exhibit13107312008.htm

(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.

EX-13.1 2 exhibit13107312008.htm EXHIBIT 13.1 MANAGEMENT'S DISCUSSION AND ANALYSIS exhibit13107312008.htm

Exhibit 13.1

TRANSCANADA CORPORATION – SECOND QUARTER 2008

Quarterly Report to Shareholders

Management's Discussion and Analysis

Management's Discussion and Analysis (MD&A) dated July 31, 2008 should be read in conjunction with the accompanying unaudited Consolidated Financial Statements of TransCanada Corporation (TransCanada or the Company) for the three and six months ended June 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.

TRANSCANADA [2

SECOND 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 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.

TRANSCANADA [3

SECOND QUARTER REPORT 2008

Consolidated Results of Operations

Reconciliation of Comparable Earnings to Net Income
(unaudited)			Three months ended June 30					Six months ended June 30
(millions of dollars except per share amounts)			2008		2007			2008			2007
Pipelines
		Comparable earnings		158		166			357			321
		Specific items (net of tax):
		Calpine bankruptcy settlements		-		-			152			-
		GTN lawsuit settlement		-		-			10			-
		Net income		158		166			519			321

Energy
		Comparable earnings		143		90			292			196
		Specific items (net of tax, where applicable):
		Writedown of Broadwater LNG project costs		-		-			(27	)		-
		Fair value adjustments of natural gas storage inventory
		and forward contracts		8		-			(4	)		-
		Income tax adjustments		-		4			-			4
		Net income		151		94			261			200
Corporate
		Comparable earnings/(expenses)		15		(15	)		(7	)		(26	)
		Specific item:
		Income tax adjustments		-		12			-			27
		Net income/(expenses)		15		(3	)		(7	)		1
Net Income (1)				324		257			773			522

Net Income Per Share (2)
Basic and Diluted			$	0.58	$	0.48		$	1.40		$	1.00

	(1)	Comparable Earnings		316		241			642			491
		Specific items (net of tax, where applicable):
		Calpine bankruptcy settlements		-		-			152			-
		GTN lawsuit settlement		-		-			10			-
		Writedown of Broadwater LNG project costs		-		-			(27	)		-
		Fair value adjustments of natural gas storage inventory
		and forward contracts		8		-			(4	)		-
		Income tax adjustments		-		16			-			31
		Net Income		324		257			773			522

	(2)	Comparable Earnings Per Share	$	0.57	$	0.45		$	1.17		$	0.94
		Specific items - per share
		Calpine bankruptcy settlements		-		-			0.27			-
		GTN lawsuit settlement		-		-			0.02			-
		Writedown of Broadwater LNG project costs		-		-			(0.05	)		-
		Fair value adjustments of natural gas storage inventory
		and forward contracts		0.01		-			(0.01	)		-
		Income tax adjustments		-		0.03			-			0.06
		Net Income Per Share	$	0.58	$	0.48		$	1.40		$	1.00

TRANSCANADA [4

SECOND QUARTER REPORT 2008

TransCanada’s net income in second-quarter 2008 was $324 million or $0.58 per share compared to $257 million or $0.48 per share in second-quarter 2007. The $67-million increase in net income was primarily due to increased second-quarter 2008 earnings in Energy and Corporate, partially offset by a decrease in earnings in Pipelines. Earnings from Energy were higher in second-quarter 2008 compared to second-quarter 2007 primarily due to increased Western Power and Eastern Power earnings. Energy’s earnings in second-quarter 2008 also included net unrealized gains of $8 million after tax ($12 million pre-tax) resulting from changes in fair value of proprietary natural gas storage inventory and natural gas forward purchase and sale contracts. Corporate’s earnings were higher in second-quarter 2008 compared to second-quarter 2007 primarily due to a reduction in financial charges. Pipelines’ earnings were lower in second-quarter 2008 compared to second-quarter 2007 primarily due to reduced Canadian Mainline and ANR earnings, and increased general, administrative and support costs, partially offset by increased GTN earnings. Net income in second-quarter 2007 included favourable income tax adjustments of $16 million ($12 million in Corporate and $4 million in Energy) resulting from changes in Canadian federal income tax legislation.

Comparable earnings for second-quarter 2008 were $316 million or $0.57 per share compared to $241 million or $0.45 per share for the same period in 2007. On a per share basis, comparable earnings increased approximately 27 per cent in second-quarter 2008 compared to second-quarter 2007. Comparable earnings in second-quarter 2008 excluded the $8 million of net unrealized gains resulting from changes in fair value of proprietary natural gas storage inventory and natural gas forward purchase and sale contracts. Comparable earnings in second-quarter 2007 excluded the $16 million of favourable income tax adjustments.

Net income was $773 million or $1.40 per share for the first six months in 2008 compared to $522 million or $1.00 per share for the same period in 2007. The $251-million increase in net income for the first six months of 2008 compared to the same period in 2007 was primarily due to increased earnings in Pipelines and Energy, partially offset by a decrease in earnings in Corporate. Earnings in Pipelines were higher for the first six months of 2008 compared to the first six months of 2007 primarily due to increased earnings from ANR and GTN, a $152 million after-tax ($240 million pre-tax) gain 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). Earnings in Energy were higher for the first six months of 2008 compared to the same period last year primarily due to increased Western Power, Eastern Power and Natural Gas Storage earnings. Partially offsetting these increases to earnings in the first six months of 2008 was a $27 million after-tax ($41 million pre-tax) writedown of costs previously capitalized for the Broadwater liquefied natural gas (LNG) project and a reduction in earnings due to favourable income tax adjustments of $31 million ($27 million in Corporate and $4 million in Energy) recorded in the first six months of 2007 relating to the reduction in Canadian federal and provincial corporate income tax rates, the resolution of certain income tax matters with taxation authorities and a corporate restructuring.

Comparable earnings for the first six months of 2008 were $642 million or $1.17 per share compared to $491 million or $0.94 per share for the same period in 2007. On a per share basis, comparable earnings increased approximately 24 per cent for the first six months in 2008 compared to the same period in 2007. Comparable earnings for the first six months of 2008 excluded the Calpine bankruptcy settlements, the GTN lawsuit settlement, the writedown of the Broadwater LNG project costs and the net unrealized losses from the natural gas storage fair value adjustments. Comparable earnings for the first six months of 2007 excluded the favourable income tax adjustments of $31 million.

