Exhibit 13.1

TRANSCANADA CORPORATION – THIRD QUARTER 2008

QuarterlyReport to Shareholders

Management's Discussion and Analysis

Management's Discussion and Analysis (MD&A) dated October 27, 2008 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, 2008.  It should also be read in conjunction with the audited Consolidated Financial Statements and notes thereto, and the MD&A contained in TransCanada's 2007 Annual Report for the year ended December 31, 2007. 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 2007 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", "believe", "may", "should", "estimate", "project", "outlook", "forecast" or other similar words are used to identify such forward-looking information. All forward-looking statements reflect TransCanada’s beliefs and assumptions based on information available at the time the statements were made. Actual results or events may differ from those predicted in these forward-looking statements. Factors that could cause actual results or events to differ materially from current expectations include, among other things, the ability of TransCanada to successfully implement its strategic initiatives and whether such strategic initiatives will yield the expected benefits, the operating performance of the Company’s pipeline and energy assets, the availability and price of energy commodities, regulatory processes and decisions, changes in environmental and other laws and regulations, competitive factors in the pipeline and energy industry sectors, construction and completion of capital projects, labour, equipment and material costs, access to capital markets, interest and currency exchange rates, technological developments and the current economic conditions in North America. By its nature, 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 expectations expressed. Additional information on these and other factors is available in the reports filed by TransCanada with Canadian securities regulators and with the U.S. Securities and Exchange Commission (SEC). Readers are cautioned to not place undue reliance on this forward-looking information, which is given as of the date it is expressed in this MD&A or otherwise, and to not use future-oriented information or financial outlooks for anything other than their intended purpose. 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.

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THIRD QUARTER REPORT 2008

Non-GAAP Measures

TransCanada 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 Canadian generally accepted accounting principles (GAAP). They are, therefore, considered to be non-GAAP measures and are unlikely to be comparable to similar measures presented by other entities. Management of TransCanada uses non-GAAP measures to improve its ability to compare financial results among reporting periods and to enhance its understanding of operating performance, liquidity and ability to generate funds to finance operations. Non-GAAP measures are also provided to readers as additional information on TransCanada’s operating performance, liquidity and ability to generate funds to finance operations.

Management uses the measure of comparable earnings/(expenses) to better evaluate trends in the Company’s underlying operations. Comparable earnings comprise net income adjusted for specific items that are significant, but are not reflective of the Company’s underlying operations. Specific items are subjective, however, management uses its judgement and informed decision-making when identifying items to be excluded in calculating comparable earnings, some of which may recur. Specific items may include but are not limited to certain income tax refunds and adjustments, gains or losses on sales of assets, legal and bankruptcy settlements, and fair value adjustments. The table in the Consolidated Results of Operations section of this MD&A presents a reconciliation of comparable earnings to net income. 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 comprises 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 of this MD&A.

Operating income is reported in the Company’s Energy business segment and comprises revenues less operating expenses as shown on the Consolidated Income Statement. A reconciliation of operating income to net income is presented in the Energy section of this MD&A.

Acquisitions

Ravenswood

On August 26, 2008, TransCanada acquired from National Grid plc (National Grid) all of the outstanding equity of KeySpan-Ravenswood, LLC and KeySpan Ravenswood Services Corp., for US$2.9 billion, subject to certain post-closing adjustments. The two companies together own, control and operate the Ravenswood Generating Station (Ravenswood), a 2,480-megawatt (MW) steam turbine, combined-cycle power generating plant located in Queens, New York. The acquisition was financed with a combination of proceeds from the Company’s recent equity and debt offerings, cash on hand and funds drawn on newly established loan facilities.

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THIRD QUARTER REPORT 2008

Consolidated Results of Operations

Reconciliation of Comparable Earnings to Net Income
(unaudited)			Three months ended September 30						Nine months ended September 30
(millions of dollars except per share amounts)			2008			2007			2008			2007
Pipelines
		Comparable earnings		173			163			530			484
		Specific items (net of tax):
		Calpine bankruptcy settlements		-			-			152			-
		GTN lawsuit settlement		-			-			10			-
		Net income		173			163			692			484
Energy
		Comparable earnings		202			156			494			352
		Specific items (net of tax, where applicable):
		Fair value adjustments of natural gas storage inventory
		and forward contracts		(2	)		-			(6	)		-
		Writedown of Broadwater LNG project costs		-			-			(27	)		-
		Income tax adjustments		-			-			-			4
		Net income		200			156			461			356
Corporate
		Comparable expenses		(9	)		(10	)		(16	)		(36	)
		Specific item:
		Income tax reassessments and adjustments		26			15			26			42
		Net income		17			5			10			6
Net Income (1)				390			324			1,163			846
Net Income Per Share (2)
Basic and Diluted			$	0.67		$	0.60		$	2.07		$	1.60
	(1)	Comparable Earnings		366			309			1,008			800
		Specific items (net of tax, where applicable):
		Calpine bankruptcy settlements		-			-			152			-
		GTN lawsuit settlement		-			-			10			-
		Fair value adjustments of natural gas storage inventory
		and forward contracts		(2	)		-			(6	)		-
		Writedown of Broadwater LNG project costs		-			-			(27	)		-
		Income tax reassessments and adjustments		26			15			26			46
		Net Income		390			324			1,163			846
	(2)	Comparable Earnings Per Share	$	0.63		$	0.57		$	1.80		$	1.51
		Specific items - per share
		Calpine bankruptcy settlements		-			-			0.27			-
		GTN lawsuit settlement		-			-			0.02			-
		Fair value adjustments of natural gas storage inventory
		and forward contracts		-			-			(0.01	)		-
		Writedown of Broadwater LNG project costs		-			-			(0.05	)		-
		Income tax reassessments and adjustments		0.04			0.03			0.04			0.09
		Net Income Per Share	$	0.67		$	0.60		$	2.07		$	1.60

TransCanada’s net income in third-quarter 2008 was $390 million or $0.67 per share compared to $324 million or $0.60 per share in third-quarter 2007. The $66-million increase in net income was due to increased third-quarter 2008 earnings from all segments. Earnings from the Energy business were higher in third-quarter 2008 compared to third-quarter 2007 primarily due to increased earnings from Eastern Power and Bruce Power operations. Eastern Power operations generated higher earnings in third quarter 2008 compared to third quarter 2007 due to higher realized power prices in New England, increased water flows from the TC Hydro generation assets and incremental income from the August 26, 2008 acquisition of Ravenswood. Bruce Power operations generated higher earnings in third quarter 2008 compared to third quarter 2007 due to higher prices and increased output. Corporate’s earnings were higher in third-quarter 2008 compared to third-quarter 2007 primarily due to the inclusion of $26 million in third-quarter 2008 relating to favourable income tax adjustments from an internal restructuring and realization of losses compared to the inclusion of $15 million in third-quarter 2007 of favourable income tax reassessments and associated interest income related to prior years. Pipelines’ earnings were higher in third-quarter 2008 compared to third-quarter 2007 primarily due to increased earnings from ANR and GTN.

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THIRD QUARTER REPORT 2008

Comparable earnings for third-quarter 2008 were $366 million or $0.63 per share compared to $309 million or $0.57 per share for the same period in 2007. Comparable earnings in third-quarter 2008 excluded the $26 million of favourable income tax adjustments and $2 million of net unrealized losses resulting from changes in fair value of proprietary natural gas storage inventory and natural gas forward purchase and sale contracts. Comparable earnings in third-quarter 2007 excluded the $15 million of favourable income tax reassessments and associated interest income.

Net income was $1.2 billion or $2.07 per share for the first nine months in 2008 compared to $846 million or $1.60 per share for the same period in 2007. The $317-million or $0.47 per share increase in net income for the first nine months of 2008 compared to the same period in 2007 was due to increased earnings from all segments. Earnings in Pipelines were higher for the first nine months of 2008 compared to the first nine months of 2007 primarily due to $152 million after-tax ($240 million pre-tax) of gains on shares received by GTN and Portland for bankruptcy settlements from certain subsidiaries of Calpine Corporation (Calpine) and proceeds from a GTN lawsuit settlement of $10 million after tax ($17 million pre-tax). Pipelines’ earnings also increased due to a full nine months of earnings from ANR in 2008 and due to the positive impact of a rate case settlement for GTN approved in January 2008. Earnings in Energy were higher for the first nine months of 2008 compared to the same period in 2007 as earnings from Eastern Power, Western Power and Bruce Power operations increased primarily due to higher realized prices, partially offset by a $27 million after-tax ($41 million pre-tax) writedown of costs previously capitalized for the Broadwater liquefied natural gas (LNG) project. Corporate net income increased in the first nine months of 2008 primarily due to lower financial charges. Corporate net income included the favourable income tax adjustments of $26 million in the first nine months of 2008. Net income in the first nine months of 2007 included $46 million of favourable income tax adjustments, which included the $15 million discussed above and $31 million ($27 million in Corporate and $4 million in Energy) recorded in 2007 relating to changes in Canadian federal and provincial corporate income tax legislation, the resolution of certain income tax matters and an internal restructuring.

