Edgar Filing: TC PIPELINES LP

form10qtclp10302012.htm

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2012

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _________ to _________

Commission File Number: 001-35358

TC PipeLines, LP

(Exact name of registrant as specified in its charter)

Delaware	52-2135448
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification Number)

717 Texas Street, Suite 2400 Houston, Texas	77002-2761
(Address of principle executive offices)	(Zip code)

877-290-2772

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes x No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes x No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer x	Accelerated filer ¨
Non-accelerated filer ¨ (Do not check if a smaller reporting company)	Smaller reporting company ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes ¨ No x

As of October 30, 2012, there were 53,472,766 of the registrant’s common units outstanding.

TC PIPELINES, LP		Page No.

TABLE OF CONTENTS

PART I	FINANCIAL INFORMATION

Item 1.	Financial Statements (Unaudited)	6
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	20
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	28
Item 4.	Controls and Procedures	30

PART II	OTHER INFORMATION

Item 1.	Legal Proceedings	30
Item 1A.	Risk Factors	30
Item 6.	Exhibits	32
	Signatures	33

All amounts are stated in United States dollars unless otherwise indicated.

DEFINITIONS

The abbreviations, acronyms, and industry terminology used in this quarterly report are defined as follows:

Acquisitions	The acquisition from subsidiaries of TransCanada of a 25 percent membership interest in each of GTN and Bison
ASC	Accounting Standards Codification
Bison	Bison Pipeline LLC
DOT	U.S. Department of Transportation
EPA	U.S. Environmental Protection Agency
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
GAAP	U.S. generally accepted accounting principles
General Partner	TC PipeLines GP, Inc.
Great Lakes	Great Lakes Gas Transmission Limited Partnership
GTN	Gas Transmission Northwest LLC
GTN Settlement	Stipulation and Agreement of Settlement for GTN regarding its rates and terms and conditions of service approved by FERC in November 2011
LIBOR	London Interbank Offered Rate
Mainline	TransCanada’s Mainline, a natural gas transmission system extending from the Alberta/Saskatchewan border east to Quebec
NGA	Natural Gas Act of 1938
North Baja	North Baja Pipeline, LLC
Northern Border	Northern Border Pipeline Company
Northern Border Settlement	Stipulation and Agreement of Settlement for Northern Border regarding its rates and terms and conditions of service subject to FERC approval
Other Pipes	North Baja and Tuscarora
Our pipeline systems	Our ownership interests in Great Lakes, Northern Border, GTN, Bison, North Baja and Tuscarora
Partnership	TC PipeLines, LP and its subsidiaries
Partnership Agreement	Second Amended and Restated Agreement of Limited Partnership
PHMSA	U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration
SEC	Securities and Exchange Commission
Senior Credit Facility	TC PipeLines, LP’s revolving credit and term loan agreement
TransCanada	TransCanada Corporation and its subsidiaries
Tuscarora	Tuscarora Gas Transmission Company
Tuscarora Settlement	Stipulation and Agreement of Settlement for Tuscarora regarding its rates and terms and conditions of service approved by FERC in March 2012
U.S.	United States of America
WCSB	Western Canada Sedimentary Basin

Unless the context clearly indicates otherwise, TC PipeLines, LP, its subsidiaries and equity investees are collectively referred to in this quarterly report as “we,” “us,” “our” and “the Partnership.” We use “our pipeline systems” when referring to the Partnership’s ownership interests in Great Lakes Gas Transmission Limited Partnership (Great Lakes), Northern Border Pipeline Company (Northern Border), Gas Transmission Northwest LLC (GTN), Bison Pipeline LLC (Bison), North Baja Pipeline, LLC (North Baja) and Tuscarora Gas Transmission Company (Tuscarora).

FORWARD-LOOKING STATEMENTS AND CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

This report includes certain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements are identified by words and phrases such as: “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “forecast,” “should,” “predict,” “could,” “will,” “may,” and other terms and expressions of similar meaning. The absence of these words, however, does not mean that the statements are not forward-looking. These statements are based on management’s beliefs and assumptions and on currently available information and include, but are not limited to, statements regarding anticipated financial performance, future capital expenditures, liquidity, plans and objectives for future operations, organic and strategic growth opportunities, contract renewals and ability to market open capacity, business prospects, outcome of regulatory proceedings, and cash distributions to unitholders.

Forward-looking statements involve known and unknown risks, uncertainties and other factors that could cause actual results to differ materially from future results, performance or achievements expressed or implied in forward-looking statements. Factors that could cause, and in certain instances have caused, actual results to differ materially from those contemplated in forward-looking statements include, but are not limited to:

·	the ability of our pipeline systems to generate positive operating cash flows and make cash distributions;

·	the ability to sell unsold capacity and renew expiring contracts on our pipeline systems;

·	the ability of our pipeline systems to market capacity on favorable terms, which is affected by, among other factors:

o	demand for and prices of natural gas;

o	level of natural gas basis differentials;

o	weather conditions that impact natural gas supply and demand;

availability of supplies of Canadian and United States of America (U.S.) natural gas, including the growing supplies of natural gas from shale gas basins such as Horn River and Montney in Western Canada and Appalachian and Barnett in the U.S., and natural gas from conventional basins such as the Western Canada Sedimentary Basin (WCSB), Rocky Mountain, Mid-Continent and Gulf Coast basins;

o	competitive natural gas transmission developments;

o	uncertainty relating to TransCanada’s Mainline (Mainline) rates;

o	the availability of natural gas storage capacity and storage levels;

o	the level of production of natural gas liquids and the subsequent impact on relative competitiveness of gas producing basins; and

o	the ability of shippers to pay including meeting creditworthiness requirements;

the costs and impact of changes in laws and governmental regulations affecting our pipeline systems, particularly regulations issued by the Federal Energy Regulatory Commission (FERC), the U.S. Environmental Protection Agency (EPA), U.S. Department of Transportation (DOT) and U.S. DOT Pipeline and Hazardous Materials Safety Administration (PHMSA);

·	the outcome and frequency of rate proceedings on our pipeline systems;

·	changes in relative cost structures and production levels of natural gas producing basins;

·	regulatory, financing, construction and operational risks associated with construction and operation of interstate natural gas pipelines;

·	our ability to identify and complete expansion projects and other accretive growth opportunities;

·	the performance by shippers, contractors and service providers of their contractual obligations on our pipeline systems;

·	changes in the taxation of limited partnerships by states or the federal government such as the elimination of pass-through taxation and the imposition of entity level taxes;

·	potential conflicts of interest between TC PipeLines GP, Inc., our general partner (General Partner) its affiliates and us;

·	the ability to maintain secure operation of our information technology;

·	the impact of potential impairment charges; and

·	unfavorable economic conditions and the impact on capital markets.

These are not the only factors that could cause actual results to differ materially from those expressed or implied in any forward-looking statement. Other factors described elsewhere in this document, or factors that are unknown or unpredictable, could also have material adverse effects on future results. These and other risks are described in greater detail in Part II, Item 1A. “Risk Factors” in this Form 10-Q and Part I, Item 1A. “Risk Factors” in our Form 10-K for the year ended December 31, 2011. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors. All forward-looking statements are made only as of the date made and except as required by applicable law, we undertake no obligation to update any forward-looking statements to reflect new information, subsequent events or other changes.

