TRP-03.31.2015-Fin Stmts

EX-13.2 3 trp-03312015xfinstmts.htm FIRST QUARTER FINANCIAL STATEMENTS TRP-03.31.2015-Fin Stmts

EXHIBIT 13.2

Condensed consolidated statement of income



	three months ended March 31
(unaudited - millions of Canadian $, except per share amounts)	2015		2014

Revenues
Natural Gas Pipelines	1,305		1,215
Liquids Pipelines	443		359
Energy	1,126		1,310
	2,874		2,884
Income from Equity Investments	137		135
Operating and Other Expenses
Plant operating costs and other	754		805
Commodity purchases resold	681		706
Property taxes	134		123
Depreciation and amortization	434		393
	2,003		2,027
Financial Charges
Interest expense	318		274
Interest income and other expense	14		8
	332		282
Income before Income Taxes	676		710
Income Tax Expense
Current	68		59
Deferred	139		162
	207		221
Net Income	469		489
Net income attributable to non-controlling interests	59		54
Net Income Attributable to Controlling Interests	410		435
Preferred share dividends	23		23
Net Income Attributable to Common Shares	387		412

Net Income per Common Share
Basic and diluted		$0.55		$0.58
Dividends Declared per Common Share		$0.52		$0.48
Weighted Average Number of Common Shares (millions)
Basic	709		708
Diluted	710		708

See accompanying notes to the condensed consolidated financial statements.

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FIRST QUARTER REPORT 2015

Condensed consolidated statement of comprehensive income



	three months ended March 31
(unaudited - millions of Canadian $)	2015		2014

Net Income	469		489
Other Comprehensive Income, Net of Income Taxes
Foreign currency translation gains on net investment in foreign operations	469		240
Change in fair value of net investment hedges	(266	)	(127	)
Change in fair value of cash flow hedges	15		31
Reclassification to net income of gains and losses on cash flow hedges	44		(62	)
Reclassification to net income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans	7		4
Other comprehensive income on equity investments	3		—
Other comprehensive income (Note 8)	272		86
Comprehensive Income	741		575
Comprehensive income attributable to non-controlling interests	207		98
Comprehensive Income Attributable to Controlling Interests	534		477
Preferred share dividends	23		25
Comprehensive Income Attributable to Common Shares	511		452

See accompanying notes to the condensed consolidated financial statements.

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Condensed consolidated statement of cash flows



	three months ended March 31
(unaudited - millions of Canadian $)	2015		2014

Cash Generated from Operations
Net income	469		489
Depreciation and amortization	434		393
Deferred income taxes	139		162
Income from equity investments	(137	)	(135	)
Distributed earnings received from equity investments	135		170
Employee post-retirement benefits expense, net of funding	15		10
Equity AFUDC	(33	)	(5	)
Unrealized losses on financial instruments	118		13
Other	13		5
Increase in operating working capital	(393	)	(123	)
Net cash provided by operations	760		979
Investing Activities
Capital expenditures	(806	)	(744	)
Capital projects under development	(201	)	(104	)
Equity investments	(93	)	(89	)
Deferred amounts and other	263		47
Net cash used in investing activities	(837	)	(890	)
Financing Activities
Dividends on common shares	(341	)	(325	)
Dividends on preferred shares	(22	)	(20	)
Distributions paid to non-controlling interests	(54	)	(45	)
Notes payable issued/(repaid), net	279		(747	)
Long-term debt issued, net of issue costs	2,277		1,364
Repayment of long-term debt	(1,016	)	(777	)
Common shares issued, net of issue costs	10		10
Preferred shares issued, net of issue costs	243		440
Partnership units of subsidiary issued, net of issue costs	4		—
Preferred shares of subsidiary redeemed	—		(200	)
Net cash provided by/(used in) financing activities	1,380		(300	)
Effect of Foreign Exchange Rate Changes on Cash and Cash Equivalents	29		33
Increase/(decrease) in Cash and Cash Equivalents	1,332		(178	)
Cash and Cash Equivalents
Beginning of period	489		927
Cash and Cash Equivalents
End of period	1,821		749

See accompanying notes to the condensed consolidated financial statements.