Comparable earnings for the first nine months of 2008 were $1.0 billion or $1.80 per share compared to $800 million or $1.51 per share for the same period in 2007. Comparable earnings for the first nine months of 2008 excluded the $152 million of gains from the Calpine bankruptcy settlements, $10-million GTN lawsuit settlement proceeds, $27-million writedown of the Broadwater LNG project costs, $6-million net unrealized losses from natural gas storage fair value adjustments and $26-million favourable income tax adjustments. Comparable earnings for the first nine months of 2007 excluded the favourable income tax adjustments of $46 million.

Results from each of the segments for the three and nine months ended September 30, 2008 are discussed further in the Pipelines, Energy and Corporate sections of this MD&A.

Funds generated from operations of $711 million and $2.3 billion for the three and nine months ended September 30, 2008, respectively, increased $9 million (or one per cent) and $429 million (or 23 per cent), respectively, compared to the same periods in 2007. For a further discussion on funds generated from operations, refer to the Liquidity and Capital Resources section in this MD&A.

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THIRD QUARTER REPORT 2008

Pipelines

The Pipelines business generated net income and comparable earnings of $173 million in third-quarter 2008, an increase of $10 million compared to net income and comparable earnings of $163 million in third-quarter 2007.

Net income and comparable earnings for the nine months ended September 30, 2008 were $692 million and $530 million, respectively, compared to net income and comparable earnings of $484 million for the nine months ended September 30, 2007. Comparable earnings for the first nine months of 2008 excluded the after-tax gains of $152 million on the Calpine shares received by GTN and Portland for the Calpine bankruptcy settlements, and proceeds received by GTN as a result of the $10 million after-tax lawsuit settlement with a software supplier.

Pipelines Results
(unaudited)	Three months ended September 30						Nine months ended September 30
(millions of dollars)	2008			2007			2008			2007
Wholly Owned Pipelines
Canadian Mainline		66			69			204			201
Alberta System		32			32			97			97
ANR (1)		24			19			94			69
GTN		15			10			49			26
Foothills		6			6			19			20
		143			136			463			413
Other Pipelines
Great Lakes (2)		9			11			32			36
PipeLines LP (3)		3			8			15			14
Iroquois		5			3			13			11
Tamazunchale		5			2			9			7
Other (4)		8			8			29			33
Northern Development		(2	)		(1	)		(3	)		(3	)
General, administrative, support costs and other		2			(4	)		(28	)		(27	)
		30			27			67			71
Comparable Earnings		173			163			530			484
Specific items (net of tax):
Calpine bankruptcy settlements (5)		-			-			152			-
GTN lawsuit settlement		-			-			10			-
Net Income		173			163			692			484
(1) ANR's results include earnings from the date of acquisition of February 22, 2007.
(2) Great Lakes' results reflect TransCanada's 53.6 per cent ownership in Great Lakes since February 22, 2007 and 50 per cent ownership prior to that date.
(3) PipeLines LP's results include TransCanada's effective ownership of an additional 14.9 per cent interest in Great Lakes since February 22, 2007 as a result of PipeLines LP's acquisition of a 46.4 per cent interest in Great Lakes and TransCanada's 32.1 per cent interest in PipeLines LP.
(4) Other includes results of Portland, Ventures LP, TQM, TransGas and Gas Pacifico/INNERGY.
(5) GTN and Portland received shares of Calpine with an initial after-tax value of $95 million and $38 million (TransCanada's share), respectively, from the bankruptcy settlements with Calpine. These shares were subsequently sold for an additional after-tax gain of $19 million.

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THIRD QUARTER REPORT 2008

Wholly Owned Pipelines

Canadian Mainline's third-quarter 2008 net income of $66 million decreased $3 million compared to $69 million in third-quarter 2007 primarily as a result of lower performance-based incentives earned and lower operations, maintenance and administrative (OM&A) cost savings.

Canadian Mainline’s net income for the nine months ended September 30, 2008 increased $3 million to $204 million primarily as a result of a higher rate of return on common equity (ROE), as determined by the NEB, of 8.71 per cent in 2008 compared to 8.46 per cent in 2007, partially offset by a lower average investment base.

The Alberta System’s net earnings in third-quarter and the first nine months of 2008 and 2007 were $32 million and $97 million, respectively. Earnings in both periods of 2008 were unchanged from 2007. Earnings in 2008 reflect an ROE of 8.75 per cent compared to 8.51 per cent in 2007, both on a deemed common equity of 35 per cent.

ANR’s net income in third-quarter 2008 was $24 million compared to $19 million in third-quarter 2007. Net income for the first nine months of 2008 was $94 million compared to $69 million for the period from February 22, 2007 to September 30, 2007. The increase in third-quarter 2008 was primarily due to higher revenues from new growth projects, partially offset by higher OM&A costs. The increase for the first nine months of 2008 was primarily due to a full nine months of earnings in 2008 and higher revenues from new growth projects, partially offset by higher OM&A costs and the negative impact on earnings of a stronger Canadian dollar.

GTN’s comparable earnings for the three and nine months ended September 30, 2008 increased $5 million and $23 million, respectively, compared to the same periods in 2007. The increases were primarily due to the positive impact of a rate case settlement approved by the U.S. Federal Energy Regulatory Commission (FERC) in January 2008 and lower OM&A expenses. For the nine months ended September 30, 2008, these increases were partially offset by the negative impact on earnings of a stronger Canadian dollar.

Operating Statistics
	Canadian		Alberta				GTN
Nine months ended September 30	Mainline(1)		System(2)		ANR(3)(4)		System(3)		Foothills
(unaudited)	2008	2007	2008	2007	2008	2007	2008	2007	2008	2007
Average investment base
($ millions)	7,065	7,323	4,322	4,236	n/a	n/a	n/a	n/a	755	824
Delivery volumes (Bcf)
Total	2,595	2,359	2,833	2,993	1,243	829	595	600	955	1,058
Average per day	9.5	8.6	10.3	11.0	4.5	3.8	2.2	2.2	3.5	3.9

(1) Canadian Mainline's physical receipts originating at the Alberta border and in Saskatchewan for the nine months ended September 30, 2008 were 1,460 billion cubic feet (Bcf) (2007 - 1,601 Bcf); average per day was 5.3 Bcf

     (2007 - 5.9  Bcf).

(2) Field receipt volumes for the Alberta System for the nine months ended September 30, 2008 were 2,908 Bcf (2007 - 3,064 Bcf); average per day was 10.6 Bcf (2007 - 11.2 Bcf).

(3) ANR's and the GTN System's results are not impacted by current average investment base as these systems operate under a fixed rate model approved by the FERC.

(4) ANR's results include delivery volumes from the date of acquistion of February 22, 2007.

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THIRD QUARTER REPORT 2008

Other Pipelines

TransCanada’s proportionate share of net income from Other Pipelines was $30 million for the three months ended September 30, 2008 compared to $27 million for the same period in 2007.  The increase was primarily due to lower general, administrative and other costs and higher earnings from Iroquois and Tamazunchale, partially offset by decreased earnings from PipeLines LP and Great Lakes. General, administrative and other costs decreased due to the capitalization of project development costs related to the expansion of the Keystone Pipeline system.  PipeLines LP's earnings decreased primarily due to a positive adjustment recorded in third-quarter 2007 related to TransCanada’s increased ownership.

Earnings for the nine months ended September 30, 2008 were $67 million compared to $71 million in the corresponding period of 2007. The decrease is primarily due to the effect of a stronger Canadian dollar on U.S. dollar-denominated earnings, partially offset by increased earnings from Iroquois, PipeLines LP and Tamazunchale.

As at September 30, 2008, TransCanada had advanced $140 million to the Aboriginal Pipeline Group (APG) with respect to the Mackenzie Gas Pipeline Project (MGP). TransCanada and the other co-venture companies involved in the MGP continue to pursue approval of the proposed project, focusing on obtaining regulatory approval and the Canadian government’s support of an acceptable fiscal framework. Detailed discussions with the Federal government have taken place and are continuing, and project timing continues to be uncertain. In the event the co-venture group is unable to reach an agreement with the government on an acceptable fiscal framework, the parties will need to determine the appropriate next steps for the project, including, with respect to TransCanada, a review of the value attributable to the APG advances.

