TC Energy (TRP) 6-K TransCanada Reports Solid Second Quarter Results

EXHIBIT 13.2

Condensed consolidated statement of income

	three months ended June 30						six months ended June 30
(unaudited - millions of Canadian $, except per share amounts)	2014			2013			2014			2013
Revenues
Natural gas pipelines	1,154			1,031			2,369			2,188
Liquids pipelines	366			278			725			549
Energy	714			700			2,024			1,524
	2,234			2,009			5,118			4,261
Income from Equity Investments	68			153			203			246
Operating and Other Expenses
Plant operating costs and other	684			648			1,489			1,289
Commodity purchases resold	328			283			1,034			659
Property taxes	119			106			242			215
Depreciation and amortization	399			356			792			723
Gain on sale of assets	(108		)	—			(108		)	—
	1,422			1,393			3,449			2,886
Financial Charges/(Income)
Interest expense	297			252			571			510
Interest income and other	(54		)	11			(46		)	(2		)
	243			263			525			508
Income before Income Taxes	637			506			1,347			1,113
Income Tax Expense
Current	23			(36		)	82			43
Deferred	142			134			304			170
	165			98			386			213
Net Income	472			408			961			900
Net income attributable to non-controlling interests	31			23			85			54
Net Income Attributable to Controlling Interests	441			385			876			846
Preferred share dividends	25			20			48			35
Net Income Attributable to Common Shares	416			365			828			811
Net Income per Common Share
Basic and diluted		$0.59			$0.52			$1.17			$1.15
Dividends Declared per Common Share		$0.48			$0.46			$0.96			$0.92
Weighted Average Number of Common Shares (millions)
Basic	708			707			708			706
Diluted	709			708			709			707

See accompanying notes to the condensed consolidated financial statements.

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SECOND QUARTER REPORT 2014

Condensed consolidated statement of comprehensive income

	three months ended June 30				six months ended June 30
(unaudited - millions of Canadian $)	2014		2013		2014		2013
Net Income	472		408		961		900
Other Comprehensive Income, Net of Income Taxes
Foreign currency translation gains and losses on net investment in foreign operations	(190	)	225		50		336
Change in fair value of net investment hedges	79		(135	)	(48	)	(184	)
Change in fair value of cash flow hedges	(4	)	(44	)	27		(23	)
Reclassification to Net Income of gains and losses on cash flow hedges	2		11		(60	)	7
Reclassification to Net Income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans	5		6		9		12
Other comprehensive income/(losses) on equity investments	2		(2	)	2		(3	)
Other comprehensive (loss)/income (Note 8)	(106	)	61		(20	)	145
Comprehensive Income	366		469		941		1,045
Comprehensive (loss)/income attributable to non-controlling interests	(8	)	60		90		111
Comprehensive Income Attributable to Controlling Interests	374		409		851		934
Preferred share dividends	25		20		50		35
Comprehensive Income Attributable to Common Shares	349		389		801		899

See accompanying notes to the condensed consolidated financial statements.

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SECOND QUARTER REPORT 2014

Condensed consolidated statement of cash flows

	three months ended June 30				six months ended June 30
(unaudited - millions of Canadian $)	2014		2013		2014		2013
Cash Generated from Operations
Net income	472		408		961		900
Depreciation and amortization	399		356		792		723
Deferred income taxes	142		134		304		170
Income from equity investments	(68	)	(153	)	(203	)	(246	)
Distributed earnings received from equity investments	84		180		254		264
Employee post-retirement benefits funding lower than expense	2		11		12		26
Gain on sale of assets	(108	)	—		(108	)	—
Other	(6	)	19		7		34
Decrease/(increase) in operating working capital	202		(114	)	79		(324	)
Net cash provided by operations	1,119		841		2,098		1,547
Investing Activities
Capital expenditures	(967	)	(1,109	)	(1,745	)	(2,038	)
Equity investments	(40	)	(39	)	(129	)	(71	)
Acquisitions	—		(55	)	—		(55	)
Proceeds from sale of assets, net of transactions costs	187		—		187		—
Deferred amounts and other	(94	)	(144	)	(117	)	(164	)
Net cash used in investing activities	(914	)	(1,347	)	(1,804	)	(2,328	)
Financing Activities
Dividends on common and preferred shares	(365	)	(351	)	(710	)	(666	)
Distributions paid to non-controlling interests	(47	)	(35	)	(92	)	(70	)
Notes payable issued/(repaid), net	225		1,388		(522	)	559
Long-term debt issued, net of issue costs	16		10		1,380		744
Repayment of long-term debt	(205	)	(695	)	(982	)	(709	)
Common shares issued, net of issue costs	6		23		16		55
Partnership units of subsidiary issued, net of issue costs	—		384		—		384
Preferred shares issued, net of issue costs	—		(1	)	440		585
Preferred shares of subsidiary redeemed	—		—		(200	)	—
Net cash (used in)/provided by financing activities	(370	)	723		(670	)	882
Effect of Foreign Exchange Rate Changes on Cash and Cash Equivalents	(17	)	14		16		22
(Decrease)/increase in Cash and Cash Equivalents	(182	)	231		(360	)	123
Cash and Cash Equivalents
Beginning of period	749		443		927		551
Cash and Cash Equivalents
End of period	567		674		567		674

See accompanying notes to the condensed consolidated financial statements.

