UNITED
STATES


SECURITIES
AND EXCHANGE COMMISSION


Washington,
D.C. 20549





Form
10-K








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





For
the fiscal year ended December 31, 2009


or





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





For
the transition period from
                   
to


Commission
file number: 001-33303





TARGA
RESOURCES PARTNERS LP


(Exact
name of registrant as specified in its charter)








Delaware
            
            65-1295427(State
      or other jurisdiction ofincorporation
      or organization)
            
            (I.R.S.
      EmployerIdentification
      No.)1000
      Louisiana St, Suite 4300Houston,
      Texas
            
            77002(Address
      of principal executive offices)
            
            (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
            
            New
      York Stock Exchange





Securities
registered pursuant to section 12(g) of the Act: None





Indicate
by check mark if the registrant is a well-known seasoned issuer, as defined in
Rule 405 of the Securities Act. Yes R No £





Indicate
by check mark if the registrant is not required to file reports pursuant to
Section 13 or Section 15(d) of the Act. Yes £ No R





Indicate
by check mark whether the registrant (1) has filed all reports required to be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the registrant was required
to file such reports) and (2) has been subject to such filing requirements for
the past 90 days. Yes R No £





Indicate
by check mark whether the registrant has submitted electronically and posted on
its corporate Web site, if any, every Interactive Data File required to be
submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this
chapter) during the preceding 12 months (or for such shorter period that the
registrant was required to submit and post such files). Yes £ No £.





Indicate
by check mark if disclosure of delinquent filers pursuant to Item 405 of
Regulation S-K is not contained herein and will not be contained, to the best of
registrant’s knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. £





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


Large
      accelerated filer £
            Accelerated
      filer R
            Non-accelerated
      filer £
            Smaller
      reporting company £


(Do not
check if a smaller reporting company)





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


Act). Yes
£ No
R.





The
aggregate market value of the Common Units representing limited partner
interests held by non-affiliates of the registrant was approximately $476.3
million on June 30, 2009, based on $13.87 per unit, the closing price of the
Common Units as reported on The NASDAQ Stock Market LLC on such
date.





As of
February 28, 2010, there were 67,980,596 Common Units and 1,387,360 General
Partner Units outstanding.





DOCUMENTS
INCORPORATED BY REFERENCE





None
















TABLE OF CONTENTSDESCRIPTIONPART I1.
            
            BUSINESS
            
            
            41A.
            
            RISK FACTORS
            
            
            251B.
            
            UNRESOLVED STAFF
      COMMENTS
            
            
            472.
            
            PROPERTIES
            
            
            473.
            
            LEGAL PROCEEDINGS
            
            
            474.
            
            RESERVED
            
            
            47PART II5.
            
            MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER
      MATTERS ANDISSUER
      PURCHASES OF EQUITY SECURITIES
            
            
            486.
            
            SELECTED FINANCIAL DATA
            
            
            497.
            
            MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
      AND RESULTSOF
      OPERATIONS
            
            
            557A.
            
            QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
      RISK
            
            
            808.
            
            FINANCIAL STATEMENTS AND SUPPLEMENTARY
    DATA
            
            
            839.
            
            CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
      ANDFINANCIAL
      DISCLOSURE
            
            
            839A.
            
            CONTROLS AND PROCEDURES
            
            
            839B.
            
            OTHER INFORMATION
            
            
            84PART III10.
            
            DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE
      GOVERNANCE
            
            
            8511.
            
            EXECUTIVE COMPENSATION
            
            
            9012.
            
            SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
      MANAGEMENT ANDRELATED
      STOCKHOLDER MATTERS
            
            
            10613.
            
            CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND
      DIRECTOR INDEPENDENCE
            
            
            10814.
            
            PRINCIPAL ACCOUNTANT FEES AND SERVICES
            
            
            113PART IV15.
            
            EXHIBITS AND FINANCIAL STATEMENT
    SCHEDULES
            
            
            114








2





Part
I





CAUTIONARY
STATEMENT ABOUT FORWARD-LOOKING STATEMENTS





Targa
Resources Partners LP’s (together with its subsidiaries (“we”, “us”, or the
“Partnership”)) reports, filings and other public announcements may from time to
time contain statements that do not directly or exclusively relate to historical
facts. Such statements are “forward-looking statements” within the meaning of
the Private Securities Litigation Reform Act of 1995. You can typically identify
forward-looking statements by the use of forward-looking words, such as “may,”
“could,” “project,” “believe,” “anticipate,” “expect,” “estimate,” “potential,”
“plan,” “forecast” and other similar words.





All
statements that are not statements of historical facts, including statements
regarding our future financial position, business strategy, budgets, projected
costs and plans and objectives of management for future operations, are
forward-looking statements.





These
forward-looking statements reflect our intentions, plans, expectations,
assumptions and beliefs about future events and are subject to risks,
uncertainties and other factors, many of which are outside our control.
Important factors that could cause actual results to differ materially from the
expectations expressed or implied in the forward-looking statements include
known and unknown risks. Known risks and uncertainties include, but are not
limited to, the risks set forth in “Item 1A. Risk Factors” as well as the
following risks and uncertainties:





·
            our
      ability to access the debt and equity markets, which will depend on
      general market conditions and the credit ratings for our debt
      obligations;





·
            the
      amount of collateral required to be posted from time to time in our
      transactions;





·
            our
      success in risk management activities, including the use of derivative
      financial instruments to hedge commodity and interest rate
      risks;





·
            the
      level of creditworthiness of counterparties to
    transactions;





·
            changes
      in laws and regulations, particularly with regard to taxes, safety and
      protection of the environment;





·
            the
      timing and extent of changes in natural gas, natural gas liquids (“NGL”)
      and other commodity prices, interest rates and demand for our
      services;





·
            weather
      and other natural phenomena;





·
            industry
      changes, including the impact of consolidations and changes in
      competition;





·
            our
      ability to obtain necessary licenses, permits and other
      approvals;





·
            the
      level and success of oil and natural gas drilling around our assets, and
      our success in connecting natural gas supplies to our gathering and
      processing systems, and NGL supplies to our logistics and marketing
      facilities;





·
            our
      ability to grow through acquisitions or internal growth projects, and the
      successful integration and future performance of such
    assets;





·
            general
      economic, market and business conditions;
and





·
            the
      risks described elsewhere in this Annual Report on Form 10-K (“Annual
      Report”).





Although
we believe that the assumptions underlying our forward-looking statements are
reasonable, any of the assumptions could be inaccurate, and, therefore, we
cannot assure you that the forward-looking statements included in this Annual
Report will prove to be accurate. Some of these and other risks and
uncertainties that could cause





3
 Table of Contents





actual
results to differ materially from such forward-looking statements are more fully
described under the heading “Risk Factors” in this Annual Report. Except as may
be required by applicable law, we undertake no obligation to publicly update or
advise of any change in any forward-looking statement, whether as a result of
new information, future events or otherwise.





As
generally used in the energy industry and in this Annual Report the identified
terms have the following meanings:





Bbl
            Barrels
      (equal to 42 gallons)BBtu
            Billion
      British thermal unitsBtu
            British
      thermal units, a measure of heating value/d
            Per
      daygal
            GallonsMBbl
            Thousand
      barrelsMcf
            Thousand
      cubic feetMMBbl
            Million
      barrelsMMBtu
            Million
      British thermal unitsMMcf
            Million
      cubic feetNGL
            Natural
      gas liquid(s)Price
      Index DefinitionsIF-NGPL
      MC
            Inside
      FERC Gas Market Report, Natural Gas Pipeline,
  Mid-ContinentIF-Waha
            Inside
      FERC Gas Market Report, West Texas WahaNY-WTI
            NYMEX,
      West Texas Intermediate Crude OilOPIS-MB
            Oil
      Price Information Service, Mont Belvieu,
Texas








Item 1. Business





Overview





Targa
Resources Partners LP (NYSE: NGLS) is a Delaware limited partnership formed on
October 26, 2006 by our parent, Targa Resources, Inc. (“Targa”), a leading
provider of midstream natural gas and NGL services in the United States
(“U.S.”), to own, operate, acquire and develop a diversified portfolio of
complementary midstream energy assets. We are engaged in the business of
gathering, compressing, treating, processing and selling natural gas and
fractionating and selling NGLs and NGL products. Our gathering and processing
assets are located in the Fort Worth Basin/Bend Arch in North Texas, the Permian
Basin in West Texas and in Southwest Louisiana. Our NGL logistics and marketing
assets are located primarily at Mont Belvieu and Galena Park near Houston, Texas
and in Lake Charles, Louisiana, with terminals and transportation assets across
the U.S. Targa has additional assets located in the Permian Basin in West Texas
and Southeast New Mexico, and the offshore coastal region of
Louisiana.





Since our
formation, we have leveraged our relationship with Targa to achieve meaningful
growth in our business. In connection with our initial public offering (“IPO”)
in February 2007, Targa contributed the assets of the North Texas System located
in the Fort Worth Basin (the “North Texas System”) to us. In October 2007, we
acquired the assets of the San Angelo Operating Unit System located in the
Permian Basin (the “SAOU System”) and the assets of the Louisiana Operating Unit
System located in Southwest Louisiana (the “LOU System”) from Targa. In
September 2009, we acquired substantially all of Targa’s NGL Logistics and
Marketing division (the “Downstream Business”). We intend to continue to
leverage our relationship with Targa to acquire and construct additional
midstream energy assets and to utilize the significant experience of Targa’s
management team to execute our strategy.





Natural
Gas Gathering and Processing





Natural
gas gathering and processing consists of gathering, compressing, dehydrating,
treating, conditioning, processing, marketing and transporting natural gas and
NGLs. The gathering of natural gas consists of aggregating





4
 Table of Contents





natural
gas produced from various wells through small diameter gathering lines for
transportation to processing plants. Natural gas has a widely varying
composition, depending on the field, the formation and the reservoir from which
it is produced. The processing of natural gas consists of the extraction of
imbedded NGLs and the removal of water vapor, solids and other contaminants to
form (i) a stream of marketable natural gas, commonly referred to as
residue gas, and (ii) a stream of raw NGL mix, commonly referred to as
“Mixed NGLs” or “Y-grade.” Once processed, the residue gas is transported to
markets through pipelines that are either owned by the gatherers/processors or
third parties. End-users of residue gas include large commercial and industrial
customers, as well as natural gas and electric utilities serving individual
consumers. We sell our residue gas either directly to such end-users or to
marketers into intrastate or interstate pipelines, which are typically located
in close proximity or ready access to our facilities.





The
largest supplier of natural gas to our Natural Gas Gathering and Processing
division is ConocoPhillips Company (“ConocoPhillips”), representing 11% of
natural gas supply for 2009 and 2008.





NGL
Logistics and Marketing





NGL
logistics and marketing consists of the fractionation, storage, terminalling,
transportation, distribution and marketing of NGLs. Through fractionation, raw
NGL mix is separated into its component parts (ethane, propane, butanes and
natural gasoline). These component parts are delivered to end-users through
pipelines, barges, trucks and rail cars. End-users of component NGLs include
petrochemical and refining companies and propane markets for heating, cooking or
crop drying applications. Retail distributors often sell to end-use propane
customers.





Business
Strategies





Our
primary objective is to provide increasing cash distributions to our unitholders
over time. Our business strategies focus on creating and increasing value for
our unitholders through efficient operations, disciplined risk management and
prudent growth through organic projects and acquisitions.





The
successful execution of our business strategies is heavily dependent on our
ability to access the equity and debt capital markets as well as the general
health of the domestic and world economies. Given the recent challenging
conditions in the capital markets and the uncertain outlook for commodity
prices, we expect that growth opportunities will be subject to more stringent
evaluation criteria and that expenditure levels may moderate to preserve capital
if economic and financial market conditions deteriorate.





We intend
to accomplish our primary objective by executing the strategies described
below:





Enhance cash
flows. We intend
to continue to pursue new contracts, cost efficiencies and operating
improvements of our assets. Such improvements in the past have included new
production and acreage commitments, reducing gas fuel, flare and loss volumes
and enhancing NGL recoveries. We will also continue to enhance existing plant
assets to improve and maximize capacity and throughput.





Managing our
contract mix to optimize profitability. The majority of our gas
gathering and processing operating margin is generated pursuant to
percent-of-proceeds contracts or similar arrangements which, if unhedged,
benefit us in increasing commodity price environments and expose us to a
reduction in profitability in decreasing commodity price environments. We
believe that an appropriately managed contract mix allows us to optimize our
profitability over time. We expect to maintain primarily percent-of-proceeds
arrangements, owing to historical contract structures and the competitive
dynamics of our gathering areas. However, we continually evaluate the market for
attractive fee-based and other arrangements which will further reduce the
variability of our cash flows.





Capitalizing on
organic expansion opportunities. We continually evaluate
economically attractive organic expansion opportunities in existing or new areas
of operation that will allow us to expand our business.





Pursuing
strategic and accretive acquisitions. We plan to pursue strategic
and accretive acquisition opportunities within the midstream energy industry. We
will seek acquisitions in our existing areas of operation that provide the
opportunity for operational efficiencies, the potential for higher capacity
utilization and expansion of existing assets, acquisitions in other related
midstream businesses and/or expansion into new geographic areas of





5
 Table of Contents





operation
and, to the extent available, assets with fee-based arrangements. Among the
factors we will consider in deciding whether to acquire assets include, but are
not limited to, the economic characteristics of the acquisition (such as return
on capital and cash flow stability), the region in which the assets are located
(both regions contiguous to our areas of operation and other regions with
attractive characteristics) and the availability and sources of capital to
finance the acquisition. We intend to finance our expansion through a
combination of debt and equity, including commercial debt facilities and public
and private offerings of debt and equity securities. Recent disruptions in the
financial markets made obtaining equity or debt funding on acceptable terms more
difficult. Similar disruptions could limit our ability to successfully complete
acquisitions.





Leveraging our
relationship with Targa.Our relationship with
Targa provides us access to its extensive pool of operational, commercial and
risk management expertise which enables all of our strategies. In addition, we
intend to pursue acquisition opportunities as well as organic growth
opportunities with Targa and with Targa’s assistance. We may also acquire assets
or businesses directly from Targa, which will provide us access to an array of
growth opportunities broader than that available to many of our
competitors.





Competitive
Strengths





We
believe that we are well positioned to execute our primary business objective
and business strategies successfully because of the following competitive
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 U.S., will help
facilitate implementation of our acquisition strategy and other strategies.
Targa has indicated that it intends to use us as a growth vehicle to pursue the
acquisition and expansion of midstream natural gas, NGL and other complementary
energy businesses and assets and we expect to have the opportunity, but not the
obligation, to acquire such businesses and assets directly from Targa in the
future. Our relationship with Targa provides us access to its extensive pool of
operational, commercial and risk management expertise which enables all of our
strategies.





Significant scale
of operations.As of December 31, 2009, we had total net assets of
$2.2 billion. We own interests in or operate approximately 6,500 miles
of natural gas pipelines and approximately 750 miles of NGL pipelines, with
natural gas gathering systems covering approximately 13,500 square miles
and seven natural gas processing plants with access to natural gas supplies in
the Permian Basin, the Fort Worth Basin, the onshore region of the Louisiana
Gulf Coast and the Gulf of Mexico. Additionally, we have an integrated NGL
logistics and marketing business with net NGL fractionation capacity of
approximately 300 MBbl/d, 37 owned and operated storage wells with a net
storage capacity of approximately 65 MMBbl, and 15 storage, marine and
transport terminals with above ground NGL storage capacity of approximately
825 MBbl. Due to the high cost of obtaining permits for and constructing
midstream assets and the difficulty of developing the expertise necessary to
operate them, the barriers to enter the midstream natural gas sector on a scale
competitive with ours are high.





Multiple
producing basins.Our major gathering and processing systems source natural gas volumes
from three producing areas: the Permian Basin, the Fort Worth Basin and the
onshore region of the Louisiana Gulf Coast. In aggregate, these basins are a
significant contributor to current domestic natural gas production, favorably
positioning us to access large, diverse and important sources of domestic
natural gas supply.





Large and diverse
customer base.We focus on providing high-quality services at competitive costs, which
we believe has allowed us to attract and retain a large, diverse customer base.
Our customer base includes a large portfolio of natural gas producers in our
regions of operations as well as purchasers and consumers of NGLs. While we have
commercial relationships with large, diversified energy companies, we also
provide services to a number of other customers, which reduces our dependence on
any one customer. As of December 31, 2009, other than the Chevron Phillips
Chemical Company LLC joint venture (“CPC”), who accounts for approximately 17%
of our revenues, no single customer accounted for more than 10% of our
consolidated revenue. We expect to continue to strengthen and grow our customer
relationships due to our broad service offerings, well-positioned assets,
competitive cost of service, market access, and commitment to providing
high-quality customer service.





6
 Table of Contents





We have an ongoing
relationship with CPC for feedstock supply and services provided at Mont
Belvieu, Texas and Galena Park, Texas. Targa and CPC completed negotiations and
executed contracts to replace the previously terminated agreement with a new
feedstock and storage agreement effective September 1, 2009 for a term of five
years with evergreen language.





Broad service and
product offering.We offer a wide range of midstream natural gas gathering and processing
services and NGL logistics and marketing services. We believe the breadth and
scope of our assets allow us to attract customers due to our ability to deliver
products and services across the value chain and due to our well-positioned
assets and markets. We believe this breadth and asset positioning, combined with
our singular midstream focus, gives us a competitive advantage over other
midstream companies and divisions of larger companies. In addition, we believe
this diversity of assets and services diversifies cash flows by reducing our
dependency on any particular line of business.





Attractive
Cash Flow Characteristics





We
believe our strategy, combined with our high-quality asset portfolio and strong
industry fundamentals, allows us to generate attractive cash flows with the
ability to reduce our leverage of the business. Geographic, business and
customer diversity enhances our cash flow profile. Our Natural Gas Gathering and
Processing division has a favorable contract mix that is primarily
percent-of-proceeds or fee-based which, along with our long-term commodity
hedging program, serves to mitigate the impact of commodity price movements on
cash flow. In our NGL Logistics and Marketing division, the majority of our
revenues are derived under fee-based contracts.





We have
hedged the commodity price risk associated with a portion of our expected
natural gas, NGL and condensate equity volumes for the years 2010 through 2013
by entering into financially settled derivative transactions including swaps and
purchased puts (or floors). The primary purpose of our commodity risk management
activities is to hedge our exposure to price risk and to mitigate the impact of
fluctuations in commodity prices on cash flow. We have intentionally tailored
our hedges to approximate specific NGL products or baskets of NGL products and
to approximate our actual NGL and residue natural gas delivery points. We intend
to continue to manage our exposure to commodity prices in the future by entering
into similar hedge transactions as market conditions permit.





We also
monitor our inventory levels with a view to mitigating losses related to
downward price exposure.





Our
maintenance capital expenditures have averaged approximately $30.2 million
over the last three years. We believe that our assets are well maintained and
anticipate that a similar level of capital expenditures will be sufficient for
us to continue to operate these assets in a prudent and cost-effective
manner.





Asset
Base Well-Positioned for Organic Growth





We
believe our asset platform and strategic locations allow us to maintain and
potentially grow our volumes and related cash flows as our supply areas continue
to benefit from exploration and development. Generally, higher oil and gas
prices result in increased domestic oil and gas drilling and work over activity
to increase production. The location of our assets provides us with access to
stable natural gas supplies and proximity to end-use markets and liquid market
hubs while positioning us to capitalize on drilling and production activity in
those areas. Our existing infrastructure has the capacity to handle incremental
volumes without significant capital investments. We believe that as domestic
demand for natural gas and NGL grows over the long term, our infrastructure will
increase in value as such infrastructure takes on increasing importance in
meeting that demand.





While we
have set forth our strategies and competitive strengths above, our business
involves numerous risks and uncertainties which may prevent us from executing
our strategies or impact the amount of distributions to our unitholders. These
risks include the adverse impact of changes in natural gas, NGL and condensate
prices, our inability to access sufficient additional production to replace
natural declines in production and our dependence on a single natural gas
producer for a significant portion of our natural gas supply. For a more
complete description of the risks associated with an investment in us, see “Item
1A. Risk Factors.”





7
 Table of Contents





Targa has
indicated that it intends to use us as a growth vehicle to pursue the
acquisition and expansion of midstream natural gas, NGL and other complementary
energy businesses and assets. Over time, depending on our ability to access the
debt and equity markets, Targa intends to offer us the opportunity to purchase
substantially all of its remaining businesses, although it is not obligated to
do so. Targa constantly evaluates acquisitions and dispositions and may elect to
acquire or construct midstream assets in the future without offering us the
opportunity to purchase or construct those assets. Targa also may elect to
accept a third party offer for assets that have been offered to us. We cannot
say with any certainty which, if any, opportunities to acquire assets from Targa
may be made available to us or if we will choose to pursue any such opportunity.
Moreover, Targa is not prohibited from competing with us and routinely evaluates
acquisitions and dispositions that do not involve us. In addition, through our
relationship with Targa, we have access to a significant pool of management
talent, strong commercial relationships throughout the energy industry and
access to Targa’s broad operational, commercial, technical, risk management and
administrative infrastructure.





As of
February 1, 2010, Targa and its management have a significant interest in
our partnership through their ownership of a 30.0% limited partner interest and
a 2% general partner interest in us. In addition, Targa owns incentive
distribution rights that entitle Targa to receive an increasing percentage of
quarterly distributions of available cash from operating surplus after the
minimum quarterly distribution and the target distribution levels have been
achieved. We are party to an Omnibus Agreement with Targa that governs our
relationship regarding certain reimbursement and indemnification matters. See
“Item 13. Certain Relationships and Related Transactions, and Director
Independence—Omnibus Agreement.” In addition to carrying out operations, our
general partner and its affiliates, which are indirectly owned by Targa, employ
approximately 1,000 people, some of whom provide direct support to our
operations. We do not have any employees. See “Employees.”





While our
relationship with Targa is a significant advantage, it is also a source of
potential conflicts. For example, Targa is not restricted from competing with
us. Targa owns substantial midstream assets and may acquire, construct or
dispose of midstream or other assets in the future without any obligation to
offer us the opportunity to purchase or construct those assets. See “Item 13.
Certain Relationships and Related Transactions, and Director
Independence—Conflicts of Interest.”





Our
Business





We
conduct our business operations through two divisions and report our results of
operations under four segments: our Natural Gas Gathering and Processing
division is a single segment consisting of our natural gas gathering and
processing facilities, as well as certain fractionation capability integrated
within those facilities; and our NGL Logistics and Marketing division includes
three segments: Logistics Assets, NGL Distribution and Marketing, and Wholesale
Marketing.





Natural
Gas Gathering and Processing Division





We gather
and process natural gas from the Permian Basin in West Texas, the Fort Worth
Basin in North Texas, and the onshore region of the Louisiana Gulf Coast. The
natural gas we process is supplied through our gathering systems which, in
aggregate, consist of approximately 6,500 miles of natural gas pipelines.
Our processing plants include seven facilities that we own and operate. In 2009,
we processed an average of approximately 421 MMcf/d of natural gas and produced
an average of approximately 42 MBbl/d of NGLs.





We
continually seek new supplies of natural gas, both to offset the natural
declines in production from connected wells and to increase throughput volumes.
We obtain additional natural gas supply in our operating areas by contracting
for production from new wells or by capturing existing production currently
gathered by others. Competition for new natural gas supplies is based primarily
on location of assets, commercial terms, service levels and access to markets.
The commercial terms of natural gas gathering and processing arrangements are
driven, in part, by capital costs, which are impacted by the proximity of
systems to the supply source and by operating costs, which are impacted by
operational efficiencies and economies of scale.





We
believe our extensive asset base and scope of operations in the regions in which
we operate provide us with significant opportunities to add both new and
existing natural gas production to our systems. We believe our size and scope
give us a strong competitive position by placing us in proximity to a large
number of existing and new





8
 Table of Contents





natural
gas producing wells in our areas of operations, allowing us to generate
economies of scale and to provide our customers with access to our existing
facilities and to multiple end-use markets and market hubs. Additionally, we
believe our ability to serve our customers’ needs across the natural gas and NGL
value chain further augments our ability to attract new customers.





The
following table lists our natural gas processing plants, all of which are
cryogenic processing units that are 100% owned and operated by us:




Facility
            
            Location
            
            Gross
              Throughput
              Capacity
              (MMcf/d)
            
            
            2009
              Plant
              Natural
              Gas Inlet
              (MMcf/d)
            
            
            2009
              Gross NGL
              Production
              (MBbl/d)North
      Texas SystemChico
      (1)
            
            Wise,
      TX
            
            
            265.0Shackelford
            
            Shackelford,TX
            
            
            13.0Area
      Total
            
            
            278.0
            
            
            
            173.6
            
            
            
            20.1SAOU
      SystemMertzon
            
            Irion,
      TX
            
            
            48.0Sterling
            
            Sterling,
      TX
            
            
            62.0Conger
      (2)
            
            Sterling,
      TX
            
            
            25.0Area
      Total
            
            
            135.0
            
            
            
            91.5
            
            
            
            14.1LOU
      SystemGillis
      (1)
            
            Calcasieu,
      LA
            
            
            180.0Acadia
            
            Acadia,
      LA
            
            
            80.0Area
      Total
            
            
            260.0
            
            
            
            180.8
            
            
            
            8.5673.0
            
            
            
            445.9
            
            
            
            42.7




_______


(1)
            The
      Chico and Gillis plants have fractionation capacities of approximately 15
      MBbl/d and 13 MBbl/d.


(2)
            The
      Conger plant is not currently operating, but is on standby and can be
      quickly reactivated on short notice to meet additional needs for
      processing capacity.





North
Texas System





The North
Texas System includes two interconnected gathering systems with approximately
4,100 miles of pipelines, covering portions of 12 counties and
approximately 5,700 square miles, gathering wellhead natural gas for the Chico
and Shackelford natural gas processing facilities. During 2009, the North Texas
System gathered approximately 179.3 MMcf/d of natural gas.





Gathering. The Chico
Gathering System consists of approximately 2,000 miles of primarily
low-pressure gathering pipelines. Wellhead natural gas is either gathered for
the Chico plant located in Wise County, Texas, and then compressed for
processing, or it is compressed in the field at numerous compressor stations and
then moved via one of several high-pressure gathering pipelines to the Chico
plant. The Shackelford Gathering System consists of approximately
2,100 miles of intermediate-pressure gathering pipelines which gather
wellhead natural gas largely for the Shackelford plant in Albany, Texas. Natural
gas gathered from the northern and eastern portions of the Shackelford Gathering
System is typically compressed in the field at numerous compressor stations and
then transported to the Chico plant for processing.





Processing. The Chico
processing plant includes two cryogenic processing trains with a combined
capacity of approximately 265 MMcf/d and an NGL fractionator with the
capacity to fractionate up to approximately 15 MBbl/d of raw NGL mix. The
Shackelford plant is a cryogenic plant with a nameplate capacity of
approximately





9
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15 MMcf/d,
but effective capacity is limited to approximately 13 MMcf/d due to
capacity constraints on the residue gas pipeline that serves the
facility.





SAOU
System





Covering
portions of 10 counties and approximately 4,000 square miles in West Texas, the
SAOU System includes approximately 1,500 miles of pipelines in the Permian
Basin that gather natural gas to the Mertzon and Sterling plants. During 2009,
the system gathered approximately 99 MMcf/d of natural gas.





Gathering. The SAOU System is
connected to numerous producing wells and/or central delivery points. The system
has approximately 1,000 miles of low-pressure gathering systems and
approximately 500 miles of high-pressure gathering pipelines to deliver the
natural gas to our processing plants. The gathering system has
numerous compressor stations to inject low-pressure gas into the
high-pressure pipelines.





Processing. The SAOU System
includes two currently operating refrigerated cryogenic processing plants; the
Mertzon plant and the Sterling plant, which have an aggregate processing
capacity of approximately 110 MMcf/d. The system also includes the Conger
cryogenic plant with a capacity of approximately 25 MMcf/d, which is on
standby and can be quickly reactivated on short notice and minimal incremental
cost to meet additional needs for processing capacity.





LOU
System





The LOU
System consists of approximately 850 miles of gathering system pipelines,
covering approximately 3,800 square miles in Southwest Louisiana. During 2009,
the system gathered approximately 189.4 MMcf/d of natural gas, including
approximately 51.4 MMcf/d purchased from third party pipeline
systems.





Gathering. The LOU System is
connected to numerous producing wells and/or central delivery points in the area
between Lafayette and Lake Charles, Louisiana. The gathering system is a
high-pressure gathering system that delivers natural gas for processing to
either the Acadia or Gillis plants via three main trunk lines.





Processing. The LOU System
includes the Gillis and Acadia processing plants, both of which are cryogenic
plants. These processing plants have an aggregate processing capacity of
approximately 260 MMcf/d. In addition, the Gillis plant has integrated
fractionation with operating capacity of approximately 13 MBbl/d of
capacity.





NGL
Logistics and Marketing Division





Our NGL
Logistics and Marketing division uses our platform of integrated assets to
fractionate, store, terminal, transport, distribute and market NGLs typically
under fee-based and margin-based arrangements. For NGLs to be used by
refineries, petrochemical manufacturers, propane distributors and other
industrial end-users, they must be fractionated into their component products
and delivered to various points throughout the U.S. Our NGL logistics and
marketing assets are generally connected to and supplied, in part, by our
Natural Gas Gathering and Processing assets and are primarily located at Mont
Belvieu and Galena Park near Houston, Texas and in Lake Charles, Louisiana with
terminals and transportation assets across the U.S. We own or commercially
manage terminal assets in a number of states, including Texas, Louisiana,
Arizona, Nevada, California, Florida, Alabama, Mississippi, Tennessee, Kentucky
and New Jersey. The geographic diversity of our assets provides us direct access
to many NGL customers as well as markets via Targa trucks, barges, rail cars and
open-access regulated NGL pipelines owned by third parties.





Our NGL
Logistics and Marketing division consists of three segments: (i) Logistics
Assets, (ii) NGL Distribution and Marketing and (iii) Wholesale
Marketing. Our Logistics Assets segment includes the assets involved in the
fractionation, storage and transportation of NGLs. Our NGL Distribution and
Marketing segment markets our own NGL production and also purchases NGL products
from third parties for resale. Our Wholesale Marketing segment includes our
refinery services business and wholesale propane marketing
operations.








10
 Table of Contents





Logistics
Assets Segment





Fractionation.NGL
fractionation facilities separate raw NGL mix into discrete NGL products:
ethane, propane, butanes and natural gasoline. Raw NGL mix delivered from our
Natural Gas Gathering and Processing division represents the largest source of
volumes processed by our NGL fractionators.





The
majority of our NGL fractionation business is under fee-based arrangements.
These fees are subject to adjustment for changes in certain fractionation
expenses, including energy costs. The operating results of our NGL fractionation
business are dependent upon the volume of raw NGL mix fractionated and the level
of fractionation fees charged.





We
believe that sufficient volumes of raw NGL mix will be available for
fractionation in commercially viable quantities for the foreseeable future due
to increases in NGL production expected from shale plays in areas of the US that
include North Texas, South Texas, Oklahoma and the Rockies and certain other
basins accessed by pipelines to Mont Belvieu, as well as from continued
production of NGLs in areas such as the Permian Basin, Mid-Continent, South
Louisiana and shelf and deepwater Gulf of Mexico. Dew point specifications
implemented by individual pipelines and potentially enacted by the Federal
Energy Regulatory Commission (“FERC”) across the industry should result in
volumes of raw NGL mix available for fractionation because the natural gas will
require processing or conditioning to meet pipeline quality specifications.
These requirements could help to establish a base volume of raw NGL mix during
periods when it might be otherwise uneconomical to process certain sources of
natural gas. Furthermore, significant volumes of raw NGL mix are contractually
committed to our NGL fractionation facilities.





Although
competition for NGL fractionation services is primarily based on the
fractionation fee, the ability of an NGL fractionator to obtain raw NGL mix and
distribute NGL products is also an important competitive factor. This ability is
a function of the existence of the pipeline and storage infrastructure necessary
to conduct such operations. The location, scope and capability of our logistics
assets, including our transportation and distribution systems, give us access to
both substantial sources of raw NGL mix and a large number of end-use
markets.





The
following table details our fractionation facilities:





Facility
            
            %
              Owned
            
            
            Maximum Gross
              Capacity
              (MBbl/d)
            
            
            2009 Gross
              Throughput
              (MBbl/d)Operated
      Fractionation Facilities:Lake
      Charles Fractionator (Lake Charles, LA)
            
            
            100.0
            
            
            
            55.0
            
            
            
            27.5Cedar
      Bayou Fractionator (Mont Belvieu, TX) (1)
            
            
            88.0
            
            
            
            215.0
            
            
            
            189.7Gillis
      Plant Fractionators (Lake Charles, LA) (2)
            
            
            100.0
            
            
            
            13.0
            
            
            
            9.7Chico
      Plant Fractionator (Wise, TX) (2)
            
            
            100.0
            
            
            
            15.0
            
            
            
            13.0Equity
      Fractionation Facilities (non-operated):Gulf
      Coast Fractionators (Mont Belvieu, TX)
            
            
            38.8
            
            
            
            108.0
            
            
            
            104.4





_______


(1)      Includes
ownership through our 88% interest in Downstream Energy Ventures Co.,
LLC.


(2)      Included
in our Natural Gas Gathering and Processing division.




Our
fractionation assets include ownership interests in three stand-alone
fractionation facilities that are located on the Gulf Coast. We operate two of
the facilities, one at Mont Belvieu, Texas, and the other at Lake Charles,
Louisiana. We also have an equity investment in a third fractionator, Gulf Coast
Fractionators (“GCF”), also located at Mont Belvieu. We are subject to a consent
decree with the Federal Trade Commission, issued December 12, 1996, that,
among other things, prevents us from participating in commercial decisions
regarding rates paid by third parties for fractionation services at GCF. This
restriction on our activity at GCF will terminate on December 12, 2016,
twenty years after the date the consent order was issued.








11
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Storage and Terminalling.In
general, our storage assets provide warehousing of raw NGL mix, NGL products and
petrochemical products in underground wells, which allows for the injection and
withdrawal of such products at various times in order to meet demand cycles.
Similarly, our terminalling operations provide the inbound/outbound logistics
and warehousing of raw NGL mix, NGL products and petrochemical products in
above-ground storage tanks. Our underground storage and terminalling facilities
serve both single markets, such as propane, as well as multiple products and
markets. For example our Mont Belvieu and Galena Park facilities have extensive
pipeline connections for mixed NGL supply and delivery of component NGLs. In
addition, some of these facilities are connected to marine, rail and truck
loading and unloading facilities that provide services and products to our
customers. We provide long and short-term storage and terminalling services and
throughput capability to affiliates and third party customers for a
fee.





We own or
operate a total of 37 storage wells at our facilities with a net storage
capacity of approximately 67 MMBbl, the usage of which may be limited by
brine handling capacity, which is utilized to displace NGLs from storage. We
also have 15 terminal facilities (14 wholly owned) in Texas, Kentucky,
Mississippi, Tennessee, Louisiana, Florida, New Jersey and Arizona.





We
operate our storage and terminalling facilities based on the needs and
requirements of our customers in the NGL, petrochemical, refining, propane
distribution and other related industries. We usually experience an increase in
demand for storage and terminalling of mixed NGLs during the summer months when
gas plants typically reach peak NGL production, refineries have excess NGL
products and LPG imports are often highest. Demand for storage and terminalling
at our propane facilities typically peaks during fall, winter and early
spring.





Our
fractionation, storage and terminalling business are supported by approximately
800 miles of company-owned pipelines to transport mixed NGL and
specification products.





The
following tables detail our NGL storage and terminalling assets:





NGL Storage FacilitiesFacility
            
            %
              Owned
            
            County/Parish, State
            
            Number of
              Permitted
              Wells
            
            Gross Storage
              Capacity
              (MMBbl)Hackberry
      Storage (Lake Charles)
            
            100.0
            
            Cameron,
      LA
            
            
            12
            (1)
            20.0Mont
      Belvieu Storage
            
            
            100.0
            
            Chambers,
      TX
            
            
            20
            (2)
            42.4Easton
      Storage
            
            
            100.0
            
            Evangeline,
      LA
            
            
            2
            
            0.8Hattiesburg
      Storage
            
            
            50.0
            
            Forrest,
      MS
            
            
            3
            
            5.9


_______


(1)
            Five
      of the twelve owned wells are leased to Citgo Petroleum Corporation
      (“Citgo”) under a long-term lease.


(2)
            We
      own and operate 20 wells and operate an additional six wells owned by
      CPC.





12
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Terminal FacilitiesFacility
            
            %
              Owned
            
            County/Parish, State
            
            Description
            
            2009 Throughput
              (Million gallons)Galena
      Park Terminal
            
            
            100.0
            
            Harris,
      TX
            
            NGL
      import/export terminal
            
            
            1,269.0Calvert
      City Terminal
            
            
            100.0
            
            Marshall,
      KY
            
            Propane
      terminal
            
            
            43.1Greenville
      Terminal (1)
            
            
            100.0
            
            Washington,
      MS
            
            Marine
      propane terminal
            
            
            21.6Pt.
      Everglades Terminal
            
            
            100.0
            
            Broward,
      FL
            
            Marine
      propane terminal
            
            
            23.0Tyler
      Terminal
            
            
            100.0
            
            Smith,
      TX
            
            Propane
      terminal
            
            
            6.7Abilene
      Transport (2)
            
            
            100.0
            
            Taylor,
      TX
            
            Raw
      NGL transport terminal
            
            
            9.8Bridgeport
      Transport (2)
            
            
            100.0
            
            Jack,
      TX
            
            Raw
      NGL transport terminal
            
            
            75.9Gladewater
      Transport (2)
            
            
            100.0
            
            Gregg,
      TX
            
            Raw
      NGL transport terminal
            
            
            22.9Hammond
      Transport
            
            
            100.0
            
            Tangipahoa,
      LA
            
            Transport
      terminal
            
            
            33.1Chattanooga
      Terminal
            
            
            100.0
            
            Hamilton,
      TN
            
            Propane
      terminal
            
            
            19.5Mont
      Belvieu Terminal (3)
            
            
            100.0
            
            Chambers,
      TX
            
            Transport
      and storage terminal
            
            
            3,867.9Hackberry
      Terminal
            
            
            100.0
            
            Cameron,
      LA
            
            Storage
      terminal
            
            
            194.9Sparta
      Terminal
            
            
            100.0
            
            Sparta,
      NJ
            
            Propane
      terminal
            
            
            11.9Hattiesburg
      Terminal
            
            
            50.0
            
            Forrest,
      MS
            
            Propane
      terminal
            
            
            178.1Winona
      Terminal
            
            
            100.0
            
            Flagstaff,
      AZ
            
            Propane
      terminal
            
            
            3.3


_______


(1)      Volumes
reflect total import and export across the dock/terminal.


(2)      Volumes
reflect total transport and injection volumes.


(3)      Volumes
reflect total transport and terminal throughput volumes.





Transportation and
Distribution. Our NGL transportation and distribution infrastructure
includes a wide range of assets supporting both third party customers and the
delivery requirements of our marketing and asset management business. We provide
fee-based transportation services to refineries and petrochemical companies
throughout the Gulf Coast area. Our assets are also deployed to serve our
wholesale distribution terminals, fractionation facilities, underground storage
facilities and pipeline injection terminals. These distribution assets provide a
variety of ways to transport and deliver products to our customers.





Our
transportation assets, as of December 31, 2009, include:





·
            approximately
      850 railcars that we lease and
manage;





·
            approximately
      70 owned and leased transport tractors and approximately 100 company-owned
      tank trailers; and





·
            21
      company-owned pressurized NGL bargeswith more than
      320,000 barrels of capacity.





NGL
Distribution and Marketing Segment





In our
NGL Distribution and Marketing segment, we market our own NGL production and
also purchase component NGL products from other NGL producers and marketers for
resale. In 2009, our distribution and marketing services business sold an
average of approximately 245.7 MBbl/d of NGLs. In addition, Targa’s
gathering and processing business sold approximately 38.9 MBbl/d of NGLs to
Targa’s NGL Distribution and Wholesale Marketing businesses.





We
generally purchase raw NGL mix from producers at a monthly pricing index less
applicable fractionation, transportation and marketing fees and resell these
products to petrochemical manufacturers, refineries and other marketing and
retail companies. This is primarily a physical settlement business in which we
earn margins from purchasing and selling NGL products from producers under
contract. We also earn margins by purchasing and reselling NGL products in the
spot and forward physical markets. To effectively serve our customers in the NGL
Distribution and Marketing segment, we contract for and use many of the assets
included in our Logistics Assets segment.





13
 Table of Contents





Wholesale
Marketing Segment





Refinery Services. In our
refinery services business, we typically provide NGL balancing services in which
we have contractual arrangements with refiners to purchase and/or market propane
and to supply butanes. We also contract for and use the storage, transportation
and distribution assets included in our Logistics Assets segment to assist
refinery customers in managing their NGL product demand and production
schedules. This includes both feedstocks consumed in refinery processes and the
excess NGLs produced by those same refining processes. Under typical net-back
contracts, we generally retain a portion of the resale price of NGL sales or
receive a fixed minimum fee per gallon on products sold. Under net-back
contracts, fees are earned for locating and supplying NGL feedstocks to the
refineries based on a percentage of the cost to obtain such supply or a minimum
fee per gallon. In 2009, we bought and sold to third parties an average of
approximately 22 MBbl/d of NGLs through this refinery services
business.





Key
factors impacting the results of our refinery services business include
production volumes, prices of propane and butanes, as well as our ability to
perform receipt, delivery and transportation services in order to meet refinery
demand.





Wholesale Propane Marketing.Our wholesale propane marketing operations include primarily the sale of
propane and related logistics services to major multi-state retailers,
independent retailers and other end-users. Our propane supply primarily
originates from both our refinery/gas supply contracts and our other owned or
managed logistics and marketing assets. We generally sell propane at a fixed or
posted price at the time of delivery and, in some circumstances, we earn margin
on a net-back basis.





Our
wholesale propane marketing business is significantly impacted by weather-driven
demand, particularly in the winter, the price of propane in the markets we serve
and our ability to deliver propane to customers to satisfy peak winter
demand.





Operational
Risks and Insurance





We are
subject to all risks inherent in the midstream natural gas business. These risks
include, but are not limited to, explosions, fires, mechanical failure,
terrorist attacks, product spillage, weather, nature and inadequate maintenance
of rights-of-way and could result in damage to or destruction of operating
assets and other property, or could result in personal injury, loss of life or
polluting the environment, as well as curtailment or suspension of operations at
the affected facility. We maintain general public liability, property, boiler
and machinery and business interruption insurance in amounts that we consider to
be appropriate for such risks. Such insurance is subject to deductibles that we
consider reasonable and not excessive given the current insurance market
environment. The costs associated with these insurance coverages increased
significantly following Hurricanes Katrina and Rita in 2005. Insurance premiums,
deductibles and co-insurance requirements increased substantially, and terms
were generally less favorable than terms that were obtained prior to those
hurricanes. Insurance market conditions worsened again as a result of industry
losses including those sustained from Hurricanes Gustav and Ike in September
2008, and as a result of volatile conditions in the financial markets. As a
result, in 2009, we experienced further increases in deductibles and premiums,
and further reductions in coverage and limits.





The
occurrence of a significant event not fully insured or indemnified against, or
the failure of a party to meet its indemnification obligations, could materially
and adversely affect our operations and financial condition. While we currently
maintain levels and types of insurance that we believe to be prudent under
current insurance industry market conditions, our inability to secure these
levels and types of insurance in the future could negatively impact our business
operations and financial stability, particularly if an uninsured loss were to
occur. No assurance can be given that we will be able to maintain these levels
of insurance in the future at rates we consider commercially reasonable,
particularly named windstorm coverage and possibly contingent business
interruption coverage for our onshore operations.








14
 Table of Contents





Significant
Customers





The
following table lists the percentage of our consolidated sales with customers
that accounted for more than 10% of our consolidated revenues and consolidated
product purchases for the periods indicated:





2009
            
            
            2008
            
            
            2007%
      of consolidated revenuesCPC
            
            
            17%
            
            
            
            20%
            
            
            
            22%%
      of consolidated product purchasesLouis
      Dreyfus Energy Services L.P.
            
            
            12%
            
            
            
            9%
            
            
            
            7%








No other
customer or supplier accounted for more than 10% of our consolidated revenues or
consolidated product purchases during these periods.





Competition





We face
strong competition in acquiring new natural gas supplies. Competition for
natural gas supplies is primarily based on the location of gathering and
processing facilities, pricing arrangements, reputation, efficiency,
flexibility, reliability and access to end-use markets or liquid marketing hubs.
Competitors to our gathering and processing operations include other natural gas
gatherers and processors, such as major interstate and intrastate pipeline
companies, master limited partnerships and oil and gas producers. Our major
competitors for natural gas supplies in our current operating regions include
Atlas Gas Pipeline Company, Copano Energy, L.L.C. (“Copano”), WTG Gas Processing
L.P. (“WTG”), DCP Midstream Partners LP (“DCP”), Devon Energy Corp (“Devon”),
Enbridge Inc., GulfSouth Pipeline Company, LP, Hanlon Gas Processing, Ltd., J W
Operating Company, Louisiana Intrastate Gas and several other interstate
pipeline companies. Some of our competitors have greater financial resources
than we possess.





We also
compete for NGL products to market through our NGL Logistics and Marketing
division. Our competitors include major oil and gas producers who market NGL
products for their own account and for others. Additionally, we compete with
several other NGL marketing companies, including Enterprise Products Partners
L.P., TEPPCO Partners, L.P., DCP, ONEOK and BP p.l.c.





Additionally,
we face competition for raw NGL mix supplies at our fractionation facilities.
Our competitors include large oil, natural gas and petrochemical companies. The
fractionators in which we own an interest in the Mont Belvieu region compete for
volumes of raw NGL mix with other fractionators also located at Mont Belvieu.
Among the primary competitors are Enterprise Products Partners L.P. and ONEOK,
Inc. In addition, certain producers fractionate raw NGL mix for their own
account in captive facilities. Our Mont Belvieu fractionators also compete on a
more limited basis with fractionators in Conway, Kansas and a number of
decentralized, smaller fractionation facilities in Texas, Louisiana and New
Mexico. Our other fractionation facilities compete for raw NGL mix with the
fractionators at Mont Belvieu as well as other fractionation facilities located
in Louisiana. Our customers who are significant producers of raw NGL mix and NGL
products or consumers of NGL products may develop their own fractionation
facilities in lieu of using our services.




Regulation
of Operations





Regulation
of pipeline gathering and transportation services, natural gas sales and
transportation of NGLs may affect certain aspects of our business and the market
for our products and services.





Gathering
Pipeline Regulation





Our
natural gas gathering operations are typically subject to ratable take and
common purchaser statutes in the states in which we operate. The common
purchaser statutes generally require our gathering pipelines to purchase or take
without undue discrimination as to source of supply or producer. These statutes
are designed to prohibit discrimination in favor of one producer over another
producer or one source of supply over another. The regulations





15
 Table of Contents





under
these statutes can have the effect of imposing some restrictions on our ability
as an owner of gathering facilities to decide with whom we contract to gather
natural gas. The states in which we operate have adopted complaint-based
regulation of natural gas gathering activities, which allows natural gas
producers and shippers to file complaints with state regulators in an effort to
resolve grievances relating to gathering access and rate discrimination. The
rates we charge for gathering are deemed just and reasonable unless challenged
in a complaint. We cannot predict whether such a complaint will be filed against
us in the future. Failure to comply with state regulations can result in the
imposition of administrative, civil and criminal penalties.





Section
1(b) of the Natural Gas Act of 1938 (“NGA”), exempts natural gas gathering
facilities from regulation as a natural gas company by FERC under the NGA. We
believe that the natural gas pipelines in our gathering systems meet the
traditional tests FERC has used to establish a pipeline’s status as a gatherer
not subject to regulation as a natural gas company. However, the distinction
between FERC-regulated transmission services and federally unregulated gathering
services is the subject of substantial, on-going litigation, so the
classification and regulation of our gathering facilities are subject to change
based on future determinations by FERC, the courts or Congress. Natural gas
gathering may receive greater regulatory scrutiny at both the state and federal
levels. Our natural gas gathering operations could be adversely affected should
they be subject to more stringent application of state or federal regulation of
rates and services. Additional rules and legislation pertaining to these matters
are considered or adopted from time to time. We cannot predict what effect, if
any, such changes might have on our operations, but the industry could be
required to incur additional capital expenditures and increased costs depending
on future legislative and regulatory changes.





In 2007,
Texas enacted new laws regarding rates, competition and confidentiality for
natural gas gathering and transmission pipelines (“Competition Statute”) and new
informal complaint procedures for challenging determinations of lost and
unaccounted for gas by gas gatherers, processors and transporters (“LUG
Statute”). The Competition Statute gives the Railroad Commission of Texas
(“RRC”) the ability to use either a cost-of-service method or a market-based
method for setting rates for natural gas gathering and transportation pipelines
in formal rate proceedings. This statute also gives the RRC specific authority
to enforce its statutory duty to prevent discrimination in natural gas gathering
and transportation, to enforce the requirement that parties participate in an
informal complaint process and to punish purchasers, transporters, and gatherers
for taking discriminatory actions against shippers and sellers. The Competition
Bill also provides producers with the unilateral option to determine whether or
not confidentiality provisions are included in a contract to which a producer is
a party for the sale, transportation, or gathering of natural gas. The LUG
Statute modifies the informal complaint process at the RRC with procedures
unique to lost and unaccounted for gas issues. Such statute also extends the
types of information that can be requested and provides the RRC with the
authority to make determinations and issue orders in specific situations. We
cannot predict what effect, if any, these statutes might have on our future
operations in Texas.





Intrastate
Pipeline Regulation





Though
our natural gas intrastate pipelines are not subject to regulation by FERC as
natural gas companies under the NGA, our intrastate pipelines may be subject to
certain FERC-imposed daily scheduled flow and capacity posting requirements
depending on the volume of flows in a given period and the design capacity of
the pipelines’ receipt and delivery meters. See “Other Federal Laws and
Regulation Affecting Our Industry–FERC Market Transparency Rules.”





Our Texas
intrastate pipeline, Targa Intrastate Pipeline LLC (“Targa Intrastate”), owns
the intrastate pipeline that transports natural gas from our Shackelford
processing plant to an interconnect with Atmos Pipeline-Texas that in turn
delivers gas to the West Texas Utilities Company’s Paint Creek Power Station.
Targa Intrastate also owns a 1.65 mile, 10 inch diameter intrastate
pipeline that transports natural gas from a third party gathering system into
the Chico System in Denton County, Texas. Targa Intrastate is a gas utility
subject to regulation by the RRC and has a tariff on file with such
agency.





Our
Louisiana intrastate pipeline, Targa Louisiana Intrastate LLC (“TLI”) owns an
approximately 60-mile intrastate pipeline system that receives all of the
natural gas it transports within or at the boundary of the State of Louisiana.
Because all such gas ultimately is consumed within Louisiana, and since the
pipeline’s rates and terms of service are subject to regulation by the Office of
Conservation of the Louisiana Department of Natural Resources (“DNR”), the
pipeline qualifies as a Hinshaw pipeline under Section 1(c) of the NGA and thus
is exempt from full





16
 Table of Contents





FERC
regulation. On July 16, 2009, FERC issued a Notice of Proposed Rulemaking
(“NOPR”) seeking comment on proposed rules imposing additional posting and
reporting requirements on Hinshaw pipelines providing interstate service under
limited blanket certificates and intrastate pipelines providing interstate
service under Section 311 of the Natural Gas Policy Act (“NGPA”). If FERC issues
a final rule based on the NOPR, it would not cover TLI as currently written, as
TLI only provides service governed by the Hinshaw amendment. TLI does not
provide interstate service pursuant to any limited blanket certificate. FERC has
not yet issued a final rule, and we cannot predict the final rules FERC will
promulgate as a result of the NOPR or the ultimate impact of any such regulatory
changes to our Hinshaw pipeline.





Texas and
Louisiana have adopted complaint-based regulation of intrastate natural gas
transportation activities, which allows natural gas producers and shippers to
file complaints with state regulators in an effort to resolve grievances
relating to pipeline access and rate discrimination. The rates we charge for
intrastate transportation are deemed just and reasonable unless challenged in a
complaint. We cannot predict whether such a complaint will be filed against us
in the future. Failure to comply with state regulations can result in the
imposition of administrative, civil and criminal penalties.





Regulation of our NGL intrastate
pipelines





Our
intrastate NGL pipelines in Louisiana gather raw NGL streams that we own from
processing plants in Louisiana and deliver such streams to our Gillis
fractionator in Lake Charles, Louisiana, where the raw NGL streams are
fractionated into various products. We deliver such refined products (ethane,
propane, butanes and natural gasoline) out of our fractionator to and from
Targa-owned storage, to other third party facilities and to various third party
pipelines in Louisiana. These pipelines are not subject to FERC regulation or
rate regulation by the DNR, but are regulated by United States Department of
Transportation (“DOT”) safety regulations.





Natural
Gas Processing





Our
natural gas gathering and processing operations are not presently subject to
FERC regulation. However, starting in May 2009 we were required to report to
FERC information regarding natural gas sale and purchase transactions for some
of our operations depending on the volume of natural gas transacted during the
prior calendar year. See “Other Federal Laws and Regulation Affecting Our
Industry–FERC Market Transparency Rules.” There can be no assurance that our
processing operations will continue to be exempt from other FERC regulation in
the future.





Availability,
Terms and Cost of Pipeline Transportation





Our
processing facilities and our marketing of natural gas and NGLs are affected by
the availability, terms and cost of pipeline transportation. The price and terms
of access to pipeline transportation can be subject to extensive federal and, if
a complaint is filed, state regulation. FERC is continually proposing and
implementing new rules and regulations affecting the interstate transportation
of natural gas, and to a lesser extent, the interstate transportation of NGLs.
These initiatives also may indirectly affect the intrastate transportation of
natural gas and NGLs under certain circumstances. We cannot predict the ultimate
impact of these regulatory changes to our processing operations and our natural
gas and NGL marketing operations. We do not believe that we would be affected by
any such FERC action materially differently than other natural gas processors
and natural gas and NGL marketers with whom we compete.





The
ability of our processing facilities and pipelines to deliver natural gas into
third party natural gas pipeline facilities is directly impacted by the gas
quality specifications required by those pipelines. In 2006, FERC issued a
policy statement on provisions governing gas quality and interchangeability in
the tariffs of interstate gas pipeline companies and a separate order declining
to set generic prescriptive national standards. FERC strongly encouraged all
natural gas pipelines subject to its jurisdiction to adopt, as needed, gas
quality and interchangeability standards in their FERC gas tariffs modeled on
the interim guidelines issued by a group of industry representatives, headed by
the Natural Gas Council (“NGC+ Work Group”), or to explain how and why their
tariff provisions differ. We do not believe that the adoption of the NGC+ Work
Group’s gas quality interim guidelines by a pipeline that either directly or
indirectly interconnects with our facilities would materially affect our
operations. We have no way to predict,





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however,
whether FERC will approve of gas quality specifications that materially differ
from the NGC+ Work Group’s interim guidelines for such an interconnecting
pipeline.





Sales
of Natural Gas and NGLs





The price
at which we buy and sell natural gas and NGLs is currently not subject to
federal rate regulation and, for the most part, is not subject to state
regulation. However, with regard to our physical purchases and sales of these
energy commodities and any related hedging activities that we undertake, we are
required to observe anti-market manipulation laws and related regulations
enforced by FERC and/or the Commodity Futures Trading Commission (“CFTC”). See
“Other Federal Laws and Regulation Affecting Our Industry–Energy Policy Act of
2005.” Starting May 1, 2009, we were required to report to FERC information
regarding natural gas sale and purchase transactions for some of our operations
depending on the volume of natural gas transacted during the prior calendar
year. See “Other Federal Laws and Regulation Affecting Our Industry–FERC Market
Transparency Rules.” Should we violate the anti-market manipulation laws and
regulations, we could also be subject to related third party damage claims by,
among others, market participants, sellers, royalty owners and taxing
authorities.





Other
State and Local Regulation of Our Operations





Our
business activities are subject to various state and local laws and regulations,
as well as orders of regulatory bodies pursuant thereto, governing a wide
variety of matters, including marketing, production, pricing, community
right-to-know, protection of the environment, safety and other matters. For
additional information regarding the potential impact of federal, state or local
regulatory measures on our business, see “Item 1A. Risk Factors—Risks Related to
Our Business.”





Interstate
common carrier liquids pipeline regulation





As part
of the Downstream Business acquired from Targa on September 24, 2009, we
acquired Targa NGL Pipeline Company LLC (“Targa NGL”). Targa NGL is an
interstate NGL common carrier subject to regulation by FERC under the Interstate
Commerce Act (“ICA”). Targa NGL owns a twelve inch diameter pipeline that runs
between Lake Charles, Louisiana and Mont Belvieu, Texas. This pipeline can move
mixed NGLs and purity NGL products. Targa NGL also owns an eight inch diameter
pipeline and a 20 inch diameter pipeline, each of which run between Mont
Belvieu, Texas and Galena Park, Texas. The eight inch and the 20 inch pipelines
are part of an extensive mixed NGL and purity NGL pipeline receipt and delivery
system that provides services to domestic and foreign import and export
customers. The ICA requires that we maintain tariffs on file with FERC for each
of these pipelines. Those tariffs set forth the rates we charge for providing
transportation services as well as the rules and regulations governing these
services. The ICA requires, among other things, that rates on interstate common
carrier pipelines be “just and reasonable” and non-discriminatory. All shippers
on this pipeline are our affiliates.





Other
Federal Laws and Regulation Affecting Our Industry





Energy
Policy Act of 2005





The
Domenici-Barton Energy Policy Act of 2005 (“EP Act 2005”) is a comprehensive
compilation of tax incentives, authorized appropriations for grants and
guaranteed loans, and significant changes to the statutory policy that affects
all segments of the energy industry. Among other matters, EP Act 2005 amends the
NGA to add an anti- market manipulation provision which makes it unlawful for
any entity to engage in prohibited behavior to be prescribed by FERC, and
furthermore provides FERC with additional civil penalty authority. The EP Act
2005 provides FERC with the power to assess civil penalties of up to
$1 million per day for violations of the NGA and $1 million per
violation per day for violations of the NGPA. The civil penalty provisions are
applicable to entities that engage in the sale of natural gas for resale in
interstate commerce. In 2006, FERC issued Order 670 to implement the anti-market
manipulation provision of EP Act 2005. Order 670 makes it unlawful to:
(1) in connection with the purchase or sale of natural gas subject to the
jurisdiction of FERC, or the purchase or sale of transportation services subject
to the jurisdiction of FERC, for any entity, directly or indirectly, to use or
employ any device, scheme or artifice to defraud; (2) to make any untrue
statement of material fact or omit any statement necessary to make the
statements made not misleading; or (3) to engage in any act or practice
that operates as a fraud or deceit upon any person. Order 670 does not apply to
activities that relate only to intrastate or other





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non-jurisdictional
sales or gathering, but does apply to activities of gas pipelines and storage
companies that provide interstate services, as well as otherwise
non-jurisdictional entities to the extent the activities are conducted “in
connection with” gas sales, purchases or transportation subject to FERC
jurisdiction, which now includes the annual reporting requirements under a final
rule on the annual natural gas transaction reporting requirements, as amended by
subsequent orders on rehearing (Order 704) and the daily schedule flow and
capacity posting requirements under Order 720. The anti-market manipulation
rule and enhanced civil penalty authority reflect an expansion of FERC’s NGA
enforcement authority.





FERC
Standards of Conduct for Transmission Providers





On
October 16, 2008, FERC issued new standards of conduct for transmission
providers (Order 717) to regulate the manner in which interstate natural gas
pipelines may interact with their marketing affiliates based on an employee
separation approach. A “Transmission Provider” includes an interstate natural
gas pipeline that provides open access transportation pursuant to FERC’s
regulations. Under these rules, a Transmission Provider’s transmission function
employees (including the transmission function employees of any of its
affiliates) must function independently from the Transmission Provider’s
marketing function employees (including the marketing function employees of any
of its affiliates). FERC clarified on October 15, 2009 in a rehearing
order, Order 717-A, however, that if a Hinshaw pipeline affiliated with a
Transmission Provider engages in off-system sales of gas that has been
transported on the Transmission Provider’s affiliated pipeline, then the
Transmission Provider and the Hinshaw pipeline (which is engaging in marketing
functions) will be required to observe the Standards of Conduct by, among other
things, having the marketing function employees function independently from the
transmission function employees. Our only Hinshaw pipeline, TLI, does not engage
in any off-system sales of gas that have been transported on an affiliated
Transmission Provider, and we do not believe that our operations will be
affected by the new standards of conduct. FERC further clarified Order 717-A in
a rehearing order, Order 717-B, on November 16, 2009. However Order 717-B
did not substantively alter the rules promulgated under Orders 717 and 717-A.
Requests for rehearing of Order 717-B have been filed and are currently pending
before FERC. We have no way to predict with certainty whether and to what extent
FERC will revise the new standards of conduct in response to those requests for
rehearing.





FERC
Market Transparency Rules





In 2007,
FERC issued Order 704, whereby wholesale buyers and sellers of more than
2.2 BBtu of physical natural gas in the previous calendar year, including
interstate and intrastate natural gas pipelines, natural gas gatherers, natural
gas processors and natural gas marketers, are now required to report, on
May 1 of each year, beginning in 2009, aggregate volumes of natural gas
purchased or sold at wholesale in the prior calendar year to the extent such
transactions utilize, contribute to, or may contribute to the formation of price
indices. It is the responsibility of the reporting entity to determine which
transactions should be reported based on the guidance of Order 704.





On
November 20, 2008, FERC issued a final rule on daily scheduled flows and
capacity posting requirements (Order 720). Under Order 720, certain
non-interstate pipelines delivering, on an annual basis, more than an average of
50 BBtu of gas over the previous three calendar years, are required to post
daily certain information regarding the pipeline’s capacity and scheduled flows
for each receipt and delivery point that has a design capacity equal to or
greater than 15,000 MMBtu/d. In response to requests for clarification and
rehearing, FERC issued Order 720-A on January 21, 2010, which clarified certain
of the rules promulgated under Order 720 and established July 1, 2010 as
the deadline for applicable major non-interstate pipelines to meet the daily
posting requirement. A petition for review of Orders 720 and 720-A has been
filed and is currently pending before the Court of Appeals for the Fifth
Circuit. A petition for review of Orders 720 and 720-A has been filed and is
currently pending before the Court of Appeals for the Fifth Circuit, and
requests for rehearing of Order 720-A are currently pending before the FERC. As
currently written, the reporting requirement under Order 720, as clarified by
Order 720-A, does not apply to us. We have no way to predict with certainty
whether and to what extent Orders 720 and 720-A may be modified as a result of
the petition for review or the requests for rehearing.





Additional
proposals and proceedings that might affect the natural gas industry are pending
before Congress, FERC and the courts. We cannot predict the ultimate impact of
these or the above regulatory changes to our natural





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gas
operations. We do not believe that we would be affected by any such FERC action
materially differently than other midstream natural gas companies with whom we
compete.





Environmental,
Health and Safety Matters





General





Our
operations are subject to stringent and complex federal, state and local laws
and regulations pertaining to health, safety and the environment. For more
information on our operations, see “Item 1. Business—Our Business”. As with the
industry generally, compliance with current and anticipated environmental laws
and regulations increases our overall cost of business, including our capital
costs to construct, maintain and upgrade equipment and facilities. These laws
and regulations may, among other things, require the acquisition of various
permits to conduct regulated activities, require the installation of pollution
control equipment or otherwise restrict the way we can handle or dispose of our
wastes; limit or prohibit construction activities in sensitive areas such as
wetlands, wilderness areas or areas inhabited by endangered or threatened
species; require investigatory and remedial action to mitigate pollution
conditions caused by our operations or attributable to former operations; and
enjoin some or all of the operations of facilities deemed in non-compliance with
permits issued pursuant to such environmental laws and regulations. Failure to
comply with these laws and regulations may result in assessment of
administrative, civil and criminal penalties, the imposition of removal or
remedial obligations and the issuance of injunctions limiting or prohibiting our
activities.





We have
implemented programs and policies designed to keep our pipelines, plants and
other facilities in compliance with existing environmental laws and regulations.
The clear trend in environmental regulation, however, is to place more
restrictions and limitations on activities that may affect the environment and
thus, any changes in environmental laws and regulations or re-interpretation of
enforcement policies that result in more stringent and costly waste handling,
storage, transport, disposal or remediation requirements could have a material
adverse effect on our operations and financial position. We may be unable to
pass on such increased compliance costs to our customers. Moreover, accidental
releases or spills may occur in the course of our operations and we cannot
assure you that we will not incur significant costs and liabilities as a result
of such releases or spills, including any third party claims for damage to
property, natural resources or persons. While we believe that we are in
substantial compliance with existing environmental laws and regulations and that
continued compliance with current requirements would not have a material adverse
effect on us, there is no assurance that the current conditions will continue in
the future.





The
following is a summary of the more significant existing environmental, health
and safety laws and regulations to which our business operations are subject and
for which compliance may have a material adverse impact on our capital
expenditures, results of operations or financial position.





Hazardous
Substances and Waste





The
Federal Comprehensive Environmental Response, Compensation and Liability Act of
1980, as amended, (“CERCLA” or the “Superfund” law) and comparable state laws
impose liability without regard to fault or the legality of the original
conduct, on certain classes of persons who are considered to be responsible for
the release of a “hazardous substance” into the environment. These persons
include current and prior owners or operators of the site where the release
occurred and entities that disposed or arranged for the disposal of the
hazardous substances found at the site. Under CERCLA, these “responsible
persons” may be subject to joint and several, strict liability for the costs of
cleaning up the hazardous substances that have been released into the
environment, for damages to natural resources and for the costs of certain
health studies. CERCLA also authorizes the federal Environmental Protection
Agency (“EPA”) and, in some instances, third parties to act in response to
threats to the public health or the environment and to seek to recover from the
responsible classes of persons the costs they incur. It is not uncommon for
neighboring landowners and other third parties to file claims for personal
injury and property damage allegedly caused by the release of hazardous
substances or other pollutants into the environment. We generate materials in
the course of our operations that are regulated as “hazardous substances” under
CERCLA or similar state statutes and, as a result, may be jointly and severally
liable under CERCLA or such statutes for all or part of the costs required to
clean up sites at which these hazardous substances have been released into the
environment.





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We also
generate solid wastes, including hazardous wastes that are subject to the
requirements of the Federal Resource Conservation and Recovery Act, as amended
(“RCRA”) and comparable state statutes. While RCRA regulates both solid and
hazardous wastes, it imposes strict requirements on the generation, storage,
treatment, transportation and disposal of hazardous wastes. In the course of our
operations we generate petroleum product wastes and ordinary industrial wastes
such as paint wastes, waste solvents and waste compressor oils that are
regulated as hazardous wastes. Certain materials generated in the exploration,
development or production of crude oil and natural gas are excluded from RCRA’s
hazardous waste regulations. However, it is possible that future changes in law
or regulation could result in these wastes, including wastes currently generated
during our operations, being designated as “hazardous wastes” and therefore
subject to more rigorous and costly disposal requirements. Any such changes in
the laws and regulations could have a material adverse effect on our capital
expenditures and operating expenses as well as those of the oil and gas industry
in general.





We
currently own or lease and have in the past owned or leased, properties that for
many years have been used for midstream natural gas and NGL activities. Although
we have utilized operating and disposal practices that were standard in the
industry at the time, hydrocarbons or other wastes may have been disposed of or
released on or under the properties owned or leased by us or on or under the
other locations where these hydrocarbons and wastes have been taken for
treatment or disposal. In addition, certain of these properties have been
operated by third parties whose treatment and disposal or release of
hydrocarbons or other wastes was not under our control. These properties and
wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws.
Under these laws, we could be required to remove or remediate previously
disposed wastes (including wastes disposed of or released by prior owners or
operators), to clean up contaminated property (including contaminated
groundwater) and to perform remedial operations to prevent future contamination.
We are not currently aware of any facts, events or conditions relating to such
requirements that could materially impact our operations or financial
condition.