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FIRST QUARTER REPORT 2015

Condensed consolidated balance sheet



		March 31,		December 31,
(unaudited - millions of Canadian $)		2015		2014

ASSETS
Current Assets
Cash and cash equivalents		1,821		489
Accounts receivable		1,419		1,313
Inventories		280		292
Other		1,589		1,446
		5,109		3,540
Plant, Property and Equipment,	net of accumulated depreciation of $20,303 and $19,563, respectively	44,211		41,774
Equity Investments		5,735		5,598
Regulatory Assets		1,247		1,297
Goodwill		4,410		4,034
Intangible and Other Assets		3,104		2,704
		63,816		58,947
LIABILITIES
Current Liabilities
Notes payable		2,818		2,467
Accounts payable and other		2,852		2,896
Accrued interest		425		424
Current portion of long-term debt		2,112		1,797
		8,207		7,584
Regulatory Liabilities		529		263
Other Long-Term Liabilities		1,309		1,052
Deferred Income Tax Liabilities		5,561		5,275
Long-Term Debt		25,733		22,960
Junior Subordinated Notes		1,268		1,160
		42,607		38,294
EQUITY
Common shares, no par value		12,212		12,202
Issued and outstanding:	March 31, 2015 - 709 million shares
	December 31, 2014 - 709 million shares
Preferred shares		2,499		2,255
Additional paid-in capital		373		370
Retained earnings		5,497		5,478
Accumulated other comprehensive loss (Note 8)		(1,111	)	(1,235	)
Controlling Interests		19,470		19,070
Non-controlling interests		1,739		1,583
		21,209		20,653
		63,816		58,947
Contingencies and Guarantees (Note 11)
Subsequent Event (Note 12)

See accompanying notes to the condensed consolidated financial statements.

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Condensed consolidated statement of equity



	three months ended March 31
(unaudited - millions of Canadian $)	2015		2014

Common Shares
Balance at beginning of period	12,202		12,149
Shares issued on exercise of stock options	10		12
Balance at end of period	12,212		12,161
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	2		1
Dilution impact from TC PipeLines, LP units issued	1		—
Redemption of subsidiary's preferred shares	—		(6	)
Balance at end of period	373		396
Retained Earnings
Balance at beginning of period	5,478		5,096
Net income attributable to controlling interests	410		435
Common share dividends	(369	)	(339	)
Preferred share dividends	(22	)	(25	)
Balance at end of period	5,497		5,167
Accumulated Other Comprehensive Loss
Balance at beginning of period	(1,235	)	(934	)
Other comprehensive income	124		42
Balance at end of period	(1,111	)	(892	)
Equity Attributable to Controlling Interests	19,470		19,087
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	50		45
Preferred share dividends of TCPL	—		2
Portland	9		7
Other comprehensive income attributable to non-controlling interests	148		44
Issuance of TC PipeLines, LP units
Proceeds, net of issue costs	4		—
Decrease in TransCanada's ownership of TC Pipelines, LP	(1	)	—
Distributions declared to non-controlling interests	(54	)	(51	)
Redemption of subsidiary's preferred shares	—		(194	)
Foreign exchange and other	—		10
Balance at end of period	1,739		1,474
Total Equity	21,209		20,561

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. 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. This new guidance is effective from January 1, 2017 with two methods in which the amendment can be applied: (1) retrospectively to each prior reporting period presented, or (2) retrospectively with the cumulative effect recognized at the date of initial application. Early application is not permitted.

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In April 2015, the FASB proposed deferring the effective date to January 1, 2018 and proposed permitting early adoption of the standard but not before the original effective date.

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.

