportunity to expand in the U.S. market and gaining a stronger competitive position in the North American gas transmission business. The goodwill recognized on this transaction is amortizable for tax purposes.

PipeLines LP

In February 2007, PipeLines LP completed a private placement offering of 17,356,086 common units at a price of US$34.57 per unit, of which 50 per cent of the units were acquired by TransCanada for US$300 million. TransCanada also invested an additional US$12 million to maintain its general partnership ownership interest in PipeLines LP. As a result of these additional investments in PipeLines LP, TransCanada's ownership in PipeLines LP increased to 32.1 per cent on February 22, 2007. The total private placement plus TransCanada's additional investment resulted in gross proceeds to PipeLines LP of US$612 million, which were used to partially finance its Great Lakes acquisition.

5. Notes Payable and Long-Term Debt

On October 5, 2007, TransCanada issued US$1.0 billion of senior unsecured notes (Notes). The Notes mature on October 15, 2037 and bear interest at a rate of 6.20 per cent. The effective interest rate at issuance was 6.30 per cent. The Notes were issued under a debt shelf prospectus in the U.S., filed in September 2007, which qualifies for issuance US$2.5 billion of debt securities, and replaced the US$1.5 billion debt shelf prospectus filed in March 2007. Prior to being replaced, the Company had issued US$1.0 billion of debt securities under the March 2007 U.S. debt shelf prospectus.

In April 2007, TransCanada issued US$1.0 billion of Junior Subordinated Notes (Junior Notes) maturing in 2067 and bearing interest of 6.35 per cent per year until May 15, 2017 at which time the interest on the Junior Notes will convert to a floating rate, reset quarterly to the three-month London Interbank Offered Rate (LIBOR) plus 221 basis points. The Junior Notes remained outstanding at September 30, 2007 and had an effective interest rate of 6.51 per cent. TransCanada has the option to defer payment of interest for one or more periods of up to ten years without giving rise to an event of default and without permitting acceleration of payment under the terms of the Junior Notes. If this were to occur, the Company would be prohibited from paying dividends during the deferral period. The Junior Notes are subordinated in right of payment to existing and future senior indebtedness and are effectively subordinated to all indebtedness and obligations of TCPL. The Junior Notes are callable at TransCanada's option at any time on or after May 15, 2017 at 100 per cent of the principal amount of the Junior Notes plus accrued and unpaid interest to the date of redemption. Upon the occurrence of certain events, the Junior Notes are callable earlier at TransCanada's option, in whole or in part, at an amount equal to the greater of 100 per cent of the principal amount of the Junior Notes plus accrued and unpaid interest to the date of redemption or at an amount determined by formula in accordance with the terms of the Junior Notes.

In April 2007, Northern Border established a US$250 million five-year bank facility. A portion of the bank facility was drawn to refinance US$150 million of senior notes that matured on May 1, 2007, with the balance available to fund Northern Border's ongoing operations.

In March 2007, the Company filed debt shelf prospectuses in Canada and the U.S. qualifying for issuance $1.5 billion of medium-term notes and US$1.5 billion of debt securities, respectively. At September 30, 2007, the Company had issued no medium-term notes under the Canadian prospectus and had replaced the March 2007 U.S. debt shelf prospectus with a new US$2.5 billion U.S. debt shelf prospectus, as described above.

In March 2007, ANR Pipeline Company voluntarily withdrew from the New York Stock Exchange the listing of its 9.625 per cent Debentures due 2021, 7.375 per cent Debentures due 2024, and 7.0 per cent Debentures due 2025. With the delisting, which became effective April 12, 2007, ANR Pipeline Company deregistered these securities from registration with the U.S. Securities Exchange Commission.

In February 2007, the Company executed an agreement for a US$2.2-billion, committed, unsecured, one-year bridge loan facility with a floating interest rate based on the one-month LIBOR plus 25 basis points. The Company utilized $1.5 billion and US$700 million from this facility to partially finance the ANR and Great Lakes acquisition. At September 30, 2007, the Company had an outstanding balance of US$400 million on this facility. The undrawn balance of this facility has been cancelled and is no longer available to the Company.

