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UNITED STATES SECURITIES AND
    EXCHANGE COMMISSION
 Washington, 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, 2006oro

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
  o þ
  Regulation S-K Form 10-K Form 10-K. þ
  Rule 12b-2
  o o þ
  Rule 12b-2 o þ
      DOCUMENTS INCORPORATED BY REFERENCE




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TABLE OF
    CONTENTS
  DESCRIPTION
  PART I1.

BUSINESS


41A.

RISK
    FACTORS


201B.

UNRESOLVED STAFF
    COMMENTS


372.

PROPERTIES


373.

LEGAL
    PROCEEDINGS


374.

SUBMISSION OF
    MATTERS TO A VOTE OF SECURITY HOLDERS


37PART II5.

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


386.

SELECTED FINANCIAL
    DATA


407.

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


437A.

QUANTITATIVE AND
    QUALITATIVE DISCLOSURES ABOUT MARKET RISK


648.

FINANCIAL
    STATEMENTS AND SUPPLEMENTARY DATA


679.

CHANGES IN AND
    DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
    DISCLOSURE


679A

CONTROLS AND
    PROCEDURES


679B

OTHER
    INFORMATION


67PART III10.

DIRECTORS,
    EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE


6711.

EXECUTIVE
    COMPENSATION


7112.

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


7613.

CERTAIN
    RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
    INDEPENDENCE


7814.

PRINCIPAL
    ACCOUNTANT FEES AND SERVICES


82PART IV15.

EXHIBITS AND
    FINANCIAL STATEMENT SCHEDULES


83Agreement of Limited PartnershipSpecimen Unit CertificateIndemnification Agreement - PearlIndemnification Agreement - EvansIndemnification Agreement - SullivanCertification of CEO Pursuant to Rule 13a-14(a)Certification of CFO Pursuant to Rule 13a-14(a)Certification of CEO Pursuant to Section 1350Certification of CFO Pursuant to Section 1350   2




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TARGA
    RESOURCES PARTNERS LPPART 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 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 increased
    regulation of the gathering and processing industry;
    the timing and extent of changes in 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 required approvals for construction or
    modernization of gathering and processing facilities, and the
    timing of production from such facilities, which are dependent
    on the issuance by federal, state and municipal governments, or
    agencies thereof, of building, environmental and other permits,
    the availability of specialized contractors and work force and
    prices of and demand for products;
    our ability to grow through acquisitions or internal growth
    projects;
    the extent of success in connecting natural gas supplies to
    gathering and processing systems; and
    general economic, market and business conditions.   3




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Form 10-K,
  BBtu

Billion British thermal unitsBtu

British thermal unit, a measure of
    heating value/d

Per dayBbl

BarrelMBbl

Thousand barrelsMcf

Thousand cubic feetMMBtu

Million British thermal unitsMMcf

Million cubic feet   Price Index DefinitionsIF-NGPL MC

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

Inside FERC Gas Market Report,
    West Texas WahaMB-OPIS

Oil Price Information Service,
    Mont Belvieu, TexasNY-WTI

NYMEX, West Texas Intermediate
    Crude Oil   Item 1.
    Business  Initial
    Public Offering
  On February 14, 2007, Targa Resources Partners LP,
    together with its subsidiaries (we, us,
    our or the Partnership)  completed its
    initial public offering, or IPO, of common units representing
    limited partner interests in the Partnership. In the IPO, we
    issued 19,320,000 common units at a price of $21.00 per
    unit. We used the net proceeds of the IPO (including 2,520,000
    common units sold pursuant to the full exercise by the
    underwriters of their option to purchase additional common
    units) to pay expenses related to the IPO and our new credit
    facility and to repay approximately $371.2 million of our
    outstanding allocated indebtedness. Upon completion of the IPO,
    we had 19,320,000 common units, 11,528,231 subordinated units,
    and 629,555 general partner units outstanding. The subordinated
    units and general partner units are indirectly owned by Targa
    Resources, Inc., or Targa. Our common units are
    listed on The NASDAQ Stock Market LLC under the symbol
    NGLS. This filing reflects the historical financial
    information of the North Texas System (defined below) which was
    contributed to us by Targa in connection with the IPO.
  General
     4




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
    the Chico system, located in the northeast part of the
    Fort Worth Basin, which consists of:  
    approximately 1,875 miles of natural gas gathering
    pipelines with approximately 1,830 active connections to
    producing wells and central delivery points;
    a cryogenic natural gas processing plant with throughput
    capacity of approximately 215 MMcf/d that can be increased
    by another 50 MMcf/d as may be required to meet production
    needs through the installation of an additional refrigeration
    compressor unit that is on site (for the years ended
    December 31, 2006 and 2005, the average daily plant inlet
    volume was 149.7 MMcf/d and 145.0 MMcf/d,
    respectively); and
    an 11,500 Bbl/d fractionator located at the processing
    plant that enables us, based on market conditions, to either
    fractionate a portion of our raw NGL mix into separate NGL
    products for sale into local and other markets or deliver raw
    NGL mix to Mont Belvieu for fractionation primarily through
    Chevrons WTLPG Pipeline;  
    the Shackelford system, located on the western side of the
    Fort Worth Basin, which consists of:  
    approximately 2,090 miles of natural gas gathering
    pipelines with approximately 820 active connections to producing
    wells and central delivery points; and
    a cryogenic natural gas processing plant with throughput
    capacity of approximately 13 MMcf/d (for the years ended
    December 31, 2006 and 2005, the average daily plant inlet
    volume was 12.1 MMcf/d and 12.2 MMcf/d,
    respectively); and  
    a 32-mile,
    10-inch
    diameter natural gas pipeline connecting the Shackelford and
    Chico systems, which we refer to as the Interconnect
    Pipeline, that is used primarily to send natural gas
    gathered in excess of the Shackelford systems processing
    capacity to the Chico plant.  Strategies
    
    Increasing the profitability of our existing
    assets.  We are currently evaluating opportunities
    to increase the profitability of our existing operations by
    connecting and processing new supplies of natural gas, improving
    operating efficiencies and increasing processing yields, adding
    processing capacity, increasing throughput at our Chico
    fractionator, increasing volumes of low pressure gas to be
    gathered and processed, continuing electronic flow measurement
    conversion of our meters, decontaminating condensate and
    shipping pipeline quality condensate to Mont Belvieu.
    Managing our contract mix to optimize
    profitability.  The majority of our operating
    margin is generated pursuant to
    percent-of-proceeds
    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 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.
    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 tailored our hedges to
    match our actual NGL product composition and to approximate our
    actual NGL and natural gas delivery points. We intend to
    continue to manage our exposure to commodity prices in the
    future by entering into hedge transactions, as market conditions
    permit. 5




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
    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
    leverage our existing market position and leverage our core
    competitiveness in the midstream energy industry.
    Focusing on producing regions with attractive
    characteristics.  We seek to focus on regions
    (1) where treating or processing is required to access
    end-markets; (2) where permitting, drilling and workover
    activity is high; (3) with the potential for long-term
    acreage dedications; (4) with a strong base of current
    production and the potential for significant future development
    and (5) 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 seek
    acquisition opportunities in our existing areas of operation
    with the opportunity for operational efficiencies and the
    potential for higher capacity utilization and expansion of those
    assets, as well as acquisitions in other related lines of our
    midstream business and new geographic areas of operation.
    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 the 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 a broader array of growth
    opportunities than those available to many of our competitors.  Strengths
    
    Affiliation with Targa.  We expect that our
    relationship with Targa will provide us with significant
    business opportunities. 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.
    Strategically located assets.  The Barnett
    Shale region of the Fort Worth Basin is one of the most
    productive natural gas-producing regions in North America and
    has generally long-lived, predictable reserves. The other
    Fort Worth Basin formations are well-established, mature
    plays that exhibit lower decline rates than those of the Barnett
    Shale. Current high levels of natural gas exploration,
    development and production activities within both Barnett and
    non-Barnett areas of our operations present significant organic
    growth opportunities to generate additional throughput on our
    system.
    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.
    Low maintenance capital expenditures.  Our
    maintenance capital expenditures have averaged approximately
    $12 million over the three years ended December 31,
    2006. We believe that this 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 a majority
    of our expected natural gas, NGL and condensate equity volumes
    for the years 2007 through 2010. This strategy minimizes
    commodity price risk related to these arrangements. For
    additional information regarding our hedging activities, please
    see Item 7A  Quantitative and Qualitative
    Disclosures about Market Risk. 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 for existing and expected
    equity production as market conditions permit. 6




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
    Strong producer customer base.  We have a
    strong producer customer base consisting of both major oil and
    gas companies and independent producers and believe we have a
    reputation as a reliable operator. 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 27 years of experience in the energy industry
    that owns a 10.2% 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 23 years of midstream
    operating experience. Our relationship with Targa provides us
    with access to significant operational, commercial, technical,
    risk management and other expertise.  Our
    Relationship with Targa Resources, Inc.
       7




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Midstream
    Sector Overview
  General.
  
  Gathering.
  Compression.
 8




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Treating and Dehydration.
  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.
    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 NGLs.
    Keep-Whole.  A keep-whole arrangement allows
    the processor to keep 100% of the NGLs 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 NGLs. As a result, a processor with these types of contracts
    benefits when the value of the NGLs 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 NGLs. 9




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
    Fee-Based.  Under a fee-based contract, the
    processor receives a fee per gallon of NGLs produced or per Mcf
    of natural gas processed. Under this arrangement, a processor
    would have no commodity price risk exposure.  Fractionation.
  
    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 content 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.
  Natural Gas Demand and Production.
  Our
    System
  Gathering
    Systems
   10




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32-mile, 10-inch
  Chico Gathering System.
  Shackelford Gathering System.
  Processing
    Plants
  Chico Processing Plant. state-of-the-art
    2
  Shackelford Processing Plant.
 11




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Market
    Access
  Chico System Market Access.
      
