##### Table of Contents



UNITED STATES SECURITIES AND
    EXCHANGE COMMISSIONWashington, D.C.
    20549
      Form 10-Q
   þ

QUARTERLY REPORT PURSUANT TO SECTION 13 or 15(d) 
    OF THE  SECURITIES EXCHANGE ACT OF 1934For the quarterly period ended
    September 30, 2007oro

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
    OF THE SECURITIES EXCHANGE ACT OF 1934For the transition period
    from          to   Commission File Number
    001-33303
      TARGA
    RESOURCES PARTNERS LP
 (Exact name of registrant as
    specified in its charter)
  Delaware(State or other jurisdiction
    of
    incorporation or organization)

65-1295427(I.R.S. Employer
    Identification No.)1000 Louisiana, Suite 4300, Houston, Texas(Address of principal
    executive offices)

77002(Zip
    Code)   Registrants telephone number, including area code:
 (713) 584-1000
  þ o
  Rule 12b-2
  Large
    accelerated
    filer o     Accelerated
    filer o     Non-accelerated
    filer þ  Rule 12b-2 o þ




---



##### 



PART I  FINANCIAL
    INFORMATIONItem 1.


Unaudited Consolidated Financial Statements


4Consolidated Balance Sheets at September 30,
    2007 and December 31, 2006


4Consolidated Statements of Operations for the
    three and nine months ended September 30, 2007 and 2006


5Consolidated Statements of Comprehensive Income
    (Loss) for the three and nine months ended September 30,
    2007 and 2006


6Consolidated Statement of Changes in
    Partners Capital for the nine months ended
    September 30, 2007


7Consolidated Statements of Cash Flows for the
    nine months ended September 30, 2007 and 2006


8Notes to Consolidated Financial Statements


9Item 2.


Managements Discussion and Analysis of
    Financial Condition and Results of Operations


28Item 3.


Quantitative and Qualitative Disclosures about
    Market Risk


42Item 4.


Controls and Procedures


44PART II  OTHER
    INFORMATIONItem 1.


Legal Proceedings


45Item 1A.


Risk Factors


45Item 2.


Unregistered Sales of Equity Securities and Use
    of Proceeds


65Item 3.


Defaults Upon Senior Securities


65Item 4.


Submission of Matters to a Vote of Security
    Holders


65Item 5.


Other Information


65Item 6.


Exhibits


65SIGNATURES


67Certification of CEO Pursuant to Section 302Certification of CFO Pursuant to Section 302Certification of CEO Pursuant to Section 906Certification of CFO Pursuant to Section 906   1




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##### Table of Contents



Form 10-Q,
  BBtu

Billion British thermal unitsBtu

British thermal unit, a measure of heating value/d

Per daygal

GallonsBbl

BarrelsMBbl

Thousand barrelsMcf

Thousand cubic feetMMBtu

Million British thermal unitsMMcf

Million cubic feetNGL(s)

Natural gas liquid(s)   Price IndexDefinitionsIF-NGPL MC

Inside FERC Gas Market Report, Natural Gas Pipeline,
    Mid-ContinentIF-Waha

Inside FERC Gas Market Report, West Texas WahaMB-OPIS

Oil Price Information Service, Mont Belvieu, TexasNY-WTI

NYMEX, West Texas Intermediate Crude Oil   Cautionary
    Statement About Forward-Looking Statements
    
    our ability to access the debt and equity markets, which will
    depend on general market conditions and the credit ratings for
    our debt obligations;
    our success in risk management activities, including the use of
    derivative financial instruments to hedge commodity and interest
    rate risks;
    the level of creditworthiness of counterparties to transactions;
    the amount of collateral required to be posted from time to time
    in our transactions;
    changes in laws and regulations, particularly with regard to
    taxes, safety and protection of the environment or the gathering
    and processing industry;
    the timing and extent of changes in natural gas, NGL and
    commodity prices, interest rates and demand for our services;
    weather and other natural phenomena;
    industry changes, including the impact of consolidations and
    changes in competition;
    our ability to obtain necessary licenses, permits and other
    approvals; 2




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##### Table of Contents




    our ability to grow through acquisitions or internal growth
    projects, and the successful integration and future performance
    of such assets;
    the level and success of natural gas drilling around our assets,
    and our success in connecting natural gas supplies to our
    gathering and processing systems;
    general economic, market and business conditions; and
    the risks described elsewhere in this quarterly report.     3




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##### Table of Contents



PART I 
    FINANCIAL INFORMATION
  Item 1.
    Consolidated
    Financial Statements  TARGA
    RESOURCES PARTNERS LP
  CONSOLIDATED BALANCE SHEETS
  September 30,


December 31,2007


2006(Unaudited)(In thousands)ASSETSCurrent assets:Cash and cash equivalents

$
28,441


$
Receivables from third parties


208



1,310Receivables from affiliated companies


32,437



Inventory


919



Assets from risk management activities


8,312



17,250Other


373



Total current assets


70,690



18,560Property, plant and equipment, at cost


1,146,566



1,129,210Accumulated depreciation


(107,981
)


(65,102
)Property, plant and equipment, net


1,038,585



1,064,108Long-term assets from risk management activities


5,755



15,541Other long-term assets


5,572



17,612Total assets

$
1,120,602


$
1,115,821LIABILITIES AND PARTNERS CAPITALCurrent liabilities:Accounts payable

$
2,392


$
2,789Accrued liabilities


37,015



28,832Current maturities of debt allocated from Parent






281,083Liabilities from risk management activities


12,540



Total current liabilities


51,947



312,704Long-term debt allocated from Parent






582,877Long-term debt


294,500



Long-term liabilities from risk management activities


10,094



96Other long-term liabilities


1,834



1,684Deferred income tax liability


3,529



2,844Commitments and contingencies (Note 9)Partners capital:Common unitholders (19,336,000 units issued and outstanding
    at September 30, 2007)


373,970



Subordinated unitholders (11,528,231 units issued and
    outstanding at September 30, 2007)


374,201



General partner (629,555 units issued and outstanding at
    September 30, 2007)


20,436



Accumulated other comprehensive income (loss)


(9,909
)


30,843Net parent investment






184,773Total partners capital


758,698



215,616Total liabilities and partners capital

$
1,120,602


$
1,115,821    4




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##### Table of Contents



TARGA
    RESOURCES PARTNERS LP
  CONSOLIDATED STATEMENTS OF OPERATIONS
  Three Months


Three Months


Nine Months


Nine MonthsEnded


Ended


Ended


EndedSeptember 30,


September 30,


September 30,


September 30,2007


2006


2007


2006(Unaudited)(In thousands, except per unit amounts)Revenues from third parties

$
6,951


$
3,505


$
17,335


$
8,233Revenues from affiliates


100,712



98,461



290,324



282,657Total operating revenues


107,663



101,966



307,659



290,890Costs and expenses:Product purchases from third parties


74,457



72,182



212,208



204,532Product purchases from affiliates


228



270



742



670Operating expenses, excluding DD&A


6,543



6,362



18,576



17,905Depreciation and amortization expense


14,396



14,274



42,880



41,713General and administrative expense


2,779



1,882



6,310



5,13798,403



94,970



280,716



269,957Income from operations


9,260



6,996



26,943



20,933Other expense:Interest expense, net


5,059







12,918



Interest expense from affiliates, net










9,827



Interest expense allocated from Parent






18,706







54,369Income (loss) before income taxes


4,201



(11,710
)


4,198



(33,436
)Deferred income tax expense


332



534



997



1,988Net income (loss)

$
3,869


$
(12,244
)

$
3,201


$
(35,424
)Allocation of net income (loss) for the three and nine months
    ended September 30, 2007:Net loss attributable to the period from January 1, 2007 to
    February 13, 2007

$







$
(6,861
)Net income attributable to the period from February 14,
    2007 to September 30, 2007


3,869







10,062Net income

$
3,869






$
3,201General partner interest in net income for the period from
    February 14, 2007 to September 30, 2007

$
77






$
201Common and subordinated unitholders interest in net income
    for the period from February 14, 2007 to September 30,
    2007