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

TRANSCANADA [5

SECOND QUARTER REPORT 2008

Funds generated from operations of $676 million and $1,598 million for the three and six months ended June 30, 2008, respectively, increased $80 million (or 13 per cent) and $420 million (or 36 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.

Pipelines

The Pipelines business generated net income and comparable earnings of $158 million in second-quarter 2008, a decrease of $8 million compared to net income and comparable earnings of $166 million in second-quarter 2007.

Net income and comparable earnings for the six months ended June 30, 2008 were $519 million and $357 million, respectively, compared to $321 million for the same six months in 2007. Comparable earnings for the first six 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 a $10 million after-tax lawsuit settlement with a software supplier.

TRANSCANADA [6

SECOND QUARTER REPORT 2008

Pipelines Results
(unaudited)	Three months ended June 30						Six months ended June 30
(millions of dollars)	2008			2007			2008			2007
Wholly Owned Pipelines
Canadian Mainline		70			75			138			132
Alberta System		33			34			65			65
ANR (1)		25			29			70			50
GTN		15			5			34			16
Foothills		6			8			13			14
		149			151			320			277
Other Pipelines
Great Lakes (2)		11			11			23			25
PipeLines LP (3)		5			4			12			6
Iroquois		3			3			8			8
Tamazunchale		2			2			4			5
Other (4)		8			10			21			25
Northern Development		(1	)		(1	)		(1	)		(2	)
General, administrative, support costs and other		(19	)		(14	)		(30	)		(23	)
		9			15			37			44
Comparable Earnings		158			166			357			321
Specific items (net of tax):
Calpine bankruptcy settlements (5)		-			-			152			-
GTN lawsuit settlement		-			-			10			-
Net Income		158			166			519			321

Wholly Owned Pipelines

Canadian Mainline's second-quarter 2008 net income of $70 million decreased $5 million compared to $75 million in second-quarter 2007. In May 2007, a settlement effective January 1, 2007 to December 31, 2011 was approved by the National Energy Board (NEB), which included an increase in the deemed common equity ratio from 36 per cent to 40 per cent and certain performance-based incentive arrangements. A favourable $6-million adjustment was recorded in second-quarter 2007 that related to the first three months of 2007 as a result of the settlement. In addition, earnings in second-quarter 2008 reflected the negative impact of a lower average investment base. These decreases were partially offset by the positive impact 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.

Canadian Mainline’s net income for the six months ended June 30, 2008 increased $6 million to $138 million primarily as a result of the higher ROE and performance-based incentive arrangements, partially offset by a lower average investment base.

TRANSCANADA [7

SECOND QUARTER REPORT 2008

The Alberta System’s net income was $33 million in second-quarter 2008 and $65 million for the first six months of 2008 compared to $34 million and $65 million for the same periods in 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 second-quarter 2008 was $25 million compared to $29 million in second-quarter 2007. Net income for the first six months of 2008 was $70 million compared to $50 million for the period commencing on the acquisition date of February 22, 2007 to June 30, 2007. The decrease in second-quarter 2008 was primarily due to higher operations, maintenance and administrative (OM&A) costs, partially offset by increased revenues from new growth projects. The increase for the first six months of 2008 was primarily due to a full six months of earnings in 2008, higher revenues from new growth projects and increased firm transport revenues, 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 six months ended June 30, 2008 increased $10 million and $18 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 Federal Energy Regulatory Commission (FERC) in January 2008 and lower OM&A expenses. For the six months ended June 30, 2008, these increases were partially offset by the negative impact on earnings of a stronger Canadian dollar.

Operating Statistics

	Canadian		Alberta				GTN
Six months ended June 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)	7,123	7,359	4,286	4,254	n/a	n/a	n/a	n/a	760	816
Delivery volumes (Bcf)
Total	1,762	1,614	1,930	2,004	881	498	394	371	660	676
Average per day	9.7	8.9	10.6	11.1	4.8	3.9	2.2	2.0	3.6	3.7

(1) Canadian Mainline's physical receipts originating at the Alberta border and in Saskatchewan for the six months ended June 30, 2008 were 800 billion cubic feet (Bcf) (2007 - 1,086 Bcf); average per day was 4.4 Bcf (2007 - 6.0 Bcf).
(2) Field receipt volumes for the Alberta System for the six months ended June 30, 2008 were 1,919 Bcf (2007 - 2,039 Bcf); average per day was 10.5 Bcf (2007 - 11.3 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) TransCanada acquired ANR on February 22, 2007.

Other Pipelines

TransCanada’s proportionate share of net income from Other Pipelines was $9 million for the three months ended June 30, 2008 compared to $15 million for the same period in 2007. The decrease was primarily due to increased project development costs and the negative impact on earnings of a stronger Canadian dollar.

TransCanada’s proportionate share of net income from Other Pipelines was $37 million for the six months ended June 30, 2008 compared to $44 million for the same period in 2007. The decrease was primarily due to increased project development costs and the negative impact on earnings of a stronger Canadian dollar, partially offset by increased earnings from PipeLines LP, reflecting PipeLines LP’s increased ownership in Great Lakes and TransCanada’s increased ownership in PipeLines LP.

TRANSCANADA [8

SECOND QUARTER REPORT 2008

As at June 30, 2008, TransCanada had advanced $140 million to the Aboriginal Pipeline Group with respect to the Mackenzie Gas Pipeline (MGP) project. TransCanada and the other co-venture companies involved in the MGP continue to pursue approval of the proposed project, focusing on the regulatory process and discussions with the Canadian government on fiscal framework. Project timing is uncertain and is conditional upon resolution of regulatory and fiscal matters.

Energy

Energy’s net income of $151 million in second-quarter 2008 increased $57 million compared to $94 million in second-quarter 2007. Comparable earnings in second-quarter 2008 of $143 million increased $53 million compared to the same period in 2007 and excluded net unrealized gains of $8 million after tax ($12 million pre-tax) resulting from changes in fair value of proprietary natural gas storage inventory and natural gas forward purchase and sale contracts. Comparable earnings of $90 million in second-quarter 2007 excluded $4 million of favourable income tax adjustments.