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SECOND QUARTER REPORT 2014

Condensed consolidated balance sheet

		June 30,		December 31,
(unaudited - millions of Canadian $)		2014		2013
ASSETS
Current Assets
Cash and cash equivalents		567		927
Accounts receivable		1,124		1,122
Inventories		252		251
Other		1,050		847
		2,993		3,147
Plant, Property and Equipment,	net of accumulated depreciation of $18,551 and $17,851, respectively	38,456		37,606
Equity Investments		5,719		5,759
Regulatory Assets		1,610		1,735
Goodwill		3,712		3,696
Intangible and Other Assets		2,220		1,955
		54,710		53,898
LIABILITIES
Current Liabilities
Notes payable		1,343		1,842
Accounts payable and other		2,353		2,155
Accrued interest		383		388
Current portion of long-term debt		1,518		973
		5,597		5,358
Regulatory Liabilities		233		229
Other Long-Term Liabilities		632		656
Deferred Income Tax Liabilities		4,890		4,564
Long-Term Debt		21,774		21,892
Junior Subordinated Notes		1,067		1,063
		34,193		33,762
EQUITY
Common shares, no par value		12,166		12,149
Issued and outstanding:	June 30, 2014 - 708 million shares
	December 31, 2013 - 707 million shares
Preferred shares		2,255		1,813
Additional paid-in capital		398		401
Retained earnings		5,244		5,096
Accumulated other comprehensive loss (Note 8)		(959	)	(934	)
Controlling Interests		19,104		18,525
Non-controlling interests		1,413		1,611
		20,517		20,136
		54,710		53,898
Contingencies and Guarantees (Note 11)

See accompanying notes to the condensed consolidated financial statements.

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SECOND QUARTER REPORT 2014

Condensed consolidated statement of equity

	six months ended June 30
(unaudited - millions of Canadian $)	2014		2013
Common Shares
Balance at beginning of period	12,149		12,069
Shares issued on exercise of stock options	17		62
Balance at end of period	12,166		12,131
Preferred Shares
Balance at beginning of period	1,813		1,224
Shares issued under public offering, net of issue costs	442		589
Balance at end of period	2,255		1,813
Additional Paid-In Capital
Balance at beginning of period	401		379
Issuance of stock options, net of exercises	3		(4	)
Dilution impact from TC PipeLines, LP units issued	—		29
Redemption of subsidiary's preferred shares	(6	)	—
Balance at end of period	398		404
Retained Earnings
Balance at beginning of period	5,096		4,687
Net income attributable to controlling interests	876		846
Common share dividends	(680	)	(650	)
Preferred share dividends	(48	)	(37	)
Balance at end of period	5,244		4,846
Accumulated Other Comprehensive Loss
Balance at beginning of period	(934	)	(1,448	)
Other comprehensive (loss)/income	(25	)	88
Balance at end of period	(959	)	(1,360	)
Equity Attributable to Controlling Interests	19,104		17,834
Equity Attributable to Non-Controlling Interests
Balance at beginning of period	1,611		1,425
Net income attributable to non-controlling interests
TC PipeLines, LP	74		36
Preferred share dividends of TCPL	2		11
Portland	9		7
Other comprehensive income attributable to non-controlling interests	5		57
Issuance of TC PipeLines, LP units
Proceeds, net of issue costs	—		384
Decrease in TransCanada's ownership	—		(47	)
Distributions to non-controlling interests	(92	)	(70	)
Redemption of subsidiary's preferred shares	(194	)	—
Foreign exchange and other	(2	)	9
Balance at end of period	1,413		1,812
Total Equity	20,517		19,646

See accompanying notes to the condensed consolidated financial statements.

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SECOND QUARTER REPORT 2014

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 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, 2013. Capitalized and abbreviated terms that are used but not otherwise defined herein are identified in TransCanada’s 2013 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 2013 audited consolidated financial statements included in TransCanada’s 2013 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 Pipelines 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, 2013, except as described in Note 2, Changes in accounting policies.

2. Changes in accounting policies

CHANGES IN ACCOUNTING POLICIES FOR 2014

Obligations resulting from joint and several liability arrangements

In February 2013, the FASB issued guidance for recognizing, measuring, and disclosing obligations resulting from joint and several liability arrangements when the total amount of the obligation is fixed at the reporting date. Debt arrangements, other contractual obligations, and settled litigation and judicial rulings are examples of these obligations. This new guidance was effective January 1, 2014. There was no material impact on the Company’s consolidated financial statements as a result of applying this new standard.

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 new guidance was effective prospectively from January 1, 2014 and will be applied for all applicable transactions after that date.

Unrecognized tax benefit

In July 2013, the FASB issued amended guidance on the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. This new guidance was effective January 1, 2014. There was no material impact on the Company's consolidated financial statements as a result of applying this new standard.