    Natural Gas Pipeline Company of America which is owned by Kinder
    Morgan, Inc. and serves the Midwest, specifically the Chicago
    market;
    ET Fuel System which is owned by Energy Transfer Partners, L.P.
    and has access to the Waha, Carthage and Katy hubs in Texas; 12




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
    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.  Shackelford System Market Access.
  Targa Intrastate Pipeline. 41-mile, 6-inch 10-inch
  Customers
    and Contracts
    percent-of-proceeds
    percent-of-proceeds 90-60% 65-50% 95-60%
  percent-of-proceeds
 13




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percent-of-proceeds percent-of-proceeds
  Competition
      Safety
    and Maintenance Regulation
         14




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right-to-know
  Regulation
    of Operations
    Gathering
    Pipeline Regulation
       15




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cost-of-service and/or
  Intrastate
    Pipeline Regulation
  41-mile, 6-inch 10-inch
  Sales
    of Natural Gas and NGLs
    Environmental
    Matters
  General
   16




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
    requiring the installation of pollution control equipment or
    otherwise restricting the way we can handle or dispose of our
    wastes;
    limiting or prohibiting construction activities in sensitive
    areas such as wetlands, coastal regions or areas inhabited by
    endangered species;
    requiring remedial action to mitigate pollution conditions
    caused by our operations or attributable to former
    operations; and
    enjoining the operations of facilities deemed in non-compliance
    with permits issued pursuant to such environmental laws and
    regulations.          Air
    Emissions
   17




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Hazardous
    Substances and Waste
     18




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Water
    Title to
    Properties and
    Rights-of-Way
  rights-of-way, right-of-way, right-of-way, rights-of-way,
  rights-of-way,
   19




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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. You should
    consider carefully the following risk factors together with all
    of the other information included in this report. If any of the
    following risks were actually to occur, then our business,
    financial condition or results of operations could be materially
    adversely affected.
  Risks
    Related to Our Business
  We may
    not have sufficient cash from operations following the
    establishment of cash reserves and payment of fees and expenses,
    including cost reimbursements to our general partner, to enable
    us to make cash distributions to holders of our common units and
    subordinated units at the initial distribution rate under our
    cash distribution policy.
    
    the fees we charge and the margins we realize for our services;
    the prices of, levels of production of, and demand for, natural
    gas and NGLs
    the volume of natural gas we gather, treat, compress, process,
    transport and sell, and the volume of NGLs we process or
    fractionate and sell;
    the relationship between natural gas and NGL prices;
    cash settlements of hedging positions;
    the level of competition from other midstream energy companies; 20




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
    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 will
    incur as a result of being a public company;
    restrictions on distributions contained in our debt agreements;
    and
    the amount of cash reserves established by our general partner
    for the proper conduct of our business.  Our
    cash flow is affected by natural gas and NGL prices, and
    decreases in these prices could adversely affect our ability to
    make distributions to holders of our common units and
    subordinated units.
        
    the impact of seasonality and weather;
    general economic conditions;
    the level of domestic crude oil and natural gas production and
    consumption;
    the availability of imported natural gas, liquified natural gas,
    NGLs and crude oil;
    actions taken by foreign oil and gas producing nations;
    the availability of local, intrastate and interstate
    transportation systems;
    the availability and marketing of competitive fuels;
    the impact of energy conservation efforts; and
    the extent of governmental regulation and taxation.  percent-of-proceeds percent-of-proceeds percent-of-proceeds
 21




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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, which depends on certain
    factors beyond our control. Any decrease in supplies of natural
    gas could adversely affect our business and operating
    results.
        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. In addition, the
    significant contribution to our results of operations that we
    are currently receiving from our hedge positions will decrease
    substantially through 2010.
   22




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We
    depend on one natural gas producer for a significant portion of
    our supply of natural gas. The loss of this customer or
    replacement of its contracts on less favorable terms could
    result in a decline in our volumes, revenues and cash available
    for distribution.
    If
    third-party pipelines and other facilities interconnected to our
    natural gas pipelines and facilities become partially or fully
    unavailable to transport natural gas and NGLs, our revenues and
    cash available for distribution could be adversely
    affected.
    We
    depend on our Chico system for a substantial majority 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.
    
    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 the Chico
    processing plant or gathering lines, labor difficulties or
    environmental proceedings or other litigation that compel
    cessation of all or a portion of the operations on our Chico
    system;
    an inability to obtain sufficient quantities of natural gas for
    the Chico system at competitive terms; or
    reductions in exploration or production activity, or shut-ins by
    producers in the areas in which we operate.   23




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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
    industry is highly competitive, and increased competitive
    pressure could adversely affect our business and 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
 24




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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;
    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 credit facility may interrupt distributions to us from
    our subsidiaries, which may limit our ability to make
    distributions to you, satisfy our obligations and capitalize on
    business opportunities.
    We may
    incur significant costs and liabilities in the future resulting
    from a failure to comply with new or existing environmental
    regulations or an accidental release of hazardous substances or
    hydrocarbons into the environment.
   25




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We
    typically do not obtain independent evaluations of natural gas
    reserves dedicated to our gathering pipeline systems; therefore,
    volumes of natural gas on our systems in the future could be
    less than we anticipate.
    A
    change in the jurisdictional characterization of some of our
    assets by federal, state or local regulatory agencies or a
    change in policy by those agencies may result in increased
    regulation of our assets, which may cause our revenues to
    decline and operating expenses to increase.
   26




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Our
    costs may increase because our credit obligations under hedging
    and other contractual arrangements are not guaranteed by
    Targa.
    All of
    our operations are based in the Fort Worth Basin and we are
    dependent on drilling activities and our ability to attract and
    maintain customers in such region.
    Under
    the terms of our gas sales agreement, Targa manages the sales of
    our natural gas and pays us the amount it realizes for gas sales
    less certain costs; however, unexpected volume changes due to
    production variability or to gathering, plant, or pipeline
    system disruptions may increase our exposure to commodity price
    movements.
   27




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##### Table of Contents



We may
    incur significant costs and liabilities resulting from pipeline
    integrity programs and related repairs.
    
    perform ongoing assessments of pipeline integrity;
    identify and characterize applicable threats to pipeline
    segments that could impact a high consequence area;
    improve data collection, integration and analysis;
    repair and remediate the pipeline as necessary; and
    implement preventive and mitigating actions.    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.
  rights-of-way rights-of-way rights-of-way rights-of-way. rights-of-way
  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.
   28




---



##### Table of Contents




    mistaken 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;
    mistaken 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 own most of the land on which our pipelines and facilities
    are located, which could disrupt our operations.
  and/or right-of-way
  We do
    not have any officers or employees and rely solely on officers
    of our general partner and employees of Targa.
    If our
    general partner fails to develop or maintain an effective system
    of internal controls, then we may not be able to accurately
    report our financial results or prevent fraud. As a result,
    current and potential unitholders could lose confidence in our
    financial reporting, which would harm our business and the
    trading price of our common units.
   29




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##### Table of Contents



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
  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. 30




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##### Table of Contents



The
    credit and business risk profile of our general partner and its
    owners could adversely affect our credit ratings and
    profile.
      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. 31




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##### Table of Contents



Targa
    is not limited in its ability to compete with us, which could
    limit our ability to acquire additional assets or
    businesses.
    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.
    Even
    if holders of our common units are dissatisfied, they cannot
    initially remove our general partner without its
    consent.
  2 3
 32




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We may
    issue additional units without your approval, which would dilute
    your existing ownership interests.
    
    our unitholders proportionate ownership interest in us
    will decrease;
    the amount of cash available for distribution on each unit may
    decrease;
    because a lower percentage of total outstanding units will be
    subordinated units, the risk that a shortfall in the payment of
    the minimum quarterly distribution will be borne by our common
    unitholders will increase;
    the ratio of taxable income to distributions may increase;
    the relative voting strength of each previously outstanding unit
    may be diminished; and
    the market price of 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.
     33




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##### Table of Contents



Increases
    in interest rates could adversely impact our unit price and our
    ability to issue additional equity to make acquisitions, for
    expansion capital expenditures or for other
    purposes.
    We
    will incur increased costs as a result of being a
    publicly-traded company.
    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.
   34




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##### Table of Contents



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
  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.
     35




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##### Table of Contents



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 foreign persons face unique tax issues from owning
    our common units that may result in adverse tax consequences to
    them.
  non-U.S. persons non-U.S. persons non-U.S. persons
 36




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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.
    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.
    You
    may be subject to state and local taxes and return filing
    requirements in states where you do not live as a result of
    investing in our common units.
    Item 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   37




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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
      Distributions
    of Available Cash
  General.
  Definition of Available Cash.
  
    less the amount of cash reserves established by our 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 distribution to our unitholders and to our
    general partner for any one or more of the next four quarters;  
    plus; if our general partner so determines, all or a portion of
    cash on hand on the date of determination of available cash for
    the quarter.  Intent to Distribute the Minimum Quarterly
    Distribution.
 38




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##### Table of Contents



General Partner Interest and Incentive Distribution
    Rights.
    Sales of
    Unregistered Units
    Repurchase
    of Equity by Targa Resources Partners LP
    Use of
    Proceeds
  No. 333-138747) Form S-1,
     39




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##### Table of Contents



Item 6.
    Selected
    Financial Data  SELECTED
    HISTORICAL FINANCIAL AND OPERATING DATA
      Predecessor BusinessTarga North Texas LP



DynegyYear


Two Months



Ten MonthsEnded


Ended



EndedDecember 31,


December 31,



October 31,


Years Ended December 31,2006


2005



2005


2004


2003


2002(Audited)


(Audited)



(Audited)


(Audited)


(Audited)


(Unaudited)(in millions of dollars, except operating and price data)Statement of Operations
    Data:Total operating revenues

$
384.8


$
75.1



$
293.3


$
258.6


$
196.8


$
112.5Product purchases


269.3



54.9




210.8



182.6



147.3



82.7Operating expense, excluding
    DD&A


24.1



3.5




18.0



17.7



15.1



14.9Depreciation and amortization
    expense


56.0



9.2




11.3



12.2



12.0



11.8General and administrative expense


6.9



1.1




7.3



7.2



7.7



7.7Interest expense, net


72.9



11.5
















Deferred income taxes(1)


2.5




















Other, net















0.3



0.6



(0.3
)Net income (loss)

$
(46.9
)

$
(5.1
)


$
45.9


$
38.6


$
14.1


$
(4.3
)Financial and Operating
    Data:Financial data:Operating margin(2)

$
91.4


$
16.7



$
64.5


$
58.3


$
34.4


$
14.9EBITDA(3)

$
84.5


$
15.6



$
57.2


$
50.8


$
26.1


$
7.5Operating data:Gathering throughput, MMcf/d(4)


168.3



168.8




161.2



152.0



134.3



106.6Plant natural gas inlet, MMcf/d(5)


