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 periodended
September 30, 2009
  or
  [  ]
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:  000-26091
 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)
 
 13710
      FNB ParkwayOmaha,
      Nebraska
                
                68154-5200(Address
      of principal executive offices)
                
                (Zip
      code)
   877-290-2772(Registrant's
      telephone number, including area code)
   Indicate
by check mark if 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
[   ]                      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
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
November 6, 2009, there were 41,227,766of
the registrant's common units outstanding.





TC
PIPELINES, LP


Page No.


TABLE
OF CONTENTS


PART I
            FINANCIAL
      INFORMATION
            3GlossaryItem
      1.
            Financial
      StatementsConsolidated Statement of Income – Three and nine
      months ended September 30, 2009and 2008
            4Consolidated Statement of Comprehensive Income –
      Three and nine months endedSeptember 30, 2009 and
2008
            4Consolidated Balance Sheet – September 30, 2009
      and December 31, 2008
            5Consolidated Statement of Cash Flows – Nine months
      ended September 30, 2009 and2008
            6Consolidated
      Statement of Changes in Partners’ Equity – Nine months ended September
      30, 2009
            7Notes to Consolidated Financial
      Statements
            8Item
    2.
            Management’s
      Discussion and Analysis of Financial Condition and Results of Operations
            16Results of Operations of TC
    PipeLines
            23Liquidity and Capital Resources of TC
      PipeLines
            29Liquidity and Capital Resources of Our Pipeline
      Systems
            30Item
    3.
            Quantitative
      and Qualitative Disclosures About Market Risk
            33Item
    4.
            Controls and
      Procedures
            35PART II
            OTHER
    INFORMATIONItem
    1A.
            Risk
      Factors
            36Item
    6.
            Exhibits
            38All amounts are stated in
      United States dollars unless otherwise indicated.







2


Glossary


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




Acquisition
              The acquisition of
      100 per cent of North Baja by the PartnershipASC
              Accounting Standards
      CodificationBison
              Bison Pipeline
      LLCBcf/d
              Billion cubic feet
      per dayCollar
      Agreement
              Northern Border's
      interest rate collar agreementEPA
              U.S. Environmental
      Protection AgencyExchange
      Agreement
              Agreement
      with the general partner pursuant to which the Partnership issued new
      common units to the general partner and provided for Revised IDRs in
      exchange for the cancellation of the Old IDRsFASB
              Financial Accounting
      Standards BoardFERC
              Federal Energy
      Regulatory CommissionGAAP
              U.S. generally
      accepted accounting principlesGeneral
      partner
              TC PipeLines GP,
      Inc.GLGT
              Great Lakes Gas
      Transmission Limited PartnershipGreat
Lakes
              Great Lakes Gas
      Transmission Limited PartnershipIDRs
              Incentive
      Distribution RightsKeystone
              TransCanada Keystone
      Pipeline LPLIBOR
              London Interbank
      Offered RateMDth/d
              Thousand dekatherms
      per dayMMcf/d
              Million cubic feet
      per dayNBPC
              Northern Border
      Pipeline CompanyNet
      WCSB Flows to Markets
              Net
      of the supply of and demand for WCSB natural gas that is available for
      transportation to downstream markets; where supply represents WCSB
      production adjusted for injections into and withdrawals from WCSB
      storageNorth Baja
              North Baja Pipeline,
      LLCNorthern
      Border
              Northern Border
      Pipeline CompanyNOV
              Notice of
      ViolationOffering
              The
      sale of 2,609,680 newly issued, unregistered common units representing
      limited partner interests in the Partnership to TransCan Northern at a
      price per common unit of $30.042 for an aggregate amount of approximately
      $78.4 millionOld
      IDRs
              IDRs
      available to the general partner under the Amended and Restated Agreement
      of Limited PartnershipOther
Pipes
              North
      Baja and TuscaroraOur
      pipeline systems
              Great
      Lakes, Northern Border, North Baja and TuscaroraPartnership
              TC PipeLines, LP and
      its subsidiariesPipeLP
              TC PipeLines, LP and
      its subsidiariesPurchase
      Agreement
              Common Unit Purchase
      Agreement with TransCan Northern in connection with the
  OfferingRevised
      IDRs
              IDRs
      available to the general partner under the Second Amended and Restated
      Agreement of Limited PartnershipREX East
              Eastern segment of
      the Rockies Express PipelineREX West
              Western segment of
      the Rockies Express PipelineSenior Credit
      Facility
              TC PipeLines'
      revolving credit and term loan agreementTC
    PipeLines
              TC PipeLines, LP and
      its subsidiariesTransCan
      Northern
              TransCan Northern
      Ltd.TransCanada
              TransCanada
      Corporation and its subsidiariesTuscarora
              Tuscarora Gas
      Transmission CompanyU.S.
              United States of
      AmericaWCSB
              Western Canada
      Sedimentary Basin







3


PART
I – FINANCIAL INFORMATION




Item
1.                  Financial
Statements




TC
PipeLines, LP


Consolidated
Statement of Income




(unaudited)
              
              Three
      months ended
                September
      30,
              
              Nine
      months ended
                September
      30,(millions
      of dollars except per common unit amounts)
              
              2009
              
              2008(a)
              
              2009(a)
              
              2008(a)Equity
      income from investment in Great Lakes (Note 2)
              
              
              13.2
              
              
              
              12.0
              
              
              
              45.6
              
              
              
              44.4Equity
      income from investment in Northern Border (Note 3)
              
              
              10.5
              
              
              
              19.9
              
              
              
              31.5
              
              
              
              48.1Transmission
      revenues
              
              
              17.5
              
              
              
              17.4
              
              
              
              51.1
              
              
              
              47.6Operating
      expenses
              
              
              (3.5
              )
              
              
              (3.7
              )
              
              
              (13.3
              )
              
              
              (10.2
              )Depreciation
              
              
              (3.7
              )
              
              
              (3.6
              )
              
              
              (11.0
              )
              
              
              (10.2
              )Financial
      charges, net and other
              
              
              (6.6
              )
              
              
              (9.0
              )
              
              
              (22.7
              )
              
              
              (25.8
              )Net
      income
              
              
              27.4
              
              
              
              33.0
              
              
              
              81.2
              
              
              
              93.9Net
      income allocation (Note 6)Common
      units
              
              
              26.8
              
              
              
              25.1
              
              
              
              66.1
              
              
              
              71.7General
      partner
              
              
              0.6
              
              
              
              3.2
              
              
              
              6.8
              
              
              
              9.427.4
              
              
              
              28.3
              
              
              
              72.9
              
              
              
              81.1Net
      income per common unit (Note 6)
              
              $
              0.65
              
              
              $
              0.72
              
              
              $
              1.78
              
              
              $
              2.06Weighted average common units
      outstanding(millions)
              
              
              41.2
              
              
              
              34.9
              
              
              
              37.0
              
              
              
              34.9Common units outstanding, end
      of the period(millions)
              
              
              41.2
              
              
              
              34.9
              
              
              
              41.2
              
              
              
              34.9




Consolidated
Statement of Comprehensive Income


(unaudited)
                
                Three
      months ended
                  September
      30,
                
                Nine
      months ended
                  September
      30,(millions
      of dollars)
                
                2009
                
                2008(a)
                
                2009(a)
                
                2008(a)Net
      income
                
                
                27.4
                
                
                
                33.0
                
                
                
                81.2
                
                
                
                93.9Other
      comprehensive income/(loss)Change
      associated with hedging transactions (Note 9)
                
                
                (0.1
                )
                
                
                (1.3
                )
                
                
                6.3
                
                
                
                (1.7
                )Change
      associated with hedging transactions of investees
                
                
                0.9
                
                
                
                -
                
                
                
                1.1
                
                
                
                (0.7
                )0.8
                
                
                
                (1.3
                )
                
                
                7.4
                
                
                
                (2.4
                )Total
      comprehensive income
                
                
                28.2
                
                
                
                31.7
                
                
                
                88.6
                
                
                
                91.5
  (a)Recast as discussed in Note 1 and Note
    4.The
      accompanying notes are an integral part of these consolidated financial
      statements.
  4


TC
PipeLines, LP


Consolidated
Balance Sheet


(unaudited)
                
                September 30,
                
                December
      31,(millions
      of dollars)
                
                2009
                
                2008(a)ASSETSCurrent
      AssetsCash
      and cash equivalents
                
                
                5.2
                
                
                
                8.4Accounts
      receivable and other
                
                
                6.8
                
                
                
                11.412.0
                
                
                
                19.8Investment
      in Great Lakes (Note 2)
                
                
                696.2
                
                
                
                704.5Investment
      in Northern Border (Note 3)
                
                
                531.2
                
                
                
                514.8Plant,
      property and equipment (net of $110.2 accumulated depreciation, 2008 -
      $103.6)
                
                
                321.4
                
                
                
                330.3Goodwill
                
                
                130.2
                
                
                
                130.2Other
      assets
                
                
                1.2
                
                
                
                1.51,692.2
                
                
                
                1,701.1LIABILITIES
      AND PARTNERS' EQUITYCurrent
      LiabilitiesAccounts
      payable
                
                
                4.3
                
                
                
                5.3Accrued
      interest
                
                
                2.4
                
                
                
                3.7Current
      portion of long-term debt (Note 5)
                
                
                4.4
                
                
                
                4.4Current
      portion of fair value of derivative contracts (Note 9)
                
                
                12.1
                
                
                
                11.823.2
                
                
                
                25.2Fair
      value of derivative contracts and other (Note 9)
                
                
                14.0
                
                
                
                20.4Long-term
      debt (Note 5)
                
                
                733.1
                
                
                
                532.4770.3
                
                
                
                578.0Due
      to North Baja's former parent
                
                
                -
                
                
                
                247.5Partners'
      EquityCommon
      units
                
                
                929.5
                
                
                
                891.4General
      partner
                
                
                19.9
                
                
                
                19.1Accumulated
      other comprehensive loss
                
                
                (27.5
                )
                
                
                (34.9
                )921.9
                
                
                
                875.61,692.2
                
                
                
                1,701.1
  (a)Recast as discussed in Note 1 and Note 4.Subsequent
      events (Note 12)The
      accompanying notes are an integral part of these consolidated financial
      statements.
   5


TC
PipeLines, LP


Consolidated
Statement of Cash Flows





(unaudited)
                
                Nine
      months ended September 30,(millions
      of dollars)
                
                2009(a)
                
                2008(a)CASH
      GENERATED FROM OPERATIONSNet
      income
                
                
                81.2
                
                
                
                93.9Depreciation
                
                
                11.0
                
                
                
                10.2Amortization
      of other assets
                
                
                0.3
                
                
                
                0.4Increase
      in long-term liabilities
                
                
                0.2
                
                
                
                0.1Equity
      allowance for funds used during construction
                
                
                (0.1
                )
                
                
                (1.0
                )Increase/(decrease)
      in operating working capital (Note 10)
                
                
                2.3
                
                
                
                (3.3
                )94.9
                
                
                
                100.3INVESTING
      ACTIVITIESCumulative
      distributions in excess of equity earnings:Great
      Lakes
                
                
                8.4
                
                
                
                10.6Northern
      Border
                
                
                27.0
                
                
                
                23.9Investment
      in Great Lakes
                
                
                (0.1
                )
                
                
                -Investment
      in Northern Border (Note 3)
                
                
                (42.3
                )
                
                
                -Investment
      in North Baja, net of cash acquired (Note 4)
                
                
                (271.3
                )
                
                
                -Capital
      expenditures
                
                
                (2.1
                )
                
                
                (31.8
                )Increase
      in investing working capital (Note 10)
                
                
                -
                
                
                
                (2.8
                )(280.4
                )
                
                
                (0.1
                )FINANCING
      ACTIVITIESDistributions
      paid (Note 7)
                
                
                (86.3
                )
                
                
                (80.8
                )Equity
      issuances, net
                
                
                80.0
                
                
                
                -Long-term
      debt issued (Note 5)
                
                
                208.0
                
                
                
                4.0Long-term
      debt repaid (Note 5)
                
                
                (7.3
                )
                
                
                (31.3
                )Due
      to North Baja's former parent
                
                
                (12.1
                )
                
                
                11.4182.3
                
                
                
                (96.7
                )(Decrease)/increase
      in cash and cash equivalents
                
                
                (3.2
                )
                
                
                3.5Cash
      and cash equivalents, beginning of period
                
                
                8.4
                
                
                
                7.5Cash
      and cash equivalents, end of period
                
                
                5.2
                
                
                
                11.0Interest
      payments made
                
                
                13.2
                
                
                
                22.8
  (a)Recast as discussed in Note 1 and Note 4.The
      accompanying notes are an integral part of these consolidated financial
      statements.
   6


TC
PipeLines, LP


Consolidated
Statement of Changes in Partners’ Equity





(unaudited)
                  
                  Common
      Units
                  
                  
                  General
                    Partner
                  
                  Accumulated
                    Other
                    Comprehensive
      (Loss)/Income(a)
                  
                  Partners'
      Equity(millions
                  
                  (millions
                  
                  (millions
                  
                  (millions
                  
                  
                  (millions
                  
                  (millionsof
      units)
                  
                  of
      dollars)
                  
                  of
      dollars)
                  
                  of
      dollars)
                  
                  
                  of
      units)
                  
                  of
      dollars)Partners'
      equity at December 31, 2008
                  
                  
                  34.9
                  
                  
                  
                  891.4
                  
                  
                  
                  19.1
                  
                  
                  
                  (34.9
                  )
                  
                  
                  34.9
                  
                  
                  
                  875.6Net
      income(b)
                  
                  
                  -
                  
                  
                  
                  74.3
                  
                  
                  
                  6.9
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  81.2Equity
      issuance
                  
                  
                  6.3
                  
                  
                  
                  78.4
                  
                  
                  
                  1.6
                  
                  
                  
                  -
                  
                  
                  
                  6.3
                  
                  
                  
                  80.0Distributions
      paid
                  
                  
                  -
                  
                  
                  
                  (79.3
                  )
                  
                  
                  (7.0
                  )
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  (86.3
                  )Excess
      purchase price over net acquired assets(c)
                  
                  
                  -
                  
                  
                  
                  (35.3
                  )
                  
                  
                  (0.7
                  )
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  (36.0
                  )Other
      comprehensive income
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  7.4
                  
                  
                  
                  -
                  
                  
                  
                  7.4Partners'
      equity at September 30, 2009
                  
                  
                  41.2
                  
                  
                  
                  929.5
                  
                  
                  
                  19.9
                  
                  
                  
                  (27.5
                  )
                  
                  
                  41.2
                  
                  
                  
                  921.9
  (a)
      TC PipeLines, LP uses derivatives to assist in managing its exposure to
      interest rate risk. Based on interest rates at September 30, 2009, the
      amount of losses related to cash flow hedges reported in accumulated other
      comprehensive income that will be reclassified to net income in the next
      12 months is $12.1 million, which will be offset by a reduction to
      interest expense of a similar amount.(b)
      Recast as discussed in Note 1 and Note 4.(c)Accounting
      adjustment for common control transaction. See Note 4 for
      details.The
      accompanying notes are an integral part of these consolidated financial
      statements.





