EXHIBIT 13.1

TRANSCANADA CORPORATION – SECOND QUARTER 2011

QuarterlyReport to Shareholders

Management's Discussion and Analysis

Management's Discussion and Analysis (MD&A) dated July 28, 2011 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, 2011. In 2011, the Company will prepare its consolidated financial statements in accordance with Canadian generally accepted accounting principles (GAAP) as defined in Part V of the Canadian Institute of Chartered Accountants (CICA) Handbook, which is discussed further in the Changes in Accounting Policies section in this MD&A. This MD&A should also be read in conjunction with the audited Consolidated Financial Statements and notes thereto, and the MD&A contained in TransCanada's 2010 Annual Report for the year ended December 31, 2010. 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’s profile. "TransCanada" or "the Company" includes TransCanada Corporation and its subsidiaries, unless otherwise indicated. Amounts are stated in Canadian dollars unless otherwise indicated.  Abbreviations and acronyms used but not otherwise defined in this MD&A are identified in the Glossary of Terms contained in TransCanada’s 2010 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.  Forward-looking statements in this document are intended to provide TransCanada security holders and potential investors with information regarding TransCanada and its subsidiaries, including management’s assessment of TransCanada’s and its subsidiaries’ future financial and operational plans and outlook. Forward-looking statements in this document may include, among others, statements regarding the anticipated business prospects, projects and financial performance of TransCanada and its subsidiaries, expectations or projections about the future, strategies and goals for growth and expansion, expected and future cash flows, costs, schedules (including anticipated construction and completion dates), and operating and financial results, and expected impact of future commitments and contingent liabilities. 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 others, 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, capacity payments, regulatory processes and decisions, changes in environmental and other laws and regulations, competitive factors in the pipeline and energy sectors, construction and completion of capital projects, labour, equipment and material costs, access to capital markets, interest and currency exchange rates, technological developments and economic conditions in North America. By its nature, forward-looking information is subject to various risks and uncertainties, including those material risks discussed in the Financial Instruments and Risk Management section in this MD&A, 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 not to place undue reliance on this forward-looking information, which is given as of the date it is expressed in this MD&A or otherwise specified, and not to 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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SECOND QUARTER REPORT 2011

Non-GAAP Measures

TransCanada uses the measures Comparable Earnings, Comparable Earnings per Share, Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA), Comparable EBITDA, Earnings Before Interest and Taxes (EBIT), Comparable EBIT, Comparable Interest Expense, Comparable Interest Income and Other, Comparable Income Taxes and Funds Generated from Operations in this MD&A. These measures do not have any standardized meaning prescribed by GAAP. They are, therefore, considered to be non-GAAP measures and may not be comparable to similar measures presented by other entities. Management of TransCanada uses these 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. These 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.

EBITDA is an approximate measure of the Company’s pre-tax operating cash flow and is generally used to better measure performance and evaluate trends of individual assets. EBITDA comprises earnings before deducting interest and other financial charges, income taxes, depreciation and amortization, net income attributable to non-controlling interests and preferred share dividends. EBIT is a measure of the Company’s earnings from ongoing operations and is generally used to better measure performance and evaluate trends within each segment. EBIT comprises earnings before deducting interest and other financial charges, income taxes, net income attributable to non-controlling interests and preferred share dividends.

Comparable Earnings, Comparable EBITDA, Comparable EBIT, Comparable Interest Expense, Comparable Interest Income and Other, and Comparable Income Taxes comprise Net Income Attributable to Common Shares, EBITDA, EBIT, Interest Expense, Interest Income and Other, and Income Taxes Expense, respectively, adjusted for specific items that are significant but are not reflective of the Company’s underlying operations in the period. Specific items are subjective, however, management uses its judgement and informed decision-making when identifying items to be excluded in calculating these non-GAAP measures, some of which may recur. Specific items may include but are not limited to certain fair value adjustments relating to risk management activities, income tax refunds and adjustments, gains or losses on sales of assets, legal and bankruptcy settlements, and write-downs of assets and investments.

The Company engages in risk management activities to reduce its exposure to certain financial and commodity price risks by utilizing instruments such as derivatives. The risk management activities, which TransCanada excludes from Comparable Earnings, provide effective economic hedges but do not meet the specific criteria for hedge accounting treatment and, therefore, changes in their fair values are recorded in Net Income each period. The unrealized gains or losses from changes in the fair value of these derivative contracts and natural gas inventory in storage are not considered to be representative of the underlying operations in the current period or the positive margin that will be realized upon settlement. As a result, these amounts have been excluded in the determination of Comparable Earnings.

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SECOND QUARTER REPORT 2011

The tables below present a reconciliation of these non-GAAP measures to Net Income Attributable to Common Shares. Comparable Earnings per Share is calculated by dividing Comparable Earnings by the weighted average number of common shares outstanding for the period.

Funds Generated from Operations comprise Net Cash Provided by Operations before changes in operating working capital and allows management to better measure consolidated operating cash flow, excluding fluctuations from working capital balances which may not necessarily be reflective of underlying operations in the same period. A reconciliation of Funds Generated from Operations to Net Cash Provided by Operations is presented in the Funds Generated from Operations table in the Liquidity and Capital Resources section in this MD&A.

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SECOND QUARTER REPORT 2011

Reconciliation of Non-GAAP Measures

For the three months
ended June 30 (unaudited)	Natural Gas Pipelines						Oil Pipelines					Energy						Corporate						Total
(millions of dollars)	2011			2010			2011			2010		2011			2010			2011			2010			2011			2010
Comparable EBITDA		711			696			153			-		290			254			(15	)		(22	)		1,139			928
Depreciation and amortization		(244	)		(251	)		(34	)		-		(97	)		(90	)		(4	)		-			(379	)		(341	)
Comparable EBIT		467			445			119			-		193			164			(19	)		(22	)		760			587
Other Income Statement Items
Comparable interest expense																									(236	)		(187	)
Interest expense of joint ventures																									(11	)		(15	)
Comparable interest income and other																									26			(18	)
Comparable income taxes																									(140	)		(60	)
Net income attributable to non-controlling interests																									(28	)		(22	)
Preferred share dividends																									(14	)		(10	)
Comparable Earnings																									357			275
Specific item (net of tax):
Risk management activities(1)																									(4	)		10
Net Income Attributable to Common Shares																									353			285

For the three months ended June 30
(unaudited)(millions of dollars except per share amounts)	2011			2010
Comparable Interest Expense		(236	)		(187	)
Specific item:
Risk management activities(1)		1			-
Interest Expense		(235	)		(187	)
Comparable Interest Income and Other		26			(18	)
Specific item:
Risk management activities(1)		(3	)		-
Interest Income and Other		23			(18	)
Comparable Income Taxes		(140	)		(60	)
Specific item:
Income taxes attributable to risk management activities(1)		1			(5	)
Income Taxes Expense		(139	)		(65	)
Comparable Earnings per Share		$0.51			$0.40
Specific items (net of tax):
Risk management activities		(0.01	)		0.01
Net Income per Share		$0.50			$0.41

(1)	For the three months ended June 30
	(unaudited)(millions of dollars)	2011		2010
	Risk Management Activities Gains/(Losses):
	U.S. Power derivatives	1		9
	Natural Gas Storage proprietary inventory and derivatives	(4	)	6
	Interest rate derivatives	1		-
	Foreign exchange derivatives	(3	)	-
	Income taxes attributable to risk management activities	1		(5	)
	Risk Management Activities	(4	)	10

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SECOND QUARTER REPORT 2011

For the six months
ended June 30 (unaudited)	Natural Gas Pipelines						Oil Pipelines					Energy						Corporate						Total
(millions of dollars)	2011			2010			2011			2010		2011			2010			2011			2010			2011			2010
Comparable EBITDA		1,507			1,464			252			-		644			513			(39	)		(48	)		2,364			1,929
Depreciation and amortization		(488	)		(504	)		(57	)		-		(197	)		(180	)		(7	)		-			(749	)		(684	)
Comparable EBIT		1,019			960			195			-		447			333			(46	)		(48	)		1,615			1,245
Other Income Statement Items
Comparable interest expense																									(446	)		(369	)
Interest expense of joint ventures																									(27	)		(31	)
Comparable interest income and other																									57			6
Comparable income taxes																									(325	)		(178	)
Net income attributable to non-controlling interests																									(64	)		(53	)
Preferred share dividends																									(28	)		(17	)
Comparable Earnings																									782			603
Specific item (net of tax):
Risk management activities(1)																									(14	)		(22	)
Net Income Attributable to Common Shares																									768			581

For the six months ended June 30
(unaudited)(millions of dollars except per share amounts)	2011			2010
Comparable Interest Expense		(446	)		(369	)
Specific item:
Risk management activities(1)		-			-
Interest Expense		(446	)		(369	)
Comparable Interest Income and Other		57			6
Specific item:
Risk management activities(1)		(1	)		-
Interest Income and Other		56			6
Comparable Income Taxes		(325	)		(178	)
Specific item:
Income taxes attributable to risk management activities(1)		8			12
Income Taxes Expense		(317	)		(166	)
Comparable Earnings per Share		$1.12			$0.87
Specific items (net of tax):
Risk management activities		(0.02	)		(0.03	)
Net Income per Share		$1.10			$0.84

(1)	For the six months ended June 30
	(unaudited)(millions of dollars)	2011		2010
	Risk Management Activities (Losses)/Gains:
	U.S. Power derivatives	(12	)	(19	)
	Natural Gas Storage proprietary inventory and derivatives	(9	)	(15	)
	Foreign exchange derivatives	(1	)	-
	Income taxes attributable to risk management activities	8		12
	Risk Management Activities	(14	)	(22	)

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SECOND QUARTER REPORT 2011

Consolidated Results of Operations

TransCanada’s Net Income Attributable to Controlling Interests in second quarter 2011 was $367 million and Net Income Attributable to Common Shares was $353 million or $0.50 per share compared to $295 million and $285 million or $0.41 per share, respectively, in second quarter 2010.

Comparable Earnings in second quarter 2011 were $357 million or $0.51 per share compared to $275 million or $0.40 per share for the same period in 2010. Comparable Earnings in second quarter 2011 excluded net unrealized after-tax losses of $4 million ($5 million pre-tax) (2010 – gains of $10 million after tax ($15 million pre-tax)) resulting from changes in the fair value of certain risk management activities.

Comparable Earnings increased $82 million or $0.11 per share in second quarter 2011 compared to the same period in 2010 and reflected the following:

·   increased Natural Gas Pipelines Comparable EBIT primarily due to higher earnings from ANR and the Alberta System, and incremental earnings from Bison and Guadalajara which were placed in service in January 2011 and June 2011, respectively, partially offset by the negative impact of a weaker U.S. dollar on U.S. operations and increased operations, maintenance and administrative (OM&A) costs;

·   Oil Pipelines Comparable EBIT as the Company commenced recording earnings from Keystone in first quarter 2011;

·   increased Energy Comparable EBIT primarily due to higher volumes and realized prices at Bruce A, incremental earnings from the start-up of Halton Hills in September 2010 and Coolidge in May 2011, and higher capacity payments and realized prices in U.S. Power, partially offset by lower prices for Western Power and lower volumes and realized prices at Bruce B;

·   increased Comparable Interest Expense primarily due to decreased capitalized interest for Keystone and Halton Hills, and incremental interest expense on new debt issues in 2010, partially offset by realized gains in second quarter 2011 compared to losses in second quarter 2010 on derivatives used to manage the Company’s exposure to fluctuating interest rates, and the positive impact of a weaker U.S. dollar on U.S. dollar-denominated interest expense;

·   increased Comparable Interest Income and Other, which included realized gains in second quarter 2011 compared to losses in second quarter 2010 on derivatives used to manage the Company’s exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income; and

·   increased Comparable Income Taxes primarily due to higher pre-tax earnings in second quarter 2011 compared to second quarter 2010 and higher positive income tax adjustments in second quarter 2010.