161.8



161.9




156.2



145.4



128.6



104.0Gross NGL production, MBbl/d


18.9



19.8




18.5



17.2



15.9



12.5Natural gas sales, BBtu/d


74.9



72.3




68.9



59.2



42.0



38.2NGL sales, MBbl/d


15.2



15.4




14.3



13.2



15.3



12.3Condensate sales, MBbl/d


0.5



0.5




0.5



0.7



0.6



0.6Average Realized
    Prices:(6)Natural gas, $/MMBtu

$
6.09


$
8.61



$
6.79


$
5.43


$
4.97


$
2.84NGL, $/gal


0.88



0.90




0.78



0.64



0.47



0.35Condensate, $/Bbl


65.31



57.54




53.42



40.56



29.86



23.24Balance Sheet Data (at period
    end):Property, plant and equipment, net

$
1,064.1


$
1,097.0



$
196.4


$
191.2


$
180.4


$
178.2Total assets


1,115.8



1,122.8




198.5



193.5



182.9



179.7Long-term debt (including current
    portion)


864.0



868.9
















Partners capital /Net parent
    equity


215.7



219.5




158.5



168.8



164.8



167.3Cash Flow Data:Net cash provided by (used in):Operating activities

$
16.2


$
(1.5
)


$
72.7


$
58.0


$
31.3


$
10.2Investing activities


(23.1
)


(2.1
)



(16.4
)


(23.4
)


(14.6
)


(30.6
)Financing activities


6.9



3.6




(56.3
)


(34.6
)


(16.7
)


20.4  40




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##### 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.
    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)
    
    EBITDA is net income before interest, income taxes, depreciation
    and amortization. Please see Non-GAAP Financial
    Measures  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
  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.      Operating Margin.
   41




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##### 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.  42




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##### Table of Contents



Predecessor BusinessTarga North Texas LP



DynegyYear


Two Months



Ten Months


Years


Years


YearsEnded


Ended



Ended


Ended


Ended


EndedDecember 31,


December 31,



October 31,


December 31,


December 31,


December 31,2006


2005



2005


2004


2003


2002(in millions)Reconciliation of
    EBITDA to net cash provided by (used in) operating
    activities:Net cash provided by (used in)
    operating activities

$
16.2


$
(1.5
)


$
72.7


$
58.0


$
31.3


$
10.2Allocated interest expense from
    parent(1)


67.8



10.7












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


(0.2
)


0.1




0.3



(0.7
)


0.7



0.3Accounts payable


(0.6
)


0.8




1.3



(2.7
)


(1.0
)


0.6Other, including changes in
    noncurrent assets and liabilities


1.3



5.5




(17.1
)


(3.8
)


(4.9
)


(3.6
)EBITDA

$
84.5


$
15.6



$
57.2


$
50.8


$
26.1


$
7.5Reconciliation of
    EBITDA to net income:Net income (loss)

$
(46.9
)

$
(5.1
)


$
45.9


$
38.6


$
14.1


$
(4.3
)Add:Interest expense, net


72.9



11.5
















Deferred tax expense


2.5




















Depreciation and amortization
    expense


56.0



9.2




11.3



12.2



12.0



11.8EBITDA

$
84.5


$
15.6



$
57.2


$
50.8


$
26.1


$
7.5Reconciliation of
    operating margin to net income:Net income (loss)

$
(46.9
)

$
(5.1
)


$
45.9


$
38.6


$
14.1


$
(4.3
)Add:Depreciation and amortization
    expense


56.0



9.2




11.3



12.2



12.0



11.8Deferred income tax


2.5




















Other, net















0.3



0.6



(0.3
)Interest expense, net


72.9



11.5
















General and administrative expense


6.9



1.1




7.3



7.2



7.7



7.7Operating margin

$
91.4


$
16.7



$
64.5


$
58.3


$
34.4


$
14.9     (1)
    
    Excludes non-cash amortization of debt issue costs of
    $5.1 million for the year ended December 31, 2006 and
    $0.8 million for the two months ended December 31, 2005  Item 7.
    Managements
    Discussion and Analysis of Financial Condition and Results of
    Operations  On February 14, 2007, we completed our initial public
    offering, or IPO, of common units. In the IPO, we issued
    19,320,000 common units (including 2,520,000 common units sold
    pursuant to the full exercise by the underwriters of their
    option to purchase additional common units) representing limited
    partner interests at a price of $21.00 per unit. We used
    the net proceeds of the IPO to pay expenses related to the IPO
    and our credit facility and to repay approximately
    $371.2 million of our outstanding affiliate indebtedness.
    Upon completion of the IPO, we had 19,320,000 common units,
    11,528,231 subordinated units, and 629,555 general
 43




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##### Table of Contents



The historical financial statements included in this item
    reflect the results of operations of the North Texas System
    contributed to us by Targa at the time of the IPO. We refer to
    the results of operations of the North Texas System as the
    results of operations of the Predecessor Business. The
    Predecessor Business was acquired by Targa as part of the DMS
    Acquisition.
  The following discussion analyzes the financial condition and
    results of operations of the Predecessor Business. In the
    discussion, the year ended December 31, 2005 is generally
    presented and evaluated on a combined basis, combining the
    results of operations reflected in the audited historical
    financial statements of the Predecessor Business for the
    10-months
    prior to the DMS Acquisition (the Pre-Acquisition
    Financial Statements) and the results of operations
    reflected in the audited historical financial statements of the
    Predecessor Business for the two-months after the DMS
    Acquisition (the Post-Acquisition Financial
    Statements). In certain circumstances, our discussion
    identifies distinctions in operating and financial results for
    the Predecessor Business associated with the change of ownership
    resulting from the DMS Acquisition. You should read the
    following discussion of the financial condition and results of
    operations for the Predecessor Business in conjunction with the
    historical combined financial statements and notes of the
    Predecessor included under Item 8 of this report.
  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). In certain circumstances and for ease of reading we
    discuss the financial results of the Predecessor Business as
    being our financial results during historic periods
    when this business was owned by Dynegy or Targa,
    respectively.
  Overview
    Factors
    That Significantly Affect Our Results
    percent-of-proceeds
   44




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##### Table of Contents



Affiliate Indebtedness and
    Borrowings.
    Impact of Our 2006 Hedging Activities. 90-60% 65-50% 95-60%
  General and Administrative Expenses.
 45




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##### Table of Contents



Schedule K-1
  Working Capital Adjustments.
  Distributions to our Unitholders.
  General
    Trends and Outlook
    Natural Gas Supply and Outlook.
  Commodity Prices. percent-of-proceeds $7.11
 46




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##### Table of Contents



percent-of-proceeds
  Rising Operating Costs.
  Our
    Operations
  percent-of-proceeds percent-of-proceeds
      How We
    Evaluate Our Operations
     47




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##### Table of Contents



Throughput Volumes, Facility Efficiencies and Fuel
    Consumption.
    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. 48




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##### Table of Contents



Operating Expenses.
  EBITDA.
  
    the financial performance of our assets without regard to
    financing methods, capital structure or historical cost basis;
    our operating performance and return on capital as compared to
    other companies in the midstream energy sector, without regard
    to financing or capital structure; and
    the viability of acquisitions and capital expenditure projects
    and the overall rates of return on alternative investment
    opportunities.        49




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##### Table of Contents



Predecessor BusinessTarga North Texas LP



Combined



DynegyYear


Two Months



Year



Ten Months


YearsEnded


Ended



Ended



Ended


EndedDecember 31,


December 31,



December 31,



October 31,


December 31,2006


2005



2005



2005


2004(in millions)Reconciliation of
    EBITDA to net cash provided by (used in) operating
    activities:Net cash provided by (used in)
    operating activities

$
16.2


$
(1.5
)


$
71.2



$
72.7


$
58.0Allocated interest expense from
    parent(1)


67.8



10.7




10.7








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


(0.2
)


0.1




0.4




0.3



(0.7
)Accounts payable


(0.6
)


0.8




2.1




1.3



(2.7
)Other, including changes in
    noncurrent assets and liabilities


1.3



5.5




(11.6
)



(17.1
)


(3.8
)EBITDA

$
84.5


$
15.6



$
72.8



$
57.2


$
50.8Reconciliation of
    EBITDA to net income:Net income (loss)

$
(46.9
)

$
(5.1
)


$
40.8



$
45.9


$
38.6Add:Interest expense, net


72.9



11.5




11.5








Deferred tax expense


2.5

















Depreciation and amortization
    expense


56.0



9.2




20.5




11.3



12.2EBITDA

$
84.5


$
15.6



$
72.8



$
57.2


$
50.8Reconciliation of
    operating margin to net income:Net income (loss)

$
(46.9
)

$
(5.1
)


$
40.8



$
45.9


$
38.6Add:Depreciation and amortization
    expense


56.0



9.2




20.5




11.3



12.2Deferred income tax


2.5

















Other, net




















0.3Interest expense, net


72.9



11.5




11.5








General and administrative expense


6.9



1.1




8.4




7.3



7.2Operating margin

$
91.4


$
16.7



$
81.2



$
64.5


$
58.3     (1)
    
    Excludes non-cash amortization of debt issue costs of
    $5.1 million for the year ended December 31, 2006 and
    $0.8 million for the two months ended December 31,
    2005.  Distributable Cash Flow. Distributable cash
    flow
 50




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##### Table of Contents



Predecessor BusinessTarga North Texas LP



Combined



DynegyYear


Two Months



Year



Ten Months


YearEnded


Ended



Ended



Ended


EndedDecember 31,


December 31,



December 31,



December 31,


December 31,2006


2005



2005



2005


2004(in millions)Reconciliation of
    distributable cash flow to Net income:Net income (loss)

$
(46.9
)

$
(5.1
)


$
40.8



$
45.9


$
38.6Depreciation and amortization
    expense


56.0



9.2




20.5




11.3



12.2Deferred tax expense


2.5

















Amortization of debt issue costs


5.1



0.8




0.8








Maintenance capital expenditures


(11.7
)


(1.6
)



(12.9
)



(11.3
)


(10.2
)Distributable cash flow(a)

$
5.0


$
3.3



$
49.2



$
45.9


$
40.6     (a)
    
    Distributable cash flow for the year ended December 31,
    2006 and the two months ended December 31, 2005, reflects
    allocated interest from parent of $72.9 million and
    $11.5 million, respectively.  Contract
    Mix
  percent-of-proceeds and/or
 51




---



##### Table of Contents



Percent ofContract Type

Throughput

Impact of Commodity PricesPercent-of-Proceeds


96%


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


4%


Increases in natural gas prices
    relative to NGL prices generate decreases in operating margins.
    Decreases in NGL prices relative to natural gas prices generate
    decreases in operating margins.   percent-of-proceeds
  Critical
    Accounting Policies and Estimates
    Revenue Recognition.
  