Energy

Energy’s net income of $200 million in third-quarter 2008 increased $44 million compared to $156 million in third-quarter 2007. Comparable earnings in third-quarter 2008 of $202 million increased $46 million compared to the same period in 2007 and excluded net unrealized losses of $2 million resulting from changes in fair value of proprietary natural gas storage inventory and natural gas forward purchase and sale contracts.

Energy’s net income for the nine months ended September 30, 2008 of $461 million increased $105 million compared to $356 million for the same period in 2007. For the first nine months of 2008, comparable earnings of $494 million increased $142 million compared to the same period in 2007 and excluded a $27 million after-tax ($41 million pre-tax) writedown of costs previously capitalized for the Broadwater LNG project and net unrealized losses of $6 million after tax ($8 million pre-tax) resulting from natural gas storage fair value changes. Comparable earnings of $352 million for the first nine months of 2007 excluded $4 million of favourable income tax adjustments.

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THIRD QUARTER REPORT 2008

Energy Results
(unaudited)	Three months ended September 30						Nine months ended September 30
(millions of dollars)	2008			2007			2008			2007
Western Power		126			120			320			250
Eastern Power (1)		100			52			265			189
Bruce Power		83			64			151			124
Natural Gas Storage		29			39			95			89
General, administrative, support costs and other		(41	)		(38	)		(117	)		(113	)
Operating income		297			237			714			539
Financial charges		(5	)		(6	)		(16	)		(16	)
Interest income and other		(1	)		2			3			8
Writedown of Broadwater LNG project costs		-			-			(41	)		-
Income taxes		(91	)		(77	)		(199	)		(175	)
Net Income		200			156			461			356
Comparable Earnings		202			156			494			352
Specific items (net of tax, where applicable):
Fair value adjustments of natural gas storage
inventory and forward contracts		(2	)		-			(6	)		-
Writedown of Broadwater LNG project costs		-			-			(27	)		-
Income tax adjustments		-			-			-			4
Net Income		200			156			461			356
(1) Eastern Power results include earnings from Ravenswood from the date of acquisition of August 26, 2008.

Western Power

Western Power Results
(unaudited)	Three months ended September 30						Nine months ended September 30
(millions of dollars)	2008			2007			2008			2007
Revenues
Power		264			302			842			800
Other (1)		56			22			108			71
		320			324			950			871
Commodity purchases resold
Power		(129	)		(149	)		(423	)		(454	)
Other (2)		(13	)		(18	)		(47	)		(53	)
		(142	)		(167	)		(470	)		(507	)
Plant operating costs and other		(47	)		(32	)		(141	)		(100	)
Depreciation		(5	)		(5	)		(19	)		(14	)
Operating Income		126			120			320			250

(1) Other revenue includes sales of natural gas, sulphur and thermal carbon black.

(2) Other commodity purchases resold includes the cost of natural gas sold.

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THIRD QUARTER REPORT 2008

Western Power Sales Volumes
(unaudited)	Three months ended September 30				Nine months ended September 30
(GWh)	2008		2007		2008		2007
Supply
Generation		598		560		1,733		1,683
Purchased
Sundance A & B and Sheerness PPAs		2,949		2,860		9,143		8,990
Other purchases		180		362		627		1,227
		3,727		3,782		11,503		11,900
Sales
Contracted		2,686		2,845		8,579		9,354
Spot		1,041		937		2,924		2,546
		3,727		3,782		11,503		11,900

Western Power’s operating income of $126 million in third-quarter 2008 increased $6 million compared to $120 million in third-quarter 2007 primarily due to a $17 million pre-tax ($12 million after tax) increase in sulphur sales at significantly higher prices in 2008. TransCanada has been selling modest quantities of sulphur on a break-even basis since 2005. Western Power’s operating income was negatively impacted in third-quarter 2008 by decreased margins from the Alberta power portfolio due to lower overall realized power prices and market heat rates on both contracted and uncontracted volumes of power sold in Alberta. Offsetting this decrease are lower power purchase arrangements (PPA) costs. The market heat rate is determined by dividing the average price of power per megawatt hour (MWh) by the average price of natural gas per gigajoule (GJ) for a given period.

Western Power’s power revenues decreased in third-quarter 2008 compared to third-quarter 2007 as a result of lower overall realized power prices.

Western Power 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 would otherwise have to purchase electricity in the open market to fulfill its contractual sales obligations. Approximately 28 per cent of power sales volumes were sold into the spot market in third-quarter 2008 compared to 25 per cent in third-quarter 2007.  To reduce its exposure to spot market prices on uncontracted volumes, as at September 30, 2008, Western Power had fixed-price power sales contracts to sell approximately 2,800 gigawatt hours (GWh) for the remainder of 2008 and 8,300 GWh for 2009.

Western Power’s operating income for the nine months ended September 30, 2008 of $320 million increased $70 million compared to the same period in 2007, primarily due to higher overall realized power prices.

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THIRD QUARTER REPORT 2008

Eastern Power

Eastern Power Results (1)
(unaudited)	Three months ended September 30						Nine months ended September 30
(millions of dollars)	2008			2007			2008			2007
Revenue
Power		311			392			852			1,135
Other (2)		81			39			258			186
		392			431			1,110			1,321
Commodity purchases resold
Power		(121	)		(226	)		(362	)		(586	)
Other (3)		(77	)		(38	)		(239	)		(163	)
		(198	)		(264	)		(601	)		(749	)
Plant operating costs and other		(74	)		(103	)		(196	)		(347	)
Depreciation		(20	)		(12	)		(48	)		(36	)
Operating Income		100			52			265			189

(1) Includes Ravenswood effective August 26, 2008 and Anse-à-Valleau effective November 10, 2007.

(2) Other revenue includes sales of natural gas.

(3) Other commodity purchases resold includes the cost of natural gas sold.

Eastern Power Sales Volumes (1)
(unaudited)	Three months ended September 30				Nine months ended September 30
(GWh)	2008		2007		2008		2007
Supply
Generation		1,442		1,915		3,584		5,966
Purchased		1,638		2,087		4,545		5,175
		3,080		4,002		8,129		11,141
Sales
Contracted		3,048		3,913		7,931		10,707
Spot		32		89		198		434
		3,080		4,002		8,129		11,141

(1) Includes Ravenswood effective August 26, 2008, Anse-à-Valleau effective November 10, 2007 and Bécancour for the nine months ended September 30, 2007.

Eastern Power’s operating income of $100 million and $265 million for the three and nine months ended September 30, 2008, respectively, increased $48 million and $76 million, respectively, compared to the same periods in 2007. The increases were primarily due to a lower overall cost per GWh on reduced purchased power volumes, higher realized power prices in New England, increased water flows from the TC Hydro generation assets and incremental operating income of $9 million ($6 million after tax) from the acquisition of Ravenswood on August 26, 2008. These increases were partially offset by decreased sales to commercial and industrial customers. The agreement to temporarily suspend generation at the Bécancour facility beginning January 1, 2008 resulted in decreases to power revenues, plant operating costs and other, generation volumes and contracted sales in 2008. The temporary suspension agreement has not materially affected Eastern Power’s operating income due to capacity payments received pursuant to the agreement with Hydro-Québec.

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THIRD QUARTER REPORT 2008

Eastern Power’s power revenues of $311 million decreased $81 million in third-quarter 2008 compared to third-quarter 2007 due to the temporary suspension of generation at the Bécancour facility and decreased sales to commercial and industrial customers in the New England market, partially offset by higher realized prices in New England and incremental income from Ravenswood. Power commodity purchases resold of $121 million and purchased power volumes of 1,638 GWh were lower in third-quarter 2008 as a result of decreased sales volumes to commercial and industrial customers, and lower overall cost per GWh on purchased power volumes. Plant operating costs and other of $74 million, which includes fuel gas consumed in generation, decreased in third-quarter 2008 from the prior year due to the temporary suspension of generation at the Bécancour facility, partially offset by the incremental operating costs from Ravenswood.

In third-quarter 2008, approximately one per cent of power sales volumes were sold into the spot market, similar to third-quarter 2007.  Eastern Power 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, 2008, Eastern Power had entered into fixed price power sales contracts to sell approximately 2,500 GWh for the remainder of 2008 and 6,300 GWh for 2009, although certain contracted volumes are dependent on customer usage levels.

