EXHIBIT 13.2

Condensed consolidated statement of income

	three months ended September 30						nine months ended September 30
(unaudited - millions of Canadian $, except per share amounts)	2015			2014			2015			2014
Revenues
Natural Gas Pipelines	1,305			1,145			3,896			3,514
Liquids Pipelines	507			387			1,410			1,112
Energy	1,132			919			3,143			2,943
	2,944			2,451			8,449			7,569
Income from Equity Investments	94			159			350			362
Operating and Other Expenses
Plant operating costs and other	823			674			2,344			2,163
Commodity purchases resold	624			388			1,731			1,422
Property taxes	133			113			390			355
Depreciation and amortization	439			403			1,313			1,195
Gain on sale of assets	—			—			—			(108		)
	2,019			1,578			5,778			5,027
Financial Charges
Interest expense	341			304			990			875
Interest income and other expense	(16		)	(17		)	(83		)	(63		)
	325			287			907			812
Income before Income Taxes	694			745			2,114			2,092
Income Tax Expense
Current	30			22			124			104
Deferred	193			217			556			521
	223			239			680			625
Net Income	471			506			1,434			1,467
Net income attributable to non-controlling interests	46			25			145			110
Net Income Attributable to Controlling Interests	425			481			1,289			1,357
Preferred share dividends	23			24			71			72
Net Income Attributable to Common Shares	402			457			1,218			1,285
Net Income per Common Share
Basic and diluted		$0.57			$0.64			$1.72			$1.81
Dividends Declared per Common Share		$0.52			$0.48			$1.56			$1.44
Weighted Average Number of Common Shares (millions)
Basic	709			708			709			708
Diluted	710			710			710			709

See accompanying notes to the condensed consolidated financial statements.

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THIRD QUARTER REPORT 2015

Condensed consolidated statement of comprehensive income

	three months ended September 30				nine months ended September 30
(unaudited - millions of Canadian $)	2015		2014		2015		2014
Net Income	471		506		1,434		1,467
Other Comprehensive Income, Net of Income Taxes
Foreign currency translation gains on net investment in foreign operations	356		287		688		337
Change in fair value of net investment hedges	(153	)	(121	)	(361	)	(169	)
Change in fair value of cash flow hedges	(29	)	37		(50	)	64
Reclassification to net income of gains and losses on cash flow hedges	50		5		83		(55	)
Reclassification to net income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans	7		5		24		14
Other comprehensive income on equity investments	3		—		10		2
Other comprehensive income (Note 9)	234		213		394		193
Comprehensive Income	705		719		1,828		1,660
Comprehensive income attributable to non-controlling interests	171		97		388		187
Comprehensive Income Attributable to Controlling Interests	534		622		1,440		1,473
Preferred share dividends	23		24		71		72
Comprehensive Income Attributable to Common Shares	511		598		1,369		1,401

See accompanying notes to the condensed consolidated financial statements.

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Condensed consolidated statement of cash flows

	three months ended September 30				nine months ended September 30
(unaudited - millions of Canadian $)	2015		2014		2015		2014
Cash Generated from Operations
Net income	471		506		1,434		1,467
Depreciation and amortization	439		403		1,313		1,195
Deferred income taxes	193		217		556		521
Income from equity investments	(94	)	(159	)	(350	)	(362	)
Distributed earnings received from equity investments	117		161		397		415
Employee post-retirement benefits expense, net of funding	11		16		41		28
Gain on sale of assets	—		—		—		(108	)
Equity AFUDC	(45	)	(40	)	(115	)	(59	)
Unrealized losses/(gains) on financial instruments	43		(18	)	52		(25	)
Other	5		(15	)	26		18
Decrease/(increase) in operating working capital	107		171		(378	)	250
Net cash provided by operations	1,247		1,242		2,976		3,340
Investing Activities
Capital expenditures	(976	)	(744	)	(2,748	)	(2,381	)
Capital projects under development	(130	)	(207	)	(465	)	(504	)
Equity investments	(105	)	(66	)	(303	)	(195	)
Acquisitions, net of cash acquired	—		(181	)	—		(181	)
Proceeds from sale of assets, net of transaction costs	—		—		—		187
Deferred amounts and other	147		67		461		139
Net cash used in investing activities	(1,064	)	(1,131	)	(3,055	)	(2,935	)
Financing Activities
Dividends on common shares	(369	)	(340	)	(1,078	)	(1,005	)
Dividends on preferred shares	(23	)	(24	)	(69	)	(69	)
Distributions paid to non-controlling interests	(60	)	(42	)	(168	)	(134	)
Notes payable (repaid)/issued, net	(358	)	377		(828	)	(145	)
Junior subordinated debt issued, net of issue costs	—		—		917		—
Long-term debt issued, net of issue costs	962		—		3,323		1,380
Repayment of long-term debt	(183	)	(38	)	(2,066	)	(1,020	)
Common shares issued, net of issue costs	1		27		12		43
Preferred shares issued, net of issue costs	—		—		243		440
Partnership units of subsidiary issued, net of issue costs	—		79		31		79
Preferred shares of subsidiary redeemed	—		—		—		(200	)
Net cash (used in)/provided by financing activities	(30	)	39		317		(631	)
Effect of Foreign Exchange Rate Changes on Cash and Cash Equivalents	12		(19	)	28		(3	)
Increase/(Decrease) in Cash and Cash Equivalents	165		131		266		(229	)
Cash and Cash Equivalents
Beginning of period	590		567		489		927
Cash and Cash Equivalents
End of period	755		698		755		698

See accompanying notes to the condensed consolidated financial statements.

