TC Energy (TRP) 6-K TransCanada Reports Third Quarter 2016 Financial Results

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)	2016			2015			2016			2015
Revenues
Natural Gas Pipelines	1,884			1,305			4,511			3,896
Liquids Pipelines	440			507			1,292			1,410
Energy	1,308			1,132			3,083			3,143
	3,632			2,944			8,886			8,449
Income from Equity Investments	154			94			355			350
Operating and Other Expenses
Plant operating costs and other	1,177			823			2,646			2,344
Commodity purchases resold	783			624			1,628			1,731
Property taxes	136			133			405			390
Depreciation and amortization	527			439			1,425			1,313
Goodwill and other asset impairment charges	1,085			—			1,296			—
	3,708			2,019			7,400			5,778
Loss on Sale of Assets	—			—			(4		)	—
Financial Charges
Interest expense	522			341			1,456			990
Interest income and other	(122		)	(16		)	(440		)	(83		)
	400			325			1,016			907
(Loss)/Income before Income Taxes	(322		)	694			821			2,114
Income Tax (Recovery)/Expense
Current	14			30			103			124
Deferred	(280		)	193			(25		)	556
	(266		)	223			78			680
Net (Loss)/Income	(56		)	471			743			1,434
Net income attributable to non-controlling interests	52			46			184			145
Net (Loss)/Income Attributable to Controlling Interests	(108		)	425			559			1,289
Preferred share dividends	27			23			77			71
Net (Loss)/Income Attributable to Common Shares	(135		)	402			482			1,218
Net (Loss)/Income per Common Share
Basic and diluted		($0.17	)		$0.57			$0.66			$1.72
Dividends Declared per Common Share		$0.565			$0.52			$1.695			$1.56
Weighted Average Number of Common Shares (millions)
Basic	797			709			734			709
Diluted	798			710			735			710

See accompanying notes to the condensed consolidated financial statements.

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Condensed consolidated statement of comprehensive income

	three months ended September 30				nine months ended September 30
(unaudited - millions of Canadian $)	2016		2015		2016		2015
Net (Loss)/Income	(56	)	471		743		1,434
Other Comprehensive Income/(Loss), Net of Income Taxes
Foreign currency translation gains/(losses) on net investment in foreign operations	55		356		(152	)	688
Change in fair value of net investment hedges	(1	)	(153	)	(9	)	(361	)
Change in fair value of cash flow hedges	5		(29	)	21		(50	)
Reclassification to net income of gains on cash flow hedges	—		50		40		83
Reclassification to net income of actuarial gains and prior service costs on pension and other post-retirement benefit plans	4		7		12		24
Other comprehensive income on equity investments	4		3		11		10
Other comprehensive income/(loss) (Note 11)	67		234		(77	)	394
Comprehensive Income	11		705		666		1,828
Comprehensive income attributable to non-controlling interests	76		171		104		388
Comprehensive (Loss)/Income Attributable to Controlling Interests	(65	)	534		562		1,440
Preferred share dividends	27		23		77		71
Comprehensive (Loss)/Income Attributable to Common Shares	(92	)	511		485		1,369

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 $)	2016		2015		2016		2015
Cash Generated from Operations
Net (loss)/income	(56	)	471		743		1,434
Depreciation and amortization	527		439		1,425		1,313
Goodwill and other asset impairment charges	1,085		—		1,296		—
Deferred income taxes	(280	)	193		(25	)	556
Income from equity investments	(154	)	(94	)	(355	)	(350	)
Distributed earnings received from equity investments	155		117		408		397
Employee post-retirement benefits expense, net of funding	4		11		(5	)	41
Loss on sale of assets	—		—		4		—
Equity allowance for funds used during construction	(71	)	(45	)	(195	)	(115	)
Unrealized losses/(gains) on financial instruments	82		43		(71	)	52
Other	1		5		24		26
(Increase)/decrease in operating working capital	(110	)	107		28		(378	)
Net cash provided by operations	1,183		1,247		3,277		2,976
Investing Activities
Capital expenditures	(1,444	)	(976	)	(3,262	)	(2,748	)
Capital projects in development	(62	)	(130	)	(219	)	(465	)
Contributions to equity investments	(286	)	(105	)	(570	)	(303	)
Restricted cash	13,113		—		—		—
Acquisitions, net of cash acquired	(12,609	)	—		(13,608	)	—
Proceeds from sale of assets, net of transaction costs	—		—		6		—
Distributions received in excess of equity earnings	30		111		942		221
Deferred amounts and other	38		36		18		240
Net cash used in investing activities	(1,220	)	(1,064	)	(16,693	)	(3,055	)
Financing Activities
Notes payable repaid, net	(423	)	(358	)	(100	)	(828	)
Long-term debt issued, net of issue costs	6		962		12,333		3,323
Long-term debt repaid	(53	)	(183	)	(2,343	)	(2,066	)
Junior subordinated notes issued, net of issue costs	1,551		—		1,551		917
Dividends on common shares	(397	)	(369	)	(1,159	)	(1,078	)
Dividends on preferred shares	(28	)	(23	)	(74	)	(69	)
Distributions paid to non-controlling interests	(77	)	(60	)	(201	)	(168	)
Common shares/subscription receipts issued, net of issue costs	(37	)	1		4,337		12
Common shares repurchased	—		—		(14	)	—
Preferred shares issued, net of issue costs	—		—		492		243
Partnership units of subsidiary issued, net of issue costs	45		—		151		31
Net cash provided by/(used in) financing activities	587		(30	)	14,973		317
Effect of Foreign Exchange Rate Changes on Cash and Cash Equivalents	3		12		(127	)	28
Increase in Cash and Cash Equivalents	553		165		1,430		266
Cash and Cash Equivalents
Beginning of period	1,727		590		850		489
Cash and Cash Equivalents
End of period	2,280		755		2,280		755

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 $)		2016		2015
ASSETS
Current Assets
Cash and cash equivalents		2,280		850
Accounts receivable		1,765		1,387
Inventories		424		323
Other		927		1,358
		5,396		3,918
Plant, Property and Equipment	net of accumulated depreciation of $23,279 and $22,299, respectively	56,203		44,817
Equity Investments		6,496		6,214
Regulatory Assets		1,346		1,184
Goodwill		13,638		4,812
Intangible and Other Assets		3,567		3,102
Restricted Investments		612		351
		87,258		64,398
LIABILITIES
Current Liabilities
Notes payable		1,000		1,218
Accounts payable and other		3,781		3,077
Accrued interest		549		520
Current portion of long-term debt		790		2,547
		6,120		7,362
Regulatory Liabilities		2,093		1,159
Other Long-Term Liabilities		1,262		1,260
Deferred Income Tax Liabilities		7,345		5,144
Long-Term Debt		43,273		28,909
Junior Subordinated Notes		3,842		2,409
		63,935		46,243
Common Units of TC PipeLines, LP Subject to Rescission		106		—
EQUITY
Common shares, no par value		16,480		12,102
Issued and outstanding:	September 30, 2016 - 800 million shares
	December 31, 2015 - 703 million shares
Preferred shares		2,992		2,499
Additional paid-in capital		—		7
Retained earnings		1,992		2,769
Accumulated other comprehensive loss (Note 11)		(936	)	(939	)
Controlling Interests		20,528		16,438
Non-controlling interests		2,689		1,717
		23,217		18,155
		87,258		64,398
Commitments and Guarantees (Note 15)
Variable Interest Entities (Note 16)
Subsequent Events (Note 17)