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

TC PIPELINES, LP

CONSOLIDATED STATEMENT OF INCOME

	Three months ended						Nine months ended
(unaudited)	September 30,						September 30,
(millions of dollars except per common unit amounts)	2012			2011			2012			2011

Equity earnings from unconsolidated affiliates (a) (Note 3)		31			40			100			116
Transmission revenues		17			18			49			53
Operating expenses		(4	)		(4	)		(12	)		(10	)
General and administrative		(1	)		(1	)		(5	)		(8	)
Depreciation		(2	)		(3	)		(8	)		(11	)
Financial charges and other		(6	)		(9	)		(17	)		(21	)
Net income		35			41			107			119

Net income allocation (Note 6)
Common units		34			40			105			117
General Partner		1			1			2			2
		35			41			107			119

Net income per common unit (Note 6)		$0.64			$0.75			$1.96			$2.33

Weighted average common units outstanding (millions)		53.5			53.5			53.5			50.2

Common units outstanding, end of period (millions)		53.5			53.5			53.5			53.5

TC PIPELINES, LP

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

	Three months ended				Nine months ended
(unaudited)	September 30,				September 30,
(millions of dollars)	2012		2011		2012		2011

Net income (a)		35		41		107		119
Other comprehensive income
Change associated with current period hedging transactions (Note 10)		-		3		-		10
Total comprehensive income		35		44		107		129

(a)	25 percent interests in each of GTN and Bison were acquired in May 2011.

The accompanying notes are an integral part of these consolidated financial statements.

TC PIPELINES, LP

CONSOLIDATED BALANCE SHEET


(unaudited)
(millions of dollars)	September 30, 2012			December 31, 2011

ASSETS
Current Assets
Cash and cash equivalents		7			29
Accounts receivable and other (Note 11)		10			9
		17			38
Investments in unconsolidated affiliates (Note 3)		1,576			1,610
Plant, property and equipment
(Net of $146 accumulated depreciation; 2011 $139)		291			298
Goodwill		130			130
Other assets		5			6
		2,019			2,082

Liabilities and Partners’ Equity
Current Liabilities
Accounts payable and accrued liabilities		7			5
Accrued interest		6			1
Current portion of long-term debt (Note 5)		3			3
		16			9
Long-term debt (Note 5)		689			739
Other liabilities		1			1
		706			749
Partners’ Equity
Common units		1,288			1,307
General partner		26			27
Accumulated other comprehensive loss		(1	)		(1	)
		1,313			1,333
		2,019			2,082

Subsequent events (Note 14)

The accompanying notes are an integral part of these consolidated financial statements.

TC PIPELINES, LP

CONSOLIDATED STATEMENT OF CASH FLOWS

	Nine months ended
(unaudited)	September 30,
(millions of dollars)	2012			2011

Cash Generated From Operations
Net income (a)		107			119
Depreciation		8			11
Amortization of debt issuance costs		1			2
Equity earnings in excess of cumulative distributions:
GTN (a)		-			(7	)
Bison (a)		-			(4	)
Decrease in long-term liabilities		-			(1	)
Decrease in operating working capital (Note 8)		7			4
		123			124
Investing Activities
Cumulative distributions in excess of equity earnings:
Great Lakes		11			7
Northern Border		17			17
GTN (a)		6			-
Bison (a)		4			-
Investment in Great Lakes (Note 3)		(4	)		(4	)
Investment in Northern Border (Note 3)		-			(50	)
Acquisition of GTN and Bison (Note 4)		-			(538	)
Capital expenditures		(2	)		(3	)
		32			(571	)
Financing Activities
Distributions paid (Note 7)		(127	)		(113	)
Equity issuance, net (Note 4)		-			338
Long-term debt issues (Note 5)		5			593
Long-term debt repaid (Note 5)		(55	)		(361	)
Debt issue costs		-			(7	)
		(177	)		450
Increase in cash and cash equivalents		(22	)		3
Cash and cash equivalents, beginning of period		29			4
Cash and cash equivalents, end of period		7			7

(a)	25 percent interests in each of GTN and Bison were acquired in May 2011, the first distribution was received in the fourth quarter of 2011.

The accompanying notes are an integral part of these consolidated financial statements.

TC PIPELINES, LP

CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS’ EQUITY

(unaudited)	Common Units					General Partner			Accumulated Other Comprehensive Loss			Partners' Equity
	(millions		(millions			(millions			(millions			(millions		(millions
	of units)		of dollars)			of dollars)			of dollars)			of units)		of dollars)
Partners' equity at December 31, 2011		53.5		1,307			27			(1	)		53.5		1,333
Net income				105			2			-					107
Distributions paid				(124	)		(3	)		-					(127	)
Partners' equity at September 30, 2012		53.5		1,288			26			(1	)		53.5		1,313

The accompanying notes are an integral part of these consolidated financial statements.

TC PIPELINES, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

NOTE 2 SIGNIFICANT ACCOUNTING POLICIES

(a) Basis of Presentation

The results of operations for the three and nine months ended September 30, 2012 and 2011 are not necessarily indicative of the results that may be expected for a full fiscal year. The unaudited interim financial statements should be read in conjunction with the financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2011. That report contains a more comprehensive summary of the Partnership’s major accounting policies. In the opinion of management, the accompanying unaudited consolidated financial statements contain all of the appropriate adjustments, all of which are normally recurring adjustments unless otherwise noted, considered necessary to present fairly the financial position of the Partnership, the results of operation and cash flows for the respective periods. Our significant accounting policies are consistent with those disclosed in Note 2 of the financial statements in our Annual Report on Form 10-K for the year ended December 31, 2011. Certain items from that Note are repeated or updated below as necessary to assist in understanding these financial statements.

Amounts are stated in U.S. dollars.

(b) Acquisitions

On May 3, 2011, the Partnership acquired a 25 percent membership interest in each of GTN and Bison from subsidiaries of TransCanada (Acquisitions). The Acquisitions were accounted for as transactions between entities under common control, whereby the equity investments in GTN and Bison were recorded at TransCanada’s carrying values. See Note 4 for additional disclosure regarding the Acquisitions.

The preparation of financial statements in conformity with United States of America (U.S.) generally accepted accounting principles (GAAP) 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. In the opinion of management, these consolidated financial statements have been properly prepared within reasonable limits of materiality and include all adjustments (consisting of normal recurring accruals) necessary for a fair presentation of the financial results for the periods presented.

NOTE 3 INVESTMENTS IN UNCONSOLIDATED AFFILIATES

Great Lakes, Northern Border, GTN and Bison are regulated by the 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								Investments in Unconsolidated Affiliates
(unaudited)	Ownership Interest at September 30,		Three months ended September 30,				Nine months ended September 30,				September 30,		December 31,
(millions of dollars)	2012		2012		2011		2012		2011		2012		2011
Great Lakes	46.45	%		6		14		23		49		679		686
Northern Border (a)	50	%		18		19		54		56		519		536
GTN (b)	25	%		5		5		15		7		219		225
Bison (b)	25	%		2		2		8		4		159		163
				31		40		100		116		1,576		1,610

(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 interest acquisition in April 2006.

(b)	25 percent interests in each of GTN and Bison were acquired in May 2011.

Great Lakes

The Partnership recorded no undistributed earnings from Great Lakes for the nine months ended September 30, 2012 and 2011.