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Condensed consolidated balance sheet

		September 30,		December 31,
(unaudited - millions of Canadian $)		2015		2014
ASSETS
Current Assets
Cash and cash equivalents		755		489
Accounts receivable		1,445		1,313
Inventories		309		292
Other		1,291		1,446
		3,800		3,540
Plant, Property and Equipment,	net of accumulated depreciation of $21,344 and $19,563, respectively	46,831		41,774
Equity Investments		5,782		5,598
Regulatory Assets		1,243		1,297
Goodwill		4,657		4,034
Intangible and Other Assets		3,415		2,704
		65,728		58,947
LIABILITIES
Current Liabilities
Notes payable		1,714		2,467
Accounts payable and other		2,635		2,896
Accrued interest		446		424
Current portion of long-term debt		2,085		1,797
		6,880		7,584
Regulatory Liabilities		966		263
Other Long-Term Liabilities		1,302		1,052
Deferred Income Tax Liabilities		6,032		5,275
Long-Term Debt		26,990		22,960
Junior Subordinated Notes		2,333		1,160
		44,503		38,294
EQUITY
Common shares, no par value		12,214		12,202
Issued and outstanding:	September 30, 2015 - 709 million shares
	December 31, 2014 - 709 million shares
Preferred shares		2,499		2,255
Additional paid-in capital		169		370
Retained earnings		5,592		5,478
Accumulated other comprehensive loss (Note 9)		(1,084	)	(1,235	)
Controlling Interests		19,390		19,070
Non-controlling interests		1,835		1,583
		21,225		20,653
		65,728		58,947
Contingencies and Guarantees (Note 13)
Subsequent Events (Note 15)

See accompanying notes to the condensed consolidated financial statements.

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Condensed consolidated statement of equity

	nine months ended September 30
(unaudited - millions of Canadian $)	2015		2014
Common Shares
Balance at beginning of period	12,202		12,149
Shares issued on exercise of stock options	12		48
Balance at end of period	12,214		12,197
Preferred Shares
Balance at beginning of period	2,255		1,813
Shares issued under public offering, net of issue costs	244		442
Balance at end of period	2,499		2,255
Additional Paid-In Capital
Balance at beginning of period	370		401
Issuance of stock options, net of exercises	8		1
Dilution impact from TC PipeLines, LP units issued	4		9
Redemption of subsidiary's preferred shares	—		(6	)
Impact of asset drop downs to TC PipeLines, LP	(213	)	—
Balance at end of period	169		405
Retained Earnings
Balance at beginning of period	5,478		5,096
Net income attributable to controlling interests	1,289		1,357
Common share dividends	(1,106	)	(1,019	)
Preferred share dividends	(69	)	(74	)
Balance at end of period	5,592		5,360
Accumulated Other Comprehensive Loss
Balance at beginning of period	(1,235	)	(934	)
Other comprehensive income	151		116
Balance at end of period	(1,084	)	(818	)
Equity Attributable to Controlling Interests	19,390		19,399
Equity Attributable to Non-Controlling Interests
Balance at beginning of period	1,583		1,611
Net income attributable to non-controlling interests
TC PipeLines, LP	132		98
Preferred share dividends of TCPL	—		2
Portland	13		10
Other comprehensive income attributable to non-controlling interests	243		77
Issuance of TC PipeLines, LP units
Proceeds, net of issue costs	31		79
Decrease in TransCanada's ownership of TC PipeLines, LP	(6	)	(14	)
Distributions declared to non-controlling interests	(161	)	(134	)
Redemption of subsidiary's preferred shares	—		(194	)
Balance at end of period	1,835		1,535
Total Equity	21,225		20,934

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 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, 2014, except as described in Note 2, Changes in accounting policies. Capitalized and abbreviated terms that are used but not otherwise defined herein are identified in TransCanada’s 2014 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 fairly 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 2014 audited consolidated financial statements included in TransCanada’s 2014 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, 2014, except as described in Note 2, Changes in accounting policies.

2. Changes in accounting policies

CHANGES IN ACCOUNTING POLICIES FOR 2015

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 was applied prospectively from January 1, 2015 and there was no impact on the Company’s consolidated financial statements as a result of applying this new standard.

FUTURE ACCOUNTING CHANGES

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. In July 2015, the FASB agreed to defer the effective date of this new standard to January 1, 2018, with early adoption not permitted before January 1, 2017. There are two methods in which the amendment can be applied:

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(1) retrospectively to each prior reporting period presented, or (2) retrospectively with the cumulative effect recognized at the date of initial application.

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.

Extraordinary and unusual income statement items

In January 2015, the FASB issued new guidance on extraordinary and unusual income statement items. This update eliminates from GAAP the concept of extraordinary items. This new guidance is effective from January 1, 2016 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.

Consolidation

In February 2015, the FASB issued new guidance on consolidation analysis. This update requires that entities reevaluate whether they should consolidate certain legal entities and eliminates the presumption that a general partner should consolidate a limited partnership. This new guidance is effective from January 1, 2016 and will be applied retrospectively. 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.

Imputation of interest

In April 2015, the FASB issued new guidance on simplifying the accounting for debt issuance costs. The amendments in this update require that debt issuance costs be presented in the balance sheet as a direct deduction from the carrying amount of the debt liability consistent with debt discounts or premiums.This new guidance is effective January 1, 2016 and will be applied retrospectively. The application of this amendment will result in a reclassification of debt issuance costs currently recorded in intangible and other assets to an offset of their respective debt liabilities.

Inventory

In July 2015, the FASB issued new guidance on simplifying the measurement of inventory. The amendments in this update specify that an entity should measure inventory within the scope of this update at the lower of cost and net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. Subsequent measurement is unchanged for inventory measured using Last In First Out or the retail inventory method. This new guidance is effective January 1, 2017 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.

Derivatives and Hedging

In August 2015, the FASB issued new guidance on the application of the normal purchases and normal sales scope exception to certain electricity contracts within nodal energy markets. The amendments in this update apply to entities that enter into contracts for the purchase or sale of electricity on a forward basis and arrange for transmission through or delivery to a location within a nodal energy market whereby one of the contracting parties incurs charges (or credits) for the transmission of that electricity based in part on locational marginal pricing differences payable to (or receivable from) an independent system operator. This new guidance was effective upon issuance, was applied prospectively and did not have a material impact on the Company's consolidated financial statements.