    sales of natural gas, NGLs and condensate; and
    natural gas processing, from which we generate revenue through
    the compression, gathering, treating and processing of natural
    gas.    percent-of-proceeds percent-of-proceeds percent-of-proceeds Percent-of-value percent-of-liquids
  No. 99-19, Reporting Revenue Gross as a Principal versus Net as an
    Agent.
 52




---



##### Table of Contents



Use of Estimates.
  Property, Plant, and Equipment.
  Service LifeAsset Group

(Years)Natural 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
    Price Risk Management (Hedging). Accounting for Derivative Instruments and Hedging
    Activities,
 53




---



##### Table of Contents



Estimated Useful Lives.
  Natural Gas Imbalances.
 54




---



##### Table of Contents



Results
    of Operations
    Predecessor BusinessTarga North Texas LP



Combined



DynegyYear


Two Months



Year



Ten Months


YearEnded


Ended



Ended



Ended


EndedDecember 31,


December 31,



December 31,



October 31,


December 31,2006


2005



2005



2005


2004(in millions of dollars, except operating and price data)Total operating revenues

$
384.8


$
75.1



$
368.4



$
293.3


$
258.6Product purchases


269.3



54.9




265.7




210.8



182.6Operating expense, excluding
    DD&A


24.1



3.5




21.5




18.0



17.7Depreciation and amortization
    expense


56.0



9.2




20.5




11.3



12.2General and administrative expense


6.9



1.1




8.4




7.3



7.2Loss on sales of assets




















0.3Income from operations


28.5



6.4




52.3




45.9



38.6Interest expense, net


(72.9
)


(11.5
)



(11.5
)







Deferred income taxes(1)


(2.5
)
















Net income (loss)

$
(46.9
)

$
(5.1
)


$
40.8



$
45.9


$
38.6Financial data:Operating margin(2)

$
91.4


$
16.7



$
81.2



$
64.5


$
58.3EBITDA(3)

$
84.5


$
15.6



$
72.8



$
57.2


$
50.8Operating data:Gathering throughput, MMcf/d(4)


168.3



168.8




162.5




161.2



152.0Plant natural gas inlet,
    MMcf/d(5)(6)


161.8



161.9




157.2




156.2



145.4Gross NGL production, MBbls/d


18.9



19.8




18.7




18.5



17.2Natural gas sales, BBtu/d(6)


74.9



72.3




69.5




68.9



59.2NGL sales, MBbl/d


15.2



15.4




14.5




14.3



13.2Condensate sales, MBbl/d


0.5



0.5




0.5




0.5



0.7Average realized prices:Natural gas, $/MMBtu

$
6.09


$
8.61



$
7.11



$
6.79


$
5.43NGL, $/gal


0.88



0.90




0.80




0.78



0.64Condensate, $/Bbl


65.31



57.54




54.03




53.42



40.56     (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.
    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)
    
    EBITDA is net income before interest, income taxes, depreciation
    and amortization. Please see Non-GAAP Financial
    Measures  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. 55




---



##### Table of Contents



Non-GAAP
    Financial Measure
  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.        Operating Margin.
        
    the financial performance of our assets without regard to
    financing methods, capital structure or historical cost basis; 56




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##### Table of Contents




    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.  Predecessor BusinessTarga North Texas LP



Combined



DynegyTwo Months







Ten MonthsYear Ended


Ended



Year Ended



Ended


Years EndedDecember 31,


December 31,



December 31,



October 31,


December 31,2006


2005



2005



2005


2004(in millions of dollars)Reconciliation of
    EBITDA to net cash provided by (used in) operating
    activities:Net cash provided by (used in)
    operating activities

$
16.2


$
(1.5
)


$
71.2



$
72.7


$
58.0Allocated interest expense from
    parent(1)


67.8



10.7




10.7








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


(0.2
)


0.1




0.4




0.3



(0.7
)Accounts payable


(0.6
)


0.8




2.1




1.3



(2.7
)Other, including changes in
    noncurrent assets and liabilities


1.3



5.5




(11.6
)



(17.1
)


(3.8
)EBITDA

$
84.5


$
15.6



$
72.8



$
57.2


$
50.8Reconciliation of
    EBITDA to net income:Net income (loss)

$
(46.9
)

$
(5.1
)


$
40.8



$
45.9


$
38.6Add:Interest expense, net


72.9



11.5




11.5








Deferred tax expense


2.5

















Depreciation and amortization
    expense


56.0



9.2




20.5




11.3



12.2EBITDA

$
84.5


$
15.6



$
72.8



$
57.2


$
50.8Reconciliation of
    operating margin to net income:Net income (loss)

$
(46.9
)

$
(5.1
)


$
40.8



$
45.9


$
38.6Add:Depreciation and amortization
    expense


56.0



9.2




20.5




11.3



12.2Deferred income tax


2.5

















Other, net




















0.3Interest expense, net


72.9



11.5




11.5








General and administrative expense


6.9



1.1




8.4




7.3



7.2Operating margin

$
91.4


$
16.7



$
81.2



$
64.5


$
58.3     (1)
    
    Excludes non-cash amortization of debt issue costs of
    $5.1 million for the year ended December 31, 2006 and
    $0.8 million for the two months ended December 31,
    2005. 57




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##### Table of Contents



Year
    Ended December 31, 2006 Compared to Year Ended
    December 31, 2005 (Combined)
    Total Operating Revenues.
  
    a net decrease attributable to commodity prices of
    $6.2 million, consisting of increases in NGL and condensate
    revenue of $19.4 million and $2.2 million,
    respectively, offset by a decrease in natural gas revenue of
    $27.8 million; and
    a net increase attributable to volumes of $22.6 million,
    consisting of increases in natural gas, NGL and condensate
    revenue of $14.0 million, $8.5 million and
    $0.1 million, respectively.      Product Purchases.
  Operating Expenses.
  Depreciation and Amortization.
 58




---



##### Table of Contents



General and Administrative.
  Interest Expense.
  Year
    Ended December 31, 2005 (Combined) Compared to Year Ended
    December 31, 2004
    Total Operating Revenues.
  
    an increase attributable to commodity prices of
    $81.3 million, consisting of increases in natural gas, NGL
    and condensate revenue of $42.6 million, $36.2 million
    and $2.5 million, respectively;
    a net increase attributable to volumes of $29.2 million,
    consisting of increases in natural gas and NGL revenue of
    $19.9 million and $11.8 million, respectively,
    partially offset by a decrease in condensate revenue of
    $2.5 million; and
    partially offset by a decrease in fee and other revenues of
    $0.7 million.      Product Purchases.
 59




---



##### Table of Contents



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.
 60




---



##### Table of Contents



Cash Flow.
  Predecessor BusinessTarga



Combined



DynegyYear


Two Months



Year



Ten Months


YearEnded


Ended



Ended



Ended


EndedDecember 31,


December 31,



December 31,



October 31,


December 31,2006


2005



2005



2005


2004(in millions)Net cash provided by (used in):Operating activities

$
16.2


$
(1.5
)


$
71.2



$
72.7


$
58.0Investing activities


(23.1
)


(2.1
)



(18.5
)



(16.4
)


(23.4
)Financing activities


6.9



3.6




(52.7
)



(56.3
)


(34.6
)       Operating Activities.
 61




---



##### Table of Contents



Investing Activities.
    Financing Activities.
  Capital Requirements.
        Description of Credit Agreement
    
    incur indebtedness; 62




---



##### Table of Contents




    grant liens; and
    engage in transactions with affiliates.    Contractual Obligations.
  Payments Due by PeriodLess Than








More ThanContractual Obligations

Total


1 Year


1-3 Years


4-5 Years


5 Years(in millions of dollars)Debt obligations(1) (2)

$
864.0


$
281.1


$
9.8


$
9.8


$
563.3Interest on debt obligations(3)


284.2



63.0



89.8



87.8



43.6Operating leases


0.3



0.1



0.2







Capacity payments(4)


8.3



2.6



4.9



0.8



Asset retirement obligations


1.7















1.7$
1,158.5


$
346.8


$
104.7


$
98.4


$
608.6     (1)
    
    Represents required future principal repayments of debt
    obligations allocated from Targa.(2)
    
    The allocated debt from Targa of $864.0 million at
    December 31, 2006 was partially repaid and the remainder of
    the allocated debt was treated as contributed capital on
    February 14, 2007 in conjunction with our IPO. The
    following table shows the extinguishment of the allocated debt
    from Targa:  (in millions)Allocated debt from Targa
    Resources at December 31, 2006 (a)

$
864.0Net proceeds from IPO


(371.2
)Net proceeds from new credit
    facility


(294.5
)Contributed capital from Targa


(198.3
)$
   (a)
    Allocated debt presented above represents indebtedness incurred
    by Targa in connection with the DMS Acquisition that has been
    allocated to the North Texas System. The entity holding the
    North Texas System provided a guarantee of this indebtedness.
    This indebtedness was also secured by a collateral interest in
    both the equity of the entity holding the North Texas System as
    well as its assets. In connection with our IPO, the guarantee
    was terminated, the collateral interest was released and the
    allocated indebtedness was retired.  (3)
    
    Represents interest expense on allocated debt, based on interest
    rates as of December 31, 2006. We used an average rate of
    7% to estimate our interest on variable rate debt obligations.(4)
    
    Consists of capacity payments for natural gas pipelines.  Available Credit.
  Recent
    Accounting Pronouncements
    
    SFAS 157, Fair Value
    Measurements, and
    SFAS 159, Fair Value Option for Financial Assets
    and Financial Liabilities  Including an amendment of
    FASB Statement No. 115. 63




---



##### Table of Contents



Item 7A.
    Quantitative
    and Qualitative Disclosures about Market Risk    Commodity Price Risk. percent-of-proceeds and/or
  65-50% 95-60%
     64