The summarized financial information for Great Lakes is as follows:

(unaudited)
(millions of dollars)	September 30, 2012		December 31, 2011

ASSETS
Current assets		56		65
Plant, property and equipment, net		805		826
Other assets		1		1
		862		892

Liabilities and Partners’ Equity
Current liabilities		23		30
Long-term debt, including current maturities		364		373
Partners’ equity		475		489
		862		892

	Three months ended						Nine months ended
(unaudited)	September 30,						September 30,
(millions of dollars)	2012			2011			2012			2011

Transmission revenues		46			63			143			196
Operating expenses		(17	)		(16	)		(48	)		(46	)
Depreciation		(8	)		(8	)		(24	)		(24	)
Financial charges and other		(7	)		(7	)		(21	)		(22	)
Michigan business tax		-			(1	)		-			2
Net income		14			31			50			106

Northern Border

On September 27, 2012, Northern Border filed a petition with the FERC requesting approval of a Stipulation and Agreement of Settlement (Northern Border Settlement) with its customers to modify its transportation rates. The Northern Border Settlement, if approved, will be effective January 1, 2013 and will eliminate Northern Border's obligation to otherwise file a Section 4 rate case by December 31, 2012. If approved, the settlement will establish maximum long-term transportation rates on the Northern Border system and current transportation rates will be reduced by approximately 11 percent. In addition, the composite depreciation rate will be reduced to 2.19 percent from 2.40 percent. The settlement includes a three-year moratorium on filing rate cases or challenging the settlement rates and requires that Northern Border file for new rates no later than January 1, 2018.

The Partnership recorded no undistributed earnings from Northern Border for the nine months ended September 30, 2012 and 2011.

The summarized financial information for Northern Border is as follows:

(unaudited)
(millions of dollars)	September 30, 2012			December 31, 2011

ASSETS
Cash and cash equivalents		35			33
Other current assets		36			35
Plant, property and equipment, net		1,237			1,267
Other assets		30			31
		1,338			1,366

Liabilities and Partners’ Equity
Current liabilities		51			48
Deferred credits and other		16			13
Long-term debt, including current maturities		473			473
Partners’ equity
Partners’ capital		801			835
Accumulated other comprehensive loss		(3	)		(3	)
		1,338			1,366

	Three months ended						Nine months ended
(unaudited)	September 30,						September 30,
(millions of dollars)	2012			2011			2012			2011

Transmission revenues		78			77			232			230
Operating expenses		(21	)		(17	)		(57	)		(53	)
Depreciation		(16	)		(15	)		(48	)		(46	)
Financial charges and other		(5	)		(6	)		(18	)		(17	)
Net income		36			39			109			114

GTN

On May 3, 2011, the Partnership acquired a 25 percent interest in GTN from a subsidiary of TransCanada. The acquisition was accounted for as a transaction between entities under common control, whereby the equity investment in GTN was recorded at TransCanada’s carrying value. See Note 4 for additional disclosure regarding the Acquisitions.

In November 2011, the FERC approved a Stipulation and Agreement of Settlement for GTN (GTN Settlement) with shippers and regulators regarding rates and terms and conditions of service without modification, effective January 1, 2012. The GTN Settlement includes a moratorium on the filing of future rate proceedings until December 31, 2015. Following the expiration of the moratorium, GTN must file a rate case such that the new rates will be effective January 1, 2016.

The Partnership recorded no undistributed earnings from GTN for the nine months ended September 30, 2012 and recorded undistributed earnings of $7 million from May 3, 2011, date of acquisition, to September 30, 2011.

The summarized financial information for GTN is as follows:

(unaudited)
(millions of dollars)	September 30, 2012		December 31, 2011

ASSETS
Current assets		62		55
Plant, property and equipment, net		1,174		1,207
Other assets		1		1
		1,237		1,263

Liabilities and Members’ Equity
Current liabilities		17		18
Deferred credits and other		20		20
Long-term debt, including current maturities		325		325
Members’ capital		875		900
		1,237		1,263

	Three months ended						Nine months ended
(unaudited)	September 30,						September 30,
(millions of dollars)	2012			2011(a)			2012			2011(a)

Transmission revenues		47			50			147			83
Operating expenses		(11	)		(14	)		(35	)		(23	)
Depreciation		(14	)		(9	)		(41	)		(15	)
Financial charges and other		(4	)		(4	)		(13	)		(10	)
Net income		18			23			58			35

(a)	25 percent interest in GTN was acquired in May 2011.

Bison

On May 3, 2011, the Partnership acquired a 25 percent interest in Bison from a subsidiary of TransCanada. The acquisition was accounted for as a transaction between entities under common control, whereby the equity investment in Bison was recorded at TransCanada’s carrying value. See Note 4 for additional disclosure regarding the Acquisitions.

The Partnership recorded no undistributed earnings from Bison for the nine months ended September 30, 2012 and recorded undistributed earnings of $4 million from May 3, 2011, date of acquisition, to September 30, 2011.

The summarized financial information for Bison is as follows:

(unaudited)
(millions of dollars)	September 30, 2012		December 31, 2011

ASSETS
Current assets		7		10
Plant, property and equipment, net		650		658
		657		668

Liabilities and Members’ Equity
Current liabilities		20		17
Members’ capital		637		651
		657		668

	Three months ended						Nine months ended
(unaudited)	September 30,						September 30,
(millions of dollars)	2012			2011(a)			2012			2011(a)

Transmission revenues		20			18			60			32
Operating expenses		(4	)		(6	)		(11	)		(9	)
Depreciation		(5	)		(5	)		(15	)		(8	)
Net income		11			7			34			15

(a)	25 percent interest in Bison was acquired in May 2011.

NOTE 4 ACQUISITIONS

GTN and Bison Equity Investment Acquisitions

On May 3, 2011, the Partnership acquired 25 percent interests in each of GTN and Bison from subsidiaries of TransCanada.

The total purchase price of the Acquisitions was $605 million (the Purchase Price). 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 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 TC PipeLines GP, Inc. (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 Acquisitions were accounted for as transactions 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 was recorded as a reduction to Partners’ Equity.

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.

NOTE 5 CREDIT FACILITIES AND LONG-TERM DEBT

(unaudited)
(millions of dollars)	September 30, 2012		December 31, 2011

Senior Credit Facility due 2016		313		363
4.65% Senior Notes due 2021		349		349
6.89% Series C Senior Notes due 2012		3		3
3.82% Series D Senior Notes due 2017		27		27
		692		742
Less: current portion of long-term debt		3		3
		689		739

The Partnership’s Senior Credit Facility consists of a $500 million senior revolving credit facility with a banking syndicate, maturing July 13, 2016, under which $313 million was outstanding at September 30, 2012 (December 31, 2011 - $363 million), leaving $187 million available for future borrowing.

The London Interbank Offered Rate (LIBOR) based interest rate on the Senior Credit Facility averaged 1.62 and 1.63 percent for the three and nine months ended September 30, 2012, respectively. The LIBOR-based interest rate was 1.61 percent at September 30, 2012.

The LIBOR-based interest rate on the Senior Credit Facility averaged 0.9 percent and 0.8 percent for the three and nine months ended September 30, 2011. After hedging activity, the LIBOR-based interest rate incurred on the Senior Credit Facility averaged 3.4 percent and 2.7 percent for the three and nine months ended September 30, 2011. Prior to hedging activities, the LIBOR-based interest rate was 1.1 percent at September 30, 2011.

At September 30, 2012, 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 Partnership Agreement, incurring additional debt and distributions to unitholders.