Energy’s net income for the six months ended June 30, 2008 of $261 million increased $61 million compared to $200 million for the same period in 2007. For the first six months of 2008, comparable earnings of $292 million increased $96 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 $4 million after tax ($5 million pre-tax) resulting from natural gas storage fair value changes. Comparable earnings of $196 million for the first six months of 2007 excluded the $4 million of favourable income tax adjustments.

Energy Results
(unaudited)	Three months ended June 30						Six months ended June 30
(millions of dollars)	2008			2007			2008			2007
Western Power		116			57			194			130
Eastern Power		80			70			165			137
Bruce Power		31			31			68			60
Natural Gas Storage		18			20			66			50
General, administrative, support costs and other		(35	)		(39	)		(76	)		(75	)
Operating income		210			139			417			302
Financial charges		(6	)		(6	)		(11	)		(10	)
Interest income and other		3			3			4			6
Writedown of Broadwater LNG project costs		-			-			(41	)		-
Income taxes		(56	)		(42	)		(108	)		(98	)
Net Income		151			94			261			200

Comparable Earnings		143			90			292			196
Specific items (net of tax, where applicable):
Fair value adjustments of natural gas storage
inventory and forward contracts		8			-			(4	)		-
Writedown of Broadwater LNG project costs		-			-			(27	)		-
Income tax adjustments		-			4			-			4
Net Income		151			94			261			200

TRANSCANADA [9

SECOND QUARTER REPORT 2008

Western Power

Western Power Results
(unaudited)	Three months ended June 30						Six months ended June 30
(millions of dollars)	2008			2007			2008			2007
Revenues
Power		283			217			578			498
Other (1)		35			21			52			49
		318			238			630			547
Commodity purchases resold
Power		(124	)		(131	)		(294	)		(305	)
Other (2)		(21	)		(12	)		(34	)		(35	)
		(145	)		(143	)		(328	)		(340	)
Plant operating costs and other		(50	)		(34	)		(94	)		(68	)
Depreciation		(7	)		(4	)		(14	)		(9	)
Operating Income		116			57			194			130

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

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


Western Power Sales Volumes
(unaudited)	Three months ended June 30				Six months ended June 30
(GWh)	2008		2007		2008		2007
Supply
Generation		506		531		1,135		1,123
Purchased
Sundance A & B and Sheerness PPAs(1)		2,835		2,877		6,194		6,130
Other purchases		178		416		447		865
		3,519		3,824		7,776		8,118
Sales
Contracted		2,819		3,017		5,893		6,509
Spot		700		807		1,883		1,609
		3,519		3,824		7,776		8,118

(1) Power purchase arrangements.

Western Power’s operating income of $116 million in second-quarter 2008 increased $59 million compared to $57 million in second-quarter 2007. This increase was primarily due to increased margins from the Alberta power portfolio resulting from higher overall realized power prices and market heat rates on both contracted and uncontracted volumes of power sold in Alberta. 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 revenues increased in second-quarter 2008 compared to second-quarter 2007 as a result of higher overall realized prices, partially offset by slightly lower sales volumes.

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 20 per cent of power sales volumes were sold into the spot market in second-quarter 2008 compared to 21 per cent in second-quarter 2007. To reduce its exposure to spot market prices on uncontracted volumes, as at June 30, 2008, Western Power had fixed-price power sales contracts to sell approximately 5,400 gigawatt hours (GWh) for the remainder of 2008 and 7,800 GWh for 2009.

TRANSCANADA [10

SECOND QUARTER REPORT 2008

Western Power’s operating income for the six months ended June 30, 2008 increased $64 million to $194 million compared to the same period in 2007, primarily due to higher overall realized power prices.

Eastern Power

Eastern Power Results (1)
(unaudited)	Three months ended June 30						Six months ended June 30
(millions of dollars)	2008			2007			2008			2007
Revenue
Power		263			389			541			743
Other (2)		95			64			177			147
		358			453			718			890
Commodity purchases resold
Power		(105	)		(183	)		(241	)		(360	)
Other (2)		(96	)		(67	)		(162	)		(125	)
		(201	)		(250	)		(403	)		(485	)
Plant operating costs and other		(63	)		(120	)		(122	)		(244	)
Depreciation		(14	)		(13	)		(28	)		(24	)
Operating Income		80			70			165			137

(1) Includes Bécancour for the six months ended June 30, 2007 and Anse-à-Valleau effective November 10, 2007.
(2) Other revenue includes sales of natural gas and other commodity purchases resold includes the cost of natural gas sold.


Eastern Power Sales Volumes (1)
(unaudited)	Three months ended June 30						Six months ended June 30
(GWh)	2008			2007			2008			2007
Supply
Generation		1,056			2,028			2,142			4,051
Purchased		1,383			1,562			2,907			3,088
		2,439			3,590			5,049			7,139
Sales
Contracted		2,371			3,437			4,883			6,794
Spot		68			153			166			345
		2,439			3,590			5,049			7,139

(1) Includes Bécancour for the six months ended June 30, 2007 and Anse-à-Valleau effective November 10, 2007.

Eastern Power’s operating income of $80 million and $165 million for the three and six months ended June 30, 2008, respectively, increased $10 million and $28 million, respectively, compared to the same periods in 2007. The increases were primarily due to the impact of higher realized power prices in New England and increased sales volumes to wholesale, commercial and industrial New England 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 agreement, however, has not materially affected Eastern Power’s operating income due to capacity payments received pursuant to the agreement with Hydro-Québec.

TRANSCANADA [11

SECOND QUARTER REPORT 2008

Eastern Power’s power revenues of $263 million decreased $126 million in second-quarter 2008 compared to second-quarter 2007 due to the temporary suspension of generation at the Bécancour facility. Power commodity purchases resold of $105 million and purchased power volumes of 1,383 GWh were lower in second-quarter 2008, compared to the same period in 2007. The reduced expense was due to a lower overall cost per GWh on purchased power volumes as well as the lower purchased power volumes. Plant operating costs and other of $63 million, which includes fuel gas consumed in generation, decreased in second-quarter 2008 from the prior year due to the temporary suspension of generation at the Bécancour facility.