$
3,792






$
9,861Basic net income per common and subordinated unit

$
0.12






$
0.32Diluted net income per common and subordinated unit

$
0.12






$
0.32Basic average number of common and subordinated units outstanding


30,848







30,848Diluted average number of common and subordinated units
    outstanding


30,857







30,855    5




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##### Table of Contents



TARGA
    RESOURCES PARTNERS LP
  CONSOLIDATED STATEMENTS OF COMPREHENSIVE
    INCOME (LOSS)
  Three Months


Three Months


Nine Months


Nine MonthsEnded


Ended


Ended


EndedSeptember 30,


September 30,


September 30,


September 30,2007


2006


2007


2006(Unaudited)(In thousands)Net income (loss)

$
3,869


$
(12,244
)

$
3,201


$
(35,424
)Other comprehensive income (loss):Commodity hedges:Change in fair value of commodity hedges


(1,083
)


20,363



(34,418
)


32,370Reclassification adjustment for settled periods


(1,070
)


(343
)


(6,070
)


(343
)Related income taxes






(274
)


311



(274
)Interest rate swaps:Change in fair value of interest rate swaps






(638
)


(575
)


921Reclassification adjustment for settled periods






(182
)






(179
)Other comprehensive income (loss)


(2,153
)


18,926



(40,752
)


32,495Comprehensive income (loss)

$
1,716


$
6,682


$
(37,551
)

$
(2,929
)    6




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##### Table of Contents



TARGA
    RESOURCES PARTNERS LP
  CONSOLIDATED STATEMENT OF CHANGES IN
    PARTNERS CAPITAL
  AccumulatedOther


Partners CapitalNet Parent


Comprehensive


Limited Partners


GeneralInvestment


Income (Loss)


Common


Subordinated


Partner


Total(Unaudited)(In thousands)Balance at December 31, 2006

$
184,773


$
30,843


$



$



$



$
215,616Net loss attributable to the period from January 1, 2007
    through February 13, 2007


(6,861
)


















(6,861
)Other contributions


218,993



















218,993Book value of net assets contributed by Targa Resources, Inc. to
    the Partnership


(396,905
)










376,351



20,554



Issuance of units to public (including underwriter
    over-allotment), net of offering and other costs










377,455











377,455Non-cash compensation










128











128Other comprehensive loss






(40,752
)














(40,752
)Net income attributable to the period from February 14,
    2007 to September 30, 2007










6,176



3,685



201



10,062Distributions










(9,789
)


(5,835
)


(319
)


(15,943
)Balance at September 30, 2007

$



$
(9,909
)

$
373,970


$
374,201


$
20,436


$
758,698    7




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##### Table of Contents



TARGA
    RESOURCES PARTNERS LP
  CONSOLIDATED STATEMENTS OF CASH FLOWS
  Nine Months


Nine MonthsEnded


EndedSeptember 30,


September 30,2007


2006(Unaudited)(In thousands)Cash flows from operating activitiesNet income (loss)

$
3,201


$
(35,424
)Adjustments to reconcile net income (loss) to net cash provided
    by operating activities Depreciation


42,880



41,713Accretion of asset retirement obligations


118



108Amortization of debt issue costs


507



3,864Noncash compensation


128



Loss on sale of assets


2



Deferred income tax expense


997



1,988Risk management activities


198



Changes in operating assets and liabilities:Accounts receivable


7,521



369Inventory


(919
)


584Other


(2,307
)


630Accounts payable


(397
)


(10
)Accrued liabilities


8,183



(2,675
)Net cash provided by operating activities


60,112



11,147Cash flows from investing activitiesPurchases of property, plant and equipment


(17,362
)


(17,769
)Other


35



32Net cash used in investing activities


(17,327
)


(17,737
)Cash flows from financing activitiesProceeds from initial public offering


380,768



Costs incurred in connection with public offerings


(3,313
)


Distributions


(15,943
)


Proceeds from borrowings under credit facility


342,500



Costs incurred in connection with financing arrangements


(4,145
)


Repayments of loans:Affiliated


(665,692
)


Credit facility


(48,000
)


Deemed parent contributions (distributions)


(519
)


6,590Net cash provided by (used in) financing activities


(14,344
)


6,590Net change in cash and cash equivatents


28,441



Cash and cash equivalents, beginning of period






Cash and cash equivalents, end of period

$
28,441


$
Supplemental cash flow information:Net settlement of allocated indebtedness and debt issue costs

$
190,493


$
256Net contribution of affiliated receivables


38,856



Noncash long-term debt allocation of payments from Parent






3,699    8




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##### Table of Contents



Targa
    Resources Partners LP
  Notes
    to Consolidated Financial Statements
  Note 1 
    Description
    of Business and Basis of Presentation            Form 10-Q Regulation S-X.
 9




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##### Table of Contents



Targa
    Resources Partners LP
  Notes to
    Consolidated Financial
    Statements  (Continued)
  Form 10-Q Form 10-K
  Note 2 
    Accounting
    Policies  Asset Retirement Obligations. Accounting for Asset Retirement
    Obligations, Accounting for
    Conditional Asset Retirement Obligations. and/or
    Balance as of December 31, 2006

$
1,684Liabilities incurred


Change in estimate


Accretion expense


118Balance as of September 30, 2007

$
1,802   Cash and Cash Equivalents.
  Comprehensive Income.
  Debt Issue Costs.
 10




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##### Table of Contents



Targa
    Resources Partners LP
  Notes to
    Consolidated Financial
    Statements  (Continued)
  Environmental Liabilities. and/or
  Impairment of Long-Lived Assets.
  Income Taxes.
  Accounting for
    Uncertainty in Income Taxes
  Inventory Imbalance. and/or
  Net Income per Limited Partner Unit. 03-6, Participating Securities and the Two-Class Method
    Under FASB Statement No. 128
  EITF 03-6
 11




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##### Table of Contents



Targa
    Resources Partners LP
  Notes to
    Consolidated Financial
    Statements  (Continued)
    EITF 03-6 EITF 03-6
  Price Risk Management (Hedging). Accounting for Derivative
    Instruments and Hedging Activities,
      Property, Plant and Equipment.
  Asset Group

Range of YearsNatural gas gathering systems and processing facilities


15 to 25Office and miscellaneous equipment


3 to 7    12




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##### Table of Contents



Targa
    Resources Partners LP
  Notes to
    Consolidated Financial
    Statements  (Continued)
  Revenue Recognition.
  
    sales of natural gas, NGLs and condensate; and
    natural gas processing, from which we generate revenues through
    the compression, gathering, treating, and processing of natural
    gas.      EITF 99-19, Reporting Revenue Gross as a Principal versus Net as an
    Agent.
  Segment Information. Disclosures about Segments of an Enterprise and Related
    Information,
  Use of Estimates.
  Recent
    Accounting Pronouncements.
  Fair Value
    Measurements.
 13




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##### Table of Contents



Targa
    Resources Partners LP
  Notes to
    Consolidated Financial
    Statements  (Continued)
    The
    Fair Value Option for Financial Assets and Financial
    Liabilities, including an amendment of FASB Statement
    No. 115,
  Note 3 
    Partnership
    Equity and Distributions  General.
  Definition of Available Cash.
  
    less the amount of cash reserves established by the general
    partner to:  
    provide for the proper conduct of our business;
    comply with applicable law, any of our debt instruments or other
    agreements; or
    provide funds for distributions to the unitholders and to the
    general partner for any one or more of the next four quarters.  General Partner Interest and Incentive Distribution
    Rights.
    Subordinated Units.
 14




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##### Table of Contents



Targa
    Resources Partners LP
  Notes to
    Consolidated Financial
    Statements  (Continued)
    Distributions of Available Cash during the Subordination
    Period.
  
    first, 98% to the common unitholders, pro rata, and 2% to
    the general partner, until we distribute for each outstanding
    common unit an amount equal to the Minimum Quarterly
    Distribution for that quarter;
    second, 98% to the common unitholders, pro rata, and 2%
    to the general partner, until we distribute for each outstanding
    common unit an amount equal to any arrearages in payment of the
    Minimum Quarterly Distribution on the common units for any prior
    quarters during the subordination period;
    third, 98% to the subordinated unitholders, pro rata, and
    2% to the general partner, until we distribute for each
    subordinated unit an amount equal to the Minimum Quarterly
    Distribution for that quarter;
    fourth, 98% to all unitholders, pro rata, and 2% to the
    general partner, until each unitholder receives a total of
    $0.3881 per unit for that quarter (the First Target
    Distribution);
    fifth, 85% to all unitholders, 2% to the general partner
    and 13% to the holders of the Incentive Distribution Rights, pro
    rata, until each unitholder receives a total of $0.4219 per unit
    for that quarter (the Second Target Distribution);
    sixth, 75% to all unitholders, 2% to the general partner
    and 23% to the holders of the Incentive Distribution Rights, pro
    rata, until each unitholder receives a total of $0.50625 per
    unit for that quarter (the Third Target Distribution); and
    thereafter, 50% to all unitholders, 2% to the general
    partner and 48% to the holders of the Incentive Distribution
    Rights, pro rata, (the Fourth Target Distribution).  Distributions of Available Cash after the Subordination
    Period.
  