Business Combinations

In September 2015, the FASB issued guidance on simplifying the accounting for measurement-period adjustments in business combinations. The new guidance in this update eliminates the requirement for an acquirer in a business combination to account for measurement-period adjustments retrospectively. This new guidance is effective January 1, 2016 and will be applied prospectively on future business combinations. 

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3. Segmented information

three months ended September 30	Natural Gas Pipelines				Liquids Pipelines				Energy				Corporate				Total
(unaudited - millions of Canadian $)	2015		2014		2015		2014		2015		2014		2015		2014		2015		2014
Revenues	1,305		1,145		507		387		1,132		919		—		—		2,944		2,451
Income from equity investments	41		35		—		—		53		124		—		—		94		159
Plant operating costs and other	(446	)	(349	)	(130	)	(92	)	(210	)	(202	)	(37	)	(31	)	(823	)	(674	)
Commodity purchases resold	—		—		—		—		(624	)	(388	)	—		—		(624	)	(388	)
Property taxes	(88	)	(81	)	(22	)	(14	)	(23	)	(18	)	—		—		(133	)	(113	)
Depreciation and amortization	(284	)	(266	)	(68	)	(55	)	(79	)	(76	)	(8	)	(6	)	(439	)	(403	)
Segmented earnings	528		484		287		226		249		359		(45	)	(37	)	1,019		1,032
Interest expense																	(341	)	(304	)
Interest income and other expense																	16		17
Income before income taxes																	694		745
Income tax expense																	(223	)	(239	)
Net income																	471		506
Net income attributable to non-controlling interests																	(46	)	(25	)
Net income attributable to controlling interests																	425		481
Preferred share dividends																	(23	)	(24	)
Net income attributable to common shares																	402		457

nine months ended September 30	Natural Gas Pipelines				Liquids Pipelines				Energy				Corporate				Total
(unaudited - millions of Canadian $)	2015		2014		2015		2014		2015		2014		2015		2014		2015		2014
Revenues	3,896		3,514		1,410		1,112		3,143		2,943		—		—		8,449		7,569
Income from equity investments	134		124		—		—		216		238		—		—		350		362
Plant operating costs and other	(1,273	)	(1,030	)	(369	)	(293	)	(585	)	(749	)	(117	)	(91	)	(2,344	)	(2,163	)
Commodity purchases resold	—		—		—		—		(1,731	)	(1,422	)	—		—		(1,731	)	(1,422	)
Property taxes	(264	)	(251	)	(61	)	(48	)	(65	)	(56	)	—		—		(390	)	(355	)
Depreciation and amortization	(845	)	(791	)	(197	)	(158	)	(248	)	(230	)	(23	)	(16	)	(1,313	)	(1,195	)
Gain on sale of assets	—		—		—		—		—		108		—		—		—		108
Segmented earnings	1,648		1,566		783		613		730		832		(140	)	(107	)	3,021		2,904
Interest expense																	(990	)	(875	)
Interest income and other expense																	83		63
Income before income taxes																	2,114		2,092
Income tax expense																	(680	)	(625	)
Net income																	1,434		1,467
Net income attributable to non-controlling interests																	(145	)	(110	)
Net income attributable to controlling interests																	1,289		1,357
Preferred share dividends																	(71	)	(72	)
Net income attributable to common shares																	1,218		1,285

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TOTAL ASSETS

(unaudited - millions of Canadian $)	September 30, 2015	December 31, 2014
Natural Gas Pipelines	30,008	27,103
Liquids Pipelines	18,856	16,116
Energy	14,820	14,197
Corporate	2,044	1,531
	65,728	58,947

4. Pipeline abandonment costs

As a result of the NEB’s Land Matters Consultation Initiative (LMCI), TransCanada is required to collect funds to cover estimated future pipeline abandonment costs for all NEB regulated Canadian pipelines. Amounts collected are included in regulatory liabilities on the condensed consolidated balance sheet. As at September 30, 2015, regulatory liabilities included $188 million (December 31, 2014 - nil) of estimated future abandonment costs on the condensed consolidated balance sheet. 

Collected funds are placed in trusts that hold and invest the funds and are accounted for as restricted investments. As at September 30, 2015, intangible and other assets included $188 million (December 31, 2014 - nil) of LMCI restricted investments on the condensed consolidated balance sheet. For more information on the fair values of these investments which are classified as available for sale refer to Note 11.

5. Income taxes

At September 30, 2015, the total unrecognized tax benefit of uncertain tax positions was approximately $18 million (December 31, 2014 - $18 million). TransCanada recognizes interest and penalties related to income tax uncertainties in income tax expense. Included in income tax expense for the three and nine months endedSeptember 30, 2015 is nil and $1 million for the reversal of interest expense and nil for penalties (September 30, 2014 - nil of interest expense and nil for penalties). At September 30, 2015, the Company had $4 million accrued for interest expense and nil accrued for penalties (December 31, 2014 - $5 million accrued for interest expense and nil for penalties).

The effective tax rates for the nine-month periods endedSeptember 30, 2015 and 2014 were 32 per cent and 30 per cent. The higher effective tax rate in 2015 was primarily the result of an increase in the Alberta statutory tax rate and changes in the proportion of income earned between Canadian and foreign jurisdictions.

