View Filing Data

Equity earnings from unconsolidated affiliates (Note 4)

$ 341

^[1]

$ 343

^[1]

$ 353

^[1]

^[1]

135

^[1]

Operation and maintenance expenses

(55)

^[1]

(57)

^[1]

(61)

^[1]

Property taxes

(23)

^[1]

(25)

^[1]

(23)

^[1]

General and administrative

(9)

^[1]

(6)

^[1]

(9)

^[1]

Financial charges and other (Note 11)

(86)

^[1]

(85)

^[1]

(87)

^[1]

(44)

^[1]

(40)

^[1]

(46)

^[1]

Income taxes (Note 2(k))

(12)

^[1]

Net income attributable to non-controlling interests

191

^[1]

229

^[1]

250

^[1]

^[1]

Net income attributable to controlling interests allocation (Note 12)

155

^[1]

192

^[1]

216

^[1]

Common units

126

^[1]

134

^[1]

154

^[1]

^[1]

Net income per common unit (Note 12) - basic (in dollars per unit) | $ / shares

$ 155

^[1]

$ 192

^[1]

$ 216

^[1]

$ 2.13

^[1]

$ 2.51

^[1]

$ 3.02

^[1]

Net income per common unit (Note 12) - diluted (in dollars per unit) | $ / shares

$ 2.13

^[1]

$ 2.51

^[1]

$ 3.02

^[1]

Weighted average common units outstanding (millions) - basic (in units) | shares

58.9

53.5

51.1

Weighted average common units outstanding (millions) - diluted (in units) | shares

58.9

53.5

51.1

Common units outstanding, end of period (millions) (in units) | shares

62.3

53.5

[1]	(a) Recast as discussed in Note 2 and Note 6.

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

Reclassification to net income of gains and losses on cash flow hedges (Note 10)

^[1]

$ 191

$ 229

$ 250

Other comprehensive income

^[1]

Other comprehensive income

^[1]

Total comprehensive income

^[1]

191

229

264

Comprehensive income attributable to non-controlling interests

^[1]

Comprehensive income attributable to controlling interests

^[1]

$ 155

$ 192

$ 230

[1]	(a) Recast as discussed in Note 2 and Note 6.

CONSOLIDATED STATEMENT OF CASH FLOWS - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Cash Generated From Operations

^[1]

$ 191

$ 229

$ 250

Amortization of debt issue costs (Note 11)

^[1]

^[1]

Equity allowance for funds used during construction

^[1]

(2)

Deferred income taxes (Note 2(k))

^[1]

Change in other long-term liabilities

^[1]

(3)

Change in operating working capital (Note 14)

^[1]

(8)

Total cash generated from operations

^[1]

272

315

340

Adjustment to the 2011 Acquisition (Note 6)

^[1]

Capital expenditures

^[1]

(15)

(36)

(163)

Change in affiliate demand loan receivable

^[1]

Total investing activities

^[1]

(920)

(725)

Financing Activities

Distributions paid on common units (Note 13)

^[1]

(188)

(169)

(155)

Distributions paid to non-controlling interests

^[1]

(52)

(53)

Change in affiliate demand loan payable

^[1]

(15)

Long term debt issued (Note 7)

^[1]

381

338

^[1]

937

1,038

Long-term debt repaid (Note 7)

^[1]

(372)

(62)

(971)

Debt issue costs

^[1]

(2)

(7)

Equity contribution from Bison's former parent (Note 16)

^[1]

305

Distributions paid to former parent of GTN and Bison

^[1]

(37)

(81)

(85)

Total financing activities

^[1]

670

(357)

410

Increase/(decrease) in cash and cash equivalents

^[1]

(26)

Cash and cash equivalents, beginning of year

^[1]

Cash and cash equivalents, end of year

^[1]

Interest payments made

^[1]

Income taxes paid, net of refunds (Note 2(k))

^[1]

Supplemental information about non-cash investing and financing activities

Accrual for Carty Lateral consideration payment (Note 16)

^[1]

Calpine receivable distributed

^[1]

Interaffiliate account representing pension plan and other post-retirement benefits distributed

^[1]

GTN and Bison

Acquisition of additional interests, net of cash acquired (Note 6)

^[1]

(921)

(539)

Great Lakes

Cumulative distributions in excess of equity earnings:

^[1]

Investment (Note 4)

^[1]

(9)

Northern Border

Cumulative distributions in excess of equity earnings:

^[1]

$ 24

Investment (Note 4)

^[1]

$ (31)

$ (55)

[1]	(a) Recast as discussed in Note 2 and Note 6.

CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' EQUITY - USD ($)
$ in Millions

Total

Former parent

Transaction between entities under common control

GTN and Bison

Controlling interests

^[1]

Non-controlling interests

Accumulated Other Comprehensive Loss

^[2]

Common units

General Partner

Balance at beginning of year at Dec. 31, 2010

$ 799

^[1]

$ 342

^[1]

$ (15)

$ 1,105

$ 23

Increase (Decrease) in Partners' Equity

Net income attributed to GTN and Bison's former parent

^[1]

$ 250

212

(59)

(58)

^[1]

(1)

^[1]

331

Excess purchase price over net acquired assets (Note 6)

Distributions paid

(85)

^[1]

(53)

^[1]

(152)

(3)

(131)

(3)

Other comprehensive income

^[1]

Effect of conversion to an LLC by GTN and other (Note 2(k))

^[1]

119

Equity contribution (Note 16)

^[1]

213

Former parent carrying amount of acquired entities

^[1]

(407)

Balance at end of year at Dec. 31, 2011

2,496

^[1]

698

^[1]

$ 1,333

465

^[1]

(1)

1,307

Increase (Decrease) in Partners' Equity

Net income attributed to GTN and Bison's former parent

^[1]

229

188

(55)

(54)

^[1]

(1)

^[1]

Distributions paid

(81)

^[1]

(53)

^[1]

(166)

(3)

Effect of conversion to an LLC by GTN and other (Note 2(k))

^[1]

(1)

Balance at end of year at Dec. 31, 2012

2,422

^[1]

673

^[1]

1,301

448

^[1]

(1)

1,275

Increase (Decrease) in Partners' Equity

Net income attributed to GTN and Bison's former parent

^[1]

191

152

(26)

^[1]

373

Excess purchase price over net acquired assets (Note 6)

Distributions paid

(37)

^[1]

(52)

^[1]

(184)

(4)

(268)

(6)

Adjustment to the 2011 Acquisition (Note 6)

Other

(1)

Equity contribution (Note 16)

^[1]

Former parent carrying amount of acquired entities

^[1]

$ (672)

Balance at end of year at Dec. 31, 2013

$ 1,789

^[1]

$ 1,349

$ 440

^[1]

$ (1)

$ 1,322

$ 28

[1]	(a) Recast as discussed in Note 2 and Note 6.
[2]	(b) Losses related to cash flow hedges reported in Accumulated Other Comprehensive Loss and expected to be reclassified to net income in the next 12 months are estimated to be less than $1 million. These estimates assume constant interest rates over time; however, the amounts reclassified will vary based on actual value of interest rates at the date of settlement.

CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' EQUITY (Parenthetical) $ in Millions	12 Months Ended
	Dec. 31, 2013 USD ($)
Maximum
Losses related to cash flow hedges reported in Accumulated Other Comprehensive Loss and expected to be reclassified to net income	$ 1

ORGANIZATION

12 Months Ended

Dec. 31, 2013

ORGANIZATION

ORGANIZATION

NOTE 1 ORGANIZATION

TC PipeLines, LP and its subsidiaries are collectively referred to herein as the Partnership. The Partnership was formed by TransCanada PipeLines Limited, a wholly-owned subsidiary of TransCanada Corporation (TransCanada Corporation together with its subsidiaries collectively referred to herein as TransCanada), to acquire, own and participate in the management of energy infrastructure assets in North America.

The Partnership owns the following interests in natural gas pipeline systems:

Pipeline	Length	Description	Ownership


Gas Transmission Northwest LLC (GTN)	1,353 miles	Extends between an interconnection near Kingsgate, British Columbia, Canada at the Canadian border to a point near Malin, Oregon at the California border and delivers natural gas to the Pacific Northwest and to California. TransCanada owns the remaining 30 percent of GTN.	70 percent
Northern Border Pipeline Company (Northern Border)	1,408 miles	Extends between the Canadian border near Port of Morgan, Montana to a terminus near North Hayden, Indiana, south of Chicago. Northern Border is capable of receiving natural gas from Canada, the Williston Basin and Rocky Mountain Basin. ONEOK Partners, L.P. owns the remaining 50 percent of Northern Border.	50 percent
Bison Pipeline LLC (Bison)	303 miles	Extends from a location near Gillette, Wyoming to Northern Border's pipeline system in North Dakota. Bison was placed into service in January 2011 to transport natural gas from the Powder River Basin to Midwest markets. TransCanada owns the remaining 30 percent of Bison.	70 percent
Great Lakes Gas Transmission Limited Partnership (Great Lakes)	2,115 miles	Connects with the TransCanada Mainline at the Canadian border near Emerson, Manitoba, Canada and St. Clair, Michigan, near Detroit. Great Lakes is a bi-directional pipeline that can receive and deliver natural gas at multiple points along its system. TransCanada owns the remaining 53.55 percent of Great Lakes.	46.45 percent
North Baja Pipeline, LLC (North Baja)	86 miles	Extends between an interconnection with the El Paso Natural Gas Company pipeline near Ehrenberg, Arizona and an interconnection with a natural gas pipeline near Ogilby, California on the Mexican border. North Baja is a bi-directional pipeline.	100 percent
Tuscarora Gas Transmission Company (Tuscarora)	305 miles	Extends between the GTN pipeline near Malin, Oregon to its terminus near Reno, Nevada and delivers natural gas in northeastern California and northwestern Nevada.	100 percent

The Partnership is managed by its General Partner, TC PipeLines GP, Inc. (General Partner), an indirect wholly-owned subsidiary of TransCanada. The General Partner provides management and operating services for the Partnership and is reimbursed for its costs and expenses. In addition to its aggregate two percent general partner interest in the Partnership, the General Partner owns 5,797,106 common units, together with its general partner interest, representing an effective 11.1 percent interest in the Partnership at December 31, 2013. TransCanada also indirectly holds additional 11,287,725 common units representing a 17.8 percent limited partner interest in the Partnership for a total interest in the Partnership of 28.9 percent at December 31, 2013.

SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
SIGNIFICANT ACCOUNTING POLICIES	Dec. 31, 2013
SIGNIFICANT ACCOUNTING POLICIES
SIGNIFICANT ACCOUNTING POLICIES	NOTE 2 SIGNIFICANT ACCOUNTING POLICIES The accompanying financial statements and related notes have been prepared in accordance with United States generally accepted accounting principles (GAAP) and amounts are stated in U.S. dollars. The financial statements and notes present the financial position of the Partnership as of December 31, 2013 and 2012 and the results of its operations, cash flows and changes in partners' equity for the years ended December 31, 2013, 2012 and 2011. (a) Basis of Presentation The Partnership consolidates its investments in GTN, Bison, North Baja and Tuscarora, over which it is able to exercise control. To the extent there are interests owned by other parties, these interests are included in non-controlling interests. The Partnership uses the equity method of accounting for its investments in Northern Border and Great Lakes, over which it is able to exercise significant influence. On July 1, 2013, the Partnership acquired an additional 45 percent membership interest in each of GTN and Bison (the 2013 Acquisition) from subsidiaries of TransCanada. The 2013 Acquisition was accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the assets and liabilities of GTN and Bison were recorded at TransCanada's carrying value and the Partnership's historical financial information was recast to consolidate GTN and Bison for all periods presented. Refer to Note 6 for additional disclosure regarding the 2013 Acquisition. (b) Use of Estimates The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Although management believes these estimates are reasonable, actual results could differ from these estimates. (c) Cash and Cash Equivalents The Partnership's cash and cash equivalents consist of cash and highly liquid short-term investments with original maturities of three months or less and are recorded at cost, which approximates fair value. (d) Trade Accounts Receivable Trade accounts receivable are recorded at the invoiced amount and do not bear interest. We review our accounts receivable regularly and record allowances for doubtful accounts using the specific identification method. (e) Inventories Inventories primarily consist of materials and supplies and are carried at the lower of weighted average cost or market. (f) Plant, Property and Equipment Plant, property and equipment are stated at original cost. Costs of restoring the land above and around the pipeline are capitalized to pipeline facilities and depreciated over the remaining life of the related pipeline facilities. Pipeline facilities and compression equipment have an estimated useful life of 20 to 77 years and metering and other equipment ranges from 5 to 77 years. Depreciation is calculated on a straight-line composite basis over the assets' estimated useful lives. Repair and maintenance costs are expensed as incurred. Costs that are considered a betterment are capitalized. An allowance for funds used during construction, using the rate of return on rate base approved by the Federal Energy Regulatory Commission (FERC), is capitalized and included in the cost of plant, property and equipment. Amounts included in construction work in progress are not amortized until transferred into service. (g) Impairment of Equity Investments We review our equity method investments when a significant event or change in circumstances has occurred that may have an adverse effect on the fair value of each investment. When such events or changes occur, we compare the estimated fair value to the carrying value of the related investment. We also perform this evaluation every reporting period for each investment for which the carrying value has exceeded the fair value in the prior period. We calculate the estimated fair value of an investment in an equity method investee using an income approach and market approach. The development of fair value estimates requires significant judgment including estimates of future cash flows, which is dependent on internal forecasts, estimates of the long-term rate of growth for the investee, estimates of the useful life over which cash flows will occur, and determination of weighted average cost of capital. The estimates used to calculate the fair value of an investee can change from year to year based on operating results and market conditions. Changes in these estimates and assumptions could materially affect the determination of fair value and our assessment as to whether an investment in an equity method investee has suffered an impairment. If the estimated fair value of an investment is less than its carrying value, we are required to determine if the decline in fair value is other than temporary. This determination considers the aforementioned valuation methodologies, the length of time and the extent to which fair value has been less than carrying value, the financial condition and near-term prospects of the investee, including any specific events which may influence the operations of the investee, the intent and ability of the holder to retain its investment in the investee for a period of time sufficient to allow for any anticipated recovery in market value, and other facts and circumstances. If the fair value of an investment is less than its carrying value and the decline in value is determined to be other than temporary, we record an impairment charge. (h) Impairment of Long-lived Assets The Partnership reviews long-lived assets, such as plant, property and equipment for impairment whenever events or changes in circumstances indicate the carrying value may not be recoverable. If the total of the estimated undiscounted future cash flows is less than the carrying value of the assets, an impairment loss is recognized for the excess of the carrying value over the fair value of the assets. (i) Partners' Equity Costs incurred in connection with the issuance of units are deducted from the proceeds received. (j) Revenue Recognition Transmission revenues are recognized in the period in which the service is provided. When a rate case is pending final FERC approval, a portion of the revenue collected is subject to possible refund. As of December 31, 2013, 2012 and 2011, the Partnership has not recognized any transmission revenue that is subject to possible refund. (k) Income Taxes The Partnership is not subject to federal or state income tax. The tax effect of the Partnership's activities accrues to its partners. The Partnership's taxable income or loss, which may vary substantially from the net income or loss reported in the consolidated statement of income, is includable in the federal income tax returns of each partner. The aggregate difference in the basis of the Partnership's net assets for financial and income tax purposes cannot be readily determined because all information regarding each partner's tax attributes related to the partnership is not available. As a result of the recast of the Partnership's historical financial information (refer to Note 2 (a)), the Partnership included income taxes in its consolidated financial statements for the year ended December 31, 2011. Those income taxes relate to GTN for the periods prior to April 1, 2011. GTN is no longer subject to income taxes and settled all current and deferred income tax balances pursuant to GTN's tax-sharing agreement with TransCanada PipeLine USA Ltd. upon conversion to an LLC on April 1, 2011. GTN used the Asset and Liability method of accounting for income taxes for the periods prior to April 1, 2011. (l) Acquisitions and Goodwill The Partnership accounts for business acquisitions from third parties using the acquisition method of accounting and, accordingly, the assets and liabilities of the acquired entities are recorded at their estimated fair values at the date of acquisition. The excess of the purchase price over the fair value of net assets acquired is attributed to goodwill. Goodwill is not amortized and is tested on an annual basis for impairment or more frequently if any indicators of impairment are evident. The Partnership initially assesses qualitative factors to determine whether events or changes in circumstances indicate that the goodwill might be impaired. If the Partnership does not conclude that it is more likely than not that fair value of the reporting unit is greater than its carrying value, the first step of the two-step impairment test is performed by comparing the fair value of the reporting unit to its book value, which includes goodwill. If the fair value is less than book value, an impairment is indicated and a second step is performed to measure the amount of the impairment. In the second step, the implied fair value of goodwill is calculated by deducting the recognized amounts of all tangible and intangible net assets of the reporting unit from the fair value determined in the initial assessment. If the carrying value of goodwill exceeds the calculated implied fair value of goodwill, an impairment charge is recorded. The Partnership accounts for business acquisitions between entities under common control using a method whereby the assets and liabilities of the acquired entities are recorded at TransCanada's carrying value and the Partnership's historical financial information is recast to include the acquired entities for all periods presented. If the fair market value paid for the acquired entities is greater than the recorded net assets of the acquired entities, the excess purchase price paid is recorded as a reduction to Partners' Equity. Similarly, if the fair market value paid for the acquired entities is less than the recorded net assets of the acquired entities, the excess of assets acquired is recorded as an increase to Partners' Equity. (m) Fair Value Measurements For cash and cash equivalents, demand loan receivable or payable to affiliate, receivables, accounts payable and certain accrued expenses, the carrying amount approximates fair value due to the short maturities of these instruments. For long-term debt instruments and the interest rate swap agreements, fair value is estimated based upon market values (if applicable) or on the current interest rates available to us for debt with similar terms and remaining maturities. Considerable judgement is required in developing these estimates. (n) Derivative Financial Instruments and Hedging Activities The Partnership recognizes all derivative instruments as either assets or liabilities in the balance sheet at their respective fair values. For derivatives designated in hedging relationships, changes in the fair value are either offset through earnings against the change in fair value of the hedged item attributable to the risk being hedged or recognized in accumulated other comprehensive income, to the extent the derivative is effective at offsetting the changes in cash flows being hedged until the hedged item affects earnings. The Partnership only enters into derivative contracts that it intends to designate as a hedge of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability (cash flow hedge). For all hedging relationships, the Partnership formally documents the hedging relationship and its risk management objective and strategy for undertaking the hedge, the hedging instrument, the hedged transaction, the nature of the risk being hedged, how the hedging instrument's effectiveness in offsetting the hedged risk will be assessed prospectively and retrospectively, and a description of the method used to measure ineffectiveness. The Partnership also formally assesses, both at the inception of the hedging relationship and on an ongoing basis, whether the derivatives that are used in hedging relationships are highly effective in offsetting changes in cash flows of hedged transactions. For derivative instruments that are designated and qualify as part of a cash flow hedging relationship, the effective portion of the gain or loss on the derivative is reported as a component of other comprehensive income and reclassified into earnings in the same period or periods during which the hedged transaction affects earnings. Gains and losses on the derivative representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings. The Partnership discontinues hedge accounting prospectively when it determines that the derivative is no longer effective in offsetting cash flows attributable to the hedged risk, the derivative expires or is sold, terminated, or exercised, the cash flow hedge is de-designated because a forecasted transaction is not probable of occurring, or management determines to remove the designation of the cash flow hedge. In all situations in which hedge accounting is discontinued and the derivative remains outstanding, the Partnership continues to carry the derivative at its fair value on the balance sheet and recognizes any subsequent changes in its fair value in earnings. When it is probable that a forecasted transaction will not occur, the Partnership discontinues hedge accounting and recognizes immediately in earnings gains and losses that were accumulated in other comprehensive income related to the hedging relationship. (o) Asset Retirement Obligation The Partnership recognizes the fair value of a liability for asset retirement obligations in the period in which it is incurred, when a legal obligation exists and a reasonable estimate of fair value can be made. The fair value is added to the carrying amount of the associated asset and the liability is accreted through charges to operating expenses. The scope and timing of asset retirements related to natural gas pipelines is indeterminable. As a result, the Partnership has recorded no asset retirement obligations as of December 31, 2013 and 2012. (p) Government Regulation The Partnership's subsidiaries are subject to regulation by FERC. Under regulatory accounting principles, certain assets or liabilities that result from the regulated ratemaking process may be recorded that would not be recorded under GAAP for non-regulated entities. The timing of recognition of certain revenues and expenses in our regulated business may differ from that otherwise expected under GAAP to appropriately reflect the economic impact of the regulators' decisions regarding revenues and rates. The Partnership regularly evaluates the continued applicability of regulatory accounting, considering such factors as regulatory changes, the impact of competition, and the ability to recover regulatory assets. The Partnership had no material regulatory assets as of December 31, 2013 and 2012. Regulatory liabilities are included in other long-term liabilities (refer to Note 8). Allowance for funds used during construction is capitalized and included in plant, property and equipment. (q) Debt Issuance Costs Costs related to the issuance of debt are deferred and amortized using the effective interest rate method over the term of the related debt.

CHANGES IN ACCOUNTING POLICIES FOR 2013	12 Months Ended
CHANGES IN ACCOUNTING POLICIES FOR 2013	Dec. 31, 2013
CHANGES IN ACCOUNTING POLICIES FOR 2013
CHANGES IN ACCOUNTING POLICIES FOR 2013	NOTE 3 CHANGES IN ACCOUNTING POLICIES FOR 2013 Balance Sheet Offsetting/Netting Effective January 1, 2013, the Partnership adopted the Accounting Standards Update (ASU) on disclosures about balance sheet offsetting as issued by the Financial Accounting Standards Board (FASB) to enable readers to evaluate the effects of netting arrangements on the Partnership's financial position. Adoption of the ASU has resulted in increased qualitative and quantitative disclosures (see note 18) regarding certain derivative instruments that are either offset in accordance with current GAAP or are subject to a master netting arrangement or similar agreement. Accumulated Other Comprehensive Income Effective January 1, 2013, the Partnership adopted the ASU on reporting of amounts reclassified out of AOCI as issued by the FASB. Adoption of the ASU has resulted in providing additional qualitative and quantitative disclosures regarding significant amounts reclassified out of accumulated other comprehensive income into net income (see note 10).

The entire disclosure of changes in accounting principles, including adoption of new accounting pronouncements, that describes the new methods, amount and effects on financial statement line items.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Change in Accounting Principle
-URI http://asc.fasb.org/extlink&oid=6507316

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Direct Effects of a Change in Accounting Principle
-URI http://asc.fasb.org/extlink&oid=6510796

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 250
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=28359718&loc=d3e22583-107794

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Indirect Effects of a Change in Accounting Principle
-URI http://asc.fasb.org/extlink&oid=6515603

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 250
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=28359718&loc=d3e22580-107794

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 270
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.10-01.(b)(6))
-URI http://asc.fasb.org/extlink&oid=27015980&loc=d3e46468-122699

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Accounting Change
-URI http://asc.fasb.org/extlink&oid=6503790

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 250
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=28359718&loc=d3e22499-107794

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Retrospective Application
-URI http://asc.fasb.org/extlink&oid=6523989

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 270
-SubTopic 10
-Section 45
-Paragraph 13
-URI http://asc.fasb.org/extlink&oid=6372559&loc=d3e765-108305

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 270
-SubTopic 10
-Section 45
-Paragraph 12
-URI http://asc.fasb.org/extlink&oid=6372559&loc=d3e725-108305

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 01
-Paragraph b
-Subparagraph 6
-Article 10

INVESTMENTS IN UNCONSOLIDATED AFFILIATES

INVESTMENTS IN UNCONSOLIDATED AFFILIATES

12 Months Ended

Dec. 31, 2013

INVESTMENTS IN UNCONSOLIDATED AFFILIATES

NOTE 4 INVESTMENTS IN UNCONSOLIDATED AFFILIATES

Great Lakes and Northern Border are regulated by FERC and are operated by TransCanada. We use the equity method of accounting for our interests in our equity investees.

		Equity Earnings from Unconsolidated Affiliates			Investment in Unconsolidated Affiliates

		Year ended December 31			December 31
	Ownership Interest at December 31, 2013	Year ended December 31			December 31
(millions of dollars)	Ownership Interest at December 31, 2013	2013	2012	2011	2013	2012

Northern Border^(a)	50%	64	72	75	523	512
Great Lakes	46.45%	3	27	60	672	677

		67	99	135	1,195	1,189

(a): Equity earnings from Northern Border is net of the 12-year amortization of a $10 million transaction fee paid to the operator of Northern Border at the time of the Partnership's additional 20 percent acquisition in April 2006.

Northern Border

The Partnership owns a 50 percent general partner interest in Northern Border. The other 50 percent partnership interest in Northern Border is held by ONEOK Partners, L.P., a publicly traded limited partnership.

TC PipeLines Intermediate Limited Partnership, as one of the general partners, may be exposed to the commitments and contingencies of Northern Border. The Partnership holds a 98.9899 percent limited partnership interest in TC PipeLines Intermediate Limited Partnership.

Northern Border has a FERC-approved settlement agreement which established maximum long-term transportation rates and charges on the Northern Border system effective January 1, 2013. The Northern Border Settlement also includes a three-year moratorium on filing rate cases and requires Northern Border to file for new rates no later than January 1, 2018. Northern Border's reservations rates were reduced by approximately 11 percent.

The Partnership recorded no undistributed earnings from Northern Border for the years ended December 31, 2013, 2012 and 2011.

At December 31, 2013, the Partnership had a $118 million (2012 – $119 million) difference between the carrying value of Northern Border and the underlying equity in the net assets primarily resulting from the recognition and inclusion of goodwill in the Partnership's investment in Northern Border relating to the Partnership's April 2006 acquisition of an additional 20 percent general partnership interest in Northern Border.

The Partnership made an equity contribution to Northern Border of $31 million in the fourth quarter of 2013. This amount represents the Partnership's 50 percent share of a $62 million cash call from Northern Border to fund repayment of the Northern Border Credit Facility.

The summarized financial information for Northern Border is as follows:

December 31 (millions of dollars)		2013		2012


Assets
Cash and cash equivalents		27		28
Other current assets		34		35
Plant, property and equipment, net		1,197		1,234
Other assets		33		31

		1,291		1,328

Liabilities and Partners' Equity
Current liabilities		51		53
Deferred credits and other		19		16
Long-term debt, including current maturities		411		473
Partners' equity
	Partners' capital	812		789
	Accumulated other comprehensive loss	(2	)	(3	)

		1,291		1,328

Year ended December 31 (millions of dollars)	2013		2012		2011


Transmission revenues	286		311		310
Operating expenses	(75	)	(79	)	(73	)
Depreciation	(58	)	(63	)	(62	)
Financial charges and other	(23	)	(24	)	(22	)

Net income	130		145		153

Great Lakes

The Partnership owns a 46.45 percent general partner interest in Great Lakes. TransCanada owns the other 53.55 percent partnership interest. TC GL Intermediate Limited Partnership, as one of the general partners, may be exposed to the commitments and contingencies of Great Lakes. The Partnership holds a 98.9899 percent limited partnership interest in TC GL Intermediate Limited Partnership.

On November 14, 2013, FERC approved a settlement between Great Lakes and its customers to modify its transportation rates effective November 1, 2013. The settlement increases maximum recourse transportation rates by approximately 21 percent. The settlement includes a moratorium on filing rate cases or challenging the settlement rates until March 31, 2015 and requires that Great Lakes file to have new rates in effect no later than January 1, 2018.

The Partnership recorded no undistributed earnings from Great Lakes for the years ended December 31, 2013, 2012, and 2011.

At December 31, 2013, the Partnership had a $458 million (2012 – $458 million) difference between the carrying value of Great Lakes and the underlying equity in the net assets primarily resulting from the recognition and inclusion of goodwill in the Partnership's investment in Great Lakes relating to the Partnership's February 2007 acquisition of a 46.45 percent general partner interest in Great Lakes.

The Partnership made equity contributions to Great Lakes of $4 million and $5 million in the first and fourth quarter of 2013, respectively. These amounts represent the Partnership's 46.45 percent share of a $9 million and $10 million cash call from Great Lakes to make scheduled debt repayments.

The summarized financial information for Great Lakes is as follows:

December 31 (millions of dollars)	2013	2012


Assets
Current assets	52	56
Plant, property and equipment, net	771	799

	823	855

Liabilities and Partners' Equity
Current liabilities	28	30
Long-term debt, including current maturities	335	354
Partners' equity	460	471

	823	855

Year ended December 31 (millions of dollars)	2013		2012		2011


Transmission revenues	124		182		250
Operating expenses	(60	)	(66	)	(62	)
Depreciation	(31	)	(31	)	(32	)
Financial charges and other	(27	)	(28	)	(30	)
Michigan business tax	–		–		2

Net income	6		57		128

PLANT, PROPERTY AND EQUIPMENT

12 Months Ended

Dec. 31, 2013

PLANT, PROPERTY AND EQUIPMENT

NOTE 5 PLANT, PROPERTY AND EQUIPMENT

The following table includes plant, property and equipment from GTN, Bison, North Baja and Tuscarora.

	2013				2012^(a)

December 31 (millions of dollars)	Cost	Accumulated Depreciation		Net Book Value	Cost	Accumulated Depreciation		Net Book Value

Pipeline	2,045	(522	)	1,523	2,040	(462	)	1,578
Compression	520	(120	)	400	514	(112	)	402
Metering and other	146	(32	)	114	142	(26	)	116
Construction in progress	5	–		5	15	–		15

	2,716	(674	)	2,042	2,711	(600	)	2,111

^(a): Recast as discussed in Note 2 and Note 6.

ACQUISITIONS

12 Months Ended

Dec. 31, 2013

ACQUISITIONS

ACQUISITIONS

NOTE 6 ACQUISITIONS

2013 Acquisition

On July 1, 2013, the Partnership acquired an additional 45 percent membership interest in each of GTN and Bison from subsidiaries of TransCanada. GTN and Bison are both Delaware limited liability companies regulated by FERC, and they are operated by subsidiaries of TransCanada. The GTN pipeline system extends from an interconnection near Kingsgate, British Columbia, Canada at the Canadian border to a point near Malin, Oregon at the California border. The Bison pipeline system extends from the Powder River Basin near Gillette, Wyoming to Northern Border's pipeline system in Morton County, North Dakota.

The total purchase price of the 2013 Acquisition was $1,050 million plus purchase price adjustments. The purchase price consisted of (i) $750 million for the GTN membership interest (less $146 million, which reflected 45 percent of GTN's outstanding debt at the time of the 2013 Acquisition), (ii) $300 million for the membership interest in Bison, (iii) $17 million in working capital adjustments and (iv) Carty Lateral consideration of $25 million (see below).