In second-quarter 2008, approximately three per cent of power sales volumes were sold into the spot market compared to approximately four per cent in second-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 June 30, 2008, Eastern Power had entered into fixed price power sales contracts to sell approximately 4,400 GWh for the remainder of 2008 and 5,700 GWh for 2009, although certain contracted volumes are dependent on customer usage levels.

TRANSCANADA [12

SECOND QUARTER REPORT 2008

Bruce Power

Bruce Power Results	Three months ended June 30						Six months ended June 30
(unaudited)	2008			2007			2008			2007
Bruce Power (100 per cent basis)
(millions of dollars)
Revenues
Power		492			450			960			910
Other (1)		20			30			37			50
		512			480			997			960
Operating expenses
Operations and maintenance(2)		(304	)		(259	)		(582	)		(554	)
Fuel		(35	)		(28	)		(63	)		(53	)
Supplemental rent(2)		(44	)		(42	)		(87	)		(85	)
Depreciation and amortization		(37	)		(36	)		(73	)		(72	)
		(420	)		(365	)		(805	)		(764	)
Operating Income		92			115			192			196

TransCanada's proportionate share - Bruce A		18			2			50			17
TransCanada's proportionate share - Bruce B		18			35			28			51
TransCanada's proportionate share		36			37			78			68
Adjustments		(5	)		(6	)		(10	)		(8	)
TransCanada's combined operating income
from Bruce Power		31			31			68			60

Bruce Power - Other Information
Plant availability
Bruce A		85	%		74	%		91	%		82	%
Bruce B		81	%		91	%		77	%		84	%
Combined Bruce Power		82	%		85	%		81	%		83	%
Planned outage days
Bruce A		26			35			33			50
Bruce B		50			9			100			80
Unplanned outage days
Bruce A		1			7			2			7
Bruce B		15			17			48			21
Sales volumes (GWh)
Bruce A - 100 per cent		2,730			2,410			5,790			5,320
TransCanada's proportionate share		1,330			1,175			2,826			2,591
Bruce B - 100 per cent		5,710			6,370			10,850			11,800
TransCanada's proportionate share		1,804			2,016			3,428			3,729
Combined Bruce Power - 100 per cent		8,440			8,780			16,640			17,120
TransCanada's proportionate share		3,134			3,191			6,254			6,320
Results per MWh
Bruce A power revenues	$	63		$	60		$	61		$	59
Bruce B power revenues	$	56		$	48		$	56		$	51
Combined Bruce Power revenues	$	58		$	51		$	58		$	53
Combined Bruce Power fuel	$	4		$	3		$	4		$	3
Combined Bruce Power operating expenses (3)	$	48		$	41		$	47		$	44
Percentage of output sold to spot market		22	%		47	%		25	%		41	%

(1) Other revenue includes Bruce A fuel cost recoveries of $15 million and $28 million for the three and six months ended June 30, 2008, respectively ($8 million and $16 million for the three and six months ended June 30, 2007, respectively). Other revenue also includes losses of $9 million and $18 million as a result of changes in fair value of held-for-trading derivatives for the three and six months ended June 30, 2008, respectively (gains of $18 million for the three and six months ended June 30, 2007).

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

(3) Net of fuel cost recoveries.

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SECOND QUARTER REPORT 2008

TransCanada’s combined operating income from its investment in Bruce Power was $31 million in second-quarter 2008, which was consistent with the same period in 2007.

TransCanada’s proportionate share of operating income in Bruce A increased $16 million to $18 million in second-quarter 2008 compared to second-quarter 2007 as a result of higher output and higher realized prices. Bruce A power prices achieved during second-quarter 2008 were $63 per MWh compared to $60 per MWh in second-quarter 2007.

TransCanada’s proportionate share of operating income in Bruce B decreased $17 million to $18 million in second-quarter 2008 compared to second-quarter 2007. Higher realized prices at Bruce B in second-quarter 2008 were more than offset by higher operating costs and lower output due to an increase in planned outage days, as well as an increase in unrealized losses from changes in fair value of electricity swaps and forwards in second-quarter 2008. Bruce B power prices achieved during second-quarter 2008 were $56 per MWh compared to $48 per MWh in second-quarter 2007. The increase was due to higher contract prices on a higher proportion of volumes sold under contract in the three and six months ended June 30, 2008 compared to the same periods in 2007. Also contributing to the increase were higher spot market prices in Ontario, partially offset by lower output for second-quarter 2008.

Bruce Power's combined operating expenses (net of fuel cost recoveries) increased to $48 per MWh in second-quarter 2008 from $41 per MWh in second-quarter 2007 primarily due to higher planned outage costs and lower output.

TransCanada’s combined operating income from its investment in Bruce Power for the six months ended June 30, 2008 was $68 million compared to $60 million for the same period in 2007. The increase of $8 million was primarily due to higher realized prices, partially offset by higher operating costs associated with an increase in outage days in 2008 compared to 2007. Increases in TransCanada’s combined interest in Bruce Power’s operating income were partially offset by lower positive purchase price amortizations related to the expiry of power sales agreements in 2007.

TransCanada’s share of Bruce Power’s generation for second-quarter 2008 decreased slightly to 3,134 GWh compared to 3,191 GWh in second-quarter 2007. The Bruce units ran at a combined average availability of 82 per cent in second-quarter 2008, compared to an 85 per cent average availability in second-quarter 2007. The lower availability in second-quarter 2008 was the result of more planned maintenance outage days at Bruce B, partially offset by fewer unplanned outage days at both Bruce A and Bruce B. As a result of actual plant outages to date, the overall plant availability percentage in 2008 is currently expected to be in the high 80s for the four Bruce B units and the 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 second-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 second-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 second-quarter 2008 and $46.82 per MWh in second-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 June 30, 2008, Bruce B had entered into fixed price sales contracts to sell forward approximately 8,630 GWh for the remainder of 2008 and 9,680 GWh for 2009.