FUTURE ACCOUNTING CHANGES

Reporting discontinued operations

In April 2014, the FASB issued amended guidance on the reporting of discontinued operations. The criteria of what will qualify as a discontinued operation has changed and there are expanded disclosures required. This new guidance is effective from January 1, 2015 and will be applied prospectively. The Company does not expect the adoption of this new standard to have a material impact on its consolidated financial statements.

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SECOND QUARTER REPORT 2014

Revenue from contracts with customers

In May 2014, the FASB issued new guidance on Revenue from Contracts with Customers. This guidance supersedes the current revenue recognition requirements and most industry-specific guidance. This new guidance requires that an entity recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. This new guidance is effective from January 1, 2017 with two methods in which the amendment can be applied: (1) retrospectively to each prior reporting period presented, or (2) retrospectively with the cumulative effect recognized at the date of initial application. Early application is not permitted. The Company is currently evaluating the impact of the adoption of this ASU and has not yet determined the effect on its consolidated financial statements.

3. Segmented information

three months ended June 30	Natural Gas Pipelines				Liquids Pipelines1				Energy				Corporate				Total
(unaudited - millions of Canadian $)	2014		2013		2014		2013		2014		2013		2014		2013		2014		2013
Revenues	1,154		1,031		366		278		714		700		—		—		2,234		2,009
Income from equity investments	37		29		—		—		31		124		—		—		68		153
Plant operating costs and other	(348	)	(339	)	(100	)	(82	)	(214	)	(210	)	(22	)	(17	)	(684	)	(648	)
Commodity purchases resold	—		—		—		—		(328	)	(283	)	—		—		(328	)	(283	)
Property taxes	(84	)	(77	)	(17	)	(10	)	(18	)	(19	)	—		—		(119	)	(106	)
Depreciation and amortization	(263	)	(245	)	(54	)	(37	)	(77	)	(69	)	(5	)	(5	)	(399	)	(356	)
Gain on sale of assets	—		—		—		—		108		—		—		—		108		—
Segmented earnings	496		399		195		149		216		243		(27	)	(22	)	880		769
Interest expense																	(297	)	(252	)
Interest income and other																	54		(11	)
Income before income taxes																	637		506
Income tax expense																	(165	)	(98	)
Net income																	472		408
Net income attributable to non-controlling interests																	(31	)	(23	)
Net income attributable to controlling interests																	441		385
Preferred share dividends																	(25	)	(20	)
Net income attributable to common shares																	416		365

1 Previously Oil Pipelines.

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six months ended June 30	Natural Gas Pipelines				Liquids Pipelines1				Energy				Corporate				Total
(unaudited - millions of Canadian $)	2014		2013		2014		2013		2014		2013		2014		2013		2014		2013
Revenues	2,369		2,188		725		549		2,024		1,524		—		—		5,118		4,261
Income from equity investments	89		69		—		—		114		177		—		—		203		246
Plant operating costs and other	(681	)	(657	)	(201	)	(161	)	(547	)	(420	)	(60	)	(51	)	(1,489	)	(1,289	)
Commodity purchases resold	—		—		—		—		(1,034	)	(659	)	—		—		(1,034	)	(659	)
Property taxes	(170	)	(155	)	(34	)	(23	)	(38	)	(37	)	—		—		(242	)	(215	)
Depreciation and amortization	(525	)	(498	)	(103	)	(74	)	(154	)	(143	)	(10	)	(8	)	(792	)	(723	)
Gain on sale of assets	—		—		—		—		108		—		—		—		108		—
Segmented earnings	1,082		947		387		291		473		442		(70	)	(59	)	1,872		1,621
Interest expense																	(571	)	(510	)
Interest income and other																	46		2
Income before income taxes																	1,347		1,113
Income tax expense																	(386	)	(213	)
Net income																	961		900
Net income attributable to non-controlling interests																	(85	)	(54	)
Net income attributable to controlling interests																	876		846
Preferred share dividends																	(48	)	(35	)
Net income attributable to common shares																	828		811

1 Previously Oil Pipelines.

TOTAL ASSETS

(unaudited - millions of Canadian $)	June 30, 2014	December 31, 2013
Natural Gas Pipelines	25,406	25,165
Liquids Pipelines1	14,189	13,253
Energy	13,580	13,747
Corporate	1,535	1,733
	54,710	53,898

1 Previously Oil Pipelines.

4. Asset disposition

The sale of Cancarb Limited and its related power generation facility was completed on April 15, 2014 for aggregate gross proceeds of $190 million. TransCanada recognized a gain on the sale of $108 million ($99 million after tax) for the three and six months ended June 30, 2014. This gain has been presented separately on the consolidated statement of income.

5. Income taxes

At June 30, 2014, the total unrecognized tax benefit of uncertain tax positions was approximately $20 million (December 31, 2013 - $23 million). TransCanada recognizes interest and penalties related to income tax uncertainties in income tax expense. Included in net tax expense for the three and six months endedJune 30, 2014 is $1 million and nil, respectively, of income for the reversal of interest expense and nil for penalties (June 30, 2013 - nil and $1 million, respectively, of interest expense and nil for penalties). At June 30, 2014, the Company had $6 million accrued for interest expense and nil accrued for penalties (December 31, 2013 - $6 million accrued for interest expense and nil for penalties).

