##### Table of Contents





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

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
    SECURITIES EXCHANGE ACT OF 1934For the fiscal year ended
    December 31, 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 St, Suite 4300
    Houston, Texas(Address of principal
    executive offices)

77002(Zip Code)   (713) 584-1000
 (Registrants telephone
    number, including area code)
  Securities registered pursuant to section 12(b) of the
    Act:
  Title of Each Class

Name of Each Exchange on Which RegisteredCommon Units Representing Limited Partnership Interests

The NASDAQ Stock Market LLC   Securities registered pursuant to section 12(g) of the
    Act:
 Title of Class: None
  o þ
  o þ
  þ o
  Regulation S-K Form 10-K Form 10-K. o
    Large accelerated
    filer o

Accelerated
    filer o

Non-accelerated
    filer þ

Smaller reporting
    company o(Do not check if a smaller reporting company)   Rule 12b-2 o þ
      DOCUMENTS
    INCORPORATED BY REFERENCE




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##### 





TABLE OF
    CONTENTS
  DESCRIPTION
   
 PART I1.


BUSINESS


41A.


RISK FACTORS


271B.


UNRESOLVED STAFF COMMENTS


482.


PROPERTIES


483.


LEGAL PROCEEDINGS


484.


SUBMISSION OF MATTERS TO A VOTE OF SECURITY
    HOLDERS


48PART II5.


MARKET FOR REGISTRANTS COMMON EQUITY,
    RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY
    SECURITIES


496.


SELECTED FINANCIAL DATA


517.


MANAGEMENTS DISCUSSION AND ANALYSIS OF
    FINANCIAL CONDITION AND RESULTS OF OPERATIONS


567A.


QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
    MARKET RISK


748.


FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA


789.


CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
    ACCOUNTING AND FINANCIAL DISCLOSURE


789A


CONTROLS AND PROCEDURES


789B


OTHER INFORMATION


79PART III10.


DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE
    GOVERNANCE


7911.


EXECUTIVE COMPENSATION


8412.


SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
    AND MANAGEMENT AND RELATED UNITHOLDER MATTERS


9913.


CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS,
    AND DIRECTOR INDEPENDENCE


10114.


PRINCIPAL ACCOUNTANT FEES AND SERVICES


106PART IV15.


EXHIBITS AND FINANCIAL STATEMENT
    SCHEDULES


107SubsidiariesConsent of Independent Registered Public Accounting FirmCertification of CEO Pursuant to Rule 13a-14(a)/15d-14(a)Certification of CFO Pursuant to Rule 13a-14(a)/15d-14(a)Certification of CEO Pursuant to Section 906Certification of CFO Pursuant to Section 906   2




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TARGA
    RESOURCES PARTNERS LP
  PART I
  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, NGLs 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;
    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 Annual Report.   3




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Form 10-K,
  Bbl

Barrels (equal to 42 gallons)BBtu

Billion British thermal unitsBcf

Billion cubic feetBtu

British thermal unit, a measure of heating value/d

Per dayGal

GallonsMBbl

Thousand barrelsMcf

Thousand cubic feetMMBbl

Million barrelsMMBtu

Million British thermal unitsMMcf

Million cubic feetNGL(s)

Natural gas liquid(s)Tcf

Trillion cubic feet   Price Index DefinitionsGD-HH

Henry Hub Gas Daily averageIF-HH

Inside FERC Gas Market Report, Henry HubIF-HSC

Inside FERC Gas Market Report, Houston Ship Channel/Beaumont,
    TexasIF-NGPL MC

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

Inside FERC Gas Market Report, West Texas WahaNY-HH

NYMEX, Henry Hub Natural GasNY-WTI

NYMEX, West Texas Intermediate Crude OilOPIS-MB

Oil Price Information Service, Mont Belvieu, Texas   Item 1.
    Business  General
       4




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Business
    Strategies
    
    Increasing the profitability of our existing
    assets.  With our North Texas System, we have an
    extensive network of gathering systems and two natural gas
    processing facilities, which positions us to capitalize on the
    active development and growing production from the Barnett Shale
    and the other Fort Worth Basin formations. The SAOU System
    is located in the Permian Basin of west Texas, which is
    characterized by long-lived, multi-horizon oil and gas reserves
    that have low natural production declines. The LOU System has
    access to onshore basins in south Louisiana and serves the Lake
    Charles industrial market. Our assets provide us opportunities
    to:  
    Utilize excess pipeline and plant capacity to connect and
    process new supplies of natural gas at minimal incremental cost;
    Undertake additional initiatives to improve operating
    efficiencies and increase processing yields;
    Eliminate bottlenecks to allow for increased throughput;
    Pursue pressure reduction projects to increase volumes of gas to
    be gathered and processed; and
    Expand our footprint in a cost effective manner.  
    Managing our contract mix to optimize
    profitability.  The majority of our operating
    margin is generated pursuant to percent-of-proceeds contracts or
    similar arrangements which, if unhedged, benefit us in
    increasing commodity price environments and expose us to a
    reduction in profitability in decreasing commodity price
    environments. We believe that if appropriately managed, our
    current contract mix allows us to optimize our profitability
    over time. Although we expect to maintain primarily
    percent-of-proceeds arrangements, we continually evaluate the
    market for attractive fee-based and other arrangements which
    will further reduce the variability of our cash flows as well as
    enhance our profitability and competitiveness.
    Mitigating commodity price exposure through prudent hedging
    arrangements.The primary purpose of our
    commodity price risk management activities is to hedge our
    exposure to commodity price risk inherent in our contract mix
    and reduce fluctuations in our operating cash flow despite
    fluctuations in commodity prices. We have hedged the commodity
    price associated with a significant portion of our expected
    natural gas, NGLs and condensate equity volumes for the years
    2008 through 2012 by entering into derivative financial
    instruments including swaps and purchased puts (or floors). The
    percentages of our expected equity volumes that are covered by
    our hedges decrease over time. We have structured our hedges to
    approximate our actual NGL product composition and to
    approximate our actual NGL and natural gas delivery points. We
    do not use crude oil prices to approximate NGL prices for
    purposes of hedging. We intend to continue to manage our
    exposure to commodity prices in the future by entering into
    similar hedge transactions using swaps, collars, purchased puts
    (or floors) or other hedge instruments as market conditions
    warrant.
    Capitalizing on organic expansion
    opportunities.  We continually evaluate
    economically attractive organic expansion opportunities in
    existing or new areas of operation that will allow us to expand
    our business.
    Focusing on producing regions with attractive
    characteristics.We seek to focus on those regions and
    supplies with attractive characteristics, including regions:  
    where treating or processing is required to access end-markets; 5




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
    where permitting, drilling and workover activity is high;
    with the potential for long-term acreage dedications;
    with a strong base of current production and the potential for
    significant future development; and
    that can serve as a platform to expand into adjacent areas with
    existing or new production.  
    Pursuing strategic and accretive
    acquisitions.  We plan to pursue strategic and
    accretive acquisition opportunities within the midstream energy
    industry, both from Targa and from third parties. We will seek
    acquisitions in our existing areas of operation that provide the
    opportunity for operational efficiencies, the potential for
    higher capacity utilization and expansion of existing assets, as
    well as acquisitions in other related midstream businesses
    and/or expansion into new geographic areas of operation. Among
    the factors we will consider in deciding whether to acquire
    assets include, but are not limited to, the economic
    characteristics of the acquisition (such as return on capital
    and cash flow stability), the region in which the assets are
    located (both regions contiguous to our areas of operation and
    other regions with attractive characteristics) and the
    availability and sources of capital to finance the acquisition.
    We intend to finance our expansion through a combination of debt
    and equity, including commercial debt facilities and public and
    private offerings of debt and equity securities.
    Leveraging our relationship with Targa.  Our
    relationship with Targa provides us access to its extensive pool
    of operational, commercial and risk management expertise which
    enables all of our strategies. In addition, we intend to pursue
    acquisition opportunities as well as organic growth
    opportunities with Targa and with Targas assistance. We
    may also acquire assets or businesses directly from Targa, which
    will provide us access to an array of growth opportunities
    broader than that available to many of our competitors.  Competitive
    Strengths
    
    Affiliation with Targa.  We expect that our
    relationship with Targa will provide us with significant
    business opportunities. Targa is a large gatherer and processor
    of natural gas in the United States. Targa owns and operates a
    large integrated platform of midstream assets in oil and natural
    gas producing regions, including the Permian Basin in west Texas
    and southeast New Mexico and the onshore and offshore regions of
    the Texas and Louisiana Gulf Coast. These operations are
    integrated with Targas NGL logistics and marketing
    business that extends services to customers throughout the
    United States. Targa has an experienced and knowledgeable
    executive management team and experienced and knowledgeable
    commercial and operations teams. We believe Targas
    relationships throughout the energy industry, including with
    producers of natural gas in the United States, will help
    facilitate implementation of our acquisition strategy and other
    strategies. Targa has indicated that it intends to use us as a
    growth vehicle to pursue the acquisition and expansion of
    midstream natural gas, NGL and other complementary energy
    businesses and assets and we expect to have the opportunity, but
    not the obligation, to acquire such businesses and assets
    directly from Targa in the future.
    Strategically located assets.  Our North Texas
    System is one of the largest integrated natural gas gathering,
    compression, treating and processing systems in the
    Fort Worth Basin. Current high levels of natural gas
    exploration, development and production activities within the
    Fort Worth Basin present significant organic growth
    opportunities to generate additional throughput on our system.   6




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
    High quality and efficient assets.  Our
    gathering and processing systems consist of high quality assets
    that have been well maintained, resulting in low cost, efficient
    operations. We have implemented state of the art processing,
    measurement and operations and maintenance technologies. These
    technologies have allowed us to proactively manage our
    operations with fewer field personnel resulting in lower costs
    and minimal downtime. As a result, we believe we have
    established a reputation in the midstream business as a reliable
    and cost-effective supplier of services to our customers and
    have a track record of safe and efficient operation of our
    facilities.
    Low maintenance capital expenditures.  We
    believe that a low level of maintenance capital expenditures is
    sufficient for us to continue operations in a safe, prudent and
    cost-effective manner.
    Prudent hedging arrangements.  While our
    percent-of-proceeds gathering and processing contracts subject
    us to commodity price risk, we have entered into long-term
    hedges covering the commodity price exposure associated with a
    significant portion of our near to mid-term expected equity gas,
    condensate and NGL volumes. This strategy reduces volumetric
    risk while managing commodity price risk related to these
    arrangements. We manage our business by hedging the commodity
    price exposure associated with a significant portion of our
    expected equity volumes of natural gas and NGLs in the near to
    mid-term.
    Strong producer customer base.  We have a
    strong producer customer base consisting of both major oil and
    gas companies and independent producers. We believe we have
    established a reputation as a reliable operator by providing
    high quality services and focusing on the needs of our
    customers. Targa also has relationships throughout the energy
    industry, including with producers of natural gas in the United
    States, and has established a positive reputation in the energy
    business which we believe will assist us in our primary business
    objectives.
    Comprehensive package of midstream
    services.  We provide a comprehensive package of
    services to natural gas producers, including natural gas
    gathering, compression, treating, processing and NGL
    fractionating. We believe our ability to provide all of these
    services provides us with an advantage in competing for new
    supplies of natural gas because we can provide substantially all
    of the services producers, marketers and others require to move
    natural gas and NGLs from wellhead to market on a cost-effective
    basis.
    Experienced management team.  Targa has an
    experienced and knowledgeable executive management team with an
    average of 28 years in the energy industry that owns a 3.4%
    direct and indirect ownership interest in us. Targas
    executive management team has a proven track record of enhancing
    value through the acquisition, optimization and integration of
    midstream assets. In addition, Targas operations and
    commercial management team consists of individuals with an
    average of of approximately 25 years of midstream operating
    experience. Our relationship with Targa provides us with access
    to significant operational, commercial, technical, risk
    management and other expertise.   7




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Our
    Relationship with Targa Resources, Inc.
      Natural Gas Gathering and Processing Division 
  NGL Logistics and Marketing Division 
     8




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Midstream
    Sector Overview
  General.
  9




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Gathering.
  Compression.
  Treating and Dehydration.
 10




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Processing.
      
    Percent-of-Proceeds, or Percent-of-Value or
    Percent-of-Liquids.In a percent-of-proceeds
    arrangement, the processor remits to the producers a percentage
    of the proceeds from the sales of residue gas and NGL products
    or a percentage of residue gas and NGL products at the tailgate
    of its processing facilities. In some percent-of-proceeds
    arrangements, the producer is paid a percentage of an index
    price for residue gas and NGL products, less agreed adjustments,
    rather than remitting a portion of the actual sales proceeds.
    The percent-of-value and percent-of-liquids are variations on
    this arrangement. These types of arrangements expose the
    processor to some commodity price risk as the revenues from the
    contracts are directly correlated with the price of natural gas
    and NGL.
    Keep-Whole.  A keep-whole arrangement allows
    the processor to keep 100% of the NGL produced and requires the
    return of the processed natural gas, or value of the gas, to the
    producer or owner. A wellhead purchase contract is a variation
    of this arrangement. Since some of the gas is used during
    processing, the processor must compensate the producer or owner
    for the gas shrink entailed in processing by supplying
    additional gas or by paying an agreed value for the gas
    utilized. These arrangements have the highest commodity price
    exposure for the processor because the costs are dependent on
    the price of natural gas and the revenues are based on the price
    of NGL. As a result, a processor with these types of contracts
    benefits when the value of the NGL is high relative to the cost
    of the natural gas and is disadvantaged when the cost of the
    natural gas is high relative to the value of the NGL.
    Fee-Based.  Under a fee-based contract, the
    processor receives a fee per gallon of NGL produced or per Mcf
    of natural gas processed. Under this arrangement, a processor
    would have no commodity price risk exposure.  Fractionation.
 11




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
    Ethane.  Ethane is used primarily as feedstock
    in the production of ethylene, one of the basic building blocks
    for a wide range of plastics and other chemical products.
    Propane.  Propane is used as heating fuel,
    engine fuel and industrial fuel, for agricultural burning and
    drying and as petrochemical feedstock for production of ethylene
    and propylene.
    Normal Butane.  Normal butane is principally
    used for motor gasoline blending and as fuel gas, either alone
    or in a mixture with propane, and feedstock for the manufacture
    of ethylene and butadiene, a key ingredient of synthetic rubber.
    Normal butane is also used to derive isobutane.
    Isobutane.  Isobutane is principally used by
    refiners to enhance the octane rating of motor gasoline and in
    the production of MTBE, an additive in cleaner burning motor
    gasoline.
    Natural Gasoline.  Natural gasoline is
    principally used as a motor gasoline blend stock or
    petrochemical feedstock.  Transportation and Storage.
 12




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Our
    Systems
    2007Approximate


Approximate


2007Gross


Inlet


Approximate





ApproximateCounty/Parish -

Processing


Throughput


NGL





FractionationApproximate

Capacity


Volume


Production


Process


CapacityFacility

Square Miles

(MMcf/d)


(MMcf/d)


(MBbl/d)


Type


(MBbl/d)Permian BasinMertzon

Irion, TX


48



39.9



6.2



Cryo(2
)


N/ASterling

Sterling, TX


62



48.6



7.9



Cryo(2
)


N/AConger(1)

Sterling, TX


25











Cryo(2
)


N/AGathering Area

10 counties - 4,000 square miles


135



88.5



14.1Louisiana Gulf CoastGillis

Calcasieu, LA


180



149.4



8.6



Cryo(2
)


13Acadia

Acadia, LA


80



28.9



1.5



Cryo(2
)


N/AGathering Area

12 parishes - 3,800 square miles


260



178.3



10.1







13North TexasChico

Wise, TX


265



152.1



17.2



Cryo(2
)


12Shackelford

Shackelford, TX


13



10.3



1.3



Cryo(2
)


N/AGathering Area

14 counties - 2,500 square miles


278



162.4



18.5







12Total Gathering and Processing




673



429.2



42.7







25     (1)
    The Conger plant is not currently operating, but is on standby
    and can be quickly reactivated on short notice to meet
    additional needs for processing capacity.(2)
    Cryo  Cryogenic Expander.  The North
    Texas System
  32-mile, 10-inch
  Gathering.
  15 MMcf/d
 13




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168 MMcf/d
  Processing. 150 MMcf/d 165 MMcf/d. 100 MMcf/d 165 MMcf/d on-site
    15 MMcf/d, 13 MMcf/d
  Market Access.
      
    Natural Gas Pipeline Company of America which is owned by Kinder
    Morgan, Inc. and serves the Midwest, specifically the Chicago
    market; 14




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
    ET Fuel System which is owned by Energy Transfer Partners, L.P.
    and has access to the Waha, Carthage and Katy hubs in Texas;
    Atmos Pipeline  Texas (Atmos-Texas) which
    is owned by Atmos Energy Corporation and has access to the Waha,
    Carthage and Katy hubs in Texas; and
    Enbridge Pipelines (North Texas) L.P. which is owned by Enbridge
    Energy Partners, L.P. and has access to several local residue
    gas markets.    Targa Intrastate Pipeline. 41-mile, 6-inch 10-inch
  Competition. J-W
  Customers and Contracts.
    The SAOU
    System
   15




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Gathering. and/or 94 MMcf/d
  Processing. 110 MMcf/d. 25MMcf/d,
  Market Access.
  Competition. 20 MMcf/d 25 MMcf/d
  Customers and Contracts.
  The LOU
    System
    Gathering. and/or 191 MMcf/d
 16




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Processing. 260 MMcf/d.
    Market Access. 500 MMcf/d
  Competition.
  Customers and Contracts.
 17




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The Combined Systems.
  Regulation
    of Operations
    Gathering
    Pipeline Regulation
     18




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Intrastate
    Pipeline Regulation
  10-inch
  60-mile
        Natural
    Gas Processing
     19




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Sales
    of Natural Gas and NGLs
  and/or
    Other
    State and Local Regulation of Our Operations
    Other
    Federal Laws and Regulation Affecting Our
    Industry
  Energy
    Policy Act of 2005
   20




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FERC
    Standards of Conduct for Transmission Providers
    FERC
    Market Transparency Rulemakings
       21




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Environmental,
    Health and Safety Matters
  General
        Hazardous
    Substances and Waste
   22




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Air
    Emissions
    Global
    Warming and Climate Control
   23




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and/or
  Massachusetts, et
    al. v. EPA, Massachusetts
  Water
    Discharges
     24




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Endangered
    Species Act
    Pipeline
    Safety
       25




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Employee
    Health and Safety
    Other
    Laws and Regulations
      Title to
    Properties and Rights-of-Way
     26




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Employees
    Available
    Information
  Form 10-K, Form 10-Q, Form 8-K, http://www.targaresources.com 1-800-SEC-0330. http://www.sec.gov
  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 similar to those that would be
    faced by a corporation engaged in similar businesses. The nature
    of our business activities subject us to certain hazards and
    risks. You should consider carefully the following risk factors
    together with all of the other information contained in this
    report. Additional risks not presently known to us or which we
    consider immaterial based on information currently available to
    us may also materially adversely affect us. If any of the
    following risks were actually to occur, then our business,
    financial condition or results of operations could be materially
    adversely affected.
  Risks
    Related to Our Business
  Our
    cash flow is affected by supply and demand for natural gas and
    NGL products, 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, liquified natural gas,
    NGLs and crude oil;
    actions taken by foreign oil and gas producing nations; 27




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
    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.
       28




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If we
    fail to balance our purchases of natural gas and our sales of
    residue gas and NGLs, our exposure to commodity price risk will
    increase.
    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 expected 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 the
    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 could be adversely affected.
   29




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We
    depend on our Chico plant in north Texas and our Gillis plant in
    southwest Louisiana 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 other gathering and processing systems, such as
    Mertzon, and Sterling.
    