---



##### Table of Contents



Summary
    of Our Hedges
    Natural
    Gas
  Avg. Price


MMBtu per DayInstrument Type

Index

$/MMBtu


2007


2008


2009


2010


Fair Value(in thousands)Swap

IF-NGPL MC


8.56



8,152














$
7,262Swap

IF-NGPL MC


8.43







6,964











3,444Swap

IF-NGPL MC


8.02











6,256







1,677Swap

IF-NGPL MC


7.43















5,685



9328,152



6,964



6,256



5,685



13,315Swap

IF-Waha


8.73



5,460















4,606Swap

IF-Waha


8.53







4,657











1,787Swap

IF-Waha


7.96











4,196







809Swap

IF-Waha


7.38















3,809



5145,460



4,657



4,146



3,809



7,716Total Swaps








13,612



11,621



10,452



9,494



21,031Floor

IF-NGPL MC


6.45



520















200Floor

IF-NGPL MC


6.55







1,000











342Floor

IF-NGPL MC


6.55











850







246520



1,000



850







788Floor

IF-Waha


6.70



350















137Floor

IF-Waha


6.85







670











231Floor

IF-Waha


6.55











565







154350



670



565







522Total Floors








870



1,670



1,415







1,310$
22,341 65




---



##### Table of Contents



NGLs Avg. Price


Barrels per DayInstrument Type

Index

$/gal


2007


2008


2009


2010


Fair Value(in thousands)Swap

OPIS-MB

$
0.99



2,416














$
3,553Swap

OPIS-MB


0.95







2,160











2,235Swap

OPIS-MB


0.91











1,948







1,223Swap

OPIS-MB


0.88















1,759



6062,416



2,160



1,948



1,759


$
7,617Condensate Avg. Price


Barrels per DayInstrument Type

Index

$/Bbl


2007


2008


2009


2010


Fair Value(in thousands)Swap

NY-WTI

$
72.82



439














$
1,225Swap

NY-WTI


70.68







384











415Swap

NY-WTI


69.00











322







183Swap

NY-WTI


68.10















301



152Total Swaps








439



384



322



301



1,975Floor

NY-WTI

$
58.60



25















19Floor

NY-WTI


60.50







55











83Floor

NY-WTI


60.00











50







84Total Floors








25



55



50







186464



439



372



301


$
2,161     Interest Rate Risk.
    Credit Risk.
 66




---



##### Table of Contents



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    Item 9B.
    Other
    Information   Part III  Item 10.
    Directors,
    Executive Officers and Corporate Governance    Management
    of Targa Resources Partners LP
      Regulation S-K
 67




---



##### Table of Contents



day-to-day
  Directors
    and Executive Officers
    Name

Age(1)

Position with Targa Resources GP LLCRene R. Joyce


59


Chief Executive Officer and
    DirectorJoe Bob Perkins


46


PresidentJames W. Whalen


65


President  Finance and
    Administration and DirectorRoy E. Johnson


62


Executive Vice PresidentMichael A. Heim


58


Executive Vice President and Chief
    Operating OfficerJeffrey J. McParland


52


Executive Vice President, Chief
    Financial Officer and TreasurerPaul W. Chung


47


Executive Vice President, General
    Counsel and SecretaryPeter R. Kagan


38


DirectorChansoo Joung


46


DirectorRobert B. Evans


58


DirectorBarry R. Pearl


57


DirectorWilliam D. Sullivan


50


Director     (1)
    
    As of March 30, 2007 68




---



##### Table of Contents



Rene R. Joyce
  Joe Bob Perkins
  James W. Whalen
  Roy E. Johnson
  Michael A. Heim
 69




---



##### Table of Contents



Jeffrey J. McParland
  Paul W. Chung
  Peter R. Kagan
  Chansoo Joung
  Robert B. Evans
  Barry R. Pearl
  William D. Sullivan
 70




---



##### Table of Contents



Reimbursement
    of Expenses of our General Partner
  Schedule K-1
  Code of
    Ethics
  Form 8-K.
  (713) 584-1000. Form 10-K
  Item 11.
    Executive
    Compensation  Executive
    Compensation
   71




---



##### Table of Contents



Director
    Compensation
  out-of-pocket
  Compensation
    Discussion and Analysis
       72




---



##### Table of Contents




    annual base salary;
    discretionary annual cash awards;
    performance awards under Targas long-term incentive plan;
    Targas contributions under its 401(k) and profit sharing
    plan; and
    Targas other benefit plans on the same basis as all other
    Targa employees.         73




---



##### Table of Contents



Compensation Mix.
  Long-Term
    Incentive Plan
  General.
  Restricted Units and Performance Units.
 74




---



##### Table of Contents



Unit Options.
    Replacement Awards.
  Termination of Long-Term Incentive Plan.
 75




---



##### Table of Contents



Targa
    Long-Term Incentive Plan
    Compensation
    Committee Interlocks and Insider Participation
    Compensation
    Committee Report
  Form 10-K. Form 10-K
  Rene R.
    Joyce
    James W. Whalen
    Peter R. Kagan
    Chansoo Joung
    Robert B. Evans
    Barry R. Pearl
    William D. Sullivan
  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.  76




---



##### Table of Contents



Percentage of


Percentage of TotalPercentage of





Subordinated


Common andCommon Units


Common Units


Subordinated


Units


Subordinated UnitsBenefically


Benefically


Units Benefically


Benefically


BeneficallyName of Benefical Owner(1)

Owned


Owned


Owned(5)


Owned


OwnedTarga Resources Investments Inc.(2)










11,528,231



100.00
%


37.37
%Rene R. Joyce


20,000




*


222,495



1.93
%


*Joe Bob Perkins


7,100




*


187,910



1.63
%


*Michael A. Heim


2,500




*


174,076



1.51
%


*Jeffrey J. McParland


1,500




*


152,173



1.32
%


*Roy E. Johnson










163,701



1.42
%


*James W. Whalen


35,700




*


138,339



1.20
%


*Paul W. Chung










138,339



1.20
%


*Peter R. Kagan(3)


2,000




*










*Chansoo Joung(4)


2,000




*










*Robert B. Evans


3,900




*










*Barry R. Pearl


4,300




*










*William D. Sullivan


6,700




*










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


85,700




*


1,177,033



10.21
%


4.09
%     *
    
    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 shares 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)
    
    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. Peter R. Kagan, one
    of our directors, is a general partner of WP and a Managing
    Director and member of WP LLC. Charles R. Kaye and Joseph P.
    Landy are Managing General Partners of WP and Managing Members
    of WP LLC and may be deemed to control the Warburg Pincus
    entities. Messrs. Kagan, Kaye and Landy disclaim beneficial
    ownership of all shares held by the Warburg Pincus entities.(4)
    
    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, one
    of our directors, is a general partner of WP. Mr. Joung
    disclaims beneficial ownership of all shares held by the Warburg
    Pincus entities. Charles R. Kaye and Joseph P. Landy are
    Managing General Partners of WP and Managing Members of WP LLC
    and may be deemed to control the Warburg Pincus entities.
    Messrs. Joung, Kaye and Landy disclaim beneficial ownership
    of all shares held by the Warburg Pincus entities.(5)
    
    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 77




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##### Table of Contents



Inc. that are attributable to such directors and officers based
    on their ownership of equity interests in Targa Resources
    Investments Inc. Item 13.  Certain
    Relationships and Related Transactions, and Director
    Independence    Distributions
    and Payments to Our General Partner and its Affiliates
    Formation
    Stage
  The consideration received by
    Targa and its subsidiaries for the contribution of the assets
    and liabilities to us

 11,528,231
    subordinated units; 629,555 general
    partner units, the incentive
    distribution rights; approximately
    $371.2 million payment from the proceeds of the IPO to
    retire a portion of our allocated indebtedness; and the net proceeds
    from borrowings under our credit agreement of
    $294.5 million, which were used to retire an additional
    portion of our allocated indebtednessOperational StageDistributions 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 $0.8 million on their general partner
    units and $15.6 million on their subordinated units. 78




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##### Table of Contents



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.
    Please see The Partnership Agreement 
    Withdrawal or Removal of the General Partner.Liquidation StageLiquidation

Upon our liquidation, the
    partners, including our general partner, will be entitled to
    receive liquidating distributions according to their respective
    capital account balances.   Agreements
    Governing the IPO Transactions
    Omnibus
    Agreement
    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 expenses, which are not subject to
    the $5 million cap for general and administrative expenses. 79




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Competition
    Indemnification
    rights-of-way,
  Contracts
    with Affiliates
  NGL and Condensate Purchase Agreement.
  Natural Gas Purchase Agreement.
  Indemnification
    Agreements
   80




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and/or
    Conflicts
    of Interest
   81




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##### Table of Contents




    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.    Item 14.
    Principal
    Accounting Fees and Services    For Year Ended December 31,2006


2005Audit Fees(1)

$
820.7


$
0Audit-Related Fees(2)


0



0Tax Fees(3)


0



0All Other Fees(4)


0



0     (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 and
    internal controls over financial reporting, (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. 82




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(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, partnership tax planning
    and property tax assistance.(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.   PART IV  Item 15.
    Exhibits
    and Financial Statement Schedules  Financial Statements
  Index to Financial Statements page F-1
  Financial Statement Schedules
    Exhibits
  83




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ExhibitNumber

Description3
.1

Certificate of Limited Partnership
    of the Partnership, incorporated by reference to
    Exhibit 3.2 to the Partnerships Registration
    Statement (File
    No. 333-138747)
    on
    Form S-1,
    as amended.3
.2

Certificate of Formation of Targa
    Resources GP LLC, incorporated by reference to Exhibit 3.3
    to the Partnerships Registration Statement (File
    No. 333-138747)
    on
    Form S-1,
    as amended.3
.3

Agreement of Limited Partnership
    of Targa Resources Partners LP.*3
.4

First Amended and Restated
    Agreement of Limited Partnership of Targa Resources Partners LP,
    dated February 14, 2007, incorporated by reference to
    Exhibit 3.1 to the Partnerships Current Report on
    Form 8-K
    filed with the SEC on February 16, 2007.3
.5

Limited Liability Company
    Agreement of Targa Resources GP LLC, incorporated by reference
    to Exhibit 3.4 to the Partnerships Registration
    Statement (File
    No. 333-138747)
    on
    Form S-1,
    as amended.4
.1

Specimen Unit Certificate
    representing common units.*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 the
    Partnerships Current Report on
    Form 8-K
    filed with the SEC on February 16, 2007.10
.2

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 the Partnerships Current Report on
    Form 8-K
    filed with the SEC on February 16, 2007.10
.3

Omnibus Agreement, dated
    February 14, 2007, by and among Targa Resources Partners
    LP, Targa Resources, Inc., Targa Resources LLC and Targa
    Resources GP LLC, incorporated by reference to Exhibit 10.3
    to the Partnerships Current Report on
    Form 8-K
    filed with the SEC on February 16, 2007.10
.4

Targa Resources Partners Long-Term
    Incentive Plan, incorporated by reference to Exhibit 10.2
    to the Partnerships Registration Statement (File
    No. 333-138747)
    on
    Form S-1,
    as amended.10
.5

Targa Resources Investments Inc.
    Long-Term Incentive Plan, incorporated by reference to
    Exhibit 10.9 to the Partnerships Registration
    Statement (File
    No. 333-138747)
    on
    Form S-1,
    as amended.10
.6