    first, 98% to all unitholders, pro rata, and 2% to the
    general partner, until each unitholder receives a total of
    $0.3881 per unit for that quarter;
    second, 85% to all unitholders, pro rata, 2% to the
    general partner and 13% to the holders of the Incentive
    Distribution Rights, until each unitholder receives a total of
    $0.4219 per unit for that quarter;
    third, 75% to all unitholders, pro rata, 2% to the
    general partner and 23% to the holders of the Incentive
    Distribution Rights, until each unitholder receives a total of
    $0.50625 per unit for that quarter; and
    thereafter, 50% to all unitholders, pro rata, 2% to the
    general partner and 48% to the holders of the Incentive
    Distribution Rights.  Note 4 
    Net
    Income per Limited Partner Unit   15




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##### Table of Contents



Targa
    Resources Partners LP
  Notes to
    Consolidated Financial
    Statements  (Continued)
     16




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##### Table of Contents



Targa
    Resources Partners LP
  Notes to
    Consolidated Financial
    Statements  (Continued)
    Three Months


Three Months


Nine Months








Nine MonthsEnded


Ended


Ended


Feb. 14, 2007 to


Jan. 1, 2007 to


EndedSeptember 30, 2007


September 30, 2006


September 30, 2007


September 30, 2007


Feb. 13, 2007


September 30, 2006Revenues from third parties

$
6,951


$
3,505


$
17,335


$
13,400


$
3,935


$
8,233Revenues from affiliates


100,712



98,461



290,324



252,155



38,169



282,657107,663



101,966



307,659



265,555



42,104



290,890Costs and expenses:Product purchases


74,685



72,452



212,950



184,255



28,695



205,202Operating expenses, excluding DD&A


6,543



6,362



18,576



15,760



2,816



17,905Depreciation and amortization expense


14,396



14,274



42,880



35,955



6,925



41,713General and administrative expense


2,779



1,882



6,310



5,608



702



5,13798,403



94,970



280,716



241,578



39,138



269,957Income from operations


9,260



6,996



26,943



23,977



2,966



20,933Other expenseInterest expense, net


5,059







12,918



12,918







Interest expense from affiliate, net










9,827







9,827



Interest expense allocated from Parent






18,706















54,369Income (loss) before income taxes


4,201



(11,710
)


4,198



11,059



(6,861
)


(33,436
)Deferred income tax expense


332



534



997



997







1,988Net income (loss)

$
3,869


$
(12,244
)

$
3,201


$
10,062


$
(6,861
)

$
(35,424
)General partner interest in net income

$
77






$
(6,660
)

$
201


$
(6,861
)Net income available to common and subordinated unitholders

$
3,792






$
9,861


$
9,861


$
Basic net income per common and subordinated unit

$
0.12






$
0.32


$
0.32Diluted net income per common and subordinated unit

$
0.12






$
0.32


$
0.32Basic average number of common and subordinated units outstanding


30,848







30,848



30,848Restrictive equivalents


9







7



7Diluted average number of common and subordinated units
    outstanding


30,857







30,855



30,855    17




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##### Table of Contents



Targa
    Resources Partners LP
  Notes to
    Consolidated Financial
    Statements  (Continued)
  Note 5 
    Related-Party
    Transactions  Targa
    Resources, Inc.
    Reimbursement
    of Operating and General and Administrative Expense
    
    general and administrative expenses, which are capped at
    $5 million annually for three years, subject to increases
    based on increases in the Consumer Price Index and subject to
    further increases in connection with expansions of our
    operations through the acquisition or construction of new assets
    or businesses with the concurrence of our conflicts committee;
    thereafter, our general partner will determine the general and
    administrative expenses to be allocated to us in accordance with
    our partnership agreement (see Note 11, Subsequent
    Events  Omnibus Agreement); and
    operations and certain direct general and administrative
    expenses, which are not subject to the $5 million cap for
    general and administrative expenses.    Sales to and purchases from affiliates.
  NGLs and Condensate Purchase Agreement.
  Natural Gas Purchase Agreement.
 18




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##### Table of Contents



Targa
    Resources Partners LP
  Notes to
    Consolidated Financial
    Statements  (Continued)
    Allocation of costs.
  Allocations of long-term debt, debt issue costs, interest
    rate swaps and interest expense
    Nine Months








Nine MonthsEnded


Feb. 14, 2007 to


Jan. 1, 2007 to


EndedSeptember 30, 2007


September 30, 2007


Feb. 13, 2007


September 30, 2006(In thousands)CashSales to affiliates

$
(290,324
)

$
(252,155
)

$
(38,169
)

$
(282,657
)Purchases from affiliates


742



665



77



670Allocations of general & administrative
    expenses  pre IPO


702







702



5,137Allocations of general & administrative expenses under
    Omnibus Agreement


5,608



5,608







Allocated interest














54,369Affiliate interest


9,837







9,837



Receivable from affiliates to be settled in cash


32,437



32,437







Payments made by the Parent


240,479



213,445



27,034



229,071$
(519
)

$



$
(519
)

$
6,590NoncashNet settlement of allocated indebtedness and debt issue costs









$
190,493


$
256Net contribution of affiliated receivables










38,856



Noncash long-term debt allocation of payments from Parent














3,699229,349



3,955$
228,830


$
10,545  19




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##### Table of Contents



Targa
    Resources Partners LP
  Notes to
    Consolidated Financial
    Statements  (Continued)
  Other
  Commodity hedges.
  Period

Commodity

Instrument Type


Daily Volumes

Average Price

IndexOct 2007  Dec 2007

Natural gas


Swap



4,200


MMBtu

$
9.14


per MMBtu


IF-WahaJan 2008  Dec 2008

Natural gas


Swap



3,847


MMBtu

$
8.76


per MMBtu


IF-WahaJan 2009  Dec 2009

Natural gas


Swap



3,556


MMBtu

$
8.07


per MMBtu


IF-WahaJan 2010  Dec 2010

Natural gas


Swap



3,289


MMBtu

$
7.39


per MMBtu


IF-WahaOct 2007  Dec 2007

NGLs


Swap



500


Bbl

$
37.80


per barrel


OPIS-MBJan 2008  Dec 2008

NGLs


Swap



375


Bbl

$
36.75


per barrel


OPIS-MBJan 2009  Dec 2009

NGLs


Swap



300


Bbl

$
35.39


per barrel


OPIS-MBOct 2007  Dec 2007

Condensate


Swap



319


Bbl

$
75.27


per barrel


NY-WTIJan 2008  Dec 2008

Condensate


Swap



264


Bbl

$
72.66


per barrel


NY-WTIJan 2009  Dec 2009

Condensate


Swap



202


Bbl

$
70.60


per barrel


NY-WTIJan 2010  Dec 2010

Condensate


Swap



181


Bbl

$
69.28


per barrel


NY-WTI   Note 6 
    Debt  Pre-IPO Indebtedness.
      Post-IPO Indebtedness. five-year
 20




---



##### Table of Contents



Targa
    Resources Partners LP
  Notes to
    Consolidated Financial
    Statements  (Continued)
      
    incur indebtedness;
    grant liens; and
    engage in transactions with affiliates.      Note 7 
    Derivative
    Instruments and Hedging Activities       21




---



##### Table of Contents



Targa
    Resources Partners LP
  Notes to
    Consolidated Financial
    Statements  (Continued)
    Natural
    Gas
  Avg. Price