TransCanada’s Net Income Attributable to Controlling Interests in the first six months of 2011 was $796 million and Net Income Attributable to Common Shares was $768 million or $1.10 per share compared to $598 million and $581 million or $0.84 per share, respectively, for the same period in 2010.

Comparable Earnings in the first six months of 2011 were $782 million or $1.12 per share compared to $603 million or $0.87 per share for the same period in 2010. Comparable Earnings for the first six months of 2011 excluded net unrealized after-tax losses of $14 million ($22 million pre-tax) (2010 – after-tax losses of $22 million ($34 million pre-tax)) resulting from changes in the fair value of certain risk management activities.

Comparable Earnings increased $179 million or $0.25 per share in the first six months of 2011 compared to the same period in 2010 and reflected the following:

·   increased EBIT from Natural Gas Pipelines primarily due to incremental earnings from Bison and Guadalajara, which were placed in service in January 2011 and June 2011, respectively, higher earnings from the Alberta System and reduced business development costs relating to the Alaska Pipeline Project, partially offset by the negative impact of a weaker U.S. dollar and increased OM&A costs;  

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SECOND QUARTER REPORT 2011

·   Oil Pipelines Comparable EBIT as the Company commenced recording earnings from Keystone in first quarter 2011;

·   increased EBIT from Energy primarily due to higher volumes and lower operating expenses due to reduced outage days, and higher realized prices at Bruce A, higher overall realized prices at Western Power, incremental earnings from the start-up of Halton Hills in September 2010, Coolidge in May 2011 and Kibby Wind in October 2011, and higher revenues from U.S. Power, partially offset by lower realized prices and reduced volumes at Bruce B, and decreased proprietary and third-party storage revenues for Natural Gas Storage;

·   increased Comparable Interest Expense primarily due to decreased capitalized interest for Keystone and Halton Hills, and incremental interest expense on new debt issues in 2010, partially offset by realized gains in 2011 compared to losses in 2010 on derivatives used to manage the Company’s exposure to fluctuating interest rates, the positive impact of a weaker U.S. dollar on U.S. dollar-denominated interest expense and Canadian debt maturities in 2011 and 2010;

·   increased Comparable Interest Income and Other, which included realized gains in 2011 compared to losses in 2010 on derivatives used to manage the Company’s exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income;

·   increased Comparable Income Taxes primarily due to higher pre-tax earnings in 2011 compared to 2010 and higher positive income tax adjustments in 2010; and

·   increased Preferred Share Dividends due to new preferred share issues in 2010.

Further discussion of the significant financial results in the first three and six months in 2011 is included in the Natural Gas Pipelines, Oil Pipelines, Energy and Other Income Statement Items sections in this MD&A.

U.S. Dollar-Denominated Balances

On a consolidated basis, the impact of changes in the value of the U.S. dollar on U.S. operations is partially offset by other U.S. dollar-denominated items as set out in the following table. The resultant pre-tax net exposure is managed using derivatives, further reducing the Company’s exposure to changes in Canadian-U.S. foreign exchange rates. The average U.S. dollar to Canadian dollar exchange rate for the three and six months ended June 30, 2011 was 0.97 and 0.98, respectively (2010 – 1.03 and 1.03, respectively).

Summary of Significant U.S. Dollar-Denominated Amounts

(unaudited)	Three months ended June 30				Six months ended June 30
(millions of U.S. dollars, pre-tax)	2011		2010		2011		2010
U.S. Natural Gas Pipelines Comparable EBIT(1)	175		147		424		373
U.S. Oil Pipelines Comparable EBIT(1)	81		-		132		-
U.S. Power Comparable EBIT(1)	65		42		97		81
Interest on U.S. dollar-denominated long-term debt	(180	)	(163	)	(362	)	(322	)
Capitalized interest on U.S capital expenditures	25		65		72		133
U.S. non-controlling interests and other	(44	)	(36	)	(95	)	(81	)
	122		55		268		184

(1)   Refer to the Non-GAAP Measures section in this MD&A for further discussion of Comparable EBIT.

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Natural Gas Pipelines

Natural Gas Pipelines’ Comparable EBIT was $467 million and $1.0 billion in the three and six months ended June 30, 2011, respectively, compared to $445 million and $960 million, respectively, for the same periods in 2010.

Natural Gas Pipelines Results

(unaudited)	Three months ended June 30				Six months ended June 30
(millions of dollars)	2011		2010		2011		2010
Canadian Natural Gas Pipelines
Canadian Mainline	267		263		532		528
Alberta System	181		176		366		351
Foothills	32		35		65		68
Other (TQM, Ventures LP)	13		14		25		27
Canadian Natural Gas Pipelines Comparable EBITDA(1)	493		488		988		974
Depreciation and amortization	(181	)	(185	)	(361	)	(368	)
Canadian Natural Gas Pipelines Comparable EBIT(1)	312		303		627		606
U.S. Natural Gas Pipelines (in U.S. dollars)
ANR	70		59		181		174
GTN(2)	31		40		76		83
Great Lakes(3)	25		25		55		57
PipeLines LP(4)(5)	23		22		50		47
Iroquois	16		17		35		35
Bison(2)(6)	14		-		27		-
Portland(5)(7)	3		1		13		11
International (Tamazunchale, Guadalajara TransGas, Gas Pacifico/INNERGY)(8)	15		14		25		24
General, administrative and support costs(9)	(2	)	(3	)	(4	)	(9	)
Non-controlling interests(5)	46		36		96		82
U.S. Natural Gas Pipelines Comparable EBITDA(1)	241		211		554		504
Depreciation and amortization	(66	)	(64	)	(130	)	(131	)
U.S. Natural Gas Pipelines Comparable EBIT(1)	175		147		424		373
Foreign exchange	(5	)	5		(9	)	14
U.S. Natural Gas Pipelines Comparable EBIT(1)(in Canadian dollars)	170		152		415		387
Natural Gas Pipelines Business Development Comparable EBITDA(1)	(15	)	(10	)	(23	)	(33	)
Natural Gas Pipelines Comparable EBIT(1)	467		445		1,019		960
Summary:
Natural Gas Pipelines Comparable EBITDA(1)	711		696		1,507		1,464
Depreciation and amortization	(244	)	(251	)	(488	)	(504	)
Natural Gas Pipelines Comparable EBIT(1)	467		445		1,019		960

(1)   Refer to the Non-GAAP Measures section in this MD&A for further discussion of Comparable EBITDA and Comparable EBIT.

(2)   Results reflect TransCanada’s direct ownership interest of 75 per cent effective May 3, 2011 and 100 per cent prior to that date.

(3)   Represents the Company’s 53.6 per cent direct ownership interest.

(4)   Effective May 3, 2011, TransCanada’s ownership interest in PipeLines LP decreased from 38.2 per cent to 33.3 per cent.  As a result, PipeLines LP’s results include TransCanada’s decreased ownership in PipeLines LP and TransCanada’s effective ownership through PipeLines LP of 8.3 per cent of each of GTN and Bison since May 3, 2011.

(5)   Non-Controlling Interests reflects Comparable EBITDA for the portions of PipeLines LP and Portland not owned by TransCanada.

(6)   Includes Bison’s operations since January 2011.

(7)   Represents the Company’s 61.7 per cent ownership interest.

(8)   Includes Guadalajara’s operations since June 15, 2011.

(9)   Represents General, Administrative and Support Costs associated with certain of the Company’s pipelines.

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Net Income for Wholly Owned Canadian Natural Gas Pipelines

(unaudited)	Three months ended June 30		Six months ended June 30
(millions of dollars)	2011	2010	2011	2010
Canadian Mainline	63	64	125	130
Alberta System	50	37	98	75
Foothills	6	7	12	13

Canadian Natural Gas Pipelines

Canadian Mainline’s net income for the three and six months ended June 30, 2011 decreased $1 million and $5 million, respectively, compared to the same periods in 2010 primarily due to a lower rate of return on common equity (ROE), as determined by the National Energy Board (NEB), of 8.08 per cent in 2011 compared to 8.52 per cent in 2010, as well as a lower average investment base. The impact of the lower ROE and average investment base was partially offset by higher incentive earnings in 2011.

Canadian Mainline’s Comparable EBITDA for the three and six months ended June 30, 2011 of $267 million and $532 million, respectively, increased $4 million compared to each of the same periods in 2010. An increase in revenues as a result of higher incentive earnings and higher flow-through costs was partially offset by a lower overall return, associated with the reduced ROE and financial charges, on a reduced average investment base. The flow-through costs do not impact net income and increased primarily due to higher income taxes.

The Alberta System’s net income was $50 million in second quarter 2011 and $98 million for the first six months of 2011 compared to $37 million and $75 million for the same periods in 2010. The increases reflect an ROE of 9.70 per cent on 40 per cent deemed common equity approved by the NEB in September 2010 as part of the Company's 2010 - 2012 Revenue Requirement Settlement application. Net income in 2010 reflected an ROE of 8.75 per cent on 35 per cent deemed common equity.

The Alberta System’s Comparable EBITDA was $181 million in second quarter 2011 and $366 million for the first six months of 2011 compared to $176 million and $351 million for the same periods in 2010. The increases were primarily due to the increased ROE included in the 2010 - 2012 Revenue Requirement Settlement.

U.S. Natural Gas Pipelines

ANR’s Comparable EBITDA for the three and six months ended June 30, 2011 was US$70 million and US$181 million, respectively, compared toUS$59 million and US$174 million for the same periods in 2010. The increases were primarily due to higher transportation and storage revenues, a settlement with a counterparty and increased incidental commodity sales, partially offset by higher OM&A costs.

GTN’s Comparable EBITDA for the three and six months ended June 30, 2011 was US$31 million and US$76 million, respectively, compared to US$40 million and US$83 million for the same periods in 2010. The decreases were primarily due to TransCanada’s sale of 25 per cent of GTN to PipeLines LP in May 2011.

The Bison pipeline was placed in service in January 2011. TransCanada’s portion of Comparable EBITDA was US$14 million and US$27 million for the three and six months ended June 30, 2011, respectively. EBIDTA reflects TransCanada’s sale of 25 per cent of Bison to PipeLines LP in May 2011.

Comparable EBITDA for the remainder of the U.S. Natural Gas Pipelines was US$157 million and US$346 million for the three and six months ended June 30, 2011, respectively, compared to US$152 million and US$333 million for the same periods in 2010. The increases were primarily due to higher revenues for Northern Border, lower general, administrative and support costs, and incremental earnings from the Guadalajara pipeline which was placed in service on June 15, 2011.

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Depreciation

Natural Gas Pipelines’ depreciation decreased $7 million and $16 million for the three and six months ended June 30, 2011, respectively, compared to the same periods in 2010. The decreases were primarily due to lower depreciation rates included in the Great Lakes and Alberta System rate settlements, and the effect of a weaker U.S. dollar on U.S. asset depreciation, partially offset by incremental depreciation for Bison.