    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.      If
    future acquisitions do not perform as expected, out 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.   30




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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.
    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.
    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.
   31




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##### Table of Contents



A
    reduction in demand for NGL products by the petrochemical,
    refining or heating industries could materially adversely affect
    our business, results of operations and financial
    condition.
    Ethane.
  Propane.
  Normal Butane.
  Isobutane.
  Natural Gasoline.
    We do
    not own most of the land on which our pipelines and facilities
    are located, which could disrupt our operations.
  and/or
 32




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##### Table of Contents



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;
    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 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; 33




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##### Table of Contents




    our debt level makes 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.    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.
    Our
    acquisition strategy requires access to new capital. Tightened
    capital markets or increased competition for investment
    opportunities could impair our ability to grow through
    acquisitions.
     34




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##### Table of Contents



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.
      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.
     35




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##### Table of Contents



Should
    we fail to comply with all applicable FERC administered
    statutes, rules, regulations and orders, we could be subject to
    substantial penalties and fines.
    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; 36




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##### Table of Contents




    repair and remediate the pipeline as necessary; and
    implement preventive and mitigating actions.      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.
   37




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
    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
    customer or key employee losses at the acquired businesses.      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 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.
   38




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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.
    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
  Cash
    distributions are not guaranteed and may fluctuate with our
    performance and the establishment of financial
    reserves.
      
    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 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; 39




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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 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.  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.  The
    credit and business risk profile of our general partner and its
    owners could adversely affect our credit ratings and
    profile.
     40




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##### Table of Contents



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 does 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
    are not 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 is 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.
   41




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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.
    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; 42




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##### Table of Contents




    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 the 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 the 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.
      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.
   43




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##### Table of Contents



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
    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
 44




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##### Table of Contents



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 Internal Revenue Service, or IRS, were to treat us as a
    corporation or if we were to become subject to a material amount
    of entity-level taxation for state tax purposes, then our cash
    available for distribution to you would be substantially
    reduced.
           45




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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 affected, and the
    cost of any 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 disposition of our common units could be more or
    less than expected.
    Tax-exempt
    entities and
    non-United
    States persons face unique tax issues from owning our common
    units that may result in adverse tax consequences to
    them.
  non-United non-United non-United non-United
 46




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##### Table of Contents



We
    treat each purchaser of our 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 the common units.
    A
    unitholder whose units are loaned to a short seller
    to cover a short sale of units may be considered as having
    disposed of those units. If so, he would no longer be treated
    for tax purposes as a partner with respect to those units during
    the period of the loan and may recognize gain or loss from the
    disposition.
    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.
   47




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##### Table of Contents



You
    may be subject to foreign, state and local taxes and return
    filing requirements in jurisdictions where you do not live as a
    result of investing in our common units.
    Item 1B.
    Unresolved
    Staff Comments    Item 2.
    Properties    713-584-1000.
  Item 3.
    Legal
    Proceedings      Item 4.
    Submission
    of Matters to a Vote of Security Holders   48




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##### Table of Contents



PART II  Item 5.
    Market
    for Registrants Common Equity, Related Unitholder Matters
    and Issuer Purchases of Equity Securities  Market
    Information
    Distribution

Distributionper Common

per SubordinatedQuarter Ended

High

Low

Unit

UnitDecember 31, 2007

$
29.84


$
25.10


$
0
.3975

$
0
.3975September 30, 2007


35.00



24.39



0
.3375


0
.3375June 30, 2007


35.28



27.70



0
.3375


0
.3375February 14, 2007 to March 31, 2007


29.30



22.75



0
.16875


0
.16875     Distributions
    of Available Cash
  General.
  Definition of Available Cash.
  
    provide for the proper conduct of our business;
    comply with applicable law, any of our debt instruments or other
    agreements; or
    provide funds for distribution to our unitholders and to our
    general partner for any one or more of the next four quarters.  Minimum Quarterly Distribution.
 49




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##### Table of Contents



General Partner Interest.
  Incentive Distribution Rights.
  Sales of
    Unregistered Units
    Repurchase
    of Equity by Targa Resources Partners LP
    Use of
    Proceeds
   50




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##### Table of Contents



Item 6.
    Selected
    Financial Data  SELECTED
    FINANCIAL AND OPERATING DATA
  On February 14, 2007, we had Targas ownership
    interests in the North Texas System contributed to us. On
    October 24, 2007, we acquired Targas ownership
    interests in the SAOU System and the LOU System. As required by
    Statement of Financial Accounting Standards (SFAS)
    141, we accounted for these transactions as transfers of net
    assets between entities under common control. For combinations
    of entities under common control, the purchase cost provisions
    (as they relate to purchase business combinations involving
    unrelated entities) of SFAS 141 explicitly do not apply;
    instead the method of accounting prescribed by SFAS 141 for
    such transfers is similar to the pooling-of-interests method of
    accounting. Under this method, the carrying amount of net assets
    recognized in the balance sheets of each combining entity are
    carried forward to the balance sheet of the combined entity, and
    no other assets or liabilities are recognized as a result of the
    combination (that is, no recognition is made for a purchase
    premium or discount representing any difference between the cash
    consideration paid and the book value of the net assets
    acquired).
  Although in connection with our IPO, the North Texas System
    was presented as our predecessor entity, as a result of our
    October 2007 acquisition of the SAOU and LOU Systems, the
    predecessor entity for us is now considered to be the net assets
    of the SAOU and LOU Systems as these were the first assets
    acquired by Targa on April 16, 2004. Therefore, subsequent
    to the contribution of the North Texas System from Targa on
    February 14, 2007, we recognized the assets and liabilities
    of the North Texas System contributed to us at their carrying
    amounts (historical cost) in the accounts of the SAOU and LOU
    Systems (the predecessor entity) at the date of transfer. The
    accounting treatment for combinations of entities under common
    control is consistent with the concept of poolings as
    combinations of common shareholder (or unitholder) interests, as
    all of the North Texas Systems equity accounts were also
    carried forward intact initially, and subsequently adjusted due
    to the cash consideration we paid for the acquired net
    assets.
  In addition to requiring that assets and liabilities be
    carried forward at historical costs, SFAS 141 also
    prescribes that for transfers of net assets between entities
    under common control, all income statements presented be
    combined as of the date of common control. Accordingly, our
    consolidated financial statements and all other financial
    information included in this report have been restated to assume
    that the transfer of the North Texas System net assets from
    Targa to us had occurred at the date when both the North Texas
    System and the SAOU and LOU Systems met the accounting
    requirements for entities under common control (October 31,
    2005). As a result, financial statements and financial
    information presented for prior periods in this report have been
    restated.
  Accordingly, our historical results include the historical
    results of the SAOU and LOU Systems (acquired by Targa effective
    April 16, 2004) for the years ended December 31,
    2007, 2006 and 2005; and the historical results of the North
    Texas System (acquired by Targa effective November 1,
    2005) subsequent to October 31, 2005.
  The financial and operating data as of and for the year ended
    December 31, 2004 are derived from the audited consolidated
    financial statements of Targa. Targas consolidated
    financial results for the year ended December 31, 2004
    includes the results of operations for the eight and a half
    month period commencing with its April 16, 2004 acquisition
    of the predecessor business from ConocoPhillips, combined with
    the acquisition-related activities of Targa for the period from
    January 1 to April 15, 2004. The selected combined
    financial and operating data of the predecessor for the three
    and a half months ended April 15, 2004 and as of and for
    the year ended December 31, 2003 are derived from the
    audited financial statements of the predecessor business.
  The information contained herein should be read together
    with, and is qualified in its entirety by reference to, the
    historical combined financial statements and the accompanying
    notes included elsewhere in this
    Form 10-K.
    Please see Item 7. Managements Discussion and
    Analysis of Financial Condition and Results of Operations
    for a discussion of factors that affect the comparability of the
    information reflected in the selected financial and operating
    data.
 51




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As used in this report, unless we indicate otherwise, the
    terms our, we, us and
    similar terms refer to Targa Resources Partners LP, together
    with our subsidiaries, and the term Targa refers to
    Targa Resources, Inc. and its subsidiaries and affiliates (other
    than us). The following table summarizes selected financial and
    operating data for the periods and as of the dates indicated.
  March 12



SAOU/LOU Systems Predecessor(Inception)



106-Day Periodthrough



Period Ended


Year EndedYears Ended December 31,


December 31,



April 15,


December 31,2007


2006


2005


2004



2004


2003(in millions of dollars, except operating and price data)Statement of Operations Data:Revenues

$
1,661.5


$
1,738.5


$
1,172.5


$
602.6



$
232.8


$
724.7Product purchases


1,406.8



1,517.7



1,061.7



544.9




212.3



665.4Operating expense


50.9



49.1



24.4



15.3




7.9



23.2Depreciation and amortization expense


71.8



69.9



23.1



10.4




3.8



12.9General and administrative expense


18.9



16.1



16.7



11.1




0.8



3.3Taxes other than income taxes



















1.4



4.3Other


(0.3
)



















0.0Interest expense, net


22.0




















Interest expense, allocated from Parent


19.4



88.0



21.2



6.1








Loss on debt extinguishment










3.7












Loss/(gain) on mark-to-market derivative contracts


30.2



(16.8
)


12.0



(1.3
)







Deferred income tax expense(1)


1.5



2.9












2.6



6.1Net income


40.3


$
11.6


$
9.7


$
16.1



$
4.0


$
9.5Less:Net income attributable to predecessor operations


12.2Net income allocable to partners


28.1General partner interest in net income


0.6Net income available to common and subordinated unitholders

$
27.5Net income per limited partner unit  basic

$
0.81Net income per limited partner unit  diluted

$
0.81Cash distributions declared per unit

$
1.24Financial and Operating Data:Financial data:Operating margin(2)

$
203.8


$
171.7


$
86.4


$
42.4



$
12.6


$
36.1Adjusted EBITDA(3)

$
185.8


$
154.1


$
66.0


$
31.3



$
11.8


$
32.8 52




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##### Table of Contents



March 12



SAOU/LOU Systems Predecessor(Inception)



106-Day Periodthrough



Period Ended


Year EndedYears Ended December 31,


December 31,



April 15,


December 31,2007


2006


2005


2004



2004


2003(in millions of dollars, except operating and price data)Operating data:Gathering throughput,
    MMcf/d(4)


452.0



433.8



302.4Plant natural gas inlet,
    MMcf/d(5)


429.2



419.6



253.6Gross NGL production, MBbl/d


42.6



42.4



23.5Natural gas sales, BBtu/d


410.2



489.4



259.3NGL sales, MBbl/d


36.4



36.0



22.0Condensate sales, MBbl/d


3.6



3.3



1.3Average Realized Prices:(6)Natural Gas, $/MMBtu

$
6.66


$
6.68


$
9.36NGL, $/gal


1.03



0.85



0.77Condensate, $/Bbl


65.62



59.87



58.96Balance sheet Data (at period end):Property plant and equipment, net

$
1,259.6


$
1,288.6


$
1,325.9


$
237.6



$
266.0


$
268.8Total Assets


1,480.0



1,416.4



1,500.0



323.4




288.8



316.8Long-term allocated debt (including current portion)






1,047.3



1,053.3



103.0








Long-term debt (including current portion)


626.3




















Partners capital/Net parent equity


614.2



245.9



281.2



139.2




170.9



177.3Cash Flow Data:Net cash provided by (used in):Operating activities

$
265.7


$
124.4


$
10.5


$
28.2



$
11.5


$
(6.3
)Investing activities


(40.7
)


(32.9
)


(6.8
)


(2.9
)



(1.2
)


(2.4
)Financing activities


(174.0
)


(91.5
)


(3.7
)


(25.4
)



(10.3
)


8.8     (1)
    
    In May 2006, Texas adopted a margin tax consisting of a 1% tax
    on the amount by which total revenue exceeds cost of goods sold,
    as apportioned to Texas. The amount presented represents our
    estimated liability for this tax.

(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 6.

(3)
    
    Adjusted EBITDA is net income before interest, income taxes,
    depreciation and amortization and non-cash income or loss
    related to derivative instruments. Please see Non-GAAP Financial
    Measures  Adjusted EBITDA, included in this
    Item 6.

(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)
    
    Average realized prices include the impact of hedging activities.  Non-GAAP Financial
    Measures
  Adjusted EBITDA.
  
    the financial performance of our assets without regard to
    financing methods, capital structure or historical cost basis; 53




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
    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 Margin.
      
    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.  54




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March 12



SAOU/LOU Systems Predecessor(Inception)



106 DayYear Ended


Year Ended


Year Ended


through



Period Ended


Year EndedDecember 31,


December 31,


December 31,


December 31,



April 15,


December 31,2007


2006


2005


2004



2004


2003(in millions)Reconciliation of Adjusted EBITDA to net cash
    provided by operating activities:Net cash provided by (used in) operating activities

$
270.5


$
124.4


$
10.5


$
28.2




11.5


$
(6.3
)Allocated interest expense from parent(1)


18.5



81.8



16.5



5.2








Interest expense, net(1)


21.1




















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


(89.8
)


(78.5
)


61.8



76.7




(23.7
)


30.3Accounts payable


(1.9
)


13.7



(11.4
)


(3.1
)



21.3



(1.5
)Accrued liabilities


(33.5
)


15.4



(13.3
)


(76.5
)



0.1



(0.2
)Other, including changes in noncurrent assets and liabilities


(29.3
)


14.1



(10.1
)


2.1




2.6



10.5Noncash mark-to-market loss (gain)


30.2



(16.8
)


12.0



(1.3
)







Adjusted EBITDA

$
185.8


$
154.1


$
66.0


$
31.3



$
11.8


$
32.8Reconciliation of Adjusted EBITDA to net
    income:Net income

$
40.3


$
11.6


$
9.7


$
16.1



$
4.0


$
9.5Add:Allocated interest expense, net


19.4



88.0



21.2



6.1








Interest expense, net


22.0




















Deferred income tax expense


1.5



2.9












2.6



6.1Taxes other than income taxes



















1.4



4.3Depreciation and amortization expense


71.8



69.9



23.1



10.4




3.8



12.9Risk Management Activities


0.6



(1.5
)















Noncash mark-to-market loss (gain)


30.2



(16.8
)


12.0



(1.3
)







Adjusted EBITDA

$
185.8


$
154.1


$
66.0


$
31.3



$
11.8


$
32.8Reconciliation of operating margin to net
    income:Net income

$
40.3


$
11.6


$
9.7


$
16.1



$
4.0


$
9.5Add:Depreciation and amortization expense


71.8



69.9



23.1



10.4




3.8



12.9Deferred income tax expense


1.5



2.9












2.6



6.1Allocated interest expense, net


19.4



88.0



21.2



6.1








Interest expense, net


22.0




















Loss on extinguishment of debt










3.7












Loss/(gain) on mark-to-market derivative contracts


30.2



(16.8
)


12.0



(1.3
)







General and administrative expense


18.9



16.1



16.7



11.1




0.8



3.3Taxes other than income taxes



















1.4



4.3Gain on sale of assets


(0.3
)



















Operating margin

$
203.8


$
171.7


$
86.4


$
42.4



$
12.6


$
36.1  55




---



##### Table of Contents



(1)
    Net of amortization of debt issuance costs of $1.8 million
    for the year ended December 31, 2007, $6.2 million for
    the year ended December 31, 2006 and $4.7 million for the
    year ended December 31, 2005.  Item 7.
    Managements
    Discussion and Analysis of Financial Condition and Results of
    Operations  On February 14, 2007, we had Targas ownership
    interests in the North Texas System contributed to us. On
    October 24, 2007, we acquired Targas ownership
    interests in the SAOU System and the LOU System. As required by
    Statement of Financial Accounting Standards (SFAS)
    141, we accounted for these transactions as transfers of net
    assets between entities under common control. For combinations
    of entities under common control, the purchase cost provisions
    (as they relate to purchase business combinations involving
    unrelated entities) of SFAS 141 explicitly do not apply;
    instead the method of accounting prescribed by SFAS 141 for
    such transfers is similar to the pooling-of-interests method of
    accounting. Under this method, the carrying amount of net assets
    recognized in the balance sheets of each combining entity are
    carried forward to the balance sheet of the combined entity, and
    no other assets or liabilities are recognized as a result of the
    combination (that is, no recognition is made for a purchase
    premium or discount representing any difference between the cash
    consideration paid and the book value of the net assets
    acquired).
  Although in connection with our IPO, the North Texas System
    was presented as our predecessor entity, as a result of our
    October 2007 acquisition of the SAOU and LOU Systems, the
    predecessor entity for us is now considered to be the net assets
    of the SAOU and LOU Systems as these were the first assets
    acquired by Targa on April 16, 2004. Therefore, subsequent
    to the contribution of the North Texas System from Targa on
    February 14, 2007, we recognized the assets and liabilities
    of the North Texas System contributed to us at their carrying
    amounts (historical cost) in the accounts of the SAOU and LOU
    Systems (the predecessor entity) at the date of transfer. The
    accounting treatment for combinations of entities under common
    control is consistent with the concept of poolings as
    combinations of common shareholder (or unitholder) interests, as
    all of the North Texas Systems equity accounts were also
    carried forward intact initially, and subsequently adjusted due
    to the cash consideration we paid for the acquired net
    assets.
  In addition to requiring that assets and liabilities be
    carried forward at historical costs, SFAS 141 also
    prescribes that for transfers of net assets between entities
    under common control, all income statements presented be
    combined as of the date of common control. Accordingly, our
    consolidated financial statements and all other financial
    information included in this report have been restated to assume
    that the transfer of the North Texas System net assets from
    Targa to us had occurred at the date when both the North Texas
    System and the SAOU and LOU Systems met the accounting
    requirements for entities under common control (October 31,
    2005). As a result, financial statements and financial
    information presented for prior periods in this report have been
    restated.
  Accordingly, our historical results include the historical
    results of the SAOU and LOU Systems (acquired by Targa effective
    April 16, 2004) for the years ended December 31,
    2007, 2006 and 2005; and the historical results of the North
    Texas System (acquired by Targa effective November 1,
    2005) subsequent to October 31, 2005.
  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 historical financial statements and notes
    included elsewhere in this annual report.
  Overview
   56




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##### Table of Contents



Factors
    That Significantly Affect Our Results
          Affiliate Indebtedness and
    Borrowings.
     57




---



##### Table of Contents



Impact of Our Hedging Activities.
  General and Administrative Expenses. Schedule K-1
 58




