exhibit13210302012q3.htm

	Three months ended					Nine months ended
(unaudited)	September 30					September 30
(millions of Canadian dollars except per share amounts)	2012			2011		2012			2011

Revenues
Natural Gas Pipelines		1,058			1,036		3,177			3,107
Oil Pipelines		259			229		769			575
Energy		809			778		1,972			2,142
		2,126			2,043		5,918			5,824

Income from Equity Investments		71			127		196			328

Operating and Other Expenses
Plant operating costs and other		758			717		2,192			1,973
Commodity purchases resold		337			271		758			782
Depreciation and amortization		342			337		1,032			987
		1,437			1,325		3,982			3,742

Financial Charges/(Income)
Interest expense		249			240		730			686
Interest income and other		(34	)		43		(70	)		(12	)
		215			283		660			674

Income before Income Taxes		545			562		1,472			1,736

Income Taxes Expense
Current		6			49		101			197
Deferred		128			82		247			252
		134			131		348			449

Net Income		411			431		1,124			1,287

Net Income Attributable to Non-Controlling Interests		29			32		90			96
Net Income Attributable to Controlling Interests		382			399		1,034			1,191
Preferred Share Dividends		13			13		41			41
Net Income Attributable to Common Shares		369			386		993			1,150

Net Income per Common Share
Basic and Diluted		$0.52			$0.55		$1.41			$1.64

Dividends Declared per Common Share		$0.44			$0.42		$1.32			$1.26

Weighted Average Number of Common Shares (millions)
Basic		705			703		704			701
Diluted		706			704		705			702

	Three months ended						Nine months ended
(unaudited)	September 30						September 30
(millions of Canadian dollars)	2012			2011			2012			2011

Net Income		411			431			1,124			1,287
Other Comprehensive Income/(Loss), Net of Income Taxes
Change in foreign currency translation gains and losses on investments in foreign operations(1)		(196	)		416			(189	)		262
Change in fair value of derivative instruments to hedge the net investments in foreign operations(2)		99			(213	)		76			(141	)
Change in fair value of derivative instruments designated as cash flow hedges(3)		60			(18	)		43			(113	)
Reclassification to Net Income of losses on derivative instruments designated as cash flow hedges(4)		47			44			119			114
Reclassification to Net Income of actuarial losses and prior service costs on pension and other post-retirement benefit plans(5)		4			2			18			7
Other Comprehensive (Loss)/Income of Equity Investments(6)		(3	)		1			(1	)		1
Other Comprehensive Income		11			232			66			130

Comprehensive Income		422			663			1,190			1,417

Comprehensive (Loss)/Income Attributable to Non-Controlling Interests		(5	)		104			59			150
Comprehensive Income Attributable to Controlling Interests		427			559			1,131			1,267
Preferred Share Dividends		13			13			41			41
Comprehensive Income Attributable to Common Shares		414			546			1,090			1,226

(6)

Primarily related to reclassification to Net Income of actuarial losses on pension and other post-retirement benefit plans, gains and losses on derivative instruments designated as cash flow hedges, offset by change in gains and losses on derivative instruments designated as cash flow hedges, net of income tax recovery of $1 million and nil for the three and nine months ended September 30, 2012, respectively (2011 – recovery of $2 million and expense of $3 million, respectively).

	Three months ended						Nine months ended
(unaudited)	September 30						September 30
(millions of Canadian dollars)	2012			2011			2012			2011

Cash Generated from Operations
Net income		411			431			1,124			1,287
Depreciation and amortization		342			337			1,032			987
Deferred income taxes		128			82			247			252
Income from equity investments		(71	)		(127	)		(196	)		(328	)
Distributions received from equity investments		95			127			252			307
Employee future benefits expense (less than)/in excess of funding		(23	)		6			(11	)		4
Other		(16	)		72			18			105
Decrease in operating working capital		235			80			80			145
Net cash provided by operations		1,101			1,008			2,546			2,759

Investing Activities
Capital expenditures		(694	)		(505	)		(1,555	)		(1,593	)
Equity investments		(144	)		(213	)		(557	)		(451	)
Deferred amounts and other		40			93			82			133
Net cash used in investing activities		(798	)		(625	)		(2,030	)		(1,911	)

Financing Activities
Dividends on common and preferred shares		(322	)		(308	)		(956	)		(706	)
Distributions paid to non-controlling interests		(33	)		(33	)		(101	)		(87	)
Notes payable (repaid)/issued, net		(930	)		154			(341	)		(257	)
Long-term debt issued, net of issue costs		995			54			1,488			573
Reduction of long-term debt		(12	)		(206	)		(782	)		(946	)
Common shares issued		17			14			35			39
Partnership units of subsidiary issued, net of costs		-			-			-			321
Net cash used in financing activities		(285	)		(325	)		(657	)		(1,063	)