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THIRD QUARTER REPORT 2008

Bruce Power

Bruce Power Results	Three months ended September 30						Nine months ended September 30
(unaudited)	2008			2007			2008			2007
Bruce Power (100 per cent basis)
(millions of dollars)
Revenues
Power		580			517			1,540			1,427
Other (1)		39			35			76			85
		619			552			1,616			1,512
Operating expenses
Operations and maintenance(2)		(245	)		(239	)		(827	)		(793	)
Fuel		(37	)		(23	)		(100	)		(76	)
Supplemental rent(2)		(43	)		(43	)		(130	)		(128	)
Depreciation and amortization		(37	)		(43	)		(110	)		(115	)
		(362	)		(348	)		(1,167	)		(1,112	)
Operating Income		257			204			449			400
TransCanada's proportionate share - Bruce A		18			12			68			29
TransCanada's proportionate share - Bruce B		69			57			97			108
TransCanada's proportionate share		87			69			165			137
Adjustments		(4	)		(5	)		(14	)		(13	)
TransCanada's combined operating income
from Bruce Power		83			64			151			124
Bruce Power - Other Information
Plant availability
Bruce A		85	%		79	%		88	%		81	%
Bruce B		94	%		96	%		82	%		88	%
Combined Bruce Power		92	%		90	%		85	%		86	%
Planned outage days
Bruce A		14			2			47			52
Bruce B		-			-			100			80
Unplanned outage days
Bruce A		5			27			7			34
Bruce B		11			8			59			29
Sales volumes (GWh)
Bruce A - 100 per cent		2,790			2,610			8,580			7,930
TransCanada's proportionate share		1,356			1,272			4,182			3,863
Bruce B - 100 per cent		6,810			6,820			17,660			18,620
TransCanada's proportionate share		2,153			2,155			5,581			5,884
Combined Bruce Power - 100 per cent		9,600			9,430			26,240			26,550
TransCanada's proportionate share		3,509			3,427			9,763			9,747
Results per MWh
Bruce A power revenues	$	63		$	60		$	62		$	59
Bruce B power revenues	$	59		$	53		$	57		$	52
Combined Bruce Power revenues	$	60		$	55		$	59		$	54
Combined Bruce Power fuel	$	4		$	3		$	4		$	3
Combined Bruce Power operating expenses (3)	$	36		$	36		$	43		$	41
Percentage of output sold to spot market		23	%		52	%		25	%		45	%

(1) Other revenue includes Bruce A fuel cost recoveries of $17 million and $45 million for the three and nine months ended September 30, 2008, respectively ($9 million and $25 million for the three and nine months ended September 30, 2007, respectively). Other revenue also includes a gain of $15 million and a loss of $3 million as a result of changes in fair value of held-for-trading derivatives for the three and nine months ended September 30, 2008, respectively (gains of $18 million and $36 million for the three and nine months ended September 30, 2007, respectively).

(2) Includes adjustments to eliminate the effects of inter-partnership transactions between Bruce A and Bruce B.

(3) Net of fuel recoveries.

TRANSCANADA [13

THIRD QUARTER REPORT 2008

TransCanada’s combined operating income of $83 million from its investment in Bruce Power increased $19 million in third-quarter 2008 compared to third-quarter 2007 primarily due to higher revenues resulting from higher realized prices and higher output.

TransCanada’s proportionate share of operating income in Bruce A increased $6 million to $18 million in third-quarter 2008 compared to third-quarter 2007 as a result of higher output and higher realized contract prices.

TransCanada’s proportionate share of operating income in Bruce B increased $12 million to $69 million in third-quarter 2008 compared to third-quarter 2007 primarily due to higher realized prices achieved during third-quarter 2008. The increase was due to higher contract prices on a higher proportion of volumes sold under contract in the three months ended September 30, 2008 compared to the same period in 2007. Also contributing to the increase were higher spot market prices in Ontario.

TransCanada’s combined operating income from its investment in Bruce Power for the nine months ended September 30, 2008 was $151 million compared to $124 million for the same period in 2007.  The increase of $27 million was primarily due to higher realized prices as a result of higher contract prices on a higher proportion of volumes sold under contract and higher output at Bruce A, partially offset by lower output at Bruce B, unrealized gains in 2007 from changes in fair value of power swaps and forwards, as well as higher operating and staff costs in 2008 compared to 2007.

TransCanada’s share of Bruce Power’s generation for third-quarter 2008 increased slightly to 3,509 GWh compared to 3,427 GWh in third-quarter 2007. The Bruce units ran at a combined average availability of 92 per cent in third-quarter 2008, compared to a 90 per cent average availability in third-quarter 2007. The higher availability in third-quarter 2008 was the result of fewer unplanned outage days at Bruce A, partially offset by more planned maintenance outage days at Bruce A. As a result of actual plant outages to date, the overall plant availability percentage in 2008 is currently expected to be in the mid to high 80s for the four Bruce B units and the low to mid 80s for the two operating Bruce A units.

Pursuant to the terms of a contract with the Ontario Power Authority (OPA), all of the output from Bruce A in third-quarter 2008 was sold at a fixed price of $63.00 per MWh (before recovery of fuel costs from the OPA) compared to $59.69 per MWh in third-quarter 2007.  In addition, sales from the Bruce B Units 5 to 8 were subject to a floor price of $47.66 per MWh in third-quarter 2008 and $46.82 per MWh in third-quarter 2007. Both the Bruce A and Bruce B reference prices are adjusted annually for inflation on April 1.  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 income has not included any amounts received under this floor price mechanism to date. To further reduce its exposure to spot market prices, as at September 30, 2008, Bruce B had entered into fixed price sales contracts to sell forward approximately 4,760 GWh for the remainder of 2008 and 10,760 GWh for 2009.

As at September 30, 2008, Bruce A had incurred $2.4 billion in costs with respect to the refurbishment and restart of Units 1 and 2, and approximately $0.2 billion for the refurbishment of Units 3 and 4.

TRANSCANADA [14

THIRD QUARTER REPORT 2008

Power Plant Availability

Weighted Average Power Plant Availability (1)
	Three months ended September 30		Nine months ended September 30
(unaudited)	2008	2007	2008	2007
Western Power (2)	92%	91%	87%	93%
Eastern Power (3)	98%	99%	96%	97%
Bruce Power	92%	90%	85%	86%
All plants, excluding Bruce Power	97%	97%	94%	95%
All plants	94%	94%	90%	92%

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

(2) Western Power plant availability decreased in the nine months ended September 30, 2008 due to an outage at the Cancarb power facility.

(3) Eastern Power includes Ravenswood effective August 26, 2008, Anse-à-Valleau effective November 10, 2007 and Bécancour for the nine months ended September 30, 2007.

Natural Gas Storage

Natural Gas Storage operating income of $29 million in third-quarter 2008 decreased $10 million compared to $39 million in third-quarter 2007.  The decrease was due to lower realized seasonal natural gas price spreads at the Edson and CrossAlta facilities compared to the same period in 2007.

Natural Gas Storage operating income of $95 million for the nine months ended September 30, 2008 was $6 million higher than the same period in 2007.  This increase was primarily due to the Edson facility becoming fully operational in April 2007, but only being in a commissioning phase prior to that time.

Natural Gas Storage operating income of $29 million and $95 million for the three and nine months ended September 30, 2008, respectively, included $2 million pre-tax ($2 million after tax) and $8 million pre-tax ($6 million after tax), respectively, of net unrealized losses resulting from the changes in fair value of proprietary natural gas inventory in storage and natural gas forward purchase and sale contracts. These unrealized losses are excluded in determining comparable earnings. TransCanada simultaneously enters into a forward purchase of natural gas for injection into storage and an offsetting forward sale of natural gas for withdrawal at a later period, thereby locking in future positive margins and effectively eliminating exposure to price movements of natural gas. Fair value adjustments recorded each period on proprietary natural gas storage inventory and these forward contracts are not representative of the amounts that will be realized on settlement.

Corporate

Corporate’s net income for the three months ended September 30, 2008 was $17 million compared to $5 million for the same period in 2007. The $12-million increase in third-quarter 2008 net income was primarily due to $26 million of favourable income tax adjustments from an internal restructuring and the realization of losses, compared to $15 million of favourable income tax reassessments and associated interest income in 2007. In addition, lower financing costs, primarily as a result of lower average short-term debt balances, as well as other tax refunds and positive adjustments, were offset by lower gains on derivatives used to manage the Company’s exposure to foreign exchange rate fluctuations. In third-quarter 2008 and 2007, Corporate’s comparable expenses were $9 million and $10 million, respectively, excluding the $26-million and $15-million favourable tax adjustments, respectively.