Air
Emissions





The Clean
Air Act, as amended, and comparable state laws and regulations restrict the
emission of air pollutants from many sources, including processing plants and
compressor stations and also impose various monitoring and reporting
requirements. These laws and regulations may require us to obtain pre-approval
for the construction or modification of certain projects or facilities expected
to produce or significantly increase air emissions, obtain and strictly comply
with stringent air permit requirements or utilize specific equipment or
technologies to control emissions. We are currently reviewing the air emissions
monitoring systems at certain of our facilities. We may be required to incur
capital expenditures in the next few years to implement various air emissions
leak detection and monitoring programs as well as to install air pollution
control equipment or non-ambient storage tanks as a result of our review or in
connection with maintaining, amending or obtaining operating permits and
approvals for air emissions. We currently believe, however, that such
requirements will not have a material adverse affect on our
operations.





Climate
Change





In
response to concerns suggesting that emissions of certain gases, commonly
referred to as greenhouse gases (“GHGs”) (including carbon dioxide (“CO2”) and
methane), are contributing to the warming of the Earth’s atmosphere and other
climatic changes, the United States Congress has been considering legislation to
reduce such emissions. In addition, more than one-third of the states, either
individually or through multi-state regional initiatives, already have begun
implementing legal measures to reduce emissions of GHGs, primarily through the
planned development of greenhouse gas emission inventories and/or greenhouse gas
cap and trade programs. As an alternative to cap and trade programs, Congress
may consider the implementation of a carbon tax program. The cap and trade
programs could require major sources of emissions, such as electric power
plants, or major producers of fuels, such as refineries or NGL fractionation
plants, to acquire and surrender emission allowances. Depending on the
particular program, we could be required to purchase and surrender allowances,
either for GHG emissions resulting from our operations (e.g., compressor
stations) or from combustion of fuels (e.g., NGLs) we process. Depending on the
design and implementation of carbon tax programs, our operations could face
additional taxes and higher cost of doing business. Although we would not be
impacted to a greater degree than other similarly situated gatherers and
processors of natural gas or NGLs, a stringent GHG control program could have an
adverse effect on our cost of doing business and could reduce demand for the
natural gas and NGLs we gather and process.





21
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On
December 15, 2009, the EPA issued a notice of its final finding and
determination that emissions of CO2, methane,
and other GHGs present an endangerment to public health and the environment
because emissions of such gases contribute to warming of the earth’s atmosphere
and other climatic changes. This final finding and determination allows the EPA
to begin regulating GHG emissions under existing provisions of the Clean Air
Act. Consequently, the EPA has proposed regulations that would require a
reduction in emissions of GHGs from motor vehicles and could trigger permit
review for GHG emissions from certain stationary sources. In addition, on
October 30, 2009, the EPA issued a final rule requiring the reporting of
GHG emissions from specified large GHG emission sources in the U.S., including
NGL fractionators, beginning in 2011 for emissions occurring in 2010. Although
it is not possible at this time to predict how legislation or new regulations
that may be adopted to address GHG emissions would impact our business, any such
new federal, state or regional restrictions on emissions of CO2 that may
be imposed in areas in which we conduct business could also have an adverse
affect on our cost of doing business and demand for the natural gas and NGLs we
gather and process.





Water
Discharges





The
Federal Water Pollution Control Act, as amended (“Clean Water Act” or “CWA”),
and analogous state laws impose restrictions and strict controls regarding the
discharge of pollutants into navigable waters. Pursuant to the CWA and analogous
state laws, permits must be obtained to discharge pollutants into state waters
or waters of the U.S. Any such discharge of pollutants into regulated waters
must be performed in accordance with the terms of the permit issued by the EPA
or the analogous state agency. Spill prevention, control and countermeasure
requirements under federal law require appropriate containment berms and similar
structures to help prevent the contamination of navigable waters in the event of
a petroleum hydrocarbon tank spill, rupture or leak. In addition, the CWA and
analogous state laws require individual permits or coverage under general
permits for discharges of storm water runoff from certain types of facilities.
These permits may require us to monitor and sample the storm water runoff. The
CWA and analogous state laws can impose substantial civil and criminal penalties
for non-compliance including spills and other non-authorized
discharges.





The Oil
Pollution Act of 1990, as amended (“OPA”), which amends the CWA, establishes
strict liability for owners and operators of facilities that are the site of a
release of oil into waters of the United States. OPA and its associated
regulations impose a variety of requirements on responsible parties related to
the prevention of oil spills and liability for damages resulting from such
spills. A “responsible party” under OPA includes owners and operators of onshore
facilities, such as our plants and our pipelines. Under OPA, owners and
operators of facilities that handle, store, or transport oil are required to
develop and implement oil spill response plans, and establish and maintain
evidence of financial responsibility sufficient to cover liabilities related to
an oil spill for which such parties could be statutorily responsible. We believe
that we are in substantial compliance with the CWA, OPA and analogous state
laws.





Endangered
Species Act





The
federal Endangered Species Act, as amended (“ESA”), restricts activities that
may affect endangered or threatened species or their habitats. While some of our
facilities may be located in areas that are designated as habitat for endangered
or threatened species, we believe that we are in substantial compliance with the
ESA. However, the designation of previously unidentified endangered or
threatened species could cause us to incur additional costs or become subject to
operating restrictions or bans in the affected areas.





Pipeline
Safety





The
pipelines we use to gather and transport natural gas and transport NGLs are
subject to regulation by the DOT under the Natural Gas Pipeline Safety Act of
1968, as amended (“NGPSA”), with respect to natural gas and the Hazardous
Liquids Pipeline Safety Act of 1979, as amended (“HLPSA”), with respect to crude
oil, NGLs and condensates. The NGPSA and HLPSA govern the design, installation,
testing, construction, operation, replacement and management of natural gas and
NGL pipeline facilities. Pursuant to these acts, the DOT has promulgated
regulations governing pipeline wall thickness, design pressures, maximum
operating pressures, pipeline patrols and leak surveys, minimum depth
requirements, and emergency procedures, as well as other matters intended to
ensure adequate protection for the public and to prevent accidents and failures.
Where applicable, the NGPSA and HLPSA require any entity that owns or operates
pipeline facilities to comply with the regulations under these acts, to
permit





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access to
and allow copying of records and to make certain reports and provide information
as required by the Secretary of Transportation. We believe that our pipeline
operations are in substantial compliance with applicable NGPSA and HLPSA
requirements; however, due to the possibility of new or amended laws and
regulations or reinterpretation of existing laws and regulations, future
compliance with the NGPSA and HLPSA could result in increased
costs.





Our
pipelines are also subject to regulation by the DOT under the Pipeline Safety
Improvement Act of 2002, which was amended by the Pipeline Inspection,
Protection, Enforcement, and Safety Act of 2006 (“PIPES Act”). The DOT, through
the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) has
established a series of rules, which require pipeline operators to develop and
implement integrity management programs for gas transmission pipelines that, in
the event of a failure, could affect “high consequence areas.” “High consequence
areas” are currently defined as areas with specified population densities,
buildings containing populations of limited mobility and areas where people
gather that are located along the route of a pipeline. Similar rules are also in
place for operators of hazardous liquid pipelines including lines transporting
NGLs and condensates.





In
addition, states have adopted regulations, similar to existing DOT regulations,
for intrastate gathering and transmission lines. Texas and Louisiana have
developed regulatory programs that parallel the federal regulatory scheme and
are applicable to intrastate pipelines transporting natural gas and NGLs. We
currently estimate an annual average cost of $1.7 million for years 2010
through 2012 to perform necessary integrity management program testing on our
pipelines required by existing DOT and state regulations. This estimate does not
include the costs, if any, of any repair, remediation, preventative or
mitigating actions that may be determined to be necessary as a result of the
testing program, which costs could be substantial. However, we do not expect
that any such costs would be material to our financial condition or results of
operations.





More
recently, on December 3, 2009, the PHMSA issued a final rule mandated by
the PIPES Act focusing on how human interactions of control room personnel, such
as avoidance of error or the performance of mitigating actions, may impact
pipeline system integrity. Among other things, the final rule requires operators
of hazardous liquid and gas pipelines to amend their existing written operations
and maintenance procedures, operator qualification programs and emergency plans
to take into account such items as specificity of the responsibilities and roles
of control room personnel; listing of planned pipeline-related occurrences
during a particular shift that may be easily shared with other controllers
during a shift turnover; establishment of appropriate shift rotations to protect
against controller fatigue; and development of appropriate communications
between controllers, management and field personnel when planning and
implementing changes to pipeline equipment or operations. We do not anticipate
that the rule, as issued in final form, will result in substantial costs with
respect to our operations.





Employee
Health and Safety





We are
subject to a number of federal and state laws and regulations, including the
federal Occupational Safety and Health Act, as amended (“OSHA”), and comparable
state statutes, whose purpose is to protect the health and safety of workers,
both generally and within the pipeline industry. In addition, the OSHA hazard
communication standard, the EPA community right-to-know regulations under Title
III of the Federal Superfund Amendment and Reauthorization Act and comparable
state statutes require that information be maintained concerning hazardous
materials used or produced in our operations and that this information be
provided to employees, state and local government authorities and citizens. We
and the entities in which we own an interest are also subject to OSHA Process
Safety Management regulations, which are designed to prevent or minimize the
consequences of catastrophic releases of toxic, reactive, flammable or explosive
chemicals. These regulations apply to any process which involves a chemical at
or above the specified thresholds or any process which involves flammable liquid
or gas, pressurized tanks, caverns and wells in excess of 10,000 pounds at
various locations. Flammable liquids stored in atmospheric tanks below their
normal boiling point without the benefit of chilling or refrigeration are
exempt. We have an internal program of inspection designed to monitor and
enforce compliance with worker safety requirements. We believe that we are in
substantial compliance with all applicable laws and regulations relating to
worker health and safety.








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Title
to Properties and Rights-of-Way





Our real
property falls into two categories: (1) parcels that we own in fee and
(2) parcels in which our interest derives from leases, easements,
rights-of-way, permits or licenses from landowners or governmental authorities
permitting the use of such land for our operations. Portions of the land on
which our plants and other major facilities are located are owned by us in fee
title and we believe that we have satisfactory title to these lands. The
remainder of the land on which our plant sites and major facilities are located
are held by us pursuant to ground leases between us, as lessee, and the fee
owner of the lands, as lessors, and we believe that we have satisfactory
leasehold estates to such lands. We have no knowledge of any challenge to any
material lease, easement, right-of-way, permit or lease and we believe that we
have satisfactory title to all of our material leases, easements, rights-of-way,
permits and licenses.





Targa may
continue to hold record title to portions of certain assets until we make the
appropriate filings in the jurisdictions in which such assets are located and
obtain any consents and approvals that are not obtained prior to transfer. Such
consents and approvals would include those required by federal and state
agencies or political subdivisions. In some cases, Targa may, where required
consents or approvals have not been obtained, temporarily hold record title to
property as nominee for our benefit and in other cases may, on the basis of
expense and difficulty associated with the conveyance of title, cause its
affiliates to retain title, as nominee for our benefit, until a future date. We
anticipate that there will be no material change in the tax treatment of our
common units resulting from the holding by Targa of title to any part of such
assets subject to future conveyance or as our nominee.





Employees





We do not
have any employees. To carry out its operations, Targa employs approximately
1,000 people, some of whom provide direct support for our operations. None of
these employees are covered by collective bargaining agreements. Targa considers
its employee relations to be good.





Financial
Information by Segment





See
“Segment Information” included under Note 19 to our “Consolidated Financial
Statements” beginning on page F-1 of this Annual Report for a presentation of
financial results by segment.





Available
Information





We make
certain filings with the Securities and Exchange Commission (“SEC”), including
our Annual Report on Form 10-K, quarterly reports on Form 10-Q,
current reports on Form 8-K, and all amendments and exhibits to those
reports. We make such filings available free of charge through our website,
http://www.targaresources.com,
as soon as reasonably practicable after they are filed with the SEC. The filings
are also available through the SEC at the SEC’s Public Reference Room at 100 F
Street, N.E., Washington, D.C. 20549 or by calling 1-800-SEC-0330. Also,
these filings are available on the internet at http://www.sec.gov. Our press
releases and recent analyst presentations are also available on our
website.








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Item 1A. Risk Factors





Limited
partner interests are inherently different from capital stock of a corporation,
although many of the business risks to which we are subject are similar to those
that would be faced by a corporation engaged in similar businesses. The nature
of our business activities subject us to certain hazards and risks. You should
consider carefully the following risk factors together with all of the other
information contained in this report. Additional risks not presently known to us
or which we consider immaterial based on information currently available to us
may also materially adversely affect us. If any of the following risks were
actually to occur, then our business, financial condition or results of
operations could be materially adversely affected.





Risks
Related to Our Business





We
may not be able to obtain funding or obtain funding on acceptable terms because
of the deterioration of the credit and capital markets. This may hinder or
prevent us from meeting our future capital needs.





Global
financial markets and economic conditions have been, and continue to be,
disrupted and volatile. The debt and equity capital markets have been
exceedingly distressed. These issues, along with significant write-offs in the
financial services sector, the re-pricing of credit risk and the current weak
economic conditions have made, and will likely continue to make, it difficult to
obtain funding.





In
particular, the cost of raising money in the debt and equity capital markets has
increased substantially while the availability of funds from those markets
generally has diminished significantly. Also, as a result of concerns about the
stability of financial markets generally and the solvency of counterparties
specifically, the cost of obtaining funds from the credit markets generally has
increased as many lenders and institutional investors have increased interest
rates, enacted tighter lending standards, refused to refinance existing debt at
maturity at all or on terms similar to our current debt and reduced and, in some
cases, ceased to provide funding to borrowers.





In
October 2008, Lehman Brothers Commercial Bank (“Lehman Bank”) defaulted on a
borrowing request under our senior secured revolving credit facility (“credit
facility”) which effectively reduced our total commitments under our credit
facility. We can provide no assurance that other lending counterparties will be
willing or able to meet their existing funding obligations under our credit
facility.





Due to
these factors, we cannot be certain that funding will be available, if needed
and to the extent required, on acceptable terms. If funding is not available
when needed or is available only on unfavorable terms, we may be unable to meet
our business funding requirements, grow our existing business, complete
acquisitions or otherwise take advantage of business opportunities or respond to
competitive pressures, any of which could have a material adverse effect on our
revenues and results of operations.





Our
substantial amount of indebtedness could adversely affect our financial
position.





We
currently have a substantial amount of indebtedness. As of December 31,
2009 we had approximately $908.4 million of total indebtedness
outstanding,approximately $69.2 million of letters of credit outstanding and
$410.1 million of additional borrowing capacity under our credit facility,
after giving effect to the Lehman Bank default. Our credit facility allows us to
request increases in the commitments under the credit facility of up to
$22.5 million. We may also incur additional indebtedness in the
future.





Our
substantial indebtedness may:





·
            make
      it difficult for us to satisfy our financial obligations, including making
      scheduled principal and interest payments on our
    indebtedness;





·
            limit
      our ability to borrow additional funds for working capital, capital
      expenditures, acquisitions or other general business
    purposes;





·
            limit
      our ability to use our cash flow or obtain additional financing for future
      working capital, capital expenditures, acquisitions or other general
      business purposes;








25
 Table of Contents





·
            require us to use a substantial portion of our cash flow
      from operations to make debt service
payments;






·
            limit
      our flexibility to plan for or react to, changes in our business and
      industry;





·
            place
      us at a competitive disadvantage compared to our less leveraged
      competitors; and





·
            increase
      our vulnerability to the impact of adverse economic and industry
      conditions.





We
require a significant amount of cash to service our indebtedness. Our ability to
generate cash depends on many factors beyond our control.





Our
ability to service our debt depends upon, among other things, our future
financial and operating performance, which will be affected by prevailing
economic conditions and financial, business, regulatory and other factors, some
of which are beyond our control. If our operating results are not sufficient to
service our current or future indebtedness, we will be forced to take actions
such as reducing distributions; reducing or delaying our business activities,
investments, acquisitions or capital expenditures; selling assets; restructuring
or refinancing our debt; or seeking additional equity capital. We may not be
able to affect any of these actions on satisfactory terms or at all. See “Item
7. Management’s Discussion and Analysis of Financial Condition and Results of
Operations—Liquidity and Capital Resources.”





Our
cash flow is affected by supply and demand for natural gas and NGL products and
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.





Our
operations can be affected by the level of natural gas and NGL prices and the
relationship between these prices. The prices of oil, natural gas and NGLs have
been volatile and we expect this volatility to continue. Our future cash flow
may be materially adversely affected if we experience significant, prolonged
pricing deterioration and we may be unable to maintain our current level of
distributions. The markets and prices for natural gas and NGLs depend upon
factors beyond our control. These factors include demand for these commodities,
which fluctuates with changes in market and economic conditions, and other
factors, including:





·
            the
      impact of seasonality and weather;





·
            general
      economic conditions and the economic conditions impacting our primary
      markets;





·
            the
      economic conditions of our
customers;





·
            the
      level of domestic crude oil and natural gas production and
      consumption;


·
            the
      availability of imported natural gas, liquefied natural gas, NGLs and
      crude oil;





·
            actions
      taken by foreign oil and gas producing
nations;





·
            the
      availability of local, intrastate and interstate transportation systems
      and storage for residue natural gas and
NGLs;





·
            the
      availability and marketing of competitive fuels and/or
      feedstocks;





·
            the
      impact of energy conservation efforts;
and





·
            the
      extent of governmental regulation and
taxation.





Our
primary natural gas gathering and processing arrangements that expose us to
commodity price risk are our percent-of-proceeds arrangements. For the year
ended December 31, 2009, our percent-of-proceeds arrangements accounted for
approximately 70% of our gathered natural gas volume. Under percent-of-proceeds
arrangements, we generally process natural gas from producers and remit to the
producers an agreed percentage of the proceeds from


26
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the sale
of residue gas and NGL products at market prices or a percentage of residue gas
and NGL products at the tailgate of our processing facilities. In some
percent-of-proceeds arrangements, we remit to the producer a percentage of an
index or index-based price for residue gas and NGL products, less agreed
adjustments, rather than remitting a portion of the actual sales proceeds. Under
these types of arrangements, our revenues and our cash flows increase or
decrease, whichever is applicable, as the prices of natural gas, NGL and crude
oil fluctuate. For additional information regarding our hedging activities, see
“Item 7A. Quantitative and Qualitative Disclosures About Market Risk—Commodity
Price Risk.”





Because
of the natural decline in production from existing wells in our operating
regions, our success depends on our ability to obtain new sources of supplies of
natural gas and NGLs, which depends on certain factors beyond our control. Any
decrease in supplies of natural gas or NGLs could adversely affect our business
and operating results.





Our
gathering systems are connected to oil and natural gas wells from which
production will naturally decline over time, which means that our cash flows
associated with these wells will likely also decline over time. To maintain or
increase throughput levels on our gathering systems and the utilization rate at
our processing plants and our treating and fractionation facilities, we must
continually obtain new natural gas and NGL supplies. A material decrease in
natural gas production from producing areas on which we rely, as a result of
depressed commodity prices or otherwise, could result in a decline in the volume
of natural gas that we process and NGL products delivered to our fractionation
facilities. Our ability to obtain additional sources of natural gas and NGLs
depends, in part, on the level of successful drilling and production activity
near our gathering systems. We have no control over the level of such activity
in the areas of our operations, the amount of reserves associated with the wells
or the rate at which production from a well will decline. In addition, we have
no control over producers or their drilling or production decisions, which are
affected by, among other things, prevailing and projected energy prices, demand
for hydrocarbons, the level of reserves, geological considerations, governmental
regulations, availability of drilling rigs, other production and development
costs and the availability and cost of capital.





Fluctuations
in energy prices can greatly affect production rates and investments by third
parties in the development of new oil and natural gas reserves. Drilling and
production activity generally decreases as oil and natural gas prices decrease.
Prices of oil and natural gas have been extremely volatile and we expect this
volatility to continue. Energy commodity prices and demand have recently
declined substantially, leading many exploration and production companies,
including several in our areas of operation, to announce reduced capital
expenditure levels for 2009 and could lead producers in our areas of operation
to shut-in wells during the coming year. Consequently, even if new natural gas
reserves are discovered in areas served by our assets, producers may choose not
to develop those reserves. Reductions in exploration and production activity,
competitor actions or shut-ins by producers in the areas in which we operate may
prevent us from obtaining new supplies of natural gas to replace the natural
decline in volumes from existing wells, which could result in reduced volumes
through our facilities and reduced utilization of our gathering, treating,
processing and fractionation assets. Should reductions negatively impact our
results of operations, they may impair our ability to make distributions to our
unitholders.





If
we fail to balance our purchases of natural gas and our sales of residue gas and
NGLs, our exposure to commodity price risk will increase.





We may
not be successful in balancing our purchases of natural gas and our sales of
residue gas and NGLs. In addition, a producer could fail to deliver promised
volumes to us or deliver in excess of contracted volumes or a purchaser could
purchase less than contracted volumes. Any of these actions could cause an
imbalance between our purchases and sales. If our purchases and sales are not
balanced, we will face increased exposure to commodity price risks and could
have increased volatility in our operating income.





Our
hedging activities may not be effective in reducing the variability of our cash
flows and may, in certain circumstances, increase the variability of our cash
flows. Moreover, our hedges may not fully protect us against volatility in basis
differentials. Finally, the percentage of our expected equity commodity volumes
that are hedged decreases substantially over time.





We have
entered into derivative transactions related to only a portion of our equity
volumes. As a result, we will continue to have direct commodity price risk to
the unhedged portion. Our actual future volumes may be


27
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significantly
higher or lower than we estimated at the time we entered into the derivative
transactions for that period. If the
actual amount is higher than we estimated, we will have greater commodity price
risk than we intended. If the actual amount is lower than the amount that is
subject to our hedges, we might be forced to satisfy all or a portion of our
derivative transactions without the benefit of the cash flow from our sale of
the underlying physical commodity. The percentages of our expected equity
volumes that are covered by our hedges decrease over time. To the extent we
hedge our commodity price risk, we may forego the benefits we would otherwise
experience if commodity prices were to change in our favor. The derivative
instruments we utilize for these hedges are based on posted market prices, which
may be higher or lower than the actual natural gas, NGLs and condensate prices
that we realize in our operations. These pricing differentials may be
substantial and could materially impact the prices we ultimately realize. In
addition, current market and economic conditions may adversely affect our hedge
counterparties’ ability to meet their obligations. Given the current volatility
in the financial and commodity markets, we may experience defaults by our hedge
counterparties in the future. As a result of these and other factors, our
hedging activities may not be as effective as we intend in reducing the
variability of our cash flows and in certain circumstances may actually increase
the variability of our cash flows. For additional information regarding our
hedging activities, see “Item 7A. Quantitative and Qualitative Disclosures
About Market Risk—Commodity Price Risk.”





We
rely on a natural gas producer for a significant portion of our supply of
natural gas. The loss of our largest supplier or the need to replace its
contract on less favorable terms could result in a decline in our volumes,
revenues and cash available for distribution.





The
largest natural gas supplier to our Natural Gas Gathering and Processing
business is ConocoPhillips, who accounted for approximately 11% of the natural
gas supplied to our systems in 2009.The loss of a significant portion of the
natural gas volumes supplied by this producer or the extension or replacement of
its contracts on less favorable terms, if at all, as a result of competition or
otherwise, could reduce our revenue or increase our cost for product purchases,
impairing our ability to make distributions to our unitholders.





If
third party pipelines and other facilities interconnected to our natural gas
pipelines and processing facilities become partially or fully unavailable to
transport natural gas and NGLs, our revenues could be adversely
affected.





We depend
upon third party pipelines, storage and other facilities that provide delivery
options to and from our pipelines and processing facilities. Since we do not own
or operate these pipelines or other facilities, their continuing operation in
their current manner is not within our control. If any of these third party
facilities become partially or fully unavailable or if the quality
specifications for their pipelines or facilities change so as to restrict our
ability to use them, our revenues and cash available for distribution could be
adversely affected.





If
future acquisitions do not perform as expected, our future financial performance
may be negatively impacted.





Acquisitions
may significantly increase our size and diversify the geographic areas in which
we operate. We cannot assure you that we will achieve the desired affect from
acquisitions we may complete in the future. In addition, failure to assimilate
future acquisitions could adversely affect our financial condition and results
of operations.





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.





Our
ability to grow depends, in part, on our ability to make acquisitions that
result in an increase in cash generated from operations per unit. If we are
unable to make these accretive acquisitions either because we are
(1) unable to identify attractive acquisition candidates or negotiate
acceptable purchase contracts with them, (2) unable to obtain financing for
these acquisitions on economically acceptable terms or (3) outbid by
competitors, then our future growth and ability to increase distributions will
be limited.








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 Table of Contents





Any
acquisition involves potential risks, including, among other
things:





·
            operating
      a significantly larger combined organization and adding
      operations;





·
            difficulties
      in the assimilation of the assets and operations of the acquired
      businesses, especially if the assets acquired are in a new business
      segment or geographic area;





·
            the
      risk that natural gas reserves expected to support the acquired assets may
      not be of the anticipated magnitude or may not be developed as
      anticipated;





·
            the
      failure to realize expected volumes, revenues, profitability or
      growth;





·
            the
      failure to realize any expected synergies and cost
  savings;





·
            coordinating
      geographically disparate organizations, systems and
      facilities.





·
            the
      assumption of unknown liabilities;





·
            limitations
      on rights to indemnity from the
seller;





·
            inaccurate
      assumptions about the overall costs of equity or
  debt;





·
            the
      diversion of management’s and employees’ attention from other business
      concerns; and





·
            customer
      or key employee losses at the acquired
  businesses.





If these
risks materialize, the acquired assets may inhibit our growth or fail to deliver
expected benefits further unexpected costs and challenges may arise whenever
businesses with different operations or management are combined and we may
experience unanticipated delays in realizing the benefits of an acquisition. If
we consummate any future acquisition, our capitalization and results of
operations may change significantly and you may not have the opportunity to
evaluate the economic, financial and other relevant information that we will
consider in evaluating future acquisitions.





Our
acquisition strategy is based, in part, on our expectation of ongoing
divestitures of energy assets by industry participants. A material decrease in
such divestitures would limit our opportunities for future acquisitions and
could adversely affect our operations and cash flows available for distribution
to our unitholders.





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





We
continuously consider and enter into discussions regarding potential
acquisitions. Any limitations on our access to capital will impair our ability
to execute this strategy. If the cost of such capital becomes too expensive, our
ability to develop or acquire strategic and accretive assets will be limited. We
may not be able to raise the necessary funds on satisfactory terms, if at all.
The primary factors that influence our initial cost of equity include market
conditions, fees we pay to underwriters and other offering costs, which include
amounts we pay for legal and accounting services. The primary factors
influencing our cost of borrowing include interest rates, credit spreads,
covenants, underwriting or loan origination fees and similar charges we pay to
lenders.





Current
weak economic conditions and the volatility and disruption in the weak financial
markets have increased the cost of raising money in the debt and equity capital
markets substantially while diminishing the availability of funds from those
markets. Also, as a result of concerns about the stability of financial markets
generally and the solvency of counterparties specifically, the cost of obtaining
money from the credit markets generally has increased as many lenders and
institutional investors have increased interest rates, enacted tighter lending
standards, refused to refinance existing debt at maturity at all or on terms
similar to our current debt and reduced and, in some cases, ceased to provide
funding to borrowers. These factors may impair our ability to execute our
acquisition strategy.





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 Table of Contents





In
addition, we typically experience competitive bidding for the types of assets we
contemplate purchasing. The weak economic conditions and competition for asset
purchases could limit our ability to fully execute our growth strategy. Our
inability to execute our growth strategy could materially adversely affect our
ability to maintain or pay higher distributions in the future.





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.





We have
entered into purchase agreements with Targa pursuant to which Targa will
purchase (i) all of the North Texas System’s natural gas, and
(ii) substantially all of the SAOU and LOU Systems’ natural gas for terms
of 15 years. We are also party to an amended and restated Omnibus Agreement
with Targa which addresses, among other things, the provision of general and
administrative and operating services to us. Targa’s corporate credit ratings as
assigned by Moody’s and Standard & Poors as of February 15, 2010 are B1 and
B+, which are speculative ratings. These speculative ratings signify a higher
risk that Targa will default on its obligations, including its obligations to
us, than does an investment grade credit rating. Any material nonperformance
under the omnibus and purchase agreements by Targa could materially and
adversely impact our ability to operate and make distributions to our
unitholders.





Our
general partner is an obligor under and subject to a pledge related to, Targa’s
credit facility; in the event Targa is unable to meet its obligations under that
facility or is declared bankrupt, Targa’s lenders may gain control of our
general partner or, in the case of bankruptcy, our partnership may be
dissolved.





Targa
Resources GP LLC, our general partner, is an obligor under, and all of its
assets and Targa’s ownership interest in it are subject to a lien related to,
Targa’s credit facility. In the event Targa is unable to satisfy its obligations
under its credit facility and the lenders foreclose on their collateral, the
lenders will own our general partner and all of its assets, which include the
general partner interest in us and our incentive distribution rights. In such
event, the lenders would control our management and operation. Moreover, in the
event Targa becomes insolvent or is declared bankrupt, our general partner may
be deemed insolvent or declared bankrupt as well. Under the terms of our
partnership agreement, the bankruptcy or insolvency of our general partner will
cause a dissolution of our partnership.





Our
industry is highly competitive and increased competitive pressure could
adversely affect our business and operating results.





We
compete with similar enterprises in our respective areas of operation. Some of
our competitors are large oil, natural gas and NGL companies that have greater
financial resources and access to supplies of natural gas and NGLs than we do.
Some of these competitors may expand or construct gathering, processing and
transportation systems that would create additional competition for the services
we provide to our customers. In addition, our customers who are significant
producers of natural gas may develop their own gathering, processing and
transportation systems in lieu of using ours. Our ability to renew or replace
existing contracts with our customers at rates sufficient to maintain current
revenues and cash flows could be adversely affected by the activities of our
competitors and our customers. All of these competitive pressures could have a
material adverse effect on our business, results of operations, financial
condition and ability to make cash distributions.





Typically
we 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.





We
typically do not obtain independent evaluations of natural gas reserves
connected to our gathering systems due to the unwillingness of producers to
provide reserve information as well as the cost of such evaluations.
Accordingly, we do not have independent estimates of total reserves dedicated to
our gathering systems or the anticipated life of such reserves. If the total
reserves or estimated life of the reserves connected to our gathering systems is
less than we anticipate and we are unable to secure additional sources of
natural gas, then the volumes of natural gas transported on our gathering
systems in the future could be less than we anticipate. A decline in the volumes
of natural gas on our systems could have a material adverse effect on our
business, results of operations and financial condition and our ability to make
cash distributions to our unitholders.





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A
reduction in demand for NGL products by the petrochemical, refining or other
industries or by the fuel markets could materially adversely affect our
business, results of operations and financial condition.





The NGL
products we produce have a variety of applications, including petrochemical
feedstocks and refining blend stocks. A reduction in demand for NGL products,
whether because of general or industry-specific economic conditions, new
government regulations, global competition, reduced demand by consumers for
products made with NGL products (for example, reduced petrochemical demand
recently observed due to lower activity in the automobile and construction
industries), increased competition from petroleum-based feedstocks due to
pricing differences, mild winter weather for some NGL applications or other
reasons, could result in a decline in the volume of NGL products we handle or
reduce the fees we charge for our services. Our NGL products and their demand
are affected as follows:





Ethane.Ethane is typically
supplied as purity ethane and as part of ethane-propane mix. Ethane is primarily
used in the petrochemical industry as feedstock for ethylene, one of the basic
building blocks for a wide range of plastics and other chemical products.
Although ethane is typically extracted as part of the mixed NGL stream at gas
processing plants, if natural gas prices increase significantly in relation to
NGL product prices or if the demand for ethylene falls, it may be more
profitable for natural gas processors to leave the ethane in the natural gas
stream thereby reducing the volume of NGLs delivered for fractionation and
marketing.





Propane.Propane is used as a
petrochemical feedstock in the production of ethylene and propylene, as a
heating, engine and industrial fuel and in agricultural applications such as
crop drying. Changes in demand for ethylene and propylene could adversely affect
demand for propane. The demand for propane as a heating fuel is significantly
affected by weather conditions. The volume of propane sold is at its highest
during the six-month peak heating season of October through March. Demand for
our propane may be reduced during periods of warmer-than-normal
weather.





Normal Butane.Normal butane
is used in the production of isobutane, as a refined product blending component,
as a fuel gas, either alone or in a mixture with propane and in the production
of ethylene and propylene. Changes in the composition of refined products
resulting from governmental regulation, changes in feedstocks, products and
economics, demand for heating fuel and for ethylene and propylene, could
adversely affect demand for normal butane.





Isobutane.Isobutane is
predominantly used in refineries to produce alkylates to enhance octane levels.
Accordingly, any action that reduces demand for motor gasoline or demand for
isobutane to produce alkylates for octane enhancement might reduce demand for
isobutane.





Natural Gasoline.Natural
gasoline is used as a blending component for certain refined products and as a
feedstock used in the production of ethylene and propylene. Changes in the
composition of motor gasoline resulting from governmental regulation and in
demand for ethylene and propylene could adversely affect demand for natural
gasoline.





NGLs and
products produced from NGLs also compete with products from global markets. Any
reduced demand for ethane, propane, normal butane, isobutane or natural gasoline
at the markets we access for any of the reasons stated above could adversely
affect demand for the services we provide as well as NGL prices, which would
negatively impact our results of operations and financial
condition.





We
do not own most of the land on which our pipelines and compression facilities
are located, which could disrupt our operations.





We do not
own most of the land on which our pipelines and compression facilities are
located and we are therefore subject to the possibility of more onerous terms
and/or increased costs to retain necessary land use if we do not have valid
rights-of-way or leases or if such rights-of-way or leases lapse or terminate.
We sometimes obtain the rights to land owned by third parties and governmental
agencies for a specific period of time. Our loss of these rights, through our
inability to renew right-of-way contracts, leases or otherwise, could cause us
to cease operations on the affected land, increase costs related to continuing
operations elsewhere, reduce our revenue and impair our


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Weather
may limit our ability to operate our business and could adversely affect our
operating results.





The
weather in the areas in which we operate can cause disruptions and in some cases
suspension of our operations. Examples include unseasonably wet weather,
extended periods of below-freezing weather and hurricanes. Disruptions or
suspension of our operations caused by weather could adversely affect our
operating results.





Our
business involves many hazards and operational risks, some of which may not be
fully covered by insurance. If a significant accident or event occurs that is
not fully insured, our operations and financial results could be adversely
affected.





Our
operations are subject to many hazards inherent in the gathering, compressing,
treating, processing and transporting of natural gas and NGLs,
including:





·
            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.





These
risks could result in substantial losses due to personal injury, loss of life,
severe damage to and destruction of property and equipment and pollution or
other environmental damage and may result in curtailment or suspension of our
related operations. A natural disaster or other hazard affecting the areas in
which we operate could have a material adverse effect on our operations. For
example, Hurricanes Katrina and Rita damaged gathering systems, processing
facilities, NGL fractionators and pipelines along the Gulf Coast, including
certain of our facilities. These hurricanes disrupted the operations of our
customers in August and September 2005, which curtailed or suspended the
operations of various energy companies with assets in the region. The Louisiana
and Texas Gulf Coast was similarly impacted in September 2008 as a result of
Hurricanes Gustav and Ike. We are not fully insured against all risks inherent
to our business. We are not insured against all environmental accidents that
might occur which may include toxic tort claims, other than incidents considered
to be sudden and accidental. If a significant accident or event occurs that is
not fully insured, if we fail to recover all anticipated insurance proceeds for
significant accidents or events for which we are insured or if we fail to
rebuild facilities damaged by such accidents or events, our operations and
financial condition could be adversely affected. In addition, we may not be able
to maintain or obtain insurance of the type and amount we desire at reasonable
rates. As a result of market conditions, premiums and deductibles for certain of
our insurance policies have increased substantially and could escalate further.
For example, following Hurricanes Katrina and Rita, insurance premiums,
deductibles and co-insurance requirements increased substantially and terms
generally are less favorable than terms that could be obtained prior to such
hurricanes. Insurance market conditions worsened as a result of the losses
sustained from Hurricanes Gustav and Ike in September 2008. As a result, we
experienced further increases in deductibles and premiums and further reductions
in coverage and limits, with some coverages unavailable at any
cost.





Increases
in interest rates could adversely affect our business.





In
addition to our exposure to commodity prices, we have significant exposure to
increases in interest rates. As of December 31, 2009, we had approximately
$479.2 million of debt outstanding under our credit facility at variable
interest rates of which $179.2 million is not covered by our hedges. Our results
of operations, cash flows and financial condition could be materially adversely
affected by significant increases in interest rates. See “Item 7A. Quantitative
and Qualitative Disclosures About Market Risk—Interest Rate Risk.”








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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 are a
holding company with no business operations. As such, we depend on the earnings
and cash flow of our subsidiaries and the distribution of that cash to us in
order to meet our obligations and to allow us to make distributions to our
unitholders. Our credit facility contains covenants limiting our ability to make
distributions, incur indebtedness, grant liens and engage in transactions with
affiliates. Furthermore, our credit facility contains covenants requiring us to
maintain a ratio of consolidated indebtedness to consolidated EBITDA of not more
than 5.50 to 1.00 or 6.00 to 1.00 for up to one year in conjunction with a
material acquisition and a ratio of consolidated EBITDA to consolidated interest
expense of not less than 2.25 to 1.00. If we fail to meet these tests or
otherwise breach the terms of our credit facility our operating subsidiary will
be prohibited from making any distribution to us and, ultimately, to you. Any
interruption of distributions to us from our subsidiaries may limit our ability
to satisfy our obligations and to make distributions to you. For more
information regarding our credit facility, see “Item 7. Management’s Discussion
and Analysis of Financial Condition and Results of Operations—Liquidity and
Capital Resources.”





We
may incur significant costs and liabilities in the future resulting from a
failure to comply with new or existing environmental laws or regulations or an
accidental release of hazardous substances, hydrocarbons or wastes into the
environment.





Our
operations are subject to stringent and complex federal, state and local
environmental laws and regulations governing the discharge of materials into the
environment or otherwise relating to environmental protection. For more
information on our operations, see “Item 1. Business—Our Systems” for
additional information on our operations. These laws include, for example,
(1) the federal Clean Air Act and comparable state laws that impose
obligations related to air emissions, (2) RCRA and comparable state laws
that impose requirements for the handling, storage, treatment or disposal of
solid and hazardous waste from our facilities, (3)  CERCLA and comparable
state laws that regulate the cleanup of hazardous substances that may have been
released at properties currently or previously owned or operated by us or at
locations to which our hazardous substances have been transported for recycling
or disposal and (4) the Clean Water Act and comparable state laws that
regulate discharges of wastewater from our facilities to state and federal
waters. Failure to comply with these laws and regulations or newly adopted laws
or regulations may trigger a variety of administrative, civil and criminal
enforcement measures, including the assessment of monetary penalties, the
imposition of remedial requirements and the issuance of orders enjoining future
operations or imposing additional compliance requirements on such operations.
Certain environmental laws, including CERCLA and analogous state laws, impose
strict, joint and several liability for costs required to clean up and restore
sites where hazardous substances or hydrocarbons have been disposed or otherwise
released. Moreover, it is not uncommon for neighboring landowners and other
third parties to file claims for personal injury and property damage allegedly
caused by noise, odor or the release of hazardous substances, hydrocarbons or
waste products into the environment.





There is
inherent risk of incurring environmental costs and liabilities in connection
with our operations due to our handling of natural gas, NGLs and other petroleum
products, because of air emissions and water discharges related to our
operations, and as a result of historical industry operations and waste disposal
practices. For example, an accidental release from one of our facilities could
subject us to substantial liabilities arising from environmental cleanup and
restoration costs, claims made by neighboring landowners and other third parties
for personal injury, natural resource and property damages and fines or
penalties for related violations of environmental laws or
regulations.





Moreover,
stricter laws, regulations or enforcement policies could significantly increase
our operational or compliance costs and the cost of any remediation that may
become necessary. For instance, the Texas Commission on Environmental Quality
has recently conducted a comprehensive analysis of air emissions in the Barnett
Shale area in response to reported concerns about high concentrations of benzene
in the air near drilling sites and natural gas processing facilities, and the
analysis could result in the adoption of new air emission limitations that could
require us to incur increased capital or operating costs. We are also conducting
our own evaluation of air emissions at certain of our facilities in the Barnett
Shale area and, as necessary, plan to conduct corrective actions at such
facilities. Additionally, environmental groups have advocated increased
regulation and a moratorium on the issuance of drilling permits for new natural
gas wells in the Barnett Shale area. The adoption of any laws, regulations or
other





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legally
enforceable mandates that result in more stringent air emission limitations or
that restrict or prohibit the drilling of new natural gas wells for any extended
period of time could increase our operating and compliance costs as well as
reduce the rate of production of natural gas operators with whom we have a
business relationship, which could have a material adverse effect on our results
of operations and cash flows. For further information on environmental matters,
see “Item 1. Business—Environmental, Health and Safety Matters” for additional
information on environmental matters.





Increased
regulation of hydraulic fracturing could result in reductions or delays in
drilling and completing new oil and natural gas wells, which could adversely
impact our revenues by decreasing the volumes of natural gas that we gather,
process and fractionate.




Hydraulic
fracturing is a process used by oil and gas exploration and production operators
in the completion of certain oil and gas wells whereby water, sand and chemicals
are injected under pressure into subsurface formations to stimulate gas and, to
a lesser extent, oil production. Due to concerns that hydraulic fracturing may
adversely affect drinking water supplies, legislation has been introducedin the U.S.
Congress to amend the federal Safe Drinking Water Act to subject hydraulic
fracturing operations to regulation under that Act and to require the disclosure
of chemicals used by the oil and gas industry in the hydraulic fracturing
process. Adoption of this or similar legislation or of any implementing
regulations could impose operational delays, increased operating costs and
additional regulatory burdens on exploration and production operators, which
could reduce their production of natural gas and, in turn, adversely affect our
revenues and results of operations by decreasing the volumes of natural gas that
we gather, process and fractionate.


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.





The NGA exempts
natural gas gathering facilities from regulation by FERC as a natural gas
company under the NGA. We believe that the natural gas pipelines in our
gathering systems meet the traditional tests FERC has used to establish a
pipeline’s status as a gatherer not subject to regulation as a natural gas
company. However, the distinction between FERC-regulated transmission services
and federally unregulated gathering services is the subject of substantial,
on-going litigation, so the classification and regulation of our gathering
facilities are subject to change based on future determinations by FERC, the
courts or Congress. In addition, the courts have determined that certain
pipelines that would otherwise be subject to the ICA are exempt from regulation
by FERC under the ICA as proprietary lines. The classification of a line as a
proprietary line is a fact-based determination subject to FERC and court review.
Accordingly, the classification and regulation of some of our gathering
facilities and transportation pipelines may be subject to change based on future
determinations by FERC, the courts, or Congress.





While our natural gas
gathering operations are generally exempt from FERC regulation under the NGA,
our gas gathering operations may be subject to certain FERC reporting and
posting requirements in a given year. FERC has recently issued a final rule (as
amended by orders on rehearing, Order 704) requiring certain participants in the
natural gas market, including intrastate pipelines, natural gas gatherers,
natural gas marketers and natural gas processors, that engage in a minimum level
of natural gas sales or purchases to submit annual reports regarding those
transactions to FERC. In addition, FERC has issued a final rule (as amended by
an order on rehearing, Order 720) requiring major non-interstate pipelines,
defined as certain non-interstate pipelines delivering, on an annual basis, more
than an average of 50 BBtus of gas over the previous three calendar years,
to post daily certain information regarding the pipeline’s capacity and
scheduled flows for each receipt and delivery point that has design capacity
equal to or greater than 15,000 MMBtu/d. A petition for review of Order 720
is currently pending before the Court of Appeals for the Fifth Circuit, and
requests for rehearing are currently pending before FERC, and we have no way to
predict with certainty whether and to what extent Order 720 will be modified in
response to the petition for review.





Other
FERC regulations may indirectly impact our businesses and the markets for
products derived from these businesses. FERC’s policies and practices across the
range of its natural gas regulatory activities, including, for example, its
policies on open access transportation, gas quality, ratemaking, capacity
release and market center promotion, may indirectly affect the intrastate
natural gas market. In recent years, FERC has pursued





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pro-competitive
policies in its regulation of interstate natural gas pipelines. However, we
cannot assure you that FERC will continue this approach as it considers matters
such as pipeline rates and rules and policies that may affect rights of access
to transportation capacity. For more information regarding the regulation of
Targa’s operations, see “Item 1. Business—Regulation of
Operations”.





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





Under the
EP Act 2005, FERC has civil penalty authority under the NGA to impose penalties
for current violations of up to $1 million per day for each violation and
disgorgement of profits associated with any violation. While our systems have
not been regulated by FERC as a natural gas companies under the NGA, FERC has
adopted regulations that may subject certain of our otherwise non-FERC
jurisdictional facilities to FERC annual reporting and daily scheduled flow and
capacity posting requirements. Additional rules and legislation pertaining to
those and other matters may be considered or adopted by FERC from time to time.
Failure to comply with those regulations in the future could subject Targa to
civil penalty liability. For more information regarding regulation of Targa’s
operations, see “Item 1. Business—Regulation of Operations”.





The adoption of climate
change legislation or regulations restricting emissions of GHGs could result in
increased operating costs and reduced demand for the products and services we
provide.





On June 26, 2009,
the U.S. House of Representatives approved adoption of the American Clean Energy
and Security Act of 2009, also known as the Waxman-Markey cap-and-trade
legislation (“ACESA”), which would establish an economy-wide cap-and-trade
program in the United States to reduce emissions of GHGs, including carbon
dioxide and methane that may be contributing to warming of the Earth’s
atmosphere and other climatic changes. ACESA would require an overall reduction
in GHG emissions of 17% (from 2005 levels) by 2020, and by over 80% by 2050.
Under ACESA, covered sources of GHG emissions would be required to obtain GHG
emission “allowances” corresponding to their annual emissions of GHGs. The
number of emission allowances issued each year would decline as necessary to
meet ACESA’s overall emission reduction goals. As the number of GHG emission
allowances declines each year, the cost or value of allowances is expected to
escalate significantly. The net effect of ACESA will be to impose increasing
costs on the combustion of carbon-based fuels such as oil, refined petroleum
products, natural gas and NGLs. The U.S. Senate has begun work on its own
legislation for controlling and reducing emissions of GHGs in the United States.
President Obama has indicated that he is in support of the adoption of
legislation to control and reduce emissions of GHGs. Although it is not possible
at this time to predict whether or when the Senate may act on climate change
legislation or how any bill approved by the Senate would be reconciled with
ACESA, any laws or regulations that may be adopted to restrict or reduce
emissions of GHGs would likely require us to incur increased operating costs,
and could have an adverse effect on demand for our gathering, treating,
processing and fractionating services.





Even if such legislation
is not adopted at the national level, more than one-third of the states either
individually or collectively as part of a multi-state, regional initiative have
begun taking actions to control and/or reduce emissions of GHGs, with most of
the state and regional-level initiatives focused on large sources of GHG
emissions, such as coal-fired electric plants. It is possible that smaller
sources of emissions could become subject to GHG emission limitations or
allowance purchase requirements in the future. Any one of these climate change
regulatory and legislative initiatives could have a material adverse effect on
our business, financial condition and results of operations.





Finally, on
December 15, 2009, the EPA issued a notice of its final finding and
determination that emissions of carbon dioxide, methane, and other GHGs present
an endangerment to human health and the environment because emissions of such
gases contribute to warming of the earth’s atmosphere and other climatic
changes. This final finding and determination by the EPA allows the agency to
begin regulating GHG emissions under existing provisions of the Clean Air Act.
In late September 2009, the EPA announced two sets of proposed regulations in
anticipation of finalizing its findings and determination that would require a
reduction in emissions of GHGs from motor vehicles and also could trigger permit
review for GHG emissions from certain stationary sources. In addition, on
September 22, 2009, the EPA issued a final rule requiring the reporting of
GHG emissions from specified large GHG emission sources in the U.S., including
natural gas liquids fractionators, beginning in 2011 for emissions occurring in
2010. Any limitation imposed by the EPA on GHG emissions from our natural
gas–fired compressor


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The
adoption of derivatives legislation by Congress could have an adverse impact on
our ability to hedge risks associated with our business.







Congress
currently is considering broad financial regulatory reform legislation that
among other things would impose comprehensive regulation on the over-the-counter
(“OTC”) derivatives marketplace and could affect the use of derivatives in
hedging transactions. The financial regulatory reform bill adopted by the House
of Representatives on December 11, 2009, would subject swap dealers and "major
swap participants" to substantial supervision and regulation, including capital
standards, margin requirements, business conduct standards, and recordkeeping
and reporting requirements. It also would require central clearing for
transactions entered into between swap dealers or major swap participants. For
these purposes, a major swap participant generally would be someone other than a
dealer who maintains a "substantial" net position in outstanding swaps,
excluding swaps used for commercial hedging or for reducing or mitigating
commercial risk, or whose positions create substantial net counterparty exposure
that could have serious adverse effects on the financial stability of the U.S.
banking system or financial markets. The House-passed bill also would provide
the CFTC with express authority to impose position limits for OTC derivatives
related to energy commodities. Separately, in late January 2010, the CFTC
proposed regulations that would impose speculative position limits for certain
futures and option contracts in natural gas, crude oil, heating oil, and
gasoline. These proposed regulations would make an exemption available for
certain bona fide hedging of commercial risks. Although it is not possible at
this time to predict whether or when Congress will act on derivatives
legislation or the CFTC will finalize its proposed regulations, any laws or
regulations that subject us to additional capital or margin requirements
relating to, or to additional restrictions on, our trading and commodity
positions could have an adverse effect on our ability to hedge risks associated
with our business or on the cost of our hedging activity.





Our interstate common
carrier liquids pipeline is regulated by the Federal Energy Regulatory
Commission.





Targa NGL, one of our
subsidiaries, is an interstate NGL common carrier subject to regulation by the
FERC under the ICA. Targa NGL owns a twelve inch diameter pipeline that runs
between Lake Charles, Louisiana and Mont Belvieu, Texas. This pipeline can move
mixed NGLs and purity NGL products. Targa NGL also owns an eight inch diameter
pipeline and a 20 inch diameter pipeline each of which run between Mont Belvieu,
Texas and Galena Park, Texas. The eight inch and the 20 inch pipelines are part
of an extensive mixed NGL and purity NGL pipeline receipt and delivery system
that provides services to domestic and foreign import and export customers. The
ICA requires that we maintain tariffs on file with FERC for each of these
pipelines. Those tariffs set forth the rates we charge for providing
transportation services as well as the rules and regulations governing these
services. The ICA requires, among other things, that rates on interstate common
carrier pipelines be “just and reasonable” and non-discriminatory.All shippers
on these pipelines are our affiliates.





Unexpected
volume changes due to production variability or to gathering, plant or pipeline
system disruptions may increase our exposure to commodity price
movements.





Targa
sells our processed natural gas to third parties and other Targa affiliates at
our plant tailgates or at pipeline pooling points. Targa also manages the SAOU
and LOU Systems’ natural gas sales to third parties under contracts that remain
in the name of the SAOU and LOU Systems. Sales made to natural gas marketers and
end-users may be interrupted by disruptions to volumes anywhere along the
system. Targa will attempt to balance sales with volumes supplied from our
processing operations, but unexpected volume variations due to production
variability or to gathering, plant or pipeline system disruptions may expose us
to volume imbalances which, in conjunction with movements in commodity prices,
could materially impact our income from operations and cash flow.





We
may incur significant costs and liabilities resulting from pipeline integrity
programs and related repairs.





Pursuant
to the Pipeline Safety Improvement Act of 2002, as reauthorized and amended by
the Pipeline Inspections, Protection, Enforcement and Safety Act of 2006, the
DOT, through the PHMSA, has adopted regulations requiring pipeline operators to
develop integrity management programs for transmission pipelines





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located
where a leak or rupture could do the most harm in “high consequence areas,”
including high population areas, areas that are sources of drinking water,
ecological resource areas that are unusually sensitive to environmental damage
from a pipeline release and commercially navigable waterways, unless the
operator effectively demonstrates by risk assessment that the pipeline could not
affect the area. The regulations require operators of covered pipelines
to:





·
            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.





In
addition, states have adopted regulations similar to existing DOT regulations
for intrastate gathering and transmission lines. We currently estimate that we
will incur an aggregate cost of approximately $5.1 million between 2010 and
2012 to implement pipeline integrity management program testing along certain
segments of our natural gas and NGL pipelines. This estimate does not include
the costs, if any, of any repair, remediation, preventative or mitigating
actions that may be determined to be necessary as a result of the testing
program, which costs could be substantial. At this time, we cannot predict the
ultimate cost of compliance with this regulation, as the cost will vary
significantly depending on the number and extent of any repairs found to be
necessary as a result of the pipeline integrity testing. Following the initial
round of testing and repairs, we will continue our pipeline integrity testing
programs to assess and maintain the integrity of our pipelines. The results of
these tests could cause us to incur significant and unanticipated capital and
operating expenditures for repairs or upgrades deemed necessary to ensure the
continued safe and reliable operations of our pipelines.





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.





One of
the ways we intend to grow our business is through the construction of new
midstream assets. The construction of additions or modifications to our existing
systems and the construction of new midstream assets involve numerous
regulatory, environmental, political and legal uncertainties beyond our control
and may require the expenditure of significant amounts of capital. If we
undertake these projects, they may not be completed on schedule or at the
budgeted cost or at all. Moreover, our revenues may not increase immediately
upon the expenditure of funds on a particular project. For instance, if we
expand a new pipeline, the construction may occur over an extended period of
time and we will not receive any material increases in revenues until the
project is completed. Moreover, we may construct facilities to capture
anticipated future growth in production in a region in which such growth does
not materialize. Since we are not engaged in the exploration for and development
of natural gas and oil reserves, we do not possess reserve expertise and we
often do not have access to third party estimates of potential reserves in an
area prior to constructing facilities in such area. To the extent we rely on
estimates of future production in our decision to construct additions to our
systems, such estimates may prove to be inaccurate because there are numerous
uncertainties inherent in estimating quantities of future production. As a
result, new facilities may not be able to attract enough throughput to achieve
our expected investment return, which could adversely affect our results of
operations and financial condition. In addition, the construction of additions
to our existing gathering and transportation assets may require us to obtain new
rights-of-way prior to constructing new pipelines. We may be unable to obtain
such rights-of-way to connect new natural gas supplies to our existing gathering
lines or capitalize on other attractive expansion opportunities. Additionally,
it may become more expensive for us to obtain new rights-of-way or to renew
existing rights-of-way. If the cost of renewing or obtaining new rights-of-way
increases, our cash flows could be adversely affected.








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We
do not have any officers or employees and rely solely on officers of our general
partner and employees of Targa.





None of
the officers of our general partner are employees of our general partner. We
have entered into an Omnibus Agreement with Targa, pursuant to which Targa
operates our assets and performs other administrative services for us such as
accounting, legal, regulatory, corporate development, finance, land and
engineering. Affiliates of Targa conduct businesses and activities of their own
in which we have no economic interest, including businesses and activities
relating to Targa. As a result, there could be material competition for the time
and effort of the officers and employees who provide services to our general
partner and Targa. If the officers of our general partner and the employees of
Targa do not devote sufficient attention to the management and operation of our
business, our financial results may suffer and our ability to make distributions
to our unitholders may be reduced.





If
our general partner fails to maintain an effective system of internal controls,
then we may not be able to accurately report our financial results or prevent
fraud. As a result, current and potential unitholders could lose confidence in
our financial reporting, which would harm our business and the trading price of
our common units.





Targa
Resources GP LLC, our general partner, has sole responsibility for conducting
our business and for managing our operations. Effective internal controls are
necessary for our general partner, on our behalf, to provide reliable financial
reports, prevent fraud and operate us successfully as a public company. If our
general partner’s efforts to develop and maintain its internal controls are not
successful, it is unable to maintain adequate controls over our financial
processes and reporting in the future or it is unable to assist us in complying
with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002, our
operating results could be harmed or we may fail to meet our reporting
obligations. Ineffective internal controls also could cause investors to lose
confidence in our reported financial information, which would likely have a
negative effect on the trading price of our common units.





The
amount of cash we have available for distribution to holders of our common 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.





You
should be aware that the amount of cash we have available for distribution
depends primarily upon our cash flow and not solely on profitability, which will
be affected by non-cash items. As a result, we may make cash distributions
during periods when we record losses for financial accounting purposes and may
not make cash distributions during periods when we record net earnings for
financial accounting purposes.





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.





The
long-term impact of terrorist attacks, such as the attacks that occurred on
September 11, 2001 and the threat of future terrorist attacks on our
industry in general and on us in particular, is not known at this time. However,
resulting regulatory requirements and/or related business decisions associated
with security are likely to increase our costs.





Increased
security measures taken by us as a precaution against possible terrorist attacks
have resulted in increased costs to our business. Uncertainty surrounding
continued hostilities in the Middle East or other sustained military campaigns
may affect our operations in unpredictable ways, including disruptions of crude
oil supplies and markets for our products and the possibility that
infrastructure facilities could be direct targets of or indirect casualties of,
an act of terror.





Changes
in the insurance markets attributable to terrorist attacks may make certain
types of insurance more difficult for us to obtain. Moreover, the insurance that
may be available to us may be significantly more expensive than our existing
insurance coverage. Instability in the financial markets as a result of
terrorism or war could also affect our ability to raise capital.








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Risks
Inherent in an Investment in Us





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





Because
distributions on the common units are dependent on the amount of cash we
generate, distributions may fluctuate based on our performance. The actual
amount of cash that is available to be distributed each quarter will depend on
numerous factors, some of which are beyond our control and the control of the
general partner. Cash distributions are dependent primarily on cash flow,
including cash flow from financial reserves and working capital borrowings and
not solely on profitability, which is affected by non-cash items. Therefore,
cash distributions might be made during periods when we record losses and might
not be made during periods when we record profits.





In order
to make cash distributions at our current distribution rate of $0.5175 per
common unit per complete quarter or $2.07 per unit per year, we will
require available cash of approximately $38.8 million per quarter or
$155.2 million per year, based on common units outstanding as of February
1, 2010. We may not have sufficient available cash from operating surplus each
quarter to enable us to make cash distributions at our current distribution rate
under our cash distribution policy. The amount of cash we can distribute on our
units principally depends upon the amount of cash we generate from our
operations, which will fluctuate from quarter to quarter based on, among other
things:





·
            the
      fees we charge and the margins we realize for our
  services;





·
            the
      prices of, levels of production of and demand for, natural gas and
      NGLs;





·
            the
      volume of natural gas we gather, treat, compress, process, transport and
      sell and the volume of NGLs we process or fractionate and
      sell;





·
            the
      relationship between natural gas and NGL
prices;





·
            cash
      settlements of hedging positions;





·
            the
      level of competition from other midstream energy
  companies;





·
            the
      level of our operating and maintenance and general and administrative
      costs; and





·
            prevailing
      economic conditions.





In
addition, the actual amount of cash we will have available for distribution will
depend on other factors, some of which are beyond our control,
including:





·
            the
      level of capital expenditures we
make;





·
            our
      ability to make borrowings under our credit facility to pay
      distributions;





·
            the
      cost of acquisitions;





·
            our
      debt service requirements and other
liabilities;





·
            fluctuations
      in our working capital needs;





·
            general
      and administrative expenses, including expenses we incur as a result of
      being a public company;


·
            restrictions
      on distributions contained in our debt
  agreements;





·
            the
      amount of cash reserves established by our general partner for the proper
      conduct of our business, and




39
 Table of Contents


·
            distribution
      support from Targa as a result of the Downstream Business
      transaction.





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.





Targa
owns and controls our general partner. Some of our general partner’s directors
and some of its executive officers, are directors or officers of Targa.
Therefore, conflicts of interest may arise between Targa, including our general
partner, on the one hand and us and our unitholders, on the other hand. In
resolving these conflicts of interest, our general partner may favor its own
interests and the interests of its affiliates over the interests of our
unitholders. These conflicts include, among others, the following
situations:





·
            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;
  and





·
            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 LLC,
      in resolving conflicts of interest.





Targa
is not limited in its ability to compete with us and is under no obligation to
offer assets to us, which could limit our ability to acquire additional assets
or businesses.





Neither
our partnership agreement nor the Omnibus Agreement between us and Targa
prohibits Targa from owning assets or engaging in businesses that compete
directly or indirectly with us. In addition, Targa may acquire, construct or
dispose of additional midstream or other assets in the future, without any
obligation to offer us the opportunity to purchase or construct any of those
assets. Targa is a large, established participant in the midstream energy
business and has significantly greater resources and experience than we have,
which factors may make it more difficult for us to compete with Targa with
respect to commercial activities as well as for acquisition candidates. As a
result, competition from Targa could adversely impact our results of operations
and cash available for distribution.





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





The
credit and business risk profiles of the general partner and its owners may be
factors in credit evaluations of a master limited partnership. This is because
the general partner can exercise significant influence over the business
activities of the partnership, including its cash distribution and acquisition
strategy and business risk profile. Another factor that may be considered is the
financial condition of the general partner and its owners, including the degree
of their financial leverage and their dependence on cash flow from the
partnership to service their indebtedness.





Targa,
the owner of our general partner, has significant indebtedness outstanding and
is partially dependent on the cash distributions from their indirect general
partner and limited partner equity interests in us to service such indebtedness.
Any distributions by us to such entities will be made only after satisfying our
then current obligations to our creditors. Our credit ratings and business risk
profile could be adversely affected if the ratings and risk profiles of the
entities that control our general partner were viewed as substantially lower or
more risky than ours.








40
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Our
partnership agreement limits our general partner’s fiduciary duties to holders
of our units and restricts the remedies available to unitholders for actions
taken by our general partner that might otherwise constitute breaches of
fiduciary duty.





The
directors and officers of our general partner have a fiduciary duty to manage
our general partner in a manner beneficial to its owner, Targa. Our partnership
agreement contains provisions that reduce the standards to which our general
partner would otherwise be held by state fiduciary duty laws. For example, our
partnership agreement:





·
            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 nonappealable 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.





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.





Pursuant
to the Omnibus Agreement we entered into with Targa and Targa Resources
GP LLC, our general partner, Targa receives reimbursement for the payment
of operating expenses related to our operations and for the provision of various
general and administrative services for our benefit. Payments for these services
are substantial and reduce the amount of cash available for distribution to
unitholders. See “Item 13. Certain Relationships and Related Transactions, and
Director Independence.” In addition, under Delaware partnership law, our general
partner has unlimited liability for our obligations, such as our debts and
environmental liabilities, except for our contractual obligations that are
expressly made without recourse to our general partner. To the extent our
general partner incurs obligations on our behalf, we are obligated to reimburse
or indemnify our general partner. If we are unable or unwilling to reimburse or
indemnify our general partner, our general partner may take actions to cause us
to make payments on these obligations and liabilities. Any such payments could
reduce the amount of cash otherwise available for distribution to our
unitholders.





Holders
of our common units have limited voting rights and are not entitled to elect our
general partner or its directors.





Unlike
the holders of common stock in a corporation, unitholders have only limited
voting rights on matters affecting our business and, therefore, limited ability
to influence management’s decisions regarding our business.





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Unitholders
will not elect our general partner or our general partner’s board of directors
and have no right to elect our general partner or our general partner’s board of
directors on an annual or other continuing basis. The board of directors of our
general partner is chosen by Targa. Furthermore, if the unitholders are
dissatisfied with the performance of our general partner, they have little
ability to remove our general partner. As a result of these limitations, the
price at which the common units trade could be diminished because of the absence
or reduction of a takeover premium in the trading price.





We
may issue additional units without your approval, which would dilute your
existing ownership interests.





Our
partnership agreement does not limit the number of additional limited partner
interests that we may issue at any time without the approval of our unitholders.
The issuance by us of additional common units or other equity securities of
equal or senior rank will have the following effects:





·
            our
      unitholders’ proportionate ownership interest in us will
      decrease;





·
            the
      amount of cash available for distribution on each unit may
      decrease;





·
            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.





As of
February 1, 2010 Targa and its management beneficially held 20,406,248
common units. The sale of these units in the public markets could have an
adverse impact on the price of the common units or on any trading market that
may develop.





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.





Our
general partner has the right when it has received incentive distributions at
the highest level to which it is entitled (48%) for each of the prior four
consecutive fiscal quarters, to reset the initial cash target distribution
levels at higher levels based on the distribution at the time of the exercise of
the reset election. Following a reset election by our general partner, the
minimum quarterly distribution amount will be reset to an amount equal to the
average cash distribution amount per common unit for the two fiscal quarters
immediately preceding the reset election (such amount is referred to as the
“reset minimum quarterly distribution”) and the target distribution levels will
be reset to correspondingly higher levels based on percentage increases above
the reset minimum quarterly distribution amount.





In
connection with resetting these target distribution levels, our general partner
will be entitled to receive Class B units. The Class B units will be
entitled to the same cash distributions per unit as our common units and will be
convertible into an equal number of common units. The number of Class B
units to be issued will be equal to that number of common units whose aggregate
quarterly cash distributions equaled the average of the distributions to our
general partner on the incentive distribution rights in the prior two quarters.
We anticipate that our general partner would exercise this reset right in order
to facilitate acquisitions or internal growth projects that would not be
sufficiently accretive to cash distributions per common unit without such
conversion; however, it is possible that our general partner could exercise this
reset election at a time when it is experiencing or may be expected to
experience, declines in the cash distributions it receives related to its
incentive distribution rights and may therefore desire to be issued our
Class B units, which are entitled to receive cash distributions from us on
the same priority as our common units, rather than retain the right to receive
incentive distributions based on the initial target distribution levels. As a
result, a reset election may cause our common unitholders to experience dilution
in the amount of cash distributions





42
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that they
would have otherwise received had we not issued new Class B units to our
general partner in connection with resetting the target distribution levels
related to our general partner’s incentive distribution rights.





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.





As with
other yield-oriented securities, our unit price is impacted by the level of our
cash distributions and implied distribution yield. The distribution yield is
often used by investors to compare and rank related yield-oriented securities
for investment decision-making purposes. Therefore, changes in interest rates,
either positive or negative, may affect the yield requirements of investors who
invest in our units and a rising interest rate environment could have an adverse
impact on our unit price and our ability to issue additional equity to make
acquisitions, for expansion capital expenditures or for other
purposes.





Our
partnership agreement restricts the voting rights of unitholders owning 20% or
more of our common units.





Unitholders’
voting rights are further restricted by the partnership agreement provision
providing that any units held by a person that owns 20% or more of any class of
units then outstanding, other than our general partner, its affiliates, their
transferees and persons who acquired such units with the prior approval of the
board of directors of our general partner, cannot vote on any matter. Our
partnership agreement also contains provisions limiting the ability of
unitholders to call meetings or to acquire information about our operations, as
well as other provisions limiting the unitholders’ ability to influence the
manner or direction of management.





Control
of our general partner may be transferred to a third party without unitholder
consent.





Our
general partner may transfer its general partner interest to a third party in a
merger or in a sale of all or substantially all of its assets without the
consent of the unitholders. Furthermore, our partnership agreement does not
restrict the ability of the owners of our general partner from transferring all
or a portion of their respective ownership interest in our general partner to a
third party. The new owners of our general partner would then be in a position
to replace the board of directors and officers of our general partner with its
own choices and thereby influence the decisions taken by the board of directors
and officers.





Our
general partner has a limited call right that may require you to sell your units
at an undesirable time or price.