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

(unaudited)
(millions of dollars)

2012			3
2013			3
2014			4
2015			4
2016			317
Thereafter			361
			692

NOTE 6 NET INCOME PER COMMON UNIT

Net income per common unit is computed by dividing net income, after deduction of the General Partner’s allocation, 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:

	Three months ended						Nine months ended
(unaudited)	September 30,						September 30,
(millions of dollars, except per unit)	2012			2011			2012			2011

Net income (a)		35			41			107			119
Net income allocated to General Partner		(1	)		(1	)		(2	)		(2	)
Net income allocable to common units		34			40			105			117
Weighted average common units outstanding (millions)		53.5			53.5			53.5			50.2
Net income per common unit		$0.64			$0.75			$1.96			$2.33

(a)	25 percent interests in each of GTN and Bison were acquired in May 2011.

NOTE 7 CASH DISTRIBUTIONS

For the three and nine months ended September 30, 2012, the Partnership distributed $0.78 and $2.32 per common unit (2011 – $0.77 and $2.27 per common unit) for a total of $43 million and $127 million (2011 - $42 million and $113 million), respectively. The distributions paid for the three and nine months ended September 30, 2012 and 2011 included no incentive distributions to the General Partner.

NOTE 8 CHANGE IN WORKING CAPITAL

(unaudited)	Nine months ended September 30,
(millions of dollars)	2012		2011

Increase/(decrease) in accounts payable and accrued liabilities		2		(1	)
Increase in accrued interest		5		5
Decrease in operating working capital		7		4

NOTE 9 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 $1 and $2 million for the three and nine months ended September 30, 2012 (2011 – $1 and $2 million) respectively.

As operator, TransCanada’s subsidiaries provide capital and operating services to 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 three and nine months ended September 30, 2012 and 2011 by TransCanada’s subsidiaries and amounts payable/(receivable) to TransCanada’s subsidiaries at September 30, 2012 and December 31, 2011 are summarized in the following tables:

	Three months ended				Nine months ended
(unaudited)	September 30,				September 30,
(millions of dollars)	2012		2011		2012		2011

Capital and operating costs charged by TransCanada’s subsidiaries to:
Great Lakes (a)		8		7		24		22
Northern Border (a)		7		8		22		22
GTN (a) (b)		7		9		21		15
Bison (a) (b)		1		3		4		5
North Baja		1		1		3		3
Tuscarora		1		1		3		3
Impact on the Partnership’s net income:
Great Lakes		4		3		11		10
Northern Border		3		3		10		10
GTN (b)		2		2		5		3
Bison (b)		-		1		1		1
North Baja		1		1		3		2
Tuscarora		1		1		3		3

(a)	Represents 100 percent of the costs.

(b)	25 percent interests in each of GTN and Bison were acquired in May 2011.

(unaudited)
(millions of dollars)	September 30, 2012			December 31, 2011

Amount payable/(receivable) to TransCanada’s subsidiaries for costs charged in the year by:
Great Lakes (a)		3			3
Northern Border (a)		3			3
GTN (a)		3			3
Bison (a)		1			1
North Baja		(1	)		1
Tuscarora		-			1

(a)	Represents 100 percent of the costs.

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 $17 million and $58 million of transportation revenues under these contracts for the three and nine months ended September 30, 2012 (2011 - $17 million and $59 million) respectively. These amounts represent 37 percent and 41 percent of total revenues earned by Great Lakes for the three and nine months ended September 30, 2012 (2011 – 27 percent and 30 percent). Great Lakes also earned $1 million of affiliated rental revenue for the three and nine months ended September 30, 2012 (2011 - $1 million and $1 million).

Revenue from TransCanada and its affiliates of $8 million and $27 million are included in the Partnership’s equity earnings from Great Lakes for the three and nine months ended September 30, 2012 (2011 - $8 million and $28 million). At September 30, 2012, $6 million was included in Great Lakes’ receivables in regards to the transportation contracts with TransCanada and its affiliates (December 31, 2011 - $7 million).

NOTE 10 FINANCIAL INSTRUMENTS

The carrying value of cash and cash equivalents, accounts receivable and other, accounts payable and accrued liabilities, and accrued interest 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 estimated fair values of the Partnership’s and its subsidiary’s long-term debt as of September 30, 2012 is $715 million (December 31, 2011 - $763 million).

The Partnership’s long-term debt results in exposures to changing interest rates. Until December 12, 2011, the Partnership used derivatives to assist in managing its exposure to interest rate risk. For the three and nine months ended September 30, 2012, the Partnership recorded interest expense of nil on interest rate swaps and options (2011 – $4 and $11 million).

NOTE 11 ACCOUNTS RECEIVABLE AND OTHER

(unaudited)
(millions of dollars)	September 30, 2012		December 31, 2011

Accounts receivable		9		8
Inventory		1		1
		10		9

NOTE 12 REGULATORY MATTERS

Tuscarora – On March 9, 2012, Tuscarora received approval from the FERC for the Tuscarora Settlement. The Tuscarora Settlement includes three-year contract extensions to the term of a number of contracts with Tuscarora’s largest customer, provides for new rates effective January 1, 2012, and a moratorium on the filing of future rate proceedings under NGA Sections 4 or 5 until December 31, 2014. Pursuant to the Tuscarora Settlement, Tuscarora has no future obligation to file a Section 4 rate case.

NOTE 13 ACCOUNTING PRONOUNCEMENTS

The Financial Accounting Standards Board (FASB) issued an update to Accounting Standards Codification (ASC) 350 – Intangibles – Goodwill and Other. Adoption of this update has resulted in a change in the accounting policy related to testing goodwill for impairment, as the Partnership is now permitted under U.S. GAAP to first assess qualitative factors affecting the fair value of a reporting unit in comparison to the carrying amount as a basis for determining whether it is required to proceed to the two-step quantitative impairment test. The Partnership adopted this update effective January 1, 2012. The adoption of this update is not expected to have a material impact on our annual goodwill assessment.

NOTE 14 SUBSEQUENT EVENTS

On October 25, 2012, the board of directors of our General Partner declared the Partnership’s third quarter 2012 cash distribution in the amount of $0.78 per common unit payable on November 14, 2012 to unitholders of record as of November 5, 2012.

Great Lakes declared its third quarter 2012 distribution of $21 million on October 23, 2012, of which the Partnership will receive its 46.45 percent share or $10 million on November 1, 2012.

Northern Border declared its third quarter 2012 distribution of $49 million on October 23, 2012, of which the Partnership will receive its 50 percent share or $24 million on November 1, 2012.

GTN declared its third quarter 2012 distribution of $30 million on October 23, 2012, of which the Partnership will receive its 25 percent share or $8 million on November 1, 2012.

Bison declared its third quarter 2012 distribution of $16 million on October 23, 2012, of which the Partnership will receive its 25 percent share or $4 million on November 1, 2012.

On October 29, 2012, the Partnership made an equity contribution to Great Lakes of $5 million. This amount represents the Partnership’s 46.45 percent share of a $10 million cash call from Great Lakes to make a scheduled debt repayment.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with the unaudited financial statements and notes included in Item 1. “Financial Statements” of this Quarterly Report on Form 10-Q as well as our Annual Report on Form 10-K for the year ended December 31, 2011.

RECENT DEVELOPMENTS

On April 24, 2012, the board of directors of our General Partner declared the Partnership’s first quarter 2012 cash distribution in the amount of $0.77 per common unit, payable on May 15, 2012 to unitholders of record as of May 4, 2012.

On July 24, 2012, the board of directors of our General Partner declared the Partnership’s second quarter 2012 cash distribution in the amount of $0.78 per common unit, an increase of $0.01 from the prior quarter, payable on August 14, 2012 to unitholders of record as of August 3, 2012.