Effect of Foreign Exchange Rate Changes on Cash and Cash Equivalents		(14	)		27			(19	)		12


Increase/(Decrease) in Cash and Cash Equivalents		4			85			(160	)		(203	)

Cash and Cash Equivalents
Beginning of period		490			372			654			660

Cash and Cash Equivalents
End of period		494			457			494			457

(unaudited)	September 30			December 31
(millions of Canadian dollars)	2012			2011

ASSETS
Current Assets
Cash and cash equivalents		494			654
Accounts receivable		873			1,094
Inventories		214			248
Other		973			1,114
		2,554			3,110
Plant, Property and Equipment, net of accumulated depreciation of $16,259 and $15,406, respectively		32,379			32,467
Equity Investments		5,520			5,077
Goodwill		3,419			3,534
Regulatory Assets		1,629			1,684
Intangibles and Other Assets		1,440			1,466
		46,941			47,338

LIABILITIES
Current Liabilities
Notes payable		1,470			1,863
Accounts payable		1,877			2,359
Accrued interest		346			365
Current portion of long-term debt		1,070			935
		4,763			5,522
Regulatory Liabilities		321			297
Deferred Amounts		706			929
Deferred Income Tax Liabilities		3,858			3,591
Long-Term Debt		17,899			17,724
Junior Subordinated Notes		983			1,016
		28,530			29,079
EQUITY
Common shares, no par value		12,049			12,011
Issued and outstanding: September 30, 2012 - 705 million shares
December 31, 2011 - 704 million shares
Preferred shares		1,224			1,224
Additional paid-in capital		380			380
Retained earnings		4,691			4,628
Accumulated other comprehensive loss		(1,352	)		(1,449	)
Controlling Interests		16,992			16,794
Non-controlling interests		1,419			1,465
Equity		18,411			18,259
		46,941			47,338

Contingencies and Guarantees (Note 8)

(unaudited) (millions of Canadian dollars)	Currency Translation Adjustments			Cash Flow Hedges and Other			Pension and Other Post-retirement Plan Adjustments			Total
Balance at December 31, 2011		(643	)		(281	)		(525	)		(1,449	)
Change in foreign currency translation gains and losses on investments in foreign operations(1)		(158	)		-			-			(158	)
Change in fair value of derivative instruments to hedge net investments in foreign operations(2)		76			-			-			76
Change in fair value of derivative instruments designated as cash flow hedges(3)		-			43			-			43
Reclassification to Net Income of losses on derivative instruments designated as cash flow hedges pertaining to prior periods(4)(5)		-			119			-			119
Reclassification of actuarial losses and prior service costs on pension and other post-retirement benefit plans(6)		-			-			18			18
Other Comprehensive (Loss)/Income of Equity Investments (7)		-			(12	)		11			(1	)
Balance at September 30, 2012		(725	)		(131	)		(496	)		(1,352	)

(unaudited) (millions of Canadian dollars)	Currency Translation Adjustments			Cash Flow Hedges and Other			Pension and Other Post-retirement Plan Adjustments			Total
Balance at December 31, 2010		(683	)		(194	)		(366	)		(1,243	)
Change in foreign currency translation gains and losses on investments in foreign operations(1)		216			-			-			216
Change in fair value of derivative instruments to hedge net investments in foreign operations(2)		(141	)		-			-			(141	)
Change in fair value of derivative instruments designated as cash flow hedges(3)		-			(113	)		-			(113	)
Reclassification to Net Income of losses on derivative instruments designated as cash flow hedges(4)(5)		-			106			-			106
Reclassification of actuarial losses and prior service costs on pension and other post-retirement benefit plans(6)		-			-			7			7
Other Comprehensive (Loss)/Income of Equity Investments (7)		-			(7	)		8			1
Balance at September 30, 2011		(608	)		(208	)		(351	)		(1,167	)

(5)

Losses related to cash flow hedges reported in AOCI and expected to be reclassified to Net Income in the next 12 months are estimated to be $56 million ($31 million, net of tax). These estimates assume constant commodity prices, interest rates and foreign exchange rates over time, however, the amounts reclassified will vary based on the actual value of these factors at the date of settlement.

(7)

Primarily related to reclassification to Net Income of actuarial losses on pension and other post-retirement benefit plans, reclassification to Net Income of gains and losses on derivative instruments designated as cash flow hedges, partially offset by changes in gains and losses on derivative instruments designated as cash flow hedges, net of income tax expense of nil for the nine months ended September 30, 2012 (2011 – nil).

