TC Energy (TRP) 6-K/A Form 6-K/A Dated April 26, 2013

EXHIBIT 13.2

Condensed consolidated statement of income

three months ended March 31
(unaudited - millions of Canadian $ except per share amounts)	2013	2012
Revenues
Natural gas pipelines	1,157	1,085
Oil pipelines	271	259
Energy	824	601
	2,252	1,945
Income from Equity Investments	93	60
Operating and Other Expenses
Plant operating costs and other	641	592
Commodity purchases resold	376	213
Property taxes	109	115
Depreciation and amortization	367	344
	1,493	1,264
Financial Charges/(Income)
Interest expense	258	242
Interest income and other	(13)	(31)
	245	211
Income before Income Taxes	607	530
Income Taxes Expense
Current	79	56
Deferred	36	73
	115	129
Net Income	492	401
Net income attributable to non-controlling interests	31	35
Net Income Attributable to Controlling Interests	461	366
Preferred share dividends	15	14
Net Income Attributable to Common Shares	446	352
Net Income per Common Share
Basic and diluted	$0.63	$0.50
Dividends Declared per Common Share	$0.46	$0.44
Weighted Average Number of Common Shares (millions)
Basic	706	704
Diluted	707	705

See accompanying notes to the condensed consolidated financial statements.

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Condensed consolidated statement of comprehensive income

three months ended March 31
(unaudited - millions of Canadian $)	2013		2012
Net Income		492		401
Other Comprehensive Income/(Loss), Net of Income Taxes
Foreign currency translation gains and losses on investments in foreign operations		111		(107	)
Change in fair value of net investment hedges		(49)		38
Change in fair value of cash flow hedges		21		(45	)
Reclassification to net income of gains and losses on cash flow hedges		(4)		45
Reclassification to net income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans		6		10
Other comprehensive income on equity investments		(1)		5
Other comprehensive income/(loss) (Note 7)		84		(54	)
Comprehensive Income		576		347
Comprehensive income attributable to non-controlling interests		51		18
Comprehensive Income Attributable to Controlling Interests		525		329
Preferred share dividends		15		14
Comprehensive Income Attributable to Common Shares		510		315

See accompanying notes to the condensed consolidated financial statements.

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Condensed consolidated statement of cash flows

three months ended March 31
(unaudited - millions of Canadian $)	2013			2012
Cash Generated from Operations
Net income		492			401
Depreciation and amortization		367			344
Deferred income taxes		36			73
Income from equity investments		(93	)		(60	)
Distributed earnings received from equity investments		84			83
Employee post-retirement benefits funding lower than expense		15			7
Other		15			23
Increase of operating working capital		(210	)		(169	)
Net cash provided by operations		706			702
Investing Activities
Capital expenditures		(929	)		(464	)
Equity investments		(32	)		(216	)
Deferred amounts and other		(20	)		(37	)
Net cash used in investing activities		(981	)		(717	)
Financing Activities
Dividends on common and preferred shares		(315	)		(310	)
Distributions paid to non-controlling interests		(35	)		(33	)
Notes payable repaid, net		(829	)		(46	)
Long-term debt issued, net of issue costs		734			492
Repayment of long-term debt		(14	)		(548	)
Common shares issued, net of issue costs		32			14
Preferred shares issued, net of issue costs		586			-
Net cash provided by/(used in) financing activities		159			(431	)
Effect of Foreign Exchange Rate Changes on Cash and Cash Equivalents		8			(12	)
Decrease in Cash and Cash Equivalents		(108	)		(458	)
Cash and Cash Equivalents
Beginning of period		551			654
Cash and Cash Equivalents
End of period		443			196

See accompanying notes to the condensed consolidated financial statements.