On October 25, 2012, the board of directors of our General Partner declared the Partnership’s third quarter 2012 cash distribution in the amount of $0.78 per common unit, payable on November 14, 2012 to unitholders of record as of November 5, 2012.

Consistent with the results we experienced in November and December 2011, during the first quarter of 2012, Great Lakes was unable to market all of its available long-haul capacity, which historically has been fully sold by the first quarter of each year. During the first quarter, an average of 440 thousand dekatherms per day or 28 percent of Great Lakes’ available annual long-haul capacity went unsold. As a result of the unsold winter capacity, Great Lakes’ transmission revenue for the first quarter of 2012 was $21 million lower than the same period in 2011. This resulted in a $9 million reduction to the Partnership’s equity earnings in the first quarter of 2012 compared to the first quarter of 2011.

For the second and third quarters of 2012, Great Lakes’ long-haul capacity was sold mostly under short-term contracts and at lower rates compared to the same periods in 2011 resulting in transmission revenues being $16 million and $17 million lower in the second and third quarter of 2012, respectively. This resulted in a $7 million and $8 million reduction to the Partnership’s equity earnings in the second and third quarters of 2012, respectively, compared to the same period in 2011.

On March 9, 2012, Tuscarora received FERC approval of the Tuscarora Settlement effective January 1, 2012. Compared to 2011, the Tuscarora Settlement is expected to reduce Tuscarora’s cash flows by approximately $6 million in 2012. Net income is expected to be reduced by $3 million as a result of the lower revenue offset by lower depreciation expense.

Northern Border’s long-haul capacity is substantially contracted through March 2014. Northern Border has continued to successfully negotiate contract extensions for expiring capacity in 2012 and 2013 from Canada to Ventura. The majority of these extensions are for terms of three years or longer.

On September 27, 2012, Northern Border filed a petition with the FERC requesting approval of the Northern Border Settlement with its customers to modify its transportation rates. The Northern Border Settlement, if approved, will be effective January 1, 2013 and will eliminate Northern Border’s obligation to otherwise file a Section 4 rate case by December 31, 2012. The Partnership expects the settlement to be approved by the FERC before the end of the year. If approved, the settlement will establish maximum long-term transportation rates on the Northern Border system and current transportation rates will be reduced by approximately 11 percent. In addition, the composite depreciation rate will be reduced to 2.19 percent from 2.40 percent. The settlement includes a three-year moratorium on filing rate cases or challenging the settlement rates and requires that Northern Border file for new rates no later than January 1, 2018.

Customers and Contracting

As of October 1, 2012, the following table provides information with respect to the contract profile of our pipeline systems over the next five years calculated as a percentage of the Partnership’s total proportionate share of 2011 revenue from each of our pipeline systems, being $387 million:

			Future Revenues Underpinned by Long-Term Contracts, as a Percentage of 2011 Total Revenue (a) (b)
	2012		92%
	2013		69%
	2014		61%
	2015		54%
	2016		43%

(a)	Long-term contracts are contracts with terms greater than twelve months.
(b)	Projections are based on rates in effect as of October 1, 2012.

Most contracting on our pipeline systems consist of arrangements where shippers are obligated to pay for their contracted capacity regardless of utilization.

Outlook for Our Business

Prior to November 1, 2011, Great Lakes had historically been substantially contracted for long-term, long-haul capacity. Due to ongoing changes in supply, demand and infrastructure fundamentals across the North American natural gas market and the expiry of certain long-term contracts, the composition of Great Lakes’ revenue continues to shift more toward shorter-term, short-haul and bidirectional transportation. Management expects this trend to continue. As a result, Great Lakes’ transmission revenue for the fourth quarter of 2012 could be significantly lower relative to the same time period of 2011. Currently, 22 percent of Great Lakes’ long-haul capacity available at November 1, 2012 is contracted, although at less than maximum rates. Great Lakes’ ability to sell its available and future capacity will depend on future market conditions which are impacted by a number of factors including weather for winter 2012/2013, levels of natural gas in storage, the price of natural gas liquids and the associated impact to North American natural gas production and the level and certainty of TransCanada’s Mainline tolls. These factors are expected to impact our earnings for 2013. Great Lakes will continue to evaluate market opportunities and develop commercial strategies to capture these opportunities.

Great Lakes operates under a rate settlement approved by the FERC in July 2010 and is required to file a NGA Section 4 general rate case or reach a settlement on or before November 1, 2013.

If approved, the Northern Border Settlement will be effective January 1, 2013 and will reduce the transportation rates charged to certain customers by approximately 11 percent. Based on the current contracted capacity that will be directly impacted by the lower transportation rates and a lower composite depreciation rate, the Partnership’s share of equity earnings in 2013 is expected to be reduced by approximately $10 million and the Partnership’s cash flows in 2013 are expected to be reduced by approximately $10 million, as compared to 2012. Actual results from Northern Border will depend on a number of other factors.

The results from the ownership interests in the other pipelines in our portfolio continue to be relatively consistent year over year reflecting the longer term contract status and recent regulatory settlements.

REGULATORY ENVIRONMENT

FERC Rate Proceedings

Northern Border – On September 27, 2012, Northern Border filed a petition with the FERC requesting approval of the Northern Border Settlement with its customers to modify its transportation rates. If approved by the FERC, Northern Border’s current transportation rates will be reduced by approximately 11 percent effective January 1, 2013. In addition, the composite depreciation rate will be reduced to 2.19 percent from 2.40 percent. The Northern Border Settlement also includes a three-year moratorium on filing rate cases or challenging the Settlement rates, and requires Northern Border to file for new rates no later than January 1, 2018.

HOW WE EVALUATE OUR OPERATIONS

We evaluate our business primarily on the basis of the underlying operating results for each of our pipeline systems, along with a measure of Partnership cash flows. This measure does not have any standardized meaning prescribed by U.S. generally accepted accounting principles (GAAP). It is, therefore, considered to be a non-GAAP measure and is unlikely to be comparable to similar measures presented by other entities. Partnership cash flows include cash distributions from the Partnership’s equity investments in Great Lakes, Northern Border, GTN and Bison plus operating cash flows from the Partnership’s wholly-owned subsidiaries, North Baja and Tuscarora, net of Partnership costs and distributions declared to the General Partner.

RESULTS OF OPERATIONS

Critical Accounting Policies and Estimates

The preparation of financial statements in accordance with GAAP requires us to make estimates and assumptions with respect to values or conditions, which cannot be known with certainty, that affect the reported amount of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements. Such estimates and assumptions also affect the reported amounts of revenue and expenses during the reporting period. Although we believe these estimates and assumptions are reasonable, actual results could differ. There were no significant changes to the Partnership’s critical accounting policies and estimates during the three and nine months ended September 30, 2012.

Information about our critical accounting policies and estimates is included under Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” in our Annual Report on Form 10-K for the year ended December 31, 2011.

Accounting Pronouncements

Effective January 1, 2012, the Partnership adopted Accounting Standards Codification (ASC) 350 – Intangibles – Goodwill and Other on testing goodwill for impairment as issued by the Financial Accounting Standards Board (FASB). Adoption of ASC 350 has resulted in a change in the accounting policy related to testing goodwill for impairment, as the company is now permitted under U.S. GAAP to first assess qualitative factors affecting the fair value of a reporting unit in comparison to the carrying amount as a basis for determining whether it is required to proceed to the two-step quantitative impairment test.