The effective tax rates for the six-month periods ended June 30, 2014 and 2013 were 29 per cent and 19 per cent, respectively. The higher effective tax rate in 2014 compared to 2013 was primarily the result of the impact of the 2013 NEB decision (RH-003-2011), changes in the proportion of income earned between Canadian and foreign jurisdictions as well as higher flow-through taxes in 2014 on Canadian regulated pipelines, partially offset by the disposition of Cancarb Limited in 2014.

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6. Long-term debt

In the three and six months ended June 30, 2014, TransCanada capitalized interest related to capital projects of $63 million and $142 million, respectively (2013 - $60 million and $115 million, respectively).

LONG-TERM DEBT ISSUED

Amount
(unaudited - millions of $)	Type	Maturity date	Interest rate		Date issued
US$1,250	Senior unsecured notes	March 1, 2034	4.625	%	February 2014

LONG-TERM DEBT RETIRED

Amount
(unaudited - millions of Canadian $)	Type	Retirement date	Interest rate
$450	Medium term notes	January 2014	5.65	%
$300	Medium term notes	February 2014	5.05	%
$125	Debenture	June 2014	11.10	%
$53	Debenture	June 2014	11.20	%

7. Equity and share capital

PREFERRED SHARE ISSUANCE

In January 2014, TransCanada completed a public offering of 18 million Series 9 cumulative redeemable first preferred shares at $25 per share resulting in gross proceeds of $450 million. The holders of the Series 9 preferred shares are entitled to receive fixed cumulative dividends at an annual rate of $1.0625 per share, payable quarterly. The dividend rate will reset on October 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 2.35 per cent. The preferred shares are redeemable by TransCanada on or after October 30, 2019 and on October 30 of every fifth year thereafter at a price of $25 per share plus accrued and unpaid dividends.

The Series 9 preferred shareholders will have the right to convert their shares into Series 10 cumulative redeemable first preferred shares on October 30, 2019 and on October 30 of every fifth year thereafter. The holders of Series 10 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 2.35 per cent.

PREFERRED SHARE REDEMPTION

On March 5, 2014, TCPL redeemed all of the four million outstanding 5.60 per cent cumulative redeemable first preferred shares Series Y at a price of $50 per share plus $0.2455 representing accrued and unpaid dividends to the redemption date.

8. 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 June 30, 2014	Before tax		Income tax recovery/		Net of tax
(unaudited - millions of Canadian $)	amount		(expense)		amount
Foreign currency translation gains and losses on net investment in foreign operations	(140	)	(50	)	(190	)
Change in fair value of net investment hedges	107		(28	)	79
Change in fair value of cash flow hedges	(9	)	5		(4	)
Reclassification to net income of gains and losses on cash flow hedges	4		(2	)	2
Reclassification to net income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans	7		(2	)	5
Other comprehensive income on equity investments	1		1		2
Other comprehensive loss	(30	)	(76	)	(106	)

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three months ended June 30, 2013	Before tax		Income tax recovery/		Net of tax
(unaudited - millions of Canadian $)	amount		(expense)		amount
Foreign currency translation gains and losses on net investment in foreign operations	170		55		225
Change in fair value of net investment hedges	(182	)	47		(135	)
Change in fair value of cash flow hedges	(68	)	24		(44	)
Reclassification to net income of gains and losses on cash flow hedges	18		(7	)	11
Reclassification to net income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans	7		(1	)	6
Other comprehensive loss on equity investments	(3	)	1		(2	)
Other comprehensive (loss)/income	(58	)	119		61

six months ended June 30, 2014	Before tax		Income tax recovery/		Net of tax
(unaudited - millions of Canadian $)	amount		(expense)		amount
Foreign currency translation gains and losses on net investment in foreign operations	51		(1	)	50
Change in fair value of net investment hedges	(64	)	16		(48	)
Change in fair value of cash flow hedges	42		(15	)	27
Reclassification to net income of gains and losses on cash flow hedges	(99	)	39		(60	)
Reclassification to net income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans	13		(4	)	9
Other comprehensive income on equity investments	1		1		2
Other comprehensive (loss)/income	(56	)	36		(20	)

six months ended June 30, 2013	Before tax		Income tax recovery/		Net of tax
(unaudited - millions of Canadian $)	amount		(expense)		amount
Foreign currency translation gains and losses on net investment in foreign operations	247		89		336
Change in fair value of net investment hedges	(248	)	64		(184	)
Change in fair value of cash flow hedges	(30	)	7		(23	)
Reclassification to net income of gains and losses on cash flow hedges	11		(4	)	7
Reclassification to net income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans	17		(5	)	12
Other comprehensive loss on equity investments	(4	)	1		(3	)
Other comprehensive (loss)/income	(7	)	152		145

The changes in accumulated other comprehensive loss by component are as follows:

three months ended June 30, 2014	Currency translation		Cash flow		Pension and OPEB plan		Equity
(unaudited - millions of Canadian $)	adjustments		hedges		adjustments		Investments		Total1
AOCI balance at April 1, 2014	(560	)	(35	)	(193	)	(104	)	(892	)
Other comprehensive loss before reclassifications2	(72	)	(4	)	—		—		(76	)
Amounts reclassified from accumulated other comprehensive loss3	—		2		5		2		9
Net current period other comprehensive (loss)/income	(72	)	(2	)	5		2		(67	)
AOCI balance at June 30, 2014	(632	)	(37	)	(188	)	(102	)	(959	)

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

2 Other comprehensive income before reclassifications on currency translation adjustments is net of non-controlling interest losses of $39 million.