3. Segmented information



three months ended March 31	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		1,215		443		359		1,126		1,310		—		—		2,874		2,884
Income from equity investments	54		52		—		—		83		83		—		—		137		135
Plant operating costs and other	(395	)	(333	)	(111	)	(101	)	(208	)	(333	)	(40	)	(38	)	(754	)	(805	)
Commodity purchases resold	—		—		—		—		(681	)	(706	)	—		—		(681	)	(706	)
Property taxes	(90	)	(86	)	(23	)	(17	)	(21	)	(20	)	—		—		(134	)	(123	)
Depreciation and amortization	(279	)	(262	)	(63	)	(49	)	(85	)	(77	)	(7	)	(5	)	(434	)	(393	)
Segmented earnings	595		586		246		192		214		257		(47	)	(43	)	1,008		992
Interest expense																	(318	)	(274	)
Interest income and other expense																	(14	)	(8	)
Income before income taxes																	676		710
Income tax expense																	(207	)	(221	)
Net income																	469		489
Net income attributable to non-controlling interests																	(59	)	(54	)
Net income attributable to controlling interests																	410		435
Preferred share dividends																	(23	)	(23	)
Net income attributable to common shares																	387		412

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TOTAL ASSETS



(unaudited - millions of Canadian $)	March 31, 2015	December 31, 2014

Natural Gas Pipelines	28,499	27,103
Liquids Pipelines	17,552	16,116
Energy	14,827	14,197
Corporate	2,938	1,531
	63,816	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 March 31, 2015, regulatory liabilities included $50 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 March 31, 2015, intangible and other assets included $50 million (December 31, 2014 - nil) of restricted investments on the condensed consolidated balance sheet. Please refer to Note 10 for information on the fair values of these investments.

5. Income taxes

At March 31, 2015, the total unrecognized tax benefit of uncertain tax positions was approximately $25 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 months ended March 31, 2015 is nil of interest expense and nil for penalties (March 31, 2014 - $1 million of interest expense and nil for penalties). At March 31, 2015, the Company had $4 million accrued for interest expense and nil accrued for penalties (December 31, 2014 - $4 million accrued for interest expense and nil for penalties).

The effective tax rates for the three-month periods ended March 31, 2015 and 2014 were both 31 per cent.

6. Long-term debt

LONG-TERM DEBT ISSUED

The Company issued long-term debt for the three months ended March 31, 2015 as follows:




(unaudited - millions of Canadian $, unless noted otherwise)	Issue date	Type	Maturity date	Amount	Interest rate
TRANSCANADA PIPELINES LIMITED
	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
	March 2015	Senior Unsecured Notes	March 2025	US 350	4.375%

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LONG-TERM DEBT RETIRED

The Company retired long-term debt for the three months ended March 31, 2015 as follows:




(unaudited - millions of Canadian $, unless noted otherwise)	Retirement date	Type	Amount	Interest rate
TRANSCANADA PIPELINES LIMITED
	March 2015	Senior Unsecured Notes	US 500	0.875%
	January 2015	Senior Unsecured Notes	US 300	4.875%

In the three months ended March 31, 2015, TransCanada had capitalized interest related to capital projects of $70 million (2014 - $79 million ).

7. Equity and share capital

PREFERRED SHARE ISSUANCE

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. Investors are entitled to receive fixed cumulative dividends at an annual rate of $0.95 per share, payable quarterly. The dividend rate will reset on November 30, 2020 and every five years thereafter to a yield per annum equal to the sum of the then five-year Government of Canada bond yield plus 2.96 per cent. The preferred shares are redeemable by TransCanada on or after November 30, 2020 and on November 30 of every fifth year thereafter at a price of $25 per share plus accrued and unpaid dividends. The Series 11 preferred shareholders will have the right to convert their 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 a yield per annum equal to the sum of the then 90-day Government of Canada treasury bill rate plus 2.96 per cent.