In February 2007, the Company established a US$1.0-billion committed, unsecured credit facility, consisting of a US$700-million five-year term loan and a US$300-million five-year, extendible revolving facility. A floating interest rate based on the three-month LIBOR plus 22.5 basis points is charged on the balance outstanding and a facility fee of 7.5 basis points is charged on the entire facility. The Company utilized US$1.0 billion from this facility and an additional US$100 million from an existing demand line to partially finance the ANR acquisition as well as its additional investment in PipeLines LP. At September 30, 2007, the Company had an outstanding balance of US$700 million on the credit facility and had repaid the demand line.

In February 2007, PipeLines LP increased the size of its syndicated revolving credit and term loan facility in connection with its Great Lakes acquisition. The amount available under the facility increased from US$410 million to US$950 million, consisting of a US$700-million senior term loan and a US$250-million senior revolving credit facility, with US$194 million of the senior term loan amount available being terminated upon closing of the Great Lakes acquisition. At September 30, 2007, US$517 million was outstanding under this facility. A floating interest rate based on the three-month LIBOR plus 55 basis points is charged on the senior term loan and a floating interest rate based on the one-month LIBOR plus 35 basis points is charged on the senior revolving credit facility. A facility fee of 10 basis points is charged on the US$250 million senior revolving credit facility. The weighted average interest rate at September 30, 2007 was 6.16 per cent.

6. Preferred Securities

In July 2007, TransCanada redeemed, at par, all of the outstanding US$460 million 8.25 per cent Preferred Securities due 2047. The redemption occurred as a result of a five-year tolls settlement reached on the Canadian Mainline and crystallized a foreign exchange gain that will flow through to the Canadian Mainline's customers.

7. Share Capital

In the nine months ended September 30, 2007, TransCanada issued 2.7 million common shares under its Dividend Reinvestment and Share Purchase Plan (DRP). In accordance with the DRP, dividends were paid with common shares issued from treasury instead of cash dividend payments totalling $104 million.

In January 2007, TransCanada filed a short form shelf prospectus with securities regulators in Canada and the U.S. to allow for the offering of up to $3.0 billion of common shares, preferred shares and/or subscription receipts in Canada and the U.S. until February 2009. As at September 30, 2007, the Company had issued 45,390,500 common shares at a price of $38.00 each, resulting in gross proceeds of approximately $1.725 billion under this shelf prospectus, which were used towards financing the acquisition of ANR and Great Lakes.

8. Financial Instruments and Risk Management

The fair values of non-derivative financial instruments at September 30, 2007 are as follows.



Non-Derivative Financial Instruments Summary(1)(2)
(unaudited)
(millions of dollars) September 30, 2007
--------------------------------------------------
Fair
Value
---------

Financial Assets (3)
Cash and cash equivalents(4) 255
Loans and receivables (4) 1,172
Available-for-sale assets 16
---------
1,443
---------
---------

Financial Liabilities(5)(6)
Notes payable 1,021
Trade and other payables 1,324
Long-term debt 13,970
Other long-term liabilities 65
---------
16,380
---------
---------
--------------------------------------------------

(1)Net Income for the three months and nine months ended September 30,
2007 included an unrealized gain or loss of nil for the fair value
adjustments to these financial instruments.
(2)Carrying value is not materially different from fair value, except for
available-for-sale financial assets, which have a carrying value equal
to fair value.
(3)At September 30, 2007, Current Assets on the Consolidated Balance Sheet
included financial assets of $960 million in Accounts Receivable and
$255 million in Cash and Cash Equivalents. The remainder of these
financial assets were included in Other Assets.
(4)Recorded at cost.
(5)Recorded at amortized cost.
(6)At September 30, 2007, Current Liabilities on the Consolidated Balance
Sheet included financial liabilities of $1,313 million in Accounts
Payable and $1,021 million in Notes Payable. Financial liabilities of
$76 million were included in Deferred Amounts and $13,970 million were
included in Long-Term Debt.


The fair values of the Company's derivative financial instruments are as
follows.