7


TC
PipeLines, LP


Notes
to Consolidated Financial Statements




Note 1
              Organization and Significant
      Accounting Policies
 TC
PipeLines, LP and its subsidiaries are collectively referred to herein as “TC
PipeLines” or “the Partnership”. In this report, references to “we”, “us” or
“our” refer to TC PipeLines or the Partnership.




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 at 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 interim periods presented.




The
results of operations for the three and nine months ended September 30, 2009 and
2008 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, 2008. 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, 2008. Certain comparative figures have been reclassified to conform
to the current period’s presentation.




On July
1, 2009, the Partnership acquired a 100 per cent interest in North Baja
Pipeline, LLC (North Baja) from a wholly-owned subsidiary of TransCanada
Corporation. TransCanada Corporation and its subsidiaries are herein
collectively referred to as “TransCanada”. Because North Baja was acquired from
TransCanada, the acquisition was accounted for as a transaction between entities
under common control, similar to a pooling of interests, whereby the assets and
liabilities of North Baja were recorded at TransCanada’s carrying value and the
Partnership’s historical financial information was recast to include the
acquired entity for all periods presented. Refer to Note 4 for additional
disclosure regarding the North Baja acquisition.




Note 2
              Investment in Great
      Lakes We own a
46.45 per cent general partner interest in Great Lakes Gas Transmission Limited
Partnership (Great Lakes). Great Lakes is regulated by the Federal Energy
Regulatory Commission (FERC) and is operated by TransCanada.




We use
the equity method of accounting for our interest in Great Lakes. Great Lakes had
no undistributed earnings for the nine months ended September 30, 2009 and
2008.




The
following tables contain summarized financial information of Great
Lakes:




Summarized
      Consolidated Great Lakes Income Statement
              
              Three
      months ended
              
              Nine
      months ended(unaudited)
              
              September 30,
              
              September
      30,(millions
      of dollars)
              
              2009
              
              2008
              
              2009
              
              2008Transmission
      revenues
              
              
              68.9
              
              
              
              66.7
              
              
              
              220.4
              
              
              
              213.9Operating
      expenses
              
              
              (16.5
              )
              
              
              (17.1
              )
              
              
              (49.6
              )
              
              
              (45.9
              )Depreciation
              
              
              (14.7
              )
              
              
              (14.7
              )
              
              
              (43.9
              )
              
              
              (43.9
              )Financial
      charges, net and other
              
              
              (8.1
              )
              
              
              (8.0
              )
              
              
              (24.4
              )
              
              
              (24.4
              )Michigan
      business tax
              
              
              (1.3
              )
              
              
              (1.2
              )
              
              
              (4.4
              )
              
              
              (4.2
              )Net
      income
              
              
              28.3
              
              
              
              25.7
              
              
              
              98.1
              
              
              
              95.5


8




Summarized
      Consolidated Great Lakes Balance Sheet(unaudited)
              
              September
      30,
              
              December
      31,(millions
      of dollars)
              
              2009
              
              2008AssetsCash
      and cash equivalents
              
              
              -
              
              
              
              1.6Other
      current assets
              
              
              90.1
              
              
              
              80.2Plant,
      property and equipment, net
              
              
              884.6
              
              
              
              923.4974.7
              
              
              
              1,005.2Liabilities
      and Partners' EquityCurrent
      liabilities
              
              
              38.4
              
              
              
              43.0Deferred
      credits
              
              
              3.4
              
              
              
              2.3Long-term
      debt, including current maturities
              
              
              421.0
              
              
              
              430.0Partners'
      capital
              
              
              511.9
              
              
              
              529.9974.7
              
              
              
              1,005.2


Note 3
              Investment in Northern
      Border We own a
50 per cent general partner interest in Northern Border Pipeline Company
(Northern Border). Northern Border is regulated by the FERC and is operated by
TransCanada.




We use
the equity method of accounting for our interest in Northern Border. Northern
Border had no undistributed earnings for the nine months ended September 30,
2009 and 2008.




Northern
Border received equity contributions totaling $84.6 million during the nine
months ended September 30, 2009 to complete the Des Plaines project and to
partially fund $200.0 million of debt which matured on September 1, 2009. The
Partnership’s share of this equity contribution was $42.3 million.




The
following tables contain summarized financial information of Northern
Border:




Summarized Northern Border
      Income Statement
              
              Three
      months ended
              
              Nine
      months ended(unaudited)
              
              September
      30,
              
              September
      30,(millions
      of dollars)
              
              2009
              
              2008
              
              2009
              
              2008Transmission
      revenues
              
              
              65.2
              
              
              
              67.7
              
              
              
              193.9
              
              
              
              212.8Operating
      expenses
              
              
              (19.0
              )
              
              
              (19.3
              )
              
              
              (55.8
              )
              
              
              (57.5
              )Depreciation
              
              
              (15.6
              )
              
              
              (15.3
              )
              
              
              (46.4
              )
              
              
              (45.8
              )Financial
      charges, net and other
              
              
              (9.1
              )
              
              
              7.1
              
              
              
              (27.4
              )
              
              
              (12.1
              )Net
      income
              
              
              21.5
              
              
              
              40.2
              
              
              
              64.3
              
              
              
              97.4




9




Summarized
      Northern Border Balance Sheet(unaudited)
              
              September
      30,
              
              December
      31,(millions
      of dollars)
              
              2009
              
              2008AssetsCash
      and cash equivalents
              
              
              18.4
              
              
              
              21.6Other
      current assets
              
              
              28.5
              
              
              
              39.1Plant,
      property and equipment, net
              
              
              1,356.4
              
              
              
              1,390.8Other
      assets
              
              
              25.5
              
              
              
              24.51,428.8
              
              
              
              1,476.0Liabilities
      and Partners' EquityCurrent
      liabilities
              
              
              42.7
              
              
              
              48.7Deferred
      credits and other
              
              
              8.0
              
              
              
              11.2Long-term
      debt, including current maturities
              
              
              558.5
              
              
              
              630.4Partners'
      equityPartners'
      capital
              
              
              823.1
              
              
              
              791.4Accumulated
      other comprehensive loss
              
              
              (3.5
              )
              
              
              (5.7
              )1,428.8
              
              
              
              1,476.0


Note 4
              Acquisition & Revised
      Incentive Distribution Rights On July
1, 2009, the Partnership acquired a 100 per cent interest in North Baja, a
Delaware limited liability company, from TransCanada. The North Baja pipeline
system extends from an interconnection with El Paso Natural Gas Company near
Ehrenberg, Arizona to a point near Ogilby, California on the California/Mexico
border where it connects with the Gasoducto Bajanorte natural gas pipeline
system which is owned by Sempra Energy International. North Baja is regulated by
the FERC and is operated by TransCanada.




The
initial purchase price of $271.3 million was financed through a combination of
(i) a draw of $170.0 million on the Partnership’s $250.0 million revolving
portion of its revolving credit and term loan agreement (Senior Credit
Facility), (ii) issuance of 2,609,680 common units at $30.042 per common unit to
TransCan Northern Ltd., a wholly-owned subsidiary of TransCanada, for gross
proceeds of $78.4 million, (iii) issuance of additional general partner interest
to the general partner of $1.6 million, which was required to maintain the
general partner’s two per cent general partner interest in the Partnership, and
(iv) approximately $21.3 million of cash on hand.




The
acquisition of North Baja was accounted for as a transaction between entities
under common control, similar to a pooling of interests, whereby the assets and
liabilities of North Baja were recorded at TransCanada’s carrying value and the
Partnership’s historical financial information was recast to include the
acquired entity for all periods presented. As the fair market value paid for
North Baja was greater than the recorded net assets of North Baja, the excess
purchase price paid was recorded as a reduction to Partners’ Equity. The effect
of recasting the Partnership’s consolidated financial statements to account for
the common control transaction increased the Partnership’s net income by
$4.7 million and $12.8 million for the three and nine months ended
September 30, 2008, respectively, from amounts previously reported. In
addition, the Partnership’s net income increased by $8.3 million for the six
months ended June 30, 2009 from amounts previously reported.




In
connection with the acquisition, if TransCanada completes an expansion of the
North Baja pipeline from the Mexico/Arizona border to Yuma City, Arizona by June
30, 2010, the Partnership will pay TransCanada up to an additional $10.0 million
for the expansion, which amount shall be determined using a formula that is
based on transportation service agreements to be entered into in connection with
the expansion. This acquisition will be accounted for if and when the
transaction occurs.




Concurrent
with the acquisition of North Baja, the Partnership entered into an exchange
agreement (Exchange Agreement) with its general partner pursuant to which the
Partnership issued 3,762,000 new common units to the general partner and
provided for revised incentive distribution rights (Revised IDRs) in exchange
for the cancellation of the incentive distribution rights available to the
general partner (Old IDRs) under the Amended and Restated Agreement of Limited
Partnership of the Partnership.






10




The
Revised IDRs reset the incentive distribution rights (IDRs) to two per cent,
down from the incentive distribution levels of the Old IDRs at 50 per
cent. The incentive distribution levels of the Revised IDRs increase to 15
per cent and 25 per cent when quarterly distributions increase to $0.81 and
$0.88 per common unit or $3.24 and $3.52 per common unit on an annualized basis,
respectively.




Note 5
            Credit Facility and Long-Term
      Debt





(unaudited)
              
              September
      30,
              
              December
      31,(millions
      of dollars)
              
              2009
              
              2008Senior
      Credit Facility due 2011
              
              
              678.0
              
              
              
              475.07.13%
      Series A Senior Notes due 2010
              
              
              49.7
              
              
              
              51.37.99%
      Series B Senior Notes due 2010
              
              
              4.7
              
              
              
              5.06.89%
      Series C Senior Notes due 2012
              
              
              5.1
              
              
              
              5.5737.5
              
              
              
              536.8
  TC
PipeLines’ Senior Credit Facility consists of a $475.0 million senior term loan
and a $250.0 million senior revolving credit facility. At September 30, 2009,
the outstanding balance on our revolving credit facility was $203.0 million,
leaving $47.0 million available for future borrowings. The interest rate on the
Senior Credit Facility averaged 1.01 per cent for the three months ended
September 30, 2009 (2008 – 3.31 per cent). For the nine months ended September
30, 2009, the interest rate on the Senior Credit Facility averaged 1.62 per cent
(2008 – 3.93 per cent). After hedging activity, the interest rate incurred on
the Senior Credit Facility averaged 3.39 per cent for the three months ended
September 30, 2009 (2008 – 5.23 per cent) and 4.28 per cent for the nine months
ended September 30, 2009 (2008 – 5.18 per cent). Prior to hedging activities,
the interest rate was 0.78 per cent at September 30, 2009 (December 31, 2008 –
2.67 per cent). At September 30, 2009, we were in compliance with our financial
covenants.




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




(unaudited)(millions
      of dollars)2009
              2.22010
              53.42011
              678.82012
              3.1737.5


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 two per cent interest, plus an amount equal to incentive
distributions. Incentive distributions are received by 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:






11





(unaudited)
                
                Three
      months ended
                  September
      30,
                
                Nine
      months ended
                  September
      30,(millions
      of dollars except per unit)
                
                2009
                
                2008
                
                2009
                
                2008Net
      income(a)
                
                
                27.4
                
                
                
                33.0
                
                
                
                81.2
                
                
                
                93.9North
      Baja's contribution prior to acquisition
                
                
                -
                
                
                
                (4.7
                )
                
                
                (8.3
                )
                
                
                (12.8
                )Net
      income prior to recast allocated to partners
                
                
                27.4
                
                
                
                28.3
                
                
                
                72.9
                
                
                
                81.1Net
      income prior to recast allocated to general partner:General
      partner interest
                
                
                (0.6
                )
                
                
                (0.6
                )
                
                
                (1.5
                )
                
                
                (1.6
                )Incentive
      distribution income allocation
                
                
                -
                
                
                
                (2.6
                )
                
                
                (5.3
                )
                
                
                (7.8
                )(0.6
                )
                
                
                (3.2
                )
                
                
                (6.8
                )
                
                
                (9.4
                )Net
      income prior to recast allocable to common units
                
                
                26.8
                
                
                
                25.1
                
                
                
                66.1
                
                
                
                71.7Weighted
      average common units outstanding (millions)
                
                
                41.2
                
                
                
                34.9
                
                
                
                37.0
                
                
                
                34.9Net
      income prior to recast per common unit
                
                $
                0.65
                
                
                $
                0.72
                
                
                $
                1.78
                
                
                $
                2.06
  (a)Recast as discussed in Note 1 and Note 4.


Effective
January 1, 2009, the Partnership adopted the provisions of Accounting
Standards Codification (ASC) 260-10-55 Earnings Per Share – Overall –
Implementation Guidance and Illustrations – Master Limited
Partnerships.




According
to the new standard, for purposes of calculating net income per common unit, net
income must be reduced by the amount of available cash that will be distributed
with respect to that period. Any undistributed income must be allocated to the
various interest holders based on the contractual provisions of the partnership
agreement. Under the partnership agreement, for any quarterly period, the
participation of the IDRs is limited to available cash distributions declared.
Accordingly, the undistributed net income has been allocated to the general
partner’s two per cent interest and the common unitholders.




The
retrospective application of ASC 260-10-55 impacted the amount of net income
allocated to the IDR holder in the nine months ended September 30, 2008, as the
amount previously allocated to the IDR holder was based on the cash distribution
paid in that period and will now be based on the amount declared for the period.
This did not impact the net income per common unit for the third quarter of
2008, but resulted in a reduction from $2.08 to $2.06 in net income per common
unit for the nine months ended September 30, 2008.