TRANSCANADA [15

THIRD QUARTER REPORT 2008

Corporate’s net income for the nine months ended September 30, 2008 was $10 million compared to $6 million for the same period in 2007. Excluding the $26 million and $42 million of favourable income tax adjustments recorded in 2008 and 2007, respectively, Corporate’s comparable expenses were $16 million and $36 million for the first nine months of 2008 and 2007, respectively. The $20-million decrease in comparable expenses in the first nine months of 2008 was primarily due to a reduction in financial charges as a result of lower average short-term debt balances, higher interest income on short-term intersegment financings, higher gains on derivatives used to manage the Company’s exposure to interest rate fluctuations and other tax refunds and positive tax adjustments. These increases were partially offset by lower gains on derivatives used to manage the Company’s exposure to foreign exchange rate fluctuations.

Liquidity and Capital Resources

Global Market Conditions

Global financial markets have recently experienced severe turmoil, however, TransCanada’s financial position and ability to generate cash in the short and long term from its operations remains sound. The Company has conducted a sizeable funding program for 2008, which consisted of a $1.3 billion common equity issue in May 2008 and term debt issues of US$1.5 billion and $500 million along with a US$255 million draw on a Ravenswood acquisition bridge facility in August 2008. In addition, common shares issued under the Company’s Dividend Reinvestment and Share Purchase Plan (DRP) are expected to approach $250 million in 2008. Continued balance sheet strength has been supported by over $4.7 billion of subordinated capital raised over the course of 2007 and 2008.

The Company’s liquidity position remains sound, underpinned by highly predictable cash flow from operations, as well as committed revolving bank lines of $2.0 billion and US$300 million maturing in December 2012 and February 2013, respectively, which remain fully available.  To date, no draws have been made on these facilities as the Company has continued to have largely uninterrupted access to the Canadian commercial paper market on competitive terms. An additional $50 million and US$325 million of capacity remain available on committed bank facilities at TransCanada-operated affiliates with maturity dates from 2010 through 2012. TransCanada is presently seeking to establish further committed bank lines in support of its Keystone pipeline construction efforts and expects these to be in place in fourth-quarter 2008.  The Company views its core bank group as high quality and its relationship with these institutions as excellent. Also, in fourth-quarter 2008, TransCanada expects to file a new US$3.0 billion debt shelf to replace the previous US$2.5 billion debt shelf which was exhausted in the recent US$1.5 billion senior unsecured notes offering. This will supplement the $3.0 billion and $1.0 billion of capacity available under its existing equity and Canadian debt shelves, respectively.

Operating Activities

At September 30, 2008, the Company held cash and cash equivalents of $752 million compared to $504 million at December 31, 2007. The increase in cash and cash equivalents was due primarily to gross proceeds of $2.2 billion from the issuance of long-term debt and $1.3 billion from the issuance of common shares in 2008. These cash inflows were partially offset by the US$2.9 billion paid for the Ravenswood acquisition in third-quarter 2008.

TRANSCANADA [16

THIRD QUARTER REPORT 2008

Funds Generated from Operations
(unaudited)	Three months ended September 30		Nine months ended September 30
(millions of dollars)	2008	2007	2008	2007
Cash Flows
Funds generated from operations (1)	711	702	2,309	1,880
Decrease in operating working capital	114	132	16	261
Net cash provided by operations	825	834	2,325	2,141
(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 decreased $9 million in third-quarter 2008 and increased $184 million for the first nine months of 2008 compared to the same periods in 2007. Funds generated from operations were $711 million and $2.3 billion for the three and nine months ended September 30, 2008, respectively, compared to $702 million and $1.9 billion for the same periods in 2007. The increase for the nine months ended September 30, 2008 was primarily due to gains from the Calpine bankruptcy settlements and higher earnings.

Investing Activities

Acquisitions, net of cash acquired, of $3.1 billion for the nine months ended September 30, 2008 included the acquisition of Ravenswood for US$2.9 billion, subject to certain post-closing adjustments. Acquisitions of $4.2 billion for the first nine months of 2007 included TransCanada’s acquisition of ANR and an additional 3.6 per cent interest in Great Lakes for US$3.4 billion, including US$491 million of assumed long-term debt, as well as PipeLines LP’s acquisition of a 46.4 per cent interest in Great Lakes for approximately US$942 million, including US$209 million of assumed long-term debt.

For the three and nine months ended September 30, 2008, capital expenditures totalled $806 million (2007 - $364 million) and $1.9 billion (2007 - $1.1 billion), respectively, and primarily related to the expansion of the Alberta System, refurbishment and restart of Bruce A Units 1 and 2, and construction of new power plants in Energy and the Keystone Pipeline system.

Financing Activities

In the three and nine months ended September 30, 2008, TransCanada retired $15 million (2007 - $64 million) and $788 million (2007 - $859 million) of long-term debt, respectively, and issued $2.1 billion (2007 - $5 million) and $2.2 billion (2007 - $2.6 billion, including junior subordinated notes) of long-term debt, respectively. TransCanada’s notes payable decreased $258 million and increased $466 million in the three and nine months ended September 30, 2008, respectively, compared to an increase of $293 million and $554 million in the three and nine months ended September 30, 2007, respectively. The Company redeemed $488 million of preferred securities in third-quarter 2007.

On August 13, 2008, TransCanada issued $500 million of medium-term notes maturing on August 20, 2013 and bearing interest at 5.05 per cent.  These notes were issued under the debt shelf prospectus filed in Canada in March 2007 qualifying for issuance $1.5 billion of medium-term notes.  At September 30, 2008, the Company had $1 billion of remaining capacity available under this shelf prospectus. The proceeds from these notes were used to partially fund the Alberta System's capital program and for general corporate purposes.

On August 6, 2008, TransCanada issued US$850 million and US$650 million of Senior Unsecured Notes maturing on August 15, 2018 and August 15, 2038, respectively, and bearing interest at 6.50 per cent and 7.25 per cent, respectively. The proceeds from these notes were used to partially fund the Ravenswood acquisition and for general corporate purposes. These notes were issued under the debt shelf prospectus filed in the U.S. in September 2007 qualifying for issuance US$2.5 billion of debt securities.  At September 30, 2008, the Company had fully utilized its capacity under the prospectus and intends to file a new U.S. debt shelf prospectus in fourth-quarter 2008.

TRANSCANADA [17

THIRD QUARTER REPORT 2008

On July 2, 2008, TransCanada filed a final short form base 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 August 2010. The filing was done in normal course similar to the filing of debt shelf prospectuses in Canada and the U.S. so as to expedite access to the capital markets depending on TransCanada’s assessment of its requirements for funding and general market conditions. This new shelf prospectus replaced the previous $3.0 billion short form shelf prospectus filed in January 2007 under which the Company had issued approximately $3.0 billion of common shares.

On June 27, 2008, TransCanada executed an agreement with a syndicate of banks for a US$1.5 billion, committed, unsecured, one-year bridge loan facility, at a floating interest rate based on the London Interbank Offered Rate. The facility is extendible at the option of the Company for an additional six-month term. On August 25, 2008, the Company utilized US$255 million from this facility to fund a portion of the Ravenswood acquisition and cancelled the remainder of the commitment. At September 30, 2008, US$255 million remained outstanding on the facility.

On May 5, 2008, TransCanada entered into an agreement with a syndicate of underwriters under which the underwriters agreed to purchase 30,200,000 common shares from TransCanada and sell them to the public at a price of $36.50 each. The underwriters also fully exercised an over-allotment option which they were granted for an additional 4,530,000 common shares at the same price. The entire issue of the 34,730,000 common shares closed on May 13, 2008 and resulted in gross proceeds to TransCanada of approximately $1.27 billion. These proceeds were used to partially fund the Ravenswood acquisition and capital projects of the Company, and for general corporate purposes.

In the three and nine months ended September 30, 2008, TransCanada issued 1.7 million and 4.8 million common shares, respectively, under its DRP, in lieu of making cash dividend payments totalling $65 million and $177 million, respectively. In the three and nine months ended September 30, 2007, TransCanada issued 1.4 million and 2.7 million common shares, respectively, under its DRP, in lieu of making cash dividend payments totalling $53 million and $104 million, respectively.  The dividends were paid with common shares issued from treasury.

Dividends

On October 27, 2008, TransCanada's Board of Directors declared a quarterly dividend of $0.36 per share for the quarter ending December 31, 2008 on the Company’s outstanding common shares. It is payable on January 30, 2009 to shareholders of record at the close of business on December 31, 2008.