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6. Long-term debt

LONG-TERM DEBT ISSUED

The Company issued long-term debt in the nine months ended September 30, 2015 as follows:

(unaudited - millions of Canadian $, unless noted otherwise)	Issue date	Type	Maturity date	Amount	Interest rate
TRANSCANADA PIPELINES LIMITED
	July 2015	Medium-Term Notes	July 2025	750	3.30	%
	March 2015	Senior Unsecured Notes	March 2045	US 750	4.60	%
	January 2015	Senior Unsecured Notes	January 2018	US 500	1.875	%
	January 2015	Senior Unsecured Notes	January 2018	US 250	Floating
TC PIPELINES, LP
	September 2015	Unsecured Term Loan	October 2018	US 170	Floating
	March 2015	Senior Unsecured Notes	March 2025	US 350	4.375	%
GAS TRANSMISSION NORTHWEST LLC
	June 2015	Unsecured Term Loan	June 2019	US 75	Floating

LONG-TERM DEBT RETIRED

The Company retired long-term debt in the nine months ended September 30, 2015 as follows:

(unaudited - millions of Canadian $, unless noted otherwise)	Retirement date	Type	Amount	Interest rate
TRANSCANADA PIPELINES LIMITED
	August 2015	Debentures	150	11.90	%
	June 2015	Senior Unsecured Notes	US 500	3.40	%
	March 2015	Senior Unsecured Notes	US 500	0.875	%
	January 2015	Senior Unsecured Notes	US 300	4.875	%
GAS TRANSMISSION NORTHWEST LLC
	June 2015	Senior Unsecured Notes	US 75	5.09	%

In the three and nine months endedSeptember 30, 2015, TransCanada capitalized interest related to capital projects of $82 million and $223 million (2014 - $57 million and $199 million).

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7. Junior Subordinated Notes

JUNIOR SUBORDINATED DEBT ISSUED

(unaudited - millions of Canadian $, unless noted otherwise)	Issue date	Type	Maturity date	Amount	Interest rate
TRANSCANADA PIPELINES LIMITED	May 2015	Junior subordinated unsecured notes1	May 2075	US 750	5.875%2

1 The Junior subordinated unsecured notes are subordinated in right of payment to existing and future senior indebtedness or other obligations of TCPL and are callable at TCPL's option at any time on or after May 20, 2025 at 100 per cent of the principal amount plus accrued and unpaid interest to the date of redemption.

2 The Junior subordinated notes were issued to TransCanada Trust. The interest rate is fixed at 5.875 per cent per annum and will reset starting May 2025 until May 2045 to the three month LIBOR plus 3.778 per cent per annum; from May 2045 to May 2075 the interest rate will reset to the three month LIBOR plus 4.528 per cent per annum.

TransCanada Trust (the Trust), a 100 per cent owned financing trust subsidiary of TCPL, issued US$750 million Trust Notes - Series 2015-A (Trust Notes) to third party investors with a fixed interest rate of 5.625 per cent for the first ten years converting to a floating rate thereafter. All of the proceeds of the issuance by the Trust were loaned to TCPL in US$750 million junior subordinated notes of TCPL at a rate of 5.875 per cent which includes a 0.25 per cent administration charge. While the obligations of the Trust are fully and unconditionally guaranteed by TCPL on a subordinated basis, the Trust is not consolidated in TransCanada's financial statements because TCPL does not have a variable interest in the Trust and the only substantive assets of the Trust are receivables from TCPL. 

Pursuant to the terms of the Trust Notes and related agreements, in certain circumstances (1) TCPL may issue deferral preferred shares to holders of the Trust Notes in lieu of interest; and (2) TransCanada and TCPL would be prohibited from declaring or paying dividends on or redeeming their outstanding preferred shares (or, if none are outstanding, their respective common shares) until all deferral preferred shares are redeemed by TCPL. The Trust Notes may also be automatically exchanged for preferred shares of TCPL upon certain kinds of bankruptcy and insolvency events. All of these preferred shares would rank equally with other outstanding first preferred shares of TCPL. Further details regarding the terms of the Trust Notes and the related agreements entered into by TransCanada and TCPL can be found in the prospectus in respect of the Trust Notes and other documents filed under the Trust's profile on SEDAR at www.sedar.com.

8. Equity and share capital

In June 2015, holders of 5.5 million Series 3 cumulative redeemable first preferred shares exercised their option to convert to Series 4 cumulative redeemable first preferred shares and receive quarterly floating rate cumulative dividends at an annual rate equal to the applicable 90-day Government of Canada treasury bill rate plus 1.28 per cent which will reset every quarter going forward. The fixed dividend rate on the remaining Series 3 preferred shares was reset for five years at 2.152 per cent per annum.

In March 2015, TransCanada completed a public offering of 10 million Series 11 cumulative redeemable first preferred shares at $25 per share resulting in gross proceeds of $250 million. The Series 11 preferred shareholders will have the right to convert their Series 11 preferred shares into Series 12 cumulative redeemable first preferred shares on November 30, 2020 and on November 30 of every fifth year thereafter. The holders of Series 12 preferred shares will be entitled to receive quarterly floating rate cumulative dividends at an annual rate equal to the applicable 90-day Government of Canada treasury bill rate plus 2.96 per cent.

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PREFERRED SHARE ISSUANCE AND CONVERSION

The following table summarizes the impact of the 2015 issuance and conversion of preferred shares discussed above:

(unaudited - millions of Canadian $, unless noted otherwise)	Number of shares issued and outstanding (thousands)	Current yield1		Annual dividend per share	Redemption price per share2	Redemption and conversion option date	Right to convert into
Cumulative first preferred shares
Series 3	8,533	2.152	%	0.5375	$25.00	June 30, 2020	Series 4
Series 4	5,467	Floating3		Floating	$25.50	June 30, 2020	Series 3
Series 11	10,000	3.80	%	0.95	$25.00	November 30, 2020	Series 12

1 Holders of the cumulative redeemable first preferred shares set out in this table are entitled to receive a quarterly fixed, cumulative, preferred dividend, as and when declared by the Board with the exception of Series 4 preferred shares. The holders of Series 4 preferred shares are entitled to receive a quarterly, floating rate, cumulative, preferred dividend as and when declared by the Board.

2 TransCanada may, at its option, redeem all or a portion of the outstanding preferred shares for the redemption price per share, plus all accrued and unpaid dividends on the redemption option date and on every fifth anniversary date thereafter.