The resulting $921 million (after working capital adjustments) paid by the Partnership was financed through a combination of (i) a public offering of 8,855,000 common units at $43.85 per common unit resulting in net proceeds of $373 million (refer to note 9), (ii) borrowing of $500 million in term loans (refer to note 7), (iii) a capital contribution from the General Partner of $8 million which was required to maintain the General Partner's effective two percent general partner interest in the Partnership (refer to note 9), and (iv) a draw on the Partnership's existing $500 million Senior Credit Facility and cash on hand.

Pursuant to the acquisition agreement between the Partnership and TransCanada relating to the Partnership's acquisition of an additional 45 percent membership interest in GTN, the Partnership agreed to make an additional payment of $25 million to TransCanada if Portland General Electric Company executes a firm transportation service agreement by December 31, 2014 containing agreed terms and relating to transportation on GTN's proposed Carty Lateral. On December 11, 2013, Portland General Electric Company executed this firm transportation service agreement relating to transportation on GTN's proposed Carty Lateral. As a result, the Partnership will pay an additional $25 million by April 11, 2014. This amount was included in accounts payable to affiliates as of December 31, 2013.

The 2013 Acquisition was accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the assets and liabilities of GTN and Bison were recorded at TransCanada's carrying value and the Partnership's historical financial information was recast to consolidate GTN and Bison for all periods presented.

The purchase price was recorded as follows:

(millions of dollars)


Current assets	67
Property, plant and equipment, net	1,792
Other assets	1
Current liabilities	(20	)
Other liabilities	(21	)
Long-term debt	(325	)

	1,494
Non-controlling interest	(448	)
Carrying value of pre-existing 25% interest in each of GTN and Bison	(374	)

Carrying value of acquired 45% interest in each of GTN and Bison	672
Excess purchase price over net assets acquired (includes Carty Lateral consideration)	274

Total cash consideration including $25 million Carty Lateral consideration payable	946

As the fair market value for the additional 45 percent interests in each of GTN and Bison was greater than the acquired net assets of GTN and Bison by $262 million and $12 million, respectively, the total excess purchase price of $274 million was recorded in Partners' Equity, including the Carty Lateral consideration. The retrospective consolidation of GTN and Bison increased net income attributable to common units by $26 million for the year ended December 31, 2013 and by $55 million and $59 million for the years ended December 31, 2012 and 2011, respectively. These amounts are however, excluded from equity attributable to controlling interests.

2011 Acquisition

On May 3, 2011, the Partnership acquired a 25 percent membership interest in each of GTN and Bison from subsidiaries of TransCanada (the 2011 Acquisition).

The total purchase price of the 2011 Acquisition was $605 million. The purchase price consisted of (i) $405 million for the GTN membership interest (less $81 million, which reflected 25 percent of GTN's outstanding debt at the time of the 2011 Acquisition), (ii) $200 million for the membership interest in Bison (less a $9 million future capital commitment to complete the Bison pipeline) (iii) $23 million at closing and (iv) $1 million in working capital adjustments paid in the fourth quarter of 2011. The resulting $539 million paid by the Partnership was financed through a combination of (i) an issuance of 7,245,000 common units offered to the public at $47.58 per common unit resulting in net proceeds of $331 million, (ii) a draw of $61 million on the Partnership's committed $400 million bridge loan facility, (iii) a draw of $125 million on the Partnership's then existing $250 million senior revolving credit facility, (iv) a capital contribution from the General Partner of $7 million, which was required to maintain the General Partner's effective two percent general partner interest in the Partnership, and (v) approximately $15 million of cash on hand.

The 2011 Acquisition was accounted for as a transaction between entities under common control, whereby the equity investments in both GTN and Bison were recorded at TransCanada's carrying values, and the total excess purchase price paid of $131 million was recorded as a reduction to Partners' Equity in 2011.

On July 22, 2013, a subsidiary of TransCanada paid $1 million to the Partnership in relation to the 2011 Acquisition of a 25 percent interest in Bison as a post-closing construction expenditures adjustment.

Yuma Lateral Asset Acquisition

Pursuant to an amendment to the acquisition agreement between the Partnership and TransCanada relating to the Partnership's acquisition of North Baja, the partnership agreed to make an additional payment of up to $2 million to TransCanada in the event that TransCanada secured additional contracts for transportation service before December 31, 2010. TransCanada secured an additional contract in July 2010 and, as a result, the Partnership paid $2 million to TransCanada on March 25, 2011 when the facilities associated with the contract were completed.

The entire disclosure for a business combination (or series of individually immaterial business combinations) completed during the period, including background, timing, and recognized assets and liabilities. The disclosure may include leverage buyout transactions (as applicable).

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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CREDIT FACILITIES AND LONG-TERM DEBT

CREDIT FACILITIES AND LONG-TERM DEBT

12 Months Ended

Dec. 31, 2013

CREDIT FACILITIES AND LONG-TERM DEBT

NOTE 7 CREDIT FACILITIES AND LONG-TERM DEBT

December 31 (millions of dollars)	2013	2012^(a)


Senior Credit Facility due 2017	380	312
Term Loan Facility due 2018	500	–
4.65% Unsecured Senior Notes due 2021	349	349
5.09% Unsecured Senior Notes due 2015	75	75
5.29% Unsecured Senior Notes due 2020	100	100
5.69% Unsecured Senior Notes due 2035	150	150
3.82% Series D Senior Notes due 2017	24	27

	1,578	1,013
Less: current portion of long-term debt	3	3

	1,575	1,010

^(a): Recast as discussed in Note 2 and Note 6.

The Partnership's Senior Credit Facility consists of a $500 million senior revolving credit facility with a banking syndicate, maturing November 20, 2017, under which $380 million was outstanding at December 31, 2013 (2012 – $312 million), leaving $120 million available for future borrowing.

At the Partnership's option, the interest rate on the outstanding borrowings under the Senior Credit Facility may be lenders' base rate or the London Interbank Offered Rate (LIBOR) plus, in either case, an applicable margin that is based on the Partnership's long-term unsecured credit ratings. The Senior Credit Facility permits the Partnership to specify the portion of the borrowings to be covered by specific interest rate options and, for LIBOR-based borrowings, to specify the interest rate period. The Partnership is required to pay a commitment fee based on its credit rating and on the unused principal amount of the commitments under the Senior Credit Facility. The Senior Credit Facility has a feature whereby at any time, so long as no event of default has occurred and is continuing, the Partnership may request an increase in the Senior Credit Facility of up to $250 million, but no lender has an obligation to increase their respective share of the facility.

The LIBOR-based interest rate on the Senior Credit Facility averaged 1.44 percent for the year ended December 31, 2013 (2012 – 1.61 percent; 2011 – 0.86 percent (4.07 percent after hedging)). The interest rate was 1.42 percent at December 31, 2013 (December 31, 2012 – 1.47 percent).

On July 1, 2013, the Partnership entered into a term loan agreement with a syndicate of lenders for a $500 million term loan credit facility (Term Loan Facility). On July 2, 2013, the Partnership borrowed $500 million under the Term Loan Facility, to pay a portion of the purchase price of the 2013 Acquisition, maturing on July 1, 2018. The Term Loan Facility bears interest based, at the Partnership's election, on the LIBOR or the base rate plus, in either case, an applicable margin. The base rate equals the highest of (i) SunTrust Bank's prime rate, (ii) 0.50 percent above the federal funds rate and (iii) 1.00 percent above one-month LIBOR. The applicable margin for the term loan is based on the Partnership's senior debt rating and ranges between 1.125 percent and 2.000 percent for LIBOR borrowings and 0.125 percent and 1.000 percent for base rate borrowings.

The LIBOR-based interest rate on the Term Loan Facility averaged 1.43 percent for the year ended December 31, 2013. After hedging activity, the interest rate incurred on the Term Loan Facility averaged 1.70 percent for the year ended December 31, 2013. Prior to hedging activities, the LIBOR-based interest rate was 1.42 percent at December 31, 2013.

GTN's Senior Notes provisions contain a covenant that limits total debt to no greater than 70 percent of total capitalization. Series D Senior Notes are secured by Tuscarora's transportation contracts, supporting agreements and substantially all of Tuscarora's property. The note purchase agreements contain certain provisions that include, among other items, limitations on additional indebtedness and distributions to partners.

At December 31, 2013, the Partnership was in compliance with its financial covenants, in addition to the other covenants which include restrictions on entering into mergers, consolidations and sales of assets, granting liens, material amendments to the second amended and restated agreement of limited partnership (Partnership Agreement), incurring additional debt and distributions to unitholders.

The principal repayments required by the Partnership on the long-term debt are as follows:

(millions of dollars)


2014		3
2015		79
2016		4
2017		393
2018		500
Thereafter		599

		1,578

OTHER LIABILITIES

12 Months Ended

Dec. 31, 2013

OTHER LIABILITIES

OTHER LIABILITIES

NOTE 8 OTHER LIABILITIES

December 31 (millions of dollars)	2013	2012^(a)


Regulatory liabilities	22	20
Fair value of derivative contracts (Note 18)	–	–
Other liabilities	2	1

	24	21

^(a): Recast as discussed in Note 2 and Note 6.

The Partnership collects estimated future removal costs related to its transmission and gathering facilities in its current rates and recognizes regulatory liabilities in this respect in the balance sheet. Estimated costs associated with the future removal of transmission and gathering facilities are collected through depreciation as allowed by FERC. These amounts do not represent asset retirement obligations as defined by FASB ASC 410, Accounting for Asset Retirement Obligations.

PARTNERS' EQUITY	12 Months Ended
PARTNERS' EQUITY	Dec. 31, 2013
PARTNERS' EQUITY
PARTNERS' EQUITY	NOTE 9 PARTNERS' EQUITY At December 31, 2013, Partners' equity included 62,327,766 common units (December 31, 2012 and 2011 – 53,472,766 common units), representing an aggregate 98 percent limited partner interest in the Partnership (including 5,797,106 common units held by the General Partner and 11,287,725 common units held indirectly by TransCanada) and an aggregate two percent general partner interest. In aggregate, the General Partner's interests represent an effective 11.1 percent ownership in the Partnership at December 31, 2013 (December 31, 2012 and 2011 – 12.6 percent). On May 22, 2013, the Partnership closed a public offering of 8,855,000 common units, including 1,155,000 common units purchased pursuant to the exercise of the underwriters' option to purchase additional common units, at a price to the public of $43.85 per common unit for gross proceeds of $388 million and net proceeds of $373 million after unit issuance costs. The General Partner maintained its effective two percent general partner interest in the Partnership by contributing $8 million to the Partnership in connection with the offering. See Note 6 for additional information regarding the equity issuance in connection with the 2013 Acquisition. On May 3, 2011, the Partnership completed a public offering of 7,245,000 common units at $47.58 per common unit for gross proceeds of $345 million and net proceeds of $331 million after unit issuance costs. The General Partner maintained its effective two percent general partner interest in the Partnership by contributing $7 million to the Partnership in connection with the offering. See Note 6 for additional information regarding the equity issuance in connection with the 2011 Acquisition.

ACCUMULATED OTHER COMPEREHENSIVE LOSS

12 Months Ended

Dec. 31, 2013

ACCUMULATED OTHER COMPEREHENSIVE LOSS

ACCUMULATED OTHER COMPEREHENSIVE LOSS

NOTE 10 ACCUMULATED OTHER COMPEREHENSIVE LOSS

The changes in accumulated other comprehensive loss (AOCL) by components are as follows:

Years ended December 31, 2013 and 2012 (millions of dollars)	Cash flow hedges		Total


AOCL Balance as of January 1, 2013 and 2012	(1	)	(1	)
Other comprehensive loss before reclassifications	–		–
Amounts reclassified from AOCL (affected financial charges and other)	–		–

Net other comprehensive loss	–		–

AOCL Balance as of December 31, 2013 and 2012	(1	)	(1	)

Year ended December 31, 2011 (millions of dollars)	Cash flow hedges		Total


AOCL Balance as of January 1, 2011	(15	)	(15	)
Other comprehensive loss before reclassifications	–		–
Amounts reclassified from AOCL (affected financial charges and other)	14		14

Net other comprehensive income	14		14

AOCL Balance as of December 31, 2011	(1	)	(1	)

The entire disclosure for comprehensive income, which includes, but is not limited to, 1) the amount of income tax expense or benefit allocated to each component of other comprehensive income, including reclassification adjustments, 2) the reclassification adjustments for each classification of other comprehensive income and 3) the ending accumulated balances for each component of comprehensive income.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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FINANCIAL CHARGES AND OTHER

FINANCIAL CHARGES AND OTHER

12 Months Ended

Dec. 31, 2013

FINANCIAL CHARGES AND OTHER

NOTE 11 FINANCIAL CHARGES AND OTHER

Year ended December 31 (millions of dollars)	2013^(a)	2012^(a)		2011^(a)


Interest expense	42	40		34
Amortization of debt issue costs	1	1		2
Net realized loss related to the interest rate swaps and options	1	–		14
Interest income	–	–		(2	)
Other	–	(1	)	(2	)

	44	40		46

^(a): Recast as discussed in Note 2 and Note 6.

NET INCOME PER COMMON UNIT

12 Months Ended

Dec. 31, 2013

NET INCOME PER COMMON UNIT

NET INCOME PER COMMON UNIT

NOTE 12 NET INCOME PER COMMON UNIT

Net income per common unit is computed by dividing net income attributable to controlling interests, after deduction of the General Partner's allocation and net income attributed to GTN's and Bison's former parent, by the weighted average number of common units outstanding. The General Partner's allocation is equal to an amount based upon the General Partner's effective two percent general partner interest, plus an amount equal to incentive distributions. Incentive distributions are paid to the General Partner if quarterly cash distributions on the common units exceed levels specified in the Partnership Agreement.

Net income per common unit was determined as follows:

(millions of dollars, except per common unit amounts)	2013^(a)		2012^(a)		2011^(a)


Net income	191		229		250
Net income attributed to GTN's and Bison's former parent	(26	)	(55	)	(59	)
Net income attributable to non-controlling interests	(36	)	(37	)	(34	)

Net income allocated to partners^(b)	129		137		157

Net income allocated to General Partner	3		3		3

Net income allocable to common units	126		134		154

Weighted average common units outstanding (millions) – basic and diluted	58.9		53.5		51.1
Net income per common unit – basic and diluted	$2.13		$2.51		$3.02

^(a): Recast as discussed in Note 2 and Note 6.
^(b): Net income allocated to partners excludes net income attributed to GTN's and Bison's former parent as it was allocated to TransCanada and was not allocable to either the general partner or common units.

CASH DISTRIBUTIONS	12 Months Ended
CASH DISTRIBUTIONS	Dec. 31, 2013
CASH DISTRIBUTIONS
CASH DISTRIBUTIONS	NOTE 13 CASH DISTRIBUTIONS The Partnership makes cash distributions to its partners with respect to each calendar quarter within 45 days after the end of each quarter. Distributions are based on Available Cash, as defined in the Partnership Agreement, which includes all cash and cash equivalents of the Partnership and working capital borrowings less reserves established by the General Partner. The unitholders currently receive a quarterly distribution of $0.81 per common unit if and to the extent there is sufficient Available Cash. As an incentive, the General Partner's percentage interest in quarterly distributions is increased after certain specified target levels are met. Currently, the combined general partner interest and incentive distribution interest payable to the General Partner is 15 percent to a maximum of 25 percent of all quarterly distributions of Available Cash that exceed target levels of $0.81 and $0.88, respectively, per common unit. For the year ended December 31, 2013, the Partnership distributed $3.18 per common unit (2012 – $3.10 per common unit; 2011 – $3.04 per common unit) for a total of $188 million (2012 – $169 million; 2011 – $155 million). The distributions paid for the years ended December 31, 2013, 2012 and 2011 included no incentive distributions to the General Partner. Partnership income attributable to controlling interests is allocated to the General Partner and the limited partners in accordance with their respective partnership percentages, after giving effect to any priority income allocations for incentive distributions that are allocated 100 percent to the General Partner.