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Condensed consolidated balance sheet

	March 31			December 31
(unaudited - millions of Canadian $)	2013			2012
ASSETS
Current Assets
Cash and cash equivalents		443			551
Accounts receivable		1,031			1,052
Inventories		231			224
Other		746			997
		2,451			2,824
Plant, Property and Equipment, net of accumulated depreciation of $16,908 and $16,540, respectively		34,356			33,713
Equity Investments		5,396			5,366
Goodwill		3,530			3,458
Regulatory Assets		1,915			1,629
Intangible and Other Assets		1,386			1,343
		49,034			48,333
LIABILITIES
Current Liabilities
Notes payable		1,474			2,275
Accounts payable and other		1,971			2,344
Accrued interest		352			368
Current portion of long-term debt		1,660			894
		5,457			5,881
Regulatory Liabilities		275			268
Other Long-Term Liabilities		859			882
Deferred Income Tax Liabilities		4,001			3,953
Long-Term Debt		18,266			18,019
Junior Subordinated Notes		1,015			994
		29,873			29,997
EQUITY
Common shares, no par value		12,106			12,069
Issued and outstanding:                          March 31, 2013 - 706 million shares
December 31, 2012 - 705 million shares
Preferred shares		1,810			1,224
Additional paid-in capital		376			379
Retained earnings		4,809			4,687
Accumulated other comprehensive loss (Note 7)		(1,384	)		(1,448	)
Controlling Interests		17,717			16,911
Non-controlling interests		1,444			1,425
		19,161			18,336
		49,034			48,333
Contingencies and Guarantees (Note 10)

See accompanying notes to the condensed consolidated financial statements.

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Condensed consolidated statement of equity

	Three months ended
	March 31
(unaudited - millions of Canadian $)	2013	2012
Common Shares
Balance at beginning of period	12,069	12,011
Shares issued on exercise of stock options	37	15
Balance at end of period	12,106	12,026
Preferred Shares
Balance at beginning of period	1,224	1,224
Share issuance, net of issue costs	586	-
Balance at end of period	1,810	1,224
Additional Paid-In Capital
Balance at beginning of period	379	380
Issuance of stock options, net of exercises	(3	)             (1	)
Balance at end of period	376	379
Retained Earnings
Balance at beginning of period	4,687	4,628
Net income attributable to controlling interests	461	366
Common share dividends	(324	)         (310	)
Preferred share dividends	(15	)           (14	)
Balance at end of period	4,809	4,670
Accumulated Other Comprehensive Loss
Balance at beginning of period	(1,448	)      (1,449	)
Other comprehensive income/(loss)	64	(37	)
Balance at end of period	(1,384	)      (1,486	)
Equity Attributable to Controlling Interests	17,717	16,813
Equity Attributable to Non-Controlling Interests
Balance at beginning of period	1,425	1,465
Net income attributable to non-controlling interests
TC PipeLines, LP	19	26
Preferred share dividends of TCPL	6	6
Portland	6	3
Other comprehensive income/(loss) attributable to non-controlling interests	20	(17	)
Distributions to non-controlling interests	(35	)           (33	)
Other	3	(3	)
Balance at end of period	1,444	1,447
Total Equity	19,161	18,260

See accompanying notes to the condensed consolidated financial statements.

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Notes to condensed consolidated financial statements

(unaudited)

1.   Basis of Presentation

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). The accounting policies applied are consistent with those outlined in TransCanada’s annual audited consolidated financial statements for the year ended December 31, 2012. Capitalized and abbreviated terms that are used but not otherwise defined herein are identified in TransCanada’s 2012 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 2012 audited Consolidated Financial Statements included in TransCanada’s 2012 Annual Report.  Certain comparative figures have been reclassified to conform with the current period’s presentation.

Earnings for interim periods may not be indicative of results for the fiscal year in the Company’s Natural Gas Pipeline segment due to the timing of regulatory decisions and 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.

USE OF ESTIMATES AND JUDGEMENTS

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 significant accounting policies included in the consolidated financial statements for the year ended December 31, 2012, except as described in Note 2, Changes in accounting policies.

2.   Changes in Accounting Policies

CHANGES IN ACCOUNTING POLICIES FOR 2013

Balance Sheet Offsetting/Netting

Effective January 1, 2013, the Company adopted the Accounting Standards Update (ASU) on disclosures about balance sheet offsetting as issued by the Financial Accounting Standards Board (FASB) to enable understanding of the effects of netting arrangements on the Company’s financial position. Adoption of the ASU has resulted in increased qualitative and quantitative disclosures regarding certain derivative instruments that are either offset in accordance with current U.S. GAAP or are subject to a master netting arrangement or similar agreement.