MMBtu per DayInstrument Type

Index

$/MMBtu


2007


2008


2009


2010


2011


2012


Fair Value(In thousands)Swap

IF-NGPL MC

$
8.56



8,152






















$
1,836Swap

IF-NGPL MC


8.43







6,964



















3,958Swap

IF-NGPL MC


8.02











6,256















1,415Swap

IF-NGPL MC


7.43















5,685











202Swap

IF-NGPL MC


7.34



















2,750







72Swap

IF-NGPL MC


7.18























2,750



1408,152



6,964



6,256



5,685



2,750



2,750



7,623Swap

IF-Waha


8.73



5,460























1,258Swap

IF-Waha


8.53







4,657



















2,053Swap

IF-Waha


7.96











4,196















331Swap

IF-Waha


7.38















3,809











(262
)Swap

IF-Waha


7.36



















2,250







(35
)Swap

IF-Waha


7.18























2,250



115,460



4,657



4,196



3,809



2,250



2,250



3,356Total Swaps








13,612



11,621



10,452



9,494



5,000



5,000



10,979Floor

IF-NGPL MC


6.45



520























32Floor

IF-NGPL MC


6.55







1,000



















267Floor

IF-NGPL MC


6.55











850















205520



1,000



850















504Floor

IF-Waha


6.70



350























25Floor

IF-Waha


6.85







670



















173Floor

IF-Waha


6.55











565















115350



670



565















313Total Floors








870



1,670



1,415















817$
11,796  22




---



##### Table of Contents



Targa
    Resources Partners LP
  Notes to
    Consolidated Financial
    Statements  (Continued)
  NGLs
  Avg. Price


Barrels per DayInstrument Type

Index


$/gal


2007


2008


2009


2010


2011


2012


Fair Value(In thousands)Swap


OPIS-MB


$
0.96



3,416






















$
(3,925
)Swap


OPIS-MB



0.93







2,910



















(9,492
)Swap


OPIS-MB



0.89











2,548















(4,542
)Swap


OPIS-MB



0.87















2,159











(684
)Swap


OPIS-MB



0.90



















1,250







43Swap


OPIS-MB



0.90























750



1073,416



2,910



2,548



2,159



1,250



750


$
(18,493
)   Condensate
  Avg. Price


Barrels per DayInstrument Type

Index

$/Bbl


2007


2008


2009


2010


2011


2012


Fair Value(In thousands)Swap

NY-WTI

$
72.82



439






















$
(268
)Swap

NY-WTI


70.68







384



















(777
)Swap

NY-WTI


69.00











322















(491
)Swap

NY-WTI


68.10















301











(388
)Total Swaps








439



384



322



301











(1,924
)Floor

NY-WTI

$
58.60



25























0Floor

NY-WTI


60.50







55



















17Floor

NY-WTI


60.00











50















37Total Floors








25



55



50















54$
(1,870
)     Note 8 
    Income
    Taxes  Accounting for Income Taxes,
 23




---



##### Table of Contents



Targa
    Resources Partners LP
  Notes to
    Consolidated Financial
    Statements  (Continued)
  Note 9 
    Commitments
    and Contingencies  Environmental
  96-1, Environmental Remediation Liabilities.
      Litigation
    Casualty
    or Other Risks
           24




---



##### Table of Contents



Targa
    Resources Partners LP
  Notes to
    Consolidated Financial
    Statements  (Continued)
    Note 10 
    Employees
    and Equity Compensation Plans    Equity
    Compensation Plans.
     25




---



##### Table of Contents



Targa
    Resources Partners LP
  Notes to
    Consolidated Financial
    Statements  (Continued)
  Note 11 
    Subsequent
    Events  Distribution
    Underwriting
    Agreement
  30-day
    Acquired
    Businesses
    Supplement
    and Amendment of Credit Facility
     26




---



##### Table of Contents



Targa
    Resources Partners LP
  Notes to
    Consolidated Financial
    Statements  (Continued)
  Omnibus
    Agreement
                  Litigation
   27




---



##### Table of Contents



Item 2.
    Managements
    Discussion and Analysis of Financial Condition and Results of
    Operations  On February 14, 2007 we completed our initial public
    offering, or IPO, of common units. In the IPO, we issued
    19,320,000 common units (including 2,520,000 common units sold
    pursuant to the full exercise by the underwriters of their
    option to purchase additional common units) representing limited
    partner interests in us at a price of $21.00 per unit. We used
    the net proceeds of the IPO to pay expenses related to the IPO
    and our credit facility, for necessary operating cash reserve
    balances and to repay approximately $371.2 million of our
    outstanding affiliate indebtedness. Upon completion of the IPO,
    we had 19,320,000 common units, 11,528,231 subordinated units,
    and 629,555 general partner units outstanding.
  The following discussion analyzes our financial condition and
    results of operations. You should read the following discussion
    of our financial condition and results of operations in
    conjunction with our consolidated financial statements and notes
    included elsewhere in this
    Form 10-Q
    and in our Annual Report on
    Form 10-K
    for the year ended December 31, 2006. The historical
    financial statements included in this item reflect the results
    of operations of the assets contributed to us by Targa in
    connection with our IPO (the North Texas System). As
    used in this report, unless we indicate otherwise, the terms
    Partnership, our, we,
    us and similar terms refer to Targa Resources
    Partners LP, together with our subsidiaries, including Targa
    North Texas LP (TNT LP). The Partnership as used
    herein refers to the consolidated financial results and
    operations of TNT LP from its inception through its contribution
    to us, and to the Partnership thereafter. The term
    Targa refers to Targa Resources, Inc. and its
    subsidiaries and affiliates (other than us).
  Overview
      Factors
    That Significantly Affect Our Results
     28




---



##### Table of Contents



Form 10-K
  Form 10-K
    Affiliate Indebtedness and Borrowings.
      Hedging Activities. Form 10-K
  General and Administrative Expenses.
 29




---



##### Table of Contents



Schedule K-1 Form 10-K
  Working Capital Adjustments.
  Distributions to our Unitholders.
  Our
    Operations
     30




---



##### Table of Contents



Form 10-K
  How We
    Evaluate Our Operations
      Throughput Volumes, Facility Efficiencies and Fuel
    Consumption.
    Operating Margin.
 31




---



##### Table of Contents




    the financial performance of our assets without regard to
    financing methods, capital structure or historical cost basis;
    our operating performance and return on capital as compared to
    other companies in the midstream energy sector, without regard
    to financing or capital structure; and
    the viability of acquisitions and capital expenditure projects
    and the overall rates of return on alternative investment
    opportunities.  Operating Expenses.
  EBITDA.
  
    the financial performance of our assets without regard to
    financing methods, capital structure or historical cost basis;
    our operating performance and return on capital as compared to
    other companies in the midstream energy sector, without regard
    to financing or capital structure; and
    the viability of acquisitions and capital expenditure projects
    and the overall rates of return on alternative investment
    opportunities.       32




---



##### Table of Contents



Reconciliation
    of Non-GAAP Measures
  Three Months


Three Months


Nine Months


Nine MonthsEnded


Ended


Ended


EndedSeptember 30,


September 30,


September 30,


September 30,2007


2006


2007


2006(In millions)(unaudited)Reconciliation of EBITDA to net cash provided by
    operating activities:Net cash provided by operating activities

$
36.6


$
7.7


$
60.1


$
11.1Allocated interest expense from parent(1)






17.4







50.5Interest expense, net(1)


4.8







22.2



Changes in operating working capital which used (provided) cash:Accounts receivable


(19.2
)






(7.5
)


(0.4
)Accounts payable and accrued liabilities


(1.2
)


(4.1
)


(7.8
)


2.7Other, including changes in noncurrent assets and liabilities


2.6



0.3



2.8



(1.2
)EBITDA

$
23.6


$
21.3


$
69.8


$
62.7Reconciliation of EBITDA to net income (loss):Net income (loss )

$
3.9


$
(12.2
)

$
3.2


$
(35.4
)Add:Allocated interest expense, net






18.7







54.4Interest expense, net


5.0







22.7



Deferred income tax expense


0.3



0.5



1.0



2.0Depreciation and amortization expense


14.4



14.3



42.9



41.7EBITDA

$
23.6


$
21.3


$
69.8


$
62.7Reconciliation of operating margin to net income
    (loss):Net income (loss)

$
3.9


$
(12.2
)

$
3.2


$
(35.4
)Add:Depreciation and amortization expense


14.4



14.3



42.9



41.7Deferred income tax expense


0.3



0.5



1.0



2.0Allocated interest expense, net






18.7







54.4Interest expense, net


5.0







22.7



General and administrative expense


2.8



1.9



6.3



5.1Operating margin

$
26.4


$
23.2


$
76.1


$
67.8     (1)
    
    Net of amortization of debt issuance costs of $.2 million
    and $.5 million for the three and nine months ended
    September 30, 2007 and $1.3 million and
    $3.9 million for the three and nine months ended
    September 30, 2006.  Distributable Cash Flow.
 33