	Nine months ended
(unaudited)	September 30
(millions of Canadian dollars)	2012			2011

Common Shares
Balance at beginning of period		12,011			11,745
Shares issued under dividend reinvestment plan		-			202
Shares issued on exercise of stock options		38			40
Balance at end of period		12,049			11,987

Preferred Shares
Balance at beginning and end of period		1,224			1,224

Additional Paid-In Capital
Balance at beginning of period		380			349
Issuance of stock options, net of exercises		-			1
Dilution gain from TC PipeLines, LP units issued		-			30
Balance at end of period		380			380

Retained Earnings
Balance at beginning of period		4,628			4,273
Net income attributable to controlling interests		1,034			1,191
Common share dividends		(930	)		(884	)
Preferred share dividends		(41	)		(41	)
Balance at end of period		4,691			4,539

Accumulated Other Comprehensive Loss
Balance at beginning of period		(1,449	)		(1,243	)
Other comprehensive income		97			76
Balance at end of period		(1,352	)		(1,167	)

Equity Attributable to Controlling Interests		16,992			16,963

Equity Attributable to Non-Controlling Interests
Balance at beginning of period		1,465			1,157
Net income attributable to non-controlling interests		90			96
Other comprehensive (loss)/income attributable to non-controlling interests		(31	)		54
Sale of TC PipeLines, LP units
Proceeds, net of issue costs		-			321
Decrease in TransCanada’s ownership		-			(50	)
Distributions to non-controlling interests		(101	)		(95	)
Other		(4	)		13
Balance at end of period		1,419			1,496

Total Equity		18,411			18,459

These condensed consolidated financial statements of TransCanada Corporation (TransCanada or the Company) have been prepared by management in accordance with United States generally accepted accounting principles (U.S. GAAP). Comparative figures, which were previously presented in accordance with Canadian generally accepted accounting principles as defined in Part V of the Canadian Institute of Chartered Accountants Handbook (CGAAP), have been adjusted as necessary to be compliant with the Company’s accounting policies under U.S. GAAP. The amounts adjusted for U.S. GAAP presented in these condensed consolidated financial statements for the three and nine months ended September 30, 2011 are the same as those that have been previously reported in the Company’s September 30, 2011 Reconciliation to U.S. GAAP. The amounts adjusted for U.S. GAAP at December 31, 2011 are the same as those reported in Note 25 of TransCanada’s 2011 audited Consolidated Financial Statements included in TransCanada’s 2011 Annual Report. The accounting policies and critical accounting estimates applied are consistent with those outlined in TransCanada’s 2011 Annual Report, except as described in Note 2, which outlines the Company’s significant accounting policies that have changed upon adoption of U.S. GAAP. Capitalized and abbreviated terms that are used but not otherwise defined herein are identified in the Glossary of Terms contained in TransCanada’s 2011 Annual Report.

These condensed consolidated financial statements reflect adjustments, all of which are normal recurring adjustments that are, in the opinion of management, necessary to reflect the financial position and results of operations for the respective periods. These condensed consolidated financial statements do not include all disclosures required in the annual financial statements and should be read in conjunction with the 2011 audited Consolidated Financial Statements included in TransCanada’s 2011 Annual Report. Certain comparative figures have been reclassified to conform with the financial statement presentation adopted for the current period.

Earnings for interim periods may not be indicative of results for the fiscal year in the Company’s Natural Gas Pipeline segment due to seasonal fluctuations in short-term throughput volumes on U.S. pipelines. Earnings for interim periods may also not be indicative of results for the fiscal year in the Company’s Energy segment due to the impact of seasonal weather conditions on customer demand and market pricing in certain of the Company’s investments in electrical power generation plants and non-regulated gas storage facilities.

In preparing these financial statements, 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. In the opinion of management, these condensed consolidated financial statements have been properly prepared within reasonable limits of materiality and within the framework of the Company’s accounting policies.

The condensed consolidated financial statements include the accounts of TransCanada and its subsidiaries. The Company consolidates its interests in entities over which it is able to exercise control. To the extent there are interests owned by other parties, these interests are included in Non-Controlling Interests. TransCanada uses the equity method of accounting for joint ventures in which the Company is able to exercise joint control and for investments in which the Company is able to exercise significant influence. TransCanada records its proportionate share of undivided interests in certain assets.

The Company uses the liability method of accounting for income taxes. This method requires the recognition of deferred income tax assets and liabilities for future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred income tax assets and liabilities are measured using enacted tax rates at the balance sheet date that are anticipated to apply to taxable income in the years in which temporary differences are expected to be recovered or settled. Changes to these balances are recognized in income in the period during which they occur except for changes in balances related to the Canadian Mainline, Alberta System and Foothills, which are deferred until they are refunded or recovered in tolls, as permitted by the NEB.