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 $)	2016		2015
Common Shares
Balance at beginning of period	12,102		12,202
Shares issued on exercise of stock options	70		12
Shares repurchased	(6	)	—
Shares issued on exchange of subscription receipts	4,314		—
Balance at end of period	16,480		12,214
Preferred Shares
Balance at beginning of period	2,499		2,255
Shares issued under public offering, net of issue costs	493		244
Balance at end of period	2,992		2,499
Additional Paid-In Capital
Balance at beginning of period	7		370
Issuance of stock options, net of exercises	3		8
Dilution impact from TC PipeLines, LP units issued	17		4
Impact of common shares repurchased	(8	)	—
Impact of asset drop down to TC PipeLines, LP	(38	)	(213	)
Reclassification of Additional Paid-In Capital deficit to Retained Earnings	19		—
Balance at end of period	—		169
Retained Earnings
Balance at beginning of period	2,769		5,478
Net income attributable to controlling interests	559		1,289
Common share dividends	(1,246	)	(1,106	)
Preferred share dividends	(71	)	(69	)
Reclassification of Additional Paid-In Capital deficit to Retained Earnings	(19	)	—
Balance at end of period	1,992		5,592
Accumulated Other Comprehensive Loss
Balance at beginning of period	(939	)	(1,235	)
Other comprehensive income	3		151
Balance at end of period	(936	)	(1,084	)
Equity Attributable to Controlling Interests	20,528		19,390
Equity Attributable to Non-Controlling Interests
Balance at beginning of period	1,717		1,583
Acquisition of non-controlling interests in Columbia Pipeline Partners LP	1,051		—
Net income attributable to non-controlling interests
TC PipeLines, LP	153		132
Portland	27		13
Columbia Pipeline Partners LP	4		—
Other comprehensive (loss)/income attributable to non-controlling interests	(80	)	243
Issuance of TC PipeLines, LP units
Proceeds, net of issue costs	151		31
Decrease in TransCanada's ownership of TC PipeLines, LP	(28	)	(6	)
Reclassification to Common Units of TC PipeLines, LP Subject to Rescission	(106	)	—
Distributions declared to non-controlling interests	(200	)	(161	)
Balance at end of period	2,689		1,835
Total Equity	23,217		21,225

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), which now includes Columbia Pipeline Group (Columbia) 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, 2015, except as described in Note 2, Accounting changes. Capitalized and abbreviated terms that are used but not otherwise defined herein are identified in TransCanada’s 2015 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 2015 audited consolidated financial statements included in TransCanada’s 2015 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 fair value of assets and liabilities acquired in a business combination accounted for under the acquisition method are also subject to estimates and judgement. 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, 2015, except as described in Note 2, Accounting changes.

2. Accounting changes

CHANGES IN ACCOUNTING POLICIES FOR 2016

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 U.S. GAAP the concept of extraordinary items. This new guidance was effective January 1, 2016, was applied prospectively and did not have a material impact on the Company’s consolidated financial statements.

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Consolidation

In February 2015, the FASB issued new guidance on consolidation. This update requires that entities re-evaluate whether they should consolidate certain legal entities and eliminates the presumption that a general partner should consolidate a limited partnership. This new guidance was effective January 1, 2016, was applied retrospectively and did not result in any change to the Company's consolidation conclusions. Disclosure requirements outlined in the new guidance are included in Note 16, Variable Interest Entities.

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 was effective January 1, 2016, was applied retrospectively and resulted in a reclassification of debt issuance costs previously recorded in Intangible and other assets to an offset of their respective debt liabilities on the Company’s consolidated balance sheet.

Business combinations

In September 2015, the FASB issued guidance which intends to simplify the accounting measurement period adjustments in business combinations. The amended guidance requires an acquirer to recognize adjustments to the provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. In the period the adjustment was determined, the guidance also requires the acquirer to record the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. This new guidance was effective January 1, 2016, was applied prospectively and did not have a material impact on the Company's consolidated financial statements.

FUTURE ACCOUNTING CHANGES

Revenue from contracts with customers

In 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 deferred 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: (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 identifying existing customer contracts or groups of contracts that are within the scope of the new guidance and has begun an assessment in order to determine any impact on the consolidated financial statements.

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. 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.

Financial instruments

In January 2016, the FASB issued new guidance on the accounting for equity investments and financial liabilities. The new guidance will change the income statement effect of equity investments and the recognition of changes in fair value of financial liabilities when the fair value option is elected. The new guidance also requires the Company to assess

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valuation allowances for deferred tax assets related to available-for-sale debt securities in combination with their other deferred tax assets. This new guidance is effective January 1, 2018. The Company is currently evaluating the impact of the adoption of this guidance and has not yet determined the effect on its consolidated financial statements.

Leases

In February 2016, the FASB issued new guidance on leases. The new guidance requires lessees to recognize most leases, including operating leases, on the balance sheet as lease assets and lease liabilities. In addition, lessees may be required to reassess assumptions associated with existing leases as well as to provide expanded qualitative and quantitative disclosures. The new standard does not make extensive changes to lessor accounting. The new guidance is effective January 1, 2019 and will be applied using a modified retrospective approach. The Company is currently identifying existing lease agreements that are within the scope of the new guidance that may have an impact on its consolidated financial statements as a result of adopting this new standard.

Derivatives and hedging

In March 2016, the FASB issued new guidance that clarifies the requirements for assessing whether contingent call or put options that can accelerate the payment of principal on debt instruments are clearly and closely related to their debt hosts. The new guidance requires only an assessment of the four-step decision sequence outlined in GAAP to determine whether the economic characteristics and risks of call or put options are clearly and closely related to the economic characteristics and risks. This new guidance is effective January 1, 2017 and the Company does not expect the adoption of this new standard to have a material impact on its consolidated financial statements.

Equity method investments

In March 2016, the FASB issued new guidance that simplifies the transition to equity method accounting. The new guidance eliminates the requirement to retroactively apply the equity method of accounting when an increase in ownership interest in an investment qualifies it for equity method accounting. 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.

Employee share-based payments

In March 2016, the FASB issued new guidance that simplifies several aspects of the accounting for employee share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The new guidance also permits entities to make an accounting policy election either to continue to estimate the total number of awards for which the requisite service period will not be rendered or to account for forfeitures when they occur. This new guidance is effective January 1, 2017 and the Company does not expect the adoption of this new standard to have a material impact on its consolidated financial statements.

Measurement of credit losses on financial instruments

In June 2016, the FASB issued new guidance that significantly changes how entities measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The new guidance amends the impairment model of financial instruments basing it on expected losses rather than incurred losses. These expected credit losses will be recognized as an allowance rather than a direct write-down of the amortized cost basis. The new guidance is effective January 1, 2020 and will be applied using a modified retrospective approach. The Company is currently evaluating the impact of the adoption of this guidance and has not yet determined the effect on its consolidated financial statements.

Classification of certain cash receipts and cash payments

In August 2016, the FASB issued new guidance to clarify how entities should classify certain cash receipts and cash payments. These include debt pre-payments or extinguishment costs, contingent consideration payments made after a

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business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance and distributions received from equity method investees. The new guidance is effective January 1, 2018 and will be applied using a retrospective approach. The new guidance also specifies how the predominance principle should be applied when cash receipts and cash payments have aspects of more than one class of cash flows. The Company is currently evaluating the impact of the adoption of this guidance and has not yet determined the impact on its consolidated financial statements.