Business Development

Natural Gas Pipelines’ Business Development Comparable EBITDA loss increased $5 million and decreased $10 million in the three and six months ended June 30, 2011, respectively, compared to the same periods in 2010. Business development costs increased in second quarter 2011 compared to second quarter 2010 primarily due to greater activity in 2011 for the Alaska Pipeline Project, partially offset by a 90 per cent reimbursement by the State of Alaska for eligible project costs effective July 31, 2010 versus a 50 per cent reimbursement prior to this date. Business development costs in the first six months of 2011 were lower primarily due to the increased reimbursement by the State of Alaska. Project applicable expenses and reimbursements are shared proportionately with ExxonMobil, TransCanada’s joint venture partner in the Alaska Pipeline Project. The decrease in business development costs in the first six months of 2011 was partially offset by a levy charged by the NEB in March 2011 to recover the Aboriginal Pipeline Group’s proportionate share of costs relating to the Mackenzie Gas Project hearings.

Operating Statistics

Six months ended June 30	Canadian Mainline(1)				Alberta System(2)				Foothills				ANR(3)
(unaudited)	2011		2010		2011		2010		2011		2010		2011		2010
Average investment base (millions of dollars)		6,328		6,572		4,993		4,975		617		666		n/a		n/a
Delivery volumes (Bcf)
Total		1,059		844		1,788		1,723		630		680		870		795
Average per day		5.9		4.7		9.9		9.5		3.5		3.8		4.8		4.4

(1)   Canadian Mainline’s throughput volumes in the above table reflect physical deliveries to domestic and export markets. Canadian Mainline’s physical receipts originating at the Alberta border and in Saskatchewan for the six months ended June 30, 2011 were 643 billion cubic feet (Bcf) (2010 – 645 Bcf); average per day was 3.6 Bcf (2010 – 3.6 Bcf).

(2)   Field receipt volumes for the Alberta System for the six months ended June 30, 2011 were 1,733 Bcf (2010 – 1,740 Bcf); average per day was 9.6 Bcf (2010 – 9.6 Bcf).

(3)   ANR’s results are not impacted by average investment base as these systems operate under fixed-rate models approved by the U.S. Federal Energy Regulatory Commission.

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SECOND QUARTER REPORT 2011

Oil Pipelines

In the three and five months ended June 30, 2011, the Company recorded $119 million and $195 million, respectively, of Comparable EBIT related to the Oil Pipelines segment. In late January 2011, work was completed to allow Keystone to increase its operating pressure following the NEB’s decision to remove the maximum operating pressure restriction along the conversion section of the system in December 2010. At the beginning of February 2011, the Company commenced recording EBITDA for the Wood River/Patoka section of Keystone and for the Cushing Extension, which was placed in service at that time.

Oil Pipelines Results

For the period February 1 to June 30	Three months ended June 30		Five months ended June 30
(unaudited)(millions of dollars)	2011		2011
Canadian Oil Pipelines Comparable EBITDA(1)	55		90
Depreciation and amortization	(13	)	(22	)
Canadian Oil Pipelines Comparable EBIT(1)	42		68
U.S. Oil Pipelines Comparable EBITDA(1) (in U.S. dollars)	103		168
Depreciation and amortization	(22	)	(36	)
U.S. Oil Pipelines Comparable EBIT(1)	81		132
Foreign exchange	(3	)	(4	)
U.S. Oil Pipelines Comparable EBIT(1)(in Canadian dollars)	78		128
Oil Pipelines Business Development Comparable EBITDA(1)	(1	)	(1	)
Oil Pipelines Comparable EBIT(1)	119		195
Summary:
Oil Pipelines Comparable EBITDA(1)	153		252
Depreciation and amortization	(34	)	(57	)
Oil Pipelines Comparable EBIT(1)	119		195

(1)   Refer to the Non-GAAP Measures section in this MD&A for further discussion of Comparable EBITDA and Comparable EBIT.

Operating Statistics

For the period February 1 to June 30	Three months ended June 30	Five months ended June 30
(unaudited)	2011	2011
Delivery volumes(thousands of barrels)(1)
Total	30,167	52,633
Average per day	332	351

(1)   Delivery volumes reflect physical deliveries.

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SECOND QUARTER REPORT 2011

Energy

Energy’s Comparable EBIT was $193 million and $447 million for the three and six months ended June 30, 2011, respectively, compared to $164 million and $333 million, respectively, for the same periods in 2010.

Energy Results

(unaudited)	Three months ended June 30							Six months ended June 30
(millions of dollars)		2011			2010				2011			2010
Canadian Power
Western Power(1)			74			85				194			127
Eastern Power(2)			71			46				151			98
Bruce Power			56			47				133			110
General, administrative and support costs			(9	)		(5	)			(17	)		(15	)
Canadian Power Comparable EBITDA(3)			192			173				461			320
Depreciation and amortization			(69	)		(58	)			(136	)		(118	)
Canadian Power Comparable EBIT(3)			123			115				325			202
U.S. Power (in U.S. dollars)
Northeast Power(4)			99			78				170			151
General, administrative and support costs			(10	)		(9	)			(19	)		(18	)
U.S. Power Comparable EBITDA(3)			89			69				151			133
Depreciation and amortization			(24	)		(27	)			(54	)		(52	)
U.S. Power Comparable EBIT(3)			65			42				97			81
Foreign exchange			(3	)		2				(3	)		3
U.S. Power Comparable EBIT(3)(in Canadian dollars)			62			44				94			84
Natural Gas Storage
Alberta Storage			21			20				52			73
General, administrative and support costs			(3	)		(2	)			(5	)		(4	)
Natural Gas Storage Comparable EBITDA(3)			18			18				47			69
Depreciation and amortization			(4	)		(4	)			(8	)		(8	)
Natural Gas Storage Comparable EBIT(3)			14			14				39			61
Energy Business Development Comparable EBITDA(3)			(6	)		(9	)			(11	)		(14	)
Energy Comparable EBIT(3)			193			164				447			333
Summary:
Energy Comparable EBITDA(3)			290			254				644			513
Depreciation and amortization			(97	)		(90	)			(197	)		(180	)
Energy Comparable EBIT(3)			193			164				447			333

(1)   Includes Coolidge effective May 2011.

(2)   Includes Halton Hills effective September 2010.

(3)   Refer to the Non-GAAP Measures section in this MD&A for further discussion of Comparable EBITDA and Comparable EBIT.

(4)   Includes phase two of Kibby Wind effective October 2010.

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SECOND QUARTER REPORT 2011

Canadian Power

Western and Eastern Canadian Power Comparable EBIT(1)(2)

(unaudited)	Three months ended June 30							Six months ended June 30
(millions of dollars)		2011			2010				2011			2010
Revenues
Western power			182			202				461			366
Eastern power			113			65				231			132
Other(3)			18			15				41			37
			313			282				733			535
Commodity Purchases Resold
Western power			(101	)		(99	)			(244	)		(205	)
Other(4)			(4	)		(7	)			(9	)		(12	)
			(105	)		(106	)			(253	)		(217	)
Plant operating costs and other			(63	)		(45	)			(135	)		(93	)
General, administrative and support costs			(9	)		(5	)			(17	)		(15	)
Comparable EBITDA(1)			136			126				328			210
Depreciation and amortization			(41	)		(32	)			(80	)		(69	)
Comparable EBIT(1)			95			94				248			141

(1)   Refer to the Non-GAAP Measures section in this MD&A for further discussion of Comparable EBITDA and Comparable EBIT.

(2)   Includes Coolidge and Halton Hills effective May 2011 and September 2010, respectively.

(3)   Includes sales of excess natural gas purchased for generation and thermal carbon black. The realized gains and losses from derivatives used to purchase and sell natural gas to manage Western and Eastern Power’s assets are presented on a net basis in Other Revenues.

(4)   Includes the cost of excess natural gas not used in operations.

Western and Eastern Canadian Power Operating Statistics

	Three months ended June 30		Six months ended June 30
(unaudited)	2011	2010	2011	2010
Sales Volumes (GWh)
Supply
Generation
Western Power(1)	626	594	1,307	1,179
Eastern Power(2)	770	395	1,848	824
Purchased
Sundance A & B and Sheerness PPAs(3)	1,855	2,459	3,960	5,114
Other purchases	174	73	376	222
	3,425	3,521	7,491	7,339
Sales
Contracted
Western Power(1)	2,038	2,573	4,307	4,842
Eastern Power(2)	770	395	1,848	840
Spot
Western Power	617	553	1,336	1,657
	3,425	3,521	7,491	7,339
Plant Availability(4)
Western Power(1)(5)	97%	94%	97%	94%
Eastern Power(2)(6)	92%	97%	95%	97%

(1)   Includes Coolidge effective May 2011.

(2)   Includes Halton Hills effective September 2010.

(3)   No volumes were delivered under the Sundance A PPA in 2011.

(4)   Plant availability represents the percentage of time in a period that the plant is available to generate power regardless of whether it is running.

(5)   Excludes facilities that provide power to TransCanada under PPAs.

(6)   Bécancour has been excluded from the availability calculation as power generation has been suspended since 2008.

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SECOND QUARTER REPORT 2011

Western Power’s Comparable EBITDA of $74 million and Power Revenues of $182 million in second quarter 2011 decreased $11 million and $20 million, respectively, compared to the same period in 2010, primarily due to lower realized power prices in Alberta, partially offset by incremental earnings from Coolidge, which went into service under a 20-year power purchase arrangement (PPA) in May 2011.  Average spot market power prices in Alberta decreased 35 per cent to $52 per megawatt hour (MWh) in second quarter 2011 compared to $80 per MWh in second quarter 2010 when certain unplanned plant and transmission outages resulted in significantly higher spot prices.

Western Power’s Comparable EBITDA of $194 million and Power Revenues of $461 million in the first six months of 2011 increased $67 million and $95 million, respectively, compared to the same period in 2010 primarily due to higher overall realized prices and incremental earnings from Coolidge.  

Western Power’s Comparable EBITDA in the three and six months ended June 30, 2011 included $12 million and $51 million, respectively, of accrued earnings from the Sundance A PPA, the revenues and costs of which have been recorded as though Sundance A Units 1 and 2 were on normal plant outages. Refer to the Recent Developments section in this MD&A for further discussion regarding the Sundance A outage.

Western Power’s Commodity Purchases Resold increased $39 million for the six months ended June 30, 2011 compared to the same period in 2010 primarily due to higher volumes at Sheerness and increased retail contracts.

Eastern Power’s Comparable EBITDA of $71 million and $151 million for the three and six months ended June 30, 2011, respectively, increased $25 million and $53 million, respectively, compared to the same periods in 2010. Power Revenues of $113 million and $231 million for the three and six months ended June 30, 2011, respectively, increased $48 million and $99 million, respectively, compared to the same periods in 2010. The increases were primarily due to incremental earnings from Halton Hills, which went into service in September 2010.

Plant Operating Costs and Other of $63 million and $135 million for the three and six months ended June 30, 2011, respectively, which includes fuel gas consumed in power generation, increased $18 million and $42 million, respectively, compared to the same periods in 2010 primarily due to incremental fuel consumed at Halton Hills.