The Company sponsors defined benefit pension plans (DB Plans), defined contribution plans (DC Plans), a Savings Plan and other post-retirement benefit plans. Contributions made by the Company to the DC Plans and Savings Plan are expensed in the period in which contributions are made. The cost of the DB Plans and other post-retirement benefits received by employees is actuarially determined using the projected benefit method pro-rated based on service and management’s best estimate of expected plan investment performance, salary escalation, retirement age of employees and expected health care costs.

The DB Plans’ assets are measured at fair value. The expected return on the DB Plans’ assets is determined using market-related values based on a five-year moving average value for all of the DB Plans’ assets. Past service costs are amortized over the expected average remaining service life of the employees. Adjustments arising from plan amendments are amortized on a straight-line basis over the average remaining service period of employees active at the date of amendment. The Company recognizes the overfunded or underfunded status of its DB Plans as an asset or liability on its Balance Sheet and recognizes changes in that funded status through Other Comprehensive Income/(Loss) (OCI) in the year in which the change occurs. The excess of net actuarial gains or losses over 10 per cent of the greater of the benefit obligation and the market-related value of the DB Plans’ assets, if any, is amortized out of Accumulated Other Comprehensive Income/(Loss) (AOCI) over the average remaining service period of the active employees. For certain regulated operations, post-retirement benefit amounts are recoverable through tolls as benefits are funded. The Company records any unrecognized gains and losses or changes in actuarial assumptions related to these post-retirement benefit plans as either regulatory assets or liabilities. The regulatory assets or liabilities are amortized on a straight-line basis over the average remaining service life of active employees. When the restructuring of a benefit plan gives rise to both a curtailment and a settlement, the curtailment is accounted for prior to the settlement.

The Company has medium-term incentive plans, under which payments are made to eligible employees. The expense related to these incentive plans is accounted for on an accrual basis. Under these plans, benefits vest when certain conditions are met, including the employees’ continued employment during a specified period and achievement of specified corporate performance targets.

The Company records long-term debt transaction costs as deferred assets and amortizes these costs using the effective interest method for all costs except those related to the Canadian natural gas regulated pipelines, which continue to be amortized on a straight-line basis in accordance with the provisions of tolling mechanisms.

Upon issuance, the Company records the fair value of certain guarantees entered into by the Company on behalf of partially owned entities for which contingent payments may be made. The fair value of these guarantees is estimated by discounting the cash flows that would be incurred by the Company if letters of credit were used in place of the guarantees. Guarantees are recorded as an increase to Equity Investments, Plant, Property and Equipment, or a charge to Net Income, and a corresponding liability is recorded in Deferred Amounts.

Effective January 1, 2012, the Company adopted the ASU on testing goodwill for impairment as issued by the FASB. Adoption of the ASU has resulted in a change in the accounting policy related to testing goodwill for impairment, as the Company is now permitted under U.S. GAAP to first assess qualitative factors affecting the fair value of a reporting unit in comparison to the carrying amount as a basis for determining whether it is required to proceed to the two-step quantitative impairment test.

In December 2011, the FASB issued amended guidance to enhance disclosures that will enable users of the financial statements to evaluate the effect, or potential effect, of netting arrangements on an entity’s financial position. The amendments result in enhanced disclosures by requiring additional information regarding financial instruments and derivative instruments that are either offset in accordance with current U.S. GAAP or subject to an enforceable master netting arrangement. This guidance is effective for annual periods beginning on or after January 1, 2013. Adoption of these amendments is expected to result in an increase in disclosure regarding financial instruments which are subject to offsetting as described in this amendment.

Three months ended September 30 (unaudited)	Natural Gas Pipelines						Oil Pipelines						Energy						Corporate						Total
(millions of Canadian dollars)	2012			2011			2012			2011			2012			2011			2012			2011			2012			2011

Revenues		1,058			1,036			259			229			809			778			-			-			2,126			2,043
Income from equity investments		37			39			-			-			34			88			-			-			71			127
Plant operating costs and other		(435	)		(376	)		(82	)		(73	)		(220	)		(250	)		(21	)		(18	)		(758	)		(717	)
Commodity purchases resold		-			-			-			-			(337	)		(271	)		-			-			(337	)		(271	)
Depreciation and amortization		(231	)		(231	)		(37	)		(38	)		(70	)		(65	)		(4	)		(3	)		(342	)		(337	)
		429			468			140			118			216			280			(25	)		(21	)		760			845
Interest expense																										(249	)		(240	)
Interest income and other																										34			(43	)
Income before Income Taxes																										545			562
Income taxes expense																										(134	)		(131	)
Net Income																										411			431
Net Income Attributable to Non-Controlling Interests																										(29	)		(32	)
Net Income Attributable to Controlling Interests																										382			399
Preferred Share Dividends																										(13	)		(13	)
Net Income Attributable to Common Shares																										369			386