3 Commencing September 30, 2015, the floating quarterly dividend rate for the Series 4 preferred shares is 1.656 per cent and will reset every quarter going forward.

9. Other comprehensive income and accumulated other comprehensive loss

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

three months ended September 30, 2015	Before tax		Income tax recovery/		Net of tax
(unaudited - millions of Canadian $)	amount		(expense)		amount
Foreign currency translation gains on net investment in foreign operations	350		6		356
Change in fair value of net investment hedges	(207	)	54		(153	)
Change in fair value of cash flow hedges	(49	)	20		(29	)
Reclassification to net income of gains and losses on cash flow hedges	80		(30	)	50
Reclassification to net income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans	10		(3	)	7
Other comprehensive income on equity investments	4		(1	)	3
Other comprehensive income	188		46		234

three months ended September 30, 2014	Before tax		Income tax recovery/		Net of tax
(unaudited - millions of Canadian $)	amount		(expense)		amount
Foreign currency translation gains on net investment in foreign operations	234		53		287
Change in fair value of net investment hedges	(164	)	43		(121	)
Change in fair value of cash flow hedges	62		(25	)	37
Reclassification to net income of gains and losses on cash flow hedges	5		—		5
Reclassification to net income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans	6		(1	)	5
Other comprehensive income on equity investments	2		(2	)	—
Other comprehensive income	145		68		213

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THIRD QUARTER REPORT 2015

nine months ended September 30, 2015	Before tax amount		Income tax recovery/(expense)		Net of tax amount
(unaudited - millions of Canadian $)
Foreign currency translation gains on net investments in foreign operations	675		13		688
Change in fair value of net investment hedges	(490	)	129		(361	)
Change in fair value of cash flow hedges	(78	)	28		(50	)
Reclassification to net income of gains and losses on cash flow hedges	136		(53	)	83
Reclassification to net income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans	30		(6	)	24
Other comprehensive income on equity investments	13		(3	)	10
Other comprehensive income	286		108		394

nine months ended September 30, 2014	Before tax amount		Income tax recovery/(expense)		Net of tax amount
(unaudited - millions of Canadian $)
Foreign currency translation gains on net investments in foreign operations	285		52		337
Change in fair value of net investment hedges	(228	)	59		(169	)
Change in fair value of cash flow hedges	104		(40	)	64
Reclassification to net income of gains and losses on cash flow hedges	(94	)	39		(55	)
Reclassification to net income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans	19		(5	)	14
Other comprehensive gain on equity investments	3		(1	)	2
Other comprehensive income	89		104		193

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

three months ended September 30, 2015	Currency translation		Cash flow		Pension and OPEB plan		Equity
(unaudited - millions of Canadian $)	adjustments		hedges		adjustments		investments		Total1
AOCI balance at July 1, 2015	(512	)	(116	)	(264	)	(301	)	(1,193	)
Other comprehensive income/(loss) before reclassifications2	76		(27	)	—		—		49
Amounts reclassified from accumulated other comprehensive loss	—		50		7		3		60
Net current period other comprehensive income	76		23		7		3		109
AOCI balance at September 30, 2015	(436	)	(93	)	(257	)	(298	)	(1,084	)

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 and cash flow hedges is net of non-controlling interest gains of $127 million and losses of $2 million.

nine months ended September 30, 2015	Currency translation adjustments		Cash flow hedges		Pension and OPEB plan adjustments		Equity Investments		Total1
(unaudited - millions of Canadian $)
AOCI balance at January 1, 2015	(518	)	(128	)	(281	)	(308	)	(1,235	)
Other comprehensive income/(loss) before reclassifications2	82		(48	)	—		—		34
Amounts reclassified from accumulated other comprehensive loss3	—		83		24		10		117
Net current period other comprehensive income	82		35		24		10		151
AOCI balance at September 30, 2015	(436	)	(93	)	(257	)	(298	)	(1,084	)

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 and cash flow hedges is net of non-controlling interest gains of $245 million and losses of $2 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 $64 million ($39 million, net of tax) at September 30, 2015. 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 are as follows: 

	Amounts reclassified from accumulated other comprehensive loss1								Affected line item in the condensed consolidated statement of income
	three months ended September 30				nine months ended September 30
(unaudited - millions of Canadian $)	2015		2014		2015		2014
Cash flow hedges
Power and Natural Gas	(76	)	(1	)	(124	)	106		Revenue (Energy)
Interest	(4	)	(4	)	(12	)	(12	)	Interest expense
	(80	)	(5	)	(136	)	94		Total before tax
	30		—		53		(39	)	Income tax expense
	(50	)	(5	)	(83	)	55		Net of tax
Pension and OPEB plan adjustments
Amortization of actuarial loss and past service cost	(10	)	(6	)	(30	)	(19	)	2
	3		1		6		5		Income tax expense
	(7	)	(5	)	(24	)	(14	)	Net of tax
Equity Investments
Equity income	(4	)	(2	)	(13	)	(3	)	Income from equity investments
	1		2		3		1		Income tax expense
	(3	)	—		(10	)	(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 10 for additional detail.

10. 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 September 30							nine months ended September 30
	Pension benefit plans				Other post-retirement benefit plans			Pension benefit plans				Other post-retirement benefit plans
(unaudited - millions of Canadian $)	2015		2014		2015		2014	2015		2014		2015		2014
Service cost	27		21		1		1	81		64		2		2
Interest cost	29		28		2		2	86		84		7		7
Expected return on plan assets	(39	)	(35	)	(1	)	—	(116	)	(104	)	(2	)	(1	)
Amortization of actuarial loss	9		5		1		—	26		16		3		1
Amortization of past service cost	—		1		—		—	1		2		—		—
Amortization of regulatory asset	6		4		—		1	18		13		—		1
Amortization of transitional obligation related to regulated business	—		—		1		—	—		—		2		1
Net benefit cost recognized	32		24		4		4	96		75		12		11

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11. Risk management and financial instruments

RISK MANAGEMENT OVERVIEW

TransCanada has exposure to market risk and counterparty credit 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 September 30, 2015, without taking into account security held, consisted of accounts receivable, available for sale assets recorded at fair value, the fair value of derivative assets and notes, loans and advances receivable. At September 30, 2015, there were no significant amounts past due or impaired, and there were no significant credit losses during the period.