Depreciation and amortization increased $9 million and $11 million for the three and six months ended June 30, 2011, respectively, compared to the same periods in 2010 primarily due to incremental depreciation from Halton Hills and Coolidge.

Western Power manages the sale of its supply volumes on a portfolio basis. A portion of its supply is sold into the spot market to assure supply in the event of an unexpected plant outage. The overall amount of spot market volumes sold is dependent upon the ability to transact in forward sales markets at acceptable contract terms. This approach to portfolio management helps to minimize costs in situations where Western Power would otherwise have to purchase electricity in the open market to fulfill its contractual sales obligations. Approximately 77 per cent of Western Power sales volumes were sold under contract in second quarter 2011, compared to 82 per cent in second quarter 2010. To reduce its exposure to spot market prices on uncontracted volumes, as at June 30, 2011, Western Power had entered into fixed-price power sales contracts to sell approximately 4,600 gigawatt hours (GWh) for the remainder of 2011 and 7,500 GWh for 2012.

Eastern Power is focused on selling power under long-term contracts. In second quarter 2011 and 2010, 100 per cent of Eastern Power’s sales volumes were sold under contract and are expected to continue to be 100 per cent sold under contract for the remainder of 2011 and in 2012.

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SECOND QUARTER REPORT 2011

Bruce Power Results

(TransCanada’s proportionate share) (unaudited)	Three months ended June 30						Six months ended June 30
(millions of dollars unless otherwise indicated)	2011			2010			2011			2010
Revenues(1)		202			197			415			422
Operating Expenses		(146	)		(150	)		(282	)		(312	)
Comparable EBITDA(2)		56			47			133			110
Bruce A Comparable EBITDA(2)		32			10			66			23
Bruce B Comparable EBITDA(2)		24			37			67			87
Comparable EBITDA(2)		56			47			133			110
Depreciation and amortization		(28	)		(26	)		(56	)		(49	)
Comparable EBIT(2)		28			21			77			61
Bruce Power – Other Information
Plant availability
Bruce A		97	%		72	%		98	%		69	%
Bruce B		80	%		86	%		86	%		92	%
Combined Bruce Power		85	%		82	%		89	%		85	%
Planned outage days
Bruce A		8			25			8			60
Bruce B		49			47			70			47
Unplanned outage days
Bruce A		5			22			9			48
Bruce B		19			-			27			6
Sales volumes (GWh)
Bruce A		1,436			1,121			2,936			2,110
Bruce B		1,760			1,944			3,792			4,099
		3,196			3,065			6,728			6,209
Results per MWh
Bruce A power revenues		$66			$65			$66			$64
Bruce B power revenues(3)		$55			$59			$54			$58
Combined Bruce Power revenues		$59			$60			$58			$60

(1)   Revenues include Bruce A’s fuel cost recoveries of $7 million and $15 million for the three and six months ended June 30, 2011, respectively (2010 – $9 million and $14 million).

(2)   Refer to the Non-GAAP Measures section in this MD&A for further discussion of Comparable EBITDA and Comparable EBIT.

(3)   Includes revenues received under the floor price mechanism, from deemed generation, including the associated volumes, and from contract settlements.

TransCanada’s proportionate share of Bruce A’s Comparable EBITDA for the three and six months ended June 30, 2011 of $32 million and $66 million, respectively, increased from $10 million and $23 million, respectively, in the same periods in 2010 as a result of higher volumes and lower operating expenses due to lower planned and unplanned outage days.  Results for the six months ended June 30, 2010 included a payment made from Bruce B to Bruce A regarding 2009 amendments to a long-term agreement with the Ontario Power Authority (OPA). The net positive impact reflected TransCanada’s higher percentage ownership interest in Bruce A.  

TransCanada’s proportionate share of Bruce B’s Comparable EBITDA for the three and six months ended June 30, 2011 of $24 million and $67 million, respectively, decreased from $37 million and $87 million, respectively, in the same periods in 2010 primarily due to lower volumes and higher operating costs due to increased outage days, as well as lower realized prices resulting from the expiration of fixed-price contracts at higher prices. Results for the six months ended June 30, 2010 included the above-noted payment in first quarter 2010 to Bruce A.

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SECOND QUARTER REPORT 2011

Under a contract with the OPA, all output from Bruce A in second quarter 2011 was sold at a fixed price of $66.33 per MWh (before recovery of fuel costs from the OPA) compared to $64.71 per MWh in second quarter 2010. Also under a contract with the OPA, all output from the Bruce B units was subject to a floor price of $50.18 per MWh in second quarter 2011 compared to $48.96 per MWh in second quarter 2010. Both the Bruce A and Bruce B contract prices are adjusted annually for inflation on April 1.  

Amounts received under the Bruce B floor price mechanism within a calendar year are subject to repayment if the monthly average spot price exceeds the floor price. With respect to 2011, TransCanada currently expects spot prices to be less than the floor price for the remainder of the year, therefore no amounts recorded in revenues in the first six months of 2011 are expected to be repaid.

Bruce B enters into fixed-price contracts whereby Bruce B receives or pays the difference between the contract price and the spot price. Bruce B’s realized price decreased to $55 per MWh and $54 per MWh for the three and six months ended June 30, 2011, respectively, a decrease of $4 per MWh from each of the same periods in 2010, and reflected revenues recognized from both the floor price mechanism and contract sales.  The decreases were a result of the majority of higher-priced contracts entered into in previous years having expired by the end of December 2010. As the remainder of these higher-priced contracts continue to expire, a further reduction in realized prices at Bruce B in future periods is expected.

The overall plant availability percentage in 2011 is expected to be in the mid-80s for the two operating Bruce A units and in the mid-80s for the four Bruce B units. Bruce B commenced an approximately three week outage on Unit 6 in late July 2011.  For further information on Bruce Power’s planned maintenance outages, refer to the MD&A in TransCanada’s 2010 Annual Report.

As at June 30, 2011, Bruce A had incurred approximately $4.4billion in costs for the refurbishment and restart of Units 1 and 2, and approximately $0.3 billion for the refurbishment of Units 3 and 4.

U.S. Power Comparable EBIT(1)(2)

(unaudited)	Three months ended June 30				Six months ended June 30
(millions of U.S. dollars)	2011		2010		2011		2010
Revenues
Power(3)	224		237		479		469
Capacity	74		66		113		106
Other(4)	13		15		43		40
	311		318		635		615
Commodity purchases resold	(84	)	(112	)	(215	)	(248	)
Plant operating costs and other(4)	(128	)	(128	)	(250	)	(216	)
General, administrative and support costs	(10	)	(9	)	(19	)	(18	)
Comparable EBITDA(1)	89		69		151		133
Depreciation and amortization	(24	)	(27	)	(54	)	(52	)
Comparable EBIT(1)	65		42		97		81

(1)   Refer to the Non-GAAP Measures section in this MD&A for further discussion of Comparable EBITDA and Comparable EBIT.

(2)   Includes phase two of Kibby Wind effective October 2010.

(3)   The realized gains and losses from financial derivatives used to purchase and sell power, natural gas and fuel oil to manage U.S. Power’s assets are presented on a net basis in Power Revenues.

(4)   Includes revenues and costs related to a third-party service agreement at Ravenswood.

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SECOND QUARTER REPORT 2011

U.S. Power Operating Statistics(1)

	Three months ended June 30		Six months ended June 30
(unaudited)	2011	2010	2011	2010
Physical Sales Volumes (GWh)
Supply
Generation	1,941	1,789	3,232	2,680
Purchased	1,181	2,061	3,120	4,547
	3,122	3,850	6,352	7,227
Plant Availability(2)(3)	86%	92%	84%	89%

(1)   Includes phase two of Kibby Wind effective October 2010.

(2)   Plant availability represents the percentage of time in a period that the plant is available to generate power regardless of whether it is running.

(3)   Plant availability decreased in the three and six months ended June 30, 2011 due to the impact of planned outages at Ravenswood and OSP.

U.S Power’s Comparable EBITDA of US$89 million and US$151 million for the three and six months ended June 30, 2011, respectively, increased US$20 million and US$18 million, respectively, compared to the same periods in 2010. The increases were primarily due to increased capacity revenues, higher realized power prices and incremental earnings from phase two of Kibby Wind which went into service in October 2010.  

U.S. Power’s Power Revenues of US$224 for the three months ended June 30, 2011 decreased US$13 million compared to the same period in 2010, primarily due to lower physical volumes of power sold, partially offset by higher realized power prices, incremental revenues from the second phase of Kibby Wind, new sales activity in the PJM Interconnection area (PJM) and an increase in the New York commercial customer base.  For the six months ended June 30, 2011, U.S. Power’s Power Revenues were US$479 million, an increase of US$10 million from the same period in 2010 as a result of higher realized power prices, incremental revenues from the second phase of Kibby Wind and additional revenue from PJM and New York commercial customers, partially offset by lower volumes of power sold.  

Capacity Revenues of US$74 million and US$113 million for the three and six months ended June 30, 2011, respectively, increased from US$66 million and US$106 million, respectively, in the same periods in 2010 primarily due to a reduction in forced outage rates at Ravenswood, partially offset by lower capacity prices in the New England power market.

Commodity Purchases Resold of US$84 million and US$215 million for the three and six months ended June 30, 2011, respectively, decreased from US$112 million and US$248 million, respectively, in the same periods in 2010 primarily due to a decrease in the quantity of power purchased for resale, partially offset by higher power prices per MWh purchased.

Plant Operating Costs and Other, including fuel gas consumed in generation, of US$128 million in second quarter 2011, was consistent with second quarter 2010.  For the six months ended June 30, 2011, Plant Operating Costs and Other were US$250 million, an increase of US$34 million from the same period in 2010 primarily due to higher fuel costs as a result of increased generation, incremental operating costs from the second phase of Kibby Wind and reduced lease costs related to Ravenswood in 2010.

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SECOND QUARTER REPORT 2011

U.S. Power focuses on selling power under short- and long-term contracts to wholesale, commercial and industrial customers in the New England, New York and PJM power markets. Exposure to fluctuations in spot prices on these power sales commitments are hedged with a combination of forward purchases of power, forward purchases of fuel to generate power and through the use of financial contracts. As at June 30, 2011, approximately 3,100 GWh or 67 per cent of U.S. Power's planned generation is contracted for the remainder of 2011. Planned generation fluctuates depending on hydrology, wind conditions, commodity prices and the resulting dispatch of the assets, and power sales fluctuate based on customer usage. The seasonal nature of the U.S. Power business generally results in higher generation volumes in the summer months.

Natural Gas Storage

Natural Gas Storage’s Comparable EBITDA for the three and six month periods ended June 30, 2011, was $18 million and $47 million, respectively, compared to $18 million and $69 million, respectively, for the same periods in 2010. The decrease in Comparable EBITDA in the six months ended June 30, 2011 compared to the same period in 2010 was primarily due to decreased proprietary and third-party storage revenues as a result of lower realized natural gas price spreads.

Other Income Statement Items

Comparable Interest Expense(1)

(unaudited)	Three months ended June 30						Six months ended June 30
(millions of dollars)	2011			2010			2011			2010
Interest on long-term debt(2)
Canadian dollar-denominated		122			129			244			260
U.S. dollar-denominated		180			163			362			322
Foreign exchange		(5	)		5			(8	)		11
		297			297			598			593
Other interest and amortization		7			33			13			53
Capitalized interest		(68	)		(143	)		(165	)		(277	)
Comparable Interest Expense(1)		236			187			446			369

(1)   Refer to the Non-GAAP Measures section in this MD&A for further discussion of Comparable Interest Expense.