Accumulated Other Comprehensive Income

Effective January 1, 2013, the Company adopted the ASU on reporting of amounts reclassified out of accumulated other comprehensive income (AOCI) as issued by the FASB. Adoption of the ASU has resulted in providing additional qualitative and quantitative disclosures regarding significant amounts reclassified out of accumulated other comprehensive income into net income.

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FUTURE ACCOUNTING CHANGES

Obligations Resulting from Joint and Several Liability Arrangements

In February 2013, the FASB issued guidance for the recognition, measurement and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date. Examples of obligations within the scope of this ASU include debt arrangements, other contractual obligations, and settled litigation and judicial rulings. This ASU is effective retrospectively for fiscal years, and interim periods within those years, beginning after December 15, 2013. The Company is currently evaluating the impact of the adoption of this ASU on its consolidated financial statements, but does not expect it to have a material impact.

Foreign Currency Matters - Cumulative Translation Adjustment

In March 2013, the FASB issued amended guidance related to the release of the cumulative translation adjustment into net income when a parent either sells a part or all of its investment in a foreign entity or no longer holds a controlling financial interest in a subsidiary or group of assets that is a business. This ASU is effective prospectively for fiscal years, and interim reporting periods within those years, beginning after December 15, 2013. Early adoption is permitted as of the beginning of the entity's fiscal year. The Company is currently evaluating the impact of the adoption of this ASU on its consolidated financial statements, but does not expect it to have a material impact.

3. Segmented Information

three months ended March 31	Natural gas pipelines		Oil pipelines		Energy		Corporate		Total
(unaudited - millions of Canadian $)	2013	2012	2013	2012	2013	2012	2013	2012	2013	2012
Revenues	1,157	1,085	271	259	824	601	-	-	2,252	1,945
Income from equity investments	40	46	-	-	53	14	-	-	93	60
Plant operating costs and other	(318)	(327)	(79)	(69)	(210)	(167)	(34)	(29)	(641)	(592)
Commodity purchases resold	-	-	-	-	(376)	(213)	-	-	(376)	(213)
Property taxes	(78)	(79)	(13)	(17)	(18)	(19)	-	-	(109)	(115)
Depreciation and amortization	(253)	(232)	(37)	(36)	(74)	(73)	(3)	(3)	(367)	(344)
	548	493	142	137	199	143	(37)	(32)	852	741
Interest expense									(258)	(242)
Interest income and other									13	31
Income before Income Taxes									607	530
Income taxes expense									(115)	(129)
Net Income									492	401
Net Income Attributable to Non-Controlling Interests									(31)	(35)
Net Income Attributable to Controlling Interests									461	366
Preferred Share Dividends									(15)	(14)
Net Income Attributable to Common Shares									446	352

TOTAL ASSETS

(unaudited - millions of Canadian $)	March 31, 2013	December 31, 2012
Natural Gas Pipelines	23,785	23,210
Oil Pipelines	10,786	10,485
Energy	13,173	13,157
Corporate	1,290	1,481
	49,034	48,333

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4. Income Taxes

At March 31, 2013, the total unrecognized tax benefit of uncertain tax positions is approximately $50 million (December 31, 2012 - $49 million). TransCanada recognizes interest and penalties related to income tax uncertainties in income tax expense. Included in net tax expense for the three months ended March 31, 2013 is $1 million of interest expense and nil for penalties (March 31, 2012 - $1 million for interest expense and nil for penalties). At March 31, 2013, the Company had $6 million accrued for interest expense and nil accrued for penalties (December 31, 2012 - $5 million accrued for interest expense and nil for penalties).

The effective tax rates for the three-month periods ended March 31, 2013 and 2012 were 19 per cent and 24 per cent, respectively. The lower effective tax rate in 2013 was a result of the impact of the NEB’s decision on the Canadian Restructuring Proposal.

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 taxing 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.

5. Long-Term Debt

In the three months ended March 31, 2013, the Company capitalized interest related to capital projects of $55 million (March 31, 2012 - $74 million).

In January 2013, TransCanada PipeLines Limited issued US$750 million of 0.75 per cent senior notes due in 2016.