---



##### Table of Contents



Working Capital Adjustments.
  Distributions to our Unitholders.
  Distribution

Distributionper Common

per SubordinatedQuarter Ended

Unit

Unit

Declared

PaidDecember 31, 2007

$
0
.3975

$
0
.3975

January 24, 2008

February 14, 2008September 30, 2007


0
.3375


0
.3375

October 23, 2007

November 14, 2007June 30, 2007


0
.3375


0
.3375

July 23. 2007

August 14, 2007February 14, 2007 to March 31, 2007


0
.16875


0
.16875

April 23, 2007

May 15, 2007  59




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##### Table of Contents



General
    Trends and Outlook
    Natural Gas Supply and Outlook.
  Commodity Prices.
  Rising Operating Costs.
  Our
    Operations
     60




---



##### Table of Contents



How We
    Evaluate Our Operations
      Throughput Volumes, Facility Efficiencies and Fuel
    Consumption.
    Operating Margin.
     61




---



##### 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.
  Adjusted 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.        62




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##### Table of Contents



Year Ended


Year Ended


Year EndedDecember 31,


December 31,


December 31,2007


2006


2005(in millions)Reconciliation of Adjusted EBITDA to net cash
    provided by operating activities:Net cash provided by (used in) operating activities

$
270.5


$
124.4


$
10.5Allocated interest expense from parent(1)


18.5



81.8



16.5Interest expense, net(1)


21.1







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


(89.8
)


(78.5
)


61.8Accounts payable


(1.9
)


13.7



(11.4
)Accrued liabilities


(33.5
)


15.4



(13.3
)Other, including changes in noncurrent assets and liabilities


(29.3
)


14.1



(10.1
)Noncash mark-to-market loss (gain)


30.2



(16.8
)


12.0Adjusted EBITDA

$
185.8


$
154.1


$
66.0Reconciliation of Adjusted EBITDA to net
    income:Net income

$
40.3


$
11.6


$
9.7Add:Allocated interest expense, net


19.4



88.0



21.2Interest expense, net


22.0







Deferred income tax expense


1.5



2.9



Taxes other than income taxes










Depreciation and amortization expense


71.8



69.9



23.1Risk Management Activities


0.6



(1.5
)


Noncash mark-to-market loss (gain)


30.2



(16.8
)


12.0Adjusted EBITDA

$
185.8


$
154.1


$
66.0Reconciliation of operating margin to net
    income:Net income

$
40.3


$
11.6


$
9.7Add:Depreciation and amortization expense


71.8



69.9



23.1Deferred income tax expense


1.5



2.9



Allocated interest expense, net


19.4



88.0



21.2Interest expense, net


22.0







Loss on extinguishment of debt










3.7Loss/(gain) on mark-to-market derivative contracts


30.2



(16.8
)


12.0General and administrative expense


18.9



16.1



16.7Taxes other than income taxes










Gain on sale of assets


(0.3
)






Operating margin

$
203.8


$
171.7


$
86.4     (1)
    Net of amortization of debt issuance costs of $1.8 million
    for the year ended December 31, 2007, $6.2 million for
    the year ended December 31, 2006 and $4.7 million for the
    year ended December 31, 2005.  Distributable Cash Flow.
 63




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##### Table of Contents



Reconciliation
    of Distributable Cash Flow to net income:
  Year Ended


Year Ended


Year EndedDecember 31,


December 31,


December 31,2007


2006


2005(a)(in millions)Net income (loss)

$
40.3


$
11.6


$
9.7Depreciation and amortization expense


71.8



69.9



23.1Deferred income tax expense


1.5



2.9



Amortization of debt issue costs


1.8



6.2



4.7Loss/(gain) on mark-to-market derivative contracts


30.2



(16.8
)


12.0Maintenance capital expenditures


(21.5
)


(16.3
)


(6.2
)Distributable cash flow(b)

$
124.1


$
57.5


$
43.3     (a)
    Includes two months of operations from North Texas System.  (b)
    Distributable cash flow for the years ended December 31,
    2007, 2006 and 2005 reflects allocated interest from parent of
    $19.4 million $88.0 million and $21.2 million,
    respectively.    For the Three Months Ended December 31, 2007


For The Year Ended December 31, 2007Pre-Acquisition








Pre-AcquisitionSAOU/LOU








North Texas


SAOU/LOUOct 1, 2007


Post





Jan 1, 2007


Jan 1, 2007


Postto


Acquisition





to


to


AcquisitionTRP LP


Oct 23, 2007


TRP LP


TRP LP


Feb 13, 2007


Oct 23, 2007


TRP LPNet income (loss)

$
22.7


$
4.7


$
18.0


$
40.3


$
(6.9
)

$
19.1


$
28.1Depreciation and amortization expense


18.1



0.9



17.2



71.8



6.9



11.7



53.2Deferred income tax expense


0.4



(0.1
)


0.5



1.5











1.5Amortization of debt issue costs


0.4







0.4



1.8







0.9



0.9Loss/(gain) on mark-to-market derivative contracts


1.9



1.9







30.2







30.2



Maintenance capital expenditures


(6.8
)


(0.4
)


(6.4
)


(21.5
)


(1.5
)


(5.9
)


(14.1
)Distributable Cash Flow

$
36.7


$
7.0


$
29.7


$
124.1


$
(1.5
)

$
56.0


$
69.6  64




---



##### Table of Contents



Contract
    Mix
  and/or
  Percent ofContract Type

Throughput

Impact of Commodity PricesPercent-of-Proceeds


79%



Decreases in natural gas and/or NGL prices generate decreases in
    operating margin.Wellhead Purchases /Keep Whole


19%



Increases in natural gas prices relative to NGL prices generate
    decreases in operating margin. Decreases in NGL prices relative
    to natural gas prices generate decreases in operating margin.Hybrid


1%



In periods of favorable processing economics, similar to
    percent-of-liquids (or wellhead purchases/keep-whole in some
    circumstances, if economically advantageous to the processor).
    In periods of unfavorable processing economics, similar to
    fee-based.Fee Based


1%



No direct impact from commodity price movements.     Critical
    Accounting Policies and Estimates
    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.     65




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##### Table of Contents



EITF 99-19, Reporting Revenue Gross as a Principal versus Net as an
    Agent.
  Use of Estimates.
  Property, Plant and Equipment.
  Asset Group

Range of YearsNatural gas gathering systems and processing facilities


15 to 25Office and miscellaneous equipment


3 to 7         Accounting for the
    Impairment or Disposal of Long-Lived Assets,
   66




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##### Table of Contents



Price Risk Management (Hedging). Accounting for Derivative
    Instruments and Hedging Activities,
      Asset Retirement Obligations. Accounting for Asset
    Retirement Obligations,
  Accounting for Conditional Asset
    Retirement Obligations. and/or
  Estimated Useful Lives.
 67




---



##### Table of Contents



Recent Accounting Announcements
    Results
    of Operations
  Our results of operations for the years ended
    December 31, 2007 and 2006 are presented and evaluated on a
    combined basis, combining the results of operations reflected in
    the audited historical financial statements of the SAOU and LOU
    Systems with the operations of the North Texas System. The
    Predecessor Business for the year ended December 31, 2005
    combines the results of operations for the SAOU and LOU Systems
    for the year then ended and the results of operations reflected
    in the audited historical financial statements of the North
    Texas System for the two-months after the DMS Acquisition.
   Year Ended


Year Ended


Year EndedDecember 31,


December 31,


December 31,2007


2006


2005(in millions of dollars, except operating and price data)Revenues

$
1,661.5


$
1,738.5


$
1,172.5Product purchases


1,406.8



1,517.7



1,061.7Operating expense


50.9



49.1



24.4Depreciation and amortization expense


71.8



69.9



23.1General and administrative expense


18.9



16.1



16.7Gain on sale of assets


(0.3
)






Income from operations


113.4



85.7



46.6Interest expense, net


22.0







Interest expense, allocated from Parent


19.4



88.0



21.2Loss on extinguishment of debt










3.7Loss/(gain) on mark-to-market derivative contracts


30.2



(16.8
)


12.0Deferred income tax expense(1)


1.5



2.9



Net income

$
40.3


$
11.6


$
9.7Financial data:Operating margin(2)

$
203.8


$
171.7


$
86.4Adjusted EBITDA(3)

$
185.8


$
154.1


$
66.0Operating data:Gathering throughput,
    MMcf/d(4)


452.0



433.8



302.4Plant natural gas inlet,
    MMcf/d(5)(6)


429.2



419.6



253.6Gross NGL production, MBbl/d


42.6



42.4



23.5Natural gas sales, BBtu/d(6)


410.2



489.4



259.3NGL sales, MBbl/d


36.4



36.0



22.0Condensate sales, MBbl/d


3.6



3.3



1.3Average realized prices:Natural Gas, $/MMBtuAverage realized sales price

$
6.58


$
6.66


$
9.36Impact of hedging


0.08



0.02



Average realized price

$
6.66


$
6.68


$
9.36NGL, $/galAverage realized sales price

$
1.05


$
0.86


$
0.79Impact of hedging


(0.02
)


(0.01
)


(0.02
)Average realized price

$
1.03


$
0.85


$
0.77Condensate, $/BblAverage realized sales price

$
65.43


$
59.28


$
58.96Impact of hedging


0.19



0.59



Average realized price

$
65.62


$
59.87


$
58.96  68




---



##### Table of Contents



(1)
    In May 2006, Texas adopted a margin tax, consisting of a 1% tax
    on the amount by which total revenue exceeds cost of goods sold,
    as apportioned to Texas. The amount presented represents our
    estimated liability for this tax.(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 7.(3)
    Adjusted EBITDA is net income before interest, income taxes,
    depreciation and amortization and non-cash income or loss
    related to derivative instruments. Please see
    Non-GAAP Financial Measures  Adjusted
    EBITDA, included in this Item 7.(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 represented the volume of natural gas
    passing through the meter located at the inlet of a natural gas
    processing plant.(6)
    Plant inlet volumes include producer
    take-in-kind,
    while natural gas sales exclude producer
    take-in-kind
    volumes.  Year
    Ended December 31, 2007 Compared to Year Ended
    December 31, 2006
  Total Operating Revenues.
  
    a net increase attributable to prices of $104.0 million,
    consisting of a decrease in natural gas revenues of
    $2.4 million and increases in NGLs and condensate revenues
    of $99.0 million and $7.4 million, respectively;
    a net decrease attributable to volumes of $182.5 million,
    consisting of a decrease in natural gas revenues of
    $193.0 million and increases of NGLs and condensate
    revenues of $5.7 million and $4.8 million,
    respectively; and
    an increase in fee and other revenues of $1.5 million.    
    natural gas decreased by $0.02 per MMBtu ($0.06 net
    increase per MMBtu due to hedging) or less than 1%, to $6.66 per
    MMBtu during 2007 compared to $6.68 per MMBtu for 2006.
    NGLs increased by $0.18 per gallon ($0.01 net decrease per
    gallon due to hedging), or 21%, to $1.03 per gallon for 2007
    compared to $0.85 per gallon for 2006.
    condensate increased by $5.75 per Bbl ($0.40 net increase
    per Bbl due to hedging), or 10%, to $65.62 per Bbl for 2007
    compared to $59.87 per Bbl for 2006.  take-in-kind
  Product Purchases.
 69




---



##### Table of Contents



Operating Expenses.
  Depreciation and Amortization.
  General and Administrative.
  Interest Expense.
  Year
    Ended December 31, 2006 Compared to Year Ended
    December 31, 2005
  Total Operating Revenues.
  
    During 2006, we recorded a full year of production volume for
    the SAOU, LOU and North Texas Systems versus a full year of
    production volume for the SAOU and LOU Systems and only two
    months of production volume for the North Texas System in 2005;
    a net decrease attributable to prices of $432.8 million,
    consisting of a decrease to natural gas revenues of
    $478.8 million and increases to NGL and condensate revenues
    of $44.9 million and $1.1 million, respectively;
    a net increase attributable to volumes of $995.9 million,
    consisting of increases to natural gas, NGLs and condensate
    volumes of $786.0 million, $165.1 million and
    $44.8 million, respectively, and
    an increase in fee and other revenues of $2.9 million.    
    natural gas decreased by $2.68 per MMBtu (including a $0.02
    increase per MMBtu due to hedging), or 29%, to $6.68 per MMBtu
    during 2006 compared to $9.36 per MMBtu for 2005.
    NGLs increased by $0.08 per gallon (with a $0.01 increase
    per gallon due to hedging), or 11%, to $0.85 per gallon for 2006
    compared to $0.77 per gallon for 2005.
    condensate increased by $0.91 per Bbl ($0.59 increase per Bbl
    due to hedging), or 2%, to $59.87 per Bbl for 2006 compared to
    $58.96 per Bbl for 2005.   70




---



##### Table of Contents



Product Purchases.
  Operating Expenses.
  Depreciation and Amortization.
  General and Administrative.
  Interest Expense.
  Liquidity
    and Capital Resources
      
    cash generated from operations;
    borrowings under our credit facility;
    issuance of additional partnership units; and
    debt offerings.    Working Capital.
 71




---



##### Table of Contents



Cash Flow.
  Year Ended


Year Ended


Year EndedDecember 31,


December 31,


December 31,2007


2006


2005(in millions)Net cash provided by (used in):Operating activities

$
270.5


$
124.4


$
10.5Investing activities


(40.7
)


(32.9
)


(6.8
)Financing activities


(178.8
)


(91.5
)


(3.7
)   Operating Activities.
  Investing Activities.
  Financing Activities.
 72




---



##### Table of Contents



Capital Requirements.
    Year Ended


Year Ended


Year EndedDecember 31,


December 31,


December 31,2007


2006


2005(in millions)Capital expenditures:Expansion

$
22.4


$
16.0


$
0.6Maintenance


21.5



16.3



6.2$
43.9


$
32.3


$
6.8       Description of Credit Agreement.
       73




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##### Table of Contents




    incur indebtedness;
    grant liens; and
    engage in transactions with affiliates.      Effective Date

Expiration Date


Notional Amount


Index


Fixed Rate12/13/2007


1/24/2011


$
50,000,000



3 Month USD LIBOR



4.0775
%12/18/2007


1/24/2011


$
50,000,000



3 Month USD LIBOR



4.2100
%12/21/2007


1/24/2012


$
50,000,000



3 Month USD LIBOR



4.0750
%12/21/2007


1/24/2012


$
50,000,000



3 Month USD LIBOR



4.0750
%     Contractual Obligations.
  Payments Due by PeriodLess Than








More ThanContractual Obligations

Total


1 Year


1-3 Years


4-5 Years


5 Years(in millions)Debt obligations

$
626.3


$



$



$
626.3


$
Interest on debt obligations(1)


150.3



36.4



72.9



41.0



Operating lease obligations


0.1



0.1











Capacity payments(2)


16.8



9.2



6.8



0.8



Right of way


4.9



0.3



0.5



0.5



3.6Asset retirement obligation


3.3















3.3$
801.7


$
46.0


$
80.2


$
668.6


$
6.9     (1)
    Represents interest expense on partnership debt, based on
    interest rates as of December 31, 2007. We used an average
    rate of 5.8% to estimate our interest on variable rate debt
    obligations.(2)
    Consists of capacity payments for natural gas pipelines.  Available Credit.
  Item 7A.
    Quantitative
    and Qualitative Disclosures about Market Risk    Commodity Price Risk. and/or
 74




---



##### Table of Contents



75




---



##### Table of Contents



Natural
    Gas
  Avg. Price


MMBtu per DayInstrument Type

Index

$/MMBtu


2008


2009


2010


2011


2012


Fair Value(in thousands)Natural Gas PurchasesSwap

NY-HH


8.34



1,467


















$
(341
)1,467



















(341
)Natural Gas SalesSwap

IF-HSC


8.09



2,328



















513Swap

IF-HSC


7.39







1,966















(551
)2,328



1,966















(38
)Swap

IF-NGPL MC


8.43



6,964



















4,475Swap

IF-NGPL MC


8.02







6,256















1,110Swap

IF-NGPL MC


7.43











5,685











(667
)Swap

IF-NGPL MC


7.34















2,750







(387
)Swap

IF-NGPL MC


7.18



















2,750



(435
)6,964



6,256



5,685



2,750



2,750



4,096Swap

IF-Waha


8.20



7,389



















3,000Swap

IF-Waha


7.61







6,936















(618
)Swap

IF-Waha


7.38











5,709











(1,288
)Swap

IF-Waha


7.36















3,250







(709
)Swap

IF-Waha


7.18



















3,250



(789
)7,389



6,936



5,709



3,250



3,250



(404
)Total Swaps








16,681



15,158



11,394



6,000



6,000



3,654Floor

IF-NGPL MC


6.55



1,000



















218Floor

IF-NGPL MC


6.55







850















1711,000



850















389Floor

IF-Waha


6.85



670



















140Floor

IF-Waha


6.55







565















93670



565















233Total Floors








1,670



1,415















622Basis Swap Jan 2008 Rec IF-HH minus $0.01, pay GD-HH,
    403,000 MMBtu














6$
3,941NGLsAvg. Price


Barrels per DayInstrument Type

Index

$/gal


2008


2009


2010


2011


2012


Fair Value(in thousands)NGL SalesSwap

OPIS-MB


1.02



7,127


















$
(40,051
)Swap

OPIS-MB


0.96







6,248















(20,573
)Swap

OPIS-MB


0.91











4,809











(5,506
)Swap

OPIS-MB


0.92















3,400







(3,210
)Swap

OPIS-MB


0.92



















2,700



(2,030
)7,127



6,248



4,809



3,400



2,700


$
(71,370
)  76




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##### Table of Contents



Condensate
  Avg. Price


Barrels per DayInstrument Type

Index

$/Bbl


2008


2009


2010


2011


2012


Fair Value(in thousands)Condensate SalesSwap

NY-WTI


70.68



384


















$
(3,013
)Swap

NY-WTI


69.00







322















(2,008
)Swap

NY-WTI


68.10











301











(1,705
)Total Swaps








384



322



301











(6,726
)Floor

NY-WTI


60.50



55



















2Floor

NY-WTI


60.00







50















9Total Floors








55



50















11439



372



301










$
(6,715
)   Customer
    Hedges
  Customer
    Hedges
  Instrument

Daily

AveragePeriod

Commodity

Type

Volume

Price

Index

Fair Value(in thousands)PurchasesJan 2008  June 2008

Natural gas

Swap

8,440 MMBtu

7.23 per MMBtu

NY-HH

$
8SalesJan 2008  June 2008

Natural gas

Fixed price sale

8,440 MMBtu

7.23 per MMBtu

NY-HH


(8
)$
     Interest
    Rate Risk
      NotionalTrade Date

Term


From


To


Rate


Amount(in thousands)12/11/07


3 years



12/13/07



1/24/11



4.0775
%

$
50,00012/14/07


3 years



12/18/07



1/24/11



4.2100
%


50,00012/19/07


4 years



12/21/07



1/24/12



4.0750
%


50,00012/19/07


4 years



12/21/07



1/24/12



4.0750
%


50,000    77




---



##### Table of Contents



Credit
    Risk
    Item 8.
    Financial
    Statements and Supplementary Data  page F-1
  Item 9.
    Changes
    in and Disagreements with Accountants on Accounting and
    Financial Disclosure    Item 9A.
    Controls
    and Procedures  Disclosure
    Controls and Procedures
  Rules 13a-15(e) 15d-15(e)
  Internal
    Control Over Financial Reporting
  Rules 13a-15(f) 15d-15(f).
     78