3. Segmented information

three months ended September 30	Natural Gas Pipelines				Liquids Pipelines				Energy				Corporate				Total
(unaudited - millions of Canadian $)	2016		2015		2016		2015		2016		2015		2016		2015		2016		2015
Revenues	1,884		1,305		440		507		1,308		1,132		—		—		3,632		2,944
Income from equity investments	66		41		—		—		88		53		—		—		154		94
Plant operating costs and other	(733	)	(452	)	(160	)	(133	)	(260	)	(215	)	(24	)	(23	)	(1,177	)	(823	)
Commodity purchases resold	—		—		—		—		(783	)	(624	)	—		—		(783	)	(624	)
Property taxes	(103	)	(88	)	(21	)	(22	)	(12	)	(23	)	—		—		(136	)	(133	)
Depreciation and amortization	(361	)	(284	)	(72	)	(68	)	(81	)	(79	)	(13	)	(8	)	(527	)	(439	)
Goodwill and other asset impairment charges	—		—		—		—		(1,085	)	—		—		—		(1,085	)	—
Segmented earnings/(losses)	753		522		187		284		(825	)	244		(37	)	(31	)	78		1,019
Interest expense																	(522	)	(341	)
Interest income and other																	122		16
(Loss)/Income before income taxes																	(322	)	694
Income tax recovery/(expense)																	266		(223	)
Net (loss)/income																	(56	)	471
Net income attributable to non-controlling interests																	(52	)	(46	)
Net (loss)/income attributable to controlling interests																	(108	)	425
Preferred share dividends																	(27	)	(23	)
Net (loss)/income attributable to common shares																	(135	)	402

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nine months ended September 30	Natural Gas Pipelines				Liquids Pipelines				Energy				Corporate				Total
(unaudited - millions of Canadian $)	2016		2015		2016		2015		2016		2015		2016		2015		2016		2015
Revenues	4,511		3,896		1,292		1,410		3,083		3,143		—		—		8,886		8,449
Income/(loss) from equity investments	157		134		(1	)	—		199		216		—		—		355		350
Plant operating costs and other	(1,496	)	(1,294	)	(406	)	(379	)	(618	)	(600	)	(126	)	(71	)	(2,646	)	(2,344	)
Commodity purchases resold	—		—		—		—		(1,628	)	(1,731	)	—		—		(1,628	)	(1,731	)
Property taxes	(280	)	(264	)	(67	)	(61	)	(58	)	(65	)	—		—		(405	)	(390	)
Depreciation and amortization	(936	)	(845	)	(209	)	(197	)	(251	)	(248	)	(29	)	(23	)	(1,425	)	(1,313	)
Goodwill and other asset impairment charges	—		—		—		—		(1,296	)	—		—		—		(1,296	)	—
Loss on sale of assets	(4	)	—		—		—		—		—		—		—		(4	)	—
Segmented earnings/(losses)	1,952		1,627		609		773		(569	)	715		(155	)	(94	)	1,837		3,021
Interest expense																	(1,456	)	(990	)
Interest income and other																	440		83
Income before income taxes																	821		2,114
Income tax expense																	(78	)	(680	)
Net income																	743		1,434
Net income attributable to non-controlling interests																	(184	)	(145	)
Net income attributable to controlling interests																	559		1,289
Preferred share dividends																	(77	)	(71	)
Net income attributable to common shares																	482		1,218

TOTAL ASSETS

(unaudited - millions of Canadian $)	September 30, 2016	December 31, 2015
Natural Gas Pipelines	53,247	31,039
Liquids Pipelines	16,278	16,046
Energy	13,881	15,614
Corporate	3,852	1,699
	87,258	64,398

4. Acquisition of Columbia

On July 1, 2016, TransCanada acquired 100 per cent ownership of Columbia for a purchase price of US$10.3 billion in cash, based on US$25.50 per share for all of Columbia's outstanding common shares as well as restricted and performance stock units. The acquisition was financed through proceeds of approximately $4.4 billion from the sale of subscription receipts, draws on committed bridge term loan credit facilities in the aggregate amount of US$6.9 billion and existing cash on hand. The sale of the subscription receipts was completed on April 1, 2016 through a public offering. Upon closing of the acquisition, the subscription receipts were exchanged into approximately 96.6 million common shares of TransCanada. Refer to Note 7, Long-term debt for additional information on the bridge term loan credit facilities and Note 10, Equity and share capital for additional information on the subscription receipts.

Columbia operates a portfolio of approximately 24,000 km of regulated natural gas pipelines, 300 Bcf of natural gas storage facilities and related midstream assets in various regions in the U.S. TransCanada acquired Columbia to expand the Company’s natural gas business in the U.S. market, positioning the Company for additional long-term growth opportunities.

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The Goodwill of $10.1 billion (US$7.7 billion) arising from the acquisition consists largely of the opportunities to expand the Company’s natural gas pipelines segment in the U.S. market and to gain a stronger competitive position in the North American natural gas business. The Goodwill resulting from the acquisition is not deductible for income tax purposes.

The acquisition has been accounted for as a business combination using the acquisition method where the acquired tangible and intangible assets and assumed liabilities are recorded at their estimated fair values at the date of acquisition. The purchase price equation reflects management’s estimate of the fair value of Columbia’s assets and liabilities as at July 1, 2016.

	July 1, 2016
(unaudited - millions of $)	U.S.		Canadian
Purchase Price Consideration	10,294		13,392
Fair Value Assigned to Net Assets
Current Assets	658		856
Plant, Property and Equipment	7,556		9,830
Equity Investments	441		574
Regulatory Assets	190		248
Intangibles and Other Assets	135		175
Current Liabilities	(597	)	(777	)
Regulatory Liabilities	(294	)	(383	)
Other Long-Term Liabilities	(144	)	(187	)
Deferred Income Tax Liabilities	(1,611	)	(2,095	)
Long-Term Debt	(2,981	)	(3,878	)
Non-controlling Interests	(808	)	(1,051	)
Fair Value of Net Assets Acquired	2,545		3,312
Goodwill	7,749		10,080

The fair values of current assets including cash and cash equivalents, accounts receivable, inventories and other and the fair values of current liabilities including notes payable and accrued interest approximate their carrying values due to the short-term nature of these items. Certain acquisition related working capital items resulted in an adjustment to accounts payable and other.

Columbia’s natural gas pipelines are subject to FERC regulations and, as a result, their rate bases are expected to be recovered with a reasonable rate of return over the life of the assets. These assets, as well as related regulatory assets and liabilities, have fair values equal to their carrying values. The fair value of mineral rights included in Columbia's plant, property and equipment was estimated using a discounted cash flow approach which resulted in a fair value increase of $241 million (US$185 million). The Company utilized an independent third party valuation in the assessment of fair value. The fair value of base gas included in Columbia’s plant, property and equipment was determined by using quoted market prices multiplied by the volume of gas in place which resulted in a fair value increase of $836 million (US$642 million).

The fair value of Columbia’s long-term debt was estimated using an income approach based on quoted market prices for similar debt instruments from external data service providers. This resulted in a fair value increase of $300 million (US$231 million).

The following table summarizes the fair value of Columbia's debt acquired by TransCanada.

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(unaudited - millions of $)	Maturity date	Type	Fair Value	Interest rate
COLUMBIA PIPELINE GROUP INC.
	June 2018	Senior Unsecured Notes (US$500)	US $506	2.45	%
	June 2020	Senior Unsecured Notes (US$750)	US $779	3.30	%
	June 2025	Senior Unsecured Notes (US$1,000)	US $1,092	4.50	%
	June 2045	Senior Unsecured Notes (US$500)	US $604	5.80	%
			US $2,981

The fair values of Columbia's defined pension benefit plan and OPEB plans were based on an actuarial valuation report as of the acquisition date. The fair value representing the funded status of the plans on the acquisition date resulted in an increase of $15 million (US$12 million) and $5 million (US$4 million) to Regulatory assets and Other long-term liabilities, respectively, and a decrease of $14 million (US$11 million) and $2 million (US$2 million) to Intangible and other assets and Regulatory liabilities, respectively.