CHANGE IN OPERATING WORKING CAPITAL

12 Months Ended

Dec. 31, 2013

CHANGE IN OPERATING WORKING CAPITAL

CHANGE IN OPERATING WORKING CAPITAL

NOTE 14 CHANGE IN OPERATING WORKING CAPITAL

Year Ended December 31 (millions of dollars)	2013^(a)		2012^(a)		2011^(a)


Change in accounts receivable and other	1		2		3
Change in accounts payable and accrued liabilities	(9	)	(2	)	(3	)
Change in accounts payable to affiliates	(2	)	–		–
Change in accrued interest	2		–		–

Change in operating working capital	(8	)	–		–

^(a): Recast as discussed in Note 2 and Note 6.

TRANSACTIONS WITH MAJOR CUSTOMERS

12 Months Ended

Dec. 31, 2013

TRANSACTIONS WITH MAJOR CUSTOMERS

TRANSACTIONS WITH MAJOR CUSTOMERS

NOTE 15 TRANSACTIONS WITH MAJOR CUSTOMERS

The following table shows revenues from the Partnership's major customers comprising more than 10 percent of the Partnership's total revenues for the years ended December 31, 2013, 2012 and 2011:

Year Ended December 31 (millions of dollars)	2013^(a)	2012^(a)	2011^(a)


Anadarko Energy Services Company	48	48	45
Pacific Gas and Electric Company	46	47	68

^(a): Recast as discussed in Note 2 and Note 6.

RELATED PARTY TRANSACTIONS

12 Months Ended

Dec. 31, 2013

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS

NOTE 16 RELATED PARTY TRANSACTIONS

The Partnership does not have any employees. The management and operating functions are provided by the General Partner. The General Partner does not receive a management fee in connection with its management of the Partnership. The Partnership reimburses the General Partner for all costs of services provided, including the costs of employee, officer and director compensation and benefits, and all other expenses necessary or appropriate to the conduct of the business of, and allocable to, the Partnership. Such costs include (i) overhead costs (such as office space and equipment) and (ii) out-of-pocket expenses related to the provision of such services. The Partnership Agreement provides that the General Partner will determine the costs that are allocable to the Partnership in any reasonable manner determined by the General Partner in its sole discretion. Total costs charged to the Partnership by the General Partner were $3 million for the year ended December 31, 2013 (2012 – $3 million; 2011 – $2 million).

As operator, TransCanada's subsidiaries provide capital and operating services to GTN, Northern Border, Bison, Great Lakes, North Baja and Tuscarora (together, "our pipeline systems"). TransCanada's subsidiaries incur costs on behalf of our pipeline systems, including, but not limited to, employee salary and benefit costs, and property and liability insurance costs.

Capital and operating costs charged to our pipeline systems for the years ended December 31, 2013, 2012 and 2011 by TransCanada's subsidiaries and amounts payable to TransCanada's subsidiaries at December 31, 2013 and 2012 are summarized in the following tables:

Year ended December 31 (millions of dollars)		2013	2012	2011


Capital and operating costs charged by TransCanada's subsidiaries to:
	GTN^(a)(b)	28	29	33
	Northern Border^(a)	30	31	29
	Bison^(a)(b)	5	6	11
	Great Lakes^(a)	31	33	31
	North Baja	4	4	4
	Tuscarora	4	4	5
Impact on the Partnership's net income attributable to controlling interests:
	GTN^(b)	19	19	22
	Northern Border	14	14	13
	Bison^(b)	4	4	4
	Great Lakes	14	15	14
	North Baja	4	4	4
	Tuscarora	4	4	5

December 31 (millions of dollars)		2013	2012


Amount payable to TransCanada's subsidiaries for costs charged in the year by:
	GTN^(a)	3	3
	Northern Border^(a)	3	4
	Bison^(a)	–	1
	Great Lakes^(a)	3	4
	North Baja	1	1
	Tuscarora	–	1

^(a): Represents 100 percent of the costs.
^(b): Recast as discussed in Note 2 and Note 6.

Great Lakes' earns transportation revenues from TransCanada and its affiliates under contracts, some of which are provided at discounted rates and some at maximum recourse rates. Great Lakes earned $68 million of transportation revenues under these contracts in 2013 (2012 – $77 million; 2011 – $81 million). This amount represents 55 percent of total revenues earned by Great Lakes in 2013 (2012 – 42 percent; 2011 – 32 percent). Great Lakes also earned $1 million in affiliated rental revenue in 2013 (2012 – $1 million; 2011 – $1 million).

Revenue from TransCanada and its affiliates of $32 million is included in the Partnership's equity earnings from Great Lakes in 2013 (2012 – $36 million; 2011 – $38 million). At December 31, 2013, $11 million was included in Great Lakes' receivables in regards to the transportation contracts with TransCanada and its affiliates (2012 – $10 million).

The Partnership accrued $25 million of additional consideration in accordance with the 2013 Acquisition with respect to Carty Lateral. This amount is payable to a subsidiary of TransCanada and is included in accounts payable to affiliates as of December 31, 2013 (refer to Note 6).

Bison's former parent made an equity contribution to Bison of $18 million in the second quarter of 2013. This amount represents the former parent's 75 percent share of a $24 million cash call from Bison to repay inter-affiliate debt primarily related to pipeline construction costs, including reclamation and restoration work. In 2011, Bison's former parent made an equity contribution to Bison of $305 million related to pipeline system construction costs.

Effective October 1, 2013, GTN and Bison participate in the Partnership's cash management program. Prior to this, GTN and Bison were part of TransCanada's cash management program. This program matches short-term cash surpluses and borrowing requirements of participating subsidiaries, thus minimizing total borrowing from outside sources. Funds advanced under the program are considered to be a loan, accruing interest and repayable on demand. GTN and Bison will receive interest on funds advanced to the Partnership at the rate of interest earned by the Partnership on its short-term cash investments and will pay interest on funds advanced from the Partnership based on the Partnership's short-term borrowing costs. At December 31, 2013, GTN and Bison did not have any demand loan receivable from an affiliate or a demand loan payable to an affiliate (December 31, 2012 – a demand loan receivable from an affiliate of $21 million and a demand loan payable to an affiliate of $15 million).

QUARTERLY FINANCIAL DATA (unaudited)

The entire disclosure for related party transactions. Examples of related party transactions include transactions between (a) a parent company and its subsidiary; (b) subsidiaries of a common parent; (c) and entity and its principal owners; and (d) affiliates.

+ References + Details

QUARTERLY FINANCIAL DATA (unaudited)

12 Months Ended

Dec. 31, 2013

QUARTERLY FINANCIAL DATA (unaudited)

NOTE 17 QUARTERLY FINANCIAL DATA (unaudited)

The following sets forth selected unaudited financial data for the four quarters in 2013 and 2012:

Quarter ended (millions of dollars except per common unit amounts)	Mar 31	Jun 30	Sept 30		Dec 31


2013
Transmission revenues^(a)	86	82	85		88
Equity earnings^(a)	18	15	15		19
Net income^(a)	53	42	46		50
Net income attributable to controlling interests^(a)	43	34	37		41
Net income per common unit	$0.52	$0.40	$0.58		$0.63
Cash distribution paid	43	43	52		52

2012
Transmission revenues^(a)	88	84	84		87
Equity earnings^(a)	29	24	24		22
Net income^(a)	65	54	57		53
Net income attributable to controlling interests^(a)	54	46	48		44
Net income per common unit	$0.71	$0.60	$0.64	^(b)	$0.56
Cash distributions paid	42	42	43		43

^(a): Recast as discussed in Note 2 and Note 6.
^(b): Net Income per common unit has been revised and is presented consistent with our presentation prior to the recast. This change conforms to our presentation for a previous common control transaction in 2009 to ensure consistency. As a result of this change, we decreased recast net income by the amount of net income attributed to GTN's and Bison's former parent in order to compute net income per common unit. It had no impact on these financial statements except as presented below:

Quarter ended September 30, 2012	As previously recast	Adjustment	Revised


Net income per common unit	$0.88	$(0.24)	$0.64

FAIR VALUE MEASUREMENTS

12 Months Ended

Dec. 31, 2013

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS

NOTE 18 FAIR VALUE MEASUREMENTS

(a) Fair Value Hierarchy

Under ASC 820, Fair Value Measurements and Disclosures, fair value measurements are characterized in one of three levels based upon the input used to arrive at the measurement. The three levels of the fair value hierarchy are as follows:

•: Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that we have the ability to access at the measurement date.
•: Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly.
•: Level 3 inputs are unobservable inputs for the asset or liability.

When appropriate, valuations are adjusted for various factors including credit considerations. Such adjustments are generally based on available market evidence. In the absence of such evidence, management's best estimate is used.

(b) Fair Value of Financial Instruments

The carrying value of cash and cash equivalents, accounts receivable and other, demand loan receivable from affiliate, accounts payable and accrued liabilities, accounts payable to affiliates, accrued interest, and demand loan payable to affiliates approximate their fair values because of the short maturity or duration of these instruments, or because the instruments bear a variable rate of interest or a rate that approximates current rates. The fair value of the Partnership's long-term debt is estimated by discounting the future cash flows of each instrument at estimated current borrowing rates. The fair value of interest rate derivatives is calculated using the income approach which uses period-end market rates and applies a discounted cash flow valuation model.

The estimated fair value of the Partnership's long-term debt as at December 31, 2013 and 2012 are as follows:

	2013		2012^(a)

December 31 (millions of dollars)	Carrying Value	Fair Value	Carrying Value	Fair Value

Senior Credit Facility due 2017	380	380	312	312
Term Loan Facility due 2018	500	500	–	–
4.65% Senior Notes due 2021	349	353	349	372
5.09% Unsecured Senior Notes due 2015	75	79	75	83
5.29% Unsecured Senior Notes due 2020	100	106	100	123
5.69% Unsecured Senior Notes due 2035	150	154	150	201
3.82% Series D Senior Notes due 2017	24	25	27	30

	1,578	1,597	1,013	1,121

^(a): Recast as discussed in Note 2 and Note 6.

Long-term debt is recorded at amortized cost and classified in Level II of the fair value hierarchy for fair value disclosure purposes. Interest rate derivative assets and liabilities are classified in Level II for all periods presented where the fair value is determined by using valuation techniques that refer to observable market data or estimated market prices.

Market risk is the risk that changes in market interest rates may result in fluctuations in the fair values or cash flows of financial instruments. The Partnership's floating rate debt is subject to LIBOR benchmark interest rate risk. The Partnership uses interest rate derivatives to manage its exposure to interest rate risk. We regularly assess the impact of interest rate fluctuations on future cash flows and evaluate hedging opportunities to mitigate our interest rate risk.

The interest rate swaps are structured such that the cash flows of the derivative instruments match those of the variable rate of interest on the Term Loan Facility. The Partnership hedged interest payments on $150 million of variable-rate Term Loan Facility with interest rate swaps effective September 3, 2013 and maturing July 1, 2018, at a weighted average fixed interest rate of 2.79 percent. At December 31, 2013, the fair value of the interest rate swaps accounted for as cash flow hedges was less than $1 million (both on a gross and net basis) (December 31, 2012 and 2011 – nil). In 2013, the Partnership did not record any amounts in net income related to ineffectiveness for interest rate hedges. The change in fair value of interest rate derivative instruments recognized in other comprehensive income was less than $1 million for the year ended December 31, 2013. In 2013, the net realized loss related to the interest rate swaps was $1 million and was included in financial charges and other (2012 – nil; 2011 – $14 million).

Until December 12, 2011, the Partnership used derivatives to assist in managing its exposure to interest rate risk relating to the Senior Credit Facility. The interest rate swaps and options were structured such that the cash flows matched those of the Senior Credit Facility. There were no amounts hedged at December 31, 2012 and 2011. $300 million of variable-rate debt was hedged by an interest rate swap through December 12, 2011, where the fixed interest rate paid was 4.89 percent. $75 million of variable-rate debt was hedged by an interest rate swap through February 28, 2011, where the fixed interest rate paid was 3.86 percent. In addition to these fixed rates, the Partnership paid an applicable margin in accordance with the Senior Credit Facility agreement.

The Partnership has no master netting agreements, however, contracts contain provisions with rights of offset. The Partnership has elected to present the fair value of derivative instruments with the right to offset on a gross basis in the balance sheet. Had the Partnership elected to present these instruments on a net basis, there would be no effect on the consolidated balance sheet as of December 31, 2013 and 2012.

Counterparty credit risk represents the financial loss that the Partnership would experience if a counterparty to a financial instrument failed to meet its obligations in accordance with the terms and conditions of the financial instruments with the Partnership. Our maximum counterparty credit exposure with respect to financial instruments at the balance sheet date consists primarily of the carrying amount, which approximates fair value, of non-derivative financial assets, such as accounts receivable, as well as the fair value of derivative financial assets. We review our accounts receivable regularly and record allowances for doubtful accounts using the specific identification method. At December 31, 2013, we had not incurred any significant credit losses and had no significant amounts past due or impaired. At December 31, 2013, the Partnership's maximum counterparty credit exposure consisted of accounts receivable of $37 million (2012 – $59 million).

ACCOUNTS RECEIVABLE AND OTHER

12 Months Ended

Dec. 31, 2013

ACCOUNTS RECEIVABLE AND OTHER

ACCOUNTS RECEIVABLE AND OTHER

NOTE 19 ACCOUNTS RECEIVABLE AND OTHER

December 31 (millions of dollars)	2013	2012^(a)


Trade accounts receivable, net of allowance of nil	33	31
Accounts receivable from affiliates	–	1
Other	4	6

	37	38

^(a): Recast as discussed in Note 2 and Note 6.

REGULATORY MATTERS	12 Months Ended
REGULATORY MATTERS	Dec. 31, 2013
REGULATORY MATTERS
REGULATORY MATTERS	NOTE 20 REGULATORY MATTERS North Baja – On January 6, 2014, FERC approved North Baja's application to temporarily abandon compression associated with the original design of its pipeline system. This temporary abandonment will preserve replacement options while reducing maintenance requirements and related expenses without any reduction in capacity or impact to existing firm transportation service.

CONTINGENCIES	12 Months Ended
CONTINGENCIES	Dec. 31, 2013
CONTINGENCIES
CONTINGENCIES	NOTE 21 CONTINGENCIES In December 2009, PacifiCorp filed suit against GTN and Northwest Pipeline in Oregon State Court for approximately $7 million for alleged damage to equipment at its natural gas generating facility in Hermiston, Oregon. Upon GTN motion, the case was removed to the U.S. District Court for the District of Oregon and was scheduled for trial in March 2014. However, in February 2014, the parties settled all claims in the case. The impact on the Partnership's consolidated results was not material.