Net Income

To supplement our financial statements, we have presented a comparison of the earnings contribution components from each of our investments. We have presented earnings in this format to enhance investors’ understanding of the way management analyzes our financial performance. We believe this summary provides a more meaningful comparison of our current period earnings to prior year periods, as we account for our partially-owned pipeline systems using the equity method. The presentation of this additional information is not meant to be considered in isolation or as a substitute for results prepared in accordance with GAAP.

	Three months ended						Nine months ended
(unaudited)	September 30,						September 30,
(millions of dollars)	2012			2011			2012			2011

Equity earnings:
Great Lakes		6			14			23			49
Northern Border		18			19			54			56
GTN (a)		5			5			15			7
Bison (a)		2			2			8			4
Net income from Other Pipes (b)		10			11			29			31
Partnership expenses		(6	)		(10	)		(22	)		(28	)
Net income		35			41			107			119

(a)	25 percent interests in each of GTN and Bison were acquired in May 2011.

(b)	“Other Pipes” includes the results of North Baja and Tuscarora.

Third Quarter 2012 Compared with Third Quarter 2011

Net income decreased $6 million to $35 million in the third quarter of 2012 compared to $41 million in the same period in 2011. This decrease was primarily due to lower equity earnings from Great Lakes, partially offset by lower Partnership expenses.

Equity earnings from Great Lakes were $6 million in the third quarter of 2012, a decrease of $8 million compared to $14 million earned in the third quarter of 2011. This decrease was primarily due to lower transportation revenue resulting from previous long-haul capacity being sold for a shorter term at lower rates relative to the same period in 2011.

Expenses at the Partnership level were $6 million for the three months ended September 30, 2012, a decrease of $4 million compared to $10 million for the same period in 2011. This decrease was primarily due to lower average interest rates from the use of floating debt in 2012 instead of fixed debt in 2011.

Nine Months Ended September 30, 2012 Compared with Nine Months ended September 30, 2011

Net income decreased $12 million to $107 million for the nine months ended September 30, 2012 compared to $119 million in the same period in 2011. This decrease was primarily due to lower equity income from Great Lakes, partially offset by earnings from GTN and Bison, which were acquired in May 2011, and lower Partnership expenses.

Equity earnings from Great Lakes was $23 million for the nine months ended September 30, 2012, a decrease of $26 million compared to $49 million for the same period last year. This decrease was primarily due to lower transportation revenue due to unsold long-haul winter capacity in 2012 and summer capacity sold for a shorter term at lower rates in the third quarter of 2012 compared to the same period in 2011.

Expenses at the Partnership level were $22 million for the nine months ended September 30, 2012, a decrease of $6 million compared to $28 million for the same period in 2011. This decrease was primarily due to one time costs incurred relating to the GTN and Bison acquisitions in 2011 and lower financial charges due to the use of floating debt in 2012 instead of fixed debt in 2011.

LIQUIDITY AND CAPITAL RESOURCES

Overview

Our principal sources of liquidity include distributions received from our investments in unconsolidated affiliates, operating cash flows from North Baja and Tuscarora, public offerings of debt and equity and our bank credit facility. The Partnership funds its operating expenses, debt service and cash distributions primarily with operating cash flow. Long-term capital needs may be met through the issuance of long-term debt and/or equity.

Our pipeline systems’ principal sources of liquidity are cash generated from operating activities, long-term debt offerings, bank credit facilities and equity contributions from their owners. Our pipeline systems have historically funded operating expenses, debt service and cash distributions to their owners primarily with operating cash flow. However, in fourth quarter 2010, Great Lakes started funding its debt repayments with cash calls to its owners.

Capital expenditures are funded by a variety of sources, including cash generated from operating activities, borrowings under bank credit facilities, issuance of senior unsecured notes or equity contributions from our pipeline systems’ owners. The ability of our pipeline systems to access the debt capital markets under reasonable terms depends on their financial position and general market conditions.

The Partnership’s pipeline systems monitor the creditworthiness of their customers and have credit provisions included in their tariffs, which allow them to request credit support as circumstances dictate.

We expect to be able to fund our liquidity requirements at the Partnership level over the next twelve months. Our cash flow is based on the distributions from our portfolio of six pipelines. Reduced transportation revenue on Great Lakes could result in lower and more volatile cash flows for Great Lakes than in prior years. The distributions received by the Partnership from Great Lakes could therefore be impacted. We believe that our pipeline systems’ ability to obtain financing at reasonable rates, together with their history of consistent cash flow from operating activities, provide a solid foundation to meet their future liquidity and capital resource requirements.

Partnership Cash Flows

The Partnership uses the non-GAAP financial measures “Partnership cash flows” and “Partnership cash flows before General Partner distributions” as they provide a measure of cash generated during the period to evaluate our cash distribution capability. As well, management uses these measures as a basis for recommendations to our General Partner’s board of directors regarding the distribution amount to be declared each quarter. Partnership cash flow information is presented to enhance investors’ understanding of the way that management analyzes the Partnership’s financial performance.

The Partnership calculates Partnership cash flows as net income plus operating cash flows from the Partnership’s wholly-owned subsidiaries, North Baja and Tuscarora, and cash distributions received in excess of equity earnings from the Partnership’s equity investments, Great Lakes, Northern Border, GTN and Bison, net of distributions declared to the General Partner. Partnership cash flows before General Partner distributions represent Partnership cash flows prior to distributions declared to the General Partner.

Partnership cash flows and Partnership cash flows before General Partner distributions are provided as a supplement to GAAP financial results and are not meant to be considered in isolation or as substitutes for financial results prepared in accordance with GAAP.

Non-GAAP Measures

Reconciliations of Net Income to Partnership Cash Flows

	Three months ended						Nine months ended
(unaudited)	September 30,						September 30,
(millions of dollars except per common unit amounts)	2012			2011			2012			2011
Net income (a)		35			41			107			119
Add:
Cash distributions from Great Lakes (b)		11			18			34			56
Cash distributions from Northern Border (b)		20			21			71			73
Cash distributions from GTN (a) (b)		7			-			21			-
Cash distributions from Bison (a) (b)		4			-			12			-
Cash flows provided by Other Pipes’ operating activities		13			15			37			41
		55			54			175			170

Less:
Equity earnings from unconsolidated affiliates		(31	)		(40	)		(100	)		(116	)
Other Pipes’ net income		(10	)		(11	)		(29	)		(31	)
		(41	)		(51	)		(129	)		(147	)

Partnership cash flows before General Partner distributions		49			44			153			142
General Partner distributions (c)		(1	)		(1	)		(3	)		(3	)

Partnership cash flows		48			43			150			139

Cash distributions declared		(43	)		(42	)		(127	)		(119	)
Cash distributions declared per common unit (d)		$0.78			$0.77			$2.33			$2.29
Cash distributions paid		(43	)		(42	)		(127	)		(113	)
Cash distributions paid per common unit (d)		$0.78			$0.77			$2.32			$2.27

(a)	25 percent interests in each of GTN and Bison were acquired in May 2011, the first distribution was received in the fourth quarter of 2011.

(b)	In accordance with the cash distribution policies of the respective pipeline systems, cash distributions from Great Lakes, Northern Border, GTN and Bison are based on their respective prior quarter financial results.

(c)	General Partner distributions represent the cash distributions declared to the General Partner with respect to its two percent interest plus an amount equal to incentive distributions. Incentive distributions in the first three quarters of 2012 and 2011 were nil.