The Company had a credit risk concentration due from a counterparty of $248 million (US$185 million) and $258 million (US$222 million) at September 30, 2015 and December 31, 2014. 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 and foreign exchange forward contracts.

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

(unaudited - millions of Canadian $, unless noted otherwise)	September 30, 2015	December 31, 2014
Carrying value	21,000 (US 15,600)	17,000 (US 14,700)
Fair value	22,400 (US 16,700)	19,000 (US 16,400)

Derivatives designated as a net investment hedge

	September 30, 2015			December 31, 2014
(unaudited - millions of Canadian $, unless noted otherwise)	Fair value1		Notional or principal amount	Fair value1		Notional or principal amount
Asset/(liability)
U.S. dollar cross-currency interest rate swaps
(maturing 2015 to 2019)2	(711	)	US 2,300	(431	)	US 2,900
U.S. dollar foreign exchange forward contracts
(maturing 2015 to 2016)	(18	)	US 800	(28	)	US 1,400
	(729	)	US 3,100	(459	)	US 4,300

1 Fair values equal carrying values.

2 Net income in the three and nine months endedSeptember 30, 2015 included net realized gains of $2 million and $7 million (2014 - gains of $5 million and $16 million) related to the interest component of cross-currency swaps which is offset in interest expense.

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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 $)	September 30, 2015		December 31, 2014
Other current assets	42		5
Intangible and other assets	6		1
Accounts payable and other	(355	)	(155	)
Other long-term liabilities	(422	)	(310	)
	(729	)	(459	)

FINANCIAL INSTRUMENTS

Non-derivative financial instruments

Fair value of non-derivative financial instruments

The fair value of the Company's notes receivable is calculated by discounting future payments of interest and principal using forward interest rates. The fair value of long-term debt and junior subordinated notes is estimated using an income approach based on quoted market prices for the same or similar debt instruments from external data service providers.

Available for sale assets are recorded at fair value which is calculated using quoted market prices where available. 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 approximate their fair value due to the nature of the item or the short time to maturity and would also be classified in Level II of the fair value hierarchy.

Credit risk has been taken into consideration when calculating the fair value of non-derivative instruments.

Balance sheet presentation of non-derivative financial instruments

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

	September 30, 2015				December 31, 2014
(unaudited - millions of Canadian $)	Carrying amount		Fair value		Carrying amount		Fair value
Notes receivable1	204		254		213		263
Current and long-term debt2,3	(29,075	)	(32,511	)	(24,757	)	(28,713	)
Junior subordinated notes	(2,333	)	(2,069	)	(1,160	)	(1,157	)
	(31,204	)	(34,326	)	(25,704	)	(29,607	)

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

2 Long-term debt is recorded at amortized cost except for US$750 million (December 31, 2014 - US$400 million) that is attributed to hedged risk and recorded at fair value.

3 Consolidated net income for the three and nine months ended September 30, 2015 included unrealized losses of $9 million and $9 million (2014 - gains of $2 million and losses of $3 million) for fair value adjustments attributable to the hedged interest rate risk associated with interest rate swap fair value hedging relationships on US$750 million of long-term debt at September 30, 2015 (December 31, 2014 - US$400 million). There were no other unrealized gains or losses from fair value adjustments to the non-derivative financial instruments.

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Available for sale assets summary

The following tables summarize additional information about the Company's restricted investments that are classified as available for sale assets:

	September 30, 2015		December 31, 2014
(unaudited - millions of Canadian $)	LMCI restricted investments	Other restricted investments2	LMCI restricted investments	Other restricted investments2
Fair Values1
Fixed income securities (maturing within 5 years)	—	110	—	75
Fixed income securities (maturing after 10 years)	186	—	—	—
	186	110	—	75

1 Available for sale assets are recorded at fair value and included in intangible and other assets on the condensed consolidated balance sheet.

2 Other restricted investments have been set aside to fund insurance claim losses to be paid by the Company's wholly-owned captive insurance subsidiary.

	September 30, 2015			September 30, 2014
(unaudited - millions of Canadian $)	LMCI restricted investments1		Other restricted investments2	LMCI restricted investments1	Other restricted investments2
Net unrealized gains/(losses) in the period
three months ended	1		—	—	—
nine months ended	(2	)	—	—	—

1 Gains and losses arising from changes in the fair value of LMCI restricted investments impact the subsequent amounts to be collected through tolls to cover future pipeline abandonment costs. As a result, the Company records these gains and losses as regulatory assets or liabilities.

2 Other restricted investments have been set aside to fund insurance claim losses to be paid by the Company's wholly-owned captive insurance subsidiary.

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 period end market rates and applies a discounted cash flow valuation model. The fair value of power and natural gas derivatives 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. The fair value of options has been calculated using the Black-Scholes pricing model. Credit risk has been taken into consideration when calculating the fair value of derivative instruments.