Temporary differences created as a result of the fair value changes described above resulted in deferred tax assets and liabilities that were recorded at the Company's U.S. effective tax rate of 39 per cent.

The fair value of Columbia’s non-controlling interest is based on the approximately 53.8 million Columbia Pipeline Partners LP common units outstanding to the public as of June 30, 2016, and valued at the June 30, 2016 closing price of US$15.00 per common unit.

Acquisition expenses of approximately $36 million are included in Plant operating costs and other in the condensed consolidated statement of income.

Upon completing the acquisition, the Company began consolidating Columbia. Columbia’s significant accounting policies are consistent with TransCanada’s and continue to be applied. Columbia contributed $427 million (US$327 million) to revenues and $55 million (US$42 million) to net income from the acquisition date to September 30, 2016.

The following supplemental unaudited pro forma consolidated financial information of the Company for the three and nine months ended September 30, 2016 and 2015 includes the results of operations for Columbia as if the acquisition had been completed on January 1, 2015.

	three months ended September 30					nine months ended September 30
(unaudited - millions of Canadian $, except per share amounts)	2016			2015		2016		2015
Revenues	3,632			3,364		9,783		9,680
Net (Loss)/Income	(56		)	495		873		1,593
Net (Loss)/Income Attributable to Common Shares	(135		)	411		580		1,342
Net (Loss)/Income per Common Share		($0.17	)		$0.51		$0.70		$1.67

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5. Goodwill and other asset impairments

Goodwill impairment

TransCanada tests goodwill for impairment on an annual basis or more frequently if events or changes in circumstances indicate that goodwill might be impaired. As a result of information received during the process to monetize the Company’s U.S. Northeast Power business in third quarter 2016, it was determined that the fair value of Ravenswood did not exceed its carrying value, including goodwill, at September 30, 2016. The fair value of Ravenswood was determined using a combination of methods including a discounted cash flow approach and a range of expected consideration from a potential sale. The expected cash flows were discounted using a risk-adjusted discount rate to determine the fair value. Plant, property and equipment was also tested for impairment. As a result, at September 30, 2016, the Company recorded a goodwill impairment charge on the full goodwill amount of $1,085 million ($656 million after-tax) related to the Ravenswood facility within the Energy segment and also determined there was no impairment on the plant, property and equipment.

Power Purchase Arrangements

On March 7, 2016, TransCanada issued notice to the Balancing Pool of the decision to terminate its Sheerness and Sundance A PPAs. In accordance with a provision in the PPAs, a buyer is permitted to terminate the arrangement if a change in law occurs that makes the arrangement unprofitable or more unprofitable. As a result of recent changes in law surrounding the Alberta Specified Gas Emitters Regulation, the Company expects increasing costs related to carbon emissions to continue throughout the remaining terms of the PPAs resulting in increasing unprofitabilty. As such, at March 31, 2016, the Company recognized a non-cash impairment charge of $211 million ($155 million after-tax) in its Energy segment, which represents the carrying value of the PPAs.

On March 7, 2016, TransCanada also issued notice to the Balancing Pool of the decision to terminate its Sundance B PPA. The Sundance B PPA is held in the ASTC Power Partnership in which the Company holds a 50 per cent ownership interest. As a result, at March 31, 2016 the Company recognized a non-cash impairment charge of $29 million ($21 million after-tax) in its Energy segment, which represents the carrying value of the equity investment. This impairment charge is included in Income from equity investments on the condensed consolidated statement of income.

6. Income taxes

At September 30, 2016, the total unrecognized tax benefit of uncertain tax positions was approximately $20 million (December 31, 2015 - $17 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 ended September 30, 2016 is nil for interest expense and nil for penalties (September 30, 2015 - nil for interest expense and nil for penalties). At September 30, 2016, the Company had $4 million accrued for interest expense and nil accrued for penalties (December 31, 2015 - $4 million accrued for interest expense and nil for penalties).

The effective tax rates for the nine-month periods ended September 30, 2016 and 2015 were 10 per cent and 32 per cent, respectively. The lower effective tax rate in 2016 was primarily the result of lower flow-through taxes in 2016 on Canadian regulated pipelines, changes in the proportion of income earned between Canadian and foreign jurisdictions and the goodwill impairment charge.

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7. Long-term debt

LONG-TERM DEBT ISSUED

The Company issued long-term debt in the nine months ended September 30, 2016 as follows:

(unaudited - millions of Canadian $, unless noted otherwise)	Issue date	Type	Maturity date	Amount	Interest rate
TRANSCANADA PIPELINES LIMITED
	June 2016	Acquisition Bridge Facility1	June 2018	US $5,213	Floating
	June 2016	Medium Term Notes	July 2023	$300	3.690	%	2
	June 2016	Medium Term Notes	June 2046	$700	4.350			%
	January 2016	Senior Unsecured Notes	January 2019	US $400	3.125			%
	January 2016	Senior Unsecured Notes	January 2026	US $850	4.875			%
ANR PIPELINE COMPANY
	June 2016	Senior Unsecured Notes	June 2026	US $240	4.140			%
TRANSCANADA PIPELINE USA LTD.
	June 2016	Acquisition Bridge Facility1	June 2018	US $1,700	Floating
TUSCARORA GAS TRANSMISSION COMPANY
	April 2016	Term Loan	April 2019	US $9.5	Floating

¹  These facilities were put in place to finance a portion of the Columbia acquisition and bear interest at Libor plus an applicable margin. Proceeds from the U.S. Northeast Power business sales and the November 2016 common equity offering will be used to partially repay these facilities.

²  Reflects coupon rate on re-opening of existing medium term notes (MTN) issue. New MTNs were issued at a premium resulting in a re-issuance yield of 2.69 per cent.

LONG-TERM DEBT RETIRED

The Company retired long-term debt in the nine months ended September 30, 2016 as follows:

(unaudited - millions of Canadian $, unless noted otherwise)	Retirement date	Type	Amount		Interest rate
TRANSCANADA PIPELINES LIMITED
	June 2016	Senior Unsecured Notes	US $84		7.69	%
	June 2016	Senior Unsecured Notes	US $500		Floating
	January 2016	Senior Unsecured Notes	US $750		0.75	%
NOVA GAS TRANSMISSION LTD.
	February 2016	Debentures		$225	12.2	%

In the three and nine months ended September 30, 2016, TransCanada capitalized interest related to capital projects of $46 million and $133 million, respectively (2015 - $82 million and $223 million, respectively).

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8. 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	August 2016	Junior Subordinated Unsecured Notes1	August 2076	US $1,200	6.125	%	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 August 15, 2026 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 6.125 per cent per annum and will reset starting August 2026 until August 2046 to the three month LIBOR plus 4.89 per cent per annum; from August 2046 to August 2076 the interest rate will reset to the three month LIBOR plus 5.64 per cent per annum.

On August 16, 2016, TransCanada Trust (the Trust), a 100 per cent owned financing trust subsidiary of TCPL, issued US$1.2 billion of Trust Notes - Series 2016-A (Trust Notes) to third party investors with a fixed interest rate of 5.875 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 through the subscription for US$1.2 billion of junior subordinated notes of TCPL at a rate of 6.125 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 any other outstanding first preferred shares of TCPL.

9. Common units of TC PipeLines, LP subject to rescission

In connection with the late filing of an employee-related Form 8-K with the SEC, in March 2016, TC PipeLines, LP became ineligible to use the then effective shelf registration statement upon the filing of its 2015 Annual Report. As a result, it was determined that the purchasers of the 1.6 million common units that were issued from March 8, 2016 to May 19, 2016 under the TC PipeLines, LP ATM program may have a rescission right for an amount equal to the purchase price paid for the units, plus statutory interest and less any distributions paid, upon the return of such units to TC PipeLines, LP. No unitholder has claimed or attempted to exercise any rescission rights to date and these rights expire one year from the date of purchase of the unit.