6. Share Capital

PREFERRED SHARE ISSUE

In March 2013, TransCanada completed a public offering of 24 million Series 7 cumulative redeemable first preferred shares under its November 2011 base shelf prospectus. The Series 7 preferred shares were issued at $25 per share resulting in gross proceeds of $600 million. The holders of the Series 7 preferred shares are entitled to receive fixed cumulative dividends at an annual rate of $1.00 per share, payable quarterly for the initial period ending April 30, 2019, with the first dividend payment scheduled for April 30, 2013. The dividend rate will reset on April 30, 2019 and every five years thereafter to a yield per annum equal to the sum of the then five year Government of Canada bond yield and 2.38 per cent. The preferred shares are redeemable by TransCanada on or after April 30, 2019 and on April 30 of every fifth year thereafter at a price of $25 per share plus accrued and unpaid dividends. The net proceeds of this offering are expected to be used to partially fund capital projects, for general corporate purposes and to repay short-term debt.

The Series 7 preferred shareholders will have the right to convert their shares into Series 8 cumulative redeemable first preferred shares on April 30, 2019 and on April 30 of every fifth year thereafter. The holders of Series 8 preferred shares will be entitled to receive quarterly floating rate cumulative dividends at a yield per annum equal to the sum of the then 90 day Government of Canada treasury bill rate and 2.38 per cent.

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7. Other Comprehensive Income/(Loss) And Accumulated Other Comprehensive Loss

Components of other comprehensive income/(loss) including non-controlling interests and the related tax effects are as follows:

three months ended March 31, 2013 (unaudited - millions of Canadian $)	Before tax amount		Income tax recovery/(expense)		Net of tax amount
Foreign currency translation gains and losses on investments in foreign operations	77		34		111
Change in fair value of net investment hedges	(66	)	17		(49	)
Change in fair value of cash flow hedges	38		(17	)	21
Reclassification to net income of gains and losses on cash flow hedges	(7	)	3		(4	)
Reclassification to net income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans	10		(4	)	6
Other comprehensive income on equity investments	(1	)	-		(1	)
Other comprehensive income	51		33		84

three months ended March 31, 2013 (unaudited - millions of Canadian $) Before tax amount Income tax recovery/(expense) Net of tax amount

Foreign currency translation gains and losses on investments in foreign operations	(85	)	(22	)	(107	)
Change in fair value of net investment hedges	49		(11	)	38
Change in fair value of cash flow hedges	(79	)	34		(45	)
Reclassification to net income of gains and losses on cash flow hedges	66		(21	)	45
Reclassification to net income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans	6		4		10
Other comprehensive income on equity investments	6		(1	)	5
Other comprehensive loss	(37	)	(17	)	(54	)

The changes in accumulated other comprehensive loss by component, for the three months ended March 31, 2013, are as follows:

(unaudited - millions of Canadian $)	Currency translation adjustments		Cash flow hedges		Pension and OPEB plan adjustments		Total1
AOCI Balance at January 1, 2013	(707	)	(110	)	(631	)	(1,448	)
Other comprehensive income before reclassifications2	42		19		1		62
Amounts reclassified from accumulated other comprehensive loss3	-		(4	)	6		2
Net current period other comprehensive income	42		15		7		64
AOCI Balance at March 31, 2013	(665	)	(95	)	(624	)	(1,384	)

1 All amounts are net of tax. Amounts in parentheses indicate losses.

2 Other comprehensive income before reclassifications on currency translation adjustments is net of non-controlling interest of $20 million.

3 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 $24 million ($16 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.

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Details about reclassifications out of accumulated other comprehensive loss, for the three months ended March 31, 2013, are as follows:

Details about accumulated other comprehensive loss components (unaudited - millions of Canadian $)	Amounts reclassified from accumulated other comprehensive loss1	Affected line item in the condensed consolidated statement of income
Cash flow hedges
Power	11	Revenue (Energy)
Interest	(4)	Interest expense
	7	Total before tax
	(3)	Income tax expense
	4	Net of tax
Pension and other post-retirement plan adjustments
Amortization of net loss2	(10)	Total before tax
	4	Income tax expense
	(6)	Net of tax

1 All amounts in parentheses indicate expenses to the condensed consolidated statement of income.

2 These accumulated other comprehensive loss components are included in the computation of net benefit cost. Refer to Note 8 for additional detail.