The capital cost of Bruce A’s refurbishment and restart of Units 1 and 2 is currently estimated by Bruce Power to total approximately $3.1 billion to $3.4 billion, with TransCanada’s share being approximately $1.55 billion to $1.7 billion. As at June 30, 2008, Bruce A had incurred $2.2 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.

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SECOND QUARTER REPORT 2008

Power Plant Availability

Weighted Average Power Plant Availability (1)
	Three months ended June 30						Six months ended June 30
(unaudited)	2008			2007			2008			2007
Western Power (2)		78	%		89	%		85	%		94	%
Eastern Power (3)		96	%		93	%		95	%		96	%
Bruce Power		82	%		85	%		81	%		83	%
All plants, excluding Bruce Power investment		92	%		91	%		93	%		95	%
All plants		88	%		89	%		88	%		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, reduced by planned and unplanned outages.
(2) Western Power plant availability decreased in the three and six months ended June 30, 2008 due to an outage at the Cancarb power facility.
(3) Eastern Power includes Bécancour for the six months ended June 30, 2007 and Anse-à-Valleau effective November 10, 2007.

Natural Gas Storage

Natural Gas Storage operating income of $18 million in second-quarter 2008 decreased $2 million compared to $20 million in second-quarter 2007. Operating income in second-quarter 2008 included $8 million after tax ($12 million pre-tax) of net unrealized gains resulting from the changes in fair value of proprietary natural gas inventory in storage and natural gas forward purchase and sale contracts. These unrealized gains were more than offset by the effects of 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 $66 million for the six months ended June 30, 2008, which included $4 million after tax ($5 million pre-tax) of net unrealized losses arising from fair value changes, was $16 million higher than the same period in 2007. The increase was primarily due to the Edson facility, which was fully operational in first-quarter 2008, but only in a commissioning phase in first-quarter 2007.

For the first six months of 2008, TransCanada excluded from Natural Gas Storage’s comparable earnings changes in fair value of proprietary natural gas inventory and forward purchase and sale contracts. 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. As a result, changes in fair value of proprietary natural gas inventory and these forward contracts do not reflect the amounts that will be realized upon settlement of the forward contracts. The natural gas storage business earns the majority of its revenues on proprietary inventories when the inventory is sold, which typically occurs during the winter withdrawal season.

Corporate

Corporate’s net income for the three months ended June 30, 2008 was $15 million compared to net expenses of $3 million for the same period in 2007. The $18-million increase in second-quarter 2008 net income was primarily due to a reduction in financial charges as a result of lower average short-term debt balances, increased capitalization of interest to finance a larger capital spending program, higher interest income on short-term intersegment financings and higher gains on derivatives used to manage the Company’s exposure to interest rate fluctuations. These increases were partially offset by lower gains

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SECOND QUARTER REPORT 2008

on derivatives used to manage the Company’s exposure to foreign exchange rate fluctuations and $12 million of favourable income tax adjustments in second-quarter 2007. Corporate's comparable expenses of $15 million in second-quarter 2007 excluded the $12 million of favourable income tax adjustments.

Corporate’s net expenses for the six months ended June 30, 2008 were $7 million compared to net income of $1 million for the same period in 2007. Excluding $27 million of favourable income tax adjustments recorded in 2007, Corporate’s comparable expenses were $7 million and $26 million for the six months ended June 30, 2008 and 2007, respectively. Corporate’s comparable expenses for the six months ended June 30, 2008 decreased due to the factors discussed above.

Liquidity and Capital Resources

At June 30, 2008, the Company held cash and cash equivalents of $1.96 billion compared to $504 million at December 31, 2007. The increase in cash and cash equivalents was due primarily to approximately $1.27 billion of gross proceeds from the issuance of common shares in second-quarter 2008.

Funds Generated from Operations
(unaudited)	Three months ended June 30					Six months ended June 30
(millions of dollars)	2008			2007		2008			2007
Cash Flows
Funds generated from operations (1)		676			596		1,598			1,178
(Increase)/decrease in operating working capital		(104	)		93		(98	)		129
Net cash provided by operations		572			689		1,500			1,307

(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 $117 million in second-quarter 2008 and increased $193 million for the first six months of 2008 compared to the same periods in 2007. Funds generated from operations were $676 million and $1.6 billion for the three and six months ended June 30, 2008, respectively, compared to $596 million and $1.2 billion for the same periods in 2007. The increases were primarily due to gains from the Calpine bankruptcy settlements and higher earnings.

The Ravenswood Generating Facility (Ravenswood) acquisition, discussed further in the Other Recent Developments section in this MD&A, is expected to be financed in a manner consistent with TransCanada’s current capital structure. TransCanada expects that both 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 remain substantially unchanged since December 31, 2007.

Investing Activities

Acquisitions, net of cash acquired, for the six months ended June 30, 2008 were $4 million compared to $4.2 billion for the same period in 2007. Acquisitions for the first six months of 2007 included TransCanada’s acquisition of ANR and an additional 3.6 per cent interest in Great Lakes for approximately 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 six months ended June 30, 2008, capital expenditures totalled $633 million (2007 - $386 million) and $1.1 billion (2007 - $692 million), respectively, and primarily related to the expansion

of the Alberta System, refurbishment and restart of Bruce A Units 1 and 2, construction of new power plants in Energy and construction of the Keystone oil pipeline.

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SECOND QUARTER REPORT 2008

Financing Activities

In the three and six months ended June 30, 2008, TransCanada retired $379 million and $773 million of long-term debt, respectively ($470 million and $795 million in the three and six months ended June 30, 2007, respectively), and issued nil and $112 million of long-term debt, respectively ($1.2 billion and $2.6 billion of long-term debt and junior subordinated notes, respectively). TransCanada’s notes payable increased $754 million and $724 million in the three and six months ended June 30, 2008, respectively, primarily due to an increase in commercial paper issued by the Company to finance general operations, compared to a decrease of $804 million and an increase of $261 million in the three and six months ended June 30, 2007, respectively.

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 replaces 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, which will be 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 and is available to fund a portion of the pending Ravenswood acquisition. No funds have been drawn on this facility at this time.

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 will be used to partially fund acquisitions and capital projects of the Company, including the acquisition of Ravenswood and the construction of Keystone, and for general corporate purposes.