Nine months ended September 30 (unaudited)	Natural Gas Pipelines						Oil Pipelines(1)						Energy						Corporate						Total
(millions of Canadian dollars)	2012			2011			2012			2011			2012			2011			2012			2011			2012			2011

Revenues		3,177			3,107			769			575			1,972			2,142			-			-			5,918			5,824
Income from equity investments		120			117			-			-			76			211			-			-			196			328
Plant operating costs and other		(1,246	)		(1,064	)		(243	)		(167	)		(638	)		(685	)		(65	)		(57	)		(2,192	)		(1,973	)
Commodity purchases resold		-			-			-			-			(758	)		(782	)		-			-			(758	)		(782	)
Depreciation and amortization		(697	)		(688	)		(109	)		(95	)		(215	)		(194	)		(11	)		(10	)		(1,032	)		(987	)
		1,354			1,472			417			313			437			692			(76	)		(67	)		2,132			2,410
Interest expense																										(730	)		(686	)
Interest income and other																										70			12
Income before Income Taxes																										1,472			1,736
Income taxes expense																										(348	)		(449	)
Net Income																										1,124			1,287
Net Income Attributable to Non-Controlling Interests																										(90	)		(96	)
Net Income Attributable to Controlling Interests																										1,034			1,191
Preferred Share Dividends																										(41	)		(41	)
Net Income Attributable to Common Shares																										993			1,150

At September 30, 2012, the total unrecognized tax benefit of uncertain tax positions was approximately $50 million (December 31, 2011 - $52 million). TransCanada recognizes interest and penalties related to income tax uncertainties in income tax expense. Included in net tax expense for the three and nine months ended September 30, 2012 is a reversal of interest expense of $2 million and $1 million, respectively, and nil for penalties (2011 – reversal of interest expense of $11 million and $13 million, respectively, and nil for penalties). At September 30, 2012, the Company had $6 million accrued for interest expense and nil accrued for penalties (December 31, 2011 - $7 million accrued for interest expense and nil accrued for penalties).

TransCanada expects the enactment of certain Canadian Federal tax legislation in the next twelve months which is expected to result in a favourable income tax adjustment of approximately $25 million. Otherwise, subject to the results of audit examinations by taxation authorities and other legislative amendments, TransCanada does not anticipate further adjustments to the unrecognized tax benefits during the next twelve months that would have a material impact on its financial statements.

	Three months ended September 30										Nine months ended September 30
(unaudited)	Pension Benefit Plans						Other Post- retirement Benefit Plans				Pension Benefit Plans						Other Post- retirement Benefit Plans
(millions of Canadian dollars)	2012			2011			2012		2011		2012			2011			2012			2011

Service cost		16			14			1		-		49			41			2			1
Interest cost		24			23			2		2		71			68			6			6
Expected return on plan assets		(28	)		(29	)		-		-		(85	)		(85	)		(1	)		(1	)
Amortization of actuarial loss		5			3			-		-		14			8			1			1
Amortization of past service cost		-			-			-		-		1			1			-			-
Amortization of regulatory asset		5			3			-		-		15			10			-			-
Amortization of transitional obligation related to regulated business		-			-			1		-		-			-			2			1
Net Benefit Cost Recognized		22			14			4		2		65			43			10			8

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, the fair value of derivative assets and notes receivable. The carrying amounts and fair values of these financial assets, except amounts for derivative assets, are included in Accounts Receivable and Other in the Non-Derivative Financial Instruments Summary table below. 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 September 30, 2012, there were no significant amounts past due or impaired.

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 September 30, 2012, the Company had designated as a net investment hedge U.S. dollar-denominated debt with a carrying value of $11.0 billion (US$11.2 billion) and a fair value of $14.4 billion (US$14.6 billion). At September 30, 2012, $60 million (December 31, 2011 - $79 million) was included in Other Current Assets, $96 million (December 31, 2011 - $66 million) was included in Intangibles and Other Assets, $6 million (December 31, 2011 - $15 million) was included in Accounts Payable and $18 million (December 31, 2011 - $41 million) was included in Deferred Amounts for the fair value of forwards and swaps used to hedge the Company’s net U.S. dollar investment in self-sustaining foreign operations.