The entire disclosure for loss and gain contingencies. Describes any existing condition, situation, or set of circumstances involving uncertainty as of the balance sheet date (or prior to issuance of the financial statements) as to a probable or reasonably possible loss incurred by an entity that will ultimately be resolved when one or more future events occur or fail to occur, and typically discloses the amount of loss recorded or a range of possible loss, or an assertion that no reasonable estimate can be made.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 460
-SubTopic 10
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-Paragraph 2
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
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Reference 5: http://www.xbrl.org/2003/role/presentationRef
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Reference 6: http://www.xbrl.org/2003/role/presentationRef
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Reference 7: http://www.xbrl.org/2003/role/presentationRef
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Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 450
-SubTopic 20
-Section 50
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-URI http://asc.fasb.org/extlink&oid=25496072&loc=d3e14615-108349

Schedule of ownership interests in natural gas pipeline systems

SUBSEQUENT EVENTS	12 Months Ended
SUBSEQUENT EVENTS	Dec. 31, 2013
SUBSEQUENT EVENTS
SUBSEQUENT EVENTS	NOTE 22 SUBSEQUENT EVENTS On January 16, 2014, the board of directors of our General Partner declared the Partnership's fourth quarter 2013 cash distribution in the amount of $0.81 per common unit. The fourth quarter cash distribution, which was paid on February 14, 2014 to unitholders of record as of January 28, 2014, totaled $52 million and was paid in the following manner: $51 million to common unitholders (including $5 million to the General Partner as holder of 5,797,106 common units and $9 million to TransCanada as holder of 11,287,725 common units) and $1 million to the General Partner in respect of its two percent general partner interest. GTN declared its fourth quarter 2013 distribution of $28 million on January 9, 2014, of which the Partnership received its 70 percent share or $20 million. The distribution was paid on February 3, 2014. Northern Border declared its fourth quarter 2013 distribution of $43 million on February 3, 2014, of which the Partnership received its 50 percent share or $21 million. The distribution was paid on February 3, 2014. Bison declared its fourth quarter 2013 distribution of $17 million on January 9, 2014, of which the Partnership received its 70 percent share or $12 million. The distribution was paid on February 3, 2014. Great Lakes declared its fourth quarter 2013 distribution of $12 million on January 9, 2014, of which the Partnership received its 46.45 percent share or $5 million. The distribution was paid on February 3, 2014.

SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
SIGNIFICANT ACCOUNTING POLICIES (Policies)	Dec. 31, 2013
SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation	(a) Basis of Presentation The Partnership consolidates its investments in GTN, Bison, North Baja and Tuscarora, over which it is able to exercise control. To the extent there are interests owned by other parties, these interests are included in non-controlling interests. The Partnership uses the equity method of accounting for its investments in Northern Border and Great Lakes, over which it is able to exercise significant influence. On July 1, 2013, the Partnership acquired an additional 45 percent membership interest in each of GTN and Bison (the 2013 Acquisition) from subsidiaries of TransCanada. The 2013 Acquisition was accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the assets and liabilities of GTN and Bison were recorded at TransCanada's carrying value and the Partnership's historical financial information was recast to consolidate GTN and Bison for all periods presented. Refer to Note 6 for additional disclosure regarding the 2013 Acquisition.
Use of Estimates	(b) Use of Estimates The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Although management believes these estimates are reasonable, actual results could differ from these estimates.
Cash and Cash Equivalents	(c) Cash and Cash Equivalents The Partnership's cash and cash equivalents consist of cash and highly liquid short-term investments with original maturities of three months or less and are recorded at cost, which approximates fair value.
Trade Accounts Receivable	(d) Trade Accounts Receivable Trade accounts receivable are recorded at the invoiced amount and do not bear interest. We review our accounts receivable regularly and record allowances for doubtful accounts using the specific identification method.
Inventories	(e) Inventories Inventories primarily consist of materials and supplies and are carried at the lower of weighted average cost or market.
Plant, Property and Equipment	(f) Plant, Property and Equipment Plant, property and equipment are stated at original cost. Costs of restoring the land above and around the pipeline are capitalized to pipeline facilities and depreciated over the remaining life of the related pipeline facilities. Pipeline facilities and compression equipment have an estimated useful life of 20 to 77 years and metering and other equipment ranges from 5 to 77 years. Depreciation is calculated on a straight-line composite basis over the assets' estimated useful lives. Repair and maintenance costs are expensed as incurred. Costs that are considered a betterment are capitalized. An allowance for funds used during construction, using the rate of return on rate base approved by the Federal Energy Regulatory Commission (FERC), is capitalized and included in the cost of plant, property and equipment. Amounts included in construction work in progress are not amortized until transferred into service.
Impairment of Equity Investments	(g) Impairment of Equity Investments We review our equity method investments when a significant event or change in circumstances has occurred that may have an adverse effect on the fair value of each investment. When such events or changes occur, we compare the estimated fair value to the carrying value of the related investment. We also perform this evaluation every reporting period for each investment for which the carrying value has exceeded the fair value in the prior period. We calculate the estimated fair value of an investment in an equity method investee using an income approach and market approach. The development of fair value estimates requires significant judgment including estimates of future cash flows, which is dependent on internal forecasts, estimates of the long-term rate of growth for the investee, estimates of the useful life over which cash flows will occur, and determination of weighted average cost of capital. The estimates used to calculate the fair value of an investee can change from year to year based on operating results and market conditions. Changes in these estimates and assumptions could materially affect the determination of fair value and our assessment as to whether an investment in an equity method investee has suffered an impairment. If the estimated fair value of an investment is less than its carrying value, we are required to determine if the decline in fair value is other than temporary. This determination considers the aforementioned valuation methodologies, the length of time and the extent to which fair value has been less than carrying value, the financial condition and near-term prospects of the investee, including any specific events which may influence the operations of the investee, the intent and ability of the holder to retain its investment in the investee for a period of time sufficient to allow for any anticipated recovery in market value, and other facts and circumstances. If the fair value of an investment is less than its carrying value and the decline in value is determined to be other than temporary, we record an impairment charge.
Impairment of Long-lived Assets	(h) Impairment of Long-lived Assets The Partnership reviews long-lived assets, such as plant, property and equipment for impairment whenever events or changes in circumstances indicate the carrying value may not be recoverable. If the total of the estimated undiscounted future cash flows is less than the carrying value of the assets, an impairment loss is recognized for the excess of the carrying value over the fair value of the assets.
Partners' Equity	(i) Partners' Equity Costs incurred in connection with the issuance of units are deducted from the proceeds received.
Revenue Recognition	(j) Revenue Recognition Transmission revenues are recognized in the period in which the service is provided. When a rate case is pending final FERC approval, a portion of the revenue collected is subject to possible refund. As of December 31, 2013, 2012 and 2011, the Partnership has not recognized any transmission revenue that is subject to possible refund.
Income Taxes	(k) Income Taxes The Partnership is not subject to federal or state income tax. The tax effect of the Partnership's activities accrues to its partners. The Partnership's taxable income or loss, which may vary substantially from the net income or loss reported in the consolidated statement of income, is includable in the federal income tax returns of each partner. The aggregate difference in the basis of the Partnership's net assets for financial and income tax purposes cannot be readily determined because all information regarding each partner's tax attributes related to the partnership is not available. As a result of the recast of the Partnership's historical financial information (refer to Note 2 (a)), the Partnership included income taxes in its consolidated financial statements for the year ended December 31, 2011. Those income taxes relate to GTN for the periods prior to April 1, 2011. GTN is no longer subject to income taxes and settled all current and deferred income tax balances pursuant to GTN's tax-sharing agreement with TransCanada PipeLine USA Ltd. upon conversion to an LLC on April 1, 2011. GTN used the Asset and Liability method of accounting for income taxes for the periods prior to April 1, 2011.
Acquisitions and Goodwill	(l) Acquisitions and Goodwill The Partnership accounts for business acquisitions from third parties using the acquisition method of accounting and, accordingly, the assets and liabilities of the acquired entities are recorded at their estimated fair values at the date of acquisition. The excess of the purchase price over the fair value of net assets acquired is attributed to goodwill. Goodwill is not amortized and is tested on an annual basis for impairment or more frequently if any indicators of impairment are evident. The Partnership initially assesses qualitative factors to determine whether events or changes in circumstances indicate that the goodwill might be impaired. If the Partnership does not conclude that it is more likely than not that fair value of the reporting unit is greater than its carrying value, the first step of the two-step impairment test is performed by comparing the fair value of the reporting unit to its book value, which includes goodwill. If the fair value is less than book value, an impairment is indicated and a second step is performed to measure the amount of the impairment. In the second step, the implied fair value of goodwill is calculated by deducting the recognized amounts of all tangible and intangible net assets of the reporting unit from the fair value determined in the initial assessment. If the carrying value of goodwill exceeds the calculated implied fair value of goodwill, an impairment charge is recorded. The Partnership accounts for business acquisitions between entities under common control using a method whereby the assets and liabilities of the acquired entities are recorded at TransCanada's carrying value and the Partnership's historical financial information is recast to include the acquired entities for all periods presented. If the fair market value paid for the acquired entities is greater than the recorded net assets of the acquired entities, the excess purchase price paid is recorded as a reduction to Partners' Equity. Similarly, if the fair market value paid for the acquired entities is less than the recorded net assets of the acquired entities, the excess of assets acquired is recorded as an increase to Partners' Equity.
Fair Value Measurements	(m) Fair Value Measurements For cash and cash equivalents, demand loan receivable or payable to affiliate, receivables, accounts payable and certain accrued expenses, the carrying amount approximates fair value due to the short maturities of these instruments. For long-term debt instruments and the interest rate swap agreements, fair value is estimated based upon market values (if applicable) or on the current interest rates available to us for debt with similar terms and remaining maturities. Considerable judgement is required in developing these estimates.
Derivative Financial Instruments and Hedging Activities	(n) Derivative Financial Instruments and Hedging Activities The Partnership recognizes all derivative instruments as either assets or liabilities in the balance sheet at their respective fair values. For derivatives designated in hedging relationships, changes in the fair value are either offset through earnings against the change in fair value of the hedged item attributable to the risk being hedged or recognized in accumulated other comprehensive income, to the extent the derivative is effective at offsetting the changes in cash flows being hedged until the hedged item affects earnings. The Partnership only enters into derivative contracts that it intends to designate as a hedge of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability (cash flow hedge). For all hedging relationships, the Partnership formally documents the hedging relationship and its risk management objective and strategy for undertaking the hedge, the hedging instrument, the hedged transaction, the nature of the risk being hedged, how the hedging instrument's effectiveness in offsetting the hedged risk will be assessed prospectively and retrospectively, and a description of the method used to measure ineffectiveness. The Partnership also formally assesses, both at the inception of the hedging relationship and on an ongoing basis, whether the derivatives that are used in hedging relationships are highly effective in offsetting changes in cash flows of hedged transactions. For derivative instruments that are designated and qualify as part of a cash flow hedging relationship, the effective portion of the gain or loss on the derivative is reported as a component of other comprehensive income and reclassified into earnings in the same period or periods during which the hedged transaction affects earnings. Gains and losses on the derivative representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings. The Partnership discontinues hedge accounting prospectively when it determines that the derivative is no longer effective in offsetting cash flows attributable to the hedged risk, the derivative expires or is sold, terminated, or exercised, the cash flow hedge is de-designated because a forecasted transaction is not probable of occurring, or management determines to remove the designation of the cash flow hedge. In all situations in which hedge accounting is discontinued and the derivative remains outstanding, the Partnership continues to carry the derivative at its fair value on the balance sheet and recognizes any subsequent changes in its fair value in earnings. When it is probable that a forecasted transaction will not occur, the Partnership discontinues hedge accounting and recognizes immediately in earnings gains and losses that were accumulated in other comprehensive income related to the hedging relationship.
Asset Retirement Obligation	(o) Asset Retirement Obligation The Partnership recognizes the fair value of a liability for asset retirement obligations in the period in which it is incurred, when a legal obligation exists and a reasonable estimate of fair value can be made. The fair value is added to the carrying amount of the associated asset and the liability is accreted through charges to operating expenses. The scope and timing of asset retirements related to natural gas pipelines is indeterminable. As a result, the Partnership has recorded no asset retirement obligations as of December 31, 2013 and 2012.
Government Regulation	(p) Government Regulation The Partnership's subsidiaries are subject to regulation by FERC. Under regulatory accounting principles, certain assets or liabilities that result from the regulated ratemaking process may be recorded that would not be recorded under GAAP for non-regulated entities. The timing of recognition of certain revenues and expenses in our regulated business may differ from that otherwise expected under GAAP to appropriately reflect the economic impact of the regulators' decisions regarding revenues and rates. The Partnership regularly evaluates the continued applicability of regulatory accounting, considering such factors as regulatory changes, the impact of competition, and the ability to recover regulatory assets. The Partnership had no material regulatory assets as of December 31, 2013 and 2012. Regulatory liabilities are included in other long-term liabilities (refer to Note 8). Allowance for funds used during construction is capitalized and included in plant, property and equipment.
Debt Issuance Costs	(q) Debt Issuance Costs Costs related to the issuance of debt are deferred and amortized using the effective interest rate method over the term of the related debt.

ORGANIZATION (Tables)

12 Months Ended

Dec. 31, 2013

ORGANIZATION

Pipeline	Length	Description	Ownership


Gas Transmission Northwest LLC (GTN)	1,353 miles	Extends between an interconnection near Kingsgate, British Columbia, Canada at the Canadian border to a point near Malin, Oregon at the California border and delivers natural gas to the Pacific Northwest and to California. TransCanada owns the remaining 30 percent of GTN.	70 percent
Northern Border Pipeline Company (Northern Border)	1,408 miles	Extends between the Canadian border near Port of Morgan, Montana to a terminus near North Hayden, Indiana, south of Chicago. Northern Border is capable of receiving natural gas from Canada, the Williston Basin and Rocky Mountain Basin. ONEOK Partners, L.P. owns the remaining 50 percent of Northern Border.	50 percent
Bison Pipeline LLC (Bison)	303 miles	Extends from a location near Gillette, Wyoming to Northern Border's pipeline system in North Dakota. Bison was placed into service in January 2011 to transport natural gas from the Powder River Basin to Midwest markets. TransCanada owns the remaining 30 percent of Bison.	70 percent
Great Lakes Gas Transmission Limited Partnership (Great Lakes)	2,115 miles	Connects with the TransCanada Mainline at the Canadian border near Emerson, Manitoba, Canada and St. Clair, Michigan, near Detroit. Great Lakes is a bi-directional pipeline that can receive and deliver natural gas at multiple points along its system. TransCanada owns the remaining 53.55 percent of Great Lakes.	46.45 percent
North Baja Pipeline, LLC (North Baja)	86 miles	Extends between an interconnection with the El Paso Natural Gas Company pipeline near Ehrenberg, Arizona and an interconnection with a natural gas pipeline near Ogilby, California on the Mexican border. North Baja is a bi-directional pipeline.	100 percent
Tuscarora Gas Transmission Company (Tuscarora)	305 miles	Extends between the GTN pipeline near Malin, Oregon to its terminus near Reno, Nevada and delivers natural gas in northeastern California and northwestern Nevada.	100 percent

INVESTMENTS IN UNCONSOLIDATED AFFILIATES (Tables)

12 Months Ended

Dec. 31, 2013

INVESTMENTS IN UNCONSOLIDATED AFFILIATES

Schedule of equity method investment in unconsolidated affiliates

		Equity Earnings from Unconsolidated Affiliates			Investment in Unconsolidated Affiliates

		Year ended December 31			December 31
	Ownership Interest at December 31, 2013	Year ended December 31			December 31
(millions of dollars)	Ownership Interest at December 31, 2013	2013	2012	2011	2013	2012

Northern Border^(a)	50%	64	72	75	523	512
Great Lakes	46.45%	3	27	60	672	677

		67	99	135	1,195	1,189

(a): Equity earnings from Northern Border is net of the 12-year amortization of a $10 million transaction fee paid to the operator of Northern Border at the time of the Partnership's additional 20 percent acquisition in April 2006.