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

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



three months ended March 31, 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	460		9		469
Change in fair value of net investment hedges	(359	)	93		(266	)
Change in fair value of cash flow hedges	21		(6	)	15
Reclassification to net income of gains and losses on cash flow hedges	73		(29	)	44
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	209		63		272



three months ended March 31, 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	191		49		240
Change in fair value of net investment hedges	(171	)	44		(127	)
Change in fair value of cash flow hedges	51		(20	)	31
Reclassification to net income of gains and losses on cash flow hedges	(103	)	41		(62	)
Reclassification to net income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans	6		(2	)	4
Other comprehensive (loss)/income	(26	)	112		86

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



three months ended March 31, 2015	Currency translation		Cash flow		Pension and OPEB plan		Equity
(unaudited - millions of Canadian $)	adjustments		hedges		adjustments		investments		Total¹

AOCI balance at January 1, 2015	(518	)	(128	)	(281	)	(308	)	(1,235	)
Other comprehensive income before reclassifications²	55		15		—		—		70
Amounts reclassified from accumulated other comprehensive loss³	—		44		7		3		54
Net current period other comprehensive income	55		59		7		3		124
AOCI balance at March 31, 2015	(463	)	(69	)	(274	)	(305	)	(1,111	)


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


2	Other comprehensive income before reclassifications on currency translation adjustments is net of non-controlling interest gains of $148 million.

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 $12 million ($5 million, net of tax) at March 31, 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.

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



	Amounts reclassified from accumulated other comprehensive loss¹				Affected line item in the condensed consolidated statement of income
(unaudited - millions of Canadian $)	three months ended March 31, 2015		three months ended March 31, 2014

Cash flow hedges
Power and Natural Gas	(69	)	108		Revenue (Energy)
Interest	(4	)	(5	)	Interest expense
	(73	)	103		Total before tax
	29		(41	)	Income tax expense
	(44	)	62		Net of tax
Pension and OPEB plan adjustments
Amortization of actuarial loss and past service cost²	(10	)	(6	)
	3		2		Income tax expense
	(7	)	(4	)	Net of tax
Equity Investments
Equity income	(4	)	—		Income from equity investments
	1		—		Income tax expense
	(3	)	—		Net of tax


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


2	These accumulated other comprehensive loss components are included in the computation of net benefit cost. Refer to Note 9 for additional detail.

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9. Employee post-retirement benefits

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



	three months ended March 31
	Pension benefit plans				Other post-retirement benefit plans
(unaudited - millions of Canadian $)	2015		2014		2015	2014

Service cost	27		22		1	1
Interest cost	28		28		2	2
Expected return on plan assets	(38	)	(35	)	—	—
Amortization of actuarial loss	9		5		1	1
Amortization of regulatory asset	6		5		—	—
Net benefit cost recognized	32		25		4	4

10. 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 March 31, 2015, without taking into account security held, consisted of accounts receivable, portfolio investments recorded at fair value, the fair value of derivative assets and notes, loans and advances receivable. At March 31, 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 $241 million (US$190 million) and $258 million (US$222 million) at March 31, 2015 and December 31, 2014, respectively. 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)	March 31, 2015	December 31, 2014

Carrying value	19,500 (US 15,400)	17,000 (US 14,700)
Fair value	22,700 (US 17,900)	19,000 (US 16,400)

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Derivatives designated as a net investment hedge



	March 31, 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	(670	)	US 2,700	(431	)	US 2,900
U.S. dollar foreign exchange forward contracts
(maturing 2015)	(91	)	US 3,500	(28	)	US 1,400
	(761	)	US 6,200	(459	)	US 4,300


1	Fair values equal carrying values.


2	Net income in the three months ended March 31, 2015 included net realized gains of $3 million (2014 - gains of $6 million) related to the interest component of cross-currency swaps which is included in interest expense.

Balance sheet presentation of net investment hedges

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



(unaudited - millions of Canadian $)	March 31, 2015		December 31, 2014

Other current assets	63		5
Intangible and other assets	2		1
Accounts payable and other	(370	)	(155	)
Other long-term liabilities	(456	)	(310	)
	(761	)	(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. The fair value of available for sale assets has been calculated using quoted market prices where available. Credit risk has been taken into consideration when calculating the fair value of non-derivative instruments.