	September 30, 2012			December 31, 2011
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 2012 to 2019)(2)		131	US 3,950		93		US 3,850

U.S. dollar forward foreign exchange contracts (maturing 2012)		1	US 100		(4	)	US 725

		132	US 4,050		89		US 4,575

	September 30, 2012				December 31, 2011
(unaudited) (millions of dollars)	Carrying Amount(1)		Fair Value(2)		Carrying Amount(1)		Fair Value(2)

Financial Assets
Cash and cash equivalents		494		494		654		654
Accounts receivable and other(3)		1,102		1,158		1,359		1,403
Available-for-sale assets(3)		32		32		23		23
		1,628		1,684		2,036		2,080

Financial Liabilities(4)
Notes payable		1,470		1,470		1,863		1,863
Accounts payable and deferred amounts(5)		1,069		1,069		1,329		1,329
Accrued interest		346		346		365		365
Long-term debt		18,969		24,938		18,659		23,757
Junior subordinated notes		983		1,048		1,016		1,027
		22,837		28,871		23,232		28,341

(1)

Recorded at amortized cost, except for US$350 million (December 31, 2011 – US$350 million) of Long-Term Debt that is recorded at fair value. This debt which is recorded at fair value on a recurring basis is classified in Level II of the fair value category using the income approach based on interest rates from external data service providers.

(4)

Consolidated Net Income in the three and nine months ended September 30, 2012 included losses of $2 million and $14 million, respectively (2011 – losses of $7 million and $18 million, respectively) for fair value adjustments related to interest rate swap agreements on US$350 million (2011 – US$350 million) of Long-Term Debt. There were no other unrealized gains or losses from fair value adjustments to the non-derivative financial instruments.

September 30, 2012
(unaudited) (millions of Canadian dollars unless otherwise indicated)	Power			Natural Gas			Foreign Exchange			Interest

Derivative Financial Instruments Held for Trading(1)
Fair Values(2)
Assets		$168			$107			$7			$16
Liabilities		$(195	)		$(126	)		$(13	)		$(16	)
Notional Values
Volumes(3)
Purchases		31,717			99			-			-
Sales		32,700			73			-			-
Canadian dollars		-			-			-			620
U.S. dollars		-			-		US 1,255			US 200
Cross-currency		-			-		47/US 37				-

Net unrealized gains/(losses) in the period(4)
Three months ended September 30, 2012		$1			$12			$13			-
Nine months ended September 30, 2012		$(17	)		$2			$5			-

Net realized (losses)/gains in the period(4)
Three months ended September 30, 2012		$4			$(4	)		$6			-
Nine months ended September 30, 2012		$8			$(19	)		$21			-

Maturity dates		2012-2016			2012-2016			2012-2013			2013-2016

Derivative Financial Instruments in Hedging Relationships(5)(6)
Fair Values(2)
Assets		$85			-			-			$13
Liabilities		$(130	)		$(6	)		$(41	)		-
Notional Values
Volumes(3)
Purchases		17,745			3			-			-
Sales		7,467			-			-			-
U.S. dollars		-			-		US 42			US 350
Cross-currency		-			-		136/US 100				-

Net realized gains/(losses) in the period(4)
Three months ended September 30, 2012		$(49	)		$(7	)		-			$2
Nine months ended September 30, 2012		$(101	)		$(21	)		-			$5

Maturity dates		2012-2018			2012-2013			2012-2014			2013-2015

(1)

All derivative financial instruments held for trading 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.

(4)

Realized and unrealized gains and losses on derivative financial instruments held for trading used to purchase and sell power and natural gas are included net 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 $13 million and a notional amount of US$350 million. Net realized gains on fair value hedges for the three and nine months ended September 30, 2012 were $2 million and $6 million, respectively, and were included in Interest Expense. In the three and nine months ended September 30, 2012, the Company did not record any amounts in Net Income related to ineffectiveness for fair value hedges.

2011
(unaudited) (millions of Canadian dollars unless otherwise indicated)	Power			Natural Gas			Foreign Exchange			Interest

Derivative Financial Instruments Held for Trading(1)
Fair Values(2)(3)
Assets		$185			$176			3			$22
Liabilities		$(192	)		$(212	)		$(14	)		$(22	)
Notional Values(3)
Volumes(4)
Purchases		21,905			103			-			-
Sales		21,334			82			-			-
Canadian dollars		-			-			-			684
U.S. dollars		-			-		US 1,269			US 250
Cross-currency		-			-		47/US 37				-

Net unrealized gains/(losses) in the period(5)
Three months ended September 30, 2011		$6			$(13	)		$(41	)		$1
Nine months ended September 30, 2011		$9			$(39	)		$(41	)		$1