If at any
time our general partner and its affiliates own more than 80% of the common
units, our general partner will have the right, but not the obligation, which it
may assign to any of its affiliates or to us, to acquire all, but not less than
all, of the common units held by unaffiliated persons at a price not less than
their then-current market price. As a result, you may be required to sell your
common units at an undesirable time or price and may not receive any return on
your investment. You may also incur a tax liability upon a sale of your units.
As of December 31, 2009, our general partner and its affiliates own
approximately 32.5% of our aggregate outstanding common units.





Your
liability may not be limited if a court finds that unitholder action constitutes
control of our business.





A general
partner of a partnership generally has unlimited liability for the obligations
of the partnership, except for those contractual obligations of the partnership
that are expressly made without recourse to the general partner. Our partnership
is organized under Delaware law and we conduct business in Louisiana and Texas
as well as other states. The limitations on the liability of holders of limited
partner interests for the obligations of a limited partnership have not been
clearly established in some of the states in which we do business. You could be
liable for any and all of our obligations as if you were a general partner
if:





·
            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




43
 Table of Contents




·
            your
      right to act with other unitholders to remove or replace the general
      partner, to approve some amendments to our partnership agreement or to
      take other actions under our partnership agreement constitute “control” of
      our business.






Unitholders
may have liability to repay distributions that were wrongfully distributed to
them.





Under
certain circumstances, unitholders may have to repay amounts wrongfully returned
or distributed to them. Under Section 17-607 of the Delaware Revised
Uniform Limited Partnership Act, we may not make a distribution to you if
the distribution would cause our liabilities to exceed the fair value of our
assets. Delaware law provides that for a period of three years from the date of
the impermissible distribution, limited partners who received the distribution
and who knew at the time of the distribution that it violated Delaware law will
be liable to the limited partnership for the distribution amount. Substituted
limited partners are liable for the obligations of the assignor to make
contributions to the partnership that are known to the substituted limited
partner at the time it became a limited partner and for unknown obligations if
the liabilities could be determined from the partnership agreement. Liabilities
to partners on account of their partnership interest and liabilities that are
non-recourse to the partnership are not counted for purposes of determining
whether a distribution is permitted.





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 (“IRS”), were to
treat us as a corporation for federal income tax purposes 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.





The
anticipated after-tax economic benefit of an investment in the common units
depends largely on our being treated as a partnership for federal income tax
purposes. In order to maintain our status as a partnership for United States
federal income tax purposes, 90% or more of our gross income in each tax year
must be qualifying income under section 7704 of the Internal Revenue Code. We
have not requested and do not plan to request a ruling from the IRS with respect
to our treatment as a partnership for federal income tax purposes.





Although
we do not believe based upon our current operations that we are so treated, and
despite the fact that we are a limited partnership under Delaware law, it is
possible, in certain circumstances for a partnership such as ours to be treated
as a corporation for federal income tax purposes. A change in our business (or a
change in current law) could cause us to be treated as a corporation for federal
income tax purposes or otherwise subject us to taxation as an
entity.





If we
were treated as a corporation for federal income tax purposes, we would pay
federal income tax on our taxable income at the corporate tax rate, which is
currently a maximum of 35% and would likely pay state income tax at varying
rates. Distributions to you would generally be taxed again as corporate
distributions and no income, gains, losses or deductions would flow through to
you. Because a tax would be imposed upon us as a corporation, our cash available
for distribution to you would be substantially reduced. Therefore, treatment of
us as a corporation would result in a material reduction in the anticipated cash
flow and after-tax return to the unitholders, likely causing a substantial
reduction in the value of our common units.





Current
law may change so as to cause us to be treated as a corporation for federal
income tax purposes or otherwise subject us to entity-level taxation. At the
federal level, legislation has been proposed that would eliminate partnership
tax treatment for certain publicly traded partnerships. Although such
legislation would not apply to us as currently proposed, it could be amended
prior to enactment in a manner that does apply to us. We are unable to predict
whether any such change or other proposals will ultimately be enacted. Moreover,
any modification to the federal income tax laws and interpretations thereof may
or may not be applied retroactively. Any such changes could negatively impact
the value of an investment in our common units. At the state level, because of
widespread state budget deficits and other reasons, several states are
evaluating ways to subject partnerships to entity-level taxation through the
imposition of state income, franchise and other forms of taxation. For example,
we are required to pay Texas franchise tax at a maximum effective rate of 0.7%
of our gross income apportioned to Texas in the prior year. Imposition of any
such tax on us by any other state will reduce the cash available for
distribution to you.








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Our




We
prorate our items of income, gain, loss and deduction between transferors and
transferees of our units each month based upon the ownership of our units on the
first day of each month, instead of on the basis of the date a particular unit
is transferred. The IRS may challenge this treatment, which could change the
allocation of items of income, gain, loss and deduction among our
unitholders.





We
prorate our items of income, gain, loss and deduction between transferors and
transferees of our units each month based upon the ownership of our units on the
first day of each month, instead of on the basis of the date a particular unit
is transferred. The use of this proration method may not be permitted under
existing Treasury Regulations. Recently, however, the Department of the Treasury
and the IRS issued proposed Treasury Regulations that provide a safe harbor
pursuant to which a publicly traded partnership may use a similar monthly
simplifying convention to allocate tax items among transferor and transferee
unitholders. Although existing publicly traded partnerships are entitled to rely
on these proposed Treasury Regulations, they are not binding on the IRS and are
subject to change until final Treasury Regulations are issued.





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.





We have
not requested a ruling from the IRS with respect to our treatment as a
partnership for federal income tax purposes. The IRS may adopt positions that
differ from the positions we take. It may be necessary to resort to
administrative or court proceedings to sustain some or all of the positions we
take. A court may not agree with some or all of the positions we take. Any
contest with the IRS may materially and adversely impact the market for our
common units and the price at which they trade. In addition, our costs of any
contest with the IRS will be borne indirectly by our unitholders and our general
partner because the costs will reduce our cash available for
distribution.





You
may be required to pay taxes on your share of our income even if you do not
receive any cash distributions from us.





Because
our unitholders are treated as partners to whom we will allocate taxable income
which could be different in amount than the cash we distribute, you may be
required to pay any federal income taxes and, in some cases, state and local
income taxes on your share of our taxable income even if you receive no cash
distributions from us. You may not receive cash distributions from us equal to
your share of our taxable income or even equal to the actual tax liability that
results from that income.





Tax
gain or loss on the disposition of our common units could be more or less than
expected.





If you
sell your common units, you will recognize a gain or loss equal to the
difference between the amount realized and your tax basis in those common units.
Because distributions in excess of your allocable share of our net taxable
income decrease your tax basis in your common units, the amount, if any, of such
prior excess distributions with respect to the units you sell will, in effect,
become taxable income to you if you sell such units at a price greater than your
tax basis in those units, even if the price you receive is less than your
original cost. A substantial portion of the amount realized, whether or not
representing gain, may be ordinary income due to potential recapture items,
including depreciation recapture. In addition, because the amount realized
includes a unitholder’s share of our non-recourse liabilities, if you sell your
units, you may incur a tax liability in excess of the amount of cash you receive
from the sale.





Tax-exempt
entities and non-United States persons face unique tax issues from owning our
common units that may result in adverse tax consequences to them.





Investment
in common units by tax-exempt entities, such as individual retirement accounts
(“IRAs”), other retirement plans and non-United States persons raises issues
unique to them. For example, virtually all of our


45
 Table of Contents





income
allocated to organizations that are exempt from federal income tax, including
IRAs and other retirement plans, will be unrelated business taxable income and
will be taxable to them. Distributions to non-United States persons will be
reduced by withholding taxes at the highest applicable effective tax rate and
non-United States persons will be required to file U.S. federal tax returns and
pay tax on their share of our taxable income. If you are a tax-exempt entity or
a non-United States person, you should consult your tax advisor before investing
in our common units.





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.




Because
we cannot match transferors and transferees of common units and because of other
reasons, we will adopt depreciation and amortization positions that may not
conform to all aspects of existing Treasury Regulations and may result in audit
adjustments to our unitholders’ tax returns. A successful IRS challenge to those
positions could adversely affect the amount of tax benefits available to you. It
also could affect the timing of these tax benefits or the amount of gain from
the sale of common units and could have a negative impact on the value of our
common units or result in audit adjustments to your tax returns.





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





Because a
unitholder whose units are loaned to a “short seller” to cover a short sale of
units may be considered as having disposed of the loaned units, he may no longer
be treated for tax purposes as a partner with respect to those units during the
period of the loan to the short seller and the unitholder may recognize gain or
loss from such disposition. Moreover, during the period of the loan to the short
seller, any of our income, gain, loss or deduction with respect to those units
may not be reportable by the unitholder and any cash distributions received by
the unitholder as to those units could be fully taxable as ordinary income.
Unitholders desiring to assure their status as partners and avoid the risk of
gain recognition from a loan to a short seller are urged to modify any
applicable brokerage account agreements to prohibit their brokers from borrowing
their units.





We
have adopted certain valuation methodologies that may result in a shift of
income, gain, loss and deduction between the general partner and the
unitholders. The IRS may challenge this treatment, which could adversely affect
the value of our common units.





When we
issue additional units or engage in certain other transactions, we will
determine the fair market value of our assets and allocate any unrealized gain
or loss attributable to our assets to the capital accounts of our unitholders
and our general partner. Our methodology may be viewed as understating the value
of our assets. In that case, there may be a shift of income, gain, loss and
deduction between certain unitholders and the general partner, which may be
unfavorable to such unitholders. Moreover, under our valuation methods,
subsequent purchasers of common units may have a greater portion of their
Internal Revenue Code Section 743(b) adjustment allocated to our tangible
assets and a lesser portion allocated to our intangible assets. The IRS may
challenge our valuation methods or our allocation of the Section 743(b)
adjustment attributable to our tangible and intangible assets and allocations of
income, gain, loss and deduction between the general partner and certain of our
unitholders.





A
successful IRS challenge to these methods or allocations could adversely affect
the amount of taxable income or loss being allocated to our unitholders. It also
could affect the amount of gain from our unitholders’ sale of common units and
could have a negative impact on the value of our common units or result in audit
adjustments to our unitholders’ tax returns without the benefit of additional
deductions.





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.





We will
be considered to have terminated our partnership for federal income tax purposes
if there is a sale or exchange of 50% or more of the total interests in our
capital and profits within a twelve-month period. For purposes of determining
whether the 50% threshold has been met, multiple sales of the same interest are
counted only once.


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Our
termination would, among other things, result in the closing of our taxable year
for all unitholders, which would result in us filing two tax returns (and our
unitholders may receive two Schedules K-1) for one fiscal year and could
result in a deferral of depreciation deductions allowable in computing our
taxable income. In the case of a unitholder reporting on a taxable year other
than a fiscal year ending December 31, the closing of our taxable year may
also result in more than twelve months of our taxable income or loss being
includable in his taxable income for the year of termination. Our termination
currently would not affect our classification as a partnership for federal
income tax purposes, but instead, we would be treated as a new partnership for
tax purposes. If treated as a new partnership, we must make new tax elections
and could be subject to penalties if we are unable to determine in a timely
manner that a termination occurred. The IRS has announced recently that it plans
to issue guidance regarding the treatment of constructive terminations of
publicly traded partnerships such as us. Any such guidance may change the
application of the rules discussed above and may affect the treatment of a
unitholder.





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





In
addition to federal income taxes, you may be subject to return filing
requirements and other taxes, including state and local taxes, unincorporated
business taxes and estate, inheritance or intangible taxes that are imposed by
the various jurisdictions in which we conduct business or own property, now or
in the future, even if you do not live in any of those jurisdictions. Further,
you may be subject to penalties for failure to comply with those return filing
requirements. We own assets and conduct business in the States of Texas and
Louisiana as well as other states. Currently, Texas does not impose a personal
income tax on individuals. As we make acquisitions or expand our business, we
may own assets or conduct business in states that impose a personal income tax.
It is your responsibility to file all U.S. federal, state and local tax
returns.





Item 1B. Unresolved Staff
Comments





None





Item 2. Properties





A
description of our properties is contained in “Item 1. Business” of this Annual
Report.





Our
principal executive offices are located at 1000 Louisiana Street, Suite 4300,
Houston, Texas 77002 and our telephone number is 713-584-1000.





Item 3. Legal Proceedings





On
December 8, 2005, WTG Gas Processing filed suit in the 333rd District Court
of Harris County, Texas against several defendants, including Targa Resources,
Inc. and three other Targa entities and private equity funds affiliated with
Warburg Pincus LLC, seeking damages from the defendants. The suit alleges that
Targa and private equity funds affiliated with Warburg Pincus LLC, along with
ConocoPhillips and Morgan Stanley, tortiously interfered with (i) a
contract WTG claims to have had to purchase the SAOU System from ConocoPhillips
and (ii) prospective business relations of WTG. WTG claims the alleged
interference resulted from Targa’s competition to purchase the ConocoPhillips’
assets and its successful acquisition of those assets in 2004. On
October 2, 2007, the District Court granted defendants’ motions for summary
judgment on all of WTG’s claims. WTG’s motion to reconsider and for a new trial
was overruled. On January 2, 2008, WTG filed a notice of appeal. On
February 3, 2009, the parties presented oral arguments to the 14th
Court of Appeals in Houston Texas. On February 23, 2010, the 14th
Court of Appeals affirmed the District Court’s final judgment in favor of
defendants in its entirety. Targa has agreed to indemnify us for any claim or
liability arising out of the WTG suit.





We are
not a party to any other legal proceedings other than legal proceedings arising
in the ordinary course of our business. We are a party to various administrative
and regulatory proceedings that have arisen in the ordinary course of our
business. See “Item 1. Business—Regulation of Operations” and “Item 1.
Business—Environmental, Health and Safety Matters.”





Item 4. Reserved








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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





Our
common units have been listed on the New York Stock Exchange since
January 25, 2010 under the symbol “NGLS.” Previously, our common units were
listed on The NASDAQ Stock Market LLC (“NASDAQ”) under the same symbol. The
following table sets forth the high and low sales prices of the common units, as
reported by NASDAQ, as well as the amount of cash distributions declared for the
period January 1, 2008 through December 31, 2009.


Distribution
            
            
            Distributionper
            
            
            perCommon
            
            
            SubordinatedQuarter Ended
            
            High
            
            
            Low
            
            
            Unit
            
            
            UnitDecember
      31, 2009
            
            $
            25.33
            
            
            $
            17.19
            
            
            $
            0.5175
            
            
            $
            -September
      30, 2009
            
            
            19.00
            
            
            
            13.65
            
            
            
            0.5175
            
            
            
            -June
      30, 2009
            
            
            14.98
            
            
            
            8.61
            
            
            
            0.5175
            
            
            
            -March
      31, 2009
            
            
            10.74
            
            
            
            7.08
            
            
            
            0.5175
            
            
            
            0.5175December
      31, 2008
            
            
            17.11
            
            
            
            6.04
            
            
            
            0.5175
            
            
            
            0.5175September
      30, 2008
            
            
            24.46
            
            
            
            15.18
            
            
            
            0.5175
            
            
            
            0.5175June
      30, 2008
            
            
            27.08
            
            
            
            22.93
            
            
            
            0.5125
            
            
            
            0.5125March
      31, 2008
            
            
            29.54
            
            
            
            20.88
            
            
            
            0.4175
            
            
            
            0.4175








As of
February 23, 2010, there were approximately 62 unitholders of record of our
common units. This number does not include unitholders whose units are held in
trust by other entities. The actual number of unitholders is greater than the
number of holders of record. There is no established trading market for the
1,387,360 general partner units held by our general partner.





On
February 12, 2010, we paid cash distributions of $0.5175 per unit on our
outstanding common units. The total distribution paid was $38.8 million, with
$24.8 million paid to our non-affiliated common unitholders and $10.4 million,
$0.8 million and $2.8 million paid to Targa for its common unit ownership,
general partner interest and incentive distribution rights.





Distributions
of Available Cash





General.Our partnership
agreement requires that, within 45 days after the end of each quarter, we
distribute all of our available cash to unitholders of record on the applicable
record date, as determined by our general partner.





Definition of Available Cash.The term “available cash,” for any quarter, means all cash and cash
equivalents on hand on the date of determination of available cash for that
quarter 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.





Minimum Quarterly Distribution.We intend to make cash distributions to the holders of common units on a
quarterly basis in an amount equal to at least the minimum quarterly
distribution of $0.3375 per unit or $1.35 per





48
 Table of Contents





unit on
an annualized basis, to the extent we have sufficient cash from our operations
after establishment of cash reserves and payment of fees and expenses, including
payments to our general partner. However, there is no guarantee that we will pay
the minimum quarterly distribution on the units in any quarter. Even if our cash
distribution policy is not modified or revoked, the amount of distributions paid
under our policy and the decision to make any distribution is determined by our
general partner, taking into consideration the terms of our partnership
agreement. The board of directors of our general partner has broad discretion to
establish cash reserves that it determines are necessary or appropriate to
properly conduct our business. These can include cash reserves for future
capital and maintenance expenditures, reserves to stabilize distributions of
cash to our unitholders, reserves to reduce debt or, as necessary, reserves to
comply with the term of any of our agreements or obligations. We will be
prohibited from making any distributions to unitholders if it would cause an
event of default or an event of default exists, under our credit agreement or
indenture.





As part
of our acquisition of Targa’s Downstream Business, Targa agreed to provide
distribution support to us in the form of a reduction in the reimbursement for
general and administrative expense allocated to us if necessary (or make a
payment to us, if needed) for a 1.0 times distribution coverage ratio, at the
current distribution level of $0.5175 per limited partner unit, subject to
maximum support of $8 million in any quarter. The distribution support is
in effect for the nine-quarter period beginning with the fourth quarter of 2009
and continuing through the fourth quarter of 2011. No distribution support was
required for the fourth quarter of 2009.





General Partner Interest.Our
general partner is currently entitled to 2% of all quarterly distributions that
we make prior to our liquidation. As of February 28, 2010 our general partner
interest is represented by 1,387,360 general partner units. Our general
partner has the right, but not the obligation, to contribute a proportional
amount of capital to us to maintain its current general partner interest. The
general partner’s 2% interest in these distributions will be reduced if we issue
additional units in the future and our general partner does not contribute a
proportional amount of capital to us to maintain its 2% general partner
interest.





Incentive Distribution Rights.Our general partner also currently holds incentive distribution rights
that entitle it to receive up to a maximum of 50% of the cash we distribute in
excess of $0.50625 per unit per quarter. The maximum distribution of 50%
includes distributions paid to our general partner on its general partner
interest and assumes that our general partner maintains its general partner
interest at 2%. The maximum distribution of 50% does not include any
distributions that our general partner may receive on limited partner units that
it owns.





Recent
Sales of Unregistered Units





None





Repurchase
of Equity by Targa Resources Partners LP





None





Item 6. Selected Financial Data





SELECTED
FINANCIAL AND OPERATING DATA





The
following table presents selected historical consolidated financial and
operating data of Targa Resources Partners LP. See “Basis of Presentation”
included under Note 2 to our “Consolidated Financial Statements” beginning on
page F-1 of this Annual Report for information regarding the retrospective
adjustment of our financial information for the years 2005 through 2009 as
entities under common control in connection with our acquisition of the
Downstream Business. The information contained herein should be read in
conjunction with our “Management’s Discussion and Analysis of Financial
Condition and Results of Operations” and “Consolidated Financial Statements”
contained in this Annual Report.








49
 Table of Contents





The
following table summarizes selected financial and operating data for the periods
and as of the dates indicated:


Year Ended December 31,2009
            
            
            2008
            
            
            2007
            
            
            2006
            
            
            2005(In
      millions, except operating and price data)Statement
      of Operations data:Revenues
      (1) (2)
            
            $
            4,095.6
            
            
            $
            7,502.1
            
            
            $
            6,843.7
            
            
            $
            5,930.1
            
            
            $
            1,771.5Costs
      and expenses:Product
      purchases (2)
            
            
            3,585.6
            
            
            
            6,950.8
            
            
            
            6,302.0
            
            
            
            5,501.5
            
            
            
            1,624.2Operating
      expenses
            
            
            185.1
            
            
            
            254.0
            
            
            
            219.6
            
            
            
            193.1
            
            
            
            44.3Depreciation
      and amortization expense
            
            
            101.2
            
            
            
            97.8
            
            
            
            93.5
            
            
            
            90.7
            
            
            
            26.3General
      and administrative expense
            
            
            78.9
            
            
            
            68.6
            
            
            
            64.0
            
            
            
            57.3
            
            
            
            23.0Other
            
            
            (0.8
            )
            
            
            (0.9
            )
            
            
            (0.3
            )
            
            
            -
            
            
            
            -Total
      costs and expenses
            
            
            3,950.0
            
            
            
            7,370.3
            
            
            
            6,678.8
            
            
            
            5,842.6
            
            
            
            1,717.8Income
      from operations
            
            
            145.6
            
            
            
            131.8
            
            
            
            164.9
            
            
            
            87.5
            
            
            
            53.7Other
      income (expense):Interest
      expense from affiliate
            
            
            (43.4
            )
            
            
            (59.2
            )
            
            
            (58.5
            )
            
            
            -
            
            
            
            -Interest
      expense allocated from Parent
            
            
            -
            
            
            
            -
            
            
            
            (19.4
            )
            
            
            (127.3
            )
            
            
            (27.9
            )Other
      interest expense, net
            
            
            (52.0
            )
            
            
            (37.9
            )
            
            
            (21.5
            )
            
            
            0.2
            
            
            
            -Equity
      in earnings of unconsolidated investment
            
            
            5.0
            
            
            
            3.9
            
            
            
            3.5
            
            
            
            2.8
            
            
            
            0.4Gain
      (loss) on debt repurchases
            
            
            (1.5
            )
            
            
            13.1
            
            
            
            -
            
            
            
            -
            
            
            
            (3.7
            )Gain
      (loss) on mark-to-market derivative instruments
            
            
            0.8
            
            
            
            (1.0
            )
            
            
            (30.2
            )
            
            
            16.8
            
            
            
            (12.0
            )Other
      income (expense):
            
            
            0.7
            
            
            
            1.4
            
            
            
            (1.1
            )
            
            
            (0.2
            )
            
            
            (0.1
            )Income
      (loss) before income taxes
            
            
            55.2
            
            
            
            52.1
            
            
            
            37.7
            
            
            
            (20.2
            )
            
            
            10.4Income
      tax expense
            
            
            (1.0
            )
            
            
            (2.4
            )
            
            
            (2.5
            )
            
            
            (3.4
            )
            
            
            -Net
      income (loss)
            
            
            54.2
            
            
            
            49.7
            
            
            
            35.2
            
            
            
            (23.6
            )
            
            
            10.4Less:Net
      income (loss) attributable to noncontrolling interest
            
            
            2.2
            
            
            
            0.3
            
            
            
            0.1
            
            
            
            (0.6
            )
            
            
            0.2Net
      income (loss) attributable to Targa Resources Partners LP
            
            
            52.0
            
            
            
            49.4
            
            
            
            35.1
            
            
            $
            (23.0
            )
            
            $
            10.2Net
      income (loss) attributable to predecessor operations
            
            $
            (2.4
            )
            
            $
            (42.1
            )
            
            $
            7.0Net
      income attributable to general partner
            
            
            10.4
            
            
            
            7.0
            
            
            
            0.6Net
      income attributable to limited partners
            
            
            44.0
            
            
            
            84.5
            
            
            
            27.5Net
      income attributable to Targa Resources Partners LP
            
            $
            52.0
            
            
            $
            49.4
            
            
            $
            35.1Net
      income per limited partner unit - basic and diluted
            
            $
            0.86
            
            
            $
            1.83
            
            
            $
            0.81Weighted
      average limited partner units outstanding -basic
      and diluted
            
            
            51.2
            
            
            
            46.2
            
            
            
            34.0Financial
      data:Operating
      margin (3)
            
            $
            324.9
            
            
            $
            297.3
            
            
            $
            322.1
            
            
            $
            235.5
            
            
            $
            103.0Adjusted
      EBITDA (4)
            
            
            286.3
            
            
            
            269.4
            
            
            
            260.5
            
            
            
            179.2
            
            
            
            76.2Distributable
      cash flow (5)
            
            
            176.3
            
            
            
            120.7
            
            
            
            132.2
            
            
            
            36.3
            
            
            
            50.5Operating
      data:Gathering
      throughput, MMcf/d (6)
            
            
            468.6
            
            
            
            445.8
            
            
            
            452.0
            
            
            
            433.8
            
            
            
            302.4Plant
      natural gas inlet, MMcf/d (7)(8)
            
            
            445.9
            
            
            
            421.2
            
            
            
            429.3
            
            
            
            419.6
            
            
            
            253.6Gross
      NGL production, MBbl/d
            
            
            42.7
            
            
            
            42.0
            
            
            
            42.6
            
            
            
            42.4
            
            
            
            23.5Natural
      gas sales, BBtu/d (8)
            
            
            390.9
            
            
            
            415.6
            
            
            
            410.2
            
            
            
            489.4
            
            
            
            259.3NGL
      sales, MBbl/d
            
            
            273.1
            
            
            
            297.3
            
            
            
            310.1
            
            
            
            290.1
            
            
            
            57.6Condensate
      sales, MBbl/d
            
            
            2.8
            
            
            
            2.5
            
            
            
            3.6
            
            
            
            3.3
            
            
            
            1.3Average
      realized prices (9):Natural
      gas, $/MMBtu
            
            
            3.96
            
            
            
            8.45
            
            
            
            6.63
            
            
            
            6.64
            
            
            
            9.36NGL,
      $/gal
            
            
            0.79
            
            
            
            1.39
            
            
            
            1.19
            
            
            
            1.03
            
            
            
            1.01Condensate,
      $/Bbl
            
            
            57.07
            
            
            
            90.00
            
            
            
            72.11
            
            
            
            57.47
            
            
            
            65.92






50
 Table of Contents


Year Ended December 31,2009
              
              
              2008
              
              
              2007
              
              
              2006
              
              
              2005(In
      millions, except operating and price data)Balance
      Sheet Data (at year end):Property
      plant and equipment, net
              
              $
              1,678.5
              
              
              $
              1,719.1
              
              
              $
              1,716.4
              
              
              $
              1,732.6
              
              
              $
              1,843.4Total
      assets
              
              
              2,180.9
              
              
              
              2,314.8
              
              
              
              2,702.9
              
              
              
              2,401.0
              
              
              
              2,524.4Long-term
      allocated debt, less current maturities
              
              
              -
              
              
              
              773.9
              
              
              
              711.3
              
              
              
              1,029.0
              
              
              
              1,532.0Long-term
      debt, less current maturities
              
              
              908.4
              
              
              
              696.8
              
              
              
              626.3
              
              
              
              -
              
              
              
              -Total
      equity
              
              
              836.2
              
              
              
              553.1
              
              
              
              614.4
              
              
              
              433.6
              
              
              
              581.1Cash
      Flow Data:Net
      cash provided by (used in):Operating
      activities
              
              $
              299.8
              
              
              $
              293.0
              
              
              $
              268.3
              
              
              $
              169.9
              
              
              $
              21.7Investing
      activities
              
              
              (57.1
              )
              
              
              (86.1
              )
              
              
              (76.8
              )
              
              
              (54.6
              )
              
              
              (8.0
              )Financing
      activities
              
              
              (277.6
              )
              
              
              (175.9
              )
              
              
              (139.7
              )
              
              
              (110.7
              )
              
              
              (12.0
              )Cash
      dividends declared per unit
              
              
              2.07
              
              
              
              1.97
              
              
              
              1.24
              
              
              
              N/A
              
              
              
              N/A
 _______


(1)
            Includes
      business interruption insurance revenues of $2.4 million,
      $18.7 million, $6.4 million and $7.0 million for the years
      ended 2009, 2008, 2007 and 2006.


(2)  
      During 2009, we reclassified NGL marketing fractionation and other service
      fees to revenues that were originally recorded in product purchase costs.
      The reclassification increased revenues and product purchases for 2008,
      2007, 2006 and 2005 by $28.7 million, $27.6 million, $20.3 million and
      $3.9 million.
              (3)  
      Operating margin is total operating revenues less product purchases and
      operating expense. See “Item 7. Management’s Discussion and Analysis of
      Financial Condition and Results of Operations—How We Evaluate Our
      Operations—Operating Margin” and “Non-GAAP Financial
      Measures.”(4)  
      Adjusted EBITDA is net income before interest, income taxes, depreciation
      and amortization and non-cash income or loss related to derivative
      instruments. See “Item 7. Management’s Discussion and Analysis of
      Financial Condition and Results of Operations—How We Evaluate Our
      Operations—Adjusted EBITDA” and “Non-GAAP Financial
    Measures.”(5)  
      Distributable Cash Flow is net income plus depreciation and amortization
      and deferred taxes, adjusted for losses/(gains) on mark-to-market
      derivative contracts and debt repurchases, less maintenance capital
      expenditures. See “Item 7. Management’s Discussion and Analysis of
      Financial Condition and Results of Operations—How We Evaluate Our
      Operations—Distributable Cash Flow” and “Non-GAAP Financial
      Measures.”


(6)
            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.


(7)
            Plant
      natural gas inlet represents the volume of natural gas passing through the
      meter located at the inlet of a natural gas processing
    plant.


(8)
            Plant
      natural gas inlet volumes include producer take-in-kind, while natural gas
      sales exclude producer take-in-kind
volumes.


(9)
            Average
      realized prices include the impact of hedging
  activities.





Non-GAAP
Financial Measures





Adjusted EBITDA.We define
Adjusted EBITDA as net income before interest, income taxes, depreciation and
amortization and non-cash income or loss related to derivative instruments.
Adjusted EBITDA is used as a supplemental financial measure by our management
and by external users of our financial statements such as investors, commercial
banks and others, to assess:





·
            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.





51
 Table of Contents





The
economic substance behind management’s use of Adjusted EBITDA is to measure the
ability of our assets to generate cash sufficient to pay interest costs, support
our indebtedness and make distributions to our investors.





The
generally accepted accounting principles (“GAAP”) measures most directly
comparable to Adjusted EBITDA are net cash provided by operating activities and
net income. Adjusted EBITDA should not be considered as an alternative to GAAP
net cash provided by operating activities and GAAP net income. Adjusted EBITDA
is not a presentation made in accordance with GAAP and has important limitations
as an analytical tool. You should not consider Adjusted EBITDA in isolation or
as a substitute for analysis of our results as reported under GAAP. Because
Adjusted EBITDA excludes some, but not all, items that affect net income and net
cash provided by operating activities and is defined differently by different
companies in our industry, our definition of Adjusted EBITDA may not be
comparable to similarly titled measures of other companies. Management
compensates for the limitations of Adjusted EBITDA as an analytical tool by
reviewing the comparable GAAP measures, understanding the differences between
the measures and incorporating these insights into management’s decision-making
processes.





Year Ended December 31,2009
              
              
              2008
              
              
              2007
              
              
              2006
              
              
              2005Reconciliation
      of net cash provided by
              
              (In
      millions)operating
      activities to Adjusted EBITDA:Net
      cash provided by operating activities
              
              $
              299.8
              
              
              $
              293.0
              
              
              $
              268.3
              
              
              $
              169.9
              
              
              $
              21.7Net
      income attributable to noncontrolling interest
              
              
              (2.2
              )
              
              
              (0.3
              )
              
              
              (0.1
              )
              
              
              0.6
              
              
              
              (0.2
              )Interest
      expense, net (1)
              
              
              48.2
              
              
              
              35.8
              
              
              
              39.1
              
              
              
              118.0
              
              
              
              22.7Gain
      (loss) on debt repurchases
              
              
              (1.5
              )
              
              
              13.1
              
              
              
              -
              
              
              
              -
              
              
              
              (3.7
              )Termination
      of commodity derivatives
              
              
              -
              
              
              
              87.4
              
              
              
              -
              
              
              
              -
              
              
              
              -Current
      income tax expense
              
              
              0.2
              
              
              
              0.6
              
              
              
              0.6
              
              
              
              -
              
              
              
              -Other
              
              
              (1.6
              )
              
              
              3.7
              
              
              
              (1.5
              )
              
              
              (0.6
              )
              
              
              (4.3
              )Changes
      in operating assets and liabilities whichused
      (provided) cash:Accounts
      receivable and other assets
              
              
              69.4
              
              
              
              (658.2
              )
              
              
              145.7
              
              
              
              (71.1
              )
              
              
              19.4Accounts
      payable and other liabilities
              
              
              (126.0
              )
              
              
              494.3
              
              
              
              (191.6
              )
              
              
              (37.6
              )
              
              
              20.6Adjusted
      EBITDA
              
              $
              286.3
              
              
              $
              269.4
              
              
              $
              260.5
              
              
              $
              179.2
              
              
              $
              76.2


________


(1)
            Net
      of amortization of debt issuance costs of $3.8 million, $2.1 million, $1.8
      million, $9.1 million and $5.2 million for 2009, 2008, 2007, 2006 and
      2005.





Year Ended December 31,2009
            
            
            2008
            
            
            2007
            
            
            2006
            
            
            2005Reconciliation
      of net income (loss) attributable to Targa
            
            (In
      millions)Resources
      Partners LP to Adjusted EBITDA:Net
      income attributable to Targa Resources Partners LP
            
            $
            52.0
            
            
            $
            49.4
            
            
            $
            35.1
            
            
            $
            (23.0
            )
            
            $
            10.2Add:Interest
      expense, net (1)
            
            
            95.4
            
            
            
            97.1
            
            
            
            99.4
            
            
            
            127.1
            
            
            
            27.9Income
      tax expense
            
            
            1.0
            
            
            
            2.4
            
            
            
            2.5
            
            
            
            3.4
            
            
            
            -Depreciation
      and amortization expense
            
            
            101.2
            
            
            
            97.8
            
            
            
            93.5
            
            
            
            90.7
            
            
            
            26.3Non-cash
      (gain) loss related to derivatives
            
            
            37.6
            
            
            
            23.4
            
            
            
            30.8
            
            
            
            (18.3
            )
            
            
            12.0Noncontrolling
      interest adjustment
            
            
            (0.9
            )
            
            
            (0.7
            )
            
            
            (0.8
            )
            
            
            (0.7
            )
            
            
            (0.2
            )Adjusted
      EBITDA
            
            $
            286.3
            
            
            $
            269.4
            
            
            $
            260.5
            
            
            $
            179.2
            
            
            $
            76.2


________


(1)
            Includes
      affiliate interest expense of $43.4 million, $59.2 million and $58.5
      million for 2009, 2008 and 2007 and allocated interest expense of $19.4
      million, $127.3 million and $27.9 million for 2007, 2006 and
      2005.





Operating Margin.We define
operating margin as total operating revenues, which consist of natural gas and
NGL sales plus service fee revenues, less product purchases, which consist
primarily of producer payments and other natural gas purchases and operating
expense. Management reviews operating margin monthly for
consistency


52
 Table of Contents





The GAAP
measure most directly comparable to operating margin is net income. Operating
margin should not be considered as an alternative to GAAP net income. Operating
margin is not a presentation made in accordance with GAAP and has important
limitations as an analytical tool. You should not consider operating margin in
isolation or as a substitute for analysis of our results as reported under GAAP.
Because operating margin excludes some, but not all, items that affect net
income and is defined differently by different companies in our industry, our
definition of operating margin may not be comparable to similarly titled
measures of other companies, thereby diminishing its utility. Management
compensates for the limitations of operating margin as an analytical tool by
reviewing the comparable GAAP measure, understanding the differences between the
measures and incorporating these insights into management’s decision-making
processes.





·
            We
      believe that investors benefit from having access to the same financial
      measures that our management uses in evaluating our operating results.
      Operating margin provides useful information to investors because it is
      used as a supplemental financial measure by our management and by external
      users of our financial statements, including such investors, commercial
      banks and others, to assess:





·
            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.





Year Ended December 31,2009
            
            
            2008
            
            
            2007
            
            
            2006
            
            
            2005(In
      millions)Reconciliation
      of net income (loss) attributable to TargaResources
      Partners LP to operating margin:Net
      income (loss) attributable to Targa Resources Partners LP
            
            $
            52.0
            
            
            $
            49.4
            
            
            $
            35.1
            
            
            $
            (23.0
            )
            
            $
            10.2Add:Depreciation
      and amortization expense
            
            
            101.2
            
            
            
            97.8
            
            
            
            93.5
            
            
            
            90.7
            
            
            
            26.3General
      and administrative and other expense
            
            
            78.1
            
            
            
            67.7
            
            
            
            63.7
            
            
            
            57.3
            
            
            
            23.0Interest
      expense, net (1)
            
            
            95.4
            
            
            
            97.1
            
            
            
            99.4
            
            
            
            127.1
            
            
            
            27.9Income
      tax expense
            
            
            1.0
            
            
            
            2.4
            
            
            
            2.5
            
            
            
            3.4
            
            
            
            -Loss
      (gain) on debt repurchases
            
            
            1.5
            
            
            
            (13.1
            )
            
            
            -
            
            
            
            -
            
            
            
            3.7Loss
      (gain) related to mark-to-market derivative instruments
            
            
            (0.8
            )
            
            
            1.0
            
            
            
            30.2
            
            
            
            (16.8
            )
            
            
            12.0Other,
      net
            
            
            (3.5
            )
            
            
            (5.0
            )
            
            
            (2.3
            )
            
            
            (3.2
            )
            
            
            (0.1
            )Operating
      margin
            
            $
            324.9
            
            
            $
            297.3
            
            
            $
            322.1
            
            
            $
            235.5
            
            
            $
            103.0





_______


(1)
            Includes
      affiliated interest expense of $43.4 million, $59.2 million and
      $58.5 million for 2009, 2008 and 2007 and allocated interest of $19.4
      million, $127.3 million and $27.9 million for 2007, 2006 and
      2005.





Distributable Cash
Flow. We define distributable cash flow as net income attributable
to Targa Resources Partners LP plus depreciation and amortization, deferred
taxes and amortization of debt issue costs included in interest expense,
adjusted for non-cash losses/(gains) related to mark-to-market derivative
instruments and debt repurchases, less maintenance capital expenditures.
Distributable cash flow is a significant performance metric used by us and by
external users of our financial statements, such as investors, commercial banks,
research analysts and others to compare basic cash flows generated by us (prior
to the establishment of any retained cash reserves by the board of directors of
our general partner) to the cash distributions we expect to pay our unitholders.
Using this


53
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metric,
management can quickly compute the coverage ratio of estimated cash flows to
planned cash distributions. Distributable cash flow is also an important
financial measure for our unitholders since it serves as an indicator of our
success in providing a cash return on investment. Specifically, this financial
measure indicates to investors whether or not we are generating cash flow at a
level that can sustain or support an increase in our quarterly distribution
rates. Distributable cash flow is also a quantitative standard used throughout
the investment community with respect to publicly-traded partnerships and
limited liability companies because the value of a unit of such an entity is
generally determined by the unit’s yield (which in turn is based on the amount
of cash distributions the entity pays to a unitholder).





The
economic substance behind our use of distributable cash flow is to measure the
ability of our assets to generate cash flow sufficient to make distributions to
our investors.





The GAAP
measure most directly comparable to distributable cash flow is net income.
Distributable cash flow should not be considered as an alternative to GAAP net
income. Distributable cash flow is not a presentation made in accordance with
GAAP and has important limitations as an analytical tool. You should not
consider distributable cash flow in isolation or as a substitute for analysis of
our results as reported under GAAP. Because distributable cash flow excludes
some, but not all, items that affect net income and is defined differently by
different companies in our industry, our definition of distributable cash flow
may not be compatible to similarly titled measures of other companies, thereby
diminishing its utility.





We
compensate for the limitations of distributable cash flow as an analytical tool
by reviewing the comparable GAAP measures, understanding the differences between
the measures and incorporating these insights into our decision making
processes.


Year Ended December 31,2009
            
            
            2008
            
            
            2007
            
            
            2006
            
            
            2005(In
      millions)Reconciliation
      of net income (loss)to
      distributable cash flow:Net
      income (loss) attributable to Targa ResourcesPartners
      LP
            
            $
            52.0
            
            
            $
            49.4
            
            
            $
            35.1
            
            
            $
            (23.0
            )
            
            $
            10.2Depreciation
      and amortization expense
            
            
            101.2
            
            
            
            97.8
            
            
            
            93.5
            
            
            
            90.7
            
            
            
            26.3Deferred
      income tax expense
            
            
            0.8
            
            
            
            1.8
            
            
            
            1.9
            
            
            
            3.4
            
            
            
            -Amortization
      of debt issue costs
            
            
            3.8
            
            
            
            2.1
            
            
            
            1.8
            
            
            
            9.1
            
            
            
            5.2Loss
      (gain) on debt repurchases
            
            
            1.5
            
            
            
            (13.1
            )
            
            
            -
            
            
            
            -
            
            
            
            3.7Non-cash
      loss (gain) on mark-to-market derivative instruments
            
            
            37.6
            
            
            
            23.4
            
            
            
            30.8
            
            
            
            (18.3
            )
            
            
            12.0Maintenance
      capital expenditures
            
            
            (20.0
            )
            
            
            (40.3
            )
            
            
            (30.4
            )
            
            
            (25.1
            )
            
            
            (6.9
            )Other
      (1)
            
            
            (0.6
            )
            
            
            (0.4
            )
            
            
            (0.5
            )
            
            
            (0.5
            )
            
            
            -Distributable
      cash flow
            
            $
            176.3
            
            
            $
            120.7
            
            
            $
            132.2
            
            
            $
            36.3
            
            
            $
            50.5





_______


(1)
            Other
      includes the non-controlling interest percentage of our unconsolidated
      investment’s depreciation, interest expense and maintenance capital
      expenditures.








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 Table of Contents





Below is
a reconciliation of distributable cash flow for the year ended December 31,
2009, to which unit holders are entitled which excludes the operations of the
Downstream Business prior to our acquisition of it:







For
      the Year Ended December 31, 2009Pre-AcquisitionDownstreamReconciliation
      of net income (loss) attributable to Targa Resources Partners LP to
      distributable cash flow:
              
              TRP LP
              
              
              Predecessor Operations
              
              
              Adjusted(In
      millions)Net
      income (loss) attributable to Targa Resources Partners LP
              
              $
              52.0
              
              
              $
              (2.4
              )
              
              $
              54.4Add:Depreciation
      and amortization expense
              
              
              101.2
              
              
              
              16.3
              
              
              
              84.9Deferred
      income tax expense
              
              
              0.8
              
              
              
              0.1
              
              
              
              0.7Amortization
      of debt issue costs
              
              
              3.8
              
              
              
              -
              
              
              
              3.8Loss
      (gain) on debt repurchases
              
              
              1.5
              
              
              
              -
              
              
              
              1.5Non-cash
      loss related to mark-to-market derivative instruments
              
              
              37.6
              
              
              
              -
              
              
              
              37.6Maintenance
      capital expenditures
              
              
              (20.0
              )
              
              
              (4.6
              )
              
              
              (15.4
              )Other
              
              
              (0.6
              )
              
              
              (0.6
              )
              
              
              -Distributable
      cash flow
              
              $
              176.3
              
              
              $
              8.8
              
              
              $
              167.5


Item 7. Management’s Discussion and Analysis of Financial Condition and
Results of Operations





The
following discussion analyzes our financial condition and results of operations.
You should read the following discussion of our financial condition and results
of operations in conjunction with our historical financial statements and notes
included in Part IV of this Annual Report.





Targa’s
conveyances to us of the North Texas System, the SAOU and LOU Systems and the
Downstream Business have been accounted for as transfers of net assets between
entities under common control. We recognize transfers of net assets between
entities under common control at Targa’s historical basis in the net assets
conveyed. In addition, transfers of net assets between entities under common
control are accounted for as if the transfer occurred at the beginning of the
period, and prior years are retroactively adjusted to furnish comparative
information similar to the pooling of interests method. The amount of the
purchase price in excess of Targa’s basis in the net assets, if any, is
recognized as a reduction to net parent investment.





Our
consolidated financial statements and all other financial information included
in this report have been retrospectively adjusted to assume that the acquisition
of the Downstream Business from Targa by us had occurred at the date when both
the Downstream Business and the North Texas System met the accounting
requirements for entities under common control (October 31, 2005) following
the acquisition of the SAOU and LOU Systems. As a result, financial statements
and financial information presented for prior periods in this report have been
retrospectively adjusted.





Overview





We are a
Delaware limited partnership formed by Targa to own, operate, acquire and
develop a diversified portfolio of complementary midstream energy assets. We are
engaged in the business of gathering, compressing, treating, processing and
selling natural gas and fractionating and selling NGLs and NGL
products.





We are
owned 98% by our limited partners and 2% by our general partner, Targa Resources
GP LLC, an indirect, wholly owned subsidiary of Targa. Our limited partner
common units began trading on the New York Stock Exchange on January 25,
2010 under the symbol “NGLS.” Previously, our limited partner common units were
listed on The NASDAQ Stock Market LLC under the same symbol.





55
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We
conduct our business operations through two divisions and report our results of
operations under four segments: Our Natural Gas Gathering and Processing
division is a single segment consisting of our natural gas gathering and
processing facilities, as well as certain fractionation capability integrated
within those facilities; and our NGL Logistics and Marketing division includes
three segments: Logistics Assets, NGL Distribution and Marketing, and Wholesale
Marketing.





Our
natural gas gathering and processing assets are located primarily in the Fort
Worth Basin in North Texas, the Permian Basin in West Texas and the onshore
region of the Louisiana Gulf Coast. Our NGL logistics and marketing assets are
located primarily at Mont Belvieu and Galena Park near Houston, Texas and in
Lake Charles, Louisiana, with terminals and transportation assets across the
U.S.





Factors
That Significantly Affect Our Results





Our
results of operations are substantially impacted by changes in commodity prices
as well as increases and decreases in the volume of natural gas that we gather
through our pipeline systems, which we refer to as throughput volume. Throughput
volumes generally are driven by wellhead production, our competitive position on
a regional basis and more broadly by prices and demand for natural gas and NGLs
(which may be impacted by economic, political and regulatory development factors
beyond our control).





Contract Mix. Our natural gas
gathering and processing contract arrangements can have a significant impact on
our profitability. Because of the significant volatility of natural gas and NGL
prices, the contract mix of our natural gas gathering and processing segment can
have a significant impact on our profitability. Negotiated contract terms are
based upon a variety of factors, including natural gas quality, geographic
location, the competitive environment at the time the contract is executed and
customer preferences. Contract mix and, accordingly, exposure to natural gas and
NGL prices may change over time as a result of changes in these underlying
factors.





Set forth
below is a table summarizing the contract mix of our natural gas gathering and
processing division for 2009 and the potential impacts of commodity prices on
operating margins:





Contract Type
            
            Percent of
              Throughput
            
            Impact of Commodity
  PricesPercent-of-Proceeds
            
            
            70%
            
            Decreases
      in natural gas and/or NGL prices generate decreases in operating
      margin.Wellhead
      Purchases/Keep Whole
            
            
            28%
            
            Increases
      in natural gas prices relative to NGL prices generate decreases in
      operating margin. Decreases in NGL prices relative to natural gas prices
      generate decreases in operating margin.Hybrid
            
            
            1%
            
            In
      periods of favorable processing economics, similar to percent-of-proceeds
      (or wellhead purchases/keep-whole in some circumstances, if economically
      advantageous to the processor). In periods of unfavorable processing
      economics, similar to fee-based.Fee
      Based
            
            
            1%
            
            No
      direct impact from commodity price
movements.








Actual
contract terms are based upon a variety of factors, including natural gas
quality, geographic location, the competitive commodity and pricing environment
at the time the contract is executed, and customer requirements. Our gathering
and processing contract mix and, accordingly, our exposure to natural gas and
NGL prices, may change as a result of producer preferences, competition, and
changes in production as wells decline at different rates or are added, our
expansion into regions where different types of contracts are more common as
well as other market factors. We prefer to enter into contracts with less
commodity price sensitivity including fee-based and percent-of-proceeds
arrangements.





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 Table of Contents





We
attempt to mitigate the impact of commodity prices on our results of operations
through hedging activities which can materially impact our results of
operations. See “Item 7A. Quantitative and Qualitative Disclosures About Market
Risk—Commodity Price Risk.”





Impact of Our Hedging
Activities. In an effort to reduce the variability of our cash flows, we
have hedged the commodity price associated with a portion of our expected
natural gas, NGLs and condensate equity volumes for the years 2010 through 2013
by entering into derivative financial instruments including swaps and purchased
puts (or floors). With these arrangements, we have attempted to mitigate our
exposure to commodity price movements with respect to our forecasted volumes for
this period. For additional information regarding our hedging activities, see
“Item 7A. Quantitative and Qualitative Disclosures About Market Risk—Commodity
Price Risk.”





General and Administrative
Expenses. Under the terms of the Second Amended and Restated Omnibus
Agreement (the “Omnibus Agreement”), we reimburse Targa for the payment of
certain operating and direct expenses, including compensation and benefits of
operating personnel, and for the provision of various general and administrative
services for our benefit. Pursuant to these arrangements, Targa performs
centralized corporate functions for us, such as legal, accounting, treasury,
insurance, risk management, health, safety and environmental, information
technology, human resources, credit, payroll, internal audit, tax, engineering
and marketing. We reimburse Targa for the direct expenses to provide these
services as well as other direct expenses it incurs on our behalf, such as
compensation of operational personnel performing services for our benefit and
the cost of its employee benefits, including 401(k), pension and health
insurance benefits. Our general partner determines the amount of general and
administrative expenses to be allocated to us in accordance with the Omnibus
Agreement.





We
reimbursed Targa for these general and administrative expenses as follows:
(i) with respect to the North Texas System, we reimbursed Targa for
(A) general and administrative expenses, which were capped at
$5 million annually, subject to certain increases through February 15,
2010, and (B) operating and certain direct expenses, which were not capped,
and (ii) with respect to the SAOU and LOU Systems and the Downstream
Business, we reimbursed Targa for general and administrative expenses, which
were not capped, allocated to the SAOU and LOU Systems and the Downstream
Business according to Targa’s allocation practice; and operating and certain
direct expenses, which were not capped.





During
the nine-quarter period beginning with the fourth quarter of 2009 and continuing
through the fourth quarter of 2011, Targa will provide distribution support to
us in the form of a reduction in the reimbursement for general and
administrative expense allocated to us if necessary (or make a payment to us, if
needed) for a 1.0 times distribution coverage ratio, at the current distribution
level of $0.5175 per limited partner unit, subject to maximum support of
$8 million in any quarter. No distribution support was required for the
fourth quarter of 2009.





Allocated
general and administrative expenses, including expenses allocated to the
Downstream Business, were $64.0 million, $61.2 million and
$60.4 million for 2009, 2008 and 2007 were subject to the cap contained in
the Omnibus Agreement.





In
addition to these allocated general and administrative expenses, we incur
incremental general and administrative expenses as a result of operating as a
separate publicly held limited partnership. These direct, incremental general
and administrative expenses, which were approximately $15.9 million,
$7.5 million and $3.6 million during 2009, 2008 and 2007, including
expenses associated with our equity offerings, financing arrangements and
acquisitions. These direct and incremental costs also include costs associated
with annual and quarterly reports to unitholders, tax return and
Schedule K-1 preparation and distribution, independent auditor fees,
registrar and transfer agent fees and independent director
compensation.





The
historical financial statements of the SAOU and LOU Systems, the North Texas
System and the Downstream Business include certain items that will not impact
our future results of operations and liquidity including the items described
below:





Affiliate Indebtedness.
Affiliate indebtedness prior to the contribution of the North Texas System and
our acquisitions of the SAOU and LOU Systems and the Downstream Business,
consisted of borrowings incurred by Targa and allocated to us for financial
reporting purposes. On January 1, 2007, Targa contributed to us affiliated
indebtedness related to the assets of the North Texas System of $846.3 million.
Also on January 1, 2007, Targa





57
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contributed
to us affiliated indebtedness related to the assets of Targa Downstream LP and
Targa LSNG LP of approximately $639.7 million (including accrued interest and
additional borrowings). During 2009, 2008 and 2007, we recorded $43.4 million,
$59.3 million and $58.5 million in interest expense associated with this
affiliated debt.





On
February 14, 2007, we borrowed approximately $294.5 million under our
credit facility. The proceeds from this borrowing, together with approximately
$371.2 million of net proceeds from our IPO, were used to repay
approximately $665.7 million of affiliate indebtedness associated with the
North Texas System. The remaining affiliated debt associated with the North
Texas System was retired and treated as a capital contribution to
us.





On
October 24, 2007, we completed our acquisition of the SAOU and LOU Systems
concurrently with the sale of 13,500,000 common units representing limited
partnership interests in us for gross proceeds of $362.7 million. We used
the net proceeds from the offering, after $2.5 million in offering expenses and
the payment of $24.2 million to Targa for certain hedge transactions, of
$322.5 million along with net borrowings of $375.5 million to pay
approximately $698.0 million of the acquisition costs of the SAOU and LOU
Systems. The allocated indebtedness from Targa related to the SAOU and LOU
Systems was $124.0 million. In conjunction with our acquisition of the SAOU
and LOU Systems, the allocated indebtedness was retired.





On
September 24, 2009, in connection with our acquisition of the Downstream
Business, the entire balance of affiliated indebtedness payable to Targa was
settled with a $397.5 million cash payment, the issuance of 8,527,615
common units with an agreed-upon value of $129.8 million, the issuance of
174,033 general partner units with an agreed-upon value of $2.7 million and
a deemed parent contribution of $287.3 million.





Working Capital Adjustments.Prior to the contribution of the North Texas System in February 2007, and
the acquisition of the SAOU and LOU Systems in October 2007, all intercompany
transactions, including commodity sales and expense reimbursements, were not
cash settled with the Targa, but were recorded as an adjustment to parent equity
on the balance sheet. The primary intercompany transactions between the
respective parent and the Predecessor Business are natural gas and NGL sales,
the provision of operations and maintenance activities and the provision of
general and administrative services. Prior to acquisition of the Downstream
Business in September 2009, all intercompany balances related to the Downstream
Business were settled with the parent as part of the customary settlement
process. Accordingly, the working capital of the Predecessor Business does not
reflect any affiliate accounts payable for the personnel and services provided
or paid for by the applicable parent on behalf of the Predecessor
Business.





Distributions
to our Unitholders





We intend
to make cash distributions to our unitholders and our general partner at least
at the minimum quarterly distribution rate of $0.3375 per common unit per
quarter ($1.35 per common unit on an annualized basis). Due to our cash
distribution policy, we expect that we will distribute to our unitholders most
of the cash generated by our operations. As a result, we expect that we will
rely upon external financing sources, including other debt and common unit
issuances, to fund our acquisition and expansion capital expenditures, as well
as our working capital needs.








58
 Table of Contents





The
following table shows the distributions we paid in 2009 and 2008:





Distributions Paid (1)
            
            
            DistributionsFor
      the Three
            
            Limited Partners
            
            
            General Partner
            
            
            
            
            
            per
      limitedDate Paid
            
            Months Ended
            
            Common
            
            
            Subordinated (2)
            
            
            Incentive
            
            
            
            2%
            
            
            Total
            
            
            partner unit(In
      millions, except per unit amounts)2009November
      14, 2009
            
            September
      30, 2009
            
            $
            31.9
            
            
            $
            -
            
            
            $
            2.6
            
            
            $
            0.7
            
            
            $
            35.2
            
            
            $
            0.5175August
      14, 2009
            
            June
      30, 2009
            
            
            23.9
            
            
            
            -
            
            
            
            2.0
            
            
            
            0.5
            
            
            
            26.4
            
            
            
            0.5175May
      15, 2009
            
            March
      31, 2009
            
            
            18.0
            
            
            
            5.9
            
            
            
            1.9
            
            
            
            0.5
            
            
            
            26.3
            
            
            
            0.5175February
      13, 2009
            
            December
      31, 2008
            
            
            18.0
            
            
            
            6.0
            
            
            
            1.9
            
            
            
            0.5
            
            
            
            26.4
            
            
            
            0.51752008November
      14, 2008
            
            September
      30, 2008
            
            $
            17.9
            
            
            $
            6.0
            
            
            $
            1.9
            
            
            $
            0.5
            
            
            $
            26.3
            
            
            $
            0.5175August
      14, 2008
            
            June
      30, 2008
            
            
            17.8
            
            
            
            5.9
            
            
            
            1.7
            
            
            
            0.5
            
            
            
            25.9
            
            
            
            0.5125May
      15, 2008
            
            March
      31, 2008
            
            
            14.5
            
            
            
            4.8
            
            
            
            0.2
            
            
            
            0.4
            
            
            
            19.9
            
            
            
            0.4175February
      14, 2008
            
            December
      31, 2007
            
            
            13.8
            
            
            
            4.6
            
            
            
            0.1
            
            
            
            0.4
            
            
            
            18.9
            
            
            
            0.3975


_______


(1)
            On
      February 12, 2010, we paid a cash distribution of $0.5175 per unit on our
      outstanding common units. The total distribution paid was
      $38.8 million, with $24.8 million paid to our non-affiliated
      common unitholders and $10.4 million, $0.8 million and
      $2.8 million paid to Targa for its common unit ownership, general
      partner interest and incentive distribution
  rights.


(2)
            Under
      the terms of our amended and restated Partnership Agreement, all
      11,528,231 subordinated units converted to common units on a one-to-one
      basis on May 19, 2009.





General
Trends and Outlook





We expect
our business to continue to be affected by the following key trends. Our
expectations are based on assumptions made by us and information currently
available to us. To the extent our underlying assumptions about or
interpretations of available information prove to be incorrect, our actual
results may vary materially from our expected results.





Natural Gas Supply and
Outlook. Fluctuations in energy prices can affect production rates and
investments by third parties in the development of new natural gas reserves.
Generally, drilling and production activity will increase as energy prices
increase. The recent substantial decline in natural gas prices has led many
exploration and production companies to reduce planned capital expenditures for
drilling and production activities during 2010 which could lead to a decrease in
the level of natural gas production in our areas of operation.




Significant Relationships.
The following table lists the percentage of our consolidated sales and
consolidated product purchases with our significant customers and
suppliers:





2009
            
            
            2008
            
            
            2007%
      of consolidated revenuesCPC
            
            
            17%
            
            
            
            20%
            
            
            
            22%%
      of consolidated product purchasesLouis
      Dreyfus Energy Services L.P.
            
            
            12%
            
            
            
            9%
            
            
            
            7%








No other
third party customer accounted for more than 10% of our consolidated revenues or
consolidated product purchases during these periods.





Commodity Prices.Our
operating income generally improves in an environment of higher natural gas, NGL
and condensate prices, primarily as a result of our percent-of-proceeds
contracts. Our processing profitability is largely dependent upon pricing and
market demand for natural gas, NGLs and condensate, which are beyond our control
and have been volatile. Recent weak economic conditions have negatively affected
the pricing and market demand





59
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for
natural gas, NGLs and condensate, which caused a reduction in profitability of
our processing operations. In a declining commodity price environment, without
taking into account our hedges, we will realize a reduction in cash flows under
our percent-of-proceeds contracts proportionate to average price declines. We
have attempted to mitigate our exposure to commodity price movements by entering
into hedging arrangements. For additional information regarding our hedging
activities, see “Item 7A. Quantitative and Qualitative Disclosures About Market
Risk—Commodity Price Risk.”





Volatile Capital Markets. We
are dependent on our ability to access the equity and debt capital markets in
order to fund acquisitions and expansion expenditures. Global financial markets
have been, and are expected to continue to be, extremely volatile and disrupted
and the current weak economic conditions have recently caused a significant
decline in commodity prices. As a result, we may be unable to raise equity or
debt capital on satisfactory terms, or at all, which may negatively impact the
timing and extent to which we execute growth plans. Prolonged periods of low
commodity prices or volatile capital markets may impact our ability or
willingness to enter into new hedges, fund organic growth, connect to new
supplies of natural gas, execute acquisitions or implement expansion capital
expenditures.





How
We Evaluate Our Operations





Our
profitability is a function of the difference between the revenues we receive
from our operations, including revenues from the natural gas, NGLs and
condensate we sell, and the costs associated with conducting our operations,
including the costs of wellhead natural gas and Y-grade that we purchase as well
as operating and general and administrative costs. Because commodity price
movements tend to impact both revenues and costs, increases or decreases in our
revenues alone are not necessarily indicative of increases or decreases in our
profitability. Our contract portfolio, the prevailing pricing environment for
natural gas and NGLs, and the natural gas and NGL throughput on our system are
important factors in determining our profitability. Our profitability is also
affected by the NGL content in gathered wellhead natural gas, demand for our
products and changes in our customer mix.





Our
management uses a variety of financial and operational measurements to analyze
our performance. These measurements include: (1) throughput volumes,
(2) facility efficiencies and fuel consumption; and the following non-GAAP
measures (3) operating margin, (4) operating expenses,
(5) Adjusted EBITDA and (6) distributable cash flow.





Throughput Volumes, Facility
Efficiencies and Fuel Consumption. Our profitability is impacted by our
ability to add new sources of natural gas supply to offset the natural decline
of existing volumes from natural gas wells that are connected to our systems.
This is achieved by connecting new wells, adding new volumes in existing areas
of production as well as by capturing supplies currently gathered by third
parties.





In
addition, we seek to increase operating margins by limiting volume losses and
reducing fuel consumption by increasing compression efficiency. With our
gathering systems’ extensive use of remote monitoring capabilities, we monitor
the volumes of natural gas received at the wellhead or central delivery points
along our gathering systems, the volume of natural gas received at our
processing plant inlets and the volumes of NGLs and residue natural gas
recovered by our processing plants. This information is tracked through our
processing plants to determine customer settlements and helps us increase
efficiency and reduce fuel consumption.





As part
of monitoring the efficiency of our operations, we measure the difference
between the volume of natural gas received at the wellhead or central delivery
points on our gathering systems and the volume received at the inlet of our
processing plants as an indicator of fuel consumption and line loss. We also
track the difference between the volume of natural gas received at the inlet of
the processing plant and the NGLs and residue gas produced at the outlet of such
plants to monitor the fuel consumption and recoveries of the facilities. These
volume, recovery and fuel consumption measurements are an important part of our
operational efficiency analysis.





Operating Margin. We review
performance based on operating margin. We define operating margin as total
operating revenues, which consist of natural gas and NGL sales plus service fee
revenues, less product purchases, which consist primarily of producer payments
and other natural gas purchases, and operating expense. Natural gas and NGL
sales revenue includes settlement gains and losses on commodity hedges. Our
operating margin is





60
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impacted
by volumes and commodity prices as well as by our contract mix and hedging
program, which are described in more detail below. We view our operating margin
as an important performance measure of the core profitability of our operations.
We review our operating margin monthly for consistency and trend
analysis.





The GAAP
measure most directly comparable to operating margin is net income. Operating
margin should not be considered as an alternative to GAAP net income. Operating
margin is not a presentation made in accordance with GAAP and has important
limitations as an analytical tool. You should not consider operating margin in
isolation or as a substitute for analysis of our results as reported under GAAP.
Because operating margin excludes some, but not all, items that affect net
income and is defined differently by different companies in our industry, our
definition of operating margin may not be comparable to similarly titled
measures of other companies, thereby diminishing its utility.





We
compensate for the limitations of operating margin as an analytical tool by
reviewing the comparable GAAP measure, understanding the differences between the
measures and incorporating these insights into our decision-making
processes.





Year Ended December 31,2009
            
            
            2008
            
            
            2007(In
      millions)Reconciliation
      of net income attributable to Targa Resources Partners LP to operating
      margin:Net
      income attributable to Targa Resources Partners LP
            
            $
            52.0
            
            
            $
            49.4
            
            
            $
            35.1Add:Depreciation
      and amortization expense
            
            
            101.2
            
            
            
            97.8
            
            
            
            93.5General
      and administrative and other expense
            
            
            78.1
            
            
            
            67.7
            
            
            
            63.7Interest
      expense, net (1)
            
            
            95.4
            
            
            
            97.1
            
            
            
            99.4Income
      tax expense
            
            
            1.0
            
            
            
            2.4
            
            
            
            2.5Loss
      (gain) on debt repurchases
            
            
            1.5
            
            
            
            (13.1
            )
            
            
            -Loss
      (gain) related to mark-to-market derivative instruments
            
            
            (0.8
            )
            
            
            1.0
            
            
            
            30.2Other,
      net
            
            
            (3.5
            )
            
            
            (5.0
            )
            
            
            (2.3
            )Operating
      margin
            
            $
            324.9
            
            
            $
            297.3
            
            
            $
            322.1





________


(1) 
Includes affiliate
interest expense of $43.4 million, $59.2 million and
$58.5 million for 2009, 2008 and 2007 and allocated interest expense of
$19.4 million for 2007.





Our
operating margin by segment and in total is as follows for the periods
indicated:





Year Ended December 31,2009
            
            
            2008
            
            
            2007(In
      millions)Natural
      Gas Gathering and Processing
            
            $
            168.4
            
            
            $
            215.8
            
            
            $
            203.8Logistics
      Assets
            
            
            87.0
            
            
            
            49.9
            
            
            
            40.0NGL
      Distribution and Marketing Services
            
            
            45.8
            
            
            
            18.5
            
            
            
            55.5Wholesale
      Marketing
            
            
            23.7
            
            
            
            13.1
            
            
            
            22.8$
            324.9
            
            
            $
            297.3
            
            
            $
            322.1








We
believe that investors benefit from having access to the same financial measures
that our management uses in evaluating our operating results. Operating margin
provides useful information to investors because it is used as a supplemental
financial measure by us and by external users of our financial statements,
including such investors, commercial banks and others, to assess:





·
            the
      financial performance of our assets without regard to financing methods,
      capital structure or historical cost
basis;







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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.





Operating Expenses. Operating
expenses are costs associated with the operation of a specific asset. Direct
labor, ad valorem taxes, repair and maintenance, utilities and contract services
compose the most significant portion of our operating expenses. These expenses
generally remain relatively stable independent of the volumes through our
systems but fluctuate depending on the scope of the activities performed during
a specific period.





Adjusted EBITDA. We define
Adjusted EBITDA as net income before interest, income taxes, depreciation and
amortization and non-cash income or loss related to derivative instruments.
Adjusted EBITDA is used as a supplemental financial measure by us and by
external users of our financial statements such as investors, commercial banks
and others, to assess:





·
            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.





The
economic substance behind our use of Adjusted EBITDA is to measure the ability
of our assets to generate cash sufficient to pay interest costs, support our
indebtedness and make distributions to our investors.





The GAAP
measures most directly comparable to Adjusted EBITDA are net cash provided by
operating activities and net income. Adjusted EBITDA should not be considered as
an alternative to GAAP net cash provided by operating activities and GAAP net
income. Adjusted EBITDA is not a presentation made in accordance with GAAP and
has important limitations as an analytical tool. You should not consider
Adjusted EBITDA in isolation or as a substitute for analysis of our results as
reported under GAAP. Because Adjusted EBITDA excludes some, but not all, items
that affect net income and net cash provided by operating activities and is
defined differently by different companies in our industry, our definition of
Adjusted EBITDA may not be comparable to similarly titled measures of other
companies.





We
compensate for the limitations of Adjusted EBITDA as an analytical tool by
reviewing the comparable GAAP measures, understanding the differences between
the measures and incorporating these insights into our decision-making
processes.





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Year Ended December 31,2009
              
              
              2008
              
              
              2007Reconciliation
      of net cash provided by operating
              
              (In
      millions)activities
      to Adjusted EBITDA:Net
      cash provided by operating activities
              
              $
              299.8
              
              
              $
              293.0
              
              
              $
              268.3Net
      income attributable to noncontrolling interest
              
              
              (2.2
              )
              
              
              (0.3
              )
              
              
              (0.1
              )Interest
      expense, net (1)
              
              
              48.2
              
              
              
              35.8
              
              
              
              39.1Gain
      (loss) on debt repurchases
              
              
              (1.5
              )
              
              
              13.1
              
              
              
              -Termination
      of commodity derivatives
              
              
              -
              
              
              
              87.4
              
              
              
              -Current
      income tax expense
              
              
              0.2
              
              
              
              0.6
              
              
              
              0.6Other
              
              
              (1.6
              )
              
              
              3.7
              
              
              
              (1.5
              )Changes
      in operating working capital whichused
      (provided) cash:Accounts
      receivable and other assets
              
              
              69.4
              
              
              
              (658.2
              )
              
              
              145.7Accounts
      payable and other liabilities
              
              
              (126.0
              )
              
              
              494.3
              
              
              
              (191.6
              )Adjusted
      EBITDA
              
              $
              286.3
              
              
              $
              269.4
              
              
              $
              260.5




_______


(1)
            Net
      of amortization of debt issuance costs of $3.8 million,
      $2.1 million and $1.8 million for 2009, 2008 and
      2007.