Note 7
            Cash
    Distributions For the
three and nine months ended September 30, 2009, we distributed $0.73 and $2.14
per common unit (2008 – $0.705 and $2.07 per common unit). The distributions for
the three and nine months ended September 30, 2009 included incentive
distributions to the general partner of $nil and $5.3 million, respectively
(2008 - $2.6 million and $7.0 million).





Note 8
            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
$0.6 million and $1.5 million for the three and nine months ended September 30,
2009, respectively (2008 - $0.5 million and $1.6 million).






12




TransCanada
and its affiliates provide capital and operating services to Great Lakes,
Northern Border, North Baja and Tuscarora (together, “our pipeline systems”).
TransCanada and its affiliates incur costs on behalf of our pipeline systems,
including, but not limited to, employee salary and benefit costs, property and
liability insurance costs.





Total
costs charged to our pipeline systems during the three and nine months ended
September 30, 2009 and 2008 by TransCanada and its affiliates and amounts owed
to TransCanada and its affiliates at September 30, 2009 and December 31, 2008
are summarized in the following tables:




(unaudited)
            
            Three
      months ended
              September
      30,
            
            Nine
      months ended
              September
      30,(millions
      of dollars)
            
            2009
            
            2008
            
            2009
            
            2008Costs
      charged by TransCanada and its affiliates:Great
      Lakes
            
            
            8.9
            
            
            
            8.2
            
            
            
            24.4
            
            
            
            23.4Northern
      Border
            
            
            6.3
            
            
            
            7.5
            
            
            
            19.0
            
            
            
            23.5North
      Baja(a)
            
            
            0.5
            
            
            
            1.9
            
            
            
            2.1
            
            
            
            4.9Tuscarora
            
            
            0.6
            
            
            
            0.9
            
            
            
            2.2
            
            
            
            2.9Impact
      on the Partnership's net income:Great
      Lakes
            
            
            3.4
            
            
            
            3.6
            
            
            
            10.3
            
            
            
            10.1Northern
      Border
            
            
            3.1
            
            
            
            3.2
            
            
            
            9.1
            
            
            
            9.6North
      Baja(a)
            
            
            0.5
            
            
            
            0.7
            
            
            
            1.8
            
            
            
            1.9Tuscarora
            
            
            0.5
            
            
            
            0.7
            
            
            
            1.9
            
            
            
            2.0






(unaudited)
            
            September
      30,
            
            December
      31,(millions
      of dollars)
            
            2009
            
            2008Amount
      owed to TransCanada and its affiliates:Great
      Lakes
            
            
            3.3
            
            
            
            4.5Northern
      Border
            
            
            2.4
            
            
            
            2.8North
      Baja(a)
            
            
            0.2
            
            
            
            (2.5
            )Tuscarora
            
            
            0.5
            
            
            
            0.8





(a)
Recast as discussed in Note 1 and Note 4.




Great
Lakes earns transportation revenues from TransCanada and its affiliates under
fixed price contracts with remaining terms ranging from one to nine years. Great
Lakes earned $33.1 million of transportation revenues under these contracts for
the three months ended September 30, 2009 (2008 - $40.5 million). This amount
represents 48.0 per cent of total revenues earned by Great Lakes for the three
months ended September 30, 2009 (2008 – 61.0 per cent). $15.4 million of
affiliated revenue is included in our equity income from Great Lakes for the
three months ended September 30, 2009 (2008 - $18.8 million).




Great
Lakes earned $105.5 million of transportation revenues from TransCanada and its
affiliates for the nine months ended September 30, 2009 (2008 - $108.7 million).
This amount represents 47.9 per cent of total revenues earned by Great Lakes for
the nine months ended September 30, 2009 (2008 – 51.0 per cent). $49.0 million
of this transportation revenue is included in our equity income from Great Lakes
for the nine months ended September 30, 2009 (2008 - $50.5
million).




At
September 30, 2009, $9.3 million is included in Great Lakes’ receivables in
regards to the transportation contracts with TransCanada and its affiliates
(December 31, 2008 - $12.5 million).




Note 9
            Derivative Financial
      Instruments


The
interest rate swaps and options are structured such that the cash flows match
those of the Senior Credit Facility. The notional amount hedged at September 30,
2009 was $375.0 million (December 31, 2008 - $475.0 million). At September 30,
2009, the fair value of the interest rate swaps accounted for as hedges was
negative $25.4 million (December 31, 2008 – negative $31.7 million). Under ASC 820 – Fair
Value Measurements and Disclosures, financial instruments are recorded at
fair value on a recurring basis. We have classified all our derivative
financial instruments as level II where the fair value is determined by using
valuation techniques that refer to observable market data or estimated market
prices.During
the three and nine months ended September 30, 2009, we recorded interest expense
of $4.0 million and $10.9 million in regards to the interest rate swaps and
options. In 2008, we recorded interest expense of $2.4 million and $4.7 million
for the three and nine months ended September 30 in regards to the interest rate
swaps and options. These expenses are included in the line item ‘Financial
charges, net and other’ on the Partnership’s consolidated statement of
income.






13




Note 10
            Changes in Working
      Capital




(unaudited)
                
                Nine
      months ended September 30,(millions
      of dollars)
                
                2009
                
                2008(a)Decrease/(increase)
      in accounts receivable and other
                
                
                4.6
                
                
                
                (0.6
                )Decrease
      in bank indebtedness
                
                
                -
                
                
                
                (1.4
                )Decrease
      in accounts payable
                
                
                (1.0
                )
                
                
                (4.2
                )(Decrease)/increase
      in accrued interest
                
                
                (1.3
                )
                
                
                0.12.3
                
                
                
                (6.1
                )Increase
      in investing working capital
                
                
                -
                
                
                
                (2.8
                )Decrease/(increase)
      in operating working capital
                
                
                2.3
                
                
                
                (3.3
                )
  (a)
      Recast as discussed in Note 1 and Note 4.




Note 11
            Accounting
      Pronouncements


The
Partnership adopted the provision of ASC 820-10-65 Fair
Value Measurements and Disclosures – Overall – Transition and Open Effective
Date Information for all non-financial assets and liabilities measured on
a non-recurring basis subsequent to initial recognition, effective January 1,
2009. The adoption of ASC 820-10-65 has had no material impact on our results of
operations or financial position.




ASC 260-10-55
Earnings Per Share – Overall – Implementation Guidance and Illustrations –
Master Limited Partnerships is effective for fiscal years beginning after
December 15, 2008. The Partnership adopted the provisions of ASC 260-10-55
effective January 1, 2009. Refer to Note 6 for the impact to our financial
statements.




The
Partnership adopted the provisions of ASC 815-10-65
Derivatives and Hedging – Overall – Transition and Open Effective Date
Information, effective January 1, 2009. There was no material effect on
the Partnerships’ disclosure following adoption of this standard.




ASC 855 -
Subsequent Events establishes general standards of accounting for and
disclosure of events that occur after the balance sheet date but before
financial statements are issued or are available to be issued. This standard has
been effective for the Partnership’s interim reporting since June 30, 2009 and
has not had a material impact on the Partnership’s
disclosures.




ASC 105 - Generally
Accepted Accounting Principleshas become the source of authoritative
GAAP recognized by the FASB to be applied by nongovernmental entities. This
standard is effective for the Partnership’s interim reporting period ending
after September 15, 2009. The adoption of this standard has had no impact on
disclosures or amounts recorded in the Partnership’s financial
statements.




Note 12
            Subsequent
    Events On
October 22, 2009, the Board of Directors of the general partner declared the
Partnership’s third quarter 2009 cash distribution in the amount of $0.73 per
common unit, payable on November 13, 2009, to unitholders of record on October
31, 2009.






14




Great
Lakes has approximately 830 thousand dekatherms per day (MDth/d) of longhaul
capacity under contract expiring on October 31, 2010 with its largest shipper,
TransCanada. On November 3, 2009,Great Lakes and TransCanada renewed contracts for one year for 470 MDth/d
of capacity and agreed to provide other transportation services. The
remaining approximate 360 MDth/d of capacity will expire October 31, 2010. Great
Lakes will actively market and post the expiring capacity for shipper interest
in early 2010.




The
Partnership has evaluated subsequent events from October 1, 2009 through
November 6, 2009, which represents the date the financial statements were
issued.


15


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




The
following discusses the results of operations and liquidity and capital
resources of TC PipeLines, LP, along with those of Great Lakes Gas Transmission
Limited Partnership (Great Lakes), Northern Border Pipeline Company (Northern
Border), North Baja Pipeline, LLC (North Baja) and Tuscarora Gas Transmission
Company (Tuscarora), as a result of the Partnership’s ownership
interests.




FORWARD-LOOKING
STATEMENTS




The
statements in this report that are not historical information, including
statements concerning plans and objectives of management for future operations,
economic performance or related assumptions, are forward-looking statements
within the meaning of Section 27A of the Securities Act of 1933 and
Section 21E of the Exchange Act. Forward-looking statements may include
words such as “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,”
“believe,” “forecast” and other words and terms of similar meaning. The absence
of these words, however, does not mean that the statements are not
forward-looking.




These
statements reflect our current views with respect to future events, based on
what we believe are reasonable assumptions. Certain factors that could cause
actual results to differ materially from those contemplated in the
forward-looking statements include:




·
            the
      ability of Great Lakes and Northern Border to continue to make
      distributions at their current
levels;


·
            the
      impact of unsold capacity on Great Lakes and Northern Border being greater
      or less than expected;


·
            competitive
      conditions in our industry and the ability of Great Lakes, Northern
      Border, North Baja and Tuscarora, (together “our pipeline systems”), to
      market pipeline capacity on favorable terms, which is affected
      by:


o
            future
      demand for and prices of natural
gas;


o
            the
      level of natural gas basis
differentials;


o
            competitive
      conditions in the overall natural gas and electricity
    markets;


o
            the
      availability and relative cost of supplies of Canadian and United States
      (U.S.) natural gas, including newly discovered natural gas developments
      such as the Horn River and Montney shale gas developments in Western
      Canada, U.S. Rockies and U.S. Mid-Continent shale gas developments, and
      the Marcellus shale gas
developments;


o
            competitive
      developments by Canadian and U.S. natural gas transmission
      companies;


o
            the
      availability of additional storage capacity and current storage
      levels;


o
            the
      level of liquefied natural gas
imports;


o
            weather
      conditions that impact supply and demand;
and


o
            the
      ability of shippers to meet credit worthiness
  requirements;


·
            changes
      in relative cost structures of natural gas producing basins, such as
      changes in royalty programs, that may prejudice the development of the
      Western Canada Sedimentary Basin
(WCSB);


·
            the
      decision by other pipeline companies to advance projects which will affect
      our pipeline systems and the regulatory, financing and construction risks
      related to construction of interstate natural gas pipelines and additional
      facilities;


·
            performance
      of contractual obligations by customers of our pipeline
      systems;


·
            the
      imposition of entity level taxation by states on
    partnerships;


·
            operating
      hazards, natural disasters, weather-related delays, casualty losses and
      other matters beyond our control;


·
            the
      impact of current and future laws, rulings and governmental regulations,
      particularly Federal Energy Regulatory Commission (FERC) regulations, and
      proposed and pending legislation by Congress and proposed and pending
      regulations by the U.S. Environmental Protection Agency (EPA) related to
      greenhouse gas emissions on us and our pipeline
  systems;


·
            the
      Partnership's ability to identify and/or consummate accretive growth
      opportunities from TransCanada or
others;


·
            our
      ability to control operating costs and the ability of TransCanada to
      implement its reorganization of U.S. pipeline operations, including the
      operations of our pipeline systems, and realize cost savings;
      and


·
            the
      severity and length of the current economic downturn, which
      impacts:


o
            the
      debt and equity capital markets and our ability to access these
      markets;


o
            the
      overall demand for natural gas by end users;
  and


o
            natural
      gas prices




16




Other
factors described elsewhere in this document, or factors that are unknown or
unpredictable, could also have material adverse effects on future results.
Please also read Item 1A. “Risk Factors” in our Annual Report on Form 10-K for
the year ended December 31, 2008. All forward-looking statements attributable to
us or persons acting on our behalf are expressly qualified in their entirety by
these factors. These forward-looking statements and information are made only as
of the date of the filing of this report, and except as required by applicable
law, we undertake no obligation to update these forward-looking statements and
information to reflect new information, subsequent events or
otherwise.




The
following discussion and analysis should be read in conjunction with our 2008
Annual Report on Form 10-K and the unaudited financial statements and notes
thereto included in Item 1. “Financial Statements” of this Quarterly Report on
Form 10-Q. All amounts are stated in U.S. dollars.




PARTNERSHIP
OVERVIEW




TC
PipeLines, LP was formed in 1998 as a Delaware limited partnership by
TransCanada PipeLines Limited, a wholly-owned subsidiary of TransCanada
Corporation, to acquire, own and participate in the management of energy
infrastructure assets in North America. Our strategic focus is on delivering
stable, sustainable cash distributions to our unitholders and finding
opportunities to increase cash distributions while maintaining a low risk
profile.




TC
PipeLines, LP and its subsidiaries are collectively referred to herein as “TC
PipeLines” or “the Partnership.” In this report, references to “we”, “us” or
“our” collectively refer to TC PipeLines or the Partnership. The general partner
of the Partnership is TC PipeLines GP, Inc., a wholly-owned subsidiary of
TransCanada. TransCanada and its subsidiaries are herein collectively referred
to as “TransCanada”.




We own a
46.45 per cent general partner interest in Great Lakes. The other 53.55 per cent
partner interest in Great Lakes is owned by TransCanada.




We own a
50 per cent general partner interest in Northern Border. The other 50 per cent
general partner interest is owned by ONEOK Partners, L.P., a publicly traded
limited partnership that is controlled by ONEOK, Inc.




We own
100 per cent of Tuscarora.




We own
100 per cent of North Baja, which we acquired on July 1, 2009 from TransCanada.
Because North Baja was acquired from an affiliate, the acquisition was accounted
for as a transaction between entities under common control, similar to a pooling
of interests, whereby the assets and liabilities of North Baja were recorded at
the carrying value of the previous owner and the Partnership’s historical
financial information was recast to include the North Baja for all periods
presented. Please read Recent Developments within this section for additional
information regarding the North Baja acquisition.




Our
general partner interests in Great Lakes and Northern Border, and ownership of
North Baja and Tuscarora represent our only material assets at September 30,
2009. As a result, we are dependent upon our pipeline systems for all of our
available cash. Our pipeline systems derive their operating revenue from the
transportation of natural gas.