8. Employee Post-Retirement Benefits

The net benefit cost recognized for the Company’s defined benefit pension plans and other post-retirement benefit plans is as follows:

three months ended March 31	Pension benefit plans			Other post-retirement benefit plans
(millions of Canadian $)	2013	2012		2013	2012
Service cost	19	16		1	1
Interest cost	24	23		2	2
Expected return on plan assets	(29	)                (28	)	-	-
Amortization of actuarial loss	9	5		1	-
Amortization of regulatory asset	7	5		-	-
Net benefit cost recognized	30	21		4	3

9. Risk Management and Financial Instruments

COUNTERPARTY CREDIT 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, and 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. The majority of counterparty credit exposure is with counterparties that are investment grade or the exposure is supported by financial assurances provided by investment grade parties. The Company regularly reviews its accounts receivable and records an allowance for doubtful accounts as necessary using the specific identification method. At March 31, 2013, there were no significant amounts past due or impaired, and there were no significant credit losses during the year.

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At March 31, 2013, the Company had a credit risk concentration of $256 million (December 31, 2012 - $259 million) due from a counterparty. This amount is expected to be fully collectible and is secured by a guarantee from the counterparty’s parent company.

NET INVESTMENT IN FOREIGN OPERATIONS

The Company hedges its net investment in 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.

U.S. DOLLAR-DENOMINATED DEBT DESIGNATED AS A NET INVESTMENT HEDGE

(unaudited - billions of $)	March 31, 2013	December 31, 2012
Carrying value	12.1 (US 11.9)	11.1 (US 11.2)
Fair value	15.0 (US 14.7)	14.3 (US 14.4)

FAIR VALUE OF DERIVATIVES USED TO HEDGE OUR

U.S. DOLLAR INVESTMENT IN FOREIGN OPERATIONS

(unaudited - millions of $)	March 31, 2013	December 31, 2012
Other current assets	47	71
Intangible and other assets	22	47
Accounts payable and other	10	6
Other long-term liabilities	55	30

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

	March 31, 2013			December 31, 2012
Asset/(liability) (unaudited - millions of Canadian $)	Fair value1		Notional or principal amount	Fair value1	Notional or principal amount
U.S. dollar cross-currency swaps
(maturing 2013 to 2019)2	5		US 3,800	82	US 3,800
U.S. dollar forward foreign exchange contracts
(maturing 2013)	(1	)	US 850	-	US 250
	4		US 4,650	82	US 4,050

1 Fair values equal carrying values.

2 Net Income in the three months ended March 31, 2013 included net realized gains of $7 million (2012 - gains of $7 million) related to the interest component of cross-currency swap settlements.

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FINANCIAL INSTRUMENTS

Non-Derivative Financial Instruments Summary

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

	March 31, 2013		December 31, 2012
(unaudited - millions of Canadian $)	Carrying amount1	Fair value2	Carrying amount1	Fair value2
Financial assets
Cash and cash equivalents	443	443	551	551
Accounts receivable and other3	1,269	1,322	1,288	1,337
Available for sale assets	49	49	44	44
	1,761	1,814	1,883	1,932
Financial liabilities4
Notes payable	1,474	1,474	2,275	2,275
Accounts payable and other long-term liabilities5	1,034	1,034	1,535	1,535
Accrued interest	352	352	368	368
Long-term debt	19,926	25,081	18,913	24,573
Junior subordinated notes	1,015	1,083	994	1,054
	23,801	29,024	24,085	29,805

1 Recorded at amortized cost, except for US$350 million (December 31, 2012 - US$350 million) of long-term debt that is attributed to hedged risk and 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 hierarchy using the income approach based on interest rates from external data service providers.

2 The fair value measurement of financial assets and liabilities recorded at amortized cost for which the fair value is not equal to the carrying value would be included in Level II of the fair value hierarchy using the income approach based on interest rates from external data service providers.

3 At March 31, 2013, financial assets of $1.0 billion (December 31, 2012 - $1.1 billion) are included in accounts receivable, $70 million (December 31, 2012 - $40 million) in other current assets and $217 million (December 31, 2012 - $240 million) in intangible and other assets.

4 Condensed consolidated statement of income in the three months ended March 31, 2013 included losses of $10 million (2012 - losses of $15 million) for fair value adjustments attributable to the hedged interest rate risk associated with interest rate swap fair value hedging relationships on US$350 million of long-term debt at March 31, 2013 (December 31, 2012 - US$350 million). There were no other unrealized gains or losses from fair value adjustments to the non-derivative financial instruments.