(2)   Includes interest on Junior Subordinated Notes.

Comparable Interest Expense for second quarter 2011 increased $49 million to $236 million from $187 million in second quarter 2010.  Comparable Interest Expense for the six months ended June 30, 2011 increased $77 million to $446 million from $369 million for the six months ended June 30, 2010. The increases reflected lower capitalized interest for Keystone and Halton Hills as assets were placed into service, and incremental interest expense on debt issues of US$1.25 billion in June 2010 and US$1.0 billion in September 2010. These increases were partially offset by realized gains in 2011 compared to losses in 2010 from derivatives used to manage the Company’s exposure to rising interest rates, the positive impact of a weaker U.S. dollar on U.S. dollar-denominated interest and Canadian dollar-denominated debt maturities in 2011 and 2010.

Comparable Interest Income and Other for second quarter 2011 increased $44 million to income of $26 million from an expense of $18 million in second quarter 2010. Comparable Interest Income and Other for the six months ended June 30, 2011 increased $51 million to income of $57 million from income of $6 million for the six months ended June 30, 2010. The increases reflected realized gains in 2011 compared to losses in 2010 on derivatives used to manage the Company’s net exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income and from the translation of working capital balances due to a weakening of the U.S. dollar.

Comparable Income Taxes were $140 million in second quarter 2011 compared to $60 million for the same period in 2010. Comparable Income Taxes for the six months ended June 30, 2011 were $325 million compared to $178 million for the same period in 2010. The increases were primarily due to higher pre-tax earnings in 2011 compared to 2010 and higher positive income tax adjustments in 2010 compared to 2011.

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SECOND QUARTER REPORT 2011

Liquidity and Capital Resources

TransCanada believes that its financial position remains sound and consistent with recent years as does its ability to generate cash in the short and long term to provide liquidity, maintain financial capacity and flexibility, and provide for planned growth. TransCanada’s liquidity is underpinned by predictable cash flow from operations, cash balances on hand and unutilized committed revolving bank lines of US$1.0 billion, $2.0 billion, US$1.0 billion and US$200 million, maturing in November 2011, December 2012, December 2012 and February 2013, respectively. These facilities also support the Company’s commercial paper programs. In addition, at June 30, 2011, TransCanada’s proportionate share of unutilized capacity on committed bank facilities at TransCanada-operated affiliates was $169 million with maturity dates in 2011 and 2012. As at June 30, 2011, TransCanada had remaining capacity of $1.75 billion, $2.0 billion and US$1.75 billion under its equity, Canadian debt and U.S. debt shelf prospectuses, respectively. TransCanada’s liquidity, market and other risks are discussed further in the Risk Management and Financial Instruments section in this MD&A.

At June 30, 2011, the Company held Cash and Cash Equivalents of $468 million compared to $764 million at December 31, 2010. The decrease in Cash and Cash Equivalents was primarily due to expenditures for the Company’s capital program, debt repayments and dividend payments, partially offset by increased cash generated from operations.

Operating Activities

Funds Generated from Operations(1)

(unaudited)	Three months ended June 30					Six months ended June 30
(millions of dollars)	2011		2010			2011		2010
Cash Flows
Funds generated from operations(1)		892		935			1,811		1,658
Decrease/(increase) in operating working capital		8		(310	)		98		(201	)
Net cash provided by operations		900		625			1,909		1,457

(1)   Refer to the Non-GAAP Measures section in this MD&A for further discussion of Funds Generated from Operations.

Net Cash Provided by Operations increased $275 million and $452 million for the three and six months ended June 30, 2011, respectively, compared to the same periods in 2010, largely as a result of changes in operating working capital. The six months ended June 30, 2011 also reflected an increase in Funds Generated from Operations. Funds Generated from Operations for the three and six months ended June 30, 2011 were $892 million and $1.8 billion, respectively, compared to $935 million and $1.7 billion, respectively, for the same periods in 2010. The decrease for the three months ended June 30, 2011 was primarily due to the second quarter 2010 income tax benefit generated from bonus depreciation for U.S. tax purposes on Keystone assets placed in service in June 2010. Cash generated through earnings increased in second quarter 2011 compared to second quarter 2010 excluding the 2010 income tax benefit from bonus depreciation. The increase for the six months ended June 30, 2011 was primarily due to an increase in cash generated through earnings, partially offset by the 2010 income tax benefit from bonus depreciation.

As at June 30, 2011, TransCanada’s current liabilities were $4.6 billion and current assets were $2.8 billion resulting in a working capital deficiency of $1.8 billion. Excluding $1.6 billion of Notes Payable under the Company’s commercial paper programs and draws on its line-of-credit facilities, TransCanada’s working capital deficiency was $0.2 billion. The Company believes this shortfall can be managed through its ability to generate cash flow from operations as well as its ongoing access to capital markets.

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SECOND QUARTER REPORT 2011

Investing Activities

TransCanada remains committed to executing its remaining $11 billion capital expenditure program. For the three and six months ended June 30, 2011, capital expenditures totalled $0.7 billion and $1.4 billion, respectively (2010 – $1.0 billion and $2.3 billion, respectively), primarily related to the construction of Keystone,  the refurbishment and restart of Bruce A Units 1 and 2, and expansion of the Alberta System.

Financing Activities

On July 13, 2011, PipeLines LP entered into a five-year, US$500 million senior syndicated revolving credit facility, maturing July 2016. The proceeds from the credit facility were used to reduce PipeLines LP’s term loan and senior revolving credit facility, and repay its bridge loan facility. PipeLines LP’s remaining US$300 million term loan matures December 2011.

In June 2011, TCPL retired $60 million of 9.5 per cent Medium-Term Notes and, in January 2011, retired $300 million of 4.3 per cent Medium-Term Notes.

In June 2011, PipeLines LP issued US$350 million of 4.65 per cent Senior Notes due 2021 and cancelled US$175 million of its unsecured syndicated senior credit facility.

In May 2011, PipeLines LP completed a public offering of 7,245,000 common units at a price of US$47.58 per unit, resulting in gross proceeds of approximately US$345 million. TransCanada contributed an additional approximate US$7 million to maintain its general partnership interest and did not purchase any other units. Upon completion of this offering, TransCanada’s ownership interest in PipeLines LP decreased from 38.2 per cent to 33.3 per cent. In addition, PipeLines LP made draws of US$61 million on a bridge loan facility and of US$125 million on its senior revolving credit facility.

In June 2011, TCPL filed a $2.0 billion Canadian Medium-Term Notes base shelf prospectus to replace an April 2009 $2.0 billion Canadian Medium-Term Notes base shelf prospectus, which expired in May 2011 and had remaining capacity of $2.0 billion.

The Company believes it has the capacity to fund its existing capital program through internally-generated cash flow, continued access to capital markets and liquidity underpinned by in excess of $4 billion of committed credit facilities. TransCanada’s financial flexibility is further bolstered by opportunities for portfolio management, including an ongoing role for PipeLines LP.

Dividends

On July 28, 2011, TransCanada's Board of Directors declared a quarterly dividend of $0.42 per share for the quarter ending September 30, 2011 on the Company’s outstanding common shares. The dividend is payable on October 31, 2011 to shareholders of record at the close of business on September 30, 2011. In addition, quarterly dividends of $0.2875 and $0.25 per Series 1 and Series 3 preferred share, respectively, were declared for the quarter ending September 30, 2011. The dividends are payable on September 30, 2011 to shareholders of record at the close of business on August 31, 2011. Furthermore, a quarterly dividend of $0.275 per Series 5 preferred share was declared for the three month period ending October 30, 2011, payable on October 31, 2011 to shareholders of record at the close of business on September 30, 2011.

Commencing with the dividends declared April 28, 2011, common shares purchased with reinvested cash dividends under TransCanada’s Dividend Reinvestment and Share Purchase Plan (DRP) will no longer be satisfied with shares issued from treasury at a discount but rather will be acquired on the open market at 100 per cent of the weighted average purchase price. The DRP is available for dividends payable on TransCanada’s common and preferred shares, and TCPL’s preferred shares.  In the three and six months ended June 30, 2011, TransCanada issued 2.8 million and 5.4 million (2010 – 2.6 million and 4.9 million) common shares, respectively, under its DRP, in lieu of making cash dividend payments of $109 million and $202 million, respectively (2010 - $92 million and $170 million).

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SECOND QUARTER REPORT 2011

Contractual Obligations

In the first six months of 2011, TransCanada had a net reduction to its purchase obligations primarily due to the settlement of its commitments in the normal course of business. There have been no other material changes to TransCanada’s contractual obligations from December 31, 2010 to June 30, 2011, 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 2010 Annual Report.

Significant Accounting Policies and Critical Accounting Estimates

To prepare financial statements that conform with 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, 2010. For further information on the Company’s accounting policies and estimates refer to the MD&A in TransCanada's 2010 Annual Report.

Changes in Accounting Policies

The Company’s accounting policies have not changed materially from those described in TransCanada’s 2010 Annual Report except as follows:

Changes in Accounting Policies for 2011

Business Combinations, Consolidated Financial Statements and Non-Controlling Interests

Effective January 1, 2011, the Company adopted CICA Handbook Section 1582 “Business Combinations”, which is effective for business combinations with an acquisition date after January 1, 2011. This standard was amended to require additional use of fair value measurements, recognition of additional assets and liabilities, and increased disclosure. Adopting the standard is expected to have a significant impact on the way the Company accounts for future business combinations. Entities adopting Section 1582 were also required to adopt CICA Handbook Sections 1601 “Consolidated Financial Statements” and 1602 “Non-Controlling Interests”. Sections 1601 and 1602 require Non-Controlling Interests to be presented as part of Equity on the balance sheet. In addition, the income statement of the controlling parent now includes 100 per cent of the subsidiary’s results and presents the allocation of income between the controlling and non-controlling interests. Changes resulting from the adoption of Section 1582 were applied prospectively and changes resulting from the adoption of Sections 1601 and 1602 were applied retrospectively.

Future Accounting Changes

U.S. GAAP/International Financial Reporting Standards

The CICA’s Accounting Standards Board (AcSB) previously 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 accordance with GAAP, TransCanada follows specific accounting policies unique to a rate-regulated business. These rate-regulated accounting (RRA) standards allow the timing of recognition of certain revenues and expenses to differ from the timing that may otherwise be expected in a non-rate-regulated business under GAAP in order to appropriately reflect the economic impact of regulators' decisions regarding the Company's revenues and tolls.

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SECOND QUARTER REPORT 2011

In July 2009, the IASB issued an Exposure Draft “Rate-Regulated Activities”, which proposed a form of RRA under IFRS. At its September 2010 meeting, the IASB concluded that the development of RRA under IFRS requires further analysis and removed the RRA project from its current agenda. TransCanada does not expect a final RRA standard under IFRS to be effective in the foreseeable future.

In October 2010, the AcSB and the Canadian Securities Administrators amended their policies applicable to Canadian publicly accountable enterprises that use RRA in order to permit these entities to defer the adoption of IFRS for one year. TransCanada deferred its adoption and accordingly will continue to prepare its consolidated financial statements in 2011 in accordance with Canadian GAAP, as defined by Part V of the CICA Handbook, in order to continue using RRA.