3 Gains 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 $9 million ($4 million, net of tax) at June 30, 2014. 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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SECOND QUARTER REPORT 2014

six months ended June 30, 2014	Currency translation		Cash flow		Pension and OPEB plan		Equity
(unaudited - millions of Canadian $)	adjustments		hedges		adjustments		Investments		Total1
AOCI balance at January 1, 2014	(629	)	(4	)	(197	)	(104	)	(934	)
Other comprehensive (loss)/income before reclassifications2	(3	)	27		—		—		24
Amounts reclassified from accumulated other comprehensive loss3	—		(60	)	9		2		(49	)
Net current period other comprehensive (loss)/income	(3	)	(33	)	9		2		(25	)
AOCI balance at June 30, 2014	(632	)	(37	)	(188	)	(102	)	(959	)

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

2 Other comprehensive (loss)/income before reclassifications on currency translation adjustments is net of non-controlling interest gains of $5 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 $9 million ($4 million, net of tax) at June 30, 2014. 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.

Details about reclassifications out of accumulated other comprehensive loss are as follows: 

	Amounts reclassified from accumulated other comprehensive loss1				Affected line item in the condensed consolidated statement of income
(unaudited - millions of Canadian $)	three months ended June 30, 2014		six months ended June 30, 2014
Cash flow hedges
Power and natural gas	(1	)	107		Revenue (Energy)
Interest	(3	)	(8	)	Interest expense
	(4	)	99		Total before tax
	2		(39	)	Income tax expense
	(2	)	60		Net of tax
Pension and other post-retirement plan adjustments
Amortization of actuarial loss and past service cost 2	(7	)	(13	)	Total before tax
	2		4		Income tax expense
	(5	)	(9	)	Net of tax
Equity Investments
Equity income	(1	)	(1	)	Income from Equity Investments
	(1	)	(1	)	Income tax expense
	(2	)	(2	)	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 9 for additional detail.

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9. 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 June 30								six months ended June 30
	Pension benefit plans				Other post-retirement benefit plans				Pension benefit plans				Other post-retirement benefit plans
(unaudited - millions of Canadian $)	2014		2013		2014		2013		2014		2013		2014		2013
Service cost	21		22		—		—		43		41		1		1
Interest cost	28		23		3		2		56		47		5		4
Expected return on plan assets	(34	)	(29	)	(1	)	(1	)	(69	)	(58	)	(1	)	(1	)
Amortization of actuarial loss	6		6		—		—		11		15		1		1
Amortization of past service cost	1		1		—		—		1		1		—		—
Amortization of regulatory asset	4		8		—		1		9		15		—		1
Amortization of transitional obligation related to regulated business	—		—		1		1		—		—		1		1
Net benefit cost recognized	26		31		3		3		51		61		7		7

10. Risk management and financial instruments

RISK MANAGEMENT OVERVIEW

TransCanada has exposure to counterparty credit risk and market risk, and has strategies, policies and limits in place to manage the impact of these risks on earnings, cash flow and, ultimately, shareholder value.

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 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 June 30, 2014, there were no significant amounts past due or impaired, and there were no significant credit losses during the period.

At June 30, 2014, the Company had a credit risk concentration of $211 million (December 31, 2013 - $240 million) due from one counterparty. This amount is expected to be fully collectible and is secured by a guarantee from the counterparty’s investment grade 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, foreign exchange forward contracts and foreign exchange options.

U.S. dollar-denominated debt designated as a net investment hedge

(unaudited - millions of Canadian $)	June 30, 2014	December 31, 2013
Carrying value	15,600 (US 14,600)	14,200 (US 13,400)
Fair value	18,200 (US 17,100)	16,000 (US 15,000)

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Derivatives designated as a net investment hedge

	June 30, 2014			December 31, 2013
(unaudited - millions of Canadian $)	Fair Value1		Notional or principal amount	Fair value1		Notional or principal amount
Asset/(liability)
U.S. dollar cross-currency interest rate swaps
(maturing 2014 to 2019)2	(186	)	US 3,250	(201	)	US 3,800
U.S. dollar foreign exchange forward contracts
(maturing 2014)	(14	)	US 300	(11	)	US 850
	(200	)	US 3,550	(212	)	US 4,650

1 Fair values equal carrying values.

2 Net income in the three and six months ended June 30, 2014 included net realized gains of $5 million and $11 million, respectively, (2013 - gains of $7 million and $14 million, respectively) related to the interest component of cross-currency swaps which is included in interest expense.