Derivative Financial Instruments Summary (1)
(unaudited)
(millions of dollars) September 30, 2007
---------------------------------------------------------------------------
Fair
Value
------------------
Derivative financial instruments held for trading
Power derivatives-assets (2) 51
Power derivatives-liabilities(2) (44)
Natural gas derivatives-assets(3) 69
Natural gas derivatives-liabilities(3) (29)
Interest rate derivatives-assets (4) 20
Interest rate derivatives-liabilities (4) (7)
Foreign exchange derivatives-assets (4) 4
Foreign exchange derivatives-liabilities(4) (83)
------------------
(19)
------------------
Derivative financial instruments in hedging
relationships (5)
Power derivatives-assets (6) 129
Power derivatives-liabilities(6) (183)
Natural gas derivatives-assets(6) 28
Natural gas derivatives-liabilities(6) (9)
Interest rate derivatives-assets (7) -
Interest rate derivatives-liabilities (7) (4)
Foreign exchange derivatives-assets (7) -
Foreign exchange derivatives-liabilities(7) (69)
------------------
(108)
------------------
Total Derivative Financial Instruments (127)
------------------
------------------
---------------------------------------------------------------------------

(1)Fair value is equal to the carrying value of these derivatives except
for derivatives used in the Company's regulatory operations, which are
carried at their regulatory values.
(2)Net Income for the three and nine months ended September 30, 2007
included unrealized gains of $4 million and $12 million, respectively,
for the change in the fair value of held-for-trading power
derivatives. Net Income for the three and nine months ended
September 30, 2007 included realized gains of $2 million and $10
million, respectively, for held-for-trading power derivatives.
(3)Net Income for the three and nine months ended September 30, 2007
included unrealized gains of nil and $7 million, respectively, for the
change in the fair value of held-for-trading natural gas derivatives.
Net Income for the three and nine months ended September 30, 2007
included realized losses of $23 million and $39 million, respectively,
for held-for-trading natural gas derivatives.
(4)Net Income for the three and nine months ended September 30, 2007
included unrealized gains of $1 million and $2 million, respectively,
for the change in the fair value of held-for-trading interest-rate and
foreign exchange derivatives. Net Income for the three and nine months
ended September 30, 2007 included realized gains of $15 million and
$39 million, respectively, for held-for-trading interest-rate and
foreign exchange derivatives.
(5)All hedging relationships are designated cash flow hedges except for
$1 million of interest-rate derivative financial instruments
designated as fair value hedges.
(6)Net Income for the three and nine months ended September 30, 2007
included gains of $4 million and $6 million, respectively, for the
changes in fair value of power and natural gas cash flow hedges that
were ineffective in offsetting the change in fair value of their
related underlyings. Net Income for the three and nine months ended
September 30, 2007 included realized gains of $50 million and
$45 million, respectively, for power cash flow hedges. Net Income for
the three and nine months ended September 30, 2007 included realized
losses of $10 million and $7 million, respectively, for natural
gas cash flow hedges.
(7)Net Income for the three and nine months ended September 30, 2007
included nil and a $4 million loss, respectively, for the change in
fair value of interest-rate and foreign exchange cash flow hedges and
fair value hedges that were ineffective in offsetting the change in
fair value of their related underlyings. Net Income for the three and
nine months ended September 30, 2007 included realized gains of
$1 million and $2 million, respectively, for interest-rate and foreign
exchange cash flow hedges.


Unrealized Gains and Losses

At September 30, 2007, there were unrealized gains from unsettled derivative financial instruments of $172 million (December 31, 2006 - $41 million) included in Other Current Assets and $129 million (December 31, 2006 - $39 million) included in Other Assets. At September 30, 2007, there were unrealized losses from unsettled derivative financial instruments of $189 million (December 31, 2006 - $144 million) included in Accounts Payable and $239 million (December 31, 2006 - $158 million) included in Deferred Amounts.

At September 30, 2007, there were unrealized losses from the fair value adjustments of proprietary natural gas storage inventory of $25 million (December 31, 2006 - nil) included in Inventories.

Energy Price, Interest Rate and Foreign Exchange Rate Risk Management

The Company enters into various contracts to mitigate its exposure to fluctuations in commodity prices, interest rates and foreign exchange rates. The contracts generally consist of the following.

- Forwards and futures contracts - contractual agreements to buy or sell a specific financial instrument or commodity at a specified price and date in the future. The Company enters into foreign exchange and commodity forwards and futures to mitigate volatility in foreign exchange rates and power and gas prices, respectively.