TransCanada’s Board of Directors also approved the issuance of common shares from treasury at a two per cent discount under TransCanada’s DRP for the dividends payable on January 30, 2009. The Company reserves the right to alter the discount or return to purchasing shares on the open market at any time.

Significant Accounting Policies and Critical Accounting Estimates

To prepare financial statements that conform with Canadian GAAP, TransCanada is required to make estimates and assumptions that affect both the amount and timing of recording assets, liabilities, revenues and expenses since the determination of these items may be dependent on future events. The Company uses the most current information available and exercises careful judgement in making these estimates and assumptions.

TransCanada's significant accounting policies and critical accounting estimates have remained unchanged since December 31, 2007 and are the use of regulatory accounting for the Company’s rate-regulated operations and the policies the Company adopts to account for financial instruments and depreciation and amortization expense. For further information on the Company’s accounting policies and estimates refer to the MD&A in TransCanada's 2007 Annual Report.

Changes in Accounting Policies

The Company’s Accounting Policies have not changed materially from those described in TransCanada’s 2007 Annual Report.

TRANSCANADA [18

THIRD QUARTER REPORT 2008

Future Accounting Changes

International Financial Reporting Standards

The Canadian Institute of Chartered Accountants’ Accounting Standards Board (AcSB) announced that Canadian publicly accountable enterprises are required to adopt International Financial Reporting Standards (IFRS), as issued by the International Accounting Standards Board (IASB), effective January 1, 2011. In June 2008, the Canadian Securities Administrators proposed that Canadian public companies which are also SEC registrants, such as TransCanada, could retain the option to prepare their financial statements under U.S. GAAP instead of IFRS. In August 2008, the SEC agreed to publish for public comment a proposal recommending that U.S. issuers be required to adopt IFRS using a phased-in approach based on market capitalization, starting in 2014.

TransCanada is currently considering the impact a conversion to IFRS or U.S. GAAP would have on its accounting systems and financial statements. TransCanada’s conversion planning includes an analysis of project structure and governance, resourcing and training, analysis of key GAAP differences and a phased approach to assess current accounting policies. To date, TransCanada has completed initial IFRS training of its staff and has begun analysing key differences between Canadian GAAP and IFRS.

Under existing Canadian GAAP, TransCanada follows specific accounting policies unique to a rate-regulated business. TransCanada is actively monitoring ongoing discussions and developments at the IASB and its International Financial Reporting Interpretations Committee (IFRIC) regarding potential future guidance to clarify the applicability of certain aspects of rate-regulated accounting under IFRS.

Contractual Obligations

As at September 30, 2008, TransCanada had entered into new agreements since December 31, 2007 to purchase construction materials and services for the Coolidge, Cartier Wind, Kibby Wind and Halton Hills power projects, totalling approximately $1.1 billion, and for the North Central Corridor natural gas pipeline and Keystone oil pipeline projects, totalling approximately $515 million. The Keystone commitments reflect TransCanada’s 79.99 per cent ownership interest. As a result of a 29.99 per cent increase in the Company’s Keystone ownership interest, TransCanada’s portion of Keystone commitments entered into at December 31, 2007 and still outstanding at September 30, 2008 increased approximately $515 million. Other than these 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, 2007 to September 30, 2008, 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 2007 Annual Report.

Financial Instruments and Risk Management

TransCanada continues to manage and monitor its exposure to market, counterparty credit and liquidity risk. With the acquisition of Ravenswood in third-quarter 2008, the Company has additional exposures to fluctuations in power and natural gas prices, and new exposures to fluctuations in the price of fuel oil and kerosene. As with the Company’s other exposures to commodity price fluctuations, these risks will be managed through the use of commodity contracts and derivative instruments.

TransCanada’s exposure to U.S. dollar fluctuations has increased as a result of the Ravenswood acquisition. The net foreign exchange impact is offset by certain related debt and financing costs being denominated in U.S. dollars, exposures in certain of TransCanada’s businesses and by the Company’s hedging activities.

TRANSCANADA [19

THIRD QUARTER REPORT 2008

At September 30, 2008, TransCanada’s consolidated Value-at-Risk (VaR), which is used to estimate the potential impact resulting from exposure to market risk, was $21 million (December 31, 2007 – $8 million). The increase since December 31, 2007 was primarily due to the Ravenswood acquisition.

TransCanada has significant exposures to financial institutions as they provide committed credit lines as well as critical liquidity in the foreign exchange and interest rate derivative and energy wholesale markets, and letters of credit to mitigate TransCanada’s exposures to non-creditworthy counterparties.

During the recent deterioration of global financial markets, TransCanada has continued to closely monitor and reassess the creditworthiness of its counterparties, including financial institutions.  This has resulted in TransCanada reducing or mitigating its exposure to certain counterparties where it is deemed warranted and permitted under contractual terms. As part of its ongoing operations, TransCanada must balance its market and counterparty risks when making business decisions.

TransCanada does not have material exposures in either the SemGroup, L.P. bankruptcy or the Lehman Brothers Holdings Inc. and affiliates (LBHI) bankruptcy except for ANR’s long-term firm transportation and storage contracts with a subsidiary of LBHI. On October 16, 2008, a bankruptcy court approved the sale of this LBHI non-bankrupt subsidiary to Electricité de France S.A. (EDF), rated AA-/Negative Watch. The Company expects that EDF will fully support these contractual obligations. The Company is currently awaiting regulatory approvals on this sale.

The Company continues to manage its liquidity risk by ensuring sufficient cash and credit facilities are available to meet its operating and capital expenditure obligations when due, under both normal and stressed economic conditions.

Natural Gas Inventory

At September 30, 2008, $92 million of proprietary natural gas inventory held in storage was included in Inventories (December 31, 2007 - $190 million). Effective April 1, 2007, TransCanada began valuing its proprietary natural gas inventory at fair value, as measured by the one-month forward price for natural gas less selling costs. The Company did not have any proprietary natural gas inventory prior to April 1, 2007. The change in fair value of proprietary natural gas inventory in the three and nine months ended September 30, 2008 resulted in net unrealized losses of $108 million and $7 million, respectively, which were recorded as a decrease to Revenues and Inventories (three and nine months ended September 30, 2007 – net unrealized losses of $2 million and $25 million, respectively).  The net change in fair value of natural gas forward purchase and sales contracts in the three and nine months ended September 30, 2008 resulted in a net unrealized gain of $106 million and a net unrealized loss of $1 million, respectively (three and nine months ended September 30, 2007 - net unrealized gains of $4 million and $20 million, respectively), which were included in Revenues.

Net Investment in Self-Sustaining Foreign Operations

The Company hedges its net investment in self-sustaining foreign operations with U.S. dollar-denominated debt, cross-currency swaps, forward foreign exchange contracts and options.  At September 30, 2008, the Company had designated U.S. dollar-denominated debt with a carrying value of $6.2 billion (US$5.9 billion) and a fair value of $5.8 billion (US$5.5 billion), and had entered into derivatives with a fair value of $9 million (US$9 million) to further reduce the net investment exposure.

TRANSCANADA [20

THIRD QUARTER REPORT 2008

Derivatives Hedging Net Investment in Foreign Operations
Asset/(Liability)
(unaudited)
(millions of dollars)	September 30, 2008		December 31, 2007
		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)(2)	39	U.S. 1,550	77	U.S. 350
U.S. dollar forward foreign exchange contracts
(maturing 2008 to 2009)(2)	(46)	U.S. 2,780	(4)	U.S. 150
U.S. dollar options
(maturing 2008)(2)	(2)	U.S. 500	3	U.S. 600
	(9)	U.S. 4,830	76	U.S. 1,100
(1) Fair values are equal to carrying values.
(2) As at September 30, 2008.