Form of Restricted Unit Grant
    Agreement, incorporated by reference to Exhibit 10.2 to the
    Partnerships Current Report on
    Form 8-K
    filed with the SEC on February 13, 2007.10
.7

Form of Performance Unit Grant
    Agreement, incorporated by reference to Exhibit 10.3 to the
    Partnerships Current Report on
    Form 8-K
    filed with the SEC on February 13, 2007.10
.8

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 pursuant to a request for confidential
    treatment), incorporated by reference to Exhibit 10.5 to
    the Partnerships Registration Statement (File
    No. 333-138747)
    on
    Form S-1,
    as amended.10
.9

Natural Gas Purchase Agreement
    with Targa Gas Marketing LLC, incorporated by reference to
    Exhibit 10.6 to the Partnerships Registration
    Statement (File
    No. 333-138747)
    on
    Form S-1,
    as amended.10
.10

NGL and Condensate Purchase
    Agreement with Targa Liquids Marketing and Trade, incorporated
    by reference to Exhibit 10.7 to the Partnerships
    Registration Statement (File
    No. 333-138747)
    on
    Form S-1,
    as amended.10
.11

Targa Resources Partners LP
    Indemnification Agreement for Barry R. Pearl dated
    February 14, 2007.*10
.12

Targa Resources Partners LP
    Indemnification Agreement for Robert B. Evans dated
    February 14, 2007.* 84




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ExhibitNumber

Description10
.13

Targa Resources Partners LP
    Indemnification Agreement for William D. Sullivan dated
    February 14, 2007.*21
.1

Subsidiaries of the Partnership,
    incorporated by reference to Exhibit 21.1 to the
    Partnerships Registration Statement (File
    No. 333-138747)
    on
    Form S-1,
    as amended.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
    
    Management contract or compensatory plan or arrangement 85




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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  86




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INDEX TO
    FINANCIAL STATEMENTS
  TARGA NORTH TEXAS LP AUDITED
    COMBINED FINANCIAL STATEMENTSReports of
    Independent Registered Public Accounting Firm


F-2Combined Balance
    Sheets as of December 31, 2006 and December 31,
    2005


F-4Combined Statements
    of Operations and Comprehensive Income (Loss) for the Year Ended
    December 31, 2006, the Two Months Ended December 31,
    2005 (Successor) and the Ten Months Ended October 31, 2005
    and the Year Ended December 31, 2004
    (Predecessor)


F-5Combined Statements
    of Changes in Partners Capital/Net Parent Equity for the
    Year Ended December 31, 2006, the Two Months Ended
    December 31, 2005 (Successor) and the Ten Months Ended
    October 2005 and the Year Ended December 31, 2004
    (Predecessor)


F-6Combined Statement
    of Cash Flows for the Year Ended December 31, 2006, the Two
    Months Ended December 31, 2005 (Successor) and the Ten
    Months Ended October 31, 2005 and the Year Ended
    December 31, 2004 (Predecessor)


F-7Notes to the
    Combined Financial Statements


F-8TARGA RESOURCES PARTNERS LP
    AUDITED BALANCE SHEETReport of
    Independent Registered Public Accounting Firm


F-26Balance Sheet as of
    December 31, 2006


F-27Note to Balance
    Sheet


F-28TARGA RESOURCES GP LLC AUDITED
    BALANCE SHEETReport of
    Independent Registered Public Accounting Firm


F-29Balance Sheet as of
    December 31, 2006


F-30Note to Balance
    Sheet


F-31  F-1




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Report of
    Independent Registered Public Accounting Firm            F-2




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Report of
    Independent Registered Public Accounting Firm
            F-3




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##### Table of Contents



TARGA
    NORTH TEXAS LP
  COMBINED
    BALANCE SHEETS
  December 31,2006


2005(in thousands)ASSETS (Collateral for Parent
    debt  See Note 6)Current assets:Trade receivables, net of
    allowances of $0 and $15

$
1,310


$
1,525Inventory






1,155Assets from risk management
    activities


17,250



34Deposits






630Total current assets


18,560



3,344Property, plant, and equipment, at
    cost


1,129,210



1,106,107Accumulated depreciation


(65,102
)


(9,126
)Property, plant, and equipment, net


1,064,108



1,096,981Debt issue costs allocated from
    Parent


17,612



22,494Long-term assets from risk
    management activities


15,541



24Total assets (collateral for
    Parent debt  See Note 6)

$
1,115,821


$
1,122,843LIABILITIES AND PARTNERS
    CAPITALCurrent liabilities:Accounts payable

$
2,789


$
2,145Accrued liabilities


28,832



30,595Current maturities of debt
    allocated from Parent


281,083



4,932Liabilities from risk management
    activities






53Total current liabilities


312,704



37,725Long-term debt allocated from
    Parent


582,877



863,960Long-term liabilities from risk
    management activities


96



72Other long-term liabilities


1,684



1,541Deferred income tax liability


2,844



Commitments and contingencies (see
    Note 8)Partners capital:General partner


107,808



109,772Limited partner


107,808



109,773Total partners capital


215,616



219,545Total liabilities and
    partners capital

$
1,115,821


$
1,122,843    F-4




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##### Table of Contents



TARGA
    NORTH TEXAS LP
  COMBINED
    STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
    (LOSS)
  TNT LP



TNT LP PredecessorYear


Two Months



Ten Months


YearEnded


Ended



Ended


EndedDecember 31,


December 31,



October 31,


December 31,2006


2005



2005


2004(in thousands)Revenues from third parties

$
15,224


$
22,192



$
8,732


$
12,039Revenues from affiliates


369,605



52,952




284,603



246,516Total operating revenues


384,829



75,144




293,335



258,555Costs and expenses:Product purchases from third
    parties


268,487



54,981




209,835



182,234Product purchases from affiliates


846



11




1,024



278Operating expense, excluding
    DD&A


24,102



3,494




18,035



17,702Depreciation and amortization
    expense


55,958



9,150




11,262



12,201General and administrative expense


6,904



1,063




7,273



7,230Loss (gain) on sale of assets











(32
)


329356,297



68,699




247,397



219,974Income from operations


28,532



6,445




45,938



38,581Other expense:Interest expense allocated from
    Parent


(72,910
)


(11,542
)







Income (loss) before income taxes


(44,378
)


(5,097
)



45,938



38,581Deferred income tax benefit


(2,532
)











Net income (loss)


(46,910
)


(5,097
)



45,938



38,581Other comprehensive income (loss):Change in fair value of commodity
    hedges


35,189












Reclassification adjustment for
    settled periods


(4,610
)











Related income taxes


(312
)


Change in fair value of interest
    rate swaps


1,047



(99
)







Reclassification adjustment for
    settled periods


(404
)


32








Other comprehensive income (loss)


30,910



(67
)







Comprehensive income (loss)

$
(16,000
)

$
(5,164
)


$
45,938


$
38,581    F-5




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##### Table of Contents



TARGA
    NORTH TEXAS LP
  COMBINED
    STATEMENTS OF CHANGES IN PARTNERS CAPITAL/NET PARENT
    EQUITY
  Targa NorthTarga North Texas LP


Texas LPGeneral


Limited


PredecessorPartner


Partner


Equity


Total(in thousands)Balance, December 31,
    2003

$



$



$
164,802


$
164,802Distributions










(34,573
)


(34,573
)Net income










38,581



38,581Balance, December 31,
    2004










168,810



168,810Distributions










(56,268
)


(56,268
)Net income










45,938



45,938Balance, October 31,
    2005










158,480



158,480Initial contribution


109,939



109,940







219,879Other contributions


2,415



2,415







4,830Other comprehensive loss


(34
)


(33
)






(67
)Net loss


(2,548
)


(2,549
)






(5,097
)Balance, December 31,
    2005


109,772



109,773







219,545Other contributions


6,036



6,035







12,071Other comprehensive income


15,455



15,455







30,910Net loss


(23,455
)


(23,455
)






(46,910
)Balance, December 31,
    2006

$
107,808


$
107,808


$



$
215,616    F-6




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##### Table of Contents



TARGA
    NORTH TEXAS LP
  COMBINED
    STATEMENTS OF CASH FLOWS
  TNT LP



TNT LP PredecessorYear


Two Months



Ten Months


YearEnded


Ended



Ended


EndedDecember 31,


December 31,



October 31,


December 31,2006


2005



2005


2004(in thousands)Cash flows from operating
    activitiesNet income (loss)

$
(46,910
)

$
(5,097
)


$
45,938


$
38,581Adjustments to reconcile net
    income (loss) to cash flows provided by (used in) operating
    activities:Depreciation


55,958



9,150




11,262



12,201Accretion


144



35




187



204Noncash amortization of debt issue
    costs and debt payments allocated from Parent


5,154



848








Loss (gain) on sale of assets











(32
)


329Deferred taxes


2,532












Hedge premium


(1,541
)











Changes in operating assets and
    liabilities:Accounts receivable


215



(60
)



(280
)


683Inventory


1,155



(1,155
)



423



87Other assets


630



10




51



(574
)Accounts payable


644



(845
)



(1,334
)


2,658Accrued liabilities


(1,763
)


(4,357
)



16,490



3,850Net cash provided by (used in)
    operating activities


16,218



(1,471
)



72,705



58,019Cash flows from investing
    activitiesPurchases of property, plant, and
    equipment


(23,117
)


(2,134
)



(16,469
)


(23,664
)Proceeds from asset sales


32



8




32



218Net cash used in investing
    activities


(23,085
)


(2,126
)



(16,437
)


(23,446
)Cash flows from financing
    activitiesContributions (distributions)


6,867



3,597




(56,268
)


(34,573
)Net cash provided by (used in)
    financing activities


6,867



3,597




(56,268
)


(34,573
)Net increase in cash and cash
    equivalents















Cash and cash equivalents,
    beginning of period















Cash and cash equivalents, end of
    period

$



$




$



$
Supplemental cash flow
    information:Noncash investing and financing
    activities:Property, plant and equipment
    allocated from Parent

$



$
907,634



$



$
Debt issue costs allocated from
    Parent


272



23,342








Long-term debt allocated from
    Parent


4,932



870,125








    F-7




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##### Table of Contents



TARGA
    NORTH TEXAS LP
  NOTES TO
    COMBINED FINANCIAL STATEMENTS
  Note 1 
    Organization and Operations
            Note 2 
    Basis of Presentation
  Business Combinations.
       F-8