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 or are not designated as a hedge 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 $)	September 30, 2015		December 31, 2014
Other current assets	314		409
Intangible and other assets	150		93
Accounts payable and other	(795	)	(749	)
Other long-term liabilities	(626	)	(411	)
	(957	)	(658	)

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2015 derivative instruments summary

The following summary does not include hedges of the Company's 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		$295			$60			$—			$3
Liabilities		($366	)		($99	)		($56	)		($3	)
Notional values3
Volumes4
Purchases	60,603			106			—			—
Sales	48,801			58			—			—
U.S. dollars	—			—			US 1,299			US 100
Net unrealized (losses)/gains in the period5
three months ended September 30, 2015		($34	)		$7			($26	)		$—
nine months ended September 30, 2015		($33	)		$3			($25	)		$—
Net realized losses in the period5
three months ended September 30, 2015		($27	)		($25	)		($34	)		$—
nine months ended September 30, 2015		($60	)		($24	)		($87	)		$—
Maturity dates3	2015-2020			2015-2020			2015-2016			2015-2016
Derivative instruments in hedging relationships6,7
Fair values2,3
Assets		$46			$—			$—			$12
Liabilities		($116	)		$—			$—			($4	)
Notional values3
Volumes4
Purchases	11,985			—			—			—
Sales	5,006			—			—			—
U.S. dollars	—			—			—			US 900
Net realized (losses)/gains in the period5
three months ended September 30, 2015		($35	)		$—			$—			$2
nine months ended September 30, 2015		($132	)		$—			$—			$6
Maturity dates3	2015-2020			—			—			2015-2019

1 The majority of derivative instruments held for trading have been entered into for risk management purposes and all 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 September 30, 2015.

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 energy revenues. Realized and unrealized gains and losses on interest rate and foreign exchange derivative instruments held for trading are included net in interest expense and interest income and other expense, respectively. The effective portion of the change in fair value of derivative instruments in hedging relationships is initially recognized in OCI and reclassified to energy revenues, interest expense and interest income and other expense, 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 $12 million and a notional amount of US$750 million as at September 30, 2015. For the three and nine months ended September 30, 2015, net realized gains on fair value hedges were $4 million and $8 million and were included in interest expense. For the three and nine months ended September 30, 2015, the Company did not record any amounts in net income related to ineffectiveness for fair value hedges.

7 For the three and nine months ended September 30, 2015, 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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2014 derivative instruments summary

The following summary does not include hedges of the Company's 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		$362			$69			$1			$4
Liabilities		($391	)		($103	)		($32	)		($4	)
Notional values3
Volumes4
Purchases	42,097			60			—			—
Sales	35,452			38			—			—
U.S. dollars	—			—			US 1,374			US 100
Net unrealized gains/(losses) in the period5
three months ended September 30, 2014		$20			$7			($32	)		$—
nine months ended September 30, 2014		$35			($14	)		($9	)		$—
Net realized gains/(losses) in the period5
three months ended September 30, 2014		$8			($27	)		($1	)		$—
nine months ended September 30, 2014		($23	)		$19			($19	)		$—
Maturity dates3	2015-2019			2015-2020			2015			2015-2016
Derivative instruments in hedging relationships6,7
Fair values2,3
Assets		$57			$—			$—			$3
Liabilities		($163	)		$—			$—			($2	)
Notional values3
Volumes4
Purchases	11,120			—			—			—
Sales	3,977			—			—			—
U.S. dollars	—			—			—			US 550
Net realized (losses)/gains in the period5
three months ended September 30, 2014		($50	)		$—			$—			$1
nine months ended September 30, 2014		$138			$—			$—			$3
Maturity dates3	2015-2019			—			—			2015-2018

1 The majority of derivative instruments held for trading have been entered into for risk management purposes and all 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, 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 energy revenues. Realized and unrealized gains and losses on interest rate and foreign exchange derivative instruments held for trading are included net in interest expense and interest income and other expense, respectively. The effective portion of the change in fair value of derivative instruments in hedging relationships is initially recognized in OCI and reclassified to energy revenues, interest expense and interest income and other expense, 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 $3 million and a notional amount of US$400 million as at December 31, 2014. Net realized gains on fair value hedges for the three and nine months ended September 30, 2014 were $2 million and $5 million and were included in interest expense. For the three and nine months ended September 30, 2014, the Company did not record any amounts in net income related to ineffectiveness for fair value hedges.

7 For the three and nine months ended September 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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Derivatives in cash flow hedging relationships

The components of OCI (Note 9) related to derivatives in cash flow hedging relationships are as follows: 

	three months ended September 30				nine months ended September 30
(unaudited - millions of Canadian $, pre-tax)	2015		2014		2015		2014
Change in fair value of derivative instruments recognized in OCI (effective portion)1
Power	(48	)	62		(77	)	96
Natural gas	—		(1	)	—		(2	)
Foreign exchange	—		—		—		10
Interest	(1	)	1		(1	)	—
	(49	)	62		(78	)	104
Reclassification of gains/(losses) on derivative instruments from AOCI to net income (effective portion)1
Power2	76		—		124		(109	)
Natural gas2	—		1		—		3
Interest3	4		4		12		12
	80		5		136		(94	)
Gains on derivative instruments recognized in net income (ineffective portion)
Power	10		23		3		13
	10		23		3		13

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.

3 Reported within interest expense 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 September 30, 2015	Gross derivative instruments presented on the balance sheet		Amounts available for offset1		Net amounts
(unaudited - millions of Canadian $)
Derivative - Asset
Power	341		(296	)	45
Natural gas	60		(48	)	12
Foreign exchange	48		(48	)	—
Interest	15		(3	)	12
Total	464		(395	)	69
Derivative - Liability
Power	(482	)	296		(186	)
Natural gas	(99	)	48		(51	)
Foreign exchange	(833	)	48		(785	)
Interest	(7	)	3		(4	)
Total	(1,421	)	395		(1,026	)

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

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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, 2014:

at December 31, 2014	Gross derivative instruments presented on the balance sheet		Amounts available for offset1		Net amounts
(unaudited - millions of Canadian $)
Derivative - Asset
Power	419		(330	)	89
Natural gas	69		(57	)	12
Foreign exchange	7		(7	)	—
Interest	7		(1	)	6
Total	502		(395	)	107
Derivative - Liability
Power	(554	)	330		(224	)
Natural gas	(103	)	57		(46	)
Foreign exchange	(497	)	7		(490	)
Interest	(6	)	1		(5	)
Total	(1,160	)	395		(765	)

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 September 30, 2015, the Company had provided cash collateral of $468 million (December 31, 2014 - $459 million) and letters of credit of $28 million (December 31, 2014 - $26 million) to its counterparties. The Company held nil (December 31, 2014 - $1 million) in cash collateral and $2 million (December 31, 2014 - $1 million) in letters of credit from counterparties on asset exposures at September 30, 2015. 