(d)

Cash distributions declared per common unit and cash distributions paid per common unit are computed by dividing cash distributions, after the deduction of the General Partner's allocation, by the number of common units outstanding. The General Partner's allocation is computed based upon the General Partner's two percent interest plus an amount equal to incentive distributions.

Third Quarter 2012 Compared with Third Quarter 2011

Partnership cash flows increased $5 million to $48 million in the third quarter of 2012 compared to $43 million in the same period of 2011. This increase was primarily due to cash distributions of $11 million from GTN and Bison, which were acquired in May 2011 but did not make a distribution until the fourth quarter of 2011, partially offset by decreased cash distributions from Great Lakes of $7 million.

The Partnership paid distributions of $43 million in the third quarter of 2012, an increase of $1 million compared to the same period in 2011 due to an increase of $0.01 per common unit paid beginning in the third quarter of 2012.

Nine Months Ended September 30, 2012 Compared with Nine Months Ended September 30, 2011

Partnership cash flows increased $11 million to $150 million for the nine months ended September 30, 2012 compared to $139 million in the same period of 2011. This increase was primarily due to cash distributions of $33 million from GTN and Bison, which were acquired in May 2011, partially offset by decreased cash distributions from Great Lakes of $22 million.

The Partnership paid distributions of $127 million in the nine months ended September 30, 2012, an increase of $14 million compared to the same period in 2011 due to an increase in the number of common units outstanding, an increase of $0.02 and $0.01 per common unit paid beginning in the third quarter of 2011 and the third quarter of 2012 respectively.

Other Cash Flows

On March 23, 2012, the Partnership made an equity contribution of $4 million to Great Lakes that was used to fund debt repayments.

On October 29, 2012, the Partnership made an equity contribution of $5 million to Great Lakes that was used to fund debt repayments.

Contractual Obligations

The Partnership’s contractual obligations related to debt as of September 30, 2012 included the following:

	Payments Due by Period
(millions of dollars)	Total	Less than 1 Year	Long-term Portion

Senior Credit Facility due 2016	313	-	313
4.65% Senior Notes due 2021	349	-	349
6.89% Series C Senior Notes due 2012	3	3	-
3.82% Series D Notes due 2017	27	-	27
	692	3	689

The LIBOR-based interest rate on the Senior Credit Facility averaged 1.62 and 1.63 percent for the three and nine months ended September 30, 2012 respectively. The LIBOR-based interest rate was 1.61 percent at September 30, 2012.

The LIBOR-based interest rate on the Senior Credit Facility averaged 0.9 and 0.8 percent for the three and nine months ended September 30, 2011. After hedging activity, the LIBOR-based interest rate incurred on the Senior Credit Facility averaged 3.4 and 2.7 percent for the three and nine months ended September 30, 2011. Prior to hedging activities, the LIBOR-based interest rate was 1.1 percent at September 30, 2011.

Series C and 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.

Great Lakes’ contractual obligations related to debt as of September 30, 2012 included the following:

	Payments Due by Period
(millions of dollars)	Total	Less than 1 Year	Long-term Portion

6.73% series Senior Notes due 2013 to 2018	54	9	45
9.09% series Senior Notes due 2012 and 2021	100	10	90
6.95% series Senior Notes due 2019 and 2028	110	-	110
8.08% series Senior Notes due 2021 and 2030	100	-	100
	364	19	345

Great Lakes is required to comply with certain financial, operational and legal covenants. Under the most restrictive covenants in the Senior Note Agreements, approximately $196 million of Great Lakes’ partners’ capital was restricted as to distributions as of September 30, 2012 (December 31, 2011 – $201 million). Great Lakes was in compliance with all of its financial covenants at September 30, 2012.

Northern Border’s contractual obligations related to debt as of September 30, 2012 included the following:

	Payments Due by Period
(millions of dollars)	Total	Less than 1 Year	Long-term Portion

6.24% Senior Notes due 2016	100	-	100
7.50% Senior Notes due 2021	250	-	250
$200 million Credit Agreement due 2016	123	-	123
	473	-	473

As of September 30, 2012, $123 million was outstanding under its $200 million revolving credit agreement, leaving $77 million available for future borrowings. The weighted average interest rate related to the borrowings on the credit agreement was 1.36 percent as of September 30, 2012. At September 30, 2012, Northern Border was in compliance with all of its financial covenants.

Northern Border has commitments of $3 million as of September 30, 2012 in connection with various overhaul projects and a transformer upgrade.

GTN’s contractual obligations related to debt as of September 30, 2012 included the following:

	Payments Due by Period
(millions of dollars)	Total	Less than 1 Year	Long-term Portion

5.09% Senior Notes due 2015	75	-	75
5.29% Senior Notes due 2020	100	-	100
5.69% Senior Notes due 2035	150	-	150
	325	-	325

The 2005 Note Purchase Agreement contains a covenant that limits total debt to no greater than 70 percent of total capitalization. At September 30, 2012, the total debt to total capitalization ratio was 40 percent.

GTN was in compliance with all terms and conditions of all its credit and other debt agreements at September 30, 2012.

Bison had commitments of $6 million as of September 30, 2012 in connection with reclamation and restoration work associated with the construction of the pipeline.

Capital Requirements

The Partnership made an equity contribution to Great Lakes of $4 million in the first quarter of 2012. This amount represents the Partnership’s 46.45 percent share of a $9 million cash call from Great Lakes to make a scheduled debt repayment. On October 29, 2012 the Partnership made an additional equity contribution to Great Lakes of $5 million. This amount represents the Partnership’s 46.45 percent share of a $10 million cash call from Great Lakes to make a scheduled debt repayment.

To the extent the Partnership has any additional capital requirements with respect to our pipeline systems or acquisitions in the future; we expect to fund these requirements with operating cash flows, debt and/or equity.

2012 Third Quarter Cash Distribution

RELATED PARTY TRANSACTIONS

Please read Note 9 within Item 1. “Financial Statements” for information regarding related party transactions.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

OVERVIEW

The Partnership and our pipeline systems are also exposed to other risks such as interest rate, credit, liquidity and foreign exchange risks. Our exposure to market risk discussed below includes forward-looking statements and is not necessarily indicative of actual results, which may not represent the maximum possible gains and losses that may occur, since actual gains and losses will differ from those estimated, based on actual market conditions.

Market risk is the risk of loss arising from adverse changes in market rates. Our primary risk management objective is to protect earnings and cash flow, and ultimately, unitholder value. We do not use financial instruments for trading purposes.

We record derivative financial instruments on the balance sheet as assets and liabilities at fair value. We estimate the fair value of derivative financial instruments using available market information and appropriate valuation techniques. Changes in the fair value of derivative financial instruments are recognized in earnings unless the instrument qualifies as a hedge and meets specific hedge accounting criteria. Qualifying derivative financial instruments’ gains and losses may offset the hedged items’ related results in earnings for a fair value hedge or be deferred in accumulated other comprehensive income for a cash flow hedge.

MARKET RISK AND INTEREST RATE RISK

From time to time, and in order to finance our business and that of our pipeline systems, the Partnership and our pipeline systems issue debt to invest in growth opportunities and provide for ongoing operations. The issuance of debt exposes the Partnership and our pipeline systems to market risk from changes in interest rates which affect earnings and the value of the financial instruments we hold.

The Partnership and our pipeline systems use derivatives as part of our overall risk management policy to manage exposures to market risk resulting from these activities within established policies and procedures. Derivative contracts used to manage market risk generally consist of the following:

·	Swaps – contractual agreements between two parties to exchange streams of payments over time according to specified terms. The Partnership and our pipeline systems enter into interest rate swaps to mitigate the impact of changes in interest rates.