At September 30, 2016, $106 million (US$82 million) was recorded as Common Units of TC PipeLines, LP Subject to Rescission on the Condensed consolidated balance sheet. The Company classified these 1.6 million common units outside Equity because the potential rescission rights of the units are not within the control of the Company.

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10. Equity and share capital

COMMON SHARES

In January 2016, the Company repurchased and cancelled 305,407 of its common shares at an average price of $44.90 for a total of $14 million (weighted average cost of $6 million). The difference of $8 million between the total price paid and the weighted average cost was recorded in Additional paid-in capital.

On April 1, 2016, the Company issued 96.6 million subscription receipts to partially fund the Columbia acquisition at a price of $45.75 each for total proceeds of approximately $4.4 billion. Holders of subscription receipts received one common share in exchange for each subscription receipt upon closing of the Columbia acquisition. On April 29, 2016, holders of record at close of business on April 15, 2016 received a cash payment per subscription receipt that was equal to dividends declared on each common share. A second dividend equivalent payment was made on July 29, 2016 to holders of record at the close of business on June 30, 2016. For the nine months ended September 30, 2016, $109 million of dividend equivalent payments was recorded as interest expense.

DIVIDEND REINVESTMENT PLAN

Under the Company's Dividend Reinvestment Plan (DRP), eligible holders of common and preferred shares of TransCanada can reinvest their dividends and make optional cash payments to obtain TransCanada common shares. Commencing with dividends declared on July 27, 2016, common shares will be issued from treasury at a discount of two per cent.

PREFERRED SHARES

OnFebruary 1, 2016, holders of 1.3 million Series 5 cumulative redeemable first preferred shares exercised their option to convert to Series 6 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 1.54 per cent which will reset every quarter going forward. The fixed dividend rate on the remaining Series 5 preferred shares was reset for five years at 2.263 per cent per annum. Such rate will reset every five years.

On April 20, 2016, the Company completed a public offering of 20 million Series 13 cumulative redeemable first preferred shares at $25 per share resulting in gross proceeds of $500 million. The Series 13 preferred shareholders will have the right to convert their Series 13 preferred shares into Series 14 cumulative redeemable first preferred shares on May 31, 2021 and on the last business day of May of every fifth year thereafter. The holders of Series 14 preferred shares will be entitled to receive quarterly floating rate cumulative dividends at an annual rate equal to the sum of the applicable 90-day Government of Canada treasury bill rate plus 4.69 per cent. The fixed dividend rate on the Series 13 preferred shares was set for five years at 5.5 per cent per annum. The dividend rate will reset every five years at a rate equal to the sum of the applicable five-year Government of Canada bond yield plus 4.69 per cent but not less than 5.5 per cent per annum.

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PREFERRED SHARE ISSUANCE AND CONVERSIONS

The following table summarizes the impact of the 2016 issuance and conversions of preferred shares discussed above:

(unaudited)	Number of shares issued and outstanding (thousands)	Current yield		Annual dividend per share1		Redemption price per share2	Redemption and conversion option date 2,3	Right to convert into3
Cumulative first preferred shares
Series 5	12,714	2.263	%		$0.56575	$25.00	January 30, 2021	Series 6
Series 6	1,286	Floating4		Floating		$25.00	January 30, 2021	Series 5
Series 13	20,000	5.5	%		$1.375	$25.00	May 31, 2021	Series 14

¹  Holders of the cumulative redeemable first preferred shares set out in this table are entitled to receive a fixed cumulative quarterly preferred dividend, as and when declared by the Board, with the exception of Series 6 preferred shares. The holders of Series 6 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 shares for the redemption price per share, plus all accrued and unpaid dividends on the applicable redemption option date and on every fifth anniversary date thereafter. In addition, Series 6 preferred shares are redeemable by TransCanada at any time other than on a designated redemption option date for $25.50 per share plus all accrued and unpaid dividends on such redemption date.

³  The holder will have the right, subject to certain conditions, to convert their first preferred shares of a specified series into first preferred shares of another specified series on the conversion option date and every fifth anniversary thereafter.

⁴  Commencing September 30, 2016 the floating quarterly dividend rate for the Series 6 preferred shares is 2.073 per cent and will reset every quarter going forward.

11. Other comprehensive income/(loss) and accumulated other comprehensive loss

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

three months ended September 30, 2016	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	55		—		55
Change in fair value of net investment hedges	(2	)	1		(1	)
Change in fair value of cash flow hedges	6		(1	)	5
Reclassification to net income of gains on cash flow hedges	1		(1	)	—
Reclassification to net income of actuarial loss and prior service costs on pension and other post-retirement benefit plans	6		(2	)	4
Other comprehensive income on equity investments	5		(1	)	4
Other comprehensive income	71		(4	)	67

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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 on cash flow hedges	80		(30	)	50
Reclassification to net income of actuarial loss 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

nine months ended September 30, 2016	Before tax		Income tax recovery/		Net of tax
(unaudited - millions of Canadian $)	amount		(expense)		amount
Foreign currency translation losses on net investment in foreign operations	(150	)	(2	)	(152	)
Change in fair value of net investment hedges	(12	)	3		(9	)
Change in fair value of cash flow hedges	33		(12	)	21
Reclassification to net income of gains on cash flow hedges	65		(25	)	40
Reclassification to net income of actuarial loss and prior service costs on pension and other post-retirement benefit plans	17		(5	)	12
Other comprehensive income on equity investments	14		(3	)	11
Other comprehensive loss	(33	)	(44	)	(77	)

nine 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	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 on cash flow hedges	136		(53	)	83
Reclassification to net income of actuarial loss 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

The changes in AOCI by component are as follows:

three months ended September 30, 2016	Currency translation		Cash flow		Pension and OPEB plan		Equity
(unaudited - millions of Canadian $)	adjustments		hedges		adjustments		investments		Total1
AOCI balance at July 1, 2016	(497	)	(38	)	(190	)	(254	)	(979	)
Other comprehensive income before reclassifications2	33		2		—		—		35
Amounts reclassified from accumulated other comprehensive loss	—		—		4		4		8
Net current period other comprehensive income	33		2		4		4		43
AOCI balance at September 30, 2016	(464	)	(36	)	(186	)	(250	)	(936	)

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 $21 million and $3 million, respectively.

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nine months ended September 30, 2016	Currency translation		Cash flow		Pension and OPEB plan		Equity
(unaudited - millions of Canadian $)	adjustments		hedges		adjustments		investments		Total1
AOCI balance at January 1, 2016	(383	)	(97	)	(198	)	(261	)	(939	)
Other comprehensive (loss)/income before reclassifications2	(81	)	21		—		—		(60	)
Amounts reclassified from accumulated other comprehensive loss	—		40		12		11		63
Net current period other comprehensive (loss)/income3	(81	)	61		12		11		3
AOCI balance at September 30, 2016	(464	)	(36	)	(186	)	(250	)	(936	)

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 losses of $80 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 $23 million ($14 million, net of tax) at September 30, 2016. 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 AOCI into the consolidated statement of income 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 $)	2016		2015		2016		2015
Cash flow hedges
Commodities	7		(76	)	(54	)	(124	)	Revenue (Energy)
Foreign exchange	(5	)	—		—		—		Interest income and other
Interest	(3	)	(4	)	(11	)	(12	)	Interest expense
	(1	)	(80	)	(65	)	(136	)	Total before tax
	1		30		25		53		Income tax expense
	—		(50	)	(40	)	(83	)	Net of tax
Pension and other post-retirement benefit plan adjustments
Amortization of actuarial loss	(6	)	(10	)	(17	)	(30	)	2
	2		3		5		6		Income tax expense
	(4	)	(7	)	(12	)	(24	)	Net of tax
Equity investments
Equity income	(5	)	(4	)	(14	)	(13	)	Income from equity investments
	1		1		3		3		Income tax expense
	(4	)	(3	)	(11	)	(10	)	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 12 for additional detail.