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##### Table of Contents



Item 9B.
    Other
    Information   Part III  Item 10.
    Directors,
    Executive Officers and Corporate Governance    Management
    of Targa Resources Partners LP
      Regulation S-
 79




---



##### Table of Contents



Directors
    and Executive Officers
    Name

Age(1)

Position with Targa Resources GP LLCRene R. Joyce


60



Chief Executive Officer and DirectorJoe Bob Perkins


47



PresidentJames W. Whalen


66



President  Finance and Administration and
    DirectorRoy E. Johnson


63



Executive Vice PresidentMichael A. Heim


59



Executive Vice President and Chief Operating OfficerJeffrey J. McParland


53



Executive Vice President, and Chief Financial OfficerPaul W. Chung


48



Executive Vice President, General Counsel and SecretaryPeter R. Kagan


39



DirectorChansoo Joung


47



DirectorRobert B. Evans


59



DirectorBarry R. Pearl


58



DirectorWilliam D. Sullivan


51



Director     (1)
    
    As of March 1, 2008    Rene R. Joyce
 80




---



##### Table of Contents



Joe Bob Perkins
  James W. Whalen
  Roy E. Johnson
  Michael A. Heim
  Jeffrey J. McParland
 81




---



##### Table of Contents



Paul W. Chung
  Peter R. Kagan
  Chansoo Joung
  Robert B. Evans
  Barry R. Pearl
  William D. Sullivan
 82




---



##### Table of Contents



Reimbursement
    of Expenses of our General Partner
    
    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; and
    operations and certain direct expenses, which are not subject to
    the $5 million cap for general and administrative expenses.    
    general and administrative expenses, which are not capped,
    allocated to the SAOU and LOU Systems according to Targas
    allocation practice; and
    operating and certain direct expenses, which are not capped.      Code of
    Ethics
  Form 8-K.
  (713) 584-1000. Form 10-K
  Section 16(A)
    Beneficial Ownership Reporting Compliance
   83




---



##### Table of Contents



Item 11.
    Executive
    Compensation  Executive
    Compensation
  Compensation
    Discussion and Analysis
  The following discussion and analysis contains statements
    regarding our and our executive officers future
    performance targets and goals. These targets and goals are
    disclosed in the limited context of our compensation programs
    and should not be understood to be statements of
    managements expectations or estimates of results or other
    guidance.
  Overview
        Compensation
    Philosophy
    
    Provide a competitive total compensation program that enables us
    to attract and retain key executives;
    Ensure an alignment between our strategic and financial
    performance and the total compensation received by our named
    executive officers; 84




---



##### Table of Contents




    Provide compensation for performance relative to expectations
    and our peer group;
    Ensure a balance between short-term and long-term compensation
    while emphasizing at-risk, or variable, compensation as a
    valuable means of supporting our strategic goals and aligning
    the interests of our named executive officers with those of our
    shareholders; and
    Ensure that our total compensation program supports our business
    objectives and priorities.    The
    Role of Peer Groups and Benchmarking
        Role
    of Senior Management in Establishing Compensation for Named
    Executive Officers
      Elements
    of Compensation for Named Executive Officers
   85




---



##### Table of Contents



Base Salary.
  Annual Cash Incentives.
      LTIP Awards.
  Retirement Benefits.
 86




---



##### Table of Contents



Health and Welfare Benefits.
  Perquisites.
  Relation
    of Compensation Elements to Compensation
    Philosophy
    Application
    of Compensation Elements
  Base Salary.
  Annual Cash Incentives.
  Rene R. Joyce

$
300,000Jeffrey J. McParland

$
235,000Joe Bob Perkins

$
270,000James W. Whalen

$
270,000Michael A. Heim

$
250,000   Equity/Stock Option Exchange.
  Long-term Cash Incentives.
 87




---



##### Table of Contents



Retirement Benefits.
  Health and Welfare Benefits.
  Perquisites.
  Changes
    for 2008
  Annual Cash Incentives. and/or
  Long-term Cash Incentives.
  Compensation
    Committee Interlocks and Insider Participation
   88




---



##### Table of Contents



Compensation
    Committee Report
  Form 10-K. Form 10-K
            Executive
    Compensation
    Summary Compensation Table for 2007Non-EquityStock


Option


Incentive Plan


All Other


TotalYear


Salary


Awards ($)(1)


Awards ($)(1)


Compensation


Compensation(2)


CompensationRene R. Joyce


2007


$
293,750


$
459,769


$
3,244


$
300,000


$
817,850


$
1,874,613Chief Executive Officer


2006



266,530



312,513



3,244



262,000



25,536



869,823Jeffrey J. McParland


2007



230,000



316,770



3,244



235,000



674,179



1,459,193Executive Vice President and Chief Financial Officer


2006



210,280



236,720



3,244



204,400



23,386



678,030Joe Bob Perkins


2007



265,000



366,318



3,244



270,000



817,775



1,722,337President


2006



244,030



260,294



3,244



238,000



23,474



769,042James W. Whalen


2007



265,000



224,796







270,000



817,775



1,577,571President  Finance and Administration


2006



244,030



227,546







238,000



17,539



727,115Michael A. Heim


2007



243,750



366,318



3,244



250,000



817,725



1,681,037Executive Vice President and Chief Operating Officer


2006



217,791



260,294



3,244



214,000



23,411



718,740     (1)
    The amounts reported in these columns reflect the aggregate
    dollar amounts recognized for stock awards (including
    performance units) and option awards, as applicable, for
    financial statement reporting purposes with respect to fiscal
    year 2007 (disregarding any estimate of forfeitures related to
    service-based vesting conditions). No stock awards or option
    awards granted to the named executive officers were forfeited
    during 2007. Detailed information about the amount recognized
    for specific awards is reported in the table under
    Outstanding Equity Awards at 2007 Fiscal Year-End
    below. 89




---



##### Table of Contents



(2)
    For 2007 All Other Compensation includes the
    (i) payments under the Change of Control Bonus Plan and
    individual Bonus Agreements made in August 2007 in connection
    with the termination of the Change of Control Bonus Plan and the
    Bonus Agreements, (ii) aggregate value of matching,
    non-matching and discretionary contributions to our 401(k) plan
    and (iii) the dollar value of life insurance coverage.  Change ofChange of

ControlControl

Agreement

401(k) and Profit

Dollar Value ofName

Plan Termination

Termination

Sharing Plan

Life Insurance

TotalRene R. Joyce

$
76,614


$
717,537


$
22,950


$
749


$
817,850Jeffrey J. McParland


76,614



574,028



22,950



587



674,179Joe Bob Perkins


76,614



717,537



22,950



674



817,775James W. Whalen


76,614



717,537



22,950



674



817,775Michael A. Heim


76,614



717,537



22,950



624



817,725   Grants of
    Plan-Based Awards
    Grants of Plan Based Awards for 2007All Other StockAwards: Number of


Grant Date FairEstimated Possible Payouts Under


Estimated Future Payouts Under


Shares of Stock or


Value of Stock andNon-Equity Incentive Plan Awards(1)


Equity Incentive Plan Awards(2)


Units


Option AwardsTargetName

Grant Date

Threshold


Target


2X Target


Threshold


(Units)


Maximum


(3)


(4)Mr. Joyce

N/A
    02/14/07
    05/01/07

$
75,000


$
150,000


$
300,000







15,000







84,110


$
447,450
    0Mr. McParland

N/A
    02/14/07
    05/01/07


58,750



117,500



235,000







8,200







69,090



244,606 
    0Mr. Perkins

N/A
    02/14/07
    05/01/07


67,500



135,000



270,000







10,800







84,110



322,164 
    0Mr. Whalen

N/A
    02/14/07
    05/01/07


67,500



135,000



270,000







10,800







25,140



322,164
    0Mr. Heim

N/A
    02/14/07
    05/01/07


62,500



125,000



250,000







10,000







84,100



298,300
    0  90




---



##### Table of Contents



(1)
    These awards were granted under the Bonus Plan. At the time the
    Bonus Plan was adopted, the estimated future payouts in the
    above table under the heading Estimated Possible Payouts
    Under Non-Equity Incentive Plan Awards represented the
    cash bonus pool available for awards to the named executive
    officers under the Bonus Plan.(2)
    These performance unit awards were granted under the Targa
    Investments Long-Term Incentive Plan and are discussed in more
    detail under the heading Compensation
    Discussion & Analysis  Application of
    Compensation Elements  Long-Term Cash
    Incentives.(3)
    These awards were granted in exchange for options relating to
    Targa Investments preferred stock held by the named
    executive officers.(4)
    The dollar amounts shown are determined by multiplying the
    number of units reported in the table by $29.83 (the per unit
    fair value under FAS 123R on the grant date) and assume full
    payout under the awards at the time of vesting.  Narrative
    Disclosure to Summary Compensation Table and Grants of Plan
    Based Awards table
    Targa
    Investments 2005 Stock Incentive Plan
  Stock Option Grants.
  Restricted Stock Grants.
  Targa
    Investments 2004 Stock Incentive Plan
  Stock Option Grants.
 91




---



##### Table of Contents



Outstanding
    Equity Awards at 2007 Fiscal Year-End
    Outstanding Equity Awards at 2007 Fiscal Year-EndOption Awards


Stock AwardsEquity IncentiveEquity Incentive


Plan Awards:Plan Awards:


Market orNumber of


Payout ValueMarket Value of


Unearned


of UnearnedNumber of Shares


Shares or Units


Shares, Units


Shares, Units orOption


Option


or Units of Stock


of Stock That


or Other Rights


Other Rights#


#


Exercise


Expiration


That Have Not


Have Not


That Have


That HaveName

Exercisable


Unexercisable


Price


Date


Vested


Vested(11)


Not Vested(12)


Not Vested(13)Rene R. Joyce






21,772
(1)

$
0.75



10/31/2015



734,199
(5)

$
2,532,987



15,000


$
444,300291,376
(1)

$
3.00



10/31/2015



7,116
(6)

$
24,550246,549
(1)

$
15.00



10/31/2015



84,110
(9)

$
290,1803,006
(2)

$
3.00



12/20/20152,559
(2)

$
15.00



12/20/2015Jeffrey J. McParland






21,772
(1)

$
0.75



10/31/2015



555,120
(5)

$
1,915,164



8,200



242,884218,532
(1)

$
3.00



10/31/2015



5,337
(6)

$
18,413184,912
(1)

$
15.00



10/31/2015



69,090
(9)

$
238,3612,254
(2)

$
3.00



12/20/20151,919
(2)

$
15.00



12/20/2015Joe Bob Perkins






21,772
(1)

$
0.75



10/31/2015



611,680
(5)

$
2,110,296



10,800



319,896236,014
(1)

$
3.00



10/31/2015



5,764
(6)

$
19,886199,705
(1)

$
15.00



10/31/2015



84,110
(9)

$
290,1802,435
(2)

$
3.00



12/20/20152,073
(2)

$
15.00



12/20/2015James W. Whalen


136,365



90,908
(3)

$
3.00



11/1/2015



202,278
(7)

$
697,859



10,800



319,896115,386



76,922
(3)

$
15.00



11/1/2015



2,220
(8)

$
7,6591,407



937
(4)

$
3.00



12/20/2015



25,140
(10)

$
86,7331,198



798
(4)

$
15.00



12/20/2015Michael A. Heim






21,772
(1)

$
0.75



10/31/2015



611,680
(5)

$
2,110,296



10,000



296,200236,014
(1)

$
3.00



10/31/2015



5,764
(6)

$
19,886199,705
(1)

$
15.00



10/31/2015



84,110
(9)

$
290,1802,435
(2)

$
3.00



12/20/20152,073
(2)

$
15.00



12/20/2015     (1)
    Represents options to purchase shares of Targa Investments
    common stock awarded on October 31, 2005. These options
    vest on the following schedule: 70% vest on April 30, 2008,
    an additional 10% vest on October 31, 2008 and the
    remaining options vest on October 31, 2009.(2)
    Represents options to purchase shares of Targa Investments
    common stock awarded on December 20, 2005. These options
    vest on the following schedule: 70% vest on June 20, 2008,
    an additional 10% vest on December 20, 2008 and the
    remaining options vest on December 20, 2009.(3)
    Represents options to purchase shares of Targa Investments
    common stock awarded on November 1, 2005. These options
    vest on the following schedule: 50% vest on each of
    November 1, 2008 and 2009.(4)
    Represents options to purchase shares of Targa Investments
    common stock awarded on December 20, 2005. These options
    vest on the following schedule: 50% vest on each of
    December 20, 2008 and 2009.(5)
    Represents shares of restricted common stock of Targa
    Investments awarded on October 31, 2005. These shares vest
    on the following schedule: 70% on April 30, 2008; an
    additional 10% on October 31, 2008 and the remaining shares
    on October 31, 2009.(6)
    Represents shares of restricted common stock of Targa
    Investments awarded on December 20, 2005. These shares vest
    on the following schedule: 70% on June 20, 2008; an
    additional 10% on December 20, 2008 and the remaining
    shares on December 20, 2009. 92




---



##### Table of Contents



(7)
    Represents shares of restricted common stock of Targa
    Investments awarded on October 31, 2005 (2,721 shares)
    and November 1, 2005 (502,975 shares). These shares
    vest on the following schedule: 50% vest on each of
    October 31, 2008 and 2009 (with respect to the
    October 31, 2005 awards) and November 1, 2008 and 2009
    (with respect to the November 1, 2005 awards).(8)
    Represents shares of restricted common stock of Targa
    Investments awarded on December 20, 2005. These shares vest
    on the following schedule: 50% vest on each of December 20,
    2008 and 2009.(9)
    Represents shares of restricted common stock of Targa
    Investments awarded on May 1, 2007 in connection with the
    exchange of options relating to Targa Investments
    preferred stock held by the named executive officers. These
    shares vest on the following schedule: 80% vest on
    January 1, 2008 and the remaining vest on April 16,
    2008.  (10)
    Represents shares of restricted common stock of Targa
    Investments awarded on May 1, 2007 in connection with the
    exchange of options relating to Targa Investments
    preferred stock held by the named executive officer. These
    shares vest on the following schedule: 80% vest on
    January 1, 2008 and the remaining vest on May 7, 2008.(11)
    The dollar amounts shown are determined by multiplying the
    number of shares or units reported in the table by $3.45 (the
    value determined by an independent consultant pursuant to a
    valuation of Targa Investments common stock as of
    October 24, 2007, which management believes is a reasonable
    approximation of the value of such stock as of December 31,
    2007.(12)
    Represents the number of performance units awarded on
    February 14, 2007 under the Targa Investments Long-Term
    Incentive Plan. These awards vest in August of 2010 based on the
    Partnerships performance over such period measured against
    a peer group of companies. These awards are discussed in more
    detail under the heading Compensation
    Discussion & Analysis  Application of
    Compensation Elements  Long-Term Cash
    Incentives.(13)
    The dollar amounts shown are determined by multiplying the
    number of units reported in the table by $29.62 (the closing
    price of a common unit of the Partnership on December 31,
    2007) and assume full payout under the awards at the time
    of vesting.  Option
    Exercises and Stock Vested in 2007
    Option Exercises and Stock Vested for 2007Option Awards

Stock AwardsNumber of SharesAcquired on

Value Realized on

Number of Shares

Value Realized onName

Exercise(1)

Exercise(2)

Acquired on Vesting

Vesting(3)Rene R. Joyce


84,110


$
325,422Jeffrey J. McParland


69,090


$
267,309Joe Bob Perkins


84,110


$
325,422James W. Whalen


25,140


$
97,267



102,249


$
352,759Michael A. Heim


84,110


$
325,422     (1)
    Represents shares of restricted common stock of Targa
    Investments awarded on May 1, 2007 in connection with the
    exchange of options relating to Targa Investments
    preferred stock held by the named executive officers. At the
    time of exchange, the restricted common stock had a value of
    $1.10 per share. This value was determined by an independent
    consultant pursuant to a valuation of Targa Investments common
    stock as of December 31, 2006. The named executive officers
    received 10 shares of restricted common stock of Targa
    Investments for each option exchanged.(2)
    This value includes a cash payment to the named executive
    officers of $27.69 per option exchanged.(3)
    On October 31, 2007 and December 20, 2007, 101,139 and
    1,110 shares, respectively, vested. The value realized on
    vesting used a per share price of $3.45. This value was
    determined by an independent consultant pursuant to a valuation
    of Targa Investments common stock as of October 24, 93




---



##### Table of Contents



2007, which management believes is a reasonable approximation of
    the value of such stock as of December 31, 2007.  Change in
    Control and Termination Benefits
  2005 Incentive Plan. and/or
        
    Change of Controlmeans, in one transaction or a series
    of related transactions, a consolidation, merger or any other
    form of corporate reorganization involving Targa Investments or
    a sale of Preferred Stock (or a sale of Targa Investments
    common stock following conversion of the Preferred Stock) by
    stockholders of Targa Investments with the result immediately
    after such merger, consolidation, corporate reorganization or
    sale that (A) a single person, together with its
    affiliates, owns, if prior to any firm commitment underwritten
    offering by Targa Investments of its common stock to the public
    pursuant to an effective registration statement under the
    Securities Act (x) for which the aggregate cash proceeds to
    be received by Targa Investments from such offering (without
    deducting underwriting discounts, expenses, and commissions) are
    at least $35,000,000, and (y) pursuant to which Targa
    Investments common stock is listed for trading on the New
    York Stock Exchange or is admitted to trading and quoted on the
    NASDAQ National Market System (a Qualified Public
    Offering), either a greater number of shares of Targa
    Investments common stock (calculated assuming that all
    shares of Preferred Stock have been converted at the specified
    conversion ratio) than Warburg Pincus and its affiliates then
    own or, in the context of a consolidation, merger or other
    corporate reorganization in which Targa Investments is not the
    surviving entity, more voting stock generally entitled to elect
    directors of such surviving entity (or in the case of a
    triangular merger, of the parent entity of such 94