Northern Border

Summarized financial information for equity method investment

December 31 (millions of dollars)		2013		2012


Assets
Cash and cash equivalents		27		28
Other current assets		34		35
Plant, property and equipment, net		1,197		1,234
Other assets		33		31

		1,291		1,328

Liabilities and Partners' Equity
Current liabilities		51		53
Deferred credits and other		19		16
Long-term debt, including current maturities		411		473
Partners' equity
	Partners' capital	812		789
	Accumulated other comprehensive loss	(2	)	(3	)

		1,291		1,328

Year ended December 31 (millions of dollars)	2013		2012		2011


Transmission revenues	286		311		310
Operating expenses	(75	)	(79	)	(73	)
Depreciation	(58	)	(63	)	(62	)
Financial charges and other	(23	)	(24	)	(22	)

Net income	130		145		153

Great Lakes

Summarized financial information for equity method investment

December 31 (millions of dollars)	2013	2012


Assets
Current assets	52	56
Plant, property and equipment, net	771	799

	823	855

Liabilities and Partners' Equity
Current liabilities	28	30
Long-term debt, including current maturities	335	354
Partners' equity	460	471

	823	855

Year ended December 31 (millions of dollars)	2013		2012		2011


Transmission revenues	124		182		250
Operating expenses	(60	)	(66	)	(62	)
Depreciation	(31	)	(31	)	(32	)
Financial charges and other	(27	)	(28	)	(30	)
Michigan business tax	–		–		2

Net income	6		57		128

PLANT, PROPERTY AND EQUIPMENT (Tables)

12 Months Ended

Dec. 31, 2013

Schedule of plant, property and equipment

	2013				2012^(a)

December 31 (millions of dollars)	Cost	Accumulated Depreciation		Net Book Value	Cost	Accumulated Depreciation		Net Book Value

Pipeline	2,045	(522	)	1,523	2,040	(462	)	1,578
Compression	520	(120	)	400	514	(112	)	402
Metering and other	146	(32	)	114	142	(26	)	116
Construction in progress	5	–		5	15	–		15

	2,716	(674	)	2,042	2,711	(600	)	2,111

^(a): Recast as discussed in Note 2 and Note 6.

ACQUISITIONS (Tables)

12 Months Ended

Dec. 31, 2013

ACQUISITIONS

Schedule of purchase price recorded

(millions of dollars)


Current assets	67
Property, plant and equipment, net	1,792
Other assets	1
Current liabilities	(20	)
Other liabilities	(21	)
Long-term debt	(325	)

	1,494
Non-controlling interest	(448	)
Carrying value of pre-existing 25% interest in each of GTN and Bison	(374	)

Carrying value of acquired 45% interest in each of GTN and Bison	672
Excess purchase price over net assets acquired (includes Carty Lateral consideration)	274

Total cash consideration including $25 million Carty Lateral consideration payable	946

CREDIT FACILITIES AND LONG-TERM DEBT (Tables)

12 Months Ended

Dec. 31, 2013

CREDIT FACILITIES AND LONG-TERM DEBT

Schedule of components of debt

December 31 (millions of dollars)	2013	2012^(a)


Senior Credit Facility due 2017	380	312
Term Loan Facility due 2018	500	–
4.65% Unsecured Senior Notes due 2021	349	349
5.09% Unsecured Senior Notes due 2015	75	75
5.29% Unsecured Senior Notes due 2020	100	100
5.69% Unsecured Senior Notes due 2035	150	150
3.82% Series D Senior Notes due 2017	24	27

	1,578	1,013
Less: current portion of long-term debt	3	3

	1,575	1,010

^(a): Recast as discussed in Note 2 and Note 6.

Schedule of principal repayments required by the Partnership on the long-term debt

(millions of dollars)


2014		3
2015		79
2016		4
2017		393
2018		500
Thereafter		599

		1,578

OTHER LIABILITIES (Tables)

12 Months Ended

Dec. 31, 2013

OTHER LIABILITIES

Schedule of other liabilities

December 31 (millions of dollars)	2013	2012^(a)


Regulatory liabilities	22	20
Fair value of derivative contracts (Note 18)	–	–
Other liabilities	2	1

	24	21

^(a): Recast as discussed in Note 2 and Note 6.

ACCUMULATED OTHER COMPEREHENSIVE LOSS (Tables)

12 Months Ended

Dec. 31, 2013

ACCUMULATED OTHER COMPEREHENSIVE LOSS

Schedule of changes in accumulated other comprehensive loss (AOCI) by components

Years ended December 31, 2013 and 2012 (millions of dollars)	Cash flow hedges		Total


AOCL Balance as of January 1, 2013 and 2012	(1	)	(1	)
Other comprehensive loss before reclassifications	–		–
Amounts reclassified from AOCL (affected financial charges and other)	–		–

Net other comprehensive loss	–		–

AOCL Balance as of December 31, 2013 and 2012	(1	)	(1	)

Year ended December 31, 2011 (millions of dollars)	Cash flow hedges		Total


AOCL Balance as of January 1, 2011	(15	)	(15	)
Other comprehensive loss before reclassifications	–		–
Amounts reclassified from AOCL (affected financial charges and other)	14		14

Net other comprehensive income	14		14

AOCL Balance as of December 31, 2011	(1	)	(1	)

FINANCIAL CHARGES AND OTHER (Tables)

12 Months Ended

Dec. 31, 2013

FINANCIAL CHARGES AND OTHER

Schedule of financial charges and other

Year ended December 31 (millions of dollars)	2013^(a)	2012^(a)		2011^(a)


Interest expense	42	40		34
Amortization of debt issue costs	1	1		2
Net realized loss related to the interest rate swaps and options	1	–		14
Interest income	–	–		(2	)
Other	–	(1	)	(2	)

	44	40		46

^(a): Recast as discussed in Note 2 and Note 6.

NET INCOME PER COMMON UNIT (Tables)

12 Months Ended

Dec. 31, 2013

NET INCOME PER COMMON UNIT

Schedule of net income per common unit

(millions of dollars, except per common unit amounts)	2013^(a)		2012^(a)		2011^(a)


Net income	191		229		250
Net income attributed to GTN's and Bison's former parent	(26	)	(55	)	(59	)
Net income attributable to non-controlling interests	(36	)	(37	)	(34	)

Net income allocated to partners^(b)	129		137		157

Net income allocated to General Partner	3		3		3

Net income allocable to common units	126		134		154

Weighted average common units outstanding (millions) – basic and diluted	58.9		53.5		51.1
Net income per common unit – basic and diluted	$2.13		$2.51		$3.02

^(a): Recast as discussed in Note 2 and Note 6.
^(b): Net income allocated to partners excludes net income attributed to GTN's and Bison's former parent as it was allocated to TransCanada and was not allocable to either the general partner or common units.

CHANGE IN OPERATING WORKING CAPITAL (Tables)

12 Months Ended

Dec. 31, 2013

CHANGE IN OPERATING WORKING CAPITAL

Summary of change in operating working capital

Year Ended December 31 (millions of dollars)	2013^(a)		2012^(a)		2011^(a)


Change in accounts receivable and other	1		2		3
Change in accounts payable and accrued liabilities	(9	)	(2	)	(3	)
Change in accounts payable to affiliates	(2	)	–		–
Change in accrued interest	2		–		–

Change in operating working capital	(8	)	–		–

^(a): Recast as discussed in Note 2 and Note 6.

TRANSACTIONS WITH MAJOR CUSTOMERS (Tables)

12 Months Ended

Dec. 31, 2013

TRANSACTIONS WITH MAJOR CUSTOMERS

Schedule of revenues from the Partnership's major customers comprising more than 10% of the Partnerships' total revenues

Year Ended December 31 (millions of dollars)	2013^(a)	2012^(a)	2011^(a)


Anadarko Energy Services Company	48	48	45
Pacific Gas and Electric Company	46	47	68

^(a): Recast as discussed in Note 2 and Note 6.

RELATED PARTY TRANSACTIONS (Tables)

12 Months Ended

Dec. 31, 2013

RELATED PARTY TRANSACTIONS

Schedule of capital and operating costs charged by related party

Year ended December 31 (millions of dollars)		2013	2012	2011


Capital and operating costs charged by TransCanada's subsidiaries to:
	GTN^(a)(b)	28	29	33
	Northern Border^(a)	30	31	29
	Bison^(a)(b)	5	6	11
	Great Lakes^(a)	31	33	31
	North Baja	4	4	4
	Tuscarora	4	4	5
Impact on the Partnership's net income attributable to controlling interests:
	GTN^(b)	19	19	22
	Northern Border	14	14	13
	Bison^(b)	4	4	4
	Great Lakes	14	15	14
	North Baja	4	4	4
	Tuscarora	4	4	5

Schedule of amounts payable to related party for costs charged during the period

December 31 (millions of dollars)		2013	2012


Amount payable to TransCanada's subsidiaries for costs charged in the year by:
	GTN^(a)	3	3
	Northern Border^(a)	3	4
	Bison^(a)	–	1
	Great Lakes^(a)	3	4
	North Baja	1	1
	Tuscarora	–	1

^(a): Represents 100 percent of the costs.
^(b): Recast as discussed in Note 2 and Note 6.

QUARTERLY FINANCIAL DATA (unaudited) (Tables)

12 Months Ended

Dec. 31, 2013

QUARTERLY FINANCIAL DATA (unaudited)

Schedule of quarterly financial data

Quarter ended (millions of dollars except per common unit amounts)	Mar 31	Jun 30	Sept 30		Dec 31


2013
Transmission revenues^(a)	86	82	85		88
Equity earnings^(a)	18	15	15		19
Net income^(a)	53	42	46		50
Net income attributable to controlling interests^(a)	43	34	37		41
Net income per common unit	$0.52	$0.40	$0.58		$0.63
Cash distribution paid	43	43	52		52

2012
Transmission revenues^(a)	88	84	84		87
Equity earnings^(a)	29	24	24		22
Net income^(a)	65	54	57		53
Net income attributable to controlling interests^(a)	54	46	48		44
Net income per common unit	$0.71	$0.60	$0.64	^(b)	$0.56
Cash distributions paid	42	42	43		43

^(a): Recast as discussed in Note 2 and Note 6.
^(b): Net Income per common unit has been revised and is presented consistent with our presentation prior to the recast. This change conforms to our presentation for a previous common control transaction in 2009 to ensure consistency. As a result of this change, we decreased recast net income by the amount of net income attributed to GTN's and Bison's former parent in order to compute net income per common unit. It had no impact on these financial statements except as presented below:

Quarter ended September 30, 2012	As previously recast	Adjustment	Revised


Net income per common unit	$0.88	$(0.24)	$0.64

Schedule of prior period adjustments

Quarter ended September 30, 2012	As previously recast	Adjustment	Revised


Net income per common unit	$0.88	$(0.24)	$0.64

FAIR VALUE MEASUREMENTS (Tables)

12 Months Ended

Dec. 31, 2013

FAIR VALUE MEASUREMENTS

Schedule of estimated fair value of the Partnership's long-term debt

	2013		2012^(a)

December 31 (millions of dollars)	Carrying Value	Fair Value	Carrying Value	Fair Value

Senior Credit Facility due 2017	380	380	312	312
Term Loan Facility due 2018	500	500	–	–
4.65% Senior Notes due 2021	349	353	349	372
5.09% Unsecured Senior Notes due 2015	75	79	75	83
5.29% Unsecured Senior Notes due 2020	100	106	100	123
5.69% Unsecured Senior Notes due 2035	150	154	150	201
3.82% Series D Senior Notes due 2017	24	25	27	30

	1,578	1,597	1,013	1,121

^(a): Recast as discussed in Note 2 and Note 6.

ACCOUNTS RECEIVABLE AND OTHER (Tables)

12 Months Ended

Dec. 31, 2013

ACCOUNTS RECEIVABLE AND OTHER

Schedule of accounts receivable and other

December 31 (millions of dollars)	2013	2012^(a)


Trade accounts receivable, net of allowance of nil	33	31
Accounts receivable from affiliates	–	1
Other	4	6

	37	38

^(a): Recast as discussed in Note 2 and Note 6.

ORGANIZATION (Details) - mi	12 Months Ended
ORGANIZATION (Details) - mi	Dec. 31, 2013	Feb. 28, 2007
Northern Border
Organization
Ownership interest (as a percent)	50.00%
Great Lakes
Organization
Ownership interest (as a percent)	46.45%	46.45%
GTN
Organization
Length of pipeline owned (in miles)	1,353
Partnership interest held (as a percent)	70.00%
GTN \| TransCanada
Organization
Remaining noncontrolling ownership interest (as a percent)	30.00%
Northern Border
Organization
Length of pipeline owned (in miles)	1,408
Northern Border \| ONEOK Partners, L.P.
Organization
Remaining ownership interest (as a percent)	50.00%
Bison
Organization
Length of pipeline owned (in miles)	303
Partnership interest held (as a percent)	70.00%
Bison \| TransCanada
Organization
Remaining noncontrolling ownership interest (as a percent)	30.00%
Great Lakes
Organization
Length of pipeline owned (in miles)	2,115
Great Lakes \| TransCanada
Organization
Remaining ownership interest (as a percent)	53.55%
North Baja Pipeline, LLC
Organization
Length of pipeline owned (in miles)	86
Partnership interest held (as a percent)	100.00%
Tuscarora Gas Transmission Company
Organization
Length of pipeline owned (in miles)	305
Partnership interest held (as a percent)	100.00%

ORGANIZATION (Details 2) - shares			12 Months Ended
ORGANIZATION (Details 2) - shares	May 22, 2013	May 03, 2011	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Ownership interests in the Partnership
Number of common units owned			62,300,000	53,500,000	53,500,000
Common units
Ownership interests in the Partnership
Number of common units owned			62,327,766	53,472,766	53,472,766
Limited partner interest (as a percent)			98.00%
TC PipeLines GP, Inc. \| General Partner
Ownership interests in the Partnership
Ownership interest in the Partnership (as a percent)	2.00%	2.00%	2.00%
TC PipeLines GP, Inc. \| Common units
Ownership interests in the Partnership
Number of common units owned			5,797,106
TC PipeLines GP, Inc. \| Common units and General Partner interest combined
Ownership interests in the Partnership
Ownership interest in the Partnership (as a percent)			11.10%	12.60%	12.60%
TransCanada \| Common units
Ownership interests in the Partnership
Number of common units owned			11,287,725
Limited partner interest (as a percent)			17.80%
TransCanada Corporation and subsidiaries \| Common units and General Partner interest combined
Ownership interests in the Partnership
Ownership interest in the Partnership (as a percent)			28.90%

SIGNIFICANT ACCOUNTING POLICIES (Details) - Former parent, TransCanada subsidiaries - Transaction between entities under common control	Jul. 02, 2013	May 03, 2011
GTN
Summary of Significant Accounting Policies
Interest acquired by the Partnership (as a percent)	45.00%	25.00%
Bison
Summary of Significant Accounting Policies
Interest acquired by the Partnership (as a percent)	45.00%	25.00%

SIGNIFICANT ACCOUNTING POLICIES (Details 2) - USD ($)	12 Months Ended
SIGNIFICANT ACCOUNTING POLICIES (Details 2) - USD ($)	Dec. 31, 2013	Dec. 31, 2012
Pipeline facilities and compression equipment \| Minimum
PLANT, PROPERTY AND EQUIPMENT
Estimated useful lives	20 years
Pipeline facilities and compression equipment \| Maximum
PLANT, PROPERTY AND EQUIPMENT
Estimated useful lives	77 years
Metering and other equipment \| Minimum
PLANT, PROPERTY AND EQUIPMENT
Estimated useful lives	5 years
Metering and other equipment \| Maximum
PLANT, PROPERTY AND EQUIPMENT
Estimated useful lives	77 years
Natural gas pipeline systems
Asset Retirement Obligation
Asset retirement liabilities	$ 0	$ 0

INVESTMENTS IN UNCONSOLIDATED AFFILIATES (Details) - USD ($)
$ in Millions

1 Months Ended

3 Months Ended

12 Months Ended

Nov. 14, 2013

Jan. 02, 2013

Apr. 30, 2006

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Feb. 28, 2007

Equity Earnings from Unconsolidated Affiliates

$ 19

$ 15

$ 18

$ 22

$ 24

$ 29

$ 67

^[1]

$ 99

^[1]

$ 135

^[1]

Investments in Unconsolidated Affiliates

$ 1,195

1,189

^[1]

$ 1,195

1,189

^[1]

Northern Border Pipeline Company (general partnership)

Term of moratorium on filing rate cases

3 years

Reduction in current transportation rates (as a percent)

11.00%

Northern Border Pipeline Company (general partnership) | ONEOK Partners, L.P.