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12. 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 $)	2016		2015		2016		2015		2016		2015		2016		2015
Service cost	28		27		1		1		79		81		2		2
Interest cost	34		29		4		2		93		86		9		7
Expected return on plan assets	(48	)	(39	)	(5	)	(1	)	(127	)	(116	)	(6	)	(2	)
Amortization of actuarial loss	5		9		1		1		15		26		2		3
Amortization of past service cost	—		—		—		—		—		1		—		—
Amortization of regulatory asset	8		6		—		—		17		18		—		—
Amortization of transitional obligation related to regulated business	—		—		—		1		—		—		1		2
Net benefit cost recognized	27		32		1		4		77		96		8		12

13. 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 and cash flow.

COUNTERPARTY CREDIT RISK

TransCanada’s maximum counterparty credit exposure with respect to financial instruments at September 30, 2016, without taking into account security held, consisted of cash and cash equivalents, accounts receivable, available for sale assets recorded at fair value, the fair value of derivative assets, notes, loans and advances receivable. The Company regularly reviews its accounts receivable and records an allowance for doubtful accounts as necessary using the specific identification method. At September 30, 2016, 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 $191 million (US$146 million) at September 30, 2016 (December 31, 2015 - $248 million (US$179 million)). 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, 2016	December 31, 2015
Notional amount	30,200 (US 23,000)	23,100 (US 16,700)
Fair value	33,700 (US 25,700)	23,800 (US 17,200)

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Derivatives designated as a net investment hedge

	September 30, 2016			December 31, 2015
(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 2016 to 2019)2	(433	)	US 2,400	(730	)	US 3,150
U.S. dollar foreign exchange forward contracts (maturing 2016 to 2017)	(16	)	US 200	50		US 1,800
	(449	)	US 2,600	(680	)	US 4,950

¹  Fair values equal carrying values.

²  In the three and nine months endedSeptember 30, 2016, net realized gains of $1 million and $5 million, respectively, (2015 - gains of $2 million and $7 million, respectively) related to the interest component of cross-currency swap settlements are included in interest expense.

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 where carrying amounts approximate fair value, and would be classified in Level II of the fair value hierarchy: 

	September 30, 2016				December 31, 2015
(unaudited - millions of Canadian $)	Carrying amount		Fair value		Carrying amount		Fair value
Notes receivable1	158		209		214		265
Current and long-term debt2,3	(44,063	)	(46,378	)	(31,456	)	(34,309	)
Junior subordinated notes	(3,842	)	(3,708	)	(2,409	)	(2,011	)
	(47,747	)	(49,877	)	(33,651	)	(36,055	)

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$800 million (December 31, 2015 - US$850 million) that is attributed to hedged risk and recorded at fair value.

³  Consolidated net income for the three and nine months endedSeptember 30, 2016 included unrealized gains of $7 million and losses of $6 million, respectively, (2015 - losses of $9 million and $9 million, respectively) for fair value adjustments attributable to the hedged interest rate risk associated with interest rate swap fair value hedging relationships on US$800 million of long-term debt at September 30, 2016

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(December 31, 2015 - US$850 million). There were no other unrealized gains or losses from fair value adjustments to the non-derivative financial instruments.

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, 2016		December 31, 2015
(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)	—	137	—	90
Fixed income securities (maturing in 5-10 years)	11	—	—	—
Fixed income securities (maturing after 10 years)	480	—	261	—
	491	137	261	90

¹  Available for sale assets are recorded at fair value and included in other current assets and restricted investments 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, 2016		September 30, 2015
(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	3	—	1		—
nine months ended	25	1	(2	)	—
Net realized gains in the period
three months ended	—	—	—		—
nine months ended	1	—	—		—

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  Unrealized gains and losses on other restricted investments are included in OCI.

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 commodity 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.

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Balance sheet presentation of derivative instruments

The balance sheet classification of the fair value of the derivative instruments as at September 30, 2016 is as follows:

at September 30, 2016	Cash Flow Hedges		Fair Value Hedges	Net Investment Hedges		Held for Trading		Total Fair Value of Derivative Instruments1
(unaudited - millions of Canadian $)
Other current assets
Commodities2	15		—	—		298		313
Foreign exchange	—		—	5		10		15
Interest rate	—		3	—		1		4
	15		3	5		309		332
Intangible and other assets
Commodities2	5		—	—		165		170
Foreign exchange	—		—	6		—		6
Interest rate	—		4	—		1		5
	5		4	6		166		181
Total Derivative Assets	20		7	11		475		513
Accounts payable and other
Commodities2	(32	)	—	—		(336	)	(368	)
Foreign exchange	—		—	(231	)	(15	)	(246	)
Interest rate	(2	)	—	—		—		(2	)
	(34	)	—	(231	)	(351	)	(616	)
Other long-term liabilities
Commodities2	—		—	—		(198	)	(198	)
Foreign exchange	—		—	(229	)	—		(229	)
Interest rate	(1	)	—	—		—		(1	)
	(1	)	—	(229	)	(198	)	(428	)
Total Derivative Liabilities	(35	)	—	(460	)	(549	)	(1,044	)

¹  Fair value equals carrying value.

²  Includes purchases and sales of power, natural gas and liquids.

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The balance sheet classification of the fair value of the derivative instruments as at December 31, 2015 is as follows:

at December 31, 2015	Cash Flow Hedges		Fair Value Hedges		Net Investment Hedges		Held for Trading		Total Fair Value of Derivative Instruments1
(unaudited - millions of Canadian $)
Other current assets
Commodities2	46		—		—		326		372
Foreign exchange	—		—		65		2		67
Interest rate	—		1		—		2		3
	46		1		65		330		442
Intangible and other assets
Commodities2	11		—		—		126		137
Foreign exchange	—		—		29		—		29
Interest rate	—		2		—		—		2
	11		2		29		126		168
Total Derivative Assets	57		3		94		456		610
Accounts payable and other
Commodities2	(112	)	—		—		(443	)	(555	)
Foreign exchange	—		—		(313	)	(54	)	(367	)
Interest rate	(1	)	(1	)	—		(2	)	(4	)
	(113	)	(1	)	(313	)	(499	)	(926	)
Other long-term liabilities
Commodities2	(31	)	—		—		(131	)	(162	)
Foreign exchange	—		—		(461	)	—		(461	)
Interest rate	(1	)	(1	)	—		—		(2	)
	(32	)	(1	)	(461	)	(131	)	(625	)
Total Derivative Liabilities	(145	)	(2	)	(774	)	(630	)	(1,551	)

¹  Fair value equals carrying value.

²  Includes purchases and sales of power and natural gas.

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.

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Notional and Maturity Summary

The following tables present the maturity and notional principal or quantity outstanding related to the Company's derivative instruments excluding hedges of the net investment in foreign operations:

at September 30, 2016	Power	Natural Gas	Liquids	Foreign Exchange	Interest
Purchases1	87,257	187	6	—	—
Sales1	62,109	145	6	—	—
Millions of dollars	—	—	—	US 2,098	US 1,500
Maturity dates	2016-2020	2016-2020	2016	2016-2017	2016-2019

¹  Volumes for power, natural gas and liquids derivatives are in GWh, Bcf and MMBbls, respectively.

at December 31, 2015	Power	Natural Gas	Foreign Exchange	Interest
Purchases1	70,331	133	—	—
Sales1	54,382	70	—	—
Millions of dollars	—	—	US 1,476	US 1,100
Maturity dates	2016–2020	2016–2020	2016	2016–2019

¹  Volumes for power and natural gas derivatives are in GWh and Bcf, respectively.