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 September 30, 2015, the aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a net liability position was $15 million (December 31, 2014 - $15 million), for which the Company had provided collateral in the normal course of business of nil (December 31, 2014 - nil). If the credit-risk-related contingent features in these agreements were triggered on September 30, 2015, the Company would have been required to provide additional collateral of $15 million (December 31, 2014 - $15 million) to its counterparties. Collateral may also need to be provided should the fair value of derivative instruments exceed pre-defined contractual exposure limit thresholds.

The Company has sufficient liquidity in the form of cash and undrawn committed revolving bank lines to meet these contingent obligations should they arise.

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FAIR VALUE HIERARCHY

The Company’s financial assets and liabilities recorded at fair value have been categorized into three categories based on a 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 are measured using a market approach based on extrapolation of inputs that are unobservable or where observable data does not support a significant portion of the derivative's fair value. This category includes long-dated commodity transactions in certain markets where liquidity is low and inputs may include long-term broker quotes. Valuation of options is based on the Black-Scholes pricing model. Long-term electricity prices may also be 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 might be estimated 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, increases in the supply of electricity or natural gas, or a small number of transactions in markets with lower liquidity are 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 significant 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 derivative instrument assets and liabilities measured on a recurring basis, including both current and non-current portions, are categorized as follows:

at September 30, 2015	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	—		337		4		341
Natural gas commodity contracts	34		14		12		60
Foreign exchange contracts	—		48		—		48
Interest rate contracts	—		15		—		15
Derivative instrument liabilities:
Power commodity contracts	—		(476	)	(6	)	(482	)
Natural gas commodity contracts	(88	)	(10	)	(1	)	(99	)
Foreign exchange contracts	—		(833	)	—		(833	)
Interest rate contracts	—		(7	)	—		(7	)
	(54	)	(912	)	9		(957	)

1 There were no transfers from Level I to Level II or from Level II to Level III for the nine months endedSeptember 30, 2015.

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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 2014, are categorized as follows:

at December 31, 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	—		417		2		419
Natural gas commodity contracts	40		24		5		69
Foreign exchange contracts	—		7		—		7
Interest rate contracts	—		7		—		7
Derivative instrument liabilities:
Power commodity contracts	—		(551	)	(3	)	(554	)
Natural gas commodity contracts	(86	)	(17	)	—		(103	)
Foreign exchange contracts	—		(497	)	—		(497	)
Interest rate contracts	—		(6	)	—		(6	)
	(46	)	(616	)	4		(658	)

1 There were no transfers from Level I to Level II or from Level II to Level III for the year ended December 31, 2014.

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

	three months ended September 30				nine months ended September 30
(unaudited - millions of Canadian $, pre-tax)	2015		2014		2015		2014
Balance at beginning of period	11		(1	)	4		1
Transfers out of Level III	—		(1	)	3		(1	)
Total (losses)/gains included in net income	(2	)	2		3		—
Sales	(1	)	—		(1	)	—
Total gains included in OCI	1		—		—		—
Balance at end of period1	9		—		9		—

1 For the three and nine months ended September 30, 2015, energy revenues include unrealized losses of $2 million and gains of $6 million attributed to derivatives in the Level III category that were still held at September 30, 2015 (2014 - gains of $2 million and nil).

A 10 per cent increase or decrease in commodity prices, with all other variables held constant, would result in a $2 million increase or decrease in the fair value of outstanding derivative instruments included in Level III as at September 30, 2015. 

12. Sale of GTN Pipeline to TC PipeLines, LP

On April 1, 2015, TransCanada completed the sale of its remaining 30 per cent interest in Gas Transmission Northwest (GTN) to TC PipeLines, LP for an aggregate purchase price of US$446 million plus a purchase price adjustment of US$11 million. Proceeds for the US$457 million sale were comprised of US$264 million in cash, the assumption of US$98 million in proportional GTN debt and US$95 million of new Class B units of TC PipeLines, LP.

13. 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.

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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 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 September 30, 2015		at December 31, 2014
(unaudited - millions of Canadian $)	Term	Potential exposure1	Carrying value	Potential exposure1	Carrying value
Bruce Power	ranging to 20192	529	5	634	6
Other jointly owned entities	ranging to 2040	140	20	104	14
		669	25	738	20

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

2 Except for one guarantee with no termination date.

14. Restructuring costs

During 2015, TransCanada commenced a business restructuring and transformation initiative to reduce overall costs and maximize the effectiveness and efficiency of its existing operations. At September 30, 2015, TransCanada had incurred $36 million before tax, mainly related to severance costs, of which $20 million before tax was included in plant operating costs and other on the income statement, $8 million was capitalized to projects impacted by the restructuring and $8 million is recoverable through regulatory and tolling structures. The total restructuring charges will be determined once the scope of the expected changes is known, which is anticipated to occur in fourth quarter 2015. The Company expects further restructuring initiatives to be undertaken in fourth quarter 2015 and to continue into 2016.

15. Subsequent events

On October 6, 2015, TCPL completed an offering of $400 million, 4.55 per cent Medium Term Notes due November 15, 2041.

On October 8, 2015, TransCanada entered into an agreement to acquire the Ironwood natural gas fired, combined cycle power plant in Pennsylvania for US$654 million. At closing, US$42 million in debt will be assumed and repaid within 45 days of closing out of funds placed into escrow by the seller. The transaction is expected to close in first quarter 2016, subject to certain conditions being satisfied.