Balance sheet presentation of net investment hedges

The balance sheet classification of the fair value of derivatives used to hedge the Company's net investment in foreign operations is as follows: 

(unaudited - millions of Canadian $)	June 30, 2014		December 31, 2013
Other current assets	5		5
Intangible and other assets	1		—
Accounts payable and other	(57	)	(50	)
Other long-term liabilities	(149	)	(167	)
	(200	)	(212	)

FINANCIAL INSTRUMENTS

Non-derivative financial instruments

Fair value of non-derivative financial instruments

The fair value of the Company's notes receivables is calculated by discounting future payments of interest and principal using forward interest rates. The fair value of long-term debt is estimated using an income approach based on quoted market prices for the same or similar debt instruments from external data service providers. The fair value of available for sale assets has been calculated using quoted market prices where available. Credit risk has been taken into consideration when calculating the fair value of non-derivative instruments.

Certain non-derivative financial instruments included in cash and cash equivalents, accounts receivable, intangible and other assets, notes payable, accounts payable and other, accrued interest and other long-term liabilities have carrying amounts that equal their fair value due to the nature of the item or the short time to maturity and would be classified in Level II of the fair value hierarchy.

Balance sheet presentation of non-derivative financial instruments

The following table details the fair value of the non-derivative financial instruments, excluding those where carrying amounts equal fair value, and would be classified in Level II of the fair value hierarchy: 

	June 30, 2014				December 31, 2013
(unaudited - millions of Canadian $)	Carrying amount1		Fair value		Carrying amount1		Fair value
Notes receivable and other1	196		235		226		269
Available for sale assets2	46		46		47		47
Current and long-term debt3,4	(23,292	)	(27,819	)	(22,865	)	(26,134	)
Junior subordinated notes	(1,067	)	(1,111	)	(1,063	)	(1,093	)
	(24,117	)	(28,649	)	(23,655	)	(26,911	)

1 Notes receivable are included in other current assets and intangible and other assets on the condensed consolidated balance sheet.

2 Available for sale assets are included in intangible and other assets on the condensed consolidated balance sheet.

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3 Long-term debt is recorded at amortized cost, except for US$300 million (December 31, 2013 - US$200 million) that is attributed to hedged risk and recorded at fair value.

4 Consolidated net income for the three and six months ended June 30, 2014 included gains of $1 million and losses of $5 million, respectively, (2013 - gains of $3 million and losses of $7 million, respectively) for fair value adjustments attributable to the hedged interest rate risk associated with interest rate swap fair value hedging relationships on US$300 million of long-term debt at June 30, 2014 (December 31, 2013 - US$200 million). There were no other unrealized gains or losses from fair value adjustments to the non-derivative financial instruments.

Derivative instruments

Fair value of derivative instruments

The fair value of foreign exchange and interest rate derivatives has been calculated using the income approach which uses current market rates and applies a discounted cash flow valuation model. The fair value of power and natural gas derivatives and available for sale assets has been calculated using quoted market prices where available. In the absence of quoted market prices, third-party broker quotes or other valuation techniques have been used. Credit risk has been taken into consideration when calculating the fair value of derivative instruments.

Where possible, derivative instruments are designated as hedges, but in some cases, even though the derivatives are considered to be effective economic hedges, they do not meet the specific criteria for hedge accounting treatment and are accounted for at fair value with changes in fair value recorded in net income in the period of change. This may expose the Company to increased variability in reported earnings because the fair value of the derivative instruments can fluctuate significantly from period to period.

Balance sheet presentation of derivative instruments

The balance sheet classification of the fair value of the derivative instruments is as follows:

(unaudited - millions of Canadian $)	June 30, 2014		December 31, 2013
Other current assets	354		395
Intangible and other assets	127		112
Accounts payable and other	(404	)	(357	)
Other long-term liabilities	(236	)	(255	)
	(159	)	(105	)

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2014 derivative instruments summary

The following summary does not include hedges of our net investment in foreign operations.

(unaudited - millions of Canadian $, unless noted otherwise)	Power			Natural gas			Foreign exchange			Interest
Derivative instruments held for trading1
Fair values2,3
Assets		$314			$51			$14			$5
Liabilities		($320	)		($70	)		($2	)		($5	)
Notional values3
Volumes4
Purchases	41,098			99			—			—
Sales	39,010			50			—			—
U.S. dollars	—			—			US 1,516			US 100
Net unrealized gains/(losses) in the period5
three months ended June 30, 2014		$6			($14	)		$25			$—
six months ended June 30, 2014		$15			($21	)		$23			$—
Net realized (losses)/gains in the period5
three months ended June 30, 2014		($3	)		($4	)		($1	)		$—
six months ended June 30, 2014		($31	)		$46			($18	)		$—
Maturity dates3	2014-2017			2014-2020			2014			2016
Derivative instruments in hedging relationships6,7
Fair values2,3
Assets		$86			$—			$—			$5
Liabilities		($35	)		$—			$—			($2	)
Notional values3
Volumes4
Purchases	10,102			—			—			—
Sales	6,034			—			—			—
U.S. dollars	—			—			—			US 450
Net realized (losses)/gains in the period5
three months ended June 30, 2014		($4	)		$—			$—			$1
six months ended June 30, 2014		$188			$—			$—			$2
Maturity dates3	2014-2018			—			—			2015-2018

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 June 30, 2014.

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 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.