Year Ended December 31,2009
              
              
              2008
              
              
              2007Reconciliation
      of net income attributable to Targa Resources Partners LP to Adjusted
      EBITDA:
              
              (In
      millions)Net
      income attributable to Targa Resources Partners LP
              
              $
              52.0
              
              
              $
              49.4
              
              
              $
              35.1Add:Interest
      expense, net (1)
              
              
              95.4
              
              
              
              97.1
              
              
              
              99.4Income
      tax expense
              
              
              1.0
              
              
              
              2.4
              
              
              
              2.5Depreciation
      and amortization expense
              
              
              101.2
              
              
              
              97.8
              
              
              
              93.5Non-cash
      loss related to derivatives
              
              
              37.6
              
              
              
              23.4
              
              
              
              30.8Noncontrolling
      interest adjustment
              
              
              (0.9
              )
              
              
              (0.7
              )
              
              
              (0.8
              )Adjusted
      EBITDA
              
              $
              286.3
              
              
              $
              269.4
              
              
              $
              260.5


_______


(1)
            Includes
      affiliate interest expense of $43.4 million, $59.2 million and $58.5
      million for 2009, 2008 and 2007 and allocated interest expense of $19.4
      million for 2007.





Distributable Cash Flow. We
define distributable cash flow as net income attributable to Targa Resources
Partners LP plus depreciation and amortization, deferred taxes and amortization
of debt issue costs included in interest expense, adjusted for non-cash
losses/(gains) related to mark-to-market derivative instruments and debt
repurchases, less maintenance capital expenditures. Distributable cash flow is a
significant performance metric used by us and by external users of our financial
statements, such as investors, commercial banks, research analysts and others to
compare basic cash flows generated by us (prior to the establishment of any
retained cash reserves by the board of directors of our general partner) to the
cash distributions we expect to pay our unitholders. Using this metric,
management can quickly compute the coverage ratio of estimated cash flows to
planned cash distributions. Distributable cash flow is also an important
financial measure for our unitholders since it serves as an indicator of our
success in providing a cash return on investment. Specifically, this financial
measure indicates to investors whether or not we are generating cash flow at a
level that can sustain or support an increase in our quarterly distribution
rates. Distributable cash flow is also a quantitative standard used throughout
the investment community with respect to publicly-traded partnerships and
limited liability companies because the value of a unit of such an





63
 Table of Contents




entity is
generally determined by the unit’s yield (which in turn is based on the amount
of cash distributions the entity pays to a unitholder).





The
economic substance behind our use of distributable cash flow is to measure the
ability of our assets to generate cash flow sufficient to make distributions to
our investors.





The GAAP
measure most directly comparable to distributable cash flow is net income.
Distributable cash flow should not be considered as an alternative to GAAP net
income. Distributable cash flow is not a presentation made in accordance with
GAAP and has important limitations as an analytical tool. You should not
consider distributable cash flow in isolation or as a substitute for analysis of
our results as reported under GAAP. Because distributable cash flow excludes
some, but not all, items that affect net income and is defined differently by
different companies in our industry, our definition of distributable cash flow
may not be compatible to similarly titled measures of other companies, thereby
diminishing its utility.





We
compensate for the limitations of distributable cash flow as an analytical tool
by reviewing the comparable GAAP measures, understanding the differences between
the measures and incorporating these insights into our decision making
processes.





Year Ended December 31,2009
            
            
            2008
            
            
            2007Reconciliation
      of net income attributable to Targa Resources Partners LP to distributable
      cash flow:
            
            (In
      millions)Net
      income attributable to Targa Resources Partners LP
            
            $
            52.0
            
            
            $
            49.4
            
            
            $
            35.1Add:Depreciation
      and amortization expense
            
            
            101.2
            
            
            
            97.8
            
            
            
            93.5Deferred
      income tax expense
            
            
            0.8
            
            
            
            1.8
            
            
            
            1.9Amortization
      of debt issue costs
            
            
            3.8
            
            
            
            2.1
            
            
            
            1.8Loss
      (gain) on debt repurchases
            
            
            1.5
            
            
            
            (13.1
            )
            
            
            -Non-cash
      loss related to mark-to-market derivative instruments
            
            
            37.6
            
            
            
            23.4
            
            
            
            30.8Maintenance
      capital expenditures
            
            
            (20.0
            )
            
            
            (40.3
            )
            
            
            (30.4
            )Other
      (1)
            
            
            (0.6
            )
            
            
            (0.4
            )
            
            
            (0.5
            )Distributable
      cash flow
            
            $
            176.3
            
            
            $
            120.7
            
            
            $
            132.2





_______


(1)
            Other
      includes the non-controlling interest percentage of our unconsolidated
      investment’s depreciation, interest expense and maintenance capital
      expenditures.








64
 Table of Contents





Results
of Operations





The
following table summarizes the key components of our results of operations for
the periods indicated:





Year Ended December 31,2009
            
            
            2008
            
            
            2007(In
      millions, except operating and price data)Revenues
      (1) (2)
            
            $
            4,095.6
            
            
            $
            7,502.1
            
            
            $
            6,843.7Costs
      and expenses:Product
      purchases (2)
            
            
            3,585.6
            
            
            
            6,950.8
            
            
            
            6,302.0Operating
      expenses
            
            
            185.1
            
            
            
            254.0
            
            
            
            219.6Depreciation
      and amortization expense
            
            
            101.2
            
            
            
            97.8
            
            
            
            93.5General
      and administrative expense
            
            
            78.9
            
            
            
            68.6
            
            
            
            64.0Other
            
            
            (0.8
            )
            
            
            (0.9
            )
            
            
            (0.3
            )Income
      from operations
            
            
            145.6
            
            
            
            131.8
            
            
            
            164.9Interest
      expense from affiliate
            
            
            (43.4
            )
            
            
            (59.2
            )
            
            
            (58.5
            )Interest
      expense allocated from Parent
            
            
            -
            
            
            
            -
            
            
            
            (19.4
            )Other
      interest expense, net
            
            
            (52.0
            )
            
            
            (37.9
            )
            
            
            (21.5
            )Equity
      in earnings of unconsolidated investment
            
            
            5.0
            
            
            
            3.9
            
            
            
            3.5Gain
      (loss) on debt repurchases
            
            
            (1.5
            )
            
            
            13.1
            
            
            
            -Gain
      (loss) on mark-to-market derivative instruments
            
            
            0.8
            
            
            
            (1.0
            )
            
            
            (30.2
            )Other
      income (expense)
            
            
            0.7
            
            
            
            1.4
            
            
            
            (1.1
            )Income
      tax expense
            
            
            (1.0
            )
            
            
            (2.4
            )
            
            
            (2.5
            )Net
      income
            
            
            54.2
            
            
            
            49.7
            
            
            
            35.2Less:
      Net income attributable to noncontrolling interest
            
            
            2.2
            
            
            
            0.3
            
            
            
            0.1Net
      income attributable to Targa Resources Partners LP
            
            $
            52.0
            
            
            $
            49.4
            
            
            $
            35.1Financial
      and operating data:Financial
      data:Operating
      margin (3)
            
            $
            324.9
            
            
            $
            297.3
            
            
            $
            322.1Adjusted
      EBITDA (4)
            
            
            286.3
            
            
            
            269.4
            
            
            
            260.5Distributable
      cash flow (5)
            
            
            176.3
            
            
            
            120.7
            
            
            
            132.2Operating
      data:Gathering
      throughput, MMcf/d (6)
            
            
            468.6
            
            
            
            445.8
            
            
            
            452.0Plant
      natural gas inlet, MMcf/d (7)(8)
            
            
            445.9
            
            
            
            421.2
            
            
            
            429.3Gross
      NGL production, MBbl/d
            
            
            42.7
            
            
            
            42.0
            
            
            
            42.6Natural
      gas sales, BBtu/d (8)
            
            
            390.9
            
            
            
            415.6
            
            
            
            410.2NGL
      sales, MBbl/d
            
            
            273.1
            
            
            
            297.3
            
            
            
            310.1Condensate
      sales, MBbl/d
            
            
            2.8
            
            
            
            2.5
            
            
            
            3.6Average
      realized prices (9):Natural
      Gas, $/MMBtu
            
            
            3.96
            
            
            
            8.45
            
            
            
            6.63NGL,
      $/gal
            
            
            0.79
            
            
            
            1.39
            
            
            
            1.19Condensate,
      $/Bbl
            
            
            57.07
            
            
            
            90.00
            
            
            
            72.11





(1)
              Includes
      business interruption insurance revenues of $2.4 million,
      $18.7 million and $6.4 million for 2009, 2008 and
      2007.
  65
 Table of Contents







(2)
            During
      2009, we reclassified NGL marketing fractionation and other service fees
      to revenues that were originally recorded in product purchase costs. The
      reclassification increased revenues and product purchases for 2008 and
      2007 by $28.7 million and $27.6
million.


(3)
            Operating
      margin is revenues less product purchases and operating expense. See “How
      We Evaluate Our Operations.”


(4)
            Adjusted
      EBITDA is net income before interest, income taxes, depreciation and
      amortization and non-cash gain or loss related to derivative instruments.
      See “How We Evaluate Our
Operations.”


(5)
            Distributable
      Cash Flow is net income plus depreciation and amortization and deferred
      taxes, adjusted for losses on mark-to-market derivative contracts and debt
      repurchases, less maintenance capital expenditures. See “How We Evaluate
      Our Operations.”


(6)
            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.


(7)
            Plant
      natural gas inlet represents the volume of natural gas passing through the
      meter located at the inlet of a natural gas processing
    plant.


(8)
            Plant
      natural gas inlet volumes include producer take-in-kind, while natural gas
      sales exclude producer take-in-kind
volumes.


(9)
            Average
      realized prices include the impact of hedging
  activities.





Year
Ended December 31, 2009 Compared to Year Ended December 31,
2008





Revenues
decreased by $3,406.5 million, or 45%, to $4,095.6 million for 2009
compared to $7,502.1 million for 2008. Revenues from the sale of natural
gas decreased by $719.0 million, consisting of decreases of
$639.6 million due to lower realized prices and $79.4 million due to
lower sales volumes. Revenues from the sale of NGL decreased by
$2,659.2 million, consisting of a decrease of $2,511.5 million due to
lower realized prices and a decrease of $147.7 million due to lower sales
volumes. Revenues from the sale of condensate decreased by $22.1 million,
which is the net of a decrease of $33.9 million due to lower realized
prices and an increase of $11.8 million due to higher sales volumes.
Non-commodity revenues, which principally include revenues derived from
fee-based services and business interruption insurance, decreased by
$6.2 million.





Our
average realized prices for natural gas decreased by $4.49 per MMBtu, or 53%, to
$3.96 per MMBtu for 2009 compared to $8.45 per MMBtu for 2008. Our average
realized prices for NGL decreased by $0.60 per gallon, or 43%, to $0.79 per
gallon for 2009 compared to $1.39 per gallon for 2008. Our average realized
price for condensate decreased by $32.93 per barrel, or 37%, to $57.07 per
barrel for 2009 compared to $90.00 per barrel for 2008.





Natural
gas sales volumes decreased by 24.7 BBtu/d, or 6%, to 390.9 BBtu/d for 2009
compared to 415.6 BBtu/d for 2008. NGL sales volumes decreased by
24.2 MBbl/d, or 8%, to 273.1 MBbl/d for 2009 compared to
297.3 MBbl/d for 2008. Condensate sales volumes increased by 0.3 MBbl/d, or
12%, to 2.8 MBbl/d for 2009 compared to 2.5 MBbl/d for 2008. For information
regarding the period to period changes in our commodity sales volumes, see
“Results of Operations—By Segment.”





Product
purchases decreased by $3,365.2 million, or 48%, to $3,585.6 million
for 2009 compared to $6,950.8 million for 2008. See “Results of
Operations—By Segment” for a detailed explanation of the components of the
decrease.





Operating
expenses decreased by $68.9 million, or 27%, to $185.1 million for
2009 compared to $254.0 million for 2008. See “Results of Operations—By
Segment” for a detailed explanation of the components of the
decrease.





Depreciation
and amortization expense increased by $3.4 million, or 3%, to
$101.2 million for 2009 compared to $97.8 million for 2008. The
increase is primarily attributable to a 3% increase in our property, plant and
equipment balance for 2009 compared to 2008.





General
and administrative expense increased by $10.3 million, or 15%, to
$78.9 million for 2009 compared to $68.6 million for 2008. The
increase included increases in compensation related expenses, professional
services, allocated corporate level expenses and insurance
expenses.





66
 Table of Contents





Interest
expense decreased by $1.7 million, or 3%, to $95.4 million for 2009
compared to $97.1 million for 2008. The decrease is primarily from lower
average outstanding debt during 2009. See “Liquidity and Capital Resources” for
information regarding our outstanding debt obligations.





Loss on
debt repurchases of $1.5 million for 2009 relates to open market
repurchases of our 111⁄4% Senior Notes due 2017.





Our gain
on mark-to-market derivative instruments was $0.8 million for 2009 compared
to a loss of $1.0 million for 2008. During 2008 we adjusted the fair value
of certain contracts with Lehman Brothers Commodity Services Inc. to zero as a
result of the Lehman Brothers bankruptcy filing.





Year
Ended December 31, 2008 Compared to Year Ended December 31,
2007





Revenues
increased by $658.4 million, or 10%, to $7,502.1 million for 2008
compared to $6,843.7 million for 2007. Revenues from the sale of natural
gas increased by $291.7 million, consisting of increases of
$275.9 million due to higher realized prices and $15.8 million due to
higher sales volumes. Revenues from the sale of NGL increased by
$306.5 million, consisting of an increase of $875.6 million due to
higher realized prices, partially offset by a decrease of $569.1 million
due to lower sales volumes. Revenues from the sale of condensate increased by
$23.2 million, consisting of increases of $22.2 million due to higher
realized prices and $1.0 million due to higher sales volumes. Non-commodity
revenues, which principally include revenues derived from fee-based services and
business interruption insurance, increased by $37.0 million.





Our
average realized prices for natural gas increased by $1.82 per MMBtu, or 27%, to
$8.45 per MMBtu for 2008 compared to $6.63 per MMBtu for 2007. Our average
realized prices for NGL increased by $0.20 per gallon, or 17%, to $1.39 per
gallon for 2008 compared to $1.19 per gallon for 2007. Our average realized
price for condensate increased by $17.89, or 25%, to $90.00 per barrel for 2008
compared to $72.11 per barrel for 2007.





Natural
gas sales volumes increased by 5.4 BBtu/d, or 1%, to 415.6 BBtu/d for 2008
compared to 410.2 BBtu/d for 2007. NGL sales volumes decreased by 12.8 MBbl/d,
or 4%, to 297.3 MBbl/d for 2008 compared to 310.1 MBbl/d for 2007.
Condensate sales volumes decreased 1.1 MBbl/d, or 31%, to 2.5 MBbl/d for 2008
compared to 3.6 MBbl/d for 2007. For information regarding the period to period
changes in our commodity sales volumes, see “Results of Operations—By
Segment.”





Product
purchases increased by $648.8 million, or 10%, to $6,950.8 million for
2008 compared to $6,302.0 million for 2007. See “Results of Operations—By
Segment” for a detailed explanation of the components of the
increase.





Operating
expenses increased by $34.4 million, or 16%, to $254.0 million for
2008 compared to $219.6 million for 2007. See “Results of Operations—By
Segment” for a detailed explanation of the components of the
increase.





Depreciation
and amortization expense increased by $4.3 million, or 5%, to
$97.8 million for 2008 compared to $93.5 million for 2007. The
increase is primarily attributable to a 27% increase in purchases of property,
plant and equipment for 2008 compared to 2007.





General
and administrative expense increased by $4.6 million, or 7%, to
$68.6 million for 2008 compared to $64.0 million for 2007. The
increase included increases in compensation related expenses, professional
services, allocated corporate level expenses and insurance
expenses.





Interest
expense decreased by $2.3 million, or 2%, to $97.1 million for 2008
compared to $99.4 million for 2007. The decrease is primarily from lower
average outstanding debt during 2008. See “Liquidity and Capital Resources” for
information regarding our outstanding debt obligations.





Gain on
debt repurchases of $13.1 million for 2008 relates to open market
repurchases of our 81⁄4% Senior Notes due 2016.





67
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Our loss
on mark-to-market derivative instruments was $1.0 million for 2008 compared
to $30.2 million for 2007. During 2008 we adjusted the fair value of
certain contracts with Lehman Brothers Commodity Services Inc. to zero as a
result of the Lehman Brothers bankruptcy filing. The 2007 loss resulted from
derivative financial instruments that did not qualify for hedge
accounting.





Results
of Operations—By Segment





Natural
Gas Gathering and Processing Segment





The
following table provides summary financial data regarding results of operations
in our Natural Gas Gathering and Processing segment for the periods
indicated:





Year Ended December 31,2009
            
            
            2008
            
            
            2007($
      in millions)Revenues
            
            $
            1,076.5
            
            
            $
            2,074.1
            
            
            $
            1,661.5Product
      purchases
            
            
            (856.7
            )
            
            
            (1,803.0
            )
            
            
            (1,406.8
            )Operating
      expenses
            
            
            (51.4
            )
            
            
            (55.3
            )
            
            
            (50.9
            )Operating
      margin (1)
            
            $
            168.4
            
            
            $
            215.8
            
            
            $
            203.8Operating
      statistics (2):Gathering
      throughput, MMcf/d
            
            
            468.6
            
            
            
            445.8
            
            
            
            452.0Plant
      natural gas inlet, MMcf/d
            
            
            445.9
            
            
            
            421.2
            
            
            
            429.3Gross
      NGL production, MBbl/d
            
            
            42.7
            
            
            
            42.0
            
            
            
            42.6Natural
      gas sales, BBtu/d
            
            
            390.9
            
            
            
            415.6
            
            
            
            410.2NGL
      sales, MBbl/d
            
            
            38.9
            
            
            
            37.3
            
            
            
            36.4Condensate
      sales, MBbl/d
            
            
            3.0
            
            
            
            3.6
            
            
            
            3.6Average
      realized prices:Natural
      gas, $/MMBtu
            
            
            3.96
            
            
            
            8.45
            
            
            
            6.63NGL,
      $/gal
            
            
            0.71
            
            
            
            1.22
            
            
            
            1.03Condensate,
      $/Bbl
            
            
            55.59
            
            
            
            81.26
            
            
            
            72.11





_______


(1)
            See
      “How We Evaluate Our Operations.”(2)
            Segment
      operating statistics include the effect of intersegment sales, which have
      been eliminated from the consolidated presentation. For all volume
      statistics presented, the numerator is the total volume sold during the
      year and the denominator is the number of calendar days during the
      year.





Year
Ended December 31, 2009 Compared to Year Ended December 31,
2008





Revenues. Revenues decreased
$997.6 million, or 48%, to $1,076.5 million for 2009 compared to
$2,074.1 million for 2008. The decrease was primarily due to a decrease
attributable to prices of $928.3 million, consisting of decreases in natural
gas, NGL, and condensate revenues of $639.6 million, $260.4 million,
and $28.3 million; a decrease attributable to volumes of
$68.5 million, consisting of decreases in natural gas and condensate
revenues of $79.4 million and $19.4 million; partially offset by an
increase in NGL revenues of $30.3 million; and a decrease in fee and other
revenues of $0.8 million.





Average
realized prices for our sales of natural gas decreased by $4.49 per MMBtu, or
53%, to $3.96 per MMBtu during 2009 compared to $8.45 per MMBtu for 2008.
Average realized prices for our sales of NGLs decreased by $0.51 per gallon, or
42%, to $0.71 per gallon for 2009 compared to $1.22 per gallon for 2008. Average
realized prices for our sales of condensate decreased by $25.67 per Bbl, or 32%,
to $55.59 per Bbl for 2009 compared to $81.26 per Bbl for 2008.





Natural
gas sales volume decreased by 24.7 BBtu/d or 6%, to 390.9 BBtu/d during
2009 compared to 415.6 BBtu/d for 2008 due to a decrease in purchases from
affiliates for resale partially offset by an increase in





68
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demand
from our industrial customers. NGL sales increased by 1.6 MBbl/d, or 4%, to
38.9 MBbl/d for 2009 compared to 37.3 MBbl/d for 2008. Condensate
sales volumes decreased by 0.6 MBbl/d, or 17%, to 3.0 MBbl/d for 2009 compared
to 3.6 MBbl/d for 2008.





Product Purchases. Product
purchases during 2009 were $856.7 million, which decreased by
$946.3 million or 52%, compared to $1,803.0 million during 2008. The
decrease in product purchases corresponds with the decrease in commodity revenue
for 2009.





Operating Expenses. Operating
expenses during 2009 were $51.4 million, which decreased by
$3.9 million or 7%, compared to $55.3 million during 2008. The
decrease in operating expenses was primarily the result of decreases in system
maintenance, repairs and supplies expenses and ad valorem taxes partially offset
by increases in compensation and benefit costs.





Year
Ended December 31, 2008 Compared to Year Ended December 31,
2007





Revenues. Revenues increased
$412.6 million, or 25%, to $2,074.1 million for 2008 compared to
$1,661.5 million for 2007. The increase was primarily due to an increase
attributable to prices of $383.5 million, consisting of increases in
natural gas, NGL, and condensate revenues of $280.5 million,
$80.8 million, and $22.2 million; an increase attributable to volumes
of $32.2 million, consisting of increases in natural gas, NGL and
condensate revenues of $15.7 million, $15.5 million, and
$1.0 million; and an increase in fee and other revenues of
$3.1 million.





Average
realized prices for our sales of natural gas increased by $1.82 per MMBtu, or
27%, to $8.45 per MMBtu during 2008 compared to $6.63 per MMBtu for 2007.
Average realized prices for our sales of NGLs increased by $0.19 per gallon, or
18%, to $1.22 per gallon for 2008 compared to $1.03 per gallon for 2007. Average
realized prices for our sales of condensate increased by $9.15 per Bbl, or 24%,
to $81.26 per Bbl for 2008 compared to $72.11 per Bbl for 2007.





Natural
gas sales volume increased by 5.4 BBtu/d or 1%, to 415.6 BBtu/d during
2008 compared to 410.2 BBtu/d for 2007 due to a lower proportion of
take-in-kind volumes, increased marketing activity and the effects of
unfavorable processing economics. NGL sales increased by 0.9 MBbl/d or 2%,
to 37.3 MBbl/d for 2008 compared to 36.4 MBbl/d for 2007. Condensate
sales remained flat at 3.6 MBbl/d.





Product Purchases. Product
purchases during 2008 were $1,803.0 million, which increased by
$396.2 million or 28%, compared to $1,406.8 million during 2007. The
increase in product purchases corresponds with the increase in commodity revenue
for 2008.





Operating Expenses. Operating
expenses during 2008 were $55.3 million, which increased by
$4.4 million or 9%, compared to $50.9 million during 2007. The
increase in operating expenses was primarily the result of increases in general
maintenance and supplies, lube oil, environmental and automotive expenses,
compensation related expenses and ad valorem taxes.








69
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Logistics
Assets Segment





The
following table provides summary financial data regarding results of operations
of our Logistics Assets segment for the periods indicated:


Year Ended December 31,2009
            
            
            2008
            
            
            2007($
      in millions)Revenues
      from services
            
            $
            212.4
            
            
            $
            235.4
            
            
            $
            195.1Other
      revenues (1)
            
            
            1.9
            
            
            
            2.6
            
            
            
            -214.3
            
            
            
            238.0
            
            
            
            195.1Operating
      expenses
            
            
            (127.3
            )
            
            
            (188.1
            )
            
            
            (155.1
            )Operating
      margin (2)
            
            $
            87.0
            
            
            $
            49.9
            
            
            $
            40.0Equity
      in earnings of GCF
            
            $
            5.0
            
            
            $
            3.9
            
            
            $
            3.5Operating
      statistics:Fractionation
      volumes, MBbl/d
            
            
            217.2
            
            
            
            212.2
            
            
            
            209.2Treating
      volumes, MBbl/d (3)
            
            
            21.9
            
            
            
            20.7
            
            
            
            9.1





_______


(1)
            Includes
      business interruption insurance revenues of $1.9 million and
      $2.6 million for 2009 and 2008.(2)
            See
      “How We Evaluate Our Operations.”(3)
            Consists
      of the volumes treated in our low sulfur natural gasoline (“LSNG”) unit,
      which began commercial operations in June
2007.





Year
Ended December 31, 2009 Compared to Year Ended December 31,
2008





Revenues
from fractionation, terminalling and storage, transport, and treating decreased
$23.0 million, or 10%, to $212.4 million for 2009 compared to
$235.4 million for 2008. Fractionation and treating volumes increased
slightly, but fractionation and treating revenue decreased as the variable
components of the related fees were lower due to decreased fuel and electricity
prices. Reduced barge and truck utilization also contributed to the lower
revenue. These reductions in revenue were partially offset by increased fixed
portions on the fractionation fees and increased wholesale terminal revenue in
2009.





Operating
expenses decreased $60.8 million, or 32%, to $127.3 million for 2009
compared to $188.1 million for 2008. The decrease was primarily the result
of lower fuel and electricity expenses. Also contributing to the lower operating
expenses were reduced barge and truck utilization, lower third party
fractionation expense in 2009, lower general maintenance and supplies expense
and lower contract labor costs.





Year
Ended December 31, 2008 Compared to Year Ended December 31,
2007





Revenues
from fractionation, terminalling and storage, transport, and treating increased
$40.3 million, or 21%, to $235.4 million for 2008 compared to
$195.1 million for 2007. The increase was due to higher service rates, a
full year of commercial operations at our LSNG unit in 2008 compared to six
months of operations in 2007, increased treating and related service revenues,
additional transport fees from spot barge activity and additional terminalling
revenue from a new common carrier connection.





Operating
expenses increased $33.0 million, or 21%, to $188.1 million for 2008
compared to $155.1 million for 2007. The increase was primarily the result
of higher fuel and utilities expense, increased LSNG unit and other facility
maintenance costs, plant turnaround costs and third party fractionation expense,
additional barge activity, inventory adjustments and pipeline integrity
costs.








70
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NGL
Distribution and Marketing Services Segment





The
following table provides summary financial data regarding results of operations
of our NGL Distribution and Marketing Services segment for the periods
indicated:





Year Ended December 31,2009
            
            
            2008
            
            
            2007($
      in millions)NGL
      sales revenues
            
            $
            2,907.7
            
            
            $
            5,172.2
            
            
            $
            4,889.3Other
      revenues (1)
            
            
            28.5
            
            
            
            41.2
            
            
            
            34.12,936.2
            
            
            
            5,213.4
            
            
            
            4,923.4Product
      purchases
            
            
            (2,890.1
            )
            
            
            (5,193.2
            )
            
            
            (4,866.4
            )Operating
      expenses
            
            
            (0.3
            )
            
            
            (1.7
            )
            
            
            (1.5
            )Operating
      margin (2)
            
            $
            45.8
            
            
            $
            18.5
            
            
            $
            55.5Operating
      statistics:NGL
      sales, MBbl/d
            
            
            245.7
            
            
            
            244.6
            
            
            
            275.6NGL
      realized price, $/gal
            
            
            0.77
            
            
            
            1.38
            
            
            
            1.16





_______


(1)
            Includes
      business interruption insurance revenues of $9.6 million and
      $3.8 million for 2008 and 2007.(2)
            See
      “How We Evaluate Our Operations.”





Year
Ended December 31, 2009 Compared to Year Ended December 31,
2008





Revenues
decreased $2,277.2 million, or 44%, to $2,936.2 million for 2009 compared to
$5,213.4million
for 2008. Lower market prices decreased revenue $2,096.0 million.
Overall sales volumes were higher as the value associated with the volumes is
$168.5 million lower due to product mix. Other revenue is lower primarily
because no business interruption revenues were received in 2009.





NGL sales
increased 1.1 MBbl/d, or less than 1%, to 245.7 MBbl/d for 2009 compared to
244.6 MBbl/d for 2008. Sales to petrochemical customers increased inasmuch
as plant operational rates were higher, partially offset by lower spot
sales.





Product
purchases decreased $2,303.1 million, or 44%, to $2,890.1 million for
2009 compared to $5,193.2 million for 2008. Lower market prices decreased
product purchases by $2,134.4 million. Overall purchase volumes were higher
but the cost associated with these purchased volumes was $168.7 million lower
due to product mix.





Year
Ended December 31, 2008 Compared to Year Ended December 31,
2007





Revenues
increased $290.0million, or 6%, to
$5,213.4million
for 2008 compared to $4,923.4 million for 2007. Higher market prices
increased revenue $820.6 million partially offset by lower sales volume,
which decreased revenue by $537.8 million. The increase in other revenues
was primarily from increased business interruption insurance revenues during
2008.





NGL sales
decreased 31.0 MBbl/d, or 11%, to 244.6 MBbl/d for 2008 compared to
275.6 MBbl/d for 2007. The decrease was primarily the result of disruptions
due to hurricanes Gustav and Ike as well as reduced petrochemical operating
rates for 2008 as compared to 2007.





Product
purchases increased $326.8 million, or 7%, to $5,193.2 million for
2008 compared to $4,866.4 million for 2007. Higher market prices increased
product purchases by $859.0 million partially offset by lower volumes,
which decreased product purchases by $532.2 million.








71
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Wholesale
Marketing Segment





The
following table provides summary financial data regarding results of operations
of our Wholesale Marketing segment for the periods indicated:


Year Ended December 31,2009
            
            
            2008
            
            
            2007($
      in millions)NGL
      sales revenues
            
            $
            884.7
            
            
            $
            1,453.3
            
            
            $
            1,294.7Other
      revenues (1)
            
            
            1.3
            
            
            
            6.8
            
            
            
            1.3886.0
            
            
            
            1,460.1
            
            
            
            1,296.0Product
      purchases
            
            
            (862.3
            )
            
            
            (1,446.9
            )
            
            
            (1,273.1
            )Operating
      expenses
            
            
            -
            
            
            
            (0.1
            )
            
            
            (0.1
            )Operating
      margin (2)
            
            $
            23.7
            
            
            $
            13.1
            
            
            $
            22.8Operating
      statistics:NGL
      sales, MBbl/d
            
            
            58.8
            
            
            
            62.5
            
            
            
            63.6NGL
      realized price, $/gal
            
            
            0.98
            
            
            
            1.51
            
            
            
            1.33





_______


(1)
            Includes
      business interruption insurance revenues of $0.5 million,
      $6.5 million and $0.8 million for 2009, 2008 and
      2007.(2)
            See
      “How We Evaluate Our Operations.”





Year
Ended December 31, 2009 Compared to Year Ended December 31,
2008





Revenues
decreased $574.1 million, or 39%, to $886.0 million for 2009 compared
to $1,460.1 million for 2008. Lower NGL market prices decreased revenue by
$478.7 million, and lower sales volume decreased revenue an additional
$89.9 million. The decrease in other revenues is due primarily to
a decrease in business interruption insurance proceeds of
$6.0 million.





Our
average realized price for NGL decreased $0.53 per gallon, or 35%, to $0.98 per
gallon for 2009 compared to $1.51 per gallon for 2008. The decrease was
primarily due to overall lower market prices. NGL sales volume decreased
3.7 MBbl/d, or 6%, to 58.8MBbl/d for 2009 compared
to 62.5 MBbl/d for 2008. The decrease in volumes is due primarily to
expiration of a refinery purchase agreement.





Product
purchases decreased $584.6 million, or 40%, to $862.3 million for 2009
compared to $1,446.9 million for 2008. Lower NGL market prices decreased
product purchases by $489.4 million while lower volumes decreased product
purchases an additional $89.2 million. During 2008, we had lower of cost or
market adjustments that flowed to product purchases of
$6.0 million.





Year
Ended December 31, 2008 Compared to Year Ended December 31,
2007





Revenues
increased $164.1 million, or 13%, to $1,460.1 million for 2008
compared to $1,296.0 million for 2007. Higher NGL market prices increased
revenue $177.4 million partially offset by lower sales volume, which
decreased revenue by $18.9 million. The increase in other revenues consists
of a $5.7 million increase in business interruption insurance
revenues.





Our
average realized price for NGL increased $0.18 per gallon, or 14%, to $1.51 per
gallon for 2008 compared to $1.33 per gallon for 2007. The increase was
primarily due to higher overall market prices for all components. However,
market prices dropped significantly in the fourth quarter of 2008 quarter due to
overall market conditions. NGL sales decreased 1.1 MBbl/d, or 2%, to
62.5MBbl/d for
2008 compared to 63.6 MBbl/d for 2007. The decrease in volumes is due
primarily to the expiration of refinery supply agreements and an operating
disruption at a customer facility.





72
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Product
purchases increased $173.8 million, or 14%, to $1,446.9 million for
2008 compared to $1,273.1 million for 2007. Higher NGL market prices and
lower of cost or market adjustments increased product purchases by
$186.4 million and $6.0 million partially offset by lower volumes,
which decreased product purchases by $18.6 million.





Insurance
Claims





Certain
of our Louisiana and Texas facilities sustained damage and had disruption to
their operations during the 2008 hurricane season from two Gulf Coast
hurricanes—Gustav and Ike. As of December 31, 2008, we recorded a
$4.8 million loss provision (net of estimated insurance reimbursements)
related to the hurricanes. The estimate was reduced by $0.8 million during
2009. During 2009, we had expenditures related to the hurricanes of
$6.9 million for previously accrued repair costs and $0.3 million
capitalized as improvements.





During
2009, 2008 and 2007, we recognized revenue from business interruption insurance
of:





Year Ended December 31,2009
            
            
            2008
            
            
            2007(In
      millions)Natural
      Gas Gathering and Processing
            
            $
            -
            
            
            $
            -
            
            
            $
            1.8Logistics
      Assets
            
            
            1.9
            
            
            
            2.6
            
            
            
            -NGL
      Distribution and Marketing
            
            
            -
            
            
            
            9.6
            
            
            
            3.8Wholesale
      Marketing
            
            
            0.5
            
            
            
            6.5
            
            
            
            0.8$
            2.4
            
            
            $
            18.7
            
            
            $
            6.4








Business
interruption insurance receipts recognized as revenue during 2009 relate
primarily to the 2008 hurricanes; amounts recognized during 2008 and 2007 relate
primarily to Hurricanes Katrina and Rita from the 2005 hurricane season. Under
the terms of our agreements related to the acquisition of the Downstream
Business, Targa retained all property damage and business interruption claims
related primarily to hurricanes.





Liquidity
and Capital Resources





Our
ability to finance our operations, including funding capital expenditures and
acquisitions, to meet our indebtedness obligations, to refinance our
indebtedness, to meet our collateral requirements, or to pay our distributions
will depend on our ability to generate cash in the future. Our ability to
generate cash is subject to a number of factors, some of which are beyond our
control, including weather, commodity prices, particularly for natural gas and
NGLs, and our ongoing efforts to manage operating costs and maintenance capital
expenditures, as well as general economic, financial, competitive, legislative,
regulatory and other factors.





Our main
sources of liquidity and capital resources are internally generated cash flow
from operations, borrowings under our credit facility, the issuance of
additional equity and access to debt markets. The capital markets continue to
experience volatility. Many financial institutions have or have had liquidity
concerns, prompting government intervention to mitigate pressure on the credit
markets. Our exposures to the current credit conditions include our credit
facility, cash investments and counterparty performance risks. Continued
volatility in the debt markets may increase costs associated with issuing debt
instruments due to increased spreads over relevant interest rate benchmarks and
affect our ability to access those markets.





Current
market conditions also elevate the concern over counterparty risks related to
our commodity derivative contracts and trade credit. We have all of our
commodity derivatives with major financial institutions or major oil companies.
Should any of these financial counterparties not perform, we may not realize the
benefit of some of our hedges under lower commodity prices, which could have a
material adverse effect on our results of operation. We sell our natural gas,
NGLs and condensate to a variety of purchasers. Non-performance by a trade
creditor could result in losses.





73
 Table of Contents





Crude oil
and natural gas prices are also volatile and have recently declined
significantly. In a continuing effort to reduce the volatility of our cash
flows, we have periodically entered into commodity derivative contracts for a
portion of our estimated equity volumes through 2013. See “Item 7A.
Quantitative and Qualitative Disclosures About Market Risk—Commodity Price
Risk.” The current market conditions may also impact our ability to enter into
future commodity derivative contracts. In the event of a continued global
recession, commodity prices may stay depressed or fall further thereby causing a
prolonged downturn, which could reduce our operating margins and cash flow from
operations.





As of
December 31, 2009, we had liquidity of $470.5 million, including
$60.4 million of available cash and $410.1 million of available
borrowings under our credit facility. We will continue to monitor our liquidity
and the credit markets. Additionally, we will continue to monitor events and
circumstances surrounding each of the other twenty three lenders in our credit
facility. To date, other than the Lehman Bank default, we have experienced no
disruptions in our ability to access funds committed under our credit facility.
However, we cannot predict with any certainty the impact to us of any further
disruptions in the credit environment.





Our cash
generated from operations has been sufficient to finance our operating
expenditures and non-acquisition related capital expenditures, with remaining
amounts being distributed to Targa during its period of ownership and to our
unitholders since our IPO. Based on our anticipated levels of operations and
absent any disruptive events, we believe that internally generated cash flow and
borrowings available under our senior secured credit facilities should provide
sufficient resources to finance our operations, non-acquisition related capital
expenditures, long-term indebtedness obligations, collateral requirements and
minimum quarterly cash distributions for at least the next twelve
months.





We intend
to make cash distributions to our unitholders and our general partner in an
amount at least equal to the minimum quarterly distribution rate of $0.3375 per
common unit per quarter ($1.35 per common unit on an annualized basis). Due to
our cash distribution policy, we expect that we will distribute to our
unitholders most of the cash generated by our operations. As a result, we expect
that we will rely upon external financing sources, including other debt and
common unit issuances, to fund our acquisition and expansion capital
expenditures. Historically, we have relied on internally generated cash flows
for these purposes. See “Factors That Significantly Affect Our
Results—Distributions to our Unitholders”for a table that shows
the distributions we declared paid in 2009 and 2008.





Working Capital. Working
capital is the amount by which current assets exceed current liabilities. Our
working capital requirements are primarily driven by changes in accounts
receivable and accounts payable. These changes are impacted by changes in the
prices of commodities that we buy and sell. In general, our working capital
requirements increase in periods of rising commodity prices and decrease in
periods of declining commodity prices. However, our working capital needs do not
necessarily change at the same rate as commodity prices because both accounts
receivable and accounts payable are impacted by the same commodity prices. In
addition, the timing of payments received by our customers or paid to our
suppliers can also cause fluctuations in working capital because we settle with
most of our larger suppliers and customers on a monthly basis and often near the
end of the month. We expect that our future working capital requirements will be
impacted by these same factors.





Prior to
the contribution of the North Texas System in February 2007, the acquisition of
the SAOU and LOU Systems in October 2007 and the acquisition of the Downstream
Business in September 2009, all intercompany transactions, including expense
reimbursements, were not cash settled with Targa, but were recorded as an
adjustment to parent equity on the balance sheet. The primary transactions
between Targa and us are natural gas and NGL sales, the provision of operations
and maintenance activities and the provision of general and administrative
services. As a result of this accounting treatment, our working capital did not
reflect any affiliate accounts receivable for intercompany commodity sales or
any affiliate accounts payable for the personnel and services provided by or
paid for by our parent prior to the acquisition of the North Texas System and
the subsequent acquisition of the SAOU and LOU Systems.





As of
December 31, 2009, we had a positive working capital balance of
$59.1 million.





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The
Partnership is obligated to make minimum quarterly cash distributions to
unitholders from available cash, as defined in the partnership agreement. As of
December 31, 2009, such minimum amounts payable to non-Targa unitholders
total approximately $56.1 million annually.





Cash
Flow





The
following table summarizes cash flow provided by or used in operating
activities, investing activities and financing activities for the periods
indicated:




Year Ended December 31,2009
              
              
              2008
              
              
              2007(In
      millions)Net
      cash provided by (used in):Operating
      activities
              
              $
              299.8
              
              
              $
              293.0
              
              
              $
              268.3Investing
      activities
              
              
              (57.1
              )
              
              
              (86.1
              )
              
              
              (76.8
              )Financing
      activities
              
              
              (277.6
              )
              
              
              (175.9
              )
              
              
              (139.7
              )




Operating
Activities





Net cash
provided by operating activities was $299.8 million for 2009 compared to
$293.0 million for 2008. The $6.8 million increase was primarily due
to changes in operating assets and liabilities,
which provided $56.6 million in cash during 2009, compared to
providing $163.9 million in cash during 2008, partially offset by an
$87.4 million payment during 2008 to terminate certain out-of-the-money
commodity derivatives.





Net cash
provided by operating activities was $293.0 million for 2008 compared to
$268.3 million for 2007. The $24.7 million increase was primarily due
to changes in operating assets and liabilities, which provided
$163.9 million in cash during 2008, compared to providing
$45.9 million in cash during 2007, partially offset by an
$87.4 million payment during 2008 to terminate certain out-of-the-money
commodity derivatives.





Investing
Activities





Net cash
used in investing activities decreased by $29.0 million to $57.1 million
for 2009 compared to $86.1 million for 2008.





Net cash
used in investing activities was $86.1 million for 2008 compared to
$76.8 million for 2007. The $9.3 million increase is primarily due to
increased capital expenditures during 2008. The increase is primarily from
increased expenditures related to gathering system expansion projects begun in
the third quarter of 2008.





The
following table lists gross additions to property, plant and equipment, cash
flows used in property, plant and equipment additions and the difference, which
is primarily settled accruals and non-cash additions:







Year Ended December 31,2009
            
            
            2008
            
            
            2007(In
      millions)Gross
      additions to property, plant and equipment
            
            $
            60.6
            
            
            $
            100.5
            
            
            $
            78.9Non-cash
      additions to property, plant and equipment
            
            
            (9.8
            )
            
            
            (5.8
            )
            
            
            0.2Change
      in accruals
            
            
            6.4
            
            
            
            (8.4
            )
            
            
            (1.5
            )Cash
      expenditures
            
            $
            57.2
            
            
            $
            86.3
            
            
            $
            77.6








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Financing
Activities





Net cash
used in financing activities was $277.6 million for 2009 compared to net
cash used in financing activities of $175.9 million for 2008. The
$101.7 million increase in cash used is primarily due to repayment of
affiliated debt associated with our purchase of the Downstream Business offset
by a net increase in debt and by equity offering proceeds from our public
offering of 6,900,000 common units in August 2009.





Net cash
used in financing activities was $175.9 million for 2008 compared to net
cash used in financing activities of $139.7 million for 2007. The
$36.2 million increase is primarily due to $772.8 million of
nonrecurring net proceeds from equity offerings in 2007, a $285.6 million
decrease in proceeds from borrowings, a $59.7 million increase in
distributions to unitholders, and a $26.8 million repurchase of senior
notes in 2008, partially offset by a $671.7 million net decrease in
distributions to Targa and a $436.9 million decrease in repayments of
indebtedness.





Capital
Requirements





The
midstream energy business can be capital intensive, requiring significant
investment to maintain and upgrade existing operations. A significant portion of
the cost of constructing new gathering lines to connect to our gathering system
is generally paid for by the natural gas producer. However, we expect to make
significant expenditures during the next year for the construction of additional
natural gas gathering and processing infrastructure and to enhance the value of
our natural gas logistics and marketing assets.





We
categorize our capital expenditures as either: (i) maintenance expenditures
or (ii) expansion expenditures. Maintenance expenditures are those
expenditures that are necessary to maintain the service capability of our
existing assets including the replacement of system components and equipment
which is worn, obsolete or completing its useful life, the addition of new
sources of natural gas supply to our systems to replace natural gas production
declines and expenditures to remain in compliance with environmental laws and
regulations. Expansion expenditures improve the service capability of the
existing assets, extend asset useful lives, increase capacities from existing
levels, add capabilities, reduce costs or enhance revenues.





Year Ended December 31,2009
            
            
            2008
            
            
            2007(In
      millions)Capital
      expenditures:Expansion
            
            $
            40.6
            
            
            $
            60.2
            
            
            $
            48.5Maintenance
            
            
            20.0
            
            
            
            40.3
            
            
            
            30.4$
            60.6
            
            
            $
            100.5
            
            
            $
            78.9








Our
planned capital expenditures for 2010 are approximately $130 million with
maintenance capital expenditures accounting for approximately 25%. Included in
the planned capital expenditures for 2010 is the expansion of our facility at
Cedar Bayou. Given our objective of growth through acquisitions, expansions of
existing assets and other internal growth projects, we anticipate that over time
we will invest significant amounts of capital to grow and acquire assets.
Expansion capital expenditures may vary significantly based on investment
opportunities.





Credit
Facilities and Long-Term Debt





As of
December 31, 2009, we had outstanding loans of $479.2 million and
approximately $410.1 million of availability under our senior secured revolving
credit facility. See “Debt Obligations” included under Note 10 to our
“Consolidated Financial Statements” beginning on page F-1 of this Annual Report
for a discussion of our credit agreements.





On
September 24, 2009, in association with our purchase of the Downstream
Business, the entire balance of affiliated indebtedness payable to Targa (by
Targa Downstream LP and Targa LSNG LP) was settled with Targa via capital
contributions made by Targa and repayments by us.





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Description of 81⁄4% Senior
Notes. On June 18, 2008, we completed the private placement under
Rule 144 A and Regulation S of the Securities Act of 1933 of $250 million in
aggregate principal amount of our 81⁄4% senior unsecured notes due 2016 (the “81⁄4%
Notes”). In connection with the issuance of the 81⁄4% Notes, we entered into an
indenture (the “2008 Indenture”) governing the terms of the 81⁄4%
Notes.





The 81⁄4%
Notes will mature on July 15, 2016 and interest is payable on the 81⁄4% Notes
semi-annually in arrears on each January 1 and July 1. The 81⁄4% Notes
are guaranteed on a senior unsecured basis by certain of our
subsidiaries.





The 2008
Indenture restricts our ability to make distributions to unitholders if we are
in default or an event of default (as defined in the 2008 Indenture) exists. It
also restricts our ability and the ability of certain of our subsidiaries to:
(i) incur additional debt or enter into sale and leaseback transactions;
(ii) pay certain distributions on or repurchase, equity interests (only if
such distributions do not meet specified conditions); (iii) make certain
investments; (iv) incur liens; (v) enter into transactions with
affiliates; (vi) merge or consolidate with another company; and
(vii) transfer and sell assets. These covenants are subject to a number of
important exceptions and qualifications. If at any time when the 81⁄4% Notes are
rated investment grade by both Moody’s Investors Service, Inc. and
Standard & Poor’s Ratings Services and no Default (as defined in the
2008 Indenture) has occurred and is continuing, many of such covenants will
terminate and we and our subsidiaries will cease to be subject to such
covenants.





Description
of 111⁄4% Senior Notes.On July 6,
2009, we completed the private placement under Rule 144A and Regulation S of the
Securities Act of 1933 of $250 million in aggregate principal amount of
111⁄4% senior notes due 2017 (the “111⁄4% Notes”).
The 111⁄4% Notes were issued at 94.973% of the face amount, resulting in gross
proceeds of $237.4 million. Proceeds from the 111⁄4% Notes were used to repay
borrowings under our senior secured revolving credit facility. In connection
with the issuance of the 111⁄4% Notes, we entered into an indenture (the “2009
Indenture”) governing the terms of the 111⁄4% Notes.





The 111⁄4%
Notes will mature on July 1, 2017 and interest is payable on the 111⁄4% Notes
semi-annually in arrears on each January 15 and July 15. The 111⁄4%
Notes are guaranteed on a senior unsecured basis by certain of our
subsidiaries.





The 2009
Indenture restricts our ability to make distributions to unitholders if we are
in default or an event of default (as defined in the 2009 Indenture) exists. It
also restricts our ability and the ability of certain of our subsidiaries to:
(i) incur additional debt or enter into sale and leaseback transactions;
(ii) pay certain distributions on or repurchase, equity interests (only if
such distributions do not meet specified conditions); (iii) make certain
investments; (iv) incur liens; (v) enter into transactions with
affiliates; (vi) merge or consolidate with another company; and
(vii) transfer and sell assets. These covenants are subject to a number of
important exceptions and qualifications. If at any time when the 111⁄4% Notes are
rated investment grade by both Moody’s Investors Service, Inc. and
Standard & Poor’s Ratings Services and no Default (as defined in the
2009 Indenture) has occurred and is continuing, many of such covenants will
terminate and we and our subsidiaries will cease to be subject to such
covenants.





Off-Balance
Sheet Arrangements





We
currently have no off-balance sheet arrangements as defined by the SEC. See
“Contractual Obligations” below and “Commitments and Contingencies” included
under Note 16 to our “Consolidated Financial Statements” beginning on page F-1
of this Annual Report for a discussion of our commitments and contingencies,
some of which are not recognized in the consolidated balance sheets under
GAAP.








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Contractual
Obligations





Following
is a summary of our contractual cash obligations over the next several fiscal
years, as of December 31, 2009:




Contractual Obligations (1)
            
            Total
            
            
            Less Than
              1 Year
            
            
            1-3 Years
            
            
            4-5 Years
            
            
            More Than
              5 Years(In
      millions)Debt
      obligations (2)
            
            $
            919.6
            
            
            $
            -
            
            
            $
            479.2
            
            
            $
            -
            
            
            $
            440.4Interest
      on debt obligations (3)
            
            
            327.5
            
            
            
            52.9
            
            
            
            97.3
            
            
            
            86.5
            
            
            
            90.8Operating
      lease obligations (4)
            
            
            38.0
            
            
            
            8.9
            
            
            
            12.7
            
            
            
            5.9
            
            
            
            10.5Capacity
      payments (5)
            
            
            2.7
            
            
            
            2.0
            
            
            
            0.7
            
            
            
            -
            
            
            
            -Right-of-way
            
            
            11.4
            
            
            
            0.9
            
            
            
            1.6
            
            
            
            1.2
            
            
            
            7.7Asset
      retirement obligation
            
            
            6.6
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            6.6Purchase
      order commitments
            
            
            3.8
            
            
            
            3.8
            
            
            
            -
            
            
            
            -
            
            
            
            -$
            1,309.6
            
            
            $
            68.5
            
            
            $
            591.5
            
            
            $
            93.6
            
            
            $
            556.0





________


(1)
            Contractual
      obligations exclude current and long-term unrealized losses on derivative
      instruments included in the consolidated balance sheet as those amounts
      represent the current fair value of various derivative contracts and do
      not represent future cash purchase obligations. These contracts may be
      settled financially at the difference between the future market price and
      the contractual price and may result in either cash payments or cash
      receipts; therefore, it is not possible to estimate the timing or amounts
      of potential future obligations.(2)
            Represents
      our scheduled future maturities of consolidated debt obligations for the
      periods indicated. See “Debt Obligations” included under “Note 10 to
      our “Consolidated Financial Statements” beginning on page F-1 of this
      Annual Report for information regarding our debt
    obligations.(3)
            Represents
      interest expense on our debt obligations based on interest rates as of
      December 31, 2009 and the scheduled future maturities of those debt
      obligations.(4)
            Include
      minimum lease payment obligations associated with site leases and railcar
      leases.(5)
            Consist
      of capacity payments for firm transportation
  contracts.





Critical
Accounting Policies and Estimates




The
preparation of financial statements in accordance with GAAP requires our
management to make estimates and assumptions that affect the reported amounts of
assets and liabilities and disclosure of contingent assets and liabilities at
the date of the financial statements and the reported amounts of revenues and
expenses during the period. Actual results could differ from these estimates.
The policies and estimates discussed below are considered by management to be
critical to an understanding of our financial statements because their
application requires the most significant judgments from management in
estimating matters for financial reporting that are inherently uncertain. See
the description of our accounting policies in the notes to the financial
statements for additional information about our critical accounting policies and
estimates.




Property, Plant and
Equipment. In general, depreciation is the systematic and rational
allocation of an asset’s cost, less its residual value (if any), to the period
it benefits. Our property, plant and equipment is depreciated using the
straight-line method over the estimated useful lives of the assets. Our estimate
of depreciation incorporates assumptions regarding the useful economic lives and
residual values of our assets. At the time we place our assets in-service, we
believe such assumptions are reasonable; however, circumstances may develop that
would cause us to change these assumptions, which would change our depreciation
amounts prospectively. Examples of such circumstances include:




·
            changes
      in energy prices;




·
            changes
      in competition;




·
            changes
      in laws and regulations that limit the estimated economic life of an
      asset;






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·
            changes
      in technology that render an asset
obsolete;




·
            changes
      in expected salvage values; and




·
            changes
      in the forecast life of applicable resources basins, if
    any.




As of
December 31, 2009, the net book value of our property, plant and equipment
was $1.7 billion and we recorded $101.2 million in depreciation
expense for 2009. The weighted average life of our long-lived assets is
approximately 20 years. If the useful lives of these assets were found to be
shorter than originally estimated, depreciation expense may increase,
liabilities for future asset retirement obligations may be insufficient and
impairments in carrying values of tangible and intangible assets may result. For
example, if the depreciable lives of our assets were reduced by 10%, we estimate
that depreciation expense would increase by $11.2 million per year, which
would result in a corresponding reduction in our operating income. In addition,
if an assessment of impairment resulted in a reduction of 1% of our long-lived
assets, our operating income would decrease by $16.8 million per year.
There have been no material changes impacting estimated useful lives of the
assets.





Revenue Recognition. As of
December 31, 2009, the Partnership’s balance sheet reflects total accounts
receivable from third parties of $328.3 million. We have recorded an
allowance for doubtful accounts as of December 31, 2009 of
$2.2 million.





The
Partnership’s exposure to uncollectible accounts receivable relates to the
financial health of its counterparties. The Partnership and its indirect parent,
Targa, have an active credit management process which is focused on controlling
loss exposure to bankruptcies or other liquidity issues of counterparties. If an
assessment of uncollectibility resulted in a 1% reduction of our third party
accounts receivable, our annual operating income would decrease by
$3.3 million.





Price Risk Management
(Hedging). Our net income and cash flows are subject to volatility
stemming from changes in commodity prices and interest rates. To reduce the
volatility of our cash flows, we have entered into (i) derivative financial
instruments related to a portion of our equity volumes to manage the purchase
and sales prices of commodities and (ii) interest rate financial
instruments to fix the interest rate on our variable debt. We are exposed to the
credit risk of our counterparties in these derivative financial instruments. We
also monitor NGL inventory levels with a view to mitigating losses related to
downward price exposure.





Our cash
flow is affected by the derivative financial instruments we enter into to the
extent these instruments are settled by (i) making or receiving a payment
to/from the counterparty or (ii) making or receiving a payment for entering
into a contract that exactly offsets the original derivative financial
instrument. Typically a derivative financial instrument is settled when the
physical transaction that underlies the derivative financial instrument
occurs.





One of
the primary factors that can affect our operating results each period is the
price assumptions we use to value our derivative financial instruments, which
are reflected at their fair values in the balance sheet. The relationship
between the derivative financial instruments and the hedged item must be highly
effective in achieving the offset of changes in cash flows attributable to the
hedged risk both at the inception of the derivative financial instrument and on
an ongoing basis. Hedge accounting is discontinued prospectively when a
derivative financial instrument becomes ineffective. Gains and losses deferred
in other comprehensive income related to cash flow hedges for which hedge
accounting has been discontinued remain deferred until the forecasted
transaction occurs. If it is probable that a hedged forecasted transaction will
not occur, deferred gains or losses on the derivative financial instrument are
reclassified to earnings immediately.





The
estimated fair value of our derivative financial instruments was a liability of
$10.3 million as of December 31, 2009, net of an adjustment for credit
risk. The credit risk adjustment is based on the default probabilities by year
for each counterparty’s traded credit default swap transactions. These default
probabilities have been applied to the unadjusted fair values of the derivative
financial instruments to arrive at the credit risk adjustment, which aggregates
to less than $0.1 million as of December 31, 2009. We and our indirect
parent, Targa, have an active credit management process which is focused on
controlling loss exposure to bankruptcies or other liquidity issues of
counterparties. If a financial instrument counterparty were to declare
bankruptcy, we would be exposed to the loss of fair value of the financial
instrument transaction with that counterparty. Ignoring our





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adjustment
for credit risk, if a bankruptcy by financial instrument counterparty impacted
10% of the fair value of commodity-based financial instruments, we estimate that
our operating income would decrease by $1.0 million per year.





Recent
Accounting Pronouncements.





For a
discussion of recent accounting pronouncements that will affect us, see
“Significant Accounting Policies” included under Note 4 to our
“Consolidated Financial Statements” beginning on page F-1 of this Annual
Report.





Item 7A. Quantitative and Qualitative Disclosures About Market
Risk





Our
principal market risks are our exposure to changes in commodity prices,
particularly to the prices of natural gas and NGLs, changes in interest rates,
as well as nonperformance by our customers. We do not use risk sensitive
instruments for trading purposes.





Commodity Price Risk. A
majority of our revenues are derived from percent-of-proceeds contracts under
which we receive a portion of the natural gas and/or NGLs or equity volumes, as
payment for services. The prices of natural gas and NGLs are subject to
fluctuations in response to changes in supply, demand, market uncertainty and a
variety of additional factors beyond our control. We monitor these risks and
enter into hedging transactions designed to mitigate the impact of commodity
price fluctuations on our business. Cash flows from a derivative instrument
designated as a hedge are classified in the same category as the cash flows from
the item being hedged.





The
primary purpose of our commodity risk management activities is to hedge our
exposure to commodity price risk and reduce fluctuations in our operating cash
flow despite fluctuations in commodity prices. In an effort to reduce the
variability of our cash flows, as of December 31, 2009, we have hedged the
commodity price associated with a significant portion of our expected natural
gas, NGL and condensate equity volumes for the years 2010 through 2013 by
entering into derivative financial instruments including swaps and purchased
puts (or floors). The percentages of our expected equity volumes that are hedged
decrease over time. With swaps, we typically receive an agreed fixed price for a
specified notional quantity of natural gas or NGL and we pay the hedge
counterparty a floating price for that same quantity based upon published index
prices. Since we receive from our customers substantially the same floating
index price from the sale of the underlying physical commodity, these
transactions are designed to effectively lock-in the agreed fixed price in
advance for the volumes hedged. In order to avoid having a greater volume hedged
than our actual equity volumes, we typically limit our use of swaps to hedge the
prices of less than our expected natural gas and NGL equity volumes. We utilize
purchased puts (or floors) to hedge additional expected equity commodity volumes
without creating volumetric 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 as
market conditions permit.





We have
tailored our hedges to generally match the NGL product composition and the NGL
and natural gas delivery points to those of our physical equity volumes. Our NGL
hedges cover baskets of ethane, propane, normal butane, isobutane and natural
gasoline based upon our expected equity NGL composition. We believe this
strategy avoids uncorrelated risks resulting from employing hedges on crude oil
or other petroleum products as “proxy” hedges of NGL prices. Our NGL hedges fair
values are based on published index prices for delivery at Mont Belvieu through
2012, except for the price of isobutane in 2012, which is based on the ending
2011 pricing. Our natural gas hedges fair values are based on published index
prices for delivery at Waha and Mid-Continent, which closely approximate our
actual NGL and natural gas delivery points. We hedge a portion of our condensate
sales using crude oil hedges that are based on the NYMEX futures contracts for
West Texas Intermediate light, sweet crude.





Our
commodity price hedging transactions are typically documented pursuant to a
standard International Swap Dealers Association form with customized credit and
legal terms. Our principal counterparties (or, if applicable, their guarantors)
have investment grade credit ratings. Our payment obligations in connection with
substantially all of these hedging transactions and any additional credit
exposure due to a rise in natural gas and NGL prices relative to the fixed
prices set forth in the hedges, are secured by a first priority lien in the
collateral securing our senior secured indebtedness that ranks equal in right of
payment with liens granted in favor of our senior secured lenders. As long as
this first priority lien is in effect, we expect to have no obligation to post
cash, letters of credit or other





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additional
collateral to secure these hedges at any time, even if our counterparty’s
exposure to our credit increases over the term of the hedge as a result of
higher commodity prices or because there has been a change in our
creditworthiness. A purchased put (or floor) transaction does not create credit
exposure to us for our counterparties.





During
2009, 2008 and 2007, we entered into hedging arrangements for a portion of our
forecasted equity volumes. Floor volumes and floor pricing are based solely on
purchased puts (or floors). During 2009, 2008 and 2007, our operating revenues
were increased (decreased) by net hedge adjustments of $45.7 million,
($33.7) million and ($1.0) million.





As of
December 31, 2009, our commodity derivative arrangements were as
follows:





Natural
Gas


Instrument
              
              
              
              Price
              
              MMBtu
      per dayType
              
              Index
              
              $/MMBtu
              
              2010
              
              2011
              
              2012
              
              2013
              
              Fair
      Value(In
      millions)Swap
              
              IF-NGPL
      MC
              
              8.86
              
              5,685
              
              -
              
              -
              
              -
              
              $                   6.7Swap
              
              IF-NGPL
      MC
              
              7.34
              
              -
              
              2,750
              
              -
              
              -
              
              1.2Swap
              
              IF-NGPL
      MC
              
              7.18
              
              -
              
              -
              
              2,750
              
              -
              
              0.95,685
              
              2,750
              
              2,750
              
              -Swap
              
              IF-Waha
              
              6.48
              
              10,809
              
              -
              
              -
              
              -
              
              3.4Swap
              
              IF-Waha
              
              6.10
              
              -
              
              11,250
              
              -
              
              -
              
              (0.1)Swap
              
              IF-Waha
              
              6.30
              
              -
              
              -
              
              7,250
              
              -
              
              0.1Swap
              
              IF-Waha
              
              5.59
              
              -
              
              -
              
              -
              
              4,000
              
              (0.9)10,809
              
              11,250
              
              7,250
              
              4,000Total
      Sales
              
              
              
              
              
              16,494
              
              14,000
              
              10,000
              
              4,000Basis
      Swap
              Jan
      2010-May 2011, Rec IF-CGT, Pay NYMEX less $0.12, 20,000
      MMBtu/d
              
              0.8Fuel
      cost swap
              Jan
      2010-May 2011, Rec  IF-CGT, Pay $5.96, 226
    MMBtu/d
              
              -$                 12.1


NGL





Instrument
            
            
            
            Price
            
            
            Barrels
      per dayType
            
            Index
            
            $/gal
            
            
            2010
            
            
            2011
            
            
            2012
            
            
            2013
            
            
            Fair
      Value(In
      millions)Swap
            
            OPIS-MB
            
            
            1.21
            
            
            
            5,607
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            $
            8.7Swap
            
            OPIS-MB
            
            
            0.90
            
            
            
            -
            
            
            
            4,000
            
            
            
            -
            
            
            
            -
            
            
            
            (10.9
            )Swap
            
            OPIS-MB
            
            
            0.92
            
            
            
            -
            
            
            
            -
            
            
            
            2,700
            
            
            
            -
            
            
            
            (6.8
            )Total
      Swaps
            
            
            
            
            
            
            
            
            5,607
            
            
            
            4,000
            
            
            
            2,700
            
            
            
            -Floor
            
            OPIS-MB
            
            
            1.44
            
            
            
            -
            
            
            
            199
            
            
            
            -
            
            
            
            -
            
            
            
            1.1Floor
            
            OPIS-MB
            
            
            1.43
            
            
            
            -
            
            
            
            -
            
            
            
            231
            
            
            
            -
            
            
            
            1.4Total
      Floors
            
            
            
            
            
            
            
            
            -
            
            
            
            199
            
            
            
            231
            
            
            
            -Total
      Sales
            
            
            
            
            
            
            
            
            5,607
            
            
            
            4,199
            
            
            
            2,931
            
            
            
            -$
            (6.5
            )











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Condensate





Instrument
            
            
            
            Price
            
            
            Barrels
      per dayType
            
            Index
            
            $/Bbl
            
            
            2010
            
            
            2011
            
            
            2012
            
            
            2013
            
            
            Fair
      Value(In
      millions)Swap
            
            NY-WTI
            
            
            70.62
            
            
            
            501
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            $
            (2.1
            )Swap
            
            NY-WTI
            
            
            76.54
            
            
            
            -
            
            
            
            350
            
            
            
            -
            
            
            
            -
            
            
            
            (1.2
            )Swap
            
            NY-WTI
            
            
            72.60
            
            
            
            -
            
            
            
            -
            
            
            
            200
            
            
            
            -
            
            
            
            (1.0
            )Swap
            
            NY-WTI
            
            
            74.00
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            200
            
            
            
            (1.0
            )Total
      Swap
            
            
            
            
            
            
            
            
            501
            
            
            
            350
            
            
            
            200
            
            
            
            200Total
      Sales
            
            
            
            
            
            
            
            
            501
            
            
            
            350
            
            
            
            200
            
            
            
            200$
            (5.3
            )








These
contracts may expose us to the risk of financial loss in certain circumstances.
Our hedging arrangements provide us protection on the hedged volumes if prices
decline below the prices at which these hedges are set. If prices rise above the
prices at which we have hedged, we will receive less revenue on the hedged
volumes than we would receive in the absence of hedges.





We
account for the fair value of our financial assets and liabilities using a
three-tier fair value hierarchy, which prioritizes the significant inputs used
in measuring fair value. These tiers include: Level 1, defined as observable
inputs such as quoted prices in active markets; Level 2, defined as inputs other
than quoted prices in active markets that are either directly or indirectly
observable; and Level 3, defined as unobservable inputs in which little or no
market data exists, therefore required an entity to develop its own assumptions.
We determine the value of our NGL derivative contracts utilizing a discounted
cash flow model for swaps and a standard option pricing model for options, based
on inputs that are either readily available in public markets or are quoted by
counterparties to these contracts. In 2008, all of our NGL contracts were
classified as Level 3 within the hierarchy. In 2009, we were able to obtain inputs from
quoted prices related to certain of these commodity derivatives for similar
assets and liabilities in active markets. These inputs are observable for the
asset or liability, either directly or indirectly, for the full term of the
commodity swaps and options. For the NGL contracts that have inputs from quoted
prices, we have changed our classification of these instruments from
Level 3 to Level 2 within the fair value hierarchy. For those NGL
contracts where we were unable to obtain quoted prices for the full term of the
commodity swap and options the NGL valuations are still classified as Level 3
within the fair value hierarchy.





Interest
Rate Risk.We are exposed to changes in interest rates, primarily as a
result of variable rate borrowings under our senior secured revolving credit
facility. To the extent that interest rates increase, interest expense for our
revolving debt will also increase. As of December 31, 2009, we had
borrowings of $479.2 million outstanding under our senior secured revolving
credit facility. In an effort to reduce the variability of our cash flows, we
have entered into several interest rate swap and interest rate basis swap
agreements. Under these agreements, which are accounted for as cash flow hedges,
the base interest rate on the specified notional amount of our variable rate
debt is effectively fixed for the term of each agreement and ineffectiveness is
required to be measured each reporting period. The fair values of the interest
rate swap agreements, which are adjusted regularly, have been aggregated by
counterparty for classification in our consolidated balance sheets. Accordingly,
unrealized gains and losses relating to the interest rate swaps are recorded in
accumulated other comprehensive income (“OCI”) until the interest expense on the
related debt is recognized in earnings.





As of
December 31, 2009 we had the following open interest rate
swaps:





Period
            
            Fixed Rate
            
            Notional Amount
            
            Fair Value(In
      millions)2010
            
            
            3.67%
            
            $300
      million
            
            $
            (7.8
            )2011
            
            
            3.52%
            
            300
      million
            
            
            (5.1
            )2012
            
            
            3.40%
            
            300
      million
            
            
            (0.6
            )2013
            
            
            3.39%
            
            300
      million
            
            
            1.601/01
      - 4/24/2014
            
            
            3.39%
            
            300
      million
            
            
            1.3$
            (10.6
            )






82
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We have
designated all interest rate swaps as cash flow hedges. Accordingly, unrealized
gains and losses relating to the interest rate swaps are recorded in OCI until
the interest expense on the related debt is recognized in earnings. A
hypothetical increase of 100 basis points in the underlying interest rate,
after taking into account our interest rate swaps, would increase our annual
interest expense by $1.8 million.