As an SEC registrant, TransCanada prepares and files a “Reconciliation to United States GAAP” and has the option to prepare and file its consolidated financial statements using U.S. GAAP. As a result of the developments noted above, the Company’s Board of Directors has approved the adoption of U.S. GAAP effective January 1, 2012.

U.S. GAAP Conversion Project

Effective January 1, 2012, the Company will begin reporting using U.S. GAAP. TransCanada’s IFRS conversion team has been redeployed to support the conversion to U.S. GAAP. The conversion team is led by a multi-disciplinary Steering Committee that provides directional leadership for the adoption of U.S. GAAP.  Management also updates TransCanada’s Audit Committee on the progress of the U.S. GAAP project at each Audit Committee meeting and reports regularly to the Company’s Board of Directors on the status of the conversion project.   

U.S. GAAP training sessions continue for TransCanada staff who are impacted by the conversion and will be ongoing as needed throughout 2011. Significant changes to existing systems and processes are not required to implement U.S. GAAP as the Company’s primary accounting standard since TransCanada prepares and files a “Reconciliation to United States GAAP”.  The impact to internal controls over financial reporting and disclosure controls and procedures will be addressed over the remainder of 2011.

Identified differences between Canadian GAAP and U.S. GAAP that are significant to the Company are explained below and are consistent with those currently reported in the Company’s publicly-filed “Reconciliation to United States GAAP.”

Joint Ventures

Canadian GAAP requires the Company to account for certain investments using the proportionate consolidation method of accounting whereby TransCanada’s proportionate share of assets, liabilities, revenues, expenses and cash flows are included in the Company’s financial statements.  U.S. GAAP does not permit the use of proportionate consolidation with respect to TransCanada’s joint ventures and requires that such investments be recorded using the equity method of accounting.  

Inventory

Canadian GAAP allows the Company’s proprietary natural gas inventory held in storage to be recorded at its fair value. Under U.S. GAAP, inventory is recorded at the lower of cost or market.

Income Tax

Canadian GAAP requires an entity to record income tax assets and liabilities resulting from substantively enacted income tax legislation.  Under U.S. GAAP, the legislation must be fully enacted for income tax adjustments to be recorded.

Employee Benefits

Canadian GAAP requires an entity to recognize an accrued benefit asset or liability for defined benefit pension and other postretirement benefit plans. Under U.S. GAAP, an employer is required to recognize the overfunded or underfunded status of defined benefit pension and other postretirement benefit plans as an asset or liability in its balance sheet and to recognize changes in the funded status through Other Comprehensive Income in the year in which the change occurs.  

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SECOND QUARTER REPORT 2011

Debt Issue Costs

Canadian GAAP requires debt issue costs to be included in long-term debt.  Under U.S. GAAP these costs are classified as deferred assets.

Financial Instruments and Risk Management

TransCanada continues to manage and monitor its exposure to counterparty credit, liquidity and market risk.

Counterparty Credit and Liquidity Risk

TransCanada’s maximum counterparty credit exposure with respect to financial instruments at the balance sheet date, without taking into account security held, consisted of accounts receivable, portfolio investments recorded at fair value, the fair value of derivative assets, and notes, loans and advances receivable. The carrying amounts and fair values of these financial assets, except amounts for derivative assets, are included in Accounts Receivable and Other, and Available-For-Sale Assets in the Non-Derivative Financial Instruments Summary table below. Guarantees, letters of credit and cash are the primary types of security provided to support these amounts. The majority of counterparty credit exposure is with counterparties who are investment grade. At June 30, 2011, there were no significant amounts past due or impaired.

At June 30, 2011, the Company had a credit risk concentration of $286 million due from a creditworthy counterparty. This amount is expected to be fully collectible and is secured by a guarantee from the counterparty’s parent company.

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 Storage Commodity Price Risk

At June 30, 2011, the fair value of proprietary natural gas inventory held in storage, as measured using a weighted average of forward prices for the following four months less selling costs, was $47 million (December 31, 2010 - $49 million). The change in the fair value adjustment of proprietary natural gas inventory in storage in the three and six months ended June 30, 2011 resulted in net pre-tax unrealized losses of $1 million and gains of $1 million, respectively (2010 – gains of $4 million and losses of $20 million, respectively), which were recorded as adjustments to Revenues and Inventories. The change in fair value of natural gas forward purchase and sale contracts in the three and six months ended June 30, 2011 resulted in net pre-tax unrealized losses of $3 million and $10 million, respectively (2010 – gains of $2 million and $5 million, respectively), which were included in Revenues.

VaR Analysis

TransCanada uses a Value-at-Risk (VaR) methodology to estimate the potential impact from its exposure to market risk on its liquid open positions. VaR represents the potential change in pre-tax earnings over a given holding period. It is calculated assuming a 95 per cent confidence level that the daily change resulting from normal market fluctuations in its open positions will not exceed the reported VaR. Although losses are not expected to exceed the statistically estimated VaR on 95 per cent of occasions, losses on the other five per cent of occasions could be substantially greater than the estimated VaR. TransCanada’s consolidated VaR was $11 million at June 30, 2011, which was consistent with VaR at December 31, 2010 of $12 million.

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SECOND QUARTER REPORT 2011

Net Investment in Self-Sustaining Foreign Operations

The Company hedges its net investment in self-sustaining foreign operations (on an after-tax basis) with U.S. dollar-denominated debt, cross-currency interest rate swaps, forward foreign exchange contracts and foreign exchange options. At June 30, 2011, the Company had designated as a net investment hedge U.S. dollar-denominated debt with a carrying value of $9.5 billion (US$9.8 billion) and a fair value of $10.8 billion (US$11.2 billion). At June 30, 2011, $279 million (December 31, 2010 - $181 million) was included in Other Current Assets and Intangibles and Other Assets for the fair value of forwards and swaps used to hedge the Company’s net U.S. dollar investment in foreign operations.

The fair values and notional principal amounts for the derivatives designated as a net investment hedge were as follows:

Derivatives Hedging Net Investment in Self-Sustaining Foreign Operations

	June 30, 2011			December 31, 2010
Asset/(Liability) (unaudited) (millions of dollars)	Fair Value(1)		Notional or Principal Amount	Fair Value(1)		Notional or Principal Amount
U.S. dollar cross-currency swaps
(maturing 2011 to 2018)		276	US 3,550		179	US 2,800
U.S. dollar forward foreign exchange contracts
(maturing 2011)		3	US 600		2	US 100
		279	US 4,150		181	US 2,900

(1)   Fair values equal carrying values.

The carrying and fair values of non-derivative financial instruments were as follows:

Non-Derivative Financial Instruments Summary

	June 30, 2011				December 31, 2010
(unaudited) (millions of dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Financial Assets(1)
Cash and cash equivalents		468		468		764		764
Accounts receivable and other(2)(3)		1,488		1,520		1,555		1,595
Available-for-sale assets(2)		22		22		20		20
		1,978		2,010		2,339		2,379
Financial Liabilities(1)(3)
Notes payable		1,628		1,628		2,092		2,092
Accounts payable and deferred amounts(4)		1,076		1,076		1,436		1,436
Accrued interest		347		347		367		367
Long-term debt		17,340		20,498		17,922		21,523
Long-term debt of joint ventures		839		946		866		971
Junior subordinated notes		955		962		985		992
		22,185		25,457		23,668		27,381

(1)   Consolidated Net Income in the three and six months ended June 30, 2011 included losses of $2 million and $11 million, respectively, (2010 – losses of $2 million and $9 million, respectively), for fair value adjustments related to interest rate swap agreements on US$350 million (2010 – US$150 million) of Long-Term Debt. There were no other unrealized gains or losses from fair value adjustments to the non-derivative financial instruments.

(2)   At June 30, 2011, the Consolidated Balance Sheet included financial assets of $1,167 million (December 31, 2010 – $1,271 million) in Accounts Receivable, $38 million (December 31, 2010 – $40 million) in Other Current Assets and $305 million (December 31, 2010 - $264 million) in Intangibles and Other Assets.

(3)   Recorded at amortized cost, except for the US$350 million (December 31, 2010 – US$250 million) of Long-Term Debt that is adjusted to fair value.

(4)   At June 30, 2011, the Consolidated Balance Sheet included financial liabilities of $1,041 million (December 31, 2010 – $1,406 million) in Accounts Payable and $35 million (December 31, 2010 - $30 million) in Deferred Amounts.

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SECOND QUARTER REPORT 2011

Derivative Financial Instruments Summary

Information for the Company’s derivative financial instruments, excluding hedges of the Company’s net investment in self-sustaining foreign operations, is as follows:

June 30, 2011
(unaudited) (all amounts in millions unless otherwise indicated)		Power			Natural Gas			Foreign Exchange			Interest
Derivative Financial Instruments Held for Trading(1)
Fair Values(2)
Assets		$149			$118			$6			$18
Liabilities		$(114	)		$(146	)		$(15	)		$(19	)
Notional Values
Volumes(3)
Purchases		21,569			155			-			-
Sales		23,961			123			-			-
Canadian dollars		-			-			-			634
U.S. dollars		-			-			US 1,622			US 250
Cross-currency		-			-			47/US 37			-
Net unrealized gains/(losses) in the period(4)
Three months ended June 30, 2011		$4			$(9	)		$(2	)		$1
Six months ended June 30, 2011		$3			$(26	)		$-			$-
Net realized gains/(losses) in the period(4)
Three months ended June 30, 2011		$8			$(15	)		$12			$3
Six months ended June 30, 2011	$11			$(41		)	$33			$5
Maturity dates	2011-2018			2011-2016			2011-2012			2012-2016
Derivative Financial Instruments in Hedging Relationships(5)(6)
Fair Values(2)
Assets		$57			$5			$-			$11
Liabilities		$(197	)		$(17	)		$(56	)		$(14	)
Notional Values
Volumes(3)
Purchases		18,524			14			-			-
Sales		9,187			-			-			-
U.S. dollars		-			-			US 120			US 1,000
Cross-currency		-			-		136/US 100				-
Net realized losses in the period(4)
Three months ended June 30, 2011		$(8	)		$(5	)		$-			$(4	)
Six months ended June 30, 2011		$(46	)		$(8	)		$-			$(9	)
Maturity dates		2011-2017			2011-2013			2011-2014			2011-2015

(1)   All derivative financial instruments in the held-for-trading classification have been entered into for risk management purposes and are subject to the Company’s risk management strategies, policies and limits. These include derivatives that have not been designated as hedges or do not qualify for hedge accounting treatment but have been entered into as economic hedges to manage the Company’s exposures to market risk.

(2)   Fair values equal carrying values.

(3)   Volumes for power and natural gas derivatives are in GWh and Bcf, respectively.

(4)   Realized and unrealized gains and losses on held-for-trading derivative financial instruments used to purchase and sell power and natural gas are included on a net basis in Revenues. Realized and unrealized gains and losses on interest rate and foreign exchange derivative financial instruments held for trading are included in Interest Expense and Interest Income and Other, respectively. The effective portion of unrealized gains and losses on derivative financial instruments in cash flow hedging relationships is initially recognized in Other Comprehensive Income and reclassified to Revenues, Interest Expense and Interest Income and Other, as appropriate, as the original hedged item settles.  