---



##### Table of Contents



Three Months


Three Months


Nine Months


Nine MonthsEnded


Ended


Ended


EndedSeptember 30,


September 30,


September 30,


September 30,2007


2006


2007


2006(In millions)(Unaudited)Reconciliation of Distributable cash flow to net
    income (loss):Net income (loss)

$
3.9


$
(12.2
)

$
3.2


$
(35.4
)Depreciation and amortization expense


14.4



14.3



42.9



41.7Deferred income tax expense


0.3



0.5



1.0



2.0Amortization of debt issue costs


0.2



1.3



0.5



3.9Maintenance capital expenditures


(4.0
)


(2.7
)


(9.3
)


(9.0
)Distributable cash flow

$
14.8


$
1.2


$
38.3


$
3.2   Critical
    Accounting Policies and Estimates
  Form 10-K
 34




---



##### Table of Contents



Results
    of Operations
    Three Months


Three Months


Nine Months


Nine MonthsEnded


Ended


Ended


EndedSeptember 30,


September 30,


September 30,


September 30,2007


2006


2007


2006(In millions of dollars, except operating and price data)Revenues

$
107.7


$
102.0


$
307.7


$
290.9Product purchases


74.7



72.4



213.0



205.2Operating expense, excluding DD&A


6.6



6.4



18.6



17.9Depreciation and amortization expense


14.4



14.3



42.9



41.7General and administrative expense


2.8



1.9



6.3



5.1Income from operations


9.2



7.0



26.9



21.0Interest expense, net


5.0



18.7



22.7



54.4Deferred income tax expense(1)


0.3



0.5



1.0



2.0Net income (loss)

$
3.9


$
(12.2
)

$
3.2


$
(35.4
)Financial data:Operating margin(2)

$
26.4


$
23.2


$
76.1


$
67.8EBITDA(3)

$
23.6


$
21.3


$
69.8


$
62.7Operating data:Gathering throughput,
    MMcf/d(4)


165.7



170.1



166.1



168.2Plant natural gas inlet,
    MMcf/d(5)(6)


160.8



164.0



160.3



161.6Gross NGL production, MBbl/d


19.2



19.1



18.0



18.8Natural gas sales, BBtu/d(6)


75.6



76.6



75.8



75.2NGL sales, MBbl/d


14.6



14.4



13.5



14.1Condensate sales, MBbl/d


1.6



1.5



1.8



1.6Natural Gas, per MMBtuAverage realized sales price

$
5.44


$
5.73


$
6.11


$
6.09Impact of hedging


0.49



0.12



0.42



0.04Average realized price

$
5.93


$
5.85


$
6.53


$
6.13NGL, per galAverage realized sales price

$
1.04


$
0.96


$
0.94


$
0.88Impact of hedging


(0.04
)


(0.01
)


(0.02
)


Average realized price

$
1.00


$
0.95


$
0.92


$
0.88Condensate, per BblAverage realized sales price

$
61.64


$
57.39


$
53.81


$
53.67Impact of hedging


(0.71
)


1.27



1.58



0.42Average realized price

$
60.93


$
58.66


$
55.39


$
54.09     (1)
    
    In May 2006, Texas adopted a margin tax effective
    January 1, 2007, consisting of a 1% tax on the amount by
    which total revenues exceed cost of goods sold. The amount
    presented represents our estimated liability for this tax. 35




---



##### Table of Contents



(2)
    
    Operating margin is total operating revenues less product
    purchases and operating expense. Please see
    Non-GAAP Financial
    Measures  Operating Margin included in this
    Item 2.(3)
    
    EBITDA is net income before interest, income taxes, depreciation
    and amortization. Please
    see Non-GAAP Financial
    Measures  EBITDA, included in this Item 2.(4)
    
    Gathering throughput represents the volume of natural gas
    gathered and passed through natural gas gathering pipelines from
    connections to producing wells and central delivery points.(5)
    
    Plant natural gas inlet represents the volume of natural gas
    passing through the meter located at the inlet of a natural gas
    processing plant.(6)
    
    Plant natural gas inlet volumes include producer
    take-in-kind,
    while natural gas sales exclude producer
    take-in-kind
    volumes.  Comparison
    of Three Months Ended September 30, 2007 to Three Months
    Ended September 30, 2006
    
    a net increase attributable to commodity sales volume of
    $0.7 million, consisting of an increase in NGL and
    condensate revenues of $0.8 million and $0.4 million,
    respectively, offset by a decrease in natural gas revenues of
    $0.5 million.
    a net increase attributable to commodity prices of
    $3.9 million, consisting of increases in natural gas, NGL
    and condensate revenues of $0.5 million, $3.0 million
    and $0.4 million, respectively.
    an increase in revenues from fee based processing activities of
    $1.1 million.           36




---



##### Table of Contents



Form 10-K
      Comparison
    of Nine Months Ended September 30, 2007 to Nine Months
    Ended September 30, 2006
    
    a net decrease attributable to commodity sales volume of
    $1.3 million, consisting of increases in natural gas and
    condensate revenues of $1.1 million and $3.1 million,
    respectively, offset by a decrease in NGL revenues of
    $5.5 million.
    an increase attributable to commodity prices of
    $15.6 million, consisting of increases in natural gas, NGL
    and condensate revenues of $8.3 million, $6.7 million
    and $0.6 million, respectively.
    an increase in revenues from fee based processing activities of
    $2.5 million.    2 2 2 2
 37




---



##### Table of Contents



Form 10-K
      Liquidity
    and Capital Resources
     38




---



##### Table of Contents




    cash generated from operations;
    borrowings under our revolving credit facility;
    issuance of additional partnership units; and
    debt offerings.          Working Capital.
  Description of Credit Agreement.
 39




---



##### Table of Contents




    incur indebtedness,
    grant liens, and
    engage in transactions with affiliates.    Contractual
    Obligations
    Payments Due By PeriodRemainingThree MonthsContractual Obligations

Total


of 2007


2008-2009


2010-2011


2012(In millions)Debt obligations

$
294.5


$



$



$



$
294.5Interest on debt obligations(1)


90.2



5.2



41.2



41.2



2.6$
384.7


$
5.2


$
41.2


$
41.2


$
297.1     (1)
    
    Represents interest expense on the Partnerships revolving
    credit facility using an average historical interest rate of 7%.  Cash
    Flow
    Nine Months


Nine MonthsEnded


EndedSeptember 30,


September 30,2007


2006(In millions)Net cash provided by operating activities

$
60.1


$
11.1Net cash used in investing activities


(17.3
)


(17.7
)Net cash provided by (used in) financing activities


(14.3
)


6.6  40




---



##### Table of Contents



Operating Activities.
  Investing Activities.
  Nine Months








Nine MonthsEnded


Feb. 14, 2007


Jan. 1, 2007 to


EndedSeptember 30,


to September 30,


Feb. 13,


September 30,2007


2007


2007


2006(In millions)Capital expenditures:Expansion

$
8.1


$
6.4


$
1.7


$
8.8Maintenance


9.3



7.8



1.5



9.0$
17.4


$
14.2


$
3.2


$
17.8   Financing Activities.
  Capital Requirements.
    Recent
    Accounting Pronouncements
    
    SFAS 157, Fair Value Measurements,and
    SFAS 159, Fair Value Option for Financial Assets
    and Financial Liabilities  Including an amendment of
    FASB Statement No. 115. 41




---



##### Table of Contents



Item 3.
    Quantitative
    and Qualitative Disclosures about Market Risk  Form 10-K
    Commodity
    Price Risk
  Form 10-K
   42