Great
Lakes Overview




Great
Lakes is a Delaware limited partnership formed in 1990. Great Lakes was
originally constructed as an operational loop of the TransCanada Mainline
Northern Ontario system. Great Lakes receives natural gas from TransCanada at
the Canadian border near Emerson, Manitoba and extends across Minnesota,
Northern Wisconsin and Michigan, and redelivers gas to TransCanada at the
Canadian border at Sault Ste. Marie, Michigan and St. Clair, Michigan. 
Great Lakes also connects to strategic storage centers in Michigan.






17




Northern
Border Overview




Northern
Border is a Texas general partnership formed in 1978. Northern Border transports
natural gas from the Canadian border near Port of Morgan, Montana to a terminus
near North Hayden, Indiana. Additionally, Northern Border transports natural gas
produced in the Williston Basin of Montana and North Dakota, and in the Powder
River Basin of Wyoming and Montana, as well as synthetic gas produced at the
Dakota Gasification plant in North Dakota.




Tuscarora
Overview




Tuscarora
is a Nevada general partnership formed in 1993. Tuscarora originates at an
interconnection point with existing facilities of Gas Transmission Northwest
Corporation, a wholly-owned subsidiary of TransCanada, near Malin, Oregon and
runs southeast through Northeastern California and Northwestern Nevada.
Tuscarora’s pipeline system terminates near Wadsworth, Nevada. Along its route,
deliveries are made in Oregon, Northern California and Northwestern
Nevada.




North
Baja Overview




The
Partnership acquired 100 per cent of North Baja from TransCanada on July 1,
2009. North Baja is a Delaware limited liability company formed in 2000. The
North Baja system extends from an interconnection with El Paso Natural Gas
Company near Ehrenberg, Arizona to a point near Ogilby, California on the
California/Mexico border where it connects with the Gasoducto Bajanorte natural
gas pipeline system which is owned by Sempra Energy International. North Baja is
a bi-directional system which allows it to accept receipts and make deliveries
of natural gas at both the interconnection with El Paso Natural Gas Company and
the interconnection with Gasoducto Bajanorte. North Baja is regulated by the
FERC and is operated by TransCanada.




RECENT
DEVELOPMENTS




PARTNERSHIP




North
Baja Acquisition and IDR Restructuring




On July
1, 2009, the Partnership acquired a 100 per cent interest in North Baja from
TransCanada for an initial purchase price of $271.3 million. The acquisition was
financed through a combination of (i) a draw of $170.0 million on the
Partnership’s $250.0 million revolving portion of its revolving credit and term
loan agreement (Senior Credit Facility), which previously had no outstanding
borrowings, (ii) issuance of 2,609,680 common units at $30.042 per common unit
to TransCan Northern Ltd., a wholly-owned subsidiary of TransCanada, for gross
proceeds of $78.4 million, (iii) issuance of additional general partner interest
to the general partner of $1.6 million, which was required to maintain the
general partner’s two per cent general partner interest in the Partnership, and
(iv) approximately $21.3 million of cash on hand.




The
acquisition of North Baja was accounted for as a transaction between entities
under common control, similar to a pooling of interests, whereby the assets and
liabilities of North Baja were recorded at TransCanada’s carrying value and the
Partnership’s historical financial information was recast to include the
acquired entity for all periods presented. As the fair market value paid for
North Baja was greater than the recorded net assets of North Baja, the excess
purchase price paid was recorded as a reduction to Partners’ Equity. The effect
of recasting the Partnership’s consolidated financial statements to account for
the common control transaction increased the Partnership’s net income by
$4.7 million and $12.8 million for the three and nine months ended
September 30, 2008, respectively, from amounts previously reported. In
addition, the Partnership’s net income increased by $8.3 million for the six
months ended June 30, 2009 from amounts previously reported.




In
connection with the acquisition, if TransCanada completes an expansion of the
North Baja pipeline from the Mexico/Arizona border to Yuma City, Arizona by June
30, 2010, the Partnership will pay TransCanada up to an additional $10.0 million
for the expansion, which amount shall be determined using a formula that is
based on transportation service agreements to be entered into in connection with
the expansion. This acquisition will be accounted for if and when the
transaction occurs.





18




Concurrent
with the acquisition of North Baja, the Partnership entered into an exchange
agreement (Exchange Agreement) with its general partner pursuant to which the
Partnership issued 3,762,000 new common units to the general partner and
provided for revised incentive distribution rights (Revised IDRs) in exchange
for the cancellation of the incentive distribution rights available to the
general partner (Old IDRs) under the Amended and Restated Agreement of Limited
Partnership of the Partnership.




The
Revised IDRs reset the IDRs to two per cent, down from the incentive
distribution levels of the Old IDRs at 50 per cent. The incentive
distribution levels of the Revised IDRs increase to 15 per cent and 25 per cent
when quarterly distributions increase to $0.81 and $0.88 per common unit or
$3.24 and $3.52 per common unit on an annualized basis,
respectively.




As part
of the Exchange Agreement, the Partnership’s Amended and Restated Agreement of
Limited Partnership was amended and restated effective as of July 1, 2009 to:
(i) eliminate the Old IDRs and replace them with the Revised IDRs as described
above, (ii) eliminate outdated provisions, (iii) incorporate all prior
amendments and changes in one document and (iv) correct typographical
errors. The Second Amended and Restated Agreement of Limited Partnership
replaces the Amended and Restated Agreement of Limited Partnership in its
entirety.




OUR
PIPELINE SYSTEMS




Great
Lakes




Great
Lakes has approximately 830 thousand dekatherms per day (MDth/d) of longhaul
capacity under contract expiring on October 31, 2010 with its largest shipper,
TransCanada. On November
3, 2009, Great Lakes and TransCanada renewed contracts for one year
for 470 MDth/d of capacity, some at a slightly discounted rate, and agreed
to provide other transportation services. The remaining approximate 360 MDth/d
of capacity will expire October 31, 2010. Great Lakes will actively market and
post the expiring capacity for shipper interest in early 2010. Please read
Factors that Impact the Business of Our Pipeline Systems within this section for
additional information regarding Great Lakes contracting.




FACTORS
THAT IMPACT OUR BUSINESS




Key
factors that impact our business are the cash flows received from our
investments and our ability to maintain a strong and balanced financial
position. Cash flows from our investments are dependent upon the ability of
Great Lakes and Northern Border to make distributions to us and of Tuscarora and
North Baja to generate positive operating cash flows. Cash flows from our
investments are necessary to fund distributions to our unitholders. A strong
financial position will ensure that we are able to maintain a prudent level of
available cash to make distributions to our unitholders.




FACTORS
THAT IMPACT THE BUSINESS OF OUR PIPELINE SYSTEMS




Our
pipeline systems provide natural gas transportation services to their customers.
Key factors that impact their business are the supply of and demand for natural
gas in the markets in which our pipeline systems operate; the customers of our
pipeline systems and the mix of services they require; competition; and
government regulation of natural gas pipelines. These factors are discussed in
more detail below.




Supply
and Demand of Natural Gas




Our
pipeline systems provide customers with natural gas transportation services to
market demand areas. Great Lakes also provides access to strategic storage
centers.  Our pipeline systems depend upon the continued availability of
natural gas production and reserves in the regions they access. The primary
region accessed by our pipeline systems, excluding North Baja, is the WCSB. The
Net WCSB Flows to Markets are dependent upon WCSB natural gas production levels,
demand for natural gas in Western Canada, storage capacity for Western Canadian
natural gas and demand for storage injection. The Net WCSB Flows to Markets were
1.2 billion cubic feet per day (Bcf/day) lower in the third quarter of 2009
compared to the same period in 2008, due primarily to a decrease in
production which was slightly offset by a reduction in net injections into
Western Canadian storage.






19




Decreased
demand in North America related to the economic environment, combined with
increased production from U.S. shale plays and high levels of natural gas in
storage have resulted in a supply/demand imbalance, which has contributed to
weaker commodity prices for natural gas over the last year and is expected
to continue into 2010. These low commodity prices have resulted in reductions in
exploration and development activity for natural gas as well as some levels of
voluntary production curtailments in the WCSB. Decreases in WCSB production are
expected to continue throughout the remainder of 2009 and into 2010 mainly
related to the low commodity price environment. While production from U.S.
shale plays has increased, overall U.S natural gas production has decreased
compared to previous periods.




Strengthening
of the North American economy, decreased natural gas inventories as a result of
reduced production levels and cold winter weather causing increased heating
related demand, are factors that would positively affect natural gas
prices.




Western
Canadian natural gas in storage is currently at a five year high. U.S. working
gas storage levels are also at record high levels. The summer is traditionally a
storage injection period. However, due to the high levels of natural gas already
in storage at the beginning of the storage injection season, lower amounts of
gas were injected over the third quarter compared to levels seen in previous
years. Normally, lower levels of injection into Western Canadian gas storage
results in more WCSB gas available for export; however, this has been offset by
less WCSB production. The high U.S. gas storage levels are negatively impacting
the demand for natural gas in the market areas that storage serves, as well as
impacting demand for transportation services related to storage injection. High
overall storage levels have a dampening effect on natural gas prices which in
turn reduces ongoing production.




Factors
which may mitigate declining WCSB production in the future include strengthening
gas prices which will support continued exploration and development of new
fields in Western Canada by WCSB natural gas producers. Over the long term, we
expect WCSB natural gas producers will direct significant activity at
unconventional resources such as coal bed methane and shale gas. Additional
Canadian natural gas supply sources may be available in the future if new
pipeline projects associated with the Montney and Horn River shale gas regions
in Western Canada are constructed, and longer term potential associated with the
proposed development of the Mackenzie Delta in Northern Canada and the North
Slope of Alaska is realized.




Factors
which may impact the overall demand for natural gas include weather conditions,
economic conditions, government regulation, availability and price of
alternative energy sources, fuel conservation measures, and technological
advances in fuel economy and energy generation devices. Although demand for
natural gas is expected to continue to decline in North America through the
remainder of 2009 and into 2010 with the current economic downturn, we expect a
demand increase in the long term. In certain sectors, such as the electric
generation sector, lower natural gas prices have resulted in a competitive
advantage for this fuel option and a resulting increase in demand for natural
gas in this sector.




Demand
for natural gas transportation service on our pipeline systems is directly
related to the activity in the natural gas markets served by these systems.
Factors that may impact demand for transportation service on any one system
include the ability and willingness of natural gas shippers to utilize one
system over alternative pipelines, relative transportation rates, and the volume
of natural gas delivered to markets from other supply sources and storage
facilities. The impact of changes in demand for natural gas transportation
services on operating revenues for our pipeline systems is dependent upon the
extent to which capacity has been contracted under long-term firm contracts.
Please read Recent Developments section above for a discussion of Great Lakes
contracting.




Net WCSB
Flows to Markets is one of the factors which impacts throughput on our Great
Lakes and Northern Border pipeline systems. The other important factor impacting
throughput is the activity in the natural gas markets served by our pipeline
systems. We cannot predict the impact of any continued declines in Net WCSB
Flows to Markets and uncertain market conditions are expected to continue to
affect throughput for the remainder of 2009 and into 2010.






20




Throughput
on the Great Lakes pipeline system in the third quarter of 2009 (average 1,622
MMcf/d) was lower compared to the same period in 2008 (average 2,122 MMcf/d).
The lower volumes in 2009 are due mainly to underutilization of long-term firm
contracts by Great Lakes’ major shipper, TransCanada, related to the early fill
of storage during the traditional summer storage-fill season, lower power
generation demand due to the cooler than normal summer weather in the market
areas served by Great Lakes, and decreased overall demand related to the
economic environment. The underutilization of the long-term firm contracts was
somewhat offset by daily sales of capacity. Decreases in throughput related to
underutilization of firm contracts have a minimal impact on revenue. If the
level of firm contracts decreases, Great Lakes may experience increased
volatility in revenues as a result of changes in throughput.




Throughput
on Northern Border declined in the third quarter of 2009 (average 1,774 MMcf/d)
relative to the same period in 2008 (average 1,813 MMcf/d) as the Midwest
markets served by Northern Border had cooler than normal weather conditions,
decreased overall demand related to the economic environment, and reduced Net
WCSB Flows to Markets. Decreased overall demand also reduces the ability to
contract available pipeline capacity serving this market area. Changes in
throughput on Northern Border related to capacity without firm contracts impacts
Northern Border’s revenues.




Tuscarora
transports natural gas supply from the WCSB; however, the transportation
capacity on our Tuscarora pipeline system is substantially contracted under
long-term firm contracts. North Baja transports gas sourced either from El Paso
Natural Gas Company which is primarily gas originating from the Texas supply
region or from the Costa Azul LNG facility in Mexico and all of North Baja’s
physical capacity has been contracted under long-term firm contracts. Therefore,
although throughput may vary on these pipeline systems, there is minimal impact
on revenue.




Customers
and Contracting




The
reduced level of Net WCSB Flows to Markets has resulted in an environment in
which the pipeline capacity serving the WCSB exceeds demand. In this
environment, there is little incentive for shippers to make long-term
commitments for capacity and the trend towards shorter term contracts is
expected to continue for Great Lakes and Northern Border. As well, there may be
increased seasonality with respect to pipeline throughput and
revenues.




Prevailing
market conditions and dynamic competitive factors in North America, particularly
lower Net WCSB Flows to Markets, increased supply from other supply basins to
our pipelines systems’ market area, and the current economic conditions
affecting the demand for natural gas, will continue to impact the value of
transportation on our pipeline systems and their ability to market available
capacity.




Great
Lakes’ average contracted capacity was 103 per cent of its design capacity for
the third quarter of 2009 compared to 95 per cent for the same period last year.
At September 30, 2009, 92 per cent of its average design capacity was contracted
on a firm basis for the remainder of the year and the weighted average remaining
life of firm transport contracts was 1.9 years. Substantially all of the
firm contracts in place at September 30, 2009 are in place until October 31,
2010.




Great
Lakes has approximately 985 MDth/d of longhaul capacity expiring on October 31,
2010, of which approximately 830 MDth/d is contracted with TransCanada. On
November 3, 2009, Great Lakes and TransCanada renewed contracts for one year for
470 MDth/d of capacity, some at a slightly discounted rate, and agreed to
provide other transportation services.  TransCanada has elected to turn
back approximately 360 MDth/d as of October 31, 2010. Great Lakes continues
shipper negotiations on the remaining capacity. Great Lakes will actively market
and post any expiring capacity for shipper interest in early 2010. Great Lakes
may discount transportation capacity as needed to optimize revenue.