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##### Table of Contents



TARGA
    NORTH TEXAS LP
  NOTES TO
    COMBINED FINANCIAL
    STATEMENTS  (Continued)
      Note 3 
    Significant Accounting Policies
  Asset Retirement Obligations. Accounting for
    Asset Retirement Obligations, Accounting for Conditional Asset Retirement
    Obligations. and/or
  Cash and Cash Equivalents.
  Comprehensive Income.
  Debt Issue Costs.
  Environmental Liabilities. and/or
  Impairment of Long-Lived Assets.
 F-9




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##### Table of Contents



TARGA
    NORTH TEXAS LP
  NOTES TO
    COMBINED FINANCIAL
    STATEMENTS  (Continued)
    Income Taxes.
  Natural Gas Imbalances.
  Price Risk Management (Hedging). Accounting for Derivative Instruments
    and Hedging Activities,
        Property, Plant and Equipment.
 F-10




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##### Table of Contents



TARGA
    NORTH TEXAS LP
  NOTES TO
    COMBINED FINANCIAL
    STATEMENTS  (Continued)
    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 revenue through
    the compression, gathering, treating, and processing of natural
    gas.    percent-of-proceeds percent-of-proceeds percent-of-proceeds Percent-of-value percent-of-liquids
  Issue 99-19,
  Segment Information. Disclosures about Segments of an Enterprise and Related
    Information,
  Use of Estimates.
 F-11




---



##### Table of Contents



TARGA
    NORTH TEXAS LP
  NOTES TO
    COMBINED FINANCIAL
    STATEMENTS  (Continued)
    Recent
    Accounting Pronouncements.
  Share-Based Payment,
  EITF 04-13, Accounting for Purchases and Sale of Inventory With the
    Same Counterparty. 04-13 04-13
  Accounting
    for Uncertainty in Income Taxes  an interpretation of
    FASB Statement No. 109
  Accounting Changes and Error
    Corrections,
  Fair
    Value Measurements.
   F-12




---



##### Table of Contents



TARGA
    NORTH TEXAS LP
  NOTES TO
    COMBINED FINANCIAL
    STATEMENTS  (Continued)
   The
    Fair Value Option for Financial Assets and Financial
    Liabilities, including an amendment of FASB Statement
    No. 115
  Note 4 
    Change of Control
    Current assets

$
2,105Property, plant, and equipment


1,104,000Debt issue costs


23,342Current liabilities


(37,937
)Long-term debt


(870,125
)Asset retirement obligations


(1,506
)Initial contribution

$
219,879     Pro FormaYear Ended December 31,2005(Unaudited)(in thousands)Revenues

$
368,479Product purchases


(265,851
)Depreciation and amortization
    expense


(54,876
)Gain (loss) on sale of assets


32Other operating expense


(29,865
)Income (loss) from operations


17,919Interest expense


(69,252
)Net loss

$
(51,333
)  F-13




---



##### Table of Contents



TARGA
    NORTH TEXAS LP
  NOTES TO
    COMBINED FINANCIAL
    STATEMENTS  (Continued)
  Note 5 
    Property, Plant, and Equipment
    December 31,2006


2005(in thousands)Gathering and processing systems

$
1,113,799


$
1,078,402Other property and equipment


15,411



27,7051,129,210



1,106,107Accumulated depreciation


(65,102
)


(9,126
)$
1,064,108


$
1,096,981   Note 6 
    Long-Term Debt
    TNT LPDecember 31,


December 31,2006


2005(in thousands)Outstanding debt

$
863,960


$
868,892Current maturities of debt


(281,083
)


(4,932
)Long-term debt

$
582,877


$
863,960   Allocation
    of Long-Term Debt from the Parent
      December 31,


December 31,2006


2005(in thousands)Senior secured term loan facility,
    variable rate, 6.7% at December 31, 2006, due October 2011

$
486,962


$
491,894Senior secured asset sale bridge
    loan facility, variable rate, 7.6% at December 31, 2006,
    due October 2007


276,151



276,151Senior unsecured notes, 8.5% fixed
    rate, due November 2013


100,847



100,847Total principal amount


863,960



868,892Less current maturities of debt


(281,083
)


(4,932
)Long-term debt

$
582,877


$
863,960  F-14




---



##### Table of Contents



TARGA
    NORTH TEXAS LP
  NOTES TO
    COMBINED FINANCIAL
    STATEMENTS  (Continued)
    Range of

Weighted AverageInterest Rates Paid

Interest Rate PaidSenior secured term loan facility

6.59% to 7.75%


7.03
%Senior secured asset sale bridge
    loan facility

6.83% to 7.62%


7.26
%     Debt
    Maturity Table
    Allocated toTNT LP2007

$
281,0832008


4,9322009


4,9322010


4,9322011


4,932Thereafter


563,149$
863,960   Critical
    Terms of Parent Debt Obligations
  Senior
    Secured Credit Facility
         F-15




---



##### Table of Contents



TARGA
    NORTH TEXAS LP
  NOTES TO
    COMBINED FINANCIAL
    STATEMENTS  (Continued)
       
    a pledge of TNT LPs general partner and limited partner
    interests; and
    a security interest in, and mortgages on, TNT LPs tangible
    and intangible assets.  81/2% Senior
    Notes due 2013
    1 2 360-day 30-day
    Interest
    Rate Swaps
      Note 7 
    Asset Retirement Obligations
    TNT LP



TNT LP PredecessorTwo Months



Ten MonthsYear Ended


Ended



Ended


Year EndedDecember 31,


December 31,



October 31,


December 31,2006


2005



2005


2004(in thousands)Beginning of period

$
1,541


$
2,054



$
1,897


$
1,838Liabilities incurred















Change in estimate


(1
)


(548
)



(30
)


(145
)Accretion expense


144



35




187



204End of period

$
1,684


$
1,541



$
2,054


$
1,897    F-16




---



##### Table of Contents



TARGA
    NORTH TEXAS LP
  NOTES TO
    COMBINED FINANCIAL
    STATEMENTS  (Continued)
   Note 8 
    Commitments and Contingencies
    2007


2008


2009


2010


2011+Capacity payments

$
2.6


$
2.5


$
2.4


$
0.8


$
Operating leases


0.1



0.1



0.1







AROs


















1.7$
2.7


$
2.6


$
2.5


$
0.8


$
1.7     Environmental
  96-1, Environmental Remediation Liabilities.
    Litigation
    Summary
    Note 9 
    Related-Party Transactions
  Sales to and purchases from affiliates.
  Allocation of costs.
 F-17




---



##### Table of Contents



TARGA
    NORTH TEXAS LP
  NOTES TO
    COMBINED FINANCIAL
    STATEMENTS  (Continued)
    Allocations of long-term debt, debt issue costs, interest
    rate swaps and interest expense.
    TNT LP



TNT LP PredecessorYear


Two Months



Ten Months


YearEnded


Ended



Ended


EndedDecember 31,


December 31,



October 31,


December 31,2006


2005



2005


2004(in thousands)CashSales to affiliates

$
(369,605
)

$
(52,952
)


$
(284,603
)

$
(246,516
)Purchases from affiliates


846



11




1,024



278Payments made by the Parent


300,967



44,781




220,038



204,435Parent allocation of interest
    expense


67,756



10,694








Parent allocation of general and
    administrative expense


6,903



1,063




7,273



7,2306,867



3,597




(56,268
)


(34,573
)NoncashInitial contribution by Parent
    (see Note 4)






219,879








Other


272












Parent allocation of debt
    repayments


4,932



1,233








5,204



221,112








Transactions settled through
    adjustments to partners capital/net parent equity

$
12,071


$
224,709



$
(56,268
)

$
(34,573
)   Centralized cash management.
 F-18




---



##### Table of Contents



TARGA
    NORTH TEXAS LP
  NOTES TO
    COMBINED FINANCIAL
    STATEMENTS  (Continued)
   Commodity hedges.
  Period

Commodity

Instrument Type

Daily Volumes

Average Price

IndexJan 2007  Dec 2007

Natural gas

Swap

4,200 MMBtu

$
9
.14 per MMBtu

IF-WahaJan 2008  Dec 2008

Natural gas

Swap

3,847 MMBtu


8
.76 per MMBtu

IF-WahaJan 2009  Dec 2009

Natural gas

Swap

3,556 MMBtu


8
.07 per MMBtu

IF-WahaJan 2010  Dec 2010

Natural gas

Swap

3,289 MMBtu


7
.39 per MMBtu

IF-WahaJan 2007  Dec 2007

Condensate

Swap

319 barrels


75
.27 per barrel

NY-WTIJan 2008  Dec 2008

Condensate

Swap

264 barrels


72
.66 per barrel

NY-WTIJan 2009  Dec 2009

Condensate

Swap

202 barrels


70
.60 per barrel

NY-WTIJan 2010  Dec 2010

Condensate

Swap

181 barrels


69
.28 per barrel

NY-WTI   Note 10 
    Significant Risks and Uncertainties
  Nature
    of Operations in Midstream Energy Industry
        Counterparty
    Risk with Respect to Financial Instruments
  and/or
 F-19




---



##### Table of Contents



TARGA
    NORTH TEXAS LP
  NOTES TO
    COMBINED FINANCIAL
    STATEMENTS  (Continued)
   Casualties
    or Other Risks
        Note 11 
    Derivative Instruments and Hedging Activities
           F-20




---



##### Table of Contents



TARGA
    NORTH TEXAS LP
  NOTES TO
    COMBINED FINANCIAL
    STATEMENTS  (Continued)
     Natural
    Gas
  Avg. Price


MMBtu per DayInstrument Type

Index

$/MMBtu


2007


2008


2009


2010


Fair Value(in thousands)Swap

IF-NGPL MC


8.56



8,152














$
7,262Swap

IF-NGPL MC


8.43







6,964











3,444Swap

IF-NGPL MC


8.02











6,256







1,677Swap

IF-NGPL MC


7.43















5,685



9328,152



6,964



6,256



5,685



13,315Swap

IF-Waha


8.73



5,460















4,606Swap

IF-Waha


8.53







4,657











1,787Swap

IF-Waha


7.96











4,196







809Swap

IF-Waha


7.38















3,809



5145,460



4,657



4,196



3,809



7,716Total Swaps








13,612



11,621



10,452



9,494



21,031Floor

IF-NGPL MC


6.45



520















200Floor

IF-NGPL MC


6.55







1,000











342Floor

IF-NGPL MC


6.55











850







246520



1,000



850







788Floor

IF-Waha


6.70



350















137Floor

IF-Waha


6.85







670











231Floor

IF-Waha


6.55











565







154350



670



565







522Total Floors








870



1,670



1,415







1,310$
22,341NGLs Avg. Price


Barrels per DayInstrument Type

Index

$/gal


2007


2008


2009


2010


Fair Value(in thousands)Swap

OPIS-MB

$
0.99



2,416














$
3,553Swap

OPIS-MB


0.95







2,160











2,235Swap

OPIS-MB


0.91











1,948







1,223Swap

OPIS-MB


0.88















1,759



6062,416



2,160



1,948



1,759


$
7,617 F-21




---



##### Table of Contents



TARGA
    NORTH TEXAS LP
  NOTES TO
    COMBINED FINANCIAL
    STATEMENTS  (Continued)
  Condensate Avg. Price