Credit
Risk.We our
subject to risk of losses resulting from nonpayment or nonperformance by our
customers.Our credit exposure related to commodity derivative
instruments is represented by the fair value of contracts with a net positive
fair value to us at the reporting date. At such times, these outstanding
instruments expose us to credit loss in the event of nonperformance by the
counterparties to the agreements. Should the creditworthiness of one or more of
our counterparties decline, our ability to mitigate nonperformance risk is
limited to a counterparty agreeing to either a voluntary termination and
subsequent cash settlement or a novation of the derivative contract to a third
party. In the event of a counterparty default, we may sustain a loss and our
cash receipts could be negatively impacted.





As of
December 31, 2009, affiliates of Goldman Sachs and BofA accounted for 93%
and 5% of our counterparty credit exposure related to commodity derivative
instruments. Goldman Sachs and BofA are major financial institutions, each
possessing investment grade credit ratings, based upon minimum credit ratings
assigned by Standard & Poor’s Ratings Services.





Item 8. Financial Statements and Supplementary Data





Our
Consolidated Financial Statements, together with the report of our independent
registered public accounting firm begin on page F-1 of this Annual
Report.





Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure





None.





Item 9A. Controls and Procedures





Disclosure
Controls and Procedures





The Chief
Executive Officer and Chief Financial Officer of our general partner, after
evaluating the effectiveness of the Partnership’s “disclosure controls and
procedures” (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities
Exchange Act of 1934 (the “Exchange Act”)), as of December 31, 2009, have
concluded that as of December 31, 2009, the Partnership’s disclosure controls
and procedures were effective and designed to provide reasonable assurance that
information required to be disclosed by the Partnership in the reports that it
files or submits under the Exchange Act is recorded, processed, summarized and
reported, within the time periods specified in the Commission’ rules and forms
and accumulated and communicated to the Partnership’s management, including the
chief executive officer and chief financial officer, as appropriate to allow
timely decisions regarding required disclosures.




Internal
Control Over Financial Reporting




(a) Management’s Report on Internal
Control Over Financial Reporting




The
management of our general partner is responsible for establishing and
maintaining adequate internal control over financial reporting, as such term is
defined in Exchange Act Rules 13a-15(f) and 15d-15(f). The general partner’s
management, including the Chief Executive Officer and Chief Financial Officer,
conducted an evaluation of the effectiveness of the Partnership’s internal
control over financial reporting based on the Internal Control — Integrated
Frameworkissued by the Committee of Sponsoring Organizations of the
Treadway Commission. Based on the results of this evaluation, the general
partner’s management concluded that the Partnership’s internal control over
financial reporting was effective as of December 31, 2009 as stated in its
report included in our consolidated financial statements on page F-2 of this
Annual Report, which is incorporated herein by reference.


83
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The
effectiveness of the Partnership’s internal control over financial reporting as
of December 31, 2009, has been audited by PricewaterhouseCoopers LLP, an
independent registered public accounting firm, as stated in its




(b)
Changes in Internal Control Over Financial Reporting





During
the quarter ended December 31, 2009, there were no changes in the Partnership’s
internal control over financial reporting that have materially affected or are
reasonably likely to materially affect, the Partnership’s internal control over
financial reporting.





Item 9B. Other Information





On March
1, 2010, we issued a press release (the “Earnings Release”) regarding our
financial results for the three months and year ended December 31, 2009, which
was filed with a current report on Form 8-K. As reflected in our Consolidated
Statement of Cash Flow for the year ended December 31, 2009 included in this
Annual Report, net cash provided by operating activities was $299.8 million and
net cash used in financing activities was $277.6 million.  The cash flow
statement included in the Earnings Release incorrectly reported net cash
provided by operating activities as $179.0 million and net cash used in
financing activities as $156.8 million. The understatement in these two figures
reported in the cash flow statement included in the Earnings Release resulted
from the inclusion of $120.8 million in repayment of affiliated indebtedness
related to the acquisition of the Downstream Business in cash flows from
operating activities rather than in cash flows from financing activities. You
should rely on the Consolidated Statements of Cash Flows included in this Annual
Report.





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Part
III





Item 10. Directors, Executive Officers and Corporate
Governance





We are a
limited partnership and, therefore, have no officers or directors. Unless
otherwise indicated, references to officers and directors of the Partnership in
Items 10-14 of this Annual Report refer to the officers and directors of our
general partner.





Management
of Targa Resources Partners LP





Targa
Resources GP LLC, our general partner, manages our operations and activities.
Our general partner is not elected by our unitholders and is not subject to
re-election on a regular basis in the future. Unitholders are not entitled to
elect the directors of our general partner or directly or indirectly participate
in our management or operation. Our general partner owes a fiduciary duty to our
unitholders, but our partnership agreement contains various provisions modifying
and restricting the fiduciary duty. Our general partner is liable, as general
partner, for all of our debts (to the extent not paid from our assets), except
for indebtedness or other obligations that are made expressly nonrecourse to it.
Our general partner therefore may cause us to incur indebtedness or other
obligations that are nonrecourse to it.





The
directors of our general partner oversee our operations. Our general partner
currently has seven directors. Targa elects all members to the board of
directors of our general partner (the “Board”) and our general partner has three
directors that are independent as defined under the independence standards
established by the New York Stock Exchange (the “NYSE”). The NYSE does not
require a listed limited partnership like us to have a majority of independent
directors on the Board or to establish a compensation committee or a
nominating/corporate governance committee.





The Board
has a standing audit committee (the “Audit Committee”) that consists of three
directors. Messrs. Robert B. Evans, Barry R. Pearl and William D. Sullivan
serve as the members of the Audit Committee. The Board has affirmatively
determined that Messrs. Evans, Pearl and Sullivan are independent as
described in the rules of the NYSE and the Exchange Act, as amended. The Board
has also determined that, based upon relevant experience, Audit Committee member
Barry R. Pearl is an “audit committee financial expert” as defined in
Item 407 of Regulation S-K of the Exchange Act, as amended.
Mr. Pearl serves as the Chairman of the Audit Committee. The Audit
Committee assists the Board in its oversight of the integrity of our financial
statements and our compliance with legal and regulatory requirements and
partnership policies and controls. The Audit Committee has sole authority to
retain and terminate our independent registered public accounting firm, approve
all auditing services and related fees and the terms thereof and pre-approve any
non-audit services to be rendered by our independent registered public
accounting firm. The Audit Committee is also responsible for confirming the
independence and objectivity of our independent registered public accounting
firm. Our independent registered public accounting firm has been given
unrestricted access to the Audit Committee.





The
compensation of our general partner’s executive officers is set by Targa
Resources Investments Inc., the indirect parent of our general partner, with the
Board playing no role in the process. Compensation decisions relating to
oversight of the long-term incentive plan described below, however, are made by
the Board. While the Board may establish a compensation committee in the future,
it has no current plans to do so.





The Board
has a standing conflicts committee (the “Conflicts Committee”) to review
specific matters that the Board believes may involve conflicts of interest.
Messrs. Evans, Pearl and Sullivan serve as the members of the Conflicts
Committee. Mr. Pearl serves as the Chairman of the Conflicts Committee. The
Conflicts Committee determines if the resolution of the conflict of interest is
fair and reasonable to us. The members of the Conflicts Committee may not be
officers or employees of our general partner or directors, officers or employees
of its affiliates and must meet the independence and experience standards
established by the NYSE and the Exchange Act to serve on an audit committee of a
board of directors and certain other requirements. Any matters approved by the
Conflicts Committee in good faith will be conclusively deemed to be fair and
reasonable to us, approved by all of our partners and not a breach by our
general partner of any duties it may owe us or our unitholders.








85
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All of
our executive management personnel are employees of Targa Resources LLC (“Targa
Resources”), a wholly-owned subsidiary of Targa, and devote their time as needed
to conduct our business and affairs. These officers of Targa Resources manage
the day-to-day affairs of our business. We believe that during 2009, the
officers of the general partner devoted similar amounts of time to Targa’s and
to the Partnership’s business. We expect the amount of time that the executive
management personnel of our general partner devote to our business in future
periods to be driven by the needs and demands of our ongoing business and
business development efforts, which are likely to increase as our asset base and
operations increase in size. However, depending on how our business develops and
the nature of the business development efforts by executive management, the
amount of time that the executive management team of our general partner devotes
to our business may increase or decrease in future periods. We also utilize a
significant number of employees of Targa Resources to operate our business and
provide us with general and administrative services. We reimburse Targa for
allocated expenses of operational personnel who perform services for our
benefit, allocated general and administrative expenses and certain direct
expenses. See “Reimbursement of Expenses of Our General Partner” included in
this Item 10.





Directors
and Executive Officers





The
following table shows information regarding the current directors and executive
officers of Targa Resources GP LLC:





Name
            
            Age
      (1)
            
            Position
      with Targa Resources GP LLCRene
      R. Joyce
            
            
            62
            
            Chief
      Executive Officer and DirectorJoe
      Bob Perkins
            
            
            49
            
            PresidentJames
      W. Whalen
            
            
            68
            
            President — Finance
      and Administration and DirectorRoy
      E. Johnson
            
            
            65
            
            Executive
      Vice PresidentMichael
      A. Heim
            
            
            61
            
            Executive
      Vice President and Chief Operating OfficerJeffrey
      J. McParland
            
            
            55
            
            Executive
      Vice President and Chief Financial OfficerPaul
      W. Chung
            
            
            49
            
            Executive
      Vice President, General Counsel and SecretaryPeter
      R. Kagan
            
            
            41
            
            DirectorChansoo
      Joung
            
            
            49
            
            DirectorRobert
      B. Evans
            
            
            61
            
            DirectorBarry
      R. Pearl
            
            
            60
            
            DirectorWilliam
      D. Sullivan
            
            
            53
            
            Director


_______


(1)
            As
      of February 25, 2010





Our
general partner’s directors hold office until the earlier of their death,
resignation, removal or disqualification or until their successors have been
elected and qualified. Officers serve at the discretion of the Board. There are
no family relationships among any of our general partner’s directors or
executive officers.







Rene R. Joycehas served as a
director and Chief Executive Officer of our general partner since October 2006
and of Targa since its formation in February 2004 and was a consultant for the
Targa predecessor company during 2003. He is also a member of the supervisory
directors of Core Laboratories N.V. Mr. Joyce served as a consultant in the
energy industry from 2000 through 2003 providing advice to various energy
companies and investors regarding their operations, acquisitions and
dispositions. Mr. Joyce served as President of onshore pipeline operations of
Coral Energy, LLC, a subsidiary of Shell Oil Company (“Shell”) from 1998 through
1999 and President of energy services of Coral Energy Holding, L.P. (“Coral”) a
subsidiary of Shell which was the gas and power marketing joint venture between
Shell and Tejas Gas Corporation (“Tejas”) during 1999. Mr. Joyce served as
President of various operating subsidiaries of Tejas, a natural gas pipeline
company, from 1990 until 1998 when Tejas was acquired by Shell. As the founding
Chief Executive Officer of Targa, Mr. Joyce brings deep experience in the
midstream business, expansive knowledge of the oil and gas industry, as well as
relationships with chief executives and other senior management at peer
companies, customers and other oil and natural gas companies throughout the
world. His experience and industry knowledge, complemented by an engineering and
legal educational background, enable Mr. Joyce to provide the board with
executive counsel on the full range of business, technical, and professional
matters.








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Joe Bob Perkinshas served as
President of our general partner since October 2006 and of Targa since February
2004 and was a consultant for the Targa predecessor company during 2003.
Mr. Perkins also served as a consultant in the energy industry from 2002
through 2003 and was an active partner in RTM Media (an outdoor advertising
firm) during such time period. Mr. Perkins served as President and Chief
Operating Officer for the Wholesale Businesses, Wholesale Group and Power
Generation Group of Reliant Resources, Inc. and its parent/predecessor
companies, from 1998 to 2002 and Vice President, Corporate Planning and
Development of Houston Industries from 1996 to 1998. He served as Vice
President, Business Development, of Coral from 1995 to 1996 and as Director,
Business Development, of Tejas from 1994 to 1995. Prior to 1994,
Mr. Perkins held various positions with the consulting firm of
McKinsey & Company and with an exploration and production
company.





James W. Whalenhas served as
a director of our general partner since February 2007 and has served as
President-Finance and Administration of our general partner since October 2006
and of Targa since January 2006 and as a director of Targa since May 2004. Since
November 2005, Mr. Whalen has served as President—Finance and Administration for
various Targa subsidiaries. Between October 2002 and October 2005, Mr. Whalen
served as the Senior Vice President and Chief Financial Officer of Parker
Drilling Company. Between January 2002 and October 2002, he was the Chief
Financial Officer of Diversified Diagnostic Products, Inc. He served as Chief
Commercial Officer of Coral from February 1998 through January 2000. Previously,
he served as Chief Financial Officer for Tejas from 1992 to 1998. Mr. Whalen is
also a director of EQT Corp. Mr. Whalen brings a breadth and depth of experience
as an executive, board member, and audit committee member across several
different companies and in energy and other industry areas. His valuable
management and financial expertise includes an understanding of the accounting
and financial matters that the Partnership and industry address on a regular
basis.





Roy E. Johnsonhas served as
Executive Vice President of our general partner since October 2006 and of Targa
since April 2004 and was a consultant for the Targa predecessor company during
2003. Mr. Johnson also served as a consultant in the energy industry from
2000 through 2003 providing advice to various energy companies and investors
regarding their operations, acquisitions and dispositions. He served as Vice
President, Business Development and President of the International Group of
Tejas from 1995 to 2000. In these positions, he was responsible for
acquisitions, pipeline expansion and development projects in North and South
America. Mr. Johnson served as President of Louisiana Resources Company, a
company engaged in intrastate natural gas transmission, from 1992 to 1995. Prior
to 1992, Mr. Johnson held various positions with a number of different
companies in the upstream and downstream energy industry.





Michael A. Heimhas served as
Executive Vice President and Chief Operating Officer of our general partner
since October 2006 and of Targa since April 2004 and was a consultant for the
Targa predecessor company during 2003. Mr. Heim also served as a consultant
in the energy industry from 2001 through 2003 providing advice to various energy
companies and investors regarding their operations, acquisitions and
dispositions. Mr. Heim served as Chief Operating Officer and Executive Vice
President of Coastal Field Services, a subsidiary of The Coastal Corp.
(“Coastal”), a diversified energy company, from 1997 to 2001 and President of
Coastal States Gas Transmission Company from 1997 to 2001. In these positions,
he was responsible for Coastal’s midstream gathering, processing and marketing
businesses. Prior to 1997, he served as an officer of several other Coastal
exploration and production, marketing and midstream subsidiaries.





Jeffrey J. McParlandhas
served as Executive Vice President and Chief Financial Officer of our general
partner since October 2006 and of Targa since April 2004 and was a consultant
for the Targa predecessor company during 2003. He served as a director of our
general partner from October 2006 to February 2007. Mr. McParland served as
Treasurer of our general partner from October 2006 until May 2007 and he has
served as Treasurer of Targa from April 2004 until May 2007. Mr. McParland
served as Secretary of Targa since February 2004 until May 2004, at which time
he was elected as Assistant Secretary. Mr. McParland served as Senior Vice
President, Finance of Dynegy Inc., a company engaged in power generation, the
midstream natural gas business and energy marketing, from 2000 to 2002. In this
position, he was responsible for corporate finance and treasury operations
activities. He served as Senior Vice President, Chief Financial Officer and
Treasurer of PG&E Gas Transmission, a midstream natural gas and regulated
natural gas pipeline company, from 1999 to 2000. Prior to 1999, he worked in
various engineering and finance positions with companies in the power generation
and engineering and construction industries.






87
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Peter R. Kaganhas served as
a director of our general partner since February 2007 and has served as a
director of Targa since February 2004. Mr. Kagan is a Managing Director of
Warburg Pincus LLC and a general partner of Warburg Pincus & Co., where he
has been employed since 1997 and became a partner of Warburg Pincus & Co. in
2002. He is also a member of Warburg Pincus’ Executive Management Group. He is
also a director of Antero Resources Corporation, Broad Oak Energy, Inc. (“Broad
Oak”), Canbriam Energy, Fairfield Energy Limited, Laredo Petroleum and MEG
Energy Corp. Mr. Kagan serves as a director because certain investment funds
managed by Warburg Pincus LLC, for whom Mr. Kagan is a managing director and
member, control us through their ownership of securities in Targa Resources
Investments Inc. Mr. Kagan has significant experience with energy companies and
investments and broad familiarity with the industry and related transactions and
capital markets activity, which enhance his contributions to the
board.





Chansoo Jounghas served as a
director of our general partner since February 2007 and has served as a director
of Targa since December 2005. Mr. Joung is a Member and Managing Director of
Warburg Pincus LLC, where he has been employed since 2005 and became a partner
of Warburg Pincus & Co. in 2005. Prior to joining Warburg Pincus, Mr. Joung
was head of the Americas Natural Resources Group in the investment banking
division of Goldman Sachs. He joined Goldman Sachs in 1987 and served in the
Corporate Finance and Mergers and Acquisitions departments and also founded and
led the European Energy Group. He is a director of Sheridan Production Partners,
Broad Oak, Ceres, Inc. and Suniva, Inc. Mr. Joung serves as a director because
certain investment funds managed by Warburg Pincus LLC, for whom Mr. Joung is a
managing director and member, control us through their ownership of securities
in Targa Resources Investments Inc. Mr. Joung has significant experience with
energy companies and investments and broad familiarity with the industry and
related transactions and capital markets activity, which enhance his
contributions to the board.





Robert B. Evanshas served as
a director of our general partner since February 2007. Mr. Evans is a director
of New Jersey Resources Corporation. Mr. Evans was the President and Chief
Executive Officer of Duke Energy Americas, a business unit of Duke Energy Corp.,
from January 2004 to March 2006, after which he retired. Mr. Evans served as the
transition executive for Energy Services, a business unit of Duke Energy, during
2003. Mr. Evans also served as President of Duke Energy Gas Transmission
beginning in 1998 and was named President and Chief Executive Officer in 2002.
Prior to his employment at Duke Energy, Mr. Evans served as Vice President of
marketing and regulatory affairs for Texas Eastern Transmission and Algonquin
Gas Transmission from 1996 to 1998. Mr. Evans’ extensive experience in the gas
transmission and energy services sectors enhances the knowledge of the board in
these areas of the oil and gas industry. As a former President and CEO of
various operating companies, his breadth of executive experiences are applicable
to many of the matters routinely facing the Partnership.





Barry R. Pearlhas served as
a director of our general partner since February 2007. Mr. Pearl is Executive
Vice President of Kealine LLC LLC (and its WesPac Energy LLC affiliate), a
private developer and operator of petroleum infrastructure facilities and is a
director of Seaspan Corporation, Kayne Anderson Energy Development Company and
Magellan Midstream Holdings, L.P., the general partner of Magellan Midstream
Partners, L.P. Mr. Pearl served as President and Chief Executive Officer of
TEPPCO Partners from May 2002 until December 2005 and as President and Chief
Operating Officer from February 2001 through April 2002. Mr. Pearl served as
Vice President of Finance and Chief Financial Officer of Maverick Tube
Corporation from June 1998 until December 2000. From 1984 to 1998, Mr. Pearl was
Vice President of Operations, Senior Vice President of business development and
planning and Senior Vice President and Chief Financial Officer of Santa Fe
Pacific Pipeline Partners, L.P. Mr. Pearl’s board and executive experience
across energy related companies including other MLPs enable him to make broad
contributions to the issues and opportunities that the Partnership faces. His
industry, financial and executive experience enable him to make valuable
contributions to our audit and conflicts committees.




88
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William D. Sullivanhas
served as a director of our general partner since February 2007. Mr. Sullivan is
a director of St. Mary Land & Exploration Company, where he serves as a
non-executive Chairman of the Board. Mr. Sullivan is also a director of Legacy
Reserves GP, LLC and Tetra Technologies, Inc. Mr. Sullivan served as President
and Chief Executive Officer of Leor Energy LP from June 15, 2005 to August 5,
2005. Between 1981 and August 2003, Mr. Sullivan was employed in various
capacities by Anadarko Petroleum Corporation, including serving as Executive
Vice President, Exploration and Production between August 2001 and August 2003.
Since Mr. Sullivan’s departure from Anadarko Petroleum Corporation in August
2003, he has served on various private energy company boards. Mr. Sullivan’s
extensive experience in the exploration and production sector enhances the
knowledge of the board in this particular area of the oil and gas industry. As a
former exploration and production operating officer with responsibilities over
significant gas gathering, compression and processing operations, his experience
is valuable to the board’s understanding of one of the Partnership’s most
important customer types and contributes to other matters routinely facing the
Partnership.





Reimbursement
of Expenses of Our General Partner





Under the
terms of the Second Amended and Restated Omnibus Agreement (the “Omnibus
Agreement”), we reimburse Targa for the payment of certain operating and direct
expenses, including compensation and benefits of operating personnel, and for
the provision of various general and administrative services for our benefit.
Pursuant to these arrangements, Targa performs centralized corporate functions
for us, such as legal, accounting, treasury, insurance, risk management, health,
safety and environmental, information technology, human resources, credit,
payroll, internal audit, taxes, engineering and marketing. We reimburse Targa
for the direct expenses to provide these services as well as other direct
expenses it incurs on our behalf, such as compensation of operational personnel
performing services for our benefit and the cost of their employee benefits,
including 401(k), pension and health insurance benefits. Our general partner
determines the amount of general and administrative expenses to be allocated to
us in accordance with our partnership agreement.





Prior to
February 15, 2010, we reimbursed Targa for these expenses as follows:
(i) with respect to the North Texas System, we reimbursed Targa for
(A) general and administrative expenses, which were capped at
$5.0 million annually, subject to certain increases; and (B) operating
and certain direct expenses, which were not capped, and (ii) with respect
to the SAOU and LOU Systems and the Downstream Business, we reimbursed Targa for
(X) general and administrative expenses, which were not capped, allocated
to the SAOU and LOU Systems and the Downstream Business according to Targa’s
allocation practice; and (Y) operating and certain direct expenses, which
were not capped.





During
the nine-quarter period beginning with the fourth quarter of 2009 and continuing
through the fourth quarter of 2011, Targa will provide distribution support to
us in the form of a reduction in the reimbursement for general and
administrative expense allocated to us if necessary (or make a payment to us, if
needed) for a 1.0 times distribution coverage ratio, at the current distribution
level of $0.5175 per limited partner unit, subject to maximum support of
$8.0 million in any quarter.





Corporate
Governance





Code
of Ethics





Our
general partner has adopted a Code of Ethics For Chief Executive Officer and
Senior Financial Officers (the “Code of Ethics”), which applies to our general
partner’s Chief Executive Officer, Chief Financial Officer, Chief Accounting
Officer, Controller and all other senior financial and accounting officers of
our general partner, and Targa’s Code of Conduct (the “Code of Conduct”), which
applies to officers, directors and employees of Targa and its subsidiaries,
including our general partner. In accordance with the disclosure requirements of
applicable law or regulation, we intend to disclose any amendment to or waiver
from, any provision of the Code of Ethics or Code of Conduct under
Item 5.05 of a current report on Form 8-K.





Available
Information





We make
available, free of charge within the “Corporate Governance” section of our
website at www.targaresources.com and in print to any unitholder who so
requests, our Corporate Governance Guidelines,





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Code of
Ethics, Code of Conduct and the Audit Committee Charter. Requests for print
copies may be directed to: Investor Relations, Targa Resources Partners LP, 1000
Louisiana, Suite 4300, Houston, Texas 77002 or made by telephone by calling
(713) 584-1000. The information contained on or connected to, our internet
website is not incorporated by reference into this Annual Report and should not
be considered part of this or any other report that we file with or furnish to
the SEC.





Executive
Sessions of Non-Management Directors





Our
non-management directors meet in executive session without management
participation at regularly scheduled executive sessions. These meetings are
chaired by Mr. Peter Kagan.





Interested
parties may communicate directly with our non-management directors by writing
to: Non-Management Directors, Targa Resources Partners LP, 1000 Louisiana, Suite
4300, Houston, Texas 77002.





Section 16(A)
Beneficial Ownership Reporting Compliance





Section 16(a)
of the Securities Exchange Act of 1934 requires our directors, executive
officers and 10% unitholders to file with the SEC reports of ownership and
changes in ownership of our equity securities. Based solely upon a review of the
copies of the Form 3, 4 and 5 reports furnished to us and certifications
from our directors and executive officers, we believe that during 2009, all of
our directors, executive officers and beneficial owners of more than 10% of our
common units complied with Section 16(a) filing requirements applicable to
them.





Item 11. Executive Compensation





Executive
Compensation





Compensation
Discussion and Analysis





The following discussion and
analysis contains statements regarding our and our executive officers’ future
performance targets and goals. These targets and goals are disclosed in the limited context of
our compensation programs and should not be understood to be statements of
management’s expectations or estimates of results or other guidance.





Overview





Neither
we nor our general partner directly employ any of the persons responsible for
managing our business. Any compensation decisions that are required to be made
by our general partner will be made by the Board, which does not have a
compensation committee. All of our general partner’s executive officers are
employees of Targa Resources LLC and serve in the same capacities for Targa. All
of the outstanding equity of Targa is held indirectly by Targa Resources
Investments Inc. (“Targa Investments”). We reimburse Targa and its affiliates
for the compensation of our general partner’s executive officers pursuant to the
terms of, and subject to the limitations contained in, the Omnibus
Agreement.





Targa
Investments has ultimate decision making authority with respect to the
compensation of our general partner’s executive officers identified in the
Summary Compensation Table (“named executive officers”). Under the terms of the
Targa Investments’ Amended and Restated Stockholders’ Agreement, as amended (the
“Stockholders’ Agreement”), compensatory arrangements with Targa’s named
executive officers, who are also our general partner’s named executive officers,
are required to be submitted to a vote of Targa Investments’ stockholders unless
such arrangements have been approved by the Compensation Committee of Targa
Investments (the “TRII Compensation Committee”). As such, the TRII Compensation
Committee is responsible for overseeing the development of an executive
compensation philosophy, strategy, framework and individual compensation
elements for our general partner’s named executive officers that are based on
Targa Investments’ business priorities.





The
following Compensation Discussion and Analysis describes the material elements
of compensation for our general partner’s named executive officers as determined
by the TRII Compensation Committee and is presented from the perspective of our
general partner’s named executive officers in their roles as officers of Targa.
These





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elements
and the TRII Compensation Committee’s decisions with respect to determinations
on payments are not subject to approval by the Board or the board of directors
of Targa (the “Targa Board”). Certain members of the Board and the entire Targa
Board, including the Targa Board’s compensation committee, are members of the
board of directors of Targa Investments (the “Targa Investments Board”),
including the TRII Compensation Committee. Mr. Pearl, one of our directors, was
an observer at the TRII Compensation Committee’s meetings in 2009.As used in this
Compensation Discussion and Analysis (other than in this overview), references
to “our,” “we,” “us,” the “Company” and similar terms refer to
Targa.





Compensation
Philosophy





The TRII
Compensation Committee believes that total compensation of executives should be
competitive with the market in which we compete for executive talent - the
energy industry and midstream natural gas companies. The following compensation
objectives guide the TRII Compensation Committee in its deliberations about
executive compensation matters:





•
            provide
      a competitive total compensation program that enables us to attract and
      retain key executives;





•
            ensure
      an alignment between our strategic and financial performance and the total
      compensation received by our named executive
  officers;





•
            provide
      compensation for performance relative to expectations and our peer
      group;





•
            ensure
      a balance between short-term and long-term compensation while emphasizing
      at-risk or variable, compensation as a valuable means of supporting our
      strategic goals and aligning the interests of our named executive officers
      with those of our shareholders; and





•
            ensure
      that our total compensation program supports our business objectives and
      priorities.





Consistent
with this philosophy and compensation objectives, we do not pay for perquisites
for any of our named executive officers, other than parking
subsidies.





The
Role of Peer Groups and Benchmarking





Our chief
executive officer (the “CEO”), president and chief financial officer
(collectively, “Senior Management”) review compensation practices at peer
companies, as well as broader industry compensation practices, at a general
level and by individual position to ensure that our total compensation is
reasonably comparable and meets our compensation objectives. In addition, when
evaluating compensation levels for each named executive officer, the TRII
Compensation Committee reviews publicly available compensation data for
executives in our peer group, compensation surveys and compensation levels for
each named executive officer with respect to their roles with the Company and
levels of responsibility, accountability and decision-making authority. Although
Senior Management and the TRII Compensation Committee consider compensation data
from other companies, they do not attempt to set compensation components to meet
specific benchmarks, such as salaries “above the median” or total compensation
“at the 50th percentile.” The peer company data that is reviewed by Senior
Management and the TRII Compensation Committee is simply one factor out of many
that is used in connection with the establishment of the compensation for the
Company’s officers. The other factors considered by Senior Management and the
TRII Compensation Committee include, but are not limited to, (i) available
compensation data about rankings and comparisons, (ii) ownership stake (both
peer management’s stake in peer companies and Targa management’s stake in the
Partnership and Targa Investments), (iii) effort and accomplishment on a group
basis, (iv) challenges faced and challenges overcome, (v) unique skills, (vi)
contribution to the management team and (vii) the perception of both the Targa
Investments Board and the TRII Compensation Committee of performance relative to
expectations, actual market/business conditions and relative peer company
performance. All of these factors, including peer company data, are utilized in
a subjective assessment of each year’s decisions relating to annual cash
incentives, long-term cash incentives and base compensation changes with a view
towards total compensation and pay-for-performance.








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For 2009,
Senior Management identified peer companies in the midstream energy industry and
reviewed compensation information filed by the peer companies with the SEC. The
peer group reviewed by Senior Management for 2009 consisted of the following
companies: Atlas America, Copano, Crosstex, DCP Midstream, Enbridge Energy
Partners, Energy Transfer Partners, Magellan Midstream, MarkWest Energy
Partners, Martin Midstream, NuStar Energy, Oneok Partners, Plains All American
Pipeline, Regency Energy Partners, TEPPCO Partners and Williams Energy
Partners.





Senior
Management and the TRII Compensation Committee review our compensation practices
and performance against peer companies on at least an annual basis.





Role
of Senior Management in Establishing Compensation for Named Executive
Officers





Typically,
Senior Management consults with a compensation consultant engaged by the TRII
Compensation Committee and reviews market data to determine relevant
compensation levels and compensation program elements. Based on these
consultations and a review of publicly available information for the peer group,
Senior Management submits a proposal to the chairman of the TRII Compensation
Committee. The proposal includes a recommendation of base salary, annual bonus
and any new long-term compensation to be paid or awarded to executive officers
and employees. The chairman of the TRII Compensation Committee reviews and
discusses this proposal with Senior Management and may request that Senior
Management provide him with additional information or reconsider their
recommendation. The resulting recommendation is then submitted to the TRII
Compensation Committee for consideration, which also meets separately with the
compensation consultant. The final compensation decisions are reported to the
Targa Investments Board.





Our
Senior Management has no other role in determining compensation for our
executive officers, but our executive officers are delegated the authority and
responsibility to determine the compensation for all other
employees.





Elements
of Compensation for Named Executive Officers





Our
compensation philosophy for executive officers emphasizes our executives having
a significant long-term equity stake. For this reason, in connection with our
formation in 2004 and with the DMS Acquisition in 2005, the named executive
officers were granted restricted stock and options to purchase restricted stock
of Targa Investments to attract, motivate and retain our executive team. As a
result, executive compensation has been weighted toward long-term equity awards.
Our executive officers have also invested a significant portion of their
personal investable assets in the equity of Targa Investments and have made
significant investments in the equity of the Partnership. With these equity
interests as context, elements of compensation for our named executive officers
are the following: (i) annual base salary; (ii) discretionary annual
cash awards; (iii) performance awards under Targa Investments’ long-term
incentive plan, (iv) contributions under our 401(k) and profit sharing
plan; and (v) participation in our health and welfare plans on the same
basis as all of our other employees.





Base Salary. The base
salaries for our named executive officers are set and reviewed annually by the
TRII Compensation Committee. The salaries are based on historical salaries paid
to our named executive officers for services rendered to us, the extent of their
equity ownership in Targa Investments, market data and responsibilities of our
named executive officers. Base salaries are intended to provide fixed
compensation comparable to market levels for similarly situated executive
officers.





Annual Cash Incentives. The
discretionary annual cash awards paid to our named executive officers supplement
the annual base salary of our named executive officers so that, on a combined
basis, the annual cash compensation for our named executive officers yield
competitive cash compensation levels and drive performance in support of our
business strategies. It is Targa Investments’ general policy to pay these awards
prior to the end of the first quarter of the next fiscal year. The payment of
individual cash bonuses to executive management, including our named executive
officers, is subject to the sole discretion of the TRII Compensation
Committee.





The
discretionary annual cash awards are designed to reward our employees for
contributions towards our achievement of financial and operational business
priorities (including business priorities of the Partnership) approved by the
TRII Compensation Committee and to aid us in retaining and motivating employees.
These





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priorities
are not objective in nature – they are subjective. The approach taken by the
TRII Compensation Committee in reviewing performance against the priorities is
along the lines of grading a multi-faceted essay rather than a simple true/false
exam. As such, success does not depend on achieving a particular target; rather,
success is determined based on past norms, expectations and unanticipated
obstacles or opportunities that arise. For example, hurricanes and deteriorating
market conditions may alter the priorities initially established by the TRII
Compensation Committee such that certain performance that would otherwise be
deemed a negative may, in context, be a positive result. This subjectivity
allows the TRII Compensation Committee to account for the full industry and
economic context of the actual performance of Targa or its personnel. The TRII
Compensation Committee considers all strategic priorities and reviews
performance against the priorities but does not assign specific weightings to
the strategic priorities in advance.





Under
plans to pay a discretionary annual cash award that have been adopted and are
expected to be adopted in subsequent years, funding of a discretionary cash
bonus pool is expected to be recommended by our CEO and approved by the TRII
Compensation Committee annually based on our achievement of certain strategic,
financial and operational objectives. Such plans are and will be approved by the
TRII Compensation Committee, which considers certain recommendations by the CEO.
Near or following the end of each year, the CEO recommends to the TRII
Compensation Committee the total amount of cash to be allocated to the bonus
pool based upon our overall performance relative to these objectives. Upon
receipt of the CEO’s recommendation, the TRII Compensation Committee, in its
sole discretion, determines the total amount of cash to be allocated to the
bonus pool. Additionally, the TRII Compensation Committee, in its sole
discretion, determines the amount of the cash bonus award to each of our
executive officers, including the CEO. The executive officers determine the
amount of the cash bonus pool to be allocated to our departments, groups and
employees (other than our executive officers) based on performance and on the
recommendation of their supervisors, managers and line officers.





LTIP Awards. Targa
Investments may grant to the named executive officers and other key employees
cash-settled performance unit awards linked to the performance of the
Partnership’s common units, with the amounts vesting under such awards dependent
on the Partnership’s performance compared to a peer-group consisting of the
Partnership and 12 other publicly traded partnerships. These performance unit
awards are made pursuant to a plan adopted by Targa Investments. These awards
are designed to further align the interests of the named executive officers and
other key employees with those of the Partnership’s equity holders.





Retirement Benefits. We
offer eligible employees a Section 401(k) tax-qualified, defined
contribution plan to enable employees to save for retirement through a
tax-advantaged combination of employee and Company contributions and to provide
employees the opportunity to directly manage their retirement plan assets
through a variety of investment options. Our employees, including our named
executive officers, are eligible to participate in our 401(k) plan and may elect
to defer up to 30% of their annual compensation on a pre-tax basis and have it
contributed to the plan, subject to certain limitations under the Internal
Revenue Code. In addition, we make the following contributions to the 401(k)
Plan for the benefit of our employees, including our named executive officers:
(i) 3% of the employee’s eligible compensation; and (ii) an amount
equal to the employee’s contributions to the 401(k)
Plan up to 5% of the employee’s eligible compensation. We may also make
discretionary contributions to the 401(k)Plan for the benefit of employees
depending on Targa’s performance.





Health and Welfare
Benefits. All full-time employees, including our named executive
officers, may participate in our health and welfare benefit programs, including
medical, health, life insurance and dental coverage and disability
insurance.





Perquisites. We believe that
the elements of executive compensation should be tied directly or indirectly to
the actual performance of the Company. It is the TRII Compensation Committee’s
policy not to pay for perquisites for any of our named executive officers, other
than parking subsidies.





Relation
of Compensation Elements to Compensation Philosophy





Our named
executive officers, other senior managers and directors, through a combination
of personal investment and equity grants, own approximately 20% of the fully
diluted equity of Targa Investments. Based on our named executive officers’
ownership interests in Targa Investments and their direct ownership of
the





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Partnership’s
common units, they own, directly and indirectly, approximately 3% of the
Partnership’s limited partner interests. The TRII Compensation Committee
believes that the elements of its compensation program fit the established
overall compensation objectives in the context of management’s substantial
ownership of Targa Investment’s equity, which allows Targa to provide
competitive compensation opportunities to align and drive the performance of the
named executive officers in support of Targa Investments’ and the Partnership’s
own business strategies and to attract, motivate and retain high quality talent
with the skills and competencies required by Targa Investments and the
Partnership.





Application
of Compensation Elements





Equity Ownership. The TRII
Compensation Committee did not award additional equity to the named executive
officers in 2009.





Base Salary. In 2009,
base salaries for our named executive officers were established based on
historical levels for these officers, taking into consideration officer salaries
in our peer group and the long-term equity component of our compensation
program.





Annual Cash
Incentives. The TRII Compensation Committee approved our 2009 Annual
Incentive Plan (the “Bonus Plan”) in January 2009 with the following eight key
business priorities to be considered when making awards under the Bonus Plan:
(i) manage controllable costs to levels at or below plan levels – with a
continuous effort to improve costs for 2009 and beyond; (ii) examine, prioritize
and approve each capital project closely for economics (or necessity) in the
current environment; (iii) increase scrutiny and proactively manage credit and
liquidity across finance, credit and commercial areas; (iv) reduce (eliminate
where appropriate) Downstream’s inventory exposure (for Targa only); (v)
continue to invest in our businesses primarily within existing cash flow; (vi)
pursue selected opportunities including new shale play gathering and processing
build outs, other fee-based capital projects and the potential to purchase
distressed strategic assets; (vii) analyze and recommend approaches to achieve
maximum value; and (viii) execute on the above priorities, including the 2009
financial business plan. The TRII Compensation Committee also established the
following overall threshold, target and maximum levels for the Company’s bonus
pool: 50% of the cash bonus pool for the threshold level; 100% for the target
level and 200% for the maximum level. The cash bonus pool target is determined
by summing, on an employee by employee basis, the product of base salaries and
market-based bonus targets. The CEO and the TRII Compensation Committee relied
on compensation consultants and market data to establish the threshold, target
and maximum levels, which were determined to be in a typical and competitive
range. The CEO and the TRII Compensation Committee arrive at the total amount of
cash to be allocated to the cash bonus pool by multiplying percentage of target
awarded by the TRII Compensation Committee by the total target cash bonus pool.
The funding of the cash bonus pool and the payment of individual cash bonuses to
executive management, including our named executive officers, are subject to the
sole discretion of the TRII Compensation Committee.





In
December 2009, the TRII Compensation Committee approved a cash bonus pool equal
to 200% of the target level for the employee group, including our named
executive officers, under the Bonus Plan for performance during 2009 in
recognition of outstanding efforts and organizational performance. The TRII
Compensation Committee determined to pay these above target level bonuses
because it considered overall performance, including organizational performance,
to have substantially exceeded expectations in 2009 based on the eight key
business priorities it established for 2009. The TRII Compensation Committee
considered or subjectively evaluated (rather than measured) organizational
performance by reviewing the performance of Targa’s personnel with respect to
the initial and subsequent business priorities relative to expectations and peer
performance, which included strategic and impactful changes to Targa’s and
Targa’s subsidiaries’ capital structures, demonstrated success in dispute
resolution and promising project development efforts. The executive officers
received the following bonus awards, which are equivalent to the same average
percentage of target as the Company bonus pool with a 1.5x performance
multiplier, based on exceeding our overall goals in 2009, including the
successful implementation of strategic initiatives that were driven by the
executive officers:






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Rene
      R. Joyce
            $  510,000Jeffrey
      J. McParland
            400,500Joe
      Bob Perkins
            459,000James
      W. Whalen
            445,500Michael
      A. Heim
            424,500


In January 2009, the
TRII Compensation Committee approved a cash bonus pool of 150% of the target
level for the employee group under the cash bonus plan for performance during
2008 in recognition of significant efforts and organizational performance. The
TRII Compensation Committee determined to pay these above target level bonuses
because it considered overall performance, including organizational performance,
to be strong in 2008 based on the six key business priorities it established for
2008 as well as a number of unanticipated priorities and performance factors,
which included operating through two hurricanes that impacted Targa’s personnel
and assets while meeting customer needs and business objectives. The TRII
Compensation Committee considered or subjectively evaluated (rather than
measured) organizational performance by reviewing the performance of Targa’s
personnel with respect to the initial and subsequent business priorities
relative to expectations and peer performance, which included demonstrated
successes in hurricane preparedness, accounting systems, commercial business
initiatives and area manager involvement.





Long-term Cash Incentives.In
January 2008 and 2009, Targa Investments granted executive officers of the
General Partner cash-settled performance unit awards linked to the performance
of the Partnership’s common units that will vest in June of 2011 and 2012, with
the amounts vesting under such awards dependent on the Partnership’s performance
compared to a peer-group consisting of the Partnership and 12 other publicly
traded partnerships. The peer group companies for 2008 and 2009 were Energy
Transfer Partners, Oneok Partners, Copano, DCP Midstream, Regency Energy
Partners, Plains All American Pipeline, MarkWest Energy Partners, Williams
Energy Partners, Magellan Midstream, Martin Midstream, Enbridge Energy Partners,
Crosstex and Targa Resources Partners LP. These performance unit awards were
made pursuant to a plan adopted by Targa Investments and administered by Targa
Resources. The TRII Compensation Committee has the ability to modify the
peer-group in the event a peer company is no longer determined to be one of the
Partnership’s peers. The cash settlement value of each performance unit award
will be the value of an equivalent Partnership common unit at the time of
vesting plus associated distributions over the vesting period, which may be
higher or lower than the Partnership’s common unit price at the time of the
award. If the Partnership’s performance equals or exceeds the performance for
the median of the group, 100% of the award will vest. If the Partnership ranks
tenth in the group, 50% of the award will vest, between tenth and seventh, 50%
to 100% will vest and for a performance ranking lower than tenth, no amounts
will vest. In January 2008, our named executive officers, who are also executive
officers of the General Partner, received an award of performance units as
follows: 4,000 performance units to Mr. Joyce, 2,700 performance units to
Mr. McParland, 3,500 performance units to Mr. Perkins, 3,500
performance units to Mr. Whalen and 3,500 performance units to
Mr. Heim. In January 2009, the named executive officers received an award
of performance units as follows: 34,000 performance units to Mr. Joyce,
15,500 performance units to Mr. McParland, 20,800 performance units to
Mr. Perkins and 20,800 performance units to Mr. Heim.




Set forth
below is the “performance for the median” of the peer group for each of the 2008
and 2009 grants and a comparison of the Partnership’s performance to the peer
group as of December 31, 2009:




Performance
      (1)Grant
            
            Peer
      Group Median
            
            
            Partnership
            
            Partnership
      Position2008
            
            
            7.9%
            
            
            
            15.2%
            
            5th
      of 132009
            
            
            53.1%
            
            
            
            79.6%
            
            3rd
      of 13








(1)
            Total
      return measured by (i) subtracting the average closing price per
      share/unit for the first ten trading days of the performance period (the
      “Beginning Price”) from the sum of (a) the average closing price per
      share/unit for the last ten trading days ending on the date that is 15
      days prior to the end of the performance period plus (b) the aggregate
      amount of dividends/distributions paid with respect to a share/unit during
      such period (the result being referred to as the “Value Increase”) and
      (ii) dividing the Value Increase by the Beginning Price. The performance
      period for the 2008 and 2009 awards begins on June 30, 2008 and June 30,
      2009, and ends on the third anniversary of such
  dates.







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In
addition to the January 2009 grants, in December 2009, our executive officers
were awarded performance units under Targa Investments’ long-term incentive plan
for the 2010 compensation cycle that will vest in June 2013 as follows: 18,025
performance units to Mr. Joyce, 13,464 performance units to Mr. Whalen,
9,350 performance units to Mr. McParland, 13,860 performance units to
Mr. Perkins and 9,894 performance units to Mr. Heim. The cash
settlement value of these performance unit awards will be the value of an
equivalent Partnership common unit at the time of vesting multiplied by a
performance percentage which may be zero or range from 25% to 150% of the value
of a common unit plus associated distributions over the three year period, which
may be higher or lower than the Partnership common unit price at the time of the
grant. If the Partnership’s performance equals or exceeds the performance for
the 25th percentile of the group but is less than or equal to the 50th
percentile of the group, the award will vest with a performance percentage
ranging from 25% to 100%. If the Partnership’s performance equals or exceeds the
performance for the 50th percentile of the group, the award will vest with a
performance percentage ranging from 100% to 150%. If the Partnership’s
performance is below the performance of the 25th percentile of the group, the
performance percentage will be zero and no amounts will vest. The performance
period for these performance unit awards begins on June 30, 2010 and ends
on the third anniversary of such date.





Health and Welfare Benefits.
For 2009, our named executive officers participated in our health and welfare
benefit programs, including medical, health, life insurance, dental coverage and
disability insurance.





Perquisites. Consistent with
our compensation philosophy, we did not pay for perquisites for any of our named
executive officers during 2009, other than parking subsidies.





Changes
for 2010





Annual Cash Incentives. In
light of recent economic and financial events, Senior Management developed and
proposed a set of strategic priorities to the TRII Compensation Committee. In
February 2010, the TRII Compensation Committee approved the Targa Investments
2010 Annual Incentive Compensation Plan (the “2010 Bonus Plan”), the cash bonus
plan for performance during 2010, and, established the following nine key
business priorities: (i) continue to control all operating, capital and general
and administrative costs, (ii) invest in our businesses primarily within
existing cashflow, (iii) continue priority emphasis and strong performance
relative to a safe workplace, (iv) reinforce business philosophy and mindset
that promotes environmental and regulatory compliance, (v) continue to tightly
manage the Downstream Business’ inventory exposure, (vi) execute on major
capital and development projects, such as finalizing negotiations, completing
projects on time and on budget, and optimizing economics and capital funding,
(vii) pursue selected opportunities, including new shale play gathering and
processing build-outs, other fee-based capex projects and potential purchases of
strategic assets, (viii) pursue commercial and financial approaches to achieve
maximum value and manage risks, and (ix) execute on all business dimensions,
including the financial business plan. The TRII Compensation Committee also
established the following overall threshold, target and maximum levels for the
Company’s bonus pool: 50% of the cash bonus pool for the threshold level; 100%
for the target level and 200% for the maximum level. As with the Bonus Plan,
funding of the cash bonus pool and the payment of individual cash bonuses to
executive management, including our named executive officers, are subject to the
sole discretion of the TRII Compensation Committee.





Long-term Cash Incentives.
The cash settlement value of any future grants of performance unit awards under
Targa Investments’ long-term incentive plan will be determined using the formula
adopted for the performance unit awards granted in December 2009.





Compensation and Peer Group
Review. The TRII Compensation Committee has engaged a consultant to
review executive and key employee compensation during the second quarter of 2010
to help the committee assure that compensation goals are met and that the most
recent trends in compensation are appropriately considered. In this process, the
peer companies will be reassessed to determine whether the peer groups for
long-term cash incentive awards (performance units) and for compensation
comparison and analysis are appropriate and adequately reflect the market for
executive talent.





Compensation
Committee Interlocks and Insider Participation





The
Partnership’s general partner does not maintain a compensation committee. The
following officers of the Partnership’s general partner participated in
deliberations of the Compensation Committee of Targa Investments





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concerning
executive officer compensation at the December 2009 committee meeting:
Messrs. Joyce, Perkins, Whalen and Chung. See “Item 13. Certain
Relationships and Related Transactions, and Director Independence” for a
description of certain relationships and related-party
transactions.


Compensation
Committee Report





In
fulfilling its oversight responsibilities, the Board reviewed and discussed with
management the compensation discussion and analysis contained in this Annual
Report. Based on these reviews and discussions, the Board recommended that the
compensation discussion and analysis be included in the Annual Report for the
year ended December 31, 2009 for filing with the SEC.





The
information contained in this report shall not be deemed to be “soliciting
material” or to be “filed” with the SEC, nor shall such information be
incorporated by reference into any future filings with the SEC or subject to the
liabilities of Section 18 of the Exchange Act, except to the extent that
the Partnership specifically incorporates it by reference into a document filed
under the Securities Act of 1933, as amended or the Exchange Act.





Rene R.
Joyce


James W.
Whalen


Peter R.
Kagan


Chansoo
Joung


Robert B.
Evans


Barry R.
Pearl


William
D. Sullivan





97
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Executive
Compensation





The
following Summary Compensation Table sets forth the compensation of our named
executive officers for 2009, 2008 and 2007. Additional details regarding the
applicable elements of compensation in the Summary Compensation Table are
provided in the footnotes following the table.





Summary Compensation Table for
      2009Non-EquityStock
            
            
            Incentive
      Plan
            
            
            All
      Other
            
            
            TotalName
            
            Year
            
            Salary
            
            
            Awards ($)(1)
            
            
            Compensation
            
            
            Compensation (2)
            
            
            CompensationRene
      R. Joyce
            
            2009
            
            $
            337,500
            
            
            $
            742,965
            
            
            $
            510,000
            
            
            $
            20,187
            
            
            $
            1,610,652Chief
      Executive Officer
            
            2008
            
            
            322,500
            
            
            
            148,218
            
            
            
            247,500
            
            
            
            19,205
            
            
            
            737,4232007
            
            
            293,750
            
            
            
            459,769
            
            
            
            300,000
            
            
            
            817,963
            
            
            
            1,871,482Jeffrey
      J. McParland
            
            2009
            
            
            265,000
            
            
            
            435,695
            
            
            
            400,500
            
            
            
            20,061
            
            
            
            1,121,256Executive
      Vice President and
            
            2008
            
            
            253,000
            
            
            
            114,247
            
            
            
            194,250
            
            
            
            19,031
            
            
            
            580,528Chief
      Financial Officer
            
            2007
            
            
            230,000
            
            
            
            316,770
            
            
            
            235,000
            
            
            
            674,292
            
            
            
            1,456,062Joe
      Bob Perkins
            
            2009
            
            
            303,750
            
            
            
            574,514
            
            
            
            459,000
            
            
            
            20,129
            
            
            
            1,357,393President
            
            2008
            
            
            290,250
            
            
            
            126,228
            
            
            
            222,750
            
            
            
            19,124
            
            
            
            658,3522007
            
            
            265,000
            
            
            
            366,318
            
            
            
            270,000
            
            
            
            817,888
            
            
            
            1,719,206James
      W. Whalen
            
            2009
            
            
            297,000
            
            
            
            306,914
            
            
            
            445,500
            
            
            
            19,936
            
            
            
            1,069,350President—Finance
      and
            
            2008
            
            
            290,250
            
            
            
            66,488
            
            
            
            222,750
            
            
            
            18,871
            
            
            
            598,359Administration
            
            2007
            
            
            265,000
            
            
            
            224,796
            
            
            
            270,000
            
            
            
            817,888
            
            
            
            1,577,684Michael
      A. Heim
            
            2009
            
            
            281,000
            
            
            
            553,310
            
            
            
            424,500
            
            
            
            20,089
            
            
            
            1,278,899Executive
      Vice President and
            
            2008
            
            
            268,750
            
            
            
            127,172
            
            
            
            206,250
            
            
            
            19,071
            
            
            
            621,243Chief
      Operating Officer
            
            2007
            
            
            243,750
            
            
            
            366,318
            
            
            
            250,000
            
            
            
            817,838
            
            
            
            1,677,906





_______


(1)
            Amounts
      represent the aggregate grant date fair value of awards computed in
      accordance with FASB ASC Topic 718. Detailed information about the amount
      recognized for specific awards is reported in the table under “Grants of
      Plan Based Awards for 2009” below. The fair value of a performance unit is
      the sum of: (i) the closing price of a common unit of the Partnership on
      the reporting date; (ii) the fair value of an at-the-money call option on
      a performance unit with a grant date equal to the reporting date and an
      expiration date equal to the last day of the performance period; and (iii)
      estimated DERs. The grant date value of a performance unit award granted
      on January 22, 2009 (for the 2009 compensation cycle) and December 3, 2009
      (for the 2010 compensation cycle), assuming the highest performance
      condition will be achieved, is $36.74 and $36.04. Accordingly, the highest
      aggregate value of the performance unit awards granted in 2009 for the
      named executive officers is as follows: Mr. Joyce - $1,898,745; Mr.
      McParland - $906,431; Mr. Perkins - $1,263,693; Mr. Whalen - $485,284; and
      Mr. Heim - $1,120,746.


(2)
            For
      2009 “All Other Compensation” includes the (i) aggregate value of matching
      and non-matching contributions to our 401(k) plan and (ii) the dollar
      value of life insurance coverage.





Name
            
            401(k) and
              Profit Sharing
              Plan
            
            
            Dollar
              Value of Life
              Insurance
            
            
            TotalRene
      R. Joyce
            
            $
            19,600
            
            
            $
            587
            
            
            $
            20,187Jeffrey
      J. McParland
            
            
            19,600
            
            
            
            461
            
            
            
            20,061Joe
      Bob Perkins
            
            
            19,600
            
            
            
            529
            
            
            
            20,129James
      W. Whalen
            
            
            19,600
            
            
            
            336
            
            
            
            19,936Michael
      A. Heim
            
            
            19,600
            
            
            
            489
            
            
            
            20,089








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Grants
of Plan-Based Awards





The
following table and the footnotes thereto provide information regarding grants
of plan-based equity and non-equity awards made to the named executive officers
during 2009:





Grants
      of Plan Based Awards for 2009Estimated Possible Payouts Under Non-Equity
      Incentive Plan Awards
              (1)
            
            Estimated Future Payouts Under
              Equity Incentive Plan Awards
      (2)
            
            Grant Date
              Fair Value of
              Stock and
              Option
              Awards (3)Name
            
            Grant
              Date
            
            
            Threshold
            
            
            Target
            
            
            2X Target
            
            Threshold
            
            Target
              (Units)
            
            MaximumMr.
      Joyce
            
            
            N/A
            
            
            $
            85,000
            
            
            $
            170,000
            
            
            $
            340,00001/22/09
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            34,000
            
            
            
            $
            1,249,06812/03/09
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            18,025
            
            
            
            
            649,677Mr.
      McParland
            
            
            N/A
            
            
            
            66,750
            
            
            
            133,500
            
            
            
            267,00001/22/09
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            15,500
            
            
            
            
            569,42812/03/09
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            9,350
            
            
            
            
            337,003Mr.
      Perkins
            
            
            N/A
            
            
            
            76,500
            
            
            
            153,000
            
            
            
            306,00001/22/09
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            20,800
            
            
            
            
            764,13612/03/09
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            13,860
            
            
            
            
            499,557Mr.
      Whalen
            
            
            N/A
            
            
            
            74,250
            
            
            
            148,500
            
            
            
            297,00012/03/09
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            13,464
            
            
            
            
            485,284Mr.
      Heim
            
            
            N/A
            
            
            
            70,750
            
            
            
            141,500
            
            
            
            283,00001/22/09
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            20,800
            
            
            
            
            764,13612/03/09
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            9,894
            
            
            
            
            356,610





_______


(1)
            These
      awards were granted under the Bonus Plan. At the time the Bonus Plan was
      adopted, the estimated future payouts in the above table under the heading
      “Estimated Possible Payouts Under Non-Equity Incentive Plan Awards”
      represented the portion of the cash bonus pool available for awards to the
      named executive officers under the  Bonus Plan based on the three
      performance levels. In December 2009, the TRII Compensation Committee
      approved a bonus award for the named executive officers equal to the
      maximum payout with a 1.5x performance multiplier. See “Compensation
      Discussion and Analysis—Application of Compensation Elements—Annual Cash
      Incentives.”


(2)
            These
      performance unit awards were granted under the Targa Investments Long-Term
      Incentive Plan and are discussed in more detail under the heading
      “Compensation Discussion & Analysis—Application of Compensation
      Elements—Long-Term Cash
Incentives.”


(3)
            The
      dollar amounts shown for the performance units granted on January 22, 2009
      are determined by multiplying the number of units reported in the table by
      $36.74 (the grant date fair value of awards computed in accordance with
      FASB ASC Topic 718) and assume full payout under the awards at the time of
      vesting. The dollar amounts shown for the performance units granted on
      December 3, 2009 are determined by multiplying the number of units
      reported in the table by $36.04 (the grant date fair value of awards
      computed in accordance with FASB ASC Topic 718) and assume full payout
      under the awards at the time of
vesting.





Narrative Disclosure to Summary
Compensation Table and Grants of Plan Based Awards Table





A
discussion of 2009 salaries, bonuses and incentive plans is included in
“Compensation Discussion and Analysis.”





Targa
Investments 2005 Stock Incentive Plan





Stock Option
Grants. Under the Targa Investments 2005 Stock Incentive Plan, as
amended (the “2005 Incentive Plan”), incentive stock options and non-incentive
stock options to purchase, in the aggregate, up to 5,159,786 shares of
Targa Investments’ restricted stock may be granted to our employees, directors
and consultants. Subject to the terms of the applicable stock option agreement,
options granted under the 2005 Incentive Plan have a vesting period of four
years, remain exercisable for ten years from the date of grant and have an
exercise price at least equal to the fair market value of a share of restricted
stock on the date of grant. Additional details relating to previously granted
non-incentive stock options under the 2005 Incentive Plan are included in
“Outstanding Equity Awards at 2009 Fiscal Year-End” below. No option awards were
granted to the named executive officers in 2007, 2008 and 2009.





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Restricted Stock Grants.
Under the 2005 Incentive Plan, up to 7,293,882 shares of restricted stock
of Targa Investments may be granted to our employees, directors and consultants.
Subject to the terms of the restricted stock agreement, restricted stock granted
under the Incentive Plan has a vesting period of four years from the date of
grant. Additional details relating to previously granted shares of common stock
are included in “Outstanding Equity Awards at 2009 Fiscal Year-End” below. No
stock awards were granted to the named executive officers in 2007, 2008 and
2009.





Outstanding
Equity Awards at 2009 Fiscal Year-End





Targa
Investments indirectly owns all of Targa’s equity interests. The following table
and the footnotes related thereto provide information regarding each stock
option and other equity-based awards of Targa Investments outstanding as of
December 31, 2009 for each of our named executive officers.





Outstanding Equity Awards at 2009 Fiscal
      Year-EndOption Awards
            
            Stock AwardsName
            
            Options
              Exercisable
            
            
            Option
              Exercise
              Price
            
            Option
              Expiration
              Date
            
            Equity Incentive
              Plan Awards:
              Number of
              Unearned
              Performance
              Units That Have
              Not Vested(1)
            
            
            Equity Incentive
              Plan Awards:
              Market or Payout
              Value of
              Unearned
              Performance
              Units That Have
              Not Vested(2)Rene
      R. Joyce
            
            
            21,772
            
            
            $
            0.75
            
            10/31/15
            
            
            71,025
            
            
            $
            1,848,849291,376
            
            
            
            3.00
            
            10/31/15246,549
            
            
            
            15.00
            
            10/31/153,006
            
            
            
            3.00
            
            12/20/152,559
            
            
            
            15.00
            
            12/20/15Jeffrey
      J. McParland
            
            
            218,532
            
            
            
            3.00
            
            10/31/15
            
            
            35,750
            
            
            
            934,717184,912
            
            
            
            15.00
            
            10/31/152,254
            
            
            
            3.00
            
            12/20/151,919
            
            
            
            15.00
            
            12/20/15Joe
      Bob Perkins
            
            
            236,014
            
            
            
            3.00
            
            10/31/15
            
            
            48,960
            
            
            
            1,276,843199,705
            
            
            
            15.00
            
            10/31/152,435
            
            
            
            3.00
            
            12/20/152,073
            
            
            
            15.00
            
            12/20/15James
      W. Whalen
            
            
            90,908
            
            
            
            3.00
            
            11/01/15192,308
            
            
            
            15.00
            
            11/01/15
            
            
            27,764
            
            
            
            740,040937
            
            
            
            3.00
            
            12/20/151,996
            
            
            
            15.00
            
            12/20/15Michael
      A. Heim
            
            
            21,772
            
            
            
            0.75
            
            10/31/15236,014
            
            
            
            3.00
            
            10/31/15
            
            
            44,194
            
            
            
            1,157,174199,705
            
            
            
            15.00
            
            10/31/152,435
            
            
            
            3.00
            
            12/20/152,073
            
            
            
            15.00
            
            12/20/15





_______


(1)
            Represents
      the number of performance units awarded on February 8, 2007, January
      17, 2008, January 22, 2009 and December 3, 2009 under the Targa
      Investments Long-Term Incentive Plan. These awards vest in August 2010,
      June 2011, June 2012, and June 2013, based on the Partnership’s
      performance over the applicable period measured against a peer group of
      companies. These awards are discussed in more detail under the heading
      “Compensation Discussion & Analysis — Application of
      Compensation Elements — Long-Term Cash
  Incentives.”


(2)
            The
      dollar amounts shown are determined by multiplying the number of
      performance units reported in the table by the sum of the closing price of
      a common unit of the Partnership on December 31, 2009
      ($24.31) and the related distribution equivalent rights for each
      award and assume full payout under the awards at the time of
      vesting.








100
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Option
Exercises and Stock Vested in 2009





The
following table provides the amount realized during 2009 by each named executive
officer upon the exercise of options and upon the vesting of restricted common
stock.





Option Exercises and Stock Vested for
      2009Option Awards
            
            
            Stock AwardsName
            
            Number of Shares
              Acquired on
              Exercise (1)
            
            
            Value Realized
              on Exercise
            
            
            Number of Shares
              Acquired on Vesting
            
            
            Value Realized
              on Vesting (2)Rene
      R. Joyce
            
            
            -
            
            
            $
            -
            
            
            
            148,263
            
            
            
            (3)
            
            
            $
            296,526Jeffrey
      J. McParland
            
            
            21,772
            
            
            
            43,544
            
            
            
            112,091
            
            
            
            (4)
            
            
            
            224,182Joe
      Bob Perkins
            
            
            21,772
            
            
            
            43,544
            
            
            
            123,489
            
            
            
            (5)
            
            
            
            246,978James
      W. Whalen
            
            
            -
            
            
            
            -
            
            
            
            102,249
            
            
            
            (6)
            
            
            
            204,498Michael
      A. Heim
            
            
            -
            
            
            
            -
            
            
            
            123,489
            
            
            
            (5)
            
            
            
            246,978





_______


(1)
            At
      the time of exercise of the stock options, the common stock acquired upon
      exercise had a value of $2.00 per share. This value was determined by an
      independent consultant pursuant to a valuation of Targa Investments common
      stock dated November 4, 2009.


(2)
            The
      value realized on vesting used a per share price based on the estimated
      market price of Targa Investments common stock on such date. These
      values were determined by an independent consultant pursuant to valuations
      of Targa Investments common stock prepared at various times during 2009
      and 2008, which management believes are reasonable approximations of the
      value of such stock as of the applicable
dates.


(3)
            The
      shares vested as follows: 146,840 shares on October 31, 2009 and 1,432
      shares on December 20, 2009.


(4)
            The
      shares vested as follows: 111,024 shares on October 31, 2009 and 1,067
      shares on December 20, 2009.


(5)
            The
      shares vested as follows: 122,336 shares on October 31, 2009 and 1,153
      shares on December 20, 2009.


(6)
            The
      shares vested as follows: 544 shares on October 31, 2009, 100,595 shares
      on November 1, 2009 and 1,110 shares on December 20,
      2009.








Change
in Control and Termination Benefits





2005 Incentive Plan. If
a Change of Control or a Liquidation Event (each as defined below) or in the
case of restricted stock, certain drag-along transactions, occurs during a named
executive officer’s employment with us, the options granted to him under Targa
Investments’ form of Non-Statutory Stock Option Agreement (the “Option
Agreement”) and/or the restricted stock granted to him under Targa Investments’
form of Restricted Stock Agreement (the “Stock Agreement”) will fully vest and
be exercisable (in the case of options) by him so long as he remains an employee
of Targa Investments.





Options
granted to a named executive officer under the Option Agreement will terminate
and cease to be exercisable upon the termination of his employment with Targa
Investments, except that: (i) if his employment is terminated by reason of
a disability, he (or his estate or the person who acquires the options by will
or the laws of descent and distribution or otherwise by reason of his death )
may exercise the options in full for 180 days following such termination;
(ii) if he dies while employed by Targa Investments, his estate or the
person who acquires the options by will or the laws of descent and distribution
or otherwise by reason of his death, may exercise the options in full for
180 days following his death; or (iii) if he resigns or is terminated
by Targa Investments without Cause (as defined below), then he (or his estate or
the person who acquires the options by will or the laws of descent and
distribution or otherwise by reason of his death) may exercise the options for
three months following such resignation or termination, but only as to the
options he was entitled to exercise as of the date his employment
terminates.





Restricted
stock granted to a named executive officer under the Stock Agreement will fully
vest if his employment is terminated by reason of a disability or his death. If
a named executive officer resigns or he is terminated by Targa Investments
without Cause, then his unvested restricted stock is forfeited to Targa
Investments for no consideration. If a named executive officer is terminated by
Targa Investments for Cause, then all restricted





101
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stock
(both vested and unvested) granted to him under the Stock Agreement is forfeited
to Targa Investments for no consideration. For five years following a named
executive officer’s termination of employment, Targa Investments has the right
to repurchase all of his restricted stock and other Capital Stock (as defined
below), after any applicable forfeitures, at a purchase price equal to, in the
case of a termination by death, disability, resignation or without Cause, the
then Fair Market Value (as defined below) of such restricted stock and Capital
Stock determined in accordance with the Stockholders Agreement, and, in the case
of a termination with Cause, the lower of the Original Cost (as defined below)
or the then Fair Market Value of such Capital Stock.