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

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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:



	March 31, 2015				December 31, 2014
(unaudited - millions of Canadian $)	Carrying amount		Fair value		Carrying amount		Fair value

Notes receivable and other¹	191		240		213		263
Current and long-term debt^2,3	(27,845	)	(33,385	)	(24,757	)	(28,713	)
Junior subordinated notes	(1,268	)	(1,240	)	(1,160	)	(1,157	)
	(28,922	)	(34,385	)	(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$500 million (December 31, 2014 - US$400 million) that is attributed to hedged risk and recorded at fair value.

Consolidated net income for the three months ended March 31, 2015 included losses of $6 million (2014 - losses of $6 million) for fair value adjustments attributable to the hedged interest rate risk associated with interest rate swap fair value hedging relationships on US$500 million of long-term debt at March 31, 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.

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. 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 $)	March 31, 2015		December 31, 2014

Other current assets	543		409
Intangible and other assets	153		93
Accounts payable and other	(1,039	)	(749	)
Other long-term liabilities	(662	)	(411	)
	(1,005	)	(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 values^2,3
Assets		$458			$72			$3			$4
Liabilities		($527	)		($109	)		($63	)		($4	)
Notional values³
Volumes⁴
Purchases	54,058			99			—			—
Sales	42,469			54			—			—
U.S. dollars	—			—			US 1,917			US 100
Net unrealized losses in the period⁵
three months ended March 31, 2015		($26	)		$—			($29	)		$—
Net realized (losses)/gains in the period⁵
three months ended March 31, 2015		($10	)		$11			($43	)		$—
Maturity dates³	2015-2019			2015-2020			2015-2016			2015-2016
Derivative instruments in hedging relationships^6,7
Fair values^2,3
Assets		$88			$—			$—			$6
Liabilities		($169	)		$—			$—			($3	)
Notional values³
Volumes⁴
Purchases	11,648			—			—			—
Sales	3,972			—			—			—
U.S. dollars	—			—			—			US 650
Net realized gains in the period⁵
three months ended March 31, 2015		$16			$—			$—			$2
Maturity dates³	2015-2019			—			—			2015-2019

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 March 31, 2015.


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

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.

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 $6 million and a notional amount of US$500 million as at March 31, 2015. For the three months ended March 31, 2015, net realized gains on fair value hedges were $2 million and were included in interest expense. For the three months ended March 31, 2015, the Company did not record any amounts in net income related to ineffectiveness for fair value hedges.


7	For the three months ended March 31, 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 values^2,3
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 March 31, 2014		$9			($7	)		($2	)		$—
Net realized (losses)/gains in the period⁵
three months ended March 31, 2014		($28	)		$50			($17	)		$—
Maturity dates³	2015-2019			2015-2020			2015			2015-2016
Derivative instruments in hedging relationships ^6,7
Fair values^2,3
Assets		$57			$—			$—			$3
Liabilities		($163	)		$—			$—			($2	)
Notional values³
Volumes⁴
Purchases	11,120			—			—			—
Sales	3,977			—			—			—
U.S. dollars	—			—			—			US 550
Net unrealized gains in the period⁵
three months ended March 31, 2014		$192			$—			$—			$1
Maturity dates³	2015-2019			—			—			2015-2018


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.

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 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.

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 months ended March 31, 2014 were $1 million and were included in interest expense. For the three months ended March 31, 2014, the Company did not record any amounts in net income related to ineffectiveness for fair value hedges.


7	For the three months ended March 31, 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 8) related to derivatives in cash flow hedging relationships are as follows:



	three months ended March 31
(unaudited - millions of Canadian $, pre-tax)	2015		2014

Change in fair value of derivative instruments recognized in OCI (effective portion)¹
Power	21		41
Foreign exchange	—		10
	21		51
Reclassification of gains/(losses) on derivative instruments from AOCI to net income (effective portion)¹
Power²	69		(108	)
Interest³	4		5
	73		(103	)
Losses on derivative instruments recognized in net income (ineffective portion)
Power	(63	)	(13	)
	(63	)	(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 March 31, 2015	Gross derivative instruments presented on the balance sheet		Amounts available for offset¹		Net amounts
(unaudited - millions of Canadian $)	Gross derivative instruments presented on the balance sheet		Amounts available for offset¹		Net amounts