---



##### Table of Contents



Natural
    Gas
  Avg. Price


MMBtu per dayInstrument Type

Index


$/MMBtu


2007


2008


2009


2010


2011


2012


Fair Value(In thousands)Swap


IF-NGPL MC


$
8.56



8,152






















$
1,836Swap


IF-NGPL MC



8.43







6,964



















3,958Swap


IF-NGPL MC



8.02











6,256















1,415Swap


IF-NGPL MC



7.43















5,685











202Swap


IF-NGPL MC



7.34



















2,750







72Swap


IF-NGPL MC



7.18























2,750



1408,152



6,964



6,256



5,685



2,750



2,750



7,623Swap


IF-Waha



8.73



5,460























1,258Swap


IF-Waha



8.53







4,657



















2,053Swap


IF-Waha



7.96











4,196















331Swap


IF-Waha



7.38















3,809











(262
)Swap


IF-Waha



7.36



















2,250







(35
)Swap


IF-Waha



7.18























2,250



115,460



4,657



4,196



3,809



2,250



2,250



3,356Total Swaps










13,612



11,621



10,452



9,494



5,000



5,000



10,979Floor


IF-NGPL MC



6.45



520























32Floor


IF-NGPL MC



6.55







1,000



















267Floor


IF-NGPL MC



6.55











850















205520



1,000



850















504Floor


IF-Waha



6.70



350























25Floor


IF-Waha



6.85







670



















173Floor


IF-Waha



6.55











565















115350



670



565















313Total Floors










870



1,670



1,415















817$
11,796   NGLs
  Avg. Price


Barrels per dayInstrument Type

Index


$/gal


2007


2008


2009


2010


2011


2012


Fair Value(In thousands)Swap


OPIS-MB


$
0.96



3,416






















$
(3,925
)Swap


OPIS-MB



0.93







2,910



















(9,492
)Swap


OPIS-MB



0.89











2,548















(4,542
)Swap


OPIS-MB



0.87















2,159











(684
)Swap


OPIS-MB



0.90



















1,250







43Swap


OPIS-MB



0.90























750



1073,416



2,910



2,548



2,159



1,250



750


$
(18,493
)  43




---



##### Table of Contents



Condensate
  Avg. Price


Barrels per dayInstrument Type

Index


$/Bbl


2007


2008


2009


2010


2011


2012


Fair Value(In thousands)Swap


NY-WTI


$
72.82



439






















$
(268
)Swap


NY-WTI



70.68







384



















(777
)Swap


NY-WTI



69.00











322















(491
)Swap


NY-WTI



68.10















301











(388
)Total Swaps










439



384



322



301











(1,924
)Floor


NY-WTI


$
58.60



25























0Floor


NY-WTI



60.50







55



















17Floor


NY-WTI



60.00











50















37Total Floors










25



55



50















54$
(1,870
)     Interest
    Rate Risk
    Credit
    Risk
    Item 4.
    Controls
    and Procedures  Evaluation
    of Disclosure Controls and Procedures
  Rules 13a-15(e) 15d-15(e)
 44




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##### Table of Contents



PART II.
    OTHER INFORMATION
  Item 1.
    Legal
    Proceedings    Item 1A.
    Risk
    Factors  Limited partner interests are inherently different from
    capital stock of a corporation, although many of the business
    risks to which we are subject are consistent with those that
    would be faced by a corporation engaged in similar businesses.
    You should consider carefully the following risk factors
    together with all of the other information included in this
    report. .If any of the following risks were actually to occur,
    then our business, financial condition or results of operations
    could be materially adversely affected.
    and/or
  Risks
    Related to Our Business
  We may
    not have sufficient cash from operations following the
    establishment of cash reserves and payment of fees and expenses,
    including cost reimbursements to our general partner, to enable
    us to make cash distributions to holders of our common units and
    subordinated units at the minimum quarterly distribution rate
    under our cash distribution policy.
    
    the fees we charge and the margins we realize for our services;
    the prices of, levels of production of, and demand for, natural
    gas and natural gas liquids, or NGLs;
    the volume of natural gas we gather, treat, compress, process,
    transport and sell, and the volume of NGLs we process or
    fractionate and sell; 45




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##### Table of Contents




    the relationship between natural gas and NGL prices;
    cash settlements of hedging positions;
    the level of competition from other midstream energy companies;
    the level of our operating and maintenance and general and
    administrative costs; and
    prevailing economic conditions.    
    the level of capital expenditures we make;
    our ability to make borrowings under our amended credit facility
    to pay distributions;
    the cost of acquisitions;
    our debt service requirements and other liabilities;
    fluctuations in our working capital needs;
    general and administrative expenses, including expenses we incur
    as a result of being a public company;
    restrictions on distributions contained in our debt
    agreements; and
    the amount of cash reserves established by our general partner
    for the proper conduct of our business.    Our
    cash flow is affected by natural gas and NGL prices, and
    decreases in these prices could adversely affect our ability to
    make distributions to holders of our common units and
    subordinated units.
        
    the impact of seasonality and weather;
    general economic conditions;
    the level of domestic crude oil and natural gas production and
    consumption;
    the availability of imported natural gas, NGLs and crude oil; 46




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##### Table of Contents




    actions taken by foreign oil and gas producing nations;
    the availability of local, intrastate and interstate
    transportation systems;
    the availability and marketing of competitive fuels;
    the impact of energy conservation efforts; and
    the extent of governmental regulation and taxation.    Because
    of the natural decline in production from existing wells in our
    operating regions, our success depends on our ability to obtain
    new sources of supplies of natural gas and NGLs, which depends
    on certain factors beyond our control. Any decrease in supplies
    of natural gas or NGLs could adversely affect our business and
    operating results.
       47




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Our
    hedging activities may not be effective in reducing the
    variability of our cash flows and may, in certain circumstances,
    increase the variability of our cash flows. Moreover, our hedges
    may not fully protect us against volatility in basis
    differentials. Finally, the percentage of our equity commodity
    volumes that are hedged decreases substantially over
    time.
    We
    depend on one natural gas producer for a significant portion of
    our supply of natural gas. The loss of this customer or
    replacement of its contracts on less favorable terms could
    result in a decline in our volumes, revenues and cash available
    for distribution.
    If
    third-party pipelines and other facilities interconnected to our
    natural gas pipelines and processing facilities become partially
    or fully unavailable to transport natural gas and NGLs, our
    revenues and cash available for distribution could be adversely
    affected.
    We
    depend on our Chico system for a substantial portion of our
    revenues and if those revenues were reduced, there would be a
    material adverse effect on our results of operations and ability
    to make distributions to unitholders. To a similar but lesser
    degree, we are dependent on the Acquired Businesses, especially
    the Mertzon, Sterling and Gillis plants and their respective
    gathering systems.
   48




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##### Table of Contents




    competition from other systems that may be able to meet producer
    needs or supply end-user markets on a more cost-effective basis;
    operational problems such as catastrophic events at a processing
    plant or our gathering lines, labor difficulties or
    environmental proceedings or other litigation that compel
    cessation of all or a portion of the operations at a plant or on
    a system;
    an inability to obtain sufficient quantities of natural gas for
    a system at competitive terms; or
    reductions in exploration or production activity, or shut-ins by
    producers in the areas in which we operate.      We
    used the proceeds of our offering together with borrowings to
    purchase the Acquired Businesses. If the Acquired Businesses or
    future acquisitions do not perform as expected, our future
    financial performance may be negatively impacted.
      
    operating a significantly larger combined organization and
    adding operations;
    difficulties in the assimilation of the assets and operations of
    the acquired businesses, especially if the assets acquired are
    in a new business segment or geographic area;
    the risk that natural gas reserves expected to support the
    acquired assets may not be of the anticipated magnitude or may
    not be developed as anticipated;
    the failure to realize expected profitability or growth;
    the failure to realize any expected synergies and cost
    savings; and
    coordinating geographically disparate organizations, systems and
    facilities.    We are
    exposed to the credit risk of Targa and any material
    nonperformance by Targa could reduce our ability to make
    distributions to our unitholders.
   49




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Our
    general partner is an obligor under, and subject to a pledge
    related to, Targas credit facility; in the event Targa is
    unable to meet its obligations under that facility, or is
    declared bankrupt, Targas lenders may gain control of our
    general partner or, in the case of bankruptcy, our partnership
    may be dissolved.
    Our
    industry is highly competitive, and increased competitive
    pressure could adversely affect our business and operating
    results.
    Weather
    may limit our ability to operate our business and could
    adversely affect our operating results.
    Our
    business involves many hazards and operational risks, some of
    which may not be fully covered by insurance. If a significant
    accident or event occurs that is not fully insured, our
    operations and financial results could be adversely
    affected.
    
    damage to pipelines and plants, related equipment and
    surrounding properties caused by hurricanes, tornadoes, floods,
    fires and other natural disasters, explosions and acts of
    terrorism;
    inadvertent damage from third parties, including from
    construction, farm and utility equipment; 50




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
    leaks of natural gas, NGLs and other hydrocarbons or losses of
    natural gas or NGLs as a result of the malfunction of equipment
    or facilities; and
    other hazards that could also result in personal injury and loss
    of life, pollution and suspension of operations.  and/or
  Our
    debt levels may limit our flexibility in obtaining additional
    financing and in pursuing other business
    opportunities.
    