The
following terms have the specified meanings for purposes of the 2005 Incentive
Plan:





•
            Change of Controlmeans, in one transaction or a series of related transactions, a
      consolidation, merger or any other form of corporate reorganization
      involving Targa Investments or a sale of Preferred Stock (or a sale of
      Targa Investments’ common stock following conversion of the Preferred
      Stock) by stockholders of Targa Investments with the result immediately
      after such merger, consolidation, corporate reorganization or sale that
      (A) a single person, together with its affiliates, owns, if prior to
      any firm commitment underwritten offering by Targa Investments of its
      common stock to the public pursuant to an effective registration statement
      under the Securities Act (x) for which the aggregate cash proceeds to
      be received by Targa Investments from such offering (without deducting
      underwriting discounts, expenses and commissions) are at least $35,000,000
      and (y) pursuant to which Targa Investments’ common stock is listed
      for trading on the New York Stock Exchange or is admitted to trading and
      quoted on the NASDAQ National Market System (a “Qualified Public
      Offering”), either a greater number of shares of Targa Investments’ common
      stock (calculated assuming that all shares of Preferred Stock have been
      converted at the specified conversion ratio) than Warburg Pincus and its
      affiliates then own or, in the context of a consolidation, merger or other
      corporate reorganization in which Targa Investments is not the surviving
      entity, more voting stock generally entitled to elect directors of such
      surviving entity (or in the case of a triangular merger, of the parent
      entity of such surviving entity) than Warburg Pincus and its affiliates
      then own or, if on or after a Qualified Public Offering, either a majority
      of Targa Investments’ common stock calculated on a fully-diluted basis
      (i.e. on the basis that all shares of Preferred Stock have been converted
      at the specified conversion ratio, that all Management Stock is
      outstanding, whether vested or not and that all outstanding options to
      acquire Targa Investments’ common stock had been exercised (whether then
      exercisable or not)) or, in the context of a consolidation, merger or
      other corporate reorganization in which Targa Investments is not the
      surviving entity, a majority of the voting stock generally entitled to
      elect directors of such surviving entity (or in the case of a triangular
      merger, of the parent entity of such surviving entity) calculated on a
      fully diluted basis and (B) Warburg Pincus and its affiliates
      collectively own less than a majority of the initial shares of Capital
      Stock outstanding on October 31, 2005 owned by them (the “Initial
      Shares”) or, in the event such Initial Shares are converted or exchanged
      into other voting securities of Targa Investment or such surviving or
      parent entity, less than a majority of such voting securities Warburg
      Pincus and its affiliates would have owned had they retained all such
      Initial Shares;





•
            Management Stockmeans
      the shares of Targa Investments’ common stock granted pursuant to the
      terms of the 2005 Incentive Plan, any such shares transferred to a
      permitted transferee and any and all securities of any kind whatsoever of
      Targa Investments which may be issued in respect of, in exchange for or
      upon conversion of such shares of common stock pursuant to a merger,
      consolidation, stock split, stock dividend, recapitalization of Targa
      Investments or otherwise;





•
            Liquidation Eventmeans
      the voluntary or involuntary liquidation, dissolution or winding up of the
      affairs of Targa Investments; provided that neither the merger or
      consolidation of Targa Investments with or into another entity, nor the
      merger or consolidation of another entity with or into Targa Investments,
      nor the sale of all or substantially all of the assets of Targa
      Investments shall be deemed to be a Liquidation
  Event;





•
            Causemeans discharge
      by Targa Investments based on (A) an employee’s gross negligence or
      willful misconduct in the performance of duties, (B) conviction of a
      felony or other crime involving moral turpitude; (C) an employee’s
      willful refusal, after fifteen days’ written notice from the Targa
      Investments Board, to perform the material lawful duties or
      responsibilities required of him; (D) willful and material breach of
      any corporate policy or code of conduct established by Targa Investments;
      and (E) willfully





102
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engaging
in conduct that is known or should be known to be materially injurious to Targa
Investments or any of its subsidiaries;





•
            Capital Stockmeans any
      and all shares of capital stock of or other equity interests in, Targa
      Investments and any and all warrants, options or other rights to purchase
      or acquire any of the foregoing;





•
            Original Costmeans,
      with respect to a particular share of Capital Stock, the cash amount
      originally paid to Targa Investments to purchase such share (or if such
      share was issued in respect of other shares of Targa Investments issued in
      connection with the merger of one of Targa Investments’ subsidiaries with
      and into us, then the cash amount originally paid to us to purchase such
      other shares), subject to adjustment for subdivisions, combinations or
      stock dividends involving such Capital Stock or, if no cash amount was
      originally paid to Targa Investments to purchase such share, then no
      consideration (or if such share was issued in respect of other shares of
      Targa Investments issued in connection with the merger of one of Targa
      Investments’ subsidiaries with and into us and such other shares were
      issued by us for no cash consideration, then no
      consideration); and





•
            Fair Market Valuemeans
      the value determined by the unanimous resolution of all directors of the
      Targa Investments Board, provided that if the Targa Investments Board does
      not or is unable to make such a determination, Fair Market Value means the
      value determined by an investment banking firm of recognized national
      standing selected by a majority of the directors of the Targa Investments
      Board.





No
payments would have been made to each of the named executive officers under the
2005 Incentive Plan and related agreements in the event there was a Change of
Control or their employment was terminated, each as of December 31,
2009.





Long Term Incentive
Plan. If a Change of Control (as defined below) occurs during the
performance period established for the performance units and related
distribution equivalent rights granted to a named executive officer under Targa
Investments’ form of Performance Unit Grant Agreement (a “Performance Unit
Agreement”), the performance units and related distribution equivalent rights
then credited to a named executive officer will be cancelled and the named
executive officer will be paid an amount of cash equal to the sum of (i) the
product of (a) the Fair Market Value (as defined below) of a common unit of the
Partnership multiplied by (b) the number of performance units granted to the
named executive officer, plus (ii) the amount of distribution equivalent rights
then credited to the named executive officer, if any.





Performance
units and the related distribution equivalent rights granted to a named
executive officer under a Performance Unit Agreement will be automatically
forfeited without payment upon the termination of his employment with Targa
Investments and its affiliates, except that: if his employment is terminated by
reason of his death, a disability that entitles him to disability benefits under
Targa Investments’ long-term disability plan or by Targa Investments’ other than
for Cause (as defined below), he will be vested in his performance units that he
is otherwise qualified to receive payment for based on achievement of the
performance goal at the end of the Performance Period.





The
following terms have the specified meanings for purposes of the Long-Term
Incentive Plan:





•
            Change of Controlmeans
      (i) any “person” or “group” within the meaning of those terms as used in
      Sections 13(d) and 14(d)(2) of the Exchange Act, other than an affiliate
      of Targa Investments, becoming the beneficial owner, by way of merger,
      consolidation, recapitalization, reorganization or otherwise, of 50% or
      more of the combined voting power of the equity interests in the
      Partnership or its general partner, (ii) the limited partners of the
      Partnership approving, in one or a series of transactions, a plan of
      complete liquidation of the Partnership, (iii) the sale or other
      disposition by either the Partnership or its general partner of all or
      substantially all of its assets in one or more transactions to any person
      other than the Partnership’s general partner or one of such general
      partner’s affiliates or (iv) a transaction resulting in a person other
      than the Partnership’s general partner or one of such general partner’s
      affiliates being the general partner of the Partnership. With respect to
      an award subject to Section 409A of the Code, Change of Control will mean
      a “change of control event” as defined in the regulations and guidance
      issued under Section 409A of the
Code.





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•
            Fair Market Valuemeans
      the closing sales price of a common unit of the Partnership on the
      principal national securities exchange or other market in which trading in
      such common units occurs on the applicable date (or if there is not
      trading in the common units on such date, on the next preceding date on
      which there was trading) as reported in The Wall Street Journal (or other
      reporting service approved by the TRII Compensation Committee). In the
      event the common units are not traded on a national securities exchange or
      other market at the time a determination of fair market value is required
      to be made, the determination of fair market value shall be made in good
      faith by the TRII Compensation
Committee.





•
            Causemeans (i) failure
      to perform assigned duties and responsibilities, (ii) engaging in conduct
      which is injurious (monetarily of otherwise) to Targa Investments or its
      affiliates, (iii) breach of any corporate policy or code of conduct
      established by Targa Investments or its affiliates or breach of any
      agreement between the named executive officer and Targa Investments or its
      affiliates or (iv) conviction of a misdemeanor involving moral turpitude
      or a felony. If the named executive officer is a party to an agreement
      with Targa Investments or its affiliates in which this term is defined,
      then that definition will apply for purposes of the Long-Term Incentive
      Plan and the Performance Unit
Agreement.





The
following table reflects payments that would have been made to each of the named
executive officers under the Long-Term Incentive Plan and related agreements in
the event there was a Change of Control or their employment was terminated, each
as of December 31, 2009. Substantially all of the stock option and
restricted stock awards available for grant under the 2005 Incentive Plan have
been granted and have subsequently vested. No payments would be made under the
2005 Incentive Plan to any named executive officer in the event there was a
Change of Control or their employment was terminated, each as of December 31,
2009.





Name
            
            Change
      of Control
            
            
            Termination
      for
              Death
      or DisabilityRene
      R. Joyce
            
            $
            1,848,849
            
            
            
            (1
            )
            
            $
            1,848,849
            
            
            
            (1
            )Jeffrey
      J. McParland
            
            
            934,717
            
            
            
            (2
            )
            
            
            934,717
            
            
            
            (2
            )Joe
      Bob Perkins
            
            
            1,276,843
            
            
            
            (3
            )
            
            
            1,276,843
            
            
            
            (3
            )James
      W. Whalen
            
            
            740,040
            
            
            
            (4
            )
            
            
            740,040
            
            
            
            (4
            )Michael
      A. Heim
            
            
            1,157,174
            
            
            
            (5
            )
            
            
            1,157,174
            
            
            
            (5
            )





_______


(1)
            Of
      this amount, $364,650 and $71,381 relate to the performance units and
      related distribution equivalent rights granted on February 7, 2007;
      $97,240 and $15,660 relate to the performance units and related
      distribution equivalent rights granted on January 17, 2008; $826,540 and
      $35,190 relate to the performance units and related distribution
      equivalent rights granted on January 22, 2009; and $438,188 and $0 relate
      to the performance units and related distribution equivalent rights
      granted on December 3, 2009.


(2)
            Of
      this amount, $199,342 and $39,022 relate to the performance units and
      related distribution equivalent rights granted on February 7, 2007;
      $65,637 and $10,571 relate to the performance units and related
      distribution equivalent rights granted on January 17, 2008; $376,805 and
      $16,043 relate to the performance units and related distribution
      equivalent rights granted on January 22, 2009; and $227,299 and $0 relate
      to the performance units and related distribution equivalent rights
      granted on December 3, 2009.


(3)
            Of
      this amount, $262,548 and $51,395 relate to the performance units and
      related distribution equivalent rights granted on February 7, 2007;
      $85,085 and $13,703 relate to the performance units and related
      distribution equivalent rights granted on January 17, 2008; $505,648 and
      $21,528 relate to the performance units and related distribution
      equivalent rights granted on January 22, 2009; and $336,937 and $0 relate
      to the performance units and related distribution equivalent rights
      granted on December 3, 2009.


(4)
            Of
      this amount, $262,548 and $51,395 relate to the performance units and
      related distribution equivalent rights granted on February 7, 2007;
      $85,085 and $13,703 relate to the performance units and related
      distribution equivalent rights granted on January 17, 2008; and $327,310
      and $0 relate to the performance units and related distribution equivalent
      rights granted on December 3, 2009.


(5)
            Of
      this amount, $243,100 and $47,588 relate to the performance units and
      related distribution equivalent rights granted on February 7, 2007;
      $85,085 and $13,703 relate to the performance units and related
      distribution equivalent rights granted on January 17, 2008; $505,648 and
      $21,548 relate to the performance units and related distribution
      equivalent rights granted on January 22, 2009; and $240,523 and $0 relate
      to the performance units and related distribution equivalent rights
      granted on December 3, 2009.








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Director
Compensation





The
following table sets forth the compensation earned by our non-employee directors
for 2009:





Name
            
            Fees Earned
              or Paid in
              Cash
            
            
            Stock
              Awards
              ($)(1)
            
            
            All Other
              Compensation (4)
            
            
            Total
              CompensationRobert
      B. Evans (2) (3)
            
            $
            76,000
            
            
            $
            40,556
            
            
            $
            16,560
            
            
            $
            133,116Chansoo
      Joung (2) (3)
            
            
            47,500
            
            
            
            40,556
            
            
            
            16,560
            
            
            
            104,616Peter
      R. Kagan (2) (3)
            
            
            46,000
            
            
            
            40,556
            
            
            
            16,560
            
            
            
            103,116Barry
      R. Pearl (2) (3)
            
            
            97,500
            
            
            
            40,556
            
            
            
            16,560
            
            
            
            154,616William
      D. Sullivan (2) (3)
            
            
            77,500
            
            
            
            40,556
            
            
            
            16,560
            
            
            
            134,616





_______


(1)
            Amounts
      represent the aggregate grant date fair value of awards computed in
      accordance with FASB ASC Topic 718. For a discussion of the assumptions
      and methodologies used to value the awards reported in these columns, see
      the discussion of stock awards contained in Accounting for Unit-Based
      Compensation included under Note 13 to our “Consolidated Financial
      Statements” beginning on page F-1 in this Annual
  Report.


(2)
            Messrs. Evans,
      Joung, Kagan, Pearl and Sullivan each received 4,000 common units of the
      Partnership on January 22, 2009 in connection with their service on
      the Board of Directors of the Partnership’s general partner. The grant
      date fair value of the 4,000 common units granted to each of these named
      individuals was $8.20, based on the closing price of the common units on
      the day prior to the grant date. During 2009, each of the directors
      received $16,560 in distributions on the common units of the Partnership
      that were awarded to them. The Partnership also recognized $16,560 of
      expense for each of the stock awards held by Messrs. Joung and
      Kagan.


(3)
            As
      of December 31, 2009, Mr. Evans held 23,900 common units,
      Mr. Joung and Mr. Kagan each held 8,000 common units,
      Mr. Pearl held 10,300 common units and Mr. Sullivan held 12,700
      common units of the Partnership.


(4)
            For
      2009 “All Other Compensation” consists of the distributions paid on common
      units of the Partnership from unit
awards.





Narrative
to Director Compensation Table


For 2009,
each independent director received an annual cash retainer of $34,000 and the
chairman of the Audit Committee received an additional annual retainer of
$20,000. All of our independent directors receive $1,500 for each Board, Audit
Committee and Conflicts Committee meeting attended. Payment of independent
director fees is generally made twice annually, at the second regularly
scheduled meeting of the Board and the final meeting of the Board for the fiscal
year. All independent directors are reimbursed for out-of-pocket expenses
incurred in attending Board and committee meetings.





A
director who is also an employee receives no additional compensation for
services as a director. Accordingly, the Summary Compensation Table reflects
total compensation received by Messrs. Joyce and Whalen for services
performed for us and our affiliates.





Director Long-term Equity
Incentives. The Partnership made equity-based awards in January 2009
to the General Partners’ non-management and independent directors under the
Partnership’s long-term incentive plan. These awards were determined by Targa
Investments and approved by the Board. Each of these directors received an award
of 4,000 restricted units, which will settle with the delivery of Partnership
common units. The Partnership has made similar grants under its long-term
incentive plan to Targa’s independent directors. All of these awards are subject
to three-year vesting, without a performance condition and vest ratably on each
anniversary of the grant. The awards are intended to align the long-term
interests of executive officers and directors of the General Partner with those
of the Partnership’s unitholders. The independent and non-management directors
of the General Partner and the independent directors of Targa Investments
currently participate in the Partnership’s plan.








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Changes
for 2010





Director Compensation.In
December 2009, the Board approved changes to director compensation for the 2010
fiscal year. For 2010, each independent director will receive an annual cash
retainer of $40,000.





Director Long-term Equity
Incentives. In January 2010, each of the General Partners’ non-management
and independent directors received an award of 2,250 restricted units under the
Partnership’s long-term incentive plan, which will settle with the delivery of
Partnership common units. The Partnership has made similar grants under its
long-term incentive plan to Targa’s independent directors.





Item
12. Security Ownership of Certain Beneficial Owners and Management and Related
StockholderMatters





The
following table sets forth the beneficial ownership of our units as of February
26, 2010 held by:





·
            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 executive officers of Targa Resources GP LLC as a
      group.





Targa
      Resources Partners LP
            
            
            Targa
      Resources Investments Inc.Name
      of Beneficial Owner (1)
            
            Common
              Units
              Beneficially
              Owned
      (2)
            
            
            Percentage
              of
      Common
              Units
              Beneficially
              Owned
            
            
            Series
      B
              Preferred
              Stock
            
            
            Restricted
              Common
              Stock
            
            
            Percentage
              of
      Series B
              Preferred
              Stock
              Beneficially
              Owned
            
            
            Percentage
              of
      Restricted
              Common
              Stock
              Beneficially
              OwnedTarga
      Resources Investments Inc. (3)
            
            
            20,055,846
            
            
            
            29.5
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -Targa
      Resources Investments Inc. (3)
            
            
            20,055,846
            
            
            
            29.5
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -Tortoise
      Capital Advisor, L.L.C. (4)
            
            
            3,562,141
            
            
            
            5.2
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -Rene
      R. Joyce
            
            
            81,000
            
            
            
            *
            
            
            
            56,208
            
            
            
            1,390,687
            (5)
            
            
            *
            
            
            
            17.1Joe
      Bob Perkins
            
            
            32,100
            
            
            
            *
            
            
            
            47,632
            
            
            
            1,163,553
            (6)
            
            
            *
            
            
            
            14.5Michael
      A. Heim
            
            
            8,000
            
            
            
            *
            
            
            
            39,192
            
            
            
            1,163,553
            (7)
            
            
            *
            
            
            
            14.5Jeffrey
      J. McParland
            
            
            16,500
            
            
            
            *
            
            
            
            32,856
            
            
            
            1,058,936
            (8)
            
            
            *
            
            
            
            13.3James
      W. Whalen
            
            
            111,152
            
            
            
            *
            
            
            
            14,978
            
            
            
            960,307
            (9)
            
            
            *
            
            
            
            12.3Chansoo
      Joung (3)
            
            
            10,250
            
            
            
            *
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -Peter
      R. Kagan (3)
            
            
            10,250
            
            
            
            *
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -Robert
      B. Evans
            
            
            26,150
            
            
            
            *
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -Barry
      R. Pearl
            
            
            12,550
            
            
            
            *
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -William
      D. Sullivan
            
            
            14,950
            
            
            
            *
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -All
      directors and executive officers as a group
            
            
            350,402
            
            
            
            *
            
            
            
            241,114
            
            
            
            7,874,526
            (10)
            
            
            3.8
            
            
            
            74.4(12
      persons)





_______


* 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 equity securities is sole voting and
      investment power.


(2)
            The
      common units of the Partnership presented as being beneficially owned by
      our directors and executive officers do not include the common units held
      indirectly by Targa Resources Investments Inc. that may be attributable to
      such directors and officers based on their ownership of equity interests
      in Targa Resources Investments Inc.


(3)
            The
      units attributed to Targa Resources Investments Inc. are held by two
      indirect wholly-owned subsidiaries, Targa GP Inc. and Targa LP Inc.
      Warburg Pincus Private Equity VIII, L.P., a Delaware limited partnership
      and two affiliated partnerships (“WP VIII”), and Warburg Pincus Private
      Equity IX, L.P., a Delaware limited partnership (“WP IX”), in the
      aggregate own, on a fully diluted basis, approximately 74% of the equity
      interests of Targa Resources Investments Inc. The general partner of WP
      VIII is Warburg Pincus Partners, LLC, a New York limited liability company
      (“WP Partners LLC”), and the general partner of WP IX is Warburg Pincus
      IX, LLC, a New York limited liability company, of which WP Partners LLC is
      the sole member. Warburg Pincus & Co., a New York general partnership
      (“WP”), is the





106
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managing
member of WP Partners LLC. WP VIII and WP IX are managed by Warburg Pincus LLC,
a New York limited liability company (“WP LLC”). The address of the Warburg
Pincus entities is 450 Lexington Avenue, New York, New York 10017. Messrs. Kagan
and Joung, are Partners of WP and Managing Directors and Members of WP LLC.
Charles R. Kaye and Joseph P. Landy are Managing General Partners of WP and
Managing Members and Co-Presidents of WP LLC and may be deemed to control the
Warburg Pincus entities. Messrs. Joung, Kagan, Kaye and Landy disclaim
beneficial ownership of all shares held by the Warburg Pincus
entities.


(4)
            The
      business address for Tortoise Capital Advisors, L.L.C. (“TCA”) is 11550
      Ash Street, Suite 300, Leawood, Kansas 66211. TCA acts as an
      investment adviser to certain closed-end investment companies registered
      or regulated under the Investment Company Act of 1940. TCA, by virtue
      of investment advisory agreements with these investment companies, has all
      investment and voting power over securities owned of record by these
      investment companies. However, despite their delegation of investment and
      voting power to TCA, these investment companies may be deemed to be the
      beneficial owners under Rule 13d-3 of the Act of the securities they own
      of record because they have the right to acquire investment and voting
      power through termination of their investment advisory agreement with
      TCA. Thus, TCA has reported that it shares voting power and
      dispositive power over the securities owned of record by these investment
      companies.  TCA also acts as an investment advisor to certain
      managed accounts. Under contractual agreements with individual
      account holders, TCA, with respect to the securities held in the managed
      accounts, shares investment and voting power with certain account holders,
      and has no voting power but shares investment power with certain other
      account holders. Of the 3,562,141 common units reported as
      beneficially owned by TCA, TCA has reported that it has shared voting
      power with respect to 3,362,465 of these units and shared dispositive
      power with respect to all of the units. None of the securities listed are
      owned of record by TCA, and TCA disclaims any beneficial interest in such
      securities. The source of the foregoing information is the Schedule 13G
      filed by TCA with the Commission on February 11,
  2010.


(5)
            Of
      this amount, 543,490 shares of restricted common stock reflect options
      that are currently exercisable for shares of restricted common
      stock.


(6)
            Of
      this amount, 440,227 shares of restricted common stock reflect options
      that are currently exercisable for shares of restricted common
      stock.


(7)
            Of
      this amount, 440,227 shares of restricted common stock reflect options
      that are currently exercisable for shares of restricted common
      stock


(8)
            Of
      this amount, 407,617 shares of restricted common stock reflect options
      that are currently exercisable for shares of restricted common
      stock.


(9)
            Of
      this amount, 286,149 shares of restricted common stock reflect options
      that are currently exercisable for shares of restricted common
      stock.


(10)
            Of
      this amount, 2,878,595 shares of restricted common stock reflect options
      that are currently exercisable for shares of restricted common
      stock.





SECURITIES
AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS





The
following table sets forth certain information as of December 31, 2009
regarding the Partnership’s long-term incentive plan, under which the
Partnership’s common units are authorized for issuance to employees, consultants
and directors of the Partnership, its general partner and their affiliates. The
Partnership’s sole equity compensation plan is its long-term incentive plan,
which was approved by its partners prior to its initial public
offering.





Plan
      category
            
            Number
      of
              securities
      to be
              issued
      upon
              exercise
      of
              outstanding
              options,
      warrants
              and
      rights
            
            
            Weighted
      average
              exercise
      price of
              outstanding
              options,
      warrants
              and
      rights
            
            
            Number
      of securities
              remaining
      available
              for
      future issuance
              under
      equity
              compensation
      plans
              (excluding
      securities
              reflected
      in column
              (a))(a)
            
            
            (b)
            
            
            (c)Equity
      compensation plans approved by security holders
            
            
            -
            
            
            $
            -
            
            
            
            1,616,000Equity
      compensation plans not approved by security holders
            
            
            -
            
            
            
            -
            
            
            
            -Total
            
            
            -
            
            
            $
            -
            
            
            
            1,616,000





Generally,
awards of restricted units under our long-term incentive plan are subject to
vesting over time as determined by the Compensation Committee and, prior to
vesting, are subject to forfeiture. Long-term incentive plan





107
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awards
may vest in other circumstances, as approved by the Compensation Committee and
reflected in an award agreement. Restricted common units are issued, subject to
vesting, on the date of grant. The Compensation Committee may provide that
distributions on restricted units are subject to vesting and forfeiture
provisions, in which case such distributions would be held, without interest,
until they vest or are forfeited.





Item 13. Certain Relationships and Related Transactions, and
Director Independence





As of
February 1, 2010, our general partner and its management own 20,406,248 common
units representing an aggregate 30.0% limited partner interest in us. In
addition, our general partner owns a 2% general partner interest in us and the
incentive distribution rights.





Distributions
and Payments to Our General Partner and its Affiliates





The
following table summarizes the distributions and payments made and to be made by
us to our general partner and its affiliates in connection with our ongoing
operation and any liquidation of us. These distributions and payments were
determined by and among affiliated entities and, consequently, are not the
result of arm’s-length negotiations.





Operational
      StageDistributions
      of available cash to our general partner
            We
      will generally make cash distributions 98% to ourand
      its affiliates
            limited
      partner unitholders pro rata, including ourgeneral
      partner and its management as the holders of20,406,248
      common units, and 2% to our generalpartner.
      In addition, if distributions exceed theminimum
      quarterly distribution and other highertarget
      distribution levels, our general partner will beentitled
      to increasing percentages of the distributions,up
      to 50% of the distributions above the highesttarget
      distribution level.





Assuming
      we have sufficient available cash to pay thefull
      minimum quarterly distribution on all of ouroutstanding
      units for four quarters, our generalpartner
      and its affiliates would receive an annualdistribution
      of approximately $1.7 million on theirgeneral
      partner units and $27.5 million on theircommon
      units.





Payments
      to our general partner and its affiliates
            We
      reimburse Targa for the payment of certainoperating
      expenses and for the provision of variousgeneral
      and administrative services for our benefit.See
      “Omnibus Agreement—Reimbursement
      of Operating and General andAdministrative
      Expense.”





Withdrawal
      or removal of our general partner
            If
      our general partner withdraws or is removed, itsgeneral
      partner interest and its incentive distributionrights
      will either be sold to the new general partnerfor
      cash or converted into common units, in each casefor
      an amount equal to the fair market value of thoseinterests.






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 Table of Contents




Liquidation
      StageLiquidation
            Upon
      our liquidation, the partners, including ourgeneral
      partner, will be entitled to receive liquidatingdistributions
      according to their respective capitalaccount
      balances.




Purchase
and Sale Agreement





On
July 27, 2009, we entered into a purchase and sale agreement (the “Purchase
Agreement”) with Targa GP Inc. and Targa LP Inc., each a subsidiary of Targa
(the “Sellers”), pursuant to which we acquired (i) 100% of the limited
liability company interests in Targa Downstream GP LLC (“Targa Downstream GP”),
(ii) 100% of the limited liability company interests in Targa LSNG GP LLC
(“Targa LSNG GP”), (iii) 100% of the limited partner interests in Targa
Downstream LP (“Targa Downstream LP”), and (iv) 100% of the limited partner
interests in Targa LSNG LP (“Targa LSNG LP”), for aggregate consideration of
$530 million, subject to certain adjustments, consisting of
$397.5 million in cash, the issuance to the Sellers of 8,527,615 common
units and the issuance to our general partner of 174,033 general partner units,
enabling our general partner to maintain its general partner interest in us.
Targa Downstream LP and Targa LSNG LP, collectively, own the Downstream
Business. Pursuant to the Purchase Agreement, the Sellers agreed to indemnify us
from and against (i) all losses that we incur arising from any breach of
the Sellers’ representations, warranties or covenants in the Purchase Agreement,
(ii) certain environmental matters and (iii) certain litigation
matters. We agreed to indemnify the Sellers from and against all losses that it
incurs arising from or out of (i) the business and operations of Targa
Downstream GP, Targa LSNG GP, Targa Downstream LP, Targa LSNG LP and their
subsidiaries at the closing of the acquisition (whether relating to periods
prior to or after the closing of the acquisition of the Downstream Business) to
the extent such losses are not matters for which the Sellers have indemnified us
or (ii) any breach of our representations, warranties or covenants in the
Purchase Agreement. Certain of the Seller’s indemnification obligations are
subject to an aggregate deductible of $7.95 million and a cap equal to
$58.3 million. In addition, the parties’ reciprocal indemnification
obligations for certain tax liability and losses are not subject to the
deductible and cap. The acquisition closed on September 24,
2009.





Agreements
Relating to the Acquisition of the Downstream Business





We and
other affiliates of our general partner entered into the various documents and
agreements that effected our acquisition of the Downstream Business, including
the vesting of assets in and the assumption of liabilities by, us and our
subsidiaries. These agreements were not the result of arm’s-length negotiations
and they or any of the transactions that they provide for, may not have been
effected on terms at least as favorable to the parties to these agreements as
they could have obtained from unaffiliated third parties. All of the transaction
expenses incurred in connection with these transactions, including the expenses
associated with transferring assets into our subsidiaries, were paid from
available cash or borrowings under our credit facility.





Omnibus
Agreement





Our
Omnibus Agreement with Targa, our general partner and others addresses the
reimbursement of our general partner for costs incurred on our behalf,
competition and indemnification matters. Any or all of the provisions of the
Omnibus Agreement, other than the indemnification provisions described below,
are terminable by Targa at its option if our general partner is removed without
cause and units held by our general partner and its affiliates are not voted in
favor of that removal. The Omnibus Agreement will also terminate in the event of
a Change of Control of us or our general partner.





Reimbursement
of Operating and General and Administrative Expense





Under the
terms of the Omnibus Agreement, we reimburse Targa for the payment of certain
operating and direct expenses, including compensation and benefits of operating
personnel, and for the provision of various general and administrative services
for our benefit. Pursuant to these arrangements, Targa performs centralized
corporate functions for us, such as legal, accounting, treasury, insurance, risk
management, health, safety and environmental,


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information technology,
human resources, credit, payroll, internal audit, taxes, engineering and
marketing. We reimburse Targa for the direct expenses to provide these services
as well as other direct expenses it incurs on our behalf, such as compensation
of operational personnel performing services for our benefit and the cost of
their employee benefits, including 401(k), pension and health insurance
benefits. Our general partner determines the amount of general and
administrative expenses to be allocated to us in accordance with our partnership
agreement.





With
respect to the North Texas System, prior to February 15, 2010, we
reimbursed Targa for general and administrative expenses, which were capped at
$5.0 million annually, subject to certain increases; and operating and
certain direct expenses, which were not capped. With respect to the SAOU and LOU
Systems and the Downstream Business, we reimbursed Targa for general and
administrative expenses, which were not capped, allocated to the SAOU and LOU
Systems and the Downstream Business according to Targa’s allocation practice;
and operating and certain direct expenses, which were not capped.





During
the nine-quarter period beginning with the fourth quarter of 2009 and continuing
through the fourth quarter of 2011, Targa will provide distribution support to
us in the form of a reduction in the reimbursement for general and
administrative expense allocated to us if necessary (or make a payment to us, if
needed) for a 1.0 times distribution coverage ratio, at the current distribution
level of $0.5175 per limited partner unit, subject to maximum support of
$8.0 million in any quarter. No distribution support was necessary for the
fourth quarter of 2009.





Competition





Targa is
not restricted, under either our partnership agreement or the Omnibus Agreement,
from competing with us. Targa may acquire, construct or dispose of additional
midstream energy or other assets in the future without any obligation to offer
us the opportunity to purchase or construct those assets.





Indemnification





Under the
Omnibus Agreement, we have agreed to indemnify Targa against environmental
liabilities related to the North Texas System arising or occurring after
February 14, 2007.





Additionally,
Targa has agreed to indemnify us for losses relating to income tax liabilities
attributable to pre-IPO operations that are not reserved on the books of the
Predecessor Business of the North Texas System as of February 14, 2007.
Targa does not have any obligation under this indemnification until our
aggregate losses exceed $250,000. Targa’s obligation under this indemnification
will terminate upon the expiration of any applicable statute of limitations. We
will indemnify Targa for all losses attributable to the post-IPO operations of
the North Texas System.





Contracts
with Affiliates





Natural Gas Purchase Agreements.Both the North Texas System and the SAOU and LOU Systems have entered
into market based natural gas purchase agreements with Targa Gas Marketing LLC.
These agreements have an initial term of 15 years and automatically extend for a
term of five years, unless the agreements are otherwise terminated by either
party. Furthermore, either party may elect to terminate the agreements if either
party ceases to be an affiliate of Targa. In addition, Targa manages the SAOU
and LOU Systems’ natural gas sales to third parties under contracts that remain
in the name of the SAOU and LOU Systems.





NGL Product Purchase Agreements for
the Downstream Business. We have entered into product purchase agreements
with Targa Midstream Services Limited Partnership, a wholly-owned subsidiary of
Targa (“TMSLP”), and Targa Permian LP, an indirect, wholly-owned subsidiary of
Targa (“Targa Permian”), pursuant to which we will purchase all volumes of NGLs
that are owned or controlled by TMSLP and Targa Permian and not otherwise
committed for sale to a third party, at a price based on the prevailing market
price less transportation, fractionation and certain other fees. The product
purchase agreements will have an initial term of 15 years and will
automatically extend for a term of five years. Furthermore, either party may
elect to terminate the agreement if either party ceases to be an affiliate of
Targa. Each product purchase agreement is effective as of September 1,
2009.








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Indemnification
Agreements.In February 2007, Targa Resources GP LLC, our general partner
and we entered into
Indemnification Agreements (each, an “Indemnification Agreement”) with each
independent director of Targa Resources GP LLC (each, an “Indemnitee”). Each
Indemnification agreement provides that each of the Partnership and Targa
Resources GP LLC will indemnify and hold harmless each Indemnitee against
Expenses (as defined in the Indemnification Agreement) to the fullest extent
permitted or authorized by law, including the Delaware Revised Uniform Limited
Partnership Act and the Delaware Limited Liability Company Act in effect on the
date of the agreement or as such laws may be amended to provide more
advantageous rights to the Indemnitee. If such indemnification is unavailable as
a result of a court decision and if we or Targa Resources GP LLC is jointly
liable in the proceeding with the Indemnitee, we and Targa Resources GP LLC will
contribute funds to the Indemnitee for his Expenses in proportion to relative
benefit and fault of the Partnership or Targa Resources GP LLC on the one hand
and Indemnitee on the other in the transaction giving rise to the
proceeding.





Each
Indemnification Agreement also provides that we and Targa Resources GP LLC will
indemnify and hold harmless the Indemnitee against Expenses incurred for actions
taken as a director or officer of the Partnership or Targa Resources GP LLC or
for serving at the request of the Partnership or Targa Resources GP LLC as a
director or officer or another position at another corporation or enterprise, as
the case may be, but only if no final and non-appealable judgment has been
entered by a court determining that, in respect of the matter for which the
Indemnitee is seeking indemnification, the Indemnitee acted in bad faith or
engaged in fraud or willful misconduct or, in the case of a criminal proceeding,
the Indemnitee acted with knowledge that the Indemnitee’s conduct was unlawful.
The Indemnification Agreement also provides that we and Targa Resources GP LLC
must advance payment of certain Expenses to the Indemnitee, including fees of
counsel, subject to receipt of an undertaking from the Indemnitee to return such
advance if it is it is ultimately determined that the Indemnitee is not entitled
to indemnification.





In
February 2007, Targa Resources Investments Inc., the indirect holder of all of
Targa’s common units, entered into Indemnification Agreements (each, a “Parent
Indemnification Agreement”) with each director and officer of Targa (each, a
“Parent Indemnitee”), including Messrs. Joyce, Whalen, Kagan and Joung who serve
as directors and/or officers of our general partner. Each Parent Indemnification
Agreement provides that Targa Resources Investments Inc. will indemnify and hold
harmless each Parent Indemnitee for Expenses (as defined in the Parent
Indemnification Agreement) to the fullest extent permitted or authorized by law,
including the Delaware General Corporation Law, in effect on the date of the
agreement or as it may be amended to provide more advantageous rights to the
Parent Indemnitee. If such indemnification is unavailable as a result of a court
decision and if Targa Resources Investments Inc. and the Parent Indemnitee are
jointly liable in the proceeding, Targa Resources Investments Inc. will
contribute funds to the Parent Indemnitee for his Expenses in proportion to
relative benefit and fault of Targa Resources Investments Inc. and Parent
Indemnitee in the transaction giving rise to the proceeding.





Each
Indemnification Agreement also provides that Targa Resources Investments Inc.
will indemnify the Parent Indemnitee for monetary damages for actions taken as a
director or officer of Targa Resources Investments Inc. or for serving at
Targa’s request as a director or officer or another position at another
corporation or enterprise, as the case may be but only if (i) the Parent
Indemnitee acted in good faith and, in the case of conduct in his official
capacity, in a manner he reasonably believed to be in the best interests of
Targa Resources Investments Inc. and, in all other cases, not opposed to the
best interests of Targa Resources Investments Inc. and (ii) in the case of
a criminal proceeding, the Parent Indemnitee must have had no reasonable cause
to believe that his conduct was unlawful. The Parent Indemnification Agreement
also provides that Targa Resources Investments Inc. must advance payment of
certain Expenses to the Parent Indemnitee, including fees of counsel, subject to
receipt of an undertaking from the Parent Indemnitee to return such advance if
it is it is ultimately determined that the Parent Indemnitee is not entitled to
indemnification.





Relationships
with Warburg Pincus LLC





Chansoo
Joung and Peter Kagan, two of the directors of our general partner and Targa,
are Managing Directors of Warburg Pincus LLC and are also directors of Broad Oak
Energy, Inc. (“Broad Oak”) from whom we buy natural gas and NGL products.
Affiliates of Warburg Pincus LLC own a controlling interest in Broad Oak. We
purchased $9.7 million and $4.8 million of product from Broad Oak
during 2009 and 2008. These transactions were at market prices consistent with
similar transactions with nonaffiliated entities.





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Conflicts
of Interest


Conflicts
of interest exist and may arise in the future as a result of the relationships
between our general partner and its affiliates (including Targa) on the one hand
and our partnership and our limited partners, on the other hand. The
directors and officers of Targa Resources GP LLC have fiduciary duties to manage
Targa and our general partner in a manner beneficial to its owners. At the same
time, our general partner has a fiduciary duty to manage our partnership in a
manner beneficial to us and our unitholders.





Whenever
a conflict arises between our general partner or its affiliates, on the one hand
and us or any other partner, on the other hand, our general partner will resolve
that conflict. Our partnership agreement contains provisions that modify and
limit our general partner’s fiduciary duties to our unitholders. Our partnership
agreement also restricts the remedies available to unitholders for actions taken
that, without those limitations, might constitute breaches of fiduciary
duty.





Our
general partner will not be in breach of its obligations under the partnership
agreement or its duties to us or our unitholders if the resolution of the
conflict is:





·
            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.





Our
general partner may, but is not required to, seek the approval of such
resolution from the conflicts committee of its board of directors. If our
general partner does not seek approval from the conflicts committee and its
board of directors determines that the resolution or course of action taken with
respect to the conflict of interest satisfies either of the standards set forth
in the third or fourth bullet points above, then it will be presumed that, in
making its decision, the board of directors acted in good faith and in any
proceeding brought by or on behalf of any limited partner or the partnership,
the person bringing or prosecuting such proceeding will have the burden of
overcoming such presumption. Unless the resolution of a conflict is specifically
provided for in our partnership agreement, our general partner or the conflicts
committee may consider any factors it determines in good faith to consider when
resolving a conflict. When our partnership agreement provides that someone act
in good faith, it requires that person to believe he is acting in the best
interests of the partnership.





Review,
Approval or Ratification of Transactions with Related Persons





If a
conflict or potential conflict of interest arises between our general partner
and its affiliates (including Targa) on the one hand and our partnership and our
limited partners, on the other hand, the resolution of any such conflict or
potential conflict is addressed as described under “Conflicts of
Interest.”





Pursuant
to Targa’s Code of Conduct, our officers and directors are required to abandon
or forfeit any activity or interest that creates a conflict of interest between
them and Targa or any of its subsidiaries, unless the conflict is pre-approved
by the Board of Directors.





Director
Independence





The NYSE
does not require a listed limited partnership like us to have a majority of
independent directors on the board of directors of our general partner or to
establish a compensation committee or a nominating/governance committee. Our
general partner has a standing Audit Committee that consists of three directors:
Messrs. Evans, Pearl and Sullivan. The board of directors of our general partner
has affirmatively determined that Messrs. Evans, Pearl





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and Sullivan are independent as described in the rules of the NYSE and the
Exchange Act for purposes of serving on the board of directors and the Audit
Committee. 
 The board
of directors of our general partner examined the relationship between Targa and
its subsidiaries and each of Legacy Reserves LP (“Legacy”) and St. Mary Land
& Exploration Company (“St. Mary”). William D.





To be
independent under the NYSE rules, a company’s board of directors must
affirmatively determine that the director has no material relationship with the
company (either directly or as a partner, stockholder or officer of an
organization that has a relationship with the company). The board of directors
of our general partner has made no such determination with respect to Messrs.
Joyce, Kagan, Joung and Whalen because the NYSE rules do not require us to have
a majority of independent directors. As such, Messrs. Joyce, Kagan, Joung and
Whalen are not independent under NYSE rules applicable to service on a
compensation and nominating/governance committee.





Item 14. Principal Accountant Fees and Service





We have
engaged PricewaterhouseCoopers LLP as our principal accountant. The following
table summarizes fees we were billed by PricewaterhouseCoopers LLP for
independent auditing, tax and related services for each of the last two fiscal
years:





Year Ended December 31,2009
            
            
            2008(In
      millions)Audit
      Fees (1)
            
            $
            1.8
            
            
            $
            1.2Tax
      Fees (2)
            
            
            0.2
            
            
            
            0.5$
            2.0
            
            
            $
            1.7







_______


(1)
            Audit
      fees represent amounts billed for each of the years presented for
      professional services rendered in connection with (i) the integrated
      audit of our annual financial statements and internal control 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.





(2)
            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.





All
services provided by our independent auditor are subject to pre-approval by our
audit committee. The Audit Committee is informed of each engagement of the
independent auditor to provide services under the policy. The Audit Committee
has approved the use of PricewaterhouseCoopers LLP as our independent principal
accountant.








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PART
IV





Item 15. Exhibits and Financial Statement
Schedules





(a)(1)
Financial
Statements





Our
Consolidated Financial Statements are included under Part II, Item 8 of the
Annual Report. For a listing of these statements and accompanying footnotes, see
“Index to Financial
Statements”Page F-1 of this Annual Report.





(a)(2)
Financial Statement
Schedules





All
schedules have been omitted because they are either not applicable, not required
or the information called for therein appears in the consolidated financials
statements or notes thereto.





(a)(3)
Exhibits





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





2.2
            Amendment
      to Purchase and Sale Agreement, dated October 1, 2007, by and between
      Targa Resources Holdings LP and Targa Resources Partners LP (incorporated
      by reference to Exhibit 2.2 to Targa Resources Partners LP’s Current
      Report on Form 8-K filed October 24, 2007 (File No.
      001-33303)).





2.3
            Purchase
      and Sale Agreement dated July 27, 2009, by and between Targa Resources
      Partners LP, Targa GP Inc. and Targa LP Inc. (incorporated by reference to
      Exhibit 2.1 to Targa Resources Partners LP’s Current Report on Form 8-K
      filed July 29, 2009 (File No.
001-33303)).





3.1
            Certificate
      of Limited Partnership of Targa Resources Partners LP (incorporated by
      reference to Exhibit 3.2 to Targa Resources Partners LP’s Registration
      Statement on Form S-1 filed November 16, 2006 (File No.
      333-138747)).





3.2
            Certificate
      of Formation of Targa Resources GP LLC (incorporated by reference to
      Exhibit 3.3 to Targa Resources Partners LP’s Registration Statement on
      Form S-1/A filed January 19, 2007 (File No.
  333-138747)).





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





3.4
            First
      Amended and Restated Agreement of Limited Partnership of Targa Resources
      Partners LP (incorporated by reference to Exhibit 3.1 to Targa Resources
      Partners LP’s Current Report on Form 8-K filed February 16, 2007 (File No.
      001-33303)).





3.5
            Amendment
      No. 1, dated May 13, 2008, to the First Amended and Restated Agreement of
      Limited Partnership of Targa Resources Partners LP (incorporated by
      reference to Exhibit 3.5 to Targa Resources Partners LP’s Quarterly Report
      on Form 10-Q filed May 14, 2008 (File No.
  001-33303)).





3.6
            Limited
      Liability Company Agreement of Targa Resources GP LLC (incorporated by
      reference to Exhibit 3.4 to Targa Resources Partners LP’s Registration
      Statement on Form S-1/A filed January 19, 2007 (File No.
      333-138747)).





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








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4.2
            Indenture
      dated June 18, 2008, among Targa Resources Partners LP, Targa Resources
      Partners Finance Corporation, the Guarantors named therein and U.S. Bank
      National Association (incorporated by reference to Exhibit 4.1 to Targa
      Resources Partners LP’s Current Report on Form 8-K filed June 18, 2008
      (File No. 001-33303)).





4.3
            Supplemental
      Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among
      Targa Downstream GP LLC, a subsidiary of Targa Resources Partners LP,
      Targa Resources Partners Finance Corporation, the other Subsidiary
      Guarantors and U.S. Bank National Association (incorporated by reference
      to Exhibit 4.3 to Targa Resources Partners LP’s Quarterly Report on Form
      10-Q filed November 9, 2009 (File No.
  001-33303)).





4.4
            Supplemental
      Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among
      Targa Downstream LP, a subsidiary of Targa Resources Partners LP, Targa
      Resources Partners Finance Corporation, the other Subsidiary Guarantors
      and U.S. Bank National Association (incorporated by reference to Exhibit
      4.5 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed
      November 9, 2009 (File No.
001-33303)).





4.5
            Supplemental
      Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among
      Targa LSNG GP LLC, a subsidiary of Targa Resources Partners LP, Targa
      Resources Partners Finance Corporation, the other Subsidiary Guarantors
      and U.S. Bank National Association (incorporated by reference to Exhibit
      4.7 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed
      November 9, 2009 (File No.
001-33303)).





4.6
            Supplemental
      Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among
      Targa LSNG LP, a subsidiary of Targa Resources Partners LP, Targa
      Resources Partners Finance Corporation, the other Subsidiary Guarantors
      and U.S. Bank National Association (incorporated by reference to Exhibit
      4.9 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed
      November 9, 2009 (File No.
001-33303)).




4.7
            Supplemental
      Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among
      Targa Sparta LLC, a subsidiary of Targa Resources Partners LP, Targa
      Resources Partners Finance Corporation, the other Subsidiary Guarantors
      and U.S. Bank National Association (incorporated by reference to Exhibit
      4.11 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed
      November 9, 2009 (File No. 001-33303)).4.8
            Supplemental
      Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among
      Midstream Barge Company LLC, a subsidiary of Targa Resources Partners LP,
      Targa Resources Partners Finance Corporation, the other Subsidiary
      Guarantors and U.S. Bank National Association (incorporated by reference
      to Exhibit 4.13 to Targa Resources Partners LP’s Quarterly Report on Form
      10-Q filed November 9, 2009 (File No. 001-33303)).4.9
            Supplemental
      Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among
      Targa Retail Electric LLC, a subsidiary of Targa Resources Partners LP,
      Targa Resources Partners Finance Corporation, the other Subsidiary
      Guarantors and U.S. Bank National Association (incorporated by reference
      to Exhibit 4.15 to Targa Resources Partners LP’s Quarterly Report on Form
      10-Q filed November 9, 2009 (File No. 001-33303)).4.10
            Supplemental
      Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among
      Targa NGL Pipeline Company LLC, a subsidiary of Targa Resources Partners
      LP, Targa Resources Partners Finance Corporation, the other Subsidiary
      Guarantors and U.S. Bank National Association (incorporated by reference
      to Exhibit 4.17 to Targa Resources Partners LP’s Quarterly Report on Form
      10-Q filed November 9, 2009 (File No. 001-33303)).





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4.11
            Supplemental
      Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among
      Targa Transport LLC, a subsidiary of Targa Resources Partners LP, Targa
      Resources Partners Finance Corporation, the other Subsidiary Guarantors
      and U.S. Bank National Association (incorporated by reference to Exhibit
      4.19 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed
      November 9, 2009 (File No. 001-33303)).4.12
            Supplemental
      Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among
      Targa Co-Generation LLC, a subsidiary of Targa Resources Partners LP,
      Targa Resources Partners Finance Corporation, the other Subsidiary
      Guarantors and U.S. Bank National Association (incorporated by reference
      to Exhibit 4.21 to Targa Resources Partners LP’s Quarterly Report on Form
      10-Q filed November 9, 2009 (File No. 001-33303)).4.13
            Supplemental
      Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among
      Targa Liquids GP LLC, a subsidiary of Targa Resources Partners LP, Targa
      Resources Partners Finance Corporation, the other Subsidiary Guarantors
      and U.S. Bank National Association (incorporated by reference to Exhibit
      4.23 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed
      November 9, 2009 (File No. 001-33303)).4.14
            Supplemental
      Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among
      Targa Liquids Marketing and Trade, a subsidiary of Targa Resources
      Partners LP, Targa Resources Partners Finance Corporation, the other
      Subsidiary Guarantors and U.S. Bank National Association (incorporated by
      reference to Exhibit 4.25 to Targa Resources Partners LP’s Quarterly
      Report on Form 10-Q filed November 9, 2009 (File No.
      001-33303)).





4.15
            Indenture
      dated as of July 6, 2009, among Targa Resources Partners LP, Targa
      Resources Partners Finance Corporation, the Guarantors named therein and
      U.S. Bank National Association (incorporated by reference to Exhibit 4.1
      to Targa Resources Partners LP’s Current Report on Form 8-K filed July 6,
      2009 (File No. 001-33303)).





4.16
            Supplemental
      Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among
      Targa Downstream GP LLC, a subsidiary of Targa Resources Partners LP,
      Targa Resources Partners Finance Corporation, the other Subsidiary
      Guarantors and U.S. Bank National Association (incorporated by reference
      to Exhibit 4.4 to Targa Resources Partners LP’s Quarterly Report on Form
      10-Q filed November 9, 2009 (File No.
  001-33303)).





4.17
            Supplemental
      Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among
      Targa Downstream LP, a subsidiary of Targa Resources Partners LP, Targa
      Resources Partners Finance Corporation, the other Subsidiary Guarantors
      and U.S. Bank National Association (incorporated by reference to Exhibit
      4.6 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed
      November 9, 2009 (File No.
001-33303)).





4.18
            Supplemental
      Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among
      Targa LSNG GP LLC, a subsidiary of Targa Resources Partners LP, Targa
      Resources Partners Finance Corporation, the other Subsidiary Guarantors
      and U.S. Bank National Association (incorporated by reference to Exhibit
      4.8 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed
      November 9, 2009 (File No.
001-33303)).





4.19
            Supplemental
      Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among
      Targa LSNG LP, a subsidiary of Targa Resources Partners LP, Targa
      Resources Partners Finance Corporation, the other Subsidiary Guarantors
      and U.S. Bank National Association (incorporated by reference to Exhibit
      4.10 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed
      November 9, 2009 (File No.
001-33303)).








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4.20
            Supplemental
      Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among
      Targa Sparta LLC, a subsidiary of Targa Resources Partners LP, Targa
      Resources Partners Finance Corporation, the other Subsidiary Guarantors
      and U.S. Bank National Association (incorporated by reference to Exhibit
      4.12 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed
      November 9, 2009 (File No.
001-33303)).





4.21
            Supplemental
      Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among
      Midstream Barge Company LLC, a subsidiary of Targa Resources Partners LP,
      Targa Resources Partners Finance Corporation, the other Subsidiary
      Guarantors and U.S. Bank National Association (incorporated by reference
      to Exhibit 4.14 to Targa Resources Partners LP’s Quarterly Report on Form
      10-Q filed November 9, 2009 (File No.
  001-33303)).





4.22
            Supplemental
      Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among
      Targa Retail Electric LLC, a subsidiary of Targa Resources Partners LP,
      Targa Resources Partners Finance Corporation, the other Subsidiary
      Guarantors and U.S. Bank National Association (incorporated by reference
      to Exhibit 4.16 to Targa Resources Partners LP’s Quarterly Report on Form
      10-Q filed November 9, 2009 (File No.
  001-33303)).





4.23
            Supplemental
      Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among
      Targa NGL Pipeline Company LLC, a subsidiary of Targa Resources Partners
      LP, Targa Resources Partners Finance Corporation, the other Subsidiary
      Guarantors and U.S. Bank National Association (incorporated by reference
      to Exhibit 4.18 to Targa Resources Partners LP’s Quarterly Report on Form
      10-Q filed November 9, 2009 (File No.
  001-33303)).





4.24
            Supplemental
      Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among
      Targa Transport LLC, a subsidiary of Targa Resources Partners LP, Targa
      Resources Partners Finance Corporation, the other Subsidiary Guarantors
      and U.S. Bank National Association (incorporated by reference to Exhibit
      4.20 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed
      November 9, 2009 (File No.
001-33303)).





4.25
            Supplemental
      Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among
      Targa Co-Generation LLC, a subsidiary of Targa Resources Partners LP,
      Targa Resources Partners Finance Corporation, the other Subsidiary
      Guarantors and U.S. Bank National Association (incorporated by reference
      to Exhibit 4.22 to Targa Resources Partners LP’s Quarterly Report on Form
      10-Q filed November 9, 2009 (File No.
  001-33303)).





4.26
            Supplemental
      Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among
      Targa Liquids GP LLC, a subsidiary of Targa Resources Partners LP, Targa
      Resources Partners Finance Corporation, the other Subsidiary Guarantors
      and U.S. Bank National Association (incorporated by reference to Exhibit
      4.24 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed
      November 9, 2009 (File No.
001-33303)).





4.27
            Supplemental
      Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among
      Targa Liquids Marketing and Trade, a subsidiary of Targa Resources
      Partners LP, Targa Resources Partners Finance Corporation, the other
      Subsidiary Guarantors and U.S. Bank National Association (incorporated by
      reference to Exhibit 4.26 to Targa Resources Partners LP’s Quarterly
      Report on Form 10-Q filed November 9, 2009 (File No.
      001-33303)).





4.28
            Registration
      Rights Agreement dated as of July 6, 2009, among Targa Resources Partners
      LP, Targa Resources Partners Finance Corporation, the Guarantors named
      therein and the initial purchasers named therein (incorporated by
      reference to Exhibit 4.2 to Targa Resources Partners LP’s Current Report
      on Form 8-K filed July 6, 2009 (File No.
  001-33303)).








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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.





10.2
            First
      Amendment to Credit Agreement, dated October 24, 2007, by and among Targa
      Resources Partners LP, Bank of America, N.A. and each Lender party thereto
      (incorporated by reference to Exhibit 10.3 to Targa Resources Partners
      LP’s Current Report on Form 8-K filed October 24, 2007 (File No.
      001-33303)).





10.3
            Commitment
      Increase Supplement, dated October 24, 2007, by and among Targa Resources
      Partners LP, Bank of America, N.A. and the parties signatory thereto as
      the Increasing Lenders and the New Lenders (incorporated by reference to
      Exhibit 10.2 to Targa Resources Partners LP’s Current Report on Form 8-K
      filed October 24, 2007 (File No.
001-33303)).





10.4
            Commitment
      Increase Supplement, dated June 18, 2008, by and among Targa Resources
      Partners LP, Bank of America, N.A. and other parties signatory thereto
      (incorporated by reference to Exhibit 10.1 to Targa Resources Partners
      LP’s Current Report on Form 8-K filed June 24, 2008 (File No.
      001-33303)).





10.5
            Commitment
      Increase Supplement, dated July 29, 2009, by and among Targa
      Resources Partners LP, Bank of America, N.A. and the other parties
      signatory thereto (incorporated by reference to Exhibit 10.1 to Targa
      Resources Partners LP's Current Report on Form 8-K filed August 4, 2009
      (File No. 001-33303).





10.6
            Contribution,
      Conveyance and Assumption Agreement, dated February 14, 2007, by and among
      Targa Resources Partners LP, Targa Resources Operating LP, Targa Resources
      GP LLC, Targa Resources Operating GP LLC, Targa GP Inc., Targa LP Inc.,
      Targa Regulated Holdings LLC, Targa North Texas GP LLC and Targa North
      Texas LP (incorporated by reference to Exhibit 10.2 to Targa Resources
      Partners LP’s Current Report on Form 8-K filed February 16, 2007 (File No.
      001-33303)).





10.7
            Contribution,
      Conveyance and Assumption Agreement, dated October 24, 2007, by and among
      Targa Resources Partners LP, Targa Resources Holdings LP, Targa TX LLC,
      Targa TX PS LP, Targa LA LLC, Targa LA PS LP and Targa North Texas GP LLC
      (incorporated by reference to Exhibit 10.4 to Targa Resources Partners
      LP’s Current Report on Form 8-K filed October 24, 2007 (File No.
      001-33303)).





10.8
            Contribution,
      Conveyance and Assumption Agreement, dated September 24, 2009, by and
      among Targa Resources Partners LP, Targa GP Inc., Targa LP Inc., Targa
      Resources Operating LP and Targa North Texas GP LLC (incorporated by
      reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report
      on Form 8-K filed September 24, 2009 (File No.
  001-33303)).





10.9
            Second
      Amended and Restated Omnibus Agreement, dated September 24, 2009, by
      and among Targa Resources Partners LP, Targa Resources, Inc., Targa
      Resources LLC and Targa Resources GP LLC (incorporated by reference to
      Exhibit 10.2 to Targa Resources Partners LP’s Current Report on Form 8-K
      filed September 24, 2009 (file No.
001-33303)).





10.10
            Purchase
      Agreement dated as of June 30, 2009 among Targa Resources Partners LP,
      Targa Resources Partners Finance Corporation, the Guarantors named therein
      and Barclays Capital Inc., as representative of the several initial
      purchasers (incorporated by reference to Exhibit 10.1 to Targa Resources
      Partners LP’s Current Report on Form 8-K filed July 6, 2009 (File No.
      001-33303)).





10.11+
            Targa
      Resources Partners Long-Term Incentive Plan (incorporated by reference to
      Exhibit 10.2 to Targa Resources Partners LP’s Registration Statement on
      Form S-1/A filed February 1, 2007 (File No.
  333-138747)).





10.12+
            Targa
      Resources Investments Inc. Long-Term Incentive Plan (incorporated by
      reference to Exhibit 10.9 to Targa Resources Partners LP’s Registration
      Statement on Form S-1/A filed February 1, 2007 (File No.
      333-138747)).





118
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10.13+
            Amendment
      to Targa Resources Partners LP Long-Term Incentive Plan dated December 18,
      2008 (incorporated by reference to Exhibit 10.10 to Targa Resources
      Partners LP’s Annual Report on Form 10-K filed February 27, 2009 (File No.
      001-33303)).





10.14+
            Form
      of Restricted Unit Grant Agreement - 2007 (incorporated by reference to
      Exhibit 10.2 to Targa Resources Partners LP’s Current Report on Form 8-K
      filed February 13, 2007 (File No.
  001-33303)).





10.15+*
            Form
      of Restricted Unit Grant Agreement -
2010.





10.16+
            Form
      of Performance Unit Grant Agreement – 2007 (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 (File No.
      001-33303)).





10.17+
            Form
      of Performance Unit Grant Agreement – 2008 (incorporated by reference to
      Exhibit 10.2 to Targa Resources Partners LP’s Current Report on
      Form 8-K filed January 22, 2008 (File No.
      001-33303)).





10.18+
            Form
      of Performance Unit Grant Agreement – 2009 (incorporated by reference to
      Exhibit 10.2 to Targa Resources Partners LP’s Current Report on Form 8-K
      filed January 28, 2009 (File No.
001-33303)).





10.19+
            Form
      of Performance Unit Grant Agreement – 2010 (incorporated by reference to
      Exhibit 10.2 to Targa Resources Partners LP’s Current Report on Form 8-K
      filed December 7, 2009 (File No.
001-33303)).





10.20+
            Targa
      Resources Investments Inc. 2008 Annual Incentive Compensation Plan
      (incorporated by reference to Exhibit 10.13 to Targa Resources Partners
      LP’s Annual Report on Form 10-K filed February 27, 2009 (File No.
      001-33303)).





10.21+
            Targa
      Resources Investments Inc. 2009 Annual Incentive Compensation Plan
      (incorporated by reference to Exhibit 10.14 to Targa Resources Partners
      LP’s Annual Report on Form 10-K filed February 27, 2009 (File No.
      001-33303)).





10.22+*
            Targa
      Resources Investments Inc. 2010 Annual Incentive Compensation
      Plan.





10.23
            Gas
      Gathering and Purchase Agreement by and between Burlington Resources Oil
      & Gas Company LP, Burlington Resources Trading Inc. and Targa
      Midstream Services Limited Partnership (portions of this exhibit have been
      omitted and filed separately with the Securities and Exchange Commission
      pursuant to a request for confidential treatment) (incorporated by
      reference to Exhibit 10.5 to Targa Resources Partners LP’s Registration
      Statement on Form S-1/A filed February 8, 2007 (File No.
      333-138747)).





10.24*
            Amended
      and Restated Natural Gas Purchase Agreement, effective March 1, 2009, by
      and between Targa Gas Marketing LLC (Buyer) and Targa North Texas LP
      (Seller).





10.25
            Raw
      Product Purchase Agreement dated September 24, 2009, to be effective
      September 1, 2009, between Targa Liquids Marketing and Trade and Targa
      Permian LP (incorporated by reference to Exhibit 10.3 to Targa Resources
      Partners LP’s Current Report on Form 8-K filed September 24, 2009 (file
      No. 001-33303)).





10.26
            Specification
      Product Purchase Agreement dated September 24 , 2009, to be effective
      September 1, 2009, between Targa Liquids Marketing and Trade and Targa
      Midstream Services Limited Partnership (SE La) (incorporated by reference
      to Exhibit 10.4 to Targa Resources Partners LP’s Current Report on Form
      8-K filed September 24, 2009 (file No.
  001-33303)).





10.27
            Raw
      Product Purchase Agreement dated September 24 , 2009, to be effective
      September 1, 2009, between Targa Liquids Marketing and Trade and Targa
      Midstream Services Limited Partnership (Versado) (incorporated by
      reference to Exhibit 10.5 to Targa Resources Partners LP’s Current Report
      on Form 8-K filed September 24, 2009 (file No.
  001-33303)).








119
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10.28
            Raw
      Product Purchase Agreement dated September 24, 2009, to be effective
      September 1, 2009, between Targa Liquids Marketing and Trade and Targa
      Midstream Services Limited Partnership (West La) (incorporated by
      reference to Exhibit 10.6 to Targa Resources Partners LP’s Current Report
      on Form 8-K filed September 24, 2009 (file No.
  001-33303)).





10.29
            Amended
      and Restated Natural Gas Sales Agreement, effective December 1, 2005, by
      and between Targa Louisiana Field Services LLC (Buyer) and Targa Gas
      Marketing LLC (Seller) (incorporated by reference to Exhibit 10.15 to
      Targa Resources Partners LP’s Registration Statement on Form S-1/A filed
      October 12, 2007 (File No.
333-146436)).





10.30
            Amended
      and Restated Natural Gas Purchase Agreement, effective December 1, 2005,
      by and between Targa Gas Marketing LLC (Buyer) and Targa Louisiana Field
      Services LLC (Seller) (incorporated by reference to Exhibit 10.16 to Targa
      Resources Partners LP’s Registration Statement on Form S-1/A filed October
      12, 2007 (File No. 333-146436)).





10.31*
            Amended
      and Restated Natural Gas Purchase Agreement, effective March 1, 2009, by
      and between Targa Gas Marketing LLC (Buyer) and Targa Texas Field Services
      LP (Seller).





10.32*
            Amendment
      to the Amended and Restated Natural Gas Purchase Agreement, effective July
      1, 2009, by and between Targa Gas Marketing LLC (Buyer) and Targa Texas
      Field Services LP (Seller).





10.33+
            Targa
      Resources Partners LP Indemnification Agreement for Barry R. Pearl dated
      February 14, 2007 (incorporated by reference to Exhibit 10.11 to Targa
      Resources Partners LP’s Annual Report on Form 10-K filed April 2, 2007
      (File No. 001-33303)).





10.34+
            Targa
      Resources Partners LP Indemnification Agreement for Robert B. Evans dated
      February 14, 2007 (incorporated by reference to Exhibit 10.12 to Targa
      Resources Partners LP’s Annual Report on Form 10-K filed April 2, 2007
      (File No. 001-33303)).





10.35+
            Targa
      Resources Partners LP Indemnification Agreement for Williams D. Sullivan
      dated February 14, 2007 (incorporated by reference to Exhibit 10.13 to
      Targa Resources Partners LP’s Annual Report on Form 10-K filed April 2,
      2007 (File No. 001-33303)).





10.36
            Purchase
      Agreement dated June 12, 2008, among Targa Resources Partners LP, Targa
      Resources Partners Finance Corporation, the Guarantors named therein and
      the initial purchasers named therein (incorporated by reference to Exhibit
      10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed
      June 18, 2008 (File No.
001-33303)).





21.1*
            Subsidiaries
      of Targa Resources Partners LP.





23.1*
            Consent
      of Independent Registered Public Accounting
  Firm.





31.1*
            Certification
      of the Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) of the
      Securities Exchange Act of 1934.





31.2*
            Certification
      of the Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) of the
      Securities Exchange Act of 1934.





32.1*
            Certification
      of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as
      adopted pursuant to Section 906 of the Sarbanes-Oxley Act of
      2002.








120
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32.2*
            Certification
      of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as
      adopted pursuant to Section 906 of the Sarbanes-Oxley Act of
      2002.


__________


*      Filed
herewith


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


+
            Management
      contract or compensatory plan or
arrangement.








121
 Table of Contents





SIGNATURES





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





Targa Resources Partners
LP


(Registrant)








By: Targa
Resources GP LLC, its general partner


By: /s/ John
Robert Sparger


John
Robert Sparger


Senior
Vice President and


Chief
Accounting Officer


(Principal
Accounting Officer)





Date:
March 3, 2010





Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has been
signed below by the following persons on behalf of the registrant and in the
capacities indicated on March 3, 2010.





Signature
            
            Title
      (Position with Targa Resources GP LLC)/s/
      Rene R. Joyce
            
            Chief
      Executive Officer and Director
              (Principal
      Executive Officer)Rene
      R. Joyce/s/
      Jeffrey J. McParland
            
            Executive
      Vice President, Chief Financial Officer and TreasurerJeffrey
      J. McParland
            
            (Principal
      Financial Officer)/s/
      John Robert Sparger
            
            Senior
      Vice President and Chief Accounting Officer (Principal Accounting
      Officer)John
      Robert Sparger/s/
      James W. Whalen
            
            President
      —Finance and Administration and DirectorJames
      W. Whalen/s/
      Peter R. Kagan
            
            DirectorPeter
      R. Kagan/s/
      Chansoo Joung
            
            DirectorChansoo
      Joung/s/
      Barry R. Pearl
            
            DirectorBarry
      R. Pearl/s/
      Robert B. Evans
            
            DirectorRobert
      B. Evans/s/
      William D. Sullivan
            
            DirectorWilliam
      D. Sullivan























INDEX TO FINANCIAL STATEMENTSTARGA
      RESOURCES PARTNERS LP AUDITED CONSOLIDATED
      FINANCIAL  STATEMENTSManagement's Report on Internal
      Control Over Financial Reporting
            
            
            F-2Report of Independent Registered Public Accounting
      Firm
            
            
            F-3Consolidated Balance Sheets as of December 31, 2009 and
      2008
            
            
            F-4Consolidated Statements of Operations for the Years Ended
      December 31, 2009, 2008 and 2007
            
            
            F-5Consolidated Statements of Comprehensive Income for the Years
      Ended December 31, 2009, 2008and
      2007
            
            
            F-6Consolidated Statement of Changes in Owners' Equity for the
      Years Ended December 31, 2009, 2008and
      2007
            
            
            F-7Consolidated Statements of Cash Flows for the Years Ended
      December 31, 2009, 2008 and 2007
            
            
            F-8Notes to Consolidated Financial
    Statements
            
            
            F-9Note 1—Organization and Operations
            
            
            F-9Note 2—Basis of Presentation
            
            
            F-9Note 3—Out of Period Adjustment
            
            
            F-10Note 4—Significant Accounting Policies
            
            
            F-10Note 5—Acquisition of Downstream
Business
            
            
            F-17Note 6—Inventory
            
            
            F-18Note 7—Property, Plant and Equipment
            
            
            F-18Note 8—Investment in Unconsolidated
      Affiliate
            
            
            F-18Note 9—Asset Retirement Obligations
            
            
            F-19Note 10—Debt Obligations
            
            
            F-19Note 11—Partnership Equity and
      Distributions
            
            
            F-22Note 12—Insurance Claims
            
            
            F-24Note 13—Accounting for Unit-Based
      Compensation
            
            
            F-24Note 14—Derivative Instruments and Hedging
      Activities
            
            
            F-25Note 15—Related-Party Transactions
            
            
            F-29Note 16—Commitments and Contingencies
            
            
            F-33Note 17—Fair Value of Financial
    Instruments
            
            
            F-34Note 18—Fair Value Measurements
            
            
            F-34Note 19—Segment Information
            
            
            F-35Note 20—Other Operating Income
            
            
            F-39Note 21—Supplemental Cash Flow
    Information
            
            
            F-39Note 22—Significant Risks and
    Uncertainties
            
            
            F-39Note 23—Selected Quarterly Financial Data
      (Unaudited)
            
            
            F-41








F -
1





MANAGEMENT’S REPORT ON INTERNAL CONTROL
OVER FINANCIAL REPORTING





The
management of Targa Resources GP LLC, the general partner of Targa Resources
Partners LP (“the Partnership”), is responsible for establishing and maintaining
adequate internal control over financial reporting. Our internal control over
financial reporting is a process designed to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with generally accepted
accounting principles.