Derivative - Asset
Power	546		(389	)	157
Natural gas	72		(60	)	12
Foreign exchange	68		(61	)	7
Interest	10		(1	)	9
Total	696		(511	)	185
Derivative - Liability
Power	(696	)	389		(307	)
Natural gas	(109	)	60		(49	)
Foreign exchange	(889	)	61		(828	)
Interest	(7	)	1		(6	)
Total	(1,701	)	511		(1,190	)


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 $)	Gross derivative instruments presented on the balance sheet		Amounts available for offset¹		Net amounts

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 March 31, 2015, the Company had provided cash collateral of $494 million (December 31, 2014 - $459 million) and letters of credit of $19 million (December 31, 2014 - $26 million) to its counterparties. The Company held nil (December 31, 2014 - $1 million) in cash collateral and $6 million (December 31, 2014 - $1 million) in letters of credit from counterparties on asset exposures at March 31, 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 March 31, 2015, the aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a net liability position was $31 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 March 31, 2015, the Company would have been required to provide additional collateral of $31 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 derivatives fair value. This category includes long-dated commodity transactions in certain markets where liquidity is low and inputs may include long-term broker quotes. 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, or increases in the supply of electricity or natural gas, 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 assets and liabilities measured on a recurring basis, including both current and non-current portions, are categorized as follows:



at March 31, 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	—		542		4		546
Natural gas commodity contracts	39		24		9		72
Foreign exchange contracts	—		68		—		68
Interest rate contracts	—		10		—		10
Derivative instrument liabilities:
Power commodity contracts	—		(685	)	(11	)	(696	)
Natural gas commodity contracts	(104	)	(5	)	—		(109	)
Foreign exchange contracts	—		(889	)	—		(889	)
Interest rate contracts	—		(7	)	—		(7	)
Non-derivative financial instruments:
Available for sale assets²	—		117		—		117
	(65	)	(825	)	2		(888	)


1	There were no transfers from Level I to Level II or from Level II to Level III for the three months ended March 31, 2015.


2	Available for sale assets (including restricted investments) are included in intangible and other assets on the condensed consolidated balance sheet.

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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	)
Non-derivative financial instruments:
Available for sale assets²	—		75		—		75
	(46	)	(541	)	4		(583	)


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.


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

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 March 31
(unaudited - millions of Canadian $, pre-tax)	2015		2014

Balance at beginning of period	4		1
Total losses included in net income	(3	)	—
Total gains included in OCI	1		—
Balance at end of period	2		1


1	For the three months ended March 31, 2015, energy revenues include unrealized losses attributed to derivatives in the Level III category that were still held at March 31, 2015 of $3 million (2014 - nil).

A 10 per cent increase or decrease in commodity prices, with all other variables held constant, would result in less than a $1 million decrease or increase, respectively, in the fair value of outstanding derivative instruments included in Level III as at March 31, 2015.

11. Contingencies and guarantees

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

GUARANTEES

TransCanada and its joint venture partner on Bruce Power, BPC Generation Infrastructure Trust (BPC), have each severally guaranteed certain contingent financial obligations of Bruce B related to a lease agreement and contractor and supplier services. In addition, TransCanada and BPC have each severally guaranteed one-half of certain contingent financial obligations of Bruce A related to a sublease agreement and certain other financial obligations. The Company’s exposure under certain of these guarantees is unlimited.

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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 March 31, 2015		at December 31, 2014
(unaudited - millions of Canadian $)	Term	Potential exposure¹	Carrying value	Potential exposure¹	Carrying value

Bruce Power	ranging to 2019²	604	6	634	6
Other jointly owned entities	ranging to 2040	108	14	104	14
		712	20	738	20


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


2	Except for one guarantee with no termination date.

12. Subsequent event

Gas Transmission Northwest LLC

On April 1, 2015, TransCanada completed the sale of its remaining 30 per cent interest in Gas Transmission Northwest LLC (GTN) to TC PipeLines, LP for an aggregate purchase price of US$446 million.