Northern
Border’s average contracted capacity was 70 per cent of its design capacity for
the third quarter of 2009 compared to 79 per cent for the same period last year.
At September 30, 2009, Northern Border had approximately 47 per cent of its
design capacity uncontracted for the remainder of the year. In the absence of
renewals on maturing contracts, the design capacity uncontracted will increase
to 65 per cent beginning April 1, 2010. Northern Border expects to continue to
discount transportation capacity as needed to optimize revenue. As at September
30, 2009, the weighted average remaining life of Northern Border’s firm
transportation contracts was 2.0 years.






21




Tuscarora
operates under long-term contracts and had 98 per cent of its design capacity
contracted for the third quarter of 2009, consistent with the same period last
year. As at September 30, 2009, 98 per cent of its design capacity was
contracted on a firm basis for the remainder of the year with a weighted average
remaining life of 11.0 years.




North
Baja operates under long-term contracts and, as at September 30, 2009, in excess
of 100 per cent of its physical capacity was contracted on a firm basis for the
remainder of the year. Due to North Baja’s bi-directional nature, it has the
capacity to accept receipts at both ends of its system. As at September 30,
2009, 79 per cent of the design capacity for southbound receipts and 64 per cent
of the design capacity for northbound receipts was contracted on a firm basis
for the remainder of the year. The weighted average remaining life of the
contracts at September 30, 2009 was 16.5 years.




Competition




Our
pipeline systems compete primarily with other interstate and intrastate
pipelines in the transportation of natural gas. Changes in North American gas
flow patterns are expected as a result of recent and proposed pipeline projects
which are changing the supply competition in the markets served by our pipeline
systems. Additionally, supply competition from other natural gas sources can
impact demand for transportation on our pipeline systems. Growth in supplies
available from other natural gas producing regions can impact prices for natural
gas delivered to some of the markets our pipeline systems serve relative to
other market regions.




As the
pipeline capacity serving the WCSB exceeds demand currently, there is
competition for Net WCSB Flows to Markets. Factors impacting the competition for
Net WCSB Flows to Markets include levels of firm transportation contracts on
each pipeline, demand for natural gas in the regions served by each pipeline,
and relative transportation values on each pipeline. In the short term, factors
impacting the competition for Net WCSB Flows to Markets include high natural gas
storage levels in Eastern Canada, Michigan and California.




The
Western segment of the Rockies Express Pipeline (REX West) introduced new gas
supplies from the Rockies natural gas basin into the markets served by Northern
Border, particularly its Mid-Continent market, starting in the second quarter of
2008. The increased supply resulted in downward pressure on prices in those
markets, which negatively impacted Northern Border’s ability to contract
available capacity. The Eastern segment of the Rockies Express Pipeline (REX
East) was placed into interim service on June 29, 2009 to Lebanon, Ohio. The
interim service of REX East is mitigating excess supply in the Mid-Continent
region; however, the movement of these natural gas supplies further east
following the full in-service of REX East is expected to create additional
supply in the markets served by Northern Border and Great Lakes, which may also
provide opportunities for Great Lakes to market its Eastern zone services.
Rockies Express Pipeline has announced that full in-service of REX East to
Clarington, Ohio is scheduled for November 2009.




Two new
pipeline projects transporting volumes from the lower Mid-Continent east to the
existing Gulf Coast pipeline infrastructure went into service in the second
quarter of 2009. These pipelines transport volumes from the lower Mid-Continent
east to existing pipelines that can deliver this supply to the Midwest market
area, Eastern U.S. market area, or to the Gulf market depending on demand. The
additional supply delivered to Eastern markets has caused and is expected to
continue to cause natural gas formerly delivered to Eastern markets to be
delivered into the Chicago market area.




Increased
supply in the Midwest markets served by Northern Border and Great Lakes as a
result of changed pipeline flows has resulted in downward pressure on prices in
this region.Additional supplies in the
Chicago market may continue to impact Northern Border’s ability to contract
upstream available capacity for the remainder of 2009 if natural gas flows on
Northern Border to Chicago materially decrease. Additional supply in the
Michigan market may impact Great Lakes’ ability to renew contracts with its
customers and market expiring capacity.






22






REGULATORY
DEVELOPMENTS




Other
Laws and Regulations




U.S.
Congress is actively considering federal legislation to reduce emissions of
“greenhouse gases” (including carbon dioxide and methane). The House of
Representatives narrowly approved the Waxman-Markey Bill on June 26, 2009. The
legislation is now under consideration by the Senate, and could be rejected by
the Senate, or could be significantly amended before being approved by the
Senate. If passed, such legislation could result in increased costs to (i)
operate and maintain our pipeline systems’ facilities; (ii) install new emission
controls on our pipeline systems’ facilities; (iii) require the construction of
new facilities; and (iv) administer and manage any greenhouse gas emissions
reduction program that may be applicable to our pipeline systems’ operations.
Separately, the EPA has proposed regulations relating to monitoring and
reporting greenhouse gas emissions pursuant to its authority under the Clean Air
Act. While our pipeline systems may be able to include some or all of the costs
associated with this environmental compliance, including future compliance with
greenhouse gas laws and regulations, in its transportation rates, the ability to
recover such costs is uncertain and may depend on events beyond our pipeline
systems’ control including the outcome of future rate proceedings before the
FERC and the provisions of any final legislation.




On
February 2, 2009, Northern Border received a Notice of Violation (NOV) from the
EPA alleging that Northern Border was in violation of certain regulations
pursuant to the Clean Air Act regarding a compressor station on its
system. Northern Border disputes the NOV. At this time, Northern
Border is unable to reasonably estimate the cost of any associated corrective
action or the possibility or amount of any penalty.




RESULTS
OF OPERATIONS OF TC PIPELINES




Critical
Accounting Policies and Estimates




The
preparation of financial statements in accordance with U.S. generally accepted
accounting principles (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 our critical accounting policies and estimates during the
nine months ended September 30, 2009.




Information
about our critical accounting 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,
2008.




Recent
Accounting Pronouncements




The
Partnership adopted the provision of Accounting
Standards Codification (ASC) 820-10-65 Fair Value Measurements and Disclosures –
Overall – Transition and Open Effective Date Information for all
non-financial assets and liabilities measured on a non-recurring basis
subsequent to initial recognition, effective January 1, 2009. The adoption of
ASC 820-10-65 has had no material impact on our results of operations or
financial position.




ASC 260-10-55
Earnings Per Share – Overall – Implementation Guidance and Illustrations –
Master Limited Partnerships is effective for fiscal years beginning after
December 15, 2008. The Partnership adopted the provisions of ASC 260-10-55
effective January 1, 2009. Refer to Note 6 for the impact to our financial
statements.




The
Partnership adopted the provisions of ASC 815-10-65
Derivatives and Hedging – Overall – Transition and Open Effective Date
Information, effective January 1, 2009. There was no material effect on
the Partnerships’ disclosure following adoption of this standard.






23




ASC 855 -
Subsequent Events establishes general standards of accounting for and
disclosure of events that occur after the balance sheet date but before
financial statements are issued or are available to be issued. This standard has
been effective for the Partnership’s interim reporting since June 30, 2009 and
has not had a material impact on the Partnership’s
disclosures.




ASC 105 - Generally
Accepted Accounting Principleshas become the source of authoritative
GAAP recognized by the FASB to be applied by nongovernmental entities. This
standard is effective for the Partnership’s interim reporting period ending
after September 15, 2009. The adoption of this standard has had no impact on
disclosures or amounts recorded in the Partnership’s financial
statements.




Net
Income




To
supplement our financial statements, we have presented a comparison of the
earnings contribution components from each of our investments. The contributions
from Tuscarora and North Baja are included under Other Pipes. We have presented
net income in this format in order to enhance investors’ understanding of the
way management analyzes our financial performance. We believe this summary
provides a more meaningful comparison of our net income to prior 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.





The
      shaded areas in the tables below disclose the results from Great Lakes and
      Northern Border, representing 100 per cent of each entity's operations for
      the given period.For
      the three months ended September 30, 2009
                  
                  
                  For
      the three months ended September 30, 2008(unaudited)
                    (millions
      of dollars)
                  
                  PipeLP
                  
                  
                  Other
                    Pipes
                  
                  
                  Corp
                  
                  
                  GLGT
                  
                  NBPC(1)
                  
                  PipeLP
                  
                  
                  Other
                    Pipes
                  
                  
                  Corp
                  
                  
                  GLGT
                  
                  NBPC(1)Transmission
      revenues
                  
                  
                  17.5
                  
                  
                  
                  17.5
                  
                  
                  
                  -
                  
                  
                  
                  68.9
                  
                  
                  
                  65.2
                  
                  
                  
                  8.2
                  
                  
                  
                  8.2
                  
                  
                  
                  -
                  
                  
                  66.7
                  
                  67.7Operating
      expenses
                  
                  
                  (3.5
                  )
                  
                  
                  (2.5
                  )
                  
                  
                  (1.0
                  )
                  
                  
                  (16.5
                  )
                  
                  
                  (19.0
                  )
                  
                  
                  (2.3
                  )
                  
                  
                  (1.4
                  )
                  
                  
                  (0.9
                  )
                  
                  (17.1
                  )
                  (19.3
                  )14.0
                  
                  
                  
                  15.0
                  
                  
                  
                  (1.0
                  )
                  
                  
                  52.4
                  
                  46.2
                  
                  
                  
                  5.9
                  
                  
                  
                  6.8
                  
                  
                  
                  (0.9
                  )
                  
                  49.6
                  
                  48.4Depreciation
                  
                  
                  (3.7
                  )
                  
                  
                  (3.7
                  )
                  
                  
                  -
                  
                  
                  
                  (14.7
                  )
                  (15.6
                  )
                  
                  
                  (1.8
                  )
                  
                  
                  (1.8
                  )
                  
                  
                  -
                  
                  
                  (14.7
                  )
                  (15.3
                  )Financial
      charges, net and other
                  
                  
                  (6.6
                  )
                  
                  
                  (1.0
                  )
                  
                  
                  (5.6
                  )
                  
                  
                  (8.1
                  )
                  (9.1
                  )
                  
                  
                  (7.7
                  )
                  
                  
                  (1.1
                  )
                  
                  
                  (6.6
                  )
                  
                  (8.0
                  )
                  7.1Michigan
      business tax
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  (1.3
                  )
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  (1.2
                  )
                  -28.3
                  
                  
                  
                  21.5
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  
                  25.7
                  
                  40.2Equity
      income
                  
                  
                  23.7
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  13.2
                  
                  
                  
                  10.5
                  
                  
                  
                  31.9
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  12.0
                  
                  
                  
                  19.9Net
      income prior to recast
                  
                  
                  27.4
                  
                  
                  
                  10.3
                  
                  
                  
                  (6.6
                  )
                  
                  
                  13.2
                  
                  
                  
                  10.5
                  
                  
                  
                  28.3
                  
                  
                  
                  3.9
                  
                  
                  
                  (7.5
                  )
                  
                  
                  12.0
                  
                  
                  
                  19.9North
      Baja's contribution prior to acquisition(2)
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  4.7
                  
                  
                  
                  4.7
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -Net
      income(2)
                  
                  
                  27.4
                  
                  
                  
                  10.3
                  
                  
                  
                  (6.6
                  )
                  
                  
                  13.2
                  
                  
                  
                  10.5
                  
                  
                  
                  33.0
                  
                  
                  
                  8.6
                  
                  
                  
                  (7.5
                  )
                  
                  
                  12.0
                  
                  
                  
                  19.9
  24
  For
      the nine months ended September 30, 2009
                    
                    
                    For
      the nine months ended September 30, 2008(unaudited)
                      (millions
      of dollars)
                    
                    PipeLP
                    
                    
                    Other
                      Pipes
                    
                    Corp
                    
                    
                    GLGT
                    
                    NBPC(1)
                    
                    PipeLP
                    
                    
                    Other
                      Pipes
                    
                    Corp
                    
                    GLGT
                    
                    NBPC(1)Transmission
      revenues
                    
                    
                    34.1
                    
                    
                    
                    34.1
                    
                    
                    
                    -
                    
                    
                    220.4
                    
                    193.9
                    
                    
                    
                    23.3
                    
                    
                    
                    23.3
                    
                    
                    
                    -
                    
                    
                    213.9
                    
                    212.8Operating
      expenses
                    
                    
                    (10.2
                    )
                    
                    
                    (5.1
                    )
                    
                    
                    (5.1
                    )
                    
                    (49.6
                    )
                    (55.8
                    )
                    
                    
                    (6.8
                    )
                    
                    
                    (3.7
                    )
                    
                    
                    (3.1
                    )
                    
                    (45.9
                    )
                    (57.5
                    )23.9
                    
                    
                    
                    29.0
                    
                    
                    
                    (5.1
                    )
                    
                    170.8
                    
                    138.1
                    
                    
                    
                    16.5
                    
                    
                    
                    19.6
                    
                    
                    
                    (3.1
                    )
                    
                    168.0
                    
                    155.3Depreciation
                    
                    
                    (7.2
                    )
                    
                    
                    (7.2
                    )
                    
                    
                    -
                    
                    
                    (43.9
                    )
                    (46.4
                    )
                    
                    
                    (5.1
                    )
                    
                    
                    (5.1
                    )
                    
                    
                    -
                    
                    
                    (43.9
                    )
                    (45.8
                    )Financial
      charges, net and other
                    
                    
                    (20.9
                    )
                    
                    
                    (3.3
                    )
                    
                    
                    (17.6
                    )
                    
                    (24.4
                    )
                    (27.4
                    )
                    
                    
                    (22.8
                    )
                    
                    
                    (3.1
                    )
                    
                    
                    (19.7
                    )
                    
                    (24.4
                    )
                    (12.1
                    )Michigan
      business tax
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    (4.4
                    )
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    (4.2
                    )
                    -98.1
                    
                    64.3
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    95.5
                    
                    97.4Equity
      income
                    
                    
                    77.1
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    45.6
                    
                    
                    
                    31.5
                    
                    
                    
                    92.5
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    44.4
                    
                    
                    
                    48.1Net
      income prior to recast
                    
                    
                    72.9
                    
                    
                    
                    18.5
                    
                    
                    
                    (22.7
                    )
                    
                    
                    45.6
                    
                    
                    
                    31.5
                    
                    
                    
                    81.1
                    
                    
                    
                    11.4
                    
                    
                    
                    (22.8
                    )
                    
                    
                    44.4
                    
                    
                    
                    48.1North
      Baja's contribution prior to acquisition(2)
                    
                    
                    8.3
                    
                    
                    
                    8.3
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    12.8
                    
                    
                    
                    12.8
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -Net
      income(2)
                    
                    
                    81.2
                    
                    
                    
                    26.8
                    
                    
                    
                    (22.7
                    )
                    
                    
                    45.6
                    
                    
                    
                    31.5
                    
                    
                    
                    93.9
                    
                    
                    
                    24.2
                    
                    
                    
                    (22.8
                    )
                    
                    
                    44.4
                    
                    
                    
                    48.1




(1)
      The Partnership owns a 50 per cent general partner interest in Northern
      Border. Equity income from Northern Border includes amortization of a
      $10.0 million transaction fee paid to the operator of Northern Border at
      the time of the additional 20 per cent acquisition in April
      2006.(2)Because North Baja was acquired from TransCanada, the acquisition
      was accounted for as a transaction between entities under common control,
      similar to a pooling of interests, whereby the assets and liabilities of
      North Baja were recorded at TransCanada's carrying value and the
      Partnership’s historical financial information was recast to include the
      acquired entity for all periods presented.
   Third
Quarter 2009 Compared with Third Quarter 2008


Net
income was $27.4 million in the third quarter of 2009, a decrease of $5.6
million compared to $33.0 million for the same period last year. Excluding the
contribution from North Baja prior to the acquisition, net income prior to
recast was $27.4 million in the third quarter of 2009, a decrease of $0.9
million compared to $28.3 million for the same period last year. This decrease
is primarily due to lower equity income from Northern Border, which decreased as
a result of the $16.1 million (Partnership share - $8.1 million) gain on sale of
Bison Pipeline LLC (Bison) in 2008,partially
offset by a $6.2 million contribution from North Baja since the
acquisition.