Options – contractual agreements to convey the right, but not the obligation, for the purchaser to buy or sell a specific amount of a financial instrument at a fixed price, either at a fixed date or at any time within a specified period. The Partnership and our pipeline systems enter into option agreements to mitigate the impact of changes in interest rates.

Interest rate risk is created by fluctuations in the fair values or cash flows of financial instruments due to changes in the market interest rates. Our interest rate exposure results from our Senior Credit Facility, which is subject to variability in LIBOR interest rates. We regularly assess the impact of interest rate fluctuations on future cash flows and evaluate hedging opportunities to mitigate our interest rate risk.

Until December 12, 2011, the Partnership used derivatives to assist in managing its exposure to interest rate risk. In the three and nine months ended September 30, 2012, the Partnership recorded interest expense of nil on the interest rate swaps and options (2011 – $4 and 11 million).

At September 30, 2012, we had $313 million (December 31, 2011 – $363 million) outstanding on our Senior Credit Facility. If LIBOR interest rates hypothetically increased by one percent (100 basis points) compared to the rates in effect at September 30, 2012, our annual interest expense would increase and our net income would decrease by $3 million; and if LIBOR interest rates hypothetically decreased by one percent compared to the rates in effect at September 30, 2012, our annual interest expense would decrease and our net income would increase by $3 million.

Northern Border utilizes both fixed-rate and variable-rate debt and is exposed to market risk due to the floating interest rates on its revolving credit facility. Northern Border regularly assesses the impact of interest rate fluctuations on future cash flows and evaluates hedging opportunities to mitigate its interest rate risk. As of September 30, 2012, 74 percent of Northern Border’s outstanding debt was at fixed rates (December 31, 2011 – 74 percent).

If interest rates hypothetically increased by one percent (100 basis points) compared with rates in effect at September 30, 2012, Northern Border’s annual interest expense would increase and its net income would decrease by approximately $1 million; and if interest rates hypothetically decreased by one percent compared with rates in effect at September 30, 2012, Northern Border’s annual interest expense would decrease and its net income would increase by approximately $1 million.

Great Lakes, GTN and Tuscarora utilize fixed-rate debt; therefore, they are not exposed to market risk due to floating interest rates. Interest rate risk does not apply to Bison and North Baja, as they currently do not have any debt.

OTHER RISKS

The Partnership is influenced by the same factors that influence our pipeline systems. None of our pipeline systems own any of the natural gas they transport; therefore, they do not assume any of the related natural gas commodity price risk with respect to transported natural gas volumes.

Counterparty credit risk represents the financial loss that the Partnership and our pipeline systems would experience if a counterparty to a financial instrument failed to meet its obligations in accordance with the terms and conditions of its contracts with the Partnership or its pipeline systems. 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. At September 30, 2012, the Partnership’s maximum counterparty credit exposure consisted of accounts receivable of $9 million (December 31, 2011 – $8 million).

The Partnership and our pipeline systems have significant credit exposure to financial institutions as they provide committed credit lines and critical liquidity in the interest rate derivative market, as well as letters of credit to mitigate exposures to non-creditworthy parties. Due to the lingering effects of the deterioration of global financial markets in the past few years, we continue to closely monitor the creditworthiness of our counterparties, including financial institutions. Overall, we do not believe the Partnership and our pipeline systems have any significant concentrations of counterparty credit risk.

Liquidity risk is the risk that the Partnership and our pipeline systems will not be able to meet our financial obligations as they become due. Our approach to managing liquidity risk is to ensure that we always have sufficient cash and credit facilities to meet our obligations when due, under both normal and stressed conditions, without incurring unacceptable losses or damage to our reputation. At September 30, 2012, the Partnership had a committed revolving bank line of $500 million maturing in 2016 with an outstanding balance of $313 million. In addition, at September 30, 2012, Northern Border had a committed revolving bank line of $200 million maturing in 2016 of which $123 million was drawn.

The Partnership does not have any material foreign exchange risks.

Item 4. Controls and Procedures

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

As required by Rule 13a-15(e) under the Exchange Act, the management of our General Partner, including the principal executive officer and principal financial officer, evaluated as of the end of the period covered by this report the effectiveness of our disclosure controls and procedures. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. The Partnership’s disclosure controls and procedures are designed to provide reasonable assurance of achieving their objectives. Based upon and as of the date of the evaluation, the management of our General Partner, including the principal executive officer and principal financial officer, concluded that the Partnership’s disclosure controls and procedures as of the end of the period covered by this quarterly report were effective to provide reasonable assurance that the information required to be disclosed by the Partnership in the reports that it files or submits under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is (a) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and (b) accumulated and communicated to the management of our General Partner, including the principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

During the three months ended September 30, 2012, there was no change in the Partnership’s internal control over financial reporting that has materially affected or is reasonably likely to materially affect our internal control over financial reporting.

PART II – OTHER INFORMATION

Item 1. Legal Proceedings

In August 2012, pursuant to a confidential settlement agreement, GTN and North Baja settled their arbitration claims against Rolls Royce Energy Systems, Inc. GTN is not entitled to any portion of the settlement due to the assignment of its rights to an affiliate. The impact of the settlement to the Partnership is immaterial.

For additional information on other legal and environmental proceedings affecting the Partnership, please refer to Part 1. Item 3 of the Partnership’s Annual Report on Form 10-K for the year-ended December 31, 2011.

In addition to the above written matters, we and our pipeline systems are parties to lawsuits and governmental proceedings that arise in the ordinary course of our business.

Item 1A. Risk Factors

The following updated risk factors should be read in conjunction with the risk factors disclosed in Part I, Item 1A. “Risk Factors,” in our Annual Report on Form 10-K for the year ended December 31, 2011.

Our business could be negatively impacted by security threats, including cyber security threats, and related disruptions.

We depend on the secure operation of our information technology to process, transmit and store electronic information, including information we use to safely operate our pipeline systems. Security breaches could expose our business to a risk of loss, misuse or interruption of critical information and functions that affect the pipeline operations. Such losses could result in operational impacts, damage to our assets, safety incidents, damage to the environment, reputational harm, competitive disadvantage, regulatory enforcement actions, potential litigation and a material adverse effect on our operations, financial position and results of operations.

Item 6. Exhibits

No.	Description

31.1	Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification of Principal Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	Certification of Principal Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS	XBRL Instance Document.
101.SCH	XBRL Taxonomy Extension Schema Document.
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF	XBRL Taxonomy Definition Linkbase Document.
101.LAB	XBRL Taxonomy Extension Label Linkbase Document.
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on this 30th day of October 2012.

TC PIPELINES, LP

(A Delaware Limited Partnership)

by its General Partner, TC PipeLines GP, Inc.

By: /s/ Steven D. Becker

______________________________

Steven D. Becker

President

TC PipeLines GP, Inc. (Principal Executive Officer)

By: /s/ Sandra P. Ryan-Robinson

______________________________

Sandra P. Ryan-Robinson

Controller

TC PipeLines GP, Inc. (Principal Financial Officer)

EXHIBIT INDEX

No.	Description

31.1	Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification of Principal Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	Certification of Principal Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS	XBRL Instance Document.
101.SCH	XBRL Taxonomy Extension Schema Document.
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF	XBRL Taxonomy Definition Linkbase Document.
101.LAB	XBRL Taxonomy Extension Label Linkbase Document.
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document.