5      At March 31, 2013, financial liabilities of $1.0 billion (December 31, 2012 - $1.5 billion) are included in accounts payable and $41 million (December 31, 2012 - $38 million) in other long-term liabilities

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Derivative Instruments Summary

Information for the Company’s derivative instruments for 2013, excluding hedges of the Company’s net investment in foreign operations, is as follows:

(unaudited - millions of Canadian $ unless noted otherwise)	Power		Natural gas		Foreign exchange		Interest
Derivative instruments held for trading1
Fair values2
Assets	$159		$85		$-		$13
Liabilities	$(206	)	$(93	)	$(8	)	$(13	)
Notional values
Volumes3
Sales	36,445		71		-		-
Purchases	34,536		102		-		-
Canadian dollars	-		-		-		620
U.S. dollars	-		-		US 1,396		US 200
Net unrealized (losses)/gains in the three months ended March 31, 20134	$(8	)	$9		$(6	)	$-
Net realized losses in the three months ended March 31, 20134	$(7	)	$(2	)	$(1	)	$-
Maturity dates	2013-2017		2013-2016		2013-2014		2013-2016
Derivative instruments in hedging relationships5,6
Fair values2
Assets	$70		$-		$-		$10
Liabilities	$(73	)	$(1	)	$(36	)	$-
Notional values
Volumes3
Sales	6,358		-		-		-
Purchases	14,400		1		-		-
U.S. dollars	-		-		US 23		US 350
Cross-currency	-		-		136/US 100		-
Net realized gains in the three months ended March 31, 20134	$73		$-		$-		$2
Maturity dates	2013-2018		2013		2013-2014		2013-2015

1 All derivative 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.

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 instruments 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 the change in fair value of derivative instruments in hedging relationships is initially recognized in OCI 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 instruments designated as fair value hedges with a fair value of $10 million and a notional amount of US$350 million. For the three months ended March 31, 2013, net realized gains on fair value hedges were $2 million and were included in interest expense. For the three months ended March 31, 2013, the Company did not record any amounts in net income related to ineffectiveness for fair value hedges.

6 For the three months ended March 31, 2013 there were no gains or losses included in Net Income for discontinued cash flow hedges where it was probable that the anticipated transaction would not occur.

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Derivative Instruments Summary

Information for the Company’s derivative instruments for 2012, excluding hedges of the Company’s net investment in foreign operations, is as follows:

(unaudited - millions of Canadian $ unless noted otherwise)	Power		Natural gas		Foreign exchange		Interest
Derivative instruments held for trading1
Fair values2,3
Assets	$139		$88		$1		$14
Liabilities	$(176	)	$(104	)	$(2	)	$(14	)
Notional values3
Volumes4
Sales	31,066		65		-		-
Purchases	31,135		83		-		-
Canadian dollars	-		-		-		620
U.S. dollars	-		-		US 1,408		US 200
Net unrealized (losses)/gains in the three months ended March 31, 20125	$(7	)	$(14	)	$6		$-
Net realized (losses)/gains in the three months ended March 31, 20125	$15		$(10	)	$9		$-
Maturity dates	2013-2017		2013-2016		2013		2013-2016
Derivative instruments in hedging relationships6,7
Fair values2,3
Assets	$76		$-		$-		$10
Liabilities	$(97	)	$(2	)	$(38	)	$-
Notional values3
Volumes4
Sales	7,200		-		-		-
Purchases	15,184		1		-		-
U.S. dollars	-		-		US 12		US 350
Cross-currency	-		-		136/US 100		-
Net realized (losses)/gains in the three months ended March 31, 20125	$(32	)	$(6	)	$-		$1
Maturity dates	2013-2018		2013		2013-2014		2013-2015

1 All derivative 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.

2 Fair values equal carrying values.

3 As at December 31, 2012.

4 Volumes for power and natural gas derivatives are in GWh and Bcf, respectively.

5 Realized and unrealized gains and losses on held for trading derivative instruments 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 change in fair value of derivative instruments in hedging relationships is initially recognized in OCI and reclassified to revenues, interest expense and interest income and other, as appropriate, as the original hedged item settles.