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##### Table of Contents



surviving entity) than Warburg Pincus and its affiliates then
    own or, if on or after a Qualified Public Offering, either a
    majority of Targa Investments common stock calculated on a
    fully-diluted basis (i.e. on the basis that all shares of
    Preferred Stock have been converted at the specified conversion
    ratio, that all Management Stock is outstanding, whether vested
    or not, and that all outstanding options to acquire Targa
    Investments common stock had been exercised (whether then
    exercisable or not)) or, in the context of a consolidation,
    merger or other corporate reorganization in which Targa
    Investments is not the surviving entity, a majority of the
    voting stock generally entitled to elect directors of such
    surviving entity (or in the case of a triangular merger, of the
    parent entity of such surviving entity) calculated on a fully
    diluted basis and (B) Warburg Pincus and its affiliates
    collectively own less than a majority of the initial shares of
    Capital Stock outstanding on October 31, 2005 owned by them
    (the Initial Shares) or, in the event such Initial
    Shares are converted or exchanged into other voting securities
    of Targa Investment or such surviving or parent entity, less
    than a majority of such voting securities Warburg Pincus and its
    affiliates would have owned had they retained all such Initial
    Shares;  
    Management Stockmeans the shares of Targa
    Investments common stock granted pursuant to the terms of
    the 2005 Incentive Plan, any such shares transferred to a
    permitted transferee and any and all securities of any kind
    whatsoever of Targa Investments which may be issued in respect
    of, in exchange for, or upon conversion of such shares of common
    stock pursuant to a merger, consolidation, stock split, stock
    dividend, recapitalization of Targa Investments or otherwise;
    Liquidation Eventmeans the voluntary or involuntary
    liquidation, dissolution, or winding up of the affairs of Targa
    Investments; provided that neither the merger or consolidation
    of Targa Investments with or into another entity, nor the merger
    or consolidation of another entity with or into Targa
    Investments, nor the sale of all or substantially all of the
    assets of Targa Investments shall be deemed to be a Liquidation
    Event;
    Causemeans discharge by Targa Investments based on
    (A) an employees gross negligence or willful
    misconduct in the performance of duties, (B) conviction of
    a felony or other crime involving moral turpitude; (C) an
    employees willful refusal, after fifteen days
    written notice from the Targa Investments Board, to perform the
    material lawful duties or responsibilities required of him;
    (D) willful and material breach of any corporate policy or
    code of conduct established by Targa Investments; and
    (E) willfully engaging in conduct that is known or should
    be known to be materially injurious to Targa Investments or any
    of its subsidiaries;
    Capital Stockmeans any and all shares of capital stock
    of, or other equity interests in, Targa Investments, and any and
    all warrants, options, or other rights to purchase or acquire
    any of the foregoing;
    Original Costmeans, with respect to a particular share
    of Capital Stock, the cash amount originally paid to Targa
    Investments to purchase such share (or if such share was issued
    in respect of other shares of Targa Investments issued in
    connection with the merger of one of Targa Investments
    subsidiaries with and into us, then the cash amount originally
    paid to us to purchase such other shares), subject to adjustment
    for subdivisions, combinations or stock dividends involving such
    Capital Stock, or, if no cash amount was originally paid to
    Targa Investments to purchase such share, then no consideration
    (or if such share was issued in respect of other shares of Targa
    Investments issued in connection with the merger of one of Targa
    Investments subsidiaries with and into us and such other
    shares were issued by us for no cash consideration, then no
    consideration); and
    Fair Market Valuemeans the value determined by the
    unanimous resolution of all directors of the Targa Investments
    Board, provided that if the Targa Investments Board does not or
    is unable to make such a determination, Fair Market Value means
    the value determined by an investment banking firm of recognized
    national standing selected by a majority of the directors of the
    Targa Investments Board. 95




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##### Table of Contents



Termination for DeathName

Change of Control


or DisabilityRene R. Joyce

$
3,038,972
(1)

$
3,038,972
(1)Jeffrey J. McParland


2,330,074
(2)


2,330,074
(2)Joe Bob Perkins


2,586,449
(3)


2,586,449
(3)James W. Whalen


833,583
(4)


833,583
(4)Michael A. Heim


2,586,449
(5)


2,586,449
(5)     (1)
    Of this amount, $2,532,987 relates to the unvested shares of
    restricted stock of Targa Investments granted on
    October 31, 2005; $24,549 relates to the unvested shares of
    restricted stock of Targa Investments granted on
    December 20, 2005; $290,180 relates to the unvested shares
    of restricted stock of Targa Investments granted on May 1,
    2007 in connection with the stock option exchange; $189,904
    relates to the unvested options to purchase Targa Investments
    common stock granted on October 31, 2005; and $1,352
    relates to the unvested options to purchase Targa Investments
    common stock granted on December 20, 2005.(2)
    Of this amount, $1,915,164 relates to the unvested shares of
    restricted stock of Targa Investments granted on
    October 31, 2005; $18,412 relates to the unvested shares of
    restricted stock of Targa Investments granted on
    December 20, 2005; $238,360 relates to the unvested shares
    of restricted stock of Targa Investments granted on May 1,
    2007 in connection with the stock option exchange; $157,124
    relates to the unvested options to purchase Targa Investments
    common stock granted on October 31, 2005; and $1,014
    relates to the unvested options to purchase Targa Investments
    common stock granted on December 20, 2005.(3)
    Of this amount, $2,110,296 relates to the unvested shares of
    restricted stock of Targa Investments granted on
    October 31, 2005; $19,886 relates to the unvested shares of
    restricted stock of Targa Investments granted on
    December 20, 2005; $290,180 relates to the unvested shares
    of restricted stock of Targa Investments granted on May 1,
    2007 in connection with the stock option exchange; $164,991
    relates to the unvested options to purchase Targa Investments
    common stock granted on October 31, 2005; and $1,096
    relates to the unvested options to purchase Targa Investments
    common stock granted on December 20, 2005.(4)
    Of this amount, $3,754 relates to the unvested shares of
    restricted stock of Targa Investments granted on
    October 31, 2005; $694,106 relates to the unvested shares
    of restricted stock of Targa Investments granted on
    November 1, 2005; $7,660 relates to the unvested shares of
    restricted stock of Targa Investments granted on
    December 20, 2005; $86,733 relates to the unvested shares
    of restricted stock of Targa Investments granted on May 1,
    2007 in connection with the stock option exchange; $40,908
    relates to the unvested options to purchase Targa Investments
    common stock granted on November 1, 2005; and $422 relates
    to the unvested options to purchase Targa Investments common
    stock granted on December 20, 2005.(5)
    Of this amount, $2,110,296 relates to the unvested shares of
    restricted stock of Targa Investments granted on
    October 31, 2005; $19,886 relates to the unvested shares of
    restricted stock of Targa Investments granted on
    December 20, 2005; $290,180 relates to the unvested shares
    of restricted stock of Targa Investments granted on May 1,
    2007 in connection with the stock option exchange; $164,991
    relates to the unvested options to purchase Targa Investments
    common stock granted on October 31, 2005; and $1,096
    relates to the unvested options to purchase Targa Investments
    common stock granted on December 20, 2005.  Other
    Agreements
   96




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##### Table of Contents



Bonus Agreements.
  Change of Control Bonus Plan.
  TRII Severance Program.
  Termination
    of Change in Control and Termination Benefits
    Director
    Compensation
    Fees Earnedor Paid

Stock

All Other

Totalin Cash

Awards ($)(1)

Compensation(4)

CompensationRobert B. Evans(2)(3)

$
76,000


$
22,250


$
1,688


$
99,938Chansoo Joung(2)(3)


46,000



22,250



1,688



69,938Peter R. Kagan(2)(3)


47,500



22,250



1,688



71,438Barry R. Pearl(2)(3)


96,000



22,250



1,688



119,938William D. Sullivan(2)(3)


74,500



22,250



1,688



98,438     (1)
    The amounts reported reflect the aggregate dollar amounts
    recognized for stock awards for financial statement reporting
    purposes with respect to fiscal year 2007 (disregarding any
    estimate of forfeitures related to service-based vesting
    conditions). No stock awards granted to the directors were
    forfeited 97




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##### Table of Contents



during 2007. For a discussion of the assumptions and
    methodologies used to value the awards reported in these
    columns, please see the discussion of stock awards contained in
    the Notes to Consolidated Financial Statements at Note 11
    included in this annual report.  (2)
    Messrs. Evans, Joung, Kagan, Pearl and Sullivan each
    received 2,000 common units of the Partnership on
    February 14, 2007 in connection with their service on the
    Board of Directors of the Partnerships general partner.
    The grant date fair value of the 2,000 common units granted to
    each of these named individuals was $42,000, based on the
    initial public offering price of the common units. During 2007,
    Messrs. Joung and Kagan each received $1,690 in
    distributions on the common units of the Partnership that were
    awarded to them. The Partnership also recognized $22,500 of
    expense for each of the stock awards held by them.(3)
    At December 31, 2007, Mr. Evans held 3,900 common
    units, Mr. Joung and Kagan each held 2,000 common units,
    Mr. Pearl held 4,300 common units and Mr. Sullivan
    held 6,700 common units of the Partnership.(4)
    For 2007 All Other Compensation consists of the
    dividends paid on common units of the Partnership from unit
    awards.  Narrative
    to Director Compensation Table
      Director Long-term Equity Incentives.
  Changes
    for 2008
  Director Long-term Equity Incentives.
 98




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##### Table of Contents



Item 12.
    Security
    Ownership of Certain Beneficial Owners and Management and
    Related Stockholder Matters    
    each person who then beneficially owns 5% or more of the then
    outstanding units;
    all of the directors of Targa Resources GP LLC;
    each named executive officer of Targa Resources GP LLC; and
    all directors and officers of Targa Resources GP LLC as a group.  Targa Resources Partners LP


Targa Resources Investments Inc.Percentage








Percentage


PercentagePercentage





Percentage


of Total








of


ofof





of


Common and








Series B


RestrictedCommon


Common


Subordinated


Subordinated


Subordinated








Preferred


CommonUnits


Units


Units


Units


Units


Series B


Restricted


Stock


StockBeneficially


Beneficially


Beneficially


Beneficially


Beneficially


Preferred


Common


Beneficially


BeneficiallyName of Beneficial Owner(1)

Owned


Owned


Owned(6)


Owned


Owned


Stock


Stock


Owned


OwnedTarga Resources Investments Inc.(2)






*



11,528,231



100
%


24.96
%














Lehman Brother Holdings Inc.(3)


2,619,219



7.56
%










5.67
%LaBranche Structured Products LLC(4)


2,510,920



7.25
%










5.44
%Rene R. Joyce


20,000



*



285,364



2.48
%


*



56,208



1,217,212
(7)


*



15.6
%Joe Bob Perkins


7,100



*



240,509



2.09
%


*



47,632



1,021,798
(8)


*



13.2
%Michael A. Heim


2,500



*



226,959



1.97
%


*



39,192



1,021,798
(9)


*



13.2
%Jeffrey J. McParland


1,500



*



201,663



1.75
%


*



32,856



927,197
(10)


*



12.1
%James W. Whalen


36,152



*



151,131



1.31
%


*



14,978



790,742
(11)


*



10.3
%Peter R. Kagan(5)


4,000



*







*



*















*Chansoo Joung(5)


4,000



*







*



*















*Robert B. Evans


5,900



*







*



*















*Barry R. Pearl


6,300



*







*



*















*William D. Sullivan


8,700



*







*



*















*All directors and executive officers as a group (12 persons)


96,152



*



1,478,208



12.82
%


3.41
%


241,114



6,795,333



3.8
%


71.5
%     *
    
    Less than 1%  (1)
    Unless otherwise indicated, the address for all beneficial
    owners in this table is 1000 Louisiana, Suite 4300,
    Houston, Texas 77002. The nature of the beneficial ownership for
    all the units is sole voting and investment power.(2)
    The units attributed to Targa Resources Investments Inc. are
    held by two indirect wholly-owned subsidiaries, Targa GP Inc.
    and Targa LP Inc.(3)
    Lehman Brothers Holdings Inc. beneficially owns 1,775,219 common
    units, of which Lehman Brothers Inc. beneficially owns 1,295,919
    common units (which includes 805,919 common units directly held
    by Lehman Brothers Inc. and 490,000 common units directly held
    by Lehman Brothers MLP Partners LP) and Lehman Brothers MLP
    Opportunity Fund LP beneficially owns 479,300 common units.
    Lehman Brothers Inc. is wholly-owned by Lehman Brothers Holdings
    Inc. The address for Lehman Brothers Holdings Inc. and its
    affiliates is 745 Seventh Avenue, New York, NY 10019.(4)
    LaBranche Structured Products LLC beneficially owns 2,510,920
    common units. The address for LaBranche Structured Products LLC
    is 33 Whitehall Street, New York, N.Y. 10004.(5)
    Warburg Pincus Private Equity VIII, L.P. (WP VIII)
    and Warburg Pincus Private Equity IX, L.P. (WP IX)
    in the aggregate beneficially own 73.6% of Targa Resources
    Investments Inc. The general partner of WP VIII is Warburg
    Pincus Partners, LLC (WP Partners LLC) and the
    general partner of WP IX is Warburg Pincus IX, LLC, of which WP
    Partners LLC is sole member. Warburg Pincus & Co.
    (WP) is the managing member of WP Partners LLC. WP
    VIII and WP IX are managed by Warburg Pincus LLC (WP
    LLC). The address of the Warburg Pincus entities is 466
    Lexington Avenue, New York, New York 10017. Chansoo Joung and
    Peter R. Kagan, two of our directors, are each a general partner
    of WP and a Managing Director and Member of WP LLC. 99




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##### Table of Contents



Charles R. Kaye and Joseph P. Landy are each Managing General
    Partners of WP and Co-Presidents and Managing Members of WP LLC
    and may be deemed to control the Warburg Pincus entities.
    Messrs. Joung, Kagan, Kaye and Landy disclaim beneficial
    ownership of all shares held by the Warburg Pincus entities.  (6)
    The subordinated units presented as being beneficially owned by
    the directors and executive officers of Targa Resources GP LLC
    represent the number of units held indirectly by Targa Resources
    Investments Inc. that are attributable to such directors and
    officers based on their ownership of equity interests in Targa
    Resources Investments Inc.(7)
    Of this amount, 391,787 shares of restricted common stock
    reflect options that are currently exercisable for shares of
    restricted common stock.(8)
    Of this amount, 320,244 shares of restricted common stock
    reflect options that are currently exercisable for shares of
    restricted common stock.(9)
    Of this amount, 297,650 shares of restricted common stock
    reflect options that are currently exercisable for shares of
    restricted common stock.  (10)
    Of this amount, 254,356 shares of restricted common stock
    reflect options that are currently exercisable for shares of
    restricted common stock.(11)
    Of this amount, 52,213 shares of restricted common stock
    reflect options that are currently exercisable for shares of
    restricted common stock. 100




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##### Table of Contents



Item 13.
    Certain
    Relationships and Related Transactions, and Director
    Independence    Distributions
    and Payments to Our General Partner and its Affiliates
    Operational
    Stage
  Distributions of available cash to our general partner and its
    affiliates

We will generally make cash distributions 98% to our limited
    partner unitholders pro rata, including our general partner and
    its affiliates, as the holders of 11,528,231 subordinated units,
    and 2% to our general partner. In addition, if distributions
    exceed the minimum quarterly distribution and other higher
    target distribution levels, our general partner will be entitled
    to increasing percentages of the distributions, up to 50% of the
    distributions above the highest target distribution level.Assuming we have sufficient available cash to pay the full
    minimum quarterly distribution on all of our outstanding units
    for four quarters, our general partner and its affiliates would
    receive an annual distribution of approximately $1.3 million on
    their general partner units and $15.6 million on their
    subordinated units.Payments to our general partner and its affiliates

We reimburse Targa for the payment of certain operating expenses
    and for the provision of various general and administrative
    services for our benefit. Please see  Omnibus
    Agreement  Reimbursement of Operating and General and
    Administrative Expense.Withdrawal or removal of our general partner

If our general partner withdraws or is removed, its general
    partner interest and its incentive distribution rights will
    either be sold to the new general partner for cash or converted
    into common units, in each case for an amount equal to the fair
    market value of those interests.   Liquidation
    Stage
  Liquidation

Upon our liquidation, the partners, including our general
    partner, will be entitled to receive liquidating distributions
    according to their respective capital account balances.  101




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##### Table of Contents



Agreements
    Governing the Transactions
    Purchase
    and Sale Agreement
      Omnibus
    Agreement
    Reimbursement
    of Operating and General and Administrative
    Expense
   102




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##### Table of Contents




    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; and
    operations and certain direct expenses, which are not subject to
    the $5 million cap for general and administrative expenses.    
    general and administrative expenses, which are not capped,
    allocated to the SAOU and LOU Systems according to Targas
    allocation practice; and
    operating and certain direct expenses, which are not capped.      Competition
    Indemnification
     103




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##### Table of Contents



Contracts
    with Affiliates
  NGL and Condensate Purchase Agreement for the North Texas
    System.
  NGL Purchase Agreements for the SAOU and LOU
    Systems.
  Natural Gas Purchase Agreements.
  Indemnification Agreements.
   104




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##### Table of Contents



and/or
    Conflicts
    of Interest
        
    approved by the conflicts committee, although our general
    partner is not obligated to seek such approval;
    approved by the vote of a majority of the outstanding common
    units, excluding any common units owned by our general partner
    or any of its affiliates;
    on terms no less favorable to us than those generally being
    provided to or available from unrelated third parties; or
    fair and reasonable to us, taking into account the totality of
    the relationships among the parties involved, including other
    transactions that may be particularly favorable or advantageous
    to us.   105




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##### Table of Contents



Item 14.
    Principal
    Accountant Fees and Services    For Year Ended December 31,2007


2006Audit Fees(1)

$
2,224.7


$
820.7Audit-Related Fees(2)






Tax Fees(3)


177.4



All Other Fees(4)






     (1)
    Audit fees represent amounts billed for each of the years
    presented for professional services rendered in connection with
    (i) the audit of our annual financial statements,
    (ii) the review of our quarterly financial statements or
    (iii) those services normally provided in connection with
    statutory and regulatory filings or engagements including
    comfort letters, consents and other services related to SEC
    matters. This information is presented as of the latest
    practicable date for this annual report on
    Form 10-K.(2)
    Audit-related fees represent amounts we were billed in each of
    the years presented for assurance and related services that are
    reasonably related to the performance of the annual audit or
    quarterly reviews. This category primarily includes services
    relating to internal control assessments and accounting-related
    consulting.(3)
    Tax fees represent amounts we were billed in each of the years
    presented for professional services rendered in connection with
    tax compliance, tax advice, and tax planning. This category
    primarily includes services relating to the preparation of
    unitholder annual K-1 statements.(4)
    All other fees represent amounts we were billed in each of the
    years presented for services not classifiable under the other
    categories listed in the table above. No such services were
    rendered by PricewaterhouseCoopers during the last two years.   106




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##### Table of Contents



PART IV  Item 15.
    Exhibits
    and Financial Statement Schedules  Financial Statements
  Index to Financial Statements page F-1
  Financial Statement Schedules
    Exhibits
  2
.1**



Purchase and Sale Agreement, dated as of September 18,
    2007, by and between Targa Resources Holdings LP and Targa
    Resources Partners 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)).2
.2



Amendment to Purchase and Sale Agreement, dated October 1,
    2007, by and between Targa Resources Holdings LP and Targa
    Resources Partners LP (incorporated by reference to
    Exhibit 2.2 to Targa Resources Partners LPs Current
    Report on
    Form 8-K
    filed October 24, 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/A
    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/A
    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/A
    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)).10
.1



Credit Agreement, dated February 14, 2007, by and among
    Targa Resources Partners LP, as Borrower, Bank of America, N.A.,
    as Administrative Agent, Wachovia Bank, N.A., as Syndication
    Agent, Merrill Lynch Capital, Royal Bank of Canada and The Royal
    Bank of Scotland PLC, as Co-Documentation Agents, and the other
    lenders party thereto (incorporated by reference to
    Exhibit 10.1 to Targa Resources Partners LPs Current
    Report on
    Form 8-K
    filed February 16, 2007 (File
    No. 001-33303)).10
.2