In the three and six months ended June 30, 2008, TransCanada issued 1.7 million and 3.1 million common shares, respectively, under its Dividend Reinvestment and Share Purchase Plan (DRP). In accordance with the DRP, dividends were paid with common shares issued from treasury in lieu of making cash dividend payments totalling $58 million and $112 million. In the three and six months ended June 30, 2007, TransCanada issued 1.3 million common shares under its DRP, in lieu of making cash dividend payments totalling $51 million.

Dividends

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

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SECOND QUARTER REPORT 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 October 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 2007 Annual Report.

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 (CSA) 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. TransCanada is currently assessing its option to adopt IFRS as of January 1, 2011 and the impact that such a conversion 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 accounting policies under IFRS.

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

Contractual Obligations

The Company is committed to acquiring the Ravenswood power facility in New York City from National Grid plc (National Grid) for approximately US$2.8 billion plus closing adjustments, as discussed in the Other Recent Developments section of this MD&A. In addition, as at June 30, 2008, TransCanada had entered into agreements to purchase construction materials and services for the Kibby Wind and Coolidge power projects, totalling approximately $625 million. Other than these commitments, there have been no other material changes to TransCanada’s contractual obligations from December 31, 2007 to June 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.

Contingencies

On April 3, 2008, the Ontario Court of Appeal dismissed an appeal filed by the Canadian Alliance of Pipeline Landowners’ Associations (CAPLA). CAPLA filed the appeal as a result of a decision by the Ontario Superior Court in November 2006 to dismiss CAPLA’s class action lawsuit against TransCanada and Enbridge Inc. for damages alleged to have arisen from the creation of a control zone within 30 metres of a pipeline pursuant to Section 112 of the National Energy Board Act. The Ontario Court of Appeal’s decision is final and binding as CAPLA did not seek any further appeal within the time frame allowed.

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SECOND QUARTER REPORT 2008

Financial Instruments and Risk Management

Natural Gas Inventory

At June 30, 2008, $240 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 six months ended June 30, 2008 resulted in net unrealized gains of $42 million and $102 million, respectively, which were recorded as an increase to Revenues and Inventory (three and six months ended June 30, 2007 – net unrealized losses of $23 million). The net change in fair value of natural gas forward purchase and sales contracts in the three and six months ended June 30, 2008 resulted in net unrealized losses of $30 million and $107 million, respectively (three and six months ended June 30, 2007 - net unrealized gains of $19 million and $16 million, respectively), which were included in Revenues.

Net Investment in Self-Sustaining Foreign Operations

Information for the derivatives used to hedge the Company’s net investment in its foreign operations is as follows:

Derivatives Hedging Net Investment in Foreign Operations
Asset/(Liability)
(unaudited)
(millions of dollars)	June 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)		75		U.S. 1,050		77		U.S. 350
U.S. dollar forward foreign exchange contracts
(maturing 2008)		(5	)	U.S. 730		(4	)	U.S. 150
U.S. dollar options
(maturing 2008)		-		U.S. 100		3		U.S. 600

		70		U.S. 1,880		76		U.S. 1,100

(1) Fair values are equal to carrying values.

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SECOND QUARTER REPORT 2008

Derivative Financial Instruments Summary

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

June 30, 2008
(all amounts in millions unless otherwise indicated)	Power		Natural Gas		Interest

Derivative Financial Instruments Held for Trading
Fair Values(1)
Assets	$	104	$	169	$	26
Liabilities	$	(103)	$	(258)	$	(26)
Notional Values
Volumes(2)
Purchases		2,955		48		-
Sales		3,301		65		-
Canadian dollars		-		-		857
U.S. dollars		-		-	U.S. 1,150
Unrealized (losses)/gains in the period(3)
Three months ended June 30, 2008	$	(3)	$	7	$	2
Six months ended June 30, 2008	$	(5)	$	(11)	$	(2)
Realized gains/(losses) in the period(3)
Three months ended June 30, 2008	$	7	$	(20)	$	7
Six months ended June 30, 2008	$	9	$	5	$	10
Maturity dates	2008-2014		2008-2010		2008-2018

Derivative Financial Instruments in Hedging Relationships(4)(5)
Fair Values(1)
Assets	$	250	$	80	$	3
Liabilities	$	(236)	$	-	$	(17)
Notional Values
Volumes(2)
Purchases		6,126		23		-
Sales		17,727		-		-
Canadian dollars		-		-		50
U.S. dollars		-		-		U.S. 925
Realized (losses)/gains in the period(3)
Three months ended June 30, 2008	$	(37)	$	11	$	(3)
Six months ended June 30, 2008	$	(38)	$	19	$	(2)
Maturity dates	2008-2014		2008-2011		2009-2013

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

(5) Net Income for the three and six months ended June 30, 2008 included losses of $3 million and $4 million, respectively (three and six months ended June 30, 2007 - nil and $3 million gain, 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 six months ended June 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. Cash flow hedge accounting was discontinued when the anticipated transaction was not probable of occurring by the end of the originally specified time period. There were no gains or losses included in Net Income for the three and six months ended June 30, 2008 for discontinued cash flow hedges.

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SECOND 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
Unrealized gains/(losses) in the period(3)
Three months ended June 30, 2007	$	5	$	1	$	(2)
Six months ended June 30, 2007	$	9	$	(16)	$	1
Realized (losses)/gains in the period(3)
Three months ended June 30, 2007	$	(3)	$	6	$	1
Six months ended June 30, 2007	$	(8)	$	18	$	1
Maturity dates (4)	2008 - 2012		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
Realized gains/(losses) in the period(3)
Three months ended June 30, 2007	$	16	$	(1)	$	1
Six months ended June 30, 2007	$	13	$	(3)	$	1
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 $2 million (December 31, 2007 - $2 million) of interest-rate derivative financial instruments designated as fair value hedges.
(6) Net Income for the three and six months ended June 30, 2008 included losses of $3 million and $4 million, respectively (three and six months ended June 30, 2007 - nil and $3 million gain, 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 six months ended June 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. Cash flow hedge accounting was discontinued when the anticipated transaction was not probable of occurring by the end of the originally specified time period. There were no gains or losses included in Net Income for the three and six months ended June 30, 2008 for discontinued cash flow hedges.