6 All hedging relationships are designated as cash flow hedges except for interest rate derivative instruments designated as fair value hedges with a fair value of $10 million and a notional amount of US$350 million. For the three months ended March 31, 2012, net realized gains on fair value hedges were $2 million and were included in interest expense. For the three months ended March 31, 2012, the Company did not record any amounts in net income related to ineffectiveness for fair value hedges.

7 For the three months ended March 31, 2012, there were no gains or losses included in net income for discontinued cash flow hedges where it was probable that the anticipated transaction would not occur.

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BALANCE SHEET PRESENTATION OF DERIVATIVE INSTRUMENTS

The fair value of the derivative instruments in the Company’s balance sheet is as follows:

(unaudited - millions of Canadian $)	March 31, 2013		December 31, 2012
Current
Other current assets	248		259
Accounts payable and other	(302	)	(283	)
Long term
Intangible and other assets	158		187
Other long-term liabilities	(193	)	(186	)

DERIVATIVES IN CASH FLOW HEDGING RELATIONSHIPS

The components of other comprehensive income (OCI) related to derivatives in cash flow hedging relationships are as follows:

	Cash flow hedges1
three months ended March 31	Power			Natural gas			Foreign exchange			Interest
(unaudited - millions of Canadian $, pre-tax)	2013	2012		2013	2012		2013	2012		2013	2012
Changes in fair value of derivative instruments recognized in OCI (effective portion)	36	(66	)	-	(10	)	2	(3	)	-	-
Reclassification of gains and losses on derivative instruments from AOCI to net income (effective portion)	(11)	47		-	13		-	-		4	6
Gains and losses on derivative instruments recognized in earnings (ineffective portion)	(5)	(6	)	-	(2	)	-	-		-	-

1 No amounts have been excluded from the assessment of hedge effectiveness.

OFFSETTING OF DERIVATIVE INSTRUMENTS

The Company enters into derivative contracts with the right to offset in the normal course of business as well as in the event of default. TransCanada has no master netting agreements, however; similar contracts are entered into containing rights of offset. The Company has elected to present the fair value of derivative instruments with the right to offset on a gross basis in the balance sheet. The following table shows the impact on the presentation of the fair value of derivative instrument assets and liabilities had the Company elected to present these contracts on a net basis:

at March 31, 2013 (unaudited - millions of Canadian $)	Gross derivative instruments presented in the balance sheet		Amounts available for offset1		Net amounts
Derivative - Asset
Power	229		(140	)	89
Natural gas	85		(74	)	11
Foreign exchange	69		(40	)	29
Interest	23		(4	)	19
Total	406		(258	)	148
Derivative - Liability
Power	(279	)	140		(139	)
Natural gas	(94	)	74		(20	)
Foreign exchange	(109	)	40		(69	)
Interest	(13	)	4		(9	)
Total	(495	)	258		(237	)

1 Amounts available for offset do not include cash collateral pledged or received.

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With respect to all financial arrangements, including the derivative instruments presented above, as at March 31, 2013, the Company had provided cash collateral of $166 million and letters of credit of $45 million to its counterparties. The Company held $1 million in cash collateral and $6 million in letters of credit on asset exposures at March 31, 2013.

The following table shows the impact on the presentation of the fair value of derivative instrument assets and liabilities had the Company elected to present these contracts on a net basis as at December 31, 2012:

at December 31, 2012 (unaudited - millions of Canadian $)	Gross derivative instruments presented in the balance sheet		Amounts available for offset1		Net amounts
Derivative - Asset
Power	215		(132	)	83
Natural gas	88		(83	)	5
Foreign exchange	119		(37	)	82
Interest	24		(6	)	18
Total	446		(258	)	188
Derivative - Liability
Power	(273	)	132		(141)
Natural gas	(106	)	83		(23)
Foreign exchange	(76	)	37		(39)
Interest	(14	)	6		(8)
Total	(469	)	258		(211)

1 Amounts available for offset do not include cash collateral pledged or received.

With respect to all financial arrangements, including the derivative instruments presented above as at December 31, 2012, the Company had provided cash collateral of $189 million and letters of credit of $45 million to its counterparties. The Company held $2 million in cash collateral and $5 million in letters of credit on asset exposures at December 31, 2012.