Commitment Increase Supplement, dated October 24, 2007, by
    and among Targa Resources Partners LP, Bank of America, N.A. and
    the parties signatory thereto as the Increasing Lenders and the
    New Lenders (incorporate by reference to Exhibit 10.2 to
    Targa Resources Partners LPs Current Report on
    Form 8-K
    filed October 24, 2007 (File
    No. 001-33303)).10
.3



First Amendment to Credit Agreement, dated October 24,
    2007, by and among Targa Resources Partners LP, Bank of America,
    N.A. and each Lender party thereto (incorporated by reference to
    Exhibit 10.3 to Targa Resources Partners LPs Current
    Report on
    Form 8-K
    filed October 24, 2007 (File
    No. 001-33303)). 107




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##### Table of Contents



10
.4



Contribution, Conveyance and Assumption Agreement, dated
    February 14, 2007, by and among Targa Resources Partners
    LP, Targa Resources Operating LP, Targa Resources GP LLC, Targa
    Resources Operating GP LLC, Targa GP Inc., Targa LP Inc., Targa
    Regulated Holdings LLC, Targa North Texas GP LLC and Targa North
    Texas LP (incorporated by reference to Exhibit 10.2 to
    Targa Resources Partners LPs Current Report on
    Form 8-K
    filed February 16, 2007 (File
    No. 001-33303)).10
.5



Contribution, Conveyance and Assumption Agreement, dated
    October 24, 2007, by and among Targa Resources Partners LP,
    Targa Resources Holdings LP, Targa TX LLC, Targa TX PS LP, Targa
    LA LLC, Targa LA PS LP and Targa North Texas GP LLC
    (incorporated by reference to Exhibit 10.4 to Targa
    Resources Partners LPs Current Report on
    Form 8-K
    filed October 24, 2007 (File
    No. 001-33303)).10
.6



Amended and Restated Omnibus Agreement, dated October 24,
    2007, by and among Targa Resources Partners LP, Targa Resources,
    Inc., Targa Resources LLC and Targa Resources GP LLC
    (incorporated by reference to Exhibit 10.5 to Targa
    Resources Partners LPs Current Report on
    Form 8-K
    filed October 24, 2007 (File
    No. 001-33303)).10
.7+



Targa Resources Partners Long-Term Incentive Plan (incorporated
    by reference to Exhibit 10.2 to Targa Resources Partners
    LPs Registration Statement on
    Form S-1/A
    filed February 1, 2007 (File
    No. 333-138747)).10
.8+



Targa Resources Investments Inc. Long-Term Incentive Plan
    (incorporated by reference to Exhibit 10.9 to Targa
    Resources Partners LPs Registration Statement on
    Form S-1/A
    filed February 1, 2007 (File
    No. 333-138747)).10
.9+



Form of Restricted Unit Grant Agreement (incorporated by
    reference to Exhibit 10.2 to Targa Resources Partners
    LPs Current Report on
    Form 8-K
    filed February 13, 2007 (File
    No. 001-33303)).10
.10+



Form of Performance Unit Grant Agreement (incorporated by
    reference to Exhibit 10.2 to Targa Resources Partners
    LPs Current Report on
    Form 8-K
    filed January 22, 2008 (File
    No. 001-33303)).10
.11



Gas Gathering and Purchase Agreement by and between Burlington
    Resources Oil & Gas Company LP, Burlington Resources
    Trading Inc. and Targa Midstream Services Limited Partnership
    (portions of this exhibit have been omitted and filed separately
    with the Securities and Exchange Commission pursuant to a
    request for confidential treatment) (incorporated by reference
    to Exhibit 10.5 to Targa Resources Partners LPs
    Registration Statement on
    Form S-1/A
    filed February 8, 2007 (File
    No. 333-138747)).10
.12



Natural Gas Purchase Agreement, effective January 1, 2007,
    by and between Targa Gas Marketing LLC (Buyer) and Targa North
    Texas LP (Seller) (incorporated by reference to
    Exhibit 10.11 to Targa Resources Partners LPs
    Registration Statement on
    Form S-1
    filed October 1, 2007 (File
    No. 333-146436)).10
.13



NGL and Condensate Purchase Agreement, effective January 1,
    2007, by and between Targa North Texas LP (Seller) and Targa
    Liquids Marketing and Trade (Buyer) (incorporated by reference
    to Exhibit 10.12 to Targa Resources Partners LPs
    Registration Statement on
    Form S-1
    filed October 1, 2007 (File
    No. 333-146436)).10
.14



Product Purchase Agreement, effective January 1, 2007, by
    and between Targa Louisiana Field Services LLC (Seller) and
    Targa Liquids Marketing and Trade (Buyer) (incorporated by
    reference to Exhibit 10.13 to Targa Resources Partners
    LPs Registration Statement on
    Form S-1/A
    filed October 12, 2007 (File
    No. 333-146436)).10
.15



Raw Product Purchase Agreement, effective January 1, 2007,
    by and between Targa Texas Field Services LP (Seller) and Targa
    Liquids Marketing and Trade (Buyer) (incorporated by reference
    to Exhibit 10.14 to Targa Resources Partners LPs
    Registration Statement on
    Form S-1/A
    filed October 12, 2007 (File
    No. 333-146436)).10
.16



Amended and Restated Natural Gas Sales Agreement, effective
    December 1, 2005, by and between Targa Louisiana Field
    Services LLC (Buyer) and Targa Gas Marketing LLC (Seller)
    (incorporated by reference to Exhibit 10.15 to Targa
    Resources Partners LPs Registration Statement on
    Form S-1/A
    filed October 12, 2007 (File
    No. 333-146436)). 108




---



##### Table of Contents



10
.17



Amended and Restated Natural Gas Purchase Agreement, effective
    December 1, 2005, by and between Targa Gas Marketing LLC
    (Buyer) and Targa Louisiana Field Services LLC (Seller)
    (incorporated by reference to Exhibit 10.16 to Targa
    Resources Partners LPs Registration Statement on
    Form S-1/A
    filed October 12, 2007 (File
    No. 333-146436)).10
.18



Amended and Restated Natural Gas Purchase Agreement, effective
    December 1, 2005, by and between Targa Gas Marketing LLC
    (Buyer) and Targa Texas Field Services LP (Seller) (incorporated
    by reference to Exhibit 10.17 to Targa Resources Partners
    LPs Registration Statement on
    Form S-1/A
    filed October 12, 2007 (File
    No. 333-146436)).10
.19+



Targa Resources Partners LP Indemnification Agreement for Barry
    R. Pearl dated February 14, 2007 (incorporated by reference
    to Exhibit 10.11 to Targa Resources Partners LPs
    Annual Report on
    Form 10-K
    filed April 2, 2007 (File
    No. 001-33303)).10
.20+



Targa Resources Partners LP Indemnification Agreement for Robert
    B. Evans dated February 14, 2007 (incorporated by reference
    to Exhibit 10.12 to Targa Resources Partners LPs
    Annual Report on
    Form 10-K
    filed April 2, 2007 (File
    No. 001-33303)).10
.21+



Targa Resources Partners LP Indemnification Agreement for
    Williams D. Sullivan dated February 14, 2007 (incorporated
    by reference to Exhibit 10.13 to Targa Resources Partners
    LPs Annual Report on
    Form 10-K
    filed April 2, 2007 (File
    No. 001-33303)).21
.1



Subsidiaries of Targa Resources Partners LP.*23
.1



Consent of Independent Registered Public Accounting Firm*31
.1



Certification of the Chief Executive Officer pursuant to
    Rule 13a-14(a)/15d-14(a)
    of the Securities Exchange Act of 1934.*31
.2



Certification of the Chief Financial Officer pursuant to
    Rule 13a-14(a)/15d-14(a)
    of the Securities Exchange Act of 1934.*.32
.1



Certification of the 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 the Chief Financial Officer pursuant to
    18 U.S.C. Section 1350, as adopted pursuant to
    Section 906 of the Sarbanes-Oxley Act of 2002.*     *
    
    Filed herewith

**
    
    Pursuant to Item 601(b)(2) of
    Regulation S-K,
    the Partnership agrees to furnish supplementally a copy of any
    omitted exhibit or Schedule to the SEC upon request.+
    
    Management contract or compensatory plan or arrangement. 109




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##### Table of Contents



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

Title (Position with Targa Resources GP LLC)/s/  Rene
    R. JoyceRene
    R. Joyce

Chief Executive Officer and Director (Principal Executive
    Officer)/s/  Jeffrey
    J. McParlandJeffrey
    J. McParland

Executive Vice President, Chief Financial Officer and Treasurer
    (Principal Financial Officer)/s/  John
    Robert SpargerJohn
    Robert Sparger

Senior Vice President and Chief Accounting Officer (Principal
    Accounting Officer)/s/  James
    W. WhalenJames
    W. Whalen

President  Finance and Administration and Director/s/  Peter
    R. KaganPeter
    R. Kagan

Director/s/  Chansoo
    JoungChansoo
    Joung

Director/s/  Barry
    R. PearlBarry
    R. Pearl

Director/s/  Robert
    B. EvansRobert
    B. Evans

Director/s/  William
    D. SullivanWilliam
    D. Sullivan

Director  110




---



##### 



INDEX TO
    FINANCIAL STATEMENTS
   
 TARGA RESOURCES PARTNERS LP AUDITED COMBINED CONSOLIDATED
    FINANCIAL STATEMENTSReport of Independent Registered Public
    Accounting Firm


F-2Consolidated Balance Sheets as of
    December 31, 2007 and December 31, 2006


F-3Consolidated Statements of Operations for the
    Years Ended December 31, 2007, 2006 and 2005


F-4Consolidated Statements of Comprehensive Income
    (Loss) for the Years Ended December 31, 2007, 2006 and
    2005


F-5Consolidated Statement of Changes in
    Partners Capital/Net Parent Investment for the Years Ended
    December 31, 2007, 2006 and 2005


F-6Consolidated Statements of Cash Flows for the
    Years Ended December 31, 2007, 2006 and 2005


F-7Notes to the Consolidated Financial Statements


F-8   F-1




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##### Table of Contents



Report of
    Independent Registered Public Accounting Firm        
    F-2




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##### Table of Contents



TARGA
    RESOURCES PARTNERS LP



CONSOLIDATED
    BALANCE SHEETS  December 31,


December 31,2007


2006(in thousands)ASSETSCurrent assets:Cash and cash equivalents

$
50,994


$
Receivables from third parties


59,346



61,559Receivables from affiliated companies


87,547



Inventory


1,624



958Assets from risk management activities


8,695



25,683Other


269



Total current assets


208,475



88,200Property, plant and equipment, at cost


1,433,955



1,391,644Accumulated depreciation


(174,361
)


(103,073
)Property, plant and equipment, net


1,259,594



1,288,571Debt issue costs


6,588



Debt issue costs allocated from Parent






21,353Long-term assets from risk management activities


3,040



15,851Other long-term assets


2,275



2,396Total assets

$
1,479,972


$
1,416,371LIABILITIES AND PARTNERS CAPITALCurrent liabilities:Accounts payable

$
5,693


$
3,773Accrued liabilities


142,836



109,337Current maturities of debt allocated from Parent






340,747Liabilities from risk management activities


44,003



3,296Total current liabilities


192,532



457,153Long-term debt allocated from Parent






706,597Long-term debt


626,300



Long-term liabilities from risk management activities


43,109



551Other long-term liabilities


3,266



2,919Deferred income tax liability


559



3,238Commitments and contingencies (Note 11)Partners capital:Common unitholders (34,636,000 units issued and outstanding
    at 
    December 31, 2007)


770,207



Subordinated unitholders (11,528,231 units issued and
    outstanding at December 31, 2007)


(84,999
)


General partner (942,128 units issued and outstanding at
    December, 2007)


4,234



Accumulated other comprehensive income (loss)


(75,236
)


30,964Net parent investment






214,949Total partners capital


614,206



245,913Total liabilities and partners capital

$
1,479,972


$
1,416,371    F-3




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##### Table of Contents



TARGA
    RESOURCES PARTNERS LP



CONSOLIDATED
    STATEMENTS OF OPERATIONS  Year


Year


YearEnded


Ended


EndedDecember 31,


December 31,


December 31,2007


2006


2005(in thousands, except per unit amounts)Revenues from third parties

$
630,773


$
951,936


$
1,110,911Revenues from affiliates


1,030,696



786,589



61,539Total operating revenues


1,661,469



1,738,525



1,172,450Costs and expenses:Product purchases from third parties


1,215,733



1,194,751



1,041,686Product purchases from affiliates


191,064



322,917



19,998Operating expenses


50,931



49,075



24,394Depreciation and amortization expense


71,756



69,957



23,069General and administrative expense


18,927



16,063



16,721Other


(296
)






1,548,115



1,652,763



1,125,868Income from operations


113,354



85,762



46,582Other expense:Interest expense, net


21,998







Interest expense allocated from Parent


19,436



88,025



21,177Loss/(gain) on
    mark-to-market
    derivative contracts


30,221



(16,756
)


11,973Loss on debt extinguishment










3,701Other


(30
)






Income before income taxes


41,729



14,493



9,731Deferred income tax expense


1,479



2,926



Net income


40,250


$
11,567


$
9,731Less net income (loss) attributable to predecessor operations:For the period January 1, 2007 to February 13, 2007
    for North Texas


(6,861
)For the period January 1, 2007 to October 23, 2007 for
    SAOU/LOU


19,045Total


12,184Net income allocable to partners


28,066General partner interest in net income for the period


561Net income available to common and subordinated unitholders

$
27,505Basic net income per common and subordinated unit

$
0.81Diluted net income per common and subordinated unit

$
0.81Basic average number of common and subordinated units outstanding


33,986Diluted average number of common and subordinated units
    outstanding


33,994    F-4




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##### Table of Contents



TARGA
    RESOURCES PARTNERS LP



CONSOLIDATED
    STATEMENTS OF COMPREHENSIVE INCOME (LOSS)  Year


Year


YearEnded


Ended


EndedDecember 31,


December 31,


December 31,2007


2006


2005(in thousands)Net income

$
40,250


$
11,567


$
9,731Other comprehensive income (loss):Commodity hedges:Change in fair value of commodity hedges


(105,584
)


36,937



(16,870
)Reclassification adjustment for settled periods


993



(822
)


10,436Related income taxes


312



(312
)


Interest rate swaps:Change in fair value of interest rate swaps


(1,689
)


1,267



(120
)Reclassification adjustment for settled periods


(232
)


(488
)


39Other comprehensive income (loss)


(106,200
)


36,582



(6,515
)Comprehensive income (loss)

$
(65,950
)

$
48,149


$
3,216    F-5




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##### Table of Contents



TARGA
    RESOURCES PARTNERS LP



CONSOLIDATED
    STATEMENT OF CHANGES IN PARTNERS

CAPITAL/NET PARENT INVESTMENT  AccumulatedOther


Partners CapitalNet Parent


Comprehensive


Limited Partners


GeneralInvestment


Income (Loss)


Common


Subordinated


Partner


Total(in thousands)Balance at December 31, 2004

$
138,326


$
897


$



$



$



$
139,223Initial contribution  North Texas System


219,879



















219,879Distributions to Parent


(81,095
)


















(81,095
)Net income


9,731



















9,731Other comprehensive loss






(6,515
)














(6,515
)Balance at December 31, 2005


286,841



(5,618
)














281,223Distributions to Parent


(83,459
)


















(83,459
)Net income


11,567



















11,567Other comprehensive income






36,582















36,582Balance at December 31, 2006


214,949



30,964















245,913Net income attributable to predecessor operations:For the period January 1, 2007 to February 13, 2007
    for North Texas


(6,861
)


















(6,861
)For the period January 1, 2007 to October 23, 2007
    for SAOU/LOU


19,045



















19,045Net income attributable to post MLP ownership










19,063



8,442



561



28,066Other contributions associated with North Texas System


218,993



















218,993Other contributions associated with SAOU/LOU System


195,960



















195,960Book value of net assets contributed byTarga Resources, Inc. to the Partnership


(396,905
)










376,351



20,554



Book value of net assets transferred via common control from
    Targa Resources, Inc. to the Partnership


(245,181
)










232,420



12,761



Distribution to Targa for assets transferred under common control














(692,486
)


(37,416
)


(729,902
)Issuance of units to public (including underwriterover-allotment), net of offering and other costs










771,835







8,398



780,233Contribution of non-cash compensation










180











180Other comprehensive loss






(106,200
)














(106,200
)Distributions to unitholders










(20,871
)


(9,726
)


(624
)


(31,221
)Balance at December 31, 2007

$



$
(75,236
)

$
770,207


$
(84,999
)

$
4,234


$
614,206    F-6




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##### Table of Contents



TARGA
    RESOURCES PARTNERS LP



CONSOLIDATED
    STATEMENTS OF CASH FLOWS  Year


Year


YearEnded


Ended


EndedDecember 31,


December 31,


December 31,2007


2006


2005(in thousands)Cash flows from operating activitiesNet income

$
40,250


$
11,567


$
9,731Adjustments to reconcile net income to net cash provided by
    operating activitiesDepreciation


71,632



69,832



22,945Accretion of asset retirement obligations


342



245



94Amortization of intangibles


124



125



124Amortization of debt issue costs


1,805



6,246



4,723Noncash compensation


180







Gain on sale of assets


(296
)






Deferred income tax expense


1,479



2,926



(Gain) loss on
    mark-to-market
    derivative contracts


30,221



(16,756
)


11,973Risk management activities


530



(1,541
)


Changes in operating assets and liabilities:Accounts receivable


89,760



78,467



(61,826
)Inventory


(666
)


1,373



(1,950
)Other


(273
)


1,106



10Accounts payable


1,920



(13,748
)


11,439Accrued liabilities


33,472



(15,408
)


13,254Net cash provided by operating activities


270,480



124,434



10,517Cash flows from investing activitiesPurchases of property, plant and equipment


(41,088
)


(32,575
)


(7,197
)Other


372



(317
)


422Net cash used in investing activities


(40,716
)


(32,892
)


(6,775
)Cash flows from financing activitiesProceeds from equity offerings


777,471







Costs incurred in connection with public offerings


(4,640
)






Distributions to unit holders


(31,221
)






Proceeds from borrowings under credit facility


721,300







Costs incurred in connection with financing arrangements


(7,491
)






Repayments of loans:Affiliated


(665,692
)






Credit facility


(95,000
)






Distributions to Parent


(873,497
)


(91,542
)


(3,742
)Net cash used in financing activities


(178,770
)


(91,542
)


(3,742
)Net change in cash and cash equivalents


50,994







Cash and cash equivalents, beginning of period










Cash and cash equivalents, end of period

$
50,994


$



$
Supplemental cash flow information:Interest paid

$
15,453


$



$
Noncash investing and financing activities:Contribution of the North Texas System










219,879Debt issue costs allocated from Parent






5,903



6,229Long-term debt allocated from ParentBorrowing










(227,106
)Repayment


59,400



5,979



146,907Net settlement of allocated indebtedness and debt issue costs


301,801



330



Net contribution of affiliated receivables


184,462







    F-7




---



##### Table of Contents



TARGA
    RESOURCES PARTNERS LP



NOTES TO
    CONSOLIDATED FINANCIAL STATEMENTS  Note 1 
    Organization
    and Operations    Initial
    Public Offering
    Acquisition
    of the SAOU and LOU Systems
      Note 2 
    Basis of
    Presentation  Business
    Combinations.
 F-8