- Swaps - contractual agreements between two parties to exchange streams of payments over time according to specified terms. The Company enters into interest rate, cross-currency and commodity swaps to mitigate changes in interest rates, foreign exchange rates and commodity prices, respectively.

- Options - contractual agreements to convey the right, but not the obligation, for the purchaser either to buy or sell a specific amount of a financial instrument or commodity at a fixed price, either at a fixed date or at any time within a specified period. The Company enters into option agreements to mitigate changes in interest rates, foreign exchange rates and commodity prices.

- Heat rate contracts - contracts for the sale or purchase of power that are priced based on a natural gas index.

Energy Price Risk

The Company is exposed to energy price movements as part of its normal business operations, particularly in relation to the prices of electricity and natural gas. The primary risk is that market prices for commodities will move adversely between the time that purchase and/or sales prices are fixed, potentially reducing expected margins.

To manage exposure to price risk, subject to the Company's overall risk management policies and procedures, the Company commits a significant portion of its supply to medium- to long-term sales contracts while reserving an amount of unsold supply to maintain flexibility in the overall management of its asset portfolio. The types of instruments used include forwards and futures contracts, swaps, options, and heat rate contracts.

TransCanada manages its exposure to seasonal gas price spreads in its natural gas storage business by hedging storage capacity with a portfolio of third party storage capacity leases and back-to-back proprietary natural gas purchases and sales. By matching purchase and sale volumes, TransCanada locks in a margin and effectively eliminates its exposure to the price movements of natural gas.

The Company continually assesses its power contracts and derivative instruments used to manage energy price risk. Contracts, with the exception of leases, have been assessed to determine whether they meet the definition of a derivative. Certain commodity purchase and sale contracts are derivatives but are not within the scope of Section 3855, as they were entered into and continue to be held for the purpose of receipt or delivery in accordance with the Company's expected purchase, sale or usage requirements (normal purchases and sales exception). As well, certain contracts are not within the scope of Section 3855 as they are considered to be executory contracts or meet other exemption criteria.

Natural Gas Inventory Price Risk

Effective April 1, 2007, TransCanada began valuing its proprietary natural gas storage inventory at fair value, as measured by the one-month forward price for natural gas. In order to record inventory at fair value, TransCanada has designated its natural gas storage business as a broker/trader business that purchases and sells natural gas on a back-to-back basis. The Company did not have any proprietary natural gas inventory prior to April 1, 2007.

The Company records its proprietary natural gas storage results in Revenues net of Commodity Purchases Resold. All changes in the fair value of the proprietary natural gas storage inventory are recorded in Inventories and Revenues. At September 30, 2007, $81 million of proprietary natural gas storage inventory was included in Inventories, which included $25 million related to changes in fair value of the proprietary natural gas storage inventory. Revenues included unrealized pre-tax losses related to the change in fair value of the proprietary natural gas storage inventory for the three and nine months ended September 30, 2007 of $2 million and $25 million, respectively. These losses were essentially offset by the change in fair value of the forward proprietary natural gas purchase and sale contracts.

TransCanada manages its exposure to seasonal gas price spreads in its natural gas storage business by hedging storage capacity with a portfolio of third party storage capacity leases and proprietary natural gas purchases and sales. By matching purchase and sale volumes, TransCanada locks in a margin and effectively eliminates its exposure to the price movements of natural gas.

Interest Rate Risk

The Company has fixed interest rate long-term debt, which subjects the Company to interest rate price risk, and has floating interest rate long-term debt, which subjects the Company to interest rate cash flow risk. To manage its exposure to these risks, the Company uses a combination of interest-rate swaps, forwards and options.

Investments in Foreign Operations

The Company hedges its net investment in self-sustaining foreign operations with U.S. dollar-denominated debt, cross-currency swaps, forward exchange contracts and options. At September 30, 2007, the Company had designated U.S. dollar-denominated debt with a carrying value of $3.8 billion (US$3.8 billion) and a fair value of $3.9 billion (US$3.9 billion) as a portion of this hedge and swaps, forwards and options with a fair value of $81 million (US$81 million) as net investment hedges.