Equity
income from Great Lakes increased $1.2 million to $13.2 million in the third
quarter of 2009, compared to $12.0 million for the same period last year. The
increase in equity income was primarily due to increased transmission revenues.
Utilization of long-term firm contracts, some of which are priced at lower rates
than during the same period last year, decreased significantly in the third
quarter of 2009 compared to the same period last year; however, this had minimal
impact on revenue.  The sale of short-term services contributed to
increased overall transmission revenues of $2.2 million for the three months
ended September 30, 2009 compared to the same period last year.




Equity
income from Northern Border was $10.5 million in the third quarter of 2009, a
decrease of $9.4 million compared to $19.9 million for the same period last
year. The decrease in equity income was primarily due to a $16.1 million
(Partnership share - $8.1 million) gain on sale of Bison in 2008. Excluding this
gain, Northern Border’s net income decreased $2.6 million compared to the same
period last year due to decreased transmission revenues. Northern Border’s
transmission revenues decreased due to reduced system utilization. Northern
Border continues to be negatively impacted by increased supply competition as a
result of increased U.S. natural gas supplies being transported to the
Mid-western and Eastern markets from new U.S. supply sources, including the
Rockies Basin and southern shale gas, which is displacing demand for gas from
traditional natural gas sources including the WCSB. Additionally, reduced
overall demand for natural gas related to the current economic environment is
affecting demand for Northern Border’s transportation.




Net
income from Other Pipes (North Baja and Tuscarora) increased $1.7 million to
$10.3 million in the third quarter of 2009 compared to $8.6 million for the same
period last year. Excluding the contribution from North Baja prior to the
acquisition, net income from Other Pipes prior to recast increased $6.4 million
to $10.3 million in the third quarter of 2009 compared to $3.9 million for the
same period last year. This increase is primarily due to the acquisition of
North Baja which contributed $6.2 million to net income for the quarter ended
September 30, 2009. As the acquisition was accounted for as a transaction
between entities under common control, North Baja contributed $4.7 million to
net income for the quarter ended September 30, 2008.






25




Costs at
the Partnership level decreased by $0.9 million to $6.6 million in the third
quarter of 2009 compared to the same period last year. This decrease is
primarily due to decreased financial charges as a result of lower interest
rates, partially offset by losses on interest rate derivatives.




Nine
Months Ended September 30, 2009 Compared with Nine Months Ended September 30,
2008


Net
income decreased $12.7 million to $81.2 million for the nine months ended
September 30, 2009 compared to $93.9 million for the same period last year.
Excluding the contribution from North Baja prior to the acquisition, net income
prior to recast decreased $8.2 million to $72.9 million for the nine months
ended September 30, 2009 compared to $81.1 million for the same period last
year. This decrease is primarily due to lower equity income from Northern
Border, partially offset by the contribution from North Baja since the
acquisition. North Baja contributed $6.2 million to net income prior to recast
for the nine months ended September 30, 2009.




Equity
income from Great Lakes was $45.6 million for the nine months ended September
30, 2009, an increase of $1.2 million compared to $44.4 million in the same
period last year. The increase in equity income was primarily due to increased
transmission revenues, partially offset by an increase in operating expenses.
Utilization of long-term firm contracts decreased in the nine months ended
September 30, 2009 compared to the same period last year with minimal impact to
revenues due to reservation charges contained in the contracts. However,
short-term services contributed to increased transmission revenues of $6.5
million for the nine months ended September 30, 2009 compared to the same period
last year. Great Lakes’ operating expenses increased $3.7 million for the nine
months ended September 30, 2009 compared to the same period in the prior year
primarily due to increased pipeline maintenance costs, partially offset by lower
property and other taxes.




Equity
income from Northern Border was $31.5 million for the nine months ended
September 30, 2009, a decrease of $16.6 million compared to $48.1 million in the
same period last year. The decrease in equity income was partially due to a
$16.1 million (Partnership share - $8.1 million) gain on sale of Bison in 2008.
Excluding this gain, Northern Border’s net income decreased $17.0 million
compared to the same period last year primarily due to decreased transmission
revenues, partially offset by lower operating expenses. Northern Border’s
transmission revenues decreased by $18.9 million for the nine months ended
September 30, 2009 compared to the same period last year, primarily due to
reduced system utilization. Northern Border continues to be negatively impacted
by the incremental natural gas supply from the Rockies Basin into the markets it
serves as a result of the in-service of REX West in the second quarter of 2008,
other new pipeline projects completed in the second quarter of 2009 which have
resulted in increased supply into Northern Border’s markets, and reduced overall
demand related to the economic environment. Northern Border’s operating expenses
decreased by $1.7 million compared to the same period last year primarily due to
adjustments to reflect property tax amounts paid.




Net
income from Other Pipes (North Baja and Tuscarora) increased $2.6 million to
$26.8 million for the nine months ended September 30, 2009 compared to $24.2
million for the same period last year. Excluding the contribution from North
Baja prior to the acquisition, net income from Other Pipes prior to recast
increased $7.1 million to $18.5 million for the nine months ended September 30,
2009 compared to $11.4 million for the same period last year. This increase is
primarily due to the acquisition of North Baja which contributed $6.2 million to
net income prior to recast for the nine months ended September, 30, 2009 and an
increase in Tuscarora’s transmission revenues. Tuscarora’s transmission revenues
were higher resulting from the Likely compressor station expansion project that
went into service on April 1, 2008. As the North Baja acquisition was accounted
for as a transaction between entities under common control, North Baja
contributed a total of $14.5 million and $12.8 million to net income for the
nine months ended September 30, 2009 and 2008, respectively.




Costs at
the Partnership level for the nine months ended September 30, 2009 were
comparable to the same period last year, as a decrease in financial charges was
offset by an increase in operating expenses. Financial charges, net and other,
decreased by $2.1 million primarily due to lower interest rates, partially
offset by losses on interest rate derivatives. Operating expenses increased by
$2.0 million due to costs relating to the North Baja acquisition and the
amendment to the IDRs.






26




Partnership
Cash Flows




The
Partnership uses the non-GAAP financial measures ‘Partnership cash flows’ and
‘Partnership cash flows allocated to common units’ as financial performance
measures. As the Partnership’s financial performance underpins the
availability of cash flows to fund the cash distributions that the Partnership
pays to its unitholders, the Partnership believes these are key measures of the
available cash flows to its unitholders. The following Partnership cash
flows information is presented to enhance investors’ understanding of the way
that management analyzes the Partnership’s financial
performance. Partnership cash flows and Partnership cash flows allocated to
common units are provided as a supplement to financial results and are not meant
to be considered in isolation or as substitutes for financial results prepared
in accordance with GAAP.







Three
      months ended
              
              Nine
      months ended(unaudited)
              
              September
      30,
              
              September
      30,(millions
      of dollars except per common unit amounts)
              2009
              
              2008
              
              2009
              
              2008Net
      income(a)
              
              
              27.4
              
              
              
              33.0
              
              
              
              81.2
              
              
              
              93.9North
      Baja's contribution prior to acquisition(a)
              
              
              -
              
              
              
              (4.7
              )
              
              
              (8.3
              )
              
              
              (12.8
              )Net
      income prior to recast
              
              
              27.4
              
              
              
              28.3
              
              
              
              72.9
              
              
              
              81.1Add:Cash
      distributions from Great Lakes(b)
              
              
              19.8
              
              
              
              19.3
              
              
              
              54.0
              
              
              
              55.0Cash
      distributions from Northern Border(b)
              
              
              11.8
              
              
              
              22.6
              
              
              
              58.5
              
              
              
              72.0Cash
      flows provided by North Baja's operating activities
              
              
              8.5
              
              
              
              -
              
              
              
              8.5
              
              
              
              -Cash
      flows provided by Tuscarora's operating activities
              
              
              6.9
              
              
              
              7.2
              
              
              
              18.9
              
              
              
              17.347.0
              
              
              
              49.1
              
              
              
              139.9
              
              
              
              144.3Less:Equity
      income from investment in Great Lakes
              
              
              (13.2
              )
              
              
              (12.0
              )
              
              
              (45.6
              )
              
              
              (44.4
              )Equity
      income from investment in Northern Border
              
              
              (10.5
              )
              
              
              (19.9
              )
              
              
              (31.5
              )
              
              
              (48.1
              )North
      Baja's net income
              
              
              (6.2
              )
              
              
              -
              
              
              
              (6.2
              )
              
              
              -Tuscarora's
      net income
              
              
              (4.1
              )
              
              
              (3.9
              )
              
              
              (12.3
              )
              
              
              (11.4
              )(34.0
              )
              
              
              (35.8
              )
              
              
              (95.6
              )
              
              
              (103.9
              )Partnership
      cash flows prior to recast
              
              
              40.4
              
              
              
              41.6
              
              
              
              117.2
              
              
              
              121.5Partnership
      cash flows prior to recast allocated to general partner (c)
              
              
              (0.7
              )
              
              
              (3.2
              )
              
              
              (7.1
              )
              
              
              (9.4
              )Partnership
      cash flows prior to recast allocated to common units
              
              
              39.7
              
              
              
              38.4
              
              
              
              110.1
              
              
              
              112.1Cash
      flows provided by North Baja's pre-acquisition operating activities(a)
              
              
              -
              
              
              
              5.2
              
              
              
              9.7
              
              
              
              14.0Cash
      distributions declared
              
              
              (30.7
              )
              
              
              (27.8
              )
              
              
              (89.2
              )
              
              
              (83.0
              )Cash
      distributions declared per common unit(d)
              
              $
              0.730
              
              
              $
              0.705
              
              
              $
              2.165
              
              
              $
              2.110Cash
      distributions paid
              
              
              (30.7
              )
              
              
              (27.8
              )
              
              
              (86.3
              )
              
              
              (80.8
              )Cash
      distributions paid per common unit(d)
              
              $
              0.730
              
              
              $
              0.705
              
              
              $
              2.140
              
              
              $
              2.070Weighted
      average common units outstanding (millions)
              
              
              41.2
              
              
              
              34.9
              
              
              
              37.0
              
              
              
              34.9




27


(a)
      Because North Baja was acquired from TransCanada, the acquisition was
      accounted for as a transaction between entities under common control,
      similar to a pooling of interests, whereby the assets and liabilities of
      North Baja were recorded at TransCanada’s carrying value and the
      Partnership’s historical financial information was recast to include the
      acquired entity for all periods presented. To calculate recasted
      partnership cash flows, add partnership cash flows prior to recast and
      cash flows provided by North Baja's pre-acquisition operating
      activities.(b)
      In accordance with the cash distribution policies of the respective
      pipeline assets, cash distributions from Great Lakes and Northern Border
      are based on their respective prior quarter financial results, except that
      the distribution paid by Northern Border in the third quarter of 2008
      included a special distribution of $16.4 million (Partnership share - $8.2
      million) related to the sale of Bison.(c)
      Partnership cash flows prior to recast allocated to general partner
      represents the cash distributions declared to the general partner with
      respect to its two per cent interest plus an amount equal to incentive
      distributions. Prior to 2009, Partnership cash flows allocated to general
      partner were based on the cash distributions paid during the quarter to
      the general partner. As a result of the retrospective application of ASC
      260-10-55 Earnings Per Share – Overall – Implementation Guidance and
      Illustrations – Master Limited Partnerships, Partnership cash flows
      allocated to general partner in the third quarter of 2008 remained the
      same. Partnership cash flows allocated to the general partner for the nine
      months ended September 30, 2008 increased from $8.6 million to $9.4
      million.(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 per cent interest plus an amount equal to
      incentive distributions.


Third
Quarter 2009 Compared with Third Quarter 2008


Partnership
cash flows decreased $1.2 million to $40.4 million for the third quarter of 2009
compared to $41.6 million, prior to recast, for the same period last year. This
decrease is primarily a result of decreased cash distributions from Northern
Border, partially offset by cash flows provided by North Baja’s operating
activities of $8.5 million. Northern Border’s decreased distribution was
primarily due to a special one-time distribution for the proceeds received in
connection with the sale of Bison in 2008 andlower
net income, partially offset by a reduction in maintenance capital expenditures.
As the North Baja acquisition was accounted for as a transaction between
entities under common control, North Baja contributed $5.2 million to
partnership cash flows for the quarter ended September 30, 2008.