(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 $11 million and a notional amount of US$350 million at June 30, 2011. Net realized gains on fair value hedges for the three and six months ended June 30, 2011 were $2 million and $4 million, respectively, and were included in Interest Expense. In the three and six months ended June 30, 2011, the Company did not record any amounts in Net Income related to ineffectiveness for fair value hedges.

(6)   For the three and six months ended June 30, 2011, Net Income included gains of $2 million and losses of $1 million, respectively, for changes in the 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. For the three and six months ended June 30, 2011, there were no gains or losses included in Net Income for discontinued cash flow hedges. No amounts have been excluded from the assessment of hedge effectiveness.

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SECOND QUARTER REPORT 2011

2010
(unaudited) (all amounts in millions unless otherwise indicated)		Power			Natural Gas			Foreign Exchange			Interest
Derivative Financial Instruments Held for Trading
Fair Values(1)(2)
Assets		$169			$144			$8			$20
Liabilities		$(129	)		$(173	)		$(14	)		$(21	)
Notional Values(2)
Volumes(3)
Purchases		15,610			158			-			-
Sales		18,114			96			-			-
Canadian dollars		-			-			-			736
U.S. dollars		-			-			US 1,479			US 250
Cross-currency		-			-			47/US 37			-
Net unrealized (losses)/gains in the period(4)
Three months ended June 30, 2010		$(10	)		$3			$(11	)		$(13	)
Six months ended June 30, 2010		$(26	)		$5			$(11	)		$(17	)
Net realized gains/(losses) in the period(4)
Three months ended June 30, 2010		$15			$(17	)		$(6	)		$(6	)
Six months ended June 30, 2010		$37			$(29	)		$2			$(10	)
Maturity dates(2)	2011-2015			2011-2015			2011-2012			2011-2016
Derivative Financial Instruments in Hedging Relationships(5)(6)
Fair Values(1)(2)
Assets		$112			$5			$-			$8
Liabilities		$(186	)		$(19	)		$(51	)		$(26	)
Notional Values(2)
Volumes(3)
Purchases		16,071			17			-			-
Sales		10,498			-			-			-
U.S. dollars		-			-			US 120			US 1,125
Cross-currency		-			-		136/US 100				-
Net realized losses in the period(4)
Three months ended June 30, 2010		$(36	)		$(6	)		$-			$(9	)
Six months ended June 30, 2010		$(43	)		$(9	)		$-			$(19	)
Maturity dates(2)		2011-2015			2011-2013			2011-2014			2011-2015

(1)   Fair values equal carrying values.

(2)   As at December 31, 2010.

(3)   Volumes for power and natural gas derivatives are in GWh and Bcf, respectively.

(4)   Realized and unrealized gains and losses on held-for-trading derivative financial instruments used to purchase and sell power and natural gas are included on a net basis in Revenues. Realized and unrealized gains and losses on interest rate and foreign exchange derivative financial instruments held for trading are included in Interest Expense and Interest Income and Other, respectively. The effective portion of unrealized gains and losses on derivative financial instruments in cash flow hedging relationships is initially recognized in Other Comprehensive Income and reclassified to Revenues, Interest Expense and Interest Income and Other, as appropriate, as the original hedged item settles. 

(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 $8 million and a notional amount of US$250 million at December 31, 2010. Net realized gains on fair value hedges for the three and six months ended June 30, 2010 were $1 million and $2 million, respectively, and were included in Interest Expense. In the three and six months ended June 30, 2010, the Company did not record any amounts in Net Income related to ineffectiveness for fair value hedges.

(6)   For the three and six months ended June 30, 2010, Net Income included gains of $7 million and losses of $1 million, respectively, for changes in the 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. For the three and six months ended June 30, 2010, there were no gains or losses included in Net Income for discontinued cash flow hedges. No amounts were excluded from the assessment of hedge effectiveness.

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SECOND QUARTER REPORT 2011

Balance Sheet Presentation of Derivative Financial Instruments

The fair value of the derivative financial instruments in the Company’s Balance Sheet was as follows:

(unaudited)
(millions of dollars)	June 30, 2011		December 31, 2010
Current
Other current assets	299		273
Accounts payable	(314	)	(337	)
Long-term
Intangibles and other assets	344		374
Deferred amounts	(264	)	(282	)

Other Risks

Additional risks faced by the Company are discussed in the MD&A in TransCanada’s 2010 Annual Report. These risks remain substantially unchanged since December 31, 2010.

Controls and Procedures

As of June 30, 2011, 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 at a reasonable assurance level as at June 30, 2011.

During the quarter ended June 30, 2011, 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.

Outlook

Since the disclosure in TransCanada's 2010 Annual Report, the Company's overall earnings outlook for 2011 has improved due to higher realized power prices in Western Power in the first half of 2011, with relatively strong prices expected throughout the remainder of 2011. The Company’s earnings outlook could also be affected by the uncertainty and ultimate resolution of the capacity pricing issues in New York, as discussed in the Recent Developments section of this MD&A. For further information on outlook, refer to the MD&A in TransCanada's 2010 Annual Report.  

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SECOND QUARTER REPORT 2011

Recent Developments

Natural Gas Pipelines

Canadian Mainline

2011 Final Tolls

In April 2011, TransCanada filed an application with the NEB for approval of Canadian Mainline’s final tolls for 2011 determined in accordance with the existing 2007-2011 Tolls Settlement.

TransCanada proposed to continue charging the interim 2011 tolls for the remainder of 2011 and to carry forward to 2012 the difference between the revenue that would have been generated from the final tolls and the revenue actually generated from the interim tolls. The interim 2011 tolls were implemented on March 1, 2011 and reflected a firm transportation toll from Empress, Saskatchewan to Dawn, Ontario of $1.89 per gigajoule. Adjusting for the difference in 2012 will result in greater Canadian Mainline toll certainty and stability.

In May 2011, the NEB solicited comments on the application for final tolls from interested parties, requesting their position and recommended process with respect to the application. Subsequently, the NEB solicited additional comments on the application and required TransCanada to file a reply submission by July 29, 2011.

2012 – 2013 Tolls Application

As part of its 2011 final tolls application, TransCanada informed the NEB of its intent to file an application for 2012 and 2013 tolls by October 31, 2011 that will include changes to the business structure, toll design and services. These changes are intended to improve the competitiveness of TransCanada’s regulated Canadian natural gas transportation infrastructure and the Western Canada Sedimentary Basin (WCSB).

In June 2011, the NEB directed TransCanada to file the 2012 and 2013 tolls application by September 1, 2011. TransCanada will comply with the NEB’s direction, however, certain elements of the application which cannot be available on September 1, 2011 will be filed by the end of October 2011.

Marcellus Facilities Expansion

The Company has concluded new capacity open seasons for the Canadian Mainline that resulted in contractual agreements to transport a total of approximately 350 million cubic feet per day (mmcf/d) of Marcellus shale gas to eastern markets for deliveries that are expected to commence in 2012 and 2013. An application for approval to construct approximately $130 million of new facilities required to provide this service was filed with the NEB on July 18, 2011.

Ongoing shipper interest is expected to result in additional requests for new capacity on the eastern part of the Canadian Mainline over time.

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SECOND QUARTER REPORT 2011

Alberta System

The Alberta System continues to operate under 2011 interim tolls approved by the NEB in 2010. In May 2011, TransCanada filed for final 2011 tolls that reflect the provisions of the Alberta System 2010 – 2012 Revenue Requirement Settlement and commercial integration of the ATCO Pipelines system.

The Alberta System’s Horn River natural gas pipeline project was approved by the NEB in January 2011 and commenced construction in March 2011, with a targeted completion date of second quarter 2012 and an estimated capital cost of  $275 million. In addition, the Company has executed an agreement to extend the Horn River pipeline by approximately 100 kilometres (km) (62 miles) at an estimated capital cost of $230 million. As a result of the extension, additional contractual commitments of 100 mmcf/d are expected to commence in 2014 with volumes increasing to 300 mmcf/d by 2020. The total contracted volumes for Horn River, including the extension, are expected to be approximately 900 mmcf/d in 2020.

On June 24, 2011, the NEB approved the construction and operation of a 24 km (15 miles) extension of the Groundbirch natural gas pipeline. Construction is expected to commence in August 2011 with an in-service date of April 1, 2012 and an estimated capital cost of approximately $60 million. The project is required to service 250 mmcf/d of new transportation contracts.

TransCanada continues to advance further pipeline development in British Columbia (B.C.) and Alberta to transport new natural gas supplies. The Company has filed several applications with the NEB requesting approval of further expansions of the Alberta System to accommodate requests for additional natural gas transmission service throughout the northwest portion of the WCSB. As at June 30, 2011, in addition to the projects previously discussed, the NEB had approved natural gas pipeline projects with capital costs of approximately $500 million. Further pipeline projects with a total capital cost of approximately $700 million at June 30, 2011 are awaiting NEB approval.

The successful Canadian Mainline open seasons and ongoing business with Western Canadian producers have resulted in new contracts from both the Montney and Horn River shale gas formations. Including the projects discussed above, TransCanada has firm commitments to transport 2.9 Bcf/d from northwest Alberta and northeast B.C. by 2014. Further requests for significant additional volumes on the Alberta System from the northwest portion of the WCSB have been received.

Guadalajara

TransCanada’s US$360 million, 307 km (191 miles) Guadalajara natural gas pipeline went into service on June 15, 2011. All of the pipeline’s utilized capacity is under a 25-year contract with Comisión Federal de Electricidad (CFE), Mexico's state-owned electric company. TransCanada and the CFE have agreed to add a US$60 million compressor station to the pipeline that is expected to be operational early in 2013.

PipeLines LP

On May 3, 2011, the Company completed the sale of a 25 per cent interest in each of Gas Transmission Northwest LLC (GTN LLC) and Bison Pipeline LLC (Bison LLC) to PipeLines LP for an aggregate purchase price of US$605 million, subject to closing adjustments, which included US$81 million of long-term debt, or 25 per cent of GTN LLC debt outstanding. GTN LLC and Bison LLC own the GTN and Bison natural gas pipelines, respectively.

On May 3, 2011, PipeLines LP completed an underwritten public offering of 7,245,000 common units, including 945,000 common units purchased by the underwriters upon full exercise of an over-allotment option, at US$47.58 per unit. Gross proceeds of approximately US$345 million from this offering were used to partially fund the acquisition. The acquisition was also funded by draws of US$61 million on PipeLines LP’s bridge loan facility and of US$125 million on its US$250 million senior revolving credit facility.

As part of this offering, TransCanada made a capital contribution of approximately US$7 million to maintain its two per cent general partnership interest in PipeLines LP and did not purchase any other units. As a result of the common units offering, TransCanada's ownership in PipeLines LP decreased from 38.2 per cent to 33.3 per cent and an after-tax dilution gain of $30 million ($50 million pre-tax) was recorded in Contributed Surplus.

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SECOND QUARTER REPORT 2011

Oil Pipelines

Keystone

On May 1, 2011, revised fixed tolls came into effect for the Wood River/Patoka section of the system. These revised tolls reflect the final project costs of the Wood River/Patoka section of Keystone.