Internal
control over financial reporting cannot provide absolute assurance of achieving
financial reporting objectives because of its inherent limitations. Internal
control over financial reporting is a process that involves human diligence and
compliance and is subject to lapses in judgment and breakdowns resulting from
human failures. Internal control over financial reporting also can be
circumvented by collusion or improper management override. Because of such
limitations, there is a risk that material misstatements may not be prevented or
detected on a timely basis by internal control over financial reporting.
However, these inherent limitations are known features of the financial
reporting process. Therefore, it is possible to design into the process
safeguards to reduce, though not eliminate, this risk.





The
management of Targa Resources GP LLC has used the framework set forth in the
report entitled “Internal Control—Integrated Framework” issued by the Committee
of Sponsoring Organizations of the Treadway Commission (“COSO”) to evaluate the
effectiveness of the Partnership’s internal control over financial reporting.
Based on that evaluation, management has concluded that the Partnership’s
internal control over financial reporting was effective as of December 31,
2009.





The
effectiveness of the Partnership's internal control over financial reporting as
of December 31, 2009 has been audited by PricewaterhouseCoopers LLP,
an independent registered public accounting firm, as stated in their report
which appears on page F-3.








/s/  Rene R.
Joyce


Rene R.
Joyce


Chief
Executive Officer of Targa Resources GP LLC,


the
general partner of Targa Resources Partners LP


(Principal
Executive Officer)








/s/  Jeffrey J.
McParland


Jeffrey
J. McParland


Executive
Vice President and Chief Financial Officer


of
Targa Resources GP LLC, the general partner of


Targa
Resources Partners LP


(Principal
Financial Officer)








F -
2
 Index to Financial Statements





REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING
FIRM





To the
Partners of Targa Resources Partners LP:





In our
opinion, the accompanying consolidated balance sheets and the related
consolidated statements of operations, of comprehensive income, of changes in
owners’ equity and of cash flows present fairly, in all material respects, the
financial position of Targa Resources Partners LP and its subsidiaries (the
"Partnership") at December 31, 2009 and 2008, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2009 in conformity with accounting principles generally accepted in
the United States of America. Also in our opinion, the Partnership maintained,
in all material respects, effective internal control over financial reporting as
of December 31, 2009, based on criteria established in Internal Control -
Integrated Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO). The Partnership's management is responsible for
these financial statements, for maintaining effective internal control over
financial reporting and for its assessment of the effectiveness of internal
control over financial reporting, included in the accompanying Management's
Report on Internal Control over Financial Reporting. Our responsibility is to
express opinions on these financial statements and on the Partnership's internal
control over financial reporting based on our audits (which were integrated
audits in 2009 and 2008). We conducted our audits in accordance with the
standards of the Public Company Accounting Oversight Board (United States).
Those standards require that we plan and perform the audits to obtain reasonable
assurance about whether the financial statements are free of material
misstatement and whether effective internal control over financial reporting was
maintained in all material respects. Our audits of the financial statements
included examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting principles
used and significant estimates made by management, and evaluating the overall
financial statement presentation. Our audit of internal control over financial
reporting included obtaining an understanding of internal control over financial
reporting, assessing the risk that a material weakness exists, and testing and
evaluating the design and operating effectiveness of internal control based on
the assessed risk. Our audits also included performing such other procedures as
we considered necessary in the circumstances. We believe that our audits provide
a reasonable basis for our opinions.





As
discussed in Note 15 to the consolidated financial statements, the Partnership
has engaged in significant transactions with other subsidiaries of its parent
company, Targa Resources, Inc., a related-party.





A
company’s internal control over financial reporting is a process designed to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company’s internal control over
financial reporting includes those policies and procedures that (i) pertain
to the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company;
(ii) provide reasonable assurance that transactions are recorded as
necessary to permit preparation of financial statements in accordance with
generally accepted accounting principles, and that receipts and expenditures of
the company are being made only in accordance with authorizations of management
and directors of the company; and (iii) provide reasonable assurance
regarding prevention or timely detection of unauthorized acquisition, use, or
disposition of the company’s assets that could have a material effect on the
financial statements.





Because
of its inherent limitations, internal control over financial reporting may not
prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance
with the policies or procedures may deteriorate.





/s/
PricewaterhouseCoopers LLP





Houston,
Texas


March 3,
2010








F -
3
 Index to Financial Statements








TARGA RESOURCES PARTNERS LPCONSOLIDATED
      BALANCE SHEETSDecember 31,2009
              
              
              2008(In
      millions)ASSETSCurrent
      assets:Cash
      and cash equivalents
              
              
              $
              60.4
              
              
              $
              95.3Trade
      receivables, net of allowances of $2.2 million
              
              
              
              328.3
              
              
              
              236.1Inventory
              
              
              
              39.3
              
              
              
              72.2Assets
      from risk management activities
              
              
              
              25.8
              
              
              
              91.8Other
      current assets
              
              
              
              1.2
              
              
              
              0.8Total
      current assets
              
              
              
              455.0
              
              
              
              496.2Property,
      plant and equipment, at cost
              
              
              
              2,096.8
              
              
              
              2,036.4Accumulated
      depreciation
              
              
              
              (418.3
              )
              
              
              (317.3
              )Property,
      plant and equipment, net
              
              
              
              1,678.5
              
              
              
              1,719.1Long-term
      assets from risk management activities
              
              
              
              9.1
              
              
              
              68.3Investment
      in unconsolidated affiliate
              
              
              
              18.5
              
              
              
              18.5Other
      long-term assets
              
              
              
              19.8
              
              
              
              12.7Total
      assets
              
              
              $
              2,180.9
              
              
              $
              2,314.8LIABILITIES
      AND OWNERS' EQUITYCurrent
      liabilities:Accounts
      payable to third parties
              
              
              $
              164.0
              
              
              $
              138.7Accounts
      payable to affiliates
              
              
              
              101.4
              
              
              
              17.2Accrued
      liabilities
              
              
              
              114.2
              
              
              
              104.2Liabilities
      from risk management activities
              
              
              
              16.3
              
              
              
              11.7Total
      current liabilities
              
              
              
              395.9
              
              
              
              271.8Long-term
      debt payable to third parties
              
              
              
              908.4
              
              
              
              696.8Long-term
      debt payable to Targa Resources, Inc.
              
              
              
              -
              
              
              
              773.9Long-term
      liabilities from risk management activities
              
              
              
              28.9
              
              
              
              9.7Deferred
      income taxes
              
              
              
              4.9
              
              
              
              3.3Other
      long-term liabilities
              
              
              
              6.6
              
              
              
              6.2Commitments
      and contingencies (see Note 16)Owners'
      equity:Common
      unitholders (61,639,846 and 34,652,000 units issued andoutstanding
      as of December 31, 2009 and 2008)
              
              
              
              850.5
              
              
              
              769.9Subordinated
      unitholders (0 and 11,528,231 units issued and outstandingas
      of December 31, 2009 and 2008)
              
              
              
              -
              
              
              
              (85.2
              )General
      partner (1,257,957 and 942,455 units issued and outstanding as
      ofDecember
      31, 2009 and 2008)
              
              
              
              10.1
              
              
              
              5.6Net
      parent investment
              
              
              
              -
              
              
              
              (223.5
              )Accumulated
      other comprehensive income (loss)
              
              
              
              (37.8
              )
              
              
              72.2822.8
              
              
              
              539.0Noncontrolling
      interest in subsidiary
              
              
              
              13.4
              
              
              
              14.1Total
      owners' equity
              
              
              
              836.2
              
              
              
              553.1Total
      liabilities and owners' equity
              
              
              $
              2,180.9
              
              
              $
              2,314.8See
      notes to consolidated financial statements
    F -
4
 Index to Financial Statements
  TARGA RESOURCES PARTNERS LPCONSOLIDATED
      STATEMENTS OF OPERATIONSYear Ended December 31,2009
              
              
              
              2008
              
              2007(In
      millions, except per unit amounts)Revenues
      from third parties
              
              $
              3,897.7
              
              
              $
              7,012.3
              
              
              $
              6,426.3Revenues
      from affiliates
              
              
              197.9
              
              
              
              489.8
              
              
              
              417.4Total
      operating revenues
              
              
              4,095.6
              
              
              
              7,502.1
              
              
              
              6,843.7Costs
      and expenses:Product
      purchases from third parties
              
              
              2,830.6
              
              
              
              5,853.1
              
              
              
              5,349.2Product
      purchases from affiliates
              
              
              755.0
              
              
              
              1,097.7
              
              
              
              952.8Operating
      expenses from third parties
              
              
              158.3
              
              
              
              195.2
              
              
              
              175.1Operating
      expenses from affiliates
              
              
              26.8
              
              
              
              58.8
              
              
              
              44.5Depreciation
      and amortization expenses
              
              
              101.2
              
              
              
              97.8
              
              
              
              93.5General
      and administrative expenses
              
              
              78.9
              
              
              
              68.6
              
              
              
              64.0Other
              
              
              (0.8
              )
              
              
              (0.9
              )
              
              
              (0.3
              )3,950.0
              
              
              
              7,370.3
              
              
              
              6,678.8Income
      from operations
              
              
              145.6
              
              
              
              131.8
              
              
              
              164.9Other
      income (expense):Interest
      expense from affiliate
              
              
              (43.4
              )
              
              
              (59.2
              )
              
              
              (58.5
              )Interest
      expense allocated from Parent
              
              
              -
              
              
              
              -
              
              
              
              (19.4
              )Other
      interest expense, net
              
              
              (52.0
              )
              
              
              (37.9
              )
              
              
              (21.5
              )Equity
      in earnings of unconsolidated investment
              
              
              5.0
              
              
              
              3.9
              
              
              
              3.5Gain
      (loss) on debt repurchases (See Note 10)
              
              
              (1.5
              )
              
              
              13.1
              
              
              
              -Gain
      (loss) on mark-to-market derivative instruments
              
              
              0.8
              
              
              
              (1.0
              )
              
              
              (30.2
              )Other
              
              
              0.7
              
              
              
              1.4
              
              
              
              (1.1
              )(90.4
              )
              
              
              (79.7
              )
              
              
              (127.2
              )Income
      before income taxes
              
              
              55.2
              
              
              
              52.1
              
              
              
              37.7Income
      tax expense:Current
              
              
              (0.2
              )
              
              
              (0.6
              )
              
              
              (0.6
              )Deferred
              
              
              (0.8
              )
              
              
              (1.8
              )
              
              
              (1.9
              )(1.0
              )
              
              
              (2.4
              )
              
              
              (2.5
              )Net
      income
              
              
              54.2
              
              
              
              49.7
              
              
              
              35.2Less:
      Net income attributable to noncontrolling interest
              
              
              2.2
              
              
              
              0.3
              
              
              
              0.1Net
      income attributable to Targa Resources Partners LP
              
              $
              52.0
              
              
              $
              49.4
              
              
              $
              35.1Net
      income (loss) attributable to predecessor operations
              
              $
              (2.4
              )
              
              $
              (42.1
              )
              
              $
              7.0Net
      income attributable to general partner
              
              
              10.4
              
              
              
              7.0
              
              
              
              0.6Net
      income attributable to limited partners
              
              
              44.0
              
              
              
              84.5
              
              
              
              27.5Net
      income attributable to Targa Resources Partners LP
              
              $
              52.0
              
              
              $
              49.4
              
              
              $
              35.1Net
      income per limited partner unit - basic and diluted
              
              $
              0.86
              
              
              $
              1.83
              
              
              $
              0.81Weighted
      average limited partner units outstanding - basic anddiluted
              
              
              51.2
              
              
              
              46.2
              
              
              
              34.0See
      notes to consolidated financial
statements





F -
5
 Index to Financial Statements










TARGA RESOURCES PARTNERS LPCONSOLIDATED
      STATEMENTS OF COMPREHENSIVE INCOMEYear Ended December 31,2009
            
            
            2008
            
            
            2007(In
      millions)Net
      income
            
            $
            54.2
            
            
            $
            49.7
            
            
            $
            35.2Other
      comprehensive income (loss):Commodity
      hedging contracts:Change
      in fair value
            
            
            (72.6
            )
            
            
            129.9
            
            
            
            (105.6
            )Reclassification
      adjustment for settled periods
            
            
            (45.7
            )
            
            
            33.7
            
            
            
            1.0Related
      income taxes
            
            
            -
            
            
            
            -
            
            
            
            0.3Interest
      rate swaps:Change
      in fair value
            
            
            (2.1
            )
            
            
            (19.0
            )
            
            
            (1.7
            )Reclassification
      adjustment for settled periods
            
            
            10.4
            
            
            
            2.7
            
            
            
            (0.2
            )Foreign
      currency translation adjustment
            
            
            -
            
            
            
            (1.8
            )
            
            
            1.9Other
      comprehensive income (loss)
            
            
            (110.0
            )
            
            
            145.5
            
            
            
            (104.3
            )Comprehensive
      income (loss)
            
            
            (55.8
            )
            
            
            195.2
            
            
            
            (69.1
            )Less:
      Comprehensive income attributable tononcontrolling
      interest
            
            
            2.2
            
            
            
            0.3
            
            
            
            0.1Comprehensive
      income (loss) attributable toTarga
      Resources Partners LP
            
            $
            (58.0
            )
            
            $
            194.9
            
            
            $
            (69.2
            )See
      notes to consolidated financial statements








F -
6
 Index to Financial Statements








TARGA RESOURCES PARTNERS LPCONSOLIDATED
      STATEMENT OF CHANGES IN OWNERS' EQUITYAccumulatedOther
            
            
            Net
            
            
            Non-Limited Partners
            
            
            General
            
            
            Comprehensive
            
            
            Parent
            
            
            controllingCommon
            
            
            Subordinated
            
            
            Partner
            
            
            Income (Loss)
            
            
            Investment
            
            
            Interest
            
            
            Total(In
      millions)Balance,
      December 31, 2006
            
            $
            -
            
            
            $
            -
            
            
            $
            -
            
            
            $
            31.3
            
            
            $
            349.2
            
            
            $
            13.4
            
            
            $
            393.9Contribution
      from Parent, net
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            (0.3
            )
            
            
            270.5
            
            
            
            -
            
            
            
            270.2Book
      value of net assets transferredunder
      common control
            
            
            -
            
            
            
            (83.7
            )
            
            
            (4.1
            )
            
            
            -
            
            
            
            (642.0
            )
            
            
            -
            
            
            
            (729.8
            )Issuance
      of units to public (includingunderwriter
      over-allotment), net ofoffering
      and other costs
            
            
            771.8
            
            
            
            -
            
            
            
            8.4
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            780.2Amortization
      of equity awards
            
            
            0.2
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            0.2Distributions
      to unitholders
            
            
            (20.9
            )
            
            
            (9.7
            )
            
            
            (0.6
            )
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            (31.2
            )Net
      income
            
            
            19.1
            
            
            
            8.4
            
            
            
            0.6
            
            
            
            -
            
            
            
            7.0
            
            
            
            0.1
            
            
            
            35.2Other
      comprehensive loss
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            (104.3
            )
            
            
            -
            
            
            
            -
            
            
            
            (104.3
            )Balance,
      December 31, 2007
            
            
            770.2
            
            
            
            (85.0
            )
            
            
            4.3
            
            
            
            (73.3
            )
            
            
            (15.3
            )
            
            
            13.5
            
            
            
            614.4Amortization
      of equity awards
            
            
            0.3
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            0.3Distributions
      to unitholders
            
            
            (64.0
            )
            
            
            (21.3
            )
            
            
            (5.7
            )
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            (91.0
            )Distribution
      to Parent
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            (166.1
            )
            
            
            -
            
            
            
            (166.1
            )Contribution
      from noncontrolling interest
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            0.3
            
            
            
            0.3Net
      income (loss)
            
            
            63.4
            
            
            
            21.1
            
            
            
            7.0
            
            
            
            -
            
            
            
            (42.1
            )
            
            
            0.3
            
            
            
            49.7Other
      comprehensive income
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            145.5
            
            
            
            -
            
            
            
            -
            
            
            
            145.5Balance,
      December 31, 2008
            
            
            769.9
            
            
            
            (85.2
            )
            
            
            5.6
            
            
            
            72.2
            
            
            
            (223.5
            )
            
            
            14.1
            
            
            
            553.1Issuance
      of common units:Equity
      offering
            
            
            103.1
            
            
            
            -
            
            
            
            2.2
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            105.3Acquisition
      related
            
            
            129.8
            
            
            
            -
            
            
            
            2.7
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            132.5Contribution
      under common control
            
            
            (7.7
            )
            
            
            -
            
            
            
            (0.2
            )
            
            
            -
            
            
            
            7.2
            
            
            
            -
            
            
            
            (0.7
            )Distributions
      to Parent
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            (68.6
            )
            
            
            (2.6
            )
            
            
            (71.2
            )Settlement
      of affiliated indebtedness
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            287.3
            
            
            
            -
            
            
            
            287.3Distributions
      to noncontrolling interest
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            (0.3
            )
            
            
            (0.3
            )Amortization
      of equity awards
            
            
            0.3
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            0.3Other
      comprehensive loss
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            (110.0
            )
            
            
            -
            
            
            
            -
            
            
            
            (110.0
            )Conversion
      of subordinated units
            
            
            (97.6
            )
            
            
            97.6
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -Net
      income (loss)
            
            
            44.5
            
            
            
            (0.5
            )
            
            
            10.4
            
            
            
            -
            
            
            
            (2.4
            )
            
            
            2.2
            
            
            
            54.2Distributions
      to unitholders
            
            
            (91.8
            )
            
            
            (11.9
            )
            
            
            (10.6
            )
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            (114.3
            )Balance,
      December 31, 2009
            
            $
            850.5
            
            
            $
            -
            
            
            $
            10.1
            
            
            $
            (37.8
            )
            
            $
            -
            
            
            $
            13.4
            
            
            $
            836.2See
      notes to consolidated financial statements








F -
7
 Index to Financial Statements


TARGA RESOURCES PARTNERS LPCONSOLIDATED
      STATEMENTS OF CASH FLOWSYear Ended December 31,2009
                
                
                2008
                
                
                2007(In
      millions)Cash
      flows from operating activitiesNet
      income
                
                $
                54.2
                
                
                $
                49.7
                
                
                $
                35.2Adjustments
      to reconcile net income to net cashprovided
      by operating activities:Amortization
      in interest expense
                
                
                3.8
                
                
                
                2.1
                
                
                
                1.8Amortization
      in general and administrative expense
                
                
                0.3
                
                
                
                0.4
                
                
                
                0.2Interest
      expense on affiliate indebtedness
                
                
                43.4
                
                
                
                59.2
                
                
                
                58.5Depreciation
      and amortization expense
                
                
                101.2
                
                
                
                97.8
                
                
                
                93.5Accretion
      of asset retirement obligations
                
                
                0.4
                
                
                
                0.3
                
                
                
                0.4Deferred
      income tax expense
                
                
                0.8
                
                
                
                1.8
                
                
                
                1.9Equity
      in earnings of unconsolidated investments, net of
      distributions
                
                
                -
                
                
                
                0.8
                
                
                
                0.4Risk
      management activities
                
                
                37.6
                
                
                
                (64.0
                )
                
                
                30.8Loss
      (gain) on debt repurchases
                
                
                1.5
                
                
                
                (13.1
                )
                
                
                -Gain
      on sale of assets
                
                
                -
                
                
                
                (5.9
                )
                
                
                (0.3
                )Changes
      in operating assets and liabilities:Receivables
      and other assets
                
                
                (92.5
                )
                
                
                582.8
                
                
                
                (117.1
                )Inventory
                
                
                23.1
                
                
                
                75.4
                
                
                
                (28.6
                )Accounts
      payable and other liabilities
                
                
                126.0
                
                
                
                (494.3
                )
                
                
                191.6Net
      cash provided by operating activities
                
                
                299.8
                
                
                
                293.0
                
                
                
                268.3Cash
      flows from investing activitiesOutlays
      for property, plant and equipment
                
                
                (57.2
                )
                
                
                (86.3
                )
                
                
                (77.6
                )Other,
      net
                
                
                0.1
                
                
                
                0.2
                
                
                
                0.8Net
      cash used in investing activities
                
                
                (57.1
                )
                
                
                (86.1
                )
                
                
                (76.8
                )Cash
      flows from financing activitiesProceeds
      from borrowings under credit facility
                
                
                569.2
                
                
                
                185.3
                
                
                
                721.3Repayments
      of credit facility
                
                
                (577.7
                )
                
                
                (323.8
                )
                
                
                (95.0
                )Proceeds
      from issuance of senior notes
                
                
                237.4
                
                
                
                250.0
                
                
                
                -Repurchases
      of senior notes
                
                
                (18.9
                )
                
                
                (26.8
                )
                
                
                -Repayment
      of affiliated indebtedness
                
                
                (397.5
                )
                
                
                -
                
                
                
                (665.7
                )Proceeds
      from equity offerings
                
                
                103.1
                
                
                
                -
                
                
                
                777.5Distributions
      to unitholders
                
                
                (114.3
                )
                
                
                (91.0
                )
                
                
                (31.2
                )General
      partner contributions
                
                
                2.2
                
                
                
                -
                
                
                
                -Costs
      incurred in connection with public offerings
                
                
                -
                
                
                
                (0.1
                )
                
                
                (4.6
                )Costs
      incurred in connection with financing arrangements
                
                
                (9.6
                )
                
                
                (7.1
                )
                
                
                (7.5
                )Parent
      distributions
                
                
                (71.2
                )
                
                
                (166.1
                )
                
                
                (847.5
                )Loan
      from Parent
                
                
                -
                
                
                
                3.4
                
                
                
                13.0Contribution
      from (distributions to) noncontrolling interest
                
                
                (0.3
                )
                
                
                0.3
                
                
                
                -Net
      cash used in financing activities
                
                
                (277.6
                )
                
                
                (175.9
                )
                
                
                (139.7
                )Net
      change in cash and cash equivalents
                
                
                (34.9
                )
                
                
                31.0
                
                
                
                51.8Cash
      and cash equivalents, beginning of year
                
                
                95.3
                
                
                
                64.3
                
                
                
                12.5Cash
      and cash equivalents, end of year
                
                $
                60.4
                
                
                $
                95.3
                
                
                $
                64.3See
      notes to consolidated financial statements


F -
8
 Index to Financial Statements





TARGA RESOURCES PARTNERS LP


NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS





Except
as noted within the context of each footnote disclosure, the dollar amounts
presented in the tabular data within these footnote disclosures are stated in
millions of dollars.





Note 1—Organization and Operations





Targa
Resources Partners LP, together with its subsidiaries, is a publicly traded
Delaware limited partnership formed on October 26, 2006 by Targa Resources,
Inc. (“Targa” or “Parent”). In this report, unless the context requires
otherwise, references to “we,” “us,” “our” or the “Partnership” are intended to
mean the business and operations of Targa Resources Partners LP and its
consolidated subsidiaries. References to “TRP LP” are intended to mean and
include Targa Resources Partners LP, individually, and not on a consolidated
basis. Our common units began trading on the New York Stock Exchange on
January 25, 2010 under the symbol “NGLS.” Previously, our common units were
listed on The NASDAQ Stock Market LLC under the same symbol. Our business
operations consist of natural gas gathering and processing, and the
fractionating, storing, terminalling, transporting, distributing and marketing
of natural gas liquids (“NGLs”). See Note 19.





Targa
Resources GP LLC is a Delaware single-member limited liability company, formed
in October 2006 to own a 2% general partner interest in us. Its primary
business purpose is to manage our affairs and operations. Targa Resources GP LLC
is an indirect wholly-owned subsidiary of Targa.





On
February 14, 2007, we completed an initial public offering (“IPO”) of
common units representing limited partner interests in the Partnership.
Concurrent with the IPO, Targa conveyed its ownership interests in Targa North
Texas GP LLC and Targa North Texas LP (collectively, the “North Texas System”)
to us.





On
October 24, 2007, Targa conveyed its ownership interests in Targa Texas
Field Services LP (the “SAOU System”) and Targa Louisiana Field Services LLC
(the “LOU System”) to us. This conveyance consisted of the SAOU System’s natural
gas gathering and processing businesses and the LOU System’s natural gas
gathering and processing businesses.




On
September 24, 2009, we acquired Targa’s interests in Targa Downstream LP,
Targa LSNG LP, Targa Downstream GP LLC and Targa LSNG GP LLC (collectively, the
“Downstream Business”) in a transaction among entities under common control. See
Note 5.





Note 2—Basis of Presentation





These
consolidated financial statements include our accounts and: (i) prior to
September 24, 2009 the assets, liabilities and operations of the Downstream
Business; (ii) prior to October 24, 2007 the assets, liabilities and
operations of the SAOU and LOU Systems as the predecessor entities; and
(iii) prior to February 14, 2007 the assets, liabilities and
operations of the North Texas System. The effect on reported equity of including
such prior results of these acquired businesses is reported as net parent
investment in our consolidated balance sheets and consolidated statement of
changes in owners’ equity.





Targa’s
conveyances to us of the North Texas System, the SAOU and LOU Systems and the
Downstream Business have been accounted for as transfers of net assets between
entities under common control. We recognize transfers of net assets between
entities under common control at Targa’s historical basis in the net assets
conveyed. In addition, transfers of net assets between entities under common
control are accounted for as if the transfer occurred at the beginning of the
period, and prior years are retroactively adjusted to furnish comparative
information similar to the pooling of interests method. The difference between
the purchase price and Targa’s basis in the net assets, if any, is recognized as
an adjustment to net parent investment.





Our
consolidated financial statements and all other financial information included
in this report have been retrospectively adjusted to assume that the acquisition
of the Downstream Business from Targa by us had occurred at the date when both
the Downstream Business and the North Texas System met the accounting
requirements for entities under common control (October31, 2005)
following the acquisition of the SAOU and LOU Systems. As a





F -
9
 Index to Financial Statements





result,
financial statements and financial information presented for prior periods in
this report have been retrospectively adjusted.





The
consolidated financial statements have been prepared in accordance with
accounting principles generally accepted in the United States of America
(“GAAP”). We refer to the operations, assets and liabilities of the North Texas
System, the SAOU and LOU Systems, and the Downstream Business, prior to our
acquisition from Targa, collectively as our “predecessors.” The consolidated
financial statements of our predecessors have been prepared from the separate
records maintained by Targa and may not necessarily be indicative of the
conditions that would have existed or the results of operations if our
predecessors had been operated as unaffiliated entities. All significant
intercompany balances and transactions have been eliminated. Transactions among
us and other Targa operations have been identified in the consolidated financial
statements as transactions among affiliates.





We have
been allocated certain general and administrative expenses incurred by our
Parent in order to present financial statements on a stand-alone basis. See Note
15. All of the allocations are not necessarily indicative of the costs and
expenses that would have resulted had we been operated as stand-alone
entities.





In
preparing the accompanying consolidated financial statements, the Partnership
has reviewed, as determined necessary by the Partnership, events that have
occurred after December 31, 2009, up until the issuance of the financial
statements. See Notes 11 and 16.




Note 3—Out of Period Adjustment





During
2009, we recorded an adjustment related to prior periods which increased our
revenue, income before income taxes and net income for 2009 by
$1.8 million. The adjustment related to natural gas sales transactions
which occurred during 2006. After evaluating the quantitative and qualitative
aspects of the error, we concluded that our previously issued financial
statements were not materially misstated and the effect of recognizing the
adjustment in the 2009 financial statements was not material to our results of
operations, financial position or cash flows.




Note 4—Significant Accounting Policies





Asset retirement obligations
(“AROs”). AROs are legal obligations associated with the retirement of
tangible long-lived assets that result from the asset’s acquisition,
construction, development and/or normal operation. An ARO is initially measured
at its estimated fair value. Upon initial recognition of an ARO, we record an
increase to the carrying amount of the related long-lived asset and an
offsetting ARO liability. The consolidated cost of the asset and the capitalized
asset retirement obligation is depreciated using the straight-line method over
the period during which the long-lived asset is expected to provide benefits.
After the initial period of ARO recognition, the ARO will change as a result of
either the passage of time or revisions to the original estimates of either the
amounts of estimated cash flows or their timing.





Changes
due to the passage of time increase the carrying amount of the liability because
there are fewer periods remaining from the initial measurement date until the
settlement date; therefore, the present values of the discounted future
settlement amount increases. These changes are recorded as a period cost called
accretion expense. Changes resulting from revisions to the timing or the amount
of the original estimate of undiscounted cash flows shall be recognized as an
increase or a decrease in the carrying amount of the liability for an asset
retirement obligation and the related asset retirement cost capitalized as part
of the carrying amount of the related long-lived asset.Upon settlement, AROs
will be extinguished by us at either the recorded amount or we will recognize a
gain or loss on the difference between the recorded amount and the actual
settlement cost. See Note 9.





Cash and Cash Equivalents.Cash and cash equivalents include all cash on hand, demand deposits, and
investments with original maturities of three months or less. We consider cash
equivalents to include short-term, highly liquid investments that are readily
convertible to known amounts of cash and which are subject to an insignificant
risk of changes in value. As of December 31, 2009 and 2008, accrued
liabilities included approximately $5.3 million and $3.6 million of
outstanding checks that were reclassified from cash and cash
equivalents.





F -
10
 Index to Financial Statements


Comprehensive Income.Comprehensive income includes net income and other comprehensive income
(“OCI”), which includes unrealized gains and losses on derivative instruments
that are designated as hedges, and currency translation
adjustments.





Concentration of Credit Risk.Financial instruments which potentially subject us to concentrations of
credit risk consist primarily of trade accounts receivable and commodity
derivative instruments.





Trade Accounts Receivable.We
extend credit to customers and other parties in the normal course of business.
We have established various procedures to manage our credit exposure, including
initial credit approvals, credit limits and terms, letters of credit, and rights
of offset. We also use prepayments and guarantees to limit credit risk to ensure
that our established credit criteria are met.





Estimated
losses on accounts receivable are provided through an allowance for doubtful
accounts. In evaluating the level of established reserves, we make judgments
regarding each party’s ability to make required payments, economic events and
other factors. As the financial condition of any party changes, circumstances
develop or additional information becomes available, adjustments to an allowance
for doubtful accounts may be required.





The
following table presents the activity of our allowance for doubtful accounts for
the periods indicated:





Year Ended December 31,2009
            
            
            2008
            
            
            2007Balance
      at beginning of year
            
            $
            2.2
            
            
            $
            0.9
            
            
            $
            0.8Additions
            
            
            -
            
            
            
            1.3
            
            
            
            0.2Deductions
            
            
            -
            
            
            
            -
            
            
            
            (0.1
            )Balance
      at end of year
            
            $
            2.2
            
            
            $
            2.2
            
            
            $
            0.9








Significant Commercial
Relationships. The following table lists the percentage of our
consolidated sales or purchases with customers and suppliers which accounted for
more than 10% of our consolidated revenues and consolidated product purchases
for the periods indicated:




Year Ended December 31,2009
            
            
            2008
            
            
            2007%
      of consolidated revenuesChevron
      Phillips Chemical Company LLC
            
            
            17%
            
            
            
            20%
            
            
            
            22%%
      of consolidated product purchasesLouis
      Dreyfus Energy Services L.P.
            
            
            12%
            
            
            
            9%
            
            
            
            7%





Consolidation Policy.We
evaluate our financial interests in business enterprises to determine if they
represent variable interest entities where we are the primary beneficiary. If
such criteria are met, we consolidate the financial statements of such
businesses with those of our own. Our consolidated financial statements include
our accounts and those of our majority-owned subsidiaries in which we have a
controlling interest.





We follow
the equity method of accounting if our ownership interest is between 20% and 50%
and we exercise significant influence over the operating and financial policies
of the investee.





Debt Issue Costs. Costs
incurred in connection with the issuance of long-term debt are deferred and
charged to interest expense over the term of the related debt.




Environmental
Liabilities.





F -
11
 Index to Financial Statements





Gas Processing Imbalances.Quantities of natural gas and/or NGLs over-delivered or under-delivered
related to certain gas plant operational balancing agreements are recorded
monthly as inventory or as a payable using weighted average prices as of the
time the imbalance was created. Monthly, inventory imbalances receivable are
valued at the lower of cost or market; inventory imbalances payable are valued
at replacement cost. These imbalances are settled either by current cash-out
settlements or by adjusting future receipts or deliveries of natural gas or
NGLs.





Income Taxes. Our earnings or
losses for federal income tax purposes are included in the tax returns of our
individual partners. As such, we are not subject to federal income
taxes.





In May
2006, Texas adopted a margin tax, consisting generally of a 1% tax on the amount
by which total revenues exceed cost of goods sold, as apportioned to Texas.
Accordingly, we have estimated our liability for this tax and it is recorded as
a tax liability.




Inventory.Our
product inventories consist primarily of NGLs. Most product inventories turn
over monthly, but some inventory, primarily propane, is acquired and held during
the year to meet anticipated heating season requirements of our customers.
Product inventories are valued at the lower of cost or market using the average
cost method.





Net Income per Limited Partner Unit.Net income attributable to Targa Resources Partners LP is allocated to
the general partner and the limited partners (common unitholders) in accordance
with their respective ownership percentages, after giving effect to incentive
distributions paid to the general partner. Basic and diluted net income per
limited partner unit is calculated by dividing limited partners’ interest in net
income by the weighted average number of outstanding limited partner units
during the period.





Unvested
share-based payment awards that contain non-forfeitable rights to dividends or
dividend equivalents (whether paid or unpaid) are classified as participating
securities and are included in our computation of basic and diluted net income
per limited partner unit.





We
compute earnings per unit using the two-class method.The two-class method
requires that securities that meet the definition of a participating security be
considered for inclusion in the computation of basic earnings per unit using the
two-class method. Under the two-class method, earnings per unit is calculated as
if all of the earnings for the period were distributed under the terms of the
partnership agreement, regardless of whether the general partner has discretion
over the amount of distributions to be made in any particular period, whether
those earnings would actually be distributed during a particular period from an
economic or practical perspective, or whether the general partner has other
legal or contractual limitations on its ability to pay distributions that would
prevent it from distributing all of the earnings for a particular
period.





The
two-class method does not impact our overall net income or other financial
results; however, in periods in which aggregate net income exceeds our aggregate
distributions for such period, it will have the impact of reducing net income
per limited partner unit. This result occurs as a larger portion of our
aggregate earnings, as if distributed, is allocated to the incentive
distribution rights of the general partner, even though we make distributions on
the basis of available cash and not earnings. In periods in which our aggregate
net income does not exceed our aggregate distributions for such period, the
two-class method does not have any impact on our calculation of earnings per
limited partner unit.





The
calculation of basic and diluted net income per common unit are the same for all
periods presented as distributable cash flow was greater than net income for
those periods.
 
 Noncontrolling
Interest. Noncontrolling interest represents third party ownership in the
net assets of our consolidated subsidiary, Cedar Bayou Fractionators. For
financial reporting purposes, the assets and liabilities of our majority owned
subsidiary are consolidated with any third party investor’s interest shown as
noncontrolling interest. In the
statements of operations, noncontrolling interest reflects the allocation of
joint venture earnings to a third party investor. Distributions to and
contributions from noncontrolling interest represent cash payments and cash
contributions from such third party investor.





F -
12
 Index to Financial Statements





Price Risk Management (Hedging).We have designated certain downstream liquids marketing contracts that
meet the definition of a derivative as normal purchases and normal sales, which
are not accounted for as derivatives. All derivative instruments not qualifying
for the normal purchases and normal sales exception are recorded on the balance
sheets at fair value. If a derivative does not qualify as a hedge or is not
designated as a hedge, the gain or loss on the derivative is recognized
currently in earnings. If a derivative qualifies for hedge accounting and is
designated as a cash flow hedge, the effective portion of the unrealized gain or
loss on the derivative is deferred in accumulated OCI, a component of owner’s
equity, and reclassified to earnings when the forecasted transaction occurs.
Cash flows from a derivative instrument designated as a hedge are classified in
the same category as the cash flows from the item being hedged.





Our
policy is to formally document all relationships between hedging instruments and
hedged items, as well as our risk management objectives and strategy for
undertaking the hedge. This process includes specific identification of the
hedging instrument and the hedged item, the nature of the risk being hedged and
the manner in which the hedging instrument’s effectiveness will be assessed. At
the inception of the hedge and on an ongoing basis, we assess whether the
derivatives used in hedging transactions are highly effective in offsetting
changes in cash flows of hedged items. Hedge ineffectiveness is measured on a
quarterly basis. Any ineffective portion of the unrealized gain or loss is
reclassified to earnings in the current period.





The
relationship between the hedging instrument and the hedged item must be highly
effective in achieving the offset of changes in cash flows attributable to the
hedged risk both at the inception of the contract and on an ongoing basis. Hedge
accounting is discontinued prospectively when a hedge instrument is terminated
or ceases to be highly effective. Gains and losses deferred in OCI related to
cash flow hedges for which hedge accounting has been discontinued remain
deferred until the forecasted transaction occurs. If it is no longer probable
that a hedged forecasted transaction will occur, deferred gains or losses on the
hedging instrument are reclassified to earnings immediately. See Notes 14, 15
and 18.





Product Exchanges. Exchanges
of NGL products are executed to satisfy timing and logistical needs of the
exchanging parties. Volumes received and delivered under exchange agreements are
recorded as inventory. If the locations of receipt and delivery are in different
markets, a price differential may be billed or owed. The price differential is
recorded as either accounts receivable or accrued liabilities.





Property, Plant and Equipment.Property, plant and equipment are stated at cost less accumulated
depreciation. Depreciation is computed using the straight-line method over the
estimated useful lives of the assets. The estimated service lives of our
functional asset groups are as follows:





Asset Group
            
            Range of YearsGas
      gathering systems and processing systems
            
            5
      to 20Fractionation,
      terminalling and natural gas liquids storage facilities
            
            5
      to 25Transportation
      assets
            
            10
      to 25Other
      property and equipment
            
            3
      to 25








Expenditures
for maintenance and repairs are expensed as incurred. Expenditures to refurbish
assets that extend the useful lives or prevent environmental contamination are
capitalized and depreciated over the remaining useful life of the asset or major
asset component.




Our
determination of the useful lives of property, plant and equipment requires us
to make various assumptions, including the supply of and demand for hydrocarbons
in the markets served by our assets, normal wear and tear of the facilities, and
the extent and frequency of maintenance programs.
 
 We
capitalize certain costs directly related to the construction of assets,
including internal labor costs, interest and engineering costs. Upon disposition
or retirement of property, plant and equipment, any gain or loss is charged to
operations.
 
 We
evaluate the recoverability of our property, plant and equipment when events or
circumstances such as economic obsolescence, the business climate, legal and
other factors indicate we may not recover the carrying





F -
13
 Index to Financial Statements









Revenue Recognition.Our
primary types of sales and service activities reported as operating revenues
include:





·      sales
of natural gas, NGLs and condensate;





·
            natural
      gas processing, from which we generate revenues through the compression,
      gathering, treating, and processing of natural gas;
  and





·
            NGL
      fractionation, terminalling and storage, transportation and
      treating.





We
recognize revenues when all of the following criteria are met:
(1) persuasive evidence of an exchange arrangement exists, if applicable,
(2) delivery has occurred or services have been rendered, (3) the
price is fixed or determinable and (4) collectibility is reasonably
assured.





For
processing services, we receive either fees or a percentage of commodities as
payment for these services, depending on the type of contract. Under
percent-of-proceeds contracts, we receive either an agreed upon percentage of
the actual proceeds that we receive from our sales of the residue natural gas
and NGLs or an agreed upon percentage based on index related prices for the
natural gas and NGLs. Percent-of-value and percent-of-liquids contracts are
variations on this arrangement. Under keep-whole contracts, we keep the NGLs
extracted and return the processed natural gas or value of the natural gas to
the producer. Natural gas or NGLs that we receive for services or purchase for
resale are in turn sold and recognized in accordance with the criteria outlined
above. Under fee-based contracts, we receive a fee based on throughput
volumes.





We
generally report revenues gross in our consolidated statements of operations.
Except for fee-based contracts, we act as the principal in the transactions
where we receive commodities, take title to the natural gas and NGLs, and incur
the risks and rewards of ownership.




During
2009, we reclassified NGL marketing fractionation and other service fees to
revenues that were originally recorded in product purchase costs. The
reclassification increased revenues and product purchases for 2008 and 2007 by
$28.7 million and $27.6 million. This reclassification had no impact on our
income from operations, net income, financial position or cash flows and we
concluded that our previously issued financial statements were not materially
misstated.




Unit-Based Employee Compensation.We award share-based compensation to non-management directors in the form
of restricted common units, which are deemed to be equity awards. Compensation
expense on restricted common units is measured by the fair value of the award at
the date of grant. Compensation expense is recognized in general and
administrative expense over the requisite service period of each award. See Note
13.  Use of Estimates.The
preparation of financial statements in conformity with accounting principles
generally accepted in the United States of America requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosures of contingent assets and liabilities as of the date
of the financial statements and the reported amounts of revenues and expenses
during the period. Estimates and judgments are based on information available at
the time such estimates and judgments are made. Adjustments made with respect to
the use of these estimates and judgments often relate to information not
previously available. Uncertainties with respect to such estimates and judgments
are inherent in the preparation of financial statements. Estimates and judgments
are used in, among other things, (1) estimating unbilled revenues and
operating and








F -
14
 Index to Financial Statements




general and
administrative costs (2) developing fair value assumptions, including
estimates of future cash flows and discount rates, (3) analyzing
long-lived assets for possible impairment, (4) estimating the useful lives
of assets and (5) determining amounts to accrue for contingencies,
guarantees and indemnifications. Actual results could differ materially from
estimated amounts.





Accounting
Pronouncements Recently Adopted





Financial
Accounting Standards Board (“FASB”) Codification





In June
2009, FASB issued the FASB Accounting Standards Codification (the “Codification”
or “ASC”) as the source of authoritative GAAP recognized by FASB to be applied
by nongovernmental entities. Rules and interpretive releases of the Securities
and Exchange Commission (“SEC”) under authority of federal securities laws are
also sources of authoritative GAAP for SEC registrants. The Codification is
effective for financial statements issued for interim and annual periods ending
after September 15, 2009. As of the effective date, the Codification supersedes
all then-existing non-SEC accounting and reporting standards. All other
non-grandfathered non-SEC accounting literature not included in the Codification
has become non-authoritative.





Following
the Codification, FASB will no longer issue new standards in the form of
Statements, FASB Staff Positions, or Emerging Issues Task Force Abstracts.
Instead, it will issue Accounting Standards Updates (“ASUs”). FASB will not
consider ASUs as authoritative in their own right. They will serve only to
update the Codification, provide background information about the guidance, and
provide the basis for conclusions on changes in the Codification.





Fair
Value Measurements





In
September 2006, FASB issued guidance regarding fair value measurement that
defines fair value, establishes a framework for measuring fair value and expands
disclosures about fair value measurements. This guidance applies to previous
accounting guidance that require or permit fair value measurements, and
accordingly, does not require any new fair value measurements. The guidance was
initially effective as of January 1, 2008, but in February 2008, FASB
delayed the effective date for applying the guidance to nonfinancial assets and
nonfinancial liabilities that are recognized or disclosed at fair value in the
financial statements on a nonrecurring basis, until periods beginning after
November 15, 2008. We adopted the guidance as of January 1, 2008 with
respect to financial assets and liabilities within its scope and the impact was
not material to our financial statements. As of January 1, 2009,
nonfinancial assets and nonfinancial liabilities were also required to be
measured at fair value. The adoption of these additional provisions did not have
a material impact on our financial statements. See Note 18.





In April
2009, FASB issued guidance for determining fair values when there is no active
market or where the price inputs being used represent distressed sales.
Specifically, it reaffirms the need to use judgment to ascertain if a formerly
active market has become inactive and in determining fair values when markets
have become inactive. We adopted the guidance as of June 30, 2009. There
have been no material financial statement implications relating to our
adoption.





In April
2009, FASB issued guidance that requires disclosures of fair value for any
financial instruments not currently reflected at fair value on the balance
sheets for all interim periods. We adopted these provisions as of June 30,
2009. There have been no material financial statement implications relating to
this adoption. See Note 17.




Our adoption did not have
a material impact on our consolidated financial statements.





F -
15
 Index to Financial Statements




Business
Combinations





In
December 2007, FASB issued guidance that requires the acquiring entity in a
business combination to recognize all assets acquired and liabilities assumed in
the transaction, establishes the acquisition-date fair value as the measurement
objective for all assets acquired and liabilities assumed and requires the
acquirer to disclose certain information related to the nature and financial
effect of the business combination. It also establishes principles and
requirements for how an acquirer recognizes any noncontrolling interest in the
acquiree and the goodwill acquired in a business combination. This guidance was
effective on a prospective basis for business combinations for which the
acquisition date is on or after January 1, 2009. For any business
combination that takes place subsequent to January 1, 2009, this guidance
may have a material impact on our financial statements. The nature and extent of
any such impact will depend upon the terms and conditions of the transaction.
This guidance did not apply to our acquisition of the Downstream Business as it is a transfer of net
assets between entities under common control.





In April 2009, FASB issued guidance
that amends and clarifies application issues on initial recognition and
measurement, subsequent measurement and accounting, and disclosure of assets and
liabilities arising from contingencies in a business combination. This update is
effective for assets and liabilities arising from contingencies in business
combinations for which the acquisition date is on or after January 1, 2009.
There have been no material financial statement implications relating to the
adoption of this update.





Other





In
December 2007, FASB issued guidance that  requires all entities to
report noncontrolling interests in subsidiaries as a separate component of
equity in the consolidated statement of financial position, to clearly identify
consolidated net income attributable to the parent and to the noncontrolling
interest on the face of the consolidated statement of income, and to provide
sufficient disclosure that clearly identifies and distinguishes between the
interest of the parent and the interests of noncontrolling owners. It also
establishes accounting and reporting standards for changes in a parent’s
ownership interest and the valuation of retained noncontrolling equity
investments when a subsidiary is deconsolidated. We adopted these amended
provisions effective January 1, 2009, which required retrospective
reclassification of our consolidated financial statements for all periods
presented in this filing. As a result of adoption, we have reclassified our
noncontrolling interest (formerly minority interest) on our consolidated balance
sheets, from a component of liabilities to a component of equity and have also
reclassified net income attributable to noncontrolling interest on our
consolidated statements of operations, to below net income for all periods
presented. Furthermore, we have displayed the portion of other comprehensive
income that is attributable to the noncontrolling interest within our
consolidated statements of comprehensive income.





In March
2008, the FASB’s Emerging Issues Task Force (“EITF”) issued guidance as to how a
master limited partnership (“MLP”) should allocate and present earnings per unit
using the two-class method when the MLP’s partnership agreement contains
incentive distribution rights. Under the two-class method, current period
earnings are allocated to the partners according to the distribution formula for
available cash set forth in the MLP’s partnership agreement. Our adoption of
this guidance on January 1, 2009, did not impact our consolidated financial
position, results of operations or cash flows, or our basic and diluted net
income per unit.





In
June 2008, FASB issued guidance that requires us to retrospectively adjust
our earnings per unit data that result in us recognizing unvested unit-based
payment awards as participating units in our basic earnings per unit
calculation. Our adoption of this guidance on adopted January 1, 2009 did
not have a material impact on our computation of basic can diluted net income
per unit.




F -
16
 Index to Financial Statements


In May
2009, FASB issued guidance that establishes general standards of accounting for
and disclosure of events that occur after the balance sheet date but before
financial statements are issued or are available to be issued. This guidance
sets forth (1) the period after the balance sheet date during which
management of a reporting entity should evaluate events or transactions that may
occur for potential recognition or disclosure in the financial statements,
(2) the circumstances under which an entity should recognize events or
transactions occurring after the balance sheet date in its financial statements,
and (3) the disclosures that an entity should make about events or
transactions that occurred after the balance sheet date. It is effective for
interim and annual periods ended after June 15, 2009 and should be applied
prospectively. Our adoption did not have a material impact on our financial
statements.


In June
2009, the SEC Staff issued guidance that amends or rescinds portions of the SEC
staff’s interpretive guidance included in the Staff Accounting Bulletin Series
in order to make the relevant interpretive guidance consistent with the ASC. Our
adoption did not have a material impact on our consolidated financial
statements.





In
December 2009, the FASB amended consolidation guidance for variable interest
entities (“VIEs”). VIEs are entities whose equity investors do not have
sufficient equity capital at risk such that the entity cannot finance its own
activities. When a business has a controlling financial interest in a VIE, the
assets, liabilities and profit or loss of that entity must be included in
consolidation. A business enterprise must consolidate a VIE when that enterprise
has a variable interest that will cover most of the entity’s expected losses
and/or receive most of the entity’s anticipated residual return. The new
guidance, among other things, eliminates the scope exception for qualifying
special-purpose entities, amends certain guidance for determining whether an
entity is a VIE, expands the list of events that trigger reconsideration of
whether an entity is a VIE, requires a qualitative rather than a quantitative
analysis to determine the primary beneficiary of a VIE, requires continuous
assessments of whether a company is the primary beneficiary of a VIE and
requires enhanced disclosures about a company’s involvement with a VIE. This
guidance is effective for us on January 1, 2010 and early adoption is
prohibited. At December 31, 2009, we had not identified any interests which
qualified as VIEs and our adoption of this new guidance is not expected to have
a material impact on our financial statements.





Note 5—Acquisition of Downstream Business





On
September 24, 2009, we acquired Targa’s interests in the Downstream
Business for $530 million. Consideration to Targa comprised
$397.5 million in cash and the issuance to Targa of 174,033 general partner
units and 8,527,615 common units. The form of the transaction reflected in our
consolidated financial statements was:
 
 ·
              Targa
      contributed the Downstream Business to
us.
 
 -
              Prior
      to the contribution, the Downstream Business’ affiliate indebtedness
      payable to Targa totaled $817.3 million, inclusive of
      $223.0 million of
  accrued interest.
 
 -
              Immediately
      prior to, and in contemplation of, the contribution, $287.3 million
      of the Downstream Business’ affiliated indebtedness was settled through a
      separate capital contribution from Targa.
 
 -
              On
      the contribution date, the Downstream Business’ affiliate indebtedness
      payable to Targa was
  $530 million.
 
 ·
              We
      repaid the affiliate indebtedness with: (i) $397.5 million in
      cash; (ii) 174,033 in general partner units with an agreed-upon value
      of $2.7 million; and (iii) 8,527,615 in common units with an
      agreed-upon value of
$129.8 million.
 
 Our
acquisition of the Downstream Business has been accounted for as a transfer of
net assets between entities under common control.





As part
of the transaction, Targa agreed to provide distribution support to us in the
form of a reduction in the reimbursement for general and administrative expense
allocated to us if necessary (or make a payment to us, if needed) for a 1.0
times distribution coverage ratio, at the current distribution level of $0.5175
per limited partner unit, subject to maximum support of $8.0 million in any
quarter. The distribution support is in effect for the nine-quarter period
beginning with the fourth quarter of 2009 and continuing through the fourth
quarter of 2011.





We now
operate in two divisions: (i) Natural Gas Gathering and Processing (also a
segment) and (ii) NGL Logistics and Marketing. Our NGL Logistics and
Marketing division consists of three segments: (a) Logistics Assets,
(b) NGL Distribution and Marketing and (c) Wholesale Marketing. As a
result of the acquisition of the Downstream Business, we are now reporting
segment information. See Note 19.





F -
17
 Index to Financial Statements


Note 6—Inventory
 
 Due to
fluctuating commodity prices for natural gas liquids, we occasionally recognize
lower of cost or market adjustments when the carrying values of our inventories
exceeds their net realizable value. These non-cash adjustments are charged to
product purchases within operating costs and expenses in the period they are
recognized, with the related cash impact in the subsequent period. For 2009, we
did not recognize an adjustment to the carrying value of our NGL inventory. As
of December 31, 2008 and 2007, we recognized $6.0 million and
$0.2 million to reduce the carrying value of NGL inventory to its net
realizable value.


Note 7—Property, Plant and Equipment





Property,
plant and equipment and accumulated depreciation were as follows as of the dates
indicated:





December 31,2009
            
            
            2008Natural
      gas gathering systems
            
            $
            1,225.6
            
            
            $
            1,187.1Processing
      and fractionation facilities
            
            
            404.4
            
            
            
            374.0Terminalling
      and natural gas liquids storage facilities
            
            
            238.5
            
            
            
            221.9Transportation
      assets
            
            
            150.7
            
            
            
            144.5Other
      property and equipment
            
            
            16.8
            
            
            
            14.9Land
            
            
            49.8
            
            
            
            49.8Construction
      in progress
            
            
            11.0
            
            
            
            44.22,096.8
            
            
            
            2,036.4Accumulated
      depreciation
            
            
            (418.3
            )
            
            
            (317.3
            )$
            1,678.5
            
            
            $
            1,719.1







Note 8—Investment in Unconsolidated Affiliate





As of
December 31, 2009 and 2008, our unconsolidated investment consisted of a
38.75% ownership interest in Gulf Coast Fractionators LP (“GCF”), a venture that
fractionates natural gas liquids on the Gulf Coast. As of December 31, 2009 and
2008, our investment in GCF was $18.5 million.





Our
equity in the net assets of GCF exceeded our acquisition date investment account
by approximately $5.2 million. This amount is being amortized over the
estimated useful life of the net assets (25 years) on a straight-line basis, and
is included as a component of our equity in earnings of unconsolidated
investments.





The
following table shows our equity earnings and cash distributions with respect to
our unconsolidated investment in GCF for the years indicated:




Year Ended December 31,2009
            
            
            2008
            
            
            2007Equity
      in earnings
            
            $
            5.0
            
            
            $
            3.9
            
            
            $
            3.5Cash
      distributions
            
            
            5.0
            
            
            
            4.7
            
            
            
            3.9








Pursuant
to the Purchase and Sales Agreement of the Downstream Business acquisition,
Targa is entitled to receive cumulative distributions made after September 23,
2009 of up to $4.6 million. As of December 31, 2009, Targa was still
entitled to $2.3 million of GCF future distributions.








F -
18
 Index to Financial Statements





Note 9—Asset Retirement Obligations





Our asset
retirement obligations are included in our consolidated balance sheets as a
component of other long-term liabilities. The changes in our aggregate asset
retirement obligations are as follows:





Year Ended December 31,2009
            
            
            2008
            
            
            2007Beginning
      of period
            
            $
            6.2
            
            
            $
            5.9
            
            
            $
            5.4Liabilities
      settled
            
            
            -
            
            
            
            (0.2
            )
            
            
            -Change
      in cash flow estimate
            
            
            -
            
            
            
            0.2
            
            
            
            0.1Accretion
      expense
            
            
            0.4
            
            
            
            0.3
            
            
            
            0.4End
      of period
            
            $
            6.6
            
            
            $
            6.2
            
            
            $
            5.9





Note 10—Debt Obligations





Consolidated
debt obligations consisted of the following as of the dates
indicated:




December 31,2009
            
            
            2008Targa
      Resources Partners LP:Senior
      secured revolving credit facility, variable rate, due February
      2012
            
            $
            479.2
            
            
            $
            487.7Senior
      unsecured notes, 81⁄4% fixed rate, due July 2016
            
            
            209.1
            
            
            
            209.1Senior
      unsecured notes, 111⁄4% fixed
      rate, due July 2017 (1)
            
            
            220.1
            
            
            
            -Targa
      Downstream LP:Note
      payable to Parent, 10% fixed rate, due December 2011 (including accrued
      interest of $0 and $175,343)
            
            
            -
            
            
            
            744.0Targa
      LSNG LP:Note
      payable to Parent, 10% fixed rate, due December 2011 (including accrued
      interest of $0 and $4,281)
            
            
            -
            
            
            
            29.9Total
      long-term debt
            
            $
            908.4
            
            
            $
            1,470.7Letters
      of credit outstanding under senior secured revolving credit
      facility
            
            $
            69.2
            
            
            $
            9.7




_______


(1)
            The
      carrying amount of the notes includes $11.2 million of unamortized
      original issue discount as of December 31,
  2009.




Information
Regarding Variable Interest Rates Paid




The
following table shows the range of interest rates paid and weighted average
interest rate paid on our variable-rate debt obligations during
2009:





Range of interest
              rates paid
            
            Weighted average
              interest rate paidSenior
      secured revolving credit facility
            1.2%
      to 4.5%
            
            
            1.7%







Affiliated
Indebtedness





The
contributions of the North Texas System and the Downstream Business have been
treated as transfers between entities under common control (see Note 2) and
periods prior to the dates of the transfers have been adjusted to present
comparative information. On January 1, 2007, Targa contributed to us
affiliated indebtedness related to the North Texas System of $904.5 million
(including accrued interest of $88.3 million computed at 10%





F -
19
 Index to Financial Statements





per
annum) and affiliated indebtedness related to the Downstream Business of
$639.7 million (including accrued interest of $61.8 million). We
recorded $9.8 million in interest expense associated with this affiliated
debt for the period from January 1, 2007 through February 13, 2007
associated with the North Texas System. During 2009, 2008 and 2007, we recorded
$43.4 million, $59.2 million and $58.5 million in affiliated
interest expense related to the affiliated indebtedness associated with the
Downstream Business.





In
connection with the contribution of the North Texas System in 2007, all
affiliated debt and accrued interest was settled. In connection with the
acquisition of the Downstream Business in September 2009, we settled all of the
remaining obligations, including accrued interest, under our affiliated debt
agreement. See Note 5. At December 31, 2009 we had no affiliated
indebtedness outstanding.





Credit
Agreement




On
February 14, 2007, we entered into a credit agreement which provided for a
five-year $500 million credit facility with a syndicate of financial
institutions. On October 24, 2007, we entered into the First Amendment to
Credit Agreement which allows us to request commitments under the credit
agreement, as supplemented and amended, up to $1 billion. We currently have
$977.5 million committed under the senior secured credit facility. In
October 2008, Lehman Bank defaulted on a borrowing request under our senior
secured credit facility. Lehman’s commitment under the facility is
$19 million and is currently unfunded which effectively reduces our total
commitments under our credit facility by $19 million.





The
credit facility bears interest at our option, at the higher of the lender’s
prime rate or the federal funds rate plus 0.5%, plus an applicable margin
ranging from 0% to 1.25% dependent on our total leverage ratio, or LIBOR plus an
applicable margin ranging from 1.0% to 2.25% dependent on our total leverage
ratio. Our credit facility is secured by substantially all of our assets. As of
December 31, 2009, we had approximately $479.2 million of borrowings
outstanding under our senior secured credit facility and approximately
$69.2 million of outstanding letters of credit.





Our
senior secured credit facility restricts our ability to make distributions of
available cash to unitholders if a default or an event of default (as defined in
our senior secured credit agreement) has occurred and is continuing. The senior
secured credit facility requires us to maintain a leverage ratio (the ratio of
consolidated indebtedness to our consolidated EBITDA, as defined in the senior
secured credit agreement of less than or equal to 5.50 to 1.00 and a senior
secured indebtedness ratio (the ratio of senior secured indebtedness to
consolidated EBITDA, as defined in the senior secured credit agreement) of less
than or equal to 4.50 to 1.00, each subject to certain adjustments. The senior
secured credit facility also requires us to maintain an interest coverage ratio
(the ratio of our consolidated EBITDA to our consolidated interest expense, as
defined in the senior secured credit agreement) of greater than or equal to 2.25
to 1.00 determined as of the last day of each quarter for the four-fiscal
quarter period ending on the date of determination, as well as upon the
occurrence of certain events, including the incurrence of additional permitted
indebtedness. In conjunction with a material acquisition, we have the option to
increase the leverage ratio to 6.00 to 1.00 and to increase the senior secured
indebtedness ratio to 5.00 to 1.00 for a period of up to a year.





The
credit facility matures on February 14, 2012, at which time all unpaid
principal and interest is due.





81⁄4%
Senior Notes due 2016





On
June 18, 2008, we completed the private placement under Rule 144A and
Regulation S of the Securities Act of 1933 of $250 million in aggregate
principal amount of 81⁄4% senior notes due 2016 (the “81⁄4% Notes”). The 81⁄4%
Notes:





·
            are
      our unsecured senior obligations;





·
            rank
      pari passuin
      right of payment with our existing and future senior indebtedness,
      including indebtedness under our credit
  facility;





·
            are
      senior in right of payment to any of our future subordinated indebtedness;
      and





F -
20
 Index to Financial Statements





·
            are
      unconditionally guaranteed by us.





The 81⁄4%
Notes are effectively subordinated to all secured indebtedness under our credit
agreement, which is secured by substantially all of our assets, to the extent of
the value of the collateral securing that indebtedness.





Interest
on the 81⁄4% Notes accrues at the rate of 81⁄4% per annum and is payable
semi-annually in arrears on January 1 and July 1, commencing on
January 1, 2009.





At any
time prior to July 1, 2011, we may redeem up to 35% of the aggregate
principal amount of the 81⁄4% Notes with the net cash proceeds of one or more
equity offerings by us at a redemption price of 108.25% of the principal amount,
plus accrued and unpaid interest and liquidated damages, if any, to the
redemption date provided that:





(1)
            at
      least 65% of the aggregate principal amount of the 81⁄4% Notes (excluding
      81⁄4% Notes held by us) remains outstanding immediately after the occurrence
      of such redemption; and





(2)
            the
      redemption occurs within 90 days of the date of the closing of such equity
      offering.





At any
time prior to July 1, 2012, we may also redeem all or a part of the 81⁄4%
Notes at a redemption price equal to 100% of the principal amount of the 81⁄4%
Notes redeemed plus the applicable premium as defined in the indenture agreement
as of, and accrued and unpaid interest and liquidated damages, if any, to the
date of redemption.





On or
after July 1, 2012, we may redeem all or a part of the 81⁄4% Notes at the
redemption prices set forth below (expressed as percentages of principal amount)
plus accrued and unpaid interest and liquidated damages, if any, on the 81⁄4%
Notes redeemed, if redeemed during the twelve-month period beginning on
July 1 of each year indicated below:





Year
            
            Percentage2012
            
            
            104.125%2013
            
            
            102.063%2014
      and thereafter
            
            
            100.000%







During
2008, we repurchased $40.9 million face value of our outstanding 81⁄4%Notes in open
market transactions at an aggregate purchase price of $28.3 million,
including $1.5 million of accrued interest. We recognized a gain on the
debt repurchases of $13.1 million associated with the purchased notes. The
repurchased 81⁄4%Notes were retired and are not eligible for re-issue at a later
date.





111⁄4%
Senior Notes due 2017





On
July 6, 2009, we completed the private placement under Rule 144A and
Regulation S of the Securities Act of 1933 of $250 million in aggregate
principal amount of 111⁄4% senior notes due 2017 (the “111⁄4% Notes”). The 111⁄4%
Notes were issued at 94.973% of the face amount, resulting in gross proceeds of
$237.4 million. The 111⁄4% Notes:





·
            are
      our unsecured senior obligations;





·
            rank
      pari passu in
      right of payment with our existing and future senior indebtedness,
      including


indebtedness
under our senior secured revolving credit facility;





·
            are
      senior in right of payment to any of our future subordinated indebtedness;
      and





·
            are
      unconditionally guaranteed by us.





The 111⁄4%
Notes are effectively subordinated to all indebtedness under our credit
agreement, which is secured by substantially all of our assets, to the extent of
the value of the collateral securing that indebtedness.





F -
21
 Index to Financial Statements





Interest
on the 111⁄4% Notes accrues at the rate of 111⁄4% per annum and is payable
semi-annually in arrears on January 15 and July 15, commencing on
January 15, 2010.





At any
time prior to July 15, 2012, we may redeem up to 35% of the aggregate
principal amount of the 111⁄4% Notes with the net cash proceeds of certain equity
offerings by us at a redemption price of 111.25% of the principal amount, plus
accrued and unpaid interest to the redemption date, provided that:





(1) 
      at least 65% of the
      aggregate principal amount of the 111⁄4% Notes (excluding 111⁄4% Notes held by
      us) remains outstanding immediately after the occurrence of such
      redemption; and





(2) 
      the redemption
      occurs within 90 days of the date of the closing of such equity
      offering.





At any
time prior to July 15, 2013, we may also redeem all or a part of the 111⁄4%
Notes at a redemption price equal to 100% of the principal amount of the 111⁄4%
Notes redeemed plus the applicable premium as defined in the indenture as of,
and accrued and unpaid interest to, the date of redemption.





On or
after July 15, 2013, we may redeem all or a part of the 111⁄4% Notes at the
redemption prices set forth below (expressed as percentages of principal amount)
plus accrued and unpaid interest on the 111⁄4% Notes redeemed, if redeemed during
the twelve-month period beginning on July 15 of each year indicated
below:





Year
            
            Percentage2013
            
            
            105.625%2014
            
            
            102.813%2015
      and thereafter
            
            
            100.000%








The 111⁄4%
Notes are subject to a registration rights agreement dated as of July 6, 2009.
Under the registration rights agreement, we are required to file by July 7, 2010
a registration statement with respect to any 111⁄4% Notes that are not freely
transferable without volume restrictions by holders of the 111⁄4% Notes that are
not affiliates of ours. If we fail to do so, additional interest will accrue on
the principal amount of the 111⁄4% Notes. We have determined that the payment of
additional interest is not probable. As a result, we have not recorded a
liability for any contingent obligation. Any subsequent accruals of a liability
or payments made under this registration rights agreement will be charged to
earnings as interest expense in the period they are recognized or
paid.





During
2009, we repurchased $18.7 million face value of our outstanding 111⁄4% Notes
in open market transactions at an aggregated purchase price of
$18.9 million plus accrued interest of $0.3 million. We recognized a
loss on the debt repurchases of $1.5 million, including $0.4 million
in debt issue costs associated with the repurchased notes.The repurchased
111⁄4% Notes
were retired and are not eligible for re-issue at a later
date.





Compliance
with Debt Covenants





As of
December 31, 2009, the Partnership was in compliance with the covenants
contained in our various debt agreements.




Note 11—Partnership Equity and Distributions





General.In accordance with
the Partnership Agreement, we must distribute all of our available cash to
unitholders of record on the applicable record date, as determined by the
general partner within 45 days after the end of each quarter.





Conversion
of Subordinated Units. Under the terms of our amended and restated
Partnership Agreement, all 11,528,231 subordinated units converted to
common units on a one-for-one basis on May 19, 2009. The conversion had no
impact upon our calculation of earnings per unit since the subordinated units
were included in the basic and diluted earnings per unit
calculation.





F -
22
 Index to Financial Statements





Public
Offering of Common Units.On August 12, 2009, we completed a unit
offering under our shelf registration statement of 6,900,000 common units
representing limited partner interests in us at a price of $15.70 per
common unit. Net proceeds of the offering were $105.3 million, after
deducting underwriting discounts, commissions and offering expenses, and
including the general partner’s proportionate capital contribution of
$2.2 million. We used a portion of the proceeds to repay
$103.5 million of outstanding borrowings under our senior secured revolving
credit facility.





Distributions
will generally be made 98% to the common unitholders and 2% to the general
partner, subject to the payment of incentive distributions to the extent that
certain target levels of cash distributions are achieved.




Under the
quarterly incentive distribution provisions, generally our general partner is
entitled to 13% of amounts distributed in excess of $0.3881 per unit, 23%
of the amounts distributed in excess of $0.4219 per unit and 48% of amounts
distributed in excess of $0.50625 per unit. No incentive distributions were
paid to us as part of our general partner interest prior to the fourth quarter
of 2007. To the extent there is sufficient available cash, the holders of common
units are entitled to receive the minimum quarterly distribution of
$0.3375 per unit, plus arrearages.