6 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 $5 million and a notional amount of US$300 million as at June 30, 2014. For the three and six months ended June 30, 2014, net realized gains on fair value hedges were $2 million and $3 million, respectively, and were included in interest expense. For the three and six months ended June 30, 2014, the Company did not record any amounts in net income related to ineffectiveness for fair value hedges.

7 For the three and six months ended June 30, 2014, 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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2013 derivative instruments summary

The following summary does not include hedges of our net investment in foreign operations.

(unaudited - millions of Canadian $, unless noted otherwise)	Power			Natural gas			Foreign exchange			Interest
Derivative instruments held for trading1
Fair values2,3
Assets		$265			$73			$—			$8
Liabilities		($280	)		($72	)		($12	)		($7	)
Notional values3
Volumes4
Purchases	29,301			88			—			—
Sales	28,534			60			—			—
Canadian dollars	—			—			—			400
U.S. dollars	—			—			US 1,015			US 100
Net unrealized gains/(losses) in the period5
three months ended June 30, 2013		$5			($21	)		($10	)		$—
six months ended June 30, 2013		($3	)		($12	)		($16	)		$—
Net realized losses in the period5
three months ended June 30, 2013		($29	)		($5	)		($6	)		$—
six months ended June 30, 2013		($36	)		($7	)		($7	)		$—
Maturity dates3	2014-2017			2014-2016			2014			2014-2016
Derivative instruments in hedging relationships6,7
Fair values2,3
Assets		$150			$—			$—			$6
Liabilities		($22	)		$—			($1	)		($1	)
Notional values3
Volumes4
Purchases	9,758			—			—			—
Sales	6,906			—			—			—
U.S. dollars	—			—			US 16			US 350
Net realized (losses)/gains in the period5
three months ended June 30, 2013		($84	)		($1	)		$—			$2
six months ended June 30, 2013		($11	)		($1	)		$—			$4
Maturity dates3	2014-2018			—			2014			2015-2018

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, 2013.

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 financial instruments designated as fair value hedges with a fair value of $5 million and a notional amount of US$200 million as at December 31, 2013. Net realized gains on fair value hedges for the three and six months ended June 30, 2013 were $2 million and $4 million, respectively, and were included in interest expense. For the three and six months ended June 30, 2013, the Company did not record any amounts in net income related to ineffectiveness for fair value hedges.

7 For the three and six months ended June 30, 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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Derivatives in cash flow hedging relationships

The components of OCI (Note 8) related to derivatives in cash flow hedging relationships are as follows:

	three months ended June 30				six months ended June 30
(unaudited - millions of Canadian $, pre-tax)	2014		2013		2014		2013
Change in fair value of derivative instruments recognized in OCI (effective portion)
Power	(7	)	(70	)	34		(34	)
Natural gas	(1	)	—		(1	)	—
Foreign exchange	—		2		10		4
Interest	(1	)	—		(1	)	—
	(9	)	(68	)	42		(30	)
Reclassification of (losses)/gains on derivative instruments from AOCI to net income (effective portion)1
Power2	(1	)	12		(109	)	1
Natural gas	2		2		2		2
Interest	3		4		8		8
	4		18		(99	)	11
Gains/(losses) on derivative instruments recognized in earnings (ineffective portion)
Power	3		(2	)	(10	)	(7	)
	3		(2	)	(10	)	(7	)

1 No amounts have been excluded from the assessment of hedge effectiveness. Amounts in parentheses indicate losses recorded to OCI.

2 Reported within Energy revenues on the condensed consolidated statement of income.

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 to 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 June 30, 2014	Gross derivative instruments presented on the balance sheet		Amounts available for offset1		Net amounts
(unaudited - millions of Canadian $)
Derivative - Asset
Power	400		(317	)	83
Natural gas	51		(50	)	1
Foreign exchange	20		(20	)	—
Interest	10		(1	)	9
Total	481		(388	)	93
Derivative - Liability
Power	(355	)	317		(38	)
Natural gas	(70	)	50		(20	)
Foreign exchange	(208	)	20		(188	)
Interest	(7	)	1		(6	)
Total	(640	)	388		(252	)

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 June 30, 2014, the Company had provided cash collateral of $164 million and letters of credit of $18 million to its counterparties. The Company held $1 million in letters of credit on asset exposures at June 30, 2014. 

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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, 2013:

at December 31, 2013	Gross derivative instruments presented on the balance sheet		Amounts available for offset1		Net amounts
(unaudited - millions of Canadian $)
Derivative - Asset
Power	415		(277	)	138
Natural gas	73		(61	)	12
Foreign exchange	5		(5	)	—
Interest	14		(2	)	12
Total	507		(345	)	162
Derivative - Liability
Power	(302	)	277		(25	)
Natural gas	(72	)	61		(11	)
Foreign exchange	(230	)	5		(225	)
Interest	(8	)	2		(6	)
Total	(612	)	345		(267	)

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, 2013, the Company had provided cash collateral of $67 million and letters of credit of $85 million to its counterparties. The Company held $11 million in cash collateral and $32 million in letters of credit on asset exposures at December 31, 2013.