Unrealized and Realized Gains/(Losses) of Derivative Instruments

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

	three months ended September 30				nine months ended September 30
(unaudited - millions of Canadian $)	2016		2015		2016		2015
Derivative instruments held for trading1
Amount of unrealized (losses)/gains in the period
Commodities2	(97	)	(27	)	23		(30	)
Foreign exchange	—		(26	)	47		(25	)
Amount of realized (losses)/gains in the period
Commodities	(23	)	(52	)	(165	)	(84	)
Foreign exchange	(5	)	(34	)	52		(87	)
Derivative instruments in hedging relationships
Amount of realized (losses)/gains in the period
Commodities	(15	)	(35	)	(155	)	(132	)
Foreign exchange	5		—		(101	)	—
Interest rate	1		2		4		6

¹  Realized and unrealized gains and losses on held for trading derivative instruments used to purchase and sell commodities are included net in 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, respectively.

²  Following the March 17, 2016 announcement of the Company's intention to sell the U.S. Northeast power assets, a loss of $49 million and a gain of $7 million (2015 - nil) were recorded in net income in the three months ended March 31, 2016 relating to discontinued cash flow hedges where it was probable that the anticipated underlying transaction would not occur as a result of a future sale.

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Derivatives in cash flow hedging relationships

The components of OCI (Note 11) related to derivatives in cash flow hedging relationships including the portion attributable to non-controlling interests are as follows: 

	three months ended September 30				nine months ended September 30
(unaudited - millions of Canadian $, pre-tax)	2016		2015		2016		2015
Change in fair value of derivative instruments recognized in OCI (effective portion)1
Commodities	7		(48	)	33		(77	)
Foreign exchange	(5	)	—		—		—
Interest rate	4		(1	)	—		(1	)
	6		(49	)	33		(78	)
Reclassification of (losses)/gains on derivative instruments from AOCI to net income (effective portion)1
Commodities2	(7	)	76		54		124
Foreign exchange3	5		—		—		—
Interest rate4	3		4		11		12
	1		80		65		136
Gains/(losses) on derivative instruments recognized in net income (ineffective portion)
Commodities2	14		10		(1	)	3
	14		10		(1	)	3

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

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

³  Reported within interest income and other on the condensed consolidated statement of income.

⁴  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, 2016	Gross derivative instruments presented on the balance sheet		Amounts available for offset1		Net amounts
(unaudited - millions of Canadian $)
Derivative - Asset
Commodities	483		(382	)	101
Foreign exchange	21		(21	)	—
Interest rate	9		(1	)	8
Total	513		(404	)	109
Derivative - Liability
Commodities	(566	)	382		(184	)
Foreign exchange	(475	)	21		(454	)
Interest rate	(3	)	1		(2	)
Total	(1,044	)	404		(640	)

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, 2015:

at December 31, 2015	Gross derivative instruments presented on the balance sheet		Amounts available for offset1		Net amounts
(unaudited - millions of Canadian $)
Derivative - Asset
Commodities	509		(418	)	91
Foreign exchange	96		(93	)	3
Interest rate	5		(1	)	4
Total	610		(512	)	98
Derivative - Liability
Commodities	(717	)	418		(299	)
Foreign exchange	(828	)	93		(735	)
Interest rate	(6	)	1		(5	)
Total	(1,551	)	512		(1,039	)

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

With respect to the derivative instruments presented above as at September 30, 2016, the Company provided cash collateral of $228 million (December 31, 2015 - $482 million) and letters of credit of $11 million (December 31, 2015 - $41 million) to its counterparties. The Company held nil (December 31, 2015 - nil) in cash collateral and $3 million (December 31, 2015 - $2 million) in letters of credit from counterparties on asset exposures at September 30, 2016. 

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, 2016, the aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a net liability position was $24 million (December 31, 2015 - $32 million), for which the Company had provided collateral in the normal course of business of nil (December 31, 2015 - nil). If the credit-risk-related contingent features in these agreements were triggered on September 30, 2016, the Company would have been required to provide additional collateral of $24 million (December 31, 2015 - $32 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 credit facilities 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 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 mainly includes long-dated commodity transactions in certain markets where liquidity is low and the Company uses the most observable inputs available or, if not available, long-term broker quotes to estimate the fair value for these transactions. Valuation of options is based on the Black-Scholes pricing model. 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 for 2016, are categorized as follows:

at September 30, 2016	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:
Commodities	66		394		23		483
Foreign exchange	—		21		—		21
Interest rate	—		9		—		9
Derivative instrument liabilities:
Commodities	(71	)	(484	)	(11	)	(566	)
Foreign exchange	—		(475	)	—		(475	)
Interest rate	—		(3	)	—		(3	)
	(5	)	(538	)	12		(531	)

¹  There were no transfers from Level I to Level II or from Level II to Level III for the nine months endedSeptember 30, 2016.

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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 2015, are categorized as follows:

at December 31, 2015	Quoted prices in active markets (Level I)1		Significant other observable inputs (Level II)1		Significant unobservable inputs (Level III)1
(unaudited - millions of Canadian $, pre-tax)							Total
Derivative instrument assets:
Commodities	34		462		13		509
Foreign exchange	—		96		—		96
Interest rate	—		5		—		5
Derivative instrument liabilities:
Commodities	(102	)	(611	)	(4	)	(717	)
Foreign exchange	—		(828	)	—		(828	)
Interest rate	—		(6	)	—		(6	)
	(68	)	(882	)	9		(941	)

¹  There were no transfers from Level I to Level II or from Level II to Level III for the year ended December 31, 2015.

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)	2016		2015		2016		2015
Balance at beginning of period	12		11		9		4
Total gains/(losses) included in net income	2		(2	)	13		3
Transfers out of Level III	(3	)	—		(6	)	3
Settlements	1		—		(1	)	—
Sales	—		(1	)	(2	)	(1	)
Total gains/(losses) included in OCI	—		1		(1	)	—
Balance at end of period1	12		9		12		9

¹  For the three and nine months endedSeptember 30, 2016, revenues include unrealized gains of $1 million and $3 million, respectively, attributed to derivatives in the Level III category that were still held at September 30, 2016 (2015 - losses of $2 million and gains of $6 million, respectively).

A 10 per cent increase or decrease in commodity prices, with all other variables held constant, would result in a $2 million decrease or increase in the fair value of outstanding derivative instruments included in Level III as at September 30, 2016. 

14. Other acquisitions and dispositions

Natural Gas Pipelines

Portland Natural Gas Transmission System

On January 1, 2016, TransCanada completed the sale of a 49.9 per cent interest in Portland Natural Gas Transmission System (PNGTS) to TC PipeLines, LP for an aggregate purchase price of US$223 million. Proceeds were comprised of US$188 million in cash and the assumption of US$35 million in proportional PNGTS debt.

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Iroquois Gas Transmission System LP

On March 31, 2016, TransCanada acquired a 4.87 per cent interest in Iroquois for an aggregate purchase price of US$53.8 million, increasing TransCanada’s interest in Iroquois to 49.35 per cent. On May 1, 2016, the Company acquired an additional 0.65 per cent interest for an aggregate purchase price of US$7.2 million, further increasing TransCanada’s interest in Iroquois to 50 per cent.

TC Offshore LLC

On March 31, 2016, TransCanada completed the sale of TC Offshore LLC to a third party. This resulted in an additional loss on disposal of $4 million pre-tax which is included in loss of sale of assets in the condensed consolidated statement of income.