TRANSCANADA [21

THIRD QUARTER REPORT 2008

Derivative Financial Instruments Summary

Information for the Company’s derivative financial instruments is as follows:

September 30, 2008
(all amounts in millions unless otherwise indicated)	Power			Natural Gas			Interest
Derivative Financial Instruments Held for Trading
Fair Values(1)
Assets	$	62		$	95		$	30
Liabilities	$	(48	)	$	(75	)	$	(25	)
Notional Values
Volumes(2)
Purchases		3,170			57			-
Sales		3,775			62			-
Canadian dollars		-			-			1,021
U.S. dollars		-			-		U.S. 1,400
Net unrealized gains/(losses) in the period(3)
Three months ended September 30, 2008	$	5		$	-		$	5
Nine months ended September 30, 2008	$	-		$	(12	)	$	3
Net realized gains/(losses) in the period(3)
Three months ended September 30, 2008	$	12		$	(12	)	$	2
Nine months ended September 30, 2008	$	21		$	(6	)	$	12
Maturity dates		2008-2014			2008-2011			2008-2018

Derivative Financial Instruments in Hedging Relationships(4)(5)
Fair Values(1)
Assets	$	156		$	3		$	5
Liabilities	$	(88	)	$	(14	)	$	(20	)
Notional Values
Volumes(2)
Purchases		7,024			14			-
Sales		15,549			-			-
Canadian dollars		-			-			50
U.S. dollars		-			-			U.S. 1,125
Net realized gains/(losses) in the period(3)
Three months ended September 30, 2008	$	14		$	(1	)	$	(2	)
Nine months ended September 30, 2008	$	(24	)	$	18		$	(4	)
Maturity dates		2008-2014			2008-2011			2009-2019

(1)  Fair value is equal to the carrying value of these derivatives.

(2)  Volumes for power and natural gas derivatives are in gigawatt hours (Gwh) and billion cubic feet (Bcf), respectively.

(3)  All realized and unrealized gains and losses are included in Net Income. Realized gains and losses are included in Net Income after the financial instrument has been settled.

(4)  All hedging relationships are designated as cash flow hedges except for interest-rate derivative financial instruments designated as fair value hedges with a fair value of $3 million.

(5)  Net Income for the three and nine months ended September 30, 2008 included gains of $7 million and $4 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 underlying positions. There were no gains or losses included in Net Income for the three and nine months ended September 30, 2008 for discontinued cash flow hedges.

TRANSCANADA [22

THIRD QUARTER REPORT 2008

2007
(all amounts in millions unless otherwise indicated)	Power			Natural Gas			Interest
Derivative Financial Instruments Held for Trading
Fair Values(1)(4)
Assets	$	55		$	43		$	23
Liabilities	$	(44	)	$	(19	)	$	(18	)
Notional Values(4)
Volumes(2)
Purchases		3,774			47			-
Sales		4,469			64			-
Canadian dollars		-			-			615
U.S. dollars		-			-		U.S. 550
Net unrealized gains/(losses) in the period(3)
Three months ended September 30, 2007	$	2		$	23		$	-
Nine months ended September 30, 2007	$	11		$	6		$	1
Net realized gains/(losses) in the period(3)
Three months ended September 30, 2007	$	2		$	18		$	3
Nine months ended September 30, 2007	$	(7	)	$	36		$	4
Maturity dates (4)		2008-2016			2008-2010			2008-2016

Derivative Financial Instruments in Hedging Relationships(5)(6)
Fair Values(1)(4)
Assets	$	135		$	19		$	2
Liabilities	$	(104	)	$	(7	)	$	(16	)
Notional Values(4)
Volumes(2)
Purchases		7,362			28			-
Sales		16,367			4			-
Canadian dollars		-			-			150
U.S. dollars		-			-		U.S. 875
Net realized (losses)/gains in the period(3)
Three months ended September 30, 2007	$	(51	)	$	10		$	2
Nine months ended September 30, 2007	$	(37	)	$	7		$	3
Maturity dates (4)		2008-2013			2008-2010			2008-2013

(1)  Fair value is equal to the carrying value of these derivatives.

(2)  Volumes for power and natural gas derivatives are in Gwh and Bcf, respectively.

(3)  All realized and unrealized gains and losses are included in Net Income. Realized gains and losses are included in Net Income after the financial instrument has been settled.

(4)  As at December 31, 2007.

(5) All hedging relationships are designated as cash flow hedges except for interest-rate derivative financial instruments designated as fair value hedges with a fair value of $2 million at December 31, 2007.

(6)  Net Income for the three and nine months ended September 30, 2007 included losses of $4 million and $7 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 underlying positions. Net Income for the three and nine months ended September 30, 2007 included nil and a  $4 million loss, respectively, for the changes in fair value of an interest-

     rate cash flow hedge that was reclassified as a result of discontinuance of cash flow hedge accounting when the anticipated transaction was identified as not probable of occurring by the end of the originally specified time period.

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THIRD QUARTER REPORT 2008

Other Risks

Additional risks faced by the Company are discussed in the MD&A in TransCanada’s 2007 Annual Report. These risks remain substantially unchanged since December 31, 2007.

Controls and Procedures

As of September 30, 2008, 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 Canadian securities regulatory authorities and by the SEC. Based on this 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, 2008.

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 Ravenswood acquisition completed in August 2008, the Company expects to exclude Ravenswood from its year end assessment of internal controls over financial reporting.

Outlook

The recent economic turmoil and deterioration of financial markets in North America could have a slowing effect on certain aspects of the North American economy, including infrastructure projects. TransCanada does not expect this to have a material effect on the Company’s earnings, financial situation, committed projects or corporate strategy.

Since the disclosure in TransCanada’s 2007 Annual Report, the Company's earnings outlook has improved primarily due to the net impact of stronger operating results in both Pipelines and Energy, the Calpine bankruptcy settlements, the writedown of the Broadwater LNG project costs, the third-quarter income tax adjustments in Corporate and the anticipated effect on earnings for the Ravenswood acquisition, which the Company closed in third-quarter 2008. For further information on outlook, refer to the MD&A in TransCanada’s 2007 Annual Report.

Since June 30, 2008, there have been no changes to TransCanada’s credit ratings. The senior unsecured debt of TCPL and its rated subsidiaries is rated ‘A-’, ‘A’ and ‘A3’ by S&P, DBRS and Moody’s, respectively. All three agencies have assigned a stable outlook to their TransCanada group ratings.

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THIRD QUARTER REPORT 2008

Other Recent Developments

Pipelines

Alberta System

On October 10, 2008, the Alberta Utilities Commission (AUC) approved TransCanada’s application for a permit to construct an approximately $925 million North Central Corridor expansion, which comprises a 300-kilometre (km) natural gas pipeline and associated facilities on the northern section of the Alberta System.

On September 8, 2008, TransCanada reached a proposed agreement with Canadian Utilities Limited (ATCO Pipelines) to provide integrated natural gas transmission service to customers. If approved by the AUC, the two companies will combine physical assets under a single rates and services structure with a single commercial interface with customers but with each company separately managing assets within distinct operating territories in the province. TransCanada continues to work with all stakeholders to finalize this agreement.

On September 4, 2008, the AUC issued the documents required for a generic cost of capital proceeding to review the level of the generic ROE for 2009, the generic ROE adjustment mechanism and capital structure of utilities on a utility-specific  basis.  The hearing commencement date was postponed until May 5, 2009.

In March 2008, TransCanada reached a settlement agreement with stakeholders on the Alberta System and filed a 2008-2009 Revenue Requirement Settlement Application with the AUC.  TransCanada expects approval of the settlement in fourth-quarter 2008.

ANR

In September 2008, the region near Galveston, Texas was impacted by Hurricane Ike. Current estimates of the Company’s exposure to damage costs are approximately US$20 million to US$30 million and are expected to be incurred during the remainder of 2008 and 2009. The majority of these costs are expected to be capitalized although the Company expects to incur some incremental operating expenses. The Company does not expect an impact on firm transportation revenues and is anticipating a minimal reduction in usage revenues with throughput volumes returning to normal levels by the end of 2008 based on representations from upstream producers.

TQM

On September 4, 2008, the NEB approved TQM’s application for a three-year partial negotiated settlement with interested parties concerning all matters, except cost of capital, for the years 2007 to 2009.

In December 2007, TQM filed a cost of capital application for the years 2007 and 2008, which requested approval of an 11 per cent ROE on 40 per cent deemed common equity. An NEB hearing on the application was conducted in September and October 2008 and a decision from the NEB is expected in early 2009. TQM’s rates currently reflect the NEB ROE formula on 30 per cent deemed common equity.

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THIRD QUARTER REPORT 2008

Keystone Pipeline System

During third quarter 2008, Keystone Pipeline system conducted an open season to solicit interest for an expansion and extension of the crude oil pipeline system from Hardisty, Alberta to the largest refining market in North America on the U.S. Gulf Coast.

Keystone Pipeline system secured additional firm, long-term contracts totalling 380,000 barrels per day (bbl/d) for an average term of approximately 17 years.  With these commitments from shippers, the Keystone Pipeline system will proceed with the necessary regulatory applications in Canada and the U.S. for approvals to construct and operate an expansion of the pipeline system that will provide additional capacity of 500,000 bbl/d from Western Canada to the U.S. Gulf Coast in 2012.