    our ability to obtain additional financing, if necessary, for
    working capital, capital expenditures, acquisitions or other
    purposes may be impaired or such financing may not be available
    on favorable terms;
    we will need a portion of our cash flow to make interest
    payments on our debt, reducing the funds that would otherwise be
    available for operations, future business opportunities and
    distributions to unitholders;
    our debt level will make us more vulnerable to competitive
    pressures or a downturn in our business or the economy
    generally; and
    our debt level may limit our flexibility in responding to
    changing business and economic conditions.   51




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Increases
    in interest rates could adversely affect our
    business.
    Restrictions
    in our amended credit facility may interrupt distributions to us
    from our subsidiaries, which may limit our ability to make
    distributions to you, satisfy our obligations and capitalize on
    business opportunities.
    We may
    incur significant costs and liabilities in the future resulting
    from a failure to comply with new or existing environmental
    regulations or an accidental release of hazardous substances or
    hydrocarbons into the environment.
     52




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We
    typically do not obtain independent evaluations of natural gas
    reserves dedicated to our gathering pipeline systems; therefore,
    volumes of natural gas on our systems in the future could be
    less than we anticipate.
    A
    change in the jurisdictional characterization of some of our
    assets by federal, state or local regulatory agencies or a
    change in policy by those agencies may result in increased
    regulation of our assets, which may cause our revenues to
    decline and operating expenses to increase.
           53




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Under
    the terms of our gas sales agreement, Targa will manage the
    sales of our natural gas and will pay us the amount it realizes
    for gas sales less certain costs; however, unexpected volume
    changes due to production variability or to gathering, plant, or
    pipeline system disruptions may increase our exposure to
    commodity price movements.
    We may
    incur significant costs and liabilities resulting from pipeline
    integrity programs and related repairs.
    
    perform ongoing assessments of pipeline integrity;
    identify and characterize applicable threats to pipeline
    segments that could impact a high consequence area;
    improve data collection, integration and analysis;
    repair and remediate the pipeline as necessary; and
    implement preventive and mitigating actions.   54




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Our
    construction of new assets may not result in revenue increases
    and is subject to regulatory, environmental, political, legal
    and economic risks, which could adversely affect our results of
    operations and financial condition.
    If we
    do not make acquisitions on economically acceptable terms, or
    efficiently and effectively integrate the acquired assets with
    our asset base, our future growth will be limited.
      
    inaccurate assumptions about volumes, revenues and costs,
    including synergies;
    an inability to integrate successfully the businesses we acquire;
    the assumption of unknown liabilities;
    limitations on rights to indemnity from the seller;
    inaccurate assumptions about the overall costs of equity or debt;
    the diversion of managements and employees attention
    from other business concerns;
    unforeseen difficulties operating in new product areas or new
    geographic areas; and 55




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##### Table of Contents




    customer or key employee losses at the acquired businesses.      We do
    not own all of the land on which our pipelines and facilities
    are located, which could disrupt our operations.
  and/or
  We do
    not have any officers or employees and rely solely on officers
    of our general partner and employees of Targa.
    If our
    general partner fails to develop or maintain an effective system
    of internal controls, then we may not be able to accurately
    report our financial results or prevent fraud. As a result,
    current and potential unitholders could lose confidence in our
    financial reporting, which would harm our business and the
    trading price of our common units.
    The
    amount of cash we have available for distribution to holders of
    our common units and subordinated units depends primarily on our
    cash flow and not solely on profitability. Consequently, even if
    we are profitable, we may not be able to make cash distributions
    to holders of our common units and subordinated
    units.
   56




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Terrorist
    attacks, and the threat of terrorist attacks, have resulted in
    increased costs to our business. Continued hostilities in the
    Middle East or other sustained military campaigns may adversely
    impact our results of operations.
        Risks
    Inherent in an Investment in Us
  Targa
    controls our general partner, which has sole responsibility for
    conducting our business and managing our operations. Targa has
    conflicts of interest with us and may favor its own interests to
    your detriment.
    
    neither our partnership agreement nor any other agreement
    requires Targa to pursue a business strategy that favors us.
    Targas directors and officers have a fiduciary duty to
    make decisions in the best interests of the owners of Targa,
    which may be contrary to our interests;
    our general partner is allowed to take into account the
    interests of parties other than us, such as Targa, or its
    owners, including Warburg Pincus, in resolving conflicts of
    interest; and
    Targa is not limited in its ability to compete with us and is
    under no obligation to offer assets to us; please see
     Targa is not limited in its ability to compete
    with us, which could limit our ability to acquire additional
    assets or businesses below.    The
    credit and business risk profile of our general partner and its
    owners could adversely affect our credit ratings and
    profile.
   57




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Our
    partnership agreement limits our general partners
    fiduciary duties to holders of our units and restricts the
    remedies available to unitholders for actions taken by our
    general partner that might otherwise constitute breaches of
    fiduciary duty.
    
    permits our general partner to make a number of decisions in its
    individual capacity, as opposed to in its capacity as our
    general partner. This entitles our general partner to consider
    only the interests and factors that it desires, and it has no
    duty or obligation to give any consideration to any interest of,
    or factors affecting, us, our affiliates or any limited partner;
    provides that our general partner will not have any liability to
    us or our unitholders for decisions made in its capacity as a
    general partner so long as it acted in good faith, meaning it
    believed the decision was in the best interests of our
    partnership;
    generally provides that affiliated transactions and resolutions
    of conflicts of interest not approved by the conflicts committee
    of the board of directors of our general partner acting in good
    faith and not involving a vote of unitholders must be on terms
    no less favorable to us than those generally being provided to
    or available from unrelated third parties or must be fair
    and reasonable to us, as determined by our general partner
    in good faith and that, in determining whether a transaction or
    resolution is fair and reasonable, our general
    partner may consider the totality of the relationships between
    the parties involved, including other transactions that may be
    particularly advantageous or beneficial to us;
    provides that our general partner and its officers and directors
    will not be liable for monetary damages to us, our limited
    partners or assignees for any acts or omissions unless there has
    been a final and non-appealable judgment entered by a court of
    competent jurisdiction determining that the general partner or
    those other persons acted in bad faith or engaged in fraud or
    willful misconduct or, in the case of a criminal matter, acted
    with knowledge that the conduct was criminal; and
    provides that in resolving conflicts of interest, it will be
    presumed that in making its decision the general partner acted
    in good faith, and in any proceeding brought by or on behalf of
    any limited partner or us, the person bringing or prosecuting
    such proceeding will have the burden of overcoming such
    presumption.    Targa
    is not limited in its ability to compete with us, which could
    limit our ability to acquire additional assets or
    businesses.
   58




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Cost
    reimbursements due our general partner and its affiliates for
    services provided, which will be determined by our general
    partner, will be substantial and will reduce our cash available
    for distribution to you.
    Holders
    of our common units have limited voting rights and are not
    entitled to elect our general partner or its
    directors.
    Removal
    of our general partner without its consent will dilute and
    adversely affect our common unitholders.
   59




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We may
    issue additional units without your approval, which would dilute
    your existing ownership interests.
    
    our unitholders proportionate ownership interest in us
    will decrease;
    the amount of cash available for distribution on each unit may
    decrease;
    because a lower percentage of total outstanding units will be
    subordinated units, the risk that a shortfall in the payment of
    the minimum quarterly distribution will be borne by our common
    unitholders will increase;
    the ratio of taxable income to distributions may increase;
    the relative voting strength of each previously outstanding unit
    may be diminished; and
    the market price of our common units may decline.  Affiliates
    of our general partner may sell common units in the public
    markets, which sales could have an adverse impact on the trading
    price of our common units.
    Our
    general partner may elect to cause us to issue Class B
    units to it in connection with a resetting of the target
    distribution levels related to our general partners
    incentive distribution rights without the approval of the
    conflicts committee of our general partner or holders of our
    common units. This ability may result in lower distributions to
    holders of our common units in certain situations.
     60




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##### Table of Contents



Increases
    in interest rates could adversely impact our unit price and our
    ability to issue additional equity to make acquisitions, for
    expansion capital expenditures or for other
    purposes.
    Our
    partnership agreement restricts the voting rights of unitholders
    owning 20% or more of our common units.
    Control
    of our general partner may be transferred to a third party
    without unitholder consent.
    Our
    general partner has a limited call right that may require you to
    sell your units at an undesirable time or price.
    Your
    liability may not be limited if a court finds that unitholder
    action constitutes control of our business.
    