Other ownership interest (as a percent)

50.00%

Great Lakes Gas Transmission Limited Partnership | TransCanada

Other ownership interest (as a percent)

53.55%

TC GL Intermediate Limited Partnership

Partnership interest held (as a percent)

98.9899%

TC PipeLines Intermediate Limited Partnership

Partnership interest held (as a percent)

98.9899%

Northern Border Pipeline Company (general partnership)

Ownership interest at the end of the period (as a percent)

50.00%

Equity Earnings from Unconsolidated Affiliates

$ 64

Investments in Unconsolidated Affiliates

$ 523

512

523

512

Amortization period of transaction fee

12 years

Transaction fee

$ 10

Additional ownership interest acquired (as a percent)

20.00%

Undistributed earnings

Amount of difference between the carrying value and the underlying equity in net assets resulting from the recognition and inclusion of goodwill

118

119

118

119

Equity contribution

^[1]

Cash and cash equivalents

Assets

Other current assets

Plant, property and equipment, net

1,197

1,234

1,197

1,234

Other assets

Assets, total

1,291

1,328

1,291

1,328

Liabilities and Partners' Equity

Current liabilities

Deferred credits and other

Long-term debt, including current maturities

411

473

411

473

Partners' equity

Partners' equity

812

789

812

789

Accumulated other comprehensive loss

(2)

(3)

(2)

(3)

Liabilities and Equity, total

$ 1,291

1,328

1,291

1,328

Revenues (expenses)

286

311

310

Operating expenses

(75)

(79)

(73)

Financial charges and other

(58)

(63)

(62)

(23)

(24)

(22)

Great Lakes Gas Transmission Limited Partnership

$ 130

145

153

Ownership interest at the end of the period (as a percent)

46.45%

Equity Earnings from Unconsolidated Affiliates

$ 3

Investments in Unconsolidated Affiliates

$ 672

677

672

677

Increase in transportation rates compared to current rates (as a percent)

21.00%

Undistributed earnings

Amount of difference between the carrying value and the underlying equity in net assets resulting from the recognition and inclusion of goodwill

458

Equity contribution

^[1]

Plant, property and equipment, net

$ 9

Assets

Current assets

771

799

771

799

Assets, total

823

855

823

855

Liabilities and Partners' Equity

Current liabilities

Long-term debt, including current maturities

335

354

335

354

Partners' equity

Partners' equity

460

471

460

471

Liabilities and Equity, total

$ 823

$ 855

823

855

Revenues (expenses)

124

182

250

Operating expenses

(60)

(66)

(62)

Financial charges and other

(31)

(32)

(27)

(28)

(30)

Michigan business tax

$ 6

$ 57

$ 128

[1]	(a) Recast as discussed in Note 2 and Note 6.

PLANT, PROPERTY AND EQUIPMENT (Details) - USD ($)
$ in Millions

Dec. 31, 2013

Dec. 31, 2012

$ 2,716

$ 2,711

(674)

(600)

2,042

2,111

^[1]

Pipeline

2,045

2,040

(522)

(462)

1,523

1,578

Compression

520

514

(120)

(112)

Metering and other equipment

400

402

146

142

(32)

(26)

114

116

Construction in progress

$ 5

$ 15

[1]	(a) Recast as discussed in Note 2 and Note 6.

ACQUISITIONS (Details) - USD ($)
$ / shares in Units, $ in Millions

3 Months Ended

12 Months Ended

Jul. 22, 2013

Jul. 02, 2013

May 22, 2013

May 03, 2011

Mar. 25, 2011

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Mar. 05, 2010

Amount received from TransCanada subsidiary as a post-closing construction expenditures adjustment

^[1]

$ 1

Common units

Units sold in public offering

8,855,000

7,245,000

Price per common unit in public offering

$ 43.85

$ 47.58

Net proceeds from issuance of common units

$ 373

$ 331

373

$ 331

Excess purchase price paid recorded as reduction to Partner's equity

268

131

Excess purchase price paid recorded as reduction to Partner's equity

Senior Credit Facility

$ 500

Term loans

500

TC PipeLines GP, Inc. | General Partner

500

General partner ownership interest in the partnership (as a percent)

$ 8

$ 7

2.00%

GTN and Bison

Units sold in public offering

Cash paid

^[1]

$ 921

539

7,245,000

Price per common unit in public offering

$ 47.58

Net proceeds from issuance of common units

$ 331

GTN and Bison | Bridge loan facility

GTN and Bison | Senior revolving credit facility

400

125

GTN and Bison | Former parent, TransCanada subsidiaries | Transaction between entities under common control

250

Working capital adjustments

Purchase price

1,050

605

$ 1

Cash paid

921

539

Cash on hand used in acquisition

Excess purchase price paid recorded as reduction to Partner's equity

$ 131

Property, plant and equipment, net

Current assets

1,792

(20)

(21)

(325)

1,494

Carrying value of acquired 45% interest in each of GTN and Bison

672

Excess purchase price over net assets acquired

274

Total cash consideration including $25 million Carty Lateral consideration payable

946

Increase in the net income attributable to common units resulting from retrospective consolidation

$ 55

$ 59

GTN and Bison | Former parent, TransCanada subsidiaries | Transaction between entities under common control | Carrying value

Pre-existing 25% interest in each of GTN and Bison

Non-controlling interest

(448)

$ (374)

GTN | Former parent, TransCanada subsidiaries | Transaction between entities under common control

Interest acquired by the Partnership (as a percent)

45.00%

25.00%

Purchase price

$ 750

$ 405

Acquired debt

146

$ 81

Contingent additional payment, maximum

Excess purchase price over net assets acquired

$ 262

Pre-existing interest acquired by the partnership (as a percent)

25.00%

GTN | Former parent, TransCanada subsidiaries | Transaction between entities under common control | Accounts payable to affiliates

Bison | Former parent, TransCanada subsidiaries | Transaction between entities under common control

Contingent consideration

$ 25

Interest acquired by the Partnership (as a percent)

45.00%

25.00%

Purchase price

$ 300

$ 200

Future commitments related to acquisitions

$ 9

Excess purchase price over net assets acquired

$ 12

Pre-existing interest acquired by the partnership (as a percent)

25.00%

Amount received from TransCanada subsidiary as a post-closing construction expenditures adjustment

$ 1

Yuma Lateral Asset Acquisition

Working capital adjustments

$ 2

Yuma Lateral Asset Acquisition | TransCanada

Contingent additional payment, maximum

$ 2

[1]	(a) Recast as discussed in Note 2 and Note 6.

CREDIT FACILITIES AND LONG-TERM DEBT (Details) - USD ($)
$ in Millions

12 Months Ended

Jul. 02, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Less: current portion of long-term debt

$ 1,578

$ 1,013

^[1]

Long-term debt

1,575

1,010

^[1]

Senior Credit Facility due 2017

Senior Credit Facility due 2017 | Maximum

380

$ 312

Option to increase borrowings on the credit facility

$ 250

Senior Credit Facility due 2017 | LIBOR

Debt average interest rate (as a percent)

LIBOR

1.44%

1.61%

0.86%

Debt average interest rate, after hedging activity (as a percent)

4.07%

Debt interest rate, at period end, prior to hedging activities (as a percent)

1.42%

1.47%

Senior revolving credit facility

Amount outstanding under credit facility

$ 500

380

$ 312

Remaining borrowing capacity

120

Term Loan Facility due 2018

$ 500

500

Term Loan Facility due 2018 | LIBOR borrowings | LIBOR

$ 500

Debt average interest rate (as a percent)

LIBOR

1.43%

Debt average interest rate, after hedging activity (as a percent)

1.70%

Debt interest rate, at period end, prior to hedging activities (as a percent)

1.42%

Term Loan Facility due 2018 | LIBOR borrowings | LIBOR | Minimum

Term Loan Facility due 2018 | LIBOR borrowings | LIBOR | Maximum

1.125%

Term Loan Facility due 2018 | Base rate borrowings | LIBOR

2.00%

one-month LIBOR

Term Loan Facility due 2018 | Base rate borrowings | Base rate

1.00%

Term Loan Facility due 2018 | Base rate borrowings | Base rate | Minimum

Lender prime rate, federal funds rate or one-month LIBOR

Term Loan Facility due 2018 | Base rate borrowings | Base rate | Maximum

0.125%

Term Loan Facility due 2018 | Base rate borrowings | Prime rate

1.00%

Term Loan Facility due 2018 | Base rate borrowings | Federal funds rate

Prime rate

Federal funds rate

4.65% Unsecured Senior Notes due 2021

0.50%

4.65%

5.09% Unsecured Senior Notes due 2015

$ 349

5.09%

5.29% Unsecured Senior Notes due 2020

$ 75

5.29%

5.69% Unsecured Senior Notes due 2035

$ 100

5.69%

3.82% Series D Senior Notes due 2017

$ 150

3.82%

GTN | Senior Notes | Maximum

$ 24

$ 27

Percentage of debt to total capitalization

70.00%

[1]	(a) Recast as discussed in Note 2 and Note 6.

CREDIT FACILITIES AND LONG-TERM DEBT (Details 2) - USD ($) $ in Millions	Dec. 31, 2013	Dec. 31, 2012
Principal repayments required by the Partnership on the long-term debt
2014	$ 3
2015	79
2016	4
2017	393
2018	500
Thereafter	599
Total long-term debt	$ 1,578	$ 1,013

OTHER LIABILITIES (Details) - USD ($)
$ in Millions

Dec. 31, 2013

Dec. 31, 2012

OTHER LIABILITIES

Regulatory liabilities

$ 22

$ 20

Other liabilities

Other liabilities, total

$ 24

$ 21

^[1]

[1]	(a) Recast as discussed in Note 2 and Note 6.

PARTNERS' EQUITY (Details) - USD ($) $ / shares in Units, $ in Millions			12 Months Ended
	May 22, 2013	May 03, 2011	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Ownership interests in the Partnership
Number of common units owned			62,300,000	53,500,000	53,500,000
Common units
Ownership interests in the Partnership
Number of common units owned			62,327,766	53,472,766	53,472,766
Ownership interest in the Partnership (as a percent)			98.00%
Units sold in public offering	8,855,000	7,245,000
Units sold in public offering pursuant to exercise of underwriters' option	1,155,000
Price per common unit in public offering	$ 43.85	$ 47.58
Gross proceeds from public offering of common units	$ 388	$ 345
Net proceeds from public offering of common units	$ 373	$ 331	$ 373		$ 331
General Partner
Ownership interests in the Partnership
Capital contribution			$ 8		$ 7
TC PipeLines GP, Inc. \| Common units
Ownership interests in the Partnership
Number of common units owned			5,797,106
TC PipeLines GP, Inc. \| General Partner
Ownership interests in the Partnership
Ownership interest in the Partnership (as a percent)	2.00%	2.00%	2.00%
Capital contribution	$ 8	$ 7
TC PipeLines GP, Inc. \| Effective interest (combined common units and General Partner interests)
Ownership interests in the Partnership
Ownership interest in the Partnership (as a percent)			11.10%	12.60%	12.60%
TransCanada \| Common units
Ownership interests in the Partnership
Number of common units owned			11,287,725
Ownership interest in the Partnership (as a percent)			17.80%

ACCUMULATED OTHER COMPEREHENSIVE LOSS (Details) $ in Millions	12 Months Ended
	Dec. 31, 2011 USD ($)
Changes in accumulated other comprehensive loss (AOCL) by components
AOCL Balance at the beginning of the period	$ (15)
Amounts reclassified from AOCL (affected financial charges and other)	14
Net other comprehensive income (loss)	14
AOCL Balance at the end of the period	(1)
Cash flow hedges
Changes in accumulated other comprehensive loss (AOCL) by components
AOCL Balance at the beginning of the period	(15)
Amounts reclassified from AOCL (affected financial charges and other)	14
Net other comprehensive income (loss)	14
AOCL Balance at the end of the period	$ (1)

Amortization of debt issue costs

Accumulated change in equity from transactions and other events and circumstances from non-owner sources, net of tax effect, at period end. Excludes Net Income (Loss), and accumulated changes in equity from transactions resulting from investments by owners and distributions to owners. Includes foreign currency translation items, certain pension adjustments, unrealized gains and losses on certain investments in debt and equity securities, other than temporary impairment (OTTI) losses related to factors other than credit losses on available-for-sale and held-to-maturity debt securities that an entity does not intend to sell and it is not more likely than not that the entity will be required to sell before recovery of the amortized cost basis, as well as changes in the fair value of derivatives related to the effective portion of a designated cash flow hedge.

+ References + Details

FINANCIAL CHARGES AND OTHER (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

FINANCIAL CHARGES AND OTHER

Interest expense

$ 42

$ 40

$ 34

Net realized loss related to the interest rate swaps and options

Interest income

(2)

Other

(1)

(2)

Financial charges and other

^[1]

$ (44)

$ (40)

$ (46)

[1]	(a) Recast as discussed in Note 2 and Note 6.

NET INCOME PER COMMON UNIT (Details) - USD ($)
$ / shares in Units, shares in Millions, $ in Millions

3 Months Ended

12 Months Ended

May 22, 2013

May 03, 2011

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Ownership interests in the Partnership

Net income attributed to GTN and Bison's former parent

$ 50

$ 46

$ 42

$ 53

$ 57

$ 54

$ 65

$ 191

^[1]

$ 229

^[1]

$ 250

^[1]

(26)

(55)

(59)

Net income attributable to non-controlling interests

^[1]

(36)

(37)

(34)

Net income allocated to General Partner

$ 41

$ 37

$ 34

$ 43

$ 44

$ 48

$ 46

$ 54

155

^[1]

192

^[1]

216

^[1]

^[1]

Net income allocable to common units

^[1]

$ 126

$ 134

$ 154

Weighted average common units outstanding (millions) - basic (in units)

58.9

53.5

51.1

Weighted average common units outstanding (millions) - diluted (in units)

58.9

53.5

51.1

Net income per common unit - basic (in dollars per unit)

$ 0.63

$ 0.58

$ 0.40

$ 0.52

$ 0.56

$ 0.64

$ 0.60

$ 0.71

$ 2.13

^[1]

$ 2.51

^[1]

$ 3.02

^[1]

Net income per common unit - diluted (in dollars per unit)

^[1]

$ 2.13

$ 2.51

$ 3.02

Ownership interests in the Partnership

Net income attributed to GTN and Bison's former parent

^[1]

$ 3

$ 4

^[1]

$ (1)

TC PipeLines GP, Inc. | General Partner

Ownership interests in the Partnership

Additional percentage investment held by General Partner

2.00%

[1]	(a) Recast as discussed in Note 2 and Note 6.