The expansion will increase the commercial design of the Keystone Pipeline system from 590,000 bbl/d to approximately 1.1 million bbl/d. With the additional contracts Keystone now has secured long-term commitments for 910,000 bbl/d for an average term of approximately 18 years.  The commitments represent approximately 83 per cent of the commercial design of the system.

The Keystone Pipeline system is currently expected to result in a capital investment of approximately US$12 billion between 2008 and 2012.  TransCanada has begun working with the contractually committed Keystone expansion shippers to optimize the construction schedule to best align the in-service dates of the system's delivery points with the in-service dates of the shippers' upstream and downstream facilities.  TransCanada has agreed to increase its equity ownership in the Keystone partnerships to 79.99 per cent from 50 per cent.  ConocoPhillips’ equity ownership will be reduced to 20.01 per cent.  Certain parties who have agreed to make volume commitments to the Keystone Pipeline system expansion have an option to acquire up to a combined 15 per cent equity ownership in the Keystone partnerships.  If the options are exercised, TransCanada’s equity ownership would be reduced to 64.99 per cent.

U.S. Rockies Pipeline Project

On September 3, 2008, TransCanada acquired Bison Pipeline LLC from Northern Border for US$20 million. The acquisition included all work completed on the Bison Pipeline project, a proposed 465-km pipeline from the Powder River Basin in Wyoming to the Northern Border system in North Dakota.  The Bison Pipeline project has shipping commitments for 405 million cubic feet per day (mmcf/d) and is planned to be in service in fourth-quarter 2010.  The capital cost of the Bison Pipeline project is estimated at approximately US$500 million to US$600 million, depending on the diameter of the pipeline.  One of the committed shippers has an option to acquire up to 25 per cent equity ownership in the project.

In addition, TransCanada is developing the Pathfinder Pipeline project, a proposed 1,006-km pipeline from Meeker, Colorado to the Northern Border system in North Dakota. In September 2008, Enterprise Product Partners L.P. (Enterprise) terminated their previously-announced commitment to become a 50 per cent partner in Pathfinder with a 500 mmcf/d shipping commitment. TransCanada is continuing to work with prospective Pathfinder shippers to advance this project.

TransCanada continues to progress its Sunstone project, a proposed 943-km pipeline with capacity of up to 1.2 billion cubic feet per day. This proposed pipeline would extend from Wyoming to Stanfield, Oregon and continue into California natural gas markets on GTN.

Alaska Pipeline Project

On August 1, 2008, the Alaska Senate approved TransCanada’s application for a license to advance the Alaska Pipeline Project under the Alaska Gasline Inducement Act (AGIA). Governor Palin signed the Bill on August 27, 2008. TransCanada expects the Alaska Commissioners of Revenue and Natural Resources to issue the AGIA license in late November 2008 after the 90-day waiting period for the Bill to become effective. TransCanada has committed under the AGIA to advance the Alaska Pipeline Project through an open season and subsequent FERC certification. TransCanada has commenced the engineering, environmental, field and commercial work, and expects to conclude an open season by July 31, 2010.

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THIRD QUARTER REPORT 2008

Energy

Ravenswood Acquisition

On August 26, 2008 TransCanada acquired the 2,480 MW Ravenswood Generating Station located in Queens, New York for US$2.9 billion, subject to certain post-closing adjustments.

For the remainder of 2008, Ravenswood will operate under a tolling arrangement that existed at the date of acquisition. Under the tolling arrangement, Ravenswood provides all available energy generation from the facility to Hess Corporation in return for a fixed operating fee. Ravenswood’s earnings in 2008 are comprised almost entirely of capacity payments from the New York Independent System Operator and the fixed operating fee.

In September 2008, the 972 MW Unit 30 experienced an unplanned outage as a result of a problem with its high pressure steam turbine. The repair costs and lost revenues associated with the unplanned outage, which are yet to be finalized, are anticipated to be recovered through insurance. As a result of the expected insurance recoveries, the Unit 30 unplanned outage is not expected to have a significant impact on TransCanada’s earnings.

Kibby

In July 2008, TransCanada commenced construction work on the Kibby Wind Power project. The capital cost of the project is expected to be approximately US$320 million with commissioning anticipated in 2009-2010.

Portlands Energy Centre

On May 30, 2008, the Portlands Energy Centre natural gas-fired combined-cycle power plant near downtown Toronto, Ontario went into service in simple-cycle mode.  In September 2008, the power plant returned to the construction phase and is expected to be fully commissioned in combined-cycle mode and capable of delivering 550MW of power in first-quarter 2009.

Coolidge

During third-quarter 2008, the Company commenced detailed engineering, geotechnical, and regulatory work for the 575 MW Coolidge power generation facility in Arizona. When constructed, the output from the plant will be sold to Salt River Project Agricultural Improvement and Power District under a 20-year agreement. The facility is expected to cost US$500 million and is expected to be in service in 2011.

Share Information

As at September 30, 2008, TransCanada had 580 million issued and outstanding common shares. In addition, there were 9 million outstanding options to purchase common shares, of which 7 million were exercisable as at September 30, 2008.

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THIRD QUARTER REPORT 2008

Selected Quarterly Consolidated Financial Data(1)

(unaudited)	2008			2007				2006
(millions of dollars except per share amounts)	Third	Second	First	Fourth	Third	Second	First	Fourth
Revenues	2,137	2,017	2,133	2,189	2,187	2,208	2,244	2,091
Net Income	390	324	449	377	324	257	265	269
Share Statistics
Net income per share - Basic	$    0.67	$    0.58	$    0.83	$  0.70	$  0.60	$  0.48	$  0.52	$  0.55
Net income per share - Diluted	$    0.67	$    0.58	$    0.83	$  0.70	$  0.60	$  0.48	$  0.52	$  0.54
Dividend declared per common share	$    0.36	$    0.36	$    0.36	$  0.34	$  0.34	$  0.34	$  0.34	$  0.32
(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 income fluctuate over the long term based on regulators' decisions and negotiated settlements with shippers. Generally, quarter-over-quarter revenues and net income 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, acquisitions and divestitures, and developments 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 income are affected by seasonal weather conditions, customer demand, market prices, planned and unplanned plant outages, acquisitions and divestitures, and developments outside of the normal course of operations.

Significant developments that impacted the last eight quarters' net income are as follows:

·   Fourth-quarter 2006 net income included approximately $12 million related to income tax refunds and related interest.

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

·   Second-quarter 2007 net income included $16 million ($12 million in Corporate and $4 million in Energy) related to favourable income tax adjustments resulting from reductions in Canadian federal income tax rates. Pipelines’ net income increased as a result of a settlement reached on the Canadian Mainline, which was approved by the NEB in May 2007.

·   Third-quarter 2007 net income included $15 million of favourable income tax reassessments and associated interest income relating to prior years.

·   Fourth-quarter 2007 net income included $56 million ($30 million in Energy and $26 million in Corporate) of favourable income tax adjustments resulting from reductions in Canadian federal income tax rates and other legislative changes. Energy’s net income increased due to a $14 million after-tax ($16 million pre-tax) gain on sale of land previously held for development. Pipelines’ net income increased as a result of recording incremental earnings related to the rate case settlement reached for the GTN System, effective January 1, 2007.

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·   First-quarter 2008, Pipelines’ net income included $152 million after tax ($240 million pre-tax) from the Calpine bankruptcy settlements received by GTN and Portland, and proceeds from a lawsuit settlement of $10 million after tax ($17 million pre-tax). Energy’s net income included a writedown of costs related to the Broadwater LNG project of $27 million after tax ($41 million pre-tax) and net unrealized losses of $12 million after tax ($17 million pre-tax) due to changes in fair value of proprietary natural gas storage inventory and natural gas forward purchase and sale contracts. Beginning in first-quarter 2008, the temporary suspension of generation at the Bécancour facility reduced Eastern Power’s revenues, however, net income was not materially impacted due to capacity payments received pursuant to an agreement with Hydro-Québec.

·   Second-quarter 2008, Energy’s net income included net unrealized gains of $8 million after tax ($12 million pre-tax) due to changes in fair value of proprietary natural gas storage inventory and natural gas forward purchase and sale contracts. In addition, Western Power’s revenues and operating income increased due to higher overall realized prices and market heat rates in Alberta.

·   Third-quarter 2008, Energy’s net income included contribution from the August 26, 2008 acquisition of Ravenswood. Corporate net income included favourable income tax adjustments of $26 million from an internal restructuring and realization of losses.