---



##### Table of Contents



TARGA
    RESOURCES PARTNERS LP
  NOTES TO
    CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
        Note 3 
    Significant
    Accounting Policies  Asset Retirement Obligations. Accounting for Asset Retirement
    Obligations, Accounting for
    Conditional Asset Retirement Obligations. and/or
 F-9




---



##### Table of Contents



TARGA
    RESOURCES PARTNERS LP
  NOTES TO
    CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
    Year Ended December 31,2007


2006


2005(in thousands)Beginning of period

$
2,888


$
2,644


$
630Other










2,054Change in estimate


32



(1
)


(134
)Accretion expense


342



245



94End of period

$
3,262


$
2,888


$
2,644   Cash and Cash Equivalents.
  Comprehensive Income.
  Concentration of Credit Risk.
      Debt Issue Costs.
  Environmental Liabilities. and/or
  Impairment of Long-Lived Assets.
 F-10




---



##### Table of Contents



TARGA
    RESOURCES PARTNERS LP
  NOTES TO
    CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
  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
  EITF 03-6 EITF 03-6
  Price Risk Management (Hedging). Accounting for Derivative
    Instruments and Hedging Activities,
 F-11




---



##### Table of Contents



TARGA
    RESOURCES PARTNERS LP
  NOTES TO
    CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
        Property, Plant and Equipment.
  Range ofAsset Group

YearsNatural gas gathering systems and processing facilities

15 to 25Office and miscellaneous equipment

3 to 7     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.    percent-of-proceeds Percent-of-value percent-of-liquids
 F-12




---



##### Table of Contents



TARGA
    RESOURCES PARTNERS LP
  NOTES TO
    CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
    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,
  Share-Based Employee Compensation. Share-Based Payment
  Use of Estimates.
  Recent
    Accounting Pronouncements.
    The
    Fair Value Option for Financial Assets and Financial
    Liabilities, including an amendment of FASB Statement
    No. 115,
  Noncontrolling Interests in Consolidated Financial
    Statements  An Amendment of ARB No. 51.
 F-13




---



##### Table of Contents



TARGA
    RESOURCES PARTNERS LP
  NOTES TO
    CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
    Business Combinations
  Note 4 
    Acquisitions  pooling-of-interests
     F-14




---



##### Table of Contents



TARGA
    RESOURCES PARTNERS LP
  NOTES TO
    CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
    TargaSAOU/LOU


North Texas


ResourcesSystem


System


Partners LP(in thousands)ASSETSCurrent assets:Trade receivables

$
60,249


$
1,310


$
61,559Assets from risk management activities


8,433



17,250



25,683Other


958







958Total current assets


69,640



18,560



88,200Property, plant, and equipment, net


224,463



1,064,108



1,288,571Debt issue costs allocated from Parent


3,741



17,612



21,353Long-term assets from risk management activities


310



15,541



15,851Other long-term assets


2,396







2,396Total assets

$
300,550


$
1,115,821


$
1,416,371LIABILITIES AND PARTNERS CAPITALCurrent liabilities:Accounts payable and other liabilities

$
81,489


$
31,621


$
113,110Current maturities of debt allocated from Parent


59,664



281,083



340,747Liabilities from risk management activities


3,296







3,296Total current liabilities


144,449



312,704



457,153Long-term debt allocated from Parent


123,720



582,877



706,597Long-term liabilities from risk management activities


455



96



551Other long-term liabilities


1,629



4,528



6,157Commitments and contingenciesPartners capital:Net parent investment


30,176



184,773



214,949Other comprehensive income


121



30,843



30,964Total partners capital


30,297



215,616



245,913Total liabilities and partners capital

$
300,550


$
1,115,821


$
1,416,371  F-15




---



##### Table of Contents



TARGA
    RESOURCES PARTNERS LP
  NOTES TO
    CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
    For the Year Ending December 31, 2006SAOU/LOU


North Texas


Targa ResourcesSystem


System


Partners LP(in thousands)Revenues from third parties

$
936,712


$
15,224


$
951,936Revenues from affiliates


416,984



369,605



786,589Total operating revenues


1,353,696



384,829



1,738,525Costs and expenses:Product purchases from third parties


926,264



268,487



1,194,751Product purchases from affiliates


322,071



846



322,917Operating expenses


24,973



24,102



49,075Depreciation and amortization expense


13,999



55,958



69,957General and administrative expense


9,159



6,904



16,0631,296,466



356,297



1,652,763Income from operations


57,230



28,532



85,762Other expense:Interest expense allocated from Parent


15,115



72,910



88,025Gain on
    mark-to-market
    derivative contracts


(16,756
)






(16,756
)Income (loss) before income taxes


58,871



(44,378
)


14,493Deferred income tax expense


394



2,532



2,926Net income (loss)

$
58,477


$
(46,910
)

$
11,567   SAOU/LOU


North Texas


Targa ResourcesSystem


System


Partners LPFor The Year


For the TwoEnded


Months EndedDecember 31,


December 31,2005


2005


Total(in thousands)Revenues from third parties

$
1,088,719


$
22,192


$
1,110,911Revenues from affiliates


8,587



52,952



61,539Total operating revenues


1,097,306



75,144



1,172,450Costs and expenses:Product purchases from third parties


986,705



54,981



1,041,686Product purchases from affiliates


19,987



11



19,998Operating expenses


20,900



3,494



24,394Depreciation and amortization expense


13,919



9,150



23,069General and administrative expense


15,658



1,063



16,7211,057,169



68,699



1,125,868Income from operations


40,137



6,445



46,582Other expense:Interest expense allocated from Parent


9,635



11,542



21,177Loss on
    mark-to-market
    derivative contracts


11,973







11,973Loss on debt extinguishment


3,701







3,701Income (loss) before income taxes


14,828



(5,097
)


9,731Deferred income tax expense










Net income (loss)

$
14,828


$
(5,097
)

$
9,731  F-16




---



##### Table of Contents



TARGA
    RESOURCES PARTNERS LP
  NOTES TO
    CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
  Note 5 
    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.
  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; F-17




---



##### Table of Contents



TARGA
    RESOURCES PARTNERS LP
  NOTES TO
    CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   
    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 6 
    Net
    Income per Limited Partner Unit       F-18




---



##### Table of Contents



TARGA
    RESOURCES PARTNERS LP
  NOTES TO
    CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
    SAOU/LOU System


North Texas SystemTarga Resources





Targa Resources


Targa NorthPartners LP


SAOU/LOU


Partners LP


Texas LPYear Ended


Oct. 24, 2007 to


Jan. 1, 2007 to


Feb. 14, 2007 to


Jan. 1, 2007 toDecember 31, 2007


Dec. 31, 2007


Oct. 23, 2007


Dec. 31, 2007


Feb. 13, 2007(in thousands, except unit and per unit information)Revenues from third parties

$
630,773


$
129,916


$
483,766


$
13,156


$
3,935Revenues from affiliates


1,030,696



139,616



472,746



380,165



38,1691,661,469



269,532



956,512



393,321



42,104Costs and expenses:Product purchases


1,406,797



242,214



858,007



277,881



28,695Operating expenses, excluding DD&A


50,931



6,837



19,270



22,008



2,816Depreciation and amortization expense


71,756



2,747



11,663



50,421



6,925General and administrative expense


18,927



965



9,018



8,242



702Loss (gain) on sale of assets


(296
)






(298
)


2



1,548,115



252,763



897,660



358,554



39,138Income from operations


113,354



16,769



58,852



34,767



2,966Other expenseInterest expense, net


21,998



4,261







17,737



Interest expense allocated from Parent


19,436







9,609







9,827Loss/(gain) on
    mark-to-market
    derivative contracts


30,221







30,221



Other


(30
)


(7
)


(23
)






Income (loss) before income taxes


41,729



12,515



19,045



17,030



(6,861
)Deferred income tax expense


1,479



99







1,380



Net income (loss)


40,250



12,416



19,045



15,650



(6,861
)Less: Net income attributable to predecessor operationsFor the period 1/1-2/13/2007 for North Texas


(6,861
)














(6,861
)For the period 1/1-10/23/2007 for SAOU/LOU


19,045







19,045







Total


12,184






$
19,045






$
(6,861
)Net income allocable to partners


28,066General partner interest in net income


561



248







313Net income available to common and subordinated unitholders

$
27,505


$
12,168






$
15,337Basic net income per common and subordinated unit

$
0.81


$
0.36






$
0.45Diluted net income per common and subordinated unit

$
0.81


$
0.36






$
0.45Basic average number of common and subordinated units outstanding


33,986



33,986







33,986Diluted average number of common and subordinated units
    outstanding


33,994



33,994







33,994  F-19




---



##### Table of Contents



TARGA
    RESOURCES PARTNERS LP
  NOTES TO
    CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
      Note 7 
    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, and
    operations and certain direct general and administrative
    expenses, which are not subject to the $5 million cap for
    general and administrative expenses.    
    General and administrative expenses, which are not capped,
    allocated to the SAOU and LOU Systems according to Targas
    allocation practice; and
    Operating and certain direct expenses, which are not capped.   F-20




---



##### Table of Contents



TARGA
    RESOURCES PARTNERS LP
  NOTES TO
    CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
    Contracts
    with Affiliates
  Sales to and purchases from affiliates.
  NGL and Condensate Purchase Agreement for the North Texas
    System.
  NGL Purchase Agreements for the SAOU and LOU
    Systems.
  Natural Gas Purchase Agreements.
  Allocations
  Allocation of costs.
 F-21




---



##### Table of Contents



TARGA
    RESOURCES PARTNERS LP
  NOTES TO
    CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
    Allocations of long-term debt, debt issue costs, interest
    rate swaps and interest expense.
 F-22




---



##### Table of Contents



TARGA
    RESOURCES PARTNERS LP
  NOTES TO
    CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
    SAOU/LOU System


North Texas SystemTarga Resources





Targa Resources


Targa NorthYear Ended


Partners LP


SAOU/LOU


Partners LP


Texas LP


Year Ended


Year EndedDecember 31,


Oct. 24, 2007 to


Jan 1, 2007 to


Feb. 14, 2007 to


Jan. 1, 2007 to


December 31,


December 31,2007


Dec. 31, 2007


Oct. 23, 2007


Dec. 31, 2007


Feb 13, 2007


2006


2005(in thousands)CashSales to affiliates

$
(1,030,696
)

$
(139,616
)

$
(472,746
)

$
(380,165
)

$
(38,169
)

$
(786,589
)

$
(61,539
)Purchases from affiliates


191,064



51,031



139,108



848



77



322,917



19,998Allocations of general & administrative
    expenses  pre IPO


8,831







8,129







702



16,062



16,721Allocations of general & administrative expenses under
    Omnibus Agreement


5,095



746







4,349











Allocated interest


19,436







9,598







9,838



88,025



21,177Receivable from affiliates to be settled in cash


87,547



65,477







22,070











Receipts (Payments) made by the Parent


584,561



22,362



182,268



352,898



27,033



268,043



(99
)$
(134,162
)

$




(133,643
)

$



$
(519
)

$
(91,542
)

$
(3,742
)NoncashInitial contribution by Parent









$







$



$



$
219,879Allocation of Parent debt repayments










59,400











5,979



146,907Allocation of Parent incremental debt borrowings


























(227,106
)Net settlement of allocated indebtedness and debt issue costs










121,145







180,656



5,903



6,229Net contribution of affiliated receivables










145,606







38,856







Parent settlement of risk management activities






















1,774



(3,384
)Other










3,452











272



329,603







219,512



13,928



142,525$
195,960






$
218,993


$
(77,614
)

$
138,783   Centralized
    Cash Management
   F-23




---



##### Table of Contents



TARGA
    RESOURCES PARTNERS LP
  NOTES TO
    CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
      Other
  Commodity hedges.
  Period

Commodity

Instrument Type

Daily Volumes

Average Price


IndexJan 2008  Mar 2008

Natural gas

Swap

1,650 MMBtu

$
8.47 per MMBtu


NY-HHJan 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-WahaJan 2008  Mar 2008

NGL

Swap

470  Bbl


1.39  per gallon


OPIS-MBJan 2008  Dec 2008

NGL

Swap

3,175 Bbl


1.06  per gallon


OPIS-MBJan 2009  Dec 2009

NGL

Swap

3,000 Bbl


0.98  per gallon


OPIS-MBJan 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    F-24




---



##### Table of Contents



TARGA
    RESOURCES PARTNERS LP
  NOTES TO
    CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
  Note 8 
    Property,
    Plant, and Equipment    December 31,2007


2006(in thousands)Gathering and processing systems

$
1,363,791


$
1,362,980Other property and equipment


70,164



28,6641,433,955



1,391,644Accumulated depreciation


(174,361
)


(103,073
)$
1,259,594


$
1,288,571   Note 9 
    Long-Term
    Debt  Pre-IPO Indebtedness.
        Post-IPO Indebtedness.
 F-25




---



##### Table of Contents



TARGA
    RESOURCES PARTNERS LP
  NOTES TO
    CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
            
    incur indebtedness;
    grant liens; and
    engage in transactions with affiliates.      Note 10 
    Derivative
    Instruments and Hedging Activities     F-26




---



##### Table of Contents



TARGA
    RESOURCES PARTNERS LP
  NOTES TO
    CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
          Natural
    Gas
  Avg. Price


MMBtu per DayInstrument Type

Index

$/MMBtu


2008


2009


2010


2011


2012


Fair Value(in thousands)Natural Gas PurchasesSwap

NY-HH


8.34



1,467


















$
(341
)1,467



















(341
)Natural Gas SalesSwap

IF-HSC


8.09



2,328



















513Swap

IF-HSC


7.39







1,966















(551
)2,328



1,966















(38
)Swap

IF-NGPL MC


8.43



6,964



















4,475Swap

IF-NGPL MC


8.02







6,256















1,110Swap

IF-NGPL MC


7.43











5,685











(667
)Swap

IF-NGPL MC


7.34















2,750







(387
)Swap

IF-NGPL MC


7.18



















2,750



(435
)6,964



6,256



5,685



2,750



2,750



4,096Swap

IF-Waha


8.20



7,389



















3,000Swap

IF-Waha


7.61







6,936















(618
)Swap

IF-Waha


7.38











5,709











(1,288
)Swap

IF-Waha


7.36















3,250







(709
)Swap

IF-Waha


7.18



















3,250



(789
)7,389



6,936



5,709



3,250



3,250



(404
)Total Swaps








16,681



15,158



11,394



6,000



6,000



3,654Floor

IF-NGPL MC


6.55



1,000



















218Floor

IF-NGPL MC


6.55







850















1711,000



850















389Floor

IF-Waha


6.85



670



















140Floor

IF-Waha


6.55







565















93670



565















233Total Floors








1,670



1,415















622Basis Swap Jan 2008 Rec IF-HH minus $0.01, pay GD-HH,
    403,000 MMBtu


















6$
3,941  F-27




---



##### Table of Contents



TARGA
    RESOURCES PARTNERS LP
  NOTES TO
    CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
  NGLs
  Avg. Price


Barrels per dayInstrument Type

Index


$/gal


2008


2009


2010


2011


2012


Fair Value(in thousands)NGL SalesSwap


OPIS-MB



1.02



7,127


















$
(40,051
)Swap


OPIS-MB



0.96







6,248















(20,573
)Swap


OPIS-MB



0.91











4,809











(5,506
)Swap


OPIS-MB



0.92















3,400







(3,210
)Swap


OPIS-MB



0.92



















2,700



(2,030
)7,127



6,248



4,809



3,400



2,700


$
(71,370
)   Condensate
  Avg. Price


Barrels per dayInstrument Type

Index


$/Bbl


2008


2009


2010


2011


2012


Fair Value(in thousands)Condensate SalesSwap


NY-WTI



70.68



384


















$
(3,013
)Swap


NY-WTI



69.00







322















(2,008
)Swap


NY-WTI



68.10











301











(1,705
)Total Swaps










384



322



301











(6,726
)Floor


NY-WTI



60.50



55



















2Floor


NY-WTI



60.00







50















9Total Floors










55



50















11439



372



301










$
(6,715
)   Customer
    Hedges
  Period

Commodity


Instrument Type

Daily Volume


Average Price


Index


Fair Value(in thousands)PurchasesJan 2008  June 2008


Natural gas


Swap


8,440 MMBtu



7.23 per MMBtu



NY-HH


$
8SalesJan 2008  June 2008


Natural gas


Fixed price sale


8,440 MMBtu



7.23 per MMBtu



NY-HH



(8
)$
     mark-to-market
 F-28




---



##### Table of Contents



TARGA
    RESOURCES PARTNERS LP
  NOTES TO
    CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
  mark-to-market mark-to-market mark-to-market
    Effective Date


Expiration Date


Notional Amount


Index


Fixed Rate12/13/2007



1/24/2011


$
50,000,000



3 Month USD LIBOR



4.0775
%12/18/2007



1/24/2011


$
50,000,000



3 Month USD LIBOR



4.2100
%12/21/2007



1/24/2012


$
50,000,000



3 Month USD LIBOR



4.0750
%12/21/2007



1/24/2012


$
50,000,000



3 Month USD LIBOR



4.0750
%     Note 11
    
    Share-Based Compensation  Share-Based Payment
  Non-Employee
    Director Grants
      Note 12 
    Income
    Taxes  Accounting for Income Taxes,
 F-29




---



##### Table of Contents



TARGA
    RESOURCES PARTNERS LP
  NOTES TO
    CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
  Note 13 
    Commitments
    and Contingencies    Payments Due by Period2013 &Contractual Obligations

Total


2008


2009


2010


2011


2012


Thereafter(in thousands)Operating lease obligations

$
142


$
110


$
32


$



$



$



$
Capacity payments


16,777



9,201



5,306



1,492



778







Right of way


4,947



310



269



255



255



252



3,606Asset retirement obligation


3,263























3,263$
25,129


$
9,621


$
5,607


$
1,747


$
1,033


$
252


$
6,869     Environmental
  96-1, Environmental Remediation Liabilities.
      Litigation
   F-30




---



##### Table of Contents



TARGA
    RESOURCES PARTNERS LP
  NOTES TO
    CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
    Note 14 
    Significant
    Risks and Uncertainties  Nature
    of Operations in Midstream Energy Industry
        Counterparty
    Risk with Respect to Financial Instruments
  and/or
  Casualty
    or Other Risks
       F-31




---



##### Table of Contents



TARGA
    RESOURCES PARTNERS LP
  NOTES TO
    CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
      Note 15 
    Selected
    Quarterly Financial Data (Unaudited)    First


Second


Third


FourthQuarter


Quarter


Quarter


Quarter


Total(Dollars in thousands, except per unit amounts)Year Ended December 31, 2007:Revenues

$
348,781


$
433,615


$
405,038


$
474,035


$
1,661,469Operating income


20,739



28,183



29,965



34,467



113,354Net income (loss)


(10,627
)


13,811



14,392



22,674



40,250less: net income (loss) attributable to predecessor operations


(12,780
)