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SECOND 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 June 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 Executive Vice-President and 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 Executive Vice-President and Chief Financial Officer concluded that the design and operation of TransCanada’s disclosure controls and procedures were effective as at June 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.

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.

Outlook

Since the disclosure in TransCanada’s 2007 Annual Report, the Company's earnings outlook is relatively unchanged except for the Calpine bankruptcy settlements, the writedown of the Broadwater LNG project costs and the anticipated effect on earnings for the recently-announced acquisition of Ravenswood, which the Company expects to close in third-quarter 2008. The Company expects Ravenswood to be modestly dilutive to TransCanada’s earnings in the first two full years of ownership based on the near-term effects of a FERC order pertaining to the New York Independent System Operator (New York City) capacity market. TransCanada expects Ravenswood’s contribution to TransCanada’s earnings to be accretive in subsequent years. The Ravenswood acquisition is discussed further in the Other Recent Developments section of this MD&A. For further information on outlook, refer to the MD&A in TransCanada’s 2007 Annual Report.

Following the announcement of the Ravenswood acquisition, Standard & Poor’s (S&P), DBRS and Moody’s Investors Service (Moody’s) conducted and completed reviews of their various TransCanada group company credit ratings. The senior unsecured debt of TCPL and its rated subsidiaries was affirmed at ‘A-’ and ‘A’ by S&P and DBRS, respectively, but lowered by Moody’s from ‘A2’ to ‘A3’. Moody’s also reduced their short-term debt rating of TCPL to ‘Prime-2 (A)’ and issuer rating of TransCanada Corporation to ‘Baa1’. All three agencies have assigned a stable outlook to their TransCanada group ratings.

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SECOND QUARTER REPORT 2008

Other Recent Developments

Pipelines

Canadian Mainline

On June 27, 2008, the NEB approved TransCanada’s application for 2008 final tolls on the Canadian Mainline, effective July 1, 2008.

Alberta System

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 is currently responding to information requests from the AUC in regard to the settlement. TransCanada expects approval of the settlement in third-quarter 2008.

On July 25, 2008, the Alberta Utilities Commission (AUC) issued a Notice of Application and Hearing Order, which details the preliminary scope and minimum filing requirements 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 set for February 23, 2009.

On June 17, 2008, TransCanada filed an application with the NEB to establish federal jurisdiction over the Alberta System. On July 18, 2008, the NEB announced it would hold an oral hearing to discuss this matter commencing November 18, 2008. A decision on the application is expected to be issued in first-quarter 2009. Currently, the provincial regulation of the Alberta System precludes TransCanada from acquiring, constructing or operating facilities that transport natural gas across Alberta provincial borders. Federal regulation would enable the Alberta System to extend across provincial borders, thereby providing integrated service to Alberta and British Columbia customers, and Northern natural gas producers.

In November 2007, TransCanada submitted an application to the Alberta Energy and Utilities Board for a permit to construct an approximately $1 billion 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 April 14, 2008, the AUC held a pre-hearing meeting with all interested parties to discuss procedural matters including scope, purpose, timing and location of the hearing. On April 24, 2008, the AUC issued a decision on the pre-hearing meeting, which established a hearing date for this application that commenced on July 28, 2008.

Keystone Oil Pipeline

In May 2008, construction began on the initial phase of the Keystone oil pipeline project in both Canada and the U.S., which will transport crude oil from Hardisty, Alberta to U.S. Midwest markets at Wood River and Patoka, Illinois. Deliveries to Wood River and Patoka are expected to commence in late 2009. Deliveries for phase two of the project, which will provide service to Cushing, Oklahoma, are expected to commence in late 2010.

On June 23, 2008, the NEB issued a decision to approve TransCanada’s application for additional pumping facilities required to expand the Canadian portion of the Keystone oil pipeline project from a nominal capacity of approximately 435,000 Bbl/d to 590,000 Bbl/d.

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On July 16, 2008, TransCanada announced plans to expand and extend the Keystone crude oil pipeline system and provide additional capacity in 2012 of 500,000 barrels per day (Bbl/d) from Western Canada to the U.S. Gulf coast, near existing terminals in Port Arthur, Texas. The expansion is expected to cost approximately US$7.0 billion and, when completed, is expected to increase the Keystone oil pipeline system from 590,000 Bbl/d to approximately 1.1 million Bbl/d and is expected to result in a total capital investment of approximately US$12.2 billion. Construction of the expansion facilities is anticipated to commence in 2010 following the receipt of the necessary regulatory approvals. Keystone has secured long-term commitments for approximately 830,000 Bbl/d for an average term of 18 years.

The Keystone project is a 50/50 partnership between TransCanada and ConocoPhillips, however, certain parties who have agreed to make volume commitments to the Keystone expansion have an option to acquire up to a combined 15 per cent equity ownership in the Keystone partnerships.

Sunstone Pipeline Project

TransCanada and Williams Companies, Inc. (Williams) continue to evaluate the development of the Sunstone pipeline project, a proposed 943-km pipeline from Wyoming to Stanfield, Oregon, with capacity of up to 1.2 billion cubic feet per day (Bcf/d). In June 2008, the joint venture concluded an open season and executed a Memorandum of Understanding with Sempra Pipelines and Storage (Sempra) whereby Sempra may acquire 25 per cent of the equity of the Sunstone pipeline and a Sempra affiliate would become a shipper on the Sunstone pipeline. Assuming Sempra’s participation, TransCanada and Williams would each hold 37.5 percent of the joint venture. The project is targeted to be placed in service in November 2011.

Pathfinder Pipeline Project

TransCanada is evaluating the development of the Pathfinder pipeline project, a proposed 1,030-km pipeline from Meeker, Colorado to the Northern Border system, with an initial capacity of 1.2 Bcf/d and an ultimate capacity of 2.0 Bcf/d. Enterprise Products Partners L.P. and Quicksilver Gas Services LP have agreed to ship a total of 500 million cubic feet per day (mmcf/d) for a 10-year term and to acquire up to an aggregate 50 percent ownership in the proposed Pathfinder pipeline project. TransCanada is currently reviewing bids received during a binding open season, for capacity on the Pathfinder pipeline, that concluded on June 27, 2008. The Pathfinder project is targeting to provide capacity exiting the U.S. Rocky Mountain Basin by the end of 2010.