Credit risk related contingent features of derivative instruments

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 June 30, 2014, the aggregate fair value of all derivative instruments with credit risk related contingent features that were in a net liability position was $17 million (December 31, 2013 - $16 million), for which the Company had provided collateral in the normal course of business of nil (December 31, 2013 - nil). If the credit risk related contingent features in these agreements were triggered on June 30, 2014, the Company would have been required to provide collateral of $17 million (December 31, 2013 - $16 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.

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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.

Levels	How fair value has been determined
Level I	Quoted prices in active markets for identical assets and liabilities that the Company has the ability to access at the measurement date.
Level II	Valuation based on the extrapolation of inputs, other than quoted prices included within Level I, for which all significant inputs are observable directly or indirectly. Inputs include published exchange rates, interest rates, interest rate swap curves, yield curves and broker quotes from external data service providers. This category includes interest rate and foreign exchange derivative assets and liabilities where fair value is determined using the income approach and power and natural gas commodity derivatives where fair value is determined using the market approach. Transfers between Level I and Level II would occur when there is a change in market circumstances.
Level III	Valuation of assets and liabilities measured on a recurring basis using a market approach based on inputs that are unobservable and significant to the overall fair value measurement. This category includes long-dated commodity transactions in certain markets where liquidity is low. 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 we operate. 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. 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. 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.

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:

at June 30, 2014	Quoted prices in active markets		Significant other observable inputs		Significant unobservable inputs
(unaudited - millions of Canadian $, pre-tax)	(Level I)1		(Level II)1		(Level III)1		Total
Derivative instrument assets:
Power commodity contracts	—		396		4		400
Natural gas commodity contracts	33		18		—		51
Foreign exchange contracts	—		20		—		20
Interest rate contracts	—		10		—		10
Derivative instrument liabilities:
Power commodity contracts	—		(352	)	(3	)	(355	)
Natural gas commodity contracts	(32	)	(36	)	(2	)	(70	)
Foreign exchange contracts	—		(208	)	—		(208	)
Interest rate contracts	—		(7	)	—		(7	)
Non-derivative financial instruments:
Available for sale assets	—		46		—		46
	1		(113	)	(1	)	(113	)

1 There were no transfers from Level I to Level II or from Level II to Level III for the six months endedJune 30, 2014.

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The fair value of the Company’s assets and liabilities measured on a recurring basis, including both current and non-current portions for 2013, are categorized as follows:

at December 31, 2013	Quoted prices in active markets		Significant other observable inputs		Significant unobservable inputs
(unaudited - millions of Canadian $, pre-tax)	(Level I)1		(Level II)1		(Level III)1		Total
Derivative instrument assets:
Power commodity contracts	—		411		4		415
Natural gas commodity contracts	48		25		—		73
Foreign exchange contracts	—		5		—		5
Interest rate contracts	—		14		—		14
Derivative instrument liabilities:
Power commodity contracts	—		(299	)	(3	)	(302	)
Natural gas commodity contracts	(50	)	(22	)	—		(72	)
Foreign exchange contracts	—		(230	)	—		(230	)
Interest rate contracts	—		(8	)	—		(8	)
Non-derivative financial instruments:
Available for sale assets	—		47		—		47
	(2	)	(57	)	1		(58	)

1 There were no transfers from Level I to Level II or from Level II to Level III for the year ended December 31, 2013.

The following table presents the net change in fair value of derivative assets and liabilities classified as Level III of the fair value hierarchy:

	Derivatives1
	three months ended June 30				six months ended June 30
(unaudited - millions of Canadian $, pre-tax)	2014		2013		2014		2013
Balance at beginning of period	1		1		1		(2	)
Settlements	—		1		—		1
Transfers out of Level III	—		(1	)	—		(1	)
Total losses included in net income	(2	)	—		(2	)	—
Total (losses)/gains included in OCI	—		(1	)	—		2
Balance at end of period	(1	)	—		(1	)	—

1 For the three and six months ended June 30, 2014, energy revenues include unrealized losses attributed to derivatives in the Level III category that were still held at the reporting date of $2 million (2013 - nil).

A 10 per cent increase or decrease in commodity prices, with all other variables held constant, would result in a $4 million decrease or increase, respectively, in the fair value of outstanding derivative instruments included in Level III as at June 30, 2014. 

11. 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.

GUARANTEES

TransCanada and its joint venture partner on Bruce Power, BPC Generation Infrastructure Trust (BPC), have each severally guaranteed certain contingent financial obligations of Bruce B related to a lease agreement and contractor and supplier services. In addition, TransCanada and BPC have each severally guaranteed one-half of certain contingent financial obligations of Bruce A related to a sublease agreement and certain other financial obligations. 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 delivery

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of natural gas, PPA payments and the payment of 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.

The carrying value of these guarantees has been included in other long-term liabilities. Information regarding the Company’s guarantees is as follows:

		at June 30, 2014		at December 31, 2013
(unaudited - millions of Canadian $)	Term	Potential Exposure1	Carrying Value	Potential Exposure1	Carrying Value
Bruce Power	ranging to 20192	674	7	740	8
Other jointly owned entities	ranging to 2040	64	10	51	10
		738	17	791	18

1 TransCanada’s share of the potential estimated current or contingent exposure.

2 Except for one guarantee with no termination date.