Derivatives Hedging Net Investment in Foreign Operations
Asset/(Liability)
(millions of dollars) September 30, 2007 December 31, 2006
---------------------------------------------------------------------------
Notional or Notional or
Fair Principal Fair Principal
Value(1) Amount Value(1) Amount
----------------------------------------------
Derivative financial
Instruments in
hedging relationships
U.S. dollar cross-currency
swaps
(maturing 2009 to 2014) 74 U.S. 350 58 U.S. 400
U.S. dollar forward foreign
exchange contracts
(maturing 2007 ) 3 U.S. 100 (7) U.S. 390
U.S. dollar options
(maturing 2007 ) 4 U.S. 100 (6) U.S. 500
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81 U.S. 550 45 U.S. 1,290
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(1)Fair values are equal to carrying values.


Fair Values

Fair values of financial instruments are determined by reference to quoted bid or asking price, as appropriate, in active markets. In the absence of an active market, the Company determines fair value by using valuation techniques that refer to observable market data or estimated market prices. These include comparisons with similar instruments where market observable prices exist, option pricing models and other valuation techniques commonly used by market participants. Fair values determined using valuation models require the use of assumptions concerning the amount and timing of estimated future cash flows and discount rates. In determining those assumptions, the Company looks primarily to external readily observable market input factors such as interest rate yield curves, currency rates, and price and rate volatilities as applicable.

9. Income Taxes

The Company is currently evaluating the impact of Mexico's Corporate Flat Rate Tax legislation, which passed into law on October 1, 2007. The Company anticipates that the legislation will not have a material impact on its financial statements.

In third quarter 2007, TransCanada recorded income tax benefits of approximately $15 million as a result of favourable income tax reassessments and associated interest income for prior years.

In second quarter 2007, TransCanada recorded income tax benefits of approximately $16 million as a result of changes in Canadian federal income tax legislation.

In first quarter 2007, TransCanada recorded income tax benefits of approximately $10 million from the resolution of certain income tax matters, as well as a $5 million income tax benefit from an internal restructuring.

10. Commitments

TransCanada has entered into contracts to purchase pipe and supplies for construction of the Keystone oil pipeline and other pipeline projects totalling approximately $2.3 billion.

11. Employee Future Benefits

The net benefit plan expense for the Company's defined benefit pension plans and other post-employment benefit plans for the three and nine months ended September 30, 2007 is as follows.



Three months ended September 30
(unaudited - millions of dollars) Pension Other Benefit
Benefit Plans Plans
-----------------------------------------
2007 2006 2007 2006
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Current service cost 11 10 - 1
Interest cost 19 16 2 2
Expected return on plan assets (23) (18) - (1)
Amortization of transitional
obligation related
to regulated business - - - 1
Amortization of net
actuarial loss 7 6 1 1
Amortization of past service costs 1 1 - -
-----------------------------------------
Net benefit cost recognized 15 15 3 4
-----------------------------------------
-----------------------------------------


Nine months ended September 30 Pension Other Benefit
(unaudited - millions of dollars) Benefit Plans Plans
------------------------------------------
2007 2006 2007 2006
----------------------------------------------------------------------------
Current service cost 33 28 1 2
Interest cost 54 49 5 6
Expected return on plan assets (62) (53) (1) (2)
Amortization of transitional
obligation
related to
regulated business - - 1 2
Amortization of net
actuarial loss 19 20 2 2
Amortization of past
service costs 3 3 (1) 1
------------------------------------------
Net benefit cost recognized 47 47 7 11
------------------------------------------
------------------------------------------


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TransCanada welcomes questions from shareholders and potential investors.
Please telephone:

Investor Relations, at 1-800-361-6522 (Canada and U.S. Mainland) or direct
dial David Moneta/Myles Dougan/Terry Hook at (403) 920-7911. The investor
fax line is (403) 920-2457. Media Relations: Shela Shapiro at
(403) 920-7859.

Visit TransCanada's Internet site at: www.transcanada.com
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Contact Information

  • TransCanada
    Media Inquiries
    Shela Shapiro/Cecily Dobson
    (403) 920-7859 or 1-800-608-7859
    or
    Analyst Inquiries:
    David Moneta/Myles Dougan/Terry Hook
    (403) 920-7911 or 1-800-361-6522
    Website: www.transcanada.com