Bison Pipeline Project

Northern Border is evaluating the development of the Bison pipeline project, a proposed 465-km pipeline from Dead Horse, Wyoming to the Northern Border system, with an initial capacity of 400 mmcf/d and an ultimate capacity of 660 mmcf/d. A binding open season for capacity on the Bison pipeline project concluded on May 23, 2008. Bison Pipeline Company LLC, a wholly owned subsidiary of Northern Border, is currently working to address bid contingencies. Northern Border will assess the project again once all bids have been finalized.

Portland Rate Case

On April 1, 2008, Portland filed a general rate case with the FERC proposing a rate increase of approximately six per cent, as well as other changes to its tariffs. The proposed tariffs are expected to go into effect on September 1, 2008, subject to refund, per the FERC’s Suspension Order dated May 1, 2008. The hearing is scheduled to begin on March 10, 2009.

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Alaska Pipeline Project

On July 23, 2008, TransCanada‘s application for a license to construct the Alaska pipeline project under the Alaska Gasline Inducement Act (AGIA) was approved by the Alaska House of Representatives. A positive Alaska Senate vote is a necessary condition for the issuance of the license. A vote by the Senate is anticipated by August 2, 2008. Although no other applicant met all the AGIA requirements, in April 2008, BP p.l.c. and ConocoPhillips proposed an alternative Alaska pipeline project. TransCanada continues to work with the State of Alaska and the Alaska producers to advance its Alaska pipeline project.

Energy

Ravenswood Acquisition

On March 31, 2008, TransCanada announced that a subsidiary of the Company entered into an agreement to acquire all of the outstanding membership interests of KeySpan-Ravenswood, LLC and all of the outstanding shares of KeySpan Ravenswood Services Corp. from National Grid. KeySpan-Ravenswood, LLC directly or indirectly owns or controls the 2,480-megawatt (MW) Ravenswood facility located in Queens, New York. The purchase price is approximately US$2.8 billion plus closing adjustments.

On June 18, 2008, the FERC issued an order authorizing the Company’s acquisition of Ravenswood. On May 21, 2008, the U.S. Department of Justice and the U.S. Federal Trade Commission granted the Company’s Request for Early Termination of the waiting period under the pre-merger notification rules. This acquisition remains subject to New York Public Service Commission approval and is expected to close in third-quarter 2008.

Coolidge Power Project

On May 12, 2008, TransCanada announced that the Phoenix, Arizona-based utility Salt River Project signed a 20-year PPA to secure 100 per cent of the output from TransCanada’s planned Coolidge Generating Station.

The simple-cycle natural gas-fired peaking power facility is expected to be located in Coolidge, Arizona. This project is expected to have a capital cost of approximately US$500 million and a nominal capacity of 575 MW. TransCanada has filed a Notice of Application with the Arizona Corporation Commission and is expected to file a full application for a Certificate of Environmental Compatibility in third-quarter 2008. Subject to receipt of required permits, construction is scheduled to begin in late 2009, with an expected in-service date of May 2011, in time to meet peak power demand.

Kibby

On July 9, 2008, TransCanada announced that the Kibby Wind power project received unanimous final development plan approval from the State of Maine’s Land Use Regulation Commission. Construction plans are now underway for the 132-MW wind project located in the Kibby and Skinner Townships in northwestern Franklin County, Maine. The project is expected to have a capital cost of approximately US$320 million. Pending all remaining regulatory approvals, construction is expected to begin in third-quarter 2008 and the project is expected to be fully commissioned in 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 on time and on budget. The power plant, which is 50 per cent owned by TransCanada, is currently able to provide 340 MW of electricity under long-term contract. In September 2008, the power plant is expected to return to the construction phase and is expected to be fully commissioned in combined-cycle mode in second-quarter 2009 with delivery capabilities of 550 MW of power.

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Bécancour Power Plant Temporary Suspension

On July 4, 2008, Hydro-Québec notified the Régie de l’énergie that it will exercise its option to extend the temporary suspension of all electricity generation from TransCanada’s Bécancour power plant through 2009. The extension of the temporary suspension, which is subject to the approval of the Régie de l’énergie, will result in TransCanada receiving payments under the agreement in 2009 similar to those that would have been received under the normal course of operations.

Broadwater

On June 6, 2008, Broadwater Energy, LLC (Broadwater) filed an appeal with the U.S. Secretary of Commerce related to New York State’s Department of State’s (NYSDOS) April 10, 2008 rejection of a proposal to construct the Broadwater LNG facility. Broadwater’s appeal was filed based on the view that the NYSDOS relied on improper considerations in making its determination. The appeal asks the Secretary of Commerce to override the NYSDOS determination on the grounds that the project meets the criteria for approval under the Coastal Zone Management Act and applicable regulations.

Share Information

As at June 30, 2008, TransCanada had 578 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 June 30, 2008.

Selected Quarterly Consolidated Financial Data(1)

(unaudited)	2008		2007				2006
(millions of dollars except per share amounts)	Second	First	Fourth	Third	Second	First	Fourth	Third

Revenues	2,017	2,133	2,189	2,187	2,208	2,244	2,091	1,850
Net Income	324	449	377	324	257	265	269	293
Share Statistics
Net income per share - Basic	$ 0.58	$ 0.83	$ 0.70	$ 0.60	$ 0.48	$ 0.52	$ 0.55	$ 0.60
Net income per share - Diluted	$ 0.58	$ 0.83	$ 0.70	$ 0.60	$ 0.48	$ 0.52	$ 0.54	$ 0.60
Dividend declared per common share	$ 0.36	$ 0.36	$ 0.34	$ 0.34	$ 0.34	$ 0.34	$ 0.32	$ 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.

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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:

●	Third-quarter 2006 net income included an income tax benefit of approximately $50 million as a result of the resolution of certain income tax matters with taxation authorities and changes in estimates. Energy’s net income included earnings from Bécancour, which came into service September 17, 2006.

●	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, and 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.

●

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.