Barrels per dayInstrument Type

Index

$/Bbl


2007


2008


2009


2010


Fair Value(in thousands)Swap

NY-WTI

$
72.82



439














$
1,225Swap

NY-WTI


70.68







384











415Swap

NY-WTI


69.00











322







183Swap

NY-WTI


68.10















301



152Total Swaps








439



384



322



301



1,975Floor

NY-WTI

$
58.60



25















19Floor

NY-WTI


60.50







55











83Floor

NY-WTI


60.00











50







84Total Floors








25



55



50







186464



439



372



301


$
2,161       December 31,2006


2005(in thousands)Current assets

$
17,250


$
34Noncurrent assets


15,541



24Current liabilities






(53
)Noncurrent liabilities


(96
)


(72
)$
32,695


$
(67
)   Note 12 
    Income Taxes
   F-22




---



##### Table of Contents



TARGA
    NORTH TEXAS LP
  NOTES TO
    COMBINED FINANCIAL
    STATEMENTS  (Continued)
   Note 13 
    Selected Quarterly Financial Data (Unaudited)
    First


Second





Third


FourthQuarter


Quarter





Quarter


Quarter


Total(Dollars in thousands, except per unit amounts)Targa North Texas LPYear Ended December 31,
    2006:Revenues

$
96,251


$
92,673






$
101,966


$
93,939


$
384,829Operating income


7,132



6,805







6,996



7,599



28,532Net loss


(10,229
)


(12,951
)






(12,244
)


(11,486
)


(46,910
)Basic income per limited partner
    unit(a)






















Two Months Ended
    December 31, 2005:Revenues

$



$







$



$
75,144
(b)

$
75,144Operating income


















6,445
(b)


6,445Net loss


















(5,097
)(b)


(5,097
)Basic income per limited partner
    unit(a)






















TNT LP PredecessorTen Months Ended
    October 31, 2005:Revenues

$
71,414


$
80,280






$
98,045


$
43,596(c
)

$
293,335Operating income


10,485



12,152







15,445



7,856(c
)


45,938Net income


10,485



12,152







15,445



7,856(c
)


45,938Basic 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.(b)
    
    Reflects two months of results.(c)
    
    Reflects one month of results.  Note 14 
    Subsequent Event
  Initial
    Public Offering
   F-23




---



##### Table of Contents



TARGA
    NORTH TEXAS LP
  NOTES TO
    COMBINED FINANCIAL
    STATEMENTS  (Continued)
    
    TRP LP issued to Targa 11,528,231 subordinated units,
    representing a 36.6% limited partner interest;
    TRP LP issued to the general partner, Targa Resources GP LLC,
    629,555 general partner units representing an 2% general partner
    interest in TRP LP, and all of TRP LPs incentive
    distribution rights, which incentive distribution rights entitle
    our general partner to increasing percentages of the cash that
    is distributed in excess of $0.3881 per unit per quarter;
    TRP LP issued 19,320,000 common units to the public in
    connection with its IPO of common units (including 2,520,000
    common units sold pursuant to the full exercise by the
    underwriters of their option to purchase additional common
    units), representing a 61.4% limited partner interest, and used
    the proceeds to pay expenses associated with the offering, the
    formation transactions, and fees associated with our credit
    facility and paid $371.2 million to Targa to retire a
    portion of our allocated indebtedness;
    TRP LP borrowed approximately $294.5 million under its
    $500 million credit facility, the net proceeds of which
    were paid to Targa to retire an additional portion of our
    allocated indebtedness; and
    our remaining allocated indebtedness was retired and treated as
    a capital contribution by Targa.    Allocated debt from Targa
    Resources at December 31,2006





$
864.0Gross proceeds from IPO

$
405.7Discounts, fees and offering
    expenses


(30.3
)Fees and expenses of new credit
    facility


(4.2
)Net proceeds from offering

$
371.2



(371.2
)Net proceeds from new credit
    facility






(294.5
)Contributed capital from Targa






(198.3
)$
  F-24




---



##### Table of Contents



TARGA
    NORTH TEXAS LP
  NOTES TO
    COMBINED FINANCIAL
    STATEMENTS  (Continued)
    Partnership Pro FormaYear EndedDecember 31,2006(unaudited)(in millions)Revenues

$
384.8Costs and expenses:Product purchases


269.3Operating expense


24.0Depreciation and amortization
    expense


56.0General and administrative expense


6.9Total costs and expenses


356.2Income from operations


28.6Other (income) expenseInterest expense allocated from
    parent


Other interest expense


20.6Deferred income tax expense


2.5Net income (loss)

$
5.5General partners interest in
    net income (loss)

$
0.1Limited partners interest in
    net income (loss)

$
5.4  F-25




---



##### Table of Contents



Report of
    Independent Registered Public Accounting Firm          F-26




---



##### Table of Contents



TARGA
    RESOURCES PARTNERS LP
  BALANCE
    SHEET
 December 31,
    2006
  ASSETSCurrent assetsCash

$
1,000Total assets

$
1,000PARTNERS EQUITYLimited partners equity

$
980General partner equity


20Total partners
    equity

$
1,000    F-27




---



##### Table of Contents



TARGA
    RESOURCES PARTNERS LP
  NOTE TO
    BALANCE SHEET
  1.
    Nature of
    Operations      2.
    Subsequent
    Event     F-28




---



##### Table of Contents



Report of
    Independent Registered Public Accounting Firm          F-29




---



##### Table of Contents



TARGA
    RESOURCES GP LLC
  BALANCE
    SHEET
 December 31,
    2006
  ASSETSCurrent
    assetsCash

$
980Investment in Targa Resources
    Partners LP


20Total assets

$
1,000MEMBERS
    EQUITYMembers equity

$
1,000Total members
    equity

$
1,000    F-30




---



##### Table of Contents



TARGA
    RESOURCES GP LLC
  NOTE TO
    BALANCE SHEET
  1.
    Nature of
    Operations        2.
    Subsequent
    Event     F-31




---



##### Table of Contents



Index to
    Exhibits
  ExhibitNumber

Description3
.1

Certificate of Limited Partnership
    of the Partnership, incorporated by reference to
    Exhibit 3.2 to the Partnerships Registration
    Statement (File
    No. 333-138747)
    on
    Form S-1,
    as amended.3
.2

Certificate of Formation of Targa
    Resources GP LLC, incorporated by reference to Exhibit 3.3
    to the Partnerships Registration Statement (File
    No. 333-138747)
    on
    Form S-1,
    as amended.3
.3

Agreement of Limited Partnership
    of Targa Resources Partners LP.*3
.4

First Amended and Restated
    Agreement of Limited Partnership of Targa Resources Partners LP,
    dated February 14, 2007, incorporated by reference to
    Exhibit 3.1 to the Partnerships Current Report on
    Form 8-K
    filed with the SEC on February 16, 2007.3
.5

Limited Liability Company
    Agreement of Targa Resources GP LLC, incorporated by reference
    to Exhibit 3.4 to the Partnerships Registration
    Statement (File
    No. 333-138747)
    on
    Form S-1,
    as amended.4
.1

Specimen Unit Certificate
    representing common units.*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 the
    Partnerships Current Report on
    Form 8-K
    filed with the SEC on February 16, 2007.10
.2

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 the Partnerships Current Report on
    Form 8-K
    filed with the SEC on February 16, 2007.10
.3

Omnibus Agreement, dated
    February 14, 2007, by and among Targa Resources Partners
    LP, Targa Resources, Inc., Targa Resources LLC and Targa
    Resources GP LLC, incorporated by reference to Exhibit 10.3
    to the Partnerships Current Report on
    Form 8-K
    filed with the SEC on February 16, 2007.10
.4

Targa Resources Partners Long-Term
    Incentive Plan, incorporated by reference to Exhibit 10.2
    to the Partnerships Registration Statement (File
    No. 333-138747)
    on
    Form S-1,
    as amended.10
.5

Targa Resources Investments Inc.
    Long-Term Incentive Plan, incorporated by reference to
    Exhibit 10.9 to the Partnerships Registration
    Statement (File
    No. 333-138747)
    on
    Form S-1,
    as amended.10
.6

Form of Restricted Unit Grant
    Agreement, incorporated by reference to Exhibit 10.2 to the
    Partnerships Current Report on
    Form 8-K
    filed with the SEC on February 13, 2007.10
.7

Form of Performance Unit Grant
    Agreement, incorporated by reference to Exhibit 10.3 to the
    Partnerships Current Report on
    Form 8-K
    filed with the SEC on February 13, 2007.10
.8

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 pursuant to a request for confidential
    treatment), incorporated by reference to Exhibit 10.5 to
    the Partnerships Registration Statement (File
    No. 333-138747)
    on
    Form S-1,
    as amended.10
.9

Natural Gas Purchase Agreement
    with Targa Gas Marketing LLC, incorporated by reference to
    Exhibit 10.6 to the Partnerships Registration
    Statement (File
    No. 333-138747)
    on
    Form S-1,
    as amended.10
.10

NGL and Condensate Purchase
    Agreement with Targa Liquids Marketing and Trade, incorporated
    by reference to Exhibit 10.7 to the Partnerships
    Registration Statement (File
    No. 333-138747)
    on
    Form S-1,
    as amended.10
.11

Targa Resources Partners LP
    Indemnification Agreement for Barry R. Pearl dated
    February 14, 2007.*10
.12

Targa Resources Partners LP
    Indemnification Agreement for Robert B. Evans dated
    February 14, 2007.*




---



##### Table of Contents



ExhibitNumber

Description10
.13

Targa Resources Partners LP
    Indemnification Agreement for William D. Sullivan dated
    February 14, 2007.*21
.1

Subsidiaries of the Partnership,
    incorporated by reference to Exhibit 21.1 to the
    Partnerships Registration Statement (File
    No. 333-138747)
    on
    Form S-1,
    as amended.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
    
    Management contract or compensatory plan or arrangement