Net realized gains/(losses) in the period(5)
Three months ended September 30, 2011		$15			$(20	)		$(7	)		-
Nine months ended September 30, 2011		$20			$(61	)		$26			$1

Maturity dates		2012-2016			2012-2016			2012			2012-2016

Derivative Financial Instruments in Hedging Relationships(6)(7)
Fair Values(2)(3)
Assets		$16			$3			-			$13
Liabilities		$(277	)		$(22	)		$(38	)		$(1	)
Notional Values(3)
Volumes(4)
Purchases		17,188			8			-			-
Sales		8,061			-			-			-
U.S. dollars		-			-		US 73			US 600
Cross-currency		-			-		136/US 100				-

Net realized losses in the period(5)
Three months ended September 30, 2011		$(56	)		$(6	)		-			$(4	)
Nine months ended September 30, 2011		$(112	)		$(14	)		-			$(13	)

Maturity dates		2012-2017			2012-2013			2012-2014			2012-2015

(1)

(5)

(13)

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 $13 million and a notional amount of US$350 million at December 31, 2011. Net realized gains on fair value hedges for the three and nine months ended September 30, 2011 were $1 million and $5 million, respectively, and were included in Interest Expense. In the three and nine months ended September 30, 2011, the Company did not record any amounts in Net Income related to ineffectiveness for fair value hedges.

	Cash Flow Hedges
Three months ended September 30 (unaudited)	Power					Natural Gas						Foreign Exchange					Interest
(millions of dollars, pre-tax)	2012		2011			2012			2011			2012			2011		2012		2011

Changes in fair value of derivative instruments recognized in OCI (effective portion)		96		(25	)		(3	)		(14	)		(5	)		13		-		(1	)
Reclassification of gains and (losses) on derivative instruments from AOCI to Net Income (effective portion)		54		26			15			27			-			-		4		11
Gains on derivative instruments recognized in earnings (ineffective portion)		5		1			1			1			-			-		-		-

	Cash Flow Hedges
Nine months ended September 30 (unaudited)	Power					Natural Gas						Foreign Exchange					Interest
(millions of dollars, pre-tax)	2012		2011			2012			2011			2012			2011		2012		2011

Changes in fair value of derivative instruments recognized in OCI (effective portion)		74		(128	)		(17	)		(39	)		(5	)		6		-		(1	)
Reclassification of gains on derivative instruments from AOCI to Net Income (effective portion)		129		58			43			80			-			-		14		33
Gains on derivative instruments recognized in earnings (ineffective portion)		6		2			-			-			-			-		-		-

Derivative contracts entered into to manage market risk often contain financial assurance provisions that allow parties to the contracts to manage credit risk. These provisions may require collateral to be provided if a credit-risk-related contingent event occurs, such as a downgrade in the Company’s credit rating to non-investment grade. Based on contracts in place and market prices at September 30, 2012, the aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a net liability position was $41 million (2011 - $77 million), for which the Company had provided collateral of nil (2011 - $6 million) in the normal course of business. If the credit-risk-related contingent features in these agreements were triggered on September 30, 2012, the Company would have been required to provide collateral of $41 million (2011 - $71 million) to its counterparties. Collateral may also need to be provided should the fair value of derivative instruments exceed pre-defined contractual exposure limit thresholds. The Company has sufficient liquidity in the form of cash and undrawn committed revolving bank lines to meet these contingent obligations should they arise.

In Level II, the fair value of interest rate and foreign exchange derivative assets and liabilities is determined using the income approach. The fair value of power and gas commodity assets and liabilities is determined using the market approach. Under both approaches, valuation is based on the extrapolation of inputs, other than quoted prices included within Level I, for which all significant inputs are observable directly or indirectly. Such inputs include published exchange rates, interest rates, interest rate swap curves, yield curves, and broker quotes from external data service providers. Transfers between Level I and Level II would occur when there is a change in market circumstances. There were no transfers between Level I and Level II in the nine months ended September 30, 2012 and 2011.

In Level III, the fair value of assets and liabilities measured on a recurring basis is determined using a market approach based on inputs that are unobservable and significant to the overall fair value measurement. Assets and liabilities measured at fair value can fluctuate between Level II and Level III depending on the proportion of the value of the contract that extends beyond the time frame for which inputs are considered to be observable. As contracts near maturity and observable market data becomes available, they are transferred out of Level III and into Level II.