The
following table shows the amount of cash distributions we paid to
date:




Distributions Paid
            
            
            DistributionsFor
      the Three
            
            Limited Partners
            
            
            General Partner
            
            
            
            
            
            per
      limitedDate
      Paid
            
            Months Ended
            
            Common
            
            
            Subordinated
            
            
            Incentive
            
            
            
            2%
            
            
            Total
            
            
            partner unit(In
      millions, except per unit amounts)2009November
      14, 2009
            September
      30, 2009
            
            $
            31.9
            
            
            $
            -
            
            
            $
            2.6
            
            
            $
            0.7
            
            
            $
            35.2
            
            
            $
            0.5175August
      14, 2009
            June
      30, 2009
            
            
            23.9
            
            
            
            -
            
            
            
            2.0
            
            
            
            0.5
            
            
            
            26.4
            
            
            
            0.5175May
      15, 2009
            March
      31, 2009
            
            
            18.0
            
            
            
            5.9
            
            
            
            1.9
            
            
            
            0.5
            
            
            
            26.3
            
            
            
            0.5175February
      13, 2009
            December
      31, 2008
            
            
            18.0
            
            
            
            6.0
            
            
            
            1.9
            
            
            
            0.5
            
            
            
            26.4
            
            
            
            0.51752008November
      14, 2008
            September
      30, 2008
            
            $
            17.9
            
            
            $
            6.0
            
            
            $
            1.9
            
            
            $
            0.5
            
            
            $
            26.3
            
            
            $
            0.5175August
      14, 2008
            June
      30, 2008
            
            
            17.8
            
            
            
            5.9
            
            
            
            1.7
            
            
            
            0.5
            
            
            
            25.9
            
            
            
            0.5125May
      15, 2008
            March
      31, 2008
            
            
            14.5
            
            
            
            4.8
            
            
            
            0.2
            
            
            
            0.4
            
            
            
            19.9
            
            
            
            0.4175February
      14, 2008
            December
      31, 2007
            
            
            13.8
            
            
            
            4.6
            
            
            
            0.1
            
            
            
            0.4
            
            
            
            18.9
            
            
            
            0.3975








Subsequent
Events.On January 19, 2010, we completed a public offering of
5,500,000 common units representing limited partner interests in the
Partnership (“common units”) under our existing shelf registration statement on
Form S-3 at a price of $23.14 per common unit ($22.17 per common unit,
net of underwriting discounts), providing net proceeds of $121.9 million.
Pursuant to the exercise of the underwriters’ overallotment option, we sold an
additional 825,000 common units at $23.14 per common unit, providing
net proceeds of $18.3 million. We used the net proceeds from the offering
for general partnership purposes, which included reducing borrowings under our
senior secured credit facility.





On
February 12, 2010, we paid a cash distribution of $0.5175 per unit on
our outstanding common units to unitholders of record on February 3, 2010,
for the three months ended December 31, 2009. The total distribution paid
was $38.8 million, with $24.8 million paid to our non-affiliated
common unitholders and $10.4 million, $0.8 million and
$2.8 million paid to Targa for its common unit ownership, general partner
interest and incentive distribution rights.








F -
23
 Index to Financial Statements





Note 12—Insurance Claims





We
recognize income from business interruption insurance in our consolidated
statements of operations as a component of revenues from third parties in the
period that a proof of loss is executed and submitted to the insurers for
payment. For 2009, income from business interruption insurance resulting from
the effects of Hurricane Ike was $1.9 million. In addition, we received
$0.5 million during 2009 as a result of fire damage at a third-party plant
related to our wholesale marketing segment. For 2008 and 2007, income from
business interruption insurance resulting from the effects of Hurricanes Katrina
and Rita was $18.1 million and $6.4 million. In addition, we received
$0.6 million during 2008 as a result of fire damage at a third-party plant
related to our wholesale marketing segment.





Hurricanes
Gustav and Ike





Certain
of our Louisiana and Texas facilities sustained damage and had disruptions to
their operations during the 2008 hurricane season from two Gulf Coast
hurricanes—Gustav and Ike. As of December 31, 2008, we recorded a
$4.8 million loss provision (net of estimated insurance reimbursements)
related to the hurricanes. During 2009, the estimate was reduced by
$0.8 million. During 2009, expenditures related to the hurricanes included
$6.9 million for previously accrued repair costs and $0.3 million
capitalized as improvements.





Under
Common Control accounting, the effects of insurance claims on predecessor
operations have been included in our restated financial statements, however, as
part of the Downstream acquisition, Targa retained the right to receive any
future insurance proceeds from claims associated with Gustav and
Ike.





Note 13—Accounting for Unit-Based Compensation





In 2007,
the parent of Targa, Targa Resources Investments Inc. (“Targa Investments”),
adopted a Long-Term Incentive Plan (“LTIP”) for employees, consultants and
directors of us and our affiliates who perform services for Targa Investments or
its affiliates. The LTIP provides for the grant of cash-settled performance
units, which are linked to the performance of our common units and may include
distribution equivalent rights (“DERs”). The LTIP is administered by the
compensation committee of the board of directors of Targa Investments. Subject
to applicable vesting criteria, a DER entitles the grantee to a cash payment
equal to cash distributions paid on an outstanding common unit.





Grants
outstanding under Targa Investments’ LTIP were 275,400 under the 2007 program,
135,800 under the 2008 program, 534,900 units under the 2009 program and 90,403
units under the 2010 program. During 2009, there were forfeitures under the LTIP
of 12,025 units. Grants under the 2007, 2008, 2009 and 2010 programs are payable
in August 2010, July 2011, June 2012 and June 2013. Each vested performance unit
will entitle the grantee to a cash payment equal to the then value of a
Partnership common unit, including DERs. Vesting of performance units is based
on the total return per our common unit through the end of the performance
period, relative to the total return of a defined peer group.





Because
the performance units require cash settlement, they have been accounted for as
liabilities by Targa. The fair value of a performance unit is the sum of:
(i) the closing price of one of our common units on the reporting date;
(ii) the fair value of an at-the-money call option on a performance unit
with a grant date equal to the reporting date and an expiration date equal to
the last day of the performance period; and (iii) estimated DERs. The fair
value of the call options was estimated using a Black-Scholes option pricing
model with a dividend yield of 8.5%, and with risk-free rates and volatilities
of 0.3% and 42% under the 2007 program, 0.8% and 61% under the 2008 program,
1.4% and 61% under the 2009 program and 1.4% and 52% under the 2010
program.





At
December 31, 2009, the aggregate fair value of performance units expected
to vest was $23.5 million. The remaining recognition period for the
unrecognized compensation cost is approximately three and a half years. During
2009, 2008 and 2007 Targa recognized compensation expense of $10.5 million,
$0.1 million and $2.7 million related to the performance units. Based on
Targa’s allocation methodology, we recognized allocated general and
administrative expenses related to the performance units of $6.6 million,
$0.1 million and $1.9 million for 2009, 2008 and 2007.





F -
24
 Index to Financial Statements





During 2009
and 2008, Targa Resources GP LLC, the general partner of the Partnership, also
made equity-based awards of 32,000 and 16,000 restricted common units of the
Partnership (4,000 and 2,000 restricted common units of the Partnership to each
of the Partnership’s and Targa Investments’ non-management directors) under its
(“Incentive Plan”). The awards will settle with the delivery of common units and
are subject to three-year vesting, without a performance condition, and will
vest ratably on each anniversary of the grant date. During 2009 and 2008, we
recognized compensation expense of $0.3 million related to these awards. We
estimate that the remaining fair value of $0.2 million will be recognized
in expense over approximately two years. As of December 31, 2009 there were
41,993 unvested restricted common units outstanding under this
plan.





The
following table summarizes our unit-based awards for each of the periods
indicated (in units and dollars):





Year Ended December 31,
2009Outstanding
      at beginning of period
            
            
            26,664Granted
            
            
            32,000Vested
            
            
            (16,671
            )Outstanding
      at end of period
            
            
            41,993Weighted
      average grant date fair value per share
            
            $
            12.88







Subsequent Event. On
January 22, 2010, TRGP made equity-based awards of 2,250 restricted common
units (15,750 total restricted common units) of the Partnership to each of ours
and Targa Investments’ non-management directors under the Incentive Plan. The
awards will settle with the delivery of common units and are subject to three
year vesting, without a performance condition, and will vest ratably on each
anniversary of the grant date.





Note 14—Derivative Instruments and Hedging
Activities





Our
principal market risks are our exposure to changes in commodity prices,
particularly to the prices of natural gas and NGLs, as well as changes in
interest rates.





Commodity Price Risk.A
majority of the revenues from our natural gas gathering and processing business
are derived from percent-of-proceeds contracts under which we receive a portion
of the natural gas and/or NGLs or equity volumes, as payment for services. The
prices of natural gas and NGLs are subject to market fluctuations in response to
changes in supply, demand, market uncertainty and a variety of additional
factors beyond our control. We monitor these risks and enter into commodity
derivative transactions designed to mitigate the impact of commodity price
fluctuations on our business. Cash flows from a derivative instrument designated
as a hedge are classified in the same category as the cash flows from the item
being hedged.





The
primary purpose of our commodity risk management activities is to hedge our
exposure to commodity price risk and reduce fluctuations in our operating cash
flow despite fluctuations in commodity prices. In an effort to reduce the
variability of our cash flows, as of December 31, 2009, we have hedged the
commodity price associated with a significant portion of our expected natural
gas, NGL and condensate equity volumes for the years 2010 through 2013 by
entering into derivative financial instruments including swaps and purchased
puts (or floors). The percentages of our expected equity volumes that are hedged
decrease over time. With swaps, we typically receive an agreed upon fixed price
for a specified notional quantity of natural gas or NGL and we pay the hedge
counterparty a floating price for that same quantity based upon published index
prices. Since we receive from our customers substantially the same floating
index price from the sale of the underlying physical commodity, these
transactions are designed to effectively lock-in the agreed fixed price in
advance for the volumes hedged. In order to avoid having a greater volume hedged
than our actual equity volumes, we typically limit our use of swaps to hedge the
prices of less than our expected natural gas and NGL equity volumes. We utilize
purchased puts (or floors) to hedge additional expected equity commodity volumes
without creating volumetric risk. Our commodity hedges may expose us to the risk
of financial loss in certain circumstances. Our hedging arrangements provide us
protection on the hedged volumes if market prices decline below the prices at
which these hedges are set. If market prices rise





F -
25
 Index to Financial Statements





above the
prices at which we have hedged, we will receive less revenue on the hedged
volumes than we would receive in the absence of hedges.





We have
tailored our hedges to generally match the NGL product composition and the NGL
and natural gas delivery points to those of our physical equity volumes. Our NGL
hedges cover baskets of ethane, propane, normal butane, iso-butane and natural
gasoline based upon our expected equity NGL composition. We believe this
strategy avoids uncorrelated risks resulting from employing hedges on crude oil
or other petroleum products as “proxy” hedges of NGL prices. Additionally, our
NGL hedges are based on published index prices for delivery at Mont Belvieu and
our natural gas hedges are based on published index prices for delivery at
Columbia Gulf, Houston Ship Channel, Mid-Continent and Waha, which closely
approximate our actual NGL and natural gas delivery points. We hedge a portion
of our condensate sales using crude oil hedges that are based on the NYMEX
futures contracts for West Texas Intermediate light, sweet crude.





At
December 31, 2009, the notional volumes of our commodity hedges
were:





Commodity
            
            Instrument
            
            Unit
            
            2010
            
            
            2011
            
            
            2012
            
            
            2013Natural
      Gas
            Swaps
            
            MMBtu/d
            
            
            16,494
            
            
            
            14,000
            
            
            
            10,000
            
            
            
            4,000NGL
            Swaps
            
            Bbl/d
            
            
            5,607
            
            
            
            4,000
            
            
            
            2,700
            
            
            
            -NGL
            Floors
            
            Bbl/d
            
            
            -
            
            
            
            199
            
            
            
            231
            
            
            
            -Condensate
            Swaps
            
            Bbl/d
            
            
            501
            
            
            
            350
            
            
            
            200
            
            
            
            200








Interest Rate Risk.We are
exposed to changes in interest rates, primarily as a result of our variable rate
borrowings under our credit facility. To the extent that interest rates
increase, our interest expense for our revolving debt will also increase. As of
December 31, 2009, we had borrowings of approximately $479.2 million
outstanding under our revolving credit facility. In an effort to reduce the
variability of our cash flows, we have entered into several interest rate swap
and interest rate basis swap agreements. Under these agreements, which are
accounted for as cash flow hedges, the base interest rate on the specified
notional amount of our variable rate debt is effectively fixed for the term of
each agreement and ineffectiveness is required to be measured each reporting
period. The fair values of the interest rate swap agreements, which are adjusted
regularly, have been aggregated by counterparty for classification in our
consolidated balance sheets. Accordingly, unrealized gains and losses relating
to the interest rate swaps are recorded in OCI until the interest expense on the
related debt is recognized in earnings.





Credit Risk.Our credit
exposure related to commodity derivative instruments is represented by the fair
value of contracts with a net positive fair value to us at the reporting date.
At such times, these outstanding instruments expose us to credit loss in the
event of nonperformance by the counterparties to the agreements. Should the
creditworthiness of one or more of our counterparties decline, our ability to
mitigate nonperformance risk is limited to a counterparty agreeing to either a
voluntary termination and subsequent cash settlement or a novation of the
derivative contract to a third party. In the event of a counterparty default, we
may sustain a loss and our cash receipts could be negatively
impacted.





As of
December 31, 2009, affiliates of Goldman Sachs and Bank of America (“BofA”)
accounted for 93% and 5% of our counterparty credit exposure related to
commodity derivative instruments. Goldman Sachs and BofA are major financial
institutions, each possessing investment grade credit ratings based upon minimum
credit ratings assigned by Standard & Poor’s Ratings Services.








F -
26
 Index to Financial Statements





The
following schedules reflect the fair values of derivative instruments in our
financial statements:




Asset Derivatives
            
            Liability DerivativesBalance
      Sheet
            
            Fair Value
            
            Balance
      Sheet
            
            Fair ValueLocation
            
            2009
            
            
            2008
            
            Location
            
            2009
            
            
            2008Derivatives designated as hedging
      instrumentsCommodity
      contracts
            Current
      assets
            
            $
            24.5
            
            
            $
            88.2
            
            Current
      liabilities
            
            $
            7.8
            
            
            $
            -Long
      term assets
            
            
            7.0
            
            
            
            68.3
            
            Long
      term liabilities
            
            
            24.2
            
            
            
            0.1Interest
      rate contracts
            Current
      assets
            
            
            0.2
            
            
            
            -
            
            Current
      liabilities
            
            
            8.0
            
            
            
            8.0Long
      term assets
            
            
            1.9
            
            
            
            -
            
            Long
      term liabilities
            
            
            4.7
            
            
            
            9.6Total
      derivatives designatedas
      hedging instruments
            
            
            
            33.6
            
            
            
            156.5
            
            
            
            
            44.7
            
            
            
            17.7Derivatives not designated as hedging
      instrumentsCommodity
      contracts
            Current
      assets
            
            
            1.1
            
            
            
            3.6
            
            Current
      liabilities
            
            
            0.5
            
            
            
            3.7Long
      term assets
            
            
            0.2
            
            
            
            -
            
            Long
      term liabilities
            
            
            -
            
            
            
            -Total
      derivatives not designatedas
      hedging instruments
            
            
            
            1.3
            
            
            
            3.6
            
            
            
            
            0.5
            
            
            
            3.7Total
      derivatives
            
            
            $
            34.9
            
            
            $
            160.1
            
            
            
            $
            45.2
            
            
            $
            21.4







The fair
value of derivative instruments, depending on the type of instrument, was
determined by the use of present value methods or standard option valuation
models with assumptions about commodity prices based on those observed in
underlying markets. These contracts may expose us to the risk of financial loss
in certain circumstances. Our hedging arrangements provide us protection on the
hedged volumes if prices decline below the prices at which these hedges are set.
If prices rise above the prices at which we have hedged, we will receive less
revenue on the hedged volumes than we would receive in the absence of
hedges.




Our
earnings are also affected by the use of the mark-to-market method of accounting
for derivative financial instruments that do not qualify for hedge accounting or
that have not been designated as hedges. The changes in fair value of these
instruments are recorded on the balance sheets and through earnings (i.e., using
the “mark-to-market” method) rather than being deferred until the anticipated
transaction affects earnings. The use of mark-to-market accounting for financial
instruments can cause non-cash earnings volatility due to changes in the
underlying commodity price indices. During 2009, 2008 and 2007, we recorded
mark-to-market gains (losses) of $0.8 million, ($1.0) million and
($30.2) million.





F -
27
 Index to Financial Statements





The
following tables reflect amounts reclassified from OCI to revenue and
expense:




Amount
      of Gain (Loss) Reclassified from OCI to IncomeLocation
      of Gain (Loss)
            
            (Effective Portion)Reclassified
      from
            
            Year Ended December 31,OCI into Income
            
            2009
            
            
            2008
            
            
            2007Interest
      expense, net
            
            $
            (10.4
            )
            
            $
            (2.7
            )
            
            $
            0.2Revenues
            
            
            45.8
            
            
            
            (33.7
            )
            
            
            (1.0
            )$
            35.4
            
            
            $
            (36.4
            )
            
            $
            (0.8
            )








Amount
      of Gain (Loss) Recognized in Income on DerivativesLocation
      of Gain (Loss)
            
            (Ineffective Portion)Reclassified
      from
            
            Year Ended December 31,OCI into Income
            
            2009
            
            
            2008
            
            
            2007Interest
      expense, net
            
            $
            -
            
            
            $
            -
            
            
            $
            -Revenues
            
            
            (0.1
            )
            
            
            -
            
            
            
            -$
            (0.1
            )
            
            $
            -
            
            
            $
            -








Amount
      of Gain (Loss)Recognized
      in OCI onDerivatives
      in
            
            Derivatives (Effective
    Portion)Cash
      Flow Hedging
            
            Year Ended December 31,Relationships
            
            2009
            
            
            2008
            
            
            2007Interest rate
      contracts
            
            $
            (2.1
            )
            
            $
            (19.0
            )
            
            $
            (1.7
            )Commodity
      contracts
            
            
            (72.6
            )
            
            
            129.9
            
            
            
            (105.6
            )$
            (74.7
            )
            
            $
            110.9
            
            
            $
            (107.3
            )











Amount
      of Gain (Loss) RecognizedDerivatives
            Location
      of Gain (Loss)
            
            in Income on DerivativesNot
      Designated as
            Recognized
      in Income
            
            Year Ended December 31,Hedging Instruments
            on Derivatives
            
            2009
            
            
            2008
            
            
            2007Commodity
      contracts
            Other income
      (expense)
            
            $
            0.8
            
            
            $
            (1.0
            )
            
            $
            (30.2
            )








As of
December 31, 2009, OCI included $28.7 million of unrealized net losses
on commodity hedges. As of December 31, 2008 and 2007, OCI included
$89.6 million and $74.0 million of unrealized net gains on commodity
hedges. Hedge ineffectiveness of $0.1 million was recorded in 2009. There
were no adjustments for hedge ineffectiveness for 2008 or 2007.





As of
December 31, 2009, 2008 and 2007, OCI also included $9.3 million,
$17.5 million and $1.2 million of unrealized losses on interest rate
hedges. There were no adjustments for hedge ineffectiveness for 2009, 2008 or
2007.





As of
December 31, 2009, deferred net gains (losses) of $31.5 million on
commodity hedges and ($7.8) million on interest rate hedges recorded in OCI
are expected to be reclassified to expense during the next twelve
months.





In May
2008 we entered into certain NGL derivative contracts with Lehman Brothers
Commodity Services Inc., a subsidiary of Lehman Brothers Holdings Inc.
(“Lehman”). Due to Lehman’s bankruptcy filing, it is unlikely that we will
receive full or partial payment of any amounts that may become owed to us under
these contracts. Accordingly, we discontinued hedge accounting treatment for
these contracts in July 2008. Deferred losses of





F -
28
 Index to Financial Statements





$0.1 million
and $0.3 million will be reclassified from OCI to revenues during 2011 and
2012 when the forecasted transactions related to these contracts are expected to
occur. During 2008, we recognized a non-cash mark-to-market loss on derivatives
of $1.0 million to adjust the fair value of the Lehman derivative contracts
to zero. In October 2008, we terminated the Lehman derivative
contracts.





In July
2008, we paid $87.4 million to terminate certain out-of-the-money natural
gas and NGL commodity swaps. Prior to the terminations, these swaps were
designated as hedges. Deferred losses of $27.9 million will be reclassified
from OCI as a non-cash reduction of revenue during 2010 when the hedged
forecasted sales transactions occur. During 2009 and 2008, deferred losses of
$38.8 million and $20.8 million related to the terminated swaps were
reclassified from OCI as a non-cash reduction to revenue. We also entered into
new natural gas and NGL commodity swaps at then current market prices that match
the production volumes of the terminated swaps through 2010.





Interest
Rate Swaps





As of
December 31, 2009, we had $479.2 million outstanding under our credit
facility, with interest accruing at a base rate plus an applicable margin. In
order to mitigate the risk of changes in cash flows attributable to changes in
market interest rates we have entered into interest rate swaps and interest rate
basis swaps that effectively fix the base rate on $300 million in
borrowings as shown below:




Period
            
            Fixed Rate
            
            Notional Amount
            
            Fair Value2010
            
            
            3.67%
            
            $300
      million
            
            $
            (7.8
            )2011
            
            
            3.52%
            
            300
      million
            
            
            (5.1
            )2012
            
            
            3.40%
            
            300
      million
            
            
            (0.6
            )2013
            
            
            3.39%
            
            300
      million
            
            
            1.601/01
      - 4/24/2014
            
            
            3.39%
            
            300
      million
            
            
            1.3$
            (10.6
            )







All
interest rate swaps and interest rate basis swaps have been designated as cash
flow hedges of variable rate interest payments on borrowings under our credit
facility.





The fair
value of derivative instruments, depending on the type of instrument, was
determined by the use of present value methods or standard option valuation
models with assumptions about commodity prices and interest rates based on those
observed in underlying markets. These contracts may expose us to the risk of
financial loss in certain circumstances.





See Notes
4, 15 and 18 for additional disclosures related to derivative instruments and
hedging activities.





Note 15—Related-Party Transactions





Targa
Resources, Inc.





On
February 14, 2007, we entered into an Omnibus Agreement with Targa, our
general partner and others that addressed the reimbursement of our general
partner for costs incurred on our behalf and indemnification matters. Any or all
of the provisions of this agreement, other than the indemnification provisions
described in Note 16, are terminable by Targa at its option if our general
partner is removed without cause and units held by our general partner and its
affiliates are not voted in favor of that removal. The Omnibus Agreement will
terminate in the event of a change of control of us or our general
partner.





Concurrent
with the closing of the acquisition of the SAOU and LOU Systems and the
Downstream Business, we amended and restated our Omnibus Agreement (as amended
and restated) with Targa, our general partner and others that addresses the
reimbursement of our general partner for costs incurred on our behalf,
competition and indemnification matters.





F -
29
 Index to Financial Statements





As part
of the Downstream Business transaction, Targa is providing distribution support
to us in the form of a reduction in the reimbursement for general and
administrative expense allocated to us if necessary for a 1.0 times distribution
coverage ratio, at the current $0.5175 per limited partner unit, subject to
maximum support of $8.0 million in any quarter. The distribution support is
in effect for the nine-quarter period beginning with the fourth quarter of 2009
and continuing through the fourth quarter of 2011. No distribution support was
required for the fourth quarter of 2009.





Reimbursement
of Operating and General and Administrative Expense





Under the
Omnibus Agreement, we reimburse Targa for the payment of certain operating
expenses, including compensation and benefits of operating personnel, and for
the provision of various general and administrative services for our benefit.
With respect to the North Texas System, we reimburse Targa for the following
expenses:





·
            general
      and administrative expenses, which were capped at $5.0 million
      annually for three years through February 14, 2010, subject to increases
      based on increases in the Consumer Price Index and subject to further
      increases in connection with expansions of our operations through the
      acquisition or construction of new assets or businesses with the
      concurrence of our conflicts committee; thereafter, our general partner
      will determine the general and administrative expenses to be allocated to
      us in accordance with our partnership agreement;
  and





·
            operations
      and certain direct general and administrative expenses, which are not
      subject to the $5.0 million cap for general and administrative
      expenses.





With
respect to the SAOU System, the LOU System and the Downstream Business, we will
reimburse Targa for the following expenses:





·
            general
      and administrative expenses, which are not capped, allocated to the SAOU
      System, the LOU System and the Downstream Business according to Targa’s
      allocation practice; and





·
            operating
      and certain direct expenses, which are not
  capped.





Pursuant
to these arrangements, Targa performs centralized corporate functions for us,
such as legal, accounting, treasury, insurance, risk management, health, safety
and environmental, information technology, human resources, credit, payroll,
internal audit, taxes, engineering and marketing. We reimburse Targa for the
direct expenses to provide these services as well as other direct expenses it
incurs on our behalf, such as compensation of operational personnel performing
services for our benefit and the cost of their employee benefits, including
401(k), pension and health insurance benefits.





Allocations





Allocation of costs. The
employees supporting our operations are employees of Targa. Our financial
statements include costs allocated to us by Targa for centralized general and
administrative services performed by Targa, as well as depreciation of assets
utilized by Targa’s centralized general and administrative functions. Costs
allocated to us were based on identification of Targa’s resources which directly
benefit us and our proportionate share of costs based on our estimated usage of
shared resources and functions. All of the allocations are based on assumptions
that management believes are reasonable; however, these allocations are not
necessarily indicative of the costs and expenses that would have resulted if we
had been operated as a stand-alone entity. Prior to the initial IPO and the
subsequent acquisition of the SAOU and LOU Systems these allocations were not
settled in cash, but were settled through an adjustment to partners’ capital
accounts. Effective February 14, 2007, all of the North Texas System’s
allocations were settled monthly in cash. Effective October 23, 2007, all
of the SAOU and LOU Systems’ allocations were settled monthly in
cash.





Allocations of long-term debt, debt
issue costs, interest rate swaps and interest expense. Prior to
January 1, 2007, our financial statements included long-term debt, debt
issue costs, interest rate swaps and interest expense allocated from Targa. The
allocations were calculated in a manner similar to Targa’s purchase price
allocation related to its acquisition of the SAOU and LOU Systems and the
Downstream Business, and were based on the fair




F -
30
 Index to Financial Statements
  value of
acquired tangible assets plus related net working capital and unconsolidated
equity interests. These allocations were not settled in cash. Settlement of
these allocations occurred through adjustments to partners’ capital. The
allocated debt, debt issue costs and interest rate swaps for the North Texas
System and the Downstream Business, were settled through deemed partner
contributions of $846.3 million and $478.7 million on January 1,
2007. On October 23, 2007, The allocated debt, debt issue costs and
interest rate swaps related to the SAOU and LOU Systems were settled through a
deemed partner contribution of $179.6 million.





Contracts
with Affiliates





Sales to and purchases from
affiliates.We routinely conduct business with other subsidiaries of
Targa. The related-party transactions result primarily from purchases and sales
of natural gas and purchases of NGL products. Prior to February 14, 2007,
all of our expenditures were paid through Targa, resulting in intercompany
transactions. Prior to February 14, 2007, settlement of these intercompany
transactions was through adjustments to partners’ capital accounts. After the
conveyance of the assets of the North Texas System, the SAOU and LOU Systems,
and the Downstream Business, all intercompany transactions were settled in
cash.





Natural Gas Purchase Agreements.During 2007, the North Texas, SAOU and LOU Systems entered into natural
gas purchase agreements at a price based on Targa Gas Marketing LLC’s (“TGM”)
sale price for such natural gas, less TGM’s costs and expenses associated
therewith. These agreements have an initial term of 15 years and automatically
extend for a term of five years, unless the agreements are otherwise terminated
by either party. Furthermore, either party may elect to terminate the agreements
if either party ceases to be an affiliate of Targa. In addition, Targa manages
the SAOU and LOU Systems’ natural gas sales to third parties under contracts
that remain in the name of the Targa Texas Field Services and Targa Louisiana
Field Services.





NGL Product Purchase
Agreements. On September 24, 2009, Targa Liquids Marketing and
Trade, a Delaware general partnership and indirectly, wholly-owned subsidiary of
the Partnership (“Targa Liquids”), entered into product purchase agreements with
Targa Midstream Services Limited Partnership, a Delaware limited partnership and
indirectly wholly-owned subsidiary of Targa (“TMSLP”), and Targa Permian LP, a
Delaware limited partnership and indirectly, wholly-owned subsidiary of Targa
(“Targa Permian”), pursuant to which Targa Liquids will purchase all volumes of
NGLs that are owned or controlled by TMSLP and Targa Permian and not otherwise
committed for sale to a third party, at a price based on the prevailing market
price less transportation, fractionation and certain other fees. The product
purchase agreements will have an initial term of 15 years and will automatically
extend for a term of five years. Furthermore, either party may elect to
terminate the agreement if either party ceases to be an affiliate of Targa. Each
product purchase agreement is effective as of September 1,
2009.





The
following table summarizes the sales to and purchases from affiliates of Targa,
payments made or received by Targa on behalf of us and allocations of costs from
Targa which were settled through adjustments to partners’ capital prior to the
contribution of the North Texas System and the Downstream Business by Targa and
the acquisition of the SAOU and LOU Systems from Targa. Management believes
these transactions are executed on terms that are fair and
reasonable.




Year Ended December 31,2009
              
              
              2008
              
              
              2007Sales
      to affiliates
              
              $
              197.9
              
              
              $
              489.8
              
              
              $
              417.4Purchases
      from affiliates:Included
      in product purchases
              
              
              755.0
              
              
              
              1,097.7
              
              
              
              952.8Included
      in operating expenses
              
              
              26.8
              
              
              
              58.8
              
              
              
              44.5Payments
      made to our Parent
              
              
              (1,255.9
              )
              
              
              (1,658.2
              )
              
              
              (911.6
              )Parent
      allocation of interest expense
              
              
              -
              
              
              
              -
              
              
              
              19.4Parent
      allocation of general and administrative expense
              
              
              63.9
              
              
              
              61.2
              
              
              
              60.4Net
      change in affiliate payable
              
              
              84.2
              
              
              
              48.4
              
              
              
              23.5Unit
      distributions to Targa
              
              
              132.5
              
              
              
              -
              
              
              
              -Cash
      distributions to Targa
              
              
              32.9
              
              
              
              27.0
              
              
              
              10.4Settlement
      of affiliated indebtedness
              
              
              287.3
              
              
              
              -
              
              
              
              -





F -
31
 Index to Financial Statements





Centralized
Cash Management





Prior to
the conveyance of the assets of the North Texas, SAOU and LOU Systems and the
Downstream Business to us, the excess cash from these subsidiaries was held in
separate bank accounts and swept to a centralized account under Targa. Beginning
with the contribution of these systems to us, their bank accounts have been
maintained under a separate centralized cash management system applicable to our
business operations.





For the
North Texas System, prior to February 14, 2007, cash distributions are
deemed to have occurred through partners’ capital and are reflected as an
adjustment to partners’ capital. For the period from January 1, 2007
through February 13, 2007, deemed net capital distributions from us were
$0.5 million. For the SAOU and LOU Systems for the period from
January 1, 2007 through October 23, 2007, deemed net capital
distributions from us were $133.6 million. For the Downstream Business for
the period from January 1, 2007 through September 23, 2009, net capital
distributions of cash to (from) Targa were $71.2 million,
$166.1 million and $(26.0) million for 2009, 2008 and
2007.





Transactions
with GCF





For the
years 2009, 2008 and 2007, transactions with GCF which were included in revenues
totaled $0.2 million, $0.5 million and $4.5 million. For the same
periods, transactions included in costs and expenses were $1.4 million,
$3.5 million and $3.3 million. These transactions were at market
prices consistent with similar transactions with nonaffiliated
entities.





Relationships
with Warburg Pincus LLC





Chansoo
Joung and Peter Kagan, two of the directors of Targa, are Managing Directors of
Warburg Pincus LLC and are also directors of Broad Oak Energy, Inc. (“Broad
Oak”) from whom we buy natural gas and NGL products. Affiliates of Warburg
Pincus LLC own a controlling interest in Broad Oak. We purchased
$9.7 million and $4.8 million of product from Broad Oak during 2009
and 2008. These transactions were at market prices consistent with similar
transactions with nonaffiliated entities.





Relationships
with Bank of America





Equity





An
affiliate of BofA is an equity investor in Targa Investments, which indirectly
owns our general partner.





Financial
Services




BofA
is a lender and an administrative agent under our senior secured credit
facility.




Hedging
Arrangements




We have entered into
various commodity derivative transactions with BofA. The following table shows
our open commodity derivatives with BofA as of December 31,
2009:




Period
              
              Commodity
              
              Daily Volumes
              
              Average Price
              
              IndexJan
      2010 - Dec 2010
              
              Natural
      Gas
              
              
              3,289
              
              MMBtu
              
              $
              7.39
              
              per
      MMBtu
              
              IF-WAHAJan
      2010 - Jun 2010
              
              Natural
      Gas
              
              
              663
              
              MMBtu
              
              
              8.16
              
              per
      MMBtu
              
              NY-HHJan
      2010 - Dec 2010
              
              Condensate
              
              
              181
              
              Bbl
              
              
              69.28
              
              per
      Bbl
              
              NY-WTI


As of
December 31, 2009, the fair value of these open positions was an asset of
$0.9 million. During 2009, 2008 and 2007, we received from (paid to) BofA
$25.4 million, ($9.1) million and ($1.9) million in commodity
derivative settlements.








F -
32
 Index to Financial Statements





Commercial
Relationships





We have
executed NGL sales and purchase transactions on the spot market with BofA. For
the years 2009, 2008 and 2007, sales to BofA which were included in revenues
totaled $0.5 million, $4.4 million and $18.1 million. For the
same periods, purchases from BofA were $0.3 million, $0.8 million and
$9.4 million.





Note 16—Commitments and Contingencies





Certain
property and equipment is leased under non-cancelable leases that require fixed
monthly rental payments and expire at various dates through 2099. Transportation
contracts require us to make payments for capacity and expire at various dates
through 2013. Surface and underground access for gathering, processing, and
distribution assets that are located on property not owned by us is obtained
through right-of-way agreements, which require annual rental payments and expire
at various dates through 2099. Future non-cancelable commitments related to
certain contractual obligations are presented below:




Payments Due by PeriodTotal
            
            
            2010
            
            
            2011
            
            
            2012
            
            
            2013
            
            
            2014
            
            
            ThereafterOperating
      lease obligations (1)
            
            $
            38.0
            
            
            $
            8.9
            
            
            $
            6.5
            
            
            $
            6.2
            
            
            $
            3.3
            
            
            $
            2.6
            
            
            $
            10.5Capacity
      payments (2)
            
            
            2.7
            
            
            
            2.0
            
            
            
            0.7
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -Right-of-way
            
            
            11.4
            
            
            
            0.9
            
            
            
            0.8
            
            
            
            0.8
            
            
            
            0.7
            
            
            
            0.5
            
            
            
            7.7$
            52.1
            
            
            $
            11.8
            
            
            $
            8.0
            
            
            $
            7.0
            
            
            $
            4.0
            
            
            $
            3.1
            
            
            $
            18.2


_______


(1)
            Include
      minimum lease payment obligations associated with gas processing plant
      site leases and railcar leases.


(2)
            Consist
      of capacity payments for firm transportation
  contracts.





Total
expenses related to operating leases, right-of-way and capacity payments were
$10.7 million, $1.1 million, and $3.4 million for 2009,
$11.3 million, $2.2 million and $3.1 million for 2008, and
$13.1 million, $1.4 million and $2.9 million for
2007.





Environmental





Under the
Omnibus Agreement described in Note 15, Targa indemnified us for three years
from February 14, 2007 against certain potential environmental claims,
losses and expenses associated with the operation of the North Texas System
occurring before such date that were not reserved on the books of the North
Texas System. Targa’s maximum liability for this indemnification obligation will
not exceed $10.0 million and Targa will not have any obligation under this
indemnification until our aggregate losses exceed $250,000. We have indemnified
Targa against environmental liabilities related to the North Texas System
arising or occurring after February 14, 2007.





Our
environmental liabilities not covered by the Omnibus Agreement are for ground
water assessment and remediation and such reserves were less than
$0.1 million as of December 31, 2008.





Legal
Proceedings





We are a
party to various legal proceedings and/or regulatory proceedings and certain
claims, suits and complaints arising in the ordinary course of business have
been filed or are pending against us. We believe all such matters are without
merit or involve amounts which, if resolved unfavorably, would not have a
material effect on our financial position, results of operations, or cash flows,
except for the items more fully described below.




On
December 8, 2005, WTG Gas Processing (“WTG”) filed suit in the 333rd
District Court of Harris County, Texas against several defendants, including
Targa Resources, Inc. and three other Targa entities and private equity funds
affiliated with Warburg Pincus LLC, seeking damages from the defendants. The
suit alleges that Targa and private equity funds affiliated with Warburg Pincus,
along with ConocoPhillips Company (“ConocoPhillips”) and Morgan Stanley,
tortiously interfered with (i) a contract WTG claims to have had to
purchase the SAOU System from ConocoPhillips and (ii) prospective business
relations of WTG. WTG claims the alleged interference resulted from Targa’s
competition to purchase the ConocoPhillips’ assets and its successful
acquisition of those assets in





F -
33
 Index to Financial Statements





2004. On
October 2, 2007, the District Court granted defendants’ motions for summary
judgment on all of WTG’s claims. WTG’s motion to reconsider and for a new trial
was overruled. On January 2, 2008, WTG filed a notice of appeal. On
February 3, 2009, the parties presented oral arguments to the 14th
Court of Appeals in Houston Texas.





Subsequent event.On February
23, 2010, the 14th
Court of Appeals affirmed the District Court’s final judgment in favor of
defendants in its entirety. Targa has agreed to indemnify us for any claim or
liability arising out of the WTG suit.





Note 17—Fair Value of Financial Instruments





The
estimated fair values of our assets and liabilities classified as financial
instruments have been determined using available market information and
valuation methodologies described below. Considerable judgment is required in
interpreting market data to develop the estimates of fair value. The use of
different market assumptions or valuation methodologies may have a material
effect on the estimated fair value amounts.





The
carrying values of items comprising current assets and current liabilities
approximate fair values due to the short term maturities of these instruments.
Derivative financial instruments included in our financial statements are stated
at fair value.





The
carrying value of the senior secured revolving credit facility approximates its
fair value, as its interest rate is based on prevailing market rates. The fair
value of the senior unsecured notes is based on quoted market prices based on
trades of such debt. The carrying value of the notes payable to Parent at
December 31, 2008 approximates their fair value as they were settled at
their stated amount on September 24, 2009. The carrying amounts and fair
values of our other financial instruments are as follows as of the dates
indicated:





As of December 31,2009
            
            
            2008Carrying
            
            
            Fair
            
            
            Carrying
            
            
            FairAmount
            
            
            Value
            
            
            Amount
            
            
            ValueSenior
      unsecured notes, 81⁄4% fixed rate
            
            $
            209.1
            
            
            $
            206.5
            
            
            $
            209.1
            
            
            $
            128.3Senior
      unsecured notes, 111⁄4% fixed rate (1)
            
            
            220.1
            
            
            
            253.5
            
            
            
            -
            
            
            
            -Notes
      payable to Parent:Targa
      Downstream LP
            
            
            -
            
            
            
            -
            
            
            
            744.0
            
            
            
            744.0Targa
      LSNG LP
            
            
            -
            
            
            
            -
            
            
            
            29.9
            
            
            
            29.9





(1)
            The carrying amount
      of the111⁄4% Notes includes $11.2 million of unamortized
      original issue discount as of December 31,
  2009.





Note 18—Fair Value Measurements





We
account for the fair value of our financial assets and liabilities using a
three-tier fair value hierarchy, which prioritizes the significant inputs used
in measuring fair value. These tiers include: Level 1, defined as
observable inputs such as quoted prices in active markets; Level 2, defined
as inputs other than quoted prices in active markets that are either directly or
indirectly observable; and Level 3, defined as unobservable inputs in which
little or no market data exists, therefore requiring an entity to develop its
own assumptions.





Our
derivative instruments consist of financially settled commodity and interest
rate swap and option contracts and fixed price commodity contracts with certain
customers. We determine the value of our derivative contracts utilizing a
discounted cash flow model for swaps and a standard option pricing model for
options, based on inputs that are readily available in public markets. We have
consistently applied these valuation techniques in all periods presented and
believe we have obtained the most accurate information available for the types
of derivative contracts we hold. We have categorized the inputs for these
contracts as Level 2 or Level 3.








F -
34
 Index to Financial Statements





The
following tables set forth, by level within the fair value hierarchy, our
financial assets and liabilities measured at fair value on a recurring basis as
of December 31, 2009 and 2008. These financial assets and liabilities are
classified in their entirety based on the lowest level of input that is
significant to the fair value measurement. Our assessment of the significance of
a particular input to the fair value measurement requires judgment, and may
affect the valuation of the fair value assets and liabilities and their
placement within the fair value hierarchy levels.





As of December 31, 2009
            
            Total
            
            
            Level 1
            
            
            Level 2
            
            
            Level 3Assets
      from commodity derivative contracts
            
            $
            31.5
            
            
            $
            -
            
            
            $
            31.5
            
            
            $
            -Assets
      from interest rate derivatives
            
            
            2.1
            
            
            
            -
            
            
            
            2.1
            
            
            
            -Total
      assets
            
            $
            33.6
            
            
            $
            -
            
            
            $
            33.6
            
            
            $
            -Liabilities
      from commodity derivative contracts
            
            $
            32.0
            
            
            $
            -
            
            
            $
            21.9
            
            
            $
            10.1Liabilities
      from interest rate derivatives
            
            
            12.7
            
            
            
            -
            
            
            
            12.7
            
            
            
            -Total
      liabilities
            
            $
            44.7
            
            
            $
            -
            
            
            $
            34.6
            
            
            $
            10.1








As of December 31, 2008
            
            Total
            
            
            Level 1
            
            
            Level 2
            
            
            Level 3Assets
      from commodity derivative contracts
            
            $
            160.1
            
            
            $
            -
            
            
            $
            36.8
            
            
            $
            123.3Assets
      from interest rate derivatives
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -Total
      assets
            
            $
            160.1
            
            
            $
            -
            
            
            $
            36.8
            
            
            $
            123.3Liabilities
      from commodity derivative contracts
            
            $
            3.9
            
            
            $
            -
            
            
            $
            3.9
            
            
            $
            -Liabilities
      from interest rate derivatives
            
            
            17.5
            
            
            
            -
            
            
            
            17.5
            
            
            
            -Total
      liabilities
            
            $
            21.4
            
            
            $
            -
            
            
            $
            21.4
            
            
            $
            -







The
following table sets forth a reconciliation of the changes in the fair value of
our financial instruments classified as Level 3 in the fair value
hierarchy:




Commodity Derivative
    Contracts2009
            
            
            2008Balance,
      December 31, 2008
            
            $
            123.3
            
            
            $
            (71.4
            )Unrealized
      gains (losses) included in OCI
            
            
            (37.7
            )
            
            
            99.1Purchases
            
            
            -
            
            
            
            2.9Terminations
            
            
            -
            
            
            
            77.8Settlements
            
            
            (31.4
            )
            
            
            14.9Transfers
      out of Level 3 (1)
            
            
            (64.3
            )
            
            
            -Balance,
      December 31, 2009
            
            $
            (10.1
            )
            
            $
            123.3





_______


(1)
            During
      2009, we reclassified certain of our NGL derivative contracts from
      Level 3 (unobservable inputs in which little or no market data exist)
      to Level 2 as we were able to obtain directly observable inputs other
      than quoted prices in active
markets.





Note 19—Segment Information





We
categorize the midstream natural gas industry into, and describe our business
in, two divisions: (i) Natural Gas Gathering and Processing (also a
segment) and (ii) NGL Logistics and Marketing. Our NGL Logistics and
Marketing division consists of three segments: (a) Logistics Assets,
(b) NGL Distribution and Marketing and (c) Wholesale
Marketing.





The
Natural Gas Gathering and Processing segment includes assets used in the
gathering of natural gas produced from oil and gas wells and processing this raw
natural gas into merchantable natural gas by extracting





F -
35
 Index to Financial Statements





natural
gas liquids and removing impurities. These assets are located in North Texas,
Louisiana and the Permian Basin of West Texas.





The
Logistics Assets segment is involved with gathering and storing mixed NGLs and
fractionating, storing, and transporting of finished NGLs. These assets are
generally connected to and supplied, in part, by our Natural Gas Gathering and
Processing segment and are predominantly located in Mont Belvieu, Texas and
Western Louisiana.





The NGL
Distribution and Marketing segment markets our own natural gas liquids
production and purchased natural gas liquids products in selected United States
markets. We also had the right to purchase or market substantially all of
Chevron’s natural gas liquids pursuant to a Master Natural Gas Liquids Purchase
Agreement.





The
Wholesale Marketing segment includes our refinery services business and
wholesale propane marketing operations. In our refinery services business, we
provide liquefied petroleum gas balancing services, purchase natural gas liquids
products from refinery customers and sell natural gas liquids products to
various customers. Our wholesale propane marketing operations include the sale
of propane and related logistics services to multi-state retailers, independent
retailers and other end users. Wholesale Marketing operates principally in the
United States, and has a small marketing presence in Canada.





Eliminations
and Other includes amounts related to general and administrative expenses not
allocated to segment operations, corporate development, interest expense, income
tax expense, and the depreciation and cost of equipment used in our headquarters
office. Eliminations and Other also includes the elimination of intersegment
revenues and expenses.





Our
reportable segment information is shown in the following tables:





Year Ended December 31,
2009Natural Gas
              Gathering
              and
              Processing
            
            
            Logistics
              Assets
            
            
            NGL
              Distribution
              and
              Marketing
            
            
            Wholesale Marketing
            
            
            Eliminations
              and Other
            
            
            TotalRevenues
      from third parties
            
            $
            448.9
            
            
            $
            118.6
            
            
            $
            2,522.2
            
            
            $
            808.0
            
            
            $
            -
            
            
            $
            3,897.7Revenues
      from affiliates
            
            
            197.0
            
            
            
            0.2
            
            
            
            -
            
            
            
            0.7
            
            
            
            -
            
            
            
            197.9Intersegment
      revenues
            
            
            430.6
            
            
            
            95.5
            
            
            
            414.0
            
            
            
            77.3
            
            
            
            (1,017.4
            )
            
            
            -Revenues
            
            
            1,076.5
            
            
            
            214.3
            
            
            
            2,936.2
            
            
            
            886.0
            
            
            
            (1,017.4
            )
            
            
            4,095.6Product
      purchases from third parties
            
            
            655.3
            
            
            
            -
            
            
            
            1,721.1
            
            
            
            454.2
            
            
            
            -
            
            
            
            2,830.6Product
      purchases from affiliates
            
            
            169.3
            
            
            
            -
            
            
            
            585.7
            
            
            
            -
            
            
            
            -
            
            
            
            755.0Intersegment
      product purchases
            
            
            32.1
            
            
            
            -
            
            
            
            583.3
            
            
            
            408.1
            
            
            
            (1,023.5
            )
            
            
            -Product
      purchases
            
            
            856.7
            
            
            
            -
            
            
            
            2,890.1
            
            
            
            862.3
            
            
            
            (1,023.5
            )
            
            
            3,585.6Operating
      expenses
            
            
            51.4
            
            
            
            106.6
            
            
            
            0.3
            
            
            
            -
            
            
            
            -
            
            
            
            158.3Operating
      expenses from affiliates
            
            
            -
            
            
            
            20.7
            
            
            
            -
            
            
            
            -
            
            
            
            6.1
            
            
            
            26.8Operating
      expenses
            
            
            51.4
            
            
            
            127.3
            
            
            
            0.3
            
            
            
            -
            
            
            
            6.1
            
            
            
            185.1Operating
      margin
            
            $
            168.4
            
            
            $
            87.0
            
            
            $
            45.8
            
            
            $
            23.7
            
            
            $
            -
            
            
            $
            324.9Other
      financial information:Equity
      in earnings of
              unconsolidated
      investment
            
            $
            -
            
            
            $
            5.0
            
            
            $
            -
            
            
            $
            -
            
            
            $
            -
            
            
            $
            5.0Identifiable
      assets
            
            
            1,284.5
            
            
            
            494.0
            
            
            
            214.2
            
            
            
            117.9
            
            
            
            70.3
            
            
            
            2,180.9Unconsolidated
      investments
            
            
            -
            
            
            
            18.5
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            18.5Capital
      expenditures
            
            
            28.8
            
            
            
            22.0
            
            
            
            9.8
            
            
            
            -
            
            
            
            -
            
            
            
            60.6Revenues
      by type:Commodity
      Sales
            
            $
            1,065.6
            
            
            $
            0.1
            
            
            $
            2,907.9
            
            
            $
            884.5
            
            
            $
            (919.8
            )
            
            $
            3,938.3Services
            
            
            11.1
            
            
            
            212.3
            
            
            
            28.3
            
            
            
            1.0
            
            
            
            (97.6
            )
            
            
            155.1Other
            
            
            (0.2
            )
            
            
            1.9
            
            
            
            -
            
            
            
            0.5
            
            
            
            -
            
            
            
            2.2$
            1,076.5
            
            
            $
            214.3
            
            
            $
            2,936.2
            
            
            $
            886.0
            
            
            $
            (1,017.4
            )
            
            $
            4,095.6








F -
36
 Index to Financial Statements








Year Ended December 31,
2008Natural Gas Gathering and
      Processing
            
            
            Logistics
              Assets
            
            
            NGL
              Distribution
              and
              Marketing
            
            
            Wholesale Marketing
            
            
            Eliminations
              and Other
            
            
            TotalRevenues
      from third parties
            
            $
            848.7
            
            
            $
            106.0
            
            
            $
            4,642.1
            
            
            $
            1,415.5
            
            
            $
            -
            
            
            $
            7,012.3Revenues
      from affiliates
            
            
            489.1
            
            
            
            -
            
            
            
            -
            
            
            
            0.7
            
            
            
            -
            
            
            
            489.8Intersegment
      revenues
            
            
            736.3
            
            
            
            132.0
            
            
            
            571.3
            
            
            
            43.9
            
            
            
            (1,483.5
            )
            
            
            -Revenues
            
            
            2,074.1
            
            
            
            238.0
            
            
            
            5,213.4
            
            
            
            1,460.1
            
            
            
            (1,483.5
            )
            
            
            7,502.1Product
      purchases from third parties
            
            
            1,479.0
            
            
            
            (0.1
            )
            
            
            3,474.0
            
            
            
            900.2
            
            
            
            -
            
            
            
            5,853.1Product
      purchases from affiliates
            
            
            286.9
            
            
            
            -
            
            
            
            808.6
            
            
            
            2.2
            
            
            
            -
            
            
            
            1,097.7Intersegment
      product purchases
            
            
            37.1
            
            
            
            0.1
            
            
            
            910.6
            
            
            
            544.5
            
            
            
            (1,492.3
            )
            
            
            -Product
      purchases
            
            
            1,803.0
            
            
            
            -
            
            
            
            5,193.2
            
            
            
            1,446.9
            
            
            
            (1,492.3
            )
            
            
            6,950.8Operating
      expenses from third parties
            
            
            55.3
            
            
            
            138.1
            
            
            
            1.7
            
            
            
            0.1
            
            
            
            -
            
            
            
            195.2Operating
      expenses from affiliates
            
            
            -
            
            
            
            50.0
            
            
            
            -
            
            
            
            -
            
            
            
            8.8
            
            
            
            58.8Operating
      expenses
            
            
            55.3
            
            
            
            188.1
            
            
            
            1.7
            
            
            
            0.1
            
            
            
            8.8
            
            
            
            254.0Operating
      margin
            
            $
            215.8
            
            
            $
            49.9
            
            
            $
            18.5
            
            
            $
            13.1
            
            
            $
            -
            
            
            $
            297.3Other
      financial information:Equity
      in earnings of
              unconsolidated
      investment
            
            $
            -
            
            
            $
            3.9
            
            
            $
            -
            
            
            $
            -
            
            
            $
            -
            
            
            $
            3.9Identifiable
      assets
            
            
            1,580.9
            
            
            
            498.2
            
            
            
            142.3
            
            
            
            115.7
            
            
            
            (22.3
            )
            
            
            2,314.8Unconsolidated
      investments
            
            
            -
            
            
            
            18.5
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            18.5Capital
      expenditures
            
            
            59.0
            
            
            
            41.5
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            100.5Revenues
      by type:Commodity
      sales
            
            $
            2,063.7
            
            
            $
            -
            
            
            $
            5,172.2
            
            
            $
            1,453.2
            
            
            $
            (1,349.3
            )
            
            $
            7,339.8Services
            
            
            10.4
            
            
            
            235.4
            
            
            
            31.6
            
            
            
            0.4
            
            
            
            (134.1
            )
            
            
            143.7Other
            
            
            -
            
            
            
            2.6
            
            
            
            9.6
            
            
            
            6.5
            
            
            
            (0.1
            )
            
            
            18.6$
            2,074.1
            
            
            $
            238.0
            
            
            $
            5,213.4
            
            
            $
            1,460.1
            
            
            $
            (1,483.5
            )
            
            $
            7,502.1








F -
37
 Index to Financial Statements








Year Ended December 31,
2007Natural Gas Gathering and
      Processing
            
            
            Logistics
              Assets
            
            
            NGL
              Distribution
              and
              Marketing
            
            
            Wholesale Marketing
            
            
            Eliminations
              and Other
            
            
            TotalRevenues
      from third parties
            
            $
            630.8
            
            
            $
            83.1
            
            
            $
            4,447.2
            
            
            $
            1,265.2
            
            
            $
            -
            
            
            $
            6,426.3Revenues
      from affiliates
            
            
            420.0
            
            
            
            -
            
            
            
            (3.3
            )
            
            
            0.7
            
            
            
            -
            
            
            
            417.4Intersegment
      revenues
            
            
            610.7
            
            
            
            112.0
            
            
            
            479.5
            
            
            
            30.1
            
            
            
            (1,232.3
            )
            
            
            -Revenues
            
            
            1,661.5
            
            
            
            195.1
            
            
            
            4,923.4
            
            
            
            1,296.0
            
            
            
            (1,232.3
            )
            
            
            6,843.7Product
      purchases from third parties
            
            
            1,215.7
            
            
            
            -
            
            
            
            3,350.1
            
            
            
            783.4
            
            
            
            -
            
            
            
            5,349.2Product
      purchases from affiliates
            
            
            188.5
            
            
            
            -
            
            
            
            764.1
            
            
            
            0.2
            
            
            
            -
            
            
            
            952.8Intersegment
      product purchases
            
            
            2.6
            
            
            
            -
            
            
            
            752.2
            
            
            
            489.5
            
            
            
            (1,244.3
            )
            
            
            -Product
      purchases
            
            
            1,406.8
            
            
            
            -
            
            
            
            4,866.4
            
            
            
            1,273.1
            
            
            
            (1,244.3
            )
            
            
            6,302.0Operating
      expenses from third parties
            
            
            50.9
            
            
            
            122.6
            
            
            
            1.5
            
            
            
            0.1
            
            
            
            -
            
            
            
            175.1Operating
      expenses from affiliates
            
            
            -
            
            
            
            32.5
            
            
            
            -
            
            
            
            -
            
            
            
            12.0
            
            
            
            44.5Operating
      expenses
            
            
            50.9
            
            
            
            155.1
            
            
            
            1.5
            
            
            
            0.1
            
            
            
            12.0
            
            
            
            219.6Operating
      margin
            
            $
            203.8
            
            
            $
            40.0
            
            
            $
            55.5
            
            
            $
            22.8
            
            
            $
            -
            
            
            $
            322.1Other
      financial information:Equity
      in earnings of
              unconsolidated
      investment
            
            $
            -
            
            
            $
            3.5
            
            
            $
            -
            
            
            $
            -
            
            
            $
            -
            
            
            $
            3.5Identifiable
      assets
            
            
            1,480.0
            
            
            
            482.2
            
            
            
            588.5
            
            
            
            239.7
            
            
            
            15.8
            
            
            
            2,806.2Unconsolidated
      investments
            
            
            -
            
            
            
            19.2
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            19.2Capital
      expenditures
            
            
            43.9
            
            
            
            35.2
            
            
            
            (0.2
            )
            
            
            -
            
            
            
            -
            
            
            
            78.9Revenues
      by type:Commodity
      Sales
            
            $
            1,652.5
            
            
            $
            -
            
            
            $
            4,889.3
            
            
            $
            1,294.6
            
            
            $
            (1,118.1
            )
            
            $
            6,718.3Services
            
            
            7.2
            
            
            
            195.1
            
            
            
            30.3
            
            
            
            0.6
            
            
            
            (114.3
            )
            
            
            118.9Other
            
            
            1.8
            
            
            
            -
            
            
            
            3.8
            
            
            
            0.8
            
            
            
            0.1
            
            
            
            6.5$
            1,661.5
            
            
            $
            195.1
            
            
            $
            4,923.4
            
            
            $
            1,296.0
            
            
            $
            (1,232.3
            )
            
            $
            6,843.7








The
following table is a reconciliation of operating margin to net income for each
period presented:





Year Ended December 31,2009
            
            
            2008
            
            
            2007Reconciliation
      of operating margin to net income:Operating
      margin
            
            $
            324.9
            
            
            $
            297.3
            
            
            $
            322.1Depreciation
      and amortization expense
            
            
            (101.2
            )
            
            
            (97.8
            )
            
            
            (93.5
            )General
      and administrative expense
            
            
            (78.9
            )
            
            
            (68.6
            )
            
            
            (64.0
            )Interest
      expense, net
            
            
            (95.4
            )
            
            
            (97.1
            )
            
            
            (99.4
            )Income
      tax expense
            
            
            (1.0
            )
            
            
            (2.4
            )
            
            
            (2.5
            )Other,
      net
            
            
            5.8
            
            
            
            18.3
            
            
            
            (27.5
            )Net
      income
            
            $
            54.2
            
            
            $
            49.7
            
            
            $
            35.2











F -
38
 Index to Financial Statements





Note 20—Other Operating Income





Our other
operating (income) expense consists of the following items for the periods
indicated:





Year Ended December 31,2009
            
            
            2008
            
            
            2007Casualty
      loss adjustment (see Note 12)
            
            $
            (0.8
            )
            
            $
            5.0
            
            
            $
            -Loss
      (gain) on sale of assets
            
            
            -
            
            
            
            (5.9
            )
            
            
            (0.3
            )$
            (0.8
            )
            
            $
            (0.9
            )
            
            $
            (0.3
            )








Note 21—Supplemental Cash Flow Information





The following table provides
supplemental cash flow information foreach period
presented:





Year Ended December 31,2009
            
            
            2008
            
            
            2007Cash:Interest
      paid
            
            $
            27.0
            
            
            $
            29.3
            
            
            $
            15.5Non-cash:Net
      settlement of allocated indebtedness and debt issue costs
            
            
            287.3
            
            
            
            -
            
            
            
            941.5Net
      contribution of affiliated receivables
            
            
            -
            
            
            
            -
            
            
            
            184.5Non-cash
      long-term debt allocation of payments from Parent
            
            
            -
            
            
            
            -
            
            
            
            (419.3
            )Debt
      issue costs allocated from Parent
            
            
            -
            
            
            
            -
            
            
            
            (9.7
            )Like-kind
      exchange of property, plant and equipment
            
            
            -
            
            
            
            5.8
            
            
            
            -Inventory
      line-fill transferred to property, plant and equipment
            
            
            9.8
            
            
            
            -
            
            
            
            (0.2
            )Issuance
      of Common Units in Downstream Acquisition
            
            
            129.8
            
            
            
            -
            
            
            
            -Issuance
      of General Partner Units in Downstream Acquisition
            
            
            2.7
            
            
            
            -
            
            
            
            -








Note 22—Significant Risks and Uncertainties





Nature
of Operations in Midstream Energy Industry





We
operate in the midstream energy industry. Our business activities include
gathering, transporting, processing, fractionating and storage of natural gas,
NGLs and crude oil. Our results of operations, cash flows and financial
condition may be affected by (i) changes in the commodity prices of these
hydrocarbon products and (ii) changes in the relative price levels among
these hydrocarbon products. In general, the prices of natural gas, NGLs,
condensate and other hydrocarbon products are subject to fluctuations in
response to changes in supply, market uncertainty and a variety of additional
factors that are beyond our control.





Our
profitability could be impacted by a decline in the volume of natural gas, NGLs
and condensate transported, gathered or processed at our facilities. A material
decrease in natural gas or condensate production or condensate refining, as a
result of depressed commodity prices, a decrease in exploration and development
activities or otherwise, could result in a decline in the volume of natural gas,
NGLs and condensate handled by our facilities.





A
reduction in demand for NGL products by the petrochemical, refining or heating
industries, whether because of (i) general economic conditions,
(ii) reduced demand by consumers for the end products made with NGL
products, (iii) increased competition from petroleum-based products due to
the pricing differences, (iv) adverse weather conditions,
(v) government regulations affecting commodity prices and production levels
of hydrocarbons or the content of motor gasoline or (vi) other reasons,
could also adversely affect our results of operations, cash flows and financial
position.








F -
39
 Index to Financial Statements





Counterparty
Risk with Respect to Financial Instruments





Where we
are exposed to credit risk in our financial instrument transactions, management
analyzes the counterparty’s financial condition prior to entering into an
agreement, establishes credit and/or margin limits and monitors the
appropriateness of these limits on an ongoing basis. Generally, management does
not require collateral and does not anticipate nonperformance by our
counterparties.





We have
master netting agreements with most of our hedge counterparties. These netting
agreements allow us to net settle asset and liability positions with the same
counterparties. As of December 31, 2009, we had $7.4 million in
liabilities to offset the default risk of counterparties with which we also had
asset positions of $25.9 million as of that date.




Casualty
or Other Risks





Targa
maintains coverage in various insurance programs on our behalf, which provides
us with property damage, business interruption and other coverages which are
customary for the nature and scope of our operations.





Management
believes that Targa has adequate insurance coverage, although insurance may not
cover every type of interruption that might occur. As a result of insurance
market conditions, premiums and deductibles for certain insurance policies have
increased substantially, and in some instances, certain insurance may become
unavailable, or available for only reduced amounts of coverage. As a result,
Targa may not be able to renew existing insurance policies or procure other
desirable insurance on commercially reasonable terms, if at all.





If we
were to incur a significant liability for which we were not fully insured, it
could have a material impact on our consolidated financial position and results
of operations. In addition, the proceeds of any such insurance may not be paid
in a timely manner and may be insufficient if such an event were to occur. Any
event that interrupts the revenues generated by us, or which causes us to make
significant expenditures not covered by insurance, could reduce our ability to
meet our financial obligations.





A portion
of the insurance costs described above is allocated to us by Targa through the
allocation methodology as prescribed in the Omnibus Agreement described in Note
15.





Under the
Omnibus Agreement, Targa has also indemnified us for losses attributable to
rights-of-way, certain consents or governmental permits, pre-closing litigation
relating to the North Texas System and income taxes attributable to pre-closing
operations that were not reserved on the books of the North Texas System as of
February 14, 2007. Targa does not have any obligation under these
indemnifications until our aggregate losses exceed $250,000. We have indemnified
Targa for all losses attributable to the post-closing operations of the North
Texas System. Targa’s obligations under this additional indemnification will
survive for three years from February 14, 2007, except that the
indemnification for income tax liabilities will terminate upon the expiration of
the applicable statutes of limitations.





F -
40
 Index to Financial Statements





Note 23—Selected Quarterly Financial Data
(Unaudited)





Our
results of operations by quarter for the years ended December 31, 2009 and
2008, as adjusted to reflect the consideration of common control accounting as
discussed in Note 2, were as follows:




First
                Quarter
              
              
              Second
                Quarter
              
              
              Third
                Quarter
              
              
              Fourth
                Quarter
              
              
              Total(In
      millions, except per unit amounts)Year
      Ended December 31, 2009:Revenues
              
              $
              916.0
              
              
              $
              916.3
              
              
              $
              1,008.5
              
              
              $
              1,254.8
              
              
              $
              4,095.6Operating
      income
              
              
              18.7
              
              
              
              32.7
              
              
              
              39.4
              
              
              
              54.8
              
              
              
              145.6Net
      income (loss)
              
              
              (5.4
              )
              
              
              9.3
              
              
              
              10.9
              
              
              
              39.4
              
              
              
              54.2Net
      income (loss) per limited partner
      unit - basic and diluted
              
              
              (0.09
              )
              
              
              0.10
              
              
              
              0.17
              
              
              
              0.56
              
              
              
              0.86Year
      Ended December 31, 2008:Revenues
              
              $
              2,085.3
              
              
              $
              2,128.3
              
              
              $
              2,222.5
              
              
              $
              1,066.0
              
              
              $
              7,502.1Operating
      income (loss)
              
              
              45.2
              
              
              
              67.9
              
              
              
              (7.4
              )
              
              
              26.1
              
              
              
              131.8Net
      income (loss)
              
              
              22.8
              
              
              
              45.0
              
              
              
              (38.1
              )
              
              
              20.0
              
              
              
              49.7Net
      income per limited partner
      unit - basic and diluted
              
              
              0.50
              
              
              
              0.54
              
              
              
              0.31
              
              
              
              0.48
              
              
              
              1.83


As
discussed in Note 3, we recorded an adjustment in the third quarter of 2009
related to prior period natural gas transactions which increased revenues,
operating income, and net income by $1.8 million.





The
following table reconciles the previously reported amounts to those shown above.
This table show the first and second quarter 2009 adjustments applicable to our
acquisition of the Downstream Business:


Historical
                Targa Resources Partners LP
              
              
              Downstream Business
              
              
              Adjustments
              
              
              Targa Resources Partners LPFirst
      Quarter 2009Revenues
              
              $
              239.0
              
              
              $
              764.4
              
              
              $
              (87.4
              )
              
              $
              916.0Operating
      income
              
              
              7.4
              
              
              
              11.3
              
              
              
              -
              
              
              
              18.7Net
      income (loss)
              
              
              (2.1
              )
              
              
              (3.3
              )
              
              
              -
              
              
              
              (5.4
              )Net loss
      per limited partner unit - basic
      and diluted
              
              
              (0.09
              )
              
              
              -
              
              
              
              -
              
              
              
              (0.09
              )Second
      Quarter 2009Revenues
              
              $
              240.7
              
              
              $
              779.5
              
              
              $
              (103.9
              )
              
              $
              916.3Operating
      income
              
              
              16.7
              
              
              
              16.0
              
              
              
              -
              
              
              
              32.7Net
      income (loss)
              
              
              6.5
              
              
              
              2.8
              
              
              
              -
              
              
              
              9.3Net
      income per limited partner unit - basic
      and diluted
              
              
              0.10
              
              
              
              -
              
              
              
              -
              
              
              
              0.10


F -
41
 Index to Financial Statements





During
2009, we reclassified NGL marketing fractionation and other service fees to
revenues that were originally recorded in product purchase costs. This
reclassification had no impact on our income
from operations, net income,financial position or cash flows. The
following table reconciles the previously reported amounts for the periods
indicated.


Revenues As Reported
              
              
              Adjustments
              
              
              Adjusted RevenuesFirst
      Quarter 2008
              
              $
              2,079.5
              
              
              $
              5.8
              
              
              $
              2,085.3Second
      Quarter 2008
              
              
              2,120.2
              
              
              
              8.1
              
              
              
              2,128.3Third
      Quarter 2008
              
              
              2,214.9
              
              
              
              7.6
              
              
              
              2,222.5Fourth
      Quarter 2008
              
              
              1,058.9
              
              
              
              7.1
              
              
              
              1,066.0First
      Quarter 2009
              
              
              912.3
              
              
              
              3.7
              
              
              
              916.0Second
      Quarter 2009
              
              
              906.1
              
              
              
              10.2
              
              
              
              916.3Third
      Quarter 2009
              
              
              1,003.8
              
              
              
              4.7
              
              
              
              1,008.5


F -
42