CASH DISTRIBUTIONS (Details) - USD ($)
$ / shares in Units, $ in Millions

3 Months Ended

12 Months Ended

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

CASH DISTRIBUTIONS

Quarterly cash distributions (in dollars per unit)

$ 0.81

Cash distributions (in dollars per unit)

$ 3.18

$ 3.10

$ 3.04

Cash distributions

$ 52

$ 43

$ 42

$ 188

^[1]

$ 169

^[1]

$ 155

^[1]

Maximum

Number of days after the end of each quarter for making cash distribution

45 days

Percentage of priority income allocations for incentive distributions

Incentive distributions

$ 0

100.00%

General Partner | Target level of $0.81 per common unit | Minimum

Combined general partner interest and incentive distribution interest percentage of quarterly distributions of Available Cash exceeding target levels, threshold

15.00%

Target level of quarterly distributions (in dollars per common unit)

$ 0.81

General Partner | Target level of $0.88 per common unit | Maximum

Combined general partner interest and incentive distribution interest percentage of quarterly distributions of Available Cash exceeding target levels, threshold

25.00%

General Partner | Target level of $0.88 per common unit | Minimum

Target level of quarterly distributions (in dollars per common unit)

$ 0.88

[1]	(a) Recast as discussed in Note 2 and Note 6.

CHANGE IN OPERATING WORKING CAPITAL (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

CHANGE IN OPERATING WORKING CAPITAL

Change in accounts receivable and other

$ 1

$ 2

$ 3

Change in accounts payable and accrued liabilities

(9)

$ (2)

$ (3)

Change in accounts payable to affiliates

(2)

Change in accrued interest

Change in operating working capital

^[1]

$ (8)

[1]	(a) Recast as discussed in Note 2 and Note 6.

TRANSACTIONS WITH MAJOR CUSTOMERS (Details) - USD ($)
$ in Millions

3 Months Ended

12 Months Ended

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Transactions with major customers

Revenues

$ 88

$ 85

$ 82

$ 86

$ 87

$ 84

$ 88

$ 341

^[1]

$ 343

^[1]

$ 353

^[1]

Total revenues | Customer concentration risk | Anadarko Energy Services Company

Transactions with major customers

Revenues

Total revenues | Customer concentration risk | Pacific Gas and Electric Company

Transactions with major customers

Revenues

$ 46

$ 47

$ 68

[1]	(a) Recast as discussed in Note 2 and Note 6.

RELATED PARTY TRANSACTIONS (Details) - USD ($)
$ in Millions

3 Months Ended

12 Months Ended

Dec. 31, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Capital and operating costs charged to the pipeline systems and amount payable

Demand loan receivable from affiliate

^[1]

$ 21

Demand loan payable to affiliate

^[1]

GTN and Bison

Capital and operating costs charged to the pipeline systems and amount payable

Demand loan receivable from affiliate

Demand loan payable to affiliate

Bison

Capital and operating costs charged to the pipeline systems and amount payable

Capital and operating costs charged to the pipeline systems and amount payable

$ 24

Northern Border

Capital and operating costs charged to the pipeline systems and amount payable

$ 62

Great Lakes

$ 9

Capital and operating costs charged to the pipeline systems and amount payable

Capital and operating costs charged by TransCanada's subsidiaries

$ 3

$ 2

TransCanada's subsidiaries | GTN

Capital and operating costs charged to the pipeline systems and amount payable

Capital and operating costs charged by TransCanada's subsidiaries

Impact on the Partnership's net income attributable to controlling interests

Percentage of capital and operating costs charged by TransCanada's subsidiaries

$ 3

100.00%

TransCanada's subsidiaries | Bison

Capital and operating costs charged to the pipeline systems and amount payable

Capital and operating costs charged by TransCanada's subsidiaries

$ 5

Impact on the Partnership's net income attributable to controlling interests

$ 4

Percentage of capital and operating costs charged by TransCanada's subsidiaries

100.00%

TransCanada's subsidiaries | North Baja

Capital and operating costs charged to the pipeline systems and amount payable

Capital and operating costs charged by TransCanada's subsidiaries

$ 4

Impact on the Partnership's net income attributable to controlling interests

TransCanada's subsidiaries | Tuscarora

Capital and operating costs charged to the pipeline systems and amount payable

Capital and operating costs charged by TransCanada's subsidiaries

Impact on the Partnership's net income attributable to controlling interests

TransCanada's subsidiaries | Northern Border

Capital and operating costs charged to the pipeline systems and amount payable

Capital and operating costs charged by TransCanada's subsidiaries

Impact on the Partnership's net income attributable to controlling interests

Percentage of capital and operating costs charged by TransCanada's subsidiaries

$ 3

100.00%

TransCanada's subsidiaries | Great Lakes

Capital and operating costs charged to the pipeline systems and amount payable

Capital and operating costs charged by TransCanada's subsidiaries

$ 31

Impact on the Partnership's net income attributable to controlling interests

Percentage of capital and operating costs charged by TransCanada's subsidiaries

$ 3

100.00%

Revenue from TransCanada and its affiliates included in the Partnership's equity earnings

$ 32

Amount included in receivables in regards to the transportation contracts with TransCanada and its affiliates

TransCanada's subsidiaries | Great Lakes | Transportation revenues

Capital and operating costs charged to the pipeline systems and amount payable

Revenues from TransCanada and its affiliates

$ 68

$ 77

$ 81

Percentage of revenues from TransCanada and its affiliates to total revenues

55.00%

42.00%

32.00%

TransCanada's subsidiaries | Great Lakes | Affiliated rental revenue

Capital and operating costs charged to the pipeline systems and amount payable

Revenues from TransCanada and its affiliates

$ 1

Former parent, TransCanada subsidiaries | GTN and Bison | Transaction between entities under common control

Capital and operating costs charged to the pipeline systems and amount payable

Former parent, TransCanada subsidiaries | Bison

^[1]

213

Capital and operating costs charged to the pipeline systems and amount payable

Ownership interest (as a percent)

$ 18

$ 305

75.00%

GTN | Former parent, TransCanada subsidiaries | Transaction between entities under common control | Accounts payable to affiliates

Capital and operating costs charged to the pipeline systems and amount payable

Accrued additional consideration

$ 25

[1]	(a) Recast as discussed in Note 2 and Note 6.

QUARTERLY FINANCIAL DATA (unaudited) (Details) - USD ($)
$ / shares in Units, $ in Millions

3 Months Ended

12 Months Ended

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

^[1]

Dec. 31, 2012

^[1]

Dec. 31, 2011

^[1]

Quarterly financial data (unaudited)

$ 88

$ 85

$ 82

$ 86

$ 87

$ 84

$ 88

$ 341

$ 343

$ 353

Equity earnings

135

191

229

250

$ 41

$ 37

$ 34

$ 43

$ 44

$ 48

$ 46

$ 54

$ 155

$ 192

$ 216

$ 0.63

$ 0.58

$ 0.40

$ 0.52

$ 0.56

$ 0.64

$ 0.60

$ 0.71

$ 2.13

$ 2.51

$ 3.02

Cash distribution paid

$ 52

$ 43

$ 42

$ 188

$ 169

$ 155

[1]	(a) Recast as discussed in Note 2 and Note 6.

QUARTERLY FINANCIAL DATA (unaudited) (Details 2) - $ / shares

3 Months Ended

12 Months Ended

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

^[1]

Dec. 31, 2012

^[1]

Dec. 31, 2011

^[1]

Prior period adjustments

$ 0.63

$ 0.58

$ 0.40

$ 0.52

$ 0.56

$ 0.64

$ 0.60

$ 0.71

$ 2.13

$ 2.51

$ 3.02

As previously recast

Prior period adjustments

0.88

Adjustment

Prior period adjustments

Trade accounts receivable, net of allowance of nil

$ (0.24)

[1]	(a) Recast as discussed in Note 2 and Note 6.

FAIR VALUE MEASUREMENTS (Details) - USD ($) $ in Millions	Dec. 31, 2013	Dec. 31, 2012
4.65% Senior Notes due 2021
Financial Instruments
Stated interest rate (as a percent)	4.65%	4.65%
5.09% Unsecured Senior Notes due 2015
Financial Instruments
Stated interest rate (as a percent)	5.09%	5.09%
5.29% Unsecured Senior Notes due 2020
Financial Instruments
Stated interest rate (as a percent)	5.29%	5.29%
5.69% Unsecured Senior Notes due 2035
Financial Instruments
Stated interest rate (as a percent)	5.69%	5.69%
3.82% Series D Senior Notes due 2017
Financial Instruments
Stated interest rate (as a percent)	3.82%	3.82%
Carrying Value
Financial Instruments
Long-term debt	$ 1,578	$ 1,013
Carrying Value \| Senior Credit Facility due 2017
Financial Instruments
Long-term debt	380	312
Carrying Value \| Term Loan Facility due 2018
Financial Instruments
Long-term debt	500
Carrying Value \| 4.65% Senior Notes due 2021
Financial Instruments
Long-term debt	349	349
Carrying Value \| 5.09% Unsecured Senior Notes due 2015
Financial Instruments
Long-term debt	75	75
Carrying Value \| 5.29% Unsecured Senior Notes due 2020
Financial Instruments
Long-term debt	100	100
Carrying Value \| 5.69% Unsecured Senior Notes due 2035
Financial Instruments
Long-term debt	150	150
Carrying Value \| 3.82% Series D Senior Notes due 2017
Financial Instruments
Long-term debt	24	27
Fair Value \| Level 2
Financial Instruments
Long-term debt	1,597	1,121
Fair Value \| Level 2 \| Senior Credit Facility due 2017
Financial Instruments
Long-term debt	380	312
Fair Value \| Level 2 \| Term Loan Facility due 2018
Financial Instruments
Long-term debt	500
Fair Value \| Level 2 \| 4.65% Senior Notes due 2021
Financial Instruments
Long-term debt	353	372
Fair Value \| Level 2 \| 5.09% Unsecured Senior Notes due 2015
Financial Instruments
Long-term debt	79	83
Fair Value \| Level 2 \| 5.29% Unsecured Senior Notes due 2020
Financial Instruments
Long-term debt	106	123
Fair Value \| Level 2 \| 5.69% Unsecured Senior Notes due 2035
Financial Instruments
Long-term debt	154	201
Fair Value \| Level 2 \| 3.82% Series D Senior Notes due 2017
Financial Instruments
Long-term debt	$ 25	$ 30

FAIR VALUE MEASUREMENTS (Details 2) - USD ($)	12 Months Ended
FAIR VALUE MEASUREMENTS (Details 2) - USD ($)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 12, 2011	Feb. 28, 2011
Accounts receivable
Interest rate derivatives
Maximum counterparty credit exposure related to accounts receivable	$ 37,000,000	$ 59,000,000
Senior Credit Facility due 2017
Interest rate derivatives
Amount of variable-rate debt hedged		0	$ 0
Interest rate swaps from September 3, 2013 through July 1, 2018 \| Term Loan Facility
Interest rate derivatives
Amount of variable-rate debt hedged	$ 150,000,000
Date of maturity	Jul. 18, 2018
Weighted average fixed interest rate (as a percent)	2.79%
Interest rate swap through December 12, 2011 \| Senior Credit Facility due 2017
Interest rate derivatives
Amount of variable-rate debt hedged				$ 300,000,000
Fixed interest rate paid (as a percent)				4.89%
Interest rate swap Through February 28, 2011 \| Senior Credit Facility due 2017
Interest rate derivatives
Amount of variable-rate debt hedged					$ 75,000,000
Fixed interest rate paid (as a percent)					3.86%
Hedges of cash flows \| Interest rate swaps \| Maximum
Interest rate derivatives
Change in fair value of interest rate derivative instruments recognized in other comprehensive income	$ 1,000,000
Hedges of cash flows \| Interest rate swaps \| Financial charges and other
Interest rate derivatives
Net realized loss related to the interest rate swaps	1,000,000		14,000,000
Designated as hedge \| Interest rate swaps
Interest rate derivatives
Fair value of derivatives, net
Designated as hedge \| Interest rate swaps \| Maximum
Interest rate derivatives
Fair value of derivatives, gross	1,000,000
Fair value of derivatives, net	$ 1,000,000

ACCOUNTS RECEIVABLE AND OTHER (Details) - USD ($)
$ in Millions

Dec. 31, 2013

Dec. 31, 2012

ACCOUNTS RECEIVABLE AND OTHER

$ 33

$ 31

Accounts receivable from affiliates

Other

Accounts receivable and other

$ 37

$ 38

^[1]

[1]	(a) Recast as discussed in Note 2 and Note 6.

CONTINGENCIES (Details) $ in Millions	1 Months Ended
CONTINGENCIES (Details) $ in Millions	Dec. 31, 2009 USD ($)
GTN \| PaciCorp suit against GTN and Northwest Pipeline for alleged equipment damage
Contingencies
Loss contingency, alleged damage amount	$ 7

SUBSEQUENT EVENTS (Details) - USD ($) $ / shares in Units, $ in Millions							12 Months Ended
	Feb. 14, 2014	Feb. 03, 2014	Jan. 16, 2014	Jan. 09, 2014	May 22, 2013	May 03, 2011	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Feb. 28, 2007
Subsequent events
Number of common units owned							62,300,000	53,500,000	53,500,000
Great Lakes
Subsequent events
Ownership interest (as a percent)							46.45%			46.45%
Northern Border
Subsequent events
Ownership interest (as a percent)							50.00%
GTN
Subsequent events
Partnership interest (as a percent)							70.00%
Bison
Subsequent events
Partnership interest (as a percent)							70.00%
Common units
Subsequent events
Partnership distribution							$ 184	$ 166	$ 152
Number of common units owned							62,327,766	53,472,766	53,472,766
Common units \| TC PipeLines GP, Inc.
Subsequent events
Number of common units owned							5,797,106
Common units \| TransCanada
Subsequent events
Number of common units owned							11,287,725
General Partner
Subsequent events
Partnership distribution							$ 4	$ 3	$ 3
General Partner \| TC PipeLines GP, Inc.
Subsequent events
General partner ownership interest in the partnership (as a percent)					2.00%	2.00%	2.00%
Subsequent event
Subsequent events
Cash distribution (in dollars per unit)			$ 0.81
Subsequent event \| GTN
Subsequent events
Aggregate distribution declared and payable by investee				$ 28
Distribution received by Partnership		$ 20
Subsequent event \| Bison
Subsequent events
Aggregate distribution declared and payable by investee				17
Distribution received by Partnership		12
Subsequent event \| General Partner \| TC PipeLines GP, Inc.
Subsequent events
Partnership distribution	$ 1
Subsequent event \| Distribution declared \| Northern Border
Subsequent events
Partnership distribution		43
Subsequent event \| Distribution declared \| Great Lakes
Subsequent events
Partnership distribution				$ 12
Subsequent event \| Cash Distribution Paid
Subsequent events
Partnership distribution	52
Subsequent event \| Cash Distribution Paid \| Northern Border
Subsequent events
Partnership's share of distributions declared and payable by investee		21
Subsequent event \| Cash Distribution Paid \| Great Lakes
Subsequent events
Partnership's share of distributions declared and payable by investee		$ 5
Subsequent event \| Cash Distribution Paid \| Common units
Subsequent events
Partnership distribution	51
Subsequent event \| Cash Distribution Paid \| Common units \| TC PipeLines GP, Inc.
Subsequent events
Partnership distribution	5
Subsequent event \| Cash Distribution Paid \| Common units \| TransCanada
Subsequent events
Partnership distribution	$ 9

Label	Element	Value
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax	us-gaap_AccumulatedOtherComprehensiveIncomeLossNetOfTax	$ (1,000,000)
Accumulated Other Comprehensive Income (Loss), Net of Tax	us-gaap_AccumulatedOtherComprehensiveIncomeLossNetOfTax	$ (1,000,000)