Long-dated commodity transactions in certain markets where liquidity is low are included in Level III of the fair value hierarchy, as the related commodity prices are not readily observable. Long-term electricity prices are estimated using a third-party modelling tool which takes into account physical operating characteristics of generation facilities in the markets in which the Company operates. Inputs into the model include market fundamentals such as fuel prices, power supply additions and retirements, power demand, seasonal hydro conditions and transmission constraints. Long-term North American natural gas prices are based on a view of future natural gas supply and demand, as well as exploration and development costs. Long-term prices are reviewed by management and the Board on a periodic basis. Significant decreases in fuel prices or demand for electricity or natural gas, or increases in the supply of electricity or natural gas may result in a lower fair value measurement of contracts included in Level III.

	Quoted Prices in Active Markets (Level I)						Significant Other Observable Inputs (Level II)						Significant Unobservable Inputs (Level III)						Total
(unaudited) (millions of dollars, pre-tax)	Sept 30 2012			Dec 31 2011			Sept 30 2012			Dec 31 2011			Sept 30 2012			Dec 31 2011			Sept 30 2012			Dec 31 2011
Derivative Financial Instrument Assets:
Interest rate contracts		-			-			29			36			-			-			29			36
Foreign exchange contracts		-			-			160			141			-			-			160			141
Power commodity contracts		-			-			242			201			9			-			251			201
Gas commodity contracts		90			124			17			55			-			-			107			179
Derivative Financial Instrument Liabilities:
Interest rate contracts		-			-			(16	)		(23	)		-			-			(16	)		(23	)
Foreign exchange contracts		-			-			(75	)		(102	)		-			-			(75	)		(102	)
Power commodity contracts		-			-			(318	)		(454	)		(5	)		(15	)		(323	)		(469	)
Gas commodity contacts		(114	)		(208	)		(18	)		(26	)		-			-			(132	)		(234	)
Non-Derivative Financial Instruments:
Available-for-sale assets		32			23			-			-			-			-			32			23
		8			(61	)		21			(172	)		4			(15	)		33			(248	)

The following table presents the net change in the Level III fair value category:

	Derivatives(1)
	Three months ended						Nine months ended
(unaudited)	September 30						September 30
(millions of dollars, pre-tax)	2012			2011			2012			2011

Balance at beginning of period		7			(30	)		(15	)		(8	)
New contracts		-			-			-			1
Settlements		-			1			(1	)		1
Transfers out of Level III		(12	)		2			(10	)		2
Total gains included in Net Income(2)		7			-			8			-
Total gains/(losses) included in OCI		2			10			22			(13	)
Balance at end of period		4			(17	)		4			(17	)

TransCanada and its subsidiaries are subject to various legal proceedings, arbitrations and actions arising in the normal course of business. While the final outcome of such legal proceedings and actions cannot be predicted with certainty, it is the opinion of management that the resolution of such proceedings and actions will not have a material impact on the Company’s consolidated financial position or results of operations.

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 2012, TransCanada currently expects spot prices to be less than the floor price for the year, therefore no amounts recorded in revenues in first nine months of 2012 are expected to be repaid.

TransCanada and its joint venture partners on Bruce Power, Cameco Corporation and BPC Generation Infrastructure Trust (BPC), have severally guaranteed one-third of certain contingent financial obligations of Bruce B related to power sales agreements, a lease agreement and contractor services. The guarantees have terms ranging from 2018 to perpetuity. In addition, TransCanada and BPC have each severally guaranteed one-half of certain contingent financial obligations related to an agreement with the Ontario Power Authority to refurbish and restart Bruce A power generation units. The guarantees have terms ending in 2018 and 2019. TransCanada’s share of the potential exposure under these Bruce A and Bruce B guarantees was estimated to be $760 million at September 30, 2012. The fair value of these Bruce Power guarantees at September 30, 2012 is estimated to be $15 million. The Company’s exposure under certain of these guarantees is unlimited.

In addition to the guarantees for Bruce Power, the Company and its partners in certain other jointly owned entities have either (i) jointly and severally, (ii) jointly or (iii) severally guaranteed the financial performance of these entities related primarily to redelivery of natural gas, power purchase arrangement (PPA) payments and the payment of liabilities. TransCanada’s share of the potential maximum exposure under these assurances was estimated at September 30, 2012 to range from $160 million to $431 million. The fair value of these guarantees at September 30, 2012 is estimated to be $68 million, which has been included in Deferred Amounts. For certain of these entities, any payments made by TransCanada under these guarantees in excess of its ownership interest are to be reimbursed by its partners.

(unaudited) (millions of dollars)	September 30 2012			December 31 2011

Current
Other current assets		302			361
Accounts payable		(340	)		(485	)

Long term
Intangibles and other assets		250			202
Deferred amounts		(211	)		(349	)