Energy

Ironwood

On February 1, 2016, TransCanada acquired the Ironwood natural gas fired, combined cycle power plant in Lebanon, Pennsylvania, with a capacity of 778 MW, for US$653 million in cash after post-acquisition adjustments. The Ironwood power plant delivers energy into the PJM power market. The evaluation of assigned fair value of acquired assets and liabilities did not result in the recognition of goodwill. The Company began consolidating Ironwood as of the date of acquisition which has not had a material impact on the consolidated revenues and net income of the Company. In addition, the pro forma incremental impact on the Company’s consolidated revenues and net income for each of the periods presented is not material.

15. Commitments 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.

COMMITMENTS

TransCanada’s commitments at December 31, 2015 included fixed payments, net of sublease receipts for Alberta PPAs. As a result of the March 7, 2016 notice to terminate our Sheerness, Sundance A and Sundance B PPAs, our future obligations from December 31, 2015 have decreased by: 2016 - $195 million, 2017 - $200 million, 2018 - $141 million, 2019 - $138 million and 2020 - $115 million. Our commitments for 2021 and beyond increased by approximately $0.5 billion as a result of the extension of premise leases in second quarter 2016. The acquisition of Columbia on July 1, 2016 resulted in a total increase to our obligations of $349 million for transportation contracts and premise leases.

GUARANTEES

TransCanada and its joint venture partner on Bruce Power, BPC Generation Infrastructure Trust, have each severally guaranteed certain contingent financial obligations of Bruce Power related to a lease agreement and contractor and supplier services. The Company’s exposure under certain of these guarantees is unlimited.

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. Such agreements include guarantees and letters of credit which are primarily related to delivery of natural gas, construction services including purchase agreements 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.

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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, 2016			at December 31, 2015
(unaudited - millions of Canadian $)	Term	Potential exposure1		Carrying value	Potential exposure1	Carrying value
Bruce Power	ranging to 20182	88		1	88	2
Sur de Texas-Tuxpan	ranging to 2040	693	��	46	—	—
Other jointly owned entities	ranging to 2040	135		31	139	24
		916		78	227	26

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

²  Except for one guarantee with no termination date.

16. Variable interest entities

As a result of the implementation of the new FASB guidance on consolidation, a number of entities controlled by TransCanada are now considered to be variable interest entities (VIEs). A VIE is a legal entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support or is structured such that equity investors lack the ability to make significant decisions relating to the entity’s operations through voting rights or do not substantively participate in the gains and losses of the entity.

In the normal course of business, the Company consolidates VIEs in which it has a variable interest and for which it is considered to be the primary beneficiary. VIEs in which the Company has a variable interest but is not the primary beneficiary are accounted for as equity investments.

Consolidated VIEs

The Company's consolidated VIEs consist of legal entities where the Company has the power, through voting or similar rights, to direct the activities of the VIE that most significantly impact economic performance including purchasing or selling significant assets; maintenance and operations of assets; incurring additional indebtedness; or determining the strategic operating direction of the entity. In addition, the Company has the obligation to absorb losses or the right to receive benefits from the consolidated VIE that could potentially be significant to the VIE.

A significant portion of the Company’s assets are held through VIEs in which the Company holds a 100 per cent voting interest, the VIE meets the definition of a business and the VIE’s assets can be used for general corporate purposes. The assets and liabilities of the consolidated VIEs whose assets cannot be used for purposes other than the settlement of the VIE’s obligations are as follows:

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	September 30,	December 31,
(unaudited - millions of Canadian $)	2016	2015
ASSETS
Current Assets
Cash and cash equivalents	97	54
Accounts receivable	55	55
Inventories	23	25
Other	6	6
	181	140
Plant, Property and Equipment	3,624	3,704
Equity Investments	592	664
Goodwill	513	541
	4,910	5,049
LIABILITIES
Current Liabilities
Accounts payable and other	60	74
Accrued interest	22	21
Current portion of long-term debt	75	45
	157	140
Regulatory Liabilities	33	33
Other Long-Term Liabilities	5	4
Deferred Income Tax Liabilities	7	—
Long-Term Debt	2,858	2,998
	3,060	3,175

Non-Consolidated VIEs

The Company’s non-consolidated VIEs consist of legal entities where the Company does not have the power to direct the activities that most significantly impact the economic performance of these VIEs or where this power is shared with third parties. The Company contributes capital to these VIEs and receives ownership interests that provide it with residual claims on assets after liabilities are paid.

The carrying value of these VIEs and the maximum exposure to loss as a result of the Company's involvement with these VIEs are as follows:

	September 30,	December 31,
(unaudited - millions of Canadian $)	2016	2015
Balance sheet
Equity investments	5,043	5,410
Off-balance sheet
Potential exposure to guarantees	222	227
Maximum exposure to loss	5,265	5,637

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17. Subsequent events

Assets held for sale

The Company’s planned monetization of the U.S. Northeast Power business, for the purposes of permanently financing the Columbia acquisition, includes the sale of Ravenswood, Ironwood, Kibby Wind, Ocean State Power, TC Hydro and the marketing business, TransCanada Power Marketing (TCPM). On November 1, 2016, subsequent to the balance sheet date the Company entered into agreements to sell all of these assets except the marketing business, the value from which is still expected to be realized going forward.

The sale of Ravenswood, Ironwood, Kibby Wind and Ocean State Power to a third party is expected to close in the first half of 2017. As a result, effective November 1, 2016, the related assets and liabilities are classified as held for sale in the Energy segment and will be recorded at their fair values less costs to sell. This is expected to result in a loss on assets held for sale of approximately $899 million in fourth quarter 2016 or $863 million after tax which includes the reclassification of an estimated $61 million of foreign currency translation gains from AOCI to net income.

The sale of TC Hydro to another third party is also expected to close in the first half of 2017 resulting in an estimated gain of $719 million or $443 million after tax which includes the reclassification of an estimated $4 million of foreign currency translation gains from AOCI to net income. This gain will be recognized upon closing of the sale transaction. Effective November 1, 2016, the related assets and liabilities are classified as held for sale in the Energy segment.

As of November 1, 2016, TCPM does not meet the criteria to be classified as held for sale.

The following table details the assets and liabilities as at September 30, 2016 related to the U.S. Northeast Power business that are classified as held for sale effective November 1, 2016. The expected loss on assets held for sale of approximately $899 million (US$686 million) is not reflected in the table below.

(unaudited - millions of $)	U.S.	Canadian1
Assets held for sale
Accounts receivable	20	26
Inventories	57	75
Other current assets	107	140
Plant, property and equipment	2,862	3,754
Intangible and other assets	324	425
Total assets held for sale	3,370	4,420
Liabilities related to assets held for sale
Accounts payable and other	27	35
Other long-term liabilities	31	41
Total liabilities related to assets held for sale	58	76

¹  At September 30, 2016 exchange rate of $1.31

Columbia Pipeline Partners LP

On November 1, 2016, TransCanada announced that it had entered into an agreement and plan of merger through which our wholly-owned subsidiary, Columbia, has agreed to acquire, for cash, all of the outstanding publicly held common units of Columbia Pipeline Partners LP (CPPL) at a price of US$17.00 per common unit for an aggregate transaction value of approximately US$915 million. The transaction is expected to close in first quarter 2017 subject to receipt of CPPL unitholder approval and customary closing conditions. At September 30, 2016, the common units are

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recorded as non-controlling interests in these condensed consolidated financial statements. As a result, there will be no gain or loss recorded on closing this transaction.

Common equity offering

On November 1, 2016, concurrent with the release of these financial results, the Company announced it has entered into an agreement with a group of underwriters to proceed with an offering of common shares. The closing for the offering is expected to be on November 16, 2016.