CREDIT RISK RELATED CONTINGENT FEATURES

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 March 31, 2013, the aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a net liability position was $34 million (December 31, 2012 - $37 million), for which the Company had provided collateral in the normal course of business of nil (December 31, 2012 - nil). If the credit-risk-related contingent features in these agreements were triggered on March 31, 2013, the Company would have been required to provide collateral of $34 million (December 31, 2012 - $37 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 feels it has sufficient liquidity in the form of cash and undrawn committed revolving bank lines to meet these contingent obligations should they arise.

FAIR VALUE HIERARCHY

The Company’s assets and liabilities recorded at fair value have been classified into three categories based on the fair value hierarchy.

In Level I, the fair value of assets and liabilities is determined by reference to quoted prices in active markets for identical assets and liabilities that the Company has the ability to access at the measurement date.

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, the valuation is based on the extrapolation of inputs, other than quoted prices included within Level I, for which all significant inputs are

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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 first quarter 2013 and 2012.

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. There were no transfers between Level II and Level III in first quarter 2013 and 2012.

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 modeling tool which takes into account physical operating characteristics of generation facilities in the markets in which the Company operates. Model inputs 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 is expected to or may result in a lower fair value measurement of contracts included in Level III.

The fair value of the Company’s assets and liabilities measured on a recurring basis, including both current and non-current portions, are categorized as follows:

	Quoted prices in active markets (Level I)				Significant other observable inputs (Level II)				Significant unobservable inputs (Level III)				Total
(unaudited - millions of Canadian $, pre-tax)	Mar 31 2013		Dec 31 2012		Mar 31 2013		Dec 31 2012		Mar 31 2013		Dec 31 2012		Mar 31 2013		Dec 31 2012
Derivative instrument assets:
Power commodity contracts	-		-		224		213		5		2		229		215
Natural gas commodity contracts	77		75		8		13		-		-		85		88
Foreign exchange contracts	-		-		69		119		-		-		69		119
Interest rate contracts	-		-		23		24		-		-		23		24
Derivative Instrument Liabilities:
Power commodity contracts	-		-		(275	)	(269	)	(4	)	(4	)	(279	)	(273	)
Natural gas commodity contracts	(79	)	(95	)	(15	)	(11	)	-		-		(94	)	(106	)
Foreign exchange contracts	-		-		(109	)	(76	)	-		-		(109	)	(76	)
Interest rate contracts	-		-		(13	)	(14	)	-		-		(13	)	(14	)
Non-derivative financial instruments:
Available for sale assets	49		44		-		-		-		-		49		44
	47		24		(88	)	(1	)	1		(2	)	(40	)	21

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

three months ended March 31	Derivatives1
(unaudited - millions of Canadian $, pre-tax)	2013		2012
Balance at January 1	(2	)	(15	)
Total gains included in OCI	3		4
Balance at March 31	1		(11	)

1 For the three months ended March 31, 2013 the unrealized gains or losses included in net income attributed to derivatives in the level III category that were still held at the reporting date was nil (2012 - nil).

A 10 per cent increase or decrease in commodity prices, with all other variables held constant, would result in a $3 million decrease or increase, respectively, in the fair value of outstanding derivative instruments included in Level III as at March 31, 2013.

10. Contingencies and Guarantees

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 2013, TransCanada currently expects spot prices to be less than the floor price for the year, therefore no amounts recorded in revenues in first quarter 2013 are expected to be repaid.

GUARANTEES

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 Bruce B guarantees have terms ranging to 2018 except for one guarantee with no termination date that has no exposure associated with it. In addition, TransCanada and BPC have each severally guaranteed one-half of certain contingent financial obligations of Bruce A related to a sublease agreement, an agreement with the OPA to restart the Bruce A power generation units, and certain other financial obligations. The Bruce A guarantees have terms to 2019. TransCanada’s share of the potential exposure under these Bruce A and Bruce B guarantees was estimated to be $887 million at March 31, 2013. The carrying value of these Bruce Power guarantees at March 31, 2013 was $10 million which is included in other long-term liabilities. 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, PPA payments and the payment of liabilities. The guarantees have terms ranging from 2013 to 2040.  TransCanada’s share of the potential exposure under these assurances was estimated to be $42 million at March 31, 2013. The carrying value of these guarantees at March 31, 2013 was $9 million, which has been included in other long-term liabilities.  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.