The
Partnership paid distributions of $30.7 million in the third quarter of 2009, an
increase of $2.9 million compared to the same period in the prior year due to an
increase in the number of common units outstanding, in addition to increases in
quarterly per common unit distribution amounts. In the third quarter of 2009,
proceeds from equity issuances of $80.0 million were used to partially fund the
acquisition of North Baja. The Partnership funded the balance of the acquisition
cost with a $170.0 million draw on its Senior Credit Facility and cash on hand.
We borrowed an additional net $33.0 million from our Senior Credit Facility
during the three months ended September 30, 2009 to partially fund an equity
contribution of $38.0 million to Northern Border.




Nine
Months Ended September 30, 2009 Compared with Nine Months Ended September 30,
2008


Partnership
cash flows prior to recast decreased $4.3 million to $117.2 million for the nine
months ended September 30, 2009 compared to $121.5 million for the same period
of last year. This decrease is primarily a result of decreased cash
distributions from Northern Border, partially offset by cash flows provided by
North Baja’s operating activities of $8.5 million. Northern Border’s decreased
distribution was primarily due to lower net income, partially offset by a
reduction in maintenance capital expenditures. As the North Baja acquisition was
accounted for as a transaction between entities under common control, North Baja
contributed a total of $18.2 million and $14.0 million to partnership cash flows
for the nine months ended September 30, 2009 and 2008,
respectively.




The
Partnership paid distributions of $86.3 million in the nine months ended
September 30, 2009, an increase of $5.5 million compared to the same period in
the prior year due to an increase in the number of common units outstanding, in
addition to increases in quarterly per common unit distribution amounts. In the
third quarter of 2009, proceeds from equity issuances of $80.0 million were used
to partially fund the acquisition of North Baja. The Partnership funded the
balance of the acquisition cost with a $170.0 million draw on its Senior Credit
Facility and cash on hand. We borrowed an additional net $33.0 million from our
Senior Credit Facility during the nine months ended September 30, 2009 to
partially fund equity contributions of $42.3 million to Northern
Border.






28




LIQUIDITY
AND CAPITAL RESOURCES OF TC PIPELINES




Overview




Our
principal sources of liquidity include distributions received from our
investments in Great Lakes and Northern Border, operating cash flows from North
Baja and Tuscarora, 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.





The
Partnership’s Debt and Credit Facility




The
following table summarizes our debt and credit facility outstanding as of
September 30, 2009:





Payments
      Due by Period(unaudited)
                (millions
      of dollars)
              
              Total
              
              
              Less
      Than 1
                Year
              
              
              Long-term
                PortionSenior
      Credit Facility due 2011
              
              
              678.0
              
              
              
              -
              
              
              
              678.07.13%
      Series A Senior Notes due 2010
              
              
              49.7
              
              
              
              3.1
              
              
              
              46.67.99%
      Series B Senior Notes due 2010
              
              
              4.7
              
              
              
              0.5
              
              
              
              4.26.89%
      Series C Senior Notes due 2012
              
              
              5.1
              
              
              
              0.8
              
              
              
              4.3Total
              
              
              737.5
              
              
              
              4.4
              
              
              
              733.1


TC
PipeLines’ Senior Credit Facility consists of a $475.0 million senior term loan
and a $250.0 million senior revolving credit facility. At September 30, 2009,
the outstanding balance on our revolving credit facility was $203.0 million,
leaving $47.0 million available for future borrowings.




The
interest rate on the Senior Credit Facility averaged 1.01 per cent for the three
months ended September 30, 2009 (2008 – 3.31 per cent). For the nine months
ended September 30, 2009, the interest rate on the Senior Credit Facility
averaged 1.62 per cent (2008 – 3.93 per cent). After hedging activity, the
interest rate incurred on the Senior Credit Facility averaged 3.39 per cent for
the three months ended September 30, 2009 (2008 – 5.23 per cent) and 4.28 per
cent for the nine months ended September 30, 2009 (2008 – 5.18 per cent). Prior
to hedging activities, the interest rate was 0.78 per cent at September 30, 2009
(December 31, 2008 – 2.67 per cent). At September 30, 2009, we were in
compliance with our financial covenants.




Interest
Rate Swaps and Options


The
interest rate swaps and options are structured such that the cash flows match
those of the Senior Credit Facility. The notional amount hedged at September 30,
2009 was $375.0 million (December 31, 2008 - $475.0 million). At September 30,
2009, the fair value of the interest rate swaps accounted for as hedges was
negative $25.4 million (December 31, 2008 – negative $31.7 million). Under ASC 820 – Fair
Value Measurements and Disclosures, financial instruments are recorded at
fair value on a recurring basis. We have classified all our derivative
financial instruments as level II where the fair value is determined by using
valuation techniques that refer to observable market data or estimated market
prices.During
the three and nine months ended September 30, 2009, we recorded interest expense
of $4.0 million and $10.9 million in regards to the interest rate swaps and
options. In 2008, we recorded interest expense of $2.4 million and $4.7 million
for the three and nine months ended September 30 in regards to the interest rate
swaps and options. These expenses are included in the line item ‘Financial
charges, net and other’ on the Partnership’s consolidated statement of
income.




2009
Third Quarter Cash Distribution




On
October 22, 2009, the Board of Directors of the general partner declared the
Partnership’s 2009 third quarter cash distribution in the amount of $0.73 per
common unit. This cash distribution, totaling $30.7 million, will be paid on
November 13, 2009 to unitholders of record as of October 31, 2009, in the
following manner: $30.1 million to common unitholders (including $4.2 million to
the general partner as holder of 5,797,106 common units and $8.2 million to
TransCan Northern Ltd. as holder of 11,287,725 common units) and $0.6 million to
the general partner in respect of its two per cent general partner interest.
This distribution was calculated pursuant to the Second Amended and Restated
Agreement of Limited Partnership dated July 1, 2009 which reflects the IDR
restructuring.






29




2009
Capital Requirements




Northern
Border’s distribution policy adopted in 2006 defines minimum equity to total
capitalization to be used by its Management Committee to establish the timing
and amount of required equity contributions. In accordance with this policy,
Northern Border required an equity contribution of $76.0 million in the third
quarter of 2009, of which the Partnership’s share was $38.0 million, to
partially fund $200.0 million of debt which matured on September 1, 2009. The
Partnership financed this equity contribution with a combination of debt and
operating cash flows. In the first quarter of 2009, the Partnership made an
equity contribution of $4.3 million to Northern Border, representing the
Partnership’s 50 per cent share of an $8.6 million cash call issued by Northern
Border to complete the Des Plaines Project.




LIQUIDITY
AND CAPITAL RESOURCES OF OUR PIPELINE SYSTEMS




Overview




Our
pipeline systems’ principal sources of liquidity are cash generated from
operating activities, bank credit facilities and equity contributions from their
partners. Our pipeline systems fund their operating expenses, debt service and
cash distributions to partners primarily with operating cash flow.




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’
partners. The ability of our pipeline systems to access the debt capital markets
under reasonable terms depends on their financial position, credit ratings and
market conditions.




Our
pipeline systems believe that their 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. 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.




Debt
of Great Lakes




The
following table summarizes Great Lakes’ debt outstanding as of September 30,
2009:





Payments
      Due by Period(unaudited)
                (millions
      of dollars)
              
              Total
              
              
              Less
      than 1 year
              
              
              Long-term
                Portion8.74%
      series Senior Notes due 2009 to 2011
              
              
              30.0
              
              
              
              10.0
              
              
              
              20.06.73%
      series Senior Notes due 2010 to 2018
              
              
              81.0
              
              
              
              9.0
              
              
              
              72.09.09%
      series Senior Notes due 2012 to 2021
              
              
              100.0
              
              
              
              -
              
              
              
              100.06.95%
      series Senior Notes due 2019 to 2028
              
              
              110.0
              
              
              
              -
              
              
              
              110.08.08%
      series Senior Notes due 2021 to 2030
              
              
              100.0
              
              
              
              -
              
              
              
              100.0Total
              
              
              421.0
              
              
              
              19.0
              
              
              
              402.0
  Great
Lakes is required to comply with certain financial, operational and legal
covenants. Under the most restrictive covenants in the Senior Note
Agreements, approximately $227.0 million of Great Lakes’ partners’ capital was
restricted as to distributions as of September 30, 2009 (December 31, 2008 -
$232.0 million). As at September 30, 2009, Great Lakes was in compliance with
all of its financial covenants.






30




Debt
and Credit Facility of Northern Border




The
following table summarizes Northern Border’s debt and credit facility
outstanding as of September 30, 2009:




Payments
      Due by Period(unaudited)
                  (millions
      of dollars)
                
                Total
                
                
                Less
      than 1 year
                
                
                Long-term
                  Portion$250
      million credit agreement due 2012 (a)
                
                
                209.0
                
                
                
                -
                
                
                
                209.06.24%
      senior notes due 2016
                
                
                100.0
                
                
                
                -
                
                
                
                100.07.50%
      senior notes due 2021
                
                
                250.0
                
                
                
                -
                
                
                
                250.0Total
                
                
                559.0
                
                
                
                -
                
                
                
                559.0
  (a)Northern Border is required to pay a facility fee of 0.05% on the
      principal commitment amount of its credit
agreement.


As of
September 30, 2009, Northern Border had outstanding borrowings of $209.0 million
under its $250.0 million revolving credit agreement and was in compliance with
the covenants of the agreement. The weighted average interest rate related to
the borrowings on its credit agreement was 0.66 per cent at September 30,
2009.




Senior
Notes


On August
26, 2009, Northern Border issued $100.0 million of 6.24 per cent Senior Notes
due August 26, 2016. The proceeds of the 6.24 per cent Senior Notes, along with
equity contributions, borrowings under the revolving credit agreement and
working capital, were used to repay $200.0 million of 7.75 per cent Senior Notes
due September 1, 2009.




Interest
Rate Collar Agreement


At
September 30, 2009, Northern Border’s balance sheet reflected an unrealized loss
of approximately $0.4 million with a corresponding increase to accumulated other
comprehensive loss related to the changes in fair value of its interest rate
collar agreement (the “Collar Agreement”) since inception. During the three and
nine months ended September 30, 2009, Northern Border recorded interest expense
of $1.3 million and $3.3 million, respectively, under the Collar Agreement. The
hedge was effective for the three and nine months ended September 30, 2009;
therefore, it had no impact on net income.




RELATED
PARTY TRANSACTIONS




Operating
Agreements




Our
pipeline systems, including the recently acquired North Baja, are operated by
TransCanada and its affiliates pursuant to operating agreements. During the
second quarter of 2009, TransCanada internally announced a reorganization of its
U.S. operations, which will include the relocation of some employees and
equipment, and some severance costs, with certain operational cost savings to be
expected in the future. According to our operating agreements, some of these
costs could be borne by our pipeline systems. It is expected that the
reorganization will be complete in 2010, with some activities occurring in
2009.




Acquisition
of North Baja and IDR Structuring




In
connection with the acquisition of North Baja on July 1, 2009, the following
transactions were consummated with certain TransCanada affiliates. The
Partnership entered into a Common Unit Purchase Agreement (Purchase Agreement)
with TransCan Northern Ltd. (TransCan Northern) to sell 2,609,680 newly issued,
unregistered common units representing limited partner interests in the
Partnership to TransCan Northern at a price per common unit of $30.042 for an
aggregate amount of approximately $78.4 million (Offering). The Offering closed
on July 1, 2009. TransCan Northern is a wholly-owned subsidiary of
TransCanada, which is the ultimate parent company of TC PipeLines GP, Inc., the
sole general partner of the Partnership.




The
Partnership used the net proceeds from the Offering to fund a portion of the
cash consideration for the Partnership’s acquisition of the 100 per cent
interest in North Baja Pipeline, LLC (Acquisition).






31




The
Partnership entered into an Exchange Agreement with TC PipeLines GP, Inc.
pursuant to which the Partnership issued to the general partner Revised IDRs and
3,762,000 newly issued, unregistered common units representing limited partner
interests in the Partnership in exchange for the cancellation of the Old IDRs
under the Amended and Restated Agreement of Limited Partnership of the
Partnership.




The
Revised IDRs provide for distribution levels at two per cent, down from the
distribution levels of the Old IDRs at 50 per cent. The distribution levels of
the Revised IDRs increase to 15 per cent and are capped at 25 per cent when
quarterly distributions increase to $0.81 and $0.88 per common unit or $3.24 and
$3.52 per common unit on an annualized basis, respectively. The quarterly
distribution level of the Old IDRs was $0.705 per common unit or $2.82 on an
annualized basis.




As a
result of the closing of the Acquisition and the transactions pursuant to the
Purchase Agreement and the Exchange Agreement, TransCanada and its affiliates
own 17,084,831 common units, representing an aggregate 40.6 per cent limited
partner interest in the Partnership. In addition, the general partner owns
an aggregate two per cent general partner interest in the Partnership (and its
subsidiary limited partnerships on a combined basis) through which it manages
and operates the Partnership. As a result, TransCanada’s aggregate
ownership interest in the Partnership (and its subsidiary limited partnerships
on a combined basis) is 42.6 per cent by virtue of its indirect ownership of the
general partner and 40.6 per cent aggregate limited partner
interest.




The
conflicts committee of the board of directors of the general partner, which is
composed entirely of independent directors, unanimously recommended approval by
the board of directors of the Acquisition, the Offering, the Exchange Agreement
and the terms of the Second Amended and Restated Agreement of Limited
Partnership of the Partnership. The conflicts committee retained
independent legal and financial advisors to assist it in evaluating and
negotiating the Acquisition, the Offering and the Exchange Agreement. The board
of directors of the General Partner unanimously approved the terms of the
Acquisition, the Offering, the Exchange Agreement and the Second Amended and
Restated Agreement of Limited Partnership of the Partnership.




Transportation
Agreements




Great
Lakes earns transportation revenues from TransCanada and its affiliates under
fixed price contracts with remaining terms ranging from one to nine years. Great
Lakes earned $33.1 million of transportation revenues under these contracts for
the three months ended September 30, 2009 (2008 - $40.5 million). This amount
represents 48.0 per cent of total revenues earned by Great Lakes for the three
months ended September 30, 2009 (2008 – 61.0 per cent). $15.4 million of
affiliated revenue is included in our equity income from Great Lakes for the
three months ended September 30, 2009 (2008 - $18.8 million).