9,771



10,523



4,670



12,184Net income available to partners


2,153



4,040



3,869



18,004



28,066General partner interest in net income


43



81



77



360



561Net income available to common and subordinated unitholders

$
2,110


$
3,959


$
3,792


$
17,644


$
27,505Basic income per limitedpartner unit

$
0.07


$
0.13


$
0.12


$
0.42


$
0.81Basic number of units


30,848



30,848



30,848



41,795



33,986Diluted number of units


30,852



30,856



30,857



41,805



33,994Year Ended December 31, 2006:Revenues

$
523,858


$
453,721


$
401,267


$
359,679


$
1,738,525Operating income


24,789



22,983



22,869



15,121



85,762Net income (loss)


14,925



(3,681
)


8,241



(7,918
)


11,567Basic income per limited partner unit(a)


















     (a)
    Total basic net income per limited partner unit was not
    calculated as Partner Units were not outstanding as of
    December 31, 2006. F-32




---



##### Table of Contents



TARGA
    RESOURCES PARTNERS LP
  NOTES TO
    CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
     For the Three Months Ended March 31, 2007TargaSAOU/LOU


North Texas


ResourcesSystem


System


Partners LP(in thousands)Revenues from third parties

$
134,106


$
6,084


$
140,190Revenues from affiliates


121,082



87,509



208,591Total operating revenues


255,188



93,593



348,781Costs and expenses:Product purchases from third parties


190,709



63,445



254,154Product purchases from affiliates


40,101



243



40,344Operating expenses


6,184



5,968



12,152Depreciation and amortization expense


3,843



14,195



18,038General and administrative expense


1,776



1,578



3,354242,613



85,429



328,042Income from operations


12,575



8,164



20,739Other expense:Interest expense allocated from Parent


3,616



9,827



13,443Interest expense, net






2,705



2,705Loss on mark-to-market derivative contracts


14,880







14,880Other


(21
)






(21
)Income before income taxes


(5,900
)


(4,368
)


(10,268
)Deferred income tax expense


21



338



359Net income

$
(5,921
)

$
(4,706
)

$
(10,627
)   F-33




---



##### Table of Contents



TARGA
    RESOURCES PARTNERS LP
  NOTES TO
    CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
  For the Three Months Ending


For the Six Months EndingJune 30, 2007


June 30, 2007Targa


SAOU/LOU





TargaSAOU/LOU


North Texas


Resources


System


North Texas


ResourcesSystem


System


Partners LP


(restated)a


System


Partners LP(in thousands)Revenues from third parties

$
170,849


$
4,300


$
175,149


$
304,955


$
10,384


$
315,339Revenues from affiliates


156,363



102,103



258,466



277,445



189,612



467,057Total operating revenues


327,212



106,403



433,615



582,400



199,996



782,396Costs and expenses:Product purchases from third parties


236,159



74,306



310,465



426,868



137,751



564,619Product purchases from affiliates


60,965



271



61,236



101,066



514



101,580Operating expenses


5,730



6,065



11,795



11,914



12,033



23,947Depreciation and amortization expense


3,330



14,289



17,619



7,173



28,484



35,657General and administrative expense


2,679



1,953



4,632



4,455



3,531



7,986Loss (gain) on sale of assets


(315
)






(315
)


(315
)






(315
)308,548



96,884



405,432



551,161



182,313



733,474Income from operations


18,664



9,519



28,183



31,239



17,683



48,922Other expense:Interest expense allocated from Parent


2,732







2,732



6,348



9,827



16,175Interest expense, net






5,154



5,154







7,859



7,859Loss/(gain) on mark-to-market derivative contracts


6,122







6,122



21,002







21,002Other


16







16



(5
)






(5
)Income before income taxes


9,794



4,365



14,159



3,894



(3
)


3,891Deferred income tax expense


21



327



348



42



665



707Net income

$
9,773


$
4,038


$
13,811


$
3,852


$
(668
)

$
3,184     a)
    Previously reported allocated interest expense from parent has
    been adjusted to reflect an additional allocation of interest
    expense of $1.5 million.  F-34




---



##### Table of Contents



TARGA
    RESOURCES PARTNERS LP
  NOTES TO
    CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
  For the Three Months Ending


For the Nine Months EndingSeptember 30, 2007


September 30, 2007Targa








TargaSAOU/LOU


North Texas


Resources


SAOU/LOU


North Texas


ResourcesSystem


System


Partners LP


System


System


Partners LP(in thousands)Revenues from third parties

$
142,036


$
6,951


$
148,987


$
446,991


$
17,335


$
464,326Revenues from affiliates


155,339



100,712



256,051



432,784



290,324



723,108Total operating revenues


297,375



107,663



405,038



879,775



307,659



1,187,434Costs and expenses:Product purchases from third parties


225,035



74,457



299,492



651,903



212,208



864,111Product purchases from affiliates


38,042



228



38,270



139,108



742



139,850Operating expenses


6,193



6,543



12,736



18,107



18,576



36,683Depreciation and amortization expense


3,588



14,396



17,984



10,761



42,880



53,641General and administrative expense


3,795



2,779



6,574



8,250



6,310



14,560Loss (gain) on sale of assets


17







17



(298
)






(298
)276,670



98,403



375,073



827,831



280,716



1,108,547Income from operations


20,705



9,260



29,965



51,944



26,943



78,887Other expense:Interest expense allocated from Parent


2,806







2,806



9,154



9,827



18,981Interest expense, net






5,059



5,059







12,918



12,918Loss/(gain) on mark-to-market derivative contracts


7,367







7,367



28,369







28,369Other


(12
)






(12
)


(17
)






(17
)Income before income taxes


10,544



4,201



14,745



14,438



4,198



18,636Deferred income tax expense


21



332



353



63



997



1,060Net income

$
10,523


$
3,869


$
14,392


$
14,375


$
3,201


$
17,576   F-35




---



##### Table of Contents



TARGA
    RESOURCES PARTNERS LP
  NOTES TO
    CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
  For the Three Months Ending March 31, 2006TargaSAOU/LOU


North Texas


ResourcesSystem


System


Partners LP(in thousands)Revenues from third parties

$
353,613


$
1,857


$
355,470Revenues from affiliates


73,995



94,393



168,388Total operating revenues


427,608



96,250



523,858Costs and expenses:Product purchases from third parties


283,059



67,694



350,753Product purchases from affiliates


117,567



172



117,739Operating expenses


5,826



5,944



11,770Depreciation and amortization expense


3,364



13,720



17,084General and administrative expense


135



1,588



1,723409,951



89,118



499,069Income from operations


17,657



7,132



24,789Other expense:Interest expense allocated from Parent


3,637



17,361



20,998Loss/(gain) on mark-to-market derivative contracts


(11,134
)






(11,134
)Income before income taxes


25,154



(10,229
)


14,925Deferred income tax expense










Net income

$
25,154


$
(10,229
)

$
14,925   F-36




---



##### Table of Contents



TARGA
    RESOURCES PARTNERS LP
  NOTES TO
    CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
  For the Three Months Ending


For the Six Months EndingJune 30, 2006


June 30, 2006Targa








TargaSAOU/LOU


North Texas


Resources


SAOU/LOU


North Texas


ResourcesSystem


System


Partners LP


System


System


Partners LP(in thousands)Revenues from third parties

$
254,594


$
2,871


$
257,465


$
608,207


$
4,728


$
612,935Revenues from affiliates


106,453



89,803



196,256



180,448



184,196



364,644Total operating revenues


361,047



92,674



453,721



788,655



188,924



977,579Costs and expenses:Product purchases from third parties


236,869



64,657



301,526



519,928



132,350



652,278Product purchases from affiliates


96,223



227



96,450



213,790



400



214,190Operating expenses


6,455



5,599



12,054



12,281



11,543



23,824Depreciation and amortization expense


3,365



13,719



17,084



6,729



27,439



34,168General and administrative expense


1,957



1,667



3,624



2,092



3,255



5,347344,869



85,869



430,738



754,820



174,987



929,807Income from operations


16,178



6,805



22,983



33,835



13,937



47,772Other expense:Interest expense allocated from Parent


3,779



18,302



22,081



7,416



35,663



43,079Loss/(gain) on mark-to-market derivative contracts


2,735







2,735



(8,399
)






(8,399
)Income before income taxes


9,664



(11,497
)


(1,833
)


34,818



(21,726
)


13,092Deferred income tax expense


394



1,454



1,848



394



1,454



1,848Net income

$
9,270


$
(12,951
)

$
(3,681
)

$
34,424


$
(23,180
)

$
11,244   F-37




---



##### Table of Contents



TARGA
    RESOURCES PARTNERS LP
  NOTES TO
    CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
  For the Nine Months EndingFor the Three Months Ending September 30, 2006


September 30, 2006Targa








TargaSAOU/LOU


North Texas


Resources


SAOU/LOU


North Texas


ResourcesSystem


System


Partners LP


System


System


Partners LP(in thousands)Revenues from third parties

$
171,241


$
3,505


$
174,746


$
779,448


$
8,233


$
787,681Revenues from affiliates


128,060



98,461



226,521



308,508



282,657



591,165Total operating revenues


299,301



101,966



401,267



1,087,956



290,890



1,378,846Costs and expenses:Product purchases from third parties


212,981



72,182



285,163



732,909



204,532



937,441Product purchases from affiliates


59,263



270



59,533



273,053



670



273,723Operating expenses


5,857



6,362



12,219



18,138



17,905



36,043Depreciation and amortization expense


3,397



14,274



17,671



10,126



41,713



51,839General and administrative expense


1,930



1,882



3,812



4,022



5,137



9,159283,428



94,970



378,398



1,038,248



269,957



1,308,205Income from operations


15,873



6,996



22,869



49,708



20,933



70,641Other expense:Interest expense allocated from Parent


3,761



18,706



22,467



11,177



54,369



65,546Loss/(gain) on mark-to-market derivative contracts


(8,373
)






(8,373
)


(16,771
)






(16,771
)Income before income taxes


20,485



(11,710
)


8,775



55,302



(33,436
)


21,866Deferred income tax expense






534



534



394



1,988



2,382Net income

$
20,485


$
(12,244
)

$
8,241


$
54,908


$
(35,424
)

$
19,484   Note 16 
    Subsequent
    Event   F-38




---



##### Table of Contents



Index to
    Exhibits
  2
.1**



Purchase and Sale Agreement, dated as of September 18,
    2007, by and between Targa Resources Holdings LP and Targa
    Resources Partners 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)).2
.2



Amendment to Purchase and Sale Agreement, dated October 1,
    2007, by and between Targa Resources Holdings LP and Targa
    Resources Partners LP (incorporated by reference to
    Exhibit 2.2 to Targa Resources Partners LPs Current
    Report on
    Form 8-K
    filed October 24, 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/A
    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/A
    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/A
    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)).10
.1



Credit Agreement, dated February 14, 2007, by and among
    Targa Resources Partners LP, as Borrower, Bank of America, N.A.,
    as Administrative Agent, Wachovia Bank, N.A., as Syndication
    Agent, Merrill Lynch Capital, Royal Bank of Canada and The Royal
    Bank of Scotland PLC, as Co-Documentation Agents, and the other
    lenders party thereto (incorporated by reference to
    Exhibit 10.1 to Targa Resources Partners LPs Current
    Report on
    Form 8-K
    filed February 16, 2007 (File
    No. 001-33303)).10
.2



Commitment Increase Supplement, dated October 24, 2007, by
    and among Targa Resources Partners LP, Bank of America, N.A. and
    the parties signatory thereto as the Increasing Lenders and the
    New Lenders (incorporate by reference to Exhibit 10.2 to
    Targa Resources Partners LPs Current Report on
    Form 8-K
    filed October 24, 2007 (File
    No. 001-33303)).10
.3



First Amendment to Credit Agreement, dated October 24,
    2007, by and among Targa Resources Partners LP, Bank of America,
    N.A. and each Lender party thereto (incorporated by reference to
    Exhibit 10.3 to Targa Resources Partners LPs Current
    Report on
    Form 8-K
    filed October 24, 2007 (File
    No. 001-33303)).10
.4



Contribution, Conveyance and Assumption Agreement, dated
    February 14, 2007, by and among Targa Resources Partners
    LP, Targa Resources Operating LP, Targa Resources GP LLC, Targa
    Resources Operating GP LLC, Targa GP Inc., Targa LP Inc., Targa
    Regulated Holdings LLC, Targa North Texas GP LLC and Targa North
    Texas LP (incorporated by reference to Exhibit 10.2 to
    Targa Resources Partners LPs Current Report on
    Form 8-K
    filed February 16, 2007
    (File No. 001-33303)).10
.5



Contribution, Conveyance and Assumption Agreement, dated
    October 24, 2007, by and among Targa Resources Partners LP,
    Targa Resources Holdings LP, Targa TX LLC, Targa TX PS LP, Targa
    LA LLC, Targa LA PS LP and Targa North Texas GP LLC
    (incorporated by reference to Exhibit 10.4 to Targa
    Resources Partners LPs Current Report on
    Form 8-K
    filed October 24, 2007 (File
    No. 001-33303)).10
.6



Amended and Restated Omnibus Agreement, dated October 24,
    2007, by and among Targa Resources Partners LP, Targa Resources,
    Inc., Targa Resources LLC and Targa Resources GP LLC
    (incorporated by reference to Exhibit 10.5 to Targa
    Resources Partners LPs Current Report on
    Form 8-K
    filed October 24, 2007 (File
    No. 001-33303)).10
.7+



Targa Resources Partners Long-Term Incentive Plan (incorporated
    by reference to Exhibit 10.2 to Targa Resources Partners
    LPs Registration Statement on
    Form S-1/A
    filed February 1, 2007
    (File No. 333-138747)).




---



##### Table of Contents



10
.8+



Targa Resources Investments Inc. Long-Term Incentive Plan
    (incorporated by reference to Exhibit 10.9 to Targa
    Resources Partners LPs Registration Statement on
    Form S-1/A
    filed February 1, 2007 (File
    No. 333-138747)).10
.9+



Form of Restricted Unit Grant Agreement (incorporated by
    reference to Exhibit 10.2 to Targa Resources Partners
    LPs Current Report on
    Form 8-K
    filed February 13, 2007 (File
    No. 001-33303)).10
.10+



Form of Performance Unit Grant Agreement (incorporated by
    reference to Exhibit 10.2 to Targa Resources Partners
    LPs Current Report on
    Form 8-K
    filed January 22, 2008 (File
    No. 001-33303)).10
.11



Gas Gathering and Purchase Agreement by and between Burlington
    Resources Oil & Gas Company LP, Burlington Resources
    Trading Inc. and Targa Midstream Services Limited Partnership
    (portions of this exhibit have been omitted and filed separately
    with the Securities and Exchange Commission pursuant to a
    request for confidential treatment) (incorporated by reference
    to Exhibit 10.5 to Targa Resources Partners LPs
    Registration Statement on
    Form S-1/A
    filed February 8, 2007 (File
    No. 333-138747)).10
.12



Natural Gas Purchase Agreement, effective January 1, 2007,
    by and between Targa Gas Marketing LLC (Buyer) and Targa North
    Texas LP (Seller) (incorporated by reference to
    Exhibit 10.11 to Targa Resources Partners LPs
    Registration Statement on
    Form S-1
    filed October 1, 2007
    (File No. 333-146436)).10
.13



NGL and Condensate Purchase Agreement, effective January 1,
    2007, by and between Targa North Texas LP (Seller) and Targa
    Liquids Marketing and Trade (Buyer) (incorporated by reference
    to Exhibit 10.12 to Targa Resources Partners LPs
    Registration Statement on
    Form S-1
    filed October 1, 2007 (File
    No. 333-146436)).10
.14



Product Purchase Agreement, effective January 1, 2007, by
    and between Targa Louisiana Field Services LLC (Seller) and
    Targa Liquids Marketing and Trade (Buyer) (incorporated by
    reference to Exhibit 10.13 to Targa Resources Partners
    LPs Registration Statement on
    Form S-1/A
    filed October 12, 2007 (File
    No. 333-146436)).10
.15



Raw Product Purchase Agreement, effective January 1, 2007,
    by and between Targa Texas Field Services LP (Seller) and Targa
    Liquids Marketing and Trade (Buyer) (incorporated by reference
    to Exhibit 10.14 to Targa Resources Partners LPs
    Registration Statement on
    Form S-1/A
    filed October 12, 2007 (File
    No. 333-146436)).10
.16



Amended and Restated Natural Gas Sales Agreement, effective
    December 1, 2005, by and between Targa Louisiana Field
    Services LLC (Buyer) and Targa Gas Marketing LLC (Seller)
    (incorporated by reference to Exhibit 10.15 to Targa
    Resources Partners LPs Registration Statement on
    Form S-1/A
    filed October 12, 2007 (File
    No. 333-146436)).10
.17



Amended and Restated Natural Gas Purchase Agreement, effective
    December 1, 2005, by and between Targa Gas Marketing LLC
    (Buyer) and Targa Louisiana Field Services LLC (Seller)
    (incorporated by reference to Exhibit 10.16 to Targa
    Resources Partners LPs Registration Statement on
    Form S-1/A
    filed October 12, 2007 (File
    No. 333-146436)).10
.18



Amended and Restated Natural Gas Purchase Agreement, effective
    December 1, 2005, by and between Targa Gas Marketing LLC
    (Buyer) and Targa Texas Field Services LP (Seller) (incorporated
    by reference to Exhibit 10.17 to Targa Resources Partners
    LPs Registration Statement on
    Form S-1/A
    filed October 12, 2007 (File
    No. 333-146436)).10
.19+



Targa Resources Partners LP Indemnification Agreement for Barry
    R. Pearl dated February 14, 2007 (incorporated by reference
    to Exhibit 10.11 to Targa Resources Partners LPs
    Annual Report on
    Form 10-K
    filed April 2, 2007 (File
    No. 001-33303)).10
.20+



Targa Resources Partners LP Indemnification Agreement for Robert
    B. Evans dated February 14, 2007 (incorporated by reference
    to Exhibit 10.12 to Targa Resources Partners LPs
    Annual Report on
    Form 10-K
    filed April 2, 2007 (File
    No. 001-33303)).10
.21+



Targa Resources Partners LP Indemnification Agreement for
    Williams D. Sullivan dated February 14, 2007 (incorporated
    by reference to Exhibit 10.13 to Targa Resources Partners
    LPs Annual Report on
    Form 10-K
    filed April 2, 2007 (File
    No. 001-33303)).21
.1



Subsidiaries of Targa Resources Partners LP.*23
.1



Consent of Independent Registered Public Accounting Firm*31
.1



Certification of the Chief Executive Officer pursuant to
    Rule 13a-14(a)/15d-14(a)
    of the Securities Exchange Act of 1934.*




---



##### Table of Contents



31
.2



Certification of the Chief Financial Officer pursuant to
    Rule 13a-14(a)/15d-14(a)
    of the Securities Exchange Act of 1934.*32
.1



Certification of the 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 the Chief Financial Officer pursuant to
    18 U.S.C. Section 1350, as adopted pursuant to
    Section 906 of the Sarbanes-Oxley Act of 2002.*     *
    
    Filed herewith**
    
    Pursuant to Item 601(b)(2) of
    Regulation S-K,
    the Partnership agrees to furnish supplementally a copy of any
    omitted exhibit or Schedule to the SEC upon request.+
    
    Management contract or compensatory plan or arrangement.