Keystone experienced two above-ground incidents in second quarter 2011, both of which involved the release of small amounts of crude oil at pump stations in North Dakota and Kansas.  In each instance, Keystone’s monitoring system worked as designed, allowing for the entire system to be shut down within minutes. As a result of these incidents, the U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA) issued a corrective action order on June 3, 2011 which required TransCanada to develop and submit a written re-start plan prior to resuming operation of the pipeline. TransCanada’s re-start plan, which included steps to facilitate the proper clean-up, investigation, and system improvements and modifications, was approved by PHMSA on June 4, 2011. As a result of these shut downs, Keystone was not able to transport all of the shippers’ nominated volumes in May and June 2011, however, the impact to EBITDA was not significant. TransCanada remains committed to building and operating a safe, reliable pipeline. Additional work to improve and modify the system will continue into July and August 2011, which will result in a reduction in available pipeline capacity of approximately 20 per cent in each month. The impact to EBITDA is not expected to be significant.

TransCanada’s Keystone U.S. Gulf Coast Expansion (Keystone XL) is now entering the final stages of regulatory review. On April 15, 2011, the U.S. Department of State (DOS), the lead agency for U.S. federal regulatory approvals, issued a Supplemental Draft Environmental Impact Statement (SDEIS) in response to comments received on a Draft Environmental Impact Statement (DEIS) issued in April 2010 and to address new and additional information received. The SDEIS provided additional information on key environmental issues, but did not change the conclusion reached in the DEIS that the project would enhance U.S. energy security, benefit the U.S. economy and have limited environmental impact. A 45-day comment period on the SDEIS concluded June 6, 2011. The DOS is processing the comments and has announced it plans to issue a Final Environmental Impact Statement (FEIS) in third quarter 2011. Following the publication of an FEIS, the DOS will consult with other U.S. federal agencies during a 90-day period to determine if granting approval for Keystone XL is in the U.S. national interest. The DOS has indicated it will make a final decision regarding the Presidential Permit prior to the end of 2011.

The capital cost of Keystone, including Keystone XL, is estimated to be US$13 billion. At June 30, 2011, US$7.9 billion had been invested, including US$1.7 billion related to Keystone XL. The remainder is expected to be invested between now and the in-service date of the expansion, which is expected in 2013. Capital costs related to the construction of Keystone are subject to capital cost risk- and reward-sharing mechanisms with Keystone’s long-term committed shippers.

Energy

Coolidge

The US$500 million Coolidge generating station went into service on May 1, 2011. Power from the 575 MW simple-cycle, natural gas-fired peaking facility located near Phoenix, Arizona is sold to the Salt River Project Agricultural Improvement and Power District under a 20-year PPA.

Sundance A

The binding arbitration process to resolve the Sundance A PPA dispute arising out of TransAlta Corporation’s claims of force majeure and economic destruction has commenced. The arbitration panel is expected to hold a hearing in March and April 2012 for these claims. Assuming the hearing concludes within the time allotted, TransCanada expects to receive a decision in mid-2012. As the limited information received by TransCanada to date does not support these claims, TransCanada continues to record revenues and costs under the PPA as though this event was a normal plant outage.

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SECOND QUARTER REPORT 2011

Ravenswood

The July 2011 spot price for capacity sales in the New York Zone J market has settled at materially lower levels than prior periods resulting from the manner in which the New York Independent System Operator (NYISO) has treated price mitigation for a new power plant that recently began service in this market. TransCanada believes that this treatment by the NYISO is in direct contravention of a series of U.S. Federal Energy Regulatory Commission (FERC) orders which direct how new entrant capacity is to be treated for the purpose of determining capacity price. TransCanada and a number of other parties have filed a series of complaints with the FERC. The outcome of the complaints and the long-term impact that this development may have on TransCanada’s Ravenswood operations are unknown.

The demand curve reset process continues with the NYISO’s June 20, 2011 compliance filing resulting in an increased demand curve for 2011 to 2014. The FERC has not yet responded to this filing and, as a result, it is not yet known when the revised demand curves will be effective.

Bruce Power

Loading of fuel commenced on the refurbished Bruce A Unit 2 in second quarter 2011 and was completed in July. Fuel channel assembly was completed on Unit 1 during second quarter 2011, which was the final stage of Atomic Energy of Canada Limited’s work on the reactors. Demobilization of refurbishment activity continues as the work transitions from construction to commissioning.

Subject to regulatory approval, Bruce Power expects to achieve a first synchronization of the Unit 2 generator to the electrical grid by the end of 2011, with commercial operation expected to occur in first quarter 2012. Bruce Power expects to load fuel into Unit 1 in third quarter 2011, with a first synchronization of the generator during first quarter 2012 and commercial operation is expected to occur during third quarter 2012. TransCanada's share of the total capital cost is expected to be approximately $2.4 billion, of which $2.1 billion was incurred as of June 30, 2011.

Bécancour

In June 2011, Hydro-Québec notified TransCanada it would exercise its option to extend the agreement to suspend all electricity generation from the Bécancour power plant throughout 2012. Under the original agreement signed in June 2009, Hydro-Québec has the option, subject to certain conditions, to extend the suspension on an annual basis until such time as regional electricity demand levels recover. TransCanada will continue to receive payments under the agreement similar to those that would have been received under the normal course of operation.

Oakville

In October 2010, the Government of Ontario announced that it would not proceed with the $1.2 billion Oakville generating station. The Company continues to negotiate a settlement with the Ontario government and its agencies that would terminate the 20-year Clean Energy Supply contract TransCanada had previously been awarded and would compensate TransCanada for the economic consequences associated with the contract’s termination.

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SECOND QUARTER REPORT 2011

Zephyr

In June 2011, Zephyr terminated the precedent agreements with its potential shippers as the parties were unable to resolve key commercial issues. In July 2011, one of Zephyr’s potential shippers exercised its contractual rights to acquire 100 per cent of the Zephyr project from TransCanada.

Cartier Wind

Construction continues on the five-stage, 590 MW Cartier Wind project in Québec. The 58 MW Montagne-Sèche project and the 101 MW first phase of the Gros-Morne wind farm are expected to be operational in December 2011. The 111 MW Gros-Morne phase two is expected to be operational in December 2012. These are the fourth and fifth Québec-based wind farms of Cartier Wind, which are 62 per cent owned by TransCanada. All of the power produced by Cartier Wind is sold under a 20-year PPA to Hydro-Québec.

Share Information

At July 25, 2011, TransCanada had 703 million issued and outstanding common shares, and had 22 million Series 1, 14 million Series 3 and 14 million Series 5 issued and outstanding first preferred shares that are convertible to 22 million Series 2, 14 million Series 4 and 14 million Series 6 preferred shares, respectively. In addition, there were eight million outstanding options to purchase common shares, of which six million were exercisable as at July 25, 2011.

Selected Quarterly Consolidated Financial Data(1)

(unaudited)	2011		2010				2009
(millions of dollars except per share amounts)	Second	First	Fourth	Third	Second	First	Fourth	Third
Revenues	2,143	2,243	2,057	2,129	1,923	1,955	1,986	2,049
Net income attributable to controlling interests	367	429	283	391	295	303	387	345
Share Statistics
Net income per common share – Basic and Diluted	$0.50	$0.59	$0.39	$0.54	$0.41	$0.43	$0.56	$0.50
Dividend declared per common share	$0.42	$0.42	$0.40	$0.40	$0.40	$0.40	$0.38	$0.38

(1)   The selected quarterly consolidated financial data has been prepared in accordance with Canadian GAAP and is presented in Canadian dollars.

Factors Affecting Quarterly Financial Information

In Natural Gas Pipelines, which consists primarily of the Company's investments in regulated natural gas pipelines and regulated natural gas storage facilities, annual revenues, EBIT 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 volumes on U.S. pipelines, acquisitions and divestitures, and developments outside of the normal course of operations.

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SECOND QUARTER REPORT 2011

In Oil Pipelines, which consists of the Company’s investment in the Keystone crude oil pipeline, annual revenues are based on contracted crude oil transportation and uncommitted spot transportation. Quarter-over-quarter revenues, EBIT and net income during any particular fiscal year remain relatively stable with fluctuations resulting from planned and unplanned outages, and changes in the amount of spot volumes transported and the associated rate charged. Spot volumes transported are affected by customer demand, market pricing, planned and unplanned outages of refineries, terminals and pipeline facilities, 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, EBIT and net income are affected by seasonal weather conditions, customer demand, market prices, capacity payments, planned and unplanned plant outages, acquisitions and divestitures, certain fair value adjustments and developments outside of the normal course of operations.

Significant developments that affected the last eight quarters' EBIT and Net Income are as follows:

·   Second Quarter 2011, Natural Gas Pipelines’ EBIT included incremental earnings from Guadalajara, which was placed in service in June 2011. Energy’s EBIT included incremental earnings from Coolidge, which was placed in service in May 2011. EBIT included net unrealized losses of $5 million pre-tax ($4 million after tax) resulting from changes in the fair value of proprietary natural gas inventory in storage and certain risk management activities.

·   First Quarter 2011, Natural Gas Pipelines’ EBIT included incremental earnings from Bison, which was placed in service in January 2011. Oil Pipelines began recording EBIT for the Wood River/Patoka and Cushing Extension sections of Keystone in February 2011. EBIT included net unrealized losses of $17 million pre-tax ($10 million after tax) resulting from changes in the fair value of proprietary natural gas inventory in storage and certain risk management activities.

·   Fourth Quarter 2010, Natural Gas Pipelines’ EBIT decreased as a result of recording a $146 million pre-tax ($127 million after-tax) valuation provision for advances to the APG for the MGP. Energy’s EBIT included contributions from the second phase of Kibby Wind, which was placed in service in October 2010, and net unrealized gains of $22 million pre-tax ($12 million after tax) resulting from changes in the fair value of proprietary natural gas inventory in storage and certain risk management activities.

·   Third Quarter 2010, Natural Gas Pipelines’ EBIT increased as a result of recording nine months of incremental earnings related to the Alberta System 2010 – 2012 Revenue Requirement Settlement, which resulted in a $33 million increase to Net Income. Energy’s EBIT included contributions from Halton Hills, which was placed in service in September 2010, and net unrealized gains of $4 million pre-tax ($3 million after tax) resulting from changes in the fair value of proprietary natural gas inventory in storage and certain risk management activities.

·   Second Quarter 2010, Energy’s EBIT included net unrealized gains of $15 million pre-tax ($10 million after tax) resulting from changes in the fair value of proprietary natural gas inventory in storage and certain risk management activities. Net Income reflected a decrease of $58 million after tax due to losses in 2010 compared to gains in 2009 for interest rate and foreign exchange rate derivatives that did not qualify as hedges for accounting purposes and the translation of U.S. dollar-denominated working capital balances.

·   First Quarter 2010, Energy’s EBIT included net unrealized losses of $49 million pre-tax ($32 million after tax) resulting from changes in the fair value of proprietary natural gas inventory in storage and certain risk management activities.

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·   Fourth Quarter 2009, Natural Gas Pipelines EBIT included a dilution gain of $29 million pre-tax ($18 million after tax) resulting from TransCanada’s reduced ownership interest in PipeLines LP, which was caused by PipeLines LP’s issue of common units to the public. Energy’s EBIT included net unrealized gains of $7 million pre-tax ($5 million after tax) resulting from changes in the fair value of proprietary natural gas inventory in storage and certain risk management activities. Net Income included $30 million of favourable income tax adjustments resulting from reductions in the Province of Ontario’s corporate income tax rates.

·   Third Quarter 2009, Energy’s EBIT included net unrealized gains of $14 million pre-tax ($10 million after tax) due to changes in the fair value of proprietary natural gas inventory in storage and certain risk management activities.