    a court or government agency determined that we were conducting
    business in a state but had not complied with that particular
    states partnership statute; or 61




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##### Table of Contents




    your right to act with other unitholders to remove or replace
    the general partner, to approve some amendments to our
    partnership agreement or to take other actions under our
    partnership agreement constitute control of our
    business.    Unitholders
    may have liability to repay distributions that were wrongfully
    distributed to them.
  Section 17-607
  Tax Risks
    to Common Unitholders
    Our
    tax treatment depends on our status as a partnership for federal
    income tax purposes, as well as our not being subject to a
    material amount of entity-level taxation by individual states.
    If the IRS were to treat us as a corporation for federal income
    tax purposes or we were to become subject to additional amounts
    of entity-level taxation for state tax purposes, then our cash
    available for distribution to you could be substantially
    reduced.
         62




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##### Table of Contents



We
    prorate our items of income, gain, loss and deduction between
    transferors and transferees of our units each month based upon
    the ownership of our units on the first day of each month,
    instead of on the basis of the date a particular unit is
    transferred. The IRS may challenge this treatment, which could
    change the allocation of items of income, gain, loss and
    deduction among our unitholders.
    If the
    IRS contests the federal income tax positions we take, the
    market for our common units may be adversely impacted and the
    cost of any IRS contest will reduce our cash available for
    distribution to you.
    You
    may be required to pay taxes on your share of our income even if
    you do not receive any cash distributions from us.
    Tax
    gain or loss on the disposition of our common units could be
    more or less than expected.
   63




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##### Table of Contents



Tax-exempt
    entities and
    non-U.S.
    persons face unique tax issues from owning our common units that
    may result in adverse tax consequences to them.
  non-U.S. persons non-U.S. persons non-U.S. persons non-U.S. person,
  We
    treat each purchaser of common units as having the same tax
    benefits without regard to the actual common units purchased.
    The IRS may challenge this treatment, which could adversely
    affect the value of our common units.
    We
    have adopted certain valuation methodologies that may result in
    a shift of income, gain, loss and deduction between the general
    partner and the unitholders. The IRS may challenge this
    treatment, which could adversely affect the value of our common
    units.
      The
    sale or exchange of 50% or more of our capital and profits
    interests during any twelve-month period will result in the
    termination of our partnership for federal income tax
    purposes.
   64




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##### Table of Contents



Schedule K-1s)
  You
    will likely be subject to state and local taxes and return
    filing requirements in states where you do not live as a result
    of investing in our common units.
    Item 2.
    Unregistered
    Sales of Equity Securities and Use of Proceeds    Item 3.
    Defaults
    Upon Senior Securities    Item 4.
    Submission
    of Matters to a Vote of Security Holders    Item 5.
    Other
    Information    Item 6.
    Exhibits  ExhibitNumber



Description2
.1*



Purchase and Sale Agreement, dated as of September 18,
    2007, by and between Targa Resources Partners LP and Targa
    Resources Holdings LP, incorporated by reference to
    Exhibit 2.1 to Targa Resources Partners LPs Current
    Report on
    Form 8-K
    filed September 21, 2007
    (File No. 001-33303).3
.1



Certificate of Limited Partnership of Targa Resources Partners
    LP, incorporated by reference to Exhibit 3.2 to Targa
    Resources Partners LPs Registration Statement on
    Form S-1
    filed November 16, 2006 (File
    No. 333-138747).3
.2



Certificate of Formation of Targa Resources GP LLC, incorporated
    by reference to Exhibit 3.3 to Targa Resources Partners
    LPs Registration Statement on
    Form S-1
    filed January 19, 2007
    (File No. 333-138747). 65




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##### Table of Contents



ExhibitNumber



Description3
.3



Agreement of Limited Partnership of Targa Resources Partners LP,
    incorporated by reference to Exhibit 3.3 to Targa Resources
    Partners LPs Annual Report on
    Form 10-K
    filed April 2, 2007 (File
    No. 001-33303).3
.4



First Amended and Restated Agreement of Limited Partnership of
    Targa Resources Partners LP, incorporated by reference to
    Exhibit 3.1 to Targa Resources Partners LPs Current
    Report on
    Form 8-K
    filed February 16, 2007 (File
    No. 001-33303).3
.5



Limited Liability Company Agreement of Targa Resources GP LLC,
    incorporated by reference to Exhibit 3.4 to Targa Resources
    Partners LPs Registration Statement on
    Form S-1
    filed January 19, 2007 (File
    No. 333-138747).4
.1



Specimen Unit Certificate representing common units,
    incorporated by reference to Exhibit 4.1 to Targa Resources
    Partners LPs Annual Report on
    Form 10-K
    filed April 2, 2007
    (File No. 001-33303).31
.1**



Certification of Chief Executive Officer pursuant to
    Section 302 of the Sarbanes-Oxley Act of 2002.31
.2**



Certification of Chief Financial Officer pursuant to
    Section 302 of the Sarbanes-Oxley Act of 2002.32
.1**



Certification of Chief Executive Officer pursuant to
    18 U.S.C. Section 1350, as adopted pursuant to
    Section 906 of the Sarbanes-Oxley Act of 2002.32
.2**



Certification of Chief Executive Officer pursuant to
    18 U.S.C. Section 1350, as adopted pursuant to
    Section 906 of the Sarbanes-Oxley Act of 2002.     *
    
    Pursuant to Item 601(b)(2) of
    Regulation S-K,
    the registrant agrees to furnish supplementally a copy of any
    omitted exhibit or schedule to the SEC upon request.**
    
    Filed herewith 66




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SIGNATURES
    Targa Resources Partners LP
     By:
    /s/  John
    Robert Sparger        67




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Exhibit Index
  ExhibitNumber



Description2
.1*



Purchase and Sale Agreement, dated as of September 18, 2007, by
    and between Targa Resources Partners LP and Targa Resources
    Holdings LP, incorporated by reference to Exhibit 2.1 to Targa
    Resources Partners LPs Current Report on Form 8-K filed
    September 21, 2007 (File No. 001-33303).3
.1



Certificate of Limited Partnership of Targa Resources Partners
    LP, incorporated by reference to Exhibit 3.2 to Targa Resources
    Partners LPs Registration Statement on Form S-1 filed
    November 16, 2006 (File No. 333-138747).3
.2



Certificate of Formation of Targa Resources GP LLC, incorporated
    by reference to Exhibit 3.3 to Targa Resources Partners
    LPs Registration Statement on Form S-1 filed January 19,
    2007 (File No. 333-138747).3
.3



Agreement of Limited Partnership of Targa Resources Partners LP,
    incorporated by reference to Exhibit 3.3 to Targa Resources
    Partners LPs Annual Report on Form 10-K filed April 2,
    2007 (File No. 001-33303).3
.4



First Amended and Restated Agreement of Limited Partnership of
    Targa Resources Partners LP, incorporated by reference to
    Exhibit 3.1 to Targa Resources Partners LPs Current Report
    on Form 8-K filed February 16, 2007 (File No. 001-33303).3
.5



Limited Liability Company Agreement of Targa Resources GP LLC,
    incorporated by reference to Exhibit 3.4 to Targa Resources
    Partners LPs Registration Statement on Form S-1 filed
    January 19, 2007 (File No. 333-138747).4
.1



Specimen Unit Certificate representing common units,
    incorporated by reference to Exhibit 4.1 to Targa Resources
    Partners LPs Annual Report on Form 10-K filed April 2,
    2007 (File No. 001-33303).31
.1**



Certification of Chief Executive Officer pursuant to Section 302
    of the Sarbanes-Oxley Act of 2002.31
.2**



Certification of Chief Financial Officer pursuant to Section 302
    of the Sarbanes-Oxley Act of 2002.32
.1**



Certification of Chief Executive Officer pursuant to
    18 U.S.C. Section 1350, as adopted pursuant to Section 906
    of the Sarbanes-Oxley Act of 2002.32
.2**



Certification of Chief Executive Officer pursuant to
    18 U.S.C. Section 1350, as adopted pursuant to Section 906
    of the Sarbanes-Oxley Act of 2002.     *
    
    Pursuant to Item 601(b)(2) of
    Regulation S-K,
    the registrant agrees to furnish supplementally a copy of any
    omitted exhibit or schedule to the SEC upon request.**
    
    Filed herewith 68