Great
Lakes earned $105.5 million of transportation revenues from TransCanada and its
affiliates for the nine months ended September 30, 2009 (2008 - $108.7 million).
This amount represents 47.9 per cent of total revenues earned by Great Lakes for
the nine months ended September 30, 2009 (2008 – 51.0 per cent). $49.0 million
of this transportation revenue is included in our equity income from Great Lakes
for the nine months ended September 30, 2009 (2008 - $50.5
million).




At
September 30, 2009, $9.3 million is included in Great Lakes’ receivables in
regards to the transportation contracts with TransCanada and its affiliates
(December 31, 2008 - $12.5 million).




Great
Lakes has approximately 830 MDth/d of longhaul capacity under contract expiring
on October 31, 2010 with its largest shipper, TransCanada. On November 3,
2009, Great Lakes and TransCanada signed an agreement to renew 470 MDth/d of
capacity under a contract expiring on October 31, 2011. The remaining
approximately 360 MDth/d of capacity will expire October 31, 2010. Great Lakes
will actively market and post the expiring capacity for shipper interest in
early 2010.




Lease
Agreements




In July
2009, Northern Border entered into an agreement with Northern Border’s operator
and TransCanada Keystone Pipeline LP (Keystone), an affiliate of TC PipeLines,
LP, for Keystone to lease vehicles and equipment from Northern Border. There
have not been any charges under this agreement for the three months ended
September 30, 2009.




Please
read Note 8 within Item 1. “Financial Statements” for additional information
regarding related party transactions.






32




Item
3.                  Quantitative
and Qualitative Disclosures About Market Risk




OVERVIEW




Our
exposure to market risk discussed below includes forward-looking statements and
represents an estimate of possible changes in future earnings that would occur
assuming hypothetical future movements in interest rates. Our views on market
risk are not necessarily indicative of actual results that may occur and do not
represent the maximum possible gains and losses that may occur, since actual
gains and losses will differ from those estimated, based on actual fluctuations
in interest rates and the timing of transactions.




We are
exposed to market risk due to interest rate fluctuations. Market risk is the
risk of loss arising from adverse changes in market rates. We utilize financial
instruments to manage the risks of certain identifiable or anticipated
transactions to achieve a more predictable cash flow. Our risk management
function follows established policies and procedures to monitor interest rates
to ensure our hedging activities mitigate market risks. 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.




In
accordance with ASC 815 –
Derivatives and Hedging, we record derivative financial instruments on
the balance sheet as assets and liabilities based on fair value. We estimate the
fair value of financial instruments using available market information and
appropriate valuation techniques. Changes in these financial instruments’ fair
value are recognized in earnings unless the instrument qualifies as a hedge
under ASC
815 and meets specific hedge accounting criteria. Qualifying 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 incur 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. 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.






33




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 London Interbank Offered Rate (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. The
notional amount hedged at September 30, 2009 was $375.0 million (December 31,
2008 - $475.0 million). $300.0 million of variable-rate debt is hedged by an
interest rate swap during the period from March 12, 2007 through December 12,
2011, where the weighted average fixed interest rate paid is 4.89 per cent.
$75.0 million of variable-rate debt is hedged by an interest rate swap during
the period from February 29, 2008 through February 28, 2011, where the fixed
interest rate paid is 3.86 per cent. The interest rate swaps and options are
structured such that the cash flows match those of the Senior Credit Facility.
The fair value of interest rate derivatives has been calculated using period-end
market rates. At September 30, 2009, the fair value of the Partnership’s
interest rate swaps accounted for as hedges was negative $25.4 million (December
31, 2008 – negative $31.7 million), of which $12.1 million is classified as a
current liability (December 31, 2008 - $11.8 million). The fair value of the
interest rate swaps is calculated using the period-end interest rate; therefore,
it is expected that this fair value will fluctuate over the year as interest
rates change.




At
September 30, 2009, we had $678.0 million outstanding on our Senior Credit
Facility. Utilizing the conditions of the interest rate swaps, if LIBOR interest
rates hypothetically increased by one per cent (100 basis points) compared to
the rates in effect as of September 30, 2009, our annual interest expense would
have increased and our net income would have decreased by $3.0 million; and if
LIBOR interest rates hypothetically decreased by one per cent (100 basis points)
compared to the rates in effect as of September 30, 2009, our annual interest
expense would have decreased and our net income would have increased by $3.0
million. These amounts have been determined by considering the impact of the
hypothetical interest rates on unhedged debt outstanding as of September 30,
2009.




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 agreement.
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, 2009, 63 per cent of Northern Border’s
outstanding debt was at fixed rates (December 31, 2008 – 71 per cent). Northern
Border utilized its Collar Agreement to limit the variability of the interest
rate on $140.0 million of variable-rate borrowings through October 30, 2009 to a
range between a floor of 4.35 per cent and a cap of 5.36 per cent.




Utilizing
the conditions of the Collar Agreement, if interest rates hypothetically
increased by one per cent (100 basis points) compared with rates in effect as of
September 30, 2009, Northern Border’s annual interest expense would increase and
its net income would decrease by approximately $0.7 million; and if interest
rates hypothetically decreased by one per cent (100 basis points) compared with
rates in effect as of September 30, 2009, Northern Border’s annual interest
expense would decrease and its net income would increase by approximately $0.7
million.




Great
Lakes 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
North Baja, as it currently does 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.




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
consist 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. At September 30, 2009, the
Partnership’s maximum counterparty credit exposure consisted of accounts
receivable of $5.8 million (December 31, 2008 - $2.9 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 deterioration of
global financial markets in 2008 and 2009, 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.






34




Liquidity
risk is the risk that the Partnership and our pipeline systems will not be able
to meet our financial obligations as they fall 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, 2009, the Partnership has a committed revolving bank line of
$250.0 million maturing in December 2011. As of September 30, 2009, the
outstanding balance on this facility was $203.0 million. In addition, at
September 30, 2009, Northern Border has a committed revolving bank line of
$250.0 million maturing in April 2012. As of September 30, 2009, $209.0 million
was drawn on this facility.




The state
of Minnesota currently requires Great Lakes to pay use tax on the value of the
shipper-provided compressor fuel burned in its Minnesota compressor
engines. Great Lakes is subject to primarily commodity price volatility and
some volume volatility in determining the amount of use tax owed. If
natural gas prices changed by $1 per million British thermal units, Great Lakes’
annual use tax expense would change by approximately $0.5 million.




The
Partnership does not have any material foreign exchange risks.




Item
4.                  Controls
and Procedures




EVALUATION
OF DISCLOSURE CONTROLS AND PROCEDURES




Based on
their evaluation of the Partnership’s disclosure controls and procedures as of
the end of the period covered by this quarterly report, the principal executive
officer and principal financial officer of the general partner of the
Partnership have concluded that the Partnership’s disclosure controls and
procedures were effective in ensuring 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 is recorded, processed, summarized and reported
within the time periods specified in the Securities and Exchange Commission’s
rules and forms and that information required to be disclosed by the Partnership
in the reports that the Partnership files or submits under the Exchange Act is
accumulated and communicated to the management of the general partner of the
Partnership, including the principal executive officer and principal financial
officer, as appropriate to allow timely decisions regarding required
disclosure.




Changes
in Internal Control Over Financial Reporting




During
the quarter ended September 30, 2009, there has been 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.


35


PART
II – OTHER INFORMATION






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, 2008.




Our
pipeline systems’ operations are regulated by federal, state and local agencies
responsible for environmental protection and operational safety, and costs of
environmental compliance and the costs of environmental liabilities could exceed
our estimates.




Risks of
substantial costs and liabilities are inherent in pipeline operations and each
of our pipeline systems may incur substantial costs and liabilities in the
future as a result of stricter environmental and safety laws, regulations, and
enforcement policies and claims for personal or property damages resulting from
our pipeline systems’ operations. Moreover, new, stricter environmental laws,
regulations or enforcement policies could be implemented that significantly
increase our pipeline systems’ compliance costs or the cost of any remediation
of environmental contamination that may become necessary, and these costs could
be material. For instance, we may be required to obtain and maintain permits and
approvals issued by various federal, state and local governmental authorities;
limit or prevent releases of materials from our operations in accordance with
these permits and approvals; and install pollution control equipment. Also,
under certain environmental laws and regulations, we may be exposed to
potentially substantial liabilities for any pollution or contamination that may
result from our operations.




The
U.S. Congress is actively considering federal legislation to reduce
emissions of “greenhouse gases” (including carbon dioxide and methane). The
House of Representatives narrowly approved the Waxman-Markey Bill on June 26,
2009 (“Waxman-Markey Bill”). The legislation is now under consideration by the
Senate, and could be rejected by the Senate, or could be significantly amended
before being approved by the Senate. Several states of the U.S. have
already taken legal measures to reduce emissions of greenhouse gases. At this
time, it is unclear what our pipeline systems future environmental compliance
costs relating to greenhouse gases will be or if the Waxman-Markey Bill will be
adopted in its current form. Various federal and state legislative proposals
have been made over the last several years and it is possible that legislation
will be enacted in the future that could negatively impact the operations of our
pipeline systems and our financial results. The level of such impact will likely
depend upon whether any of our pipeline systems’ facilities will be directly
responsible for compliance with any adopted program; whether cost containment
measures will be available; the ability of our pipeline systems to recover
compliance costs from their customers; and the manner in which allowances are
provided. At the federal regulatory level, the U.S. Environmental Protection
Agency (EPA) has requested public comments on the potential regulation of
greenhouse gases under the Clean Air Act. It is uncertain whether the EPA will
proceed with adopting final rules or whether the regulation of greenhouse gases
will be addressed in federal and state legislation.




It is
uncertain what impact these actions might have on our pipeline systems until
further definition is known; there is risk that such future measures could
result in changes to the operations of our pipeline systems and to the
consumption and demand for natural gas. If passed, changes to the operations of
our pipeline systems could include increased costs to (i) operate and
maintain our facilities; (ii) install new emission controls on our
facilities; (iii) construct new facilities; and (iv) administer and manage
any greenhouse gas emissions reduction program that may be applicable to our
operations. Separately, the EPA has proposed regulations relating to monitoring
and reporting greenhouse gas emissions pursuant to its authority under the Clean
Air Act. While we may be able to include some or all of the costs associated
with our environmental liabilities and environmental compliance, including
future compliance with greenhouse gas laws and regulations, in the rates charged
by our pipeline systems, their ability to recover such costs is uncertain and
may depend on events beyond our control including the outcome of future rate
proceedings before the FERC and the provisions of any final
legislation.




One of
our pipeline systems, Northern Border, received a Notice of Violation (NOV) from
the EPA on February 2, 2009 alleging that Northern Border was in violation of
certain regulations pursuant to the Clean Air Act regarding a
compressor station on its system. Northern Border disputes the NOV. At this
time, Northern Border is unable to reasonably estimate the cost of any
associated corrective action or the possibility or amount of any
penalty.






36




Our
pipeline systems may not be able to maintain existing customers or acquire new
customers when the current shipper contracts expire or customers may recontract
for shorter periods or at less than maximum rates.




The
ability to extend and replace contracts on terms comparable to prior contracts
or on any terms at all could be adversely affected by factors,
including:




·
            the
      available supply of natural gas in Canada and the
  U.S.;


·
            competition
      from alternative sources of supply in the
U.S.;


·
            competition
      from other pipelines, including their transportation rates or through
      their access to upstream supplies, as well as the proposed construction by
      other companies of additional pipeline
capacity;


·
            the
      price of, and demand for, natural gas in markets served by our pipeline
      systems;


·
            the
      liquidity and willingness of shippers to contract for transportation
      services; and


·
            regulatory
      actions.




Ongoing
changes in these factors and customers’ ability to adjust to changing market
conditions may cause Great Lakes and Northern Border to sell a significant
portion of available capacity on a short-term basis. The weighted average lives
of Great Lakes’ and Northern Border’s contracts have generally declined over
time. As of September 30, 2009, the weighted average remaining lives of
Great Lakes’ and Northern Border’s contracts were 1.9 years and 2.0 years,
respectively. Great Lakes has approximately 830 thousand dekatherms per day
(MDth/d) of longhaul capacity under contract expiring on October 31, 2010 with
its largest shipper, TransCanada. Great Lakes and TransCanada renewed contracts
for one year for 470 MDth/d of capacity, some at a slightly discounted rate, and
agreed to provide other transportation services. The remaining approximate 360
MDth/d of capacity will expire October 31, 2010.




Additionally,
if the forward natural gas basis differentials do not support maximum rates,
Great Lakes and Northern Border may sell portions of their capacity at
discounted rates. Any inability by Great Lakes and Northern Border to renew
existing contracts at maximum rates, or at all, or to enter into new
long-term shipper contracts for upcoming excess capacity may have an
adverse impact on their revenues and, as a result, cash distributions made
to us.


37


Item 6.
              ExhibitsNo.
              Description*3.1
              Second
      Amended and Restated Agreement of Limited Partnership of TC PipeLines, LP
      dated July 1, 2009 (Exhibit 3.1 to TC PipeLines, LP’s Form 8-K filed on
      July 1, 2009 (File No. 000-26091)).*10.1
              Common
      Unit Purchase Agreement dated July 1, 2009 by and between TC PipeLines, LP
      and TransCan Northern Ltd. (Exhibit 10.1 to TC PipeLines, LP’s Form 8-K
      filed on July 1, 2009 (File No. 000-26091)).*10.2
              Management
      Services Agreement dated January 1, 2002 by and between Gas Transmission
      Service Company, LLC (formally PG&E Gas Transmission Service Company,
      LLC) and North Baja Pipeline, LLC. (Exhibit 10.2 to TC PipeLines, LP’s
      Form 10-Q filed on August 4, 2009 (File No.
000-26091)).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.* Indicates exhibits
      incorporated by reference.






38


SIGNATURES
   Pursuant
to the requirements of the Securities and Exchange Act of 1934, the Registrant
has duly caused this report to be signed on its behalf by the undersigned
thereunto duly authorized.
  TC
      PipeLines, LP(a
      Delaware Limited Partnership)By:
                  TC
      PipeLines GP, Inc., its general partnerDate:
                  November
      6, 2009
                  By:
                  /s/  Russell
      K. Girling
                    Russell
      K. Girling
                    Chairman,
      Chief Executive Officer and Director
                    TC
      PipeLines GP, Inc. (Principal Executive Officer)Date:
                  November
      6, 2009
                  By:
                  /s/  Amy
      W. Leong
                    Amy
      W. Leong
                    Controller
                    TC
      PipeLines GP, Inc. (Principal Financial
Officer)
       39